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, 2025

 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.

Exelon Corporation	Yes	☐	No	x
Commonwealth Edison Company	Yes	☐	No	x
PECO Energy Company	Yes	x	No	☐
Baltimore Gas and Electric Company	Yes	x	No	☐
Pepco Holdings LLC	Yes	☐	No	x
Potomac Electric Power Company	Yes	☐	No	x
Delmarva Power & Light Company	Yes	☐	No	x
Atlantic City Electric Company	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.

Exelon Corporation	Yes	☐	No	x
Commonwealth Edison Company	Yes	☐	No	x
PECO Energy Company	Yes	☐	No	x
Baltimore Gas and Electric Company	Yes	☐	No	x
Pepco Holdings LLC	Yes	☐	No	x
Potomac Electric Power Company	Yes	☐	No	x
Delmarva Power & Light Company	Yes	☐	No	x
Atlantic City Electric Company	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  ý    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  ý    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.

Exelon Corporation	Large Accelerated Filer	x	Accelerated Filer	☐	Non-accelerated Filer	☐	Smaller Reporting Company	☐	Emerging Growth Company	☐
Commonwealth Edison Company	Large Accelerated Filer	☐	Accelerated Filer	☐	Non-accelerated Filer	x	Smaller Reporting Company	☐	Emerging Growth Company	☐
PECO Energy Company	Large Accelerated Filer	☐	Accelerated Filer	☐	Non-accelerated Filer	x	Smaller Reporting Company	☐	Emerging Growth Company	☐
Baltimore Gas and Electric Company	Large Accelerated Filer	☐	Accelerated Filer	☐	Non-accelerated Filer	x	Smaller Reporting Company	☐	Emerging Growth Company	☐
Pepco Holdings LLC	Large Accelerated Filer	☐	Accelerated Filer	☐	Non-accelerated Filer	x	Smaller Reporting Company	☐	Emerging Growth Company	☐
Potomac Electric Power Company	Large Accelerated Filer	☐	Accelerated Filer	☐	Non-accelerated Filer	x	Smaller Reporting Company	☐	Emerging Growth Company	☐
Delmarva Power & Light Company	Large Accelerated Filer	☐	Accelerated Filer	☐	Non-accelerated Filer	x	Smaller Reporting Company	☐	Emerging Growth Company	☐
Atlantic City Electric Company	Large Accelerated Filer	☐	Accelerated Filer	☐	Non-accelerated Filer	x	Smaller Reporting Company	☐	Emerging Growth Company	☐

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. o

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). ☐

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, 2025 was as follows:

Exelon Corporation Common Stock, without par value	$43,835,664,870
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
Pepco Holdings LLC	Not applicable
Potomac Electric Power Company	None
Delmarva Power & Light Company	None
Atlantic City Electric Company	None

The number of shares outstanding of each registrant’s Common stock as of January 31, 2026 was as follows:

Exelon Corporation Common Stock, without par value	1,022,892,585
Commonwealth Edison Company Common Stock, $12.50 par value	127,021,422
PECO Energy Company Common Stock, without par value	170,478,507
Baltimore Gas and Electric Company Common Stock, without par value	1,000
Pepco Holdings LLC	Not applicable
Potomac Electric Power Company Common Stock, $0.01 par value	100
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 2026 Annual Meeting of Shareholders and the Commonwealth Edison Company 2026 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.

TABLE OF CONTENTS

		Page No.
GLOSSARY OF TERMS AND ABBREVIATIONS		1
FILING FORMAT		5
CAUTIONARY STATEMENTS REGARDING FORWARD-LOOKING INFORMATION		5
WHERE TO FIND MORE INFORMATION		6
PART I
ITEM 1.	BUSINESS	7
	General	7
	Utility Operations	8
	Exelon's Strategy and Outlook	11
	Employees	12
	Environmental Matters and Regulation	13
	Executive Officers of the Registrants	18
ITEM 1A.	RISK FACTORS	20
ITEM 1B.	UNRESOLVED STAFF COMMENTS	30
ITEM 1C.	CYBERSECURITY	30
ITEM 2.	PROPERTIES	32
ITEM 3.	LEGAL PROCEEDINGS	33
ITEM 4.	MINE SAFETY DISCLOSURES	33
PART II
ITEM 5.	MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS, AND ISSUER PURCHASES OF EQUITY SECURITIES	34
ITEM 6.	[RESERVED]	38
ITEM 7.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	39
	Exelon Corporation	39
	Executive Overview	39
	Financial Results of Operations	39
	Significant 2025 Transactions and Developments	41
	Other Key Business Drivers and Management Strategies	43
	Critical Accounting Policies and Estimates	45
	Results of Operations	53
	Commonwealth Edison Company	53
	PECO Energy Company	56
	Baltimore Gas and Electric Company	60
	Pepco Holdings LLC	63
	Potomac Electric Power Company	64
	Delmarva Power & Light Company	67
	Atlantic City Electric Company	71
	Liquidity and Capital Resources	73
ITEM 7A.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	89
ITEM 8.	FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA	92
	Exelon Corporation
	Consolidated Statements of Operations and Comprehensive Income	116

	Page No.
Consolidated Statements of Cash Flows	117
Consolidated Balance Sheets	118
Consolidated Statements of Changes in Shareholders' Equity	120
Commonwealth Edison Company
Consolidated Statements of Operations and Comprehensive Income	121
Consolidated Statements of Cash Flows	122
Consolidated Balance Sheets	123
Consolidated Statements of Changes in Shareholders' Equity	125
PECO Energy Company
Consolidated Statements of Operations and Comprehensive Income	126
Consolidated Statements of Cash Flows	127
Consolidated Balance Sheets	128
Consolidated Statements of Changes in Shareholder's Equity	130
Baltimore Gas and Electric Company
Statements of Operations and Comprehensive Income	131
Statements of Cash Flows	132
Balance Sheets	133
Statements of Changes in Shareholder's Equity	135
Pepco Holdings LLC
Consolidated Statements of Operations and Comprehensive Income	136
Consolidated Statements of Cash Flows	137
Consolidated Balance Sheets	138
Consolidated Statements of Changes in Member's Equity	140
Potomac Electric Power Company
Statements of Operations and Comprehensive Income	141
Statements of Cash Flows	142
Balance Sheets	143
Statements of Changes in Shareholder's Equity	145
Delmarva Power & Light Company
Statements of Operations and Comprehensive Income	146
Statements of Cash Flows	147
Balance Sheets	148
Statements of Changes in Shareholder's Equity	150
Atlantic City Electric Company
Consolidated Statements of Operations and Comprehensive Income	151
Consolidated Statements of Cash Flows	152
Consolidated Balance Sheets	153
Consolidated Statements of Changes in Shareholder's Equity	155
Combined Notes to Consolidated Financial Statements
1. Significant Accounting Policies	156

		Page No.
	2. Regulatory Matters	164
	3. Revenue from Contracts with Customers	184
	4. Segment Information	186
	5. Accounts Receivable	193
	6. Property, Plant, and Equipment	195
	7. Jointly Owned Electric Utility Plant	197
	8. Asset Retirement Obligations	198
	9. Leases	198
	10. Intangible Assets	203
	11. Income Taxes	205
	12. Retirement Benefits	215
	13. Derivative Financial Instruments	227
	14. Debt and Credit Agreements	230
	15. Fair Value of Financial Assets and Liabilities	237
	16. Commitments and Contingencies	244
	17. Shareholders' Equity	253
	18. Stock-Based Compensation Plans	255
	19. Changes in Accumulated Other Comprehensive Income (Loss)	257
	20. Supplemental Financial Information	258
	21. Related Party Transactions	263
ITEM 9.	CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE	265
ITEM 9A.	CONTROLS AND PROCEDURES	265
ITEM 9B.	OTHER INFORMATION	265
ITEM 9C.	DISCLOSURE REGARDING FOREIGN JURISDICTIONS THAT PREVENT INSPECTIONS	266
PART III
ITEM 10.	DIRECTORS, EXECUTIVE OFFICERS, AND CORPORATE GOVERNANCE	267
ITEM 11.	EXECUTIVE COMPENSATION	268
ITEM 12.	SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS	269
ITEM 13.	CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR INDEPENDENCE	270
ITEM 14.	PRINCIPAL ACCOUNTING FEES AND SERVICES	271
PART IV
ITEM 15.	EXHIBITS, FINANCIAL STATEMENT SCHEDULES	272
ITEM 16.	FORM 10-K SUMMARY	316
SIGNATURES		317
	Exelon Corporation	317
	Commonwealth Edison Company	318
	PECO Energy Company	319
	Baltimore Gas and Electric Company	320
	Pepco Holdings LLC	321
	Potomac Electric Power Company	322
	Delmarva Power & Light Company	323
	Atlantic City Electric Company	324

GLOSSARY OF TERMS AND ABBREVIATIONS
Exelon Corporation and Related Entities
Exelon	Exelon Corporation
ComEd	Commonwealth Edison Company
PECO	PECO Energy Company
BGE	Baltimore Gas and Electric Company
Pepco Holdings or PHI	Pepco Holdings LLC (formerly Pepco Holdings, Inc.)
Pepco	Potomac Electric Power Company
DPL	Delmarva Power & Light Company
ACE	Atlantic City Electric Company
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
PHISCO	PHI Service Company
UII	Unicom Investments, Inc.
Former Related Entities
Constellation	Constellation Energy Corporation and 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)

1

GLOSSARY OF TERMS AND ABBREVIATIONS
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
Convertible Senior Notes	Exelon's 3.25% Convertible Senior Notes due 2029
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
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
IIJA	Infrastructure Investment and Jobs Act

2

GLOSSARY OF TERMS AND ABBREVIATIONS
Other Terms and Abbreviations
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
RFP	Request for Proposal

3

GLOSSARY OF TERMS AND ABBREVIATIONS
Other Terms and Abbreviations
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

4

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;

•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;

•disruptions or cost increases in the supply chain, including shortages in labor, materials or parts, or significant increases in relevant tariffs;

•lack of sufficient power generation resources to meet actual or forecasted demand or disruptions at 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.

5

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 16, 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.

6

PART I

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

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.

7

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, 2025:

	ComEd	PECO	BGE	Pepco	DPL	ACE
Service Territories (in square miles)
Electric	11,450	1,900	2,550	650	5,400	2,700
Natural Gas	N/A	1,900	3,050	N/A	250	N/A
Total(a)	11,450	2,100	3,250	650	5,400	2,700
Service Territory Population (in millions)
Electric	9.5	4.2	3.0	2.5	1.5	1.2
Natural Gas	N/A	2.6	2.9	N/A	0.6	N/A
Total(b)	9.5	4.2	3.2	2.5	1.5	1.2
Main City	Chicago	Philadelphia	Baltimore	District of Columbia	Wilmington	Atlantic City
Main City Population	2.7	1.6	0.6	0.7	0.1	0.1
Number of Customers (in millions)
Electric	4.2	1.7	1.4	1	0.6	0.6
Natural Gas	N/A	0.6	0.7	N/A	0.1	N/A
Total(c)	4.2	1.7	1.4	1	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 Maryland'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 effect 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.

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

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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 eliminates 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 in accordance with a multi-year rate plan approved by the ICC and through annual reconciliation proceedings litigated before 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 October 2025, Pepco Maryland filed a fully forecasted test year rate case while it awaits the conclusion of the lessons learned process. In certain instances, the Utility Registrants use specific recovery mechanisms as approved by their respective regulatory agencies. See Note 2 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.

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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 2 — 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, 258,000 mmcf, and 44,000 mmcf, respectively, for delivery of gas. To supplement gas transportation and supply at times of heavy winter demands and in the event of temporary emergencies, PECO, BGE, and DPL have available storage capacity from the following sources:

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

___________

(a)Natural gas from underground storage represents approximately 27%, 44%, and 33% of PECO's, BGE’s, and DPL's 2025-2026 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.

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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 as a result of the EmPOWER Maryland Cost Recovery program Beginning January 1, 2026, program costs are no longer being deferred. See Note 2 — 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 2026 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 affordability, reliability, resiliency, security and safety to enhance the service experience of our customers. The Utility Registrants make these investments prudently at a reasonable cost to customers. Exelon seeks to

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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 $41 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 including data centers, and transmission projects, which is projected to result in an increase to current rate base of approximately $23 billion by the end of 2029. 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

Human Capital Management

Exelon’s workforce is critical to advancing energy transformation and achieving sustainable, long‑term growth. As the Company competes for critical capabilities in the marketplace, Exelon must attract, develop, and equip its workforce to meet evolving business and industry needs. Accordingly, Exelon’s human capital management strategy is centered on maintaining and enhancing its reputation as an employer of choice within the energy and utility industry.

Exelon seeks to attract and retain talent by fostering a safe, inclusive, and engaging workplace that offers meaningful work, clearly defined roles, opportunities for professional development, supportive leadership, work‑life balance, and competitive benefits that support employee well‑being across all stages of life.

Exelon’s talent strategy supports the attraction, development, engagement, and advancement of employees across all businesses and functions. The Company deploys a comprehensive recruiting approach to address current and future workforce needs, including workforce development initiatives, annual internship and cooperative education programs, targeted recruiting for specialized and hard‑to‑fill roles, and partnerships with colleges, universities, trade schools, and community organizations.

Exelon invests in employee development through leadership development programs, technical training, and mentoring. Talent growth and internal mobility are supported through performance development, talent review, and succession planning processes. Employees are encouraged to complete annual individual development plans to identify skill‑building opportunities, supported by managers and Exelon’s development offerings.

Exelon’s total rewards programs support its talent strategy by attracting, retaining, and motivating high‑performing employees while reinforcing the Company’s pay‑for‑performance philosophy and supporting employee well‑being. Compensation is designed to be market‑competitive and is informed by benchmarking many positions using external survey data. All employees participate in an annual incentive program that aligns individual performance with business results and supports a high‑performance culture.

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Exelon promotes transparency in compensation and performance‑based rewards by providing education, tools, and resources that help leaders and employees understand the Company’s market‑based pay approach and the connection between performance, ratings, and compensation outcomes.

In addition, Exelon offers a comprehensive portfolio of benefit programs that support employees’ emotional, physical, and financial well‑being, enabling employees to perform effectively and supporting overall organizational effectiveness.

The following table shows the total number of employees at each Registrant as of December 31, 2025.

Employees	Exelon(a)	ComEd	PECO	BGE	PHI(b)	Pepco	DPL	ACE
Total Employees	20,571	6,688	3,169	3,383	4,422	1,374	945	630

 __________

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

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

Approximately 42% of Exelon’s employees participate in CBAs. The following table presents employee information, including information about CBAs, as of December 31, 2025.

	Total Employees Covered by CBAs	Number of CBAs	CBAs New and Renewed in 2025(a)	Total Employees Under CBAs New and Renewed in 2025
Exelon	8,656	10	2	941
ComEd	3,543	2	1	73
PECO	1,524	2	—	—
BGE	1,495	1	—	—
PHI	2,094	5	1	868
Pepco	861	1	1	861
DPL	650	2	—	—
ACE	397	2	—	—
Corporate(b)	186	—	—	7

 __________

(a)Does not include CBAs that were extended in 2025 while negotiations are ongoing for renewal.

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

The table below shows the average turnover rate for all employees for 2023 to 2025.

Employees	Exelon		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Retirement Age	2.39	%	2.72	%	2.54	%	2.06	%	2.17	%	2.00	%	2.40	%	2.10	%
Voluntary	2.58	%	2.40	%	2.06	%	1.82	%	2.78	%	2.82	%	1.29	%	2.58	%
Non-Voluntary	0.96	%	0.83	%	1.34	%	1.00	%	1.04	%	1.78	%	0.68	%	0.65	%

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

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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 continues to support the EPA's authority to regulate 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 2024, new methods were introduced that resulted in changes to Exelon's verified GHG inventory. Exelon's final verified 2024 Scope 1 and 2 GHG emissions were just over 4.6 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 PECO, BGE, and DPL. The remaining 4.2 million metric tons, approximately 91%, 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

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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 2026 to 2029 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 achieved their goal to electrify 30% of their vehicle fleet by 2025. Clean fuels and other emerging technologies can also support the transition, lessen the strain on electric system expansion, and support energy system resiliency. Exelon, 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. In January 2025, the current administration issued a Presidential Executive Order instructing the federal government to begin the actions needed to withdraw from the Paris Agreement. This withdrawal process will take a year to complete. The United States elected not to participate in the COP meeting (COP 30) in 2025.

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

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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 2 — 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 2 — 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 current administration has issued notice that the application of Waters of the United States will use a more narrow scope than has been applied historically.

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

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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 2026 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 $21 million, which consists primarily of $13 million at PECO.

As of December 31, 2025, 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 2 — Regulatory Matters and Note 16 — 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.

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Information about our Executive Officers as of February 12, 2026

Exelon

Name	Age	Position	Period
Butler Jr., Calvin G.	56	President and Chief Executive Officer, Exelon	2022 - Present
		Chief Operating Officer, Exelon	2021 - 2022
		Senior Executive Vice President, Exelon	2019 - 2022
		Chief Executive Officer, Exelon Utilities	2019 - 2022
Honorable, Colette	55	Executive Vice President, Chief Legal Officer, Compliance and Corporate Secretary, Exelon	2026 - Present
		Chief Legal Officer and Corporate Secretary	2024 - 2025
		Executive Vice President, Public Policy	2023 - 2024
		Chief External Affairs Officer	2023 - 2024
		Partner, Reed Smith LLP	2017 - 2023
Innocenzo, Michael A.	60	Executive Vice President and Chief Operating Officer, Exelon	2024 - Present
		President and Chief Executive Officer, PECO	2018 - 2024
Jones, Jeanne	46	Executive Vice President, Chief Finance Officer, Audit and Risk, Exelon	2026 - Present
		Executive Vice President and Chief Financial Officer, Exelon	2022 - 2025
		Senior Vice President, Corporate Finance, Exelon	2021 - 2022
		Senior Vice President and Chief Financial Officer, ComEd	2018 - 2021
Kleczynski, Robert A.	57	Senior Vice President, Controller and Tax, Exelon	2023 - Present
		Senior Vice President, Tax, Exelon	2020 - 2023
Peterson, Timothy	49	Executive Vice President, Chief Customer & Technology Officer, Exelon	2026 - Present
		Senior Vice President, Chief Technology Officer, Xcel Energy	2019-2026

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ComEd

Name	Age	Position	Period
Quiniones, Gil	59	President, ComEd	2024 - Present
		Chief Executive Officer, ComEd	2021 - Present
		President and Chief Executive Officer, New York Power Authority	2011 - 2021
Levin, Joshua	46	Senior Vice President, Chief Financial Officer & Treasurer, ComEd	2023 - Present
		Vice President, Corporate Finance, Planning and Analysis	2021 - 2023
		Director of Financial Planning and Analysis, ComEd	2019-2021
Perez, David R.	56	Executive Vice President and Chief Operating Officer, ComEd	2024 - Present
		Senior Vice President, Distribution Operations, ComEd	2019 - 2023
Rippie, E. Glenn	65	Senior Vice President and General Counsel, ComEd	2022 - Present
		Senior Vice President and Deputy General Counsel, Energy Regulation, Exelon	2022 - Present
		Partner, Jenner & Block LLP	2019 - 2022
Washington, Melissa	56	Senior Vice President, Governmental, Regulatory and External Affairs, ComEd	2025 - Present
		Senior Vice President, Customer Operations, ComEd	2021 - 2025
		Senior Vice President, Governmental and External Affairs, ComEd	2019 - 2021

PECO

Name	Age	Position	Period
Vahos, David	53	President and Chief Executive Officer, PECO	2025 - Present
		Senior Vice President, Chief Financial Officer, and Treasurer, PHI	2024 - 2025
		Senior Vice President, Chief Financial Officer, and Treasurer, BGE	2016 - 2024
Gay, Anthony	60	Vice President and General Counsel, PECO	2019 - Present
Humphrey, Marissa	46	Senior Vice President, Chief Financial Officer and Treasurer, PECO	2022 - Present
		Vice President, Regulatory Policy and Strategy (NJ/DE), PHI, DPL, and ACE	2021 - 2022
Levine, Nicole	49	Senior Vice President and Chief Operations Officer, PECO	2022 - Present
		Vice President, Electrical Operations, PECO	2018 - 2022
Oliver, Douglas	51	Senior Vice President, Governmental, Regulatory and External Affairs, PECO	2023 - Present
		Vice President, Governmental and External Affairs, PECO	2019 - 2023

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BGE

Name	Age	Position	Period
Olivier, Tamla	53	President and Chief Executive Officer, BGE	2025 - Present
		Senior Vice President and Chief Operating Officer, PHI, Pepco, DPL, and ACE	2021 - 2025
		Senior Vice President, Customer Operations, BGE	2020 - 2021
Cloyd, Michael	55	Senior Vice President, Chief Financial Officer, and Treasurer, BGE	2024 - Present
		Vice President, Support Services, BGE	2021 - 2024
Dickens, Derrick	61	Senior Vice President and Chief Operating Officer, BGE	2021 - Present
		Senior Vice President, Customer Operations, PHI, Pepco, DPL, and ACE	2020 - 2021
Ralph, David	59	Vice President and General Counsel, BGE	2021 - Present
		Associate General Counsel, BGE	2019 - 2021

PHI, Pepco, DPL, and ACE

Name	Age	Position	Period
Anthony, J. Tyler	61	President and Chief Executive Officer, PHI, Pepco, DPL, and ACE	2021 - Present
		Senior Vice President and Chief Operating Officer, PHI, Pepco, DPL, and ACE	2016 - 2021
Bancroft, Anne	59	Vice President and General Counsel, PHI, Pepco, DPL, and ACE	2021 - Present
		Associate General Counsel, Exelon	2017 - 2021
Oddoye, Rodney	49	Senior Vice President and Chief Operating Officer	2025 - Present
		Senior Vice President, Governmental, Regulatory and External Affairs, PHI, Pepco, DPL, and ACE	2021 - 2025
Cantler, Jaclyn	46	Senior Vice President, Governmental, Regulatory and External Affairs, PHI, DPL, and ACE	2025 - Present
		Vice President, Pepco Electric Operations, PHI, Pepco	2024 - 2025
		Vice President, Projects and Contracts, PHI, Pepco, DPL, and ACE	2021 - 2024
O'Donnell, Morgan	50	Senior Vice President, Chief Financial Officer, and Treasurer, PHI, Pepco, DPL, and ACE	2025 - Present
		Vice President, Regulatory Policy and Strategy, PHI, Pepco and DPL	2021 - 2025

ITEM 1A. RISK FACTORS

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

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Risks Related to Legislative, Regulatory, and Legal Factors

The Registrants' businesses are highly regulated and electric and gas revenue and earnings could be negatively affected by legislative and/or regulatory actions (All Registrants).

Substantial aspects of the Registrants' businesses are subject to comprehensive Federal or state legislation and/or regulation.

The Utility Registrants' consolidated financial statements are heavily dependent on the ability of the Utility Registrants to recover their costs associated with the retail purchase, transmission, and distribution of power and natural gas to their customers.

Fundamental changes in laws or regulations or adverse legislative or regulatory actions affecting the Registrants’ businesses would require changes in their business planning models and operations. Registrants cannot always predict when or whether legislative or regulatory action will occur and may not be able to influence the outcome of legislative or regulatory initiatives.

Changes in the Utility Registrants' respective terms and conditions of service, including their respective rates, along with adoption of new rate structures and constructs, or establishment of new rate cases, are subject to regulatory approval proceedings and/or negotiated settlements that are at times contentious, lengthy, and subject to appeal, which leads to uncertainty as to the ultimate result, and which could result in uncertainties in rate case outcomes, and/or introduce time delays in effectuating rate changes (All Registrants).

The Utility Registrants are required to engage in regulatory approval proceedings as a part of the process of establishing the terms and rates for their respective services, adoption of new rate structures and constructs or establishment of new rate cases. These proceedings typically involve multiple parties, including governmental bodies and officials, consumer advocacy groups, and various consumers of energy, who have differing concerns but who have the common objective of limiting rate increases or even reducing rates. Decisions are subject to appeal, potentially leading to additional uncertainty associated with the approval proceedings. The potential duration of such proceedings creates a risk that rates ultimately approved by the applicable regulatory body may not be sufficient for a Utility Registrant to recover its costs once the rates become effective. Established rates are also subject to subsequent prudency reviews by state regulators, whereby various portions of rates including recovery mechanisms for costs associated with the procurement of electricity or gas, credit losses, MGP remediation, smart grid infrastructure, and energy efficiency and demand response programs, could be adjusted, subject to refund, or disallowed. In certain instances, the Utility Registrants could agree to negotiated settlements related to various rate matters, customer initiatives, or franchise agreements. These settlements are subject to regulatory approval. The ultimate outcome and timing of regulatory rate proceedings have a significant effect on the ability of the Utility Registrants to recover their costs or earn an adequate return.

In addition to potential timing delays, the Registrants also face other uncertainties in rate proceedings that could impact recovery, including not obtaining anticipated allowed rates of return, allowed capital structures, or allowed return on pension assets, and various other factors.

See Note 2 — Regulatory Matters of the Combined Notes to the Consolidated Financial Statements for additional information.

The Registrants could be subject to higher costs and/or penalties related to mandatory reliability standards, including the likely exposure of the Utility Registrants to the results of NERC compliance requirements (All Registrants).

The Utility Registrants as users, owners, and operators of the bulk power transmission system are subject to mandatory reliability standards promulgated by NERC and enforced by FERC. The standards are based on the functions that need to be performed to ensure the bulk power system operates reliably and are guided by reliability and market interface principles. Compliance with or changes in the reliability standards could subject the Registrants to higher operating costs and/or increased capital expenditures. In addition, the ICC, PAPUC, MDPSC, DCPSC, DEPSC, and NJBPU impose certain distribution reliability standards on the Utility Registrants. If the Utility Registrants were found in non-compliance with the Federal or state mandatory reliability standards,

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they could be subject to remediation costs as well as sanctions, which could include substantial monetary penalties.

The Registrants could incur substantial costs to fulfill their obligations related to environmental and other matters (All Registrants).

The Registrants are subject to extensive environmental regulation and legislation by local, state, and Federal authorities. These laws and regulations affect the way the Registrants conduct their operations and make capital expenditures, including how they handle air and water emissions, hazardous and solid waste, and activities affecting surface waters, groundwater, and aquatic and other species. Violations of these requirements could subject the Registrants to enforcement actions, capital expenditures to bring existing facilities into compliance, additional operating costs for remediation and clean-up costs, civil penalties and exposure to third parties’ claims for alleged health or property damages, or operating restrictions to achieve compliance. In addition, the Registrants are subject to liability under these laws for the remediation costs for environmental contamination of property now or formerly owned by the Registrants and of property contaminated by hazardous substances they generated or released. Remediation activities associated with MGP operations conducted by predecessor companies are one component of such costs. Also, the Registrants are currently involved in several proceedings relating to sites where hazardous substances have been deposited and could be subject to additional proceedings in the future. See ITEM 1. BUSINESS — Environmental Matters and Regulation for additional information.

The Registrants could be negatively affected by federal and state RPS, energy conservation and GHG reduction legislation and regulation, and/or changing customer expectations, along with energy conservation by customers (All Registrants).

Risks include changes to energy systems due to new technologies, changing customer expectations and/or voluntary GHG goals, as well as local, state, or federal regulatory requirements intended to reduce GHG emissions and/or mandate implementation of energy conservation programs, including through limitation of the use of natural gas. Changes to current state legislation or the development of Federal legislation that requires the use of low-emission, renewable, and/or alternate fuel sources could significantly impact the Utility Registrants, especially if timely cost recovery is not allowed. In addition, where requirements and compliance mechanisms have previously been established, the withdrawal of such requirements can introduce costs and uncertainty.

Federal and state legislation mandating the implementation of energy conservation programs that require the implementation of new technologies, such as smart grid, DERs and energy efficiency programs, could increase capital expenditures and could significantly impact the Utility Registrants' consolidated financial statements if timely cost recovery is not allowed. These energy conservation programs, regulated energy consumption reduction targets, and new energy consumption technologies for PECO, could cause declines in customer energy consumption and lead to a decline in the Registrants' earnings, if timely recovery is not allowed.

The Registrants also periodically perform analyses of potential energy system transition pathways to reduce economy-wide GHG emissions to mitigate climate change. To the extent additional GHG reduction legislation and/or regulation becomes effective at the Federal and/or state levels, the Registrants could incur costs to further limit the GHG emissions from their operations or otherwise comply with applicable requirements and such legislation and/or regulation could otherwise adversely affect the Registrants' businesses. See ITEM 1. BUSINESS — Environmental Matters and Regulation — Renewable and Clean Energy Standards and "The Registrants are potentially affected by emerging technologies that could over time affect or transform the energy industry" above for additional information.

The Registrants could be negatively affected by challenges to tax positions taken, tax law changes, and the inherent difficulty in quantifying potential tax effects of business decisions. (All Registrants).

The Registrants are required to make judgments to estimate their obligations to taxing authorities, which includes general tax positions taken and associated reserves established. Tax obligations include, but are not limited to: income, real estate, sales and use, and employment-related taxes and ongoing appeal issues related to these tax matters. All tax estimates could be subject to challenge by the tax authorities. Additionally, earnings may be impacted due to changes in federal or local/state tax laws, and the inherent difficulty of estimating potential tax

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effects of ongoing business decisions. See Note 1 — Significant Accounting Policies and Note 11 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information.

Legal proceedings could result in a negative outcome, which the Registrants cannot predict (All Registrants).

The Registrants are involved in legal proceedings, claims, and litigation arising out of their business operations. The material legal proceedings, claims, and litigation arising out of business operations are summarized in Note 16 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements. Adverse outcomes in these proceedings could require significant expenditures, result in lost revenue, or restrict or disrupt business activities.

The Registrants could be subject to adverse publicity and reputational risks, which make them vulnerable to negative customer perception and could lead to increased regulatory oversight or other consequences (All Registrants).

The Registrants could be the subject of public criticism. Adverse publicity could render public service commissions and other regulatory and legislative authorities less likely to view energy companies generally, or the Registrants specifically, in a favorable light, and could cause the Registrants to be susceptible to less favorable legislative and regulatory outcomes, as well as increased regulatory oversight and more stringent legislative or regulatory requirements.

Risks Related to Operational Factors

The Utility Registrants' operating costs are affected by their ability to maintain the availability and reliability of their delivery and operational systems (All Registrants).

Failures of the equipment or facilities used in the Utility Registrants' delivery systems could interrupt electric transmission and/or electric or natural gas delivery, which could result in a loss of revenues and an increase in maintenance and capital expenditures. Equipment or facilities failures can occur due to several factors, including natural causes such as weather or information systems failure. Specifically, if the implementation of AMI, smart grid, or other technologies in the Utility Registrants' service territory fail to perform as intended or are not successfully integrated with billing and other information systems, or if any of the financial, accounting, or other data processing systems fail or have other significant shortcomings, the Utility Registrants' financial results could be negatively impacted. In addition, dependence upon automated systems could further increase the risk that operational system flaws or internal and/or external tampering or manipulation of those systems will result in losses that are difficult to detect.

Regulated utilities, which are required to provide service to all customers within their respective service territories, have generally been afforded liability protections against claims by customers relating to failure of service. Under Illinois law, however, ComEd could be required to pay damages to its customers in some circumstances involving extended outages affecting large numbers of its customers, which could be material.

The Registrants are subject to physical security and cybersecurity risks (All Registrants).

Risks from cybersecurity and physical threats to energy infrastructures and personnel are increasing. Threat actors, including sophisticated nation-state actors and criminal groups, exploit potential vulnerabilities in the electric and natural gas utility industry, grid infrastructure, and other energy infrastructures. Attacks and disruptions, which could involve physical, cyber, and hybrid targeting of physical and cyber assets, are increasingly sophisticated and dynamic. Physical attacks targeting the Registrants' physical assets or personnel could cause injuries, damage, or operational disruptions. The increased implementation of, and reliance on, information technologies and networks to manage business operations, including the operation of technical systems, as well as the Registrants' use of numerous vendors and suppliers, create additional points of vulnerability that could be, and in certain instances have been, exploited by malicious threat actors. Several U.S. government agencies have warned that the energy sector and its supply chains are subject to increasing risks of physical attacks, ransomware attacks and cybersecurity threats, and that the risks may escalate during periods of heightened geopolitical tensions. In addition, the rapid evolution and increased adoption of artificial intelligence technologies may intensify the Registrants' cybersecurity risks.

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A security breach of the Registrants' physical assets or information systems or those of the Registrants' competitors, vendors, business partners and interconnected entities (including RTOs and ISOs) could materially impact Registrants by, among other things, impairing the availability of electricity and gas distributed by Registrants and/or the reliability of transmission and distribution systems, damaging grid infrastructure, interrupting critical business functions, impairing the availability of vendor services and materials that the Registrants rely on to maintain their operations, or by leading to the theft or inappropriate release of certain types of information, including critical infrastructure information, system data and architecture, sensitive customer, vendor, or employee data, or other confidential data. While Registrants and some of the Registrants' vendors have experienced cybersecurity incidents, such incidents have not, to Registrants' knowledge, resulted in material impact to any of the Registrants to date.

If a material physical or cybersecurity breach or disruption were to occur, the Registrants' reputation could be negatively affected, customer confidence in the Registrants could be diminished and the Registrants could be subject to legal claims, regulatory exposure, loss of revenues, and increased costs, including infrastructure repairs or operations shutdown, all of which could materially affect the Registrants' financial condition and materially damage their business reputation. Moreover, the amount and scope of insurance maintained against losses resulting from any such security breaches or disruptions may not be sufficient to cover losses or otherwise adequately compensate for any resulting business disruptions. The continued increase in Federal and state regulatory requirements related to cybersecurity and evolving threat actor-capabilities could require changes to measures currently undertaken by the Registrants or to their business operations and could adversely affect their consolidated financial statements.

The Registrants’ electricity and natural gas operations are inherently hazardous and involve significant risks to employees, contractors, customers, and the general public (All Registrants).

Employees and contractors throughout the organization work in, and customers and the general public could be exposed to, potentially dangerous environments near the Registrants’ operations. As a result, employees, contractors, customers, and the general public may face, and in the past have experienced, serious injury, including loss of life, damage to or destruction of facilities and residences, business interruptions, and environmental pollution. These risks include, among others, gas explosions, uncontrolled release of natural gas and other environmental hazards, fires, pole strikes, and electric contact cases. Further, the location of natural gas pipelines and associated distribution facilities, or electric generation, transmission, substations and distribution facilities near populated areas, including residential areas, commercial business centers and industrial sites, increases the potential damages resulting from these risks.

Extreme weather events, natural disasters, operational accidents such as wildfires or natural gas explosions, war, acts and threats of terrorism or sabotage, cyberattacks or compromises, equipment or process failures, public health crises, or other significant events could negatively impact the Registrants' results of operations, ability to raise capital and future growth (All Registrants).

The Utility Registrants' infrastructures and/or operations could be affected by extreme weather events, natural disasters, operational accidents such as wildfires or natural gas explosions or equipment or process failures due to aging infrastructure or otherwise, each of which could result in increased costs, including supply chain costs and claims for third-party property damage. An extreme weather event, natural disaster, wildfire, or operational accident within the Utility Registrants’ service areas can also directly affect their capital assets, causing disruption in service to customers due to downed wires and poles or damage to other operating equipment.

The Registrants face a risk that their operations would be direct targets or indirect casualties of attacks or sabotaged by nation-states or their agents, or by foreign or domestic terrorist groups. Responses to such attacks or sabotage, and any resulting retaliatory actions or sustained conflict could affect the Registrants’ operations and finances in unpredictable and material ways. Furthermore, such events could compromise the physical or cybersecurity of the Registrants' facilities, which could adversely affect the Registrants' ability to manage their businesses effectively. Instability in the financial markets as a result of terrorism, war, natural disasters, public health crises, epidemics, pandemics, credit crises, recession, sustained high inflation, or other significant events also could result in a decline in energy consumption or interruption of fuel or the supply chain. In addition, the

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implementation of security guidelines and measures has resulted in and is expected to continue to result in increased costs.

The Registrants could be significantly affected by public health crises, including epidemics or pandemics. The Registrants have plans in place to respond to such events. However, depending on the severity and the resulting impacts to workforce and other resource availability, a public health crisis, epidemic, or pandemic could adversely affect our vendors, or customers and customer demand as well as the Registrants’ ability to operate their transmission and distribution assets.

In addition, Exelon, on behalf of the Registrants, maintains a level of insurance coverage consistent with industry practices against property, casualty, third party liability, and cybersecurity losses subject to unforeseen occurrences or catastrophic events that could damage or destroy assets or interrupt operations. However, such losses may not be covered under applicable insurance policies, or the amount of insurance may be inadequate to cover all such losses.

The Registrants are subject to risks associated with climate change (All Registrants).

The Registrants periodically perform analyses to better understand long-term projections of climate change and how those changes in the physical environments where they operate could affect their facilities and operations. The Registrants primarily operate in the Midwest and Mid-Atlantic of the United States, areas that historically have been prone to various types of severe weather events, and the Registrants have well-developed response and recovery programs based on these historical events. However, the Registrants’ physical facilities could be at greater risk of damage as changes in the global climate affect temperature and weather patterns, including if such climate changes result in more intense, frequent and extreme weather events, elevated or decreased levels of precipitation, sea level rise, increased temperatures, wildfires and/or other effects.

In addition, changes to the climate may impact levels and patterns of demand for energy and related services, which could affect Registrants’ operations and business.

The Registrants’ businesses are capital intensive, and their assets could require significant expenditures to maintain, are subject to operational failure and could be impacted by disruptions or cost increases in the supply chain, including shortages in labor, materials or parts, or significant increases in relevant tariffs which could result in potential liability (All Registrants).

The Utility Registrants’ businesses are capital intensive and require significant investments in transmission and distribution infrastructure projects. Equipment, even if maintained in accordance with good utility practices, is subject to operational failure, including events that are beyond the Utility Registrants’ control, and could require significant expenditures to operate efficiently. Disruptions or cost increases in the supply chain, including shortages in labor, materials or parts, or significant increases in relevant tariffs, could materially impact the timing and execution of capital projects, and the timing of placing assets in service, as well as other aspects of the Registrants' businesses. In recent years, the energy industry has been experiencing shortages of, and long lead times for, critical equipment such as transformers and conductors. The Registrants' consolidated financial statements could be negatively affected if they were unable to effectively manage their capital projects or raise the necessary capital, or if they are deemed liable for operational failure. See ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS — Liquidity and Capital Resources for additional information regarding the Registrants’ potential future capital expenditures.

Lack of sufficient generation and energy storage to meet actual or forecasted demand or disruptions at power generation facilities owned by third parties could interrupt transmission and distribution services, impair economic development, cause outages, and result in use limitations or affordability implications for customers. (All Registrants)

Exelon does not generate the electricity it delivers. The Utility Registrants purchase, transmit, and distribute electric power obtained from power generation facilities owned by third parties. This power is primarily procured through contracts as directed by the Utility Registrants’ respective state laws and regulatory commission actions from various approved bidders or from purchases on the PJM operated markets. Third-party power generation may be insufficient to meet our customers’ electricity demand in the short- and medium-term because of extreme

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weather, fuel security, market procurement, regulatory requirements, operational issues, maintenance outages, inflexibility of demand, or financial uncertainty impacting existing or prospective generation facilities. Faster energy demand growth, acceleration of generator retirements, or the limited entry of new generating resources in any of the Utility Registrants’ respective service territories may result in a longer-term power generation capacity shortfall. Exelon has forecast substantial increases in load, driven largely by the increasing use of data processing facilities dedicated to cloud services, artificial intelligence technologies, and other applications. If third-party power generation capacity is insufficient to meet any Utility Registrant’s customers’ electricity demand or customers’ electricity demand across PJM over any period, transmission and distribution services may be diminished or interrupted, and results of operations, financial condition, and cash flows could be adversely affected.

In the event generation capacity is insufficient to meet demand, the Utility Registrants’ customers may experience greater price volatility, power service outages during peak demand periods or during generation contingencies (e.g., severe storms), and electricity use limits to maintain system balance. Furthermore, the Utility Registrants may be unable to support new economic development should generation constraints last for extended periods.

Energy storage systems provide additional resources for enhancing grid reliability and stability by providing rapid response capabilities, allowing the injection and absorption of power during electric supply and demand imbalances. As forecasted load increases, the lack of sufficient energy storage growth may also lead to greater price volatility and challenges in power services for customers.

The Utility Registrants' respective ability to deliver electricity, their operating costs, and their capital expenditures could be negatively impacted by the insufficiency of generation or energy storage resources to meet demand, transmission congestion, and failures of neighboring transmission systems (All Registrants).

Demand for electricity within the Utility Registrants' service areas could stress available transmission capacity requiring alternative routing or curtailment of electricity usage. Also, insufficient availability of electric supply to meet customer demand could jeopardize the Utility Registrants' ability to comply with reliability standards and strain customer and regulatory agency relationships. As is the case for electric utilities generally, potential concerns over transmission capacity or generation facility retirements could result in PJM or FERC requiring the Utility Registrants to upgrade or expand their respective transmission systems through additional capital expenditures. Delays in siting, permitting, and interconnection could defer the introduction of new generation or energy storage resources that could address resource adequacy concerns.

PJM’s systems and operations are designed to ensure the reliable operation of the transmission grid and prevent the operations of one utility from having an adverse impact on the operations of the other utilities. However, service interruptions at other utilities may cause interruptions in the Utility Registrants’ service areas. Additionally, efforts to artificially manipulate power demand on the grid, or even accidental activity that results in sharp fluctuations of demand, could disrupt grid operations.

The Registrants' performance could be negatively affected if they fail to attract and retain an appropriately qualified workforce (All Registrants).

Certain factors, such as employee strikes, work stoppages, loss of employees, loss of contract resources due to a major event, inability to negotiate future collective bargaining agreements on commercially reasonable terms, an aging workforce, mismatching of skill sets for current and future needs, and failing to appropriately anticipate future workforce needs, could lead to operating challenges and increased costs for the Registrants. Such challenges include lack of resources, loss of knowledge and a lengthy time period associated with skill development. Such events and other factors could result in increased costs, including costs of replacing lost labor through contractors or new hires, training costs, and costs of lost productivity. Such events also could increase operational risks. The Registrants are particularly affected due to the specialized knowledge required of the technical and support employees needed to conduct Registrants' transmission and distribution operations as well as areas where new technologies are pertinent.

The Registrants’ performance could be negatively affected by poor performance of third-party contractors that perform periodic or ongoing work (All Registrants).

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The Registrants rely on third-party contractors to perform operations, maintenance, and construction work. Performance standards typically are included in all contractual obligations, but poor performance may impact capital execution plans or operations, or have adverse financial, regulatory, or reputational consequences.

The Registrants could make acquisitions or investments in new business initiatives and new markets, which may not be successful or achieve the intended financial results (All Registrants).

The Utility Registrants face risks associated with regulator-mandated or other new business initiatives, such as smart grids and broader beneficial electrification. Such risks include, but are not limited to, cost recovery, regulatory concerns, cybersecurity, and obsolescence of technology. Such initiatives may not be successful, and failures could result in adverse financial or reputational consequences.

Risks Related to Market and Financial Factors

The Registrants are potentially affected by emerging technologies that could over time affect or transform the energy industry (All Registrants).

Advancements in power generation technology, including commercial and residential solar generation installations and commercial micro turbine installations, are improving the cost-effectiveness of customer self-supply of electricity. Improvements in energy storage technology, including batteries and fuel cells, could also better position customers to meet their around-the-clock electricity requirements. Improvements in energy efficiency of lighting, appliances, equipment and building materials will also affect energy consumption by customers. Changes in power generation, storage, and use technologies could have significant effects on customer behaviors and their energy consumption.

These developments could affect levels of customer-owned generation, customer expectations, and current business models and make portions of the Utility Registrants' transmission and/or distribution facilities uneconomic prior to the end of their useful lives. Increasing pressure from both the private and public sectors to take actions to mitigate climate change could also push the speed and nature of this transition. These factors could affect the Registrants’ consolidated financial statements through, among other things, increased Operating and maintenance expenses, increased capital expenditures, and potential asset impairment charges or accelerated depreciation over shortened remaining asset useful lives.

The Registrants could be negatively affected by unstable capital and credit markets (All Registrants).

The Registrants rely on the capital markets, particularly for publicly offered debt, as well as the banking and commercial paper markets, to meet their financial commitments and short-term liquidity needs. Disruptions in the capital and credit markets in the United States or abroad could negatively affect the Registrants’ ability to access the capital markets or draw on their respective bank revolving credit facilities. The banks may not be able to meet their funding commitments to the Registrants if they experience shortages of capital and liquidity or if they experience excessive volumes of borrowing requests within a short period of time. The inability to access capital markets or credit facilities, and longer-term disruptions in the capital and credit markets because of uncertainty, changing or increased regulation, reduced alternatives, or failures of significant financial institutions could result in the deferral of discretionary capital expenditures, or require a reduction in dividend payments or other discretionary uses of cash. In addition, the Registrants have exposure to worldwide financial markets, including Europe, Canada, and Asia. Disruptions in these markets could reduce or restrict the Registrants’ ability to secure sufficient liquidity or secure liquidity at reasonable terms. As of December 31, 2025, approximately 17%, 11%, and 17% of the Registrants’ available credit facilities were with European, Canadian, and Asian banks, respectively. Additionally, higher interest rates may put pressure on the Registrants’ overall liquidity profile, financial health and impact financial results. See Note 14 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information on the credit facilities.

If any of the Registrants were to experience a downgrade in its credit ratings to below investment grade or otherwise fail to satisfy the credit standards in its agreements with its counterparties or regulatory financial requirements, it would be required to provide significant

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amounts of collateral that could affect its liquidity and could experience higher borrowing costs (All Registrants).

The Utility Registrants' operating agreements with PJM and PECO's, BGE's, and DPL's natural gas procurement contracts contain collateral provisions that are affected by their credit rating and market prices. If certain wholesale market conditions were to exist and the Utility Registrants were to lose their investment grade credit ratings (based on their senior unsecured debt ratings), they would be required to provide collateral in the forms of letters of credit or cash, which could have a material adverse effect upon their remaining sources of liquidity. PJM collateral posting requirements will generally increase as market prices rise and decrease as market prices fall. Collateral posting requirements for PECO, BGE, and DPL, with respect to their natural gas supply contracts, will generally increase as forward market prices fall and decrease as forward market prices rise. If the Utility Registrants were downgraded, they could experience higher borrowing costs as a result of the downgrade. In addition, changes in ratings methodologies by the agencies could also have an adverse negative impact on the ratings of the Utility Registrants.

The Utility Registrants conduct their respective businesses and operate under governance models and other arrangements and procedures intended to assure that the Utility Registrants are treated as separate, independent companies, distinct from Exelon and other Exelon subsidiaries in order to isolate the Utility Registrants from Exelon and other Exelon subsidiaries in the event of financial difficulty at Exelon or another Exelon subsidiary. These measures (commonly referred to as “ring-fencing”) could help avoid or limit a downgrade in the credit ratings of the Utility Registrants in the event of a reduction in the credit rating of Exelon. Despite these ring-fencing measures, the credit ratings of the Utility Registrants could remain linked, to some degree, to the credit ratings of Exelon. Consequently, a reduction in the credit rating of Exelon could result in a reduction of the credit rating of some or all of the Utility Registrants. A reduction in the credit rating of a Utility Registrant could have a material adverse effect on the Utility Registrant.

See ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS — Liquidity and Capital Resources — Credit Matters and Cash Requirements — Security Ratings for additional information regarding the potential impacts of credit downgrades on the Registrants’ cash flows.

The impacts of significant economic downturns or increases in customer rates, could lead to decreased volumes delivered and increased expense for uncollectible customer balances (All Registrants).

The impacts of significant economic downturns on the Utility Registrants' customers and the related regulatory limitations on residential service terminations for the Utility Registrants, could result in an increase in the number of uncollectible customer balances and related expense. Further, increases in customer rates, including those related to increases in Purchased power and natural gas prices, could result in declines in customer usage and lower revenues for the Utility Registrants that do not have decoupling mechanisms.

See ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK for additional information on the Registrants’ credit risk.

The Registrants could be negatively affected by the impacts of weather (All Registrants).

Weather conditions directly influence the demand for electricity and natural gas and affect the price of energy commodities. Temperatures above normal levels in the summer tend to increase summer cooling electricity demand and revenues, and temperatures below normal levels in the winter tend to increase winter heating electricity and gas demand and revenues. Moderate temperatures adversely affect the usage of energy and resulting operating revenues at PECO and DPL Delaware. Due to revenue decoupling, operating revenues from electric distribution at ComEd, BGE, Pepco, DPL Maryland, and ACE and gas distribution at BGE are not intended to be affected by abnormal weather.

Extreme weather conditions or damage resulting from storms could stress the Utility Registrants' transmission and distribution systems, communication systems, and technology, resulting in increased maintenance and capital costs and limiting each Utility Registrant's ability to meet peak customer demand. First and third quarter financial results, in particular, are substantially dependent on weather conditions, and could make period comparisons less relevant.

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Climate change projections suggest increases to summer temperature and humidity trends, as well as more erratic precipitation and storm patterns over the long-term in the areas where the Utility Registrants have transmission and distribution assets. The frequency in which weather conditions emerge outside the current expected climate norms could contribute to weather-related impacts discussed above.

Long-lived assets, goodwill, and other assets could become impaired (All Registrants).

Long-lived assets represent the single largest asset class on the Registrants’ statements of financial position. In addition, Exelon, ComEd, and PHI have material goodwill balances.

The Registrants evaluate the recoverability of the carrying value of long-lived assets to be held and used whenever events or circumstances indicating a potential impairment exist. Factors such as, but not limited to, the business climate, including current and future energy and market conditions, environmental regulation, and the condition of assets are considered.

ComEd and PHI perform an assessment for possible impairment of their goodwill at least annually or more frequently if an event occurs or circumstances change that would more likely than not reduce the fair value of the reporting units below their carrying amount. Regulatory actions or changes in significant assumptions, including discount and growth rates, utility sector market performance and transactions, projected operating and capital cash flows for ComEd’s, Pepco’s, DPL’s, and ACE’s business, and the fair value of debt, could potentially result in future impairments of Exelon’s, ComEd's, and PHI’s goodwill.

An impairment would require the Registrants to reduce the carrying value of the long-lived asset or goodwill to fair value through a non-cash charge to expense by the amount of the impairment. See ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS — Critical Accounting Policies and Estimates, Note 6 — Property, Plant, and Equipment, Note N/A — Asset Impairments, and Note 10 — Intangible Assets of the Combined Notes to the Consolidated Financial Statements for additional information on long-lived asset impairments and goodwill impairments.

The Registrants could incur substantial costs in the event of non-performance by third-parties under indemnification agreements, or when the Registrants have guaranteed their performance (All Registrants).

The Registrants have entered into various agreements with counterparties that require those counterparties to reimburse a Registrant and hold it harmless against specified obligations and claims. To the extent that any of these counterparties are affected by deterioration in their creditworthiness or the agreements are otherwise determined to be unenforceable, the affected Registrant could be held responsible for the obligations. Each of the Utility Registrants has transferred its former generation assets to one or more third parties and in each case the transferee has agreed to assume certain obligations and to indemnify the applicable Utility Registrant for such obligations. In connection with the restructurings under which ComEd, PECO, and BGE transferred their generating assets to Constellation, Constellation assumed certain of ComEd’s, PECO’s, and BGE's rights and obligations with respect to their former generation assets. Further, ComEd, PECO, and BGE have entered into agreements with third parties under which the third-party agreed to indemnify ComEd, PECO, or BGE for certain obligations related to their respective former generation assets that have been assumed by Constellation as part of the restructuring. If Constellation or a transferee of one of the Utility Registrant’s generation assets experienced events that reduced its creditworthiness or the indemnity arrangement became unenforceable, the applicable Utility Registrant could be liable for any existing or future claims. In addition, the Utility Registrants have residual liability under certain laws in connection with their former generation assets.

The Registrants have issued indemnities to third parties regarding environmental or other matters in connection with purchases and sales of assets, including several of the Utility Registrants in connection with Constellation's absorption of their former generating assets. The Registrants could incur substantial costs to fulfill their obligations under these indemnities.

The Registrants have issued guarantees of the performance of third parties, which obligate the Registrants to perform if the third parties do not perform. In the event of non-performance by those third parties, the Registrants could incur substantial cost to fulfill their obligations under these guarantees.

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Market performance and other factors could decrease the value of employee benefit plan assets and could increase the related employee benefit plan obligations, which then could require significant additional funding (All Registrants).

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

ITEM 1B. UNRESOLVED STAFF COMMENTS

All Registrants

None.

ITEM 1C. CYBERSECURITY

Risk management and strategy

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

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

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

Governance

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

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

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

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

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ITEM 2. PROPERTIES

The Utility Registrants

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

Transmission and Distribution

The Utility Registrants’ high voltage electric transmission lines owned and in service as of December 31, 2025 were as follows:

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

___________

(a)In addition, PECO, DPL, and ACE have an ownership interest located in Delaware and New Jersey. See Note 7 — Jointly Owned Electric Utility Plant of the Combined Notes to the Consolidated Financial Statements for additional information.

The Utility Registrants' electric distribution system includes the following number of circuit miles of overhead and underground lines as of December 31, 2025:

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

Gas

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

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

___________

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

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

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

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

First Mortgage and Insurance

The principal properties of ComEd, PECO, Pepco, DPL, and ACE are subject to the lien of their respective mortgages under which their respective First Mortgage Bonds are issued. See Note 14 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information.

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

Exelon

Security Measures

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

ITEM 3. LEGAL PROCEEDINGS

All Registrants

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

ITEM 4. MINE SAFETY DISCLOSURES

Not Applicable

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PART II

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

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

Exelon

Exelon’s common stock is listed on the Nasdaq (trading symbol: EXC). As of January 31, 2026, there were 1,022,892,585 shares of Common stock outstanding and approximately 68,884 record holders of Common stock.

Stock Performance Graph

The performance graph below illustrates a five-year comparison of cumulative total returns based on an initial investment of $100 in Exelon Common stock, compared with the S&P 500 Stock Index and the S&P Utility Index, for the period 2021 through 2025. Cumulative total returns account for the separation of Constellation, as the spin-off dividend was assumed to have been reinvested upon receipt.

This performance chart assumes:

•$100 invested on December 31, 2020 in Exelon Common stock, the S&P 500 Stock Index, and the S&P Utility Index; and

•All dividends are reinvested.

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

ComEd

As of January 31, 2026, there were 127,021,422 outstanding shares of Common stock, $12.50 par value, of ComEd, of which 127,002,904 shares were indirectly held by Exelon. As of January 31, 2026, in addition to Exelon, there were 277 record holders of ComEd Common stock. There is no established market for shares of the Common stock of ComEd.

PECO

As of January 31, 2026, there were 170,478,507 outstanding shares of Common stock, without par value, of PECO, all of which were indirectly held by Exelon.

BGE

As of January 31, 2026, there were 1,000 outstanding shares of Common stock, without par value, of BGE, all of which were indirectly held by Exelon.

PHI

As of January 31, 2026, Exelon indirectly held the entire membership interest in PHI.

Pepco

As of January 31, 2026, there were 100 outstanding shares of Common stock, $0.01 par value, of Pepco, all of which were indirectly held by Exelon.

DPL

As of January 31, 2026, there were 1,000 outstanding shares of Common stock, $2.25 par value, of DPL, all of which were indirectly held by Exelon.

ACE

As of January 31, 2026, there were 8,546,017 outstanding shares of Common stock, $3.00 par value, of ACE, all of which were indirectly held by Exelon.

All Registrants

Dividends

Under applicable Federal law, ComEd, PECO, BGE, PHI, Pepco, DPL, and ACE can pay dividends only from retained, undistributed, or current earnings. A significant loss recorded at ComEd, PECO, BGE, PHI, Pepco, DPL, or ACE may limit the dividends that these Registrants can distribute to Exelon.

ComEd has agreed, in connection with a financing arranged through ComEd Financing III, that ComEd will not declare dividends on any shares of its capital stock in the event that: (1) it exercises its right to extend the interest payment periods on the subordinated debt securities issued to ComEd Financing III; (2) it defaults on its guarantee of the payment of distributions on the preferred trust securities of ComEd Financing III; or (3) an event of default occurs under the Indenture under which the subordinated debt securities are issued. No such event has occurred.

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PECO has agreed, in connection with financings arranged through PEC L.P. and PECO Trust IV, that PECO will not declare dividends on any shares of its capital stock in the event that: (1) it exercises its right to extend the interest payment periods on the subordinated debentures which were issued to PEC L.P. or PECO Trust IV; (2) it defaults on its guarantee of the payment of distributions on the Series D Preferred Securities of PEC L.P. or the preferred trust securities of PECO Trust IV; or (3) an event of default occurs under the Indenture under which the subordinated debentures are issued. No such event has occurred.

BGE is subject to restrictions established by the MDPSC that prohibit BGE from paying a dividend on its common shares if (a) after the dividend payment, BGE’s equity ratio would be below 48% as calculated pursuant to the MDPSC’s ratemaking precedents or (b) BGE’s senior unsecured credit rating is rated by two of the three major credit rating agencies below investment grade. No such event has occurred.

Pepco is subject to certain dividend restrictions established by settlements approved by the MDPSC and DCPSC that prohibit Pepco from paying a dividend on its common shares if (a) after the dividend payment, Pepco's equity ratio would be below 48% as calculated pursuant to the MDPSC's and DCPSC's ratemaking precedents, or (b) Pepco’s senior unsecured credit rating is rated by one of the three major credit rating agencies below investment grade. No such event has occurred.

DPL is subject to certain dividend restrictions established by settlements approved by the DEPSC and MDPSC that prohibit DPL from paying a dividend on its common shares if (a) after the dividend payment, DPL's equity ratio would be below 48% as calculated pursuant to the DEPSC's and MDPSC's ratemaking precedents, or (b) DPL’s corporate issuer or senior unsecured credit rating, or its equivalent, is rated by any of the three major credit rating agencies below the generally accepted definition of investment grade. No such event has occurred.

ACE is subject to certain dividend restrictions established by settlements approved by the NJBPU that prohibit ACE from paying a dividend on its common shares if (a) after the dividend payment, ACE's common equity ratio would be below 48% as calculated pursuant to the NJBPU's ratemaking precedents, or (b) ACE's senior corporate issuer or senior unsecured credit rating is rated by one of the three major credit rating agencies below investment grade. ACE is also subject to a dividend restriction which requires ACE to notify and obtain the prior approval of the NJBPU before dividends can be paid if its equity as a percent of its total capitalization, excluding securitization debt, falls below 30%. No such event has occurred.

Exelon’s Board of Directors approved an updated dividend policy for 2026. The 2026 quarterly dividend will be $0.42 per share.

As of December 31, 2025, Exelon had Retained earnings of $7,577 million, ComEd had Retained earnings of $2,998 million, PECO had Retained earnings of $2,438 million, BGE had Retained earnings of $2,588 million, and PHI had Undistributed losses of $151 million.

The following table sets forth Exelon’s quarterly cash dividends per share paid during 2025 and 2024:

	2025								2024
(per share)	Fourth Quarter		Third Quarter		Second Quarter		First Quarter		Fourth Quarter		Third Quarter		Second Quarter		First Quarter
Exelon	$	0.4000	$	0.4000	$	0.4000	$	0.4000	$	0.3800	$	0.3800	$	0.3800	$	0.3800

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

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

First Quarter 2026 Dividend

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

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ITEM 6. [RESERVED]

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

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

Exelon

Executive Overview

Exelon is a utility services holding company engaged in the energy transmission and distribution businesses through its six reportable segments: ComEd, PECO, BGE, Pepco, DPL, and ACE. See Note 1 — Significant Accounting Policies and Note 4 — Segment Information of the Combined Notes to Consolidated Financial Statements for additional information regarding Exelon's principal subsidiaries and reportable segments.

Exelon’s consolidated financial information includes the results of its seven separate operating subsidiary registrants, ComEd, PECO, BGE, PHI, Pepco, DPL, and ACE, which, along with Exelon, are collectively referred to as the Registrants. The following combined Management’s Discussion and Analysis of Financial Condition and Results of Operations is separately filed by Exelon, ComEd, PECO, BGE, PHI, Pepco, DPL, and ACE. However, none of the Registrants makes any representation as to information related solely to any of the other Registrants. For discussion of the Utility Registrants' year ended December 31, 2024 compared to the year ended December 31, 2023, refer to ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS in the 2024 Form 10-K, which was filed with the SEC on February 12, 2025.

Financial Results of Operations

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

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

__________

(a)Other primarily includes eliminating and consolidating adjustments, Exelon’s corporate operations, shared service entities, and other financing and investing activities.

Year Ended December 31, 2025 Compared to Year Ended December 31, 2024. Net income attributable to common shareholders increased by $308 million and Diluted earnings per average common share increased to $2.73 in 2025 from $2.45 in 2024 primarily due to:

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•Favorable impacts of rate increases at ComEd, PECO, BGE, and PHI;

•Favorable weather at PECO;

•Higher return on regulatory assets at ComEd;

•Higher AFUDC at ComEd;

•Lower income tax expense at PECO;

•Lower storm costs at BGE; and

•Impacts of the multi-year plan reconciliation at BGE.

Note that rate increases are associated with updated recovery rates for costs and investments to serve customers. The increases were partially offset by:

•Higher interest expense at PECO, BGE, PHI, and Exelon Corporate;

•Higher depreciation expense at PECO and PHI;

•Higher contracting costs at PECO and PHI;

•Lower transmission peak load due to lower energy demand at ComEd;

•Absence of the Maryland multi-year plan reconciliations at PHI;

•Charitable contributions at Exelon Corporate;

•Lower AFUDC at PHI; and

•Higher income tax expense at Exelon Corporate.

Adjusted (non-GAAP) operating earnings. In addition to Net income, Exelon evaluates its operating performance using the measure of Adjusted (non-GAAP) operating earnings because management believes it represents earnings directly related to the ongoing operations of the business. Adjusted (non-GAAP) operating earnings exclude certain costs, expenses, gains and losses, and other specified items. This information is intended to enhance an investor’s overall understanding of year-over-year operating results and provide an indication of Exelon’s baseline operating performance excluding items not considered by management to be directly related to the ongoing operations of the business. In addition, this information is among the primary indicators management uses as a basis for evaluating performance, allocating resources, setting incentive compensation targets, and planning and forecasting of future periods. Adjusted (non-GAAP) operating earnings is not a presentation defined under GAAP and may not be comparable to other companies’ presentations or deemed more useful than the GAAP information provided elsewhere in this report.

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

	2025				2024
(In millions, except per share data)			Earnings per Diluted Share				Earnings per Diluted Share
Net income attributable to common shareholders	$	2,768	$	2.73	$	2,460	$	2.45
Asset retirement obligations (net of taxes of $0 and $3, respectively)	(1)		—		8		0.01
Change in FERC audit liability (net of taxes of $1 and $13, respectively)	2		—		42		0.04
Cost management charge (net of taxes of $0 and $4, respectively)(a)	(1)		—		13		0.01
Environmental costs (net of taxes of $5)	—		—		(13)		(0.01)
Regulatory matters (net of taxes of $10)(b)	30		0.03		—		—
Income tax-related adjustments (entire amount represents tax expense)(c)	1		—		(3)		—
Adjusted (non-GAAP) operating earnings	$	2,801	$	2.77	$	2,507	$	2.50

__________

Note:

Amounts may not sum due to rounding.

Unless otherwise noted, the income tax impact of each reconciling item between GAAP Net income and Adjusted (non-GAAP) operating earnings is based on the marginal statutory federal and state income tax rates for each Registrant, taking into account whether the income or expense item is taxable or deductible, respectively, in whole or in part. The marginal statutory income tax rates for 2025 and 2024 ranged from 24.0% to 29.0%.

(a)Primarily represents severance and reorganization costs related to cost management.

(b)Represents the disallowance of certain capitalized costs.

(c)In 2024, reflects the adjustment to state deferred income taxes due to change in DPL's Delaware net operating loss valuation allowance. In 2025, reflects the adjustment to state deferred income taxes due to changes in forecasted apportionment.

Significant 2025 Transactions and Developments

At-the-Market Program

During 2025, Exelon issued approximately 16 million shares of Common Stock at a net weighted-average price of $43.24 per share. The net proceeds from the 2025 issuances were $691 million, which were used for general corporate purposes. See Note 17 — Shareholders' Equity of the Combined Notes to Consolidated Financial Statements for additional information.

Distribution Base Rate Case Proceedings

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

The following tables show the Utility Registrants’ completed and pending distribution base rate case proceedings in 2025. See Note 2 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information on these and other regulatory proceedings.

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Completed Distribution Base Rate Case Proceedings

Registrant/Jurisdiction	Filing Date	Service	Requested Revenue Requirement Increase		Approved Revenue Requirement Increase		Approved ROE	Approval Date	Rate Effective Date
ComEd - Illinois	January 17, 2023	Electric	$	1,487	$	1,045	8.905%	December 19, 2024	January 1, 2024
	April 26, 2024 (amended on September 11, 2024)	Electric	$	624	$	623	9.89%	October 31, 2024	January 1, 2025
PECO - Pennsylvania	March 28, 2024	Electric	$	464	$	354	N/A	December 12, 2024	January 1, 2025
		Natural Gas	$	111	$	78
BGE - Maryland	February 17, 2023	Electric	$	313	$	179	9.50%	December 14, 2023	January 1, 2024
		Natural Gas	$	289	$	229	9.45%
Pepco - District of Columbia	April 13, 2023 (amended February 27, 2024)	Electric	$	186	$	123	9.50%	November 26, 2024	January 1, 2025
Pepco - Maryland	May 16, 2023 (amended February 23, 2024)	Electric	$	111	$	45	9.50%	June 10, 2024	April 1, 2024
DPL - Maryland	May 19, 2022	Electric	$	38	$	29	9.60%	December 14, 2022	January 1, 2023
DPL - Delaware	December 15, 2022 (amended September 29, 2023)	Electric	$	39	$	28	9.60%	April 18, 2024	July 15, 2023
	September 20, 2024 (amended September 5, 2025)	Natural Gas	$	37	$	22	9.60%	December 17, 2025	January 1, 2026
ACE - New Jersey	February 15, 2023 (amended August 21, 2023)	Electric	$	92	$	45	9.60%	November 17, 2023	December 1, 2023
	November 21, 2024	Electric	$	109	$	54	9.60%	November 21, 2025	December 1, 2025

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Pending Distribution Base Rate Case Proceedings

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

Transmission Formula Rates

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

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

ComEd's FERC Audit

The Utility Registrants are subject to periodic audits and investigations by FERC. FERC’s Division of Audits and Accounting initiated a nonpublic audit of ComEd in April 2021 evaluating ComEd’s compliance with (1) approved terms, rates and conditions of its federally regulated service; (2) accounting requirements of the Uniform System of Accounts; (3) reporting requirements of the FERC Form 1; and (4) the requirements for record retention. The audit period extended back to January 1, 2017.

On July 27, 2023, FERC published a final audit report which included, among other things, findings and recommendations related to ComEd's methodology regarding the allocation of certain overhead costs to capitalized construction costs under FERC regulations, including a suggestion that refunds may be due to customers for amounts collected in previous years. On July 30, 2024, ComEd reached an agreement in principle on the contested overhead allocation finding. As a result of the settlement process, ComEd recorded a charge for the probable disallowance of $70 million of certain currently capitalized construction costs to operating expenses, which are not expected to be recovered in future rates. The existing loss estimate was reflected in Exelon and ComEd's financial statements as of December 31, 2024. ComEd and FERC staff jointly filed the settlement agreement with FERC for approval on February 11, 2025. The settlement was approved by FERC on April 4, 2025.

Other Key Business Drivers and Management Strategies

Utility Rates and Rate Proceedings

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

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Allocation of Income Taxes to Regulated Utilities (All Registrants)

In Q2 2024, the IRS issued a series of PLRs, to another taxpayer, providing guidance with respect to the application of the tax normalization rules to the allocation of consolidated tax benefits among the members of a consolidated group associated with NOLC for ratemaking purposes. The rulings provide that for ratemaking purposes the tax benefit of NOLC should be reflected on a separate company basis not taking into consideration the utilization of losses by other affiliates. A PLR issued to another taxpayer may not be relied on as precedent.

For the Utility Registrants, except for PECO, the methodology prescribed by the IRS in these PLRs could result in a material reduction of the regulatory liability established for EDITs arising from the TCJA corporate tax rate change that are being amortized and flowed through to customers as well as a reduction in the accumulated deferred income taxes included in rate base for ratemaking purposes of approximately $1.2 billion - $1.7 billion.

The Utility Registrants, except for PECO, filed PLR requests with the IRS confirming the treatment of the NOLC for ratemaking purposes. The Utility Registrants will record the impact, if any, upon receiving the PLR from the IRS.

Legislative and Regulatory Developments

Infrastructure Investment and Jobs Act

On November 15, 2021, the $1.2 trillion IIJA was signed into law. IIJA provides for approximately $550 billion in new federal spending. Categories of funding include funding for a variety of infrastructure needs, including but not limited to: (1) power and grid reliability and resilience, (2) resilience for cybersecurity to address critical infrastructure needs, and (3) electric vehicle charging infrastructure for alternative fuel corridors. The Registrants continue to evaluate programs under the legislation and consider possible opportunities to apply for funding, either directly or in potential collaborations with state and/or local agencies and key stakeholders. The Registrants cannot predict the ultimate timing and success of securing funding from programs under IIJA.

On January 20, 2025, the Unleashing American Energy Order was issued as a Presidential Executive Order, which required an immediate pause in the disbursement of funds appropriated through the IRA and IIJA pending DOE review. In October 2025, Exelon, ComEd, and BGE received termination notifications from the DOE for their Renewable-Aware Distribution Operations, Deployment of a Community-Oriented Interoperable Control Framework for Aggregating and Integrating Distributed Energy Resources and Other Grid-Edge Devices, and Baltimore Interconnection Readiness & Deployment of Storage (BIRDS) awards, respectively. In the fourth quarter of 2025, Exelon, ComEd, and BGE elected to decline the previously awarded Middle Mile Grant (MMG) and Exelon and PECO elected to decline the previously awarded Creating a Resilient, Equitable, and Accessible Transformation in Energy for Greater Philadelphia (CREATE) grant. There are no material financial statement impacts as a result of the DOE terminations. Exelon, ComEd, PECO, and BGE will continue to evaluate whether to move forward with these projects.

Next Generation Energy Act (Exelon, BGE, PHI, Pepco, and DPL)

On May 20, 2025, the Governor of Maryland signed into law legislation that addresses several matters pertaining to electric and gas utilities, including affirming that the MDPSC may approve the use of multi-year rate plans that demonstrate customer benefits, among other things. It also prohibits utilities from filing after January 1, 2025, for the reconciliation of actuals costs and revenues to amounts approved within the multi-year plans. In the second quarter of 2025, BGE derecognized Regulatory assets of $10 million and Regulatory liabilities of $3 million for multi-year plan reconciliations that are no longer eligible to be filed. DPL also derecognized Regulatory liabilities of $0.4 million during the second quarter of 2025 for multi-year reconciliations ineligible to be filed. Multi-year plan reconciliations filed prior to January 1, 2025, remain lawful and will be resolved in their respective proceedings.

Summer and Winter Rate Mitigation (Exelon, BGE, PHI, Pepco, DPL, and ACE).

As part of the passing of the Next Generation Energy Act by the Maryland General Assembly, the MDPSC issued an order on June 26, 2025, to implement the Legislative Energy Relief Refund program under which bill credits were distributed to residential customers based on their consumption of electricity supply that was subject to the renewable energy portfolio standard. On July 24, 2025, the MDPSC issued an order accepting BGE, Pepco, and DPL's proposal for the implementation of the program. As a result, BGE, Pepco, and DPL received approximately

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$49 million, $21 million, and $8 million, respectively, from the MDPSC on August 6, 2025. These amounts were used to reduce residential customer accounts receivable balances within the third quarter of 2025. Additional disbursements from the state of Maryland were received by BGE, Pepco, and DPL on February 3, 2026 for approximately $49 million, $21 million, and $8 million, respectively. These amounts will also be used to reduce residential customer receivables in the first quarter of 2026.

In response to significant increases in electric supply costs, on April 23, 2025, the NJBPU issued an order directing the State's electric public utilities to file petitions proposing distribution side measures to mitigate residential customer bill impacts during summer months. As a result, on June 18, 2025, the NJBPU approved a stipulation of settlement for ACE to issue a bill credit of $30 per residential customer for the months of July and August 2025, which was deferred to Regulatory assets. The amounts will subsequently be collected from September 2025 through February 2026 at a flat rate of $10 per residential customer. The bill credit and subsequent collections will not be subject to carrying costs. As of December 31, 2025, the Regulatory asset has a remaining balance of $10 million.

Residential Universal Bill Credit (Exelon and ACE).

In an effort to further reduce the burden of increased electric supply costs, on August 13, 2025, the NJBPU issued an order to establish the Residential Universal Bill Credit (RUBC), which will be funded by the NJBPU. The program provided a $50 bill credit per eligible residential customer for the months of September and October 2025. ACE received $51 million from the NJBPU on September 25, 2025, which was recognized as a Regulatory liability. ACE subsequently issued all bill credits to residential customers in September and October. As of December 31, 2025, there is no Regulatory liability remaining.

One Big Beautiful Bill Act (All Registrants).

On July 4, 2025, the OBBBA was signed into law. The bill permanently extends expiring tax benefits of the TCJA and provides additional tax relief for individuals and businesses while accelerating the phase-out and curtailment for renewable energy tax credits enacted by the IRA. The tax law changes enacted as part of OBBBA will not have a direct material impact on the Registrants’ financial statements.

Critical Accounting Policies and Estimates

The preparation of financial statements in conformity with GAAP requires that management apply accounting policies and make estimates and assumptions that affect results of operations and the amounts of assets and liabilities reported in the financial statements. Management believes that the accounting policies described below require significant judgment in their application or incorporate estimates and assumptions that are inherently uncertain and that may change in subsequent periods. Additional information on the application of these accounting policies can be found in the Combined Notes to Consolidated Financial Statements.

Regulatory Accounting (All Registrants)

For their regulated electric and gas operations, the Registrants reflect the effects of cost-based rate regulation in their financial statements, which is required for entities with regulated operations that meet the following criteria: (1) rates are established or approved by a third-party regulator; (2) rates are designed to recover the entities’ cost of providing services or products; and (3) a reasonable expectation that rates designed to recover costs can be charged to and collected from customers. Regulatory assets represent incurred costs that have been deferred because of their probable future recovery from customers through regulated rates. Regulatory liabilities represent (1) revenue or gains that have been deferred because it is probable such amounts will be returned to customers through future regulated rates; or (2) billings in advance of expenditures for approved regulatory programs. If it is concluded in a future period that a separable portion of operations no longer meets the criteria discussed above, the Registrants would be required to eliminate any associated regulatory assets and liabilities and the impact, which could be material, would be recognized in the Consolidated Statements of Operations and Comprehensive Income.

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

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

___________

(a)Exelon's charge against OCI (before taxes) consists of up to $2.4 billion, $346 million, $298 million, $214 million, and $75 million, related to ComEd's, BGE's, PHI's, Pepco's, and DPL's respective portions of the deferred costs associated with Exelon's pension and OPEB plans. Exelon also has a net regulatory liability (before taxes) of $86 million and $6 million related to PECO's and ACE's portions of the deferred costs associated with Exelon’s OPEB plans that would result in an increase in OCI if reversed.

See Note 2 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information regarding regulatory matters, including the regulatory assets and liabilities of the Registrants.

For each regulatory jurisdiction in which they conduct business, the Registrants assess whether the regulatory assets and liabilities continue to meet the criteria for probable future recovery or refund at each balance sheet date and when regulatory events occur. This assessment includes consideration of recent rate orders, historical regulatory treatment for similar costs in each Registrant's jurisdictions, and factors such as changes in applicable regulatory and political environments. If the assessments and estimates made by the Registrants for regulatory assets and regulatory liabilities are ultimately different than actual regulatory outcomes, the impact in their consolidated financial statements could be material.

Refer to the revenue recognition discussion below for additional information on the annual revenue reconciliations associated with ICC-approved electric distribution MRP and formula rate mechanisms for ComEd, and FERC transmission formula rate tariffs for the Utility Registrants.

Revenues (All Registrants)

Sources of Revenue and Determination of Accounting Treatment. The Registrants earn revenues from the sale and delivery of power and natural gas in regulated markets. The accounting treatment for revenue recognition is based on the nature of the underlying transaction and applicable authoritative guidance. The Registrants primarily apply the Revenue from Contracts with Customers, and Alternative Revenue Program accounting guidance to recognize revenues as discussed in more detail below.

Revenue from Contracts with Customers. The Registrants recognize revenues in the period in which the performance obligations within contracts with customers are satisfied, which generally occurs when power and natural gas are physically delivered to the customer. Transactions of the Registrants within the scope of Revenue from Contracts with Customers generally include sales to utility customers under regulated service tariffs.

The determination of the Registrants' power and natural gas sales to individual customers is based on systematic readings of customer meters, generally monthly. At the end of each month, amounts of energy delivered to customers since the date of the last meter reading are estimated, and corresponding unbilled revenue is recorded. The measurement of unbilled revenue is affected by the following factors: daily customer usage measured by generation or gas throughput volume, customer usage by class, losses of energy during delivery to customers and applicable customer rates. Increases or decreases in volumes delivered to the Registrant’s customers and favorable or unfavorable rate mix due to changes in usage patterns in customer classes in the period could be significant to the calculation of unbilled revenue. In addition, revenues may fluctuate monthly as a result of customers electing to use an alternative supplier, since unbilled commodity revenues are not recorded for these customers. Changes in the timing of meter reading schedules and the number and type of customers scheduled for each meter reading date also impact the measurement of unbilled revenue; however, total operating revenues would remain materially unchanged. See Note 1 — Significant Accounting Policies of the Combined Notes to Consolidated Financial Statements for additional information.

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Alternative Revenue Program Accounting. Certain of the Registrants’ ratemaking mechanisms qualify as ARPs if they (i) are established by a regulatory order and allow for automatic adjustment to future rates, (ii) provide for additional revenues (above those amounts currently reflected in the price of utility service) that are objectively determinable and probable of recovery, and (iii) allow for the collection of those additional revenues within 24 months following the end of the period in which they were recognized. For mechanisms that meet these criteria, the Registrants adjust revenue and record an offsetting regulatory asset or liability once the condition or event allowing additional billing or refund has occurred. The ARP revenues presented in the Registrants’ Consolidated Statements of Operations and Comprehensive Income include both: (i) the recognition of “originating” ARP revenues (when the regulator-specified condition or event allowing for additional billing or refund has occurred) and (ii) an equal and offsetting reversal of the “originating” ARP revenues as those amounts are reflected in the price of utility service and recognized as Revenue from Contracts with Customers.

ComEd records ARP revenue for its best estimate of the electric distribution, energy efficiency, distributed generation rebates, and transmission revenue impacts resulting from future changes in rates that ComEd believes are probable of approval by the ICC and FERC in accordance with its distribution multi-year rate plan, distribution revenue decoupling mechanisms, and formula rate mechanisms. BGE, Pepco, DPL, and ACE record ARP revenue for their best estimate of the electric and natural gas distribution revenue impacts resulting from future changes in rates that they believe are probable of approval by the MDPSC, DCPSC, and/or NJBPU in accordance with their revenue decoupling mechanisms. PECO, BGE, Pepco, DPL, and ACE record ARP revenue for their best estimate of the transmission revenue impacts resulting from future changes in rates that they believe are probable of approval by FERC in accordance with their formula rate mechanisms. Estimates of the current year revenue requirement are based on actual and/or forecasted costs and investments in rate base for the period and the rates of return on common equity and associated regulatory capital structure allowed under the applicable tariff. The estimated reconciliation can be affected by, among other things, variances in costs incurred, investments made, allowed ROE, and actions by regulators or courts.

See Note 2 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.

Income Taxes (All Registrants)

Significant management judgment is required in determining the Registrants’ provisions for income taxes, primarily due to the uncertainty related to tax positions taken, as well as deferred tax assets and liabilities and valuation allowances. The Registrants account for uncertain income tax positions using a benefit recognition model with a two-step approach including a more-likely-than-not recognition threshold and a measurement approach based on the largest amount of tax benefit that is greater than 50% likely of being realized upon ultimate settlement. Management evaluates each position based solely on the technical merits and facts and circumstances of the position, assuming the position will be examined by a taxing authority having full knowledge of all relevant information. Significant judgment is required to determine whether the recognition threshold has been met and, if so, the appropriate amount of tax benefits to be recorded in the Registrants’ consolidated financial statements.

The Registrants evaluate quarterly the probability of realizing deferred tax assets by reviewing a forecast of future taxable income and their intent and ability to implement tax planning strategies, if necessary, to realize deferred tax assets. The Registrants also assess negative evidence, such as the expiration of historical operating loss or tax credit carryforwards, that could indicate the Registrant's inability to realize its deferred tax assets. Based on the combined assessment, the Registrants record valuation allowances for deferred tax assets when it is more-likely-than-not such benefit will not be realized in future periods.

Actual income taxes could vary from estimated amounts due to the future impacts of various items, including future changes in income tax laws, the Registrants’ forecasted financial condition and results of operations, failure to successfully implement tax planning strategies, as well as results of audits and examinations of filed tax returns by taxing authorities. See Note 11 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information.

Allowance for Credit Losses on Customer Receivables (All Registrants)

The Registrants allowance for credit losses on customer receivables is estimated based on historical experience, current conditions, and forward-looking risk factors. Historical experience considered include

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collection activities and payment history utilized for risk segmentation; current conditions include changes in economic conditions, aging of receivable balances, payment options and programs available to customers, and industry trends for each company; and forward-looking risk factors include assumptions related to the level of write-offs and recoveries. Risk segments represent a group of customers with similar forward-looking credit quality indicators and risk factors that are comprised based on various attributes, including delinquency of their balances and payment history and represent expected, future customer behavior. The Registrants' customer accounts are generally considered delinquent if the amount billed is not received by the time the next bill is issued, which normally occurs on a monthly basis. The Registrants' customer accounts are written off consistent with approved regulatory requirements. The Registrants' allowances for credit losses will continue to be affected by changes in volume, prices, and economic conditions as well as changes in ICC, PAPUC, MDPSC, DCPSC, DEPSC, and NJBPU regulations.

Depreciable Lives of Property, Plant, and Equipment (All Registrants)

The Registrants have significant investments in electric and natural gas transmission and distribution assets. These assets are generally depreciated on a straight-line basis, using the group, or composite methods of depreciation. The group approach is typically for groups of similar assets that have approximately the same useful lives and the composite approach is used for heterogeneous assets that have different lives. Under both methods, a reporting entity depreciates the assets over the average life of the assets in the group. The estimation of asset useful lives requires management judgment, supported by formal depreciation studies of historical asset retirement experience. Depreciation studies are conducted periodically and as required by a rate regulator or regulatory action, or changes in retirement patterns indicate an update is necessary.

Depreciation studies generally serve as the basis for amounts allowed in customer rates for recovery of depreciation costs. Generally, the Registrants adjust their depreciation rates for financial reporting purposes concurrent with adjustments to depreciation rates reflected in customer rates, unless the depreciation rates reflected in customer rates do not align with management’s judgment as to an appropriate estimated useful life or have not been updated on a timely basis. Depreciation expense and customer rates for ComEd, BGE, Pepco, DPL, and ACE include an estimate of the future costs of dismantling and removing plant from service upon retirement. See Note 2 — Regulatory Matters of the Combined Notes to the Consolidated Financial Statements for information regarding regulatory liabilities and assets recorded by ComEd, BGE, Pepco, DPL, and ACE related to removal costs.

PECO’s removal costs are capitalized to accumulated depreciation when incurred and recorded to depreciation expense over the life of the new asset constructed consistent with PECO’s regulatory recovery method. Estimates for such removal costs are also evaluated in the periodic depreciation studies.

Changes in estimated useful lives of electric and natural gas transmission and distribution assets could have a significant impact on the Registrants’ future results of operations. See Note 1 — Significant Accounting Policies of the Combined Notes to Consolidated Financial Statements for information regarding depreciation and estimated service lives of the property, plant, and equipment of the Registrants.

Goodwill (Exelon, ComEd, and PHI)

As of December 31, 2025, Exelon’s $6.6 billion carrying amount of goodwill consists of $2.6 billion at ComEd and $4 billion at PHI. These entities are required to perform an assessment for possible impairment of their goodwill at least annually or more frequently if an event occurs or circumstances change that would more likely than not reduce the fair value of the reporting units below their carrying amount. A reporting unit is an operating segment or one level below an operating segment (known as a component) and is the level at which goodwill is assessed for impairment. ComEd has a single operating segment and reporting unit. PHI’s operating segments and reporting units are Pepco, DPL, and ACE. See Note 4 — Segment Information of the Combined Notes to Consolidated Financial Statements for additional information. Exelon's and ComEd’s goodwill has been assigned entirely to the ComEd reporting unit. Exelon's and PHI’s goodwill has been assigned to the Pepco, DPL, and ACE reporting units in the amounts of $2.1 billion, $1.4 billion, and $0.5 billion, respectively. See Note 10 — Intangible Assets of the Combined Notes to Consolidated Financial Statements for additional information.

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

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cash flows for their businesses, outcomes of recent regulatory proceedings, changes in certain market conditions, including the discount rate and regulated utility peer EBITDA multiples, and the passing margin from their last quantitative assessments performed.

Application of the goodwill impairment assessment requires management judgment, including the identification of reporting units and determining the fair value of the reporting unit, which management estimates using a weighted combination of a discounted cash flow analysis and a market multiples analysis. Significant assumptions used in these fair value analyses include discount and growth rates, utility sector market performance and transactions, and projected operating and capital cash flows for ComEd’s, Pepco's, DPL's, and ACE's businesses and the fair value of debt.

While the 2025 annual assessments indicated no impairments, certain assumptions used in the assessment are highly sensitive to changes. Adverse regulatory actions or changes in significant assumptions could potentially result in future impairments of Exelon’s, ComEd's, or PHI’s goodwill, which could be material.

See Note 1 — Significant Accounting Policies and Note 10 — Intangible Assets of the Combined Notes to Consolidated Financial Statements for additional information.

Unamortized Energy Contract Liabilities (Exelon and PHI)

Unamortized energy contract liabilities represent the remaining unamortized balances of non-derivative electricity contracts that Exelon acquired as part of the PHI merger. The initial amount recorded represents the difference between the fair value of the contracts at the time of acquisition and the contract value based on the terms of each contract. Offsetting regulatory assets were also recorded for those energy contract costs that are probable of recovery through customer rates. The unamortized energy contract liabilities and the corresponding regulatory assets, respectively, are amortized over the life of the contract in relation to the expected realization of the underlying cash flows. Amortization of the unamortized energy contract liabilities are recorded through Purchased power and fuel expense. See Note 2 — Regulatory Matters and Note 10 — Intangible Assets of the Combined Notes to Consolidated Financial Statements for additional information.

Accounting for Loss Contingencies (All Registrants)

In the preparation of the financial statements, the Registrants make judgments regarding the future outcome of contingent events and record liabilities for loss contingencies that are probable and can be reasonably estimated based upon available information. The amount recorded may differ from the actual expense incurred when the uncertainty is resolved. Such difference could have a significant impact in the Registrants' consolidated financial statements.

Environmental Costs. Environmental investigation and remediation liabilities are based upon estimates with respect to the number of sites for which the Registrants will be responsible, the scope and cost of work to be performed at each site, the portion of costs that will be shared with other parties, the timing of the remediation work, regulations, and the requirements of local governmental authorities. Annual studies and/or reviews are conducted at ComEd, PECO, BGE, and DPL to determine future remediation requirements for MGP sites and estimates are adjusted accordingly. In addition, periodic reviews are performed at each of the Registrants to assess the adequacy of other environmental reserves. These matters, if resolved in a manner different from the estimate, could have a significant impact in the Registrants’ consolidated financial statements. See Note 16 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for additional information.

Other, Including Personal Injury Claims. The Registrants are self-insured for general liability, automotive liability, workers’ compensation, and personal injury claims to the extent that losses are within policy deductibles or exceed the amount of insurance maintained. The Registrants have reserves for both open claims asserted, and an estimate of claims incurred but not reported (IBNR). The IBNR reserve is estimated based on actuarial assumptions and analysis and is updated annually. Future events, such as the number of new claims to be filed each year, the average cost of disposing of claims, as well as the numerous uncertainties surrounding litigation and possible state and national legislative measures could cause the actual costs to be higher or lower than estimated. Accordingly, these claims, if resolved in a manner different from the estimate, could have a material impact to the Registrants’ consolidated financial statements.

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Retirement Benefits (All Registrants)

Exelon sponsors defined benefit pension plans and OPEB plans. The measurement of the plan obligations and costs of providing benefits involves various factors, including the development of valuation assumptions and inputs and accounting policy elections. When developing the required assumptions, Exelon considers historical information as well as future expectations. The measurement of benefit obligations and costs is affected by several assumptions including the discount rate, the long-term expected rate of return on plan assets, the anticipated rate of increase of health care costs, Exelon's contributions, the rate of compensation increases, and the long-term expected investment rate credited to employees of certain plans, among others. The assumptions are updated annually and upon any interim remeasurement of the plan obligations.

Pension and OPEB plan assets include cash and cash equivalents, equity securities, including U.S. and international securities, and fixed income securities, as well as certain alternative investment classes such as private equity, real estate, private credit, and hedge funds.

Expected Rate of Return on Plan Assets. In determining the EROA, Exelon considers historical economic indicators (including inflation and GDP growth) that impact asset returns, as well as expectations regarding future long-term capital market performance, weighted by Exelon’s target asset class allocations. Exelon calculates the amount of expected return on pension and OPEB plan assets by multiplying the EROA by the MRV of plan assets at the beginning of the year, taking into consideration anticipated contributions and benefit payments to be made during the year. In determining MRV, the authoritative guidance for pensions and postretirement benefits allows the use of either fair value or a calculated value that recognizes changes in fair value in a systematic and rational manner over not more than five years. For the majority of pension plan assets, Exelon uses a calculated value that adjusts for 20% of the difference between fair value and expected MRV of plan assets. Use of this calculated value approach enables less volatile expected asset returns to be recognized as a component of pension cost from year to year. For OPEB plan assets and certain pension plan assets, Exelon uses fair value to calculate the MRV.

Discount Rate. The discount rates are determined by developing a spot rate curve based on the yield to maturity of a universe of high-quality bonds with similar maturities to the related pension and OPEB obligations. The spot rates are used to discount the estimated future benefit distribution amounts under the pension and OPEB plans. The discount rate is the single level rate that produces the same result as the spot rate curve. Exelon utilizes an analytical tool developed by its actuaries to determine the discount rates.

Mortality. The mortality assumption is composed of a base table that represents the current expectation of life expectancy of the population adjusted by an improvement scale that attempts to anticipate future improvements in life expectancy. Exelon’s mortality assumption utilizes the SOA 2019 base table (Pri-2012) and MP-2021 improvement scale adjusted to use Proxy SSA ultimate improvement rates.

50

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

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

__________

(a)In general, the discount rate will have a larger impact on the pension and OPEB cost and obligation as the rate moves closer to 0%. Therefore, the discount rate sensitivities above cannot necessarily be extrapolated for larger increases or decreases in the discount rate. Additionally, Exelon utilizes a liability-driven investment strategy for its pension asset portfolio. The sensitivities shown above do not reflect the offsetting impact that changes in discount rates may have on pension asset returns.

See Note 1 — Significant Accounting Policies and Note 12 — Retirement Benefits of the Combined Notes to Consolidated Financial Statements for additional information regarding the accounting for the defined benefit pension plans and OPEB plans.

Derivative Financial Instruments (All Registrants)

The Registrants use derivative instruments to manage commodity price risk and interest rate risk related to ongoing business operations. See Note 13 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information.

Determining whether a contract qualifies as a derivative requires that management exercise significant judgment, including assessing market liquidity as well as determining whether a contract has one or more underlying and one or more notional quantities.

All derivatives are recognized on the balance sheet at their fair value, except for certain derivatives that qualify for, and are elected under, NPNS. For derivatives that qualify and are designated as cash flow hedges, changes in fair value each period are initially recorded in AOCI and recognized in earnings when the hedged transaction affects earnings. For derivatives intended to serve as economic hedges, which are not designated for hedge accounting, changes in fair value each period are recognized in earnings on the Consolidated Statement of Operations and Comprehensive Income or are recorded as a regulatory asset or liability when there is an ability to recover or return the associated costs or benefits in accordance with regulatory requirements.

NPNS. Contracts that are designated as NPNS are not required to be recorded at fair value, but rather on an accrual basis of accounting. Determining whether a contract qualifies for NPNS requires judgment on whether the contract will physically deliver and requires that management ensure compliance with all the associated qualification and documentation requirements. For all NPNS derivative instruments, accounts payable is recorded when derivatives settle and expense is recognized in earnings as the underlying physical commodity is consumed. Contracts that qualify for NPNS are those for which physical delivery is probable, quantities are expected to be used or sold in the normal course of business over a reasonable period, and the contract is not financially settled on a net basis. See Note 13 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for all contracts that are accounted for under NPNS.

Commodity Contracts. The Registrants make estimates and assumptions concerning future commodity prices, interest rates, and the timing of future transactions and their probable cash flows in deciding whether to enter derivative transactions, and in determining the initial accounting treatment for derivative transactions. The

51

Registrants categorize these derivatives under a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value.

Derivative contracts can be traded in both exchange-based and non-exchange-based markets. Exchange-based derivatives that are valued using unadjusted quoted prices in active markets are generally categorized in Level 1 in the fair value hierarchy. Certain derivative pricing is verified using indicative price quotations available through brokers or over-the-counter, online exchanges. For derivatives that trade in liquid markets, the model inputs are generally observable. Such instruments are categorized in Level 2. For derivatives that trade in less liquid markets with limited pricing information, the model inputs generally would include both observable and unobservable inputs and are categorized in Level 3.

The Registrants consider nonperformance risk, including credit risk in the valuation of derivative contracts, and both historical and current market data in the assessment of nonperformance risk. The impacts of nonperformance and credit risk to date have generally not been material to the Registrants’ financial statements.

Interest Rate Derivative Instruments. Exelon Corporate utilizes interest rate swaps to manage interest rate risk on existing and planned future debt issuances. The fair value of the swaps is calculated by discounting the future net cash flows to the present value based on the terms and conditions of the agreements and the forward interest rate curves. As these inputs are based on observable data and valuations of similar instruments, the interest rate derivatives are primarily categorized in Level 2 in the fair value hierarchy.

See ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK and Note 15 — Fair Value of Financial Assets and Liabilities and Note 13 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information regarding the Registrants’ derivative instruments.

52

ComEd

Results of Operations by Registrant

Results of Operations—ComEd

	2025		2024		(Unfavorable) Favorable Variance
Operating revenues	$	7,267	$	8,219	$	(952)
Operating expenses
Purchased power	1,782		3,042		1,260
Operating and maintenance	1,710		1,703		(7)
Depreciation and amortization	1,560		1,514		(46)
Taxes other than income taxes	409		376		(33)
Total operating expenses	5,461		6,635		1,174
Gain on sales of assets	—		5		(5)
Operating income	1,806		1,589		217
Other income and (deductions)
Interest expense, net	(530)		(501)		(29)
Other, net	132		94		38
Total other income and (deductions)	(398)		(407)		9
Income before income taxes	1,408		1,182		226
Income taxes	261		116		(145)
Net income	$	1,147	$	1,066	$	81

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

The changes in Operating revenues consisted of the following:

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

Revenue Decoupling. The demand for electricity is affected by weather and customer usage. Operating revenues are not intended to be impacted by abnormal weather, usage per customer, or number of customers as a result of revenue decoupling mechanisms.

Distribution Revenue. Starting in 2024, distribution revenues are under a MRP. The MRP requires an annual reconciliation of the revenue requirement in effect to the actual costs the ICC determines are prudently and reasonably incurred. Electric distribution revenue varies from year to year based upon fluctuations in the underlying costs, (e.g., severe weather and storm restoration), investments being recovered, and allowed ROE. Electric distribution revenue increased during the year ended December 31, 2025, compared to the same period in 2024, primarily due to higher fully recoverable costs, higher rate base, and higher return on regulatory assets.

53

ComEd

Transmission Revenue. Under a FERC-approved formula, transmission revenue varies from year to year based upon fluctuations in the underlying costs, capital investments being recovered, and the highest daily peak load, which is updated annually in January based on the prior calendar year. Transmission revenue for the year ended December 31, 2025, compared to the same period in 2024, remained relatively consistent.

Energy Efficiency Revenue. Energy efficiency revenues are under a performance-based formula rate, which requires an annual reconciliation of the revenue requirement in effect to the actual costs the ICC determines are prudently and reasonably incurred in a given year. Energy efficiency revenue varies from year to year based upon fluctuations in the underlying costs, investments being recovered, and allowed ROE. Energy efficiency revenue increased during the year ended December 31, 2025, compared to the same period in 2024, primarily due to increased regulatory asset amortization, which is fully recoverable.

Other Revenue primarily includes assistance provided to other utilities through mutual assistance programs. Other revenue decreased for the year ended December 31, 2025, compared to the same period in 2024, which primarily reflects decreased mutual assistance revenues associated with storm restoration efforts.

Regulatory Required Programs represents revenues collected under approved riders to recover costs incurred for regulatory programs such as recoveries under the credit loss expense tariff, environmental costs associated with MGP sites, ETAC, and costs related to electricity, ZEC, CMC, and REC procurement. ETAC is a retail customer surcharge collected and remitted to an Illinois state agency for programs to support clean energy jobs and training. The riders are designed to provide full and current cost recovery. The costs of these programs are included in Purchased power expense, Operating and maintenance expense, Depreciation and amortization expense, and Taxes other than income taxes. Customers have the choice to purchase electricity from competitive electric generation suppliers. Customer choice programs do not impact the volume of deliveries as ComEd remains the distribution service provider for all customers and charges a regulated rate for distribution service, which is recorded in Operating revenues. For customers that choose to purchase electric generation from competitive suppliers, ComEd either acts as the billing agent or the competitive supplier separately bills its own customers, and therefore does not record Operating revenues or Purchased power expense related to the electricity. For customers that choose to purchase electric generation from ComEd, ComEd is permitted to recover the electricity, ZEC, CMC, and REC procurement costs without mark-up and therefore records equal and offsetting amounts in Operating revenues and Purchased power expense related to the electricity, ZECs, CMCs, and RECs.

See Note 4 — Segment Information of the Combined Notes to Consolidated Financial Statements for the presentation of ComEd's revenue disaggregation.

The $1,260 million decrease in Purchased power expense for the year ended December 31, 2025 compared to the same period in 2024, which includes the impacts of CMC nuclear production tax credits, is offset in Operating revenues as part of regulatory required programs. See Note 2 — Regulatory Matters for additional information.

54

ComEd

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

	2025 vs. 2024
	(Decrease) Increase
Labor, other benefits, contracting, and materials	$	(9)
BSC costs	(14)
Pension and non-pension postretirement benefits expense	5
Storm-related costs	2
	(15)
Regulatory required programs(a)	22
Total increase	$	7

__________

(a)ComEd is allowed to recover from or refund to customers the difference between its annual credit loss expense and the amounts collected in rates annually through a rider mechanism.

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

	2025 vs. 2024
	Increase (Decrease)
Depreciation and amortization(a)	$	56
Regulatory asset amortization(b)	(10)
Total increase	$	46

__________

(a)Reflects ongoing capital expenditures.

(b)Includes amortization of ComEd's energy efficiency formula rate regulatory asset.

Interest expense, net increased $29 million for the year ended December 31, 2025, compared to the same period in 2024, primarily due to an increase in interest rates and the issuance of debt in 2025.

Other, net increased $38 million for the year ended December 31, 2025, compared to the same period in 2024, primarily due to higher AFUDC equity.

Effective income tax rates were 18.5% and 9.8% for the years ended December 31, 2025 and 2024, respectively. See Note 11 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the effective income tax rates.

55

PECO

Results of Operations—PECO

	2025		2024		Favorable (Unfavorable) Variance
Operating revenues	$	4,684	$	3,973	$	711
Operating expenses
Purchased power and fuel	1,733		1,477		(256)
Operating and maintenance	1,195		1,120		(75)
Depreciation and amortization	454		428		(26)
Taxes other than income taxes	240		218		(22)
Total operating expenses	3,622		3,243		(379)
Gain on sales of assets	—		4		(4)
Operating income	1,062		734		328
Other income and (deductions)
Interest expense, net	(260)		(232)		(28)
Other, net	41		37		4
Total other income and (deductions)	(219)		(195)		(24)
Income before income taxes	843		539		304
Income taxes	29		(12)		(41)
Net income	$	814	$	551	$	263

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

The changes in Operating revenues consisted of the following:

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

Weather. The demand for electricity and natural gas is affected by weather conditions. With respect to the electric business, very warm weather in summer months and, with respect to the electric and natural gas businesses, very cold weather in winter months are referred to as “favorable weather conditions” because these weather conditions result in increased deliveries of electricity and natural gas. Conversely, mild weather reduces demand. For the year ended December 31, 2025, compared to the same period in 2024, Operating revenues related to weather increased due to favorable weather conditions in PECO's service territory.

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

56

PECO

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

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

Electric Retail Deliveries to Customers (in GWhs)	2025	2024	% Change		Weather - Normal % Change(b)
Residential	14,078	13,963	0.8	%	(1.5)	%
Small commercial & industrial	7,537	7,683	(1.9)	%	(3.0)	%
Large commercial & industrial	13,683	13,889	(1.5)	%	(2.2)	%
Public authorities & electric railroads	678	613	10.6	%	11.0	%
Total electric retail deliveries(a)	35,976	36,148	(0.5)	%	(1.9)	%

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

__________

(a)Reflects delivery volumes from customers purchasing electricity directly from PECO and customers purchasing electricity from a competitive electric generation supplier as all customers are assessed distribution charges.

(b)Reflects the change in delivery volumes assuming normalized weather based on the historical 30-year average.

Natural Gas Deliveries to Customers (in mmcf)	2025	2024	% Change		Weather - Normal % Change(b)
Residential	43,189	38,328	12.7	%	1.6	%
Small commercial & industrial	23,709	21,906	8.2	%	0.6	%
Large commercial & industrial	15	17	(11.8)	%	(2.2)	%
Transportation	24,204	23,357	3.6	%	0.7	%
Total natural gas deliveries(a)	91,117	83,608	9.0	%	1.1	%

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

__________

(a)Reflects delivery volumes from customers purchasing natural gas directly from PECO and customers purchasing natural gas from a competitive natural gas supplier as all customers are assessed distribution charges.

(b)Reflects the change in delivery volumes assuming normalized weather based on the historical 30-year average.

Pricing for the year ended December 31, 2025, compared to the same period in 2024, increased primarily due to electric and gas distribution rates charged to customers.

57

PECO

Transmission Revenue. Under a FERC-approved formula, transmission revenue varies from year to year based upon fluctuations in the underlying costs and capital investments being recovered. Transmission revenue for the year ended December 31, 2025, compared to the same period in 2024, remained relatively consistent.

Other Revenue primarily includes revenue related to late payment charges. Other revenues for the year ended December 31, 2025, compared to the same period in 2024, increased primarily due to revenue related to late payment charges.

Regulatory Required Programs represent revenues collected under approved riders to recover costs incurred for regulatory programs such as energy efficiency, PGC, TSC, and the GSA. The riders are designed to provide full and current cost recovery, and in some cases, a return. The costs of these programs are included in Purchased power and fuel expense, Operating and maintenance expense, Depreciation and amortization expense, and Income taxes. Customers have the choice to purchase electricity and natural gas from competitive electric generation and natural gas suppliers. Customer choice programs do not impact the volume of deliveries as PECO remains the distribution service provider for all customers and charges a regulated rate for distribution service, which is recorded in Operating revenues. For customers that choose to purchase electric generation or natural gas from competitive suppliers, PECO either acts as the billing agent or the competitive supplier separately bills its own customers and therefore PECO does not record Operating revenues or Purchased power and fuel expense related to the electricity and/or natural gas. For customers that choose to purchase electric generation or natural gas from PECO, PECO is permitted to recover the electricity, natural gas, and REC procurement costs without mark-up and therefore records equal and offsetting amounts in Operating revenues and Purchased power and fuel expense related to the electricity, natural gas, and RECs.

See Note 4 — Segment Information of the Combined Notes to Consolidated Financial Statements for the presentation of PECO's revenue disaggregation.

The increase of $256 million for the year ended December 31, 2025, compared to the same period in 2024, in Purchased power and fuel expense is fully offset in Operating revenues as part of regulatory required programs.

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

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

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

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

__________

(a)Depreciation and amortization expense increased primarily due to ongoing capital expenditures.

Taxes other than income taxes increased by $22 million for the year ended December 31, 2025, compared to the same period in 2024, primarily due to higher Pennsylvania gross receipts tax.

58

PECO

Interest expense, net increased $28 million for the year ended December 31, 2025, compared to the same period in 2024, primarily due to an increase in interest rates and the issuance of debt in 2025.

Effective income tax rates were 3.4% and (2.2)% for the years ended December 31, 2025 and 2024, respectively. See Note 11 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the effective income tax rates.

59

BGE

Results of Operations—BGE

	2025		2024		Favorable (Unfavorable) Variance
Operating revenues	$	5,222	$	4,426	$	796
Operating expenses
Purchased power and fuel	2,221		1,651		(570)
Operating and maintenance	1,066		1036		(30)
Depreciation and amortization	632		638		6
Taxes other than income taxes	370		345		(25)
Total operating expenses	4,289		3,670		(619)
Operating income	933		756		177
Other income and (deductions)
Interest expense, net	(247)		(216)		(31)
Other, net	51		36		15
Total other income and (deductions)	(196)		(180)		(16)
Income before income taxes	737		576		161
Income taxes	159		49		(110)
Net income	$	578	$	527	$	51

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

The changes in Operating revenues consisted of the following:

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

60

BGE

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

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

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

Distribution Revenue increased for the year ended December 31, 2025 compared to the same period in 2024, due to favorable impacts of the multi-year plans.

Transmission Revenue. Under a FERC-approved formula, transmission revenue varies from year to year based upon fluctuations in the underlying costs and capital investments being recovered. Transmission revenue increased for the year ended December 31, 2025 compared to the same period in 2024 primarily due to increases in underlying costs and capital investments.

Other Revenue includes revenue related to late payment charges, mutual assistance, off-system sales, and service application fees. Other Revenue increased for the year ended December 31, 2025 compared to the same period in 2024, primarily driven by an increase in service application fees.

Regulatory Required Programs represent revenues collected under approved riders to recover costs incurred for regulatory programs such as conservation, demand response, and the POLR mechanism. The riders are designed to provide full and current cost recovery, as well as a return in certain instances. The costs of these programs are included in Purchased power and fuel expense, Operating and maintenance expense, Depreciation and amortization expense, and Taxes other than income taxes. Customers have the choice to purchase electricity and natural gas from competitive electric generation and natural gas suppliers. Customer choice programs do not impact the volume of deliveries as BGE remains the distribution service provider for all customers and charges a regulated rate for distribution service, which is recorded in Operating revenues. For customers that choose to purchase electric generation or natural gas from competitive suppliers, BGE acts as the billing agent and therefore does not record Operating revenues or Purchased power and fuel expense related to the electricity and/or natural gas. For customers that choose to purchase electric generation or natural gas from BGE, BGE is permitted to recover the electricity and natural gas procurement costs from customers and therefore records the amounts related to the electricity and/or natural gas in Operating revenues and Purchased power and fuel expense. BGE recovers electricity and natural gas procurement costs from customers with a slight mark-up.

See Note 4 — Segment Information of the Combined Notes to Consolidated Financial Statements for the presentation of BGE's revenue disaggregation.

The increase of $570 million for the year ended December 31, 2025 compared to the same period in 2024 in Purchased power and fuel expense is fully offset in Operating revenues as part of regulatory required programs.

61

BGE

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

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

__________

(a)See Note 2 — Regulatory Matters for additional information on the multi-year plan reconciliation.

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

(c)Reflects the cost recovery associated with EmPOWER Maryland. See Note 2 — Regulatory Matters for additional information.

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

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

__________

(a)Reflects the cost recovery associated with EmPOWER Maryland. See Note 2 — Regulatory Matters for additional information.

Taxes other than income taxes increased by $25 million for the year ended December 31, 2025 compared to the same period in 2024, primarily due to increased property taxes.

Interest expense, net increased $31 million for the year ended December 31, 2025 compared to the same period in 2024, primarily due to the issuance of debt in the second quarter of 2025.

Other, net increased by $15 million for the year ended December 31, 2025 compared to the same period in 2024, primarily due to increased interest income and higher AFUDC equity.

Effective income tax rates were 21.6% and 8.5% for the years ended December 31, 2025 and 2024, respectively. See Note 11 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the effective income tax rates.

62

PHI

Results of Operations—PHI

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

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

__________

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

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

63

Pepco

Results of Operations—Pepco

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

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

The changes in Operating revenues consisted of the following:

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

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

64

Pepco

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

Distribution Revenue increased for the year ended December 31, 2025 compared to the same period in 2024, primarily due to the favorable impacts of the Maryland and District of Columbia multi-year plans and customer growth in Maryland.

Transmission Revenue. Under a FERC-approved formula, transmission revenue varies from year to year based upon fluctuations in the underlying costs and capital investments being recovered. Transmission revenue increased for the year ended December 31, 2025 compared to the same period in 2024 primarily due to increases in underlying costs and capital investment.

Other Revenue includes rental revenue, revenue related to late payment charges, mutual assistance revenues, and recoveries of other taxes.

Regulatory Required Programs represent revenues collected under approved riders to recover costs incurred for regulatory programs such as energy efficiency programs, DC PLUG, and SOS procurement and administrative costs. The riders are designed to provide full and current cost recovery as well as a return in certain instances. The costs of these programs are included in Purchased power expense, Operating and maintenance expense, Depreciation and amortization expense, and Taxes other than income taxes. Customers have the choice to purchase electricity from competitive electric generation suppliers. Customer choice programs do not impact the volume of deliveries, as Pepco remains the distribution service provider for all customers and charges a regulated rate for distribution service, which is recorded in Operating revenues. For customers that choose to purchase electric generation from competitive suppliers, Pepco acts as the billing agent and therefore, Pepco does not record Operating revenues or Purchased power expense related to the electricity. For customers that choose to purchase electric generation from Pepco, Pepco is permitted to recover the electricity and REC procurement costs from customers and therefore records the amounts related to the electricity and RECs in Operating revenues and Purchased power expense. Pepco recovers electricity and REC procurement costs from customers with a slight mark-up.

See Note 4 — Segment Information of the Combined Notes to Consolidated Financial Statements for the presentation of Pepco's revenue disaggregation.

The increase of $207 million for the year ended December 31, 2025 compared to the same period in 2024, in Purchased power expense is fully offset in Operating revenues as part of regulatory required programs.

65

Pepco

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

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

__________

(a)See Note 2 — Regulatory Matters for additional information on multi-year plan reconciliations.

(b)Reflects the cost recovery associated with EmPOWER Maryland. Please refer to Note 2 — Regulatory Matters for additional information.

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

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

__________

(a)Depreciation and amortization increased primarily due to ongoing capital expenditures.

(b)Reflects the cost recovery associated with EmPOWER Maryland. Please refer to Note 2 — Regulatory Matters for additional information.

Taxes other than income taxes increased $31 million for the year ended December 31, 2025 compared to the same period in 2024, primarily due to increases in utility taxes, which are offset in revenues, and property taxes.

Interest expense, net increased $22 million for the year ended December 31, 2025 compared to the same period in 2024 primarily due to an increase in interest rates and the issuance of debt in 2025.

Other, net decreased $13 million for the year ended December 31, 2025 compared to the same period in 2024, primarily due to lower AFUDC equity.

Effective income tax rates were 20.9% and 18.8% for the years ended December 31, 2025 and 2024, respectively. See Note 11 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the effective income tax rates.

66

DPL

Results of Operations—DPL

	2025		2024		Favorable (Unfavorable) Variance
Operating revenues	$	1,971	$	1,787	$	184
Operating expenses
Purchased power and fuel	861		760		(101)
Operating and maintenance	391		377		(14)
Depreciation and amortization	252		245		(7)
Taxes other than income taxes	88		79		(9)
Total operating expenses	1,592		1,461		(131)
Operating income	379		326		53
Other income and (deductions)
Interest expense, net	(102)		(93)		(9)
Other, net	16		25		(9)
Total other income and (deductions)	(86)		(68)		(18)
Income before income taxes	293		258		35
Income taxes	69		49		(20)
Net income	$	224	$	209	$	15

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

The changes in Operating revenues consisted of the following:

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

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

Weather. The demand for electricity and natural gas in Delaware is affected by weather conditions. With respect to the electric business, very warm weather in summer months and, with respect to the electric and natural gas businesses, very cold weather in winter months are referred to as "favorable weather conditions” because these weather conditions result in increased deliveries of electricity and natural gas. Conversely, mild weather reduces demand. During the year ended December 31, 2025 compared to the same period in 2024, Operating revenues

67

DPL

related to weather increased due to favorable weather conditions in DPL's Delaware electric and natural gas service territories.

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

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

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

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

Electric Retail Deliveries to Delaware Customers (in GWhs)	2025	2024	% Change		Weather - Normal % Change (b)
Residential	3,288	3,227	1.9	%	(1.4)	%
Small commercial & industrial	1,459	1,445	1.0	%	0.2	%
Large commercial & industrial	3,049	3,019	1.0	%	0.6	%
Public authorities & electric railroads	31	32	(3.1)	%	(3.5)	%
Total electric retail deliveries(a)	7,827	7,723	1.3	%	(0.3)	%

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

__________

(a)Reflects delivery volumes from customers purchasing electricity directly from DPL and customers purchasing electricity from a competitive electric generation supplier as all customers are assessed distribution charges.

(b)Reflects the change in delivery volumes assuming normalized weather based on the historical 20-year average.

Natural Gas Retail Deliveries to Delaware Customers (in mmcf)	2025	2024	% Change		Weather - Normal % Change(b)
Residential	9,052	7,810	15.9	%	7.5	%
Small commercial & industrial	4,339	3,801	14.2	%	5.5	%
Large commercial & industrial	1,680	1,674	0.4	%	0.4	%
Transportation	6,355	6,206	2.4	%	(0.3)	%
Total natural gas deliveries(a)	21,426	19,491	9.9	%	4.1	%

68

DPL

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

__________

(a)Reflects delivery volumes from customers purchasing natural gas directly from DPL and customers purchasing natural gas from a competitive natural gas supplier as all customers are assessed distribution charges.

(b)Reflects the change in delivery volumes assuming normalized weather based on the historical 30-year average.

Distribution Revenue increased for the year ended December 31, 2025 compared to the same period in 2024 primarily due to Delaware electric DSIC rates and natural gas rates that became effective in 2025.

Transmission Revenue. Under a FERC-approved formula, transmission revenue varies from year to year based upon fluctuations in the underlying costs and capital investments being recovered. Transmission revenue increased for the year ended December 31, 2025 compared to the same period in 2024 primarily due to increases in underlying costs and capital investment.

Other Revenue includes rental revenue, revenue related to late payment charges, mutual assistance revenues, and recoveries of other taxes.

Regulatory Required Programs represent revenues collected under approved riders to recover costs incurred for regulatory programs such as energy efficiency programs, DE Renewable Portfolio Standards, SOS procurement and administrative costs, and GCR costs. The riders are designed to provide full and current cost recovery as well as a return in certain instances. The costs of these programs are included in Purchased power and fuel expense, Operating and maintenance expense, Depreciation and amortization expense, and Taxes other than income taxes. All customers have the choice to purchase electricity from competitive electric generation suppliers; however, only certain commercial and industrial customers have the choice to purchase natural gas from competitive natural gas suppliers. Customer choice programs do not impact the volume of deliveries as DPL remains the distribution service provider for all customers and charges a regulated rate for distribution service, which is recorded in Operating revenues. For customers that choose to purchase electric generation or natural gas from competitive suppliers, DPL either acts as the billing agent or the competitive supplier separately bills its own customers, and therefore does not record Operating revenues or Purchased power and fuel expense related to the electricity and/or natural gas. For customers that choose to purchase electric generation or natural gas from DPL, DPL is permitted to recover the electricity, natural gas, and REC procurement costs from customers and therefore records the amounts related to the electricity, natural gas, and RECs in Operating revenues and Purchased power and fuel expense. DPL recovers electricity and REC procurement costs from customers with a slight mark-up, and natural gas costs without mark-up.

See Note 4 — Segment Information of the Combined Notes to Consolidated Financial Statements for the presentation of DPL's revenue disaggregation.

The increase of $101 million for the year ended December 31, 2025 compared to the same period in 2024, in Purchased power and fuel expense is fully offset in Operating revenues as part of regulatory required programs.

69

DPL

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

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

__________

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

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

	2025 vs. 2024
	Increase (Decrease)
Depreciation and amortization(a)	$	8
Regulatory asset amortization	(1)
Total increase	$	7

__________

(a)Depreciation and amortization increased primarily due to ongoing expenditures.

Taxes other than income taxes increased by $9 million for the year ended December 31, 2025 compared to the same period in 2024, primarily due to an increase in property taxes.

Interest expense, net increased $9 million for the year ended December 31, 2025 compared to the same period in 2024 primarily due to an increase in interest rates and the issuance of debt in 2025.

Other, net decreased by $9 million for the year ended December 31, 2025 compared to the same period in 2024, primarily due to lower AFUDC equity and a decrease in interest income.

Effective income tax rates were 23.5% and 19.0% for the years ended December 31, 2025 and 2024, respectively. See Note 11 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the change in effective income tax rates.

70

ACE

Results of Operations—ACE

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

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

The changes in Operating revenues consisted of the following:

	2025 vs. 2024
	Increase
Distribution	$	6
Other	3
	9
Regulatory required programs	81
Total increase	$	90

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

71

ACE

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

Distribution Revenue increased for the year ended December 31, 2025 compared to the same period in 2024 primarily due to distribution rates and an increase in customer growth.

Transmission Revenue. Under a FERC-approved formula, transmission revenue varies from year to year based upon fluctuations in the underlying costs and capital investments being recovered. Transmission revenue remained relatively consistent for the year ended December 31, 2025 compared to the same period in 2024.

Other Revenue includes rental revenue, revenue related to late payment charges, mutual assistance revenues, and recoveries of other taxes.

Regulatory Required Programs represent revenues collected under approved riders to recover costs incurred for regulatory programs such as energy efficiency programs, Societal Benefits Charge, Transition Bonds, and BGS procurement and administrative costs. The riders are designed to provide full and current cost recovery as well as a return in certain instances. The costs of these programs are included in Purchased power expense, Operating and maintenance expense, Depreciation and amortization expense, and Taxes other than income taxes. Customers have the choice to purchase electricity from competitive electric generation suppliers. Customer choice programs do not impact the volume of deliveries, as ACE remains the distribution service provider for all customers and charges a regulated rate for distribution service, which is recorded in Operating revenues. For customers that choose to purchase electric generation from competitive suppliers, ACE acts as the billing agent and therefore, ACE does not record Operating revenues or Purchased power expense related to the electricity. For customers that choose to purchase electric generation from ACE, ACE is permitted to recover the electricity, ZEC, and REC procurement costs without mark-up and therefore records equal and offsetting amounts in Operating revenues and Purchased power expense related to the electricity, ZECs, and RECs.

See Note 4 – Segment Information of the Combined Notes to Consolidated Financial Statements for the presentation of ACE's revenue disaggregation.

The increase of $110 million for the year ended December 31, 2025 compared to same period in 2024, in Purchased power expense is fully offset in Operating revenues as part of regulatory required programs.

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

	2025 vs. 2024
	Increase (Decrease)
Storm-related costs	$	3
BSC and PHISCO costs	(10)
Labor, other benefits, contracting and materials(a)	(33)
Other	(1)
	(41)
Regulatory required programs	1
Total decrease	$	(40)

__________

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

72

ACE

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

	2025 vs. 2024
	Increase (Decrease)
Depreciation and amortization(a)	$	12
Regulatory asset amortization	(11)
Regulatory required programs(b)	(31)
Total decrease	$	(30)

__________

(a)Depreciation and amortization increased primarily due to ongoing capital expenditures.

(b)Regulatory required programs decreased primarily due to the absence of the regulatory asset amortization of the PPA termination obligation, which was fully amortized in 2024.

Interest expense, net increased $3 million for the year ended December 31, 2025 compared to the same period in 2024 primarily due to an increase in interest rates and the issuance of debt in 2025.

Effective income tax rates were 26.3% and 26.2% for the years ended December 31, 2025 and 2024, respectively. See Note 11 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the effective income tax rates.

Liquidity and Capital Resources

All results included throughout the liquidity and capital resources section are presented on a GAAP basis.

The Registrants’ operating and capital expenditure requirements are provided by internally generated cash flows from operations, as well as funds from external sources in the capital markets and through bank borrowings. The Registrants’ businesses are capital intensive and require considerable capital resources. Each of the Registrants annually evaluates its financing plan, dividend practices, and credit line sizing, focusing on maintaining its investment grade ratings while meeting its cash needs to fund capital requirements, including construction expenditures, retire debt, pay dividends, and fund pension and OPEB obligations. The Registrants spend a significant amount of cash on capital improvements and construction projects that have a long-term return on investment. Additionally, the Utility Registrants operate in rate-regulated environments in which the amount of new investment recovery may be delayed or limited and where such recovery takes place over an extended period of time. Each Registrant’s access to external financing on reasonable terms depends on its credit ratings and current overall capital market business conditions, including that of the utility industry in general. If these conditions deteriorate to the extent that the Registrants no longer have access to the capital markets at reasonable terms, the Registrants have access to credit facilities with aggregate bank commitments of $4 billion, as of December 31, 2025. The Registrants utilize their credit facilities to support their commercial paper programs, provide for other short-term borrowings, and to issue letters of credit. See the “Credit Matters and Cash Requirements” section below for additional information. The Registrants expect cash flows to be sufficient to meet operating expenses, financing costs, and capital expenditure requirements. See Note 14 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information on the Registrants’ debt and credit agreements.

Cash Flows from Operating Activities

The Utility Registrants' cash flows from operating activities primarily result from the transmission and distribution of electricity and, in the case of PECO, BGE, and DPL, gas distribution services. The Utility Registrants' distribution services are provided to an established and diverse base of retail customers. The Utility Registrants' future cash flows may be affected by the economy, weather conditions, future legislative initiatives, future regulatory proceedings with respect to their rates or operations, and their ability to achieve operating cost reductions. Additionally, ComEd is required to purchase CMCs from participating nuclear-powered generating facilities for a five-year period, and all of its costs of doing so is recovered through a rider. The price to be paid for each CMC is established through a competitive bidding process. ComEd will provide net payments to, or collect net payments from, customers for the difference between customer credits issued and the credit to be received from the participating nuclear-powered generating facilities. ComEd’s cash flows are affected by the establishment of CMC prices and the timing of recovering costs through the CMC regulatory liability.

73

See Note 2 — Regulatory Matters and Note 16 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for additional information on regulatory and legal proceedings and proposed legislation.

The following table provides a summary of the change in cash flows from operating activities for the years ended December 31, 2025 and 2024 by Registrant:

Increase (decrease) in cash flows from operating activities	Exelon		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Net income (loss)	$	308	$	81	$	263	$	51	$	58	$	11	$	15	$	33
Adjustments to reconcile net income to cash:
Non-cash operating activities	1,058		617		43		207		98		131		40		(56)
Collateral (paid) received, net	(43)		(66)		6		5		17		12		—		5
Income taxes	125		113		359		223		26		(3)		40		14
Pension and non-pension postretirement benefit contributions	(162)		(184)		(9)		(7)		36		—		2		5
Regulatory assets and liabilities, net	206		260		(60)		(13)		31		(8)		16		26
Changes in working capital and other noncurrent assets and liabilities	(807)		(869)		47		(132)		(78)		(102)		(35)		74
Increase (decrease) in cash flows from operating activities	$	685	$	(48)	$	649	$	334	$	188	$	41	$	78	$	101

Changes in the Registrants' cash flows from operations were generally consistent with changes in each Registrant’s respective results of operations, as adjusted by changes in working capital in the normal course of business, except as discussed below. Significant operating cash flow impacts for the Registrants for the years ended December 31, 2025 and 2024 were as follows:

•See Note 20 —Supplemental Financial Information of the Combined Notes to Consolidated Financial Statements and the Registrants’ Consolidated Statements of Cash Flows for additional information on non-cash operating activities.

•Changes in collateral depended upon whether the Registrant was in a net mark-to-market liability or asset position and whether collateral may have been required to be posted with or collected from its counterparties. In addition, the collateral posting and collection requirements differed depending on whether the transactions were on an exchange or in the over-the-counter markets. Changes in collateral for the Utility Registrants are dependent upon the credit exposure of procurement contracts that may require suppliers to post collateral. The amount of cash collateral received from external counterparties remained relatively consistent due to stable energy prices. See Note 13 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information.

•See Note 11 — Income Taxes of the Combined Notes to Consolidated Financial Statements and the Registrants' Consolidated Statements of Cash Flows for additional information on income taxes.

•Changes in Pension and non-pension postretirement benefit contributions relate to Exelon's increased contributions to the Qualified Plans during the year ended December 31, 2025. See Note 14 — Retirement Benefits

•Changes in Regulatory assets and liabilities, net, are due to the timing of cash payments for costs recoverable, or cash receipts for costs recovered, under our regulatory mechanisms differing from the recovery period of those costs. ComEd recognized changes of $849 million and $493 million related to carbon mitigation credits for the years ended December 31, 2025 and 2024, respectively. Included within the change in 2025 is an $804 million adjustment for CMC nuclear production tax credits, which is offset by an increase in Accounts receivable. See Note 2 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information. ComEd's energy efficiency program recognized changes of $447 million and $435 million for the years ended December 31, 2025 and 2024, respectively. Additionally, ComEd recognized changes in the distributed generation rebates program of $83 million and $74 million for the years ended December 31, 2025 and 2024, respectively. Also included within the changes is

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energy efficiency and demand response programs spend for BGE, Pepco, DPL, and ACE of $85 million, $41 million, $16 million, and $55 million for the year ended December 31, 2025, respectively, and $127 million, $52 million, $21 million, and $37 million for the year ended December 31, 2024, respectively. PECO had no energy efficiency and demand response programs spend recorded to a regulatory asset for the years ended December 31, 2025 and 2024.

•Changes in working capital and other noncurrent assets and liabilities for the Utility Registrants and Exelon Corporate total $(1,017) million and $(807) million. The change in working capital and other noncurrent assets and liabilities for Exelon Corporate and the Utility Registrants is dependent upon the normal course of operations for all Registrants. For ComEd, it is also dependent upon whether the participating nuclear-powered generating facilities owe money to ComEd as a result of the established pricing for CMCs. For the year ended December 31, 2025, the established pricing resulted in nuclear-powered generating facilities owing payments to ComEd primarily due to $804 million of nuclear production tax credits, which is reported within the cash flows from operations as a change in Accounts receivable. This change is offset by an increase in the Carbon mitigation credit regulatory liability. See Note 2 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.

Cash Flows from Investing Activities

The following table provides a summary of the change in cash flows from investing activities for the years ended December 31, 2025 and 2024 by Registrant:

(Decrease) increase in cash flows from investing activities	Exelon		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Capital expenditures	$	(1,432)	$	(704)	$	(314)	$	(237)	$	(193)	$	(28)	$	22	$	(17)
Proceeds from sales of assets	(34)		—		—		—		4		2		—		2
Other investing activities	(17)		(1)		(3)		(3)		—		—		—		—
(Decrease) increase in cash flows from investing activities	$	(1,483)	$	(705)	$	(317)	$	(240)	$	(189)	$	(26)	$	22	$	(15)

Significant investing cash flow impacts for the Registrants for 2025 and 2024 were as follows:

•Variances in Capital expenditures are primarily due to the timing of cash expenditures for capital projects. See the "Credit Matters and Cash Requirements" section below for additional information on projected capital expenditure spending for the Registrants.

Cash Flows from Financing Activities

The following table provides a summary of the change in cash flows from financing activities for the years ended December 31, 2025 and 2024 by Registrant:

Increase (decrease) in cash flows from financing activities	Exelon		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Changes in short-term borrowings, net	$	(583)	$	530	$	(219)	$	(14)	$	(54)	$	35	$	(64)	$	(25)
Long-term debt, net	1,347		175		125		(150)		(17)		—		(17)		—
Changes in intercompany money pool	—		—		—		—		19		—		—		—
Issuance of common stock	543		—		—		—		—		—		—		—
Dividends paid on common stock	(93)		(37)		(146)		(25)		—		32		18		(56)
Distributions to member	—		—		—		—		(4)		—		—		—
Contributions from parent/member	—		164		(18)		294		63		(67)		(53)		13
Other financing activities	8		6		(3)		1		13		10		(2)		(1)
Increase (decrease) in cash flows from financing activities	$	1,222	$	838	$	(261)	$	106	$	20	$	10	$	(118)	$	(69)

Significant financing cash flow impacts for the Registrants for 2025 and 2024 were as follows:

•Changes in short-term borrowings, net, is driven by repayments on and issuances of notes due in less than 365 days. Refer to Note 14 — Debt and Credit Agreements of the Combined Notes to

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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 is driven by the issuance of Exelon common stock under the ATM program in 2025 compared to 2024. See Note 17 — Shareholders' Equity of the Combined Notes to Consolidated Financial Statements for additional information.

•Exelon’s ability to pay dividends on its Common stock depends on the receipt of dividends paid by its operating subsidiaries. The payments of dividends to Exelon by its subsidiaries in turn depend on their results of operations and cash flows and other items affecting Retained earnings. See Note 16 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for additional information on dividend restrictions. See below for quarterly dividends declared.

•Other financing activities primarily consists of debt issuance costs. See the debt issuances table below for additional information on the Registrants’ debt issuances.

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Debt Issuances and Redemptions

See Note 14 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information of the Registrants’ long-term debt. The Registrants' debt activities for 2025 and 2024 was as follows:

During 2025, the following long-term debt was issued:

Company	Type	Interest Rate	Maturity	Amount	Use of Proceeds
Exelon	Junior Subordinated Notes(a)	6.50%	March 15, 2055	$1,000	Repay outstanding commercial paper obligations and for general corporate purposes.
Exelon	Notes	5.125%	March 15, 2031	500	Repay outstanding commercial paper obligations and for general corporate purposes.
Exelon	Notes	5.875%	March 15, 2055	500	Repay outstanding commercial paper obligations and for general corporate purposes.
Exelon	Convertible Senior Notes	3.25%	March 15, 2029	1,000	Repay or refinance debt and for general corporate purposes.
ComEd	First Mortgage Bonds	5.95%	June 1, 2055	725	Repay outstanding commercial paper obligations and for general corporate purposes.
PECO	First Mortgage Bonds	4.875%	September 15, 2035	525	Repay existing indebtedness, repay outstanding commercial paper obligations, and for general corporate purposes.
PECO	First Mortgage Bonds	5.65%	September 15, 2055	525	Repay existing indebtedness, repay outstanding commercial paper obligations, and for general corporate purposes.
BGE	Notes	5.45%	June 1, 2035	650	Repay outstanding commercial paper obligations and for general corporate purposes.
Pepco	First Mortgage Bonds	5.78%	September 17, 2055	75	Repay existing indebtedness and for general corporate purposes.
Pepco	First Mortgage Bonds	5.48%	March 26, 2040	200	Repay existing indebtedness and for general corporate purposes.
DPL	First Mortgage Bonds	5.28%	March 26, 2035	125	Repay existing indebtedness and for general corporate purposes.
ACE	First Mortgage Bonds	5.28%	March 26, 2035	100	Repay existing indebtedness and for general corporate purposes.
ACE	First Mortgage Bonds	5.54%	November 19, 2040	75	Repay existing indebtedness and for general corporate purposes.
ACE	First Mortgage Bonds	5.81%	November 19, 2055	75	Repay existing indebtedness and for general corporate purposes.

__________

(a)The Junior Subordinated Notes bear interest at 6.50% per annum, commencing February 19, 2025 to, but excluding March 15, 2035. Thereafter, the interest rate resets every five years on March 15 and will be set at a rate per annum equal to the Five-year U.S. Treasury Rate plus a spread of 1.975%.

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During 2024, the following long-term debt was issued:

Company	Type	Interest Rate	Maturity	Amount	Use of Proceeds
Exelon	Notes	5.15%	March 15, 2029	$650	Repay existing indebtedness and for general corporate purposes.
Exelon	Notes	5.45%	March 15, 2034	650	Repay existing indebtedness and for general corporate purposes.
Exelon	Notes	5.60%	March 15, 2053	400	Repay existing indebtedness and for general corporate purposes.
ComEd	First Mortgage Bonds	5.30%	June 1, 2034	400	Repay outstanding commercial paper obligations and to fund other general corporate purposes.
ComEd	First Mortgage Bonds	5.65%	June 1, 2054	400	Repay outstanding commercial paper obligations and to fund other general corporate purposes.
PECO	First Mortgage Bonds	5.25%	September 15, 2054	575	Refinance existing indebtedness, refinance outstanding commercial paper obligations, and for general corporate purposes.
BGE	Notes	5.30%	June 1, 2034	400	Repay outstanding commercial paper obligations, repay existing indebtedness, and for general corporate purposes.
BGE	Notes	5.65%	June 1, 2054	400	Repay existing indebtedness and for general corporate purposes.
Pepco	First Mortgage Bonds	5.20%	March 15, 2034	375	Repay existing indebtedness and for general corporate purposes.
Pepco	First Mortgage Bonds	5.50%	March 15, 2054	300	Repay existing indebtedness and for general corporate purposes.
Pepco	First Mortgage Bonds	5.24%	March 20, 2034	100	Repay existing indebtedness and for general corporate purposes.
DPL	First Mortgage Bonds	5.55%	March 20, 2054	75	Repay existing indebtedness and for general corporate purposes.
DPL	First Mortgage Bonds	5.55%	March 20, 2054	75	Repay existing indebtedness and for general corporate purposes.
DPL	First Mortgage Bonds	5.29%	August 28, 2034	75	Repay existing indebtedness and for general corporate purposes.
DPL	First Mortgage Bonds	5.49%	August 28, 2039	100	Repay existing indebtedness and for general corporate purposes.

During 2025, the following long-term debt was retired and/or redeemed:

Company	Type	Interest Rate	Maturity	Amount
Exelon	Senior Notes	3.95%	June 15, 2025	$	807
Exelon	Software Licensing Agreement	2.30%	December 1, 2025	4
PECO	First Mortgage Bonds	3.15%	October 15, 2025	350
ACE	Senior Notes	3.50%	December 1, 2025	150

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

Company (a)	Type	Interest Rate	Maturity	Amount
Exelon	SMBC Term Loan Agreement	SOFR plus 0.85%	April 8, 2024	$	500
Exelon	Software Licensing Agreement	3.62%	December 1, 2025	1
Exelon	Software Licensing Agreement	3.95%	May 1, 2024	2
Exelon	Software Licensing Agreement	2.30%	December 1, 2025	4
ComEd	First Mortgage Bonds	3.10%	November 1, 2024	250
Pepco	First Mortgage Bonds	3.60%	March 15, 2024	400
DPL(b)	Unsecured tax-exempt bonds	4.32%	July 1, 2024	33
ACE	First Mortgage Bonds	3.38%	September 1, 2024	150

(a)Exelon repurchased a portion of its Senior unsecured notes during 2024. Refer to Note 14 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information.

(b)Variable interest on the DPL unsecured tax-exempt bonds reset on a weekly basis.

From time to time and as market conditions warrant, the Registrants may engage in long-term debt retirements via tender offers, open market repurchases or other viable options to reduce debt on their respective Balance sheets.

Dividends

Quarterly dividends declared by the Exelon Board of Directors during the year ended December 31, 2025 and for the first quarter of 2026 were as follows:

Period	Declaration Date	Shareholder of Record Date	Dividend Payable Date	Cash per Share(a)
First Quarter 2025	February 12, 2025	February 24. 2025	March 14, 2025	$	0.4000
Second Quarter 2025	April 29, 2025	May 12, 2025	June 13, 2025	$	0.4000
Third Quarter 2025	July 29, 2025	August 11, 2025	September 15, 2025	$	0.4000
Fourth Quarter 2025	October 29, 2025	November 10, 2025	December 15, 2025	$	0.4000
First Quarter 2026	February 12, 2026	March 2, 2026	March 13, 2026	$	0.4200

___________

(a)Exelon's Board of Directors approved an updated dividend policy for 2026. The 2026 quarterly dividend will be $0.42 per share.

Credit Matters and Cash Requirements

The Registrants fund liquidity needs for capital expenditures, working capital, energy hedging, and other financial commitments through cash flows from operations, public debt offerings, commercial paper markets, and large diversified credit facilities. The credit facilities include $4 billion in aggregate total commitments of which $3.3 billion was available to support additional commercial paper as of December 31, 2025, and of which no financial institution has more than 6.2% of the aggregate commitments for the Registrants. During 2025, the Registrants had access to the commercial paper markets and availability under their revolving credit facilities to fund their short-term liquidity needs, when necessary. Exelon Corporate and the Utility Registrants each have a 5-year revolving credit facility. See Note 14 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information. The Registrants routinely review the sufficiency of their liquidity position, including appropriate sizing of credit facility commitments, by performing various stress test scenarios, such as commodity price movements, increases in margin-related transactions, changes in hedging levels, and the impacts of hypothetical credit downgrades. The Registrants closely monitor events in the financial markets and the financial institutions associated with the credit facilities, including monitoring credit ratings and outlooks, credit default swap levels, capital raising, and merger activity. See PART I, ITEM 1A. RISK FACTORS for additional information regarding the effects of uncertainty in the capital and credit markets.

The Registrants believe their cash flow from operating activities, access to credit markets, and their credit facilities provide sufficient liquidity to support the estimated future cash requirements discussed below.

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On August 4, 2022, Exelon executed an equity distribution agreement (“2022 Equity Distribution Agreement”), with certain sales agents and forward sellers and certain forward purchasers, establishing an ATM equity distribution program under which it may offer and sell shares of its Common stock, having an aggregate gross sales price of up to $1 billion through August 3, 2025. On May 2, 2025, Exelon executed an additional equity distribution agreement ("2025 Equity Distribution Agreement" and, together with the August 4, 2022 Equity Distribution Agreement, "Equity Distribution Agreements"), with certain sales agents and forward sellers and certain forward purchasers, establishing an ATM equity distribution program which it may offer and sell shares of its Common stock, having an aggregate gross sales price of up to $2.5 billion through May 2, 2028. The 2025 Equity Distribution Agreement replaced the 2022 Equity Distribution Agreement. Exelon has no obligation to offer or sell any shares of Common stock under the 2025 Equity Distribution Agreement and may, at any time, suspend or terminate offers and sales under the 2025 Equity Distribution Agreement. Exelon issued a total of 23.6 million shares of common stock with net proceeds of $979 million under these agreements in the years ended December 31, 2023 through December 31, 2025.

In addition, during the twelve months ended December 31, 2025, Exelon entered into various forward sale agreements under the 2025 ATM programs. The forward sale agreements require Exelon to, at its election prior to the maturity date, either (i) physically settle the transactions by issuing shares of its Common stock to the forward counterparties in exchange for net proceeds at the then-applicable forward sale price specified by the agreements or (ii) net settle the transactions in whole or in part through the delivery to the forward counterparties or receipt from the forward counterparties of cash or shares in accordance with the provisions of the agreements.

No amounts have been or will be recorded on Exelon's Balance sheets with respect to the equity offerings until the equity forward sale agreements have been settled. Each initial forward sale price is subject to adjustment on a daily basis based on a floating interest rate factor and will decrease by other fixed amounts specified in the agreements. Until settlement of the equity forward, earnings per share dilution resulting from the agreement, if any, will be determined under the treasury stock method. For the twelve months ended December 31, 2025, approximately 15.4 million shares under the forward sale agreements were not included in the calculation of diluted earnings per share because their effect would have been antidilutive.

Inclusive of the impact of the forward sale agreements, $1.5 billion of Common stock remained available for sale pursuant to the ATM program as of December 31, 2025.

See Note 17 — Shareholders' Equity of the Combined Notes to the Consolidated Financial Statements for additional information regarding ATM program terms, forward sale agreements, and share-level activity.

The following table presents the incremental collateral that each Utility Registrant would have been required to provide in the event each Utility Registrant lost its investment grade credit rating at December 31, 2025 and available credit facility capacity prior to any incremental collateral at December 31, 2025:

	PJM Credit Policy Collateral		Other Incremental Collateral Required(a)		Available Credit Facility Capacity Prior to Any Incremental Collateral
ComEd	$	27	$	—	$	985
PECO	—		58		595
BGE	—		43		575
Pepco	4		—		55
DPL	1		14		139
ACE	—		—		92

__________

(a)Represents incremental collateral related to natural gas procurement contracts.

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Capital Expenditures

As of December 31, 2025, estimates of future capital expenditures for plant additions and improvements were as follows:

(in millions)(a)	2026 Transmission	2026 Distribution	2026 Gas	Total 2026		Beyond 2026(b)
Exelon	N/A	N/A	N/A	$	9,950	$	31,300
ComEd	1,100	2,425	N/A	3,500		11,450
PECO	450	1,375	400	2,225		7,075
BGE	1,075	575	525	2,175		6,100
PHI	725	1,250	50	2,050		6,650
Pepco	325	650	N/A	975		2,925
DPL	225	325	50	625		2,175
ACE	175	275	N/A	450		1,550

___________

(a)Numbers rounded to the nearest $25M and may not sum due to rounding.

(b)Includes estimated capital expenditures for the Utility Registrants from 2027 to 2029.

Projected capital expenditures and other investments are subject to periodic review and revision to reflect changes in economic conditions and other factors. Projected capital expenditures at the Utility Registrants are for continuing projects to maintain and improve operations, including enhancing reliability and adding capacity to the transmission and distribution systems. The Utility Registrants anticipate that they will fund their capital expenditures with a combination of internally generated funds and borrowings and additional capital contributions from parent.

Retirement 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 $325 million in 2026. Unlike the qualified pension plans, Exelon’s non-qualified pension plans are not funded, given that they are not subject to statutory minimum contribution requirements.

While OPEB plans are also not subject to statutory minimum contribution requirements, Exelon does fund certain of its plans. For Exelon's funded OPEB plans, contributions generally equal accounting costs, however, Exelon’s management has historically considered several factors in determining the level of contributions to its OPEB plans, including liabilities management, levels of benefit claims paid, and regulatory implications (amounts deemed prudent to meet regulatory expectations and best assure continued rate recovery). The amounts below include benefit payments related to unfunded plans.

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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 2026:

	Qualified Pension Plans		Non-Qualified Pension Plans		OPEB
Exelon	$	325	$	19	$	48
ComEd	217		3		22
PECO	9		1		4
BGE	32		2		14
PHI	48		7		6
Pepco	1		—		6
DPL	1		—		—
ACE	14		—		—

To the extent interest rates decline significantly or the pension and OPEB plans earn less than the expected asset returns, annual pension contribution requirements in future years could increase. Conversely, to the extent interest rates increase significantly or the pension and OPEB plans earn greater than the expected asset returns, annual pension and OPEB contribution requirements in future years could decrease. Additionally, expected contributions could change if Exelon changes its pension or OPEB funding strategy.

See Note 12 — Retirement Benefits of the Combined Notes to Consolidated Financial Statements for additional information on pension and OPEB contributions.

Cash Requirements for Other Financial Commitments

The following tables summarize the Registrants' future estimated cash payments as of December 31, 2025 under existing financial commitments:

Exelon

	2026		Beyond 2026		Total		Time Period
Long-term debt and finance leases(a)	$	1,665	$	47,763	$	49,428	2026 - 2055
Interest payments on long-term debt(b)	1,932		31,796		33,728		2026 - 2055
Operating leases	26		187		213		2026 - 2099
Fuel purchase agreements(c)	321		1,293		1,614		2026 - 2039
Electric supply procurement	4,259		2,733		6,992		2026 - 2029
Long-term renewable energy and REC commitments	290		7,716		8,006		2026 - 2044
ZEC commitments	156		62		218		2026 - 2027
Pension contributions(d)	325		1,625		1,950		2026 - 2031
Other purchase obligations(e)	9,526		5,303		14,829		2026 - 2035
Total cash requirements	$	18,500	$	98,478	$	116,978

__________

(a)Includes amounts from ComEd and PECO financing trusts.

(b)Interest payments are estimated based on final maturity dates of debt securities outstanding as of December 31, 2025 and do not reflect anticipated future refinancing, early redemptions, or debt issuances. Variable rate interest obligations are estimated based on rates as of December 31, 2025. Includes estimated interest payments due to ComEd and PECO financing trusts.

(c)Represents commitments to purchase natural gas and related transportation, storage capacity, and services.

(d)These amounts represent Exelon’s expected contributions to its qualified pension plans. Qualified pension contributions for years after 2031 are not included.

(e)Represents the future estimated value at December 31, 2025 of the cash flows associated with all contracts, both cancellable and non-cancellable, entered into between the Registrants and third-parties for the provision of services and materials, entered into in the normal course of business, and not specifically reflected elsewhere in this table. These estimates are subject to significant variability from period to period.

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ComEd

	2026		Beyond 2026		Total		Time Period
Long-term debt(a)	$	500	$	12,592	$	13,092	2026 - 2055
Interest payments on long-term debt(b)	507		9,880		10,387		2026 - 2055
Electric supply procurement	286		273		559		2026 - 2028
Long-term renewable energy and REC commitments	268		7,606		7,874		2026 - 2044
ZEC commitments	156		62		218		2026 - 2027
Other purchase obligations(c)	2,093		1,076		3,169		2026 - 2034
Total cash requirements	$	3,810	$	31,489	$	35,299

__________

(a)Includes amounts from ComEd financing trust.

(b)Interest payments are estimated based on final maturity dates of debt securities outstanding as of December 31, 2025 and do not reflect anticipated future refinancing, early redemptions, or debt issuances. Includes estimated interest payments due to the ComEd financing trust.

(c)Represents the future estimated value, as of December 31, 2025, of the cash flows associated with all contracts, both cancellable and non-cancellable, entered into between ComEd and third-parties for the provision of services and materials, entered into in the normal course of business, and not specifically reflected elsewhere in this table. These estimates are subject to significant variability from period to period.

PECO

	2026		Beyond 2026		Total		Time Period
Long-term debt(a)	$	—	$	6,659	$	6,659	2026 - 2055
Interest payments on long-term debt(b)	266		5,895		6,161		2026 - 2055
Operating leases	1		—		1		2026 - 2035
Fuel purchase agreements(c)	156		578		734		2026 - 2039
Electric supply procurement	767		177		944		2026 - 2027
Other purchase obligations(d)	1,774		632		2,406		2026 - 2035
Total cash requirements	$	2,964	$	13,941	$	16,905

__________

(a)Includes amounts from PECO financing trusts.

(b)Interest payments are estimated based on final maturity dates of debt securities outstanding as of December 31, 2025 and do not reflect anticipated future refinancing, early redemptions, or debt issuances. Includes estimated interest payments due to the PECO financing trusts.

(c)Represents commitments to purchase natural gas and related transportation, storage capacity, and services.

(d)Represents the future estimated value, as of December 31, 2025, of the cash flows associated with all contracts, both cancellable and non-cancellable, entered into between PECO and third-parties for the provision of services and materials, entered into in the normal course of business, and not specifically reflected elsewhere in this table. These estimates are subject to significant variability from period to period.

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BGE

	2026		Beyond 2026		Total		Time Period
Long-term debt	$	350	$	5,750	$	6,100	2026 - 2054
Interest payments on long-term debt(a)	241		4,749		4,990		2026 - 2054
Operating leases	4		29		33		2026 - 2099
Fuel purchase agreements(b)	130		506		636		2026 - 2039
Electric supply procurement	1,396		961		2,357		2026 - 2028
Other purchase obligations(c)	2,363		945		3,308		2026 - 2033
Total cash requirements	$	4,484	$	12,940	$	17,424

__________

(a)Interest payments are estimated based on final maturity dates of debt securities outstanding as of December 31, 2025 and do not reflect anticipated future refinancing, early redemptions, or debt issuances.

(b)Represents commitments to purchase natural gas and related transportation, storage capacity, and services.

(c)Represents the future estimated value, as of December 31, 2025, of the cash flows associated with all contracts, both cancellable and non-cancellable, entered into between BGE and third-parties for the provision of services and materials, entered into in the normal course of business, and not specifically reflected elsewhere in this table. These estimates are subject to significant variability from period to period.

PHI

	2026		Beyond 2026		Total		Time Period
Long-term debt and finance leases	$	64	$	9,225	$	9,289	2026 - 2055
Interest payments on long-term debt(a)	389		6,408		6,797		2026 - 2055
Operating leases	13		66		79		2026 - 2032
Fuel purchase agreements(b)	35		209		244		2026 - 2031
Electric supply procurement	1,810		1,322		3,132		2026 - 2029
Long-term renewable energy commitments	22		110		132		2026 - 2033
Other purchase obligations(c)	1,749		1,534		3,283		2026 - 2033
Total cash requirements	$	4,082	$	18,874	$	22,956

__________

(a)Interest payments are estimated based on final maturity dates of debt securities outstanding as of December 31, 2025 and do not reflect anticipated future refinancing, early redemptions, or debt issuances. Variable rate interest obligations are estimated based on rates as of December 31, 2025.

(b)Represents commitments to purchase natural gas and related transportation, storage capacity, and services.

(c)Represents the future estimated value, as of December 31, 2025, of the cash flows associated with all contracts, both cancellable and non-cancellable, entered into between Pepco, DPL, ACE, and PHISCO and third-parties for the provision of services and materials, entered into in the normal course of business, and not specifically reflected elsewhere in this table. These estimates are subject to significant variability from period to period.

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Pepco

	2026		Beyond 2026		Total		Time Period
Long-term debt and finance leases	$	6	$	4,694	$	4,700	2026 - 2055
Interest payments on long-term debt(a)	205		3,553		3,758		2026 - 2055
Operating leases	5		25		30		2026 - 2032
Electric supply procurement	936		711		1,647		2026 - 2029
Other purchase obligations(b)	1,032		836		1,868		2026 - 2033
Total cash requirements	$	2,184	$	9,819	$	12,003

__________ 

(a)Interest payments are estimated based on final maturity dates of debt securities outstanding as of December 31, 2025 and do not reflect anticipated future refinancing, early redemptions, or debt issuances.

(b)Represents the future estimated value, as of December 31, 2025, of the cash flows associated with all contracts, both cancellable and non-cancellable, entered into between Pepco and third-parties for the provision of services and materials, entered into in the normal course of business, and not specifically reflected elsewhere in this table. These estimates are subject to significant variability from period to period.

DPL

	2026		Beyond 2026		Total		Time Period
Long-term debt and finance leases	$	53	$	2,308	$	2,361	2026 - 2054
Interest payments on long-term debt(a)	100		1,695		1,795		2026 - 2054
Operating leases	6		37		43		2025 - 2031
Fuel purchase agreements(b)	35		209		244		2026 - 2031
Electric supply procurement	474		307		781		2026 - 2028
Long-term renewable energy commitments	22		110		132		2026 - 2033
Other purchase obligations(c)	401		231		632		2026 - 2031
Total cash requirements	$	1,091	$	4,897	$	5,988

__________

(a)Interest payments are estimated based on final maturity dates of debt securities outstanding as of December 31, 2025 and do not reflect anticipated future refinancing, early redemptions, or debt issuances. Variable rate interest obligations are estimated based on rates as of December 31, 2025.

(b)Represents commitments to purchase natural gas and related transportation, storage capacity, and services.

(c)Represents the future estimated value, as of December 31, 2025, of the cash flows associated with all contracts, both cancellable and non-cancellable, entered into between DPL and third-parties for the provision of services and materials, entered into in the normal course of business, and not specifically reflected elsewhere in this table. These estimates are subject to significant variability from period to period.

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ACE

	2026		Beyond 2026		Total		Time Period
Long-term debt and finance leases	$	5	$	2,038	$	2,043	2026 - 2055
Interest payments on long-term debt(a)	70		1,068		1,138		2026 - 2055
Operating leases	2		5		7		2026 - 2030
Electric supply procurement	400		304		704		2026 - 2028
Other purchase obligations(b)	255		428		683		2026 - 2030
Total cash requirements	$	732	$	3,843	$	4,575

__________

(a)Interest payments are estimated based on final maturity dates of debt securities outstanding as of December 31, 2025 and do not reflect anticipated future refinancing, early redemptions, or debt issuances.

(b)Represents the future estimated value, as of December 31, 2025, of the cash flows associated with all contracts, both cancellable and non-cancellable, entered into between ACE and third-parties for the provision of services and materials, entered into in the normal course of business, and not specifically reflected elsewhere in this table. These estimates are subject to significant variability from period to period.

See Note 16 — Commitments and Contingencies and Note 2 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information of the Registrants’ other commitments potentially triggered by future events. Additionally, see below for where to find additional information regarding the financial commitments in the tables above in the Combined Notes to the Consolidated Financial Statements:

Item	Location within Notes to the Consolidated Financial Statements
Long-term debt	Note 14 — Debt and Credit Agreements
Interest payments on long-term debt	Note 14 — Debt and Credit Agreements
Finance leases	Note 9 — Leases
Operating leases	Note 9 — Leases
Long-term renewable energy and REC commitments	Note 2 — Regulatory Matters
ZEC commitments	Note 2 — Regulatory Matters
Pension contributions	Note 12 — Retirement Benefits

Credit Facilities

Exelon Corporate, ComEd, and BGE meet their short-term liquidity requirements primarily through the issuance of commercial paper. PECO meets its short-term liquidity requirements primarily through the issuance of commercial paper and borrowings from the Exelon intercompany money pool. Pepco, DPL, and ACE meet their short-term liquidity requirements primarily through the issuance of commercial paper and borrowings from the PHI intercompany money pool. PHI Corporate meets its short-term liquidity requirements primarily through the issuance of short-term notes and the Exelon intercompany money pool. The Registrants may use their respective credit facilities for general corporate purposes, including meeting short-term funding requirements and the issuance of letters of credit.

See Note 14 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information on the Registrants’ credit facilities and short term borrowing activity.

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Capital Structure

As of December 31, 2025, the capital structures of the Registrants consisted of the following:

	Exelon		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Long-term debt	62	%	45	%	45	%	48	%	41	%	48	%	48	%	48	%
Long-term debt to affiliates(a)	—	%	1	%	1	%	—	%	—	%	—	%	—	%	—	%
Common equity	37	%	54	%	54	%	52	%	—	%	49	%	49	%	48	%
Member’s equity	—	%	—	%	—	%	—	%	56	%	—	%	—	%	—	%
Commercial paper and notes payable	1	%	—	%	—	%	—	%	3	%	3	%	3	%	4	%

__________ 

(a)Includes approximately $390 million, $206 million, and $184 million owed to unconsolidated affiliates of Exelon, ComEd, and PECO respectively. These special purpose entities were created for the sole purposes of issuing mandatory redeemable trust preferred securities of ComEd and PECO.

Security Ratings

The Registrants’ access to the capital markets, including the commercial paper market, and their respective financing costs in those markets, may depend on the securities ratings of the entity that is accessing the capital markets.

The Registrants’ borrowings are not subject to default or prepayment as a result of a downgrading of securities, although such a downgrading of a Registrant’s securities could increase fees and interest charges under that Registrant’s credit agreements.

As part of the normal course of business, the Registrants enter into contracts that contain express provisions or otherwise permit the Registrants and their counterparties to demand adequate assurance of future performance when there are reasonable grounds for doing so. In accordance with the contracts and applicable contracts law, if the Registrants are downgraded by a credit rating agency, it is possible that a counterparty would attempt to rely on such a downgrade as a basis for making a demand for adequate assurance of future performance, which could include the posting of additional collateral. See Note 13 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information on collateral provisions.

The credit ratings for ComEd, BGE, PHI, Pepco, DPL, and ACE did not change for the year ended December 31, 2025. On January 17, 2025, Fitch Ratings affirmed and withdrew the long-term and short-term issuer default ratings along with individual securities ratings of the Registrants for commercial reasons. On February 7, 2025, S&P raised its long-term issuer credit rating for Exelon and PECO from 'BBB+' to 'A-', and raised its rating on Exelon’s senior unsecured debt from ‘BBB’ to 'BBB+'. S&P also affirmed its short-term issuer and commercial paper rating for Exelon and PECO of 'A-2'.

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Intercompany Money 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, 2025, are presented in the following tables.

	For the Year Ended December 31, 2025				As of December 31, 2025
Exelon Intercompany Money Pool	Maximum Contributed		Maximum Borrowed		Contributed (Borrowed)
Exelon Corporate	$	578	$	—	$	250
PECO	336		(253)		—
BSC	—		(413)		(233)
PHI Corporate	—		(85)		(80)
PCI	63		—		63

	For the Year Ended December 31, 2025				As of December 31, 2025
PHI Intercompany Money Pool	Maximum Contributed		Maximum Borrowed		Contributed (Borrowed)
Pepco	$	20	$	(35)	$	—
DPL	48		(1)		—
ACE	—		(46)		—

Shelf Registration Statements

On February 13, 2025, Exelon and ComEd filed a combined shelf registration statement on Form S-3 registering $12.6 billion in aggregate amount of securities, which was declared effective by the SEC on April 8, 2025. The shelf registration statement may be used to issue Exelon debt and equity securities as well as ComEd debt securities through the expiration date of April 8, 2028. On February 21, 2024, PECO and BGE filed with the SEC a standalone automatically effective shelf registration statement, unlimited in amount, which can be used to issue PECO and BGE debt securities through the expiration date of February 20, 2027. The ability of Exelon, ComEd, PECO and BGE to sell securities off their corresponding registration statements will depend on a number of factors at the time of the proposed sale, including other required regulatory approvals, as applicable, the current financial condition of the Registrant, its securities ratings, and market conditions.

Pepco, DPL, and ACE periodically issue securities through the private placement markets. Pepco, DPL, and ACE's ability to access the private placement markets will depend on a number of factors at the time of the proposed sale, including other required regulatory approvals, as applicable, current financial condition, securities ratings, and market conditions.

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Regulatory Authorizations

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

	At December 31, 2025
	Short-term Financing Authority				Remaining Long-term Financing Authority
	Commission	Expiration Date	Amount		Commission	Expiration Date	Amount
ComEd(a)(b)	FERC	December 31, 2025	$	2,500	ICC	January 1, 2027, May 1, 2027	$	1,593
PECO(a)	FERC	December 31, 2025	1,500		PAPUC	December 31, 2027	1,850
BGE(a)	FERC	December 31, 2025	700		MDPSC	N/A	1,850
Pepco(a)(c)(d)	FERC	December 31, 2025	500		MDPSC / DCPSC	December 31, 2025	100
DPL(a)(c)(e)	FERC	December 31, 2025	500		MDPSC / DEPSC	December 31, 2025	172
ACE(f)	NJBPU	January 1, 2028	350		NJBPU	December 31, 2026	625

__________

(a)On September 8, 2025, ComEd, PECO, BGE, Pepco, and DPL filed applications with the FERC for renewal of their short-term financing authority through December 31, 2027. On November 7, 2025, ComEd, PECO, BGE, Pepco, and DPL received approval for $2.5 billion, $1.5 billion, $900 million, $700 million, and $700 million, respectively, with an effective date of January 1, 2026.

(b)On December 18, 2025, ComEd received approval from the ICC for $2.8 billion in new long-term debt financing authority, with an effective date of January 1, 2026.

(c)The financing authority filed with MDPSC does not have an expiration date, while the financing authority filed with DCPSC and DEPSC have an expiration date of December 31, 2025.

(d)On September 3, 2025 and December 17, 2025, Pepco received approval from the MDPSC and DCPSC, respectively, for $1.1 billion in new long-term financing authority, with an effective date of January 1, 2026.

(e)On September 3, 2025, DPL received approval from the MDSPC and DEPSC, respectively, for $700 million in new long-term financing authority, with an effective date of January 1, 2026.

(f)On November 21, 2025, ACE received approval from the NJBPU to extend their $350 million short-term financing authority through January 1, 2028, with an effective date of November 28, 2025.

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 13 — 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 12 — 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 hybrid, convertible, fixed-rate and variable-rate debt to manage interest rate exposure. See Note 14 — 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. See Note 13 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information.

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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. PECO, 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 2 — Regulatory Matters and Note 13 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements.

The following table presents the maturity and source of fair value for Exelon's and ComEd's mark-to-market commodity contract net liabilities. These net liabilities are associated with ComEd's floating-to-fixed energy swap contracts with unaffiliated suppliers. 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 15 — 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):	2026		2027		2028		2029		2030		2031 and Beyond
Prices based on model or other valuation methods (Level 3)	$	(24)	$	(19)	$	(20)	$	(20)	$	(20)	$	(28)	$	(131)

_________

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

Credit Risk (All Registrants)

Credit risk for the Utility Registrants is governed by credit and collection policies, which are aligned with state regulatory requirements. The Utility Registrants are currently obligated to provide service to all electric customers within their franchised territories. The Utility Registrants record an allowance for credit losses, based upon historical experience, current information, and forward-looking risk factors, to provide for the potential loss from nonpayment by these customers. The Utility Registrants will monitor nonpayment from customers and will make any necessary adjustments to the allowance for credit losses. See Note 1 — Significant Accounting Policies of

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the Combined Notes to Consolidated Financial Statements for the allowance for credit losses policy. The Utility Registrants did not have any customers representing over 10% of their revenues as of December 31, 2025. See Note 2 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

Management’s Report on Internal Control Over Financial Reporting

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, 2025. 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, 2025, Exelon’s internal control over financial reporting was effective.

The effectiveness of Exelon’s internal control over financial reporting as of December 31, 2025, has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report which appears herein.

February 12, 2026

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Management’s Report on Internal Control Over Financial Reporting

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, 2025. 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, 2025, ComEd’s internal control over financial reporting was effective.

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Management’s Report on Internal Control Over Financial Reporting

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, 2025. 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, 2025, PECO’s internal control over financial reporting was effective.

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Management’s Report on Internal Control Over Financial Reporting

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, 2025. 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, 2025, BGE’s internal control over financial reporting was effective.

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Management’s Report on Internal Control Over Financial Reporting

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, 2025. 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, 2025, PHI’s internal control over financial reporting was effective.

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Management’s Report on Internal Control Over Financial Reporting

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, 2025. 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, 2025, Pepco’s internal control over financial reporting was effective.

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Management’s Report on Internal Control Over Financial Reporting

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, 2025. 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, 2025, DPL’s internal control over financial reporting was effective.

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Management’s Report on Internal Control Over Financial Reporting

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, 2025. 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, 2025, ACE’s internal control over financial reporting was effective.

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Report of Independent Registered Public Accounting Firm

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, 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), of Exelon Corporation and its subsidiaries (the "Company") (collectively referred to as the "consolidated financial statements"). We also have audited the Company's internal control over financial reporting as of December 31, 2025, 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, 2025 and 2024, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2025 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, 2025, 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.

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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.

Critical Audit Matters

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.

Accounting for the Effects of Rate Regulation

As described in Notes 1 and 2 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, 2025, there were $10.57 billion of regulatory assets and $12.14 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.

/s/ PricewaterhouseCoopers LLP

Chicago, Illinois

February 12, 2026

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

101

Report of Independent Registered Public Accounting Firm

To the Board of Directors and Shareholders of Commonwealth Edison Company

Opinion on the Financial Statements

We have audited the consolidated financial statements, including the related notes, 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), of Commonwealth Edison Company and its subsidiaries (the "Company") (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, 2025 and 2024, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2025 in conformity with accounting principles generally accepted in the United States of America.

Basis for Opinion

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 audits 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.

Critical Audit Matters

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.

Accounting for the Effects of Rate Regulation

As described in Notes 1 and 2 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

102

recovered and settled, respectively, in future rates. As of December 31, 2025, there were $3.28 billion of regulatory assets and $10.01 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.

/s/ PricewaterhouseCoopers LLP

Chicago, Illinois

February 12, 2026

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

103

Report of Independent Registered Public Accounting Firm

To the Board of Directors and Shareholders of PECO Energy Company

Opinion on the Financial Statements

We have audited the consolidated financial statements, including the related notes, 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), of PECO Energy Company and its subsidiaries (the "Company") (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, 2025 and 2024, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2025 in conformity with accounting principles generally accepted in the United States of America.

Basis for Opinion

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 audits 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.

Critical Audit Matters

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.

Accounting for the Effects of Rate Regulation

As described in Notes 1 and 2 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

104

recovered and settled, respectively, in future rates. As of December 31, 2025, there were $1.35 billion of regulatory assets and $589 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.

/s/ PricewaterhouseCoopers LLP

Philadelphia, Pennsylvania

February 12, 2026

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

105

Report of Independent Registered Public Accounting Firm

To the Board of Directors and Shareholder of Baltimore Gas and Electric Company

Opinion on the Financial Statements

We have audited the financial statements, including the related notes, 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), of Baltimore Gas and Electric Company (the "Company") (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, 2025 and 2024, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2025 in conformity with accounting principles generally accepted in the United States of America.

Basis for Opinion

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 audits 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.

Critical Audit Matters

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.

Accounting for the Effects of Rate Regulation

As described in Notes 1 and 2 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,

106

respectively, in future rates. As of December 31, 2025, there were $979 million of regulatory assets and $626 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.

/s/ PricewaterhouseCoopers LLP

Baltimore, Maryland

February 12, 2026

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.

107

Report of Independent Registered Public Accounting Firm

To the Board of Directors and Member of Pepco Holdings LLC

Opinion on the Financial Statements

We have audited the consolidated financial statements, including the related notes, 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), of Pepco Holdings LLC and its subsidiaries (the "Company") (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, 2025 and 2024, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2025 in conformity with accounting principles generally accepted in the United States of America.

Basis for Opinion

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 audits 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.

Critical Audit Matters

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.

Accounting for the Effects of Rate Regulation

As described in Notes 1 and 2 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

108

recovered and settled, respectively, in future rates. As of December 31, 2025, there were $1.91 billion of regulatory assets and $825 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.

/s/ PricewaterhouseCoopers LLP

Philadelphia, Pennsylvania

February 12, 2026

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

109

Report of Independent Registered Public Accounting Firm

To the Board of Directors and Shareholder of Potomac Electric Power Company

Opinion on the Financial Statements

We have audited the financial statements, including the related notes, 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), of Potomac Electric Power Company (the "Company") (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, 2025 and 2024, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2025 in conformity with accounting principles generally accepted in the United States of America.

Basis for Opinion

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 audits 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.

Critical Audit Matters

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.

Accounting for the Effects of Rate Regulation

As described in Notes 1 and 2 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,

110

respectively, in future rates. As of December 31, 2025, there were $587 million of regulatory assets and $281 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.

/s/ PricewaterhouseCoopers LLP

Philadelphia, Pennsylvania

February 12, 2026

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.

111

Report of Independent Registered Public Accounting Firm

To the Board of Directors and Shareholder of Delmarva Power & Light Company

Opinion on the Financial Statements

We have audited the financial statements, including the related notes, 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), of Delmarva Power & Light Company (the "Company") (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, 2025 and 2024, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2025 in conformity with accounting principles generally accepted in the United States of America.

Basis for Opinion

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 audits 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.

Critical Audit Matters

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.

Accounting for the Effects of Rate Regulation

As described in Notes 1 and 2 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,

112

respectively, in future rates. As of December 31, 2025, there were $286 million of regulatory assets and $358 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.

/s/ PricewaterhouseCoopers LLP

Philadelphia, Pennsylvania

February 12, 2026

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.

113

Report of Independent Registered Public Accounting Firm

To the Board of Directors and Shareholder of Atlantic City Electric Company

Opinion on the Financial Statements

We have audited the consolidated financial statements, including the related notes, 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), of Atlantic City Electric Company and its subsidiary (the "Company") (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, 2025 and 2024, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2025 in conformity with accounting principles generally accepted in the United States of America.

Basis for Opinion

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 audits 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.

Critical Audit Matters

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.

Accounting for the Effects of Rate Regulation

As described in Notes 1 and 2 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

114

recovered and settled, respectively, in future rates. As of December 31, 2025, there were $652 million of regulatory assets and $185 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.

/s/ PricewaterhouseCoopers LLP

Philadelphia, Pennsylvania

February 12, 2026

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

115

Exelon Corporation and Subsidiary Companies

Consolidated Statements of Operations and Comprehensive Income

	For the Years Ended December 31,
(In millions, except per share data)	2025		2024		2023
Operating revenues
Electric operating revenues	$	22,655	$	21,338	$	19,267
Natural gas operating revenues	2,349		1,782		1,764
Revenues from alternative revenue programs	(746)		(92)		696
Total operating revenues	24,258		23,028		21,727
Operating expenses
Purchased power	7,944		8,214		7,648
Purchased fuel	723		469		593
Operating and maintenance	5,177		4,940		4,559
Depreciation and amortization	3,640		3,594		3,506
Taxes other than income taxes	1,629		1,504		1,408
Total operating expenses	19,113		18,721		17,714
Gain on sale of assets	3		12		10
Operating income	5,148		4,319		4,023
Other income and (deductions)
Interest expense, net	(2,102)		(1,889)		(1,704)
Interest expense to affiliates	(25)		(25)		(25)
Other, net	270		262		408
Total other income and (deductions)	(1,857)		(1,652)		(1,321)
Income before income taxes	3,291		2,667		2,702
Income taxes	523		207		374
Net income attributable to common shareholders	$	2,768	$	2,460	$	2,328
Comprehensive income, net of income taxes
Net income	$	2,768	$	2,460	$	2,328
Other comprehensive (loss) income, net of income taxes
Pension and non-pension postretirement benefit plans:
Actuarial losses reclassified to periodic benefit cost	22		28		26
Pension and non-pension postretirement benefit plans valuation adjustments	(52)		(70)		(109)
Unrealized (loss) gain on cash flow hedges	(12)		48		(5)
Other comprehensive (loss) income	(42)		6		(88)
Comprehensive income attributable to common shareholders	$	2,726	$	2,466	$	2,240
Average shares of common stock outstanding:
Basic	1,011		1,003		996
Assumed exercise and/or distributions of stock-based awards(a)	1		—		1
Diluted	1,012		1,003		997
Earnings per average common share
Basic	$	2.74	$	2.45	$	2.34
Diluted	$	2.73	$	2.45	$	2.34

__________

(a)The dilutive effects of stock-based compensation awards are calculated using the treasury stock method for all periods presented.

See the Combined Notes to Consolidated Financial Statements

116

Exelon Corporation and Subsidiary Companies

Consolidated Statements of Cash Flows

	For the Years Ended December 31,
(In millions)	2025		2024		2023
Cash flows from operating activities
Net income	$	2,768	$	2,460	$	2,328
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation, amortization, and accretion	3,643		3,596		3,506
Gain on sales of assets	(3)		(12)		(10)
Deferred income taxes and amortization of investment tax credits	391		128		319
Net fair value changes related to derivatives	—		—		22
Other non-cash operating activities	1,331		592		(335)
Changes in assets and liabilities:
Accounts receivable	(1,691)		(644)		(37)
Inventories	(22)		(56)		(45)
Accounts payable and accrued expenses	260		(37)		(191)
Collateral (paid) received, net	(10)		33		(146)
Income taxes	121		(4)		48
Regulatory assets and liabilities, net	156		(50)		(439)
Pension and non-pension postretirement benefit contributions	(342)		(180)		(129)
Other assets and liabilities	(348)		(257)		(188)
Net cash flows provided by operating activities	6,254		5,569		4,703
Cash flows from investing activities
Capital expenditures	(8,529)		(7,097)		(7,408)
Proceeds from sales of assets	4		38		25
Other investing activities	—		17		8
Net cash flows used in investing activities	(8,525)		(7,042)		(7,375)
Cash flows from financing activities
Changes in short-term borrowings	(747)		(265)		(313)
Proceeds from short-term borrowings with maturities greater than 90 days	—		150		400
Repayments on short-term borrowings with maturities greater than 90 days	(500)		(549)		(150)
Issuance of long-term debt	6,075		4,974		5,825
Retirement of long-term debt	(1,311)		(1,557)		(1,713)
Issuance of common stock	691		148		140
Dividends paid on common stock	(1,617)		(1,524)		(1,433)
Proceeds from employee stock plans	36		43		41
Other financing activities	(94)		(109)		(114)
Net cash flows provided by financing activities	2,533		1,311		2,683
Increase (decrease) in cash, restricted cash, and cash equivalents	262		(162)		11
Cash, restricted cash, and cash equivalents at beginning of period	939		1,101		1,090
Cash, restricted cash, and cash equivalents at end of period	$	1,201	$	939	$	1,101
Supplemental cash flow information
Increase (decrease) in capital expenditures not paid	$	553	$	301	$	(215)
Increase (decrease) in PP&E related to ARO update	13		16		(13)

See the Combined Notes to Consolidated Financial Statements

117

Exelon Corporation and Subsidiary Companies

Consolidated Balance Sheets

	December 31,
(In millions)	2025		2024
ASSETS
Current assets
Cash and cash equivalents	$	626	$	357
Restricted cash and cash equivalents	525		541
Accounts receivable
Customer accounts receivable	3,732		3,144
Customer allowance for credit losses	(435)		(406)
Customer accounts receivable, net	3,297		2,738
Other accounts receivable	1,879		1,123
Other allowance for credit losses	(94)		(107)
Other accounts receivable, net	1,785		1,016
Inventories, net
Fossil fuel	88		72
Materials and supplies	780		781
Regulatory assets	1,359		1,940
Prepaid renewable energy credits	563		494
Other	523		445
Total current assets	9,546		8,384
Property, plant, and equipment (net of accumulated depreciation and amortization of $20,080 and $18,445 as of December 31, 2025 and 2024, respectively)	84,318		78,182
Deferred debits and other assets
Regulatory assets	9,214		8,710
Goodwill	6,630		6,630
Receivable related to Regulatory Agreement Units	4,755		4,026
Investments	312		290
Other	1,795		1,562
Total deferred debits and other assets	22,706		21,218
Total assets	$	116,570	$	107,784

See the Combined Notes to Consolidated Financial Statements

118

Exelon Corporation and Subsidiary Companies

Consolidated Balance Sheets

	December 31,
(In millions)	2025		2024
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities
Short-term borrowings	$	612	$	1,859
Long-term debt due within one year	1,665		1,453
Accounts payable	3,721		2,994
Accrued expenses	1,582		1,468
Payables to affiliates	5		5
Customer deposits	533		446
Regulatory liabilities	1,128		411
Mark-to-market derivative liabilities	30		29
Unamortized energy contract liabilities	5		5
Renewable energy credit obligations	473		429
Other	577		512
Total current liabilities	10,331		9,611
Long-term debt	47,413		42,947
Long-term debt to financing trusts	390		390
Deferred credits and other liabilities
Deferred income taxes and unamortized investment tax credits	13,715		12,793
Regulatory liabilities	11,016		10,198
Pension obligations	1,749		1,745
Non-pension postretirement benefit obligations	546		472
Asset retirement obligations	321		301
Mark-to-market derivative liabilities	106		103
Unamortized energy contract liabilities	16		21
Other	2,169		2,282
Total deferred credits and other liabilities	29,638		27,915
Total liabilities	87,772		80,863
Commitments and contingencies
Shareholders’ equity
Common stock (No par value, 2,000 shares authorized, 1,023 shares and 1,005 shares outstanding as of December 31, 2025 and 2024, respectively)	22,106		21,338
Treasury stock, at cost (2 shares as of December 31, 2025 and 2024)	(123)		(123)
Retained earnings	7,577		6,426
Accumulated other comprehensive loss, net	(762)		(720)
Total shareholders’ equity	28,798		26,921
Total liabilities and shareholders' equity	$	116,570	$	107,784

See the Combined Notes to Consolidated Financial Statements

119

Exelon Corporation and Subsidiary Companies

Consolidated Statements of Changes in Equity

(In millions, shares in thousands)	Issued Shares	Common Stock		Treasury Stock		Retained Earnings		Accumulated Other Comprehensive Loss, net		Total Equity
Balance at December 31, 2022	995,830	$	20,908	$	(123)	$	4,597	$	(638)	$	24,744
Net income	—	—		—		2,328		—		2,328
Long-term incentive plan activity	659	19		—		—		—		19
Employee stock purchase plan activity	1,173	47		—		—		—		47
Issuance of common stock	3,587	140		—		—		—		140
Common stock dividends ($1.44/common share)	—	—		—		(1,435)		—		(1,435)
Other comprehensive loss, net of income taxes	—	—		—		—		(88)		(88)
Balance at December 31, 2023	1,001,249	$	21,114	$	(123)	$	5,490	$	(726)	$	25,755
Net income	—	—		—		2,460		—		2,460
Long-term incentive plan activity	464	26		—		—		—		26
Employee stock purchase plan activity	1,344	50		—		—		—		50
Issuance of common stock	3,989	148		—		—		—		148
Common stock dividends ($1.52/common share)	—	—		—		(1,524)		—		(1,524)
Other comprehensive income, net of income taxes	—	—		—		—		6		6
Balance at December 31, 2024	1,007,046	$	21,338	$	(123)	$	6,426	$	(720)	$	26,921
Net income	—	—		—		2,768		—		2,768
Long-term incentive plan activity	323	34		—		—		—		34
Employee stock purchase plan activity	931	43		—		—		—		43
Issuance of common stock	16,101	691		—		—		—		691
Common stock dividends ($1.60/common share)	—	—		—		(1,617)		—		(1,617)
Other comprehensive loss, net of income taxes	—	—		—		—		(42)		(42)
Balance at December 31, 2025	1,024,401	$	22,106	$	(123)	$	7,577	$	(762)	$	28,798

See the Combined Notes to Consolidated Financial Statements

120

Commonwealth Edison Company and Subsidiary Companies

Consolidated Statements of Operations and Comprehensive Income

	For the Years Ended December 31,
(In millions)	2025		2024		2023
Operating revenues
Electric operating revenues	$	7,842	$	8,362	$	7,272
Revenues from alternative revenue programs	(596)		(151)		556
Operating revenues from affiliates	21		8		16
Total operating revenues	7,267		8,219		7,844
Operating expenses
Purchased power	1,782		3,042		2,816
Operating and maintenance	1,306		1,284		1,096
Operating and maintenance from affiliates	404		419		354
Depreciation and amortization	1,560		1,514		1,403
Taxes other than income taxes	409		376		369
Total operating expenses	5,461		6,635		6,038
Gain on sale of assets	—		5		—
Operating income	1,806		1,589		1,806
Other income and (deductions)
Interest expense, net	(517)		(487)		(464)
Interest expense to affiliates, net	(13)		(14)		(13)
Other, net	132		94		75
Total other income and (deductions)	(398)		(407)		(402)
Income before income taxes	1,408		1,182		1,404
Income taxes	261		116		314
Net income	$	1,147	$	1,066	$	1,090
Comprehensive income	$	1,147	$	1,066	$	1,090

See the Combined Notes to Consolidated Financial Statements

121

Commonwealth Edison Company and Subsidiary Companies

Consolidated Statements of Cash Flows

	For the Years Ended December 31,
(In millions)	2025		2024		2023
Cash flows from operating activities
Net income	$	1,147	$	1,066	$	1,090
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation and amortization	1,560		1,514		1,403
Gain on sales of assets	—		(5)		—
Deferred income taxes and amortization of investment tax credits	39		(19)		196
Other non-cash operating activities	740		232		(536)
Changes in assets and liabilities:
Accounts receivable	(1,026)		(185)		(138)
Receivables from and payables to affiliates, net	3		4		(2)
Inventories	17		(15)		(82)
Accounts payable and accrued expenses	77		(115)		(87)
Collateral (paid) received, net	(36)		30		69
Income taxes	(1)		(114)		106
Regulatory assets and liabilities, net	506		246		(60)
Pension and non-pension postretirement benefit contributions	(209)		(25)		(41)
Other assets and liabilities	(152)		99		(70)
Net cash flows provided by operating activities	2,665		2,713		1,848
Cash flows from investing activities
Capital expenditures	(2,899)		(2,195)		(2,576)
Other investing activities	6		7		8
Net cash flows used in investing activities	(2,893)		(2,188)		(2,568)
Cash flows from financing activities
Changes in short-term borrowings	(36)		(166)		(225)
Proceeds from short-term borrowings with maturities greater than 90 days	—		—		400
Repayments on short-term borrowings with maturities greater than 90 days	—		(400)		(150)
Issuance of long-term debt	725		800		975
Retirement of long-term debt	—		(250)		—
Dividends paid on common stock	(813)		(776)		(746)
Contributions from parent	391		227		655
Other financing activities	(8)		(14)		(14)
Net cash flows provided by (used in) financing activities	259		(579)		895
Increase (decrease) in cash, restricted cash, and cash equivalents	31		(54)		175
Cash, restricted cash, and cash equivalents at beginning of period	632		686		511
Cash, restricted cash, and cash equivalents at end of period	$	663	$	632	$	686
Supplemental cash flow information
Increase (decrease) in capital expenditures not paid	$	233	$	(17)	$	(10)

See the Combined Notes to Consolidated Financial Statements

122

Commonwealth Edison Company and Subsidiary Companies

Consolidated Balance Sheets

	December 31,
(In millions)	2025		2024
ASSETS
Current assets
Cash and cash equivalents	$	159	$	105
Restricted cash and cash equivalents	454		486
Accounts receivable
Customer accounts receivable	1,058		994
Customer allowance for credit losses	(115)		(109)
Customer accounts receivable, net	943		885
Other accounts receivable	1,155		290
Other allowance for credit losses	(23)		(34)
Other accounts receivable, net	1,132		256
Receivables from affiliates	5		4
Inventories, net	268		292
Regulatory assets	595		1,159
Other	217		141
Total current assets	3,773		3,328
Property, plant, and equipment (net of accumulated depreciation and amortization of $8,291 and $7,619 as of December 31, 2025 and 2024, respectively)	32,255		30,211
Deferred debits and other assets
Regulatory assets	2,687		2,562
Goodwill	2,625		2,625
Receivable related to Regulatory Agreement Units	4,313		3,780
Investments	6		6
Prepaid pension asset	1,284		1,165
Other	1,342		1,073
Total deferred debits and other assets	12,257		11,211
Total assets	$	48,285	$	44,750

See the Combined Notes to Consolidated Financial Statements

123

Commonwealth Edison Company and Subsidiary Companies

Consolidated Balance Sheets

	December 31,
(In millions)	2025		2024
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities
Short-term borrowings	$	—	$	36
Long-term debt due within one year	500		—
Accounts payable	1,033		748
Accrued expenses	474		463
Payables to affiliates	81		77
Customer deposits	192		134
Regulatory liabilities	846		197
Mark-to-market derivative liabilities	25		29
Other	288		270
Total current liabilities	3,439		1,954
Long-term debt	12,253		12,030
Long-term debt to financing trust	206		206
Deferred credits and other liabilities
Deferred income taxes and unamortized investment tax credits	5,828		5,601
Regulatory liabilities	9,163		8,421
Asset retirement obligations	193		167
Non-pension postretirement benefit obligations	151		156
Mark-to-market derivative liabilities	106		103
Other	1,341		1,232
Total deferred credits and other liabilities	16,782		15,680
Total liabilities	32,680		29,870
Commitments and contingencies
Shareholders’ equity
Common stock ($12.50 par value, 250 shares authorized, 127 shares outstanding as of December 31, 2025 and 2024)	1,588		1,588
Other paid-in capital	11,019		10,628
Retained earnings	2,998		2,664
Total shareholders’ equity	15,605		14,880
Total liabilities and shareholders’ equity	$	48,285	$	44,750

See the Combined Notes to Consolidated Financial Statements

124

Commonwealth Edison Company and Subsidiary Companies

Consolidated Statements of Changes in Shareholders’ Equity

(In millions)	Common Stock		Other Paid-In Capital		Retained Earnings		Total Shareholders’ Equity
Balance at December 31, 2022	$	1,588	$	9,746	$	2,030	$	13,364
Net income	—		—		1,090		1,090
Common stock dividends	—		—		(746)		(746)
Contributions from parent	—		655		—		655
Balance at December 31, 2023	$	1,588	$	10,401	$	2,374	$	14,363
Net income	—		—		1,066		1,066
Common stock dividends	—		—		(776)		(776)
Contributions from parent	—		227		—		227
Balance at December 31, 2024	$	1,588	$	10,628	$	2,664	$	14,880
Net income	—		—		1,147		1,147
Common stock dividends	—		—		(813)		(813)
Contributions from parent	—		391		—		391
Balance at December 31, 2025	$	1,588