UNITED STATES SECURITIES AND EXCHANGE COMMISSION
 WASHINGTON, D.C. 20549
 FORM 10-K

 ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

 For the Fiscal Year Ended December 31, 2024
 or

 TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

 Commission
File Number
 Name of Registrant; State or Other Jurisdiction of Incorporation; Address of Principal Executive Offices; and Telephone Number
 IRS Employer Identification Number

 001-16169
 EXELON CORPORATION
 23-2990190

 (a Pennsylvania corporation)
 10 South Dearborn Street
 P.O. Box 805379
 Chicago, Illinois 60680-5379
 (800) 483-3220

 001-01839
 COMMONWEALTH EDISON COMPANY
 36-0938600

 (an Illinois corporation)
 10 South Dearborn Street
 Chicago, Illinois 60603-2300
 (312) 394-4321

 000-16844
 PECO ENERGY COMPANY
 23-0970240

 (a Pennsylvania corporation)
 2301 Market Street
 P.O. Box 8699
 Philadelphia, Pennsylvania 19101-8699
 (215) 841-4000

 001-01910
 BALTIMORE GAS AND ELECTRIC COMPANY
 52-0280210

 (a Maryland corporation)
 2 Center Plaza
 110 West Fayette Street
 Baltimore, Maryland 21201-3708
 (410) 234-5000

 001-31403
 PEPCO HOLDINGS LLC
 52-2297449

 (a Delaware limited liability company)
 701 Ninth Street, N.W.
 Washington, District of Columbia 20068-0001
 (202) 872-2000

 001-01072
 POTOMAC ELECTRIC POWER COMPANY
 53-0127880

 (a District of Columbia and Virginia corporation)
 701 Ninth Street, N.W.
 Washington, District of Columbia 20068-0001
 (202) 872-2000

 001-01405
 DELMARVA POWER & LIGHT COMPANY
 51-0084283

 (a Delaware and Virginia corporation)
 500 North Wakefield Drive
 Newark, Delaware 19702-5440
 (202) 872-2000

 001-03559
 ATLANTIC CITY ELECTRIC COMPANY
 21-0398280

 (a New Jersey corporation)
 500 North Wakefield Drive
 Newark, Delaware 19702-5440
 (202) 872-2000

 Securities registered pursuant to Section 12(b) of the Act:

 Title of each class
 Trading Symbol(s)
 Name of each exchange on which registered

 EXELON CORPORATION:

 Common Stock, without par value
 EXC
 The Nasdaq Stock Market LLC

 Securities registered pursuant to Section 12(g) of the Act:

 Title of Each Class

 COMMONWEALTH EDISON COMPANY:

 Common Stock Purchase Warrants (1971 Warrants and Series B Warrants)

 Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.

 Yes

 No
 x

 Yes

 No
 x

 Yes
 x
 No

 Yes
 x
 No

 Yes

 No
 x

 Yes

 No
 x

 Yes

 No
 x

 Yes

 No
 x

 Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.

 Yes

 No
 x

 Yes

 No
 x

 Yes

 No
 x

 Yes

 No
 x

 Yes

 No
 x

 Yes

 No
 x

 Yes

 No
 x

 Yes

 No
 x

 Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes No
 Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes No

 Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of "large accelerated filer," "accelerated filer," "smaller reporting company," and "emerging growth company" in Rule 12b-2 of the Exchange Act.

 x

 x

 x

 x

 x

 x

 x

 x

 If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. o
 Indicate by check mark whether the registrant has filed a report on and attestation to its management's assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act by the registered public accounting firm that prepared or issued its audit report. x
 If securities are registered pursuant to Section 12(b) of the Act, indicate by check mark whether the financial statements of the registrant included in the filing reflect the correction of an error to previously issued financial statements. x
 Indicate by check mark whether any of those error corrections are restatements that required a recovery analysis of incentive-based compensation received by any of the registrant's executive officers during the relevant recovery period pursuant to §240.10D-1(b). x
 Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes No x
 The estimated aggregate market value of the voting and non-voting common equity held by nonaffiliates of each registrant as of June 30, 2024 was as follows:

 Exelon Corporation Common Stock, without par value
 $ 34,615,866,949

 Commonwealth Edison Company Common Stock, $12.50 par value
 No established market

 PECO Energy Company Common Stock, without par value
 None

 Baltimore Gas and Electric Company, without par value
 None

 Not applicable

 None

 None

 None

 The number of shares outstanding of each registrant's Common stock as of January 31, 2025 was as follows:

 Exelon Corporation Common Stock, without par value
 1,005,217,157

 Commonwealth Edison Company Common Stock, $12.50 par value
 127,021,417

 PECO Energy Company Common Stock, without par value
 170,478,507

 Baltimore Gas and Electric Company Common Stock, without par value
 1,000

 Not applicable

 Potomac Electric Power Company Common Stock, $0.01 par value

 Delmarva Power & Light Company Common Stock, $2.25 par value
 1,000

 Atlantic City Electric Company Common Stock, $3.00 par value
 8,546,017

 Documents Incorporated by Reference

 Portions of the Exelon Proxy Statement for the 2025 Annual Meeting of Shareholders and the Commonwealth Edison Company 2025 Information Statement are incorporated by reference in Part III.

 PECO Energy Company, Baltimore Gas and Electric Company, Pepco Holdings LLC, Potomac Electric Power Company, Delmarva Power & Light Company, and Atlantic City Electric Company meet the conditions set forth in General Instruction I(1)(a) and (b) of Form 10-K and are therefore filing this Form in the reduced disclosure format.

 Page No.

 FILING FORMAT

 CAUTIONARY STATEMENTS REGARDING FORWARD-LOOKING INFORMATION

 WHERE TO FIND MORE INFORMATION

 ITEM 1.

 BUSINESS

 General

 Utility Operations

 Exelon's Strategy and Outlook

 Employees

 Environmental Matters and Regulation

 Executive Officers of the Registrants

 ITEM 1A.

 RISK FACTORS

 ITEM 1B.

 UNRESOLVED STAFF COMMENTS

 ITEM 1C.

 CYBERSECURITY

 ITEM 2.

 PROPERTIES

 ITEM 3.

 LEGAL PROCEEDINGS

 ITEM 4.

 MINE SAFETY DISCLOSURES

 ITEM 5.

 MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS, AND ISSUER PURCHASES OF EQUITY SECURITIES

 ITEM 6.

 [RESERVED]

 ITEM 7.

 MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

 Executive Overview

 Financial Results of Operations

 Significant 2024 Transactions and Developments

 Other Key Business Drivers and Management Strategies

 Critical Accounting Policies and Estimates

 Results of Operations

 Liquidity and Capital Resources

 ITEM 7A.

 QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

 ITEM 8.

 FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

 Page No.

 Consolidated Statements of Changes in Shareholders' Equity

 Consolidated Statements of Changes in Shareholders' Equity

 Consolidated Statements of Changes in Shareholder's Equity

 Consolidated Statements of Changes in Member's Equity

 Consolidated Statements of Changes in Shareholder's Equity

 1. Significant Accounting Policies

 2. Discontinued Operations

 Page No.

 3. Regulatory Matters

 4. Revenue from Contracts with Customers

 5. Segment Information

 6. Accounts Receivable

 7. Property, Plant, and Equipment

 8. Jointly Owned Electric Utility Plant

 9. Asset Retirement Obligations

 10. Leases

 11. Asset Impairments

 12. Intangible Assets

 13. Income Taxes

 14. Retirement Benefits

 15. Derivative Financial Instruments

 16. Debt and Credit Agreements

 17. Fair Value of Financial Assets and Liabilities

 18. Commitments and Contingencies

 19. Shareholders' Equity

 20. Stock-Based Compensation Plans

 21. Changes in Accumulated Other Comprehensive Income (Loss)

 22. Supplemental Financial Information

 23. Related Party Transactions

 ITEM 9.

 CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

 ITEM 9A.

 CONTROLS AND PROCEDURES

 ITEM 9B.

 OTHER INFORMATION

 ITEM 9C.

 DISCLOSURE REGARDING FOREIGN JURISDICTIONS THAT PREVENT INSPECTIONS

 ITEM 10.

 DIRECTORS, EXECUTIVE OFFICERS, AND CORPORATE GOVERNANCE

 ITEM 11.

 EXECUTIVE COMPENSATION

 ITEM 12.

 SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

 ITEM 13.

 CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR INDEPENDENCE

 ITEM 14.

 PRINCIPAL ACCOUNTING FEES AND SERVICES

 ITEM 15.

 EXHIBITS, FINANCIAL STATEMENT SCHEDULES

 ITEM 16.

 FORM 10-K SUMMARY

 Exelon Corporation and Related Entities

 ComEd

 PECO

 BGE

 Pepco Holdings or PHI

 Pepco Holdings LLC (formerly Pepco Holdings, Inc.)

 Pepco

 DPL

 ACE

 Registrants
 Exelon, ComEd, PECO, BGE, PHI, Pepco, DPL, and ACE, collectively

 Utility Registrants
 ComEd, PECO, BGE, Pepco, DPL, and ACE, collectively

 Legacy PHI
 PHI, Pepco, DPL, ACE, PES, and PCI, collectively

 BSC
 Exelon Business Services Company, LLC

 EEDC
 Exelon Energy Delivery Company, LLC

 Exelon Corporate
 Exelon in its corporate capacity as a holding company

 Exelon Enterprises
 Exelon Enterprises Company, LLC

 Exelon InQB8R
 Exelon InQB8R, LLC

 PCI

 Potomac Capital Investment Corporation and its subsidiaries

 PEC L.P.
 PECO Energy Capital, L.P.

 PECO Trust III
 PECO Energy Capital Trust III

 PECO Trust IV
 PECO Energy Capital Trust IV

 Pepco Energy Services or PES

 Pepco Energy Services, Inc. and its subsidiaries

 PHI Corporate
 PHI in its corporate capacity as a holding company

 PHI Service Company

 UII
 Unicom Investments, Inc.

 Former Related Entities

 Constellation
 Constellation Energy Corporation

 Generation
 Constellation Energy Generation, LLC (formerly Exelon Generation Company, LLC, a subsidiary of Exelon as of December 31, 2021 prior to separation on February 1, 2022)

 Other Terms and Abbreviations

 ABO
 Accumulated Benefit Obligation

 AECs
 Alternative Energy Credits that are issued for each megawatt hour of generation from a qualified alternative energy source

 AFUDC
 Allowance for Funds Used During Construction

 AMI
 Advanced Metering Infrastructure

 AOCI
 Accumulated Other Comprehensive Income (Loss)

 ARO
 Asset Retirement Obligation

 ATM
 At the market

 ARP
 Alternative Revenue Program

 BGS

 Basic Generation Service

 BSA
 Bill Stabilization Adjustment

 CBAs
 Collective Bargaining Agreements

 CEJA
 Climate and Equitable Jobs Act; Illinois Public Act 102-0662 signed into law on September 15, 2021

 CERCLA
 Comprehensive Environmental Response, Compensation, and Liability Act of 1980, as amended

 CIP
 Conservation Incentive Program

 Clean Air Act
 Clean Air Act of 1963, as amended

 Clean Water Act
 Federal Water Pollution Control Amendments of 1972, as amended

 CMC
 Carbon Mitigation Credit

 CODMs
 Chief Operating Decision Makers

 Conectiv

 Conectiv, LLC, a wholly owned subsidiary of PHI and the parent of DPL and ACE during the Predecessor periods

 DC PLUG
 District of Columbia Power Line Undergrounding Initiative

 DCPSC

 District of Columbia Public Service Commission

 DEPSC
 Delaware Public Service Commission

 DERs
 Distributed Energy Resources

 DOEE
 Department of Energy & Environment

 DPA
 Deferred Prosecution Agreement

 DPP
 Deferred Purchase Price

 DSIC
 Distribution System Improvement Charge

 EDIT
 Excess Deferred Income Taxes

 EIMA
 Energy Infrastructure Modernization Act (Illinois Senate Bill 1652 and Illinois House Bill 3036)

 EPA
 United States Environmental Protection Agency

 ERCOT
 Electric Reliability Council of Texas

 ERISA
 Employee Retirement Income Security Act of 1974, as amended

 EROA
 Expected Rate of Return on Assets

 ETAC
 Energy Transition Assistance Charge

 FEJA
 Illinois Public Act 99-0906 or Future Energy Jobs Act

 FERC
 Federal Energy Regulatory Commission

 GAAP
 Generally Accepted Accounting Principles in the United States

 GCR

 Gas Cost Rate

 GDP
 Gross Domestic Product

 GHG
 Greenhouse Gas

 GSA
 Generation Supply Adjustment

 GWhs
 Gigawatt hours

 ICC
 Illinois Commerce Commission

 Other Terms and Abbreviations

 IIJA
 Infrastructure Investment and Jobs Act

 IIP
 Infrastructure Investment Program

 Illinois Settlement Legislation
 Legislation enacted in 2007 affecting electric utilities in Illinois

 IPA
 Illinois Power Agency

 IRA
 Inflation Reduction Act

 IRC
 Internal Revenue Code

 IRS
 Internal Revenue Service

 ISOs
 Independent System Operators

 LNG
 Liquefied Natural Gas

 LTIP
 Long-Term Incentive Plan

 LTRRPP
 Long-Term Renewable Resources Procurement Plan

 MDPSC
 Maryland Public Service Commission

 MGP
 Manufactured Gas Plant

 mmcf
 Million Cubic Feet

 MRP
 Multi-Year Rate Plan

 MRV
 Market-Related Value

 MW
 Megawatt

 MWh
 Megawatt hour

 N/A
 Not Applicable

 NAV
 Net Asset Value

 NDT
 Nuclear Decommissioning Trust

 NERC
 North American Electric Reliability Corporation

 NJBPU

 New Jersey Board of Public Utilities

 NOLC
 Tax Net Operating Loss Carryforward

 NPDES
 National Pollutant Discharge Elimination System

 NPNS
 Normal Purchase Normal Sale scope exception

 NPS
 National Park Service

 NRD
 Natural Resources Damages

 OCI
 Other Comprehensive Income

 OPEB
 Other Postretirement Employee Benefits

 PAPUC
 Pennsylvania Public Utility Commission

 PCBs
 Polychlorinated Biphenyls

 PGC
 Purchased Gas Cost Clause

 PJM
 PJM Interconnection, LLC

 PJM Tariff
 PJM Open Access Transmission Tariff

 PLR
 Private Letter Ruling

 POLR
 Provider of Last Resort

 PPA
 Purchase Power Agreement

 PP&E
 Property, Plant, and Equipment

 PRPs
 Potentially Responsible Parties

 PSEG
 Public Service Enterprise Group Incorporated

 RCRA
 Resource Conservation and Recovery Act of 1976, as amended

 REC
 Renewable Energy Credit which is issued for each megawatt hour of generation from a qualified renewable energy source

 Regulatory Agreement Units
 Nuclear generating units or portions thereof whose decommissioning-related activities are subject to regulatory agreements with the ICC and PAPUC

 RES
 Retail Electric Suppliers

 Other Terms and Abbreviations

 RFP
 Request for Proposal

 Rider
 Reconcilable Surcharge Recovery Mechanism

 RGGI
 Regional Greenhouse Gas Initiative

 ROE

 Return on Equity

 ROU
 Right-of-use

 RPS
 Renewable Energy Portfolio Standards

 RTO
 Regional Transmission Organization

 S&P
 Standard & Poor's Ratings Services

 SEC
 United States Securities and Exchange Commission

 SOA
 Society of Actuaries

 SOFR
 Secured Overnight Financing Rate

 SOS
 Standard Offer Service

 SSA
 Social Security Administration

 TCJA
 Tax Cuts and Jobs Act

 Transition Bonds

 Transition Bonds issued by Atlantic City Electric Transition Funding LLC

 USAO
 United States Attorney's Office for the Northern District of Illinois

 ZEC
 Zero Emission Credit

 FILING FORMAT
 This combined Annual Report on Form 10-K is being filed separately by Exelon Corporation, Commonwealth Edison Company, PECO Energy Company, Baltimore Gas and Electric Company, Pepco Holdings LLC, Potomac Electric Power Company, Delmarva Power & Light Company, and Atlantic City Electric Company (Registrants). Information contained herein relating to any individual Registrant is filed by such Registrant on its own behalf. No Registrant makes any representation as to information relating to any other Registrant.

 CAUTIONARY STATEMENTS REGARDING FORWARD-LOOKING INFORMATION
 This Report contains certain forward-looking statements within the meaning of federal securities laws that are subject to risks and uncertainties. Words such as "could," "may," "expects," "anticipates," "will," "targets," "goals," "projects," "intends," "plans," "believes," "seeks," "estimates," "predicts," "should," and variations on such words, and similar expressions that reflect our current views with respect to future events and operational, economic and financial performance, are intended to identify such forward-looking statements. Accordingly, any such statements are qualified in their entirety by reference to, and are accompanied by, the following important factors that may cause our actual results or outcomes to differ materially from those contained in our forward-looking statements, including, but not limited to:

 • unfavorable legislative and/or regulatory actions;
 • uncertainty as to outcomes and timing of regulatory approval proceedings and/or negotiated settlements thereof;
 • environmental liabilities and remediation costs;
 • state and federal legislation requiring use of low-emission, renewable, and/or alternate fuel sources and/or mandating implementation of energy conservation programs requiring implementation of new technologies;
 • challenges to tax positions taken, tax law changes, and difficulty in quantifying potential tax effects of business decisions;
 • negative outcomes in legal proceedings;
 • adverse impact of the activities associated with the past DPA and now-resolved SEC investigation on Exelon's and ComEd's reputation and relationships with legislators, regulators, and customers;
 • physical security and cybersecurity risks;
 • extreme weather events, natural disasters, operational accidents such as wildfires or natural, gas explosions, war, acts and threats of terrorism, public health crises, epidemics, pandemics, or other significant events;
 • lack of sufficient capacity to meet actual or forecasted demand or disruptions at power generation facilities owned by third parties;
 • emerging technologies that could affect or transform the energy industry;
 • instability in capital and credit markets;
 • a downgrade of any Registrant's credit ratings or other failure to satisfy the credit standards in the Registrants' agreements or regulatory financial requirements;
 • significant economic downturns or increases in customer rates;
 • impacts of climate change and weather on energy usage and maintenance and capital costs; and
 • impairment of long-lived assets, goodwill, and other assets.

 New factors emerge from time to time, and it is impossible for us to predict all of such factors, nor can we assess the impact of each such factor on the business or the extent to which any factor, or combination of factors, may cause actual results to differ materially from those contained in any forward-looking statements. For more information, see those factors discussed with respect to the Registrants in Part I, ITEM 1A. Risk Factors, and in other reports filed by the Registrants from time to time with the SEC. This Annual Report on Form 10-K also describes material contingencies and critical accounting policies in (a) Part II, ITEM 7. Management's Discussion and Analysis of Financial Condition and Results of Operations and (b) Part II, ITEM 8. Financial Statements and Supplementary Data: Note 18, Commitments and Contingencies.
 Investors are cautioned not to place undue reliance on these forward-looking statements, which apply only as of the date of this Report. None of the Registrants undertakes any obligation to publicly release any revision to its forward-looking statements to reflect events or circumstances after the date of this Report.

 WHERE TO FIND MORE INFORMATION
 The SEC maintains an Internet site at www.sec.gov that contains reports, proxy and information statements, and other information that the Registrants file electronically with the SEC. These documents are also available to the public from commercial document retrieval services and free of charge at the Registrants' website at www.exeloncorp.com. Information contained on the Registrants' website shall not be deemed incorporated into, or to be a part of, this Report.

 ITEM 1.

 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

 Northern Illinois, including the City of Chicago

 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)

 Central Maryland, including the City of Baltimore (electricity and natural gas)

 Transmission and distribution of electricity and distribution of natural gas to retail customers

 Utility services holding company engaged, through its reportable segments: Pepco, DPL, and ACE
 Service Territories of Pepco, DPL, and ACE

 District of Columbia and Major portions of Montgomery and Prince George's Counties, Maryland

 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)

 Portions of Southern New Jersey

 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:

 ComEd
 PECO
 BGE
 Pepco
 DPL
 ACE

 Service Territories (in square miles)

 11,450
 1,900
 2,300
 5,400
 2,700

 N/A
 1,900
 3,050
 N/A
 N/A

 Total(a)

 11,450
 2,100
 3,250
 5,400
 2,700

 Service Territory Population (in millions)

 9.1
 4.2
 3.0
 2.4
 1.5
 1.2

 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)

 4.1
 1.7
 1.3
 1.0
 0.6
 0.6

 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
 19,400

 BGE
 1,056
 22,000

 DPL
 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
 1,345

 People of Color(a)

 8,370
 2,791
 1,093
 1,359
 1,948

 Aged <30
 2,341

 Aged 30-50
 11,348
 3,963
 1,633
 1,993
 2,375

 Aged >50
 6,325
 1,800
 1,037
 1,463

 Total Employees(b)

 20,014
 6,547
 3,055
 3,409
 4,278
 1,315

 Management
 Exelon(c)

 ComEd
 PECO
 BGE
 PHI(d)

 Pepco
 DPL
 ACE

 Female(a)

 1,173

 People of Color(a)

 1,314

 Aged <30
 —

 Aged 30-50
 2,056

 Aged >50
 1,400

 Total Employees in Management(b)

 3,479

 (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.

 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

 8,549

 ComEd
 3,553
 —
 —

 PECO
 1,462
 —
 —

 BGE
 1,485
 —
 —

 PHI
 2,045

 Pepco
 —
 —

 DPL

 ACE

 Corporate(b)

 —
 —

 (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

 Name
 Age

 Butler Jr., Calvin G.
 President and Chief Executive Officer, Exelon

 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
 Executive Vice President, Compliance, Audit and Risk, Exelon
 2020 - Present

 Chief Compliance Officer, Citadel LLC
 2017 - 2020

 Honorable, Colette
 Chief Legal Officer and Corporate Secretary

 Executive Vice President, Public Policy
 2023 - 2024

 Chief External Affairs Officer
 2023 - 2024

 Partner, Reed Smith LLP
 2017 - 2023

 Innocenzo, Michael A.
 Executive Vice President and Chief Operating Officer, Exelon

 President and Chief Executive Officer, PECO
 2018 - 2024

 Jones, Jeanne
 Executive Vice President and Chief Financial Officer, Exelon

 Senior Vice President, Corporate Finance, Exelon
 2021 - 2022

 Senior Vice President and Chief Financial Officer, ComEd
 2018 - 2021

 Kleczynski, Robert A.
 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

 ComEd

 Name
 Age

 Quiniones, Gil
 President, ComEd

 Chief Executive Officer, ComEd

 President and Chief Executive Officer, New York Power Authority
 2011 - 2021

 Binswanger, Lewis
 Senior Vice President, Governmental, Regulatory and External Affairs, ComEd

 Vice President, External Affairs, Nicor Gas
 2013 - 2022

 Levin, Joshua
 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.
 Executive Vice President and Chief Operating Officer, ComEd

 Senior Vice President, Distribution Operations, ComEd
 2019 - 2023

 Rippie, E. Glenn
 Senior Vice President and General Counsel, ComEd

 Senior Vice President and Deputy General Counsel, Energy Regulation, Exelon

 Partner, Jenner & Block LLP
 2019 - 2022

 PECO

 Name
 Age

 Velazquez, David
 President and Chief Executive Officer, PECO

 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
 Vice President and General Counsel, PECO
 2019 - Present

 Vice President, Governmental and External Affairs, PECO
 2016 - 2019

 Humphrey, Marissa
 Senior Vice President, Chief Financial Officer and Treasurer, PECO

 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
 Senior Vice President and Chief Operations Officer, PECO

 Vice President, Electrical Operations, PECO
 2018 - 2022

 Oliver, Douglas
 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

 BGE

 Name
 Age

 Khouzami, Carim V.
 President, BGE

 Chief Executive Officer, BGE
 2019 - Present

 Cloyd, Michael
 Senior Vice President, Chief Financial Officer, and Treasurer, BGE

 Vice President, Support Services, BGE
 2021 - 2024

 Dickens, Derrick
 Senior Vice President and Chief Operating Officer, BGE

 Senior Vice President, Customer Operations, PHI, Pepco, DPL, and ACE
 2020 - 2021

 Vice President, Technical Services, BGE
 2016 - 2020

 N ez, Alexander G.
 Senior Vice President, Governmental, Regulatory and External Affairs, BGE

 Senior Vice President, Regulatory Affairs and Strategy, BGE
 2020 - 2021

 Senior Vice President, Regulatory and External Affairs, BGE
 2016 - 2020

 Ralph, David
 Vice President and General Counsel, BGE

 Associate General Counsel, BGE
 2019 - 2021

 Assistant General Counsel, Exelon
 2017 - 2019

 PHI, Pepco, DPL, and ACE

 Name
 Age

 Anthony, J. Tyler
 President and Chief Executive Officer, PHI, Pepco, DPL, and ACE

 Senior Vice President and Chief Operating Officer, PHI, Pepco, DPL, and ACE
 2016 - 2021

 Bancroft, Anne
 Vice President and General Counsel, PHI, Pepco, DPL, and ACE

 Associate General Counsel, Exelon
 2017 - 2021

 Oddoye, Rodney
 Senior Vice President, Governmental, Regulatory and External Affairs, PHI, Pepco, DPL, and ACE

 Senior Vice President, Governmental and External Affairs, BGE
 2020 - 2021

 Vice President, Customer Operations, BGE
 2018 - 2020

 Olivier, Tamla
 Senior Vice President and Chief Operating Officer, PHI, Pepco, DPL, and ACE

 Senior Vice President, Customer Operations, BGE
 2020 - 2021

 Senior Vice President, Constellation NewEnergy, Inc.
 2016 - 2020

 Vahos, David
 Senior Vice President, Chief Financial Officer, and Treasurer, PHI, Pepco, DPL, ACE

 Senior Vice President, Chief Financial Officer, and Treasurer, BGE
 2016 - 2024

 ITEM 1A.
 RISK FACTORS

 Each of the Registrants operates in a complex market and regulatory environment that involves significant risks, many of which are beyond that Registrant's direct control. A number of these risks, any of which could negatively affect one or more of the Registrants' future Consolidated Statements of Operations and Comprehensive Income, Consolidated Statements of Cash Flows, and/or Consolidated Balance Sheets (consolidated financial statements), are captured below. Although the risks are generally organized by category and separately described, many of these risks are interrelated. Additionally, the risks should be considered holistically with other information included in this filing and future filings with the SEC. There may be further risks and uncertainties that are presently known or that are not currently believed to be material that could negatively affect the Registrants' future consolidated financial statements.
 Risks Related to Legislative, Regulatory, and Legal Factors
 The Registrants' businesses are highly regulated and electric and gas revenue and earnings could be negatively affected by legislative and/or regulatory actions (All Registrants).
 Substantial aspects of the Registrants' businesses are subject to comprehensive Federal or state legislation and/or regulation.
 The Utility Registrants' consolidated financial statements are heavily dependent on the ability of the Utility Registrants to recover their costs associated with the retail purchase, transmission, and distribution of power and natural gas to their customers.
 Fundamental changes in laws or regulations or adverse legislative or regulatory actions affecting the Registrants' businesses would require changes in their business planning models and operations. Registrants cannot always predict when or whether legislative or regulatory action will occur and may not be able to influence the outcome of legislative or regulatory initiatives.
 Changes in the Utility Registrants' respective terms and conditions of service, including their respective rates, along with adoption of new rate structures and constructs, or establishment of new rate cases, are subject to regulatory approval proceedings and/or negotiated settlements that are at times contentious, lengthy, and subject to appeal, which lead to uncertainty as to the ultimate result, and which could result in uncertainties in rate case outcomes, and/or introduce time delays in effectuating rate changes (All Registrants).
 The Utility Registrants are required to engage in regulatory approval proceedings as a part of the process of establishing the terms and rates for their respective services, adoption of new rate structures and constructs or establishment of new rate cases. These proceedings typically involve multiple parties, including governmental bodies and officials, consumer advocacy groups, and various consumers of energy, who have differing concerns but who have the common objective of limiting rate increases or even reducing rates. Decisions are subject to appeal, potentially leading to additional uncertainty associated with the approval proceedings. The potential duration of such proceedings creates a risk that rates ultimately approved by the applicable regulatory body may not be sufficient for a Utility Registrant to recover its costs once the rates become effective. Established rates are also subject to subsequent prudency reviews by state regulators, whereby various portions of rates including recovery mechanisms for costs associated with the procurement of electricity or gas, credit losses, MGP remediation, smart grid infrastructure, and energy efficiency and demand response programs, could be adjusted, subject to refund, or disallowed. In certain instances, the Utility Registrants could agree to negotiated settlements related to various rate matters, customer initiatives, or franchise agreements. These settlements are subject to regulatory approval. The ultimate outcome and timing of regulatory rate proceedings have a significant effect on the ability of the Utility Registrants to recover their costs or earn an adequate return.
 In addition to potential timing delays, the Registrants also face other uncertainties in rate proceedings that could impact recovery, including not obtaining anticipated allowed rates of return, allowed capital structures, or allowed return on pension assets, and various other factors.
 See Note 3 — Regulatory Matters of the Combined Notes to the Consolidated Financial Statements for additional information.

 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.

 ITEM 1B.
 UNRESOLVED STAFF COMMENTS

 None.

 ITEM 1C.
 CYBERSECURITY

 Risk management and strategy
 Cybersecurity risk for all Registrants is managed at the enterprise-level. Management of material risks from cybersecurity threats is integrated into the Registrants' overall risk management processes and is monitored as

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

 ITEM 2.
 PROPERTIES

 The Utility Registrants
 The Utility Registrants' electric substations and a portion of their transmission rights are located on property that they own. A significant portion of their electric transmission and distribution facilities are located above or underneath highways, streets, other public places, or property that others own. The Utility Registrants believe that they have satisfactory rights to use those places or property in the form of permits, grants, easements, licenses, and franchise rights; however, they have not necessarily undertaken to examine the underlying title to the land upon which the rights rest.
 Transmission and Distribution
 The Utility Registrants' high voltage electric transmission lines owned and in service at December 31, 2024 were as follows:

 Voltage
 Circuit Miles

 (Volts)
 ComEd
 PECO
 BGE
 Pepco
 DPL
 ACE

 765,000
 —
 —
 —
 —
 —

 500,000(a)

 —
 —

 345,000
 2,678
 —
 —
 —
 —
 —

 230,000
 —

 138,000
 2,268

 115,000
 —
 —
 —
 —

 69,000
 —
 —
 —

 (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)

 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
 Storage Capacity
(mmcf)
 Send-out or Peaking Capacity
(mmcf/day)

 PECO
 LNG Facility
 West Conshohocken, PA
 1,200

 PECO
 Propane Air Plant
 Chester, PA

 BGE
 LNG Facility
 Baltimore, MD
 1,056

 BGE
 Propane Air Plant
 Baltimore, MD

 DPL
 LNG Facility
 Wilmington, DE

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

 ITEM 3.
 LEGAL PROCEEDINGS

 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.

 ITEM 4.
 MINE SAFETY DISCLOSURES

 Not Applicable

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

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

 Exelon's common stock is listed on the Nasdaq (trading symbol: EXC). As of January 31, 2025, there were 1,005,217,157 shares of Common stock outstanding and approximately 73,288 record holders of Common stock.
 Stock Performance Graph
 The performance graph below illustrates a five-year comparison of cumulative total returns based on an initial investment of $100 in Exelon Common stock, compared with the S&P 500 Stock Index and the S&P Utility Index, for the period 2020 through 2024. Cumulative total returns account for the separation of Constellation, as the spin-off dividend was assumed to have been reinvested upon receipt.
 This performance chart assumes:
 •$100 invested on December 31, 2019 in Exelon Common stock, the S&P 500 Stock Index, and the S&P Utility Index; and
 • All dividends are reinvested.

 Value of Investment at December 31,

 2019
 2020
 2021
 2022
 2023
 2024

 $100.00
 $100.22
 $141.73
 $153.53
 $132.08
 $144.25

 S&P 500
 $100.00
 $155.68
 $200.37
 $164.08
 $207.21
 $259.05

 S&P Utilities
 $100.00
 $126.96
 $149.39
 $151.73
 $140.99
 $174.02

 ComEd
 As of January 31, 2025, there were 127,021,417 outstanding shares of Common stock, $12.50 par value, of ComEd, of which 127,002,904 shares were indirectly held by Exelon. As of January 31, 2025, in addition to Exelon, there were 280 record holders of ComEd Common stock. There is no established market for shares of the Common stock of ComEd.
 PECO
 As of January 31, 2025, there were 170,478,507 outstanding shares of Common stock, without par value, of PECO, all of which were indirectly held by Exelon.
 BGE
 As of January 31, 2025, there were 1,000 outstanding shares of Common stock, without par value, of BGE, all of which were indirectly held by Exelon.
 PHI
 As of January 31, 2025, Exelon indirectly held the entire membership interest in PHI.
 Pepco
 As of January 31, 2025, there were 100 outstanding shares of Common stock, $0.01 par value, of Pepco, all of which were indirectly held by Exelon.
 DPL
 As of January 31, 2025, there were 1,000 outstanding shares of Common stock, $2.25 par value, of DPL, all of which were indirectly held by Exelon.
 ACE
 As of January 31, 2025, there were 8,546,017 outstanding shares of Common stock, $3.00 par value, of ACE, all of which were indirectly held by Exelon.
 Dividends
 Under applicable Federal law, ComEd, PECO, BGE, PHI, Pepco, DPL, and ACE can pay dividends only from retained, undistributed, or current earnings. A significant loss recorded at ComEd, PECO, BGE, PHI, Pepco, DPL, or ACE may limit the dividends that these Registrants can distribute to Exelon.
 ComEd has agreed, in connection with a financing arranged through ComEd Financing III, that ComEd will not declare dividends on any shares of its capital stock in the event that: (1) it exercises its right to extend the interest payment periods on the subordinated debt securities issued to ComEd Financing III; (2) it defaults on its guarantee of the payment of distributions on the preferred trust securities of ComEd Financing III; or (3) an event of default occurs under the Indenture under which the subordinated debt securities are issued. No such event has occurred.

 PECO has agreed, in connection with financings arranged through PEC L.P. and PECO Trust IV, that PECO will not declare dividends on any shares of its capital stock in the event that: (1) it exercises its right to extend the interest payment periods on the subordinated debentures which were issued to PEC L.P. or PECO Trust IV; (2) it defaults on its guarantee of the payment of distributions on the Series D Preferred Securities of PEC L.P. or the preferred trust securities of PECO Trust IV; or (3) an event of default occurs under the Indenture under which the subordinated debentures are issued. No such event has occurred.
 BGE is subject to restrictions established by the MDPSC that prohibit BGE from paying a dividend on its common shares if (a) after the dividend payment, BGE's equity ratio would be below 48% as calculated pursuant to the MDPSC's ratemaking precedents or (b) BGE's senior unsecured credit rating is rated by two of the three major credit rating agencies below investment grade. No such event has occurred.
 Pepco is subject to certain dividend restrictions established by settlements approved by the MDPSC and DCPSC that prohibit Pepco from paying a dividend on its common shares if (a) after the dividend payment, Pepco's equity ratio would be below 48% as calculated pursuant to the MDPSC's and DCPSC's ratemaking precedents, or (b) Pepco's senior unsecured credit rating is rated by one of the three major credit rating agencies below investment grade. No such event has occurred.
 DPL is subject to certain dividend restrictions established by settlements approved by the DEPSC and MDPSC that prohibit DPL from paying a dividend on its common shares if (a) after the dividend payment, DPL's equity ratio would be below 48% as calculated pursuant to the DEPSC's and MDPSC's ratemaking precedents, or (b) DPL's corporate issuer or senior unsecured credit rating, or its equivalent, is rated by any of the three major credit rating agencies below the generally accepted definition of investment grade. No such event has occurred.
 ACE is subject to certain dividend restrictions established by settlements approved by the NJBPU that prohibit ACE from paying a dividend on its common shares if (a) after the dividend payment, ACE's common equity ratio would be below 48% as calculated pursuant to the NJBPU's ratemaking precedents, or (b) ACE's senior corporate issuer or senior unsecured credit rating is rated by one of the three major credit rating agencies below investment grade. ACE is also subject to a dividend restriction which requires ACE to notify and obtain the prior approval of the NJBPU before dividends can be paid if its equity as a percent of its total capitalization, excluding securitization debt, falls below 30%. No such event has occurred.
 Exelon's Board of Directors approved an updated dividend policy for 2025. The 2025 quarterly dividend will be $0.40 per share.
 As of December 31, 2024, Exelon had Retained earnings of $6,426 million, ComEd had Retained earnings of $2,664 million, PECO had Retained earnings of $2,170 million, BGE had Retained earnings of $2,403 million, and PHI had Undistributed losses of $240 million.
 The following table sets forth Exelon's quarterly cash dividends per share paid during 2024 and 2023:

 2024
 2023

 (per share)
 Fourth
 Third
 Second
 First
 Fourth
 Third
 Second
 First

 $
 $
 $
 $
 $
 0.3600
 $
 0.3600
 $
 0.3600
 $
 0.3600

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

 2024
 2023

 (in millions)
 4th
 3rd
 2nd
 1st
 4th
 3rd
 2nd
 1st

 ComEd
 $
 $
 $
 $
 $
 $
 $
 $

 PECO

 BGE

 PHI

 Pepco

 DPL

 ACE

 First Quarter 2025 Dividend
 On February 12, 2025, Exelon's Board of Directors declared a regular quarterly dividend of $0.40 per share on Exelon's Common stock for the first quarter of 2025. The dividend is payable on Friday, March 14, 2025, to shareholders of record of Exelon as of 5 p.m. Eastern time on Monday, February 24, 2025.

 ITEM 6.
 [RESERVED]

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

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

 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

 $
 2,460
 $
 2,328
 $

 ComEd
 1,066
 1,090
 (24)

 PECO
 (12)

 BGE

 PHI

 Pepco

 DPL

 ACE

 (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:

 2024
 2023

 (In millions, except per share data)
 Earnings per
Diluted Share
 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)
 0.03

 Asset retirement obligations (net of taxes of $3 and $1, respectively)

 0.01
 (1)
 —

 SEC matter loss contingency (net of taxes of $0)

 —
 —
 0.05

 Separation costs (net of taxes of $0 and $7, respectively)(a)

 —
 —
 0.02

 Cost management charge (net of taxes of 4)(b)

 0.01
 —
 —

 Change in FERC audit liability (net of taxes of $13 and $4, respectively)

 0.04
 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
 Service
 Approved Revenue Requirement Increase
 Approved ROE
 Approval Date
 Rate Effective Date

 ComEd - Illinois
 January 17, 2023
 $
 1,487
 $
 1,045
 8.905%
 December 19, 2024
 January 1, 2024

 April 26, 2024 (amended on September 11, 2024)
 $
 $
 9.89%
 October 31, 2024

 PECO - Pennsylvania
 March 28, 2024
 $464
 $
 N/A
 December 12, 2024

 $111
 $

 BGE - Maryland
 February 17, 2023
 $
 $
 9.50%
 December 14, 2023
 January 1, 2024

 $
 $
 9.45%

 Pepco - District of Columbia
 April 13, 2023 (amended February 27, 2024)
 $
 $
 9.50%
 November 26, 2024

 Pepco - Maryland
 October 26, 2020 (amended March 31, 2021)
 $
 $
 9.55%
 June 28, 2021
 June 28, 2021

 May 16, 2023 (amended February 23, 2024)
 $
 $
 9.50%
 June 10, 2024
 April 1, 2024

 DPL - Maryland
 May 19, 2022
 $
 $
 9.60%
 December 14, 2022
 January 1, 2023

 DPL - Delaware
 December 15, 2022 (amended September 29, 2023)
 $
 $
 9.60%
 April 18, 2024
 July 15, 2023

 ACE - New Jersey
 February 15, 2023 (amended August 21, 2023)
 $
 $
 9.60%
 November 17, 2023
 December 1, 2023

 Pending Distribution Base Rate Case Proceedings

 Registrant/Jurisdiction
 Service
 Requested ROE
 Expected Approval Timing

 DPL - Delaware
 September 20, 2024
 $
 10.50%
 First quarter of 2026

 ACE - New Jersey
 November 21, 2024
 $
 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
 $
 $
 (12)
 $
 8.14
 %
 11.50
 %

 PECO
 $
 $
 $
 7.45
 %
 10.35
 %

 BGE
 $
 $
 $
 7.47
 %
 10.50
 %

 Pepco
 $
 $
 $
 7.62
 %
 10.50
 %

 DPL
 $
 $
 $
 7.23
 %
 10.50
 %

 ACE
 $
 $
 $
 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:

 Actual Assumption
 (Decrease) Increase

 Actuarial Assumption
 Pension
 OPEB
 Change in
Assumption
 Pension
 OPEB
 Total

 Change in 2024 cost:

 Discount rate(a)

 5.19%
 5.17%
 0.5%
 $
 (18)
 $
 (2)
 $
 (20)

 5.19%
 5.17%
 (0.5)%
 $
 $
 $

 EROA
 7.00%
 6.50%
 0.5%
 $
 (53)
 $
 (6)
 $
 (59)

 7.00%
 6.50%
 (0.5)%
 $
 $
 $

 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)%
 $
 $
 $

 (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:

 ComEd
 PECO
 BGE
 PHI
 Pepco
 DPL
 ACE

 Gain (loss)
 $
 2,803
 $
 4,897
 $
 (693)
 $
 (347)
 $
 (1,030)
 $
 (276)
 $
 $
 (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

 $
 8,219
 $
 7,844
 $

 3,042
 2,816
 (226)

 1,703
 1,450
 (253)

 1,514
 1,403
 (111)

 (7)

 6,635
 6,038
 (597)

 Gain on sales of assets
 —

 1,589
 1,806
 (217)

 (501)
 (477)
 (24)

 (407)
 (402)
 (5)

 1,182
 1,404
 (222)

 $
 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.

 $

 Energy efficiency

 Other

 $

 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

 Labor, other benefits, contracting, and materials(a)

 $

 BSC costs

 (4)

 Other(b)

 (7)

 $

 (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:

 $

 Regulatory asset amortization(b)

 $

 (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

 $
 3,973
 $
 3,894
 $

 Purchased power and fuel
 1,477
 1,544

 1,120
 1,003
 (117)

 (31)

 (16)

 3,243
 3,146
 (97)

 Gain on sales of assets
 —

 (14)

 (232)
 (201)
 (31)

 (195)
 (165)
 (30)

 (44)

 (12)

 $
 $
 $
 (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.

 Gas
 Total

 Weather
 $
 $
 $

 Volume

 Pricing

 —

 Other
 (2)
 (1)

 (62)
 (48)

 Total increase (decrease)
 $
 $
 (45)
 $

 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
 2024
 2023
 Normal
 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
 Weather - Normal % Change(b)

 13,963
 13,262
 5.3
 %
 0.2
 %

 7,683
 7,367
 4.3
 %
 1.3
 %

 13,889
 13,638
 1.8
 %
 0.6
 %

 1.2
 %
 1.2
 %

 Total electric retail deliveries(a)

 36,148
 34,873
 3.7
 %
 0.6
 %

 Number of Electric Customers
 2024
 2023

 1,533,443
 1,535,927

 155,164
 156,248

 3,150
 3,127

 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
 Weather - Normal % Change(b)

 38,328
 35,842
 6.9
 %
 0.7
 %

 21,906
 21,182
 3.4
 %
 0.1
 %

 (66.7)
 %
 (11.1)
 %

 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
 2024
 2023

 508,224
 507,197

 44,846
 45,001

 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.

 Credit loss expense
 $

 BSC costs

 Labor, other benefits, contracting, and materials

 (6)

 Other

 $

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

 $

 —

 $

 (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

 $
 4,426
 $
 4,027
 $

 Purchased power and fuel
 1,651
 1,531
 (120)

 1,036
 (295)

 (26)

 3,670
 3,245
 (425)

 (26)

 (216)
 (182)
 (34)

 (180)
 (164)
 (16)

 (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.

 Gas
 Total

 $
 $
 $

 —

 Other
 (2)
 —

 (55)

 $
 $
 $

 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
 2024
 2023

 1,216,614
 1,211,889

 115,010
 115,787

 13,266
 13,072

 Total
 1,345,150
 1,341,009

 Number of Gas Customers
 2024
 2023

 658,776
 657,823

 37,874
 37,993

 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

 BSC costs
 $

 Labor, other benefits, contracting, and materials

 Credit loss expense

 Multi-year plans reconciliations(a)

 Other(b)

 Regulatory required programs(c)

 $

 (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:

 (Decrease) Increase

 $
 (7)

 Regulatory required programs(a)

 (64)

 $
 (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
 $
 $
 $

 Pepco

 DPL

 ACE

 (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

 $
 3,039
 $
 2,824
 $

 1,055
 (81)

 (34)

 2,420
 2,377
 (43)

 (Loss) gain on sales of assets
 (1)
 (10)

 (192)
 (165)
 (27)

 (12)

 (138)
 (99)
 (39)

 (39)

 $
 $
 $

 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.

 $

 Other
 (2)

 $

 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
 2024
 2023

 877,916
 866,018

 54,036
 54,142

 23,068
 22,941

 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

 (Decrease) Increase

 Labor, other benefits, contracting, and materials(a)

 $
 (56)

 BSC and PHISCO costs

 (2)

 Credit loss expense
 (4)

 (4)

 Pepco Maryland multi-year plan reconciliations (b)

 (23)

 Other
 (6)

 (82)

 Regulatory required programs (c)

 $
 (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:

 $

 (1)

 Regulatory required programs(b)

 (58)

 $
 (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

 $
 1,787
 $
 1,688
 $

 Purchased power and fuel
 (23)

 (13)

 (1)

 (4)

 1,461
 1,420
 (41)

 (93)
 (74)
 (19)

 (68)
 (56)
 (12)

 (14)

 $
 $
 $

 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.

 Gas
 Total

 Weather
 $
 $
 $

 Volume

 —

 Other
 —

 (34)

 $
 $
 (25)
 $

 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
 2024
 2023
 Normal
 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
 2024
 2023
 Normal
 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
 Weather - Normal % Change (b)

 3,227
 3,065
 5.3
 %
 3.1
 %

 1,445
 1,399
 3.3
 %
 2.2
 %

 3,019
 3,071
 (1.7)
 %
 (1.9)
 %

 (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)
 2024
 2023

 490,626
 485,713

 64,813
 64,220

 1,255
 1,260

 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
 Weather - Normal % Change(b)

 7,810
 7,326
 6.6
 %
 0.9
 %

 3,801
 3,660
 3.9
 %
 (1.9)
 %

 1,674
 1,588
 5.4
 %
 5.4
 %

 6,206
 6,004
 3.4
 %
 1.6
 %

 Total natural gas deliveries(a)

 19,491
 18,578
 4.9
 %
 0.9
 %

 DPL

 Number of Delaware Natural Gas Customers
 2024
 2023

 131,392
 129,903

 10,218
 10,133

 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

 BSC and PHISCO costs
 $

 (2)

 Labor, other benefits, contracting, and materials
 (2)

 (4)

 Other
 (2)

 $

 Regulatory required programs(a)

 $

 (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:

 $

 Regulatory required programs(b)

 (9)

 $

 (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

 $
 1,628
 $
 1,522
 $

 (61)

 (1)

 1,353
 1,314
 (39)

 (79)
 (72)
 (7)

 (6)

 (65)
 (52)
 (13)

 (19)

 $
 $
 $

 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.

 $

 (1)

 $

 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
 2024
 2023

 507,483
 504,919

 62,739
 62,646

 2,843
 2,909

 Total
 573,779
 571,201

 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.

 BSC and PHISCO costs

 (1)

 (1)

 Labor, other benefits, contracting and materials(a)

 (42)

 Other
 (3)

 (37)

 $
 (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:

 $

 Regulatory required programs(b)

 (25)

 $
 (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
 ComEd
 PECO
 BGE
 PHI
 Pepco
 DPL
 ACE

 Net income (loss)
 $
 $
 (24)
 $
 (12)
 $
 $
 $
 $
 $

 Adjustments to reconcile net income to cash:

 Non-cash operating activities
 (38)
 (5)

 Collateral received (paid), net
 (39)
 —

 (52)
 (220)
 (162)
 (91)
 (98)
 (90)
 (50)
 (5)

 (51)
 (3)
 (18)
 (62)
 (6)

 (162)
 (40)
 (76)
 (41)

 Changes in working capital and other noncurrent assets and liabilities
 (533)
 (199)
 (180)
 (8)
 (35)

 Increase (decrease) in cash flows from operating activities
 $
 $
 $
 (265)
 $
 (56)
 $
 $
 (15)
 $
 $

 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
 ComEd
 PECO
 BGE
 PHI
 Pepco
 DPL
 ACE

 $
 $
 $
 (127)
 $
 (53)
 $
 $
 $
 $

 Proceeds from sales of assets and businesses
 —
 —
 —
 (10)
 (10)
 —
 —

 (1)
 (8)
 (8)
 —
 —

 Increase (decrease) in cash flows from investing activities
 $
 $
 $
 (123)
 $
 (48)
 $
 $
 $
 $

 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
 ComEd
 PECO
 BGE
 PHI
 Pepco
 DPL
 ACE

 Changes in short-term borrowings, net
 $
 (601)
 $
 (591)
 $
 $
 (89)
 $
 $
 $
 $
 (212)

 Long-term debt, net
 (695)
 (425)
 (58)
 (75)
 (8)

 Changes in intercompany money pool
 —
 —
 —
 —
 (23)
 —
 —
 —

 —
 —
 —
 —
 —
 —
 —

 (91)
 (30)
 (52)
 —
 (107)
 (87)
 (1)

 Distributions to member
 —
 —
 —
 —
 (193)
 —
 —
 —

 Contributions from parent/member
 —
 (428)
 (148)
 (48)

 —
 (1)
 (2)
 (1)

 (Decrease) increase in cash flows from financing activities
 $
 (1,372)
 $
 (1,474)
 $
 $
 $
 (85)
 $
 $
 $
 (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
 Use of Proceeds

 Notes
 5.15%
 March 15, 2029
 $650
 Repay Exelon SMBC Term Loan, outstanding commercial paper, and for general corporate purposes.

 Notes
 5.45%
 March 15, 2034
 Repay Exelon SMBC Term Loan, outstanding commercial paper, and for general corporate purposes.

 Notes
 5.60%
 Repay Exelon SMBC Term Loan, outstanding commercial paper, and for general corporate purposes.

 ComEd
 5.30%
 June 1, 2034
 Repay existing indebtedness, repay outstanding commercial paper obligations, and to fund other general corporate purposes.

 ComEd
 5.65%
 June 1, 2054
 Repay existing indebtedness, repay outstanding commercial paper obligations, and to fund other general corporate purposes.

 PECO
 5.25%
 September 15, 2054
 Refinance outstanding commercial paper and for general corporate purposes

 BGE
 Notes
 5.30%
 June 1, 2034
 Repay outstanding commercial paper obligations and for general corporate purposes

 BGE
 Notes
 5.65%
 June 1, 2054
 Repay outstanding commercial paper obligations and for general corporate purposes

 Pepco
 5.20%
 March 15, 2034
 Refinance existing indebtedness, refinance outstanding commercial paper obligations, and for general corporate purposes.

 Pepco
 5.50%
 March 15, 2054
 Refinance existing indebtedness, refinance outstanding commercial paper obligations, and for general corporate purposes.

 DPL
 5.24%
 March 20, 2034

 DPL
 5.55%
 March 20, 2054

 ACE
 5.55%
 March 20, 2054

 ACE
 5.29%
 August 28, 2034

 ACE
 5.49%
 August 28, 2039

 During 2023, the following long-term debt was issued:

 Company
 Type
 Use of Proceeds

 Notes
 5.15%
 March 15, 2028
 $1,000

 Notes
 5.30%
 March 15, 2033

 Notes
 5.60%

 ComEd
 First Mortgage Bonds, Series 134
 4.90%
 February 1, 2033
 Repay outstanding commercial paper obligations and to fund other general corporate purposes.

 ComEd
 First Mortgage Bonds Series 135
 5.30%
 February 1, 2053
 Repay outstanding commercial paper obligations and to fund other general corporate purposes.

 PECO
 First and Refunding Mortgage Bonds
 4.90%
 June 15, 2033
 Refinance existing indebtedness, refinance outstanding commercial paper obligations, and for general corporate purposes.

 BGE
 Notes
 5.40%
 June 1, 2053
 Repay outstanding commercial paper obligations, repay existing indebtedness, and for general corporate purposes.

 Pepco
 5.35%
 September 13, 2033

 Pepco
 5.30%
 March 15, 2033

 Pepco
 5.40%
 March 15, 2038

 Pepco
 5.57%

 DPL
 5.30%
 March 15, 2033

 DPL
 5.57%

 DPL
 5.45%
 November 8, 2033

 DPL
 5.55%
 November 8, 2038

 DPL
 5.72%
 November 8, 2053

 ACE
 5.57%

 During 2024, the following long-term debt was retired and/or redeemed:

 Company(b)

 Type

 SMBC Term Loan Agreement
 SOFR plus 0.85%
 April 8, 2024
 $

 Software Licensing Agreement
 3.62%
 December 1, 2025

 Software Licensing Agreement
 3.95%
 May 1, 2024

 Software Licensing Agreement
 2.30%
 December 1, 2025

 ComEd
 3.10%
 November 1, 2024

 Pepco
 3.60%
 March 15, 2024

 DPL(a)

 Unsecured tax-exempt bonds
 4.32%
 July 1, 2024

 ACE
 3.38%
 September 1, 2024

 (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

 SMBC Term Loan Agreement
 SOFR plus 0.65%
 July 21, 2023
 $

 US Bank Term Loan Agreement
 SOFR plus 0.65%
 July 21, 2023

 PNC Term Loan Agreement
 SOFR plus 0.65%
 July 24, 2023

 Long-Term Software License Agreement
 3.70%
 August 9, 2025

 Long-Term Software License Agreement
 3.95%
 May 1, 2024

 Long-Term Software License Agreement
 3.70%
 August 9, 2025

 Long-Term Software License Agreement
 2.30%
 December 1, 2025

 PECO
 Loan Agreement
 2.00%
 June 20, 2023

 BGE
 Notes
 3.35%
 July 1, 2023

 DPL
 3.50%
 November 15, 2023

 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:

 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
 $

 Second Quarter 2024
 April 30, 2024
 May 13, 2024
 June 14, 2024
 $

 Third Quarter 2024
 July 30, 2024
 August 12, 2024
 September 13, 2024
 $

 Fourth Quarter 2024
 October 29, 2024
 November 11, 2024
 December 13, 2024
 $

 First Quarter 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
 $
 $
 —
 $

 PECO
 —

 BGE
 —

 Pepco
 —
 —

 DPL
 —

 ACE
 —
 —

 (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)

 N/A
 N/A
 N/A
 $
 9,075
 $
 28,925

 ComEd
 2,225
 N/A
 3,200
 10,650

 PECO
 1,300
 1,875
 5,900

 BGE
 1,850
 5,950

 PHI
 1,400
 2,150
 6,400

 Pepco
 N/A
 1,050
 3,000

 DPL
 1,900

 ACE
 N/A
 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

 $
 $
 $

 ComEd

 PECO

 BGE

 PHI

 Pepco

 DPL
 —

 ACE
 —

 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:

 2025
 Total

 Long-term debt and finance leases(a)

 $
 1,453
 $
 43,215
 $
 44,668

 Interest payments on long-term debt(b)

 1,922
 29,825
 31,747

 2025 - 2099

 Fuel purchase agreements(c)

 1,613
 1,906
 2025 - 2039

 3,716
 2,217
 5,933
 2025 - 2028

 Long-term renewable energy and REC commitments
 2,541
 2,963
 2025 - 2044

 Other purchase obligations(d)

 5,532
 5,431
 10,963
 2025 - 2034

 ZEC commitments

 Pension contributions(e)

 1,375
 1,650
 2025 - 2030

 $
 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
 Total

 Long-term debt(a)

 $
 —
 $
 12,368
 $
 12,368

 Interest payments on long-term debt(b)

 8,601
 9,108

 —
 —
 —
 2025 - 2026

 Long-term renewable energy and REC commitments
 2,416
 2,817
 2025 - 2044

 Other purchase obligations(c)

 1,712
 2,595
 2025 - 2034

 ZEC commitments

 $
 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
 Total

 Long-term debt(a)

 $
 $
 5,609
 $
 5,959

 Interest payments on long-term debt(b)

 4,752
 5,002

 —
 —
 —
 2025 - 2034

 Fuel purchase agreements(c)

 2025 - 2039

 2025 - 2026

 Other purchase obligations(d)

 1,059
 1,669
 2025 - 2031

 $
 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
 Total

 $
 —
 $
 5,450
 $
 5,450

 4,418
 4,646

 2025 - 2099

 Fuel purchase agreements(b)

 1,007
 2025 - 2038

 1,197
 1,997

 Other purchase obligations(c)

 1,197
 1,693
 2,890
 2025 - 2034

 $
 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
 Total

 Long-term debt and finance leases
 $
 $
 8,502
 $
 8,792

 5,802
 6,196

 Fuel purchase agreements(b)

 2025 - 2030

 1,456
 1,055
 2,511
 2025 - 2028

 Long-term renewable energy commitments
 2025 - 2033

 Other purchase obligations(c)

 1,093
 1,339
 2,432
 2025 - 2033

 $
 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
 Total

 Long-term debt and finance leases
 $
 $
 4,421
 $
 4,427

 3,265
 3,475

 1,133
 2025 - 2028

 Other purchase obligations(b)

 1,203
 2025 - 2033

 $
 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
 Total

 Long-term debt and finance leases
 $
 $
 2,106
 $
 2,236

 1,620
 1,716

 Fuel purchase agreements(b)

 2025 - 2030

 Long-term renewable energy commitments
 2025 - 2033

 Other purchase obligations(c)

 2025 - 2031

 $
 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
 Total

 Long-term debt and finance leases
 $
 $
 1,789
 $
 1,943

 Other purchase obligations(b)

 2025 - 2029

 $
 $
 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

 Interest payments on long-term debt

 Long-term renewable energy and REC commitments

 ZEC commitments

 DC PLUG obligation

 Pension contributions

 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:

 ComEd
 PECO
 BGE
 PHI
 Pepco
 DPL
 ACE

 %
 %
 %
 %
 %
 %
 %
 %

 Long-term debt to affiliates(a)

 %
 %
 %
 —
 %
 —
 %
 —
 %
 —
 %
 —
 %

 Common equity
 %
 %
 %
 %
 —
 %
 %
 %
 %

 Member's equity
 —
 %
 —
 %
 —
 %
 —
 %
 %
 —
 %
 —
 %
 —
 %

 Commercial paper and notes payable
 %
 —
 %
 %
 %
 %
 %
 %
 %

 (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.

 As of December 31, 2024

 Exelon Intercompany Money Pool
 Maximum Contributed
 Maximum Borrowed
 Contributed (Borrowed)

 Exelon Corporate
 $
 $
 —
 $

 PECO
 (255)
 —

 BSC
 —
 (420)
 (213)

 PHI Corporate
 —
 (86)
 (63)

 PCI
 —

 As of December 31, 2024

 PHI Intercompany Money Pool
 Maximum Contributed
 Maximum Borrowed
 Contributed (Borrowed)

 Pepco
 $
 $
 (48)
 $
 —

 DPL
 (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:

 Short-term Financing Authority
 Remaining Long-term Financing Authority

 Commission
 Expiration Date
 Commission
 Expiration Date

 ComEd
 FERC
 $
 2,500
 ICC
 January 1, 2027 & May 1, 2027
 $
 2,318

 PECO(b)

 FERC
 1,500
 PAPUC
 —

 BGE
 FERC
 MDPSC
 N/A

 Pepco(a)

 FERC
 MDPSC / DCPSC

 DPL(a)

 FERC
 MDPSC / DEPSC

 ACE(c)

 NJBPU
 NJBPU

 (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.

 ITEM 7A.
 QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

 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.

 Maturities Within
 Total Fair
Value

 Commodity derivative contracts(a):

 2025
 2026
 2027
 2028
 2029
 2030 and Beyond

 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.

 ITEM 8.
 FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

 The management of Exelon Corporation (Exelon) is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rule 13a-15(f). Internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.
 Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
 Exelon's management conducted an assessment of the effectiveness of Exelon's internal control over financial reporting as of December 31, 2024. In making this assessment, management used the criteria in Internal Control—Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this assessment, Exelon's management concluded that, as of December 31, 2024, Exelon's internal control over financial reporting was effective.
 The effectiveness of Exelon's internal control over financial reporting as of December 31, 2024, has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report which appears herein.

 The management of Commonwealth Edison Company (ComEd) is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rule 13a-15(f). Internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.
 Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
 ComEd's management conducted an assessment of the effectiveness of ComEd's internal control over financial reporting as of December 31, 2024. In making this assessment, management used the criteria in Internal Control—Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this assessment, ComEd's management concluded that, as of December 31, 2024, ComEd's internal control over financial reporting was effective.

 The management of PECO Energy Company (PECO) is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rule 13a-15(f). Internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.
 Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
 PECO's management conducted an assessment of the effectiveness of PECO's internal control over financial reporting as of December 31, 2024. In making this assessment, management used the criteria in Internal Control—Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this assessment, PECO's management concluded that, as of December 31, 2024, PECO's internal control over financial reporting was effective.

 The management of Baltimore Gas and Electric Company (BGE) is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rule 13a-15(f). Internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.
 Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
 BGE's management conducted an assessment of the effectiveness of BGE's internal control over financial reporting as of December 31, 2024. In making this assessment, management used the criteria in Internal Control—Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this assessment, BGE's management concluded that, as of December 31, 2024, BGE's internal control over financial reporting was effective.

 The management of Pepco Holdings LLC (PHI) is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rule 13a-15(f). Internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.

 Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

 PHI's management conducted an assessment of the effectiveness of PHI's internal control over financial reporting as of December 31, 2024. In making this assessment, management used the criteria in Internal Control—Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this assessment, PHI's management concluded that, as of December 31, 2024, PHI's internal control over financial reporting was effective.

 The management of Potomac Electric Power Company (Pepco) is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rule 13a-15(f). Internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.
 Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
 Pepco's management conducted an assessment of the effectiveness of Pepco's internal control over financial reporting as of December 31, 2024. In making this assessment, management used the criteria in Internal Control—Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this assessment, Pepco's management concluded that, as of December 31, 2024, Pepco's internal control over financial reporting was effective.

 The management of Delmarva Power & Light Company (DPL) is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rule 13a-15(f). Internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.
 Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
 DPL's management conducted an assessment of the effectiveness of DPL's internal control over financial reporting as of December 31, 2024. In making this assessment, management used the criteria in Internal Control—Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this assessment, DPL's management concluded that, as of December 31, 2024, DPL's internal control over financial reporting was effective.

 The management of Atlantic City Electric Company (ACE) is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rule 13a-15(f). Internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.
 Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
 ACE's management conducted an assessment of the effectiveness of ACE's internal control over financial reporting as of December 31, 2024. In making this assessment, management used the criteria in Internal Control—Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this assessment, ACE's management concluded that, as of December 31, 2024, ACE's internal control over financial reporting was effective.

 To the Board of Directors and Shareholders of Exelon Corporation
 Opinions on the Financial Statements and Internal Control over Financial Reporting
 We have audited the consolidated financial statements, including the related notes, of Exelon Corporation and its subsidiaries (the "Company") as listed in the index appearing under Item 15(a)(1)(i), and the financial statement schedules listed in the index appearing under Item 15(a)(1)(ii), (collectively referred to as the "consolidated financial statements"). We also have audited the Company's internal control over financial reporting as of December 31, 2024, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).
 In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of the Company as of December 31, 2024 and 2023, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2024 in conformity with accounting principles generally accepted in the United States of America. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2024, based on criteria established in Internal Control - Integrated Framework (2013) issued by the COSO.
 Basis for Opinions
 The Company's management is responsible for these consolidated financial statements, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting, included in Management's Report on Internal Control Over Financial Reporting appearing under Item 8. Our responsibility is to express opinions on the Company's consolidated financial statements and on the Company's internal control over financial reporting based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
 We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud, and whether effective internal control over financial reporting was maintained in all material respects.
 Our audits of the consolidated financial statements included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.
 Definition and Limitations of Internal Control over Financial Reporting
 A company's internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company's internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company's assets that could have a material effect on the financial statements.

 Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
 The critical audit matter communicated below is a matter arising from the current period audit of the consolidated financial statements that was communicated or required to be communicated to the audit committee and that (i) relates to accounts or disclosures that are material to the consolidated financial statements and (ii) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.
 As described in Notes 1 and 3 to the consolidated financial statements, the Company applies the authoritative guidance for accounting for certain types of regulation, which requires management to record in the consolidated financial statements the effects of cost-based rate regulation for entities with regulated operations that meet the following criteria, (i) rates are established or approved by a third-party regulator; (ii) rates are designed to recover the entity's cost of providing services or products; and (iii) there is a reasonable expectation that rates designed to recover costs can be charged to and collected from customers. The Company accounts for its regulated operations in accordance with regulatory and legislative guidance from the regulatory authorities having jurisdiction under state public utility laws and the FERC under various Federal laws. Upon updates in material regulatory and legislative proceedings, where applicable, management will record new regulatory assets or liabilities and will assess whether it is probable that its currently recorded regulatory assets and liabilities will be recovered and settled, respectively, in future rates. As of December 31, 2024, there were $10.65 billion of regulatory assets and $10.61 billion of regulatory liabilities.
 The principal considerations for our determination that performing procedures relating to the Company's accounting for the effects of rate regulation is a critical audit matter are the high degree of audit effort to assess the impact of regulation on accounting for regulatory assets and liabilities and to evaluate the complex audit evidence related to whether the regulatory assets and liabilities will be recovered and settled.
 Addressing the matter involved performing procedures and evaluating audit evidence in connection with forming our overall opinion on the consolidated financial statements. These procedures included testing the effectiveness of controls relating to accounting for regulatory matters and evaluation of new and existing regulatory assets and liabilities. These procedures also included, among others, obtaining the Company's correspondence with regulators, evaluating the reasonableness of management's interpretation of regulatory guidance and proceedings and the related accounting implications, and recalculating regulatory assets and liabilities based on provisions outlined in rate orders and other correspondence with regulators.

 Chicago, Illinois
 We have served as the Company's auditor since 2000.

 To the Board of Directors and Shareholders of Commonwealth Edison Company
 We have audited the consolidated financial statements, including the related notes, of Commonwealth Edison Company and its subsidiaries (the "Company") as listed in the index appearing under Item 15(a)(2)(i), and the financial statement schedule listed in the index appearing under Item 15(a)(2)(ii) (collectively referred to as the "consolidated financial statements"). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2024 and 2023, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2024 in conformity with accounting principles generally accepted in the United States of America.
 These consolidated financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on the Company's consolidated financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
 We conducted our audits of these consolidated financial statements in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion.
 Our audits included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. We believe that our audits provide a reasonable basis for our opinion.
 The critical audit matter communicated below is a matter arising from the current period audit of the consolidated financial statements that was communicated or required to be communicated to the audit committee and that (i) relates to accounts or disclosures that are material to the consolidated financial statements and (ii) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.
 As described in Notes 1 and 3 to the consolidated financial statements, the Company applies the authoritative guidance for accounting for certain types of regulation, which requires management to record in the consolidated financial statements the effects of cost-based rate regulation for entities with regulated operations that meet the following criteria, (i) rates are established or approved by a third-party regulator; (ii) rates are designed to recover the entity's cost of providing services or products; and (iii) there is a reasonable expectation that rates designed to recover costs can be charged to and collected from customers. The Company accounts for its regulated operations in accordance with regulatory and legislative guidance from the regulatory authorities having jurisdiction under state public utility laws and the FERC under various Federal laws. Upon updates in material regulatory and legislative proceedings, where applicable, management will record new regulatory assets or liabilities and will assess whether it is probable that its currently recorded regulatory assets and liabilities will be

 recovered and settled, respectively, in future rates. As of December 31, 2024, there were $3.72 billion of regulatory assets and $8.62 billion of regulatory liabilities.
 The principal considerations for our determination that performing procedures relating to the Company's accounting for the effects of rate regulation is a critical audit matter are the high degree of audit effort to assess the impact of regulation on accounting for regulatory assets and liabilities and to evaluate the complex audit evidence related to whether the regulatory assets and liabilities will be recovered and settled.
 Addressing the matter involved performing procedures and evaluating audit evidence in connection with forming our overall opinion on the consolidated financial statements. These procedures included testing the effectiveness of controls relating to accounting for regulatory matters and evaluation of new and existing regulatory assets and liabilities. These procedures also included, among others, obtaining the Company's correspondence with regulators, evaluating the reasonableness of management's interpretation of regulatory guidance and proceedings and the related accounting implications, and recalculating regulatory assets and liabilities based on provisions outlined in rate orders and other correspondence with regulators.

 Chicago, Illinois

 We have served as the Company's auditor since 2000.

 To the Board of Directors and Shareholders of PECO Energy Company
 We have audited the consolidated financial statements, including the related notes, of PECO Energy Company and its subsidiaries (the "Company") as listed in the index appearing under Item 15(a)(3)(i), and the financial statement schedule listed in the index appearing under Item 15(a)(3)(ii) (collectively referred to as the "consolidated financial statements"). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2024 and 2023, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2024 in conformity with accounting principles generally accepted in the United States of America.
 These consolidated financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on the Company's consolidated financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
 We conducted our audits of these consolidated financial statements in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion.
 Our audits included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. We believe that our audits provide a reasonable basis for our opinion.
 The critical audit matter communicated below is a matter arising from the current period audit of the consolidated financial statements that was communicated or required to be communicated to the audit committee and that (i) relates to accounts or disclosures that are material to the consolidated financial statements and (ii) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.
 As described in Notes 1 and 3 to the consolidated financial statements, the Company applies the authoritative guidance for accounting for certain types of regulation, which requires management to record in the consolidated financial statements the effects of cost-based rate regulation for entities with regulated operations that meet the following criteria, (i) rates are established or approved by a third-party regulator; (ii) rates are designed to recover the entity's cost of providing services or products; and (iii) there is a reasonable expectation that rates designed to recover costs can be charged to and collected from customers. The Company accounts for its regulated operations in accordance with regulatory and legislative guidance from the regulatory authorities having jurisdiction under state public utility laws and the FERC under various Federal laws. Upon updates in material regulatory and legislative proceedings, where applicable, management will record new regulatory assets or liabilities and will assess whether it is probable that its currently recorded regulatory assets and liabilities will be

 recovered and settled, respectively, in future rates. As of December 31, 2024, there were $1.07 billion of regulatory assets and $375 million of regulatory liabilities.
 The principal considerations for our determination that performing procedures relating to the Company's accounting for the effects of rate regulation is a critical audit matter are the high degree of audit effort to assess the impact of regulation on accounting for regulatory assets and liabilities and to evaluate the complex audit evidence related to whether the regulatory assets and liabilities will be recovered and settled.
 Addressing the matter involved performing procedures and evaluating audit evidence in connection with forming our overall opinion on the consolidated financial statements. These procedures included testing the effectiveness of controls relating to accounting for regulatory matters and evaluation of new and existing regulatory assets and liabilities. These procedures also included, among others, obtaining the Company's correspondence with regulators, evaluating the reasonableness of management's interpretation of regulatory guidance and proceedings and the related accounting implications, and recalculating regulatory assets and liabilities based on provisions outlined in rate orders and other correspondence with regulators.

 We have served as the Company's auditor since 1932.

 To the Board of Directors and Shareholder of Baltimore Gas and Electric Company
 We have audited the financial statements, including the related notes, of Baltimore Gas and Electric Company (the "Company") as listed in the index appearing under Item 15(a)(4)(i), and the financial statement schedule listed in the index appearing under Item 15(a)(4)(ii) (collectively referred to as the "financial statements"). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2024 and 2023, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2024 in conformity with accounting principles generally accepted in the United States of America.
 These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on the Company's financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
 We conducted our audits of these financial statements in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion.
 Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.
 The critical audit matter communicated below is a matter arising from the current period audit of the financial statements that was communicated or required to be communicated to the audit committee and that (i) relates to accounts or disclosures that are material to the financial statements and (ii) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.
 As described in Notes 1 and 3 to the financial statements, the Company applies the authoritative guidance for accounting for certain types of regulation, which requires management to record in the financial statements the effects of cost-based rate regulation for entities with regulated operations that meet the following criteria, (i) rates are established or approved by a third-party regulator; (ii) rates are designed to recover the entity's cost of providing services or products; and (iii) there is a reasonable expectation that rates designed to recover costs can be charged to and collected from customers. The Company accounts for its regulated operations in accordance with regulatory and legislative guidance from the regulatory authorities having jurisdiction under state public utility laws and the FERC under various Federal laws. Upon updates in material regulatory and legislative proceedings, where applicable, management will record new regulatory assets or liabilities and will assess whether it is probable that its currently recorded regulatory assets and liabilities will be recovered and settled,

 respectively, in future rates. As of December 31, 2024, there were $995 million of regulatory assets and $648 million of regulatory liabilities.
 The principal considerations for our determination that performing procedures relating to the Company's accounting for the effects of rate regulation is a critical audit matter are the high degree of audit effort to assess the impact of regulation on accounting for regulatory assets and liabilities and to evaluate the complex audit evidence related to whether the regulatory assets and liabilities will be recovered and settled.
 Addressing the matter involved performing procedures and evaluating audit evidence in connection with forming our overall opinion on the financial statements. These procedures included testing the effectiveness of controls relating to accounting for regulatory matters and evaluation of new and existing regulatory assets and liabilities. These procedures also included, among others, obtaining the Company's correspondence with regulators, evaluating the reasonableness of management's interpretation of regulatory guidance and proceedings and the related accounting implications, and recalculating regulatory assets and liabilities based on provisions outlined in rate orders and other correspondence with regulators.

 Baltimore, Maryland
 We have served as the Company's auditor since at least 1993. We have not been able to determine the specific year we began serving as auditor of the Company.

 To the Board of Directors and Member of Pepco Holdings LLC
 We have audited the consolidated financial statements, including the related notes, of Pepco Holdings LLC and its subsidiaries (the "Company") as listed in the index appearing under Item 15(a)(5)(i), and the financial statement schedule listed in the index appearing under Item 15(a)(5)(ii) (collectively referred to as the "consolidated financial statements"). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2024 and 2023, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2024 in conformity with accounting principles generally accepted in the United States of America.
 These consolidated financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on the Company's consolidated financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
 We conducted our audits of these consolidated financial statements in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion.
 Our audits included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. We believe that our audits provide a reasonable basis for our opinion.
 The critical audit matter communicated below is a matter arising from the current period audit of the consolidated financial statements that was communicated or required to be communicated to the audit committee and that (i) relates to accounts or disclosures that are material to the consolidated financial statements and (ii) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.
 As described in Notes 1 and 3 to the consolidated financial statements, the Company applies the authoritative guidance for accounting for certain types of regulation, which requires management to record in the consolidated financial statements the effects of cost-based rate regulation for entities with regulated operations that meet the following criteria, (i) rates are established or approved by a third-party regulator; (ii) rates are designed to recover the entity's cost of providing services or products; and (iii) there is a reasonable expectation that rates designed to recover costs can be charged to and collected from customers. The Company accounts for its regulated operations in accordance with regulatory and legislative guidance from the regulatory authorities having jurisdiction under state public utility laws and the FERC under various Federal laws. Upon updates in material regulatory and legislative proceedings, where applicable, management will record new regulatory assets or liabilities and will assess whether it is probable that its currently recorded regulatory assets and liabilities will be

 recovered and settled, respectively, in future rates. As of December 31, 2024, there were $1.89 billion of regulatory assets and $863 million of regulatory liabilities.
 The principal considerations for our determination that performing procedures relating to the Company's accounting for the effects of rate regulation is a critical audit matter are the high degree of audit effort to assess the impact of regulation on accounting for regulatory assets and liabilities and to evaluate the complex audit evidence related to whether the regulatory assets and liabilities will be recovered and settled.
 Addressing the matter involved performing procedures and evaluating audit evidence in connection with forming our overall opinion on the consolidated financial statements. These procedures included testing the effectiveness of controls relating to accounting for regulatory matters and evaluation of new and existing regulatory assets and liabilities. These procedures also included, among others, obtaining the Company's correspondence with regulators, evaluating the reasonableness of management's interpretation of regulatory guidance and proceedings and the related accounting implications, and recalculating regulatory assets and liabilities based on provisions outlined in rate orders and other correspondence with regulators.

 We have served as the Company's auditor since 2001.

 To the Board of Directors and Shareholder of Potomac Electric Power Company
 We have audited the financial statements, including the related notes, of Potomac Electric Power Company (the "Company") as listed in the index appearing under Item 15(a)(6)(i), and the financial statement schedule listed in the index appearing under Item 15(a)(6)(ii) (collectively referred to as the "financial statements"). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2024 and 2023, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2024 in conformity with accounting principles generally accepted in the United States of America.
 These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on the Company's financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
 We conducted our audits of these financial statements in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion.
 Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.
 The critical audit matter communicated below is a matter arising from the current period audit of the financial statements that was communicated or required to be communicated to the audit committee and that (i) relates to accounts or disclosures that are material to the financial statements and (ii) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.
 As described in Notes 1 and 3 to the financial statements, the Company applies the authoritative guidance for accounting for certain types of regulation, which requires management to record in the financial statements the effects of cost-based rate regulation for entities with regulated operations that meet the following criteria, (i) rates are established or approved by a third-party regulator; (ii) rates are designed to recover the entity's cost of providing services or products; and (iii) there is a reasonable expectation that rates designed to recover costs can be charged to and collected from customers. The Company accounts for its regulated operations in accordance with regulatory and legislative guidance from the regulatory authorities having jurisdiction under state public utility laws and the FERC under various Federal laws. Upon updates in material regulatory and legislative proceedings, where applicable, management will record new regulatory assets or liabilities and will assess whether it is probable that its currently recorded regulatory assets and liabilities will be recovered and settled,

 respectively, in future rates. As of December 31, 2024, there were $603 million of regulatory assets and $327 million of regulatory liabilities.
 The principal considerations for our determination that performing procedures relating to the Company's accounting for the effects of rate regulation is a critical audit matter are the high degree of audit effort to assess the impact of regulation on accounting for regulatory assets and liabilities and to evaluate the complex audit evidence related to whether the regulatory assets and liabilities will be recovered and settled.
 Addressing the matter involved performing procedures and evaluating audit evidence in connection with forming our overall opinion on the financial statements. These procedures included testing the effectiveness of controls relating to accounting for regulatory matters and evaluation of new and existing regulatory assets and liabilities. These procedures also included, among others, obtaining the Company's correspondence with regulators, evaluating the reasonableness of management's interpretation of regulatory guidance and proceedings and the related accounting implications, and recalculating regulatory assets and liabilities based on provisions outlined in rate orders and other correspondence with regulators.

 We have served as the Company's auditor since at least 1993. We have not been able to determine the specific year we began serving as auditor of the Company.

 To the Board of Directors and Shareholder of Delmarva Power & Light Company
 We have audited the financial statements, including the related notes, of Delmarva Power & Light Company (the "Company") as listed in the index appearing under Item 15(a)(7)(i), and the financial statement schedule listed in the index appearing under Item 15(a)(7)(ii) (collectively referred to as the "financial statements"). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2024 and 2023, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2024 in conformity with accounting principles generally accepted in the United States of America.
 These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on the Company's financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
 We conducted our audits of these financial statements in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion.
 Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.
 The critical audit matter communicated below is a matter arising from the current period audit of the financial statements that was communicated or required to be communicated to the audit committee and that (i) relates to accounts or disclosures that are material to the financial statements and (ii) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.
 As described in Notes 1 and 3 to the financial statements, the Company applies the authoritative guidance for accounting for certain types of regulation, which requires management to record in the financial statements the effects of cost-based rate regulation for entities with regulated operations that meet the following criteria, (i) rates are established or approved by a third-party regulator; (ii) rates are designed to recover the entity's cost of providing services or products; and (iii) there is a reasonable expectation that rates designed to recover costs can be charged to and collected from customers. The Company accounts for its regulated operations in accordance with regulatory and legislative guidance from the regulatory authorities having jurisdiction under state public utility laws and the FERC under various Federal laws. Upon updates in material regulatory and legislative proceedings, where applicable, management will record new regulatory assets or liabilities and will assess whether it is probable that its currently recorded regulatory assets and liabilities will be recovered and settled,

 respectively, in future rates. As of December 31, 2024, there were $275 million of regulatory assets and $367 million of regulatory liabilities.
 The principal considerations for our determination that performing procedures relating to the Company's accounting for the effects of rate regulation is a critical audit matter are the high degree of audit effort to assess the impact of regulation on accounting for regulatory assets and liabilities and to evaluate the complex audit evidence related to whether the regulatory assets and liabilities will be recovered and settled.
 Addressing the matter involved performing procedures and evaluating audit evidence in connection with forming our overall opinion on the financial statements. These procedures included testing the effectiveness of controls relating to accounting for regulatory matters and evaluation of new and existing regulatory assets and liabilities. These procedures also included, among others, obtaining the Company's correspondence with regulators, evaluating the reasonableness of management's interpretation of regulatory guidance and proceedings and the related accounting implications, and recalculating regulatory assets and liabilities based on provisions outlined in rate orders and other correspondence with regulators.

 We have served as the Company's auditor since at least 1993. We have not been able to determine the specific year we began serving as auditor of the Company.

 To the Board of Directors and Shareholder of Atlantic City Electric Company
 We have audited the consolidated financial statements, including the related notes, of Atlantic City Electric Company and its subsidiary (the "Company") as listed in the index appearing under Item 15(a)(8)(i), and the financial statement schedule listed in the index appearing under Item 15(a)(8)(ii) (collectively referred to as the "consolidated financial statements"). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2024 and 2023, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2024 in conformity with accounting principles generally accepted in the United States of America.
 These consolidated financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on the Company's consolidated financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
 We conducted our audits of these consolidated financial statements in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion.
 Our audits included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. We believe that our audits provide a reasonable basis for our opinion.
 The critical audit matter communicated below is a matter arising from the current period audit of the consolidated financial statements that was communicated or required to be communicated to the audit committee and that (i) relates to accounts or disclosures that are material to the consolidated financial statements and (ii) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.
 As described in Notes 1 and 3 to the consolidated financial statements, the Company applies the authoritative guidance for accounting for certain types of regulation, which requires management to record in the consolidated financial statements the effects of cost-based rate regulation for entities with regulated operations that meet the following criteria, (i) rates are established or approved by a third-party regulator; (ii) rates are designed to recover the entity's cost of providing services or products; and (iii) there is a reasonable expectation that rates designed to recover costs can be charged to and collected from customers. The Company accounts for its regulated operations in accordance with regulatory and legislative guidance from the regulatory authorities having jurisdiction under state public utility laws and the FERC under various Federal laws. Upon updates in material regulatory and legislative proceedings, where applicable, management will record new regulatory assets or liabilities and will assess whether it is probable that its currently recorded regulatory assets and liabilities will be

 recovered and settled, respectively, in future rates. As of December 31, 2024, there were $603 million of regulatory assets and $156 million of regulatory liabilities.
 The principal considerations for our determination that performing procedures relating to the Company's accounting for the effects of rate regulation is a critical audit matter are the high degree of audit effort to assess the impact of regulation on accounting for regulatory assets and liabilities and to evaluate the complex audit evidence related to whether the regulatory assets and liabilities will be recovered and settled.
 Addressing the matter involved performing procedures and evaluating audit evidence in connection with forming our overall opinion on the consolidated financial statements. These procedures included testing the effectiveness of controls relating to accounting for regulatory matters and evaluation of new and existing regulatory assets and liabilities. These procedures also included, among others, obtaining the Company's correspondence with regulators, evaluating the reasonableness of management's interpretation of regulatory guidance and proceedings and the related accounting implications, and recalculating regulatory assets and liabilities based on provisions outlined in rate orders and other correspondence with regulators.

 We have served as the Company's auditor since 1998.

 (In millions, except per share data)
 2024
 2023
 2022

 $
 21,338
 $
 19,267
 $
 16,899

 1,782
 1,764
 2,018

 ( 92)

 23,028
 21,727
 19,078

 8,214
 7,648
 5,380

 Purchased power and fuel from affiliates
 —
 —

 4,940
 4,559
 4,673

 3,594
 3,506
 3,325

 1,504
 1,408
 1,390

 18,721
 17,714
 15,761

 Gain (loss) on sale of assets and businesses
 ( 2)

 4,319
 4,023
 3,315

 ( 1,889)
 ( 1,704)
 ( 1,422)

 Interest expense to affiliates
 ( 25)
 ( 25)
 ( 25)

 ( 1,652)
 ( 1,321)
 ( 912)

 Income from continuing operations before income taxes
 2,667
 2,702
 2,403

 Net income from continuing operations after income taxes
 2,460
 2,328
 2,054

 Net income from discontinued operations after income taxes (Note 2)
 —
 —

 2,460
 2,328
 2,171

 Net income attributable to noncontrolling interests
 —
 —

 Net income attributable to common shareholders
 $
 2,460
 $
 2,328
 $
 2,170

 Amounts attributable to common shareholders:

 Net income from continuing operations
 2,460
 2,328
 2,054

 Net income from discontinued operations
 —
 —

 Net income attributable to common shareholders
 $
 2,460
 $
 2,328
 $
 2,170

 Comprehensive income, net of income taxes

 $
 2,460
 $
 2,328
 $
 2,171

 Other comprehensive income (loss), net of income taxes

 Pension and non-pension postretirement benefit plans:

 Prior service benefits reclassified to periodic benefit cost
 —
 —
 ( 1)

 Actuarial losses reclassified to periodic benefit cost

 Pension and non-pension postretirement benefit plans valuation adjustments
 ( 70)

 Unrealized gain (loss) on cash flow hedges
 ( 5)

 Other comprehensive income (loss)
 ( 88)

 2,466
 2,240
 2,260

 Comprehensive income attributable to noncontrolling interests
 —
 —

 Comprehensive income attributable to common shareholders
 $
 2,466
 $
 2,240
 $
 2,259

 Average shares of common stock outstanding:

 Basic
 1,003

 Assumed exercise and/or distributions of stock-based awards
 —

 Diluted
 1,003

 Earnings per average common share from continuing operations

 Basic
 $
 2.45
 $
 2.34
 $
 2.08

 Diluted
 $
 2.45
 $
 2.34
 $
 2.08

 Earnings per average common share from discontinued operations

 Basic
 $
 —
 $
 —
 $
 0.12

 Diluted
 $
 —
 $
 —
 $
 0.12

 2024
 2023
 2022

 $
 2,460
 $
 2,328
 $
 2,171

 Adjustments to reconcile net income to net cash flows provided by operating activities:

 Depreciation, amortization, and accretion, including nuclear fuel and energy contract amortization
 3,596
 3,506
 3,533

 Asset impairments
 —
 —

 Gain on sales of assets and businesses
 ( 12)
 ( 10)
 ( 8)

 Net fair value changes related to derivatives
 —
 ( 53)

 Net realized and unrealized losses (gains) on NDT funds
 —
 —

 Net unrealized losses on equity investments
 —
 —

 ( 335)

 ( 644)
 ( 37)
 ( 1,222)

 ( 56)
 ( 45)
 ( 121)

 ( 37)
 ( 191)
 1,318

 Option premiums paid, net
 —
 —
 ( 39)

 Collateral received (paid), net
 ( 146)
 1,248

 ( 4)
 ( 4)

 ( 50)
 ( 439)
 ( 1,326)

 ( 180)
 ( 129)
 ( 616)

 ( 257)
 ( 188)
 ( 905)

 5,569
 4,703
 4,870

 ( 7,097)
 ( 7,408)
 ( 7,147)

 Proceeds from NDT fund sales
 —
 —

 Investment in NDT funds
 —
 —
 ( 516)

 Collection of DPP
 —
 —

 Proceeds from sales of assets and businesses

 —

 ( 7,042)
 ( 7,375)
 ( 6,990)

 ( 265)
 ( 313)

 Proceeds from short-term borrowings with maturities greater than 90 days
 1,300

 Repayments on short-term borrowings with maturities greater than 90 days
 ( 549)
 ( 1,500)

 4,974
 5,825
 6,309

 ( 1,557)
 ( 1,713)
 ( 2,073)

 ( 1,524)
 ( 1,433)
 ( 1,334)

 Proceeds from employee stock plans

 Transfer of cash, restricted cash, and cash equivalents to Constellation
 —
 —
 ( 2,594)

 ( 114)
 ( 102)

 1,311
 2,683
 1,591

 ( 162)
 ( 529)

 1,101
 1,090
 1,619

 $
 $
 1,101
 $
 1,090

 $
 $
 ( 215)
 $

 Increase in DPP
 —
 —

 Increase (decrease) in PP&E related to ARO update
 ( 13)

 2024
 2023

 $
 $

 3,144
 2,659

 ( 406)
 ( 317)

 2,738
 2,342

 1,123
 1,101

 ( 107)
 ( 82)

 1,016
 1,019

 1,940
 2,215

 Other

 8,384
 8,087

 Property, plant, and equipment (net of accumulated depreciation and amortization of $ 18,445 and $ 17,251 as of December 31, 2024 and 2023, respectively)

 78,182
 73,593

 8,710
 8,698

 Goodwill
 6,630
 6,630

 Receivable related to Regulatory Agreement Units
 4,026
 3,232

 Other
 1,562
 1,365

 21,218
 20,176

 $
 107,784
 $
 101,856

 2024
 2023

 LIABILITIES AND SHAREHOLDERS' EQUITY

 $
 1,859
 $
 2,523

 1,453
 1,403

 2,994
 2,846

 1,468
 1,375

 Mark-to-market derivative liabilities

 Unamortized energy contract liabilities

 Other

 9,611
 9,901

 42,947
 39,692

 Long-term debt to financing trusts

 12,793
 11,956

 10,198
 9,576

 Pension obligations
 1,745
 1,571

 Mark-to-market derivative liabilities

 Unamortized energy contract liabilities

 Other
 2,282
 2,088

 27,915
 26,118

 80,863
 76,101

 Shareholders' equity

 Common stock ( No par value, 2,000 shares authorized, 1,005 shares and 999 shares outstanding as of December 31, 2024 and 2023, respectively)

 21,338
 21,114

 Treasury stock, at cost ( 2 shares as of December 31, 2024 and 2023)

 6,426
 5,490

 Accumulated other comprehensive loss, net
 ( 720)
 ( 726)

 Total shareholders' equity
 26,921
 25,755

 Total liabilities and shareholders' equity
 $
 107,784
 $
 101,856

 Consolidated Statements of Changes in Equity

 (In millions, shares in thousands)
 Issued
Shares
 Common
Stock
 Treasury
Stock
 Retained
Earnings
 Accumulated
Other
Comprehensive
Loss, net
 Noncontrolling
Interests
 Total Equity

 981,291
 $
 20,324
 $
 $
 16,942
 $
 ( 2,750)
 $
 $
 34,795

 —
 —
 —
 2,170
 —
 2,171

 Long-term incentive plan activity
 —
 —
 —
 —

 Employee stock purchase plan issuances
 —
 —
 —
 —

 Changes in equity of noncontrolling interests
 —
 —
 —
 —
 —
 ( 7)
 ( 7)

 Distribution of Constellation (Note 2)
 —
 ( 21)
 —
 ( 13,179)
 2,023
 ( 396)
 ( 11,573)

 12,995
 —
 —
 —
 —

 ($ 1.35 /common share)

 —
 —
 —
 ( 1,336)
 —
 —
 ( 1,336)

 Other comprehensive income, net of income taxes
 —
 —
 —
 —
 —

 995,830
 $
 20,908
 $
 $
 4,597
 $
 ( 638)
 $
 —
 $
 24,744

 —
 —
 —
 2,328
 —
 —
 2,328

 Long-term incentive plan activity
 —
 —
 —
 —

 Employee stock purchase plan issuances
 1,173
 —
 —
 —
 —

 3,587
 —
 —
 —
 —

 ($ 1.44 /common share)

 —
 —
 —
 ( 1,435)
 —
 —
 ( 1,435)

 Other comprehensive loss, net of income taxes
 —
 —
 —
 —
 ( 88)
 —
 ( 88)

 1,001,249
 $
 21,114
 $
 $
 5,490
 $
 ( 726)
 $
 —
 $
 25,755

 —
 —
 —
 2,460
 —
 —
 2,460

 Long-term incentive plan activity
 —
 —
 —
 —

 Employee stock purchase plan issuances
 1,344
 —
 —
 —
 —

 3,989
 —
 —
 —
 —

 ($ 1.52 /common share)

 —
 —
 —
 ( 1,524)
 —
 —
 ( 1,524)

 Other comprehensive income, net of income taxes
 —
 —
 —
 —
 —

 1,007,046
 $
 21,338
 $
 $
 6,426
 $
 ( 720)
 —
 $
 26,921

 2024
 2023
 2022

 $
 8,362
 $
 7,272
 $
 5,478

 ( 151)

 8,219
 7,844
 5,761

 3,042
 2,816
 1,050

 Purchased power from affiliates
 —
 —

 1,284
 1,096
 1,094

 1,514
 1,403
 1,323

 6,635
 6,038
 4,218

 Gain (loss) on sale of assets
 —
 ( 2)

 1,589
 1,806
 1,541

 ( 487)
 ( 464)
 ( 401)

 Interest expense to affiliates, net
 ( 14)
 ( 13)
 ( 13)

 ( 407)
 ( 402)
 ( 360)

 1,182
 1,404
 1,181

 $
 1,066
 $
 1,090
 $

 $
 1,066
 $
 1,090
 $

 2024
 2023
 2022

 $
 1,066
 $
 1,090
 $

 Adjustments to reconcile net income to net cash flows provided by operating activities:

 1,514
 1,403
 1,323

 Gain on sales of assets
 ( 5)
 —
 —

 ( 19)

 ( 536)
 ( 165)

 ( 185)
 ( 138)
 ( 163)

 ( 2)
 ( 34)

 ( 15)
 ( 82)
 ( 28)

 ( 115)
 ( 87)

 Collateral received, net

 ( 114)
 —

 ( 60)
 ( 1,033)

 ( 25)
 ( 41)
 ( 184)

 ( 70)
 ( 134)

 2,713
 1,848
 1,197

 ( 2,195)
 ( 2,576)
 ( 2,506)

 ( 2,188)
 ( 2,568)
 ( 2,478)

 ( 166)
 ( 225)

 Proceeds from short-term borrowings with maturities greater than 90 days
 —

 Repayments on short-term borrowings with maturities greater than 90 days
 —

 ( 250)
 —
 —

 ( 776)
 ( 746)
 ( 578)

 ( 14)
 ( 14)
 ( 11)

 Net cash flows (used in) provided by financing activities
 ( 579)
 1,408

 ( 54)

 $
 $
 $

 Decrease in capital expenditures not paid
 $
 ( 17)
 $
 ( 10)
 $
 ( 20)

 2024
 2023

 $
 $

 ( 69)

 ( 34)
 ( 17)

 1,159
 1,335

 Other

 3,328
 3,268

 Property, plant, and equipment (net of accumulated depreciation and amortization of $ 7,619 and $ 7,222 as of December 31, 2024 and 2023, respectively)

 30,211
 29,088

 2,562
 2,794

 Goodwill
 2,625
 2,625

 Receivable related to Regulatory Agreement Units
 3,780
 2,954

 1,165
 1,217

 Other
 1,073

 11,211
 10,471

 $
 44,750
 $
 42,827

 2024
 2023

 LIABILITIES AND SHAREHOLDERS' EQUITY

 $
 $

 —

 Mark-to-market derivative liabilities

 Other

 1,954
 2,922

 12,030
 11,236

 Long-term debt to financing trust

 5,601
 5,327

 8,421
 7,493

 Mark-to-market derivative liabilities

 Other
 1,232

 15,680
 14,101

 29,870
 28,464

 Shareholders' equity

 Common stock ($ 12.50 par value, 250 shares authorized, 127 shares outstanding as of December 31, 2024 and 2023)

 1,588
 1,588

 Other paid-in capital
 10,628
 10,401

 2,664
 2,374

 Total shareholders' equity
 14,880
 14,363

 Total liabilities and shareholders' equity
 $
 44,750
 $
 42,827

 Consolidated Statements of Changes in Shareholders' Equity

 Common
Stock
 Other
Paid-In
Capital
 Retained
Earnings
 Total
Shareholders'
Equity

 $
 1,588
 $
 9,076
 $
 1,691
 $
 12,355

 —
 —

 —
 —
 ( 578)
 ( 578)

 —
 —

 $
 1,588
 $
 9,746
 $
 2,030
 $
 13,364

 —
 —
 1,090
 1,090

 —
 —
 ( 746)
 ( 746)

 —
 —

 $
 1,588
 $
 10,401
 $
 2,374
 $
 14,363

 —
 —
 1,066
 1,066

 —
 —
 ( 776)
 ( 776)

 —
 —

 $
 1,588
 $
 10,628
 $
 2,664
 $
 14,880

 2024
 2023
 2022

 $
 3,312
 $
 3,202
 $
 3,156

 ( 7)

 3,973
 3,894
 3,903

 1,265
 1,270
 1,160

 Purchased power from affiliates
 —
 —

 3,243
 3,146
 3,102

 Gain on sale of assets
 —
 —

 ( 221)
 ( 192)
 ( 165)

 Interest expense to affiliates, net
 ( 11)
 ( 9)
 ( 12)

 ( 195)
 ( 165)
 ( 146)

 ( 12)

 $
 $
 $

 $
 $
 $

 2024
 2023
 2022

 $
 $
 $

 Adjustments to reconcile net income to net cash flows provided by
operating activities:

 Gain on sale of assets
 ( 4)
 —
 —

 Deferred income taxes and amortization of investment tax
credits
 ( 63)
 ( 43)

 ( 210)
 ( 205)

 ( 1)
 ( 31)

 ( 56)

 ( 78)

 ( 76)
 ( 20)

 ( 31)
 ( 45)

 ( 4)
 ( 1)
 ( 18)

 1,019

 ( 1,553)
 ( 1,426)
 ( 1,349)

 ( 1,547)
 ( 1,424)
 ( 1,341)

 Change in short-term borrowings
 ( 74)

 —
 ( 50)
 ( 350)

 ( 399)

 ( 7)
 ( 6)
 ( 15)

 ( 3)
 ( 17)

 $
 $
 $

 $
 $
 ( 56)
 $

 2024
 2023

 $
 $

 —

 ( 95)

 ( 18)
 ( 8)

 —

 Other

 Property, plant, and equipment (net of accumulated depreciation and amortization of $ 4,042 and $ 4,097 as of December 31, 2024 and 2023, respectively)

 14,392
 13,128

 1,003

 Receivable related to Regulatory Agreement Units

 Other

 1,758
 1,564

 $
 17,123
 $
 15,595

 2024
 2023

 $
 $

 —

 Other

 1,670
 1,182

 5,354
 5,134

 Long-term debt to financing trusts

 2,433
 2,321

 Other

 3,100
 3,026

 10,308
 9,526

 Common stock ( No par value, 500 shares authorized, 170 shares outstanding as of December 31, 2024 and 2023)

 4,645
 4,050

 2,170
 2,019

 6,815
 6,069

 $
 17,123
 $
 15,595

 Consolidated Statements of Changes in Shareholder's Equity

 Common
Stock
 Retained
Earnings
 Total
Shareholder's
Equity

 $
 3,428
 $
 1,684
 $
 5,112

 —

 —
 ( 399)
 ( 399)

 —

 $
 3,702
 $
 1,861
 $
 5,563

 —

 —

 —

 $
 4,050
 $
 2,019
 $
 6,069

 —

 —

 —

 $
 4,645
 $
 2,170
 $
 6,815

 2024
 2023
 2022

 $
 3,407
 $
 3,065
 $
 2,890

 1,037

 ( 47)

 4,426
 4,027
 3,895

 1,460
 1,311
 1,186

 Purchased power and fuel from affiliates
 —
 —

 3,670
 3,245
 3,376

 ( 216)
 ( 182)
 ( 152)

 ( 180)
 ( 164)
 ( 131)

 $
 $
 $

 $
 $
 $

 2024
 2023
 2022

 $
 $
 $

 Adjustments to reconcile net income to net cash flows provided by operating activities:

 Asset impairments
 —
 —

 ( 1)

 ( 142)
 ( 197)

 ( 5)
 ( 2)

 ( 5)
 ( 61)

 ( 75)

 Collateral (paid) received, net
 ( 1)
 ( 22)

 ( 54)
 ( 17)

 ( 84)
 ( 292)
 ( 160)

 ( 37)
 ( 19)
 ( 68)

 ( 39)
 ( 13)
 ( 33)

 ( 1,420)
 ( 1,367)
 ( 1,262)

 ( 1,408)
 ( 1,360)
 ( 1,251)

 ( 161)
 ( 72)

 —
 ( 300)
 ( 250)

 ( 368)
 ( 316)
 ( 300)

 ( 9)
 ( 7)
 ( 11)

 ( 14)
 ( 19)

 $
 $
 $

 $
 $
 ( 44)
 $

 2024
 2023

 $
 $

 ( 56)
 ( 46)

 ( 6)
 ( 7)

 Prepaid utility taxes

 Other

 1,348
 1,194

 Property, plant, and equipment (net of accumulated depreciation and amortization of $ 5,005 and $ 4,744 as of December 31, 2024 and 2023, respectively)

 13,134
 12,102

 Other

 1,060
 1,035

 $
 15,542
 $
 14,331

 2024
 2023

 $
 $

 Other

 1,243
 1,240

 5,395
 4,602

 2,099
 1,945

 Other

 3,018
 2,999

 9,656
 8,841

 Common stock ( No par value, 0 shares(a) authorized, 0 shares(a) outstanding as of December 31, 2024 and 2023)

 3,483
 3,246

 2,403
 2,244

 5,886
 5,490

 $
 15,542
 $
 14,331

 _____________
 (a) In millions, shares round to zero. Number of shares is 1,500 authorized and 1,000 outstanding as of December 31, 2024 and 2023.

 Common
Stock
 Retained
Earnings
 Total
Shareholder's
Equity

 $
 2,575
 $
 1,995
 $
 4,570

 —

 —
 ( 300)
 ( 300)

 —

 $
 2,861
 $
 2,075
 $
 4,936

 —

 —
 ( 316)
 ( 316)

 —

 $
 3,246
 $
 2,244
 $
 5,490

 —

 —
 ( 368)
 ( 368)

 —

 $
 3,483
 $
 2,403
 $
 5,886

 2024
 2023
 2022

 $
 6,257
 $
 5,748
 $
 5,376

 ( 59)

 6,448
 6,026
 5,565

 2,447
 2,250
 1,984

 Purchased power from affiliates
 —
 —

 1,046
 1,110

 5,238
 5,114
 4,734

 (Loss) gain on sales of assets
 ( 1)
 —

 1,209

 ( 373)
 ( 323)
 ( 292)

 Interest expense to affiliates, net
 ( 3)
 —
 —

 ( 279)
 ( 215)
 ( 214)

 $
 $
 $

 $
 $
 $

 2024
 2023
 2022

 $
 $
 $

 Adjustments to reconcile net income to net cash flows used in operating activities:

 Loss (gain) on sales of assets
 ( 9)
 —

 ( 9)

 ( 110)
 ( 79)
 ( 184)

 ( 8)
 ( 46)

 ( 37)
 ( 42)
 ( 34)

 Collateral (paid) received, net
 —
 ( 196)

 ( 33)
 ( 1)

 ( 223)
 ( 61)
 ( 136)

 ( 86)
 ( 24)
 ( 78)

 ( 119)
 ( 101)
 ( 149)

 1,410
 1,304
 1,250

 ( 1,863)
 ( 1,988)
 ( 1,709)

 Proceeds from sales of long-lived assets
 —
 —

 —

 ( 1,863)
 ( 1,970)
 ( 1,703)

 ( 20)
 ( 54)

 1,100
 1,075

 ( 583)
 ( 500)
 ( 310)

 Change in Exelon intercompany money pool
 ( 2)

 Distributions to member
 ( 706)
 ( 513)
 ( 750)

 Contributions from member

 ( 38)
 ( 41)
 ( 22)

 ( 41)
 ( 169)

 $
 $
 $

 $
 $
 $

 2024
 2023

 $
 $

 ( 108)
 ( 107)

 ( 49)
 ( 50)

 Receivable from affiliates

 Prepaid utility taxes

 Other

 2,080
 2,001

 Property, plant, and equipment (net of accumulated depreciation and amortization of $ 3,728 and $ 3,175 as of December 31, 2024 and 2023, respectively)

 20,053
 18,851

 1,570
 1,587

 Goodwill
 4,005
 4,005

 Other

 6,164
 6,214

 $
 28,297
 $
 27,066

 2024
 2023

 LIABILITIES AND EQUITY

 $
 $

 Borrowings from Exelon intercompany money pool

 Unamortized energy contract liabilities

 PPA Termination Obligation
 —

 Other

 2,565
 2,712

 8,834
 8,004

 3,190
 3,031

 Unamortized energy contract liabilities

 Other

 4,576
 4,568

 15,975
 15,284

 Member's equity

 Membership interest
 12,562
 12,057

 Undistributed losses
 ( 240)
 ( 275)

 Total member's equity
 12,322
 11,782

 Total liabilities and member's equity
 $
 28,297
 $
 27,066

 Consolidated Statements of Changes in Equity

 Membership Interest
 Undistributed (Losses)/Gains
 Total
Member's Equity

 $
 10,795
 $
 ( 210)
 $
 10,585

 —

 Distribution to member
 —
 ( 750)
 ( 750)

 Contributions from member
 —

 $
 11,582
 $
 ( 352)
 $
 11,230

 Net Income
 —

 Distribution to member
 —
 ( 513)
 ( 513)

 Contributions from member
 —

 $
 12,057
 $
 ( 275)
 $
 11,782

 —

 Distribution to member
 —
 ( 706)
 ( 706)

 Contributions from member
 —

 $
 12,562
 $
 ( 240)
 $
 12,322

 2024
 2023
 2022

 $
 3,017
 $
 2,793
 $
 2,557

 ( 31)

 3,039
 2,824
 2,531

 1,055

 Purchased power from affiliate
 —
 —

 2,420
 2,377
 2,140

 (Loss) gain on sales of assets
 ( 1)
 —

 ( 195)
 ( 165)

 Interest income from affiliates, net
 —
 —

 ( 138)
 ( 99)
 ( 95)

 ( 9)

 $
 $
 $

 $
 $
 $

 2024
 2023
 2022

 $
 $
 $

 Adjustments to reconcile net income to net cash flows provided by operating activities:

 Loss (gain) on sales of assets
 ( 9)
 —

 ( 15)
 ( 17)

 ( 26)
 ( 29)
 ( 104)

 ( 3)
 ( 33)

 ( 10)
 ( 24)
 ( 16)

 Collateral (paid) received, net
 —
 ( 25)

 ( 30)
 ( 19)

 ( 85)
 ( 45)
 ( 69)

 ( 9)
 ( 12)
 ( 11)

 ( 84)
 ( 5)
 ( 66)

 ( 929)
 ( 957)
 ( 874)

 Proceeds from sale of long-lived assets
 —
 —

 —

 ( 929)
 ( 939)
 ( 871)

 ( 167)

 —
 ( 310)

 ( 359)
 ( 252)
 ( 463)

 ( 20)
 ( 26)
 ( 10)

 ( 21)
 ( 27)

 $
 $
 $

 $
 $
 ( 55)
 $

 2024
 2023

 $
 $

 ( 59)
 ( 52)

 ( 27)
 ( 28)

 Other

 1,049
 1,025

 Property, plant, and equipment (net of accumulated depreciation and amortization of $ 4,522 and $ 4,284 as of December 31, 2024 and 2023, respectively)

 10,097
 9,430

 Other

 $
 12,000
 $
 11,330

 2024
 2023

 $
 $

 Merger related obligation

 Other

 1,118
 1,365

 4,356
 3,691

 1,509
 1,431

 Other

 2,091
 2,130

 7,565
 7,186

 Common stock ($ 0.01 par value, 200 shares authorized, 0 shares(a) outstanding as of December 31, 2024 and 2023)

 3,335
 3,075

 1,100
 1,069

 4,435
 4,144

 $
 12,000
 $
 11,330

 _____________
 (a) In millions, shares round to zero. Number of shares is 100 outstanding as of December 31, 2024 and 2023.

 Common Stock
 Retained Earnings
 Total Shareholder's Equity

 $
 2,302
 $
 1,173
 $
 3,475

 —

 —
 ( 463)
 ( 463)

 —

 $
 2,767
 $
 1,015
 $
 3,782

 —

 —
 ( 252)
 ( 252)

 —

 $
 3,075
 $
 1,069
 $
 4,144

 —

 —
 ( 359)
 ( 359)

 —

 $
 3,335
 $
 1,100
 $
 4,435

 2024
 2023
 2022

 $
 1,602
 $
 1,460
 $
 1,360

 ( 2)
 ( 9)

 1,787
 1,688
 1,595

 Purchased power from affiliates
 —
 —

 1,461
 1,420
 1,359

 ( 94)
 ( 74)
 ( 66)

 Interest income from affiliates, net
 —
 —

 ( 68)
 ( 56)
 ( 53)

 $
 $
 $

 $
 $
 $

 2024
 2023
 2022

 $
 $
 $

 Adjustments to reconcile net income to net cash flows provided by operating activities:

 ( 46)
 ( 59)

 ( 10)

 ( 20)
 ( 5)
 ( 11)

 ( 7)

 Collateral received (paid), net
 ( 121)

 ( 24)
 —

 ( 51)
 ( 34)

 ( 3)
 ( 4)
 ( 1)

 ( 10)

 ( 556)
 ( 562)
 ( 430)

 —
 —

 ( 556)
 ( 562)
 ( 427)

 ( 52)
 ( 34)

 ( 33)
 ( 500)
 —

 ( 220)
 ( 143)

 ( 8)
 ( 11)
 ( 5)

 Increase (decrease) in cash, restricted cash, and cash equivalents
 ( 136)

 $
 $
 $

 $
 $
 ( 6)
 $

 2024
 2023

 $
 $

 —

 ( 17)
 ( 19)

 ( 9)
 ( 8)

 —

 Prepaid utility taxes

 Other

 Property, plant, and equipment, (net of accumulated depreciation and amortization of $ 2,075 and $ 1,925 as of December 31, 2024 and 2023, respectively)

 5,540
 5,165

 Other

 $
 6,421
 $
 5,993

 2024
 2023

 $
 $

 Other

 2,090
 1,996

 Other

 1,401
 1,380

 4,179
 3,900

 Common stock ($ 2.25 par value, 0 shares(a) authorized, 0 shares(a) outstanding as of December 31, 2024 and 2023, respectively)

 1,615
 1,455

 2,242
 2,093

 $
 6,421
 $
 5,993

 _____________
 (a) In millions, shares round to zero. Number of shares is 1,000 authorized and outstanding as of December 31, 2024 and 2023.

 Common Stock
 Retained Earnings
 Total Shareholder's Equity

 $
 1,209
 $
 $
 1,777

 —

 —
 ( 143)
 ( 143)

 —

 $
 1,356
 $
 $
 1,950

 —

 —

 —

 $
 1,455
 $
 $
 2,093

 —

 —
 ( 220)
 ( 220)

 —

 $
 1,615
 $
 $
 2,242

 2024
 2023
 2022

 $
 1,638
 $
 1,493
 $
 1,448

 ( 12)
 ( 19)

 1,628
 1,522
 1,431

 Purchased power from affiliate
 —
 —

 1,353
 1,314
 1,225

 ( 74)
 ( 72)
 ( 66)

 Interest expense to affiliates, net
 ( 5)
 —
 —

 ( 65)
 ( 52)
 ( 55)

 $
 $
 $

 $
 $
 $

 2024
 2023
 2022

 $
 $
 $

 Adjustments to reconcile net income to net cash flows provided by operating activities:

 ( 2)

 —

 ( 35)
 ( 57)
 ( 19)

 ( 8)
 ( 4)
 ( 4)

 ( 8)
 ( 12)
 ( 7)

 ( 18)
 ( 9)

 Collateral (paid) received, net
 —
 ( 50)

 ( 5)
 —

 ( 88)
 ( 47)
 ( 19)

 ( 9)
 ( 3)
 ( 7)

 ( 44)
 ( 83)
 ( 61)

 ( 373)
 ( 460)
 ( 398)

 —
 —

 ( 373)
 ( 460)
 ( 397)

 ( 13)
 ( 144)

 —
 —

 ( 127)
 ( 126)
 ( 145)

 ( 6)
 ( 5)
 ( 5)

 ( 7)
 ( 51)

 $
 $
 $

 $
 $
 ( 47)
 $

 2024
 2023

 $
 $

 ( 32)
 ( 36)

 ( 13)
 ( 14)

 Other

 Property, plant, and equipment, (net of accumulated depreciation and amortization of $ 1,798 and $ 1,684 as of December 31, 2024 and 2023, respectively)

 4,366
 4,192

 Other

 $
 5,349
 $
 5,157

 2024
 2023

 $
 $

 PPA termination obligation
 —

 Other

 1,779
 1,679

 —

 Other

 1,024

 3,424
 3,345

 Common stock ($ 3.00 par value, 25 shares authorized, 9 shares outstanding as of December 31, 2024 and 2023)

 1,915
 1,830

 Retained earnings (deficit)
 ( 18)

 1,925
 1,812

 $
 5,349
 $
 5,157

 Consolidated Statements of Changes in Shareholder's Equity

 Common Stock
 Retained Earnings (Deficit)
 Total Shareholder's Equity

 $
 1,590
 $
 ( 15)
 $
 1,575

 —

 —
 ( 145)
 ( 145)

 —

 $
 1,765
 $
 ( 12)
 $
 1,753

 —

 —
 ( 126)
 ( 126)

 —

 $
 1,830
 $
 ( 18)
 $
 1,812

 —

 —
 ( 127)
 ( 127)

 —

 $
 1,915
 $
 $
 1,925

 1. Significant Accounting Policies (All Registrants)
 Description of Business (All Registrants)
 Exelon is a utility services holding company engaged in the energy transmission and distribution businesses through ComEd, PECO, BGE, Pepco, DPL, and ACE.
 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 for additional information.

 Name of Registrant

 Business

 Service Territories

 Northern Illinois, including the City of Chicago

 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)

 Central Maryland, including the City of Baltimore (electricity and natural gas)

 Transmission and distribution of electricity and distribution of natural gas to retail customers

 Utility services holding company engaged, through its reportable segments Pepco, DPL, and ACE
 Service Territories of Pepco, DPL, and ACE

 District of Columbia, and major portions of Montgomery and Prince George's Counties, Maryland.

 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)

 Portions of Southern New Jersey

 Revision of Previously Issued Financial Statements (Exelon, BGE, PHI, Pepco, and DPL)
 In the fourth quarter of 2024, management identified an error related to the recording of Renewable energy credit obligations in Maryland and Washington D.C., and the corresponding Prepaid renewable energy credits, which were incorrectly netted on the balance sheet rather than reflected on a gross basis. As a result of this error, the Prepaid renewable energy credits and the Renewable energy credit obligations were understated on the Consolidated Balance Sheets of Exelon, BGE, PHI, Pepco, and DPL as of December 31, 2023, by $ 310 million, $ 147 million, $ 163 million, $ 136 million, and $ 27 million, respectively. There was no impact on the Consolidated Statements of Operations and Comprehensive Income, the Consolidated Statements of Cash Flows, or the Consolidated Statements of Changes in Equity for any of the Registrants for the years ended December 31, 2023, or December 31, 2022.
 Management has concluded that the error was not material to previously issued financial statements for Exelon, BGE, PHI, Pepco, or DPL. The Consolidated Balance Sheets as of December 31, 2023, for Exelon, BGE, PHI, Pepco, and DPL were revised to reflect the correction of the error.
 Basis of Presentation (All Registrants)
 This is a combined annual report of all Registrants. The Notes to the Consolidated Financial Statements apply to the Registrants as indicated parenthetically next to each corresponding disclosure. When appropriate, the Registrants are named specifically for their related activities and disclosures. Each of the Registrant's Consolidated Financial Statements includes the accounts of its subsidiaries. All intercompany transactions have been eliminated, except for the historical transactions between the Utility Registrants and Generation for the

 purposes of presenting discontinued operations in all periods presented in the Consolidated Statements of Operations and Comprehensive Income.
 Through its business services subsidiary, BSC, Exelon provides its subsidiaries with a variety of support services at cost, including legal, human resources, financial, 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.
 As of December 31, 2024, and 2023, Exelon owned 100 % of PECO, BGE, and PHI and more than 99 % of ComEd. PHI owns 100 % of Pepco, DPL, and ACE. As of February 1, 2022, as a result of the completion of the separation, Exelon no longer owns any interest in Generation. The separation of Constellation, including Generation and its subsidiaries, meets the criteria for discontinued operations and as such, its results of operations are presented as discontinued operations and have been excluded from continuing operations for all periods presented. Accounting rules require that certain BSC costs previously allocated to Generation be presented as part of Exelon's continuing operations as these costs do not qualify as direct expenses of the discontinued operations. Comprehensive income, shareholders' equity, and cash flows related to Generation have not been segregated and are included in the Consolidated Statements of Operations and Comprehensive Income, Consolidated Statements of Changes in Shareholders' Equity, and Consolidated Statements of Cash Flows, respectively, for the period ended December 31, 2022. See Note 2 — Discontinued Operations for additional information.
 The accompanying consolidated financial statements have been prepared in accordance with GAAP for annual financial statements and in accordance with the instructions to Form 10-K and Regulation S-X promulgated by the SEC.
 Use of Estimates (All Registrants)
 The preparation of financial statements of each of the Registrants in conformity with GAAP requires management to make estimates and assumptions that affect the amounts reported in the financial statements and accompanying notes. Areas in which significant estimates have been made include, but are not limited to, the accounting for pension and OPEB, unbilled energy revenues, allowance for credit losses, inventory reserves, goodwill and long-lived asset impairment assessments, derivative instruments, unamortized energy contracts, fixed asset depreciation, capitalization of indirect construction costs, environmental costs and other loss contingencies, AROs, and income taxes. Actual results could differ from those estimates.
 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) there is a reasonable expectation that rates designed to recover costs can be charged to and collected from customers. The Registrants account for their regulated operations in accordance with regulatory and legislative guidance from the regulatory authorities having jurisdiction, principally the ICC, PAPUC, MDPSC, DCPSC, DEPSC, and NJBPU, under state public utility laws and the FERC under various Federal laws. Regulatory assets and liabilities are amortized and the related expense or revenue is recognized in the Consolidated Statements of Operations consistent with the recovery or refund included in customer rates. The Registrants' regulatory assets and liabilities as of the balance sheet date are probable of being recovered or settled in future rates. If a separable portion of the Registrants' business was no longer able to meet the criteria discussed above, the affected entities would be required to eliminate from their consolidated financial statements the effects of regulation for that portion, which could have a material impact on their financial statements. See Note 3 — Regulatory Matters for additional information.
 With the exception of income tax-related regulatory assets and liabilities, the Registrants classify regulatory assets and liabilities with a recovery or settlement period greater than one year as both current and noncurrent in their Consolidated Balance Sheets, with the current portion representing the amount expected to be recovered

 from or refunded to customers over the next twelve-month period as of the balance sheet date. Income tax-related regulatory assets and liabilities are classified entirely as noncurrent in the Registrants' Consolidated Balance Sheets to align with the classification of the related deferred income tax balances.
 The Registrants treat the impacts of a final rate order received after the balance sheet date but prior to the issuance of the financial statements as a non-recognized subsequent event, as the receipt of a final rate order is a separate and distinct event that has future impacts on the parties affected by the order.
 Revenues (All Registrants)
 Operating Revenues. The Registrants' operating revenues generally consist of revenues from contracts with customers involving the sale and delivery of power and natural gas and utility revenues from ARPs. The Registrants recognize revenue from contracts with customers to depict the transfer of goods or services to customers in an amount that the entities expect to be entitled to in exchange for those goods or services. The primary sources of revenue include regulated electric and natural gas tariff sales, distribution, and transmission services. At the end of each month, the Registrants accrue an estimate for the unbilled amount of energy delivered or services provided to customers.
 ComEd records ARP revenue for its best estimate of the electric distribution, energy efficiency, 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. The Registrants recognize all ARP revenues that will be collected within 24 months of the end of the annual period in which they are recorded. See Note 3 — Regulatory Matters for additional information.
 Taxes Directly Imposed on Revenue-Producing Transactions. The Registrants collect certain taxes from customers such as sales and gross receipts taxes, along with other taxes, surcharges, and fees, that are levied by state or local governments on the sale or distribution of electricity and gas. Some of these taxes are imposed on the customer, but paid by the Registrants, while others are imposed on the Registrants. Where these taxes are imposed on the customer, such as sales taxes, they are reported on a net basis with no impact to the Consolidated Statements of Operations and Comprehensive Income. However, where these taxes are imposed on the Registrants, such as gross receipts taxes or other surcharges or fees, they are reported on a gross basis. Accordingly, revenues are recognized for the taxes collected from customers along with an offsetting expense. See Note 22 — Supplemental Financial Information for taxes that are presented on a gross basis.
 Leases (All Registrants)
 The Registrants recognize a ROU asset and lease liability for operating and finance leases when the term is greater than one year. Operating lease ROU assets are included in Other deferred debits and other assets and operating lease liabilities are included in Other current liabilities and Other deferred credits and other liabilities on the Consolidated Balance Sheets. Finance lease ROU assets are included in Property, plant, and equipment, net and finance lease liabilities are included in Long-term debt due within one year and Long-term debt on the Consolidated Balance Sheets. The ROU asset is measured as the sum of (1) the present value of all remaining fixed and in-substance fixed payments using the rate implicit in the lease whenever that is readily determinable or each Registrant's incremental borrowing rate, (2) any lease payments made at or before the commencement date (less any lease incentives received), and (3) any initial direct costs incurred. The lease liability is measured the same as the ROU asset, but excludes any payments made before the commencement date and initial direct costs incurred. Lease terms include options to extend or terminate the lease if it is reasonably certain they will be exercised. The Registrants include non-lease components, which are service-related costs that are not integral to the use of the asset, in the measurement of the ROU asset and lease liability.
 Expense for operating leases and leases with a term of one year or less is recognized on a straight-line basis over the term of the lease, unless another systematic and rational basis is more representative of the derivation of benefit from use of the leased property. Variable lease payments are recognized in the period in which the

 related obligation is incurred. Operating lease expense, finance lease expense, and variable lease payments are primarily recorded to Operating and maintenance expense on the Registrants' Statements of Operations and Comprehensive Income.
 Income from operating leases, including subleases, is recognized on a straight-line basis over the term of the lease, unless another systematic and rational basis is more representative of the pattern in which income is earned over the term of the lease. Variable lease income is recognized in the period in which the related obligation is performed. Operating lease income and variable lease income are recorded to Operating revenues on the Registrants' Statements of Operations and Comprehensive Income.
 The Registrants' operating and finance leases consist primarily of real estate, including office buildings, and vehicles and equipment. The Registrants account for land right arrangements that provide for exclusive use as leases while shared use land arrangements are generally not leases. The Registrants do not account for secondary use pole attachments as leases.
 See Note 10 — Leases for additional information.
 Income Taxes (All Registrants)
 Deferred federal and state income taxes are recorded on significant temporary differences between the book and tax basis of assets and liabilities and for tax benefits carried forward. Investment tax credits have been deferred in the Registrants' Consolidated Balance Sheets and are recognized in book income over the life of the related property. The Registrants account for uncertain income tax positions using a benefit recognition model with a two-step approach; a more-likely-than-not recognition criterion; and a measurement approach that measures the position as the largest amount of tax benefit that is greater than 50 % likely of being realized upon ultimate settlement. If it is not more-likely-than-not that the benefit of the tax position will be sustained on its technical merits, no benefit is recorded. Uncertain tax positions that relate only to timing of when an item is included on a tax return are considered to have met the recognition threshold. The Registrants recognize accrued interest related to unrecognized tax benefits in Interest expense, net or Other, net (interest income) and recognize penalties related to unrecognized tax benefits in Other, net in their Consolidated Statements of Operations and Comprehensive Income.
 Cash and Cash Equivalents (All Registrants)
 The Registrants consider investments purchased with an original maturity of three months or less to be cash equivalents.
 Restricted Cash and Cash Equivalents (All Registrants)
 Restricted cash and cash equivalents represent funds that are restricted to satisfy designated current liabilities. As of December 31, 2024 and 2023, the Registrants' restricted cash and cash equivalents primarily represented the following items:

 Registrant(a)

 Payment of medical, dental, vision, and long-term disability benefits, in addition to the items listed below for the Utility Registrants.

 ComEd
 Collateral held from suppliers associated with energy and REC procurement contracts, any over-recovered RPS costs and alternative compliance payments received from RES pursuant to FEJA, and costs for the remediation of an MGP site.

 PECO
 Proceeds from the sales of assets that were subject to PECO's mortgage indenture.

 BGE
 Proceeds from the loan program for the completion of certain energy efficiency measures and collateral held from energy suppliers.

 PHI(a)

 Payment of merger commitments and collateral held from its energy suppliers associated with procurement contracts.

 Pepco
 Payment of merger commitments and collateral held from energy suppliers.

 DPL
 Collateral held from energy suppliers.

 (a) As of December 31, 2024 and 2023, ACE had no restricted cash and cash equivalents.

 Restricted cash and cash equivalents not available to satisfy current liabilities are classified as noncurrent assets. As of December 31, 2024 and 2023, the Registrants' noncurrent restricted cash and cash equivalents primarily represented ComEd's over-recovered RPS costs and alternative compliance payments received from RES pursuant to FEJA and costs for the remediation of an MGP site and are included in other deferred debits and other assets.
 See Note 16 — Debt and Credit Agreements and Note 22 — Supplemental Financial Information for additional information.
 Allowance for Credit Losses on Customer Receivables (All Registrants)
 The allowance for credit losses reflects the Registrants' best estimates of losses on the customers' accounts receivable balances based on historical experience, current information, and reasonable and supportable forecasts.
 The allowance for credit losses is estimated based on historical experience, current conditions, and forward-looking risk factors. Utility Registrants' customer accounts are written off consistent with approved regulatory requirements. Adjustments to the allowance for credit losses are primarily recorded to Operating and maintenance expense on the Registrants' Consolidated Statements of Operations and Comprehensive Income or Regulatory assets and liabilities on the Registrants' Consolidated Balance Sheets. See Note 3 — Regulatory Matters for additional information regarding the regulatory recovery of credit losses on customer accounts receivable.
 The Registrants have certain non-customer receivables in Other deferred debits and other assets which primarily are with governmental agencies and other high-quality counterparties with no history of default. As such, the allowance for credit losses related to these receivables is not material. The Registrants monitor these balances and will record an allowance if there are indicators of a decline in credit quality. See Note 6 — Accounts Receivable for additional information.
 Inventories (All Registrants)
 Inventory is recorded at the lower of weighted average cost or net realizable value. Provisions are recorded for excess and obsolete inventory. Fossil fuel and Materials and supplies are generally included in inventory when purchased. Fossil fuel is expensed to Purchased power and fuel expense when used or sold. Materials and supplies generally includes transmission and distribution materials and are expensed to Operating and maintenance or capitalized to Property, plant, and equipment, as appropriate, when installed or used.
 Property, Plant, and Equipment (All Registrants)
 Property, plant, and equipment is recorded at original cost. Original cost includes construction-related direct labor and material costs and indirect construction costs including labor and related costs of departments associated with supporting construction activities. When appropriate, original cost also includes AFUDC for regulated property at the Utility Registrants. The cost of repairs and maintenance and minor replacements of property is charged to Operating and maintenance expense as incurred.
 Third parties reimburse the Utility Registrants for all or a portion of expenditures for certain capital projects. Such contributions in aid of construction costs (CIAC) are recorded as a reduction to Property, plant, and equipment, net.
 Upon retirement, the cost of property, net of salvage, is charged to accumulated depreciation consistent with the composite and group methods of depreciation. Depreciation expense at ComEd, BGE, Pepco, DPL, and ACE includes the estimated cost of dismantling and removing plant from service upon retirement. Actual incurred removal costs are applied against a related regulatory liability or recorded to a regulatory asset if in excess of previously collected 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.
 Capitalized Software. Certain costs, such as design, coding, and testing incurred during the application development stage of software projects that are internally developed or purchased for operational use are capitalized within Property, plant, and equipment. Similar costs incurred for cloud-based solutions treated as

 service arrangements are capitalized within Other Current Assets and Deferred Debits and Other Assets. Such capitalized amounts are amortized ratably over the expected lives of the projects when they become operational, generally not to exceed five years. Certain other capitalized software costs are being amortized over longer lives based on the expected life or pursuant to prescribed regulatory requirements.
 AFUDC. AFUDC is the cost, during the period of construction, of debt and equity funds used to finance construction projects for regulated operations. AFUDC is recorded to construction work in progress and as a non-cash credit to an allowance that is included in interest expense for debt-related funds and other income and deductions for equity-related funds. The rates used for capitalizing AFUDC are computed under a method prescribed by regulatory authorities.
 See Note 7 — Property, Plant, and Equipment, Note 8 — Jointly Owned Electric Utility Plant and Note 22 — Supplemental Financial Information for additional information.
 Depreciation and Amortization (All Registrants)
 Depreciation is generally recorded over the estimated service lives of property, plant, and equipment 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 dissimilar assets that have different lives. Under both methods, a reporting entity depreciates the assets over the average life of the assets in the group. ComEd, BGE, Pepco, DPL, and ACE's depreciation expense includes the estimated cost of dismantling and removing plant from service upon retirement, which is consistent with each utility's regulatory recovery method. 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. The estimated service lives for the Registrants are based on a combination of depreciation studies and historical retirements. See Note 7 — Property, Plant, and Equipment for additional information regarding depreciation.
 Amortization of regulatory assets and liabilities are recorded over the recovery or refund period specified in the related legislation or regulatory order or agreement. When the recovery or refund period is less than one year, amortization is recorded to the line item in which the deferred cost or income would have originally been recorded in the Registrants' Consolidated Statements of Operations and Comprehensive Income. Amortization of ComEd's electric distribution rate reconciliations and energy efficiency formula rate regulatory assets and the Utility Registrants' transmission formula rate regulatory assets is recorded to Operating revenues.
 Amortization of income tax related regulatory assets and liabilities is generally recorded to Income tax expense. Except for the regulatory assets and liabilities discussed above, amortization is generally recorded to Depreciation and amortization in the Registrants' Consolidated Statements of Operations and Comprehensive Income when the recovery period is more than one year.
 See Note 3 — Regulatory Matters and Note 22 — Supplemental Financial Information for additional information regarding the amortization of the Registrants' regulatory assets.
 Asset Retirement Obligations (All Registrants)
 The Registrants estimate and recognize a liability for their legal obligation to perform asset retirement activities even though the timing and/or methods of settlement may be conditional on future events. The Registrants update their AROs either annually or on a rotational basis at least once every three years, based on a risk profile, unless circumstances warrant more frequent updates. The updates factor in new cost estimates, credit-adjusted, risk-free rates (CARFR) and escalation rates, and the timing of cash flows. AROs are accreted throughout each year to reflect the time value of money for these present value obligations through an increase to Regulatory assets. See Note 9 — Asset Retirement Obligations for additional information.
 Guarantees (All Registrants)
 If necessary, the Registrants recognize a liability at the time of issuance of a guarantee for the fair value of the obligations they have undertaken. The liability is reduced or eliminated as the Registrants are released from risk under the guarantee. Depending on the nature of the guarantee, the release from risk of the Registrant may be recognized only upon the expiration or settlement of the guarantee or by a systematic and rational amortization

 method over the term of the guarantee. See Note 18 — Commitments and Contingencies for additional information.
 Asset Impairments
 Long-Lived Assets (All Registrants). The Registrants evaluate the carrying value of long-lived assets for recoverability whenever events or changes in circumstances indicate that the carrying value of those assets may not be recoverable. Indicators of impairment may include specific regulatory disallowance, abandonment, or plans to dispose of a long-lived asset significantly before the end of its useful life. When the estimated undiscounted future cash flows attributable to the long-lived asset may not be recoverable, the amount of the impairment loss is determined by measuring the excess of the carrying amount of the long-lived asset over its fair value.
 Goodwill (Exelon, ComEd, and PHI). Goodwill represents the excess of the purchase price paid over the estimated fair value of the net assets acquired and liabilities assumed in the acquisition of a business. Goodwill is not amortized but is assessed for impairment at least annually or on an interim basis if an event occurs or circumstances change that would more likely than not reduce the fair value of a reporting unit below its carrying value. See Note 12 — Intangible Assets for additional information.
 Derivative Financial Instruments (All Registrants)
 Derivatives are recognized on the balance sheet at their fair value unless they qualify for certain exceptions, including 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 underlying hedged transaction affects earnings. Amounts recognized in earnings are recorded in Interest expense, net on the Consolidated Statement of Operations and Comprehensive Income based on the activity the transaction is economically hedging. Cash inflows and outflows related to derivative instruments designated as cash flow hedges are included as a component of operating, investing, or financing cash flows in the Consolidated Statements of Cash Flows, depending on the nature of each transaction.
 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 or as a regulatory asset or liability. Amounts recognized in earnings are recorded in Electric operating revenues, Purchased power and fuel, or Interest expense in the Consolidated Statements of Operations and Comprehensive Income based on the activity the transaction is economically hedging. Changes in fair value are also 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. Cash inflows and outflows related to derivative instruments are included as a component of operating, investing, or financing cash flows in the Consolidated Statements of Cash Flows, depending on the nature of the hedged item. See Note 3 — Regulatory Matters and Note 15 — Derivative Financial Instruments for additional information.
 Retirement Benefits (All Registrants)
 Exelon sponsors defined benefit pension plans and OPEB plans.

 The plan obligations and costs of providing benefits under these plans are measured as of December 31. The measurement involves various factors, assumptions, and accounting elections. The impact of assumption changes or experiences different from those assumed on pension and OPEB obligations is recognized over time rather than immediately recognized in the Consolidated Statements of Operations and Comprehensive Income. Gains or losses in excess of the greater of ten percent of the projected benefit obligation or the MRV of plan assets are amortized over the expected average remaining service period of plan participants. See Note 14 — Retirement Benefits for additional information.
 New Accounting Standards (All Registrants)
 New Accounting Standards Adopted in 2024: In 2024, the Registrants adopted the following new FASB authoritative accounting guidance.

 Segment Reporting (Issued November 2023). Improves reportable segment disclosure requirements, primarily through enhanced disclosures about significant segment expenses. The objective of the revised guidance is to introduce a new requirement to disclose significant segment expenses regularly provided to the CODM, extend

 certain annual disclosures to interim periods, clarify single reportable segment entities must apply ASC 280 in its entirety, permit more than one measure of segment profit or loss to be reported under certain conditions, and require disclosure of the title and position of the CODM. The standard is effective for annual periods beginning January 1, 2024 and interim periods beginning January 1, 2025. The standard is required to be applied retrospectively. The Registrants' adoption of this guidance in the fourth quarter of 2024 resulted in expanded significant segment expenses and enhanced qualitative disclosures regarding the CODMs title and use of the Net income (loss) from continuing operations profitability measure. See Note 5 — Segment Information for additional information.

 New Accounting Standards Issued and Not Yet Adopted as of December 31, 2024: The following new authoritative accounting guidance issued by the FASB has not yet been adopted and reflected by the Registrants in their consolidated financial statements as of December 31, 2024. Unless otherwise indicated, the Registrants are currently assessing the impacts such guidance may have (which could be material) in their Consolidated Balance Sheets, Consolidated Statements of Operations and Comprehensive Income, Consolidated Statements of Cash Flows and disclosures, as well as the potential to early adopt where applicable. The Registrants have assessed other FASB issuances of new standards which are not listed below given the current expectation that such standards will not significantly impact the Registrants' financial reporting.

 Improvement to Income Tax Disclosures (Issued December 2023). Provides additional disclosure requirements related to the effective tax rate reconciliation and income taxes paid. Under the revised guidance for the effective tax reconciliations, entities would be required to disclose: (1) eight specific categories in the effective tax rate reconciliation in both percentages and reporting currency amount, (2) additional information for reconciling items over a certain threshold, (3) explanation of individual reconciling items disclosed, and (4) provide a qualitative description of the state and local jurisdictions that contribute to the majority of the state income tax expense. For each annual period presented, the new standard requires disclosure of the year-to-date amount of income taxes paid (net of refunds received) disaggregated by federal, state, and foreign. It also requires additional disaggregated information on income taxes paid (net of refunds received) to an individual jurisdiction equal to or greater than 5% of total income taxes paid (net of refunds received). The standard is effective January 1, 2025, with early adoption permitted.

 Disaggregation of Income Statement Expenses (Issued November 2024). Provides additional disclosure requirements related to relevant expense captions of income statement expense line items. The revised guidance requires a new tabular disclosure of disaggregated income statement expenses including a break out of (1) purchases of inventory, (2) employee compensation, (3) depreciation, (4) intangible asset amortization, (5) depreciation, depletion, and amortization recognized as part of oil and gas producing activities included in each relevant expense line item on the income statement. The tabular disaggregation should include certain amounts already required to be disclosed under GAAP elsewhere. Any remaining amounts not separately disaggregated quantitatively should include a qualitative description. Additionally, on an annual basis, the standard requires disclosure of management's definition of selling expenses and the amount of expense. The standard is effective January 1, 2027, with early adoption permitted. The Registrants are currently assessing the impacts of this standard.

 2. Discontinued Operations (Exelon)
 On February 21, 2021, Exelon's Board of Directors approved a plan to separate the Utility Registrants and Generation, creating two publicly traded companies ("the separation"). Exelon completed the separation on February 1, 2022, through the distribution of 326,663,937 common stock shares of Constellation, the new publicly traded company, to Exelon shareholders. Under the separation plan, Exelon shareholders retained their current shares of Exelon stock and received one share of Constellation common stock for every three shares of Exelon common stock held on January 20, 2022, the record date for the distribution, in a transaction that was tax-free to Exelon and its shareholders for U.S. federal income tax purposes.
 Constellation was newly formed and incorporated in Pennsylvania on June 15, 2021 for the purposes of separation and holds Generation (including Generation's subsidiaries).
 Pursuant to the separation:
 • Exelon entered into four term loans consisting of a 364-day term loan for $ 1.15 billion and three 18-month term loans for $ 300 million, $ 300 million, and $ 250 million, respectively. Exelon issued these

 Note 2 — Discontinued Operations

 term loans primarily to fund the cash payment to Constellation and for general corporate purposes. See Note 16 — Debt and Credit Agreements for additional information.
 • Exelon made a cash payment of $ 1.75 billion to Constellation on January 31, 2022.
 • Exelon contributed its equity ownership interest in Generation to Constellation. Exelon no longer retains any equity ownership interest in Generation or Constellation.
 • Exelon transferred certain corporate assets and employee-related obligations to Constellation.
 • Exelon received cash from Generation of $ 258 million to settle the intercompany loan on January 31, 2022. See Note 16 — Debt and Credit Agreements for additional information.
 Continuing Involvement
 In order to govern the ongoing relationships between Exelon and Constellation after the separation, and to facilitate an orderly transition, Exelon and Constellation have entered into several agreements, including the following:
 • Separation Agreement – governs the rights and obligations between Exelon and Constellation regarding certain actions to be taken in connection with the separation, among others, including the allocation of assets and liabilities between Exelon and Constellation.
 • Transition Services Agreement (TSA) – governed the terms and conditions of the services that Exelon provided to Constellation and Constellation provided to Exelon. As of December 31, 2024, the TSA has been exited. The services included specified accounting, finance, information technology, human resources, employee benefits, and other services that had historically been provided on a centralized basis by BSC. For the year ended December 31, 2024, the amounts Exelon billed Constellation and Constellation billed Exelon for these services were $ 14 million recorded in Other income, net and an immaterial amount recorded in Operating and maintenance expense, respectively. For the year ended December 31, 2023, the amounts Exelon billed Constellation and Constellation billed Exelon for these services were $ 151 million recorded in Other income, net and $ 14 million recorded in Operating and maintenance expense, respectively. For the period from February 1, 2022 to December 31, 2022, the amounts Exelon billed Constellation and Constellation billed Exelon for these services were $ 266 million recorded in Other income, net and $ 43 million recorded in Operating and maintenance expense, respectively.
 • Tax Matters Agreement (TMA) – governs the respective rights, responsibilities and obligations of Exelon and Constellation with respect to all tax matters, including tax liabilities and benefits, tax attributes, tax returns, tax contests and other tax sharing regarding U.S. federal, state, local and foreign income taxes, other tax matters and related tax returns. See Note 13 — Income Taxes for additional information.
 In addition, the Utility Registrants will continue to incur expenses from transactions with Constellation after the separation. Prior to the separation, such expenses were primarily recorded as Purchased power from affiliates and an immaterial amount recorded as Operating and maintenance expense from affiliates at the Utility Registrants. After the separation, such expenses are primarily recorded as Purchased power and an immaterial amount recorded as Operating and maintenance expense at the Utility Registrants.
 • ComEd had an ICC-approved RFP contract with Constellation to provide a portion of ComEd's electric supply requirements. ComEd also purchased RECs and ZECs from Constellation.
 • PECO received electric supply from Constellation under contracts executed through PECO's competitive procurement process. In addition, PECO had a ten-year agreement with Constellation to sell solar AECs.
 • BGE received a portion of its energy requirements from Constellation under its MDPSC-approved market-based SOS and gas commodity programs.
 • Pepco received electric supply from Constellation under contracts executed through Pepco's competitive procurement process approved by the MDPSC and DCPSC.

 Note 2 — Discontinued Operations

 • DPL received a portion of its energy requirements from Constellation under its MDPSC and DEPSC approved market-based SOS commodity programs.
 • ACE received electric supply from Constellation under contracts executed through ACE's competitive procurement process approved by the NJBPU.
 ComEd and PECO also have receivables with Constellation for estimated excess funds at the end of decommissioning the Regulatory Agreement Units, such amounts are due back to ComEd and PECO, as applicable, for payment to their respective customers. See Note 3 — Regulatory Matters and Note 23 — Related Party Transactions for additional information.
 Discontinued Operations
 The separation represented a strategic shift that had a major effect on Exelon's operations and financial results. Accordingly, the separation met the criteria for discontinued operations.
 There were no results from discontinued operations for the years ended December 31, 2024 and 2023. The following table presents the results of Constellation that have been reclassified from continuing operations and included in discontinued operations within Exelon's Consolidated Statements of Operations and Comprehensive Income for the year ended December 31, 2022.
 These results are primarily Generation, which is comprised of Exelon's Mid-Atlantic, Midwest, New York, ERCOT, and Other Power Regions reportable segments, and include the impact of transaction costs, certain BSC costs, including any transition costs, that were historically allocated and directly attributable to Generation, transactions between Generation and the Utility Registrants, and tax-related adjustments. Transaction costs include costs for external bankers, accountants, appraisers, lawyers, external counsels and other advisors, among others, who are involved in the negotiation, appraisal, due diligence and regulatory approval of the separation. Transition costs are primarily employee-related costs such as recruitment expenses, costs to establish certain stand-alone functions and information technology systems, professional services fees, and other separation-related costs during the transition to separate Generation. For the purposes of reporting discontinued operations, these results also include transactions between Generation and the Utility Registrants that were historically eliminated within Exelon's Consolidated Statements of Operations, as these transactions will be ongoing after the separation. Certain BSC costs that were historically allocated to Generation are presented as part of continuing operations in Exelon's Consolidated Statements of Operations as these costs do not qualify as expenses of the discontinued operations per the accounting rules.

 Note 2 — Discontinued Operations

 For the Year Ended December 31,

 2022

 Competitive business revenues
 $
 1,855

 Competitive business revenues from affiliates

 2,016

 Competitive businesses purchased power and fuel
 1,138

 Operating and maintenance(a)

 1,647

 Gain on sales of assets and businesses

 ( 20)

 ( 281)

 ( 301)

 ( 40)

 Equity in losses of unconsolidated affiliates
 ( 1)

 Net income attributable to noncontrolling interests

 Net income from discontinued operations
 $

 (a)Includes transaction and transition costs related to the separation of $ 52 million for the year ended December 31, 2022.
 There were no assets or liabilities of discontinued operations included in Exelon's Consolidated Balance Sheet as of December 31, 2024 and 2023. Constellation had net assets of $ 11,573 million that separated on February 1, 2022 that resulted in a reduction to Exelon's equity during the year ended December 31, 2022. Refer to the Distribution of Constellation line in Exelon's Consolidated Statement of Changes in Shareholders' Equity for further information.
 There were no discontinued operations included within Exelon's Consolidated Statements of Cash Flows for the years ended December 31, 2024 and December 31, 2023. The following table presents selected financial information regarding cash flows of the discontinued operations that are included within Exelon's Consolidated Statements of Cash Flows for the year ended December 31, 2022.

 Note 2 — Discontinued Operations

 For the Year Ended December 31,

 2022

 Non-cash items included in net income from discontinued operations:

 Depreciation, amortization, and accretion, including nuclear fuel and energy contract amortization
 $

 Loss on sales of assets and businesses

 ( 143)

 Net fair value changes related to derivatives
 ( 59)

 Net realized and unrealized losses on NDT fund investments

 Net unrealized losses on equity investments

 Other decommissioning-related activity

 Cash flows from investing activities:

 ( 227)

 Collection of DPP

 Supplemental cash flow information:

 Decrease in capital expenditures not paid
 $
 ( 128)

 Increase in DPP

 Increase in PP&E related to ARO update

 3. Regulatory Matters (All Registrants)
 The following matters below discuss the status of material regulatory and legislative proceedings of the Registrants.
 Distribution Base Rate Case Proceedings
 The following tables show the completed and pending distribution base rate case proceedings in 2024.
 Completed Distribution Base Rate Case Proceedings

 Registrant/Jurisdiction
 Service
 Approved Revenue Requirement Increase
 Approved ROE
 Approval Date
 Rate Effective Date

 ComEd - Illinois
 January 17, 2023(a)

 $
 1,487
 $
 1,045
 8.905 %
 December 19, 2024
 January 1, 2024

 April 26, 2024 (amended on September 11, 2024)(b)

 $
 $
 9.89 %
 October 31, 2024

 PECO - Pennsylvania
 March 28, 2024
 Electric(c)(d)

 $ 464
 $
 N/A(e)

 December 12, 2024

 Natural Gas(d)

 $ 111
 $

 BGE - Maryland
 February 17, 2023(f)

 $
 $
 9.50 %
 December 14, 2023
 January 1, 2024

 $
 $
 9.45 %

 Pepco - District of Columbia(g)

 April 13, 2023 (amended February 27, 2024)
 $
 $
 9.50 %
 November 26, 2024

 Pepco - Maryland
 October 26, 2020 (amended March 31, 2021)(h)

 $
 $
 9.55 %
 June 28, 2021
 June 28, 2021

 May 16, 2023 (amended February 23, 2024)(i)

 $
 $
 9.50 %
 June 10, 2024
 April 1, 2024

 DPL - Maryland(j)

 May 19, 2022
 $
 $
 9.60 %
 December 14, 2022
 January 1, 2023

 DPL - Delaware(k)

 December 15, 2022 (amended September 29, 2023)
 $
 $
 9.60 %
 April 18, 2024
 July 15, 2023

 ACE - New Jersey(l)

 February 15, 2023 (amended August 21, 2023)
 $
 $
 9.60 %
 November 17, 2023
 December 1, 2023

 (a)Reflects a four-year cumulative multi-year rate plan for January 1, 2024 to December 31, 2027. The MRP was originally approved by the ICC on December 14, 2023 and was subsequently amended on January 10, 2024, April 18, 2024 and December 19, 2024. The December 19, 2024 order provided a total revenue requirement increase of $ 1.045 billion inclusive of rate increases of approximately $ 752 million in 2024, $ 80 million in 2025, $ 102 million in 2026, and $ 111 million in 2027.
 (b)On October 31, 2024, the Delivery Reconciliation Amount for 2023 defined in Rider Delivery Service Pricing Reconciliation (Rider DSPR) was approved. Rider DSPR allows for the reconciliation of the revenue requirement in effect in the final years in which formula rates are determined and until such time as new rates are established under ComEd's approved MRP. The 2024 order reconciled the delivery service rates in effect in 2023 with the actual delivery service costs incurred in 2023. The reconciliation revenue requirement provides for a weighted average debt and equity return on distribution rate base of 7.02 %, inclusive of an allowed ROE of 9.89 %, reflecting the monthly yields on 30-year treasury bonds plus 580 basis points.
 (c)PECO's approved annual electric revenue requirement increase of $ 354 million is partially offset by a one-time credit of $ 64 million in 2025. In addition, the PAPUC approved the recovery of storm damage costs incurred by PECO in January 2024, up to $ 23 million, subject to review for reasonableness and prudency in PECO's next distribution rate case.
 (d)On December 12, 2024, the PAPUC issued their Opinions and Orders which approved the non-unanimous partial settlements with limited modifications for both the electric and natural gas base rate cases, and denied the Weather Normalization Adjustment requested in the natural gas base rate case.

 (e)The PECO electric and natural gas base rate case proceedings were resolved through settlement agreements, which did not specify an approved ROE.
 (f)Reflects a three-year cumulative multi-year plan for January 1, 2024 through December 31, 2026. The MDPSC awarded BGE electric revenue requirement increases of $ 41 million, $ 113 million, and $ 25 million in 2024, 2025, and 2026, respectively, and natural gas revenue requirement increases of $ 126 million, $ 62 million, and $ 41 million in 2024, 2025, and 2026, respectively. Requested revenue requirement increases will be used to recover capital investments designed to increase the resilience of the electric and gas distribution systems and support Maryland's climate and regulatory initiatives. The MDPSC also approved a portion of the requested 2021 and 2022 reconciliation amounts, which will be recovered through separate electric and gas riders between March 2024 and February 2025. As such, the reconciliation amounts are not included in the approved revenue requirement increases. The 2021 reconciliation amounts are $ 13 million and $ 7 million for electric and gas, respectively, and the 2022 reconciliation amounts are $ 39 million and $ 15 million for electric and gas, respectively. In April 2024, BGE filed with the MDPSC its request for recovery of the 2023 reconciliation amounts of $ 79 million and $ 73 million for electric and gas, respectively, with supporting testimony and schedules.
 (g)Reflects a two-year cumulative multi-year plan for January 1, 2025, through December 31, 2026. The DCPSC awarded Pepco electric incremental revenue requirement increases of $ 99 million and $ 24 million for 2025 and 2026, respectively.
 (h)Reflects a three-year cumulative multi-year plan for April 1, 2021 through March 31, 2024. The MDPSC awarded Pepco electric incremental revenue requirement increases of $ 21 million, $ 16 million, and $ 15 million, before offsets, for the 12-month periods ending March 31, 2022, 2023, and 2024, respectively. Pepco proposed to utilize certain tax benefits to fully offset the increase through 2023 and partially offset customer rate increases in 2024. However, the MDPSC only utilized the acceleration of refunds for certain tax benefits to fully offset the increases such that customer rates remain unchanged through March 31, 2022. On February 23, 2022, the MDPSC chose to offset 25 % of the cumulative revenue requirement increase through March 31, 2023. In 2021, the MDPSC deferred a decision on whether to use certain tax benefits to offset the revenue requirement increases for the 12-month period ending March 31, 2024. In December 2022 Pepco proposed that tax benefits not be used to offset the revenue requirement increases for this period. On January 25, 2023, the MDPSC accepted Pepco's recommendations not to use tax benefits to offset revenue requirement increases for the 12-month period ending March 31, 2024.
 (i)Reflects the amounts requested (before offsets) and awarded for a one-year multi-year plan for April 1, 2024 through March 31, 2025. The MDPSC awarded Pepco an electric incremental revenue requirement increase of $ 45 million for the 12-month period ending March 31, 2025. The MDPSC did not adopt the requested revenue requirement increases of $ 80 million (before offsets), $ 51 million, and $ 14 million as filed for 2025, 2026, and the 2027 nine-month extension period, respectively. The order allows for Pepco to perform an annual reconciliation after the 2024 rate year. The MDPSC also approved the requested reconciliation amounts for the 12-month periods ending March 31, 2022, and March 31, 2023, which will be recovered through a rider between August 2024 through March 2026. As such, the reconciliation amounts are not included in the approved revenue requirement increases. The reconciliation amounts are $ 1 million, and $ 7 million, for the 12-month periods ending March 31, 2022, and March 31, 2023, respectively. In July 2024, Pepco filed its request with the MDPSC for recovery of $ 31 million for the 12-month period ended March 31, 2024, with supporting testimony and schedules.
 (j)Reflects a three-year cumulative multi-year plan for January 1, 2023 through December 31, 2025. The MDPSC awarded DPL electric incremental revenue requirement increases of $ 17 million, $ 6 million, and $ 6 million for 2023, 2024, and 2025, respectively.
 (k)On April 18, 2024, the DEPSC approved the Significant Storm Expense Rate Rider (Rider SSER) which will allow DPL to recover expenses associated with qualified storms. A qualified storm will be an individual storm for which DPL incurs expenses between $ 5 million and $ 15 million. The Rider SSER allows DPL to recover significant storm damage expenses for the previous 12-month period over a future 24-month period. For individual storm events for which DPL incurs expenses of more than $ 15 million, the future recovery period will be evaluated on a case-by-case basis and the unamortized balance will earn a return at DPL's authorized long-term cost of debt. The Rider SSER will have an annual true-up filing, subject to DEPSC review and approval.
 (l)Requested and approved increases are before New Jersey sales and use tax. The NJBPU awarded ACE electric revenue requirement increases of $ 36 million and $ 9 million effective December 1, 2023 and February 1, 2024, respectively.

 Pending Distribution Base Rate Case Proceedings

 Registrant/Jurisdiction
 Service
 Requested ROE
 Expected Approval Timing

 DPL - Delaware(a)

 September 20, 2024
 $
 10.65 %
 First quarter of 2026

 ACE - New Jersey(b)

 November 21, 2024
 $
 10.70 %
 Fourth quarter of 2025

 (a)DPL can implement interim rates on April 20, 2025, subject to refund.

 (b)Requested increases are before New Jersey sales and use tax. ACE intends to put rates into effect on August 21, 2025, subject to refund.
 Transmission Formula Rates
 The Utility Registrants' transmission rates are each established based on a FERC-approved formula. ComEd, BGE, Pepco, DPL, and ACE are required to file an annual update to the FERC-approved formula on or before May 15, and PECO is required to file on or before May 31, with the resulting rates effective on June 1 of the same year. The annual update for ComEd is based on prior year actual costs and current year projected capital additions (initial year revenue requirement). The update for ComEd also reconciles any differences between the revenue requirement in effect beginning June 1 of the prior year and actual costs incurred for that year (annual reconciliation). The annual update for PECO is based on prior year actual costs and current year projected capital additions, accumulated depreciation, and accumulated deferred income taxes. The annual update for BGE, Pepco, DPL, and ACE is based on prior year actual costs and current year projected capital additions, accumulated depreciation, depreciation and amortization expense, and accumulated deferred income taxes. The update for PECO, BGE, Pepco, DPL, and ACE also reconciles any differences between the actual costs and actual revenues for the calendar year (annual reconciliation).
 For 2024, the following increases/(decreases) were included in the Utility Registrants' electric transmission formula rate updates:

 Registrant(a)

 Initial Revenue Requirement Increase
 Annual Reconciliation (Decrease) Increase
 Total Revenue Requirement Increase
 Allowed Return on Rate Base(b)

 Allowed ROE(c)

 ComEd
 $
 $
 ( 12)
 $
 8.14
 %
 11.50
 %

 PECO
 $
 $
 $
 7.45
 %
 10.35
 %

 BGE
 $
 $
 $
 (d)
 7.47
 %
 10.50
 %

 Pepco
 $
 $
 $
 7.62
 %
 10.50
 %

 DPL
 $
 $
 $
 7.23
 %
 10.50
 %

 ACE
 $
 $
 $
 7.11
 %
 10.50
 %

 (a)All rates are effective June 1, 2024 - May 31, 2025, subject to review by interested parties pursuant to review protocols of each Utility Registrants' tariffs.
 (b)Represents the weighted average debt and equity return on transmission rate bases. For PECO, the common equity component of the ratio used to calculate the weighted average debt and equity return on the transmission formula rate base is currently capped at 55.75 %.
 (c)The rate of return on common equity for each Utility Registrant includes a 50 -basis-point incentive adder for being a member of an RTO.
 (d)The increase in BGE's transmission revenue requirement includes a $ 2 million reduction related to a FERC-approved dedicated facilities charge to recover the costs of providing transmission service to specifically designated load by BGE.
 Other State Regulatory Matters
 Illinois Regulatory Matters
 CEJA (Exelon and ComEd). On September 15, 2021, the Governor of Illinois signed into law CEJA. CEJA includes, among other features, (1) procurement of CMCs from qualifying nuclear-powered generating facilities, (2) a requirement to file a general rate case or a new four-year MRP no later than January 20, 2023 to establish rates effective after ComEd's existing performance-based distribution formula rate sunsets, (3) requirements that ComEd and the ICC initiate and conduct various regulatory proceedings on subjects including ethics, spending, grid investments, and performance metrics.
 ComEd Electric Distribution Rates
 ComEd filed, and received approval for, its last performance-based electric distribution formula rate update under EIMA in 2022; those rates were in effect throughout 2023.
 On February 3, 2022, the ICC approved a tariff that established the process under which ComEd reconciled its 2022 and 2023 rate year revenue requirements with actual costs. Those reconciliation amounts were determined

 using the same process used for prior reconciliations under the performance-based electric distribution formula rate. Using that process, for the rate years 2022 and 2023 ComEd will ultimately collect revenues from customers reflecting each year's actual recoverable costs, year-end rate base, and a weighted average debt and equity return on distribution rate base, with the ROE component based on the annual average of the monthly yields of the 30-year U.S. Treasury bonds plus 580 basis points. In April 2023, ComEd filed its first petition with the ICC to reconcile its 2022 actual costs with the approved revenue requirement that was in effect in 2022; the final order was issued on November 30, 2023, for rates beginning January 2024. On April 26, 2024, ComEd filed its final petition with the ICC to reconcile its 2023 actual costs with the approved revenue requirement that was in effect in 2023; the final order was issued on October 31, 2024, for rates beginning January 2025.
 Beginning in 2024, ComEd started recovering from retail customers, subject to certain exceptions, the costs it incurs to provide electric delivery services either through its electric distribution rate or other recovery mechanisms authorized by CEJA. On January 17, 2023, ComEd filed a petition with the ICC seeking approval of a MRP for 2024-2027. The MRP supports a multi-year grid plan (Grid Plan), also filed on January 17, covering planned investments on the electric distribution system within ComEd's service area through 2027. Costs incurred during each year of the MRP are subject to ICC review and the plan's revenue requirement for each year will be reconciled with the actual costs that the ICC determines are prudently and reasonably incurred for that year. The reconciliation is subject to adjustment for certain costs, including a limitation on recovery of costs that are more than 105 % of certain costs in the previously approved MRP revenue requirement, absent a modification of the rate plan itself. Thus, for example, the rate adjustments necessary to reconcile 2024 revenues to ComEd's actual 2024 costs incurred would take effect in January 2026 after the ICC's review during 2025.
 On December 14, 2023, the ICC issued a final order. The ICC rejected ComEd's Grid Plan as non-compliant with certain requirements of CEJA and required ComEd to file a revised Grid Plan. In the absence of an approved Grid Plan, the ICC set ComEd's forecast revenue requirements for 2024-2027 based on ComEd's approved year-end 2022 rate base. This resulted in a total cumulative revenue requirement increase of $ 501 million, a $ 986 million total revenue reduction from the requested cumulative revenue requirement increase but remains subject to annual reconciliation in accordance with CEJA. The final order approved the process and formulas associated with the MRP reconciliation mechanisms. The ICC's December 2023 order also denied ComEd's ability to earn a return on its pension asset.
 On December 22, 2023, ComEd filed an application for rehearing on several findings in the final order including the use of the 2022 year-end rate base to establish forecast revenue requirements for 2024-2027, ROE, pension asset return, and capital structure. On January 10, 2024, ComEd's application for rehearing was denied on all issues except for the order's use of the 2022 year-end rate base. On April 18, 2024, the ICC issued its final order on ComEd's January 31, 2024 rehearing motion, which approved the use of the forecasted year-end 2023 rate base that resulted in increased revenue requirements for 2024-2027. These revenue requirements determined during the rehearing process established base revenue requirements until the ICC approved the Refiled Grid Plan on December 19, 2024.
 On January 10, 2024, ComEd also filed an appeal in the Illinois Appellate Court of the issues on which rehearing was denied, including but not limited to the allowed ROE, 50 % equity ratio, and denial of a return on ComEd's pension asset. There is no deadline by when the appellate court must rule. On March 13, 2024, ComEd filed its Refiled Grid Plan with supporting testimony and schedules with the ICC and subsequently on March 15, 2024, ComEd also filed a petition to adjust its MRP to authorize increased rates consistent with the Refiled Grid Plan. On December 19, 2024, the ICC approved the Refiled Grid Plan and adjusted the approved MRP with rates effective on January 1, 2025. The final approved MRP, as adjusted, which reflects the Refiled Grid Plan, resulted in a total cumulative revenue requirement increase of $ 1.045 billion over the 2024-2027 plan years and remains subject to annual reconciliations in accordance with CEJA.
 In January 2022, ComEd filed a request with the ICC proposing performance metrics that would be used in determining ROE incentives and penalties in the event ComEd filed a MRP in January 2023. On September 27, 2022, the ICC issued a final order approving seven performance metrics that provide symmetrical performance adjustments of 32 total basis points to ComEd's rate of return on common equity based on the extent to which ComEd achieves the annual performance goals. On November 10, 2022, the ICC granted ComEd's application for rehearing, in part. On April 5, 2023, the ICC issued its final order on rehearing for the performance and tracking metrics proceeding, in which the ICC declined to adopt ComEd's proposed modifications to the reliability and peak load reduction performance metrics. Efforts are underway to implement the performance metrics, which took effect on January 1, 2024. ComEd will make its initial filing in 2025 to assess performance achieved under

 the metrics in 2024, and to determine any ROE adjustment, which would take effect in 2026. In 2024, ComEd has recognized an estimate of the impact of the performance metrics' adjustment.
 Carbon Mitigation Credit
 CEJA establishes decarbonization requirements for Illinois as well as programs to support the retention and development of emissions-free sources of electricity. ComEd is required to purchase CMCs from participating nuclear-powered generating facilities between June 1, 2022 and May 31, 2027. The price to be paid for each CMC was established through a competitive bidding process that included consumer-protection measures that capped the maximum acceptable bid amount and a formula that reduces CMC prices by an energy price index, the base residual auction capacity price in the ComEd zone of PJM, and the monetized value of any federal tax credit or other subsidy if applicable. The seller has not provided notification to ComEd or the IPA that any subsidies or tax credits, such as nuclear production tax credits that became available for electricity generated beginning January 1, 2024, have been monetized and the IPA did not adjust the CMC price paid by ComEd in 2024. The consumer protection measures contained in CEJA will result in net payments to ComEd ratepayers if the energy index, the capacity price and applicable federal tax credits or subsidy exceed the CMC contract price. Beginning with the June 2022 monthly billing period, ComEd began issuing credits and/or charges to its retail customers under its CMC rider, the Rider Carbon-Free Resource Adjustment (Rider CFRA). A regulatory asset is recorded for the difference between ComEd's costs associated with the procurement of CMCs from participating nuclear power generating facilities and revenues received from customers. The balance as of December 31, 2024 is $ 179 million.
 Under CEJA, the costs of procuring CMCs, including carrying costs, are recovered through Rider CFRA. As originally approved by the ICC, Rider CFRA provides for an annual reconciliation and true-up to actual costs incurred or credits received by ComEd to purchase CMCs, with any difference to be credited to or collected from ComEd's retail customers in subsequent periods. The difference between the net payments to (or receivables from) ComEd ratepayers and the credits received by ComEd to purchase CMCs is recorded to Purchased power expense with an offset to the regulatory asset (or regulatory liability). On December 21, 2022, ComEd filed an amendment to Rider CFRA proposing that it recover costs or provide credits faster than the tariff allows, implement monthly reconciliations, and allow ComEd to adjust Rider CFRA rates based not only on anticipated differences but also past payments or credits, and implement monthly reconciliations beginning with the June 2023 delivery period. The ICC approved the proposal on January 19, 2023. In addition, on March 24, 2023, ComEd submitted revisions to Rider CFRA which clarified the methodology for calculating interest to be included in the annual reconciliation associated with the June 2022 through May 2023 delivery year. The ICC approved the proposal on April 20, 2023. On February 2, 2024, ComEd filed a petition with the ICC to initiate the reconciliation proceeding for the costs incurred in connection with the procurement of CMCs during the delivery year beginning June 1, 2022 and extending through May 31, 2023.
 Excess Deferred Income Taxes

 The ICC initiated a docket to accelerate and fully credit to customers TCJA unprotected property-related EDIT no later than December 31, 2025. On July 7, 2022, the ICC issued a final order on the schedule for the acceleration of EDIT amortization, adopting the proposal as submitted by several parties, including ComEd, ICC Staff, the Illinois Attorney General's Office, and the Citizens Utility Board. EDIT amortization will be credited to customers through a new rider from January 1, 2023 through December 31, 2025.
 Energy Efficiency
 CEJA extends ComEd's current cumulative annual energy efficiency MWh savings goals through 2040, adds expanded electrification measures to those goals, increases low-income commitments, and adds a new performance adjustment to the energy efficiency formula rate. ComEd expects its annual spend to increase in 2023 through 2040 to achieve these energy efficiency MWh savings goals, which is deferred as a separate regulatory asset that is recovered through the energy efficiency formula rate over the weighted average useful life, as approved by the ICC, of the related energy efficiency measures.
 Energy Efficiency Formula Rate (Exelon and ComEd). FEJA allows ComEd to defer energy efficiency costs (except for any voltage optimization costs which are recovered through electric distribution rates) as a separate regulatory asset that is recovered through the energy efficiency formula rate over the weighted average useful life, as approved by the ICC, of the related energy efficiency measures. ComEd earns a return on the energy

 efficiency regulatory asset at a rate equal to a weighted average cost of capital, which is based on a year-end capital structure and a statutorily-based formula based on long-term treasury debt. The ROE that ComEd earns on its energy efficiency regulatory asset is subject to a maximum downward or upward adjustment of 200 basis points if ComEd's cumulative persisting annual MWh savings falls short of or exceeds specified percentage benchmarks of its annual incremental savings goal. ComEd is required to file an update to its energy efficiency formula rate on or before June 1st each year, with resulting rates effective in January of the following year. The annual update is based on projected rate year energy efficiency costs, PJM capacity revenues, and the projected year-end regulatory asset balance less any related deferred income taxes (initial year revenue requirement). The update also reconciles any differences between the revenue requirement in effect for the prior year and actual costs incurred from the year (annual reconciliation). The approved energy efficiency formula rate also provides for revenue decoupling provisions.
 During 2024, the ICC approved the following total increases in ComEd's requested energy efficiency revenue requirement:

 Approved Revenue Requirement Increase(a)

 Approved ROE
 Approval Date
 Rate Effective Date

 May 30, 2024
 $
 $
 9.89
 %
 December 5, 2024

 (a)ComEd's 2025 approved revenue requirement above reflects an increase of $ 66 million for the initial year revenue requirement for 2025 and a decrease of $ 8 million related to the annual reconciliation for 2023. The revenue requirement for 2025 provides for a weighted average debt and equity return on the energy efficiency regulatory asset and rate base of 7.02 % inclusive of an allowed ROE of 9.89 %, reflecting the monthly average yields for 30-year treasury bonds plus 580 basis points. The revenue requirement for the 2023 reconciliation year provides for a weighted average debt and equity return on the energy efficiency regulatory asset and rate base of 7.24 % inclusive of an allowed ROE of 10.34 %, which includes an upward performance adjustment that increased the ROE. The performance adjustment can either increase or decrease the ROE based upon the achievement of energy efficiency savings goals. See table below for ComEd's regulatory assets associated with its energy efficiency formula rate.
 Maryland Regulatory Matters
 Maryland Revenue Decoupling (Exelon, BGE, PHI, Pepco, and DPL). In 1998, the MDPSC approved natural gas monthly rate adjustments for BGE and in 2007, the MDPSC approved electric monthly rate adjustments for BGE and BSAs for Pepco and DPL, all of which are decoupling mechanisms. As a result of the decoupling mechanisms, certain Operating revenues from electric and natural gas distribution at BGE and Operating revenues from electric distribution at Pepco Maryland (see also District of Columbia Revenue Decoupling below for Pepco District of Columbia) and DPL are not intended to be impacted by abnormal weather or usage per customer. For BGE, Pepco, and DPL, the decoupling mechanism eliminates the impacts of abnormal weather or customer usage by recognizing revenues based on an authorized distribution amount per customer by customer class. Operating revenues from electric and natural gas distribution at BGE and Operating revenues from electric distribution at Pepco Maryland and DPL are, however, impacted by changes in the number of customers.
 EmPOWER Maryland Cost Recovery (Exelon, BGE, PHI, Pepco and DPL). On December 29, 2023, the MDPSC issued an order authorizing the next three-year program cycle for EmPOWER Maryland and approved various proposals by the program administrators to implement new energy efficiency programs for the 2024-2026 program cycle, as well as continue operating core programs. Historically, BGE, Pepco, and DPL 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. Beginning in 2024, BGE, Pepco, and DPL will begin deferring less energy efficiency and demand response program costs to a regulatory asset. Additionally, as part of the order, the MDPSC directed BGE, Pepco, and DPL to extend the amortization of unamortized costs as of December 31, 2023 from 5 to 7 years to mitigate customer bill impacts.
 District of Columbia Regulatory Matters
 District of Columbia Revenue Decoupling (Exelon, PHI, and Pepco). In 2009, the DCPSC approved a BSA, which is a decoupling mechanism. As a result of the decoupling mechanism, Operating revenues from electric distribution at Pepco District of Columbia (see also Maryland Revenue Decoupling above for Pepco Maryland) are not intended to be impacted by abnormal weather or usage per customer. The decoupling mechanism eliminates the impacts of abnormal weather or customer usage by recognizing revenues based on an authorized

 distribution amount per customer by customer class. Historically, operating revenues from electric distribution at Pepco District of Columbia are, however, impacted by changes in the number of customers. Beginning in 2025, based on modifications approved by the DCPSC, Pepco District of Columbia will recognize revenues on an authorized distribution amount per customer class basis, and operating revenues from electric distribution will not be impacted by changes in the number of customers.
 New Jersey Regulatory Matters
 Conservation Incentive Program (CIP) (Exelon, PHI, and ACE). On September 25, 2020, ACE filed an application with the NJBPU as was required seeking approval to implement a portfolio of energy efficiency programs pursuant to New Jersey's clean energy legislation. The filing included a request to implement a CIP that would eliminate the favorable and unfavorable impacts of weather and customer usage patterns on distribution revenues for most customers. 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.
 On April 27, 2021, the NJBPU approved the settlement filed by ACE and the third parties to the proceeding. The approved settlement addresses all material aspects of ACE's filing, including ACE's ability to implement the CIP prospectively effective July 1, 2021. As a result of this decoupling mechanism, operating revenues are no longer intended to be impacted by abnormal weather or usage for most customers. Starting in third quarter of 2021, ACE has recorded alternative revenue program revenues for its best estimate of the distribution revenue impacts resulting from future changes in CIP rates that it believes are probable of approval by the NJBPU in accordance with this mechanism.
 Termination of Energy Procurement Provisions of PPAs (Exelon, PHI, and ACE). On December 22, 2021, ACE filed with the NJBPU a petition to terminate the provisions in the PPAs to purchase electricity from two coal-powered generation facilities located in the state of New Jersey. The petition was approved by the NJBPU on March 23, 2022. Upon closing of the transaction on March 31, 2022, ACE recognized a liability of $ 203 million for the contract termination fee and recognized a corresponding regulatory asset of $ 203 million. The liability has been paid in full as of December 31, 2024.
 For the year ended December 31, 2024 and 2023, ACE has respectively paid $ 49 million and $ 88 million of the liability, which is recorded in Changes in Other assets and liabilities in Exelon's, PHI's, and ACE's Consolidated Statements of Cash Flows.
 ACE Infrastructure Investment Program Filings (Exelon, PHI, and ACE). On October 31, 2022, ACE filed with the NJBPU an IIP, called "Powering the Future", proposing to seek recovery through a new component of ACE's rider mechanism, totaling $ 379 million, over the four-year period of July 1, 2023, to June 30, 2027. The new IIP will allow ACE to invest in projects that are designed to enhance the reliability, resiliency, and safety of the service ACE provides to its customers. On June 15, 2023, ACE entered into a settlement agreement with other parties, which allows for a recovery totaling $ 93 million of reliability related capital investments from July 1, 2023, through June 30, 2027. ACE will have the option of seeking approval from the NJBPU to extend the end date of the IIP beyond June 30, 2027, if ACE determines an extension is necessary. On June 29, 2023, the NJBPU adopted the settlement agreement and issued an order approving the program.
 Advanced Metering Infrastructure Filing (Exelon, PHI, and ACE). On August 26, 2020, ACE filed an application with the NJBPU as was required seeking approval to deploy a smart energy network in alignment with New Jersey's Energy Master Plan and Clean Energy Act. The proposal consisted of estimated costs totaling $ 220 million with deployment taking place over a 3-year implementation period from approximately 2021 to 2024 that involves the installation of an integrated system of smart meters for all customers accompanied by the requisite communications facilities and data management systems.
 On July 14, 2021, the NJBPU approved the settlement filed by ACE and the third parties to the proceeding. The approved settlement addresses all material aspects of ACE's smart energy network deployment plan, including cost recovery of the investment costs, incremental Operating and maintenance expenses, and the unrecovered balance of existing infrastructure through future distribution rates.
 New Jersey Clean Energy Legislation (Exelon, PHI, and ACE). On May 23, 2018, New Jersey enacted legislation that established and modified New Jersey's clean energy and energy efficiency programs and solar

 and RPS. On the same day, New Jersey enacted legislation that established a ZEC program that provides compensation for nuclear plants that demonstrate to the NJBPU that they meet certain requirements. Under the legislation, the NJBPU will issue ZECs to the qualifying nuclear power plants and the electric distribution utilities in New Jersey, including ACE, will be required to purchase those ZECs. ACE began collecting from retail distribution customers, through a non-bypassable charge, all costs associated with the procurement of the ZECs effective April 18, 2019.
 Other Federal Regulatory Matters
 FERC Audit (Exelon and ComEd). 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.
 Regulatory Assets and Liabilities
 Regulatory assets represent incurred costs that have been deferred because of their probable future recovery from customers through regulated rates. Regulatory liabilities represent the excess recovery of costs or accrued credits that have been deferred because it is probable such amounts will be returned to customers through future regulated rates or represent billings in advance of expenditures for approved regulatory programs.

 The following tables provide information about the regulatory assets and liabilities of the Registrants at December 31, 2024 and 2023:

 ComEd
 PECO
 BGE
 PHI
 Pepco
 DPL
 ACE

 AMI programs - deployment costs
 $
 $
 —
 $
 —
 $
 $
 $
 $
 $

 AMI programs - legacy meters
 —

 Carbon mitigation credit
 —
 —
 —
 —
 —
 —

 COVID-19
 —
 —

 DC PLUG charge
 —
 —
 —
 —
 —

 —
 —
 —
 —

 Deferred storm costs
 —

 Electric distribution formula rate annual reconciliations
 —
 —
 —
 —
 —
 —

 Electric distribution formula rate significant one-time events
 —
 —
 —
 —
 —
 —

 —
 —

 —

 Energy efficiency costs
 1,890
 1,890
 —
 —
 —
 —
 —
 —

 Fair value of long-term debt
 —
 —
 —
 —
 —
 —

 Fair value of PHI's unamortized energy contracts
 —
 —
 —
 —
 —
 —

 MGP remediation costs
 —
 —
 —
 —

 —
 —
 —

 Pension and OPEB
 2,382
 —
 —
 —
 —
 —
 —
 —

 Pension and OPEB - merger related
 —
 —
 —
 —
 —
 —
 —

 —
 —

 Renewable energy
 —
 —
 —
 —
 —
 —

 Transmission formula rate annual reconciliations
 —
 —

 Under-recovered credit loss expense
 —
 —
 —
 —

 Under-recovered revenue decoupling
 —
 —
 —

 Universal service fund charge under-recovery - Electric
 —
 —
 —
 —
 —
 —

 Zero emission credit
 —
 —
 —
 —
 —
 —

 Other

 Total regulatory assets
 10,650
 3,721
 1,068
 1,893

 Less: current portion
 1,940
 1,159

 Total noncurrent regulatory assets
 $
 8,710
 $
 2,562
 $
 1,003
 $
 $
 1,570
 $
 $
 $

 ComEd
 PECO
 BGE
 PHI
 Pepco
 DPL
 ACE

 Decommissioning the Regulatory Agreement Units
 $
 4,027
 $
 3,780
 $
 $
 —
 $
 —
 $
 —
 $
 —
 $
 —

 Dedicated facilities charge
 —
 —
 —
 —
 —
 —

 2,756
 1,607
 —

 —
 —

 —
 —
 —
 —
 —
 —

 Fiber Refund
 —
 —
 —
 —
 —
 —

 —
 —
 —
 —
 —

 Over-recovered revenue decoupling
 —
 —
 —
 —
 —

 1,958
 1,841
 —
 —

 Renewable portfolio standards costs
 1,369
 1,369
 —
 —
 —
 —
 —
 —

 Transmission formula rate annual reconciliations
 —
 —
 —
 —
 —

 Other

 Total regulatory liabilities
 10,609
 8,618

 Less: current portion

 Total noncurrent regulatory liabilities
 $
 10,198
 $
 8,421
 $
 $
 $
 $
 $
 $

 ComEd
 PECO
 BGE
 PHI
 Pepco
 DPL
 ACE

 AMI programs - deployment costs
 $
 $
 —
 $
 —
 $
 $
 $
 $
 $

 AMI programs - legacy meters
 —

 Carbon mitigation credit
 —
 —
 —
 —
 —
 —

 COVID-19
 —

 DC PLUG charge
 —
 —
 —
 —
 —

 —
 —
 —
 —

 Deferred storm costs
 —
 —

 Electric distribution formula rate annual reconciliations
 —
 —
 —
 —
 —
 —

 Electric distribution formula rate significant one-time events
 —
 —
 —
 —
 —
 —

 —

 —

 Energy efficiency costs
 1,691
 1,691
 —
 —
 —
 —
 —
 —

 Fair value of long-term debt
 —
 —
 —
 —
 —
 —

 Fair value of PHI's unamortized energy contracts
 —
 —
 —
 —
 —
 —

 MGP remediation costs
 —
 —
 —
 —

 —
 —
 —
 —
 —
 —

 Pension and OPEB
 2,254
 —
 —
 —
 —
 —
 —
 —

 Pension and OPEB - merger related
 —
 —
 —
 —
 —
 —
 —

 —
 —

 Renewable energy
 —
 —
 —
 —
 —
 —

 Transmission formula rate annual reconciliations
 —

 Under-recovered credit loss expense
 —
 —
 —
 —

 Under-recovered revenue decoupling
 —
 —
 —

 Universal service fund charge under-recovery - Electric
 —
 —
 —
 —
 —
 —

 Zero emission credit
 —
 —
 —
 —
 —
 —

 Other

 Total regulatory assets
 10,913
 4,129
 1,924

 Less: current portion
 2,215
 1,335

 Total noncurrent regulatory assets
 $
 8,698
 $
 2,794
 $
 $
 $
 1,587
 $
 $
 $

 ComEd
 PECO
 BGE
 PHI
 Pepco
 DPL
 ACE

 Decommissioning the Regulatory Agreement Units
 $
 3,232
 $
 2,954
 $
 $
 —
 $
 —
 $
 —
 $
 —
 $
 —

 Dedicated facilities charge
 —
 —
 —
 —
 —
 —

 3,284
 1,900
 —

 —
 —

 —
 —
 —
 —
 —
 —

 Fiber Refund
 —
 —
 —
 —
 —
 —

 —
 —
 —
 —

 Over-recovered revenue decoupling
 —
 —
 —
 —
 —

 1,845
 1,701
 —
 —

 Renewable portfolio standards costs
 1,102
 1,102
 —
 —
 —
 —
 —
 —

 Other

 Total regulatory liabilities
 9,965
 7,684

 Less: current portion

 Total noncurrent regulatory liabilities
 $
 9,576
 $
 7,493
 $
 $
 $
 $
 $
 $

 Descriptions of the regulatory assets and liabilities included in the tables above are summarized below, including their recovery and amortization periods.

 AMI programs - deployment costs

 Represents installation and ongoing incremental costs of new smart meters, including implementation costs at Pepco and DPL of dynamic pricing for energy usage resulting from smart meters.
 BGE - 2026
 Pepco - 2029
 DPL - 2030
 ACE - 2029

 BGE, Pepco, DPL - Yes

 ACE - Yes, on incremental costs of new smart meters

 AMI programs - legacy meters
 Represents early retirement costs of legacy meters.
 ComEd - 2028
 BGE - 2026
 Pepco - 2029
 DPL - 2030
 ACE - To be determined in next distribution rate case filed with NJBPU.

 ComEd, Pepco (District of Columbia), DPL (Delaware), ACE - Yes
 BGE, Pepco (Maryland), DPL (Maryland) - No

 Represents future legally required removal costs associated with existing AROs.
 Over the life of the related assets.
 Yes, once the removal activities have been performed

 Carbon mitigation credit
 Represents CMC procurement costs and credits as well as reasonable costs ComEd has incurred to implement and comply with the CMC procurement process.
 2025
 No

 COVID-19
 Represents incremental credit losses and direct costs related to COVID-19 incurred primarily in 2020 at the Utility Registrants, partially offset by a decrease in travel costs at BGE, Pepco and DPL. Direct costs consisted primarily of costs to acquire personal protective equipment, costs for cleaning supplies and services, and costs to hire healthcare professionals to monitor the health of employees. This also includes under-recovered amounts due to COVID-19 that were previously deferred under Pepco's revenue decoupling program.
 ComEd - 2025

 BGE - 2028

 PECO - 2024

 Pepco (District of Columbia) - $ 42 million - 2034

 Pepco (Maryland) - $ 7 million - 2029

 DPL (Maryland) - $ 1 million - 2027

 DPL (Delaware) - $ 2 million - 2028

 ComEd, BGE, Pepco, and DPL (Maryland) - Yes

PECO and DPL (Delaware) - No

 DC PLUG charge

 Represents costs associated with DC PLUG, which is a projected six-year, $ 500 million project to place underground some of the District of Columbia's most outage-prone power lines with $ 250 million of the project costs funded by Pepco and $ 250 million funded by the District of Columbia. Rates for the DC PLUG initiative went into effect on February 7, 2018.

 2024
 Portion of asset funded by Pepco-Yes

 Decommissioning the Regulatory Agreement Units

 Represents estimated excess funds at the end of decommissioning the Regulatory Agreement Units. See below regarding Decommissioning the Regulatory Agreement Units for additional information.

 Not currently being refunded.

 No

 Dedicated facilities charge
 Represents the timing difference between the recovery of certain transmission-related assets and their depreciable life.
 Depreciable life of the related assets.
 Yes

 Represents deferred income taxes that are recoverable or refundable through customer rates, primarily associated with accelerated depreciation, the equity component of AFUDC, and the effects of income tax rate changes, including those resulting from the TCJA.

 Amounts are recoverable over the period in which the related deferred income taxes reverse, which is generally based on the expected life of the underlying assets. For TCJA, generally refunded over the remaining depreciable life of the underlying assets, except in certain jurisdictions where the commissions have approved a shorter refund period for certain assets not subject to IRS normalization rules.
 No

 Deferred storm costs
 For Pepco, DPL, ACE, PECO and BGE, amounts represent total incremental storm restoration costs incurred due to major storm events recoverable from customers in the Maryland, New Jersey jurisdictions and Pennsylvania.
 Pepco - $ 8 million to be determined in a future multi-year plan filed with MDPSC.

 DPL - 2027

 ACE - $ 4 million - 2026; $ 15 million to be determined in pending distribution rate case filed with NJBPU.

 PECO - $ 23 million to be determined in the next distribution rate case filed with the PAPUC.

 BGE - $ 46 million - 2028; $ 27 million to be determined in the next multi-year plan filed with MDPSC.

 Pepco, DPL, BGE - Yes

ACE, PECO - No

 Electric distribution formula rate annual reconciliations
 Represents under/(over)-recoveries related to electric distribution service costs recoverable through ComEd's performance-based formula rate, which was updated annually with rates effective on January 1st.

 2026
 Yes

 Electric distribution formula rate significant one-time events
 Represents deferred distribution service costs related to ComEd's significant one-time events (e.g., storm costs), which are recovered over 5 years from date of the event.
 2028
 Yes

 Represents under (over)-recoveries related to energy and gas supply related costs recoverable (refundable) under approved rate riders.
 ComEd, PECO, Pepco, DPL, ACE - 2025
 BGE - 2026

 DPL (Delaware), ACE - Yes
 ComEd, PECO, BGE, Pepco, DPL (Maryland) - No

 Includes under (over)-recoveries of costs incurred related to energy efficiency programs and demand response programs and recoverable costs associated with customer direct load control and energy efficiency and conservation programs that are being recovered from customers.

 PECO - 2025
 BGE - 2030
 Pepco, DPL - 2030
 ACE - 2032

 BGE, Pepco (Maryland), DPL (Maryland) - See above regarding EmPOWER Maryland Cost Recovery for additional information
 Pepco (District of Columbia) - No
 DPL (Delaware), ACE - Yes
 PECO - Yes on capital investment recovered through this mechanism

 Energy efficiency costs

 Represents ComEd's costs recovered through the energy efficiency formula rate tariff and the reconciliation of the difference of the revenue requirement in effect for the prior year and the revenue requirement based on actual prior year costs. Deferred energy efficiency costs are recovered over the weighted average useful life of the related energy measure.
 2036
 Yes

 Fair value of long-term debt

 Represents the difference between the carrying value and fair value of long-term debt of BGE, recorded at Exelon, and PHI of $ 95 million and $ 362 million, respectively, as of December 31, 2024, and $ 101 million and $ 385 million, respectively, as of December 31, 2023, as of the 2016 PHI and 2012 Constellation merger dates.

 Exelon - 2036
 PHI - 2045

 No

 Fair value of PHI's unamortized energy contracts

 Represents the regulatory assets recorded at Exelon and PHI offsetting the fair value adjustment related to Pepco's, DPL's, and ACE's electricity and natural gas energy supply contracts recorded at PHI as of the PHI merger date.
 2036
 No

 Fiber Refund
 Represents revenues collected from Generation and BSC for their use of PECO's fiber assets before the end of 2021.
 2025
 No

 MGP remediation costs

 Represents environmental remediation costs for MGP sites recorded at ComEd, PECO, and BGE.

 ComEd and PECO - Over the expected remediation period. See Note 18 — Commitments and Contingencies for additional information.

 BGE - 10 years from when the remediation spend occurs.

 ComEd and PECO - No

BGE - Yes

 Represents under (over)-recoveries related to electric and gas distribution multi-year plans.
 ComEd - 2027

 BGE - $ 13 million related to 2021 and 2022 reconciliations. $ 53 million related to 2023 and 2024 reconciliations - to be determined in a future MDPSC order.

 Pepco (Maryland) - $ 5 million related to 2023 reconciliation - 2026. $ 18 million related to 2024 reconciliation - to be determined in a future MDPSC order.

 DPL (Maryland) - $ 5 million related to 2023 reconciliation - 2025. $ 4 million related to 2024 reconciliation - to be determined in a future MDPSC order.

 ComEd - Yes

 BGE - No

 Pepco (Maryland) - No

 DPL (Maryland) - Yes

 Pension and OPEB
 Primarily reflects the Utility Registrants' and PHI's portion of deferred costs, including unamortized actuarial losses (gains) and prior service costs (credits), associated with Exelon's pension and OPEB plans, which are recovered through customer rates once amortized through net periodic benefit cost. Also, includes the Utility Registrants' and PHI's non–service cost components capitalized in Property, plant and equipment, net on their Consolidated Balance Sheets.
 The deferred costs are amortized over the plan participants' average remaining service periods subject to applicable pension and OPEB cost recognition policies. See Note 14 — Retirement Benefits for additional information. The capitalized non–service cost components are amortized over the lives of the underlying assets.

 No

 Pension and OPEB - merger related
 The deferred costs established at the date of the 2012 Constellation and 2016 PHI mergers are amortized over the plan participants' average remaining service periods subject to applicable pension and OPEB cost recognition policies. The costs are recovered through customer rates once amortized through net periodic benefit cost. See Note 14 — Retirement Benefits for additional information. The capitalized non–service cost components are amortized over the lives of the underlying assets.

 Legacy BGE - 2038
 Legacy PHI - 2032

 No

 For BGE, Pepco, DPL, and ACE, the regulatory asset represents costs incurred to remove property, plant and equipment in excess of amounts received from customers through depreciation rates. For ComEd, BGE, Pepco, and DPL, the regulatory liability represents amounts received from customers through depreciation rates to cover the future non–legally required cost to remove property, plant and equipment, which reduces rate base for ratemaking purposes.
 BGE, Pepco, DPL, and ACE - Asset is generally recovered over the life of the underlying assets.

 ComEd, BGE, Pepco, and DPL - Liability is reduced as costs are incurred.

 Yes

 Renewable energy
 Represents the change in fair value of ComEd's 20-year floating-to-fixed long-term renewable energy swap contracts.
 2032
 No

 Renewable portfolio standards costs
 Represents an overcollection of funds from both ComEd customers and alternative retail electricity suppliers to be spent on future renewable energy procurements.
 $ 1,296 million to be determined in pending ICC annual reconciliation for the Renewable Energy Adjustment rider.

 $ 73 million to be determined based on the LTRRPP developed by the IPA.

 No

 Transmission formula rate annual reconciliations
 Represents under (over)-recoveries related to transmission service costs recoverable through the Utility Registrants' FERC formula rates, which are updated annually with rates effective each June 1st.

 2026
 Yes

 Under (over) -recovered revenue decoupling

 Represents electric and / or gas distribution costs recoverable from or refundable to customers under decoupling mechanisms.
 BGE - 2026
 Pepco (Maryland) - $ 8 million - 2025
 Pepco (District of Columbia) - $ 52 million - 2028
 DPL - 2025
 ACE - 2026

 BGE, Pepco, DPL, ACE - No

 Under-recovered credit loss expense
 For ComEd and ACE, amounts represent the difference between annual credit loss expense and revenues collected in rates through ICC and NJBPU-approved riders. The difference between net credit loss expense and revenues collected through the rider each calendar year for ComEd is recovered over a twelve-month period beginning in June of the following calendar year. ACE intends to recover from June through May of each respective year, subject to approval of the NJBPU.
 ComEd - 2025

ACE - To be determined in pending Societal Benefits Rider filing with NJBPU.
 No

 Universal service fund charge under-recovery - Electric
 Represents under-recovery of electric supply and distribution revenue shortfalls net of base rate recovery related to PECO's Universal Service programs, which are designed to provide affordable bills for electric service to low-income, residential customers based on individual household needs.
 PECO - To be determined in the annual adjustment and reconciliation as approved by the PAPUC.
 No

 Zero emission credit
 Represents ZEC procurement costs and any reasonable costs ComEd has incurred to implement and comply with the ZEC procurement process.
 Over 9 months starting with the September billing period and ending with the following May billing period.
 No

 Decommissioning the Regulatory Agreement Units
 The regulatory agreements with the ICC and PAPUC dictate obligations related to the shortfall or excess of NDT funds necessary for decommissioning the former ComEd units on a unit-by-unit basis and the former PECO units in total.
 For the former PECO units, given the symmetric settlement provisions that allow for continued recovery of decommissioning costs from PECO customers in the event of a shortfall and the obligation for Constellation to ultimately return excess funds to PECO customers (on an aggregate basis for all seven units), decommissioning-related activities prior to separation on February 1, 2022 were generally offset in Exelon's Consolidated Statements of Operations and Comprehensive Income with an offsetting adjustment to the regulatory liabilities or regulatory assets and an equal noncurrent affiliate receivable from or payable to Generation at PECO. Following the separation, decommissioning-related activities result in an adjustment to the Receivable related to Regulatory Agreement Units and an equal adjustment to the regulatory liabilities or regulatory assets at PECO.
 For the former ComEd units, given no further recovery from ComEd customers is permitted and Constellation retains an obligation to ultimately return excess funds to ComEd customers (on a unit-by-unit basis), to the extent excess funds are expected for each unit, decommissioning-related activities prior to separation on February 1, 2022 were offset in the Consolidated Statements of Operations and Comprehensive Income with an offsetting adjustment to regulatory liabilities and noncurrent affiliate receivable from Generation at ComEd. Following the separation, decommissioning-related activities result in an adjustment to the Receivable related to Regulatory Agreement Units and an equal adjustment to the regulatory liabilities at ComEd. However, given the asymmetric settlement provision that does not allow for continued recovery from ComEd customers in the event of a shortfall, recognition of a regulatory asset at ComEd is not permissible.

 Capitalized Ratemaking Amounts Not Recognized
 The following table presents authorized amounts capitalized for ratemaking purposes related to earnings on shareholders' investment that are not recognized for financial reporting purposes in the Registrants' Consolidated Balance Sheets. These amounts will be recognized as revenues in the related Consolidated Statements of Operations and Comprehensive Income in the periods they are billable to the Utility Registrants' customers. PECO had no related amounts at December 31, 2024 and December 31, 2023

 ComEd(a)

 BGE(b)

 PHI
 Pepco(c)

 DPL(d)

 ACE(e)

 $
 $
 $
 $
 $
 $
 $

 $
 $
 $
 $
 $
 $
 $

 (a)Reflects ComEd's unrecognized equity returns earned for ratemaking purposes on its electric distribution rates and formula rates regulatory assets.
 (b)BGE's amount capitalized for ratemaking purposes primarily relates to earnings on shareholders' investment on AMI programs and investments in rate base included in the multi-year plan reconciliations.
 (c)Pepco's authorized amounts capitalized for ratemaking purposes relate to earnings on shareholders' investment on AMI programs, Energy efficiency and demand response programs, COVID-19, investments in rate base and revenues included in the multi-year plan reconciliations, and a portion of Pepco District of Columbia's revenue decoupling.
 (d)DPL's authorized amounts capitalized for ratemaking purposes relate to earnings on shareholders' investment on AMI programs and Energy efficiency and demand response programs.
 (e) ACE's authorized amounts capitalized for ratemaking purposes primarily relate to earnings on shareholders' investment on AMI programs.

 4. Revenue from Contracts with Customers (All Registrants)
 The Registrants recognize revenue from contracts with customers to depict the transfer of goods or services to customers at an amount that the entities expect to be entitled to in exchange for those goods or services. The primary sources of revenue include regulated electric and gas tariff sales, distribution, and transmission services. The performance obligations, revenue recognition, and payment terms associated with these sources of revenue are further discussed in the table below. There are no significant financing components for these sources of revenue and no variable consideration.
 Unless otherwise noted, for each of the significant revenue categories and related performance obligations described below, the Registrants have the right to consideration from the customer in an amount that corresponds directly with the value transferred to the customer for the performance completed to date. Therefore, the Registrants generally recognize revenue in the amount for which they have the right to invoice the customer. As a result, there are generally no significant judgments used in determining or allocating the transaction price.

 Note 4 — Revenue from Contracts with Customers

 Revenue Source
 Performance Obligation
 Timing of Revenue Recognition
 Payment Terms

 Regulated Electric and Gas Tariff Sales
 Sales of electricity and electricity distribution services (the Utility Registrants) and natural gas and gas distribution services (PECO, BGE, and DPL) to residential, commercial, industrial, and governmental customers through regulated tariff rates approved by state regulatory commissions.
 Delivery of electricity and/or natural gas.
 Over time (each day) as the electricity and/or natural gas is delivered to customers. Tariff sales are generally considered daily contracts as customers can discontinue service at any time. (a)

 Within the month following delivery of the electricity or natural gas to the customer.

 Regulated Transmission Services
 The Utility Registrants provide open access to their transmission facilities to PJM, which directs and controls the operation of these transmission facilities and accordingly compensates the Utility Registrants pursuant to filed tariffs at cost-based rates approved by FERC.
 Various including (i) Network Integration Transmission Services ("NITS"), (ii) scheduling, system control and dispatch services, and (iii) access to the wholesale grid.
 Over time utilizing output methods to measure progress towards completion. (b)

 Paid weekly by PJM.

 (a)Electric and natural gas utility customers have the choice to purchase electricity or natural gas from competitive electric generation and natural gas suppliers. While the Utility Registrants are required under state legislation to bill their customers for the supply and distribution of electricity and/or natural gas, they recognize revenue related only to the distribution services when customers purchase their electricity or natural gas from competitive suppliers.
 (b)Passage of time is used for NITS and access to the wholesale grid and MWhs of energy transported over the wholesale grid is used for scheduling, system control and dispatch services.
 The Utility Registrants do not incur any material costs to obtain or fulfill contracts with customers.
 Contract Liabilities
 The Registrants record contract liabilities when consideration is received or due prior to the satisfaction of the performance obligations. The Registrants record contract liabilities in Other current liabilities and Other noncurrent liabilities in the Registrants' Consolidated Balance Sheets.
 On July 1, 2020, Pepco, DPL, and ACE each entered into a collaborative arrangement ("Agreement") with an unrelated owner and manager of communication infrastructure (the "Buyer"). Under this arrangement, Pepco, DPL, and ACE sold a 60 % undivided interest in their respective portfolios of transmission tower attachment agreements with telecommunications companies to the Buyer, in addition to transitioning management of the day-to-day operations of the jointly-owned agreements to the Buyer for 35 years, while retaining the safe and reliable operation of its utility assets. In return, Pepco, DPL, and ACE will provide the Buyer limited access on the portion of the towers where the equipment resides for the purposes of managing the agreements for the benefit of Pepco, DPL, ACE, and the Buyer. Pursuant to the Agreement, Pepco, DPL, and ACE have the option ("Payment Option"), but not obligation, to sell two additional 10 % undivided interests in the tower attachment agreements to the Buyer for specified consideration. In addition, for an initial period of three years and two, two-year extensions that are subject to certain conditions, the Buyer has the exclusive right to enter into new agreements with telecommunications companies and to receive a specified undivided percentage interest in those new agreements as set forth in the Agreement. Pepco, DPL, and ACE received cash and recorded contract liabilities as of July 1, 2020. The revenue attributable to this arrangement will be recognized as Electric operating revenues over the 35 years under the Agreement.

 Note 4 — Revenue from Contracts with Customers

 During the fourth quarter of 2023, Pepco, DPL, and ACE entered into an amendment to the Agreement ("Amendment") to modify the terms of the Payment Option and the conditions to exercise the exclusive right extensions. Concurrently, Pepco, DPL and ACE exercised both Payment Options which also triggered the extension of the exclusive right period until 2027. The Amendment and executed Payment Options represent a contract modification that is accounted for prospectively in accordance with authoritative guidance. Pepco, DPL and ACE received cash and recorded an increase to the contract liabilities as of December 31, 2023 as shown in the table below. The revenue will be recognized as Electric operating revenues over the remaining term of the Agreement (approximately 31 years from the Amendment date).
 The following table provides a rollforward of the contract liabilities reflected in Exelon's, PHI's, Pepco's, DPL's, and ACE'S Consolidated Balance Sheets. As of December 31, 2024, 2023, and 2022, ComEd's, PECO's, and BGE's contract liabilities were not material.

 PHI(a)

 Pepco(a)

 DPL(a)

 ACE(a)

 $
 $
 $
 $
 $

 Consideration received

 Revenues recognized
 ( 7)
 ( 7)
 ( 5)
 ( 1)
 ( 1)

 $
 $
 $
 $
 $

 Revenues recognized
 ( 6)
 ( 6)
 ( 6)
 —
 —

 $
 $
 $
 $
 $

 (a) Revenues recognized in the years ended December 31, 2024 and 2023, were included in the contract liabilities at December 31, 2023 and 2022, respectively.
 Transaction Price Allocated to Remaining Performance Obligations
 The following table shows the amounts of future revenues expected to be recorded in each year for performance obligations that are unsatisfied or partially unsatisfied as of December 31, 2024. This disclosure only includes contracts for which the total consideration is fixed and determinable at contract inception. The average contract term varies by customer type and commodity but ranges from one month to several years.
 This disclosure excludes the Utility Registrants' gas and electric tariff sales contracts and transmission revenue contracts as they generally have an original expected duration of one year or less and, therefore, do not contain any future, unsatisfied performance obligations to be included in this disclosure.

 Year
 PHI
 Pepco
 DPL
 ACE

 2025
 $
 $
 $
 $
 $

 2026
 —

 2027
 —
 —

 2028
 —
 —

 2029 and thereafter

 Total
 $
 $
 $
 $
 $

 Revenue Disaggregation
 The Registrants disaggregate revenue recognized from contracts with customers into categories that depict how the nature, amount, timing, and uncertainty of revenue and cash flows are affected by economic factors. See Note 5 — Segment Information for the presentation of the Registrant's revenue disaggregation.

 5. Segment Information (All Registrants)
 Operating segments for each of the Registrants are determined based on information used by the CODMs in deciding how to evaluate performance and allocate resources at each of the Registrants. The Chief Executive Officer is the CODM for Exelon. For PHI and each of the Utility Registrants, CODM responsibilities are shared by Exelon's Chief Operating Officer and the Utility Registrant's Chief Executive Officer.

 Exelon has six reportable segments, which include ComEd, PECO, BGE, and PHI's three reportable segments consisting of Pepco, DPL, and ACE. ComEd, PECO, BGE, Pepco, DPL, and ACE each represent a single reportable segment, and as such, no separate segment information is provided for these Registrants. Exelon, ComEd, PECO, BGE, Pepco, DPL, and ACE's CODMs rely on a variety of business considerations, including net income, in evaluating segment performance, determining reinvestment of profits, and establishing the amounts of dividend distributions.
 The separation of Constellation Energy Corporation, including Generation and its subsidiaries, meets the criteria for discontinued operations and as such, results of operations are presented as discontinued operations and have been excluded from continuing operations for all periods presented. Furthermore, the reportable segment information related to the discontinued operations has been excluded from the tables presented below. See Note 2 — Discontinued Operations for additional information.
 An analysis and reconciliation of the Registrants' reportable segment information to the respective information in the consolidated financial statements for the years ended December 31, 2024, 2023, and 2022 is as follows:

 ComEd
 PECO
 BGE
 PHI

 Operating revenues(b):

 2024

 $
 8,219
 $
 3,325
 $
 3,436
 $
 6,258
 $
 —
 $
 ( 22)
 $
 21,216

 —
 —
 ( 6)
 1,812

 —
 —
 —
 1,865
 ( 1,875)
 —

 $
 8,219
 $
 3,973
 $
 4,426
 $
 6,448
 $
 1,865
 $
 ( 1,903)
 $
 23,028

 2023

 $
 7,844
 $
 3,202
 $
 3,109
 $
 5,812
 $
 —
 $
 ( 51)
 $
 19,916

 —
 —
 ( 4)
 1,811

 —
 —
 —
 1,759
 ( 1,768)
 —

 $
 7,844
 $
 3,894
 $
 4,027
 $
 6,026
 $
 1,759
 $
 ( 1,823)
 $
 21,727

 2022

 $
 5,761
 $
 3,165
 $
 2,871
 $
 5,317
 $
 —
 $
 ( 31)
 $
 17,083

 —
 1,024
 —
 ( 5)
 1,995

 —
 —
 —
 1,823
 ( 1,833)
 —

 $
 5,761
 $
 3,903
 $
 3,895
 $
 5,565
 $
 1,823
 $
 ( 1,869)
 $
 19,078

 Less:

 ComEd
 PECO
 BGE
 PHI

 2024
 $
 3,042
 $
 1,265
 $
 1,460
 $
 2,447
 $
 —
 $
 —
 $
 8,214

 2023
 2,816
 1,270
 1,311
 2,250
 —
 7,648

 2022
 1,050
 1,160
 1,186
 1,984
 —
 —
 5,380

 2024
 $
 —
 $
 $
 $
 $
 —
 $
 —
 $

 2023
 —
 —

 2022
 —
 —
 —

 Purchased power and fuel from affiliates

 2024
 $
 —
 $
 —
 $
 —
 $
 —
 $
 —
 $
 —
 $
 —

 2023
 —
 —
 —
 —
 —
 —
 —

 2022
 —
 ( 2)

 2024
 $
 1,284
 $
 $
 $
 1,046
 $
 1,733
 $
 ( 788)
 $
 4,940

 2023
 1,096
 1,110
 1,861
 ( 814)
 4,559

 2022
 1,094
 1,907
 ( 755)
 4,673

 2024
 $
 $
 $
 $
 $
 $
 ( 1,155)
 $
 —

 2023
 ( 1,008)
 —

 2022
 ( 1,005)
 —

 2024
 $
 1,514
 $
 $
 $
 $
 $
 —
 $
 3,594

 2023
 1,403
 —
 3,506

 2022
 1,323
 —
 3,325

 2024
 $
 $
 $
 $
 $
 $
 —
 $
 1,504

 2023
 —
 1,408

 2022
 —
 1,390

 (Gain) loss on sale of assets and businesses

 2024
 $
 ( 5)
 $
 ( 4)
 $
 —
 $
 $
 ( 4)
 $
 —
 $
 ( 12)

 2023
 —
 —
 —
 ( 9)
 ( 1)
 —
 ( 10)

 2022
 —
 —
 —
 —
 —

 Interest expense, net(c)

 2024
 $
 $
 $
 $
 $
 $
 —
 $
 1,889

 2023
 ( 2)
 1,704

 2022
 ( 3)
 1,422

 Interest expense to affiliates, net(c)

 2024
 $
 $
 $
 —
 $
 $
 ( 3)
 $
 —
 $

 2023
 —
 —

 2022
 —
 —
 ( 2)

 ComEd
 PECO
 BGE
 PHI

 2024
 $
 ( 94)
 $
 ( 37)
 $
 ( 36)
 $
 ( 97)
 $
 ( 38)
 $
 $
 ( 262)

 2023
 ( 75)
 ( 36)
 ( 18)
 ( 108)
 ( 190)
 ( 408)

 2022
 ( 54)
 ( 31)
 ( 21)
 ( 78)
 ( 290)
 ( 61)
 ( 535)

 2024
 $
 $
 ( 12)
 $
 $
 $
 ( 135)
 $
 —
 $

 2023
 ( 207)
 ( 2)

 2022
 —
 ( 11)

 Net income (loss) from continuing operations

 2024
 $
 1,066
 $
 $
 $
 $
 ( 425)
 $
 —
 $
 2,460

 2023
 1,090
 ( 380)
 ( 20)
 2,328

 2022
 ( 393)
 ( 34)
 2,054

 Supplemental segment information

 Intersegment revenues(d)

 2024
 $
 $
 $
 $
 $
 1,855
 $
 ( 1,893)
 $
 —

 2023
 1,750
 ( 1,793)
 —

 2022
 1,823
 ( 1,865)

 2024
 $
 2,195
 $
 1,553
 $
 1,420
 $
 1,863
 $
 $
 —
 $
 7,097

 2023
 2,576
 1,426
 1,367
 1,988
 —
 7,411

 2022
 2,506
 1,349
 1,262
 1,709
 —
 6,921

 2024
 $
 44,750
 $
 17,123
 $
 15,542
 $
 28,297
 $
 6,012
 $
 ( 3,940)
 $
 107,784

 2023
 42,827
 15,595
 14,331
 27,066
 6,374
 ( 4,337)
 101,856

 (a)Other primarily includes Exelon's corporate operations, shared service entities, and other financing and investment activities.
 (b)Includes gross utility tax receipts from customers. The offsetting remittance of utility taxes to the governing bodies is recorded in Taxes other than income taxes in the Registrants' Consolidated Statements of Operations and Comprehensive Income. See Note 22 — Supplemental Financial Information for additional information on total utility taxes.
 (c)Interest expense, net and Interest expense to affiliates, net are primarily inclusive of Interest expense, which is partially offset by an immaterial amount of interest income.
 (d)See Note 23 — Related Party Transactions for additional information on intersegment revenues.

 PHI:

 Pepco
 DPL
 ACE

 PHI

 Operating revenues(b):

 2024

 $
 3,039
 $
 1,607
 $
 1,628
 $
 —
 $
 ( 16)
 $
 6,258

 —
 —
 —
 —

 —
 —
 —
 ( 428)

 $
 3,039
 $
 1,787
 $
 1,628
 $
 $
 ( 444)
 $
 6,448

 2023

 $
 2,824
 $
 1,483
 $
 1,522
 $
 $
 ( 18)
 $
 5,812

 —
 —
 —
 —

 —
 —
 —
 ( 413)

 $
 2,824
 $
 1,688
 $
 1,522
 $
 $
 ( 431)
 $
 6,026

 2022

 $
 2,531
 $
 1,357
 $
 1,431
 $
 —
 $
 ( 2)
 $
 5,317

 —
 —
 —
 —

 —
 —
 —
 ( 381)

 $
 2,531
 $
 1,595
 $
 1,431
 $
 $
 ( 383)
 $
 5,565

 Less:

 2024
 $
 1,055
 $
 $
 $
 —
 $
 —
 $
 2,447

 2023
 —
 —
 2,250

 2022
 —
 —
 1,984

 2024
 $
 —
 $
 $
 —
 $
 —
 $
 —
 $

 2023
 —
 —
 —
 —

 2022
 —
 —
 —
 —

 Purchased power and fuel from affiliates

 2024
 $
 —
 $
 —
 $
 —
 $
 —
 $
 —
 $
 —

 2023
 —
 —
 —
 —
 —
 —

 2022
 —
 —

 2024
 $
 $
 $
 $
 $
 —
 $
 1,046

 2023
 —
 1,110

 2022
 —

 2024
 $
 $
 $
 $
 $
 ( 444)
 $

 2023
 ( 431)

 2022
 ( 383)

 2024
 $
 $
 $
 $
 $
 —
 $

 2023
 —

 Pepco
 DPL
 ACE

 PHI

 2022
 —

 2024
 $
 $
 $
 $
 $
 —
 $

 2023
 —

 2022
 —

 Loss (gain) on sale of assets and businesses

 2024
 $
 $
 —
 $
 —
 $
 —
 $
 —
 $

 2023
 ( 9)
 —
 —
 —
 —
 ( 9)

 2022
 —
 —
 —
 —
 —
 —

 Interest expense, net(c)

 2024
 $
 $
 $
 $
 $
 —
 $

 2023
 —

 2022

 Interest expense to affiliates, net(c)

 2024
 $
 ( 3)
 $
 ( 1)
 $
 $
 $
 —
 $

 2023
 —
 —
 —
 —
 —
 —

 2022
 —
 —
 —
 —
 —
 —

 2024
 $
 ( 54)
 $
 ( 25)
 $
 ( 14)
 $
 ( 4)
 $
 —
 $
 ( 97)

 2023
 ( 66)
 ( 18)
 ( 20)
 ( 4)
 —
 ( 108)

 2022
 ( 55)
 ( 13)
 ( 11)
 ( 1)
 ( 78)

 2024
 $
 $
 $
 $
 ( 5)
 $
 —
 $

 2023
 ( 6)
 —

 2022
 ( 9)
 —

 Net income (loss) from continuing operations

 2024
 $
 $
 $
 $
 ( 13)
 $
 —
 $

 2023
 ( 13)
 —

 2022
 ( 14)
 —

 Supplemental segment information

 Intersegment revenues(d)

 2024
 $
 $
 $
 $
 $
 ( 444)
 $

 2023
 ( 432)

 2022
 ( 383)

 2024
 $
 $
 $
 $
 $
 —
 $
 1,863

 2023
 —
 1,988

 2022
 —
 1,709

 2024
 $
 12,000
 $
 6,421
 $
 5,349
 $
 4,567
 $
 ( 40)
 $
 28,297

 2023
 11,330
 5,993
 5,157
 4,627
 ( 41)
 27,066

 (a)Other primarily includes PHI's corporate operations, shared service entities, and other financing and investment activities.
 (b)Includes gross utility tax receipts from customers. The offsetting remittance of utility taxes to the governing bodies is recorded in Taxes other than income taxes in the Registrants' Consolidated Statements of Operations and Comprehensive Income. See Note 22 — Supplemental Financial Information for additional information on total utility taxes.
 (c)Interest expense, net is primarily inclusive of Interest expense, which is partially offset by an immaterial amount of Interest income.
 (d)Includes intersegment revenues with ComEd, PECO, and BGE, which are eliminated at Exelon.

 Electric and Gas Revenue by Customer Class (Utility Registrants):
 The following tables disaggregate the Registrants' revenues recognized from contracts with customers into categories that depict how the nature, amount, timing, and uncertainty of revenue and cash flows are affected by economic factors. For the Utility Registrants, the disaggregation of revenues reflects the two primary utility services of electric sales and natural gas sales (where applicable), with further disaggregation of these tariff sales provided by major customer groups. Exelon's disaggregated revenues are consistent with the Utility Registrants, but exclude any intercompany revenues.

 2024

 Revenues from contracts with customers
 ComEd
 PECO
 BGE
 PHI
 Pepco
 DPL
 ACE

 $
 3,809
 $
 2,169
 $
 2,038
 $
 3,256
 $
 1,413
 $
 $

 2,259

 1,145
 1,372
 1,053

 1,080

 Total electric revenues(b)

 $
 8,353
 $
 3,302
 $
 3,400
 $
 6,254
 $
 3,014
 $
 1,606
 $
 1,640

 $
 —
 $
 $
 $
 $
 —
 $
 $
 —

 —
 —
 —

 —
 —
 —
 —

 —
 —
 —
 —

 Other(c)

 —
 —
 —

 Total natural gas revenues(d)

 $
 —
 $
 $
 $
 $
 —
 $
 $
 —

 Total revenues from contracts with customers
 $
 8,353
 $
 3,948
 $
 4,357
 $
 6,434
 $
 3,014
 $
 1,786
 $
 1,640

 Other revenues

 $
 ( 151)
 $
 $
 $
 $
 $
 ( 2)
 $
 ( 12)

 Other electric revenues(e)

 —

 Other natural gas revenues(e)

 —
 —
 —
 —
 —

 Total other revenues
 $
 ( 134)
 $
 $
 $
 $
 $
 $
 ( 12)

 Total revenues for reportable segments
 $
 8,219
 $
 3,973
 $
 4,426
 $
 6,448
 $
 3,039
 $
 1,787
 $
 1,628

 2023

 Revenues from contracts with customers
 ComEd
 PECO
 BGE
 PHI
 Pepco
 DPL
 ACE

 $
 3,565
 $
 2,090
 $
 1,765
 $
 2,845
 $
 1,236
 $
 $

 1,857

 1,420
 1,087

 Total electric revenues(b)

 $
 7,262
 $
 3,193
 $
 3,055
 $
 5,743
 $
 2,791
 $
 1,465
 $
 1,495

 $
 —
 $
 $
 $
 $
 —
 $
 $
 —

 —
 —
 —

 —
 —
 —

 —
 —
 —
 —

 Other(c)

 —
 —
 —

 Total natural gas revenues(d)

 $
 —
 $
 $
 $
 $
 —
 $
 $
 —

 Total revenues from contracts with customers
 $
 7,262
 $
 3,883
 $
 3,921
 $
 5,948
 $
 2,791
 $
 1,670
 $
 1,495

 Other revenues

 $
 $
 ( 7)
 $
 $
 $
 $
 $

 Other electric revenues(e)

 —

 Other natural gas revenues(e)

 —
 —
 —
 —
 —

 Total other revenues
 $
 $
 $
 $
 $
 $
 $

 Total revenues for reportable segments
 $
 7,844
 $
 3,894
 $
 4,027
 $
 6,026
 $
 2,824
 $
 1,688
 $
 1,522

 2022

 Revenues from contracts with customers
 ComEd
 PECO
 BGE
 PHI
 Pepco
 DPL
 ACE

 $
 3,304
 $
 2,026
 $
 1,564
 $
 2,590
 $
 1,076
 $
 $

 1,173

 1,422
 1,083

 Total electric revenues(b)

 $
 5,466
 $
 3,147
 $
 2,883
 $
 5,378
 $
 2,556
 $
 1,364
 $
 1,450

 $
 —
 $
 $
 $
 $
 —
 $
 $
 —

 —
 —
 —

 —
 —
 —
 —

 —
 —
 —
 —

 Other(c)

 —
 —
 —

 Total natural gas revenues(d)

 $
 —
 $
 $
 1,040
 $
 $
 —
 $
 $
 —

 Total revenues from contracts with customers
 $
 5,466
 $
 3,883
 $
 3,923
 $
 5,616
 $
 2,556
 $
 1,602
 $
 1,450

 Other revenues

 $
 $
 $
 ( 47)
 $
 ( 59)
 $
 ( 31)
 $
 ( 9)
 $
 ( 19)

 Other electric revenues(e)

 —

 Other natural gas revenues(e)

 —
 —
 —
 —
 —

 Total other revenues
 $
 $
 $
 ( 28)
 $
 ( 51)
 $
 ( 25)
 $
 ( 7)
 $
 ( 19)

 Total revenues for reportable segments
 $
 5,761
 $
 3,903
 $
 3,895
 $
 5,565
 $
 2,531
 $
 1,595
 $
 1,431

 (a)Includes transmission revenue from PJM, wholesale electric revenue and mutual assistance revenue.
 (b)Includes operating revenues from affiliates in 2024, 2023, and 2022 respectively of:
 •$ 8 million, $ 16 million, and $ 16 million at ComEd
 •$ 7 million, $ 7 million, and $ 7 million at PECO
 •$ 7 million, $ 6 million, and $ 7 million at BGE
 •$ 10 million, $ 9 million, and $ 10 million at PHI
 •$ 7 million, $ 9 million, and $ 5 million at Pepco
 •$ 7 million, $ 8 million, and $ 6 million at DPL
 •$ 2 million, $ 2 million, and $ 2 million at ACE
 (c)Includes revenues from off-system natural gas sales.
 (d)Includes operating revenues from affiliates in 2024, 2023, and 2022 respectively of:
 •$ 3 million, $ 2 million, and less than $1 million at PECO
 •$ 3 million, $ 3 million, and $ 8 million at BGE
 (e)Includes late payment charge revenues.

 6. Accounts Receivable (All Registrants)
 Allowance for Credit Losses on Accounts Receivable
 The following tables present the rollforward of Allowance for Credit Losses on Customer Accounts Receivable.

 Year Ended December 31, 2024

 ComEd
 PECO
 BGE
 PHI
 Pepco
 DPL
 ACE

 $
 $
 $
 $
 $
 $
 $
 $

 Plus: Current period provision for expected credit losses(a)(b)

 Less: Write-offs(c)(d)(e), net of recoveries(f)

 $
 $
 $
 $
 $
 $
 $
 $

 Year Ended December 31, 2023

 ComEd
 PECO
 BGE
 PHI
 Pepco
 DPL
 ACE

 $
 $
 $
 $
 $
 $
 $
 $

 Plus: Current period provision for expected credit losses

 Less: Write-offs, net of recoveries

 $
 $
 $
 $
 $
 $
 $
 $

 (a)For PECO and ComEd, the increase is primarily a result of increased aging of receivables.
 (b)For BGE and Pepco, the increase is primarily a result of changes in customer risk profile and increased receivable balances.
 (c)For PECO, the decrease is primarily a result of decreased disconnection activities.
 (d)For BGE, the decrease is primarily a result of increased collection activities.
 (e)For Pepco, the increase is primarily attributable to unfavorable customer payment behavior.
 (f)Recoveries were not material to the Registrants.

 Note 6 — Accounts Receivable

 The following tables present the rollforward of Allowance for Credit Losses on Other Accounts Receivable.

 Year Ended December 31, 2024

 ComEd
 PECO
 BGE
 PHI
 Pepco
 DPL
 ACE

 $
 $
 $
 $
 $
 $
 $
 $

 Plus: Current period provision (benefit) for expected credit losses(a)(b)

 ( 1)

 Less: Write-offs, net of recoveries(c)

 —
 —

 $
 $
 $
 $
 $
 $
 $
 $

 Year Ended December 31, 2023

 ComEd
 PECO
 BGE
 PHI
 Pepco
 DPL
 ACE

 $
 $
 $
 $
 $
 $
 $
 $

 Plus: Current period provision for expected credit losses

 Less: Write-offs, net of recoveries
 —
 —

 $
 $
 $
 $
 $
 $
 $
 $

 (a)For PECO and ComEd, the increase is primarily a result of increased aging of receivables.
 (b)For Pepco, the decrease is primarily a result of decreased aging of receivables.
 (c)Recoveries were not material to the Registrants.
 Unbilled Customer Revenue
 The following table provides additional information about unbilled customer revenues recorded in the Registrants' Consolidated Balance Sheets as of December 31, 2024 and 2023.

 Unbilled customer revenues(a)

 ComEd
 PECO
 BGE
 PHI
 Pepco
 DPL
 ACE

 $
 1,114
 $
 $
 $
 $
 $
 $
 $

 (a)Unbilled customer revenues are classified in Customer accounts receivables, net in the Registrants' Consolidated Balance Sheets.
 Other Purchases of Customer and Other Accounts Receivables
 For the twelve months ended December 31, 2024 and 2023, the Utility Registrants were required, under separate legislation and regulations in Illinois, Pennsylvania, Maryland, District of Columbia, and New Jersey, to purchase certain receivables from alternative retail electric and, as applicable, natural gas suppliers that participated in the utilities' consolidated billing. The following table presents the total receivables purchased.

 Total receivables purchased

 ComEd
 PECO
 BGE
 PHI
 Pepco
 DPL
 ACE

 Year ended December 31, 2024
 $
 4,128
 $
 $
 1,111
 $
 $
 1,275
 $
 $
 $

 Year ended December 31, 2023
 4,056
 1,099
 1,211

 Note 7 — Property, Plant, and Equipment

 7. Property, Plant, and Equipment (All Registrants)
 The following tables present a summary of property, plant, and equipment by asset category at December 31, 2024 and 2023:

 Asset Category
 ComEd
 PECO
 BGE
 PHI
 Pepco
 DPL
 ACE

 $
 79,283
 $
 36,493
 $
 12,234
 $
 11,131
 $
 21,130
 $
 13,593
 $
 6,086
 $
 5,947

 9,599
 —
 4,247
 4,796
 —
 —

 2,630
 —
 1,064
 1,385
 —
 —

 4,306
 1,219
 1,472
 1,002

 Other property, plant, and equipment(a)

 Total property, plant, and equipment
 96,627
 37,830
 18,434
 18,139
 23,781
 14,619
 7,615
 6,164

 Less: accumulated depreciation
 18,445
 7,619
 4,042
 5,005
 3,728
 4,522
 2,075
 1,798

 Property, plant, and equipment, net
 $
 78,182
 $
 30,211
 $
 14,392
 $
 13,134
 $
 20,053
 $
 10,097
 $
 5,540
 $
 4,366

 $
 74,102
 $
 34,834
 $
 11,295
 $
 10,537
 $
 19,153
 $
 12,429
 $
 5,590
 $
 5,659

 8,818
 —
 3,905
 4,428
 —
 —

 2,510
 —
 1,083
 1,275
 —
 —

 4,589
 1,369
 1,762
 1,226

 Other property, plant and equipment(a)

 Total property, plant and equipment
 90,844
 36,310
 17,225
 16,846
 22,026
 13,714
 7,090
 5,876

 Less: accumulated depreciation
 17,251
 7,222
 4,097
 4,744
 3,175
 4,284
 1,925
 1,684

 Property, plant, and equipment, net
 $
 73,593
 $
 29,088
 $
 13,128
 $
 12,102
 $
 18,851
 $
 9,430
 $
 5,165
 $
 4,192

 (a)Primarily composed of land and non-utility property.

 Note 7 — Property, Plant, and Equipment

 The following table presents the average service life for each asset category in number of years:

 Average Service Life (years)

 Asset Category
 ComEd
 PECO
 BGE
 PHI
 Pepco
 DPL
 ACE

 Electric - transmission and distribution
 5-80
 5-80
 5-70
 5-80
 5-75
 5-75
 5-75
 5-75

 Gas - transportation and distribution
 5-80
 N/A
 5-70
 5-80
 5-75
 N/A
 5-75
 N/A

 Common - electric and gas
 4-75
 N/A
 5-55
 4-50
 5-75
 N/A
 5-75
 N/A

 Other property, plant, and equipment
 4-61
 29-50
 20-50
 10-43
 10-33
 10-43
 10-43

 The following table presents the annual depreciation rates for each asset category.

 Annual Depreciation Rates

 ComEd
 PECO
 BGE
 PHI
 Pepco
 DPL
 ACE

 2.83 %
 3.06 %
 2.30 %
 2.55 %
 2.87 %
 2.49 %
 2.99 %
 3.41 %

 2.12 %
 N/A
 1.96 %
 2.42 %
 1.38 %
 N/A
 1.38 %
 N/A

 7.00 %
 N/A
 6.73 %
 7.81 %
 4.82 %
 N/A
 6.14 %
 N/A

 2.90 %
 3.02 %
 2.30 %
 2.89 %
 3.03 %
 2.51 %
 3.29 %
 3.66 %

 2.15 %
 N/A
 1.85 %
 2.56 %
 1.44 %
 N/A
 1.44 %
 N/A

 7.77 %
 N/A
 6.87 %
 8.68 %
 7.18 %
 N/A
 8.79 %
 N/A

 December 31, 2022

 2.87 %
 3.00 %
 2.29 %
 2.82 %
 2.96 %
 2.58 %
 3.08 %
 3.38 %

 2.14 %
 N/A
 1.87 %
 2.53 %
 1.45 %
 N/A
 1.45 %
 N/A

 7.54 %
 N/A
 6.31 %
 8.20 %
 8.96 %
 N/A
 10.03 %
 N/A

 AFUDC
 The following table summarizes credits to AFUDC by year:

 2024
 2023
 2022

 $
 $
 $

 ComEd

 PECO

 BGE

 PHI

 Pepco

 DPL

 ACE

 See Note 1 — Significant Accounting Policies for additional information regarding property, plant and equipment policies. See Note 16 — Debt and Credit Agreements for additional information regarding Exelon's, ComEd's, PECO's, Pepco's, DPL's, and ACE's property, plant and equipment subject to mortgage liens.

 Note 8 — Jointly Owned Electric Utility Plant

 8. Jointly Owned Electric Utility Plant (Exelon, PECO, PHI, DPL, and ACE)
 PECO's, DPL's, and ACE's material undivided ownership interests in transmission facilities jointly owned with non-affiliated utilities as of December 31, 2024 and 2023 were as follows:

 NJ/DE(a)

 Operator
 PSEG/DPL

 Ownership interest
 various

 Exelon's share at December 31, 2024:

 Plant in service
 $

 Accumulated depreciation

 Exelon's share at December 31, 2023:

 Plant in service
 $

 Accumulated depreciation

 (a)PECO, DPL, and ACE own a 42.55 %, 1 %, and 13.9 % share, respectively, in 151.3 miles of 500kV lines located in New Jersey and in the Salem substation. PECO, DPL, and ACE also own a 42.55 %, 7.45 %, and 7.45 % share, respectively, in 2.5 miles of 500kV line located over the Delaware River. ACE also has a 21.78 % share in a 500kV New Freedom Switching substation.
 Certain facilities are fully owned by Exelon through its 100 % ownership in PECO, DPL, and ACE. These facilities are operated by Exelon Registrants. PECO's, DPL's, and ACE's material undivided ownership interests in Exelon owned facilities as of December 31, 2024 and 2023 were as follows:

 PECO
 PHI
 DPL
 ACE

 Ownership interest
 %
 %
 %
 %

 Registrant's share at December 31, 2024:

 Plant in service
 $
 $
 $
 $

 Accumulated depreciation
 —

 —
 —
 —
 —

 Registrant's share at December 31, 2023:

 Plant in service
 $
 $
 $
 $

 Accumulated depreciation
 —
 —
 —
 —

 PECO's, DPL's, and ACE's undivided ownership interests presented in the tables above are financed with their funds and all operations are accounted for as if such participating interests were wholly owned facilities. PECO's, DPL's, and ACE's share of direct expenses of the jointly owned plants are included in Operating and maintenance expenses in Exelon's, PECO's, PHI's, DPL's, and ACE's Consolidated Statements of Operations and Comprehensive Income.

 Note 9 — Asset Retirement Obligations

 9. Asset Retirement Obligations (All Registrants)
 The Registrants have AROs primarily associated with the abatement and disposal of equipment and buildings contaminated with asbestos and PCBs. See Note 1 — Significant Accounting Policies for additional information on the Registrants' accounting policy for AROs.
 The following table provides a rollforward of the AROs reflected in the Registrants' Consolidated Balance Sheets from December 31, 2022 to December 31, 2024:

 ComEd
 PECO
 BGE
 PHI
 Pepco
 DPL
 ACE

 AROs at December 31, 2022
 $
 $
 $
 $
 $
 $
 $
 $

 Revisions in estimates of cash flows
 ( 9)
 ( 3)
 ( 1)
 ( 6)
 ( 4)
 ( 1)
 ( 1)

 Accretion expense(a)

 —

 Payments
 ( 4)
 ( 3)
 ( 1)
 —
 —
 —
 —
 —

 AROs at December 31, 2023
 $
 $
 $
 $
 $
 $
 $
 $

 Revisions in estimates of cash flows
 —
 —

 Accretion expense(a)

 —
 —

 Payments
 ( 2)
 ( 1)
 ( 1)
 —
 —
 —
 —
 —

 AROs at December 31, 2024
 $
 $
 $
 $
 $
 $
 $
 $

 (a)For ComEd, PECO, BGE, DPL and ACE, the majority of the accretion is recorded as an increase to a regulatory asset due to the associated regulatory treatment.

 10. Leases (All Registrants)
 Lessee
 The Registrants have operating and finance leases for which they are the lessees. The following tables outline the significant types of leases at each of the Registrants and other terms and conditions of the lease agreements as of December 31, 2024. Exelon, ComEd, PECO, and BGE did not have material finance leases in 2024, 2023, or 2022.

 ComEd
 PECO
 BGE

 PHI
 Pepco
 DPL
 ACE

 Real estate

 Vehicles and equipment

 (in years)

 ComEd
 PECO
 BGE
 PHI
 Pepco
 DPL
 ACE

 Remaining lease terms
 1-81
 1-28
 1-9
 1-81
 1-7
 1-7
 1-7
 1-7

 Options to extend the term
 3-30
 N/A
 N/A
 3-5
 3-30
 3-30

 Options to terminate within
 3-8
 N/A
 N/A
 N/A
 N/A
 N/A
 N/A

 The components of operating lease costs were as follows:

 ComEd
 PECO
 BGE
 PHI
 Pepco
 DPL
 ACE

 Operating lease costs
 $
 $
 —
 $
 —
 $
 $
 $
 $
 $

 Variable lease costs
 —
 —
 —

 Total lease costs(a)

 $
 $
 —
 $
 —
 $
 $
 $
 $
 $

 Operating lease costs
 $
 $
 $
 —
 $
 $
 $
 $
 $

 Variable lease costs
 —
 —

 Total lease costs(a)

 $
 $
 $
 —
 $
 $
 $
 $
 $

 Operating lease costs
 $
 $
 $
 —
 $
 $
 $
 $
 $

 Variable lease costs
 —
 —

 Total lease costs(a)

 $
 $
 $
 —
 $
 $
 $
 $
 $

 (a)Excludes sublease income recorded at Exelon, PHI, and DPL of $ 4 million for the years ended December 31, 2024, 2023, and 2022.
 The components of financing lease costs were as follows:

 PHI
 Pepco
 DPL
 ACE

 Amortization of ROU asset
 $
 $
 $
 $

 Interest on lease liabilities

 Total finance lease cost
 $
 $
 $
 $

 Amortization of ROU asset
 $
 $
 $
 $

 Interest on lease liabilities

 Total finance lease cost
 $
 $
 $
 $

 Amortization of ROU asset
 $
 $
 $
 $

 Interest on lease liabilities

 Total finance lease cost
 $
 $
 $
 $

 The following tables provide additional information regarding the presentation of operating and finance lease ROU assets and lease liabilities within the Registrants' Consolidated Balance Sheets:

 ComEd
 PECO
 BGE
 PHI
 Pepco
 DPL
 ACE

 Operating lease ROU assets

 Other deferred debits and other assets
 $
 $
 —
 $
 —
 $
 $
 $
 $
 $

 Operating lease liabilities

 Other current liabilities
 $
 $
 —
 $
 —
 $
 $
 $
 $
 $

 Other deferred credits and other liabilities
 —
 —

 Total operating lease liabilities
 $
 $
 —
 $
 —
 $
 $
 $
 $
 $

 Operating lease ROU assets

 Other deferred debits and other assets
 $
 $
 —
 $
 $
 $
 $
 $
 $

 Operating lease liabilities

 Other current liabilities
 $
 $
 —
 $
 —
 $
 $
 $
 $
 $

 Other deferred credits and other liabilities
 —
 —

 Total operating lease liabilities
 $
 $
 —
 $
 —
 $
 $
 $
 $
 $

 PHI
 Pepco
 DPL
 ACE

 Finance lease ROU assets

 Plant, property and equipment, net
 $
 $
 $
 $

 Finance lease liabilities

 $
 $
 $
 $

 Total finance lease liabilities
 $
 $
 $
 $

 Finance lease ROU assets

 Plant, property and equipment, net
 $
 $
 $
 $

 Finance lease liabilities

 $
 $
 $
 $

 Total finance lease liabilities
 $
 $
 $
 $

 Future minimum lease payments for operating and finance leases as of December 31, 2024 were as follows:

 Year

 ComEd
 PECO
 BGE
 PHI
 Pepco
 DPL
 ACE

 2025
 $
 $
 —
 $
 —
 $
 $
 $
 $
 $

 2026
 —
 —

 2027
 —
 —

 2028
 —
 —

 2029
 —
 —

 Remaining years
 —
 —
 —

 Total
 —
 —

 Interest
 —
 —

 Total operating lease liabilities
 $
 $
 —
 $
 —
 $
 $
 $
 $
 $

 Year
 PHI
 Pepco
 DPL
 ACE

 2025
 $
 $
 $
 $

 2026

 2027

 2028

 2029

 Remaining years

 Total

 Interest

 Total finance lease liabilities
 $
 $
 $
 $

 The weighted average remaining lease terms, in years, for operating and finance leases were as follows:

 ComEd
 PECO
 BGE
 PHI
 Pepco
 DPL
 ACE

 8.2
 1.7
 5.3
 17.4
 5.3
 7.1
 6.9
 3.1

 8.8
 1.8
 5.0
 17.1
 6.1
 7.6
 7.4
 3.2

 PHI
 Pepco
 DPL
 ACE

 4.4
 4.4
 4.2
 4.5

 4.9
 4.9
 4.8
 5.1

 The weighted average discount rates for operating and finance leases were as follows:

 ComEd
 PECO
 BGE
 PHI
 Pepco
 DPL
 ACE

 4.0
 %
 0.8
 %
 2.8
 %
 5.0
 %
 4.2
 %
 4.1
 %
 4.1
 %
 3.9
 %

 4.0
 %
 0.7
 %
 2.5
 %
 5.0
 %
 4.2
 %
 4.1
 %
 4.0
 %
 3.6
 %

 PHI
 Pepco
 DPL
 ACE

 3.4
 %
 3.5
 %
 3.1
 %
 3.5
 %

 2.7
 %
 2.7
 %
 2.6
 %
 2.8
 %

 Cash paid for amounts included in the measurement of operating and finance lease liabilities were as follows:

 Operating Cash Flows from Operating Leases

 ComEd
 PECO
 BGE
 PHI
 Pepco
 DPL
 ACE

 $
 $
 —
 $
 —
 $
 $
 $
 $
 $

 —

 —

 Financing Cash Flows from Finance Leases

 PHI
 Pepco
 DPL
 ACE

 $
 $
 $
 $

 ROU assets obtained in exchange for operating and finance lease obligations were as follows:

 ComEd
 PECO
 BGE
 PHI
 Pepco
 DPL
 ACE

 $
 $
 —
 $
 —
 $
 $
 $
 $
 $

 —
 —
 —

 —
 —
 —
 —

 PHI
 Pepco
 DPL
 ACE

 $
 $
 $
 $

 Lessor
 The Registrants have operating leases for which they are the lessors. The following tables outline the significant types of leases at each of the Registrants and other terms and conditions of their lease agreements as of December 31, 2024. ACE did not have any operating leases for which they are the lessors for the years ended December 31, 2024, 2023, and 2022.

 ComEd
 PECO
 BGE
 PHI
 Pepco
 DPL

 Real estate

 (in years)

 ComEd
 PECO
 BGE
 PHI
 Pepco
 DPL

 Remaining lease terms
 1-78
 1-12
 1-78
 1-8
 7-8

 Options to extend the term
 5-79
 5-79
 5-50
 N/A
 N/A
 N/A
 N/A

 The components of lease income were as follows:

 ComEd
 PECO
 BGE
 PHI
 Pepco
 DPL

 Operating lease income
 $
 $
 —
 $
 —
 $
 —
 $
 $
 —
 $

 Variable lease income
 —
 —
 —
 —

 Operating lease income
 $
 $
 —
 $
 —
 $
 —
 $
 $
 —
 $

 Variable lease income
 —
 —
 —
 —

 Operating lease income
 $
 $
 —
 $
 —
 $
 —
 $
 $
 —
 $

 Variable lease income
 —
 —
 —
 —

 Future minimum lease payments to be recovered under operating leases as of December 31, 2024 were as follows:

 Year

 ComEd
 PECO
 BGE
 PHI
 Pepco
 DPL

 2025
 $
 $
 $
 $
 —
 $
 $
 —
 $

 2026
 —
 —
 —

 2027
 —
 —
 —
 —

 2028
 —
 —
 —
 —

 2029
 —
 —
 —
 —

 Remaining years
 —
 —

 Total
 $
 $
 $
 $
 $
 $
 —
 $

 Note 11 — Asset Impairments

 11. Asset Impairments (Exelon and BGE)
 In the third quarter of 2022, a review of the impacts of COVID-19 on office use resulted in plans to cease the renovation and dispose of an office building at BGE before the asset was placed into service. BGE determined that the carrying value was not recoverable and that its fair value was less than carrying value. As a result, in 2022, a pre-tax impairment charge of $ 48 million was recorded in Operating and maintenance expense in Exelon's and BGE's Consolidated Statements of Operations and Comprehensive Income. The fair value used in the analysis was based on an estimate of an expected sales price.

 12. Intangible Assets
 Goodwill (Exelon, ComEd, PHI, Pepco, DPL, and ACE)
 The following table presents the gross amount, accumulated impairment loss, and carrying amount of Goodwill at Exelon, ComEd, and PHI at December 31, 2024 and 2023. There were no additions or impairments during the years ended December 31, 2024, 2023, and 2022.

 Gross Amount
 Accumulated Impairment Loss
 Carrying Amount

 $
 8,613
 $
 1,983
 $
 6,630

 ComEd(a)

 4,608
 1,983
 2,625

 PHI(b)

 4,005
 —
 4,005

 (a)Reflects goodwill recorded in 2000 from the PECO/Unicom merger (predecessor parent company of ComEd).
 (b)Reflects goodwill recorded in 2016 from the PHI merger.
 Goodwill is not amortized, but is subject to an assessment for impairment at least annually, or more frequently if events occur or circumstances change that would more likely than not reduce the fair value of ComEd's and PHI's reporting units below their carrying amounts. 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. A component of an operating segment is a reporting unit if the component constitutes a business for which discrete financial information is available and its operating results are regularly reviewed by segment management. ComEd has a single operating segment. PHI's operating segments are Pepco, DPL, and ACE. See Note 5 — Segment Information for additional information. There is no level below these operating segments for which operating results are regularly reviewed by segment management. Therefore, the ComEd, Pepco, DPL, and ACE operating segments are also considered reporting units for goodwill impairment assessment purposes. Exelon's and ComEd's $ 2.6 billion of goodwill has been assigned entirely to the ComEd reporting unit, while Exelon's and PHI's $ 4.0 billion of 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.
 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. If an entity bypasses the qualitative assessment, a quantitative, fair value-based assessment is performed, which compares the fair value of the reporting unit to its carrying amount, including goodwill. If the carrying amount of the reporting unit exceeds its fair value, the entity recognizes an impairment charge, which is limited to the amount of goodwill allocated to the reporting unit.
 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, projected operating and capital cash flows for ComEd's, Pepco's, DPL's, and ACE's businesses, and the fair value of debt.
 2024 and 2023 Goodwill Impairment Assessment. ComEd and PHI qualitatively determined that it was more likely than not that the fair values of their reporting units exceeded their carrying values and, therefore, did not

 Note 12 — Intangible Assets

 perform quantitative assessments as of November 1, 2024 and 2023. The last quantitative assessments performed for PHI was as of November 1, 2018. On December 14, 2023, due to the issuance of the ICC's final order rejecting ComEd's proposed Grid Plan and establishing retail rates for 2024-2027 as further discussed in Note 3 — Regulatory Matters, Exelon's stock price decreased approximately 10 % triggering an interim quantitative assessment for potential goodwill impairment at ComEd. ComEd performed a quantitative assessment as of December 31, 2023, comparing the estimated fair value of ComEd to its carrying value, and determined there was no indication of goodwill impairment.
 While the annual and interim assessments indicated no impairments, certain assumptions used to estimate reporting unit fair values are highly sensitive to changes. Adverse regulatory actions or changes in significant assumptions could potentially result in future impairments of Exelon's, ComEd's, and PHI's goodwill, which could be material.
 Other Intangible Assets and Liabilities (Exelon and PHI)
 Exelon's other intangible assets, included in Other current assets and Other deferred debits and other assets in the Consolidated Balance Sheets, consisted of the following at December 31, 2024 and 2023. Exelon's and PHI's other intangible liabilities, included in current and noncurrent Unamortized energy contract liabilities in their Consolidated Balance Sheets, consisted of the following at December 31, 2024 and 2023. The intangible assets and liabilities shown below are amortized on a straight-line basis, except for unamortized energy contracts which are amortized in relation to the expected realization of the underlying cash flows:

 Gross
 Accumulated Amortization
 Net
 Gross
 Accumulated Amortization
 Net

 Unamortized Energy Contracts
 $
 ( 1,515)
 $
 1,489
 $
 ( 26)
 $
 ( 1,515)
 $
 1,480
 $
 ( 35)

 Software License
 ( 78)
 ( 70)

 Exelon Total
 $
 ( 1,434)
 $
 1,411
 $
 ( 23)
 $
 ( 1,434)
 $
 1,410
 $
 ( 24)

 PHI

 Unamortized Energy Contracts
 $
 ( 1,515)
 $
 1,489
 $
 ( 26)
 $
 ( 1,515)
 $
 1,480
 $
 ( 35)

 The following table summarizes the amortization expense related to intangible assets and liabilities for each of the years ended December 31, 2024, 2023, and 2022:

 PHI(a)

 2024
 $
 ( 1)
 $
 ( 9)

 2023
 ( 1)
 ( 10)

 2022(b)

 ( 182)
 ( 190)

 (a)For PHI unamortized energy contracts, the amortization of the fair value adjustment amounts and the corresponding offsetting regulatory asset amounts are amortized through Purchased power and fuel expense in their Consolidated Statements of Operations and Comprehensive Income resulting in no effect to net income.
 (b)On March 23, 2022, the NJBPU approved a petition by ACE to terminate the provisions in its PPAs. As such, the contract was fully amortized during the year ended December 31, 2022. See Note 3 - Regulatory Matters for additional information.

 13. Income Taxes (All Registrants)
 Components of Income Tax Expense or Benefit
 Income tax expense (benefit) from continuing operations is comprised of the following components:

 ComEd
 PECO
 BGE
 PHI
 Pepco
 DPL
 ACE

 Included in operations:

 Federal

 $
 $
 $
 $
 $
 $
 $
 $

 ( 27)
 ( 76)
 ( 46)
 ( 42)

 Investment tax credit amortization
 ( 2)
 ( 1)
 —
 —
 ( 1)
 —
 —
 —

 State

 —
 —
 —

 ( 17)

 Total
 $
 $
 $
 ( 12)
 $
 $
 $
 $
 $

 ComEd
 PECO
 BGE
 PHI
 Pepco
 DPL
 ACE

 Included in operations:

 Federal

 $
 $
 $
 $
 $
 $
 $
 $

 ( 36)
 ( 8)
 ( 28)
 ( 6)

 Investment tax credit amortization
 ( 2)
 ( 1)
 —
 —
 ( 1)
 —
 —
 —

 State

 ( 13)
 —
 —
 —

 ( 7)

 Total
 $
 $
 $
 $
 $
 $
 $
 $

 ComEd
 PECO
 BGE
 PHI
 Pepco
 DPL
 ACE

 Included in operations:

 Federal

 $
 ( 24)
 $
 $
 $
 ( 1)
 $
 $
 $
 ( 2)
 $

 ( 3)
 ( 23)
 ( 2)
 ( 15)

 Investment tax credit amortization
 ( 3)
 ( 1)
 —
 —
 ( 1)
 —
 —
 —

 State

 ( 13)
 ( 6)
 ( 4)
 —
 —
 —
 —

 ( 16)

 Total
 $
 $
 $
 $
 $
 $
 ( 9)
 $
 $

 Rate Reconciliation
 The effective income tax rate from continuing operations varies from the U.S. federal statutory rate principally due to the following:

 For the Year Ended December 31, 2024(a)

 ComEd(b)

 PECO(c)

 BGE(b)

 PHI
 Pepco
 DPL
 ACE

 U.S. federal statutory rate
 21.0
 %
 21.0
 %
 21.0
 %
 21.0
 %
 21.0
 %
 21.0
 %
 21.0
 %
 21.0
 %

 Increase (decrease) due to:

 State income taxes, net of Federal income tax benefit
 5.7
 7.8
 ( 2.5)
 6.4
 6.1
 6.1
 5.2
 7.3

 ( 4.5)
 ( 17.8)
 ( 1.5)
 ( 0.8)
 ( 1.0)
 ( 1.1)
 0.3

 Excess deferred tax amortization
 ( 13.9)
 ( 17.3)
 ( 2.9)
 ( 17.1)
 ( 5.5)
 ( 6.8)
 ( 5.6)
 ( 2.0)

 Amortization of investment tax credit, including deferred taxes on basis differences
 —
 —
 —

 Tax credits
 ( 0.8)
 —

 Other
 0.2
 —
 0.2
 0.1
 —
 0.1

 Effective income tax rate
 7.8
 %
 9.8
 %
 ( 2.2)
 %
 8.5
 %
 20.3
 %
 18.8
 %
 19.0
 %
 26.2
 %

 For the Year Ended December 31, 2023(a)

 ComEd
 PECO(c)

 BGE
 PHI
 Pepco
 DPL
 ACE

 U.S. federal statutory rate
 21.0
 %
 21.0
 %
 21.0
 %
 21.0
 %
 21.0
 %
 21.0
 %
 21.0
 %
 21.0
 %

 Increase (decrease) due to:

 State income taxes, net of Federal income tax benefit(d)

 3.9
 7.9
 ( 1.0)
 6.4
 5.9
 5.5
 6.1
 7.1

 ( 3.9)
 ( 14.4)
 ( 0.9)
 ( 1.4)
 ( 2.2)

 Excess deferred tax amortization
 ( 6.6)
 ( 5.5)
 ( 2.4)
 ( 4.6)
 ( 8.6)
 ( 9.6)
 ( 9.4)
 ( 4.2)

 Amortization of investment tax credit, including deferred taxes on basis differences
 —
 —
 —
 ( 0.2)

 Tax credits
 —

 Other
 0.1
 0.2
 0.2
 0.2
 0.2
 0.3
 —
 0.3

 Effective income tax rate
 13.8
 %
 22.4
 %
 3.4
 %
 21.5
 %
 16.4
 %
 14.3
 %
 16.5
 %
 23.1
 %

 For the Year Ended December 31, 2022(a)

 ComEd
 PECO(e)

 BGE(e)

 PHI(e)

 Pepco(e)

 DPL(e)

 ACE(e)

 U.S. federal statutory rate
 21.0
 %
 21.0
 %
 21.0
 %
 21.0
 %
 21.0
 %
 21.0
 %
 21.0
 %
 21.0
 %

 Increase (decrease) due to:

 State income taxes, net of federal income tax benefit(f)

 8.8
 8.0
 5.8
 2.6
 2.1
 ( 4.1)
 6.5
 6.9

 ( 4.1)
 ( 11.9)
 ( 1.0)
 ( 1.7)
 ( 2.7)

 Excess deferred tax amortization
 ( 11.8)
 ( 5.6)
 ( 3.0)
 ( 19.8)
 ( 19.5)
 ( 16.8)
 ( 18.4)
 ( 24.5)

 Amortization of investment tax credit, including deferred taxes on basis differences
 —
 —
 ( 0.2)
 ( 0.2)

 Tax credits(g)

 0.1
 ( 0.3)
 —

 Other(h)

 0.6
 —
 0.2
 0.1
 0.4
 0.3
 0.1
 —

 Effective income tax rate
 14.5
 %
 22.4
 %
 12.1
 %
 2.1
 %
 1.5
 %
 ( 3.0)
 %
 7.7
 %
 2.0
 %

 (a)Positive percentages represent income tax expense. Negative percentages represent income tax benefit.

 (b)For ComEd, the lower effective tax rate is primarily due to CEJA which resulted in the acceleration of certain income tax benefits. For BGE, the lower effective tax rate is primarily due to the Maryland multi-year plan which resulted in the acceleration of certain income tax benefits.
 (c)For PECO, the lower effective tax rate is primarily related to plant basis differences attributable to tax repair deductions.
 (d)For Exelon, the lower state income taxes, net of federal income tax benefit, is primarily due to the long-term marginal state income tax rate change of $ 54 million.
 (e)For PECO, the lower effective tax rate is primarily related to plant basis differences attributable to tax repair deductions partially offset by higher state income taxes, net of federal income tax benefit, related to a one-time expense of $ 38 million attributable to the change in the Pennsylvania corporate income tax rate. For BGE, PHI, Pepco, DPL, and ACE, the lower effective tax rate is primarily related to the acceleration of certain income tax benefits due to transmission and distribution rate case settlements.
 (f)For Exelon, the higher state income taxes, net of federal income tax benefit, is primarily due to the long-term marginal state income tax rate change of $ 67 million and the recognition of a valuation allowance of $ 40 million against the net deferred tax asset position for certain standalone state filing jurisdictions, partially offset by a one-time impact associated with a state tax benefit of $ 43 million and indemnification adjustments pursuant to the Tax Matters Agreement of $ 11 million as a result of the separation. For PECO, the higher state income taxes, net of federal income tax benefit, related to a one-time expense of $ 38 million attributable to the change in the Pennsylvania corporate income tax rate.
 (g)For Exelon, reflects the income tax expense related to the write-off of federal tax credits subject to recapture of $ 15 million as a result of the separation.
 (h)For Exelon, reflects the nondeductible transaction costs of approximately $ 12 million arising as part of the separation and indemnification adjustments pursuant to the Tax Matters Agreement of $ 9 million.
 Tax Differences and Carryforwards
 The tax effects of temporary differences and carryforwards, which give rise to significant portions of the deferred tax assets (liabilities), at December 31, 2024 and 2023 are presented below:

 ComEd
 PECO
 BGE
 PHI
 Pepco
 DPL
 ACE

 $
 ( 13,150)
 $
 ( 5,069)
 $
 ( 2,446)
 $
 ( 2,232)
 $
 ( 3,371)
 $
 ( 1,512)
 $
 ( 975)
 $
 ( 881)

 Accrual based contracts
 —
 —
 —
 —
 —
 —

 Derivatives and other financial instruments
 —
 —
 —
 —
 —

 Deferred pension and postretirement obligation
 ( 339)
 ( 39)
 ( 24)
 ( 68)
 ( 64)
 ( 32)
 —

 Deferred debt refinancing costs
 ( 4)
 —
 ( 2)
 ( 3)
 ( 1)
 ( 1)

 Regulatory assets and liabilities
 ( 1,665)
 ( 515)
 ( 254)
 ( 37)
 ( 96)
 ( 16)
 ( 18)

 Tax loss carryforward, net of valuation allowances
 —
 —

 Tax credit carryforward
 —
 —
 —
 —
 —
 —
 —

 Corporate Alternative Minimum Tax

 Investment in partnerships
 ( 27)
 —
 —
 —
 —
 —
 —
 —

 Deferred income tax liabilities (net)
 ( 12,776)
 ( 5,595)
 ( 2,433)
 ( 2,098)
 ( 3,180)
 ( 1,508)
 ( 945)
 ( 814)

 Unamortized investment tax credits
 ( 10)
 ( 6)
 —
 ( 1)
 ( 3)
 ( 1)
 ( 1)
 ( 2)

 Total deferred income tax liabilities (net) and unamortized investment tax credits
 $
 ( 12,786)
 $
 ( 5,601)
 $
 ( 2,433)
 $
 ( 2,099)
 $
 ( 3,183)
 $
 ( 1,509)
 $
 ( 946)
 $
 ( 816)

 ComEd
 PECO
 BGE
 PHI
 Pepco
 DPL
 ACE

 $
 ( 12,631)
 $
 ( 4,993)
 $
 ( 2,264)
 $
 ( 2,064)
 $
 ( 3,262)
 $
 ( 1,454)
 $
 ( 947)
 $
 ( 850)

 Accrual based contracts
 —
 —
 —
 —
 —
 —

 Derivatives and other financial instruments
 —
 —
 —
 —
 —

 Deferred pension and postretirement obligation
 ( 299)
 ( 36)
 ( 26)
 ( 78)
 ( 70)
 ( 35)
 ( 2)

 Deferred debt refinancing costs
 ( 5)
 —
 ( 2)
 ( 3)
 ( 2)
 ( 1)

 Regulatory assets and liabilities
 ( 1,429)
 ( 208)
 ( 4)
 ( 52)
 ( 4)

 Tax loss carryforward, net of valuation allowances
 —
 —

 Tax credit carryforward
 —
 —
 —
 —
 —
 —
 —

 Corporate Alternative Minimum Tax
 —
 —

 Investment in partnerships
 ( 28)
 —
 —
 —
 —
 —
 —
 —

 Deferred income tax liabilities (net)
 ( 11,936)
 ( 5,320)
 ( 2,321)
 ( 1,943)
 ( 3,020)
 ( 1,430)
 ( 903)
 ( 769)

 Unamortized investment tax credits
 ( 13)
 ( 7)
 —
 ( 2)
 ( 4)
 ( 1)
 ( 1)
 ( 2)

 Total deferred income tax liabilities (net) and
unamortized investment tax credits
 $
 ( 11,949)
 $
 ( 5,327)
 $
 ( 2,321)
 $
 ( 1,945)
 $
 ( 3,024)
 $
 ( 1,431)
 $
 ( 904)
 $
 ( 771)

 The following table provides Exelon's, ComEd's, PECO's, BGE's, PHI's, Pepco's, DPL's, and ACE's carryforwards, of which the state related items are presented on a post-apportioned basis, as well as, any corresponding valuation allowances at December 31, 2024.

 ComEd
 PECO
 BGE
 PHI
 Pepco
 DPL
 ACE

 Federal

 Federal general business credits carryforwards(a)

 —
 —
 —
 —
 —
 —
 —

 Corporate Alternative Minimum Tax credit carryforward(b)

 State

 State net operating loss carryforwards
 6,349
 —
 1,711
 1,204
 1,392
 —

 Deferred taxes on state tax attributes (net of federal taxes)
 —
 —

 Valuation allowance on state tax attributes (net of federal taxes)(c)

 —
 —
 —
 —

 Year in which net operating loss or credit carryforwards will begin to expire(d)

 2035
 N/A
 2031
 2033
 N/A
 N/A
 2033
 2031

 (a)For Exelon, the federal general business credit carryforward will begin expiring in 2035.
 (b)For Exelon, ComEd, PECO, BGE and ACE, the Corporate Alternative Minimum Tax credit carryforward has an indefinite carryforward period.
 (c)For Exelon, a full valuation allowance has been recorded against certain separate company state net operating loss carryforwards that are expected to expire before realization. For PECO, a valuation allowance has been recorded against certain Pennsylvania net operating losses that are expected to expire before realization. For DPL, a full valuation

 allowance has been recorded against Delaware net operating losses carryforwards due to a change in Delaware tax law that restricts the ability for corporate taxpayers to monetize net operating losses.
 (d)A portion of Exelon's, BGE's, and DPL's Maryland state net operating loss carryforward have an indefinite carryforward period.
 Tabular Reconciliation of Unrecognized Tax Benefits
 The following table presents changes in unrecognized tax benefits, for Exelon, PHI, and ACE. ComEd's, PECO's, BGE's, Pepco's, and DPL's amounts are not material.

 PHI
 ACE

 Balance at January 1, 2022
 $
 $
 $

 Change to positions that only affect timing
 ( 1)

 Increases based on tax positions related to 2022
 —

 Increases based on tax positions prior to 2022
 —
 —

 Decreases based on tax positions prior to 2022
 —
 —
 —

 $
 $
 $

 Change to positions that only affect timing
 ( 57)
 ( 9)
 ( 2)

 Increases based on tax positions related to 2023
 —

 Increases based on tax positions prior to 2023
 —
 —

 Decreases based on tax positions prior to 2023
 ( 1)
 —
 —

 $
 $
 $

 Change to positions that only affect timing
 —

 Increases based on tax positions related to 2024
 —

 Increases based on tax positions prior to 2024
 —
 —

 Decreases based on tax positions prior to 2024
 ( 14)
 ( 14)
 ( 14)

 $
 $
 $

 ______
 (a)At December 31, 2024 and 2023, Exelon recorded a receivable of $ 31 million and $ 31 million, respectively, in noncurrent Other assets in the Consolidated Balance Sheet for Constellation's share of unrecognized tax benefits for periods prior to the separation.
 Recognition of Unrecognized Tax Benefits
 The following table presents Exelon's unrecognized tax benefits that, if recognized, would decrease the effective tax rate. The Utility Registrants' amounts are not material.

 $

 December 31, 2022

 Total Amounts of Interest and Penalties Recognized
 The following table represents the net interest and penalties receivable (payable) related to tax positions reflected in Exelon's Consolidated Balance Sheets. The Utility Registrants' amounts are not material.

 Net interest and penalties receivable at

 December 31, 2024 (a)

 $

 December 31, 2023 (b)

 (a)At December 31, 2024, Exelon classified $ 27 million and $ 49 million of the interest receivable as current and noncurrent, respectively, based on the expected timing for settlement in cash. At December 31, 2024, Exelon recorded a receivable of $ 9 million in noncurrent Other assets in the Consolidated Balance Sheet for Constellation's share of net interest for periods prior to the separation.

 (b)At December 31, 2023, Exelon classified $ 21 million and $ 41 million of the interest receivable as current and noncurrent, respectively, based on the expected timing for settlement in cash. At December 31, 2023, Exelon recorded a receivable of $ 5 million in noncurrent Other assets in the Consolidated Balance Sheet for Constellation's share of net interest for periods prior to the separation.
 The Registrants did not record material interest and penalty expense related to tax positions reflected in their Consolidated Balance Sheets. Interest expense and penalty expense are recorded in Interest expense, net and Other, net, respectively, in Other income and deductions in the Registrants Consolidated Statements of Operations and Comprehensive Income.
 Description of Tax Years Open to Assessment by Major Jurisdiction

 Major Jurisdiction
 Open Years
 Registrants Impacted

 Federal consolidated income tax returns(a)

 2010-2023

 Delaware separate corporate income tax returns
 Same as federal
 DPL

 District of Columbia combined corporate income tax returns
 2021-2023
 Exelon, PHI, Pepco

 Illinois unitary corporate income tax returns
 2012-2023
 Exelon, ComEd

 Maryland separate company corporate net income tax returns
 Same as federal
 BGE, Pepco, DPL

 New Jersey combined corporate income tax returns
 2020-2023

 New Jersey separate corporate income tax returns
 2020-2023
 ACE

 New York combined corporate income tax returns
 2019-2023

 Pennsylvania separate corporate income tax returns
 2021-2023

 Pennsylvania separate corporate income tax returns
 2021-2023
 PECO

 (a) Certain registrants are only open to assessment for tax years since joining the Exelon federal consolidated group; BGE beginning in 2012 and PHI, Pepco, DPL, and ACE beginning in 2016.
 Other Tax Matters
 Separation (Exelon)
 In the first quarter of 2022, in connection with the separation, Exelon recorded an income tax expense related to continuing operations of $ 148 million primarily due to the long-term marginal state income tax rate change of $ 54 million discussed further below, the recognition of valuation allowances of approximately $ 40 million against the net deferred tax assets positions for certain standalone state filing jurisdictions, the write-off of federal and state tax credits subject to recapture of $ 17 million, and nondeductible transaction costs for federal and state taxes of $ 24 million.
 Tax Matters Agreement (Exelon)
 In connection with the separation, Exelon entered into a TMA with Constellation. The TMA governs the respective rights, responsibilities, and obligations between Exelon and Constellation after the separation with respect to tax liabilities, refunds and attributes for open tax years that Constellation was part of Exelon's consolidated group for U.S. federal, state, and local tax purposes.
 Indemnification for Taxes. As a former subsidiary of Exelon, Constellation has joint and several liability with Exelon to the IRS and certain state jurisdictions relating to the taxable periods prior to the separation. The TMA specifies that Constellation is liable for their share of taxes required to be paid by Exelon with respect to taxable periods prior to the separation to the extent Constellation would have been responsible for such taxes under the existing Exelon tax sharing agreement. In 2024, Exelon remitted $ 11 million of payments to Constellation. At December 31, 2024, there is no balance due to or from Constellation.
 Tax Refunds. The TMA specifies that Constellation is entitled to their share of any future tax refunds claimed by Exelon with respect to taxable periods prior to the separation to the extent that Constellation would have received such tax refunds under the existing Exelon tax sharing agreement. At December 31, 2024, there is no balance due to or from Constellation.
 Tax Attributes. At the date of separation certain tax attributes, primarily pre-closing tax credit carryforwards, that were generated by Constellation were required by law to be allocated to Exelon. The TMA also provides that

 Exelon will reimburse Constellation when those allocated tax attribute carryforwards are utilized. In 2024, Exelon remitted $ 174 million of payments to Constellation for the utilization of pre-closing tax credit carryforwards. At December 31, 2024, Exelon recorded a payable of $ 141 million and $ 198 million in Other current liabilities and Other deferred credits and other liabilities, respectively, in the Consolidated Balance Sheet for tax attribute carryforwards that are expected to be utilized and reimbursed to Constellation.
 Corporate Alternative Minimum Tax (All Registrants)
 On August 16, 2022, the IRA was signed into law and implemented a new corporate alternative minimum tax (CAMT) that imposes a 15.0 % tax on modified GAAP net income. Corporations are entitled to a tax credit (minimum tax credit) to the extent the CAMT liability exceeds the regular tax liability. This amount can be carried forward indefinitely and used in future years when regular tax exceeds the CAMT.

 Beginning in 2023, based on the existing statue, Exelon and each of the Utility Registrants will be subject to and will report the CAMT on a separate Registrant basis in the Consolidated Statements of Operations and Comprehensive Income and the Consolidated Balance Sheets. The deferred tax asset related to the minimum tax credit carryforward will be realized to the extent Exelon's consolidated deferred tax liabilities exceed the minimum tax credit carryforward. Exelon's deferred tax liabilities are expected to exceed the minimum tax credit carryforward for the foreseeable future and thus no valuation allowance is required.

 On September 12, 2024, the U.S. Treasury issued proposed regulations providing further guidance addressing the implementation of CAMT. The proposed regulations are consistent with Exelon's prior interpretation and therefore there are no financial statement impacts. Exelon will continue to monitor and assess the potential financial statement impacts of final regulations or other guidance when issued.
 Long-Term Marginal State Income Tax Rate (All Registrants)
 Quarterly, Exelon reviews and updates its marginal state income tax rates for material changes in state tax laws and state apportionment. The Registrants remeasure their existing deferred income tax balances to reflect the changes in marginal rates, which results in either an increase or a decrease to their net deferred income tax liability balances. Utility Registrants record corresponding regulatory liabilities or assets to the extent such amounts are probable of settlement or recovery through customer rates and an adjustment to income tax expense for all other amounts. In the third quarter of 2023, Exelon updated its marginal state income tax rates for changes in state apportionment. The changes in marginal rates in the third quarter resulted in a decrease of $ 54 million to the deferred tax liability at Exelon, and a corresponding adjustment to income tax expense, net of federal taxes. There were no impacts to ComEd, BGE, PHI, Pepco, DPL, and ACE for the years ended December 31, 2024, 2023, and 2022.

 Decrease to Deferred Income Tax Liability and Income Tax Expense, Net of Federal Taxes
 $
 —

 Decrease to Deferred Income Tax Liability and Income Tax Expense, Net of Federal Taxes
 ( 54)

 December 31, 2022

 Increase to Deferred Income Tax Liability and Income Tax Expense, Net of Federal Taxes

 Pennsylvania Corporate Income Tax Rate Change (Exelon and PECO)
 On July 8, 2022, Pennsylvania enacted House Bill 1342, which will permanently reduce the corporate income tax rate from 9.99 % to 4.99 %. The tax rate will be reduced to 8.99 % for the 2023 tax year. Starting with the 2024 tax year, the rate is reduced by 0.50 % annually until it reaches 4.99 % in 2031. As a result of the rate change, in the third quarter of 2022, Exelon and PECO recorded a one-time decrease to deferred income taxes of $ 390 million with a corresponding decrease to the deferred income taxes regulatory asset of $ 428 million for the amounts that are expected to be settled through future customer rates and an increase to income tax expense of $ 38 million (net of federal taxes). The tax rate decrease is not expected to have a material ongoing impact to Exelon's and PECO's financial statements. There were no changes to PECO's marginal state income tax rates for the years ended December 31, 2024 and 2023.
 Allocation of Tax Benefits (All Registrants)

 The Utility Registrants are party to an agreement with Exelon and other subsidiaries of Exelon that provides for the allocation of consolidated tax liabilities and benefits (Tax Sharing Agreement). The Tax Sharing Agreement provides that each party is allocated an amount of tax similar to that which would be owed had the party been separately subject to tax. In addition, any net federal and state benefits attributable to Exelon are reallocated to the other Registrants. That allocation is treated as a contribution from Exelon to the party receiving the benefit.
 The following table presents the allocation of tax benefits from Exelon under the Tax Sharing Agreement, for the year ended December 31, 2024, 2023, and 2022.

 ComEd
 PECO
 BGE
 PHI
 Pepco
 DPL
 ACE

 $
 $
 $
 $
 $
 $
 $

 December 31, 2023(a)

 —
 —

 December 31, 2022(b)

 —

 (a)BGE and DPL did not record an allocation of federal tax benefits from Exelon under the Tax Sharing Agreement as a result of a tax net operating loss.
 (b)BGE did not record an allocation of federal tax benefits from Exelon under the Tax Sharing Agreement as a result of a tax net operating loss.

 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 material reduction of the regulatory liability established for EDITs arising from the TCJA corporate tax rate change that are being amortized and flowed through to customers as well as a reduction in the accumulated deferred income taxes included in rate base for ratemaking purposes. The Registrants will record the impact, if any, upon receiving their own PLRs from the IRS.

 14. Retirement Benefits (All Registrants)
 Exelon sponsors defined benefit pension and OPEB plans. Substantially all non-union employees and electing union employees hired on or after January 1, 2001 participate in cash balance pension plans. Effective January 1, 2009, substantially all newly-hired union-represented employees participate in cash balance pension plans. Effective February 1, 2018 for most newly-hired BSC non-represented, non-craft, employees, January 1, 2021 for most newly-hired utility management employees, and for certain newly-hired union employees pursuant to their collective bargaining agreements, these newly-hired employees are not eligible for pension benefits, and will instead be eligible to receive an enhanced non-discretionary employer contribution in an Exelon defined contribution savings plan. Effective January 1, 2018, most newly-hired non-represented, non-craft, employees are not eligible for OPEB benefits and employees represented by Local 614 are not eligible for retiree health care benefits. Effective January 1, 2021, most non-represented, non-craft, employees who are under the age of 40 are not eligible for retiree health care benefits. Effective January 1, 2022, management employees retiring on or after that date are no longer eligible for retiree life insurance benefits.

 The tables below show the pension and OPEB plans in which current and former employees of each operating company participated as of December 31, 2024:

 Operating Company(a)

 Name of Plan:
 ComEd
 PECO
 BGE
 PHI
 Pepco
 DPL
 ACE

 Qualified Pension Plans:

 Exelon Corporation Retirement Program (ECRP)
 X
 X
 X
 X
 X
 X
 X

 Exelon Corporation Pension Plan for Bargaining Unit Employees (PPBU)
 X

 Exelon Pension Plan (EPP)
 X
 X
 X
 X
 X
 X
 X

 Pepco Holdings LLC Retirement Plan (PHI Qualified)
 X
 X
 X
 X
 X
 X
 X

 Non-Qualified Pension Plans:

 Exelon Corporation Supplemental Pension Benefit Plan and 2000 Excess Benefit Plan (SPBP)
 X
 X
 X

 Exelon Corporation Supplemental Management Retirement Plan (SMRP)
 X
 X
 X
 X

 Constellation Energy Group, Inc. Senior Executive Supplemental Plan
 X
 X

 Constellation Energy Group, Inc. Supplemental Pension Plan
 X
 X

 Constellation Energy Group, Inc. Benefits Restoration Plan
 X
 X
 X

 Baltimore Gas & Electric Company Executive Benefit Plan
 X

 Baltimore Gas & Electric Company Manager Benefit Plan
 X
 X

 Pepco Holdings LLC 2011 Supplemental Executive Retirement Plan
 X
 X
 X
 X

 Conectiv Supplemental Executive Retirement Plan
 X
 X
 X

 Pepco Holdings LLC Combined Executive Retirement Plan
 X
 X

 Operating Company(a)

 Name of Plan:

 ComEd
 PECO
 BGE
 PHI
 Pepco
 DPL
 ACE

 OPEB Plans:

 PECO Energy Company Retiree Medical Plan (East)
 X
 X
 X
 X
 X
 X
 X

 Exelon Corporation Health Care Program (West)
 X
 X
 X
 X
 X
 X
 X

 Pepco Holdings LLC Welfare Plan for Retirees (PHI PRW)
 X
 X
 X
 X
 X
 X
 X

 Exelon Corporation Employees' Life Insurance Plan
 X
 X
 X

 Exelon Corporation Health Reimbursement Arrangement Plan
 X
 X
 X

 BGE Retiree Medical Plan
 X
 X
 X
 X
 X
 X
 X

 BGE Retiree Dental Plan
 X

 Exelon Retiree Medical Plan of Constellation Energy Nuclear Group, LLC
 X
 X
 X

 Exelon Retiree Dental Plan of Constellation Energy Nuclear Group, LLC
 X
 X
 X

 (a)Employees generally remain in their legacy benefit plans when transferring between operating companies.

 Exelon's traditional and cash balance pension plans are intended to be tax-qualified defined benefit plans. Exelon has elected that the trusts underlying these plans be treated as qualified trusts under the IRC. If certain conditions are met, Exelon can deduct payments made to the qualified trusts, subject to certain IRC limitations.
 Benefit Obligations, Plan Assets, and Funded Status

 As of February 1, 2022, in connection with the separation, Exelon's pension and OPEB plans were remeasured. The remeasurement and separation resulted in a decrease to the Pension obligation, net of plan assets, of $ 921 million and a decrease to the OPEB obligation of $ 893 million. Additionally, AOCI decreased by $ 1,994 million (after-tax) and Regulatory assets and liabilities increased by $ 14 million and $ 5 million, respectively. Key assumptions were held consistent with the year end December 31, 2021 assumptions with the exception of the discount rate.
 During the first quarter of 2024, Exelon received an updated valuation of its pension and OPEB to reflect actual census data as of January 1, 2024. This valuation resulted in an increase to the pension obligation of $ 98 million and a decrease to the OPEB obligations of $ 1 million. Additionally, AOCI increased by $ 25 million (after-tax) and Regulatory assets and liabilities increased by $ 66 million and $ 2 million, respectively.
 The following tables provide a rollforward of the changes in the benefit obligations and plan assets of Exelon for the most recent two years for all plans combined:

 OPEB

 2024
 2023
 2024
 2023

 Change in benefit obligation:

 Net benefit obligation as of the beginning of year
 $
 10,988
 $
 10,677
 $
 1,908
 $
 1,884

 Service cost

 Interest cost

 Plan participants' contributions
 —
 —

 Actuarial (gain) loss
 ( 331)
 ( 32)

 Plan amendments
 —
 —
 —

 Settlements
 ( 22)
 ( 42)
 —
 —

 Gross benefits paid
 ( 821)
 ( 790)
 ( 189)
 ( 185)

 Net benefit obligation as of the end of year
 $
 10,545
 $
 10,988
 $
 1,837
 $
 1,908

 OPEB

 2024
 2023
 2024
 2023

 Change in plan assets:

 Fair value of net plan assets as of the beginning of year
 $
 9,402
 $
 9,521
 $
 1,355
 $
 1,351

 Actual return on plan assets

 Employer contributions

 Plan participants' contributions
 —
 —

 Gross benefits paid
 ( 821)
 ( 790)
 ( 189)
 ( 185)

 Settlements
 ( 22)
 ( 42)
 —
 —

 Fair value of net plan assets as of the end of year
 $
 8,785
 $
 9,402
 $
 1,355
 $
 1,355

 (a)The pension and OPEB gains in 2024 primarily reflect an increase in the discount rate. The pension and OPEB losses in 2023 primarily reflect a decrease in the discount rate.

 Exelon presents its benefit obligations and plan assets net on its Consolidated Balance Sheets within the following line items:

 OPEB

 2024
 2023
 2024
 2023

 Other noncurrent assets
 $
 —
 $
 —
 $
 $
 —

 Other current liabilities
 ( 15)
 ( 15)
 ( 20)
 ( 26)

 Pension obligations
 ( 1,745)
 ( 1,571)
 —
 —

 —
 —
 ( 472)
 ( 527)

 Unfunded status, net (net benefit obligation less plan assets)
 $
 ( 1,760)
 $
 ( 1,586)
 $
 ( 482)
 $
 ( 553)

 The following table provides the ABO and fair value of plan assets for all pension plans with an ABO in excess of plan assets. Information for pension and OPEB plans with projected benefit obligations (PBO) and accumulated postretirement benefit obligations (APBO), respectively, in excess of plan assets have been disclosed in the Obligations and Plan Assets table above as all pension and a majority of the OPEB plans are underfunded.

 2024
 2023

 ABO
 $
 10,076
 $
 10,376

 Fair value of net plan assets
 8,785
 9,279

 Components of Net Periodic Benefit Costs
 The majority of the 2024 pension benefit cost for the Exelon-sponsored plans is calculated using an expected long-term rate of return on plan assets of 7.00 % and a discount rate of 5.19 %. The majority of the 2024 OPEB cost is calculated using an expected long-term rate of return on plan assets of 6.50 % for funded plans and a discount rate of 5.17 %.
 A portion of the net periodic benefit cost for all plans is capitalized in the Consolidated Balance Sheets. The following table presents the components of Exelon's net periodic benefit costs, prior to capitalization, for the years ended December 31, 2024, 2023, and 2022.

 OPEB

 2024
 2023
 2022
 2024
 2023
 2022

 Components of net periodic benefit cost:

 Service cost
 $
 $
 $
 $
 $
 $

 Interest cost

 Expected return on assets
 ( 736)
 ( 755)
 ( 822)
 ( 84)
 ( 83)
 ( 99)

 Amortization of:

 Prior service cost (credit)
 ( 8)
 ( 10)
 ( 19)

 Actuarial loss (gain)
 —
 ( 2)

 Settlement and other charges
 —
 —
 —
 —

 Net periodic benefit cost
 $
 $
 $
 $
 $
 $

 Cost Allocation to Exelon Subsidiaries
 All Registrants account for their participation in Exelon's pension and OPEB plans by applying multi-employer accounting. Exelon allocates costs related to its pension and OPEB plans to its subsidiaries based on both active and retired employee participation in each plan.

 The amounts below represent the Registrants' allocated pension and OPEB costs (benefit). For Exelon, the service cost component is included in Operating and maintenance expense and Property, plant, and equipment, net while the non-service cost components are included in Other, net and Regulatory assets. For PHI and each of the Utility Registrants, the service cost and non-service cost components are included in Operating and maintenance expense and Property, plant, and equipment, net in their consolidated financial statements.

 ComEd
 PECO
 BGE
 PHI
 Pepco
 DPL
 ACE

 2024
 $
 $
 $
 ( 1)
 $
 $
 $
 $
 $

 2023
 ( 14)

 2022
 ( 9)

 Components of AOCI and Regulatory Assets
 Exelon recognizes the overfunded or underfunded status of defined benefit pension and OPEB plans as an asset or liability on its Consolidated Balance Sheets, with offsetting entries to AOCI and Regulatory assets (liabilities). A portion of current year actuarial (gains) losses and prior service costs (credits) is capitalized in Exelon's Consolidated Balance Sheets to reflect the expected regulatory recovery of these amounts, which would otherwise be recorded to AOCI. The following tables provide the components of AOCI and Regulatory assets (liabilities) for Exelon for the years ended December 31, 2024, 2023, and 2022 for all plans combined. The tables include amounts related to Generation prior to the separation.

 OPEB

 2024
 2023
 2022
 2024
 2023
 2022

 Changes in plan assets and benefit obligations recognized in AOCI and Regulatory assets (liabilities):

 Current year actuarial loss (gain)
 $
 $
 $
 ( 226)
 $
 ( 56)
 $
 $
 ( 271)

 Amortization of actuarial (loss) gain
 ( 214)
 ( 166)
 ( 295)
 —
 ( 12)

 Separation of Constellation
 —
 —
 ( 2,631)
 —
 —
 ( 43)

 Current year prior service cost
 —
 —
 —
 —
 —

 Amortization of prior service (cost) credit
 ( 2)
 ( 2)
 ( 2)

 Settlements
 ( 10)
 ( 20)
 —
 —
 —
 —

 Total recognized in AOCI and Regulatory assets (liabilities)
 $
 $
 $
 ( 3,154)
 $
 ( 48)
 $
 $
 ( 307)

 Total recognized in AOCI
 $
 $
 $
 ( 2,719)
 $
 ( 1)
 $
 $
 ( 74)

 Total recognized in Regulatory assets (liabilities)
 $
 $
 $
 ( 435)
 $
 ( 47)
 $
 $
 ( 233)

 The following table provides the components of gross AOCI and Regulatory assets (liabilities) for Exelon that have not been recognized as components of periodic benefit cost as of December 31, 2024 and 2023, respectively, for all plans combined:

 OPEB

 2024
 2023
 2024
 2023

 Prior service cost (credit)
 $
 $
 $
 ( 37)
 $
 ( 45)

 Actuarial loss (gain)
 4,029
 3,948
 ( 157)
 ( 101)

 Total
 $
 4,048
 $
 3,969
 $
 ( 194)
 $
 ( 146)

 Total included in AOCI
 $
 1,028
 $
 $
 ( 18)
 $
 ( 17)

 Total included in Regulatory assets (liabilities)
 $
 3,020
 $
 2,997
 $
 ( 176)
 $
 ( 129)

 Average Remaining Service Period
 For pension benefits, Exelon amortizes its unrecognized prior service costs (credits) and certain actuarial (gains) losses, as applicable, based on participants' average remaining service periods.
 For OPEB, Exelon amortizes its unrecognized prior service costs (credits) over participants' average remaining service period to benefit eligibility age and amortizes certain actuarial (gains) losses over participants' average remaining service period to expected retirement. The resulting average remaining service periods for pension and OPEB were as follows:

 2024
 2023
 2022

 Pension plans
 12.5
 12.6
 12.5

 OPEB plans:

 Benefit Eligibility Age
 7.8
 8.1
 7.9

 Expected Retirement
 9.0
 9.3
 9.1

 Assumptions
 The measurement of the plan obligations and costs of providing benefits under Exelon's defined benefit and OPEB plans involves various factors, including the development of valuation assumptions and inputs and accounting policy elections. The measurement of benefit obligations and costs is impacted by several assumptions and inputs, as shown below, among other factors. When developing the required assumptions, Exelon considers historical information as well as future expectations.
 Expected Rate of Return. 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.
 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. For the years ended December 31, 2024 and 2023, 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.
 For Exelon, the following assumptions were used to determine the benefit obligations for the plans as of December 31, 2024 and 2023. Assumptions used to determine year-end benefit obligations are the assumptions used to estimate the subsequent year's net periodic benefit costs.

 OPEB

 2024

 2023

 2024

 2023

 Discount rate(a)

 5.68
 %
 5.19
 %
 5.64
 %
 5.17
 %

 Investment crediting rate(b)

 5.69
 %

 5.03
 %
 N/A
 N/A

 Rate of compensation increase
 3.75
 %
 3.75
 %
 3.75
 %
 3.75
 %

 Mortality table

 Health care cost trend on covered charges
 N/A
 N/A
 Initial and ultimate trend rate of 5.00 %

 Initial and ultimate trend rate of 5.00 %

 (a)The discount rates above represent the blended rates used to determine the majority of Exelon's pension and OPEB obligations. Certain benefit plans used individual rates, which range from 5.56 % - 5.76 % and 5.60 % - 5.64 % for pension and OPEB plans, respectively, as of December 31, 2024 and 5.11 % - 5.27 % and 5.15 % - 5.17 % for pension and OPEB plans, respectively, as of December 31, 2023.
 (b)The investment crediting rate above represents a weighted average rate.

 The following assumptions were used to determine the net periodic benefit cost for Exelon for the years ended December 31, 2024, 2023 and 2022:

 OPEB

 2024

 2023

 2022

 2024

 2023

 2022

 Discount rate(a)

 5.19
 %
 5.53
 %
 3.24
 %
 5.17
 %
 5.51
 %
 3.20
 %

 Investment crediting rate(b)

 5.03
 %
 5.07
 %
 3.75
 %
 N/A

 N/A

 N/A

 Expected return on plan assets(c)

 7.00
 %
 7.00
 %
 7.00
 %
 6.50
 %
 6.50
 %
 6.44
 %

 Rate of compensation increase
 3.75
 %

 3.75
 %

 3.75
 %

 3.75
 %

 3.75
 %

 3.75
 %

 Mortality table

 Health care cost trend on covered charges
 N/A
 N/A
 N/A
 Initial and ultimate rate
 of 5.00 %

 Initial and ultimate rate of 5.00 %

 Initial and ultimate rate of 5.00 %

 (a)The discount rates above represent the blended rates used to establish the majority of Exelon's pension and OPEB costs. Certain benefit plans used individual rates, which range from 5.11 %- 5.27 % and 5.15 %- 5.17 % for pension and OPEB plans, respectively, for the year ended December 31, 2024; 5.46 %- 5.60 % and 5.49 %- 5.51 % for pension and OPEB plans; respectively, for the year ended December 31, 2023; and 2.55 %- 3.24 % and 2.84 %- 3.20 % for pension and OPEB plans, respectively, for the year ended December 31, 2022.
 (b)The investment crediting rate above represents a weighted average rate.
 (c)Not applicable to pension and OPEB plans that do not have plan assets.
 Contributions
 Exelon allocates contributions related to its ECRP and PPBU pension plans and East and West OPEB plans to its subsidiaries based on accounting cost. For the EPP pension plan, PHI Qualified, and PHI PRW plans, pension and OPEB contributions are allocated to the subsidiaries based on employee participation (both active and retired). For Exelon, in connection with the separation, additional qualified pension contributions of $ 207 million and $ 33 million were completed on February 1, 2022 and March 2, 2022, respectively. The following table provides contributions to the pension and OPEB plans:

 OPEB

 2024
 2023
 2022
 2024

 2023

 2022

 $
 $
 $
 $
 $
 $

 ComEd

 PECO
 —

 BGE
 —

 PHI

 Pepco

 DPL
 —

 ACE
 —
 —

 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. Based on this funding strategy and current market conditions, which are subject to change, Exelon's estimated annual qualified pension contributions will be approximately $ 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

 $
 $
 $

 ComEd

 PECO

 BGE

 PHI

 Pepco

 DPL
 —

 ACE
 —

 Estimated Future Benefit Payments
 Estimated future benefit payments to participants in all of the pension plans and postretirement benefit plans as of December 31, 2024 were:

 OPEB

 2025
 $
 $

 2026

 2027

 2028

 2029

 2030 through 2034
 4,019

 Total estimated future benefits payments through 2034
 $
 8,084
 $
 1,524

 Plan Assets
 Investment Strategy. On a regular basis, Exelon evaluates its investment strategy to ensure plan assets will be sufficient to pay plan benefits when due. As part of this ongoing evaluation, Exelon may make changes to its targeted asset allocation and investment strategy.
 Exelon has developed and implemented a liability hedging investment strategy for its qualified pension plans that has reduced the volatility of its pension assets relative to its pension liabilities. Exelon is likely to continue to gradually increase the liability hedging portfolio as the funded status of its plans improves. The overall objective is to achieve attractive risk-adjusted returns that will balance the liquidity requirements of the plans' liabilities while striving to minimize the risk of significant losses. Trust assets for Exelon's OPEB plans are managed in a diversified investment strategy that prioritizes maximizing liquidity and returns while minimizing asset volatility.
 Actual asset returns have an impact on the costs reported for the Exelon-sponsored pension and OPEB plans. The actual asset returns across Exelon's pension and OPEB plans for the year ended December 31, 2024 were 1.49 % and 8.54 %, respectively, compared to an expected long-term return assumption of 7.00 % and 6.50 %, respectively. Exelon used an EROA of 7.00 % and 6.50 % to estimate its 2025 pension and OPEB costs, respectively.
 Exelon's pension and OPEB plan target asset allocations as of December 31, 2024 and 2023 were as follows:

 Asset Category
 OPEB
 OPEB

 Equity securities
 %
 %
 %
 %

 Fixed income securities
 %
 %
 %
 %

 Alternative investments(a)

 %
 %
 %
 %

 Total
 %
 %
 %
 %

 (a)Alternative investments include private equity, hedge funds, real estate, and private credit.
 Concentrations of Credit Risk. Exelon evaluated its pension and OPEB plans' asset portfolios for the existence of significant concentrations of credit risk as of December 31, 2024. Types of concentrations that were evaluated include, but are not limited to, investment concentrations in a single entity, type of industry, foreign country, and individual fund. As of December 31, 2024, there were no significant concentrations (defined as greater than 10% of plan assets) of risk in Exelon's pension and OPEB plan assets.

 Fair Value Measurements
 The following tables present pension and OPEB plan assets measured and recorded at fair value in Exelon's Consolidated Balance Sheets on a recurring basis and their level within the fair value hierarchy as of December 31, 2024 and 2023:

 Not Subject to Leveling
 Total
 Not Subject to Leveling
 Total

 Pension plan assets(a)

 $
 $
 —
 $
 —
 $
 —
 $
 $
 $
 —
 $
 —
 $
 —
 $

 Equities(b)

 1,127
 —
 1,361
 2,489
 1,513
 —
 2,208

 Fixed income:

 U.S. Treasury and agencies
 1,333
 —
 —
 1,532
 1,291
 —
 —
 1,475

 State and municipal debt
 —
 —
 —
 —
 —
 —

 Corporate debt
 —
 1,551
 —
 1,567
 —
 1,792
 —
 1,801

 Other(b)

 —
 —
 —
 —

 Fixed income subtotal
 1,333
 1,807
 3,774
 1,291
 2,097
 4,185

 Private equity
 —
 —
 —
 1,249
 1,249
 —
 —
 —
 1,166
 1,166

 Hedge funds
 —
 —
 —
 —
 —
 —

 Real estate
 —
 —
 —
 —
 —
 —

 Private credit
 —
 —
 —
 —
 —
 —

 Pension plan assets subtotal
 $
 2,665
 $
 1,807
 $
 $
 4,966
 $
 9,455
 $
 3,071
 $
 2,097
 $
 $
 4,612
 $
 9,790

 OPEB plan assets(a)

 $
 $
 —
 $
 —
 $
 —
 $
 $
 $
 —
 $
 —
 $
 —
 $

 Equities
 —
 —

 Fixed income:

 U.S. Treasury and agencies
 —
 —
 —
 —

 State and municipal debt
 —
 —
 —
 —
 —
 —

 Corporate debt
 —
 —
 —
 —
 —
 —

 Other
 —
 —

 Fixed income subtotal
 —
 —

 Hedge funds
 —
 —
 —
 —
 —
 —

 Real estate
 —
 —
 —
 —
 —
 —

 Private credit
 —
 —
 —
 —
 —
 —

 OPEB plan assets subtotal
 $
 $
 $
 —
 $
 $
 1,355
 $
 $
 $
 —
 $
 $
 1,355

 Total pension and OPEB plan assets(c)

 $
 3,330
 $
 1,878
 $
 $
 5,585
 $
 10,810
 $
 3,621
 $
 2,207
 $
 $
 5,307
 $
 11,145

 (a)See Note 17—Fair Value of Financial Assets and Liabilities for a description of levels within the fair value hierarchy.
 (b)Includes derivative instruments of $( 21) million and $ 51 million for the years ended December 31, 2024 and 2023, respectively, which have total notional amounts of $ 5,123 million and $ 3,351 million as of December 31, 2024 and 2023, respectively. The notional principal amounts for these instruments provide one measure of the transaction volume outstanding as of the fiscal years ended and do not represent the amount of Exelon's exposure to credit or market loss.
 (c)Excludes net liabilities of $ 670 million and $ 388 million as of December 31, 2024 and 2023, respectively, which include certain derivative assets that have notional amounts of $ 41 million and $ 59 million as of December 31, 2024 and 2023, respectively. These items are required to reconcile to the fair value of net plan assets and consist primarily of receivables or payables related to pending securities sales and purchases, interest and dividends receivable, and repurchase agreement obligations. The repurchase agreements generally have maturities ranging from 3 - 6 months.

 The following table presents the reconciliation of Level 3 assets and liabilities for Exelon measured at fair value for pension and OPEB plans for the years ended December 31, 2024 and 2023:

 Fixed Income
 Equities
 Total

 Pension Assets

 Balance as of January 1, 2024
 $
 $
 $

 Actual return on plan assets:

 Relating to assets still held as of the reporting date
 ( 1)
 —
 ( 1)

 Purchases, sales and settlements:

 Purchases
 —

 Level 3 transfers in
 —

 Balance as of December 31, 2024
 $
 $
 $

 Fixed Income
 Equities
 Total

 Pension Assets

 Balance as of January 1, 2023
 $
 $
 —
 $

 Actual return on plan assets:

 Relating to assets still held as of the reporting date
 —
 —
 —

 Purchases, sales and settlements:

 Purchases
 —
 —
 —

 Level 3 transfers (out) in
 ( 3)
 ( 2)

 Balance as of December 31, 2023
 $
 $
 $

 _
 Valuation Techniques Used to Determine Fair Value
 The techniques used to fair value the pension and OPEB assets invested in cash equivalents are the same as the valuation techniques used to determine the fair value of financial assets. See Cash Equivalents in Note 17 - Fair Value of Financial Assets and Liabilities for further information. Below outlines the techniques used to fair value the pension and OPEB assets invested in equities, fixed income, derivative instruments, private credit, private equity, real estate, and hedge funds.
 Equities. These investments consist of individually held equity securities, equity mutual funds, and equity commingled funds in domestic and foreign markets. With respect to individually held equity securities, the trustees obtain prices from pricing services, whose prices are generally obtained from direct feeds from market exchanges, which Exelon is able to independently corroborate. Equity securities held individually, including real estate investment trusts, rights, and warrants, are primarily traded on exchanges that contain only actively traded securities due to the volume trading requirements imposed by these exchanges. The equity securities that are held directly by the trust funds are valued based on quoted prices in active markets and categorized as Level 1. Certain equity securities have been categorized as Level 2 because they are based on evaluated prices that reflect observable market information, such as actual trade information or similar securities. Certain private placement equity securities are categorized as Level 3 because they are not publicly traded and are priced using significant unobservable inputs.

 Equity commingled funds and mutual funds are maintained by investment companies, and fund investments are held in accordance with a stated set of fund objectives. The values of some of these funds are publicly quoted. For mutual funds which are publicly quoted, the funds are valued based on quoted prices in active markets and have been categorized as Level 1. For equity commingled funds and mutual funds that are not publicly quoted, the fund administrators value the funds using the NAV per fund share, derived from the quoted prices in active markets on the underlying securities and are not classified within the fair value hierarchy. These investments can typically be redeemed monthly or more frequently, with 30 or less days of notice and without further restrictions.
 Fixed income. For fixed income securities, which consist primarily of corporate debt securities, U.S. government securities, foreign government securities, municipal bonds, asset and mortgage-backed securities, commingled funds, mutual funds, and derivative instruments, the trustees obtain multiple prices from pricing vendors whenever possible, which enables cross-provider validations in addition to checks for unusual daily movements. A primary price source is identified based on asset type, class, or issue for each security. With respect to individually held fixed income securities, the trustees monitor prices supplied by pricing services and may use a supplemental price source or change the primary price source of a given security if the portfolio managers challenge an assigned price and the trustees determine another price source is considered to be preferable. Exelon has obtained an understanding of how these prices are derived, including the nature and observability of the inputs used in deriving such prices. Additionally, Exelon selectively corroborates the fair values of securities by comparison to other market-based price sources. Investments in U.S. Treasury securities have been categorized as Level 1 because they trade in highly-liquid and transparent markets. Certain private placement fixed income securities have been categorized as Level 3 because they are priced using certain significant unobservable inputs and are typically illiquid. The remaining fixed income securities, including certain other fixed income investments, are based on evaluated prices that reflect observable market information, such as actual trade information of similar securities, adjusted for observable differences and are categorized as Level 2.
 Other fixed income investments primarily consist of fixed income commingled funds and mutual funds, which are maintained by investment companies and hold fund investments in accordance with a stated set of fund objectives. The values of some of these funds are publicly quoted. For mutual funds which are publicly quoted, the funds are valued based on quoted prices in active markets and have been categorized as Level 1. For fixed income commingled funds and mutual funds that are not publicly quoted, the fund administrators value the funds using the NAV per fund share, derived from the quoted prices in active markets of the underlying securities and are not classified within the fair value hierarchy. These investments typically can be redeemed monthly or more frequently, with 30 or less days of notice and without further restrictions.
 Derivative instruments. These instruments, consisting primarily of futures and swaps to manage risk, are recorded at fair value. Over-the-counter derivatives are valued daily, based on quoted prices in active markets and trade in open markets, and have been categorized as Level 1. Derivative instruments other than over-the-counter derivatives are valued based on external price data of comparable securities and have been categorized as Level 2.
 Private credit. Private credit investments primarily consist of investments in private debt strategies. These investments are generally less liquid assets with an underlying term of 3 to 5 years and are intended to be held to maturity. The fair value of these investments is determined by the fund manager or administrator using a combination of valuation models including cost models, market models, and income models and typically cannot be redeemed until maturity of the term loan. Managed private credit fund investments are not classified within the fair value hierarchy because their fair value is determined using NAV or its equivalent as a practical expedient.
 Private equity. These investments include those in limited partnerships that invest in operating companies that are not publicly traded on a stock exchange such as leveraged buyouts, growth capital, venture capital, distressed investments, and investments in natural resources. These investments typically cannot be redeemed and are generally liquidated over a period of 8 to 10 years from the initial investment date, which is based on Exelon's understanding of the investment funds. Private equity valuations are reported by the fund manager and are based on the valuation of the underlying investments, which include unobservable inputs such as cost, operating results, discounted future cash flows, and market based comparable data. The fair value of private equity investments is determined using NAV or its equivalent as a practical expedient, and therefore, these investments are not classified within the fair value hierarchy.
 Real estate. These investments are funds with a direct investment in pools of real estate properties. These funds are reported by the fund manager and are generally based on independent appraisals of the underlying

 investments from sources with professional qualifications, typically using a combination of market based comparable data and discounted cash flows. These valuation inputs are unobservable. Certain real estate investments cannot be redeemed and are generally liquidated over a period of 8 to 10 years from the initial investment date, which is based on Exelon's understanding of the investment funds. The remaining liquid real estate investments are generally redeemable from the investment vehicle quarterly, with 30 to 90 days of notice. The fair value of real estate investments is determined using NAV or its equivalent as a practical expedient, and therefore, these investments are not classified within the fair value hierarchy.
 Hedge funds. Hedge fund investments include those that employ a broad range of strategies to enhance returns and provide additional diversification. The fair value of hedge funds is determined using NAV or its equivalent as a practical expedient, and therefore, hedge funds are not classified within the fair value hierarchy. Exelon has the ability to redeem these investments at NAV or its equivalent subject to certain restrictions that may include a lock-up period or a gate.
 Defined Contribution Savings Plan
 The Registrants participate in a 401(k) defined contribution savings plan that is sponsored by Exelon. The plan is qualified under applicable sections of the IRC and allows employees to contribute a portion of their pre-tax and/or after-tax income in accordance with specified guidelines. All Registrants match a percentage of the employee contributions up to certain limits. The following table presents the employer contributions and employer matching contributions to the savings plan for the years ended December 31, 2024, 2023, and 2022:

 ComEd
 PECO
 BGE
 PHI
 Pepco
 DPL
 ACE

 2024
 $
 $
 $
 $
 $
 $
 $

 2023

 2022

 15. Derivative Financial Instruments (All Registrants)
 The Registrants use derivative instruments to manage commodity price risk and interest rate risk related to ongoing business operations. The Registrants do not execute derivatives for speculative or proprietary trading purposes.
 Authoritative guidance requires that derivative instruments be recognized as either assets or liabilities at fair value, with changes in fair value of the derivative recognized in earnings immediately. Other accounting treatments are available through special election and designation, provided they meet specific, restrictive criteria both at the time of designation and on an ongoing basis. These alternative permissible accounting treatments include NPNS, cash flow hedges, and fair value hedges. At ComEd, derivative economic hedges related to commodities are recorded at fair value and offset by a corresponding regulatory asset or liability. At Exelon, derivative economic hedges related to interest rates are recorded at fair value and offsets are recorded to Electric operating revenues or Interest expense based on the activity the transaction is economically hedging. For all NPNS derivative instruments, accounts receivable or accounts payable are recorded when derivatives settle and revenue or expense is recognized in earnings as the underlying physical commodity is sold or consumed. At Exelon, derivative hedges that qualify and are designated as cash flow hedges are recorded at fair value and offsets are recorded to AOCI.
 ComEd's use of cash collateral is generally unrestricted unless ComEd is downgraded below investment grade. Cash collateral held by PECO, BGE, Pepco, DPL, and ACE must be deposited in an unaffiliated major U.S. commercial bank or foreign bank with a U.S. branch office that meets certain qualifications.
 Commodity Price Risk
 The Utility Registrants employ established policies and procedures to manage their risks associated with market fluctuations in commodity prices by entering into physical and financial derivative contracts, which are either determined to be non-derivative or classified as economic hedges. The Utility Registrants procure electric and natural gas supply through a competitive procurement process approved by each of the respective state utility commissions. The Utility Registrants' hedging programs are intended to reduce exposure to energy and natural

 Note 15 — Derivative Financial Instruments

 gas price volatility and have no direct earnings impact as the costs are fully recovered from customers through regulatory-approved recovery mechanisms. The following table provides a summary of the Utility Registrants' primary derivative hedging instruments, listed by commodity and accounting treatment.

 Registrant
 Commodity
 Accounting Treatment
 Hedging Instrument

 ComEd
 NPNS
 Fixed price contracts based on all requirements in the IPA procurement plans.

 Changes in fair value of economic hedge recorded to an offsetting regulatory asset or liability(a)

 20-year floating-to-fixed energy swap contracts beginning June 2012 based on the renewable energy resource procurement requirements in the Illinois Settlement Legislation of approximately 1.3 million MWhs per year.

 PECO
 NPNS
 Fixed price contracts for default supply requirements through full requirements contracts.

 Gas
 NPNS
 Fixed price contracts to cover about 10 % of planned natural gas purchases in support of projected firm sales.

 BGE
 NPNS
 Fixed price contracts for all SOS requirements through full requirements contracts.

 Gas
 NPNS
 Fixed price purchases associated with forecasted gas supply requirements.

 Pepco
 NPNS
 Fixed price contracts for all SOS requirements through full requirements contracts.

 DPL
 NPNS
 Fixed price contracts for all SOS requirements through full requirements contracts.

 Gas
 NPNS
 Fixed and index priced contracts through full requirements contracts.

 Gas
 Changes in fair value of economic hedge recorded to an offsetting regulatory asset or liability(b)

 Exchange traded future contracts for up to 50 % of estimated monthly purchase requirements each month, including purchases for storage injections.

 ACE
 NPNS
 Fixed price contracts for all BGS requirements through full requirements contracts.

 (a)See Note 3—Regulatory Matters for additional information.
 (b)The fair value of the DPL economic hedge is not material as of December 31, 2024 and 2023.
 The fair value of derivative economic hedges is presented in Other current assets and current and noncurrent Mark-to-market derivative liabilities in Exelon's and ComEd's Consolidated Balance Sheets.
 Interest Rate and Other Risk (Exelon)
 Exelon Corporate uses a combination of fixed-rate and variable-rate debt to manage interest rate exposure. 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. In addition, Exelon Corporate utilized interest rate swaps to manage interest rate exposure and manage potential fluctuations in Electric operating revenues at the corporate level in consolidation. These interest rate swaps were accounted for as economic hedges. A hypothetical 50 basis point change in the interest rates associated with Exelon's interest rate swaps as of December 31, 2024 would result in an immaterial impact to Exelon's Consolidated Net Income.
 Below is a summary of the interest rate hedge balances at December 31, 2024 and 2023.

 Note 15 — Derivative Financial Instruments

 Derivatives Designated
as Hedging Instruments
 Economic Hedges
 Total

 Other current assets
 $
 $
 —
 $

 Other deferred debits (noncurrent assets)
 —

 Total derivative assets
 —

 Mark-to-market derivative liabilities (current liabilities)
 ( 1)
 —
 ( 1)

 Total mark-to-market derivative liabilities
 ( 1)
 —
 ( 1)

 Total mark-to-market derivative net assets
 $
 $
 —
 $

 Derivatives Designated
as Hedging Instruments
 Economic Hedges
 Total

 Other current assets
 $

 Total derivative assets

 Mark-to-market derivative liabilities (current liabilities)
 ( 24)
 ( 22)
 ( 46)

 Total mark-to-market derivative liabilities
 ( 24)
 ( 22)
 ( 46)

 Total mark-to-market derivative net liabilities
 $
 ( 13)
 $
 ( 21)
 $
 ( 34)

 Cash Flow Hedges (Interest Rate Risk)
 For derivative instruments that qualify and are designated as cash flow hedges, the changes in fair value each period are initially recorded in AOCI and reclassified into earnings when the underlying transaction affects earnings.
 In February 2024, Exelon terminated the previously issued floating-to-fixed swaps with a total notional of $ 1.3 billion upon issuance of $ 1.7 billion of debt. See Note 16 — Debt and Credit Agreements for additional information on the debt issuance. Prior to the termination, the AOCI derivative gain was $ 33 million (net of tax). The settlements resulted in a cash receipt of $ 30 million. The accumulated AOCI gain of $ 23 million (net of tax) is being amortized into Interest expense in Exelon's Consolidated Statement of Operations and Comprehensive Income over the 5-year and 10-year terms of the swaps. During the fourth quarter of 2024, Exelon Corporate entered into $ 55 million notional of 5-year maturity floating-to-fixed swaps and $ 55 million notional of 10-year maturity floating-to-fixed swaps, for a total notional of $ 110 million designated as cash flow hedges. The following table provides the notional amounts outstanding held by Exelon at December 31, 2024 and 2023.

 5-year maturity floating-to-fixed swaps
 $
 $

 10-year maturity floating-to-fixed swaps

 Total
 $
 1,315
 $
 1,310

 The AOCI derivative gain (net of tax) was $ 19 million as of December 31, 2024 and loss was $ 10 million as of December 31, 2023. See Note 21 – Changes in Accumulated Other Comprehensive Income (Loss) for additional information.
 Economic Hedges (Interest Rate and Other Risk)
 Exelon Corporate executes derivative instruments to mitigate exposure to fluctuations in interest rates but for which the fair value or cash flow hedge elections were not made. For derivatives intended to serve as economic hedges, fair value is recorded on the balance sheet and changes in fair value each period are recognized in earnings or as a regulatory asset or liability, if regulatory requirements are met, each period.

 Note 15 — Derivative Financial Instruments

 Exelon Corporate entered into floating-to-fixed interest rate cap swaps to manage a portion of interest rate exposure in connection with existing borrowings. As of December 31, 2023, Exelon held $ 1,000 million notional of floating-to-fixed interest rate cap swaps, which matured in March 2024. Exelon received payments on the interest rate cap when the floating rate exceeds the fixed rate. Settlements received were immaterial.
 Additionally, to manage potential fluctuations in Electric operating revenues related to ComEd's distribution formula rate, Exelon Corporate entered into a total of $ 4,875 million notional of 30-year constant maturity treasury interest rate (Corporate 30-year treasury) swaps from 2022 through 2023. The Corporate 30-year treasury swaps matured on December 31, 2023 and Exelon recorded a Mark-to-market liability of $ 22 million for the final settlement amount, which was paid in January 2024.
 Exelon Corporate recognized the following net pre-tax mark-to-market (losses) which are also recognized in Net fair value changes related to derivatives in Exelon's Consolidated Statements of Cash Flows.

 Twelve months ended December 31, 2024
 Twelve months ended December 31, 2023

 Income Statement Location
 Gain (Loss)
 Gain (Loss)

 $
 —
 $
 ( 20)

 Interest expense
 —
 —

 Total
 $
 —
 $
 ( 20)

 Credit Risk
 The Registrants would be exposed to credit-related losses in the event of non-performance by counterparties on executed derivative instruments. The credit exposure of derivative contracts, before collateral, is represented by the fair value of contracts at the reporting date. The Utility Registrants have contracts to procure electric and natural gas supply that provide suppliers with a certain amount of unsecured credit. If the exposure on the supply contract exceeds the amount of unsecured credit, the suppliers may be required to post collateral. The net credit exposure is mitigated primarily by the ability to recover procurement costs through customer rates. The amount of cash collateral received from external counterparties remained relatively consistent as of December 31, 2024 due to stable energy prices. The following table reflects the Registrants' cash collateral held from external counterparties, which is recorded in Other current liabilities on their respective Consolidated Balance Sheets, at December 31, 2024 and 2023

 $
 $

 ComEd

 PECO(a)

 —
 —

 BGE

 PHI

 Pepco

 DPL
 —

 ACE(a)

 —
 —

 (a)PECO and ACE had less than one million in cash collateral held with external parties as of December 31, 2024 and 2023
 (b)DPL had less than one million in cash collateral held with external parties at December 31, 2023.
 The Utility Registrants' electric supply procurement contracts do not contain provisions that would require them to post collateral. PECO's, BGE's, and DPL's natural gas procurement contracts contain provisions that could require PECO, BGE, and DPL to post collateral in the form of cash or credit support, which vary by contract and counterparty, with thresholds contingent upon PECO's, BGE's, and DPL's credit rating. As of December 31, 2024, PECO, BGE, and DPL were not required to post collateral for any of these agreements. If PECO, BGE, or DPL lost their investment grade credit rating as of December 31, 2024, they could have been required to post collateral to their counterparties of $ 51 million, $ 91 million, and $ 10 million, respectively.

 16. Debt and Credit Agreements (All Registrants)
 Short-Term Borrowings
 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 borrowings from 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.

 Commercial Paper
 The following table reflects the Registrants' commercial paper programs supported by the revolving credit agreements at December 31, 2024 and 2023:

 Credit Facility Size
at December 31,
 Outstanding Commercial
Paper at December 31,
 Average Interest Rate on
Commercial Paper Borrowings
at December 31,

 Commercial Paper Issuer
 2024(a)

 2023(a)

 2024
 2023
 2024
 2023

 Exelon(b)

 $
 4,000
 $
 4,000
 $
 1,359
 $
 1,624
 4.66
 %
 5.58
 %

 ComEd
 $
 1,000
 $
 1,000
 $
 $
 4.55
 %
 5.53
 %

 PECO
 $
 $
 $
 $
 4.65
 %
 5.57
 %

 BGE
 $
 $
 $
 $
 4.61
 %
 5.59
 %

 PHI(c)

 $
 $
 $
 $
 4.70
 %
 5.60
 %

 Pepco
 $
 (d)

 $
 $
 $
 4.69
 %
 5.59
 %

 DPL
 $
 (d)

 $
 $
 $
 4.74
 %
 5.60
 %

 ACE
 $
 (d)

 $
 $
 $
 4.67
 %
 5.60
 %

 (a)Excludes credit facility agreements arranged at minority and community banks. See below for additional information.
 (b)Includes revolving credit agreements at Exelon Corporate with a maximum program size of $ 900 million as of December 31, 2024 and December 31, 2023. Exelon Corporate had $ 426 million in outstanding commercial paper as of December 31, 2024 and $ 527 million outstanding commercial paper as of December 31, 2023.
 (c)Represents the consolidated amounts of Pepco, DPL, and ACE.
 (d) The standard maximum program size for revolving credit facilities is $ 300 million each for Pepco, DPL and ACE based on the credit agreements in place. However, the facilities at Pepco, DPL, and ACE have the ability to flex to $ 500 million, $ 500 million, and $ 350 million, respectively. The borrowing capacity may be increased or decreased during the term of the facility, except that (i) the sum of the borrowing capacity must equal the total amount of the facility, and (ii) the aggregate amount of credit used at any given time by each of Pepco, DPL, or ACE may not exceed $ 900 million or the maximum amount of short-term debt the company is permitted to have outstanding by its regulatory authorities. The total number of the borrowing reallocations may not exceed eight per year during the term of the facility. In January 2025, this ability was utilized to increase Pepco's program size to $ 340 million. As a result, the program size for ACE did not change and DPL was decreased to $ 260 million, which prevents the aggregate amount of outstanding short-term debt from exceeding the $ 900 million limit.
 In order to maintain their respective commercial paper programs in the amounts indicated above, each Registrant must have credit facilities in place, at least equal to the amount of its commercial paper program. A registrant does not issue commercial paper in an aggregate amount exceeding the then available capacity under its credit facility.

 At December 31, 2024, the Registrants had the following aggregate bank commitments, credit facility borrowings, and available capacity under their respective credit facilities:

 Available Capacity at December 31, 2024

 Borrower
 Facility Type
 Aggregate Bank
Commitment(a)

 Facility Draws
 Outstanding
Letters of Credit
 Actual
 To Support
 Additional
 Commercial
Paper(b)

 Exelon(b)

 $
 4,000
 $
 —
 $
 $
 3,951
 $
 2,592

 ComEd
 1,000
 —

 PECO
 —

 BGE
 —

 PHI(c)

 —

 Pepco
 —

 DPL
 —
 —

 ACE
 —
 —

 (a)Excludes credit facility agreements arranged at minority and community banks. See below for additional information.
 (b)Includes $ 900 million aggregate bank commitment related to Exelon Corporate. Exelon Corporate had $ 3 million outstanding letters of credit as of December 31, 2024. Exelon Corporate had $ 471 million in available capacity to support additional commercial paper as of December 31, 2024.
 (c)Represents the consolidated amounts of Pepco, DPL, and ACE.
 The following table reflects the Registrants' credit facility agreements arranged at minority and community banks at December 31, 2024 and 2023. These are excluded from the Maximum Program Size and Aggregate Bank Commitment amounts within the two tables above and the facilities may be used to issue letters of credit.

 Aggregate Bank Commitments
 Outstanding Letters of Credit

 Borrower
 2024(a)

 2023
 2024
 2023

 Exelon(b)

 $
 $
 $
 $

 ComEd

 PECO
 —

 BGE

 PHI(c)

 —
 —

 Pepco
 —
 —

 DPL
 —
 —

 ACE
 —
 —

 (a)These facilities were entered into on October 4, 2024 and expire on October 3, 2025.
 (b)Represents the consolidated amounts of ComEd, PECO, BGE, Pepco, DPL, and ACE.
 (c)Represents the consolidated amounts of Pepco, DPL, and ACE.
 Revolving Credit Agreements
 On August 29, 2024, Exelon Corporate and each of the Utility Registrants amended and restated their respective syndicated revolving credit facility, extending the maturity date to August 29, 2029. The following table reflects the credit agreements:

 Borrower
 Aggregate Bank Commitment

 Exelon Corporate
 $
 SOFR plus 1.275 %

 ComEd
 $
 1,000
 SOFR plus 1.000 %

 PECO
 $
 SOFR plus 0.900 %

 BGE
 $
 SOFR plus 0.900 %

 Pepco
 $
 SOFR plus 1.075 %

 DPL
 $
 SOFR plus 1.000 %

 ACE
 $
 SOFR plus 1.000 %

 Borrowings under Exelon's, ComEd's, PECO's, BGE's, Pepco's, DPL's, and ACE's revolving credit agreements bear interest at a rate based upon either the prime rate or a SOFR-based rate, plus an adder based upon the particular Registrant's credit rating. The adders for the prime based borrowings and SOFR-based borrowings as of December 31, 2024 are presented in the following table:

 ComEd
 PECO
 BGE
 Pepco
 DPL
 ACE

 Prime based borrowings
 0 - 27.5

 —
 —
 —
 7.5
 —
 —

 SOFR-based borrowings
 90.0 - 127.5

 100.0
 90.0
 90.0
 107.5
 100.0
 100.0

 (a)Includes interest rate adders at Exelon Corporate of 27.5 basis points and 127.5 basis points for prime and SOFR-based borrowings, respectively.
 If any registrant loses its investment grade rating, the maximum adders for prime rate borrowings and SOFR-based rate borrowings would be 65 basis points and 165 basis points, respectively. The credit agreements also require the borrower to pay a facility fee based upon the aggregate commitments. The fee varies depending upon the respective credit ratings of the borrower. Exelon Corporate and the Utility Registrants had no outstanding amounts on the revolving credit facilities as of December 31, 2024.
 Short-Term Loan Agreements
 On March 23, 2017, Exelon Corporate entered into a term loan agreement for $ 500 million. The loan agreement was renewed in the first quarter of 2024 and was bifurcated into two tranches of $ 350 million and $ 150 million on March 14, 2024. The agreements will expire on March 14, 2025. Pursuant to the loan agreements, loans made thereunder bear interest at a variable rate equal to SOFR plus 1.05 % and all indebtedness thereunder is unsecured. The loan agreement is reflected in Exelon's Consolidated Balance Sheets within Short-term borrowings.
 On May 9, 2023, ComEd entered into a 364-day term loan agreement for $ 400 million with a variable rate equal to SOFR plus 1.00 % and an expiration date of May 7, 2024. On May 1, 2024, ComEd entered into an agreement to extend the loan through the expiration date of June 28, 2024. The original proceeds from the loan were used to repay outstanding commercial paper obligations and for general corporate purposes. The balance of the loan was repaid on May 16, 2024.
 Variable Rate Demand Bonds
 DPL has outstanding obligations in respect of Variable Rate Demand Bonds (VRDB). VRDBs are subject to repayment on the demand of the holders and, for this reason, are accounted for as short-term debt in accordance with GAAP. However, these bonds may be converted to a fixed-rate, fixed-term option to establish a maturity which corresponds to the date of final maturity of the bonds. On this basis, PHI views VRDBs as a source of long-term financing. As of December 31, 2024 and December 31, 2023, $ 46 million and $ 79 million in variable rate demand bonds issued by DPL were outstanding and are included in the Long-term debt due within one year in Exelon's, PHI's, and DPL's Consolidated Balance Sheets.
 Long-Term Debt

 The following tables present the outstanding long-term debt at the Registrants at December 31, 2024 and 2023:

Date

 Rates
 2024
 2023

 1.05
 %
 -
 7.90
 %
 $
 26,451
 $
 24,776

 Senior unsecured notes
 2.75
 %
 -
 7.60
 %
 2025 - 2053
 12,280
 10,824

 Unsecured notes
 2.25
 %
 -
 6.35
 %
 5,450
 4,650

 Notes payable and other
 1.64
 %
 -
 7.49
 %
 2025 - 2053

 Long-term software licensing agreement
 2.30
 %
 -
 2.30
 %
 2025

 Unsecured tax-exempt bonds
 4.15
 %
 -
 4.20
 %
 2024
 —

 Medium-terms notes (unsecured)
 7.72
 %
 2027

 Loan agreement(b)

 6.23
 %
 2024
 —

 44,278
 40,889

 ( 94)
 ( 80)

 ( 326)
 ( 296)

 Fair value adjustment

 ( 1,453)
 ( 1,403)

 $
 42,947
 $
 39,692

 Long-term debt to financing trusts(c)

 Subordinated debentures to ComEd Financing III
 6.35
 %
 2033
 $
 $

 Subordinated debentures to PECO Trust III
 7.38
 %
 -
 9.50
 %
 2028

 Subordinated debentures to PECO Trust IV
 5.75
 %
 2033

 Total long-term debt to financing trusts
 $
 $

 (a)Substantially all of ComEd's assets other than expressly excluded property and substantially all of PECO's, Pepco's, DPL's, and ACE's assets are subject to the liens of their respective mortgage indentures.
 (b)Pursuant to the loan agreement, loans made thereunder bear interest at a variable rate equal to SOFR plus 0.85 %.
 (c)Amounts owed to these financing trusts are recorded as Long-term debt to financing trusts within Exelon's Consolidated Balance Sheets.

 ComEd

Date

 Rates
 2024
 2023

 2.20
 %
 -
 6.45
 %
 $
 12,154
 $
 11,603

 Other
 7.49
 %
 2053

 12,162
 11,611

 ( 31)
 ( 28)

 ( 101)
 ( 97)

 —
 ( 250)

 $
 12,030
 $
 11,236

 Long-term debt to financing trust(b)

 Subordinated debentures to ComEd Financing III
 6.35
 %
 2033
 $
 $

 Total long-term debt to financing trusts

 —
 ( 1)

 Long-term debt to financing trusts
 $
 $

 (a)Substantially all of ComEd's assets, other than expressly excluded property, are subject to the lien of its mortgage indenture.
 (b)Amount owed to this financing trust is recorded as Long-term debt to financing trust within ComEd's Consolidated Balance Sheets.
 PECO

Date

 Rates
 2024
 2023

 2.80
 %
 -
 5.95
 %
 $
 5,775
 $
 5,200

 5,775
 5,200

 ( 25)
 ( 24)

 ( 46)
 ( 42)

 ( 350)
 —

 $
 5,354
 $
 5,134

 Long-term debt to financing trusts(b)

 Subordinated debentures to PECO Trust III
 7.38
 %
 -
 9.50
 %
 2028
 $
 $

 Subordinated debentures to PECO Trust IV
 5.75
 %
 2033

 Long-term debt to financing trusts
 $
 $

 (a)Substantially all of PECO's assets are subject to the lien of its mortgage indenture.
 (b)Amounts owed to this financing trust are recorded as Long-term debt to financing trusts within PECO's Consolidated Balance Sheets.

 BGE

Date

 Rates
 2024
 2023

 Unsecured notes
 2.25
 %
 -
 6.35
 %
 $
 5,450
 $
 4,650

 5,450
 4,650

 ( 13)
 ( 12)

 ( 42)
 ( 36)

 —
 —

 $
 5,395
 $
 4,602

 PHI

Date

 Rates
 2024
 2023

 1.05
 %
 -
 7.90
 %
 $
 8,522
 $
 7,972

 Senior unsecured notes

 7.45
 %
 2032

 Unsecured tax-exempt bonds
 4.15
 %
 -
 4.20
 %
 2024
 —

 Medium-terms notes (unsecured)
 7.72
 %
 2027

 5.62
 %

 8,792
 8,274

 ( 2)
 —

 ( 66)
 ( 55)

 Fair value adjustment

 ( 290)
 ( 644)

 $
 8,834
 $
 8,004

 (a)Substantially all of Pepco's, DPL's, and ACE's assets are subject to the liens of their respective mortgage indentures.
 Pepco

Date

 Rates
 2024
 2023

 2.32
 %
 -
 7.90
 %
 2029 - 2054
 $
 4,400
 $
 4,125

 5.62
 %

 4,427
 4,151

 —

 ( 65)
 ( 57)

 ( 6)

 $
 4,356
 $
 3,691

 ________
 (a)Substantially all of Pepco's assets are subject to the lien of its mortgage indenture.
 DPL

Date

 Rates
 2024
 2023

 1.05
 %
 -
 5.72
 %
 $
 2,198
 $
 2,024

 Unsecured tax-exempt bonds
 4.15
 %
 -
 4.20
 %
 2024
 —

 Medium-terms notes (unsecured)

 7.72
 %
 2027

 5.62
 %

 2,236
 2,096

 ( 16)
 ( 16)

 ( 130)
 ( 84)

 $
 2,090
 $
 1,996

 (a)Substantially all of DPL's assets are subject to the lien of its mortgage indenture.

 ACE

Date

 Rates
 2024
 2023

 2.25
 %
 -
 5.80
 %
 $
 1,923
 $
 1,823

 5.62
 %

 1,943
 1,842

 ( 10)
 ( 9)

 ( 154)
 ( 154)

 $
 1,779
 $
 1,679

 (a)Substantially all of ACE's assets are subject to the lien of its mortgage indenture.

 Long-term debt maturities at the Registrants in the periods 2025 through 2029 and thereafter are as follows:

 Year

 ComEd
 PECO
 BGE
 PHI
 Pepco
 DPL
 ACE

 2025
 $
 1,453
 $
 —
 $
 $
 —

 $
 $
 $
 $

 2026
 1,618
 —

 2027
 1,025
 —
 —

 2028
 1,992
 —

 2029
 —
 —
 —

 Thereafter
 37,650
 (a)

 10,968
 (b)

 5,528
 (c)

 5,100
 7,816
 4,252
 2,076
 1,302

 Total
 $
 44,668
 $
 12,368
 $
 5,959
 $
 5,450
 $
 8,792
 $
 4,427
 $
 2,236
 $
 1,943

 (a)Includes $ 390 million due to ComEd and PECO financing trusts.
 (b)Includes $ 206 million due to ComEd financing trust.
 (c)Includes $ 184 million due to PECO financing trusts.
 Debt Extinguishment
 During the twelve months ended December 31, 2024, Exelon repurchased a portion of its Senior unsecured notes with a principal balance of $ 244 million outstanding in exchange for cash of $ 215 million. The repurchase was accounted for as a debt extinguishment and resulted in a pre-tax gain of $ 28 million, which is reflected on Exelon's Consolidated Statement of Operations and Comprehensive income within Interest expense, net.
 Debt Covenants
 As of December 31, 2024, the Registrants are in compliance with debt covenants.

 17. Fair Value of Financial Assets and Liabilities (All Registrants)
 Exelon measures and classifies fair value measurements in accordance with the hierarchy as defined by GAAP. The hierarchy prioritizes the inputs to valuation techniques used to measure fair value into three levels as follows:
 • Level 1 — quoted prices (unadjusted) in active markets for identical assets or liabilities that the Registrants have the ability to liquidate as of the reporting date.
 • Level 2 — inputs other than quoted prices included within Level 1 that are directly observable for the asset or liability or indirectly observable through corroboration with observable market data.
 • Level 3 — unobservable inputs, such as internally developed pricing models or third-party valuations for the asset or liability due to little or no market activity for the asset or liability.

 Fair Value of Financial Liabilities Recorded at Amortized Cost
 The following tables present the carrying amounts and fair values of the Registrants' short-term liabilities, long-term debt, and trust preferred securities (long-term debt to financing trusts or junior subordinated debentures) at December 31, 2024 and 2023. The Registrants have no financial liabilities classified as Level 1 or measured using the NAV practical expedient.
 The carrying amounts of the Registrants' short-term liabilities as presented in their Consolidated Balance Sheets are representative of their fair value (Level 2) because of the short-term nature of these instruments.

 Carrying Amount
 Fair Value
 Carrying Amount
 Fair Value

 Total
 Total

 Long-Term Debt, including amounts due within one year(a)

 $
 44,400
 $
 —
 $
 35,337
 $
 3,720
 $
 39,057
 $
 41,095
 $
 —
 $
 33,804
 $
 3,442
 $
 37,246

 ComEd
 12,030
 —
 10,260
 —
 10,260
 11,486
 —
 10,210
 —
 10,210

 PECO
 5,704
 —
 4,816
 —
 4,816
 5,134
 —
 4,562
 —
 4,562

 BGE
 5,395
 —
 4,702
 —
 4,702
 4,602
 —
 4,145
 —
 4,145

 PHI
 9,124
 —
 4,093
 3,720
 7,813
 8,648
 —
 4,160
 3,442
 7,602

 Pepco
 4,362
 —
 2,475
 1,544
 4,019
 4,096
 —
 2,311
 1,600
 3,911

 DPL
 2,220
 —
 1,250
 1,873
 2,080
 —
 1,134
 1,828

 ACE
 1,933
 —
 1,712
 1,833
 —
 1,647

 Long-Term Debt to Financing Trusts

 $
 $
 —
 $
 —
 $
 $
 $
 $
 —
 $
 —
 $
 $

 ComEd
 —
 —
 —
 —

 PECO
 —
 —
 —
 —

 (a)Includes unamortized debt issuance costs, unamortized debt discount and premium, net, purchase accounting fair value adjustments, and finance lease liabilities which are not fair valued. Refer to Note 16 — Debt and Credit Agreements for unamortized debt issuance costs, unamortized debt discount and premium, net, and purchase accounting fair value adjustments and Note 10 — Leases for finance lease liabilities.

 Exelon uses the following methods and assumptions to estimate fair value of financial liabilities recorded at carrying cost:

 Type
 Level
 Registrants
 Valuation

 Long-Term Debt, including amounts due within one year

 Taxable Debt Securities
 All
 The fair value is determined by a valuation model that is based on a conventional discounted cash flow methodology and utilizes assumptions of current market pricing curves. Exelon obtains credit spreads based on trades of existing Exelon debt securities as well as other issuers in the utility sector with similar credit ratings. The yields are then converted into discount rates of various tenors that are used for discounting the respective cash flows of the same tenor for each bond or note.

 Variable Rate Financing Debt
 Exelon, DPL
 Debt rates are reset on a regular basis and the carrying value approximates fair value.

 Non-Government Backed Fixed Rate Nonrecourse Debt
 Fair value is based on market and quoted prices for its own and other nonrecourse debt with similar risk profiles. Given the low trading volume in the nonrecourse debt market, the price quotes used to determine fair value will reflect certain qualitative factors, such as market conditions, investor demand, new developments that might significantly impact the project cash flows or off-taker credit, and other circumstances related to the project.

 Taxable Private Placement Debt Securities
 Exelon, Pepco, DPL, ACE
 Rates are obtained similar to the process for taxable debt securities. Due to low trading volume and qualitative factors such as market conditions, low volume of investors, and investor demand, these debt securities are Level 3.

 Long-Term Debt to Financing Trusts

 Long Term Debt to Financing Trusts
 Exelon, ComEd, PECO
 Fair value is based on publicly traded securities issued by the financing trusts. Due to low trading volume of these securities and qualitative factors, such as market conditions, investor demand, and circumstances related to each issue, this debt is classified as Level 3.

 Recurring Fair Value Measurements
 The following tables present assets and liabilities measured and recorded at fair value in the Registrants' Consolidated Balance Sheets on a recurring basis and their level within the fair value hierarchy at December 31, 2024 and 2023. Exelon and the Utility Registrants have immaterial and no financial assets or liabilities measured using the NAV practical expedient, respectively:

 Total
 Total

 $
 $
 —
 $
 —
 $
 $
 $
 —
 $
 —
 $

 Cash equivalents
 —
 —
 —
 —

 Mutual funds
 —
 —
 —
 —

 Fixed income
 —
 —
 —
 —

 —
 —

 Interest rate derivative assets

 Derivatives designated as hedging instruments
 —
 —
 —
 —

 Economic hedges
 —
 —
 —
 —
 —
 —

 Interest rate derivative assets subtotal
 —
 —
 —
 —

 Commodity derivative liabilities
 —
 —
 —
 —

 Interest rate derivative liabilities

 Derivatives designated as hedging instruments
 —
 ( 1)
 —
 ( 1)
 —
 ( 24)
 —
 ( 24)

 Economic hedges
 —
 —
 —
 —
 —
 ( 22)
 —
 ( 22)

 Interest rate derivative liabilities subtotal
 —
 ( 1)
 —
 ( 1)
 —
 ( 46)
 —
 ( 46)

 —
 ( 74)
 —
 ( 74)
 —
 ( 75)
 —
 ( 75)

 —
 ( 75)
 ( 207)
 —
 ( 121)
 ( 254)

 Total net assets (liabilities)
 $
 $
 $
 ( 110)
 $
 $
 $
 ( 41)
 $
 ( 90)
 $

 (a)Excludes cash of $ 219 million and $ 334 million at December 31, 2024 and 2023, respectively, and restricted cash of $ 176 million and $ 149 million at December 31, 2024 and 2023, respectively, and includes long-term restricted cash of $ 41 million and $ 174 million at December 31, 2024 and 2023, respectively, which is reported in Other deferred debits in the Consolidated Balance Sheets.
 ComEd, PECO, and BGE

 ComEd
 PECO
 BGE

 Total
 Total
 Total

 $
 $
 —
 $
 —
 $
 $
 $
 —
 $
 —
 $
 $
 $
 —
 $
 —
 $

 Mutual funds
 —
 —
 —
 —
 —
 —
 —
 —

 —
 —
 —
 —
 —
 —
 —
 —
 —
 —

 —
 —
 —
 —
 —
 —
 —

 —
 —
 —
 —
 —

 Commodity derivative liabilities(b)

 —
 —
 —
 —
 —
 —
 —
 —
 —
 —

 —
 ( 8)
 —
 ( 8)
 —
 ( 7)
 —
 ( 7)
 —
 ( 4)
 —
 ( 4)

 —
 ( 8)
 ( 140)
 —
 ( 7)
 —
 ( 7)
 —
 ( 4)
 —
 ( 4)

 Total net assets (liabilities)
 $
 $
 ( 8)
 $
 $
 $
 $
 $
 —
 $
 $
 $
 ( 4)
 $
 —
 $

 ComEd
 PECO
 BGE

 Total
 Total
 Total

 $
 $
 —
 $
 —
 $
 $
 $
 —
 $
 —
 $
 $
 —
 $
 —
 $
 —
 $
 —

 Mutual funds
 —
 —
 —
 —
 —
 —
 —
 —

 —
 —
 —
 —
 —
 —
 —
 —
 —
 —

 —
 —
 —
 —
 —
 —
 —

 —
 —
 —
 —
 —

 Commodity derivative liabilities(b)

 —
 —
 —
 —
 —
 —
 —
 —
 —
 —

 —
 ( 8)
 —
 ( 8)
 —
 ( 8)
 —
 ( 8)
 —
 ( 4)
 —
 ( 4)

 —
 ( 8)
 ( 141)
 —
 ( 8)
 —
 ( 8)
 —
 ( 4)
 —
 ( 4)

 Total net assets (liabilities)
 $
 $
 ( 8)
 $
 $
 $
 $
 $
 —
 $
 $
 $
 ( 4)
 $
 —
 $

 (a)ComEd excludes cash of $ 66 million and $ 86 million at December 31, 2024 and 2023, respectively, and restricted cash of $ 176 million and $ 147 million at December 31, 2024 and 2023, respectively, and includes long-term restricted cash of $ 41 million and $ 174 million at December 31, 2024 and 2023, respectively, which is reported in Other deferred debits in the Consolidated Balance Sheets. PECO excludes cash of $ 19 million and $ 42 million at December 31, 2024 and 2023, respectively. BGE excludes cash of $ 33 million and $ 47 million at December 31, 2024 and 2023, respectively, and restricted cash of zero and $ 1 million at December 31, 2024 and 2023, respectively.
 (b)The Level 3 balance consists of the current and noncurrent liability of $ 29 million and $ 103 million, respectively, at December 31, 2024, and $ 27 million and $ 106 million, respectively, at December 31, 2023 related to floating-to-fixed energy swap contracts with unaffiliated suppliers.
 PHI, Pepco, DPL, and ACE

 PHI
 Total
 Total

 $
 $
 —
 $
 —
 $
 $
 $
 —
 $
 —
 $

 Cash equivalents
 —
 —
 —
 —

 Mutual funds
 —
 —
 —
 —

 Fixed income
 —
 —
 —
 —

 —
 —

 —
 ( 12)
 —
 ( 12)
 —
 ( 13)
 —
 ( 13)

 —
 ( 12)
 —
 ( 12)
 —
 ( 13)
 —
 ( 13)

 Total net assets
 $
 $
 $
 $
 $
 $
 $
 $

 Pepco
 DPL
 ACE

 Total
 Total
 Total

 $
 $
 —
 $
 —
 $
 $
 $
 —
 $
 —
 $
 $
 —
 $
 —
 $
 —
 $
 —

 Cash equivalents
 —
 —
 —
 —
 —
 —
 —
 —
 —
 —

 —
 —
 —
 —
 —
 —
 —
 —
 —

 —
 —
 —
 —
 —
 —
 —
 —

 —
 —
 —
 —
 —
 —

 —
 ( 1)
 —
 ( 1)
 —
 —
 —
 —
 —
 —
 —
 —

 —
 ( 1)
 —
 ( 1)
 —
 —
 —
 —
 —
 —
 —
 —

 Total net assets
 $
 $
 $
 $
 $
 $
 —
 $
 —
 $
 $
 —
 $
 —
 $
 —
 $
 —

 Pepco
 DPL
 ACE

 Total
 Total
 Total

 $
 $
 —
 $
 —
 $
 $
 $
 —
 $
 —
 $
 $
 —
 $
 —
 $
 —
 $
 —

 Cash equivalents
 —
 —
 —
 —
 —
 —
 —
 —
 —
 —

 —
 —
 —
 —
 —
 —
 —
 —
 —

 —
 —
 —
 —
 —
 —
 —
 —

 —
 —
 —
 —
 —
 —

 —
 ( 1)
 —
 ( 1)
 —
 —
 —
 —
 —
 —
 —
 —

 —
 ( 1)
 —
 ( 1)
 —
 —
 —
 —
 —
 —
 —
 —

 Total net assets
 $
 $
 $
 $
 $
 $
 —
 $
 —
 $
 $
 —
 $
 —
 $
 —
 $
 —

 (a)PHI excludes cash of $ 70 million and $ 96 million at December 31, 2024 and 2023, respectively, and restricted cash of zero and $ 1 million at December 31, 2024 and 2023, respectively. Pepco excludes cash of $ 30 million and $ 48 million at December 31, 2024 and 2023, respectively, and restricted cash of zero and $ 1 million at December 31, 2024 and 2023, respectively. DPL excludes cash of $ 20 million and $ 15 million at December 31, 2024 and 2023, respectively. ACE excludes cash of $ 14 million and $ 21 million at December 31, 2024 and 2023, respectively.

 Reconciliation of Level 3 Assets and Liabilities
 The following tables present the fair value reconciliation of Level 3 assets and liabilities measured at fair value on a recurring basis during the years ended December 31, 2024 and 2023:

 ComEd
 PHI and Pepco

 Total
 Commodity
Derivatives
 Life Insurance Contracts

 $
 ( 90)
 $
 $

 Total realized / unrealized gains (losses)

 Included in net income(a)

 —

 Included in regulatory assets/liabilities
 (b)

 —

 Purchases, sales, and settlements

 Settlements
 ( 22)
 —
 ( 22)

 $
 ( 110)
 $
 (c)

 $

 The amount of total gains included in income attributed to the change in unrealized gains (losses) related to assets and liabilities as of December 31, 2024
 $
 $
 —
 $

 ComEd
 PHI and Pepco

 Total
 Commodity
Derivatives
 Life Insurance Contracts

 $
 ( 44)
 $
 ( 84)
 $

 Total realized / unrealized gains (losses)

 Included in net income(a)

 —

 Included in regulatory assets/liabilities
 ( 49)
 ( 49)
 (b)

 —

 $
 ( 90)
 $
 (c)

 $

 The amount of total gains included in income attributed to the change in unrealized gains (losses) related to assets and liabilities as of December 31, 2023
 $
 $
 —
 $

 (a)Classified in Operating and maintenance expense in the Consolidated Statements of Operations and Comprehensive Income.
 (b)Includes $ 40 million of decreases in fair value and an increase for realized gains due to settlements of $ 40 million recorded in Purchased power expense associated with floating-to-fixed energy swap contracts with unaffiliated suppliers for the year ended December 31, 2024. Includes $ 83 million of decreases in fair value and an increase for realized gains due to settlements of $ 34 million recorded in Purchased power expense associated with floating-to-fixed energy swap contracts with unaffiliated suppliers for the year ended December 31, 2023.
 (c)The balance of the current and noncurrent asset was effectively zero as of December 31, 2024. The balance consists of a current and noncurrent liability of $ 29 million and $ 103 million, respectively, as of December 31, 2024.
 Valuation Techniques Used to Determine Fair Value
 Cash Equivalents (All Registrants). Investments with original maturities of three months or less when purchased, including mutual and money market funds, are considered cash equivalents. The fair values are based on observable market prices and, therefore, are included in the recurring fair value measurements hierarchy as Level 1.
 Rabbi Trust Investments (Exelon, PECO, BGE, PHI, Pepco, DPL, and ACE). The Rabbi trusts were established to hold assets related to deferred compensation plans existing for certain active and retired members of Exelon's executive management and directors. The Rabbi trusts' assets are included in Investments in the Registrants' Consolidated Balance Sheets and consist primarily of money market funds, mutual funds, fixed income securities, and life insurance policies. Money market funds and mutual funds are publicly quoted and have been categorized as Level 1 given the clear observability of the prices. The fair values of fixed income securities are based on evaluated prices that reflect observable market information, such as actual trade information or similar securities, adjusted for observable differences and are categorized in Level 2. The life

 insurance policies are valued using the cash surrender value of the policies, net of loans against those policies, which is provided by a third-party. Certain life insurance policies, which consist primarily of mutual funds that are priced based on observable market data, have been categorized as Level 2 because the life insurance policies can be liquidated at the reporting date for the value of the underlying assets. Life insurance policies that are valued using unobservable inputs have been categorized as Level 3, where the fair value is determined based on the cash surrender value of the policy, which contains unobservable inputs and assumptions. Because Exelon relies on its third-party insurance provider to develop the inputs without adjustment for the valuations of its Level 3 investments, quantitative information about significant unobservable inputs used in valuing these investments is not reasonably available to Exelon. Therefore, Exelon has not disclosed such inputs.
 Interest Rate Derivatives (Exelon) Exelon may utilize fixed-to-floating or floating-to-fixed interest rate swaps as a means to manage interest rate risk. These interest rate swaps are typically accounted for as economic hedges. In addition, Exelon may utilize interest rate derivatives to lock in interest rate levels in anticipation of future financings. These interest rate derivatives are typically designated as cash flow hedges. Exelon determines the current fair value by calculating the net present value of expected payments and receipts under the swap agreement, based on and discounted by the market's expectation of future interest rates. Additional inputs to the net present value calculation may include the contract terms, counterparty credit risk and other market parameters. As these inputs are based on observable data and valuations of similar instruments, the interest rate swaps are categorized as Level 2 in the fair value hierarchy. See Note 15 — Derivative Financial Instruments for additional information on mark-to-market derivatives.
 Deferred Compensation Obligations (All Registrants). The Registrants' deferred compensation plans allow participants to defer certain cash compensation into a notional investment account. The Registrants include such plans in other current and noncurrent liabilities in their Consolidated Balance Sheets. The value of the Registrants' deferred compensation obligations is based on the market value of the participants' notional investment accounts. The underlying notional investments are comprised primarily of equities, mutual funds, commingled funds, and fixed income securities which are based on directly and indirectly observable market prices. Since the deferred compensation obligations themselves are not exchanged in an active market, they are categorized as Level 2 in the fair value hierarchy.
 The value of certain employment agreement obligations (which are included with the Deferred Compensation Obligation in the tables above) are based on a known and certain stream of payments to be made over time and are categorized as Level 2 within the fair value hierarchy.
 Commodity Derivatives (Exelon and ComEd). On December 17, 2010, ComEd entered into several 20-year floating to fixed energy swap contracts with unaffiliated suppliers for the procurement of long-term renewable energy and associated RECs. Delivery under the contracts began in June 2012. The fair value of these swaps has been designated as a Level 3 valuation due to the long tenure of the positions and the internal modeling assumptions. The modeling assumptions include using forward power prices. See Note 15 — Derivative Financial Instruments for additional information on mark-to-market derivatives.
 The following table discloses the significant unobservable inputs to the forward curve used to value mark-to-market derivatives:

 Type of trade
 Fair Value as of December 31, 2024
 Fair Value as of December 31, 2023
 Valuation
Technique
 Unobservable
Input
 2024 Range & Arithmetic Average
 2023 Range & Arithmetic Average

 Commodity derivatives
 $
 $
 Discounted Cash Flow
 Forward power price(a)

 $
 30.31
 -
 $
 59.88
 $
 42.08
 $
 30.27
 -
 $
 73.71
 $
 43.35

 (a)An increase to the forward power price would increase the fair value.

 18. Commitments and Contingencies (All Registrants)
 Commitments
 PHI Merger Commitments (Exelon, PHI, Pepco, DPL, and ACE). Approval of the PHI Merger in Delaware, New Jersey, Maryland, and the District of Columbia was conditioned upon Exelon and PHI agreeing to certain

 commitments. The following amounts represent total commitment costs that have been recorded since the acquisition date and the total remaining obligations for Exelon, PHI, Pepco, DPL, and ACE at December 31, 2024:

 PHI
 Pepco
 DPL
 ACE

 Total commitments
 $
 $
 $
 $
 $

 Remaining commitments(a)

 —

 (a)Remaining commitments extend through 2026 and include escrow funds, charitable contributions, and rate credits.

 Commercial Commitments (All Registrants). The Registrants' commercial commitments at December 31, 2024, representing commitments potentially triggered by future events were as follows:

 Expiration within

 Total
 2025
 2026
 2027
 2028
 2029
 2030 and beyond

 $

 $

 $

 $
 —

 $
 —

 $
 —
 $
 —

 —
 —
 —

 Financing trust guarantees(c)

 —
 —
 —
 —

 —

 $

 $

 $

 $

 $
 $
 $

 ComEd

 $
 $
 $
 $
 —
 $
 —
 $
 —
 $
 —

 —
 —
 —
 —

 Financing trust guarantees(c)

 —
 —
 —
 —
 —

 $

 $

 $

 $

 $
 —
 $
 —
 $

 PECO

 $
 $
 $
 —
 $
 —
 $
 —
 $
 —
 $
 —

 —
 —
 —
 —
 —

 Financing trust guarantees(c)

 —
 —
 —
 —

 $

 $

 $
 —

 $
 —

 $
 $
 —
 $

 BGE

 $
 $
 $
 —
 $
 —
 $
 —
 $
 —
 $
 —

 —
 —
 —
 —
 —

 $

 $

 $
 —

 $
 —

 $
 —
 $
 —
 $
 —

 PHI

 $
 $
 $
 —
 $
 —
 $
 —
 $
 —
 $
 —

 —
 —
 —
 —

 —

 $

 $

 $

 $

 $
 $
 $

 Pepco

 $
 $
 $
 —
 $
 —
 $
 —
 $
 —
 $
 —

 —
 —
 —
 —

 —

 $

 $

 $

 $

 $
 $
 $

 DPL

 $
 $
 $
 —
 $
 —
 $
 —
 $
 —
 $
 —

 —
 —
 —
 —
 —

 —

 $

 $

 $

 $

 $
 $
 $

 ACE

 $
 $
 $
 —
 $
 —
 $
 —
 $
 —
 $
 —

 —

 $

 $

 $

 $

 $
 $
 $

 (a)Exelon and certain of its subsidiaries maintain non-debt letters of credit to provide credit support for certain transactions as requested by third parties.
 (b)Surety bonds—Guarantees issued related to contract and commercial agreements, excluding bid bonds. Historically, payments under the guarantees have not been made and the likelihood of payments being required is remote.
 (c)Reflects guarantee of ComEd and PECO securities held by ComEd Financing III, PECO Trust III, and PECO Trust IV.
 (d)Represents the maximum potential obligation in the event the fair value of certain leased equipment and fleet vehicles is zero at the end of the maximum lease term. The lease term associated with these assets ranges from 1 to 8 years. The maximum potential obligation at the end of the minimum lease term would be $ 60 million guaranteed by Exelon and PHI, of which $ 20 million, $ 23 million, and $ 17 million is guaranteed by Pepco, DPL, and ACE, respectively. Historically, payments under the guarantees have not been made and PHI believes the likelihood of payments being required under the guarantees is remote.
 Environmental Remediation Matters
 General (All Registrants). The Registrants' operations have in the past, and may in the future, require substantial expenditures to comply with environmental laws. Additionally, under federal and state environmental laws, the Registrants are generally 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. In addition, the Registrants are currently involved in a number of proceedings relating to sites where hazardous substances have been deposited and may be subject to additional proceedings in the future. Unless otherwise disclosed, the Registrants cannot reasonably estimate whether they will incur significant liabilities for additional investigation and remediation costs at these or additional sites identified by the Registrants, environmental agencies, or others, or whether such costs will be recoverable from third parties, including customers. Additional costs could have a material, unfavorable impact on the Registrants' financial statements.
 MGP Sites (All Registrants). ComEd, PECO, BGE, and DPL have identified sites where former MGP or gas purification activities have or may have resulted in actual site contamination. For some sites, there are additional PRPs that may share responsibility for the ultimate remediation of each location.
 • ComEd has 16 sites currently under some degree of active study and/or remediation. ComEd expects the majority of the remediation at these sites to continue through at least 2031.
 • PECO has 6 sites currently under some degree of active study and/or remediation. PECO expects the majority of the remediation at these sites to continue through at least 2027.
 • BGE has 4 sites currently requiring some level of remediation and/or ongoing activity. BGE expects the majority of the remediation at these sites to continue through at least 2025.
 • DPL has 1 site currently under study and the required cost at the site is not expected to be material.
 The historical nature of the MGP and gas purification sites, and the fact that many of the sites have been buried and built over, impacts the ability to determine a precise estimate of the ultimate costs prior to initial sampling and determination of the exact scope and method of remedial activity. Management determines its best estimate of remediation costs using all available information at the time of each study, including probabilistic and deterministic modeling for ComEd and PECO, and the remediation standards currently required by the applicable state environmental agency. Prior to completion of any significant clean up, each site remediation plan is approved by the appropriate state environmental agency.
 ComEd, pursuant to an ICC order, and PECO, pursuant to a PAPUC order, are currently recovering environmental remediation costs of former MGP facility sites through customer rates. While BGE and DPL do not have riders for MGP clean-up costs, they have historically received recovery of actual clean-up costs in distribution rates.
 In 2024, ComEd and PECO completed an annual study of their future estimated MGP remediation requirements. The study resulted in increases of $ 13 million and $ 4 million to the environmental liability and related Regulatory

 asset for ComEd and PECO, respectively. The increases were primarily due to increased costs resulting from inflation and changes in remediation plans.
 At December 31, 2024 and 2023, the Registrants had accrued the following undiscounted amounts for environmental liabilities in Accrued expenses, Other current liabilities, and Other deferred credits and other liabilities in their respective Consolidated Balance Sheets:

 Total Environmental
Investigation and
Remediation Liabilities
 Portion of Total Related to
MGP Investigation and
Remediation
 Total Environmental
Investigation and
Remediation Liabilities
 Portion of Total Related to
MGP Investigation and
Remediation

 $
 $
 $
 $

 ComEd

 PECO

 BGE

 PHI
 —
 —

 Pepco
 —
 —

 DPL
 —
 —

 ACE
 —
 —

 Benning Road Site (Exelon, PHI, and Pepco). In September 2010, PHI received a letter from the EPA identifying the Benning Road site as one of six land-based sites potentially contributing to contamination of the lower Anacostia River. A portion of the site, which is owned by Pepco, was formerly the location of an electric generating facility owned by Pepco subsidiary, Pepco Energy Services (PES), which became a part of Generation following the 2016 merger between PHI and Exelon. This generating facility was deactivated in June 2012. The remaining portion of the site consists of a Pepco transmission and distribution service center that remains in operation. In December 2011, the U.S. District Court for the District of Columbia approved a Consent Decree entered into by Pepco and Pepco Energy Services (hereinafter "Pepco Entities") with the DOEE, which requires the Pepco Entities to conduct a Remedial Investigation and Feasibility Study (RI/FS) for the Benning Road site and an approximately 10 to 15-acre portion of the adjacent Anacostia River. The purpose of this RI/FS is to define the nature and extent of contamination from the Benning Road site and to evaluate remedial alternatives.
 Pursuant to an internal agreement between the Pepco Entities, since 2013, Pepco has performed the work required by the Consent Decree and has been reimbursed for that work by an agreed upon allocation of costs between the Pepco Entities. In September 2019, the Pepco Entities issued a draft "final" RI report which the DOEE approved on February 3, 2020. The Pepco Entities are completing a FS to evaluate possible remedial alternatives for submission to the DOEE. In October 2022, the DOEE approved dividing the work to complete the landside portion of the FS from the waterside portion to expedite the overall schedule for completion of the project. The landside FS was approved by the DOEE on March 15, 2024, and the waterside FS was approved by the DOEE on December 16, 2024. Following the completion of each FS, the DOEE will issue a Proposed Plan for public comment and then issue a Record of Decision (ROD) identifying the remedial actions determined to be necessary for the area in question. On October 3, 2023, the DOEE and Pepco entered into an addendum to the Benning Consent Decree pursuant to which Pepco has agreed to fund or perform the remedial actions to be selected by the DOEE for the landside and waterside areas. This addendum to the Benning Consent Decree was entered by the Court on February 27, 2024 and became effective on that date.
 As part of the separation between Exelon and Constellation in February 2022, the internal agreement between the Pepco Entities for completion and payment for the remaining Consent Decree work was memorialized in a formal agreement for post-separation activities. A second post-separation assumption agreement between Exelon and Constellation transferred any of the potential remaining remediation liability, if any, of PES/Generation to a non-utility subsidiary of Exelon which going forward will be responsible for those liabilities. Exelon, PHI, and Pepco have determined that a loss associated with this matter is probable and have accrued an estimated liability, which is included in the table above.
 Anacostia River Tidal Reach (Exelon, PHI, and Pepco). Contemporaneous with the Benning Road site RI/FS being performed by the Pepco Entities, the DOEE and NPS have been conducting a separate RI/FS focused on the entire tidal reach of the Anacostia River extending from just north of the Maryland-District of Columbia

 boundary line to the confluence of the Anacostia and Potomac Rivers. The riverwide RI incorporated the results of the river sampling performed by the Pepco Entities as part of the Benning RI/FS, as well as similar sampling efforts conducted by owners of other sites adjacent to this segment of the river and supplemental river sampling conducted by the DOEE's contractor.
 On September 30, 2020, the DOEE released its Interim ROD for the Anacostia River sediments. The Interim ROD reflects an adaptive management approach which will require several identified "hot spots" in the river to be addressed first while continuing to conduct studies and to monitor the river to evaluate improvements and determine potential future remediation plans. The adaptive management process chosen by the DOEE is less intrusive, provides more long-term environmental certainty, is less costly, and allows for site specific remediation plans already underway, including the plan for the Benning Road site to proceed to conclusion.
 On July 15, 2022, Pepco received a letter from the District of Columbia's Office of the Attorney General (D.C. OAG) on behalf of the DOEE conveying a settlement offer to resolve all PRPs' liability to the District of Columbia (District) for their past costs and their anticipated future costs to complete the work for the Interim ROD. Pepco responded on July 27, 2022 agreeing to enter into settlement discussions. On October 3, 2023, Pepco and the District entered into another consent decree (the "Anacostia River Consent Decree") pursuant to which Pepco agreed to pay $ 47 million to resolve its liability to the District for all past costs to perform the riverwide RI/FS and all future costs to complete the work required by the Interim ROD. This amount was agreed to be paid in four equal annual installments beginning a year after the effective date of the Anacostia River Consent Decree. The funds will be deposited into the DOEE's Clean Land Fund for the District's costs of the Interim ROD work. The Anacostia River Consent Decree caps Pepco's liability for these costs and provides Pepco with the right to seek contributions from other PRPs. The Anacostia River Consent Decree was signed by the judge for the U.S. District Court for the District of Columbia and became effective on April 11, 2024. Exelon, PHI, and Pepco have accrued a liability for Pepco's payment obligations under the Anacostia Consent Decree and management's best estimate of its share of any other future Anacostia River response costs. Pepco has concluded that incremental exposure remains reasonably possible, but management cannot reasonably estimate a range of loss beyond the amounts recorded, which are included in the table above.
 In addition to the activities associated with the remedial process outlined above, CERCLA separately requires federal and state (here including Washington, D.C.) Natural Resource Trustees (federal or state agencies designated by the President or the relevant state, respectively, or Indian tribes) to conduct an assessment of any damages to natural resources within their jurisdiction as a result of the contamination that is being remediated. The Trustees can seek compensation from responsible parties for such damages, including restoration costs. During the second quarter of 2018, Pepco became aware that the Trustees are in the beginning stages of a NRD assessment, a process that often takes many years beyond the remedial decision to complete. Pepco has concluded that a loss associated with the eventual NRD assessment is reasonably possible. Due to the early stage of the NRD process, Pepco cannot reasonably estimate the final range of loss potentially resulting from this process. Pepco has become aware, however, that the District is pursuing claims against other parties. Specifically, in January 2025, D.C. OAG filed a lawsuit against the United States seeking to declare the United States liable under CERCLA and the District of Columbia's Brownfield Revitalization Act of 2000 and to recover the District's response costs associated with its investigation and remediation of the river and for future NRDs. This lawsuit is in the early stages. Pepco is monitoring this lawsuit and considering its legal options.
 As noted in the Benning Road Site disclosure above, as part of the separation of Exelon and Constellation in February 2022, an assumption agreement was executed transferring any potential future remediation liabilities associated with the Benning Site remediation to a non-utility subsidiary of Exelon. Similarly, any potential future liability associated with the Anacostia River Sediment Project was also assumed by this entity.
 Buzzard Point Site (Exelon, PHI, and Pepco). On December 8, 2022, Pepco received a letter from the D.C. OAG, alleging wholly past violations of the District's stormwater discharge and waste disposal requirements related to operations at the Buzzard Point facility, a 9-acre parcel of waterfront property in Washington, D.C. occupied by an active substation and former steam plant building. The letter also alleged wholly past violations by Pepco of stormwater discharge requirements related to its district-wide system of underground vaults. On October 3, 2023, Pepco entered into a Consent Order with the District of Columbia to resolve the alleged violations without any admission of liability. The Consent Order requires Pepco to pay a civil penalty of $ 10 million. In addition, Pepco has agreed to assess the environmental conditions at its Buzzard Point facility and conduct any remedial actions deemed necessary as a result of the assessment, and also to assess potential

 environmental impacts associated with the operation of its underground vaults. The court signed and entered the Consent Order, and it became effective on February 2, 2024. Exelon, PHI, and Pepco have accrued a liability for the penalty payments and for the projected costs for the required environmental assessments and remediation. Pepco has concluded that incremental exposure remains reasonably possible, but management cannot reasonably estimate a range of loss beyond the amounts recorded, which are included in the table above.
 Litigation and Regulatory Matters
 Fund Transfer Restrictions (All Registrants). Under applicable law, Exelon may borrow or receive an extension of credit from its subsidiaries. Under the terms of Exelon's intercompany money pool agreement, Exelon can lend to, but not borrow from the money pool.
 Under applicable law, ComEd, PECO, BGE, PHI, Pepco, DPL, and ACE can pay dividends only from retained, undistributed or current earnings. A significant loss recorded at ComEd, PECO, BGE, PHI, Pepco, DPL, or ACE may limit the dividends that these Registrants can distribute to Exelon.
 ComEd has agreed in connection with financings arranged through ComEd Financing III that it will not declare dividends on any shares of its capital stock in the event that: (1) it exercises its right to extend the interest payment periods on the subordinated debt securities issued to ComEd Financing III; (2) it defaults on its guarantee of the payment of distributions on the preferred trust securities of ComEd Financing III; or (3) an event of default occurs under the Indenture under which the subordinated debt securities are issued. No such event has occurred.
 PECO has agreed in connection with financings arranged through PEC L.P. and PECO Trust IV that PECO will not declare dividends on any shares of its capital stock in the event that: (1) it exercises its right to extend the interest payment periods on the subordinated debentures, which were issued to PEC L.P. or PECO Trust IV; (2) it defaults on its guarantee of the payment of distributions on the Series D Preferred Securities of PEC L.P. or the preferred trust securities of PECO Trust IV; or (3) an event of default occurs under the Indenture under which the subordinated debentures are issued. No such event has occurred.
 BGE is subject to restrictions established by the MDPSC that prohibit BGE from paying a dividend on its common shares if (a) after the dividend payment, BGE's equity ratio would be below 48 % as calculated pursuant to the MDPSC's ratemaking precedents or (b) BGE's senior unsecured credit rating is rated by two of the three major credit rating agencies below investment grade. No such event has occurred.
 Pepco is subject to certain dividend restrictions established by settlements approved by the MDPSC and DCPSC that prohibit Pepco from paying a dividend on its common shares if (a) after the dividend payment, Pepco's equity ratio would be below 48 % as calculated pursuant to the MDPSC's and DCPSC's ratemaking precedents, of or (b) Pepco's senior unsecured credit rating is rated by one of the three major credit rating agencies below investment grade. No such event has occurred.
 DPL is subject to certain dividend restrictions established by settlements approved by the DEPSC and MDPSC that prohibit DPL from paying a dividend on its common shares if (a) after the dividend payment, DPL's equity ratio would be below 48 % as calculated pursuant to the DEPSC's and MDPSC's ratemaking precedents, or (b) DPL's corporate issuer or senior unsecured credit rating, or its equivalent, is rated by any of the three major credit rating agencies below the generally accepted definition of investment grade. No such event has occurred.
 ACE is subject to certain dividend restrictions established by settlements approved by the NJBPU that prohibit ACE from paying a dividend on its common shares if (a) after the dividend payment, ACE's common equity ratio would be below 48 % as calculated pursuant to the NJBPU's ratemaking precedents, or (b) ACE's senior corporate issuer or senior unsecured credit rating is rated by one of the three major credit rating agencies below investment grade. ACE is also subject to a dividend restriction which requires ACE to notify and obtain the prior approval of the NJBPU before dividends can be paid if its equity as a percent of its total capitalization, excluding securitization debt, falls below 30 %. No such events have occurred.
 DPA and Related Matters (Exelon and ComEd). Exelon and ComEd received a grand jury subpoena in the second quarter of 2019 from the U.S. Attorney's Office for the Northern District of Illinois (USAO) requiring production of information concerning their lobbying activities in the State of Illinois. On October 4, 2019, Exelon and ComEd received a second grand jury subpoena from the USAO requiring production of records of any communications with certain individuals and entities. On October 22, 2019, the SEC notified Exelon and ComEd

 that it had also opened an investigation into their lobbying activities. On July 17, 2020, ComEd entered into a DPA with the USAO to resolve the USAO investigation, which included a payment to the U.S. Treasury of $ 200 million, which was paid in November 2020. The three-year term of the DPA ended on July 17, 2023, and on that same date the court granted the USAO's motion to dismiss the pending charge against ComEd that had been deferred by the DPA.
 On September 28, 2023, Exelon and ComEd reached a settlement with the SEC, concluding and resolving in its entirety the SEC investigation, which related to the conduct identified in the DPA that was entered into by ComEd in July 2020 and successfully exited in July 2023. Under the terms of the settlement, Exelon agreed to pay a civil penalty of $ 46.2 million and Exelon and ComEd agreed to cease and desist from committing or causing any violations and any future violations of specified provisions of the federal securities laws and rules promulgated thereunder. Exelon recorded an expense and paid the full amount of the penalty in 2023, which was reflected in Operating and maintenance expense within Exelon's Consolidated Statements of Operations and Comprehensive Income.
 Subsequent to Exelon announcing the receipt of the USAO subpoenas, various lawsuits were filed, and various demand letters were received related to the subject of the subpoenas, the conduct described in the DPA and the SEC's investigation, including:
 • Four putative class action lawsuits against ComEd and Exelon were filed in federal court on behalf of ComEd customers in the third quarter of 2020 alleging, among other things, civil violations of federal racketeering laws. The court granted ComEd and Exelon's motion to dismiss these actions in 2021 and that dismissal was affirmed on appeal in 2022. Plaintiffs have no further appeal rights and therefore the dismissal is final.
 • Three putative class action lawsuits against ComEd and Exelon were filed in Illinois state court in the third quarter of 2020 seeking restitution and compensatory damages on behalf of ComEd customers. The cases were consolidated into a single action in October of 2020. In 2021, the plaintiffs that filed the class action lawsuits in federal court ("federal plaintiffs") refiled their dismissed state law claims in state court. ComEd and Exelon moved to dismiss both lawsuits. The court dismissed the original consolidated state court lawsuit in December 2021 and dismissed the federal plaintiffs' refiled claims in February 2022. Both sets of plaintiffs appealed their dismissals, and the appeals were consolidated in March 2022. On September 8, 2023, the appellate court affirmed the dismissals. On December 22, 2023, plaintiffs collectively filed a petition for leave to appeal to the Illinois Supreme Court, which ComEd and Exelon responded to on January 12, 2024. On March 27, 2024, the Illinois Supreme Court denied plaintiffs' petition for leave to appeal. The dismissal of this action is final.
 • On November 3, 2022, a plaintiff filed a putative class action complaint in Lake County, Illinois Circuit Court against ComEd and Exelon for unjust enrichment and deceptive business practices in connection with the conduct giving rise to the DPA. Plaintiff seeks an accounting and disgorgement of any benefits ComEd allegedly obtained from said conduct. ComEd and Exelon filed a motion to dismiss the Complaint on February 3, 2023. On June 16, 2023, the court granted ComEd and Exelon's motion to dismiss the action with prejudice. Plaintiff filed its notice of appeal of that dismissal on July 17, 2023. On April 12, 2024, the appellate court issued its decision affirming dismissal of the action. On June 3, 2024, plaintiff filed a petition for leave to appeal the dismissal to the Illinois Supreme Court, which is a discretionary appeal. ComEd and Exelon filed its response to that petition on July 19, 2024. On September 25, 2024, the Illinois Supreme Court denied plaintiff's petition for leave to appeal. The dismissal of this action is now final.
 • A putative class action lawsuit against Exelon and certain officers of Exelon and ComEd was filed in federal court in December 2019 alleging misrepresentations and omissions in Exelon's SEC filings related to ComEd's lobbying activities and the related investigations. The complaint was amended on September 16, 2020, to dismiss two of the original defendants and add other defendants, including ComEd. Defendants filed a motion to dismiss in November 2020. The court denied the motion in April 2021. Following mediation, the parties reached a settlement of the lawsuit, under which defendants agreed to pay plaintiffs $ 173 million. On May 26, 2023, plaintiffs filed a motion for preliminary approval of the settlement, which the court granted on June 9, 2023. The court granted final settlement approval on September 7, 2023. The settlement was fully covered by insurance and has been paid in full.

 • Several shareholders have sent letters to the Exelon Board of Directors since 2020 demanding, among other things, that the Exelon Board of Directors investigate and address alleged breaches of fiduciary duties and other alleged violations by Exelon and ComEd officers and directors related to the conduct described in the DPA. In the first quarter of 2021, the Exelon Board of Directors appointed a Special Litigation Committee (SLC) consisting of disinterested and independent parties to investigate and address these shareholders' allegations and make recommendations to the Exelon Board of Directors based on the outcome of the SLC's investigation. In July 2021, one of the demand letter shareholders filed a derivative action against current and former Exelon and ComEd officers and directors, and against Exelon, as nominal defendant, asserting the same claims made in its demand letter. Since that date, multiple parties have filed separate derivative lawsuits that were subsequently consolidated. On October 12, 2021, the parties filed an agreed motion to stay the litigation for 120 days in order to allow the SLC to continue its investigation, which the court granted. The stay was extended several times. Through mediation efforts, a settlement of the derivative claims was reached by the SLC, the Independent Review Committee of the Board (which had been formed in the third quarter of 2022, to ensure the Board's consideration of any SLC recommendations would be independent and objective), the Board, and certain of the derivative shareholders. On June 16, 2023, the SLC filed a motion for preliminary approval of the settlement, attaching the Stipulation and Agreement of Settlement (Stipulation), which contained the terms of the proposed settlement. The proposed settlement terms include but are not limited to: a payment of $ 40 million to Exelon by Exelon's insurers of which $ 10 million constitutes the attorneys' fee award to be paid to the Settling Shareholders' counsel; various compliance and disclosure-related reforms; and certain changes in Board and Committee composition. On June 30, 2023, the court granted the non-settling shareholders' request for limited discovery into the settlement. Following that discovery, on October 26, 2023, the SLC filed its renewed motion for preliminary approval with supporting submissions filed by the Independent Review Committee, Exelon, and the Settling Shareholders on that same day. The parties briefing on preliminary approval was completed on January 18, 2024. On September 20, 2024, the court denied without prejudice the SLC's motion for preliminary approval. The court's order provides that if the SLC can substantiate or otherwise revise the attorneys' fees aspect of the settlement, then the SLC can renew its motion for preliminary approval by October 21, 2024. Otherwise, the court directed the parties to file a joint status report by October 30, 2024, proposing next steps to advance the case. On October 21, 2024, the SLC filed its second renewed motion for preliminary approval, and the Settling Shareholders filed a brief in support of the SLC's second renewed motion for preliminary approval. On November 20, 2024, the non-settling plaintiffs filed an opposition to the renewed motion for preliminary approval. On December 18, 2024, the SLC and Settling Shareholders filed replies in support of the renewed motion for preliminary approval.

 In August 2022, the ICC concluded its investigation initiated on August 12, 2021 into rate impacts of conduct admitted in the DPA, including the costs recovered from customers related to the DPA and Exelon's funding of the fine paid by ComEd. On August 17, 2022, the ICC issued its final order accepting ComEd's voluntary customer refund offer of approximately $ 38 million (of which about $ 31 million was ICC jurisdictional; the remaining balance was FERC jurisdictional) that resolved the question of whether customer funds were used for DPA related activities. The customer refund included the cost of every individual or entity that was either (i) identified in the DPA or (ii) identified by ComEd as an associate of the former Speaker of the Illinois House of Representatives in the ICC proceeding. The ICC's DPA investigation is now closed. The ICC jurisdictional refund was made to customers during the April 2023 billing cycle, as required by the ICC. The FERC jurisdictional refund was completed as of May 2024 as part of ComEd's transmission formula rate update proceeding, submitted on May 12, 2023. The customer refund was not recovered in rates or charged to customers and ComEd will not seek or accept reimbursement or indemnification from any source other than Exelon.
 Maryland Sales and Use Tax Refund Claim (Exelon, BGE, PHI, Pepco, and DPL). Maryland imposes a 6% sales and use tax on the purchase of most goods and services. BGE, Pepco, and DPL have filed or plan to file protective refund claims, totaling an estimated $ 100 million, treating electric transmission and distribution machinery and equipment as nontaxable pursuant to the manufacturing exemption available under the Maryland sales and use tax law. The Maryland Comptroller has initially denied the refund claim and litigation is pending.
 On November 22, 2024, the Appellate Court of Maryland, in a case involving a regulated electric utility operating in Maryland, ruled the purchase of certain transmission and distribution equipment qualify for the sales tax manufacturing exemption. The Maryland Attorney General, on behalf of the Maryland Comptroller, filed a motion for reconsideration with the Appellate Court of Maryland of its ruling. If the motion for reconsideration is denied, the Maryland Comptroller is permitted to petition the Maryland Supreme Court to review the decision.

 In the event transmission and distribution equipment is determined to be exempt, Exelon, BGE, PHI, Pepco, and DPL will record estimated receivables of $ 100 million, $ 65 million, $ 35 million, $ 25 million, and $ 10 million, respectively. The sales tax payments were primarily capitalized; therefore, the refund would be recorded as a reduction to property, plant, and equipment included in rate base.
 General (All Registrants). The Registrants are involved in various other litigation matters that are being defended and handled in the ordinary course of business. The Registrants are also from time to time subject to audits and investigations by the FERC and other regulators. The assessment of whether a loss is probable or reasonably possible, and whether the loss or a range of loss is estimable, often involves a series of complex judgments about future events. The Registrants maintain accruals for such losses that are probable of being incurred and subject to reasonable estimation. Management is sometimes unable to estimate an amount or range of reasonably possible loss, particularly where (1) the damages sought are indeterminate, (2) the proceedings are in the early stages, or (3) the matters involve novel or unsettled legal theories. In such cases, there is considerable uncertainty regarding the timing or ultimate resolution of such matters, including a possible eventual loss.

 19. Shareholders' Equity (All Registrants)
 Equity Securities Offering (Exelon)
 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.
 At-the-Market Program (Exelon)
 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.
 ComEd Common Stock Warrants
 The following table presents warrants outstanding to purchase ComEd common stock and shares of common stock reserved for the conversion of warrants. The warrants entitle the holders to convert such warrants into common stock of ComEd at a conversion rate of one share of common stock for three warrants.

 2024
 2023

 Warrants outstanding

 59,970
 60,032

 Common Stock reserved for conversion
 19,990
 20,011

 Share Repurchases

 Note 19 — Shareholders' Equity

 There currently is no Exelon Board of Director authority to repurchase shares. Any previous shares repurchased are held as treasury shares, at cost, unless cancelled or reissued at the discretion of Exelon's management.
 Preferred and Preference Securities
 The following table presents Exelon, ComEd, PECO, BGE, Pepco, and ACE's shares of preferred securities authorized, none of which were outstanding, as of December 31, 2024 and 2023. There are no shares of preferred securities authorized for DPL.

 Preferred Securities Authorized

 100,000,000

 ComEd
 850,000

 PECO
 15,000,000

 BGE
 1,000,000

 Pepco
 6,000,000

 ACE(a)

 2,799,979

 (a)Includes 799,979 shares of cumulative preferred stock and 2,000,000 of no par value preferred stock as of December 31, 2024 and 2023.
 The following table presents ComEd, BGE, and ACE's preference securities authorized, none of which were outstanding as of December 31, 2024 and 2023. There are no shares of preference securities authorized for Exelon, PECO, Pepco, and DPL.

 Preference Securities Authorized

 ComEd
 6,810,451

 BGE(a)

 6,500,000

 ACE
 3,000,000

 (a)Includes 4,600,000 shares of unclassified preference securities and 1,900,000 shares of previously redeemed preference securities as of December 31, 2024 and 2023.

 20. Stock-Based Compensation Plans (All Registrants)
 Stock-Based Compensation Plans
 Exelon grants stock-based awards through its LTIP, which primarily includes performance share awards, restricted stock units, and stock options. At December 31, 2024, there were approximately 32 million shares authorized for issuance under the LTIP. For the years ended December 31, 2024, 2023, and 2022, exercised and distributed stock-based awards were primarily issued from authorized but unissued Common stock shares.
 Separation-related Adjustments. In connection with the separation, Exelon and Constellation entered into an Employee Matters Agreement, effective February 1, 2022. Under the terms of the Employee Matters Agreement, and pursuant to the terms of the LTIP, the Compensation Committee of the Board of Exelon approved an adjustment to outstanding awards granted under the LTIP in order to preserve the intrinsic aggregate value of such awards before the separation. The separation-related adjustments did not have a material impact on either compensation expense or the potentially dilutive securities to be considered in the calculation of diluted earnings per share of Common stock. Former Exelon employees transferred to Constellation as a result of the separation surrendered their outstanding unvested Exelon awards effective February 1, 2022.
 The Registrants grant cash awards. The following table does not include expense related to these plans as they are not considered stock-based compensation plans under the applicable authoritative guidance.
 The following table presents the stock-based compensation expense included in Exelon's Consolidated Statements of Operations and Comprehensive Income. The Utility Registrants' stock-based compensation expense for the years ended December 31, 2024, 2023, and 2022 was not material.

 Note 20 — Stock-Based Compensation Plans

 2024
 2023
 2022

 Total stock-based compensation expense included in Operating and maintenance expense
 $
 $
 $

 Income tax benefit
 ( 8)
 ( 5)
 ( 10)

 Total after-tax stock-based compensation expense
 $
 $
 $

 Exelon receives a tax deduction based on the intrinsic value of the award on the exercise date for stock options and the distribution date for performance share awards and restricted stock units. For each award, throughout the requisite service period, Exelon recognizes the tax benefit related to compensation costs. The following table presents information regarding Exelon's realized tax benefit when distributed:

 2024
 2023
 2022

 Performance share awards
 $
 $
 $

 Restricted stock units

 Performance Share Awards
 Performance share awards are granted under the LTIP. The performance share awards granted in 2024 are settled in common stock at the end of the three-year performance period. The performance share awards granted prior to 2024 are settled 50 % in common stock and 50 % in cash at the end of the three-year performance period, except for awards that are settled 100 % in cash if certain ownership requirements are satisfied.
 The common stock portion of the performance share awards is considered an equity award and is valued based on Exelon's stock price on the grant date. The cash portion of the performance share awards is considered a liability award which is remeasured each reporting period based on Exelon's current stock price. As the value of the common stock and cash portions of the awards are based on Exelon's stock price during the performance period, coupled with changes in the total shareholder return modifier and expected payout of the award, the compensation costs are subject to volatility until payout is established.
 For nonretirement-eligible employees, stock-based compensation costs are recognized over the vesting period of three years using the straight-line method. For performance share awards granted to retirement-eligible employees, the value of the performance shares is recognized ratably over the vesting period, which is the year of grant. Exelon processes forfeitures as they occur for employees who do not complete the requisite service period.
 The following table summarizes Exelon's nonvested performance share awards activity:

 Shares
 Weighted Average
Grant Date Fair
Value (per share)

 Nonvested at December 31, 2023(a)

 958,242
 $
 42.01

 Granted
 679,683
 35.29

 Change in performance
 ( 131,794)
 40.38

 Vested
 ( 311,971)
 41.25

 Forfeited
 ( 86,359)
 37.80

 Undistributed vested awards(b)

 ( 496,276)
 37.34

 Nonvested at December 31, 2024(a)

 611,525
 $
 39.66

 (a)Excludes 635,526 and 1,198,093 of performance share awards issued to retirement-eligible employees as of December 31, 2024 and 2023, respectively, as they are fully vested.
 (b)Represents performance share awards that vested but were not distributed to retirement-eligible employees during 2024.

 Note 20 — Stock-Based Compensation Plans

 The following table summarizes the weighted average grant date fair value and the total fair value of performance share awards vested.

 2024(a)

 2023
 2022

 Weighted average grant date fair value (per share)
 $
 35.29
 $
 41.82
 $
 43.05

 Total fair value of performance shares vested

 Total fair value of performance shares settled in cash

 (a)As of December 31, 2024, $ 8 million of total unrecognized compensation costs related to nonvested performance shares are expected to be recognized over the remaining weighted-average period of 1.7 years.
 Restricted Stock Units
 Restricted stock units are granted under the LTIP with the majority being settled in a specific number of shares of common stock after the service condition has been met. The corresponding cost of services is measured based on the grant date fair value of the restricted stock unit issued.
 The value of the restricted stock units is expensed over the requisite service period using the straight-line method. The requisite service period for restricted stock units is generally three to five years. However, certain restricted stock unit awards become fully vested upon the employee reaching retirement-eligibility. The value of the restricted stock units granted to retirement-eligible employees is either recognized ratably over the first six months in the year of grant if the employee reaches retirement eligibility prior to July 1st of the grant year or through the date of which the employee reaches retirement eligibility. Exelon processes forfeitures as they occur for employees who do not complete the requisite service period.
 The following table summarizes Exelon's nonvested restricted stock unit activity:

 Shares
 Weighted Average
Grant Date Fair
Value (per share)

 Nonvested at December 31, 2023(a)

 531,945
 $
 42.87

 Granted
 361,745
 35.54

 Vested
 ( 309,500)
 42.79

 Forfeited
 ( 31,466)
 40.07

 Undistributed vested awards(b)

 ( 259,135)
 37.16

 Nonvested at December 31, 2024(a)

 293,589
 $
 39.29

 (a)Excludes 126,732 and 205,855 of restricted stock units issued to retirement-eligible employees as of December 31, 2024 and 2023, respectively, as they are fully vested.
 (b)Represents restricted stock units that vested but were not distributed to retirement-eligible employees during 2024.
 The following table summarizes the weighted average grant date fair value and the total fair value of restricted stock units vested.

 2024(a)

 2023
 2022

 Weighted average grant date fair value (per share)
 $
 35.54
 $
 41.84
 $
 42.97

 Total fair value of restricted stock units vested

 (a) As of December 31, 2024, $ 5 million of total unrecognized compensation costs related to nonvested restricted stock units are expected to be recognized over the remaining weighted-average period of 1.5 years.
 Stock Options

 Note 20 — Stock-Based Compensation Plans

 Non-qualified stock options to purchase shares of Exelon's common stock were granted through 2012 under the LTIP. The exercise price of the stock options is equal to the fair market value of the underlying stock on the date of option grant. Stock options will expire no later than ten years from the date of grant.
 There were no stock options granted during the years ended December 31, 2024 and 2023. All stock options were vested and exercised as of December 31, 2022.
 The following table summarizes additional information regarding stock options exercised:

 2024
 2023
 2022

 Intrinsic value(a)

 $
 —
 $
 —
 $
 —

 Cash received for exercise price
 —
 —

 (a)The difference between the market value on the date of exercise and the option exercise price.

 21. Changes in Accumulated Other Comprehensive Income (Loss) (Exelon)
 The following table presents changes in Exelon's AOCI, net of tax, by component:

 Cash Flow
Hedges
 Pension and
Non-Pension
Postretirement
Benefit Plan
Items (a)

 Foreign
Currency
Items
 Total

 $
 ( 6)
 $
 ( 2,721)

 $
 ( 23)
 $
 ( 2,750)

 Separation of Constellation
 1,994
 2,023

 OCI before reclassifications
 —

 Amounts reclassified from AOCI
 —
 —

 Net current-period OCI
 $
 $
 $
 —
 $

 $
 $
 ( 640)
 $
 —
 $
 ( 638)

 OCI before reclassifications
 ( 4)
 —
 ( 113)

 Amounts reclassified from AOCI
 ( 1)
 —

 Net current-period OCI
 $
 ( 5)
 $
 ( 83)
 $
 —
 $
 ( 88)

 $
 ( 3)
 $
 ( 723)
 $
 —
 $
 ( 726)

 OCI before reclassifications
 ( 70)
 —
 ( 18)

 Amounts reclassified from AOCI
 ( 4)
 —

 Net current-period OCI
 $
 $
 ( 42)
 $
 —
 $

 $
 $
 ( 765)
 $
 —
 $
 ( 720)

 (a) This AOCI component is included in the computation of net periodic pension and OPEB cost. Additionally, as of February 1, 2022, in connection with the separation, Exelon's pension and OPEB plans were remeasured. See Note 14 — Retirement Benefits for additional information. See Exelon's Statements of Operations and Comprehensive Income for individual components of AOCI.
 The following table presents income tax benefit (expense) allocated to each component of Exelon's Other comprehensive income (loss):

 2024
 2023
 2022

 Pension and non-pension postretirement benefit plans:

 Actuarial losses reclassified to periodic benefit cost
 $
 ( 10)
 $
 ( 8)
 $
 ( 14)

 Pension and non-pension postretirement benefit plans valuation adjustments
 ( 14)

 Unrealized gains on cash flow hedges
 ( 15)
 —

 22. Supplemental Financial Information (All Registrants)
 Supplemental Statement of Operations Information
 The following tables provide additional information about material items recorded in the Registrants' Consolidated Statements of Operations and Comprehensive Income.

 ComEd
 PECO
 BGE
 PHI
 Pepco
 DPL
 ACE

 Utility(a)

 $
 $
 $
 $
 $
 $
 $
 $

 Property

 Payroll

 Utility(a)

 $
 $
 $
 $
 $
 $
 $
 $

 Property

 Payroll

 Utility(a)

 $
 $
 $
 $
 $
 $
 $
 $

 Property

 Payroll

 (a)The Registrants' utility taxes represents municipal and state utility taxes and gross receipts taxes related to their operating revenues. The offsetting collection of utility taxes from customers is recorded in revenues in the Registrants' Consolidated Statements of Operations and Comprehensive Income.

 ComEd
 PECO
 BGE
 PHI
 Pepco
 DPL
 ACE

 AFUDC—Equity
 $
 $
 $
 $
 $
 $
 $
 $

 Non-service net periodic benefit cost
 ( 38)
 —
 —
 —
 —
 —
 —
 —

 AFUDC—Equity
 $
 $
 $
 $
 $
 $
 $
 $

 Non-service net periodic benefit cost
 ( 18)
 —
 —
 —
 —
 —
 —
 —

 AFUDC—Equity
 $
 $
 $
 $
 $
 $
 $
 $

 Non-service net periodic benefit cost
 —
 —
 —
 —
 —
 —
 —

 Supplemental Cash Flow Information
 The following tables provide additional information about material items recorded in the Registrants' Consolidated Statements of Cash Flows.

 Depreciation, amortization, and accretion

 ComEd
 PECO
 BGE
 PHI
 Pepco
 DPL
 ACE

 Property, plant, and equipment(b)

 $
 2,910
 $
 1,167
 $
 $
 $
 $
 $
 $

 Amortization of regulatory assets(b)

 Amortization of intangible assets, net(b)

 —
 —
 —
 —
 —
 —
 —

 ARO accretion(e)

 —
 —
 —
 —
 —

 Total depreciation and amortization
 $
 3,596
 $
 1,514
 $
 $
 $
 $
 $
 $

 Property, plant, and equipment(b)

 $
 2,778
 $
 1,095
 $
 $
 $
 $
 $
 $

 Amortization of regulatory assets(b)

 Amortization of intangible assets, net(b)

 —
 —
 —
 —
 —
 —
 —

 Total depreciation, amortization, and accretion
 $
 3,506
 $
 1,403
 $
 $
 $
 $
 $
 $

 Property, plant, and equipment(b)

 $
 2,690
 $
 1,031
 $
 $
 $
 $
 $
 $

 Amortization of regulatory assets(b)

 Amortization of intangible assets, net(b)

 —
 —
 —
 —
 —
 —
 —

 Amortization of energy contract assets and liabilities(c)

 —
 —
 —
 —
 —
 —
 —

 Nuclear fuel(d)

 —
 —
 —
 —
 —
 —
 —

 ARO accretion(e)

 —
 —
 —
 —
 —
 —
 —

 Total depreciation, amortization, and accretion
 $
 3,533
 $
 1,323
 $
 $
 $
 $
 $
 $

 (a)Exelon's 2022 amounts include amounts related to Generation prior to the separation. See Note 2 — Discontinued Operations for additional information.
 (b)Included in Depreciation and amortization in the Registrants' Consolidated Statements of Operations and Comprehensive Income.
 (c)Included in Electric operating revenues or Purchased power expense in Exelon's Consolidated Statements of Operations and Comprehensive Income.
 (d)Included in Purchased fuel expense in Exelon's Consolidated Statements of Operations and Comprehensive Income.
 (e)Included in Operating and maintenance expense in Exelon's Consolidated Statements of Operations and Comprehensive Income.

 Cash paid (refunded) during the year

 ComEd
 PECO
 BGE
 PHI
 Pepco
 DPL
 ACE

 Interest (net of amount capitalized)
 $
 1,849
 $
 $
 $
 $
 $
 $
 $

 Income taxes (net of refunds)

 Interest (net of amount capitalized)
 $
 1,616
 $
 $
 $
 $
 $
 $
 $

 Income taxes (net of refunds)
 ( 24)

 Interest (net of amount capitalized)
 $
 1,434
 $
 $
 $
 $
 $
 $
 $

 Income taxes (net of refunds)
 ( 2)
 ( 6)

 (a)Exelon's 2022 amounts include amounts related to Generation prior to the separation. See Note 2 — Discontinued Operations for additional information.

 ComEd
 PECO
 BGE
 PHI
 Pepco
 DPL
 ACE

 Pension and OPEB costs (benefit)
 $
 $
 $
 ( 1)
 $
 $
 $
 $
 $

 True-up adjustments to decoupling mechanisms and formula rates(b)

 ( 6)
 ( 52)
 ( 15)

 Amortization of operating ROU asset
 —
 —

 Change in environmental liabilities
 —
 —
 —
 —
 —
 —
 —
 —

 AFUDC - Equity
 ( 157)
 ( 46)
 ( 32)
 ( 25)
 ( 54)
 ( 40)
 ( 12)
 ( 2)

 Pension and OPEB costs (benefit)
 $
 $
 $
 ( 14)
 $
 $
 $
 $
 $

 True-up adjustments to decoupling mechanisms and formula rates(b)

 ( 708)
 ( 556)
 ( 84)
 ( 77)
 ( 22)
 ( 21)
 ( 34)

 Amortization of operating ROU asset
 —

 Change in environmental liabilities
 —
 —
 —
 —
 —

 AFUDC - Equity
 ( 151)
 ( 33)
 ( 31)
 ( 16)
 ( 71)
 ( 54)
 ( 10)
 ( 7)

 Pension and OPEB costs (benefit)
 $
 $
 $
 ( 9)
 $
 $
 $
 $
 $

 Other decommissioning-related activity
 —
 —
 —
 —
 —
 —
 —

 Energy-related options
 —
 —
 —
 —
 —
 —
 —

 True-up adjustments to decoupling mechanisms and formula rates(b)

 ( 168)
 ( 267)
 ( 2)

 Long-term incentive plan
 —
 —
 —
 —
 —
 —
 —

 Amortization of operating ROU Asset
 —

 AFUDC - Equity
 ( 35)
 ( 31)
 ( 21)
 ( 63)
 ( 48)
 ( 7)
 ( 8)

 (a)Exelon's 2022 amounts include amounts related to Generation prior to the separation. See Note 2 — Discontinued Operations for additional information.
 (b)For ComEd, reflects the true-up adjustments in Regulatory assets and liabilities associated with its distribution MRP and distribution, energy efficiency, distributed generation, and transmission formula rates. For PECO, reflects the change in Regulatory assets and liabilities associated with its transmission formula rate. For BGE, Pepco, DPL, and ACE, reflects the change in Regulatory assets and liabilities associated with their decoupling mechanisms and transmission formula rates. See Note 3 — Regulatory Matters for additional information.

 The following tables provide a reconciliation of cash, restricted cash, and cash equivalents reported within the Registrants' Consolidated Balance Sheets that sum to the total of the same amounts in their Consolidated Statements of Cash Flows.

 Cash, restricted cash, and cash equivalents

 ComEd
 PECO
 BGE
 PHI
 Pepco
 DPL
 ACE

 $
 $
 $
 $
 $
 $
 $
 $

 —
 —

 Restricted cash included in Other deferred debits and other assets
 —
 —
 —
 —
 —
 —

 Total cash, restricted cash, and cash equivalents
 $
 $
 $
 $
 $
 $
 $
 $

 $
 $
 $
 $
 $
 $
 $
 $

 —
 —

 Restricted cash included in Other deferred debits and other assets
 —
 —
 —
 —
 —
 —

 Total cash, restricted cash, and cash equivalents
 $
 1,101
 $
 $
 $
 $
 $
 $
 $

 $
 $
 $
 $
 $
 $
 $
 $

 —

 Restricted cash included in Other deferred debits and other assets
 —
 —
 —
 —
 —
 —

 Total cash, restricted cash, and cash equivalents
 $
 1,090
 $
 $
 $
 $
 $
 $
 $

 $
 $
 $
 $
 $
 $
 $
 $

 —

 Restricted cash included in Other deferred debits and other assets
 —
 —
 —
 —
 —
 —

 Cash, restricted cash, and cash equivalents included in current assets of discontinued operations
 —
 —
 —
 —
 —

 Total cash, restricted cash, and cash equivalents
 $
 1,619
 $
 $
 $
 $
 $
 $
 $

 For additional information on restricted cash, see Note 1 — Significant Accounting Policies.

 Supplemental Balance Sheet Information
 The following tables provide additional information about material items recorded in the Registrants' Consolidated Balance Sheets.

 ComEd
 PECO
 BGE
 PHI
 Pepco

 Rabbi trust investments(a)

 $
 $
 —
 $
 $
 $
 $

 Equity method investments
 —
 —

 Other investments
 —
 —
 —
 —
 —

 Total investments
 $
 $
 $
 $
 $
 $

 Rabbi trust investments(a)

 $
 $
 —
 $
 $
 $
 $

 Equity method investments
 $
 $
 $
 $
 —
 $
 $
 —

 Other investments
 —
 —
 —
 —
 —

 Total investments
 $
 $
 $
 $
 $
 $

 (a)The Registrants' debt and equity security investments and life insurance contracts are recorded at fair market value.

 ComEd
 PECO
 BGE
 PHI
 Pepco
 DPL
 ACE

 Compensation-related accruals(a)

 $
 $
 $
 $
 $
 $
 $
 $

 Taxes accrued

 Interest accrued

 Compensation-related accruals(a)

 $
 $
 $
 $
 $
 $
 $
 $

 Taxes accrued

 Interest accrued

 (a)Primarily includes accrued payroll, bonuses and other incentives, vacation, and benefits.

 23. Related Party Transactions (All Registrants)
 Utility Registrants' expense with Generation
 The Utility Registrants incurred expenses from transactions with the Generation affiliate as described in the footnotes to the table below prior to separation on February 1, 2022. Such expenses were primarily recorded as Purchased power from affiliates and an immaterial amount recorded as Operating and maintenance expense from affiliates at the Utility Registrants:

 Note 23 — Related Party Transactions

 2022

 ComEd(a)

 $

 PECO(b)

 BGE(c)

 PHI

 Pepco(d)

 DPL(e)

 ACE(f)

 (a)ComEd had an ICC-approved RFP contract with Generation to provide a portion of ComEd's electric supply requirements. ComEd also purchased RECs and ZECs from Generation.
 (b)PECO received electric supply from Generation under contracts executed through PECO's competitive procurement process. In addition, PECO had a ten -year agreement with Generation to sell solar AECs.
 (c)BGE received a portion of its energy requirements from Generation under its MDPSC-approved market-based SOS and gas commodity programs.
 (d)Pepco received electric supply from Generation under contracts executed through Pepco's competitive procurement process approved by the MDPSC and DCPSC.
 (e)DPL received a portion of its energy requirements from Generation under its MDPSC and DEPSC approved market-based SOS commodity programs.
 (f)ACE received electric supply from Generation under contracts executed through ACE's competitive procurement process approved by the NJBPU.

 Service Company Costs for Corporate Support
 The Registrants receive a variety of corporate support services from BSC. Pepco, DPL, and ACE also receive corporate support services from PHISCO. See Note 1 — Significant Accounting Policies for additional information regarding BSC and PHISCO.

 Note 23 — Related Party Transactions

 The following table presents the service company costs allocated to the Registrants:

 Capitalized costs

 For the years ended December 31,
 For the years ended December 31,

 2024
 2023
 2022
 2024
 2023
 2022

 BSC
 $
 $
 $

 ComEd

 BSC
 $
 $
 $

 PECO

 BSC

 BGE

 BSC

 PHI

 BSC

 —
 —
 —

 Pepco

 BSC

 DPL

 BSC

 ACE

 BSC

 Current Receivables from/Payables to affiliates

 Note 23 — Related Party Transactions

 The following tables present current Receivables from affiliates and current Payables to affiliates:

 Receivables from affiliates:

 Payables to affiliates:
 ComEd
 PECO
 BGE
 Pepco
 DPL
 ACE
 BSC
 Other
 Total

 ComEd
 $
 —
 $
 —
 $
 —
 $
 —
 $
 —
 $
 $
 —
 $
 $

 PECO
 $
 —
 —
 —
 —
 —
 —

 BGE
 —
 —
 —
 —
 —
 —

 PHI
 —
 —
 —
 —
 —
 —

 Pepco
 —
 —

 —
 —

 DPL
 —
 —
 —
 —
 —

 ACE
 —
 —
 —
 —
 —

 Other
 —
 —
 —
 —
 —

 Total
 $
 $
 —
 $
 —
 $
 $
 —
 $
 $
 $
 $
 $

 Receivables from affiliates:

 Payables to affiliates:
 ComEd
 PECO
 BGE
 Pepco
 DPL
 ACE
 BSC
 Other
 Total

 ComEd
 $
 —
 $
 —
 $
 —
 $
 —
 $
 —
 $
 $
 —
 $
 $

 PECO
 $
 —
 —
 —
 —
 —
 —

 BGE
 —
 —
 —
 —
 —
 —

 PHI
 —
 —
 —
 —
 —
 —
 —

 Pepco
 —
 —
 —
 —
 —

 DPL
 —
 —
 —
 —

 ACE
 —
 —
 —

 Other
 —
 —
 —
 —

 Total
 $
 $
 $
 —
 $
 $
 $
 $
 $
 $
 $

 Borrowings from Exelon/PHI 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. PECO and PHI Corporate participate in the Exelon money pool. Pepco, DPL, and ACE participate in the PHI intercompany money pool.
 Long-term Debt to Financing Trusts
 The following table presents Long-term debt to financing trusts:

 2024
 2023

 ComEd
 PECO
 ComEd
 PECO

 ComEd Financing III
 $
 $
 $
 —
 $
 $
 $
 —

 PECO Trust III
 —
 —

 PECO Trust IV
 —
 —

 Total
 $
 $
 $
 $
 $
 $

 ITEM 9.
 CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

 None.

 ITEM 9A.
 CONTROLS AND PROCEDURES

 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.

 ITEM 9B.
 OTHER INFORMATION

 None of our officers or directors, as defined in Rule 16a-1(f) of the Securities Exchange Act of 1934, adopted, modified, or terminated a "Rule 10b5-1 trading arrangement" or a "non-Rule 10b5-1 trading arrangement," as defined in Item 408 of Regulation S-K, during the three months ended December 31, 2024.

 ITEM 9C.
 DISCLOSURE REGARDING FOREIGN JURISDICTIONS THAT PREVENT INSPECTIONS

 Not Applicable

 PECO Energy Company, Baltimore Gas and Electric Company, Pepco Holdings LLC, Potomac Electric Power Company, Delmarva Power & Light Company, and Atlantic City Electric Company meet the conditions set forth in General Instruction (I)(1)(a) and (b) of Form 10-K for a reduced disclosure format. Accordingly, all items in this section relating to PECO, BGE, PHI, Pepco, DPL, and ACE are not presented.

 ITEM 10.
 DIRECTORS, EXECUTIVE OFFICERS, AND CORPORATE GOVERNANCE

 Executive Officers
 The information required by ITEM 10 relating to executive officers is set forth above in ITEM 1. BUSINESS—Executive Officers of the Registrants as of February 12, 2025.
 Directors, Director Nomination Process and Audit Committee
 The information required under ITEM 10 concerning directors and nominees for election as directors at the annual meeting of shareholders (Item 401 of Regulation S-K), the director nomination process (Item 407(c)(3)), the audit committee (Item 407(d)(4) and (d)(5)), and the beneficial reporting compliance (Sec. 16(a)) is incorporated herein by reference to information to be contained in Exelon's Proxy Statement for the 2025 Annual Meeting of Shareholders (2025 Exelon Proxy Statement) and the ComEd information statement (2025 ComEd Information Statement) to be filed with the SEC on or before April 30, 2025 pursuant to Regulation 14A or 14C, as applicable, under the Securities Exchange Act of 1934.
 Code of Ethics
 Exelon's Code of Business Conduct is the code of ethics that applies to all directors, officers, and employees of the Registrants and their subsidiaries. The Code of Business Conduct is filed as Exhibit 14 to this report and is available on Exelon's website at www.exeloncorp.com. The Code of Business Conduct will be made available, without charge, in print to any shareholder who requests such document from Exelon's Corporate Secretary, 10 South Dearborn Street, P.O. Box 805398, Chicago, Illinois 60680-5398.
 If any substantive amendments to the Code of Business Conduct are made or any waivers are granted, including any implicit waiver, from a provision of the Code of Business Conduct, to its Chief Executive Officer, Chief Financial Officer or Corporate Controller, Exelon will disclose the nature of such amendment or waiver on Exelon's website, www.exeloncorp.com, or in a report on Form 8-K.
 Insider Trading Policy
 The information required under ITEM 10 concerning insider trading policies and procedures (Item 408(b) of Regulation S-K) is incorporated herein by reference to information to be contained in the 2025 Exelon Proxy Statement.

 ITEM 11.
 EXECUTIVE COMPENSATION

 As described earlier in PART II, ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA: Note 1 — Significant Accounting Policies, the Consolidated Balance Sheets as of December 31, 2023, for Exelon, BGE, PHI, Pepco, and DPL were revised as of December 31, 2023, to correct the accounting for the RPS obligations and the corresponding Prepaid assets. The error revision required a recovery analysis of incentive-based compensation under the Exelon Financial Restatement Compensation Recoupment Policy ("Recoupment Policy"). The Recoupment Policy is included as Exhibit 97-1 to this report.
 In connection with the revision of the financial statements for the fiscal year ended December 31, 2023, Exelon, BGE, PHI, Pepco, and DPL conducted a recovery analysis and concluded that the revision did not affect the incentive-based compensation received by Exelon's former and current executive officers covered under the Recoupment Policy (each, a "Covered Executive") with respect to the 2023 fiscal year. As a result, Exelon, BGE, PHI, Pepco, and DPL determined that no Covered Executive received any erroneously awarded incentive-based compensation with respect to the 2023 fiscal year.
 The additional information required by this item will be set forth under Executive Compensation Data and Compensation Committee Report in the 2025 Exelon Proxy Statement or the 2025 ComEd Information Statement, which are incorporated herein by reference.

 ITEM 12.
 SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

 The additional information required by this item will be set forth under Ownership of Exelon Stock in the 2025 Exelon Proxy Statement or the 2025 ComEd Information Statement, which are incorporated herein by reference.

No ComEd securities are authorized for issuance under equity compensation plans.
 Securities Authorized for Issuance under Exelon Equity Compensation Plans

 [A]
 [B]
 [C]

 Plan Category
 Number of securities to
be issued upon
exercise of outstanding
Options, warrants and
rights (Note 1)
 Weighted-average
price of outstanding
Options, warrants
and rights (Note 2)
 Number of securities
remaining available
for future issuance
under equity
compensation plans
(excluding securities
reflected in
column [A]) (Note 3)

 Equity compensation plans approved by security holders
 2,931,752
 $
 —
 41,908,566

 (1)Balance includes (a) unvested performance shares and unvested restricted stock units that were granted under the Exelon LTIP or predecessor company plans (including shares awarded under those plans and deferred into the stock deferral plan) and (b) deferred stock units granted to directors as part of their compensation. See Note 20 — Stock-Based Compensation Plans of the Combined Notes to Consolidated Financial Statements for additional information about the material features of the plans.
 (2)There are no outstanding stock options. The weighted-average price reported in column B does not take the performance shares and shares credited to deferred compensation plans into account.
 (3)Includes 10,131,387 shares remaining available for issuance from the employee stock purchase plan.

 ITEM 13.
 CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR INDEPENDENCE

 The additional information required by this item will be set forth under Related Person Transactions and Director Independence in the 2025 Exelon Proxy Statement or the 2025 ComEd Information Statement, which are incorporated herein by reference.

 ITEM 14.
 PRINCIPAL ACCOUNTING FEES AND SERVICES

 The information required by this item will be set forth under Ratification of PricewaterhouseCoopers LLP as Exelon's Independent Accountant for 2025 in the 2025 Exelon Proxy Statement and the 2025 ComEd Information Statement, which are incorporated herein by reference.

 ITEM 15.
 EXHIBITS, FINANCIAL STATEMENT SCHEDULES

 (a)The following documents are filed as a part of this report:
 (1) Exelon

 (i)

 Report of Independent Registered Public Accounting Firm dated February 13, 2024 of PricewaterhouseCoopers LLP (PCAOB ID 238)

 Consolidated Statements of Operations and Comprehensive Income for the Years Ended December 31, 2024, 2023, and 2022

 Consolidated Statements of Cash Flows for the Years Ended December 31, 2024, 2023, and 2022

 Consolidated Statements of Changes in Equity for the Years Ended December 31, 2024, 2023, and 2022

 (ii)

 Financial Statement Schedules:

 Schedule I—Condensed Financial Information of Parent (Exelon Corporate) at December 31, 2024 and 2023 and for the Years Ended December 31, 2024, 2023, and 2022

 Schedule II—Valuation and Qualifying Accounts for the Years Ended December 31, 2024, 2023, and 2022

 Schedules not included are omitted because of the absence of conditions under which they are required or because the required information is provided in the consolidated financial statements, including the notes thereto.

 Condensed Statements of Operations and Other Comprehensive Income

 2024
 2023
 2022

 $
 $
 $

 Other

 Operating loss
 ( 16)
 ( 96)
 ( 31)

 ( 593)
 ( 544)
 ( 413)

 Equity in earnings of investments
 2,887
 2,728
 2,450

 Interest income from affiliates, net

 2,331
 2,212
 2,064

 Income from continuing operations before income taxes
 2,315
 2,116
 2,033

 ( 145)
 ( 212)
 ( 21)

 Net income from continuing operations after income taxes
 2,460
 2,328
 2,054

 Net income from discontinued operations after income taxes
 —
 —

 $
 2,460
 $
 2,328
 $
 2,170

 Other comprehensive income (loss), net of income taxes

 Pension and non-pension postretirement benefit plans:

 Prior service benefits reclassified to periodic benefit cost
 —
 —
 ( 1)

 Actuarial losses reclassified to periodic benefit cost

 Pension and non-pension postretirement benefit plans valuation adjustments
 ( 70)

 Unrealized gain (loss) on cash flow hedges
 ( 5)

 Other comprehensive income (loss)
 ( 88)

 $
 2,466
 $
 2,240
 $
 2,259

 See the Notes to Financial Statements

 Condensed Statements of Cash Flows

 2024
 2023
 2022

 $
 2,022
 $
 1,486
 $
 1,690

 Changes in Exelon intercompany money pool
 ( 43)

 Notes receivable from affiliates
 —
 —

 Investment in affiliates
 ( 1,568)
 ( 1,864)
 ( 4,011)

 ( 2)
 ( 1)
 —

 ( 1,562)
 ( 1,908)
 ( 3,702)

 ( 99)

 Proceeds from short-term borrowings with maturities greater than 90 days
 —
 1,150

 Repayments on short-term borrowings with maturities greater than 90 days
 —
 ( 1,300)

 1,700
 2,500
 3,350

 ( 715)
 ( 850)
 ( 1,150)

 ( 1,523)
 ( 1,433)
 ( 1,334)

 Proceeds from employee stock plans

 ( 36)
 ( 39)
 ( 35)

 Net cash flows (used in) provided by financing activities
 ( 482)
 1,728

 ( 22)
 ( 284)

 $
 $
 $

 See the Notes to Financial Statements

 Condensed Balance Sheets

 2024
 2023

 $
 $

 Accounts receivable, net

 Accounts receivable from affiliates

 Notes receivable from affiliates

 Other

 1,031

 Property, plant, and equipment, net

 2,851
 2,877

 Investments in affiliates from continuing operations
 40,741
 38,545

 Non-pension postretirement benefit asset

 Other

 44,674
 42,557

 $
 45,452
 $
 43,632

 See the Notes to Financial Statements

 Condensed Balance Sheets

 2024
 2023

 LIABILITIES AND SHAREHOLDERS' EQUITY

 $
 $
 1,026

 Pension obligations

 Other

 2,445
 2,329

 11,334
 10,713

 Pension obligations
 4,346
 4,268

 Other

 4,752
 4,835

 18,531
 17,877

 Shareholders' equity

 Common stock ( No par value, 2,000 shares authorized, 1005 shares and 999 shares outstanding as of December 31, 2024 and 2023, respectively)

 21,338
 21,114

 Treasury stock, at cost ( 2 shares as of December 31, 2024 and 2023)

 6,426
 5,490

 Accumulated other comprehensive loss, net
 ( 720)
 ( 726)

 Total shareholders' equity
 26,921
 25,755

 Total liabilities and shareholders' equity
 $
 45,452
 $
 43,632

 See the Notes to Financial Statements

 1. Basis of Presentation
 Exelon Corporate is a holding company that conducts substantially all of its business operations through its subsidiaries. These condensed financial statements and related footnotes have been prepared in accordance with Rule 12-04, Schedule I of Regulation S-X. These statements should be read in conjunction with the consolidated financial statements, and notes thereto, of Exelon Corporation.
 As of December 31, 2024 and 2023, Exelon Corporate owned 100 % of all of its significant subsidiaries, either directly or indirectly, except for Commonwealth Edison Company (ComEd), of which Exelon Corporate owns more than 99 %. As of February 1, 2022, as a result of the completion of the separation, Exelon Corporate no longer retains any equity ownership interest in Generation or Constellation. The separation of Constellation, including Generation and its subsidiaries, met the criteria for discontinued operations and as such, results of operations are presented as discontinued operations and have been excluded from continuing operations for all periods presented. Accounting rules require certain BSC costs previously allocated to Generation to be presented as part of Exelon's continuing operations as these costs do not qualify as expenses of the discontinued operations. Comprehensive income and cash flows related to Generation have not been segregated and are included in the Condensed Statements of Operations and Comprehensive Income and Condensed Statements of Cash Flows, respectively, for all periods presented. See Note 2 — Discontinued Operations of the Combined Notes to Consolidated Financial Statements for additional information.

 2. Regulatory Matters and Retirement Benefits
 See Note 3—Regulatory Matters and Note 14—Retirement Benefits of the Combined Notes to Consolidated Financial Statements for Exelon Corporate's regulatory assets and retirement benefits.

 3. Derivative Financial Instruments
 See Note 15—Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for Exelon Corporate's derivatives.

 4. Debt and Credit Agreements
 Short-Term Borrowings
 Exelon Corporate meets its short-term liquidity requirements primarily through the issuance of commercial paper. Exelon Corporate had $ 426 million in outstanding commercial paper borrowings as of December 31, 2024 and $ 527 million outstanding commercial paper as of December 31, 2023.
 Revolving Credit Agreements
 As of December 31, 2024, Exelon Corporate had a $ 900 million aggregate bank commitment under its existing syndicated revolving facility in which $ 471 million was available to support additional commercial paper as of December 31, 2024. Exelon Corporate had $ 3 million outstanding letters of credit as of December 31, 2024. See Note 16 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information regarding Exelon Corporate's credit agreement.
 On August 29, 2024, Exelon Corporate entered into a new revolving credit facility with an aggregate bank commitment of $ 900 million at a variable interest rate of SOFR plus 1.275 % which replaced its existing $ 900 million syndicated revolving credit facility, and extended the maturity date to August 29, 2029.
 Exelon Corporate had no outstanding amounts on the revolving credit facilities as of December 31, 2024.

 Short-Term Loan Agreements
 On March 23, 2017, Exelon Corporate entered into a term loan agreement for $ 500 million. The loan agreement was renewed in the first quarter of 2024 and was bifurcated into two tranches of $ 350 million and $ 150 million on March 14, 2024. The agreements will expire on March 14, 2025. Pursuant to the loan agreements, loans made thereunder bear interest at a variable rate equal to SOFR plus 1.05 % and all indebtedness thereunder is unsecured. The loan agreement is reflected in Exelon Corporate's Condensed Balance Sheets within Short-term borrowings.
 Debt Extinguishment
 During the twelve months ended December 31, 2024, Exelon Corporate repurchased a portion of its Senior unsecured notes with a principal balance of $ 244 million outstanding in exchange for cash of $ 215 million. The repurchase was accounted for as a debt extinguishment and resulted in a pre-tax gain of $ 28 million, which is reflected on Exelon Corporate's Condensed Statement of Operations and Comprehensive income within Interest expense, net.
 Long-Term Debt
 The following tables present the outstanding long-term debt for Exelon Corporate at December 31, 2024 and December 31, 2023:

Date

 Rates
 2024
 2023

 Senior unsecured notes
 2.75
 %
 -
 7.60
 %
 2025 - 2053
 $
 12,095
 $
 10,639

 Loan agreement(b)

 6.23
 %
 2024
 —

 12,095
 11,139

 ( 24)
 ( 13)

 ( 71)
 ( 65)

 Fair value adjustment

 Long-term debt due within one year(a)

 ( 807)
 ( 500)

 $
 11,334
 $
 10,713

 (a)Pursuant to the loan agreement, loans made thereunder bear interest at a variable rate equal to SOFR plus 0.85 %.
 The long-term debt maturities for Exelon Corporate for the periods 2025 through 2029 and thereafter are as follows:

 2025
 $

 2026

 2027

 2028
 1,000

 2029

 Thereafter
 8,238

 $
 12,095

 5. Commitments and Contingencies
 See Note 18—Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for Exelon Corporate's commitments and contingencies.

 6. Related Party Transactions

 The financial statements of Exelon Corporate include related party transactions as presented in the tables below:

 2024
 2023
 2022

 Operating and maintenance from affiliates:

 BSC(a)

 $
 $
 $

 Total operating and maintenance from affiliates:
 $
 $
 $

 Interest income (expense) from affiliates, net:

 BSC
 $
 $
 $

 EEDC(b)

 Total interest income from affiliates, net:
 $
 $
 $

 Equity in earnings (losses) of investments:

 BSC
 $
 —
 $
 —
 $
 ( 18)

 EEDC(b)

 2,886
 2,727
 2,482

 PCI
 ( 9)

 Connectiv, LLC
 ( 2)
 —
 —

 Exelon Enterprises
 —
 —

 Exelon InQB8R
 —
 ( 2)
 ( 4)

 Other
 —
 —
 ( 1)

 Total equity in earnings of investments:
 $
 2,887
 $
 2,728
 $
 2,450

 Cash contributions received from affiliates
 $
 2,250
 $
 1,978
 $
 2,027

 (in millions)
 2024
 2023

 Accounts receivable from affiliates (current):

 BSC
 $
 $
 —

 ComEd

 PECO

 BGE

 Total accounts receivable from affiliates (current):
 $
 $

 Notes receivable from affiliates (current):

 BSC(a)

 $
 $

 PHI

 Total notes receivable from affiliates (current):
 $
 $

 Investments in affiliates from continuing operations:

 BSC(a)

 $
 $

 EEDC(b)

 39,905
 37,705

 PCI

 UII

 Voluntary Employee Beneficiary Association trust
 —

 Exelon Enterprises

 Conectiv

 Exelon InQB8R

 Other(c)

 ( 1)
 ( 1)

 Total investments in affiliates from continuing operations:
 $
 40,741
 $
 38,545

 Accounts payable to affiliates (current):

 UII
 $
 $

 BSC(a)

 —

 Total accounts payable to affiliates (current):
 $
 $

 (a)Exelon Corporate receives a variety of corporate support services from BSC, including legal, human resources, financial, information technology, and supply management services. All services are provided at cost, including applicable overhead.
 (b)EEDC consists of ComEd, PECO, BGE, PHI, Pepco, DPL, and ACE.
 (c)Primarily relates to elimination of affiliate transactions with Generation, primarily related to the Regulatory Agreement Units. See Note 3 — Regulatory Matters and Note 23 — Related Party Transactions of the Combined Notes to Consolidated Financial Statements for additional information.

End

 $

 $
 (b)

 $
 $
 (c)

 $

 —

 —

 $

 $
 (b)

 $

 $
 (c)

 $

 —

 —

 $

 $
 (b)

 $
 $
 (c)

 $

 —

 (d)

 —

 (a)Excludes the noncurrent Allowance for credit losses related to PECO's installment plan receivables of $ 13 million, $ 6 million, and $ 7 million for the years ended December 31, 2024, 2023, and 2022, respectively.
 (b)The amount charged to costs and expenses includes the amount reclassified to Regulatory assets/liabilities under different mechanisms applicable to the different jurisdictions in which the Utility Registrants operate.
 (c)Primarily reflects write-offs, net of recoveries, of individual accounts receivable.
 (d)DPL recorded a full valuation allowance against Delaware net operating losses carryforwards due to a change in Delaware tax law. See Note 13 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information on the valuation allowance.

 (2) ComEd

 (i)

 Report of Independent Registered Public Accounting Firm dated February 12, 2025 of PricewaterhouseCoopers LLP (PCAOB ID 238)

 Consolidated Statements of Operations and Comprehensive Income for the Years Ended December 31, 2024, 2023, and 2022

 Consolidated Statements of Cash Flows for the Years Ended December 31, 2024, 2023, and 2022

 Consolidated Statements of Changes in Shareholders' Equity for the Years Ended December 31, 2024, 2023, and 2022

 (ii)

 Schedule II—Valuation and Qualifying Accounts for the Years Ended December 31, 2024, 2023, and 2022

 Schedules not included are omitted because of the absence of conditions under which they are required or because the required information is provided in the consolidated financial statements, including the notes thereto

End

 $
 $
 (a)

 $
 $
 (b)

 $

 $
 $
 (a)

 $
 $
 (b)

 $

 $
 $
 (a)

 $
 $
 (b)

 $

 (a)ComEd is allowed to recover from or refund to customers the difference between its annual credit loss expense and the amounts collected in rates annually through a rider mechanism. The amount charged to costs and expenses includes the amount that was reclassified to Regulatory assets/liabilities under such mechanism. See Note 3 – Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.

 (3) PECO

 (i)

 Report of Independent Registered Public Accounting Firm dated February 12, 2025 of PricewaterhouseCoopers LLP (PCAOB ID 238)

 Consolidated Statements of Operations and Comprehensive Income for the Years Ended December 31, 2024, 2023, and 2022

 Consolidated Statements of Cash Flows for the Years Ended December 31, 2024, 2023, and 2022

 Consolidated Statements of Changes in Shareholder's Equity for the Years Ended December 31, 2024, 2023, and 2022

 (ii)

 Schedule II—Valuation and Qualifying Accounts for the Years Ended December 31, 2024, 2023, and 2022

 Schedules not included are omitted because of the absence of conditions under which they are required or because the required information is provided in the consolidated financial statements, including the notes thereto

End

 $

 $
 $
 ( 1)
 $
 (c)

 $

 —
 ( 1)
 —

 $
 $
 (b)

 $
 $
 (c)

 $

 —
 —
 —

 $
 $
 (b)

 $
 $
 (c)

 $

 —
 —

 (a)Excludes the noncurrent Allowance for credit losses related to PECO's installment plan receivables of $ 13 million, $ 6 million, and $ 7 million for the years ended December 31, 2024, 2023, and 2022, respectively.
 (b)The amount charged to costs and expenses includes the amount that was reclassified to the COVID-19 regulatory asset. See Note 3 – Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.
 (c)Write-offs, net of recoveries of individual accounts receivable.

 (4) BGE

 (i)

 Report of Independent Registered Public Accounting Firm dated February 12, 2025 of PricewaterhouseCoopers LLP (PCAOB ID 238)

 Statements of Operations and Comprehensive Income for the Years Ended December 31, 2024, 2023 and 2022

 Statements of Cash Flows for the Years Ended December 31, 2024, 2023 and 2022

 Balance Sheets at December 31, 2024 and 2023

 Statements of Changes in Shareholder's Equity for the Years Ended December 31, 2024, 2023 and 2022

 (ii)

 Schedule II—Valuation and Qualifying Accounts for the Years Ended December 31, 2024, 2023, and 2022

 Schedules not included are omitted because of the absence of conditions under which they are required or because the required information is provided in the consolidated financial statements, including the notes thereto

End

 $

 $
 (a)

 $

 $
 (b)

 $

 —
 —

 —

 $
 $
 (a)

 $

 $
 (b)

 $

 —
 —

 —

 $
 $
 (a)

 $

 $
 (b)

 $

 —
 —
 —

 (a)The amount charged to costs and expenses includes the amount that was reclassified to Regulatory assets/liabilities under different mechanisms as approved by the MDPSC.

 (5) PHI

 (i)

 Report of Independent Registered Public Accounting Firm dated February 12, 2025 of PricewaterhouseCoopers LLP (PCAOB ID 238)

 Consolidated Statements of Operations and Comprehensive Income for the Years Ended December 31, 2024, 2023, and 2022

 Consolidated Statements of Cash Flows for the Years Ended December 31, 2024, 2023, and 2022

 Consolidated Statements of Changes in Equity for the Years Ended December 31, 2024, 2023, and 2022

 (ii)

 Schedule II—Valuation and Qualifying Accounts for the Years Ended December 31, 2024, 2023, and 2022

 Schedules not included are omitted because of the absence of conditions under which they are required or because the required information is provided in the consolidated financial statements, including the notes thereto

End

 $
 $
 (a)

 $
 ( 9)
 $
 (b)

 $

 —
 ( 3)
 —

 $
 $
 (a)

 $
 ( 7)
 $
 (b)

 $

 —
 —
 —

 $
 $
 (a)

 $
 —
 $
 (b)

 $

 —
 (c)

 —

 (a)The amount charged to costs and expenses includes the amount that was reclassified to Regulatory assets/liabilities under different mechanisms applicable to the different jurisdictions Pepco, DPL, and ACE operate in.
 (c)DPL recorded a full valuation allowance against Delaware net operating losses carryforwards due to a change in Delaware tax law. See Note 13 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information on the valuation allowance.

 (6) Pepco

 (i)

 Report of Independent Registered Public Accounting Firm dated February 12, 2025 of PricewaterhouseCoopers LLP (PCAOB ID 238)

 Statements of Operations and Comprehensive Income for the Years Ended December 31, 2024, 2023 and 2022

 Statements of Cash Flows for the Years Ended December 31, 2024, 2023 and 2022

 Balance Sheets at December 31, 2024 and 2023

 Statements of Changes in Shareholder's Equity for the Years Ended December 31, 2024, 2023 and 2022

 (ii)

 Schedule II—Valuation and Qualifying Accounts for the Years Ended December 31, 2024, 2023, and 2022

 Schedules not included are omitted because of the absence of conditions under which they are required or because the required information is provided in the consolidated financial statements, including the notes thereto

End

 $
 $
 (a)

 $
 ( 10)
 $
 (b)

 $

 $
 $
 (a)

 $
 ( 5)
 $
 (b)

 $

 $
 $
 (a)

 $
 $
 (b)

 $

 (a)The amount charged to costs and expenses includes the amount that was reclassified to Regulatory assets/liabilities under different mechanisms as approved by the DCPSC and MDPSC.

 (7) DPL

 (i)

 Report of Independent Registered Public Accounting Firm dated February 12, 2025 of PricewaterhouseCoopers LLP (PCAOB ID 238)

 Statements of Operations and Comprehensive Income for the Years Ended December 31, 2024, 2023 and 2022

 Statements of Cash Flows for the Years Ended December 31, 2024, 2023 and 2022

 Balance Sheets at December 31, 2024 and 2023

 Statements of Changes in Shareholder's Equity for the Years Ended December 31, 2024, 2023 and 2022

 (ii)

 Schedule II—Valuation and Qualifying Accounts for the Years Ended December 31, 2024, 2023, and 2022

 Schedules not included are omitted because of the absence of conditions under which they are required or because the required information is provided in the consolidated financial statements, including the notes thereto

End

 $
 $
 (a)

 $
 —
 $
 (b)

 $

 —
 ( 3)

 —

 $
 $
 (a)

 $
 —
 $
 (b)

 $

 —
 —
 —

 $
 $
 (a)

 $
 ( 2)
 $
 (b)

 $

 —
 —

 (a)The amount charged to costs and expenses includes the amount that was reclassified to Regulatory assets/liabilities under different mechanisms as approved by the DEPSC and MDPSC.

 (8) ACE

 (i)

 Report of Independent Registered Public Accounting Firm dated February 12, 2025 of PricewaterhouseCoopers LLP (PCAOB ID 238)

 Consolidated Statements of Operations and Comprehensive Income for the Years Ended December 31, 2024, 2023, and 2022

 Consolidated Statements of Cash Flows for the Years Ended December 31, 2024, 2023, and 2022

 Consolidated Statements of Changes in Shareholder's Equity for the Years Ended December 31, 2024, 2023, and 2022

 (ii)

 Schedule II—Valuation and Qualifying Accounts for the Years Ended December 31, 2024, 2023, and 2022

 Schedules not included are omitted because of the absence of conditions under which they are required or because the required information is provided in the consolidated financial statements, including the notes thereto

End

 $
 $
 (a)

 $
 $
 (b)

 $

 $
 $
 (a)

 ( 2)
 $
 (b)

 $

 $
 $
 (a)

 $
 ( 2)
 $
 (b)

 $

 (a)ACE is allowed to recover from or refund to customers the difference between its annual credit loss expense and the amounts collected in rates annually through the Societal Benefits Charge. The amount charged to costs and expenses includes the amount that was reclassified to Regulatory assets/liabilities under such mechanism. See Note 3 – Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.

 Exhibits required by Item 601 of Regulation S-K:
 Certain of the following exhibits are incorporated herein by reference under Rule 12b-32 of the Securities and Exchange Act of 1934, as amended. Certain other instruments which would otherwise be required to be listed below have not been so listed because such instruments do not authorize securities in an amount which exceeds 10% of the total assets of the applicable registrant and its subsidiaries on a consolidated basis and the relevant registrant agrees to furnish a copy of any such instrument to the Commission upon request.
 (2) Plans of acquisition, reorganization, arrangement, liquidation, or succession

 2-1

 Separation Agreement, dated January 31, 2022, between Exelon Corporation and Constellation Energy Corporation
 File No. 001-16169, Form 8K dated February 2, 2022, Exhibit 2.1

 (3) Articles of Incorporation and Bylaws

 3-1

 Amended and Restated Articles of Incorporation of Exelon Corporation, as amended April 30, 2024
 File No. 001-16169, Form 10-Q dated August 1, 2024, Exhibit 3.1

 3-2

 Amended and Restated Bylaws of Exelon Corporation, as amended on April 30, 2024
 File No. 001-16169, Form 10-Q dated August 1, 2024, Exhibit 3.2

 3-3

 Articles of Restatement to the Charter of Baltimore Gas and Electric Company, restated as of August 16, 1996
 File No. 001-01910, Form 10-Q dated November 14, 1996, Exhibit 3

 3-4

 Articles of Amendment to the Charter of Baltimore Gas and Electric Company as of February 2, 2010
 File No. 001-01910, Form 8-K dated February 4, 2010, Exhibit 3.1

 3-5

 Amended and Restated Bylaws of Baltimore Gas and Electric Company dated August 3, 2020
 File No. 001-01910, Form 10-Q dated August 4, 2020, Exhibit 3.4

 3-6

 Restated Articles of Incorporation of Commonwealth Edison Company Effective February 20, 1985, including Statements of Resolution Establishing Series, relating to the establishment of three new series of Commonwealth Edison Company preference stock known as the "$9.00 Cumulative Preference Stock," the "$6.875 Cumulative Preference Stock" and the "$2.425 Cumulative Preference Stock"
 File No. 001-01839, Form 10-K dated March 30, 1995, Exhibit 3.2

 3-7

 Amended and Restated Bylaws of Commonwealth Edison Company, Effective February 22, 2021
 File No. 001-01839, Form 10-K dated February 24, 2021, Exhibit 3.6

 3-8

 Amended and Restated Articles of Incorporation of PECO Energy Company
 File No. 001-01401, Form 10-K dated April 2, 2001, Exhibit 3.3

 3-9

 Amended and Restated Bylaws of PECO Energy Company dated August 3, 2020
 File No. 000-16844, Form 10-Q dated August 4, 2020, Exhibit 3.3

 3-10

 Certificate of Formation of Pepco Holdings LLC, dated March 23, 2016
 File No. 001-31403, Form 8-K dated March 24, 2016, Exhibit 3.2

 3-11

 Amended and Restated Limited Liability Company Agreement of Pepco Holdings LLC, dated August 3, 2020
 File No. 001-31403, Form 10-Q dated August 4, 2020, Exhibit 3.5

 3-12

 Restated Certificate of Incorporation of Atlantic City Electric Company (filed in New Jersey on August 9, 2002)
 File No. 001-03559, Amendment No. 1 to Form U5B dated February 13, 2003, Exhibit B.8.1

 3-13

 Bylaws of Atlantic City Electric Company
 File No. 001-03559, Form 10-Q dated May 9, 2005, Exhibit 3.2.2

 3-14

 Restated Certificate and Articles of Incorporation of Delmarva Power & Light Company (as filed in Delaware and Virginia)
 File No. 001-01405, Form 10-K dated March 1, 2007, Exhibit 3.3

 3-15

 Bylaws of Delmarva Power & Light Company
 File No. 001-01405, Form 10-Q dated May 9, 2005, Exhibit 3.2.1

 3-16

 Restated Articles of Incorporation of Potomac Electric Power Company (as filed in the District of Columbia)
 File No. 001-31403, Form 10-Q dated May 5, 2006, Exhibit 3.1

 3-17

 Restated Articles of Incorporation and Articles of Restatement of Potomac Electric Power Company (as filed in Virginia)
 File No. 001-01072, Form 10-Q dated November 4, 2011, Exhibit 3.3

 3-18

 Bylaws of Potomac Electric Power Company
 File No. 001-01072, Form 10-Q dated May 5, 2006, Exhibit 3.2

 (4) Instruments Defining the Rights of Securities Holders, Including Indentures

 4-1

 Exelon Corporation Direct Stock Purchase Plan
 File No. 333-222989, Prospectus 424(b)(2) dated June 30, 2023

 4-2

 Indenture dated May 1, 2001 between Exelon Corporation and The Bank of New York Mellon Trust Company, N.A., as trustee
 File No. 001-16169, Form 10-Q dated July 26, 2005, Exhibit 4.10

 4-3

 Form of $500,000,000 5.625% senior notes due 2035 dated June 9, 2005 issued by Exelon Corporation
 File No. 001-16169, Form 8-K dated June 9, 2005, Exhibit 99.3

 4-4

 Indenture, dated as of June 17, 2014, between Exelon Corporation and The Bank of New York Mellon Trust Company, N.A., as Trustee
 File No. 001-16169, Form 8-K dated June 23, 2014, Exhibit 4.1

 4-4-1

 First Supplemental Indenture, dated as of June 17, 2014, between Exelon Corporation and The Bank of New York Mellon Trust Company, N.A., as Trustee
 File No. 001-16169, Form 8-K dated June 23, 2014, Exhibit 4.2

 4-4-2

 Second Supplemental Indenture, dated April 3, 2017, between Exelon and The Bank of New York Mellon Trust Company, N.A., as trustee, to that certain Indenture (For Unsecured Subordinated Debt Securities), dated June 17, 2014
 File No. 001-16169, Form 8-K dated April 4, 2017, Exhibit 4.3

 4-5

 Indenture, dated as of June 11, 2015, among Exelon Corporation and The Bank of New York Mellon Trust Company, N.A., as trustee

 File No. 001-16169, Form 8-K dated June 11, 2015, Exhibit 4.1

 4-5-1

 First Supplemental Indenture, dated as of June 11, 2015, among Exelon Corporation and The Bank of New York Mellon Trust Company, N.A., as trustee

 File No. 001-16169, Form 8-K dated June 11, 2015, Exhibit 4.2

 4-5-2

 Second Supplemental Indenture, dated as of December 2, 2015, among Exelon Corporation and The Bank of New York Mellon Trust Company, N.A., as trustee

 File No. 001-16169, Form 8-K dated December 2, 2015, Exhibit 4.1

 4-5-3

 Third Supplemental Indenture, dated as of April 7, 2016, among Exelon Corporation and The Bank of New York Mellon Trust Company, N.A., as trustee
 File No. 001-16169, Form 8-K dated April 7, 2016, Exhibit 4.2

 4-5-4

 Fourth Supplemental Indenture, dated as of April 1, 2020, among Exelon Corporation and The Bank of New York Mellon Trust Company, N.A., as trustee
 File No. 001-16169, Form 8-K dated April 1, 2020, Exhibit 4.2

 4-5-5

 Fifth Supplemental Indenture, dated as of March 7, 2022, among Exelon Corporation and The Bank of New York Mellon Trust Company, N.A., as trustee
 File No. 001-16169, Form 8-K dated March 7, 2022, Exhibit 4.2

 4-5-6

 Sixth Supplemental Indenture, dated as of February 1, 2023, among Exelon Corporation and The Bank of New York Mellon Trust Company, N.A., as trustee
 File No. 001-16169, Form 8-K dated February 21, 2023, Exhibit 4.2

 4-5-7

 Seventh Supplemental Indenture, dated as of February 27, 2024, among Exelon Corporation and The Bank of New York Mellon Trust Company, N.A., as trustee
 File No. 001-16169, Form 8-K dated February 27, 2024, Exhibit 4.2

 4-6

 Description of Exelon Securities
 File No. 001-16169, Form 10-K dated February 11, 2020, Exhibit 4.63

 4-7

 Indenture dated as of July 24, 2006 between Baltimore Gas and Electric Company and Deutsche Bank Trust Company Americas, as trustee
 File No. 333-135991, Registration Statement on Form S-3 dated July 24, 2006, Exhibit 4(b)

 4-8

 Form of 2.400% notes due 2026 issued August 18, 2016 by Baltimore Gas and Electric Company
 File No. 001-01910, Form 8-K dated August 18, 2016, Exhibit 4.1

 4-9

 Form of 3.500% Note due 2046 issued August 18, 2016 by Baltimore Gas and Electric Company
 File No. 001-01910, Form 8-K dated August 18, 2016, Exhibit 4.2

 4-10

 Form of 3.750% Note due 2047 issued August 24, 2017 by Baltimore Gas and Electric Company
 File No. 001-01910, Form 8-K dated August 24, 2017, Exhibit 4.1

 4-11

 Form of 4.550% Note due 2052 issued June 6, 2022 by Baltimore Gas and Electric Company
 File No. 001-01910, Form 8-K dated June 6, 2022, Exhibit 4.2

 4-12

 Form of 5.400% Note due 2053 issued May 10, 2023 by Baltimore Gas and Electric
 File No. 001-01910, Form 8-K dated May 10, 2023, Exhibit 4.2

 4-13

 Form of 5.300% Note due 2034 issued June 1, 2024 by Baltimore Gas and Electric
 File No. 001-01910, Form 8-K dated June 06, 2024, Exhibit 4.1

 4-14

 Form of 5.650% Note due 2054 issued June 1, 2024 by Baltimore Gas and Electric
 File No. 001-01910, Form 8-K dated June 06, 2024, Exhibit 4.2

 4-15

 Indenture, dated as of September 1, 2019, between Baltimore Gas and Electric Company and U.S. Bank N.A., as trustee
 File No. 001-01910, Form 8-K dated September 12, 2019, Exhibit 4.1

 4-16
 Mortgage of Commonwealth Edison Company to Illinois Merchants Trust Company, Trustee (BNY Mellon Trust Company of Illinois, as current successor Trustee), dated July 1, 1923, as supplemented and amended by Supplemental Indenture thereto dated August 1, 1944
 Registration No. 2-60201, Form S-7, Exhibit 2-1(a)

 4-16-1

 Supplemental Indenture to Commonwealth Edison Company Mortgage dated as of January 13, 2003
 File No. 001-01839, Form 8-K dated February 13, 2003, Exhibit 4.4

 4-16-2

 Supplemental Indenture to Commonwealth Edison Company Mortgage dated as of February 22, 2006
 File No. 001-01839, Form 8-K dated March 6, 2006, Exhibit 4.1

 4-16-3

 Supplemental Indenture to Commonwealth Edison Company Mortgage dated as of March 1, 2007
 File No. 001-01839, Form 8-K dated March 23, 2007, Exhibit 4.1

 4-16-4

 Supplemental Indenture to Commonwealth Edison Company Mortgage dated as of December 20, 2007
 File No. 001-01839, Form 8-K dated January 16, 2008, Exhibit 4.1

 4-16-5

 Supplemental Indenture to Commonwealth Edison Company Mortgage dated as of September 17, 2012
 File No. 001-01839, Form 8-K dated October 1, 2012, Exhibit 4.1

 4-16-6

 Supplemental Indenture to Commonwealth Edison Company Mortgage dated as of August 1, 2013
 File No. 001-01839, Form 8-K dated August 19, 2013, Exhibit 4.1

 4-16-7

 Supplemental Indenture to Commonwealth Edison Company Mortgage dated as of January 2, 2014
 File No. 001-01839, Form 8-K dated January 10, 2014, Exhibit 4.1

 4-16-8

 Supplemental Indenture to Commonwealth Edison Company Mortgage dated as of February 18, 2015
 File No. 001-01839, Form 8-K dated March 2, 2015, Exhibit 4.1

 4-16-9

 Supplemental Indenture to Commonwealth Edison Company Mortgage dated as of November 4, 2015
 File No. 001-01839, Form 8-K dated November 19, 2015, Exhibit 4.1

 4-16-10

 Supplemental Indenture to Commonwealth Edison Company Mortgage dated as of June 15, 2016
 File No. 001-01839, Form 8-K dated June 27, 2016, Exhibit 4.1

 4-16-11

 Supplemental Indenture to Commonwealth Edison Company Mortgage dated as of August 9, 2017
 File No. 001-01839, Form 8-K dated August 23, 2017, Exhibit 4.1

 4-16-12

 Supplemental Indenture to Commonwealth Edison Company Mortgage dated as of February 6, 2018
 File No. 001-01839, Form 8-K dated February 20, 2018, Exhibit 4.1

 4-16-13

 Supplemental Indenture to Commonwealth Edison Company Mortgage dated as of July 26, 2018
 File No. 001-01839, Form 8-K dated August 14, 2018, Exhibit 4.1

 4-16-14

 Supplemental Indenture to Commonwealth Edison Company Mortgage dated as of February 7, 2019
 File No. 001-01839, Form 8-K dated February 19, 2019, Exhibit 4.1

 4-16-15

 Supplemental Indenture to Commonwealth Edison Company Mortgage dated as of October 29, 2019
 File No. 001-01839, Form 8-K dated November 12, 2019, Exhibit 4.1

 4-16-16

 Supplemental Indenture to Commonwealth Edison Company Mortgage dated as of February 10, 2020
 File No. 001-01839, Form 8-K dated February 25, 2020, Exhibit 4.1

 4-16-17

 Supplemental Indenture to Commonwealth Edison Company Mortgage dated as of February 16, 2021
 File No. 001-01839, Form 8-K dated March 9, 2021, Exhibit 4.1

 4-16-18

 Supplemental Indenture to Commonwealth Edison Company Mortgage dated as of August 2, 2021
 File No. 001-01839, Form 8-K dated August 12, 2021, Exhibit 4.1

 4-16-19

 Supplemental Indenture to Commonwealth Edison Company Mortgage dated as of February 23, 2022
 File No. 001-01839, Form 8-K/A dated March 15, 2022, Exhibit 4.1

 4-16-20

 Supplemental Indenture to Commonwealth Edison Company Mortgage dated as of December 21, 2022
 File No. 001-01839, Form 8-K dated January 10, 2023, Exhibit 4.1

 4-16-21

 Supplemental Indenture to Commonwealth Edison Company Mortgage dated as of May 1, 2024
 File No. 001-01839, Form 8-K dated May 13, 2024, Exhibit 4.1

 4-16

 Instrument of Resignation, Appointment and Acceptance dated as of February 20, 2002, under the provisions of the Mortgage of Commonwealth Edison Company dated July 1, 1923, and Indentures Supplemental thereto, regarding corporate trustee
 File No. 001-01839, Form 10-K dated April 1, 2002, Exhibit 4.4.2

 4-17

 Instrument dated as of January 31, 1996, under the provisions of the Mortgage of Commonwealth Edison Company dated July 1, 1923 and Indentures Supplemental thereto, regarding individual
 File No. 001-01839, Form 10-K dated March 29, 1996, Exhibit 4.29

 4-18

 Description of ComEd Securities
 File No. 001-16169, Form 10-K dated February 11, 2020, Exhibit 4.65

 4-19
 First and Refunding Mortgage dated May 1, 1923 between The Counties Gas and Electric Company (predecessor to PECO Energy Company) and Fidelity Trust Company, Trustee (U.S. Bank N.A., as current successor trustee)
 Registration No. 2-2281, Exhibit B-1(a)

 4-19-1
 Supplemental Indenture to PECO Energy Company's First and Refunding Mortgage dated as of December 1, 1941
 Registration No. 2-4863, Exhibit B-1(h)(a)

 4-19-2

 Supplemental Indenture to PECO Energy Company's First and Refunding Mortgage dated as of April 15, 2004
 File No. 000-16844, Form 10-Q dated September 30, 2004, Exhibit 4-1-1

 4-19-3

 Supplemental Indenture to PECO Energy Company's First and Refunding Mortgage dated as of September 15, 2006
 File No. 000-16844, Form 8-K dated September 25, 2006, Exhibit 4.1

 4-19-4

 Supplemental Indenture to PECO Energy Company's First and Refunding Mortgage dated as of March 1, 2007
 File No. 000-16844, Form 8-K dated March 19, 2007, Exhibit 4.1

 4-19-5

 Supplemental Indenture to PECO Energy Company's First and Refunding Mortgage dated as of September 1, 2014
 File No. 000-16844, Form 8-K dated September 15, 2014, Exhibit 4.1

 4-19-6

 Supplemental Indenture to PECO Energy Company's First and Refunding Mortgage dated as of September 15, 2015
 File No. 000-16844, Form 8-K dated October 5, 2015, Exhibit 4.1

 4-19-7

 Supplemental Indenture to PECO Energy Company's First and Refunding Mortgage dated as of September 1, 2017
 File No. 000-16844, Form 8-K dated September 18, 2017, Exhibit 4.1

 4-19-8

 Supplemental Indenture to PECO Energy Company's First and Refunding Mortgage dated as of February 1, 2018
 File No. 000-16844, Form 8-K dated February 23, 2018, Exhibit 4.1

 4-19-9

 Supplemental Indenture to PECO Energy Company's First and Refunding Mortgage dated as of September 1, 2018
 File No. 000-16844, Form 8-K dated September 11, 2018, Exhibit 4.1

 4-19-10

 Supplemental Indenture to PECO Energy Company's First and Refunding Mortgage dated as of August 15, 2019
 File No. 000-16844, Form 8-K dated September 10, 2019, Exhibit 4.1

 4-19-11

 Supplemental Indenture to PECO Energy Company's First and Refunding Mortgage dated as of June 1, 2020
 File No. 000-16844, Form 8-K dated June 8, 2020, Exhibit 4.1

 4-19-12

 Supplemental Indenture to PECO Energy Company's First and Refunding Mortgage dated as of February 15, 2021
 File No. 000-16844, Form 8-K dated March 8, 2021, Exhibit 4.1

 4-19-13

 Supplemental Indenture to PECO Energy Company's First and Refunding Mortgage dated as of September 1, 2021
 File No. 000-16844, Form 8-K dated September 14, 2021, Exhibit 4.1

 4-19-14

 Supplemental Indenture to PECO Energy Company's First and Refunding Mortgage dated as of May 1, 2022
 File No. 000-16844, Form 8-K dated May 24, 2022, Exhibit 4.1

 4-19-15

 Supplemental Indenture to PECO Energy Company's First and Refunding Mortgage dated as of August 1, 2022
 File No. 000-16844, Form 8-K dated August 23, 2022, Exhibit 4.1

 4-19-16

 Supplemental Indenture to PECO Energy Company's First and Refunding Mortgage dated as of June 1, 2023
 File No. 001-16844, Form 8-K dated June 23, 2023, Exhibit 4.1

 4-19-17

 Supplemental Indenture to PECO Energy Company's First and Refunding Mortgage dated as of August 15, 2024
 File No. 001-16844, Form 8-K dated September 10, 2024, Exhibit 4.1

 4-20

 Indenture to Subordinated Debt Securities dated as of June 24, 2003 between PECO Energy Company, as Issuer, and U.S. Bank N.A., as Trustee
 File No. 000-16844, Form 10-Q dated July 30, 2003, Exhibit 4.1

 4-21

 Preferred Securities Guarantee Agreement between PECO Energy Company, as Guarantor, and U.S. Bank N.A., as Trustee, dated as of June 24, 2003
 File No. 000-16844, Form 10-Q dated July 30, 2003, Exhibit 4.2

 4-22

 PECO Energy Capital Trust IV Amended and Restated Declaration of Trust among PECO Energy Company, as Sponsor, U.S. Bank Trust N.A., as Delaware Trustee and Property Trustee, and J. Barry Mitchell, George R. Shicora and Charles S. Walls as Administrative Trustees dated as of June 24, 2003
 File No. 000-16844, Form 10-Q dated July 30, 2003, Exhibit 4.3

 4-23
 Mortgage and Deed of Trust, dated January 15, 1937, between Atlantic City Electric Company and The Bank of New York Mellon (formerly Irving Trust Company), as trustee
 2-66280, Registration Statement dated December 21, 1979, Exhibit 2(a)(a)

 4-23-1
 Supplemental Indenture to Atlantic City Electric Company Mortgage dated as of June 1, 1949
 2-66280, Registration Statement dated December 21, 1979, Exhibit 2(b)(a)

 4-23-2
 Supplemental Indenture to Atlantic City Electric Company Mortgage dated as of March 1, 1991
 Form 10-K dated March 28, 1991, Exhibit 4(d)(1)(a)

 4-23-3

 Supplemental Indenture to Atlantic City Electric Company Mortgage dated as of April 1, 2004
 File No. 001-03559, Form 8-K dated April 6, 2004, Exhibit 4.3

 4-23-4

 Supplemental Indenture to Atlantic City Electric Company Mortgage dated as of March 8, 2006
 File No. 001-03559, Form 8-K dated March 17, 2006, Exhibit 4

 4-23-5

 Supplemental Indenture to Atlantic City Electric Company Mortgage dated as of December 1, 2015
 File No. 001-03559, Form 8-K dated December 2, 2015, Exhibit 4.2 (included as Exhibit A to Exhibit 1.1).

 4-23-6

 Supplemental Indenture to Atlantic City Electric Company Mortgage dated as of October 9, 2018
 File No. 001-03559, Form 8-K dated October 16, 2018, Exhibit 4.1

 4-23-7

 Supplemental Indenture to Atlantic City Electric Company Mortgage dated as of May 2, 2019
 File No. 001-03559, Form 8-K dated May 21, 2019, File No. 4.3

 4-23-8

 Supplemental Indenture to Atlantic City Electric Company Mortgage dated as of June 1, 2020
 File No. 001-03559, Form 8-K dated June 9, 2020, Exhibit 4.2

 4-23-9

 Supplemental Indenture to Atlantic City Electric Company Mortgage dated as of February 15, 2021
 File No. 001-03559, Form 8-K dated March 10, 2021, Exhibit 4.1

 4-23-10

 Supplemental Indenture to Atlantic City Electric Company Mortgage dated as of November 1, 2021
 File No. 001-03559, Form 8-K dated November 16, 2021, Exhibit 4.2

 4-23-11

 Supplemental Indenture to Atlantic City Electric Company Mortgage dated as of February 1, 2022
 File No. 001-03559, Form 8-K dated February 15, 2022, Exhibit 4.2

 4-23-12

 Supplemental Indenture to the Atlantic City Electric Company Mortgage and Deed of Trust, dated as of March 1, 2023
 File No. 001-03559, Form 8-K dated March 15, 2023, Exhibit 4.2

 4-23-13

 Supplemental Indenture to the Atlantic City Electric Company Mortgage and Deed of Trust, dated as of March 1, 2024
 File No. 001-03559, Form 8-K dated March 20, 2024, Exhibit 4.2

 4-24

 Pollution Control Facilities Loan Agreement, dated as of June 1, 2020, between The Pollution Control Financing Authority of Salem County and Atlantic City Electric
 File No. 001-03559, Form 8-K dated June 2, 2020, Exhibit 4.1

 4-25
 Mortgage and Deed of Trust of Delaware Power & Light Company to The Bank of New York Mellon (ultimate successor to the New York Trust Company), as trustee, dated as of October 1, 1943, and copies of the First through Sixty-Eighth Supplemental Indentures thereto
 33-1763, Registration Statement dated November 27, 1985, Exhibit 4-(A)(a)

 4-25-1
 Supplemental Indenture to Delmarva Power & Light Company Mortgage dated as of October 1, 1993
 33-53855, Registration Statement dated January 30, 1995, Exhibit 4-L(a)

 4-25-2
 Supplemental Indenture to Delmarva Power & Light Company Mortgage dated as of October 1, 1994
 33-53855, Registration Statement dated January 30, 1995, Exhibit 4-N(a)

 4-25-3

 Supplemental Indenture to Delmarva Power & Light Company Mortgage dated as of May 4, 2015
 File No. 001-01405, Form 8-K dated May 5, 2015, Exhibit 4.2

 4-25-4

 Supplemental Indenture to Delmarva Power & Light Company Mortgage dated as of December 5, 2016
 File No. 001-01405, Form 8-K dated December 12, 2016, Exhibit 4.2

 4-25-5

 Supplemental Indenture to Delmarva Power & Light Company Mortgage dated as of June 1, 2018
 File No. 001-01405, Form 8-K dated June 21, 2018, Exhibit 4.2

 4-25-6

 Supplemental Indenture to Delmarva Power & Light Company Mortgage dated as of May 2, 2019
 File No. 001-01405, Form 8-K dated December 12, 2019, Exhibit 4.2

 4-25-7

 Supplemental Indenture to Delmarva Power & Light Company Mortgage dated as of January 1, 2020
 File No. 001-01405, Form 10-Q dated May 8, 2020, Exhibit 4.4

 4-25-8

 Supplemental Indenture to Delmarva Power & Light Company Mortgage dated as of June 1, 2020
 File No. 001-01405, Form 8-K dated June 9, 2020, Exhibit 4.4

 4-25-9

 Supplemental Indenture to Delmarva Power & Light Company Mortgage dated as of February 15, 2021
 File No. 001-01405, Form 8-K dated March 30, 2021, Exhibit 4.4

 4-25-10

 Supplemental Indenture to Delmarva Power & Light Company Mortgage dated as of February 1, 2022
 File No. 001-01405, Form 8-K dated February 15, 2022, Exhibit 4.4

 4-25-11

 Supplemental Indenture to Delmarva Power & Light Company Mortgage dated as of January 1, 2022
 File No. 001-01405, Form 10-Q dated May 9, 2022, Exhibit 4.1

 4-25-12

 Supplemental Indenture to the Delmarva Power & Light Company Mortgage and Deed of Trust, dated as of March 1, 2023
 File No. 001-01405, Form 8-K dated March 15, 2023, Exhibit 4.4

 4-25-13

 Supplemental Indenture to the Delmarva Power & Light Company Mortgage and Deed of Trust, dated as of March 1, 2024
 File No. 001-01405, Form 8-K dated March 20, 2024, Exhibit 4.4

 4-26

 Gas Facilities Loan Agreement, dated as of July 1, 2020, between The Delaware Economic Development Authority and Delmarva Power & Light Company
 File No. 001-01405, Form 8-K dated July 1, 2020, Exhibit 4.1

 4-27
 Mortgage and Deed of Trust, dated July 1, 1936, of Potomac Electric Power Company to The Bank of New York Mellon as successor trustee, securing First Mortgage Bonds of Potomac Electric Power Company, and Supplemental Indenture dated July 1, 1936
 File No. 2-2232, Registration Statement dated June 19, 1936, Exhibit B-4(a)

 4-27-1
 Supplemental Indenture to Potomac Electric Power Company Mortgage dated as of December 10, 1939
 8-K dated January 3, 1940, Exhibit B(a)

 4-27-2

 Supplemental Indenture to Potomac Electric Power Company Mortgage dated as of March 16, 2004
 File No. 001-01072, Form 8-K dated March 23, 2004, Exhibit 4.3

 4-27-3

 Supplemental Indenture to Potomac Electric Power Company Mortgage dated as of May 24, 2005
 File No. 001-01072, Form 8-K dated May 26, 2005, Exhibit 4.2

 4-27-4

 Supplemental Indenture to Potomac Electric Power Company Mortgage dated as of November 13, 2007
 File No. 001-01072, Form 8-K dated November 15, 2007, Exhibit 4.2

 4-27-5

 Supplemental Indenture to Potomac Electric Power Company Mortgage dated as of March 24, 2008
 File No. 001-01072, Form 8-K dated March 28, 2008, Exhibit 4.1

 4-27-6

 Supplemental Indenture to Potomac Electric Power Company Mortgage dated as of December 3, 2008
 File No. 001-01072, Form 8-K dated December 8, 2008, Exhibit 4.2

 4-27-7

 Supplemental Indenture to Potomac Electric Power Company Mortgage dated as of March 11, 2013
 File No. 001-01072, Form 8-K dated March 12, 2013, Exhibit 4.2

 4-27-8

 Supplemental Indenture to Potomac Electric Power Company Mortgage dated as of November 14, 2013
 File No. 001-01072, Form 8-K dated November 15, 2013, Exhibit 4.2

 4-27-9

 Supplemental Indenture to Potomac Electric Power Company Mortgage dated as of March 9, 2015
 File No. 001-01072, Form 8-K dated March 10, 2015, Exhibit 4.3

 4-27-10

 Supplemental Indenture to Potomac Electric Power Company Mortgage dated as of May 15, 2017
 File No. 001-01072, Form 8-K dated May 22, 2017, Exhibit 4.2

 4-27-11

 Supplemental Indenture to Potomac Electric Power Company Mortgage dated as of June 1, 2018
 File No. 001-01072, Form 8-K dated June 21, 2018, Exhibit 4.2

 4-27-12

 Supplemental Indenture to Potomac Electric Power Company Mortgage dated as of May 2, 2019
 File No. 001-01072, Form 8-K dated June 13, 2019, Exhibit 4.2

 4-27-13

 Supplemental Indenture to Potomac Electric Power Company Mortgage dated as of February 12, 2020
 File No. 001-01072, Form 8-K dated February 25, 2020, Exhibit 4.2

 4-27-14

 Supplemental Indenture to Potomac Electric Power Company Mortgage dated as of February 15, 2021
 File No. 001-01072, Form 8-K dated March 30, 2021, Exhibit 4.4

 4-27-15

 Supplemental Indenture to Potomac Electric Power Company Mortgage dated as of March 1, 2022
 File No. 001-01072, Form 8-K dated March 24, 2022, Exhibit 4.2

 4-27-16

 Supplemental Indenture to the Potomac Electric Power Company Mortgage and Deed of Trust, dated as of March 1, 2023
 File No. 001-01072, Form 8-K dated March 15, 2023, Exhibit 4.6

 4-27-17

 Supplemental Indenture to the Potomac Electric Power Company Mortgage and Deed of Trust, dated as of February 15, 2024
 File No. 001-01072, Form 8-K dated March 4, 2024, Exhibit 4.3

 4-28

 Exempt Facilities Loan Agreement dated as of June 1, 2019 between the Maryland Economic Development Corporation and Potomac Electric Power Company
 File No. 001-01072, Form 8-K dated June 27, 2019, Exhibit 4.1

 (10) Material Contracts

 10-1

 Transition Services Agreement, dated January 31, 2022, between Exelon Corporation and Constellation Energy Corporation
 File No. 001-16169, Form 8K dated February 2, 2022, Exhibit 10.1

 10-2

 Tax Matters Agreement, dated January 31, 2022, between Exelon Corporation and Constellation Energy Corporation
 File No. 001-16169, Form 8K dated February 2, 2022, Exhibit 10.2

 10-3

 Employee Matters Agreement, dated January 31, 2022, between Exelon Corporation and Constellation Energy Corporation
 File No. 001-16169, Form 8K dated February 2, 2022, Exhibit 10.3

 10-4

 Amended and Restated Credit Agreement for $900,000,000 dated August 29, 2024, between Exelon Corporation and various financial institutions
 File No. 001-16169, Form 10-K dated October 30, 2024, Exhibit 10.1

 10-5

 Exelon Corporation Non-Employee Directors' Deferred Stock Unit Plan (As Amended and Restated Effective April 28, 2020)
 File No. 001-16169, Form 10-Q dated August 4, 2020, Exhibit 10.1

 10-6

 Form of Exelon Corporation Unfunded Deferred Compensation Plan for Directors (as amended and restated Effective March 12, 2012) *
 File No. 001-16169, Form 10-K dated February 13, 2015, Exhibit 10.3

 10-7

 Exelon Corporation Supplemental Management Retirement Plan (As Amended and Restated Effective January 1, 2009) *
 File No. 001-16169, Form 10-K dated February 6, 2009, Exhibit 10.19

 10-8

 Exelon Corporation Employee Stock Purchase Plan, as amended and restated effective September 25, 2019
 File No. 001-16169, Form 10-Q dated October 31, 2019, Exhibit 10.3

 10-9

 Exelon Corporation Employee Stock Purchase Plan for Unincorporated Subsidiaries, as amended and restated effective September 25, 2019
 File No. 001-16169, Form 10-Q dated October 31, 2019, Exhibit 10.4

 10-10

 Exelon Corporation 2020 Long-Term Incentive Plan (Effective April 28, 2020)
 File No. 001-16169, Proxy Statement dated March 18, 2020, Appendix A

 10-11

 Exelon Corporation 2020 Long-Term Incentive Plan Prospectus, dated May 27, 2020
 File No. 001-16169, Form 10-Q dated August 4, 2020, Exhibit 10.3

 10-12

 Form of Restricted Stock Unit Award Notice and Agreement under the Exelon Corporation 2020 Long-Term Incentive Plan
 File No. 001-16169, Form 10-Q dated August 4, 2020, Exhibit 10.4

 10-13

 Form of Performance Share Award Notice and Agreement under the Exelon Corporation 2020 Long-Term Incentive Plan
 File No. 001-16169, Form 10-Q dated August 4, 2020, Exhibit 10.5

 10-14

 Exelon Corporation Senior Management Severance Plan as Amended and Restated effective February 1, 2024
 File No. 001-16169, Form 10-K dated February 21, 2024, Exhibit 10.15.1

 10-15

 Form of Separation Agreement under Exelon Corporation Senior Management Severance Plan (As Amended and Restated Effective January 1, 2020)
 File No. 001-16169, Form 10-K dated February 11, 2020, Exhibit 10.21

 10-16

 Exelon Corporation Executive Death Benefits Plan dated as of January 1, 2003 *
 File No. 001-16169, Form 10-K dated February 13, 2007, Exhibit 10.52

 10-16-1

 First Amendment to Exelon Corporation Executive Death Benefits Plan, Effective January 1, 2006 *
 File No. 001-16169, Form 10-K dated February 13, 2007, Exhibit 10.53

 10-17

 Exelon Corporation Deferred Compensation Plan (As Amended and Restated Effective December 1, 2024)
 Filed herewith

 10-18

 Exelon Corporation Stock Deferral Plan (As Amended and Restated Effective September 25, 2019)
 File No. 001-16169, Form 10-Q dated October 31, 2019, Exhibit 10.5

 10-19

 2023 Amendment to Certain Plans of Exelon Corporation
 File No. 001-16169, Form 10-K dated February 24, 2021, Exhibit 10.22

 10-20

 Constellation Energy Group Benefits Restoration Plan (As Amended and Restated Effective January 1, 2025)
 Filed herewith

 10-21

 Deferred Prosecution Agreement, dated July 17, 2020, between Commonwealth Edison Company and the U.S. Department of Justice and the U.S. Attorney for the Northern District of Illinois
 File No. 001-01839, Form 8-K dated July 17, 2020, Exhibit 10.1

 10-22

 Amended and Restated Credit Agreement for $1,000,000,000 dated August 29, 2024, between Commonwealth Edison Company and various financial institutions
 File No. 001-01839, Form 10-K dated October 30, 2024, Exhibit 10.2

 10-23

 Amended and Restated Credit Agreement for $600,000,000 dated August 29, 2024, between Baltimore Gas and Electric Company and various financial institutions
 File No. 001-01910, Form 10-K dated October 30, 2024, Exhibit 10.4

 10-25

 PECO Energy Company Supplemental Pension Benefit Plan (As Amended and Restated Effective January 1, 2009)
 File No. 000-16844, Form 10-K dated February 6, 2009, Exhibit 10.20

 10-26

 Amended and Restated Credit Agreement for $600,000,000 dated August 29, 2024, between PECO Energy Company and various financial institutions
 File No. 000-16844, Form 10-K dated October 30, 2024, Exhibit 10.3

 Atlantic City Electric Company, Potomac Electric Power Company, Delmarva Power & Light Company

 10-27

 Bond Purchase Agreement, dated December 1, 2015, among Atlantic City Electric Company and the purchasers signatory thereto
 File No. 001-03559, Form 8-K dated December 2, 2015, Exhibit 1.1

 10-28

 Amended and Restated Credit Agreement for $900,000,000 dated August 29, 2024, between Potomac Electric Power Company, Delmarva Power & Light Company, Atlantic City Electric Company and various financial institutions
 File Nos. 001-010172, 001-01405, 001-03559, Form 10-K dated October 30, 2024, Exhibit 10.5

(14) Code of Ethics

 14-1

 Exelon Code of Conduct, as amended December 04, 2024
 Filed herewith.

 (19) Insider trading policies and procedures

 19-1

 Exelon Insider Trading Policy
 File No. 001-16169, Form 10-K dated February 21, 2024, Exhibit 19.1

 (97) Policy Relating to Recovery of Erroneously Awarded Compensation

 97-1

 Exelon Financial Restatement Compensation Recoupment Policy
 File No. 001-16169, Form 10-K dated February 21, 2024, Exhibit 97.1

 Subsidiaries

 21-1

 21-2

 21-3

 21-4

 21-5

 21-6

 21-7

 21-8

 Consent of Independent Registered Public Accountants

 23-1

 23-2

 23-3

 Power of Attorney (Exelon Corporation)

 24-1

 Anna Richo

 24-2

 Calvin G. Butler, Jr.

 24-3

 W. Paul Bowers

 24-4

 Marjorie Rodgers Cheshire

 24-5

 Matthew Rogers

 24-6

 Linda P. Jojo

 24-7

 Charisse R. Lillie

 24-8

 John F. Young

 24-9

 Bryan Segedi

 Power of Attorney (Commonwealth Edison Company)

 24-10

 24-11

 Elizabeth Buchanan

 24-12

 Stephen Bowman

 24-13

 Ricardo Estrada

 24-14

 Zaldwaynaka Scott

 24-15

 Smita Shah

 24-16

 Gil C. Quiniones

 Power of Attorney (PECO Energy Company)

 24-17

 Nicholas Bertram

 24-18

 24-19

 John S. Grady

 24-20

 David M. Velazquez

 24-21

 Sharmain Matlock-Turner

 24-22

 Michael Nutter

 24-23

 Michelle Hong

 24-24

 Roberto E. Perez

 Power of Attorney (Baltimore Gas and Electric Company)

 24-25

 24-26

 Carim V. Khouzami

 24-27

 Keith Lee

 24-28

 Rachel Garbow Monroe

 24-29

 Byron Marchant

 24-30

 Tim Regan

 24-31

 Amy Seto

 24-32

 Maria Harris Tildon

 Power of Attorney (Pepco Holdings LLC)

 24-33

 Antoine Allen

 24-34

 24-35

 24-36

 Debra P. DiLorenzo

 24-37

 Benjamin Wu

 24-38

 Linda W. Cropp

 24-39

 Rosie Allen-Herring

 Power of Attorney (Potomac Electric Power Company)

 24-40

 24-41

 24-42

 24-43

 Rodney Oddoye

 24-44

 Valencia McClure

 24-45

 Tamla Olivier

 24-46

 Anne C. Bancroft

 Power of Attorney (Delmarva Power & Light Company)

 24-47

 24-48

 Power of Attorney (Atlantic City Electric Company)

 24-49

 Certifications Pursuant to Rule 13a-14(a) and 15d-14(a) of the Securities and Exchange Act of 1934 as to the Annual Report on Form 10-K for the year ended December 31, 2024 filed by the following officers for the following registrants:

 31-1

 Filed by Calvin G. Butler, Jr. for Exelon Corporation

 31-2

 Filed by Jeanne M. Jones for Exelon Corporation

 31-3

 Filed by Gil C. Quiniones for Commonwealth Edison Company

 31-4

 Filed by Joshua S. Levin for Commonwealth Edison Company

 31-5

 Filed by David M. Velazquez for PECO Energy Company

 31-6

 Filed by Marissa E. Humphrey for PECO Energy Company

 31-7

 Filed by Carim V. Khouzami for Baltimore Gas and Electric Company

 31-8

 Filed by Michael J. Cloyd for Baltimore Gas and Electric Company

 31-9

 Filed by J. Tyler Anthony for Pepco Holdings LLC

 31-10

 Filed by David M. Vahos for Pepco Holdings LLC

 31-11

 Filed by J. Tyler Anthony for Potomac Electric Power Company

 31-12

 Filed by David M. Vahos for Potomac Electric Power Company

 31-13

 Filed by J. Tyler Anthony for Delmarva Power & Light Company

 31-14

 Filed by David M. Vahos for Delmarva Power & Light Company

 31-15

 Filed by J. Tyler Anthony for Atlantic City Electric Company

 31-16

 Filed by David M. Vahos for Atlantic City Electric Company

 Certifications Pursuant to Section 1350 of Chapter 63 of Title 18 United States Code as to the Annual Report on Form 10-K for the year ended December 31, 2024 filed by the following officers for the following registrants:

 32-1

 Filed by Calvin G. Butler, Jr. for Exelon Corporation

 32-2

 Filed by Jeanne M. Jones for Exelon Corporation

 32-3

 Filed by Gil C. Quiniones for Commonwealth Edison Company

 32-4

 Filed by Joshua S. Levin for Commonwealth Edison Company

 32-5

 Filed by David M. Velazquez for PECO Energy Company

 32-6

 Filed by Marissa E. Humphrey for PECO Energy Company

 32-7

 Filed by Carim V. Khouzami for Baltimore Gas and Electric Company

 32-8

 Filed by Michael J. Cloyd for Baltimore Gas and Electric Company

 32-9

 Filed by J. Tyler Anthony for Pepco Holdings LLC

 32-10

 Filed by David M. Vahos for Pepco Holdings LLC

 32-11

 Filed by J. Tyler Anthony for Potomac Electric Power Company

 32-12

 Filed by David M. Vahos for Potomac Electric Power Company

 32-13

 Filed by J. Tyler Anthony for Delmarva Power & Light Company

 32-14

 Filed by David M. Vahos for Delmarva Power & Light Company

 32-15

 Filed by J. Tyler Anthony for Atlantic City Electric Company

 32-16

 Filed by David M. Vahos for Atlantic City Electric Company

 101.INS

 101.SCH

 101.CAL

 101.DEF

 101.LAB

 101.PRE

 * Compensatory plan or arrangements in which directors or officers of the applicable registrant participate and which are not available to all employees.
 (a)These filings are not available electronically on the SEC website as they were filed in paper previous to the electronic system that is currently in place.

 ITEM 16.
 FORM 10-K SUMMARY

 None.

 Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of Chicago and State of Illinois on the 12th day of February, 2025.

 EXELON CORPORATION

 By:

 /s/ CALVIN G. BUTLER, JR.

 Name:

 Calvin G. Butler, Jr.

 Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed by the following persons on behalf of the Registrant and in the capacities indicated on the 12th day of February, 2025.

 Title

 /s/ CALVIN G. BUTLER, JR.

 Calvin G. Butler, Jr.

 /s/ JEANNE M. JONES

 Executive Vice President and Chief Financial Officer (Principal Financial Officer)

 Jeanne M. Jones

 /s/ ROBERT A. KLECZYNSKI

 Senior Vice President, Corporate Controller and Tax (Principal Accounting Officer)

 Robert A. Kleczynski

 This annual report has also been signed below by Colette D. Honorable, Attorney-in-Fact, on behalf of the following Directors on the date indicated:

 Anna Richo

 Charisse R. Lillie

 W. Paul Bowers
 John F. Young

 Marjorie Rodgers Cheshire
 Bryan Segedi

 Matthew Rogers

 Linda P. Jojo

 By:

 /s/ COLETTE D. HONORABLE

 Name:

 Colette D. Honorable

 Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of Chicago and State of Illinois on the 12th day of February, 2025.

 COMMONWEALTH EDISON COMPANY

 By:

 /s/ GIL C. QUINIONES

 Name:

 Gil C. Quiniones

 Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed by the following persons on behalf of the Registrant and in the capacities indicated on the 12th day of February, 2025.

 Title

 /s/ GIL C. QUINIONES

 Gil C. Quiniones

 /s/ JOSHUA S. LEVIN

 Senior Vice President, Chief Financial Officer and Treasurer (Principal Financial Officer)

 Joshua S. Levin

 /s/ CAROLINE FULGINITI

 Vice President and Assistant Controller, Exelon (Principal Accounting Officer, ComEd)

 Caroline Fulginiti

 This annual report has also been signed below by Gil C. Quiniones, Attorney-in-Fact, on behalf of the following Directors on the date indicated:

 Ricardo Estrada

 Elizabeth Buchanan
 Zaldwaynaka Scott

 Stephen Bowman
 Smita Shah

 By:

 /s/ GIL C. QUINIONES

 Name:

 Gil C. Quiniones

 Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of Chicago and State of Illinois on the 12th day of February, 2025.

 PECO ENERGY COMPANY

 By:

 /s/ DAVID M. VELAZQUEZ

 Name:

 David M. Velazquez

 Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed by the following persons on behalf of the Registrant and in the capacities indicated on the 12th day of February, 2025.

 Title

 /s/ DAVID M. VELAZQUEZ

 David M. Velazquez

 /s/ MARISSA E. HUMPHREY

 Senior Vice President, Chief Financial Officer and Treasurer (Principal Financial Officer)

 Marissa E. Humphrey

 /s/ MARIANA HUFFORD

 Mariana Hufford

 This annual report has also been signed below by David M. Velazquez, Attorney-in-Fact, on behalf of the following Directors on the date indicated:

 Nicholas Bertram

 Michael Nutter

 Michelle Hong

 John S. Grady
 Roberto E. Perez

 Sharmain Matlock-Turner

 By:

 /s/ DAVID M. VELAZQUEZ

 Name:

 David M. Velazquez

 Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of Chicago and State of Illinois on the 12th day of February, 2025.

 BALTIMORE GAS AND ELECTRIC COMPANY

 By:

 /s/ CARIM V. KHOUZAMI

 Name:

 Carim V. Khouzami

 Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed by the following persons on behalf of the Registrant and in the capacities indicated on the 12th day of February, 2025.

 Title

 /s/ CARIM V. KHOUZAMI

 Carim V. Khouzami

 /s/ MICHAEL J. CLOYD

 Senior Vice President, Chief Financial Officer and Treasurer (Principal Financial Officer)

 Michael J. Cloyd

 /s/ DAMON M. SCOLERI

 Damon M. Scoleri

 This annual report has also been signed below by Carim V. Khouzami, Attorney-in-Fact, on behalf of the following Directors on the date indicated:

 Tim Regan

 Keith Lee
 Amy Seto

 Rachel Garbow Monroe
 Maria Harris Tildon

 Byron Marchant

 By:

 /s/ CARIM V. KHOUZAMI

 Name:

 Carim V. Khouzami

 Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of Chicago and State of Illinois on the 12th day of February, 2025.

 PEPCO HOLDINGS LLC

 By:

 Name:

 Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed by the following persons on behalf of the Registrant and in the capacities indicated on the 12th day of February, 2025.

 Title

 /s/ DAVID M. VAHOS

 Senior Vice President, Chief Financial Officer and Treasurer (Principal Financial Officer) and Director

 /s/ JASON T. JONES

 Jason T. Jones

 This annual report has also been signed below by J. Tyler Anthony, Attorney-in-Fact, on behalf of the following Directors on the date indicated:

 Antoine Allen

 Benjamin Wu

 Linda W. Cropp

 Debra P. DiLorenzo
 Rosie Allen-Herring

 By:

 Name:

 Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of Chicago and State of Illinois on the 12th day of February, 2025.

 POTOMAC ELECTRIC POWER COMPANY

 By:

 Name:

 Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed by the following persons on behalf of the Registrant and in the capacities indicated on the 12th day of February, 2025.

 Title

 /s/ DAVID M. VAHOS

 Senior Vice President, Chief Financial Officer, Treasurer (Principal Financial Officer)

 /s/ JASON T. JONES

 Jason T. Jones

 This annual report has also been signed below by J. Tyler Anthony, Attorney-in-Fact, on behalf of the following Directors on the date indicated:

 Tamla Olivier

 Rodney Oddoye
 Anne C. Bancroft

 Valencia McClure

 By:

 Name:

 Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of Chicago and State of Illinois on the 12th day of February, 2025.

 DELMARVA POWER & LIGHT COMPANY

 By:

 Name:

 Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed by the following persons on behalf of the Registrant and in the capacities indicated on the 12th day of February, 2025.

 Title

 /s/ DAVID M. VAHOS

 Senior Vice President, Chief Financial Officer and Treasurer (Principal Financial Officer)

 /s/ JASON T. JONES

 Jason T. Jones

 This annual report has also been signed below by J. Tyler Anthony, Attorney-in-Fact, on behalf of the following Directors on the date indicated:

 By:

 Name:

 Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of Chicago and State of Illinois on the 12th day of February, 2025.

 ATLANTIC CITY ELECTRIC COMPANY

 By:

 Name:

 Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed by the following persons on behalf of the Registrant and in the capacities indicated on the 12th day of February, 2025.

 Title

 /s/ DAVID M. VAHOS

 Senior Vice President, Chief Financial Officer and Treasurer (Principal Financial Officer)

 /s/ JASON T. JONES

 Jason T. Jones