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Exelon Corporation
EXC
#506
Rank
$48.77 B
Marketcap
๐Ÿ‡บ๐Ÿ‡ธ United States
Country
$47.68
Share price
0.68%
Change (1 day)
14.86%
Change (1 year)
๐Ÿ”‹ Electricity
Categories
  1. Exelon Corporation
  2. Annual Reports (10-K)
  3. Submitted on 2026-02-12

Exelon Corporation - 10-K annual report


Text size:
December 31, 2025December 31, 2025December 31, 2025December 31, 2025December 31, 2025December 31, 2025December 31, 2025December 31, 202520252025202520252025202520252025FYFYFYFYFYFYFYFY--12-31--12-31--12-31--12-31--12-31--12-31--12-31--12-3100011093570000022606000007810000000094660001135971000007973200000278790000008192FALSEFALSEFALSEFALSEFALSEFALSEFALSEFALSE111111111111111111111111158058047546158028505705805535058058044520505755755751043575103357557557510435751043http://fasb.org/us-gaap/2025#DeferredCostsAndOtherAssetshttp://fasb.org/us-gaap/2025#OperatingLeaseLiabilityhttp://fasb.org/us-gaap/2025#DeferredCostsAndOtherAssetshttp://fasb.org/us-gaap/2025#OperatingLeaseLiabilityhttp://fasb.org/us-gaap/2025#PropertyPlantAndEquipmentNethttp://fasb.org/us-gaap/2025#PropertyPlantAndEquipmentNet111111113 yearsN/A yearsN/A years3 years3 years5 years3 yearsN/A years2 yearsN/A yearsN/A years2 yearsN/A yearsN/A yearsN/A yearsN/A years8027980777730 yearsN/A yearsN/A years5 years30 years5 years30 yearsN/A years7 yearsN/A yearsN/A years2 yearsN/A yearsN/A yearsN/A yearsN/A years9.30.06.419.26.26.66.33.28.21.75.317.45.37.16.93.14.14.03.94.44.44.44.24.5111171161 years5 years1 yearsN/A yearsN/A yearsN/A yearsN/A years7711771771779 years79 years50 yearsN/A yearsN/A yearsN/A yearsN/A yearsAsset Impairments (Exelon and BGE)In the third quarter of 2022, a review of the impacts of COVID-19 on office use resulted in plans to cease the renovation and dispose of an office building at BGE before the asset was placed into service. BGE determined that the carrying value was not recoverable and that its fair value was less than carrying value. As a result, in 2022, a pre-tax impairment charge of $48 million was recorded in Operating and maintenance expense in Exelon’s and BGE’s Consolidated Statements of Operations and Comprehensive Income. The fair value used in the analysis was based on an estimate of an expected sales price.48482031-12-312031-12-312033-12-312033-12-312033-12-312010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 20242010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 20242010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 20242010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 20242010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 20242010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 20242010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 20242010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 20242010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 20242022 2023 20242022 2023 20242022 2023 20242012 2013 2014 2015 2016 2017 2018 2019 2021 2022 2023 20242012 2013 2014 2015 2016 2017 2018 2019 2021 2022 2023 20242010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 20242010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 20242010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 20242021 2022 2023 20242021 2022 2023 20242021 2022 2023 20242021 2022 2023 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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 NumberIRS Employer Identification Number
001-16169EXELON CORPORATION23-2990190
(a Pennsylvania corporation)
10 South Dearborn Street
P.O. Box 805379
Chicago, Illinois 60680-5379
(800) 483-3220
001-01839COMMONWEALTH EDISON COMPANY36-0938600
(an Illinois corporation)
10 South Dearborn Street
Chicago, Illinois 60603-2300
(312) 394-4321
000-16844PECO ENERGY COMPANY23-0970240
(a Pennsylvania corporation)
2301 Market Street
P.O. Box 8699
Philadelphia, Pennsylvania 19101-8699
(215) 841-4000
001-01910BALTIMORE GAS AND ELECTRIC COMPANY52-0280210
(a Maryland corporation)
2 Center Plaza
110 West Fayette Street
Baltimore, Maryland 21201-3708
(410) 234-5000
001-31403PEPCO HOLDINGS LLC52-2297449
(a Delaware limited liability company)
701 Ninth Street, N.W.
Washington, District of Columbia 20068-0001
(202) 872-2000
001-01072POTOMAC ELECTRIC POWER COMPANY53-0127880
(a District of Columbia and Virginia corporation)
701 Ninth Street, N.W.
Washington, District of Columbia 20068-0001
(202) 872-2000
001-01405DELMARVA POWER & LIGHT COMPANY51-0084283
(a Delaware and Virginia corporation)
500 North Wakefield Drive
Newark, Delaware 19702-5440
(202) 872-2000
001-03559ATLANTIC CITY ELECTRIC COMPANY21-0398280
(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 classTrading Symbol(s)Name of each exchange on which registered
EXELON CORPORATION:
Common Stock, without par valueEXCThe 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 CorporationYes☐Nox
Commonwealth Edison CompanyYes☐Nox
PECO Energy CompanyYesxNo☐
Baltimore Gas and Electric CompanyYesxNo☐
Pepco Holdings LLCYes☐Nox
Potomac Electric Power CompanyYes☐Nox
Delmarva Power & Light CompanyYes☐Nox
Atlantic City Electric CompanyYes☐Nox
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 CorporationYes☐Nox
Commonwealth Edison CompanyYes☐Nox
PECO Energy CompanyYes☐Nox
Baltimore Gas and Electric CompanyYes☐Nox
Pepco Holdings LLCYes☐Nox
Potomac Electric Power CompanyYes☐Nox
Delmarva Power & Light CompanyYes☐Nox
Atlantic City Electric CompanyYes☐Nox
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 CorporationLarge Accelerated FilerxAccelerated Filer
☐
Non-accelerated Filer
☐
Smaller Reporting Company
☐
Emerging Growth Company
☐
Commonwealth Edison CompanyLarge Accelerated Filer
☐
Accelerated Filer
☐
Non-accelerated FilerxSmaller Reporting Company
☐
Emerging Growth Company
☐
PECO Energy CompanyLarge Accelerated Filer
☐
Accelerated Filer
☐
Non-accelerated FilerxSmaller Reporting Company
☐
Emerging Growth Company
☐
Baltimore Gas and Electric CompanyLarge Accelerated Filer
☐
Accelerated Filer
☐
Non-accelerated FilerxSmaller Reporting Company
☐
Emerging Growth Company
☐
Pepco Holdings LLCLarge Accelerated Filer
☐
Accelerated Filer
☐
Non-accelerated FilerxSmaller Reporting Company
☐
Emerging Growth Company
☐
Potomac Electric Power CompanyLarge Accelerated Filer
☐
Accelerated Filer
☐
Non-accelerated FilerxSmaller Reporting Company
☐
Emerging Growth Company
☐
Delmarva Power & Light CompanyLarge Accelerated Filer
☐
Accelerated Filer
☐
Non-accelerated FilerxSmaller Reporting Company
☐
Emerging Growth Company
☐
Atlantic City Electric CompanyLarge Accelerated Filer
☐
Accelerated Filer
☐
Non-accelerated FilerxSmaller 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 valueNo established market
PECO Energy Company Common Stock, without par valueNone
Baltimore Gas and Electric Company, without par valueNone
Pepco Holdings LLCNot applicable
Potomac Electric Power CompanyNone
Delmarva Power & Light CompanyNone
Atlantic City Electric CompanyNone
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 value1,022,892,585 
Commonwealth Edison Company Common Stock, $12.50 par value127,021,422 
PECO Energy Company Common Stock, without par value170,478,507 
Baltimore Gas and Electric Company Common Stock, without par value1,000 
Pepco Holdings LLCNot applicable
Potomac Electric Power Company Common Stock, $0.01 par value100 
Delmarva Power & Light Company Common Stock, $2.25 par value1,000 
Atlantic City Electric Company Common Stock, $3.00 par value8,546,017 
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.
1
5
5
6
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
20
30
30
32
33
33
34
38
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
89
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
265
265
265
266
267
268
269
270
271
272
316
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
ExelonExelon Corporation
ComEdCommonwealth Edison Company
PECOPECO Energy Company
BGEBaltimore 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
RegistrantsExelon, ComEd, PECO, BGE, PHI, Pepco, DPL, and ACE, collectively
Utility RegistrantsComEd, PECO, BGE, Pepco, DPL, and ACE, collectively
Legacy PHIPHI, Pepco, DPL, ACE, PES, and PCI, collectively
BSCExelon Business Services Company, LLC
EEDCExelon Energy Delivery Company, LLC
Exelon CorporateExelon in its corporate capacity as a holding company
Exelon EnterprisesExelon Enterprises Company, LLC
Exelon InQB8RExelon InQB8R, LLC
PCI  Potomac Capital Investment Corporation and its subsidiaries
PEC L.P.PECO Energy Capital, L.P.
PECO Trust IIIPECO Energy Capital Trust III
PECO Trust IVPECO Energy Capital Trust IV
Pepco Energy Services or PES  Pepco Energy Services, Inc. and its subsidiaries
PHI CorporatePHI in its corporate capacity as a holding company
PHISCOPHI Service Company
UIIUnicom Investments, Inc.
Former Related Entities
ConstellationConstellation 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)
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GLOSSARY OF TERMS AND ABBREVIATIONS
Other Terms and Abbreviations
ABOAccumulated Benefit Obligation
AECsAlternative Energy Credits that are issued for each megawatt hour of generation from a qualified alternative energy source
AFUDCAllowance for Funds Used During Construction
AMIAdvanced Metering Infrastructure
AOCIAccumulated Other Comprehensive Income (Loss)
AROAsset Retirement Obligation
ATMAt the market
ARPAlternative Revenue Program
BGS  Basic Generation Service
BSABill Stabilization Adjustment
CBAsCollective Bargaining Agreements
CEJAClimate and Equitable Jobs Act; Illinois Public Act 102-0662 signed into law on September 15, 2021
CERCLAComprehensive Environmental Response, Compensation, and Liability Act of 1980, as amended
CIPConservation Incentive Program
Clean Air ActClean Air Act of 1963, as amended
Clean Water ActFederal Water Pollution Control Amendments of 1972, as amended
Convertible Senior NotesExelon's 3.25% Convertible Senior Notes due 2029
CMCCarbon Mitigation Credit
CODMsChief Operating Decision Makers
Conectiv  Conectiv, LLC, a wholly owned subsidiary of PHI and the parent of DPL and ACE during the Predecessor periods
DC PLUGDistrict of Columbia Power Line Undergrounding Initiative
DCPSC  District of Columbia Public Service Commission
DEPSCDelaware Public Service Commission
DERsDistributed Energy Resources
DOEEDepartment of Energy & Environment
DPA
Deferred Prosecution Agreement
DPPDeferred Purchase Price
DSICDistribution System Improvement Charge
EDITExcess Deferred Income Taxes
EPAUnited States Environmental Protection Agency
ERCOTElectric Reliability Council of Texas
ERISAEmployee Retirement Income Security Act of 1974, as amended
EROAExpected Rate of Return on Assets
ETACEnergy Transition Assistance Charge
FEJAIllinois Public Act 99-0906 or Future Energy Jobs Act
FERCFederal Energy Regulatory Commission
GAAPGenerally Accepted Accounting Principles in the United States
GCR  Gas Cost Rate
GDPGross Domestic Product
GHGGreenhouse Gas
GSAGeneration Supply Adjustment
GWhsGigawatt hours
ICCIllinois Commerce Commission
IIJAInfrastructure Investment and Jobs Act
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GLOSSARY OF TERMS AND ABBREVIATIONS
Other Terms and Abbreviations
IIPInfrastructure Investment Program
Illinois Settlement LegislationLegislation enacted in 2007 affecting electric utilities in Illinois
IPAIllinois Power Agency
IRAInflation Reduction Act
IRCInternal Revenue Code
IRSInternal Revenue Service
ISOsIndependent System Operators
LNGLiquefied Natural Gas
LTIPLong-Term Incentive Plan
LTRRPPLong-Term Renewable Resources Procurement Plan
MDPSCMaryland Public Service Commission
MGPManufactured Gas Plant
mmcfMillion Cubic Feet
MRPMulti-Year Rate Plan
MRVMarket-Related Value
MWMegawatt
MWhMegawatt hour
N/ANot Applicable
NAVNet Asset Value
NDTNuclear Decommissioning Trust
NERCNorth American Electric Reliability Corporation
NJBPU  New Jersey Board of Public Utilities
NOLCTax Net Operating Loss Carryforward
NPDESNational Pollutant Discharge Elimination System
NPNSNormal Purchase Normal Sale scope exception
NPSNational Park Service
NRDNatural Resources Damages
OCIOther Comprehensive Income
OPEBOther Postretirement Employee Benefits
PAPUCPennsylvania Public Utility Commission
PCBsPolychlorinated Biphenyls
PGCPurchased Gas Cost Clause
PJMPJM Interconnection, LLC
PJM TariffPJM Open Access Transmission Tariff
PLRPrivate Letter Ruling
POLRProvider of Last Resort
PPAPurchase Power Agreement
PP&EProperty, Plant, and Equipment
PRPsPotentially Responsible Parties
PSEGPublic Service Enterprise Group Incorporated
RCRAResource Conservation and Recovery Act of 1976, as amended
RECRenewable Energy Credit which is issued for each megawatt hour of generation from a qualified renewable energy source
Regulatory Agreement UnitsNuclear generating units or portions thereof whose decommissioning-related activities are subject to regulatory agreements with the ICC and PAPUC
RESRetail Electric Suppliers
RFPRequest for Proposal
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GLOSSARY OF TERMS AND ABBREVIATIONS
Other Terms and Abbreviations
RiderReconcilable Surcharge Recovery Mechanism
RGGIRegional Greenhouse Gas Initiative
ROE  Return on Equity
ROURight-of-use
RPSRenewable Energy Portfolio Standards
RTORegional Transmission Organization
S&PStandard & Poor’s Ratings Services
SECUnited States Securities and Exchange Commission
SOASociety of Actuaries
SOFRSecured Overnight Financing Rate
SOSStandard Offer Service
SSASocial Security Administration
TCJATax Cuts and Jobs Act
Transition Bonds  Transition Bonds issued by Atlantic City Electric Transition Funding LLC
USAOUnited States Attorney's Office for the Northern District of Illinois
ZECZero Emission Credit
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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.
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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.

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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 CompanyPurchase and regulated retail sale of electricityNorthern Illinois, including the City of Chicago
Transmission and distribution of electricity to retail customers
PECO Energy CompanyPurchase and regulated retail sale of electricity and natural gasSoutheastern Pennsylvania, including the City of Philadelphia (electricity)
Transmission and distribution of electricity and distribution of natural gas to retail customersPennsylvania counties surrounding the City of Philadelphia (natural gas)
Baltimore Gas and Electric CompanyPurchase and regulated retail sale of electricity and natural gasCentral 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 LLCUtility services holding company engaged, through its reportable segments: Pepco, DPL, and ACEService 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 CompanyPurchase and regulated retail sale of electricity and natural gasPortions of Delaware and Maryland (electricity)
Transmission and distribution of electricity and distribution of natural gas to retail customersPortions of New Castle County, Delaware (natural gas)
Atlantic City Electric CompanyPurchase and regulated retail sale of electricityPortions 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.
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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:
ComEdPECOBGEPepcoDPLACE
Service Territories (in square miles)
Electric11,450 1,900 2,550 650 5,400 2,700 
Natural GasN/A1,900 3,050 N/A250 N/A
Total(a)
11,450 2,100 3,250 650 5,400 2,700 
Service Territory Population (in millions)
Electric9.5 4.2 3.0 2.5 1.5 1.2 
Natural GasN/A2.6 2.9 N/A0.6N/A
Total(b)
9.5 4.2 3.2 2.5 1.5 1.2 
Main CityChicagoPhiladelphiaBaltimoreDistrict of ColumbiaWilmingtonAtlantic City
Main City Population2.7 1.6 0.6 0.7 0.1 0.1 
Number of Customers (in millions)
Electric4.2 1.7 1.4 1 0.6 0.6 
Natural GasN/A0.6 0.7 N/A0.1N/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:
RegistrantCommission
ComEdICC
PECOPAPUC
BGEMDPSC
PepcoDCPSC/MDPSC
DPLDEPSC/MDPSC
ACENJBPU
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 FacilityPropane-Air Plant
Underground Storage Service Agreements(a)
PECO1,200 150 19,400 
BGE1,056 550 22,000 
DPL250 N/A3,900 
___________
(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)
ComEdPECOBGE
PHI(b)
PepcoDPLACE
Total Employees20,571 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 CBAsNumber of CBAs
CBAs New and Renewed in 2025(a)
Total Employees Under CBAs
New and Renewed
in 2025
Exelon8,656 10 2 941 
ComEd3,543 2 1 73 
PECO1,524 2 — — 
BGE1,495 1 — — 
PHI2,094 5 1 868 
Pepco861 1 1 861 
DPL650 2 — — 
ACE397 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.
EmployeesExelonComEdPECOBGEPHIPepcoDPLACE
Retirement Age2.39 %2.72 %2.54 %2.06 %2.17 %2.00 %2.40 %2.10 %
Voluntary2.58 %2.40 %2.06 %1.82 %2.78 %2.82 %1.29 %2.58 %
Non-Voluntary0.96 %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
NameAgePositionPeriod
Butler Jr., Calvin G.56President and Chief Executive Officer, Exelon2022 - Present
Chief Operating Officer, Exelon2021 - 2022
Senior Executive Vice President, Exelon2019 - 2022
Chief Executive Officer, Exelon Utilities2019 - 2022
Honorable, Colette55Executive Vice President, Chief Legal Officer, Compliance and Corporate Secretary, Exelon2026 - Present
Chief Legal Officer and Corporate Secretary2024 - 2025
Executive Vice President, Public Policy2023 - 2024
Chief External Affairs Officer2023 - 2024
Partner, Reed Smith LLP2017 - 2023
Innocenzo, Michael A.60Executive Vice President and Chief Operating Officer, Exelon2024 - Present
President and Chief Executive Officer, PECO2018 - 2024
Jones, Jeanne46Executive Vice President, Chief Finance Officer, Audit and Risk, Exelon2026 - Present
Executive Vice President and Chief Financial Officer, Exelon2022 - 2025
Senior Vice President, Corporate Finance, Exelon2021 - 2022
Senior Vice President and Chief Financial Officer, ComEd2018 - 2021
Kleczynski, Robert A.57Senior Vice President, Controller and Tax, Exelon2023 - Present
Senior Vice President, Tax, Exelon2020 - 2023
Peterson, Timothy49Executive Vice President, Chief Customer & Technology Officer, Exelon2026 - Present
Senior Vice President, Chief Technology Officer, Xcel Energy2019-2026
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ComEd
NameAgePositionPeriod
Quiniones, Gil59President, ComEd2024 - Present
Chief Executive Officer, ComEd2021 - Present
President and Chief Executive Officer, New York Power Authority2011 - 2021
Levin, Joshua46Senior Vice President, Chief Financial Officer & Treasurer, ComEd2023 - Present
Vice President, Corporate Finance, Planning and Analysis2021 - 2023
Director of Financial Planning and Analysis, ComEd2019-2021
Perez, David R. 56Executive Vice President and Chief Operating Officer, ComEd2024 - Present
Senior Vice President, Distribution Operations, ComEd2019 - 2023
Rippie, E. Glenn65Senior Vice President and General Counsel, ComEd2022 - Present
Senior Vice President and Deputy General Counsel, Energy Regulation, Exelon2022 - Present
Partner, Jenner & Block LLP2019 - 2022
Washington, Melissa56Senior Vice President, Governmental, Regulatory and External Affairs, ComEd2025 - Present
Senior Vice President, Customer Operations, ComEd
2021 - 2025
Senior Vice President, Governmental and External Affairs, ComEd2019 - 2021
PECO
NameAgePositionPeriod
Vahos, David53President and Chief Executive Officer, PECO2025 - Present
Senior Vice President, Chief Financial Officer, and Treasurer, PHI2024 - 2025
Senior Vice President, Chief Financial Officer, and Treasurer, BGE2016 - 2024
Gay, Anthony60Vice President and General Counsel, PECO2019 - Present
Humphrey, Marissa46Senior Vice President, Chief Financial Officer and Treasurer, PECO2022 - Present
Vice President, Regulatory Policy and Strategy (NJ/DE), PHI, DPL, and ACE2021 - 2022
Levine, Nicole49Senior Vice President and Chief Operations Officer, PECO2022 - Present
Vice President, Electrical Operations, PECO2018 - 2022
Oliver, Douglas51Senior Vice President, Governmental, Regulatory and External Affairs, PECO2023 - Present
Vice President, Governmental and External Affairs, PECO2019 - 2023
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BGE
NameAgePositionPeriod
Olivier, Tamla 53President and Chief Executive Officer, BGE2025 - Present
Senior Vice President and Chief Operating Officer, PHI, Pepco, DPL, and ACE2021 - 2025
Senior Vice President, Customer Operations, BGE2020 - 2021
Cloyd, Michael55Senior Vice President, Chief Financial Officer, and Treasurer, BGE2024 - Present
Vice President, Support Services, BGE2021 - 2024
Dickens, Derrick61Senior Vice President and Chief Operating Officer, BGE2021 - Present
Senior Vice President, Customer Operations, PHI, Pepco, DPL, and ACE2020 - 2021
Ralph, David59Vice President and General Counsel, BGE2021 - Present
Associate General Counsel, BGE2019 - 2021
PHI, Pepco, DPL, and ACE
NameAgePositionPeriod
Anthony, J. Tyler61President and Chief Executive Officer, PHI, Pepco, DPL, and ACE2021 - Present
Senior Vice President and Chief Operating Officer, PHI, Pepco, DPL, and ACE2016 - 2021
Bancroft, Anne59Vice President and General Counsel, PHI, Pepco, DPL, and ACE2021 - Present
Associate General Counsel, Exelon2017 - 2021
Oddoye, Rodney49Senior Vice President and Chief Operating Officer2025 - Present
Senior Vice President, Governmental, Regulatory and External Affairs, PHI, Pepco, DPL, and ACE2021 - 2025
Cantler, Jaclyn46Senior Vice President, Governmental, Regulatory and External Affairs, PHI, DPL, and ACE2025 - Present
Vice President, Pepco Electric Operations, PHI, Pepco2024 - 2025
Vice President, Projects and Contracts, PHI, Pepco, DPL, and ACE2021 - 2024
O'Donnell, Morgan50Senior Vice President, Chief Financial Officer, and Treasurer, PHI, Pepco, DPL, and ACE2025 - Present
Vice President, Regulatory Policy and Strategy, PHI, Pepco and DPL2021 - 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:
VoltageCircuit Miles
(Volts)ComEdPECOBGEPepcoDPLACE
765,00090—————
500,000(a)
—19121610916—
345,0002,678—————
230,000—550352794472259
138,0002,2681355561587215
115,000——70026——
69,000—178——570675
___________
(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 MilesComEdPECOBGEPepcoDPLACE
Overhead35,34912,9729,1014,1726,0147,349
Underground33,1809,89818,2627,4126,7153,149
Gas
The following table presents PECO’s, BGE’s, and DPL’s natural gas pipeline miles as of December 31, 2025.
PECOBGEDPL
Transmission(a)
61468
Distribution7,3497,6512,183
Service piping6,5906,5561,502
Total13,94514,3533,693
___________
(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.
RegistrantFacilityLocationStorage Capacity
(mmcf)		Send-out or Peaking Capacity
(mmcf/day)
PECOLNG FacilityWest Conshohocken, PA1,200195
PECOPropane Air PlantChester, PA10525
BGELNG FacilityBaltimore, MD1,056332
BGEPropane Air PlantBaltimore, MD55085
DPLLNG FacilityWilmington, DE25060
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,
202020212022202320242025
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:
20252024
(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:
20252024
(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 
PECO136 137 136 137 100 100 100 100 
BGE99 98 98 98 92 92 92 92 
PHI162 256 160 132 157 267 164 118 
Pepco60 109 92 66 73 133 102 51 
DPL53 59 44 46 58 78 39 45 
ACE51 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.
20252024Favorable (Unfavorable) Variance
Exelon$2,768 $2,460 $308 
ComEd1,147 1,066 81 
PECO814 551 263 
BGE578 527 51 
PHI799 741 58 
Pepco401 390 11 
DPL224 209 15 
ACE188 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: 
20252024
(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/JurisdictionFiling DateServiceRequested Revenue Requirement Increase Approved Revenue Requirement Increase Approved ROEApproval DateRate Effective Date
ComEd - IllinoisJanuary 17, 2023Electric$1,487 $1,045 8.905%December 19, 2024January 1, 2024
April 26, 2024 (amended on September 11, 2024)Electric$624 $623 9.89%October 31, 2024January 1, 2025
PECO - PennsylvaniaMarch 28, 2024Electric$464 $354 N/ADecember 12, 2024January 1, 2025
Natural Gas$111 $78 
BGE - MarylandFebruary 17, 2023Electric$313 $179 9.50%December 14, 2023January 1, 2024
Natural Gas$289 $229 9.45%
Pepco - District of ColumbiaApril 13, 2023 (amended February 27, 2024)Electric$186 $123 9.50%November 26, 2024January 1, 2025
Pepco - MarylandMay 16, 2023 (amended February 23, 2024)Electric$111 $45 9.50%June 10, 2024April 1, 2024
DPL - MarylandMay 19, 2022Electric$38 $29 9.60%December 14, 2022January 1, 2023
DPL - DelawareDecember 15, 2022 (amended September 29, 2023)Electric$39 $28 9.60%April 18, 2024July 15, 2023
September 20, 2024 (amended September 5, 2025)Natural Gas$37 $22 9.60%December 17, 2025January 1, 2026
ACE - New JerseyFebruary 15, 2023 (amended August 21, 2023)Electric$92 $45 9.60%November 17, 2023December 1, 2023
November 21, 2024Electric$109 $54 9.60%November 21, 2025December 1, 2025
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Pending Distribution Base Rate Case Proceedings
Registrant/JurisdictionFiling DateServiceRequested Revenue Requirement IncreaseRequested ROEExpected Approval Timing
Pepco - MarylandOctober 14, 2025Electric$133 10.50%Third quarter of 2026
DPL - DelawareDecember 9, 2025Electric$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.
RegistrantInitial Revenue Requirement Increase (Decrease)Annual Reconciliation Increase (Decrease)Total Revenue Requirement Increase (Decrease)Allowed Return on Rate BaseAllowed 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)ExelonComEdPECOBGEPHIPepcoDPLACE
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.
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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 AssumptionPensionOPEBChange in
Assumption		PensionOPEBTotal
Change in 2025 cost:
Discount rate(a)
5.68%5.64%0.5%$(16)$(2)$(18)
5.68%5.64%(0.5)%$18 $2 $20 
EROA7.00%6.50%0.5%$(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
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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.

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ComEd
Results of Operations by Registrant
Results of Operations—ComEd
20252024(Unfavorable) Favorable Variance
Operating revenues$7,267 $8,219 $(952)
Operating expenses
Purchased power1,782 3,042 1,260 
Operating and maintenance1,710 1,703 (7)
Depreciation and amortization1,560 1,514 (46)
Taxes other than income taxes409 376 (33)
Total operating expenses5,461 6,635 1,174 
Gain on sales of assets— 5 (5)
Operating income1,806 1,589 217 
Other income and (deductions)
Interest expense, net(530)(501)(29)
Other, net132 94 38 
Total other income and (deductions)(398)(407)9 
Income before income taxes1,408 1,182 226 
Income taxes261 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$297 
Transmission— 
Energy efficiency32 
Other (47)
282 
Regulatory required programs(1,234)
Total decrease$(952)

Revenue Decoupling. The demand for electricity is affected by weather and customer usage. Operating revenues are not intended to be impacted by abnormal weather, usage per customer, or number of customers as a result of revenue decoupling mechanisms.
Distribution Revenue. Starting in 2024, distribution revenues are under a MRP. The MRP requires an annual reconciliation of the revenue requirement in effect to the actual costs the ICC determines are prudently and reasonably incurred. Electric distribution revenue varies from year to year based upon fluctuations in the underlying costs, (e.g., severe weather and storm restoration), investments being recovered, and allowed ROE. Electric distribution revenue increased during the year ended December 31, 2025, compared to the same period in 2024, primarily due to higher fully recoverable costs, higher rate base, and higher return on regulatory assets.
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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 $1,260 million decrease in Purchased power expense for the year ended December 31, 2025 compared to the same period in 2024, which includes the impacts of CMC nuclear production tax credits, is offset in Operating revenues as part of regulatory required programs. See Note 2 — Regulatory Matters for additional information.
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ComEd
The changes in Operating and maintenance expense consisted of the following:
2025 vs. 2024
(Decrease) Increase
Labor, other benefits, contracting, and materials$(9)
BSC costs(14)
Pension and non-pension postretirement benefits expense5 
Storm-related costs2 
(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.
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PECO
Results of Operations—PECO
20252024Favorable (Unfavorable) Variance
Operating revenues$4,684 $3,973 $711 
Operating expenses
Purchased power and fuel1,733 1,477 (256)
Operating and maintenance1,195 1,120 (75)
Depreciation and amortization454 428 (26)
Taxes other than income taxes240 218 (22)
Total operating expenses3,622 3,243 (379)
Gain on sales of assets — 4 (4)
Operating income1,062 734 328 
Other income and (deductions)
Interest expense, net(260)(232)(28)
Other, net41 37 4 
Total other income and (deductions)(219)(195)(24)
Income before income taxes843 539 304 
Income taxes29 (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)
ElectricGasTotal
Weather$27 $32 $59 
Volume(27)2 (25)
Pricing321 91 412 
Transmission4 — 4 
Other10 2 12 
335 127 462 
Regulatory required programs168 81 249 
Total increase$503 $208 $711 
Weather. The demand for electricity and natural gas is affected by weather conditions. With respect to the electric business, very warm weather in summer months and, with respect to the electric and natural gas businesses, very cold weather in winter months are referred to as “favorable weather conditions” because these weather conditions result in increased deliveries of electricity and natural gas. Conversely, mild weather reduces demand. For the year ended December 31, 2025, compared to the same period in 2024, Operating revenues related to weather increased due to favorable weather conditions in PECO's service territory.
Heating and cooling degree days are quantitative indices that reflect the demand for energy needed to heat or cool a home or business. Normal weather is determined based on historical average heating and cooling degree days for a 30-year period in PECO’s service territory. The changes in heating and cooling degree days in PECO’s service territory for the year ended December 31, 2025, compared to the same period in 2024, and normal weather consisted of the following:
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PECO
 For the Years Ended December 31, % Change
PECO Service Territory20252024Normal2025 vs. 20242025 vs. Normal
Heating Degree-Days4,274 3,786 4,348 12.9 %(1.7)%
Cooling Degree-Days1,547 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)20252024% Change
Weather - Normal % Change(b)
Residential14,078 13,963 0.8 %(1.5)%
Small commercial & industrial7,537 7,683 (1.9)%(3.0)%
Large commercial & industrial13,683 13,889 (1.5)%(2.2)%
Public authorities & electric railroads678 613 10.6 %11.0 %
Total electric retail deliveries(a)
35,976 36,148 (0.5)%(1.9)%

 At December 31,
Number of Electric Customers20252024
Residential1,541,970 1,533,443 
Small commercial & industrial154,841 155,164 
Large commercial & industrial3,158 3,150 
Public authorities & electric railroads10,248 10,708 
Total1,710,217 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)20252024% Change
Weather - Normal % Change(b)
Residential43,189 38,328 12.7 %1.6 %
Small commercial & industrial23,709 21,906 8.2 %0.6 %
Large commercial & industrial15 17 (11.8)%(2.2)%
Transportation24,204 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 Customers20252024
Residential510,959 508,224 
Small commercial & industrial44,698 44,846 
Large commercial & industrial7 7 
Transportation617 644 
Total556,281 553,721 
__________
(a)Reflects delivery volumes from customers purchasing natural gas directly from PECO and customers purchasing natural gas from a competitive natural gas supplier as all customers are assessed distribution charges.
(b)Reflects the change in delivery volumes assuming normalized weather based on the historical 30-year average.
Pricing for the year ended December 31, 2025, compared to the same period in 2024, increased primarily due to electric and gas distribution rates charged to customers.
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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 expense8 
Pension and non-pension postretirement benefits expense4 
Storm-related costs3 
BSC costs2 
Other22 
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.
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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.
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BGE
Results of Operations—BGE
20252024Favorable (Unfavorable) Variance
Operating revenues$5,222 $4,426 $796 
Operating expenses
Purchased power and fuel2,221 1,651 (570)
Operating and maintenance1,066 1036 (30)
Depreciation and amortization632 638 6 
Taxes other than income taxes370 345 (25)
Total operating expenses4,289 3,670 (619)
Operating income933 756 177 
Other income and (deductions)
Interest expense, net(247)(216)(31)
Other, net51 36 15 
Total other income and (deductions)(196)(180)(16)
Income before income taxes737 576 161 
Income taxes159 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
ElectricGasTotal
Distribution$82 $62 $144 
Transmission6 — 6 
Other11 — 11 
99 62 161 
Regulatory required programs471 164 635 
Total increase$570 $226 $796 
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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 Customers20252024
Residential1,222,397 1,216,614 
Small commercial & industrial 115,197 115,010 
Large commercial & industrial 13,445 13,266 
Public authorities & electric railroads252 260 
Total1,351,291 1,345,150 
At December 31,
Number of Natural Gas Customers20252024
Residential660,986 658,776 
Small commercial & industrial37,759 37,874 
Large commercial & industrial6,417 6,369 
Total705,162 703,019 
Distribution Revenue increased for the year ended December 31, 2025 compared to the same period in 2024, due to favorable impacts of the multi-year plans.
Transmission Revenue. Under a FERC-approved formula, transmission revenue varies from year to year based upon fluctuations in the underlying costs and capital investments being recovered. Transmission revenue increased for the year ended December 31, 2025 compared to the same period in 2024 primarily due to increases in underlying costs and capital investments.
Other Revenue includes revenue related to late payment charges, mutual assistance, off-system sales, and service application fees. Other Revenue increased for the year ended December 31, 2025 compared to the same period in 2024, primarily driven by an increase in service application fees.
Regulatory Required Programs represent revenues collected under approved riders to recover costs incurred for regulatory programs such as conservation, demand response, and the POLR mechanism. The riders are designed to provide full and current cost recovery, as well as a return in certain instances. The costs of these programs are included in Purchased power and fuel expense, Operating and maintenance expense, Depreciation and amortization expense, and Taxes other than income taxes. Customers have the choice to purchase electricity and natural gas from competitive electric generation and natural gas suppliers. Customer choice programs do not impact the volume of deliveries as BGE remains the distribution service provider for all customers and charges a regulated rate for distribution service, which is recorded in Operating revenues. For customers that choose to purchase electric generation or natural gas from competitive suppliers, BGE acts as the billing agent and therefore does not record Operating revenues or Purchased power and fuel expense related to the electricity and/or natural gas. For customers that choose to purchase electric generation or natural gas from BGE, BGE is permitted to recover the electricity and natural gas procurement costs from customers and therefore records the amounts related to the electricity and/or natural gas in Operating revenues and Purchased power and fuel expense. BGE recovers electricity and natural gas procurement costs from customers with a slight mark-up.
See Note 4 — Segment Information of the Combined Notes to Consolidated Financial Statements for the presentation of BGE's revenue disaggregation.
The increase of $570 million for the year ended December 31, 2025 compared to the same period in 2024 in Purchased power and fuel expense is fully offset in Operating revenues as part of regulatory required programs.
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BGE
The changes in Operating and maintenance expense consisted of the following:
2025 vs. 2024
Increase (Decrease)
BSC costs$5 
Credit loss expense1 
Labor, other benefits, contracting, and materials1 
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.
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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.
20252024Favorable Variance
PHI$799 $741 $58 
Pepco401 390 11 
DPL224 209 15 
ACE188 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.
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Pepco
Results of Operations—Pepco
20252024Favorable (Unfavorable) Variance
Operating revenues$3,454 $3,039 $415 
Operating expenses
    Purchased power1,262 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 expenses2,775 2,420 (355)
(Loss) gain on sales of assets1 (1)2 
Operating income680 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 taxes507 480 27 
Income taxes106 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 
Transmission27 
Other(9)
153 
Regulatory required programs262 
Total increase$415 
Revenue Decoupling. The demand for electricity is affected by weather and customer usage. However, Operating revenues from electric distribution in both Maryland and the District of Columbia are not intended to be impacted by abnormal weather or usage per customer as a result of a BSA that provides for a fixed distribution charge per customer class in the District of Columbia and per customer by customer class in Maryland. Therefore, changes in the number of customers only impacts Operating revenues in Maryland. See Note 2 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information on revenue decoupling Pepco Maryland.
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Pepco
At December 31,
Number of Electric Customers in Maryland20252024
Residential560,304 556,239 
Small commercial & industrial30,548 30,571 
Large commercial & industrial19,078 18,989 
Public authorities & electric railroads179 179 
Total610,109 605,978 
Distribution Revenue increased for the year ended December 31, 2025 compared to the same period in 2024, primarily due to the favorable impacts of the Maryland and District of Columbia multi-year plans and customer growth in Maryland.
Transmission Revenue. Under a FERC-approved formula, transmission revenue varies from year to year based upon fluctuations in the underlying costs and capital investments being recovered. Transmission revenue increased for the year ended December 31, 2025 compared to the same period in 2024 primarily due to increases in underlying costs and capital investment.
Other Revenue includes rental revenue, revenue related to late payment charges, mutual assistance revenues, and recoveries of other taxes.
Regulatory Required Programs represent revenues collected under approved riders to recover costs incurred for regulatory programs such as energy efficiency programs, DC PLUG, and SOS procurement and administrative costs. The riders are designed to provide full and current cost recovery as well as a return in certain instances. The costs of these programs are included in Purchased power expense, Operating and maintenance expense, Depreciation and amortization expense, and Taxes other than income taxes. Customers have the choice to purchase electricity from competitive electric generation suppliers. Customer choice programs do not impact the volume of deliveries, as Pepco remains the distribution service provider for all customers and charges a regulated rate for distribution service, which is recorded in Operating revenues. For customers that choose to purchase electric generation from competitive suppliers, Pepco acts as the billing agent and therefore, Pepco does not record Operating revenues or Purchased power expense related to the electricity. For customers that choose to purchase electric generation from Pepco, Pepco is permitted to recover the electricity and REC procurement costs from customers and therefore records the amounts related to the electricity and RECs in Operating revenues and Purchased power expense. Pepco recovers electricity and REC procurement costs from customers with a slight mark-up.
See Note 4 — Segment Information of the Combined Notes to Consolidated Financial Statements for the presentation of Pepco's revenue disaggregation.
The increase of $207 million for the year ended December 31, 2025 compared to the same period in 2024, in Purchased power expense is fully offset in Operating revenues as part of regulatory required programs.

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Pepco
The changes in Operating and maintenance expense consisted of the following:
2025 vs. 2024
Increase (Decrease)
Labor, other benefits, contracting, and materials$26 
Maryland multi-year plan reconciliations (a)
23 
Credit loss expense2 
Pension and non-pension postretirement benefits expense1 
Storm-related costs1 
BSC and PHISCO costs(5)
Other7 
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 amortization6 
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.

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DPL
Results of Operations—DPL
20252024Favorable (Unfavorable) Variance
Operating revenues$1,971 $1,787 $184 
Operating expenses
Purchased power and fuel861 760 (101)
Operating and maintenance
391 377 (14)
Depreciation and amortization
252 245 (7)
Taxes other than income taxes
88 79 (9)
Total operating expenses1,592 1,461 (131)
Operating income379 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 taxes293 258 35 
Income taxes69 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)
ElectricGasTotal
Weather$8 $3 $11 
Volume(4)7 3 
Distribution20 14 34 
Transmission19 — 19 
Other(1)— (1)
42 24 66 
Regulatory required programs90 28 118 
Total increase$132 $52 $184 
Revenue Decoupling. The demand for electricity is affected by weather and customer usage. However, Operating revenues from electric distribution in Maryland are not intended to be impacted by abnormal weather or usage per customer as a result of a BSA that provides for a fixed distribution charge per customer by customer class. While Operating revenues from electric distribution customers in Maryland are not impacted by abnormal weather or usage per customer, they are impacted by changes in the number of customers. See Note 2 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information on revenue decoupling for DPL Maryland.
Weather. The demand for electricity and natural gas in Delaware is affected by weather conditions. With respect to the electric business, very warm weather in summer months and, with respect to the electric and natural gas businesses, very cold weather in winter months are referred to as "favorable weather conditions” because these weather conditions result in increased deliveries of electricity and natural gas. Conversely, mild weather reduces demand. During the year ended December 31, 2025 compared to the same period in 2024, Operating revenues
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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 Territory20252024Normal2025 vs. 20242025 vs. Normal
Heating Degree-Days4,500 4,100 4,477 9.8 %0.5 %
Cooling Degree-Days1,309 1,277 1,302 2.5 %0.5 %
For the Years Ended December 31,% Change
Delaware Natural Gas Service Territory20252024Normal2025 vs. 20242025 vs. Normal
Heating Degree-Days4,500 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)20252024% Change
Weather - Normal % Change (b)
Residential3,288 3,227 1.9 %(1.4)%
Small commercial & industrial1,459 1,445 1.0 %0.2 %
Large commercial & industrial3,049 3,019 1.0 %0.6 %
Public authorities & electric railroads31 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)20252024
Residential495,254 490,626 
Small commercial & industrial65,500 64,813 
Large commercial & industrial1,273 1,255 
Public authorities & electric railroads634 606 
Total562,661 557,300 
__________
(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)20252024% Change
Weather - Normal % Change(b)
Residential9,052 7,810 15.9 %7.5 %
Small commercial & industrial4,339 3,801 14.2 %5.5 %
Large commercial & industrial1,680 1,674 0.4 %0.4 %
Transportation 6,355 6,206 2.4 %(0.3)%
Total natural gas deliveries(a)
21,426 19,491 9.9 %4.1 %

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DPL
At December 31,
Number of Delaware Natural Gas Customers20252024
Residential132,148 131,392 
Small commercial & industrial10,255 10,218 
Large commercial & industrial14 14 
Transportation160 162 
Total142,577 141,786 
__________
(a)Reflects delivery volumes from customers purchasing natural gas directly from DPL and customers purchasing natural gas from a competitive natural gas supplier as all customers are assessed distribution charges.
(b)Reflects the change in delivery volumes assuming normalized weather based on the historical 30-year average.
Distribution Revenue increased for the year ended December 31, 2025 compared to the same period in 2024 primarily due to Delaware electric DSIC rates and natural gas rates that became effective in 2025.
Transmission Revenue. Under a FERC-approved formula, transmission revenue varies from year to year based upon fluctuations in the underlying costs and capital investments being recovered. Transmission revenue increased for the year ended December 31, 2025 compared to the same period in 2024 primarily due to increases in underlying costs and capital investment.
Other Revenue includes rental revenue, revenue related to late payment charges, mutual assistance revenues, and recoveries of other taxes.
Regulatory Required Programs represent revenues collected under approved riders to recover costs incurred for regulatory programs such as energy efficiency programs, DE Renewable Portfolio Standards, SOS procurement and administrative costs, and GCR costs. The riders are designed to provide full and current cost recovery as well as a return in certain instances. The costs of these programs are included in Purchased power and fuel expense, Operating and maintenance expense, Depreciation and amortization expense, and Taxes other than income taxes. All customers have the choice to purchase electricity from competitive electric generation suppliers; however, only certain commercial and industrial customers have the choice to purchase natural gas from competitive natural gas suppliers. Customer choice programs do not impact the volume of deliveries as DPL remains the distribution service provider for all customers and charges a regulated rate for distribution service, which is recorded in Operating revenues. For customers that choose to purchase electric generation or natural gas from competitive suppliers, DPL either acts as the billing agent or the competitive supplier separately bills its own customers, and therefore does not record Operating revenues or Purchased power and fuel expense related to the electricity and/or natural gas. For customers that choose to purchase electric generation or natural gas from DPL, DPL is permitted to recover the electricity, natural gas, and REC procurement costs from customers and therefore records the amounts related to the electricity, natural gas, and RECs in Operating revenues and Purchased power and fuel expense. DPL recovers electricity and REC procurement costs from customers with a slight mark-up, and natural gas costs without mark-up.
See Note 4 — Segment Information of the Combined Notes to Consolidated Financial Statements for the presentation of DPL's revenue disaggregation.
The increase of $101 million for the year ended December 31, 2025 compared to the same period in 2024, in Purchased power and fuel expense is fully offset in Operating revenues as part of regulatory required programs.
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DPL
The changes in Operating and maintenance expense consisted of the following:
2025 vs. 2024
Increase (Decrease)
Credit loss expense$3 
Pension and non-pension postretirement benefits expense1 
Labor, other benefits, contracting, and materials(2)
BSC and PHISCO costs(5)
Storm-related costs(5)
Other3 
$(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.
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ACE
Results of Operations—ACE
20252024Favorable (Unfavorable) Variance
Operating revenues$1,718 $1,628 $90 
Operating expenses
Purchased power808 698 (110)
Operating and maintenance
328 368 40 
Depreciation and amortization
248 278 30 
Taxes other than income taxes
9 9 — 
Total operating expenses1,393 1,353 (40)
Gain on sale of assets2 — 2 
Operating income327 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 taxes255 210 45 
Income taxes67 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 
Other3 
9 
Regulatory required programs81 
Total increase$90 
Revenue Decoupling. The demand for electricity is affected by weather and customer usage. However, Operating revenues from electric distribution in New Jersey are not intended to be impacted by abnormal weather or usage per customer as a result of the CIP which compares current distribution revenues by customer class to approved target revenues established in ACE’s most recent distribution base rate case. The CIP is calculated annually, and recovery is subject to certain conditions, including an earnings test and ceilings on customer rate increases. While Operating revenues are not impacted by abnormal weather or usage per customer, they are impacted by changes in the number of customers. See Note 2 — Regulatory Matters of the Combined Notes to the Consolidated Financial Statements for additional information on the ACE CIP.

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ACE
At December 31,
Number of Electric Customers20252024
Residential510,005 507,483 
Small commercial & industrial63,154 62,739 
Large commercial & industrial2,682 2,843 
Public authorities & electric railroads754 714 
Total576,595 573,779 
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$3 
BSC and PHISCO costs(10)
Labor, other benefits, contracting and materials(a)
(33)
Other(1)
(41)
Regulatory required programs1 
Total decrease$(40)
__________
(a)Reflects a decrease in contracting costs for the year ended December 31, 2025, resulting from the favorable impacts of the ACE Electric Distribution Base Rate Case, including the recognition of the regulatory asset and corresponding decrease in O&M associated with work stoppage costs that were incurred by ACE in 2023. See Note 2 — Regulatory Matters for additional information.

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ACE
The changes in Depreciation and amortization expense consisted of the following:
2025 vs. 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.
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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 activitiesExelonComEdPECOBGEPHIPepcoDPLACE
Net income (loss)$308 $81 $263 $51 $58 $11 $15 $33 
Adjustments to reconcile net income to cash:
Non-cash operating activities1,058 617 43 207 98 131 40 (56)
Collateral (paid) received, net(43)(66)6 5 17 12 — 5 
Income taxes125 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, net206 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 $804 million of nuclear production tax credits, which is reported within the cash flows from operations as a change in Accounts receivable. This change is offset by an increase in the Carbon mitigation credit regulatory liability. See Note 2 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.
Cash Flows from Investing Activities
The following table provides a summary of the change in cash flows from investing activities for the years ended December 31, 2025 and 2024 by Registrant:
(Decrease) increase in cash flows from investing activitiesExelonComEdPECOBGEPHIPepcoDPLACE
Capital expenditures$(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 $(15)
Significant investing cash flow impacts for the Registrants for 2025 and 2024 were as follows:
•Variances in Capital expenditures are primarily due to the timing of cash expenditures for capital projects. See the "Credit Matters and Cash Requirements" section below for additional information on projected capital expenditure spending for the Registrants.
Cash Flows from Financing Activities
The following table provides a summary of the change in cash flows from financing activities for the years ended December 31, 2025 and 2024 by Registrant:
Increase (decrease) in cash flows from financing activitiesExelonComEdPECOBGEPHIPepcoDPLACE
Changes in short-term borrowings, net$(583)$530 $(219)$(14)$(54)$35 $(64)$(25)
Long-term debt, net1,347 175 125 (150)(17)— (17)— 
Changes in intercompany money pool— — — — 19 — — — 
Issuance of common stock543 — — — — — — — 
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 activities8 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:
CompanyTypeInterest RateMaturityAmountUse of Proceeds
Exelon
Junior Subordinated Notes(a)
6.50%March 15, 2055$1,000Repay outstanding commercial paper obligations and for general corporate purposes.
ExelonNotes5.125%March 15, 2031500Repay outstanding commercial paper obligations and for general corporate purposes.
ExelonNotes5.875%March 15, 2055500Repay outstanding commercial paper obligations and for general corporate purposes.
Exelon Convertible Senior Notes3.25%March 15, 20291,000Repay or refinance debt and for general corporate purposes.
ComEdFirst Mortgage Bonds5.95%June 1, 2055725Repay outstanding commercial paper obligations and for general corporate purposes.
PECOFirst Mortgage Bonds4.875%September 15, 2035525Repay existing indebtedness, repay outstanding commercial paper obligations, and for general corporate purposes.
PECOFirst Mortgage Bonds5.65%September 15, 2055525Repay existing indebtedness, repay outstanding commercial paper obligations, and for general corporate purposes.
BGENotes5.45%June 1, 2035650Repay outstanding commercial paper obligations and for general corporate purposes.
PepcoFirst Mortgage Bonds5.78%September 17, 205575Repay existing indebtedness and for general corporate purposes.
PepcoFirst Mortgage Bonds5.48%March 26, 2040200Repay existing indebtedness and for general corporate purposes.
DPLFirst Mortgage Bonds5.28%March 26, 2035125Repay existing indebtedness and for general corporate purposes.
ACEFirst Mortgage Bonds5.28%March 26, 2035100Repay existing indebtedness and for general corporate purposes.
ACEFirst Mortgage Bonds5.54%November 19, 204075Repay existing indebtedness and for general corporate purposes.
ACEFirst Mortgage Bonds5.81%November 19, 205575Repay 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:
CompanyTypeInterest RateMaturityAmountUse of Proceeds
ExelonNotes5.15%March 15, 2029$650Repay existing indebtedness and for general corporate purposes.
ExelonNotes5.45%March 15, 2034650Repay existing indebtedness and for general corporate purposes.
ExelonNotes5.60%March 15, 2053400Repay existing indebtedness and for general corporate purposes.
ComEdFirst Mortgage Bonds5.30%June 1, 2034400Repay outstanding commercial paper obligations and to fund other general corporate purposes.
ComEdFirst Mortgage Bonds5.65%June 1, 2054400Repay outstanding commercial paper obligations and to fund other general corporate purposes.
PECOFirst Mortgage Bonds5.25%September 15, 2054575Refinance existing indebtedness, refinance outstanding commercial paper obligations, and for general corporate purposes.
BGENotes5.30%June 1, 2034400Repay outstanding commercial paper obligations, repay existing indebtedness, and for general corporate purposes.
BGENotes5.65%June 1, 2054400Repay existing indebtedness and for general corporate purposes.
PepcoFirst Mortgage Bonds5.20%March 15, 2034375Repay existing indebtedness and for general corporate purposes.
PepcoFirst Mortgage Bonds5.50%March 15, 2054300Repay existing indebtedness and for general corporate purposes.
PepcoFirst Mortgage Bonds5.24%March 20, 2034100Repay existing indebtedness and for general corporate purposes.
DPLFirst Mortgage Bonds5.55%March 20, 205475Repay existing indebtedness and for general corporate purposes.
DPLFirst Mortgage Bonds5.55%March 20, 205475Repay existing indebtedness and for general corporate purposes.
DPLFirst Mortgage Bonds5.29%August 28, 203475Repay existing indebtedness and for general corporate purposes.
DPLFirst Mortgage Bonds5.49%August 28, 2039100Repay existing indebtedness and for general corporate purposes.

During 2025, the following long-term debt was retired and/or redeemed:
CompanyTypeInterest RateMaturityAmount
ExelonSenior Notes3.95%June 15, 2025$807 
ExelonSoftware Licensing Agreement2.30%December 1, 20254 
PECOFirst Mortgage Bonds3.15%October 15, 2025350 
ACESenior Notes3.50%December 1, 2025150 
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During 2024, the following long-term debt was retired and/or redeemed:
Company (a)
TypeInterest RateMaturityAmount
ExelonSMBC Term Loan AgreementSOFR plus 0.85%April 8, 2024$500 
ExelonSoftware Licensing Agreement3.62%December 1, 20251 
ExelonSoftware Licensing Agreement3.95%May 1, 20242 
ExelonSoftware Licensing Agreement2.30%December 1, 20254 
ComEdFirst Mortgage Bonds3.10%November 1, 2024250 
PepcoFirst Mortgage Bonds3.60%March 15, 2024400 
DPL(b)
Unsecured tax-exempt bonds4.32%July 1, 202433 
ACEFirst Mortgage Bonds3.38%September 1, 2024150 

(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:
PeriodDeclaration DateShareholder of
Record Date		Dividend Payable Date
Cash per Share(a)
First Quarter 2025February 12, 2025February 24. 2025March 14, 2025$0.4000 
Second Quarter 2025April 29, 2025May 12, 2025June 13, 2025$0.4000 
Third Quarter 2025July 29, 2025August 11, 2025September 15, 2025$0.4000 
Fourth Quarter 2025October 29, 2025November 10, 2025December 15, 2025$0.4000 
First Quarter 2026February 12, 2026March 2, 2026March 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 
Pepco4 — 55 
DPL1 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)
ExelonN/AN/AN/A$9,950 $31,300 
ComEd1,100 2,425 N/A3,500 11,450 
PECO450 1,375 400 2,225 7,075 
BGE 1,075 575 525 2,175 6,100 
PHI725 1,250 50 2,050 6,650 
Pepco325 650 N/A975 2,925 
DPL225 325 50 625 2,175 
ACE175 275 N/A450 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 PlansNon-Qualified Pension PlansOPEB
Exelon$325 $19 $48 
ComEd217 3 22 
PECO9 1 4 
BGE32 2 14 
PHI48 7 6 
Pepco1 — 6 
DPL1 — — 
ACE14 — — 
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
2026Beyond 2026TotalTime 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 leases26 187 213 2026 - 2099
Fuel purchase agreements(c)
321 1,293 1,614 2026 - 2039
Electric supply procurement4,259 2,733 6,992 2026 - 2029
Long-term renewable energy and REC commitments290 7,716 8,006 2026 - 2044
ZEC commitments156 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
2026Beyond 2026TotalTime 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 procurement286 273 559 2026 - 2028
Long-term renewable energy and REC commitments268 7,606 7,874 2026 - 2044
ZEC commitments156 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
2026Beyond 2026TotalTime 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 leases1 — 1 2026 - 2035
Fuel purchase agreements(c)
156 578 734 2026 - 2039
Electric supply procurement767 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
2026Beyond 2026TotalTime 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 leases4 29 33 2026 - 2099
Fuel purchase agreements(b)
130 506 636 2026 - 2039
Electric supply procurement1,396 961 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
2026Beyond 2026TotalTime 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 leases13 66 79 2026 - 2032
Fuel purchase agreements(b)
35 209 244 2026 - 2031
Electric supply procurement1,810 1,322 3,132 2026 - 2029
Long-term renewable energy commitments22 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
2026Beyond 2026TotalTime 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 leases5 25 30 2026 - 2032
Electric supply procurement936 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
2026Beyond 2026TotalTime 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 leases6 37 43 2025 - 2031
Fuel purchase agreements(b)
35 209 244 2026 - 2031
Electric supply procurement474 307 781 2026 - 2028
Long-term renewable energy commitments22 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
2026Beyond 2026TotalTime 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 leases2 5 7 2026 - 2030
Electric supply procurement400 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:
ItemLocation within Notes to the Consolidated Financial Statements
Long-term debtNote 14 — Debt and Credit Agreements
Interest payments on long-term debtNote 14 — Debt and Credit Agreements
Finance leasesNote 9 — Leases
Operating leasesNote 9 — Leases
Long-term renewable energy and REC commitmentsNote 2 — Regulatory Matters
ZEC commitmentsNote 2 — Regulatory Matters
Pension contributionsNote 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:
ExelonComEdPECOBGEPHIPepcoDPLACE
Long-term debt62 %45 %45 %48 %41 %48 %48 %48 %
Long-term debt to affiliates(a)
— %1 %1 %— %— %— %— %— %
Common equity37 %54 %54 %52 %— %49 %49 %48 %
Member’s equity— %— %— %— %56 %— %— %— %
Commercial paper and notes payable1 %— %— %— %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, 2025As of December 31, 2025
Exelon Intercompany Money PoolMaximum ContributedMaximum BorrowedContributed (Borrowed)
Exelon Corporate$578 $— $250 
PECO336 (253)— 
BSC— (413)(233)
PHI Corporate— (85)(80)
PCI63 — 63 
For the Year Ended December 31, 2025As of December 31, 2025
PHI Intercompany Money PoolMaximum ContributedMaximum BorrowedContributed (Borrowed)
Pepco$20 $(35)$— 
DPL48 (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 AuthorityRemaining Long-term Financing Authority
CommissionExpiration DateAmountCommissionExpiration DateAmount
ComEd(a)(b)
FERCDecember 31, 2025$2,500 ICCJanuary 1, 2027, May 1, 2027$1,593 
PECO(a)
FERCDecember 31, 20251,500 PAPUCDecember 31, 20271,850 
BGE(a)
FERCDecember 31, 2025700 MDPSCN/A1,850 
Pepco(a)(c)(d)
FERCDecember 31, 2025500 MDPSC / DCPSCDecember 31, 2025100 
DPL(a)(c)(e)
FERCDecember 31, 2025500 MDPSC / DEPSCDecember 31, 2025172 
ACE(f)
NJBPUJanuary 1, 2028350 NJBPUDecember 31, 2026625 
__________
(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 WithinTotal Fair
Value
Commodity derivative contracts(a):
202620272028202920302031 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.
February 12, 2026
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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.
February 12, 2026
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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.
February 12, 2026
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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.


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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
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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.



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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
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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.




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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,
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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.



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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
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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.










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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,
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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.


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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,
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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.




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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
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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.


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Exelon Corporation and Subsidiary Companies
Consolidated Statements of Operations and Comprehensive Income
For the Years Ended December 31,
(In millions, except per share data)202520242023
Operating revenues
Electric operating revenues$22,655 $21,338 $19,267 
Natural gas operating revenues2,349 1,782 1,764 
Revenues from alternative revenue programs(746)(92)696 
Total operating revenues24,258 23,028 21,727 
Operating expenses
Purchased power7,944 8,214 7,648 
Purchased fuel723 469 593 
Operating and maintenance5,177 4,940 4,559 
Depreciation and amortization3,640 3,594 3,506 
Taxes other than income taxes1,629 1,504 1,408 
Total operating expenses19,113 18,721 17,714 
Gain on sale of assets3 12 10 
Operating income5,148 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, net270 262 408 
Total other income and (deductions)(1,857)(1,652)(1,321)
Income before income taxes3,291 2,667 2,702 
Income taxes523 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 cost22 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:
Basic1,011 1,003 996 
Assumed exercise and/or distributions of stock-based awards(a)
1 — 1 
Diluted1,012 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


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Exelon Corporation and Subsidiary Companies
Consolidated Statements of Cash Flows
For the Years Ended December 31,
(In millions)202520242023
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 accretion3,643 3,596 3,506 
Gain on sales of assets(3)(12)(10)
Deferred income taxes and amortization of investment tax credits391 128 319 
Net fair value changes related to derivatives— — 22 
Other non-cash operating activities1,331 592 (335)
Changes in assets and liabilities:
Accounts receivable(1,691)(644)(37)
Inventories(22)(56)(45)
Accounts payable and accrued expenses260 (37)(191)
Collateral (paid) received, net(10)33 (146)
Income taxes121 (4)48 
Regulatory assets and liabilities, net156 (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 activities6,254 5,569 4,703 
Cash flows from investing activities
Capital expenditures(8,529)(7,097)(7,408)
Proceeds from sales of assets4 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 debt6,075 4,974 5,825 
Retirement of long-term debt(1,311)(1,557)(1,713)
Issuance of common stock691 148 140 
Dividends paid on common stock(1,617)(1,524)(1,433)
Proceeds from employee stock plans36 43 41 
Other financing activities(94)(109)(114)
Net cash flows provided by financing activities2,533 1,311 2,683 
Increase (decrease) in cash, restricted cash, and cash equivalents262 (162)11 
Cash, restricted cash, and cash equivalents at beginning of period939 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 update13 16 (13)
See the Combined Notes to Consolidated Financial Statements


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Exelon Corporation and Subsidiary Companies
Consolidated Balance Sheets
December 31,
(In millions)20252024
ASSETS
Current assets
Cash and cash equivalents$626 $357 
Restricted cash and cash equivalents525 541 
Accounts receivable
Customer accounts receivable3,7323,144
Customer allowance for credit losses(435)(406)
Customer accounts receivable, net3,297 2,738 
Other accounts receivable1,8791,123
Other allowance for credit losses(94)(107)
Other accounts receivable, net1,785 1,016 
Inventories, net
Fossil fuel88 72 
Materials and supplies780 781 
Regulatory assets1,359 1,940 
Prepaid renewable energy credits563 494 
Other523 445 
Total current assets9,546 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 assets9,214 8,710 
Goodwill6,630 6,630 
Receivable related to Regulatory Agreement Units4,755 4,026 
Investments312 290 
Other1,795 1,562 
Total deferred debits and other assets22,706 21,218 
Total assets$116,570 $107,784 
See the Combined Notes to Consolidated Financial Statements


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Exelon Corporation and Subsidiary Companies
Consolidated Balance Sheets
December 31,
(In millions)20252024
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities
Short-term borrowings$612 $1,859 
Long-term debt due within one year1,665 1,453 
Accounts payable3,721 2,994 
Accrued expenses1,582 1,468 
Payables to affiliates5 5 
Customer deposits533 446 
Regulatory liabilities1,128 411 
Mark-to-market derivative liabilities30 29 
Unamortized energy contract liabilities5 5 
Renewable energy credit obligations473 429 
Other577 512 
Total current liabilities10,331 9,611 
Long-term debt47,413 42,947 
Long-term debt to financing trusts390 390 
Deferred credits and other liabilities
Deferred income taxes and unamortized investment tax credits13,715 12,793 
Regulatory liabilities11,016 10,198 
Pension obligations1,749 1,745 
Non-pension postretirement benefit obligations546 472 
Asset retirement obligations321 301 
Mark-to-market derivative liabilities106 103 
Unamortized energy contract liabilities16 21 
Other2,169 2,282 
Total deferred credits and other liabilities29,638 27,915 
Total liabilities87,772 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 earnings7,577 6,426 
Accumulated other comprehensive loss, net(762)(720)
Total shareholders’ equity28,798 26,921 
Total liabilities and shareholders' equity$116,570 $107,784 

See the Combined Notes to Consolidated Financial Statements


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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, 2022995,830 $20,908 $(123)$4,597 $(638)$24,744 
Net income— — — 2,328 — 2,328 
Long-term incentive plan activity659 19 — — — 19 
Employee stock purchase plan activity1,173 47 — — — 47 
Issuance of common stock3,587 140 — — — 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, 20231,001,249 $21,114 $(123)$5,490 $(726)$25,755 
Net income— — — 2,460 — 2,460 
Long-term incentive plan activity464 26 — — — 26 
Employee stock purchase plan activity1,344 50 — — — 50 
Issuance of common stock3,989 148 — — — 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, 20241,007,046 $21,338 $(123)$6,426 $(720)$26,921 
Net income— — — 2,768 — 2,768 
Long-term incentive plan activity323 34 — — — 34 
Employee stock purchase plan activity931 43 — — — 43 
Issuance of common stock16,101 691 — — — 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, 20251,024,401 $22,106 $(123)$7,577 $(762)$28,798 
See the Combined Notes to Consolidated Financial Statements


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Commonwealth Edison Company and Subsidiary Companies
Consolidated Statements of Operations and Comprehensive Income
For the Years Ended December 31,
(In millions)202520242023
Operating revenues
Electric operating revenues$7,842 $8,362 $7,272 
Revenues from alternative revenue programs(596)(151)556 
Operating revenues from affiliates21 8 16 
Total operating revenues7,267 8,219 7,844 
Operating expenses
Purchased power1,782 3,042 2,816 
Operating and maintenance1,306 1,284 1,096 
Operating and maintenance from affiliates404 419 354 
Depreciation and amortization1,560 1,514 1,403 
Taxes other than income taxes409 376 369 
Total operating expenses5,461 6,635 6,038 
Gain on sale of assets— 5 — 
Operating income1,806 1,589 1,806 
Other income and (deductions)
Interest expense, net(517)(487)(464)
Interest expense to affiliates, net(13)(14)(13)
Other, net132 94 75 
Total other income and (deductions)(398)(407)(402)
Income before income taxes1,408 1,182 1,404 
Income taxes261 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


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Commonwealth Edison Company and Subsidiary Companies
Consolidated Statements of Cash Flows
For the Years Ended December 31,
(In millions)202520242023
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 credits39 (19)196 
Other non-cash operating activities740 232 (536)
Changes in assets and liabilities:
Accounts receivable(1,026)(185)(138)
Receivables from and payables to affiliates, net3 4 (2)
Inventories17 (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, net506 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 activities2,665 2,713 1,848 
Cash flows from investing activities
Capital expenditures(2,899)(2,195)(2,576)
Other investing activities6 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 debt725 800 975 
Retirement of long-term debt— (250)— 
Dividends paid on common stock(813)(776)(746)
Contributions from parent391 227 655 
Other financing activities(8)(14)(14)
Net cash flows provided by (used in) financing activities259 (579)895 
Increase (decrease) in cash, restricted cash, and cash equivalents31 (54)175 
Cash, restricted cash, and cash equivalents at beginning of period632 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

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Commonwealth Edison Company and Subsidiary Companies
Consolidated Balance Sheets
December 31,
(In millions)20252024
ASSETS
Current assets
Cash and cash equivalents$159 $105 
Restricted cash and cash equivalents454 486 
Accounts receivable
Customer accounts receivable1,058994
Customer allowance for credit losses(115)(109)
Customer accounts receivable, net943 885 
Other accounts receivable1,155290
Other allowance for credit losses(23)(34)
Other accounts receivable, net1,132 256 
Receivables from affiliates5 4 
Inventories, net268 292 
Regulatory assets595 1,159 
Other217 141 
Total current assets3,773 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 assets2,687 2,562 
Goodwill2,625 2,625 
Receivable related to Regulatory Agreement Units4,313 3,780 
Investments6 6 
Prepaid pension asset1,284 1,165 
Other1,342 1,073 
Total deferred debits and other assets12,257 11,211 
Total assets$48,285 $44,750 
See the Combined Notes to Consolidated Financial Statements

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Commonwealth Edison Company and Subsidiary Companies
Consolidated Balance Sheets
December 31,
(In millions)20252024
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities
Short-term borrowings$— $36 
Long-term debt due within one year500 — 
Accounts payable1,033 748 
Accrued expenses474 463 
Payables to affiliates81 77 
Customer deposits192 134 
Regulatory liabilities846 197 
Mark-to-market derivative liabilities25 29 
Other288 270 
Total current liabilities3,439 1,954 
Long-term debt12,253 12,030 
Long-term debt to financing trust206 206 
Deferred credits and other liabilities
Deferred income taxes and unamortized investment tax credits5,828 5,601 
Regulatory liabilities9,163 8,421 
Asset retirement obligations193 167 
Non-pension postretirement benefit obligations151 156 
Mark-to-market derivative liabilities106 103 
Other1,341 1,232 
Total deferred credits and other liabilities16,782 15,680 
Total liabilities32,680 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 capital11,019 10,628 
Retained earnings2,998 2,664 
Total shareholders’ equity15,605 14,880 
Total liabilities and shareholders’ equity$48,285 $44,750 
See the Combined Notes to Consolidated Financial Statements

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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 $11,019 $2,998 $15,605 
See the Combined Notes to Consolidated Financial Statements

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PECO Energy Company and Subsidiary Companies
Consolidated Statements of Operations and Comprehensive Income
For the Years Ended December 31,
(In millions)202520242023
Operating revenues
Electric operating revenues$3,818 $3,312 $3,202 
Natural gas operating revenues854 645 690 
Revenues from alternative revenue programs— 6 (7)
Operating revenues from affiliates12 10 9 
Total operating revenues4,684 3,973 3,894 
Operating expenses
Purchased power1,436 1,265 1,270 
Purchased fuel297 212 274 
Operating and maintenance946 875 786 
Operating and maintenance from affiliates249 245 217 
Depreciation and amortization454 428 397 
Taxes other than income taxes240 218 202 
Total operating expenses3,622 3,243 3,146 
Gain on sale of assets— 4 — 
Operating income1,062 734 748 
Other income and (deductions)
Interest expense, net(249)(221)(192)
Interest expense to affiliates, net(11)(11)(9)
Other, net41 37 36 
Total other income and (deductions)(219)(195)(165)
Income before income taxes843 539 583 
Income taxes29 (12)20 
Net income$814 $551 $563 
Comprehensive income$814 $551 $563 
    
See the Combined Notes to Consolidated Financial Statements

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PECO Energy Company and Subsidiary Companies
Consolidated Statements of Cash Flows
For the Years Ended December 31,
(In millions)202520242023
Cash flows from operating activities
Net income$814 $551 $563 
Adjustments to reconcile net income to net cash flows provided by
operating activities:
Depreciation and amortization454 428 397 
Gain on sales of assets— (4)— 
Deferred income taxes and amortization of investment tax
credits		(69)(63)(43)
Other non-cash operating activities78 59 13 
Changes in assets and liabilities:
Accounts receivable(238)(210)67 
Receivables from and payables to affiliates, net(6)4 (1)
Inventories(12)1 34 
Accounts payable and accrued expenses118 23 (78)
Collateral received, net6 — — 
Income taxes283 (76)86 
Regulatory assets and liabilities, net(33)27 (31)
Pension and non-pension postretirement benefit contributions(13)(4)(1)
Other assets and liabilities21 18 13 
Net cash flows provided by operating activities1,403 754 1,019 
Cash flows from investing activities
Capital expenditures(1,867)(1,553)(1,426)
Other investing activities3 6 2 
Net cash flows used in investing activities(1,864)(1,547)(1,424)
Cash flows from financing activities
Change in short-term borrowings(192)27 (74)
Issuance of long-term debt1,050 575 575 
Retirement of long-term debt(350)— (50)
Dividends paid on common stock(546)(400)(405)
Contributions from parent577 595 348 
Other financing activities(10)(7)(6)
Net cash flows provided by financing activities529 790 388 
Increase (decrease) in cash, restricted cash, and cash equivalents68 (3)(17)
Cash, restricted cash, and cash equivalents at beginning of period48 51 68 
Cash, restricted cash, and cash equivalents at end of period$116 $48 $51 
Supplemental cash flow information
Increase (decrease) in capital expenditures not paid$94 $103 $(56)
See the Combined Notes to Consolidated Financial Statements

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PECO Energy Company and Subsidiary Companies
Consolidated Balance Sheets
December 31,
(In millions)20252024
ASSETS
Current assets
Cash and cash equivalents$116 $48 
Accounts receivable
Customer accounts receivable811670
Customer allowance for credit losses(137)(133)
Customer accounts receivable, net674 537 
Other accounts receivable144145
Other allowance for credit losses(18)(18)
Other accounts receivable, net126 127 
Inventories, net
Fossil fuel43 37 
Materials and supplies83 79 
Prepaid renewable energy credits55 51 
Regulatory assets72 65 
Other34 29 
Total current assets1,203 973 
Property, plant, and equipment (net of accumulated depreciation and amortization of $4,131 and $4,042 as of December 31, 2025 and 2024, respectively)
15,922 14,392 
Deferred debits and other assets
Regulatory assets1,275 1,003 
Receivable related to Regulatory Agreement Units442 247 
Investments45 41 
Prepaid pension asset441 435 
Other34 32 
Total deferred debits and other assets2,237 1,758 
Total assets$19,362 $17,123 
See the Combined Notes to Consolidated Financial Statements

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PECO Energy Company and Subsidiary Companies
Consolidated Balance Sheets
December 31,
(In millions)20252024
LIABILITIES AND SHAREHOLDER'S EQUITY
Current liabilities
Short-term borrowings$— $192 
Long-term debt due within one year— 350 
Accounts payable811 639 
Accrued expenses483 166 
Payables to affiliates35 41 
Customer deposits93 80 
Renewable energy credit obligations56 52 
Regulatory liabilities140 122 
Other40 28 
Total current liabilities1,658 1,670 
Long-term debt6,396 5,354 
Long-term debt to financing trusts184 184 
Deferred credits and other liabilities
Deferred income taxes and unamortized investment tax credits2,594 2,433 
Regulatory liabilities449 253 
Asset retirement obligations26 27 
Non-pension postretirement benefit obligations286 287 
Other109 100 
Total deferred credits and other liabilities3,464 3,100 
Total liabilities11,702 10,308 
Commitments and contingencies
Shareholder's equity
Common stock (No par value, 500 shares authorized, 170 shares outstanding as of December 31, 2025 and 2024)
5,222 4,645 
Retained earnings2,438 2,170 
Total shareholder's equity7,660 6,815 
Total liabilities and shareholder's equity$19,362 $17,123 
See the Combined Notes to Consolidated Financial Statements

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PECO Energy Company and Subsidiary Companies
Consolidated Statements of Changes in Shareholder's Equity
(In millions)Common
Stock		Retained
Earnings		Total
Shareholder's
Equity
Balance at December 31, 2022$3,702 $1,861 $5,563 
Net income— 563 563 
Common stock dividends— (405)(405)
Contributions from parent348 — 348 
Balance at December 31, 2023$4,050 $2,019 $6,069 
Net income— 551 551 
Common stock dividends— (400)(400)
Contributions from parent595 — 595 
Balance at December 31, 2024$4,645 $2,170 $6,815 
Net income— 814 814 
Common stock dividends— (546)(546)
Contributions from parent577 — 577 
Balance at December 31, 2025$5,222 $2,438 $7,660 
 
See the Combined Notes to Consolidated Financial Statements

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Baltimore Gas and Electric Company
Statements of Operations and Comprehensive Income
For the Years Ended December 31,
(In millions)202520242023
Operating revenues
Electric operating revenues$4,037 $3,407 $3,065 
Natural gas operating revenues1,264 957 869 
Revenues from alternative revenue programs(87)52 84 
Operating revenues from affiliates8 10 9 
Total operating revenues5,222 4,426 4,027 
Operating expenses
Purchased power 1,890 1,460 1,311 
Purchased fuel 331 191 220 
Operating and maintenance815 790 520 
Operating and maintenance from affiliates251 246 221 
Depreciation and amortization632 638 654 
Taxes other than income taxes370 345 319 
Total operating expenses4,289 3,670 3,245 
Operating income933 756 782 
Other income and (deductions)
Interest expense, net(247)(216)(182)
Other, net51 36 18 
Total other income and (deductions)(196)(180)(164)
Income before income taxes737 576 618 
Income taxes159 49 133 
Net income$578 $527 $485 
Comprehensive income$578 $527 $485 
See the Combined Notes to Consolidated Financial Statements

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Baltimore Gas and Electric Company
Statements of Cash Flows
For the Years Ended December 31,
(In millions)202520242023
Cash flows from operating activities
Net income$578 $527 $485 
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation and amortization632 638 654 
Deferred income taxes and amortization of investment tax credits86 5 66 
Other non-cash operating activities170 38 (1)
Changes in assets and liabilities:
Accounts receivable(244)(142)89 
Receivables from and payables to affiliates, net(9)14 (5)
Inventories3 (5)47 
Accounts payable and accrued expenses(18)35 (75)
Collateral received (paid), net4 (1)(22)
Income taxes169 (54)37 
Regulatory assets and liabilities, net(97)(84)(292)
Pension and non-pension postretirement benefit contributions(44)(37)(19)
Other assets and liabilities(1)(39)(13)
Net cash flows provided by operating activities1,229 895 951 
Cash flows from investing activities
Capital expenditures(1,657)(1,420)(1,367)
Other investing activities9 12 7 
Net cash flows used in investing activities(1,648)(1,408)(1,360)
Cash flows from financing activities
Changes in short-term borrowings(175)(161)(72)
Issuance of long-term debt650 800 700 
Retirement of long-term debt— — (300)
Dividends paid on common stock(393)(368)(316)
Contributions from parent531 237 385 
Other financing activities(8)(9)(7)
Net cash flows provided by financing activities605 499 390 
Increase (decrease) in cash, restricted cash, and cash equivalents186 (14)(19)
Cash, restricted cash, and cash equivalents at beginning of period34 48 67 
Cash, restricted cash, and cash equivalents at end of period$220 $34 $48 
Supplemental cash flow information
Increase (decrease) in capital expenditures not paid$153 $156 $(44)
See the Combined Notes to Consolidated Financial Statements

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Baltimore Gas and Electric Company
Balance Sheets
December 31,
(In millions)20252024
ASSETS
Current assets
Cash and cash equivalents $217 $33 
Restricted cash and cash equivalents3 1 
Accounts receivable
Customer accounts receivable887654
Customer allowance for credit losses(68)(56)
Customer accounts receivable, net819 598 
Other accounts receivable100113
Other allowance for credit losses(4)(6)
Other accounts receivable, net96 107 
Receivables from affiliates1 — 
Inventories, net
Fossil fuel36 29 
Materials and supplies74 84 
Prepaid utility taxes126 115 
Regulatory assets175 207 
Prepaid renewable energy credits189 157 
Other14 17 
Total current assets1,750 1,348 
Property, plant, and equipment (net of accumulated depreciation and amortization of $5,234 and $5,005 as of December 31, 2025 and 2024, respectively)
14,385 13,134 
Deferred debits and other assets
Regulatory assets804 788 
Investments10 10 
Prepaid pension asset194 218 
Other41 44 
Total deferred debits and other assets1,049 1,060 
Total assets$17,184 $15,542 
See the Combined Notes to Consolidated Financial Statements

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Baltimore Gas and Electric Company
Balance Sheets
December 31,
(In millions)20252024
LIABILITIES AND SHAREHOLDER'S EQUITY
Current liabilities
Short-term borrowings$— $175 
Long-term debt due within one year350 — 
Accounts payable640 515 
Accrued expenses352 176 
Payables to affiliates39 48 
Customer deposits125 118 
Regulatory liabilities31 12 
Renewable energy credit obligations194 160 
Other39 39 
Total current liabilities1,770 1,243 
Long-term debt5,691 5,395 
Deferred credits and other liabilities
Deferred income taxes and unamortized investment tax credits2,242 2,099 
Regulatory liabilities595 636 
Asset retirement obligations36 36 
Non-pension postretirement benefit obligations144 150 
Other104 97 
Total deferred credits and other liabilities3,121 3,018 
Total liabilities10,582 9,656 
Commitments and contingencies
Shareholder's equity
Common stock (No par value, 0 shares(a) authorized, 0 shares(a) outstanding as of December 31, 2025 and 2024)
4,014 3,483 
Retained earnings2,588 2,403 
Total shareholder's equity6,602 5,886 
Total liabilities and shareholder's equity$17,184 $15,542 
_____________
(a)In millions, shares round to zero. Number of shares is 1,500 authorized and 1,000 outstanding as of December 31, 2025 and 2024.

See the Combined Notes to Consolidated Financial Statements

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Baltimore Gas and Electric Company
Statements of Changes in Shareholder's Equity
(In millions)Common
Stock		Retained
Earnings		Total
Shareholder's
Equity
Balance at December 31, 2022$2,861 $2,075 $4,936 
Net income— 485 485 
Common stock dividends— (316)(316)
Contributions from parent385 — 385 
Balance at December 31, 2023$3,246 $2,244 $5,490 
Net income— 527 527 
Common stock dividends— (368)(368)
Contributions from parent237 — 237 
Balance at December 31, 2024$3,483 $2,403 $5,886 
Net income— 578 578 
Common stock dividends— (393)(393)
Contributions from parent531 — 531 
Balance at December 31, 2025$4,014 $2,588 $6,602 
See the Combined Notes to Consolidated Financial Statements

135
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Pepco Holdings LLC and Subsidiary Companies
Consolidated Statements of Operations and Comprehensive Income
For the Years Ended December 31,
(In millions)202520242023
Operating revenues
Electric operating revenues$6,957 $6,257 $5,748 
Natural gas operating revenues231 180 205 
Revenues from alternative revenue programs(63)1 64 
Operating revenues from affiliates10 10 9 
Total operating revenues7,135 6,448 6,026 
Operating expenses
Purchased power2,836 2,447 2,250 
Purchased fuel95 66 98 
Operating and maintenance1,123 1,046 1,110 
Operating and maintenance from affiliates204 204 179 
Depreciation and amortization935 947 990 
Taxes other than income taxes568 528 487 
Total operating expenses5,761 5,238 5,114 
Gain (loss) on sales of assets3 (1)9 
Operating income1,377 1,209 921 
Other income and (deductions)
Interest expense, net(408)(373)(323)
Interest expense to affiliates, net(3)(3)— 
Other, net72 97 108 
Total other income and (deductions)(339)(279)(215)
Income before income taxes 1,038 930 706 
Income taxes239 189 116 
Net income$799 $741 $590 
Comprehensive income$799 $741 $590 
See the Combined Notes to Consolidated Financial Statements

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Pepco Holdings LLC and Subsidiary Companies
Consolidated Statements of Cash Flows
For the Years Ended December 31,
(In millions)202520242023
Cash flows from operating activities
Net income$799 $741 $590 
Adjustments to reconcile net income to net cash flows used in operating activities:
Depreciation, amortization, and accretion937 947 990 
(Gain) loss on sales of assets(3)1 (9)
Deferred income taxes and amortization of investment tax credits132 73 29 
Other non-cash operating activities241 188 110 
Changes in assets and liabilities:
Accounts receivable(204)(110)(79)
Receivables from and payables to affiliates, net(1)2 (8)
Inventories(32)(37)(42)
Accounts payable and accrued expenses8 66 40 
Collateral received (paid), net17 — (196)
Income taxes (7)(33)65 
Regulatory assets and liabilities, net(192)(223)(61)
Pension and non-pension postretirement benefit contributions (50)(86)(24)
Other assets and liabilities(47)(119)(101)
Net cash flows provided by operating activities1,598 1,410 1,304 
Cash flows from investing activities
Capital expenditures (2,056)(1,863)(1,988)
Proceeds from sales of long-lived assets4 — 10 
Other investing activities — — 8 
Net cash flows used in investing activities(2,052)(1,863)(1,970)
Cash flows from financing activities
Changes in short-term borrowings 82 136 (20)
Issuance of long-term debt650 1,100 1,075 
Retirement of long-term debt(150)(583)(500)
Change in Exelon intercompany money pool17 (2)21 
Distributions to member(710)(706)(513)
Contributions from member568 505 475 
Other financing activities (25)(38)(41)
Net cash flows provided by financing activities432 412 497 
Decrease in cash, restricted cash, and cash equivalents(22)(41)(169)
Cash, restricted cash, and cash equivalents at beginning of period163 204 373 
Cash, restricted cash, and cash equivalents at end of period$141 $163 $204 
Supplemental cash flow information
Increase (decrease) in capital expenditures not paid$79 $76 $(109)
See the Combined Notes to Consolidated Financial Statements

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Pepco Holdings LLC and Subsidiary Companies
Consolidated Balance Sheets
December 31,
(In millions)20252024
ASSETS
Current assets
Cash and cash equivalents$103 $139 
Restricted cash and cash equivalents38 24 
Accounts receivable
Customer accounts receivable975827
Customer allowance for credit losses(115)(108)
Customer accounts receivable, net860 719 
Other accounts receivable292284
Other allowance for credit losses(49)(49)
Other accounts receivable, net243 235 
Receivable from affiliates14 8 
Inventories, net
Fossil fuel9 7 
Materials and supplies357 325 
Prepaid utility taxes77 70 
Regulatory assets352 323 
Prepaid renewable energy credits201 194 
Other34 36 
Total current assets2,288 2,080 
Property, plant, and equipment (net of accumulated depreciation and amortization of $4,350 and $3,728 as of December 31, 2025 and 2024, respectively)
21,377 20,053 
Deferred debits and other assets
Regulatory assets1,556 1,570 
Goodwill4,005 4,005 
Investments158 152 
Prepaid pension asset199 252 
Other132 185 
Total deferred debits and other assets6,050 6,164 
Total assets$29,715 $28,297 
See the Combined Notes to Consolidated Financial Statements

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Pepco Holdings LLC and Subsidiary Companies
Consolidated Balance Sheets
December 31,
(In millions)20252024
LIABILITIES AND MEMBER'S EQUITY
Current liabilities
Short-term borrowings$612 $530 
Long-term debt due within one year64 290 
Accounts payable816 721 
Accrued expenses359 367 
Payables to affiliates71 66 
Borrowings from Exelon intercompany money pool80 63 
Customer deposits123 113 
Regulatory liabilities 103 69 
Unamortized energy contract liabilities5 5 
Renewable energy credit obligations223 217 
Other121 124 
Total current liabilities2,577 2,565 
Long-term debt9,526 8,834 
Deferred credits and other liabilities
Deferred income taxes and unamortized investment tax credits3,391 3,190 
Regulatory liabilities722 794 
Asset retirement obligations62 67 
Non-pension postretirement benefit obligations24 31 
Unamortized energy contract liabilities16 21 
Other418 473 
Total deferred credits and other liabilities4,633 4,576 
Total liabilities16,736 15,975 
Commitments and contingencies
Member's equity
Membership interest13,130 12,562 
Undistributed losses(151)(240)
Total member's equity12,979 12,322 
Total liabilities and member's equity$29,715 $28,297 
See the Combined Notes to Consolidated Financial Statements

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Pepco Holdings LLC and Subsidiary Companies
Consolidated Statements of Changes in Member's Equity
(In millions)Membership InterestUndistributed (Losses)/GainsTotal
Member's Equity
Balance at December 31, 2022$11,582 $(352)$11,230 
Net income— 590 590 
Distribution to member— (513)(513)
Contributions from member475 — 475 
Balance at December 31, 2023$12,057 $(275)$11,782 
Net income— 741 741 
Distribution to member— (706)(706)
Contributions from member505 — 505 
Balance at December 31, 2024$12,562 $(240)$12,322 
Net income— 799 799 
Distribution to member— (710)(710)
Contributions from member568 — 568 
Balance at December 31, 2025$13,130 $(151)$12,979 

See the Combined Notes to Consolidated Financial Statements

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Potomac Electric Power Company
Statements of Operations and Comprehensive Income
For the Years Ended December 31,
(In millions)202520242023
Operating revenues
Electric operating revenues$3,497 $3,017 $2,793 
Revenues from alternative revenue programs(49)15 22 
Operating revenues from affiliates6 7 9 
Total operating revenues3,454 3,039 2,824 
Operating expenses
Purchased power1,262 1,055 974 
Operating and maintenance379 283 336 
Operating and maintenance from affiliates246 251 236 
Depreciation and amortization433 407 441 
Taxes other than income taxes455 424 390 
Total operating expenses2,775 2,420 2,377 
Gain (loss) on sales of assets1 (1)9 
Operating income680 618 456 
Other income and (deductions)
Interest expense, net(214)(195)(165)
Interest income from affiliates, net— 3 — 
Other, net41 54 66 
Total other income and (deductions)(173)(138)(99)
Income before income taxes507 480 357 
Income taxes106 90 51 
Net income$401 $390 $306 
Comprehensive income$401 $390 $306 
See the Combined Notes to Consolidated Financial Statements

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Potomac Electric Power Company
Statements of Cash Flows
For the Years Ended December 31,
(In millions)202520242023
Cash flows from operating activities
Net income$401 $390 $306 
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation, amortization, and accretion435 407 441 
(Gain) loss on sales of assets(1)1 (9)
Deferred income taxes and amortization of investment tax credits51 24 (15)
Other non-cash operating activities111 33 53 
Changes in assets and liabilities:
Accounts receivable(121)(26)(29)
Receivables from and payables to affiliates, net4 6 (3)
Inventories(4)(10)(24)
Accounts payable and accrued expenses1 67 6 
Collateral received (paid), net12 — (25)
Income taxes(33)(30)60 
Regulatory assets and liabilities, net(93)(85)(45)
Pension and non-pension postretirement benefit contributions(9)(9)(12)
Other assets and liabilities(29)(84)(5)
Net cash flows provided by operating activities725 684 699 
Cash flows from investing activities
Capital expenditures(957)(929)(957)
Proceeds from sale of long-lived assets2 — 10 
Other investing activities— — 8 
Net cash flows used in investing activities(955)(929)(939)
Cash flows from financing activities
Changes in short-term borrowings103 68 (167)
Issuance of long-term debt275 675 350 
Retirement of long-term debt— (400)— 
Dividends paid on common stock(327)(359)(252)
Contributions from parent193 260 308 
Other financing activities(10)(20)(26)
Net cash flows provided by financing activities234 224 213 
Increase (decrease) in cash, restricted cash, and cash equivalents4 (21)(27)
Cash, restricted cash, and cash equivalents at beginning of period51 72 99 
Cash, restricted cash, and cash equivalents at end of period$55 $51 $72 
Supplemental cash flow information
Increase (decrease) in capital expenditures not paid$56 $30 $(55)
See the Combined Notes to Consolidated Financial Statements

142
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Potomac Electric Power Company
Balance Sheets
December 31,
(In millions)20252024
ASSETS
Current assets
Cash and cash equivalents$22 $30 
Restricted cash and cash equivalents33 21 
Accounts receivable
Customer accounts receivable484395
Customer allowance for credit losses(69)(59)
Customer accounts receivable, net415 336 
Other accounts receivable154142
Other allowance for credit losses(26)(27)
Other accounts receivable, net128 115 
Receivables from affiliates— 1 
Inventories, net174 169 
Regulatory assets182 157 
Prepaid renewable energy credits171 165 
Other59 55 
Total current assets1,184 1,049 
Property, plant, and equipment (net of accumulated depreciation and amortization of $4,784 and $4,522 as of December 31, 2025 and 2024, respectively)
10,747 10,097 
Deferred debits and other assets
Regulatory assets405 446 
Investments141 135 
Prepaid pension asset194 222 
Other57 51 
Total deferred debits and other assets797 854 
Total assets$12,728 $12,000 
See the Combined Notes to Consolidated Financial Statements

143
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Potomac Electric Power Company
Balance Sheets
December 31,
(In millions)20252024
LIABILITIES AND SHAREHOLDER'S EQUITY
Current liabilities
Short-term borrowings$303 $200 
Long-term debt due within one year6 6 
Accounts payable418 360 
Accrued expenses173 201 
Payables to affiliates37 37 
Customer deposits61 55 
Regulatory liabilities13 17 
Merger related obligation20 22 
Renewable energy credit obligations174 169 
Other64 51 
Total current liabilities1,269 1,118 
Long-term debt4,626 4,356 
Deferred credits and other liabilities
Deferred income taxes and unamortized investment tax credits1,604 1,509 
Regulatory liabilities268 310 
Asset retirement obligations45 49 
Other214 223 
Total deferred credits and other liabilities2,131 2,091 
Total liabilities8,026 7,565 
Commitments and contingencies
Shareholder's equity
Common stock ($0.01 par value, 200 shares authorized, 0 shares(a) outstanding as of December 31, 2025 and 2024)
3,528 3,335 
Retained earnings1,174 1,100 
Total shareholder's equity4,702 4,435 
Total liabilities and shareholder's equity$12,728 $12,000 
_____________
(a)In millions, shares round to zero. Number of shares is 100 outstanding as of December 31, 2025 and 2024.

See the Combined Notes to Consolidated Financial Statements

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Potomac Electric Power Company
Statements of Changes in Shareholder's Equity
(In millions)Common Stock Retained EarningsTotal Shareholder's Equity
Balance at December 31, 2022$2,767 $1,015 $3,782 
Net income — 306 306 
Common stock dividends— (252)(252)
Contributions from parent308 — 308 
Balance at December 31, 2023$3,075 $1,069 $4,144 
Net income— 390 390 
Common stock dividends— (359)(359)
Contributions from parent260 — 260 
Balance at December 31, 2024$3,335 $1,100 $4,435 
Net income— 401 401 
Common stock dividends— (327)(327)
Contributions from parent193 — 193 
Balance at December 31, 2025$3,528 $1,174 $4,702 
See the Combined Notes to Consolidated Financial Statements

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Delmarva Power & Light Company
Statements of Operations and Comprehensive Income
For the Years Ended December 31,
(In millions)202520242023
Operating revenues
Electric operating revenues$1,747 $1,602 $1,460 
Natural gas operating revenues231 180 205 
Revenues from alternative revenue programs(16)(2)15 
Operating revenues from affiliates9 7 8 
Total operating revenues1,971 1,787 1,688 
Operating expenses
Purchased power 766 694 639 
Purchased fuel 95 66 98 
Operating and maintenance213 196 193 
Operating and maintenance from affiliates 178 181 171 
Depreciation and amortization252 245 244 
Taxes other than income taxes88 79 75 
Total operating expenses1,592 1,461 1,420 
Operating income379 326 268 
Other income and (deductions)
Interest expense, net(102)(94)(74)
Interest income from affiliates, net— 1 — 
Other, net16 25 18 
Total other income and (deductions)(86)(68)(56)
Income before income taxes293 258 212 
Income taxes69 49 35 
Net income$224 $209 $177 
Comprehensive income$224 $209 $177 
See the Combined Notes to Consolidated Financial Statements

146
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Delmarva Power & Light Company
Statements of Cash Flows
For the Years Ended December 31,
(In millions)202520242023
Cash flows from operating activities
Net income$224 $209 $177 
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation and amortization252 245 244 
Deferred income taxes and amortization of investment tax credits32 16 4 
Other non-cash operating activities57 40 13 
Changes in assets and liabilities:
Accounts receivable(70)(46)6 
Receivables from and payables to affiliates, net(3)2 2 
Inventories(14)(20)(5)
Accounts payable and accrued expenses 20 22 (7)
Collateral received (paid), net2 2 (121)
Income taxes16 (24)26 
Regulatory assets and liabilities, net(35)(51)25 
Pension and non-pension postretirement benefit contributions(1)(3)(4)
Other assets and liabilities6 16 13 
Net cash flows provided by operating activities486 408 373 
Cash flows from investing activities
Capital expenditures(534)(556)(562)
Net cash flows used in investing activities(534)(556)(562)
Cash flows from financing activities
Changes in short-term borrowings17 81 (52)
Issuance of long-term debt125 175 650 
Retirement of long-term debt— (33)(500)
Dividends paid on common stock(202)(220)(133)
Contributions from parent107 160 99 
Other financing activities(10)(8)(11)
Net cash flows provided by financing activities37 155 53 
(Decrease) increase in cash, restricted cash, and cash equivalents(11)7 (136)
Cash, restricted cash, and cash equivalents at beginning of period23 16 152 
Cash, restricted cash, and cash equivalents at end of period$12 $23 $16 
Supplemental cash flow information
Increase (decrease) in capital expenditures not paid$13 $41 $(6)
See the Combined Notes to Consolidated Financial Statements

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Delmarva Power & Light Company
Balance Sheets
December 31,
(In millions)20252024
ASSETS
Current assets
Cash and cash equivalents$9 $21 
Restricted cash and cash equivalents3 2 
Accounts receivable
Customer accounts receivable253210
Customer allowance for credit losses(19)(17)
Customer accounts receivable, net234 193 
Other accounts receivable7563
Other allowance for credit losses(10)(9)
Other accounts receivable, net65 54 
Receivables from affiliates2 — 
Inventories, net
Fossil fuel9 6 
Materials and supplies107 95 
Prepaid utility taxes29 26 
Regulatory assets72 60 
Prepaid renewable energy credits30 29 
Other13 16 
Total current assets573 502 
Property, plant, and equipment, (net of accumulated depreciation and amortization of $2,241 and $2,075 as of December 31, 2025 and 2024, respectively)
5,855 5,540 
Deferred debits and other assets
Regulatory assets214 215 
Other147 164 
Total deferred debits and other assets361 379 
Total assets$6,789 $6,421 
See the Combined Notes to Consolidated Financial Statements

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Delmarva Power & Light Company
Balance Sheets
December 31,
(In millions)20252024
LIABILITIES AND SHAREHOLDER'S EQUITY
Current liabilities
Short-term borrowings$161 $144 
Long-term debt due within one year53 130 
Accounts payable218 187 
Accrued expenses70 55 
Payables to affiliates25 26 
Customer deposits36 34 
Regulatory liabilities 42 42 
Renewable energy credit obligations49 48 
Other22 22 
Total current liabilities676 688 
Long-term debt2,291 2,090 
Deferred credits and other liabilities
Deferred income taxes and unamortized investment tax credits996 946 
Regulatory liabilities316 325 
Asset retirement obligations12 13 
Other127 117 
Total deferred credits and other liabilities1,451 1,401 
Total liabilities4,418 4,179 
Commitments and contingencies
Shareholder's equity
Common stock ($2.25 par value, 0 shares(a) authorized, 0 shares(a) outstanding as of December 31, 2025 and 2024, respectively)
1,722 1,615 
Retained earnings649 627 
Total shareholder's equity2,371 2,242 
Total liabilities and shareholder's equity$6,789 $6,421 
_____________
(a)In millions, shares round to zero. Number of shares is 1,000 authorized and outstanding as of December 31, 2025 and 2024.
See the Combined Notes to Consolidated Financial Statements

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Delmarva Power & Light Company
Statements of Changes in Shareholder's Equity
(In millions)Common StockRetained EarningsTotal Shareholder's Equity
Balance at December 31, 2022$1,356 $594 $1,950 
Net income— 177 177 
Common stock dividends— (133)(133)
Contributions from parent99 — 99 
Balance at December 31, 2023$1,455 $638 $2,093 
Net income— 209 209 
Common stock dividends— (220)(220)
Contributions from parent160 — 160 
Balance at December 31, 2024$1,615 $627 $2,242 
Net income— 224 224 
Common stock dividends— (202)(202)
Contributions from parent107 — 107 
Balance at December 31, 2025$1,722 $649 $2,371 
See the Combined Notes to Consolidated Financial Statements

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Atlantic City Electric Company and Subsidiary Company
Consolidated Statements of Operations and Comprehensive Income
For the Years Ended December 31,
(In millions)202520242023
Operating revenues
Electric operating revenues$1,712 $1,638 $1,493 
Revenues from alternative revenue programs2 (12)27 
Operating revenues from affiliates4 2 2 
Total operating revenues1,718 1,628 1,522 
Operating expenses
Purchased power808 698 637 
Operating and maintenance173 206 233 
Operating and maintenance from affiliates155 162 153 
Depreciation and amortization248 278 283 
Taxes other than income taxes9 9 8 
Total operating expenses1,393 1,353 1,314 
Gain on sale of assets2 — — 
Operating income327 275 208 
Other income and (deductions)
Interest expense, net(82)(74)(72)
Interest expense to affiliates, net— (5)— 
Other, net10 14 20 
Total other income and (deductions)(72)(65)(52)
Income before income taxes255 210 156 
Income taxes67 55 36 
Net income$188 $155 $120 
Comprehensive income$188 $155 $120 
See the Combined Notes to Consolidated Financial Statements

151
Table of Contents
Atlantic City Electric Company and Subsidiary Company
Consolidated Statements of Cash Flows
For the Years Ended December 31,
(In millions)202520242023
Cash flows from operating activities
Net income$188 $155 $120 
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation and amortization248 278 283 
Gain on sales of assets(2)— — 
Deferred income taxes and amortization of investment tax credits47 39 27 
Other non-cash operating activities38 70 — 
Changes in assets and liabilities:
Accounts receivable(14)(35)(57)
Receivables from and payables to affiliates, net(3)(8)(4)
Inventories(13)(8)(12)
Accounts payable and accrued expenses(8)(18)27 
Collateral received (paid), net5 — (50)
Income taxes9 (5)— 
Regulatory assets and liabilities, net(62)(88)(47)
Pension and non-pension postretirement benefit contributions(4)(9)(3)
Other assets and liabilities(1)(44)(83)
Net cash flows provided by operating activities428 327 201 
Cash flows from investing activities
Capital expenditures(390)(373)(460)
Proceeds from sale of long-lived assets2 — — 
Net cash flows used in investing activities(388)(373)(460)
Cash flows from financing activities
Changes in short-term borrowings(38)(13)199 
Issuance of long-term debt250 250 75 
Retirement of long-term debt(150)(150)— 
Dividends paid on common stock(183)(127)(126)
Contributions from parent98 85 65 
Other financing activities(7)(6)(5)
Net cash flows (used in) provided by financing activities(30)39 208 
Increase (decrease) in cash, restricted cash, and cash equivalents10 (7)(51)
Cash, restricted cash, and cash equivalents at beginning of period14 21 72 
Cash, restricted cash, and cash equivalents at end of period$24 $14 $21 
Supplemental cash flow information
Increase (decrease) in capital expenditures not paid$11 $4 $(47)
See the Combined Notes to Consolidated Financial Statements

152
Table of Contents
Atlantic City Electric Company and Subsidiary Company
Consolidated Balance Sheets
December 31,
(In millions)20252024
ASSETS
Current assets
Cash and cash equivalents$22 $14 
Restricted cash and cash equivalents2 — 
Accounts receivable
Customer accounts receivable239223
Customer allowance for credit losses(27)(32)
Customer accounts receivable, net212 191 
Other accounts receivable6479
Other allowance for credit losses(13)(13)
Other accounts receivable, net51 66 
Receivables from affiliates12 7 
Inventories, net76 62 
Regulatory assets93 101 
Other8 6 
Total current assets476 447 
Property, plant, and equipment, (net of accumulated depreciation and amortization of $1,956 and $1,798 as of December 31, 2025 and 2024, respectively)
4,556 4,366 
Deferred debits and other assets
Regulatory assets559 502 
Other41 34 
Total deferred debits and other assets600 536 
Total assets$5,632 $5,349 
See the Combined Notes to Consolidated Financial Statements

153
Table of Contents
Atlantic City Electric Company and Subsidiary Company
Consolidated Balance Sheets
December 31,
(In millions)20252024
LIABILITIES AND SHAREHOLDER'S EQUITY
Current liabilities
Short-term borrowings$148 $186 
Long-term debt due within one year5 154 
Accounts payable168 163 
Accrued expenses64 52 
Payables to affiliates24 22 
Customer deposits26 24 
Regulatory liabilities48 10 
Other13 10 
Total current liabilities496 621 
Long-term debt2,028 1,779 
Deferred credits and other liabilities
Deferred income taxes and unamortized investment tax credits869 816 
Regulatory liabilities137 146 
Other74 62 
Total deferred credits and other liabilities1,080 1,024 
Total liabilities3,604 3,424 
Commitments and contingencies
Shareholder's equity
Common stock ($3.00 par value, 25 shares authorized, 9 shares outstanding as of December 31, 2025 and 2024)
2,013 1,915 
Retained earnings15 10 
Total shareholder's equity2,028 1,925 
Total liabilities and shareholder's equity$5,632 $5,349 
See the Combined Notes to Consolidated Financial Statements

154
Table of Contents
Atlantic City Electric Company and Subsidiary Company
Consolidated Statements of Changes in Shareholder's Equity
(In millions)Common Stock Retained Earnings (Deficit)Total Shareholder's Equity
Balance at December 31, 2022$1,765 $(12)$1,753 
Net income— 120 120 
Common stock dividends— (126)(126)
Contributions from parent65 — 65 
Balance at December 31, 2023$1,830 $(18)$1,812 
Net income— 155 155 
Common stock dividends— (127)(127)
Contributions from parent85 — 85 
Balance at December 31, 2024$1,915 $10 $1,925 
Net income— 188 188 
Common stock dividends— (183)(183)
Contributions from parent98 — 98 
Balance at December 31, 2025$2,013 $15 $2,028 

See the Combined Notes to Consolidated Financial Statements

155
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)

Note 1 — Significant Accounting Policies
1. Significant Accounting Policies (All Registrants)
Description of Business (All Registrants)
Exelon is a utility services holding company engaged in the energy transmission and distribution businesses through ComEd, PECO, BGE, Pepco, DPL, and ACE.
Name of Registrant   Business  Service Territories
Commonwealth Edison Company Purchase and regulated retail sale of electricityNorthern 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 gasSoutheastern Pennsylvania, including the City of Philadelphia (electricity)
Transmission and distribution of electricity and distribution of natural gas to retail customersPennsylvania counties surrounding the City of Philadelphia (natural gas)
Baltimore Gas and Electric Company Purchase and regulated retail sale of electricity and natural gasCentral 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 ACEService 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 gasPortions of Delaware and Maryland (electricity)
Transmission and distribution of electricity and distribution of natural gas to retail customersPortions of New Castle County, Delaware (natural gas)
Atlantic City Electric Company Purchase and regulated retail sale of electricityPortions of Southern New Jersey
Transmission and distribution of electricity to retail customers
Basis of Presentation (All Registrants)
This is a combined annual report of all Registrants. The Notes to the Consolidated Financial Statements apply to the Registrants as indicated parenthetically next to each corresponding disclosure. When appropriate, the Registrants are named specifically for their related activities and disclosures. Each of the Registrants' Consolidated Financial Statements includes the accounts of its subsidiaries. All intercompany transactions have been eliminated.
Through its business services subsidiary, BSC, Exelon provides its subsidiaries with a variety of support services at cost, including legal, human resources, financial, information technology, and supply management services. PHI also has a business services subsidiary, PHISCO, which provides a variety of support services at cost, including legal, finance, engineering, customer operations, transmission and distribution planning, asset management, system operations, and power procurement, to PHI operating Registrants. The costs of BSC and PHISCO are directly charged or allocated to the applicable subsidiaries. The results of Exelon’s corporate operations are presented as “Other” within the consolidated financial statements and include intercompany eliminations unless otherwise disclosed.
As of December 31, 2025, 2024, and 2023, Exelon owned 100% of PECO, BGE, and PHI and more than 99% of ComEd. PHI owns 100% of Pepco, DPL, and ACE.
The accompanying consolidated financial statements have been prepared in accordance with GAAP for annual financial statements and in accordance with the instructions to Form 10-K and Regulation S-X promulgated by the SEC.
156
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)

Note 1 — Significant Accounting Policies
Use of Estimates (All Registrants)
The preparation of financial statements of each of the Registrants in conformity with GAAP requires management to make estimates and assumptions that affect the amounts reported in the financial statements and accompanying notes. Areas in which significant estimates have been made include, but are not limited to, the accounting for pension and OPEB, unbilled energy revenues, allowance for credit losses, inventory reserves, goodwill and long-lived asset impairment assessments, derivative instruments, unamortized energy contracts, fixed asset depreciation, capitalization of indirect construction costs, environmental costs and other loss contingencies, AROs, and income taxes. Actual results could differ from those estimates.
Regulatory Accounting (All Registrants)
For their regulated electric and gas operations, the Registrants reflect the effects of cost-based rate regulation in their financial statements, which is required for entities with regulated operations that meet the following criteria: (1) rates are established or approved by a third-party regulator; (2) rates are designed to recover the entities’ cost of providing services or products; and (3) there is a reasonable expectation that rates designed to recover costs can be charged to and collected from customers. The Registrants account for their regulated operations in accordance with regulatory and legislative guidance from the regulatory authorities having jurisdiction, principally the ICC, PAPUC, MDPSC, DCPSC, DEPSC, and NJBPU, under state public utility laws and the FERC under various Federal laws. Regulatory assets and liabilities are amortized and the related expense or revenue is recognized in the Consolidated Statements of Operations consistent with the recovery or refund included in customer rates. The Registrants' regulatory assets and liabilities as of the balance sheet date are probable of being recovered or settled in future rates. If a separable portion of the Registrants' business was no longer able to meet the criteria discussed above, the affected entities would be required to eliminate from their consolidated financial statements the effects of regulation for that portion, which could have a material impact on their financial statements. See Note 2 — Regulatory Matters for additional information.
With the exception of income tax-related regulatory assets and liabilities, the Registrants classify regulatory assets and liabilities with a recovery or settlement period greater than one year as both current and noncurrent in their Consolidated Balance Sheets, with the current portion representing the amount expected to be recovered from or refunded to customers over the next twelve-month period as of the balance sheet date. Income tax-related regulatory assets and liabilities are classified entirely as noncurrent in the Registrants’ Consolidated Balance Sheets to align with the classification of the related deferred income tax balances.
The Registrants treat the impacts of a final rate order received after the balance sheet date but prior to the issuance of the financial statements as a non-recognized subsequent event, as the receipt of a final rate order is a separate and distinct event that has future impacts on the parties affected by the order.
Revenues (All Registrants)
Operating Revenues. The Registrants’ operating revenues generally consist of revenues from contracts with customers involving the sale and delivery of power and natural gas and utility revenues from ARPs. The Registrants recognize revenue from contracts with customers to depict the transfer of goods or services to customers in an amount that the entities expect to be entitled to in exchange for those goods or services. The primary sources of revenue include regulated electric and natural gas tariff sales, distribution, and transmission services. At the end of each month, the Registrants accrue an estimate for the unbilled amount of energy delivered or services provided to customers.
ComEd records ARP revenue for its best estimate of the electric distribution, energy efficiency, 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. The Registrants recognize all ARP revenues that will be collected within 24 months of the end of the annual period in which they are recorded. See Note 2 — Regulatory Matters for additional information.
157
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)

Note 1 — Significant Accounting Policies
Taxes Directly Imposed on Revenue-Producing Transactions. The Registrants collect certain taxes from customers such as sales and gross receipts taxes, along with other taxes, surcharges, and fees, that are levied by state or local governments on the sale or distribution of electricity and gas. Some of these taxes are imposed on the customer, but paid by the Registrants, while others are imposed on the Registrants. Where these taxes are imposed on the customer, such as sales taxes, they are reported on a net basis with no impact to the Consolidated Statements of Operations and Comprehensive Income. However, where these taxes are imposed on the Registrants, such as gross receipts taxes or other surcharges or fees, they are reported on a gross basis. Accordingly, revenues are recognized for the taxes collected from customers along with an offsetting expense. See Note 20 — Supplemental Financial Information for taxes that are presented on a gross basis.
Leases (All Registrants)
The Registrants recognize a ROU asset and lease liability for operating and finance leases when the term is greater than one year. Operating lease ROU assets are included in Other deferred debits and other assets and operating lease liabilities are included in Other current liabilities and Other deferred credits and other liabilities on the Consolidated Balance Sheets. Finance lease ROU assets are included in Property, plant, and equipment, net and finance lease liabilities are included in Long-term debt due within one year and Long-term debt on the Consolidated Balance Sheets. The ROU asset is measured as the sum of (1) the present value of all remaining fixed and in-substance fixed payments using the rate implicit in the lease whenever that is readily determinable or each Registrant’s incremental borrowing rate, (2) any lease payments made at or before the commencement date (less any lease incentives received), and (3) any initial direct costs incurred. The lease liability is measured the same as the ROU asset, but excludes any payments made before the commencement date and initial direct costs incurred. Lease terms include options to extend or terminate the lease if it is reasonably certain they will be exercised. The Registrants include non-lease components, which are service-related costs that are not integral to the use of the asset, in the measurement of the ROU asset and lease liability.
Expense for operating leases and leases with a term of one year or less is recognized on a straight-line basis over the term of the lease, unless another systematic and rational basis is more representative of the derivation of benefit from use of the leased property. Variable lease payments are recognized in the period in which the related obligation is incurred. Operating lease expense, finance lease expense, and variable lease payments are primarily recorded to Operating and maintenance expense on the Registrants’ Statements of Operations and Comprehensive Income.
Income from operating leases, including subleases, is recognized on a straight-line basis over the term of the lease, unless another systematic and rational basis is more representative of the pattern in which income is earned over the term of the lease. Variable lease income is recognized in the period in which the related obligation is performed. Operating lease income and variable lease income are recorded to Operating revenues on the Registrants’ Statements of Operations and Comprehensive Income.
The Registrants’ operating and finance leases consist primarily of real estate, including office buildings, and vehicles and equipment. The Registrants account for land right arrangements that provide for exclusive use as leases while shared use land arrangements are generally not leases. The Registrants do not account for secondary use pole attachments as leases. See Note 9 — Leases for additional information.
Income Taxes (All Registrants)
Deferred federal and state income taxes are recorded on significant temporary differences between the book and tax basis of assets and liabilities and for tax benefits carried forward. Investment tax credits have been deferred in the Registrants’ Consolidated Balance Sheets and are recognized in book income over the life of the related property. The Registrants account for uncertain income tax positions using a benefit recognition model with a two-step approach; a more-likely-than-not recognition criterion; and a measurement approach that measures the position as the largest amount of tax benefit that is greater than 50% likely of being realized upon ultimate settlement. If it is not more-likely-than-not that the benefit of the tax position will be sustained on its technical merits, no benefit is recorded. Uncertain tax positions that relate only to timing of when an item is included on a tax return are considered to have met the recognition threshold. The Registrants recognize accrued interest related to unrecognized tax benefits in Interest expense, net or Other, net (interest income) and recognize penalties related to unrecognized tax benefits in Other, net in their Consolidated Statements of Operations and Comprehensive Income.
158
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)

Note 1 — Significant Accounting Policies
Cash and Cash Equivalents (All Registrants)
The Registrants consider investments purchased with an original maturity of three months or less to be cash equivalents.
Restricted Cash and Cash Equivalents (All Registrants)
Restricted cash and cash equivalents represent funds that are restricted to satisfy designated current liabilities. As of December 31, 2025 and 2024, the Registrants' restricted cash and cash equivalents primarily represented the following items:
RegistrantDescription
ExelonPayment of medical, dental, vision, and long-term disability benefits, in addition to the items listed below for the Utility Registrants.
ComEdCollateral held from suppliers associated with energy and REC procurement contracts, any over-recovered RPS costs and alternative compliance payments received from RES pursuant to FEJA.
PECOProceeds from the sales of assets that were subject to PECO’s mortgage indenture.
BGECollateral held from energy suppliers.
PHIPayment of merger commitments, collateral held from energy suppliers associated with procurement contracts, and payments of REC procurement costs to NJBPU program participants through an administrator.
PepcoPayment of merger commitments and collateral held from energy suppliers.
DPLCollateral held from energy suppliers.
ACEPayment of REC procurement costs to NJBPU program participants through an administrator.
__________
Restricted cash and cash equivalents not available to satisfy current liabilities are classified as noncurrent assets. As of December 31, 2025 and 2024, the Registrants' noncurrent restricted cash and cash equivalents primarily represented ComEd’s alternative compliance payments received from RES pursuant to FEJA and are included in other deferred debits and other assets.
See Note 14 — Debt and Credit Agreements and Note 20 — Supplemental Financial Information for additional information.
Allowance for Credit Losses on Customer Receivables (All Registrants)
The allowance for credit losses reflects the Registrants’ best estimates of losses on the customers' accounts receivable balances based on historical experience, current information, and reasonable and supportable forecasts.
The allowance for credit losses is estimated based on historical experience, current conditions, and forward-looking risk factors. Utility Registrants' customer accounts are written off consistent with approved regulatory requirements. Adjustments to the allowance for credit losses are primarily recorded to Operating and maintenance expense on the Registrants' Consolidated Statements of Operations and Comprehensive Income or Regulatory assets and liabilities on the Registrants' Consolidated Balance Sheets. See Note 2 — Regulatory Matters for additional information regarding the regulatory recovery of credit losses on customer accounts receivable.
The Registrants have certain non-customer receivables in Other deferred debits and other assets which primarily are with governmental agencies and other high-quality counterparties with no history of default. As such, the allowance for credit losses related to these receivables is not material. The Registrants monitor these balances and will record an allowance if there are indicators of a decline in credit quality. See Note 5 — Accounts Receivable for additional information.
Inventories (All Registrants)
Inventory is recorded at the lower of weighted average cost or net realizable value. Provisions are recorded for excess and obsolete inventory. Fossil fuel and Materials and supplies are generally included in inventory when purchased. Fossil fuel is expensed to Purchased power and fuel expense when used or sold. Materials and
159
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)

Note 1 — Significant Accounting Policies
supplies generally includes transmission and distribution materials and are expensed to Operating and maintenance or capitalized to Property, plant, and equipment, as appropriate, when installed or used.
Property, Plant, and Equipment (All Registrants)
Property, plant, and equipment is recorded at original cost. Original cost includes construction-related direct labor and material costs and indirect construction costs including labor and related costs of departments associated with supporting construction activities. When appropriate, original cost also includes AFUDC for regulated property at the Utility Registrants. The cost of repairs and maintenance and minor replacements of property is charged to Operating and maintenance expense as incurred.
Third parties reimburse the Utility Registrants for all or a portion of expenditures for certain capital projects. Such contributions in aid of construction costs (CIAC) are recorded as a reduction to Property, plant, and equipment, net.
Upon retirement, the cost of property, net of salvage, is charged to accumulated depreciation consistent with the composite and group methods of depreciation. Depreciation expense at ComEd, BGE, Pepco, DPL, and ACE includes the estimated cost of dismantling and removing plant from service upon retirement. Actual incurred removal costs are applied against a related regulatory liability or recorded to a regulatory asset if in excess of previously collected removal costs. PECO’s removal costs are capitalized to accumulated depreciation when incurred and recorded to depreciation expense over the life of the new asset constructed consistent with PECO’s regulatory recovery method.
Capitalized Software. Certain costs, such as design, coding, and testing incurred during the application development stage of software projects that are internally developed or purchased for operational use are capitalized within Property, plant, and equipment. Similar costs incurred for cloud-based solutions treated as service arrangements are capitalized within Other Current Assets and Deferred Debits and Other Assets. Such capitalized amounts are amortized ratably over the expected lives of the projects when they become operational, generally not to exceed five years. Certain other capitalized software costs are being amortized over longer lives based on the expected life or pursuant to prescribed regulatory requirements.
AFUDC. AFUDC is the cost, during the period of construction, of debt and equity funds used to finance construction projects for regulated operations. AFUDC is recorded to construction work in progress and as a non-cash credit to an allowance that is included in interest expense for debt-related funds and other income and deductions for equity-related funds. The rates used for capitalizing AFUDC are computed under a method prescribed by regulatory authorities.
See Note 6 — Property, Plant, and Equipment, Note 7 — Jointly Owned Electric Utility Plant and Note 20 — Supplemental Financial Information for additional information.
Depreciation and Amortization (All Registrants)
Depreciation is generally recorded over the estimated service lives of property, plant, and equipment on a straight-line basis using the group or composite methods of depreciation. The group approach is typically for groups of similar assets that have approximately the same useful lives and the composite approach is used for dissimilar assets that have different lives. Under both methods, a reporting entity depreciates the assets over the average life of the assets in the group. ComEd, BGE, Pepco, DPL, and ACE's depreciation expense includes the estimated cost of dismantling and removing plant from service upon retirement, which is consistent with each utility's regulatory recovery method. PECO's removal costs are capitalized to accumulated depreciation when incurred and recorded to depreciation expense over the life of the new asset constructed consistent with PECO's regulatory recovery method. The estimated service lives for the Registrants are based on a combination of depreciation studies and historical retirements. See Note 6 — Property, Plant, and Equipment for additional information regarding depreciation.
Amortization of regulatory assets and liabilities are recorded over the recovery or refund period specified in the related legislation or regulatory order or agreement. When the recovery or refund period is less than one year, amortization is recorded to the line item in which the deferred cost or income would have originally been recorded in the Registrants’ Consolidated Statements of Operations and Comprehensive Income. Amortization of ComEd’s electric distribution rate reconciliations and energy efficiency formula rate regulatory assets and the Utility Registrants' transmission formula rate regulatory assets is recorded to Operating revenues.
160
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)

Note 1 — Significant Accounting Policies
Amortization of income tax related regulatory assets and liabilities is generally recorded to Income tax expense. Except for the regulatory assets and liabilities discussed above, amortization is generally recorded to Depreciation and amortization in the Registrants’ Consolidated Statements of Operations and Comprehensive Income when the recovery period is more than one year.
See Note 2 — Regulatory Matters and Note 20 — Supplemental Financial Information for additional information regarding the amortization of the Registrants' regulatory assets.
Asset Retirement Obligations (All Registrants)
The Registrants estimate and recognize a liability for their legal obligation to perform asset retirement activities even though the timing and/or methods of settlement may be conditional on future events. The Registrants update their AROs either annually or on a rotational basis at least once every three years, based on a risk profile, unless circumstances warrant more frequent updates. The updates factor in new cost estimates, credit-adjusted, risk-free rates (CARFR) and escalation rates, and the timing of cash flows. AROs are accreted throughout each year to reflect the time value of money for these present value obligations through an increase to Regulatory assets. See Note 8 — Asset Retirement Obligations for additional information.
Guarantees (All Registrants)
If necessary, the Registrants recognize a liability at the time of issuance of a guarantee for the fair value of the obligations they have undertaken. The liability is reduced or eliminated as the Registrants are released from risk under the guarantee. Depending on the nature of the guarantee, the release from risk of the Registrant may be recognized only upon the expiration or settlement of the guarantee or by a systematic and rational amortization method over the term of the guarantee. See Note 16 — Commitments and Contingencies for additional information.
Asset Impairments
Long-Lived Assets (All Registrants). The Registrants evaluate the carrying value of long-lived assets for recoverability whenever events or changes in circumstances indicate that the carrying value of those assets may not be recoverable. Indicators of impairment may include specific regulatory disallowance, abandonment, or plans to dispose of a long-lived asset significantly before the end of its useful life. When the estimated undiscounted future cash flows attributable to the long-lived asset may not be recoverable, the amount of the impairment loss is determined by measuring the excess of the carrying amount of the long-lived asset over its fair value.
Goodwill (Exelon, ComEd, and PHI). Goodwill represents the excess of the purchase price paid over the estimated fair value of the net assets acquired and liabilities assumed in the acquisition of a business. Goodwill is not amortized but is assessed for impairment at least annually or on an interim basis if an event occurs or circumstances change that would more likely than not reduce the fair value of a reporting unit below its carrying value. See Note 10 — Intangible Assets for additional information.
Derivative Financial Instruments (All Registrants)
Derivatives are recognized on the balance sheet at their fair value unless they qualify for certain exceptions, including NPNS. For derivatives that qualify and are designated as cash flow hedges, changes in fair value each period are initially recorded in AOCI and recognized in earnings when the underlying hedged transaction affects earnings. Amounts recognized in earnings are recorded in Interest expense, net on the Consolidated Statement of Operations and Comprehensive Income based on the activity the transaction is economically hedging. Cash inflows and outflows related to derivative instruments designated as cash flow hedges are included as a component of operating, investing, or financing cash flows in the Consolidated Statements of Cash Flows, depending on the nature of each transaction.
For derivatives intended to serve as economic hedges, which are not designated for hedge accounting, changes in fair value each period are recognized in earnings or as a regulatory asset or liability. Amounts recognized in earnings are recorded in Electric operating revenues, Purchased power and fuel, or Interest expense in the Consolidated Statements of Operations and Comprehensive Income based on the activity the transaction is economically hedging. Changes in fair value are also recorded as a regulatory asset or liability when there is an ability to recover or return the associated costs or benefits in accordance with regulatory requirements. Cash
161
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)

Note 1 — Significant Accounting Policies
inflows and outflows related to derivative instruments are included as a component of operating, investing, or financing cash flows in the Consolidated Statements of Cash Flows, depending on the nature of the hedged item. See Note 2 — Regulatory Matters and Note 13 — Derivative Financial Instruments for additional information.
Retirement Benefits (All Registrants)
Exelon sponsors defined benefit pension plans and OPEB plans.

The plan obligations and costs of providing benefits under these plans are measured as of December 31. The measurement involves various factors, assumptions, and accounting elections. The impact of assumption changes or experiences different from those assumed on pension and OPEB obligations is recognized over time rather than immediately recognized in the Consolidated Statements of Operations and Comprehensive Income. Gains or losses in excess of the greater of ten percent of the projected benefit obligation or the MRV of plan assets are amortized over the expected average remaining service period of plan participants. See Note 12 — Retirement Benefits for additional information.
New Accounting Standards (All Registrants)
New Accounting Standards Adopted in 2025: In 2025, the Registrants adopted the following new FASB authoritative accounting guidance.
Improvements to Income Tax Disclosures (Issued December 2023). Provides additional disclosure requirements related to the effective tax rate reconciliation and income taxes paid. Under the revised guidance for the effective tax reconciliations, entities would be required to disclose: (1) eight specific categories in the effective tax rate reconciliation in both percentages and reporting currency amount, (2) additional information for reconciling items over a certain threshold, (3) explanation of individual reconciling items disclosed, and (4) provide a qualitative description of the state and local jurisdictions that contribute to the majority of the state income tax expense. For each annual period presented, the new standard requires disclosure of the year-to-date amount of income taxes paid (net of refunds received) disaggregated by federal, state, and foreign. It also requires additional disaggregated information on income taxes paid (net of refunds received) to an individual jurisdiction equal to or greater than 5% of total income taxes paid (net of refunds received). The standard is effective for annual periods beginning January 1, 2025. The Registrants' adoption of this guidance in the fourth quarter of 2025 resulted in an expanded effective tax rate reconciliation. The standard has been applied retrospectively. See Note 11 — Income Taxes for additional information.
New Accounting Standards Issued and Not Yet Adopted as of December 31, 2025: The following new authoritative accounting guidance issued by the FASB has not yet been adopted and reflected by the Registrants in their consolidated financial statements as of December 31, 2025. Unless otherwise indicated, the Registrants are currently assessing the impacts such guidance may have (which could be material) in their Consolidated Balance Sheets, Consolidated Statements of Operations and Comprehensive Income, Consolidated Statements of Cash Flows and disclosures, as well as the potential to early adopt where applicable. The Registrants have assessed other FASB issuances of new standards which are not listed below given the current expectation that such standards will not significantly impact the Registrants' financial reporting.
Disaggregation of Income Statement Expenses (Issued November 2024). Provides additional disclosure requirements related to relevant expense captions of income statement expense line items. The revised guidance requires a new tabular disclosure of disaggregated income statement expenses including a break out of (1) purchases of inventory, (2) employee compensation, (3) depreciation, (4) intangible asset amortization, (5) depreciation, depletion, and amortization recognized as part of oil and gas producing activities included in each relevant expense line item on the income statement. The tabular disaggregation should include certain amounts already required to be disclosed under GAAP elsewhere. Any remaining amounts not separately disaggregated quantitatively should include a qualitative description. Additionally, on an annual basis, the standard requires disclosure of management’s definition of selling expenses and the amount of expense. The standard is effective January 1, 2027, with early adoption permitted.
Targeted Improvements to the Accounting for Internal Use Software (Issued September 2025). Modernizes the accounting for costs related to internal use software to align with the agile basis utilized to develop software. The revised guidance removes references to project stages, clarifies the capitalization threshold for software costs, and expands disclosure requirements for capitalized software. Cost capitalization will begin with (1) management
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Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)

Note 1 — Significant Accounting Policies
authorized and committed project funding and (2) it is 'probable' to complete the project and the software will be used in its intended function. The standard is effective for annual and interim periods beginning January 1, 2028. The standard can be implemented using a prospective, retrospective, or modified retrospective transition approach with early adoption permitted.
Accounting for Government Grants (Issued December 2025). Establishes accounting guidance for government grants received by defining (1) a grant related to an asset and (2) a grant related to income. Updates provide that a grant should not be recognized until it is probable the entity will comply with grant conditions and the grant will be received. A grant related to an asset is required to be recognized on the balance sheet either as (1) deferred income (deferred income approach) or (2) an adjustment to carrying value (cost accumulation approach). Grants related to income and grants related to assets for which the deferred income approach is elected should be recognized in earnings on a systematic basis over the periods in which an entity recognizes expenses for the costs the grant was intended to compensate. The standard is effective for annual and interim periods beginning January 1, 2029, with early adoption permitted.
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Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)

Note 2 — Regulatory Matters
2.  Regulatory Matters (All Registrants)
The following matters below discuss the status of material regulatory and legislative proceedings of the Registrants.
Distribution Base Rate Case Proceedings
The following tables show the completed and pending distribution base rate case proceedings in 2025.
Completed Distribution Base Rate Case Proceedings
Registrant/JurisdictionFiling DateServiceRequested Revenue Requirement Increase Approved Revenue Requirement Increase Approved ROEApproval DateRate Effective Date
ComEd - IllinoisJanuary 17, 2023Electric$1,487 $1,045 8.905%December 19, 2024January 1, 2024
April 26, 2024 (amended on September 11, 2024)Electric$624 $623 9.89%October 31, 2024January 1, 2025
PECO - PennsylvaniaMarch 28, 2024Electric$464$354 N/ADecember 12, 2024January 1, 2025
Natural Gas$111$78 
BGE - MarylandFebruary 17, 2023Electric$313 $179 9.50%December 14, 2023January 1, 2024
Natural Gas$289 $229 9.45%
Pepco - District of ColumbiaApril 13, 2023 (amended February 27, 2024)Electric$186 $123 9.50%November 26, 2024January 1, 2025
Pepco - MarylandMay 16, 2023 (amended February 23, 2024)Electric$111 $45 9.50%June 10, 2024April 1, 2024
DPL - MarylandMay 19, 2022Electric$38 $29 9.60%December 14, 2022January 1, 2023
DPL - DelawareDecember 15, 2022 (amended September 29, 2023)Electric$39 $28 9.60%April 18, 2024July 15, 2023
September 20, 2024 (amended September 5, 2025)Natural Gas$37 $22 9.60%December 17, 2025January 1, 2026
ACE - New JerseyFebruary 15, 2023 (amended August 21, 2023)Electric$92 $45 9.60%November 17, 2023December 1, 2023
November 21, 2024Electric$109 $54 9.60%November 21, 2025December 1, 2025


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Note 2 — Regulatory Matters
Pending Distribution Base Rate Case Proceedings
Registrant/JurisdictionFiling DateServiceRequested Revenue Requirement IncreaseRequested ROEExpected Approval Timing
Pepco - MarylandOctober 14, 2025Electric$133 10.50%Third quarter of 2026
DPL - Delaware(a)
December 9, 2025Electric$45 10.50%Third quarter of 2027
__________
(a)DPL can implement interim rates on July 9, 2026, subject to refund.

ComEd Distribution Base Rate Case Proceedings
The ICC approved ComEd's four-year MRP for the period January 1, 2024 through December 31, 2027. The MRP was originally approved by the ICC on December 14, 2023 and was subsequently amended on January 10, 2024, April 18, 2024 and December 19, 2024. The December 19, 2024 order provided a total revenue requirement increase of $1.045 billion inclusive of rate increases of approximately $752 million in 2024, $80 million in 2025, $102 million in 2026, and $111 million in 2027.
On March 20, 2025, ComEd filed its annual revenue balancing reconciliation for 2024. This reconciliation, which is a component of revenue decoupling, reflected a revenue reduction of $55 million, effective January 1, 2026.
On December 18, 2025, the ICC approved ComEd's 2024 MRP Reconciliation reflecting a revenue increase of $243 million, including the tax benefit of NOLCs. While NOLCs are included in the MRP Reconciliation per the final order, the impacts of the NOLCs will not be reflected in the financial statements until the PLR is received from the IRS. See Note 11 — Income Taxes for additional information on NOLCs. On January 20, 2026, the Illinois Attorney General filed an Application for Rehearing of the December 18 order, which focuses solely on NOLCs. On February 5, 2026, the ICC denied the Illinois Attorney General's Application for Rehearing.
On October 31, 2024, the Delivery Reconciliation Amount for 2023 defined in Rider Delivery Service Pricing Reconciliation (Rider DSPR) was approved. Rider DSPR allows for the reconciliation of the revenue requirement in effect in the final years in which formula rates were determined and until such time as new rates were established under ComEd's approved MRP. The 2024 order reconciled the delivery service rates in effect in 2023 with the actual delivery service costs incurred in 2023. The reconciliation revenue requirement provides for a weighted average debt and equity return on distribution rate base of 7.02%, inclusive of an allowed ROE of 9.89%, reflecting the monthly yields on 30-year treasury bonds plus 580 basis points.
PECO Distribution Base Rate Case Proceedings
On December 12, 2024, the PAPUC issued their Opinions and Orders which approved the non-unanimous partial settlements with limited modifications for both the electric and natural gas base rate cases, and denied the Weather Normalization Adjustment requested in the natural gas base rate case.
PECO’s approved annual electric revenue requirement increase of $354 million is partially offset by a one-time credit of $64 million in 2025. In addition, the PAPUC approved the recovery of storm damage costs incurred by PECO in January 2024, up to $23 million, subject to review for reasonableness and prudency in PECO’s next distribution rate case.
BGE Distribution Base Rate Case Proceedings
In February 2023, BGE filed its three-year cumulative multi-year plan for January 1, 2024 through December 31, 2026 to the MDPSC, which was approved in December 2023 and went into effect on January 1, 2024. The MDSPC awarded BGE electric revenue requirement increases of $41 million, $113 million, and $25 million with an approved ROE of 9.50% in 2024, 2025, and 2026, respectively, and natural gas revenue requirement increases of $126 million, $62 million, and $41 million with an approved ROE of 9.45% in 2024, 2025, and 2026, respectively. The requested revenue requirement increases will be used to recover capital investments designed to increase the resilience of the electric and gas distribution systems and support Maryland's climate and regulatory initiatives.
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Note 2 — Regulatory Matters
The MDPSC also approved a portion of the requested 2021 and 2022 reconciliation amounts, which were recovered through separate electric and gas riders between March 2024 and February 2025. As such, the reconciliation amounts are not included in the approved revenue increases. The 2021 reconciliation amounts are $13 million and $7 million for electric and gas, respectively, and the 2022 reconciliation amounts are $39 million and $15 million for electric and gas, respectively. In April 2024, BGE filed with the MDPSC its request for recovery of the 2023 reconciliation amounts of $79 million and $73 million for electric and gas, respectively, with supporting testimony and schedules. In December 2025, the MDPSC authorized BGE to recover $31 million and $46 million for electric and gas, respectively, beginning in February 2026 and extending through December 2027, in the reconciliation rider. In addition to the amounts approved in the reconciliation rider, the MDPSC provided for additional regulatory assets related to minor storms of $24 million (to be recovered over 5 years) and the Baltimore City conduit of $4 million (to be reviewed along with a cost-benefit analysis in BGE’s next rate case).
Pepco District of Columbia Distribution Base Rate Case Proceedings
On April 13, 2023, Pepco filed an electric base rate case with the DCPSC (amended February 27, 2024) requesting a total revenue requirement increase of $186 million and an ROE of 10.50%. The DCPSC issued an order approving the two-year cumulative multi-year plan on November 26, 2024, which included a total revenue requirement increase of $123 million with an ROE of 9.50% effective January 1, 2025 through December 31, 2026. The DCPSC awarded Pepco electric incremental revenue requirement increases of $99 million and $24 million for 2025 and 2026, respectively.
Pepco Maryland Distribution Base Rate Case Proceedings
On May 16, 2023, Pepco filed an electric base rate case with the MDPSC (amended February 23, 2024) requesting a total revenue requirement increase of $111 million (before offsets) and an ROE of 10.50%. The MDPSC issued an order on June 10, 2024 awarding Pepco a one-year multi-year plan for April 1, 2024 through March 31, 2025 which included an incremental revenue requirement increase of $45 million and an ROE of 9.50%. The MDPSC did not adopt the requested revenue requirement increases of $80 million (before offsets), $51 million, and $14 million as filed for 2025, 2026, and the 2027 nine-month extension period, respectively. The MDPSC also approved the requested reconciliation amounts for the 12-month periods ending March 31, 2022, and March 31, 2023, which will be recovered through a rider between August 2024 through March 2026. As such, the reconciliation amounts are not included in the approved revenue requirement increases. The reconciliation amounts are $1 million and $7 million, for the 12-month periods ending March 31, 2022, and March 31, 2023, respectively. In July 2024, Pepco filed its request with the MDPSC, for which it is awaiting approval, for recovery of the reconciliation amounts of $31 million for the 12-month period ended March 31, 2024, with supporting testimony and schedules.
DPL Maryland Distribution Base Rate Case Proceedings
On May 19, 2022, DPL filed an electric base rate case with the MDPSC requesting a total revenue requirement increase of $38 million based on an ROE of 10.25%. On December 14, 2022, the MDPSC issued an order awarding DPL a total revenue requirement increase of $29 million with an ROE of 9.60%. The order reflects a three-year cumulative multi-year plan for January 1, 2023 through December 31, 2025, with rates remaining in effect subsequent to the multi-year plan period. The MDPSC awarded DPL electric incremental revenue requirement increases of $17 million, $6 million, and $6 million for 2023, 2024, and 2025, respectively.
DPL Delaware Distribution Base Rate Case Proceedings
On December 15, 2022, DPL filed an electric base rate case with the DEPSC (amended September 29, 2023) requesting a total revenue requirement increase of $39 million and an ROE of 10.50%. On April 18, 2024, the DEPSC issued an order awarding DPL a total revenue requirement increase of $28 million with an ROE of 9.60%, effective July 15, 2023. As part of the approved order, the DEPSC approved the Significant Storm Expense Rate Rider (Rider SSER) which will allow DPL to recover expenses associated with qualified storms. A qualified storm will be an individual storm for which DPL incurs expenses between $5 million and $15 million. The Rider SSER allows DPL to recover significant storm damage expenses for the previous 12-month period over a future 24-month period. For individual storm events for which DPL incurs expenses of more than $15 million, the future recovery period will be evaluated on a case-by-case basis and the unamortized balance will earn a return at DPL's authorized long-term cost of debt. The Rider SSER will have an annual true-up filing, subject to DEPSC review and approval.
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Note 2 — Regulatory Matters
ACE New Jersey Distribution Base Rate Case Proceedings
On February 15, 2023, ACE filed an electric base rate case with the NJBPU (amended August 21, 2023) requesting a total revenue requirement increase of $92 million, before NJ sales and use tax, and an ROE of 10.50%. On November 17, 2023, the NJBPU issued an order awarding ACE electric revenue requirement increases, before NJ sales and use tax, of $36 million and $9 million effective December 1, 2023 and February 1, 2024, respectively, with an ROE of 9.60%.
On November 21, 2024, ACE filed an electric base rate case with the NJBPU requesting a total revenue requirement increase of $109 million, before NJ sales and use tax, and an ROE of 10.70%. On November 21, 2025, the NJBPU issued an order awarding ACE an electric revenue requirement increase, before NJ sales and use tax, of $54 million effective December 1, 2025, with an ROE of 9.60%. In addition, the NJBPU approved the recovery through a regulatory asset of work stoppage costs that were incurred by ACE in 2023 of $38 million.
Transmission Formula Rates
The Utility Registrants' transmission rates are each established based on a FERC-approved formula. ComEd, BGE, Pepco, DPL, and ACE are required to file an annual update to the FERC-approved formula on or before May 15, and PECO is required to file on or before May 31, with the resulting rates effective on June 1 of the same year. The annual update for ComEd is based on prior year actual costs and current year projected capital additions (initial year revenue requirement). The update for ComEd also reconciles any differences between the revenue requirement in effect beginning June 1 of the prior year and actual costs incurred for that year (annual reconciliation). The annual update for PECO is based on prior year actual costs and current year projected capital additions, accumulated depreciation, and accumulated deferred income taxes. The annual update for BGE, Pepco, DPL, and ACE is based on prior year actual costs and current year projected capital additions, accumulated depreciation, depreciation and amortization expense, and accumulated deferred income taxes. The update for PECO, BGE, Pepco, DPL, and ACE also reconciles any differences between the actual costs and actual revenues for the calendar year (annual reconciliation).
For 2025, the following increases/(decreases) were included in the Utility Registrants' electric transmission formula rate updates:
Registrant(a)
Initial Revenue Requirement Increase (Decrease)Annual Reconciliation Increase (Decrease)
Total Revenue Requirement Increase (Decrease)(b)
Allowed Return on Rate Base(c)
Allowed ROE(d)
ComEd$78 $49 $127 8.13 %11.50 %
PECO$9 $13 $22 7.54 %10.35 %
BGE$21 $21 $35 (e)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 %
__________
(a)All rates are effective June 1, 2025 - May 31, 2026, subject to review by interested parties pursuant to review protocols of each Utility Registrants' tariffs.
(b)For the Utility Registrants, except for PECO, while the transmission filings reflect the tax benefit of NOLCs, the impacts of the NOLCs will not be reflected in the financial statements until the PLR is received from the IRS. See Note 11 — Income Taxes for additional information on NOLCs.
(c)Represents the weighted average debt and equity return on transmission rate base.
(d)The rate of return on common equity for each Utility Registrant includes a 50-basis-point incentive adder for being a member of an RTO.
(e)The increase in BGE's transmission revenue requirement includes a $7 million reduction related to a FERC-approved dedicated facilities charge to recover the costs of providing transmission service to specifically designated load by BGE.
Other State Regulatory Matters
Illinois Regulatory Matters
CEJA (Exelon and ComEd). On September 15, 2021, the Governor of Illinois signed into law CEJA. CEJA includes, among other features, (1) procurement of CMCs from qualifying nuclear-powered generating facilities,
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Note 2 — Regulatory Matters
(2) a requirement to file a general rate case or a new four-year MRP no later than January 20, 2023 to establish rates effective after ComEd’s existing performance-based distribution formula rate sunsets, (3) requirements that ComEd and the ICC initiate and conduct various regulatory proceedings on subjects including ethics, spending, grid investments, and performance metrics.
ComEd Electric Distribution Rates
Beginning in 2024, ComEd recovers from retail customers, subject to certain exceptions, the costs it incurs to provide electric delivery services either through its electric distribution rate or other recovery mechanisms authorized by CEJA. On January 17, 2023, ComEd filed a petition with the ICC seeking approval of a MRP for 2024-2027. The MRP supports a multi-year grid plan (2024-2027 Grid Plan), also filed on January 17, covering planned investments on the electric distribution system within ComEd’s service area through 2027. Costs incurred during each year of the MRP are subject to ICC review and the plan’s revenue requirement for each year will be reconciled with the actual costs that the ICC determines are prudently and reasonably incurred for that year. The reconciliation is subject to adjustment for certain costs, including a limitation on recovery of costs that are more than 105% of certain costs in the previously approved MRP revenue requirement, absent a modification of the rate plan itself. Thus, for example, the rate adjustments necessary to reconcile 2024 revenues to ComEd’s actual 2024 costs incurred would take effect in January 2026 after the ICC’s review during 2025.
On December 14, 2023, the ICC issued a final order. The ICC rejected ComEd’s 2024-2027 Grid Plan as non-compliant with certain requirements of CEJA and required ComEd to file a revised 2024-2027 Grid Plan. In the absence of an approved 2024-2027 Grid Plan, the ICC set ComEd’s forecast revenue requirements for 2024-2027 based on ComEd's approved year-end 2022 rate base. This resulted in a total cumulative revenue requirement increase of $501 million, a $986 million total revenue reduction from the requested cumulative revenue requirement increase but remained subject to annual reconciliation in accordance with CEJA. The final order approved the process and formulas associated with the MRP reconciliation mechanisms. The ICC's December 2023 order also denied ComEd's ability to earn a return on its pension asset.
On December 22, 2023, ComEd filed an application for rehearing on several findings in the final order including the use of the 2022 year-end rate base to establish forecast revenue requirements for 2024-2027, ROE, pension asset return, and capital structure. On January 10, 2024, ComEd’s application for rehearing was denied on all issues except for the order’s use of the 2022 year-end rate base. On April 18, 2024, the ICC issued its final order on rehearing, which approved the use of the forecasted year-end 2023 rate base that resulted in increased revenue requirements for 2024-2027. These revenue requirements determined during the rehearing process established base revenue requirements until the ICC approved the Refiled 2024-2027 Grid Plan on December 19, 2024.
On January 10, 2024, ComEd filed an appeal in the Illinois Appellate Court of the issues on which rehearing was denied, including but not limited to the allowed ROE, 50% equity ratio, and denial of a return on ComEd’s pension asset. There is no deadline by when the appellate court must rule. On March 13, 2024, ComEd filed its Refiled 2024-2027 Grid Plan with supporting testimony and schedules with the ICC and subsequently on March 15, 2024, ComEd also filed a petition to adjust its MRP to authorize increased rates consistent with the Refiled 2024-2027 Grid Plan. On December 19, 2024, the ICC approved the Refiled 2024-2027 Grid Plan and adjusted the approved MRP with rates effective on January 1, 2025. The final approved MRP, as adjusted, which reflects the Refiled Grid Plan, resulted in a total cumulative revenue requirement increase of $1.045 billion over the 2024-2027 plan years and remains subject to annual reconciliations in accordance with CEJA. ComEd filed timely requests for rehearing and an appeal of the MRP order, again limited to the issues on which rehearing of the December 2023 order was denied, including the allowed ROE, 50% equity ratio, and denial of a return on ComEd's pension asset.
On January 16, 2026, ComEd filed a multi-year integrated grid plan (2028-2031 Grid Plan), seeking approval for planned investments on the electric distribution system within ComEd's service area in 2028-2031. The ICC must issue an order by December 15, 2026.
Carbon Mitigation Credit
CEJA establishes decarbonization requirements for Illinois as well as programs to support the retention and development of emissions-free sources of electricity. ComEd is required to purchase CMCs from participating nuclear power generating facilities between June 1, 2022 and May 31, 2027. The price to be paid for each CMC
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Note 2 — Regulatory Matters
was established through a competitive bidding process that included consumer-protection measures that capped the maximum acceptable bid amount and a formula that reduces CMC prices by an energy price index, the base residual auction capacity price in the ComEd zone of PJM, and the monetized value of any federal tax credit or other subsidy if applicable. On October 31, 2025, the seller provided notification to ComEd and the IPA that it has reflected on its 2024 federal tax return $804 million of nuclear production tax credits associated with its participating nuclear power generating facilities. These amounts will be collected from the seller through an adjustment to the CMC price to be paid by ComEd and returned to customers in 2026. As of December 31, 2025, Exelon and ComEd's Consolidated Balance Sheets reflect these amounts as a receivable from the seller with an offsetting balance within the Carbon mitigation credit regulatory liability. These adjustments had no net impact on Exelon and ComEd’s Consolidated Statements of Operations and Comprehensive Income. The consumer protection measures contained in CEJA will result in net payments to ComEd ratepayers if the energy index, the capacity price and applicable federal tax credits or subsidy exceed the CMC contract price. Beginning with the June 2022 monthly billing period, ComEd began issuing credits and/or charges to its retail customers under its CMC rider, the Rider Carbon-Free Resource Adjustment (Rider CFRA). A regulatory asset or liability is recorded for the difference between ComEd's costs associated with the procurement of CMCs from participating nuclear power generating facilities and revenues received from customers. The balance of the liability as of December 31, 2025 is $670 million.
On February 2, 2024, ComEd filed a petition with the ICC to initiate the reconciliation proceeding for the costs incurred in connection with the procurement of CMC’s during the delivery year beginning June 1, 2022 and extending through May 31, 2023. While both Staff and the Administrative Law Judge's proposed order supported ComEd’s proposed reconciliation adjustment, on September 4, 2025, the ICC issued its final order rejecting the proposed reconciliation adjustment. Specifically, the order disallowed portions of the administrative costs as well as a portion of ComEd's interest costs on the balance of credit extended to customers under the applicable tariff that were not yet funded by payments from the generator. The CMC costs themselves were not disallowed. The order resulted in an immaterial impact to the financial statements and on October 3, 2025 ComEd filed its Application for Rehearing. On October 16, 2025, the ICC denied ComEd's Application. On October 17, 2025, ComEd filed its appeal with the Illinois Appellate Court for review of the ICC's order and its denial of rehearing.
Energy Efficiency
CEJA extends ComEd’s current cumulative annual energy efficiency MWh savings goals through 2040, adds expanded electrification measures to those goals, increases low-income commitments, and adds a new performance adjustment to the energy efficiency formula rate. ComEd expects its annual spend to increase through 2040 to achieve these energy efficiency MWh savings goals, which is deferred as a separate regulatory asset that is recovered through the energy efficiency formula rate over the weighted average useful life, as approved by the ICC, of the related energy efficiency measures.
Energy Efficiency Formula Rate (Exelon and ComEd). FEJA allows ComEd to defer energy efficiency costs (except for any voltage optimization costs which are recovered through electric distribution rates) as a separate regulatory asset that is recovered through the energy efficiency formula rate over the weighted average useful life, as approved by the ICC, of the related energy efficiency measures. ComEd earns a return on the energy efficiency regulatory asset at a rate equal to a weighted average cost of capital, which is based on a year-end capital structure and a statutorily-based formula based on long-term treasury debt. The ROE that ComEd earns on its energy efficiency regulatory asset is subject to a maximum downward or upward adjustment of 200 basis points if ComEd’s cumulative persisting annual MWh savings falls short of or exceeds specified percentage benchmarks of its annual incremental savings goal. ComEd is required to file an update to its energy efficiency formula rate on or before June 1st each year, with resulting rates effective in January of the following year. The annual update is based on projected rate year energy efficiency costs, PJM capacity revenues, and the projected year-end regulatory asset balance less any related deferred income taxes (initial year revenue requirement). The update also reconciles any differences between the revenue requirement in effect for the prior year and actual costs incurred from the year (annual reconciliation). The approved energy efficiency formula rate also provides for revenue decoupling provisions.
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Note 2 — Regulatory Matters
During 2025, the ICC approved the following total increases in ComEd's requested energy efficiency revenue requirement:
Filing DateRequested Revenue Requirement Increase
Approved Revenue Requirement Increase(a)
Approved ROEApproval DateRate Effective Date
May 23, 2025$19 $19 10.21 %November 19, 2025January 1, 2026
_________
(a)ComEd's 2026 approved revenue requirement reflects an increase of $24 million for the initial year revenue requirement for 2026 and a decrease of $5 million related to the annual reconciliation for 2024. The revenue requirement for 2025 provides for a weighted average debt and equity return on the energy efficiency regulatory asset and rate base of 7.23% inclusive of an allowed ROE of 10.21%, reflecting the monthly average yields for 30-year treasury bonds plus 580 basis points. The revenue requirement for the 2024 reconciliation year provides for a weighted average debt and equity return on the energy efficiency regulatory asset and rate base of 7.50% inclusive of an allowed ROE of 10.75%, which includes an upward performance adjustment that increased the ROE. The performance adjustment can either increase or decrease the ROE based upon the achievement of energy efficiency savings goals. See table below for ComEd's regulatory assets associated with its energy efficiency formula rate.
Maryland Regulatory Matters
Maryland Revenue Decoupling (Exelon, BGE, PHI, Pepco, and DPL). In 1998, the MDPSC approved natural gas monthly rate adjustments for BGE and in 2007, the MDPSC approved electric monthly rate adjustments for BGE and BSAs for Pepco and DPL, all of which are decoupling mechanisms. As a result of the decoupling mechanisms, certain Operating revenues from electric and natural gas distribution at BGE and Operating revenues from electric distribution at Pepco Maryland (see also District of Columbia Revenue Decoupling below for Pepco District of Columbia) and DPL are not intended to be impacted by abnormal weather or usage per customer. For BGE, Pepco, and DPL, the decoupling mechanism eliminates the impacts of abnormal weather or customer usage by recognizing revenues based on an authorized distribution amount per customer by customer class. Operating revenues from electric and natural gas distribution at BGE and Operating revenues from electric distribution at Pepco Maryland and DPL are, however, impacted by changes in the number of customers.
EmPOWER Maryland Cost Recovery (Exelon, BGE, PHI, Pepco and DPL). On December 29, 2023, the MDPSC issued an order authorizing the next three-year program cycle for EmPOWER Maryland and approved various proposals by the program administrators to implement new energy efficiency programs for the 2024-2026 program cycle, as well as continue operating core programs. Historically, BGE, Pepco, and DPL deferred most of their energy efficiency program costs to a regulatory asset and either deferred most of their demand response program costs to a regulatory asset or capitalized them. Beginning in 2024, BGE, Pepco, and DPL began deferring less energy efficiency and demand response program costs and beginning January 1, 2026, program costs are no longer being deferred. Additionally, as part of the order, the MDPSC directed BGE, Pepco, and DPL to extend the amortization of unamortized costs as of December 31, 2023 from 5 to 7 years to mitigate customer bill impacts.
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, and DPL). 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 $49 million, $21 million, and $8 million, respectively, from the MDPSC on August 6, 2025. These amounts were used to reduce residential customer account receivable balances within the third quarter of 2025. Additional disbursements from the state of
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Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)

Note 2 — Regulatory Matters
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.
District of Columbia Regulatory Matters
District of Columbia Revenue Decoupling (Exelon, PHI, and Pepco). In 2009, the DCPSC approved a BSA, which is a decoupling mechanism. As a result of the decoupling mechanism, Operating revenues from electric distribution at Pepco District of Columbia (see also Maryland Revenue Decoupling above for Pepco Maryland) are not intended to be impacted by abnormal weather or usage per customer. The decoupling mechanism initially approved eliminated the impacts of abnormal weather or customer usage by recognizing revenues based on an authorized distribution amount per customer by customer class. Prior to 2025, operating revenues from electric distribution at Pepco District of Columbia were, impacted by changes in the number of customers. Beginning in 2025, based on modifications approved by the DCPSC, Pepco District of Columbia began recognizing revenues on an authorized distribution amount per customer class basis, and operating revenues from electric distribution have no longer been impacted by changes in the number of customers.
New Jersey Regulatory Matters
Conservation Incentive Program (CIP) (Exelon, PHI, and ACE). On September 25, 2020, ACE filed an application with the NJBPU as required to seek approval to implement a portfolio of energy efficiency programs pursuant to New Jersey’s clean energy legislation. The filing included a request to implement a CIP that would eliminate the favorable and unfavorable impacts of weather and customer usage patterns on distribution revenues for most customers. The CIP compares current distribution revenues by customer class to approved target revenues established in ACE’s most recent distribution base rate case. The CIP is calculated annually and recovery is subject to certain conditions, including an earnings test and ceilings on customer rate increases.
On April 27, 2021, the NJBPU approved the settlement filed by ACE and the third parties to the proceeding. The approved settlement addresses all material aspects of ACE’s filing, including ACE’s ability to implement the CIP prospectively effective July 1, 2021. As a result of this decoupling mechanism, operating revenues are no longer intended to be impacted by abnormal weather or usage for most customers. Starting in the third quarter of 2021, ACE began recording alternative revenue program revenues for its best estimate of the distribution revenue impacts resulting from future changes in CIP rates that it believes are probable of approval by the NJBPU in accordance with this mechanism.
Termination of Energy Procurement Provisions of PPAs (Exelon, PHI, and ACE). On December 22, 2021, ACE filed a petition with the NJBPU to terminate the provisions in the PPAs to purchase electricity from two coal-powered generation facilities located in the state of New Jersey. The petition was approved by the NJBPU on March 23, 2022. Upon closing of the transaction on March 31, 2022, ACE recognized a liability of $203 million for the contract termination fee and recognized a corresponding regulatory asset of $203 million. The liability has been paid in full as of December 31, 2024.
For the year ended December 31, 2024, ACE paid $49 million of the liability, which is recorded in Changes in Other assets and liabilities in Exelon's, PHI's, and ACE's Consolidated Statements of Cash Flows.
ACE Infrastructure Investment Program Filings (Exelon, PHI, and ACE). On October 31, 2022, ACE filed with the NJBPU an IIP, called “Powering the Future”, proposing to seek recovery through a new component of ACE’s rider mechanism, totaling $379 million, over the four-year period of July 1, 2023, to June 30, 2027. The new IIP will allow ACE to invest in projects that are designed to enhance the reliability, resiliency, and safety of the service ACE provides to its customers. On June 15, 2023, ACE entered into a settlement agreement with other parties, which allows for a recovery totaling $93 million of reliability related capital investments from July 1, 2023, through June 30, 2027. ACE will have the option of seeking approval from the NJBPU to extend the end date of the IIP beyond June 30, 2027, if ACE determines an extension is necessary. On June 29, 2023, the NJBPU adopted the settlement agreement and issued an order approving the program.
Advanced Metering Infrastructure Filing (Exelon, PHI, and ACE). On August 26, 2020, ACE filed an application with the NJBPU as required to seek approval to deploy a smart energy network in alignment with New Jersey’s Energy Master Plan and Clean Energy Act. The proposal consisted of estimated costs totaling $220 million with deployment taking place over a 3-year implementation period from approximately 2021 to 2024 that
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Note 2 — Regulatory Matters
involved the installation of an integrated system of smart meters for all customers accompanied by the requisite communications facilities and data management systems.
On July 14, 2021, the NJBPU approved the settlement filed by ACE and the third parties to the proceeding. The approved settlement addressed all material aspects of ACE's smart energy network deployment plan, including cost recovery of the investment costs, incremental Operating and maintenance expenses, and the unrecovered balance of existing infrastructure through future distribution rates.
New Jersey Clean Energy Legislation (Exelon, PHI, and ACE). On May 23, 2018, New Jersey enacted legislation that established and modified New Jersey’s clean energy and energy efficiency programs and solar and RPS. On the same day, New Jersey enacted legislation that established a ZEC program that provides compensation for nuclear plants that demonstrate to the NJBPU that they meet certain requirements. Under the legislation, the NJBPU will issue ZECs to the qualifying nuclear power plants and the electric distribution utilities in New Jersey, including ACE, will be required to purchase those ZECs. ACE began collecting from retail distribution customers, through a non-bypassable charge, all costs associated with the procurement of the ZECs effective April 18, 2019.
Summer Rate Mitigation (Exelon and ACE). 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 RUBC, which was 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.
Other Federal Regulatory Matters
FERC Audit (Exelon and ComEd). The Utility Registrants are subject to periodic audits and investigations by FERC. FERC’s Division of Audits and Accounting initiated a nonpublic audit of ComEd in April 2021 evaluating ComEd’s compliance with (1) approved terms, rates and conditions of its federally regulated service; (2) accounting requirements of the Uniform System of Accounts; (3) reporting requirements of the FERC Form 1; and (4) the requirements for record retention. The audit period extended back to January 1, 2017.
On July 27, 2023, FERC 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.
Regulatory Assets and Liabilities
Regulatory assets represent incurred costs that have been deferred because of their probable future recovery from customers through regulated rates. Regulatory liabilities represent the excess recovery of costs or accrued credits that have been deferred because it is probable such amounts will be returned to customers through future regulated rates or represent billings in advance of expenditures for approved regulatory programs.
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(Dollars in millions, except per share data unless otherwise noted)

Note 2 — Regulatory Matters
The following tables provide information about the regulatory assets and liabilities of the Registrants at December 31, 2025 and 2024:
December 31, 2025ExelonComEdPECOBGEPHIPepcoDPLACE
Regulatory assets
AMI programs - deployment costs$49 $— $— $8 $41 $6 $8 $27 
AMI programs - legacy meters64 4 — 1 59 19 7 33 
Asset retirement obligations193 129 22 28 14 9 4 1 
COVID-1945 — — 2 43 42 1 — 
Deferred income taxes1,167 — 1,154 — 13 13 — — 
Deferred storm costs182 — 75 81 26 8 1 17 
Distributed generation rebates246 246 — — — — — — 
Electric distribution formula rate annual reconciliations20 20 — — — — — — 
Electric distribution formula rate significant one-time events73 73 — — — — — — 
Electric energy and natural gas costs205 43 — 52 110 67 37 6 
Energy efficiency and demand response programs686 — — 327 359 178 68 113 
Energy efficiency costs2,018 2,018 — — — — — — 
Fair value of long-term debt426 — — — 338 — — — 
Fair value of PHI's unamortized energy contracts21 — — — 21 — — — 
MGP remediation costs310 283 14 13 — — — — 
Multi-year plan reconciliations116 71 — 26 19 19 — — 
Pension and OPEB2,603 — — — — — — — 
Pension and OPEB - merger related371 — — — — — — — 
Removal costs967 — — 340 627 139 140 348 
Renewable energy131 131 — — — — — — 
Transmission formula rate annual reconciliations61 17 14 4 26 18 8 — 
Under-recovered credit loss expense152 152 — — — — — — 
Under-recovered revenue decoupling107 — — 39 68 30 — 38 
Universal service fund charge under-recovery - Electric32 — 32 — — — — — 
Work stoppage costs37 — — — 37 — — 37 
Zero emission credit41 41 — — — — — — 
Other250 54 36 58 107 39 12 32 
Total regulatory assets10,573 3,282 1,347 979 1,908 587 286 652 
        Less: current portion1,359 595 72 175 352 182 72 93 
Total noncurrent regulatory assets$9,214 $2,687 $1,275 $804 $1,556 $405 $214 $559 

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

Note 2 — Regulatory Matters
December 31, 2025ExelonComEdPECOBGEPHIPepcoDPLACE
Regulatory liabilities
Carbon mitigation credit$670 $670 $— $— $— $— $— $— 
Decommissioning the Regulatory Agreement Units4,755 4,313 442 — — — — — 
Dedicated facilities charge155 — — 155 — — — — 
Deferred income taxes2,447 1,419 — 427 601 241 232 128 
Electric energy and natural gas costs155 — 113 25 17 — — 17 
Energy efficiency and demand response programs16 — 16 — — — — — 
Fiber Refund— — — — — — — — 
Multi-year plan reconciliations13 — — — 13 6 7 — 
Over-recovered credit loss expense5 — — — 5 — — 5 
Over-recovered revenue decoupling8 — — 1 7 — 7 — 
Removal costs2,070 1,960 — — 110 20 88 2 
Renewable portfolio standards costs1,611 1,611 — — — — — — 
Transmission formula rate annual reconciliations31 — — 4 27 — 7 20 
Other208 36 18 14 45 14 17 13 
Total regulatory liabilities12,144 10,009 589 626 825 281 358 185 
        Less: current portion1,128 846 140 31 103 13 42 48 
Total noncurrent regulatory liabilities$11,016 $9,163 $449 $595 $722 $268 $316 $137 
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(Dollars in millions, except per share data unless otherwise noted)

Note 2 — Regulatory Matters
December 31, 2024ExelonComEdPECOBGEPHIPepcoDPLACE
Regulatory assets
AMI programs - deployment costs$82 $— $— $29 $53 $11 $13 $29 
AMI programs - legacy meters90 13 — 4 73 30 10 33 
Asset retirement obligations173 112 23 26 12 8 3 1 
Carbon mitigation credit179 179 — — — — — — 
COVID-1959 3 — 4 52 49 3 — 
Deferred income taxes937 — 925 — 12 12 — — 
Deferred storm costs125 — 23 73 29 8 1 20 
Distributed generation rebate171 171 — — — — — — 
Electric distribution formula rate annual reconciliations554 554 — — — — — — 
Electric distribution formula rate significant one-time events98 98 — — — — — — 
Electric energy and natural gas costs108 — — 38 70 18 20 32 
Energy efficiency and demand response programs652 — 10 329 313 174 72 67 
Energy efficiency costs1,890 1,890 — — — — — — 
Fair value of long-term debt457 — — — 362 — — — 
Fair value of PHI's unamortized energy contracts26 — — — 26 — — — 
MGP remediation costs307 275 18 14 — — — — 
Multi-year plan reconciliations170 81 — 66 23 23 — — 
Pension and OPEB2,382 — — — — — — — 
Pension and OPEB - merger related503 — — — — — — — 
Removal costs869 — — 261 608 127 127 356 
Renewable energy131 131 — — — — — — 
Transmission formula rate annual reconciliations114 20 15 30 49 37 12 — 
Under-recovered credit loss expense 147 126 — — 21 — — 21 
Under-recovered revenue decoupling188 — — 98 90 60 — 30 
Universal service fund charge under-recovery - Electric19 — 19 — — — — — 
Zero emission credit4 4 — — — — — — 
Other215 64 35 23 100 46 14 14 
Total regulatory assets10,650 3,721 1,068 995 1,893 603 275 603 
        Less: current portion1,940 1,159 65 207 323 157 60 101 
Total noncurrent regulatory assets$8,710 $2,562 $1,003 $788 $1,570 $446 $215 $502 
175
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)

Note 2 — Regulatory Matters
December 31, 2024ExelonComEdPECOBGEPHIPepcoDPLACE
Regulatory liabilities
Decommissioning the Regulatory Agreement Units$4,027 $3,780 $247 $— $— $— $— $— 
Dedicated facilities charge143 — — 143 — — — — 
Deferred income taxes2,756 1,607 — 484 665 285 247 133 
Electric energy and natural gas costs108 12 81 — 15 8 7 — 
Energy efficiency and demand response programs1 — 1 — — — — — 
Fiber Refund16 — 16 — — — — — 
Multi-year plan reconciliations9 — — — 9 — 9 — 
Over-recovered revenue decoupling2 — — — 2 — 2 — 
Removal costs1,958 1,841 — 11 106 20 86 — 
Renewable portfolio standards costs1,369 1,369 — — — — — — 
Transmission formula rate annual reconciliations14 — — — 14 — — 14 
Other206 9 30 10 52 14 16 9 
Total regulatory liabilities10,609 8,618 375 648 863 327 367 156 
        Less: current portion411 197 122 12 69 17 42 10 
Total noncurrent regulatory liabilities$10,198 $8,421 $253 $636 $794 $310 $325 $146 
Descriptions of the regulatory assets and liabilities included in the tables above are summarized below, including their recovery and amortization periods.
Line ItemDescriptionEnd Date of Remaining Recovery/Refund PeriodReturn
AMI programs - deployment costs
Represents installation and ongoing incremental costs of new smart meters, including implementation costs at Pepco and DPL of dynamic pricing for energy usage resulting from smart meters.
BGE - 2026
Pepco - 2029
DPL - 2030
ACE - 2045
BGE, Pepco, DPL - Yes

ACE - Yes, on incremental costs of new smart meters
AMI programs - legacy metersRepresents early retirement costs of legacy meters.
ComEd - 2028
BGE - 2026
Pepco - 2029
DPL - 2030
ACE - 2045
ComEd, Pepco (District of Columbia), DPL (Delaware), ACE - Yes
BGE, Pepco (Maryland), DPL (Maryland) - No
Asset retirement obligationsRepresents future legally required removal costs associated with existing AROs.Over the life of the related assets.Yes, once the removal activities have been performed
Carbon mitigation creditRepresents CMC procurement costs and credits as well as reasonable costs ComEd has incurred to implement and comply with the CMC procurement process.2026No
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(Dollars in millions, except per share data unless otherwise noted)

Note 2 — Regulatory Matters
Line ItemDescriptionEnd Date of Remaining Recovery/Refund PeriodReturn
COVID-19Represents incremental credit losses and direct costs related to COVID-19 incurred primarily in 2020 at the Utility Registrants, partially offset by a decrease in travel costs at BGE, Pepco and DPL. Direct costs consisted primarily of costs to acquire personal protective equipment, costs for cleaning supplies and services, and costs to hire healthcare professionals to monitor the health of employees. This also includes under-recovered amounts due to COVID-19 that were previously deferred under Pepco’s revenue decoupling program.
ComEd - 2025

BGE - 2028

PECO - 2025

Pepco (District of Columbia) - $37 million - 2034

Pepco (Maryland) - $5 million - 2029

DPL (Delaware) - $1 million - 2028
ComEd, BGE, and Pepco - Yes

PECO and DPL (Delaware) - No
Decommissioning the Regulatory Agreement Units
Represents estimated excess funds at the end of decommissioning the Regulatory Agreement Units. See below regarding Decommissioning the Regulatory Agreement Units for additional information.
Not currently being refunded.
No
Dedicated facilities chargeRepresents the timing difference between the recovery of certain transmission-related assets and their depreciable life.Depreciable life of the related assets.Yes
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(Dollars in millions, except per share data unless otherwise noted)

Note 2 — Regulatory Matters
Line ItemDescriptionEnd Date of Remaining Recovery/Refund PeriodReturn
Deferred income taxes
Represents deferred income taxes that are recoverable or refundable through customer rates, primarily associated with accelerated depreciation, the equity component of AFUDC, and the effects of income tax rate changes, including those resulting from the TCJA.
Amounts are recoverable over the period in which the related deferred income taxes reverse, which is generally based on the expected life of the underlying assets. For TCJA, generally refunded over the remaining depreciable life of the underlying assets, except in certain jurisdictions where the commissions have approved a shorter refund period for certain assets not subject to IRS normalization rules.No
Deferred storm costsFor Pepco, DPL, ACE, PECO and BGE, amounts represent total incremental storm restoration costs incurred due to major storm events recoverable from customers in the Maryland, New Jersey jurisdictions and Pennsylvania.
Pepco (Maryland) - $8 million to be determined in pending multi-year plan filed with MDPSC.

DPL - 2027

ACE - $2 million - 2026; $15 million - 2028

PECO - $75 million to be determined in the next distribution rate case filed with the PAPUC.

BGE - $34 million - 2028; $47 million to be determined in the next multi-year plan filed with MDPSC.
Pepco, DPL, BGE - Yes

ACE, PECO - No
Distributed generation rebatesRepresents ComEd's costs recovered through the distributed generation rebate adjustment tariff and the reconciliation of the difference of the revenue requirement in effect for the prior year and the revenue requirement based on actual prior year costs. Deferred distributed generation rebate costs are recovered over a 15-year period.2039Yes
178
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(Dollars in millions, except per share data unless otherwise noted)

Note 2 — Regulatory Matters
Line ItemDescriptionEnd Date of Remaining Recovery/Refund PeriodReturn
Electric distribution formula rate annual reconciliations
Represents under/(over)-recoveries related to electric distribution service costs recoverable through ComEd's performance-based formula rate, which was updated annually with rates effective on January 1st.
2026Yes
Electric distribution formula rate significant one-time eventsRepresents deferred distribution service costs related to ComEd's significant one-time events (e.g., storm costs), which are recovered over 5 years from date of the event.2029Yes
Electric energy and natural gas costsRepresents under (over)-recoveries related to energy and gas supply related costs recoverable (refundable) under approved rate riders.
2026
DPL (Delaware), ACE - Yes
ComEd, PECO, BGE, Pepco, DPL (Maryland) - No
Energy efficiency and demand response programsIncludes under (over)-recoveries of costs incurred related to energy efficiency programs and demand response programs and recoverable costs associated with customer direct load control and energy efficiency and conservation programs that are being recovered from customers.

PECO - 2025
BGE - 2030
Pepco, DPL - 2030
ACE - 2032
BGE, Pepco (Maryland), DPL (Maryland) - See above regarding EmPOWER Maryland Cost Recovery for additional information
Pepco (District of Columbia) - No
DPL (Delaware), ACE - Yes
PECO - Yes on capital investment recovered through this mechanism
Energy efficiency costs
Represents ComEd's costs recovered through the energy efficiency formula rate tariff and the reconciliation of the difference of the revenue requirement in effect for the prior year and the revenue requirement based on actual prior year costs. Deferred energy efficiency costs are recovered over the weighted average useful life of the related energy measure.2038Yes
179
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(Dollars in millions, except per share data unless otherwise noted)

Note 2 — Regulatory Matters
Line ItemDescriptionEnd Date of Remaining Recovery/Refund PeriodReturn
Fair value of long-term debt
Represents the difference between the carrying value and fair value of long-term debt of BGE, recorded at Exelon, and PHI of $88 million and $338 million, respectively, as of December 31, 2025, and $95 million and $362 million, respectively, as of December 31, 2024, as of the 2016 PHI and 2012 Constellation merger dates.
Exelon - 2036
PHI - 2045
No
Fair value of PHI’s unamortized energy contracts
Represents the regulatory assets recorded at Exelon and PHI offsetting the fair value adjustment related to Pepco's, DPL's, and ACE's electricity and natural gas energy supply contracts recorded at PHI as of the PHI merger date.2036No
Fiber RefundRepresents revenues collected from Constellation and BSC for their use of PECO's fiber assets before the end of 2021.2025No
MGP remediation costs
Represents environmental remediation costs for MGP sites recorded at ComEd, PECO, and BGE.
ComEd and PECO - Over the expected remediation period. See Note 16 — Commitments and Contingencies for additional information.

BGE - 10 years from when the remediation spend occurs.
ComEd and PECO - No

BGE - Yes
Multi-year plan reconciliationsRepresents under (over)-recoveries related to electric and gas distribution multi-year plans.
ComEd - 2028

BGE - 2027

Pepco (Maryland) - $1 million related to 2023 reconciliation - 2026. $18 million related to 2024 reconciliation - to be determined in a future MDPSC order.

Pepco (District of Columbia) - $6 million related to 2025 reconciliation - to be determined in a future DCPSC order.

DPL (Maryland) - $7 million related to 2024 reconciliation.
ComEd - Yes

BGE - No

Pepco (Maryland) - No

Pepco (District of Columbia) - Yes

DPL (Maryland) - Yes
180
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)

Note 2 — Regulatory Matters
Line ItemDescriptionEnd Date of Remaining Recovery/Refund PeriodReturn
Pension and OPEBPrimarily reflects the Utility Registrants' and PHI's portion of deferred costs, including unamortized actuarial losses (gains) and prior service costs (credits), associated with Exelon's pension and OPEB plans, which are recovered through customer rates once amortized through net periodic benefit cost. Also, includes the Utility Registrants' and PHI's non–service cost components capitalized in Property, plant and equipment, net on their Consolidated Balance Sheets.
The deferred costs are amortized over the plan participants' average remaining service periods subject to applicable pension and OPEB cost recognition policies. See Note 12 — Retirement Benefits for additional information. The capitalized non–service cost components are amortized over the lives of the underlying assets.
No
Pension and OPEB - merger related
The deferred costs established at the date of the 2012 Constellation and 2016 PHI mergers are amortized over the plan participants' average remaining service periods subject to applicable pension and OPEB cost recognition policies. The costs are recovered through customer rates once amortized through net periodic benefit cost. See Note 12 — Retirement Benefits for additional information. The capitalized non–service cost components are amortized over the lives of the underlying assets.
Legacy BGE - 2038
Legacy PHI - 2032
No
Removal costs
For BGE, Pepco, DPL, and ACE, the regulatory asset represents costs incurred to remove property, plant and equipment in excess of amounts received from customers through depreciation rates. For ComEd, BGE, Pepco, and DPL, the regulatory liability represents amounts received from customers through depreciation rates to cover the future non–legally required cost to remove property, plant and equipment, which reduces rate base for ratemaking purposes.
BGE, Pepco, DPL, and ACE - Asset is generally recovered over the life of the underlying assets.

ComEd, BGE, Pepco, DPL, and ACE - Liability is reduced as costs are incurred.
Yes
Renewable energyRepresents the change in fair value of ComEd‘s 20-year floating-to-fixed long-term renewable energy swap contracts. 2032No
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(Dollars in millions, except per share data unless otherwise noted)

Note 2 — Regulatory Matters
Line ItemDescriptionEnd Date of Remaining Recovery/Refund PeriodReturn
Renewable portfolio standards costsRepresents an overcollection of funds from both ComEd customers and alternative retail electricity suppliers to be spent on future renewable energy procurements.
$1,535 million to be determined in pending ICC annual reconciliation for the Renewable Energy Adjustment rider.

$76 million to be determined based on the LTRRPP developed by the IPA.
No
Transmission formula rate annual reconciliations
Represents under (over)-recoveries related to transmission service costs recoverable through the Utility Registrants’ FERC formula rates, which are updated annually with rates effective each June 1st.
2027Yes
Under (over) -recovered revenue decoupling
Represents electric and / or gas distribution costs recoverable from or refundable to customers under decoupling mechanisms.
BGE - 2026
Pepco (Maryland) - $4 million - 2026
Pepco (District of Columbia) - $26 million - 2028
DPL - 2025
ACE - 2026
BGE, Pepco, DPL, ACE - No
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(Dollars in millions, except per share data unless otherwise noted)

Note 2 — Regulatory Matters
Line ItemDescriptionEnd Date of Remaining Recovery/Refund PeriodReturn
Under (over) -recovered credit loss expenseFor ComEd and ACE, amounts represent the difference between annual credit loss expense and revenues collected in rates through ICC and NJBPU-approved riders. The difference between net credit loss expense and revenues collected through the rider each calendar year for ComEd is recovered over a twelve-month period beginning in June of the following calendar year. ACE intends to recover from or refund to customers June through May of each respective year, subject to approval of the NJBPU.ComEd - 2026

ACE - To be determined in the annual Societal Benefits Rider filing with NJBPU.		No
Universal service fund charge under-recovery - ElectricRepresents under-recovery of electric supply and distribution revenue shortfalls net of base rate recovery related to PECO’s Universal Service programs, which are designed to provide affordable bills for electric service to low-income, residential customers based on individual household needs.PECO - To be determined in the annual adjustment and reconciliation as approved by the PAPUC.No
Work stoppage costsRepresents work stoppage costs incurred by ACE.2030No
Zero emission creditRepresents ZEC procurement costs and any reasonable costs ComEd has incurred to implement and comply with the ZEC procurement process.Over 9 months starting with the September billing period and ending with the following May billing period.No
Decommissioning the Regulatory Agreement Units
The regulatory agreements with the ICC and PAPUC dictate obligations related to the shortfall or excess of NDT funds necessary for decommissioning the former ComEd units on a unit-by-unit basis and the former PECO units in total.
For the former PECO units, given the symmetric settlement provisions that allow for continued recovery of decommissioning costs from PECO customers in the event of a shortfall and the obligation for Constellation to ultimately return excess funds to PECO customers (on an aggregate basis for all seven units), decommissioning-related activities result in an adjustment to the Receivable related to Regulatory Agreement Units and an equal adjustment to the regulatory liabilities or regulatory assets at PECO.
For the former ComEd units, given no further recovery from ComEd customers is permitted and Constellation retains an obligation to ultimately return excess funds to ComEd customers (on a unit-by-unit basis), to the extent excess funds are expected for each unit, decommissioning-related activities result in an adjustment to the Receivable related to Regulatory Agreement Units and an equal adjustment to the regulatory liabilities at ComEd. However, given the asymmetric settlement provision that does not allow for continued recovery from ComEd customers in the event of a shortfall, recognition of a regulatory asset at ComEd is not permissible.
183
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)

Note 2 — Regulatory Matters
Capitalized Ratemaking Amounts Not Recognized
The following table presents authorized amounts capitalized for ratemaking purposes related to earnings on shareholders’ investment that are not recognized for financial reporting purposes in the Registrants' Consolidated Balance Sheets. These amounts will be recognized as revenues in the related Consolidated Statements of Operations and Comprehensive Income in the periods they are billable to the Utility Registrants' customers. PECO had no related amounts at December 31, 2025 and December 31, 2024
Exelon
ComEd(a)
BGE(b)
PHI
Pepco(c)
DPL(d)
ACE(e)
December 31, 2025$98 $12 $47 $39 $22 $1 $16 
December 31, 2024$117 $46 $16 $55 $40 $1 $14 
__________
(a)For the year ended December 31, 2025, reflects ComEd's unrecognized equity returns earned for ratemaking purposes on its electric distribution rates and distributed generation regulatory assets. For the year ended December 31, 2024, reflects ComEd's unrecognized equity returns earned for ratemaking purposes on its electric distribution rates and formula rates regulatory assets.
(b)BGE's amount capitalized for ratemaking purposes primarily relates to earnings on shareholders' investment on AMI programs and investments in rate base included in the multi-year plan reconciliations.
(c)Pepco's authorized amounts capitalized for ratemaking purposes relate to earnings on shareholders' investment on AMI programs, Energy efficiency and demand response programs, COVID-19 costs, investments in rate base and revenues included in the multi-year plan reconciliations, and a portion of Pepco District of Columbia's revenue decoupling.
(d)DPL's authorized amounts capitalized for ratemaking purposes relate to earnings on shareholders' investment on AMI programs and Energy efficiency and demand response programs.
(e)ACE's authorized amounts capitalized for ratemaking purposes primarily relate to earnings on shareholders' investment on AMI programs.

3. Revenue from Contracts with Customers (All Registrants)
The Registrants recognize revenue from contracts with customers to depict the transfer of goods or services to customers at an amount that the entities expect to be entitled to in exchange for those goods or services. The primary sources of revenue include regulated electric and gas tariff sales, distribution, and transmission services. The performance obligations, revenue recognition, and payment terms associated with these sources of revenue are further discussed in the table below. There are no significant financing components for these sources of revenue and no variable consideration.
Unless otherwise noted, for each of the significant revenue categories and related performance obligations described below, the Registrants have the right to consideration from the customer in an amount that corresponds directly with the value transferred to the customer for the performance completed to date. Therefore, the Registrants generally recognize revenue in the amount for which they have the right to invoice the customer. As a result, there are generally no significant judgments used in determining or allocating the transaction price.
184
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)

Note 3 — Revenue from Contracts with Customers
Revenue SourceDescriptionPerformance ObligationTiming of Revenue RecognitionPayment Terms
Regulated Electric and Gas Tariff SalesSales of electricity and electricity distribution services (the Utility Registrants) and natural gas and gas distribution services (PECO, BGE, and DPL) to residential, commercial, industrial, and governmental customers through regulated tariff rates approved by state regulatory commissions.Delivery of electricity and/or natural gas.
Over time (each day) as the electricity and/or natural gas is delivered to customers. Tariff sales are generally considered daily contracts as customers can discontinue service at any time. (a)
Within the month following delivery of the electricity or natural gas to the customer.
Regulated Transmission Services The Utility Registrants provide open access to their transmission facilities to PJM, which directs and controls the operation of these transmission facilities and accordingly compensates the Utility Registrants pursuant to filed tariffs at cost-based rates approved by FERC.Various including (i) Network Integration Transmission Services (NITS), (ii) scheduling, system control and dispatch services, and (iii) access to the wholesale grid.
Over time utilizing output methods to measure progress towards completion. (b)
Paid weekly by PJM.
__________
(a)Electric and natural gas utility customers have the choice to purchase electricity or natural gas from competitive electric generation and natural gas suppliers. While the Utility Registrants are required under state legislation to bill their customers for the supply and distribution of electricity and/or natural gas, they recognize revenue related only to the distribution services when customers purchase their electricity or natural gas from competitive suppliers.
(b)Passage of time is used for NITS and access to the wholesale grid and MWhs of energy transported over the wholesale grid is used for scheduling, system control and dispatch services.
The Utility Registrants do not incur any material costs to obtain or fulfill contracts with customers.
Contract Liabilities
The Registrants record contract liabilities when consideration is received or due prior to the satisfaction of the performance obligations. The Registrants record contract liabilities in Other current liabilities and Other noncurrent liabilities in the Registrants' Consolidated Balance Sheets.
In July 2020, Pepco, DPL, and ACE entered into a collaborative arrangement with an unrelated communications‑infrastructure owner involving the sale of an undivided interest in certain transmission tower attachment agreements and the transfer of management rights, as further described in Note 4 — Revenue from Contracts with Customers of the 2024 Form 10‑K. The Companies received additional consideration in 2023 related to an amendment of the payment options under the arrangement. Contract liabilities associated with the original arrangement and the 2023 amendment are being recognized as Electric operating revenues over 35‑year and 31‑year periods, respectively.
185
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)

Note 3 — Revenue from Contracts with Customers
The following table provides a rollforward of the contract liabilities reflected in Exelon's, PHI's, Pepco's, DPL's, and ACE'S Consolidated Balance Sheets. As of December 31, 2025, 2024, and 2023, ComEd's, PECO's, and BGE's contract liabilities were not material.
Exelon(a)
PHI(a)
Pepco(a)
DPL(a)
ACE(a)
Balance at December 31, 2023$133 $133 $107 $13 $13 
Revenues recognized(6)(6)(6)— — 
Balance at December 31, 2024$127 $127 $101 $13 $13 
Revenues recognized(8)(8)(6)(1)(1)
Balance at December 31, 2025$119 $119 $95 $12 $12 
__________
(a)Revenues recognized in the years ended December 31, 2025 and 2024, were included in the contract liabilities at December 31, 2024 and 2023, respectively.
Transaction Price Allocated to Remaining Performance Obligations
The following table shows the amounts of future revenues expected to be recorded in each year for performance obligations that are unsatisfied or partially unsatisfied as of December 31, 2025. This disclosure only includes contracts for which the total consideration is fixed and determinable at contract inception. The average contract term varies by customer type and commodity but ranges from one month to several years.
This disclosure excludes the Utility Registrants' gas and electric tariff sales contracts and transmission revenue contracts as they generally have an original expected duration of one year or less and, therefore, do not contain any future, unsatisfied performance obligations to be included in this disclosure.
YearExelonPHIPepcoDPLACE
2026$5 $5 $5 $— $— 
20276 6 5 1 — 
20286 6 5 — 1 
20297 7 6 1 — 
2030 and thereafter95 95 74 10 11 
Total$119 $119 $95 $12 $12 
Revenue Disaggregation
The Registrants disaggregate revenue recognized from contracts with customers into categories that depict how the nature, amount, timing, and uncertainty of revenue and cash flows are affected by economic factors. See Note 4 — Segment Information for the presentation of the Registrant's revenue disaggregation.
4. Segment Information (All Registrants)
Operating segments for each of the Registrants are determined based on information used by the CODMs in deciding how to evaluate performance and allocate resources at each of the Registrants. The Chief Executive Officer is the CODM for Exelon. For PHI and each of the Utility Registrants, CODM responsibilities are shared by Exelon's Chief Operating Officer and the Utility Registrant's Chief Executive Officer.
Exelon has six reportable segments, which include ComEd, PECO, BGE, and PHI's three reportable segments consisting of Pepco, DPL, and ACE. ComEd, PECO, BGE, Pepco, DPL, and ACE each represent a single reportable segment, and as such, no separate segment information is provided for these Registrants. Exelon, ComEd, PECO, BGE, Pepco, DPL, and ACE's CODMs rely on a variety of business considerations, including net income, in evaluating segment performance, determining reinvestment of profits, and establishing the amounts of dividend distributions.
186
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)

Note 4 — Segment Information
An analysis and reconciliation of the Registrants' reportable segment information to the respective information in the consolidated financial statements for the years ended December 31, 2025, 2024, and 2023 is as follows:
ComEdPECOBGEPHI
Other(a)
Intersegment
Eliminations		Exelon
Operating revenues(b):
2025
Electric revenues$7,267 $3,827 $4,007 $6,894 $— $(36)$21,959 
Natural gas revenues— 857 1,215 231 — (4)2,299 
Shared service and other revenues— — — 10 1,900 (1,910)— 
Total operating revenues$7,267 $4,684 $5,222 $7,135 $1,900 $(1,950)$24,258 
2024
Electric revenues$8,219 $3,325 $3,436 $6,258 $— $(22)$21,216 
Natural gas revenues— 648 990 180 — (6)1,812 
Shared service and other revenues— — — 10 1,865 (1,875)— 
Total operating revenues$8,219 $3,973 $4,426 $6,448 $1,865 $(1,903)$23,028 
2023
Electric revenues$7,844 $3,202 $3,109 $5,812 $— $(51)$19,916 
Natural gas revenues— 692 918 205 — (4)1,811 
Shared service and other revenues— — — 9 1,759 (1,768)— 
Total operating revenues$7,844 $3,894 $4,027 $6,026 $1,759 $(1,823)$21,727 
Less:
Purchased power
2025$1,782 $1,436 $1,890 $2,836 $— $— $7,944 
20243,042 1,265 1,460 2,447 — — 8,214 
20232,816 1,270 1,311 2,250 — 1 7,648 
Purchased fuel
2025$— $297 $331 $95 $— $— $723 
2024— 212 191 66 — — 469 
2023— 274 220 98 — 1 593 
Operating and maintenance
2025$1,306 $946 $815 $1,123 $1,840 $(853)$5,177 
20241,284 875 790 1,046 1,733 (788)4,940 
20231,096 786 520 1,110 1,861 (814)4,559 
Operating and maintenance from affiliates
2025$404 $249 $251 $204 $43 $(1,151)$— 
2024419 245 246 204 41 (1,155)— 
2023354 217 221 179 37 (1,008)— 
Depreciation and amortization
2025$1,560 $454 $632 $935 $59 $— $3,640 
20241,514 428 638 947 67 — 3,594 
20231,403 397 654 990 62 — 3,506 
Taxes other than income taxes
2025$409 $240 $370 $568 $42 $— $1,629 
2024376 218 345 528 37 — 1,504 
2023369 202 319 487 31 — 1,408 
187
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)

Note 4 — Segment Information
ComEdPECOBGEPHI
Other(a)
Intersegment
Eliminations		Exelon
(Gain) loss on sale of assets and businesses
2025$— $— $— $(3)$— $— $(3)
2024(5)(4)— 1 (4)— (12)
2023— — — (9)(1)— (10)
Interest expense, net(c)
2025$517 $249 $247 $408 $681 $— $2,102 
2024487 221 216 373 592 — 1,889 
2023464 192 182 323 545 (2)1,704 
Interest expense to affiliates, net(c)
2025$13 $11 $— $3 $(2)$— $25 
202414 11 — 3 (3)— 25 
202313 9 — — 1 2 25 
Other, net
2025$(132)$(41)$(51)$(72)$(28)$54 $(270)
2024(94)(37)(36)(97)(38)40 (262)
2023(75)(36)(18)(108)(190)19 (408)
Income taxes
2025$261 $29 $159 $239 $(165)$— $523 
2024116 (12)49 189 (135)— 207 
2023314 20 133 116 (207)(2)374 
Net income (loss)
2025$1,147 $814 $578 $799 $(570)$— $2,768 
20241,066 551 527 741 (425)— 2,460 
20231,090 563 485 590 (380)(20)2,328 
Supplemental segment information
Intersegment revenues(d)
2025$21 $12 $8 $10 $1,890 $(1,941)$— 
20248 10 10 10 1,855 (1,893)— 
202316 9 9 9 1,750 (1,793)— 
Capital expenditures
2025$2,899 $1,867 $1,657 $2,056 $50 $— $8,529 
20242,195 1,553 1,420 1,863 66 — 7,097 
20232,576 1,426 1,367 1,988 54 — 7,411 
Total assets
2025$48,285 $19,362 $17,184 $29,715 $6,170 $(4,146)$116,570 
202444,750 17,123 15,542 28,297 6,012 (3,940)107,784 
__________
(a)Other primarily includes Exelon’s corporate operations, shared service entities, and other financing and investment activities.
(b)Includes gross utility tax receipts from customers. The offsetting remittance of utility taxes to the governing bodies is recorded in Taxes other than income taxes in the Registrants’ Consolidated Statements of Operations and Comprehensive Income. See Note 20 — Supplemental Financial Information for additional information on total utility taxes.
(c)Interest expense, net and Interest expense to affiliates, net are primarily inclusive of Interest expense, which is partially offset by an immaterial amount of interest income.
(d)See Note 21 — Related Party Transactions for additional information on intersegment revenues.
188
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)

Note 4 — Segment Information
PHI:
PepcoDPLACE
Other(a)
Intersegment
Eliminations		PHI
Operating revenues(b):
2025
Electric revenues$3,454 $1,740 $1,718 $— $(18)$6,894 
Natural gas revenues— 231 — — — 231 
Shared service and other revenues— — — 424 (414)10 
Total operating revenues$3,454 $1,971 $1,718 $424 $(432)$7,135 
2024
Electric revenues$3,039 $1,607 $1,628 $— $(16)$6,258 
Natural gas revenues— 180 — — — 180 
Shared service and other revenues— — — 438 (428)10 
Total operating revenues$3,039 $1,787 $1,628 $438 $(444)$6,448 
2023
Electric revenues$2,824 $1,483 $1,522 $1 $(18)$5,812 
Natural gas revenues— 205 — — — 205 
Shared service and other revenues— — — 422 (413)9 
Total operating revenues$2,824 $1,688 $1,522 $423 $(431)$6,026 
Less:
Purchased power
2025$1,262 $766 $808 $— $— $2,836 
20241,055 694 698 — — 2,447 
2023974 639 637 — — 2,250 
Purchased fuel
2025$— $95 $— $— $— $95 
2024— 66 — — — 66 
2023— 98 — — — 98 
Operating and maintenance
2025$379 $213 $173 $358 $— $1,123 
2024283 196 206 361 — 1,046 
2023336 193 233 348 — 1,110 
Operating and maintenance from affiliates
2025$246 $178 $155 $57 $(432)$204 
2024251 181 162 54 (444)204 
2023236 171 153 50 (431)179 
Depreciation and amortization
2025$433 $252 $248 $2 $— $935 
2024407 245 278 17 — 947 
189
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)

Note 4 — Segment Information
PepcoDPLACE
Other(a)
Intersegment
Eliminations		PHI
2023441 244 283 22 — 990 
Taxes other than income taxes
2025$455 $88 $9 $16 $— $568 
2024424 79 9 16 — 528 
2023390 75 8 14 — 487 
(Gain) loss on sale of assets and businesses
2025$(1)$— $(2)$— $— $(3)
20241 — — — — 1 
2023(9)— — — — (9)
Interest expense, net(c)
2025$214 $102 $82 $10 $— $408 
2024195 94 74 10 — 373 
2023165 74 72 12 — 323 
Interest expense to affiliates, net(c)
2025$— $— $— $3 $— $3 
2024(3)(1)5 2 — 3 
2023— — — — — — 
Other, net
2025$(41)$(16)$(10)$(5)$— $(72)
2024(54)(25)(14)(4)— (97)
2023(66)(18)(20)(4)— (108)
Income taxes
2025$106 $69 $67 $(3)$— $239 
202490 49 55 (5)— 189 
202351 35 36 (6)— 116 
Net income (loss) from continuing operations
2025$401 $224 $188 $(14)$— $799 
2024390 209 155 (13)— 741 
2023306 177 120 (13)— 590 
Supplemental segment information
Intersegment revenues(d)
2025$6 $9 $4 $423 $(432)$10 
20247 7 2 438 (444)10 
20239 8 2 422 (432)9 
Capital expenditures
2025$957 $534 $390 $175 $— $2,056 
2024929 556 373 5 — 1,863 
2023957 562 460 9 — 1,988 
Total assets
2025$12,728 $6,789 $5,632 $4,602 $(36)$29,715 
202412,000 6,421 5,349 4,567 (40)28,297 
__________
(a)Other primarily includes PHI’s corporate operations, shared service entities, and other financing and investment activities.
(b)Includes gross utility tax receipts from customers. The offsetting remittance of utility taxes to the governing bodies is recorded in Taxes other than income taxes in the Registrants’ Consolidated Statements of Operations and Comprehensive Income. See Note 20 — Supplemental Financial Information for additional information on total utility taxes.
(c)Interest expense, net is primarily inclusive of Interest expense, which is partially offset by an immaterial amount of Interest income.
(d)Includes intersegment revenues with ComEd, PECO, and BGE, which are eliminated at Exelon.
190
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)

Note 4 — Segment Information
Electric and Gas Revenue by Customer Class (Utility Registrants):
The following tables disaggregate the Registrants' revenues recognized from contracts with customers into categories that depict how the nature, amount, timing, and uncertainty of revenue and cash flows are affected by economic factors. For the Utility Registrants, the disaggregation of revenues reflects the two primary utility services of electric sales and natural gas sales (where applicable), with further disaggregation of these tariff sales provided by major customer groups. Exelon's disaggregated revenues are consistent with the Utility Registrants, but exclude any intercompany revenues.
2025
Revenues from contracts with customersComEdPECOBGEPHIPepcoDPLACE
Electric revenues
Residential$4,203 $2,494 $2,503 $3,733 $1,669 $1,049 $1,015 
Small commercial & industrial2,072 627 414 722 205 264 253 
Large commercial & industrial593 339 603 1,514 1,212 122 180 
Public authorities & electric railroads47 34 33 73 39 16 18 
Other(a)
907 312 476 917 372 303 250 
Total electric revenues(b)
$7,822 $3,806 $4,029 $6,959 $3,497 $1,754 $1,716 
Natural gas revenues
Residential$— $593 $823 $139 $— $139 $— 
Small commercial & industrial— 206 140 55 — 55 — 
Large commercial & industrial— — 248 7 — 7 — 
Transportation— 37 — 19 — 19 — 
Other(c)
— 19 51 11 — 11 — 
Total natural gas revenues(d)
$— $855 $1,262 $231 $— $231 $— 
Total revenues from contracts with customers$7,822 $4,661 $5,291 $7,190 $3,497 $1,985 $1,716 
Other revenues
Revenues from alternative revenue programs$(596)$— $(87)$(63)$(49)$(16)$2 
Other electric revenues(e)
41 21 14 8 6 2 — 
Other natural gas revenues(e)
— 2 4 — — — — 
Total other revenues$(555)$23 $(69)$(55)$(43)$(14)$2 
Total revenues for reportable segments$7,267 $4,684 $5,222 $7,135 $3,454 $1,971 $1,718 
191
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)

Note 4 — Segment Information
2024
Revenues from contracts with customersComEdPECOBGEPHIPepcoDPLACE
Electric revenues
Residential$3,809 $2,169 $2,038 $3,256 $1,413 $943 $900 
Small commercial & industrial2,259 547 360 681 184 253 244 
Large commercial & industrial1,145 261 557 1,372 1,053 123 196 
Public authorities & electric railroads60 29 31 74 37 17 20 
Other(a)
1,080 296 414 871 327 270 280 
Total electric revenues(b)
$8,353 $3,302 $3,400 $6,254 $3,014 $1,606 $1,640 
Natural gas revenues
Residential$— $445 $625 $108 $— $108 $— 
Small commercial & industrial— 157 110 43 — 43 — 
Large commercial & industrial— — 204 5 — 5 — 
Transportation— 28 — 17 — 17 — 
Other(c)
— 16 18 7 — 7 — 
Total natural gas revenues(d)
$— $646 $957 $180 $— $180 $— 
Total revenues from contracts with customers$8,353 $3,948 $4,357 $6,434 $3,014 $1,786 $1,640 
Other revenues
Revenues from alternative revenue programs$(151)$6 $52 $1 $15 $(2)$(12)
Other electric revenues(e)
17 17 14 13 10 3 — 
Other natural gas revenues(e)
— 2 3 — — — — 
Total other revenues$(134)$25 $69 $14 $25 $1 $(12)
Total revenues for reportable segments$8,219 $3,973 $4,426 $6,448 $3,039 $1,787 $1,628 
2023
Revenues from contracts with customersComEdPECOBGEPHIPepcoDPLACE
Electric revenues
Residential$3,565 $2,090 $1,765 $2,845 $1,236 $827 $782 
Small commercial & industrial1,857 526 331 651 176 246 229 
Large commercial & industrial824 249 528 1,420 1,087 126 207 
Public authorities & electric railroads51 30 29 67 34 16 17 
Other(a)
965 298 402 760 258 250 260 
Total electric revenues(b)
$7,262 $3,193 $3,055 $5,743 $2,791 $1,465 $1,495 
Natural gas revenues
Residential$— $473 $568 $122 $— $122 $— 
Small commercial & industrial— 172 100 53 — 53 — 
Large commercial & industrial— 1 161 4 — 4 — 
Transportation— 27 — 16 — 16 — 
Other(c)
— 17 37 10 — 10 — 
Total natural gas revenues(d)
$— $690 $866 $205 $— $205 $— 
Total revenues from contracts with customers$7,262 $3,883 $3,921 $5,948 $2,791 $1,670 $1,495 
Other revenues
Revenues from alternative revenue programs$556 $(7)$84 $64 $22 $15 $27 
Other electric revenues(e)
26 16 16 14 11 3 — 
Other natural gas revenues(e)
— 2 6 — — — — 
Total other revenues$582 $11 $106 $78 $33 $18 $27 
Total revenues for reportable segments$7,844 $3,894 $4,027 $6,026 $2,824 $1,688 $1,522 
192
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)

Note 4 — Segment Information
__________
(a)Includes transmission revenue from PJM, wholesale electric revenue and mutual assistance revenue.
(b)Includes operating revenues from affiliates in 2025, 2024, and 2023 respectively of:
•$21 million, $8 million, and $16 million at ComEd
•$9 million, $7 million, and $7 million at PECO
•$6 million, $7 million, and $6 million at BGE
•$10 million, $10 million, and $9 million at PHI
•$6 million, $7 million, and $9 million at Pepco
•$9 million, $7 million, and $8 million at DPL
•$4 million, $2 million, and $2 million at ACE
(c)Includes revenues from off-system natural gas sales.
(d)Includes operating revenues from affiliates in 2025, 2024, and 2023 respectively of:
•$3 million, $3 million, and $2 million at PECO
•$2 million, $3 million, and $3 million at BGE
(e)Includes late payment charge revenues.

5. Accounts Receivable (All Registrants)
Allowance for Credit Losses on Accounts Receivable
The following tables present the rollforward of Allowance for Credit Losses on Customer Accounts Receivable.
Year Ended December 31, 2025
ExelonComEdPECOBGEPHIPepcoDPLACE
Balance at December 31, 2024$406 $109 $133 $56 $108 $59 $17 $32 
Plus: Current period provision for expected credit losses(a)(b)(c)
289 90 91 43 65 41 16 8 
Less: Write-offs(d)(e), net of recoveries(f)(g)
260 84 87 31 58 31 14 13 
Balance at December 31, 2025$435 $115 $137 $68 $115 $69 $19 $27 
Year Ended December 31, 2024
ExelonComEdPECOBGEPHIPepcoDPLACE
Balance at December 31, 2023$317 $69 $95 $46 $107 $52 $19 $36 
Plus: Current period provision for expected credit losses
248 78 72 37 61 39 10 12 
Less: Write-offs, net of recoveries159 38 34 27 60 32 12 16 
Balance at December 31, 2024$406 $109 $133 $56 $108 $59 $17 $32 
__________
(a)For ComEd, the increase is primarily a result of increased aging of receivables.
(b)For PECO, BGE, and DPL, the increase is primarily a result of increased receivable balances.
(c)For ACE, the decrease is primarily a result of decreased aging of receivables.
(d)For ComEd, PECO, and DPL, the increase is primarily a result of increased disconnection activities.
(e)For ACE, the decrease is primarily a result of decreased disconnection activities.
(f)Recoveries were not material to ComEd, BGE, Pepco, DPL, and ACE.
(g)For PECO, the increase in recoveries collected is primarily a result of increased customer repayments.
193
Table of Contents
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)

Note 5 — Accounts Receivable
The following tables present the rollforward of Allowance for Credit Losses on Other Accounts Receivable.
Year Ended December 31, 2025
ExelonComEdPECOBGEPHIPepcoDPLACE
Balance at December 31, 2024$107 $34 $18 $6 $49 $27 $9 $13 
Plus: Current period provision (benefit) for expected credit losses(a)(b)
24 10 14 (2)2 (1)1 2 
Less: Write-offs(c)(d), net of recoveries(e)
37 21 14 — 2 — — 2 
Balance at December 31, 2025$94 $23 $18 $4 $49 $26 $10 $13 
Year Ended December 31, 2024
ExelonComEdPECOBGEPHIPepcoDPLACE
Balance at December 31, 2023$82 $17 $8 $7 $50 $28 $8 $14 
Plus: Current period provision (benefit) for expected credit losses
45 21 15 6 3 (1)1 3 
Less: Write-offs, net of recoveries20 4 5 7 4 — — 4 
Balance at December 31, 2024$107 $34 $18 $6 $49 $27 $9 $13 
__________
(a)For ComEd, the decrease is primarily a result of decreased aging of receivables.
(b)For BGE, the decrease is primarily a result of decreased receivable balances.
(c)For ComEd and PECO, the increase is primarily a result of increased disconnection activities.
(d)For BGE and ACE, the decrease is primarily a result of decreased disconnection activities.
(e)Recoveries were not material to the Registrants.
Unbilled Customer Revenue
The following table provides additional information about unbilled customer revenues recorded in the Registrants' Consolidated Balance Sheets as of December 31, 2025 and 2024.
Unbilled customer revenues(a)
ExelonComEdPECOBGEPHIPepcoDPLACE
December 31, 2025$1,231 $301 $278 $325 $327 $155 $100 $72 
December 31, 20241,114 335 254 257 268 121 76 71 
__________
(a)Unbilled customer revenues are classified in Customer accounts receivable, net in the Registrants' Consolidated Balance Sheets.
Other Purchases of Customer and Other Accounts Receivables
For the twelve months ended December 31, 2025 and 2024, the Utility Registrants were required, under separate legislation and regulations in Illinois, Pennsylvania, Maryland, District of Columbia, Delaware, and New Jersey, to purchase certain receivables from alternative retail electric and, as applicable, natural gas suppliers that participated in the utilities' consolidated billing. The following table presents the total receivables purchased.
Total receivables purchased
ExelonComEdPECOBGEPHIPepcoDPLACE
Year ended December 31, 2025
$4,341 $1,066 $1,257 $700 $1,318 $823 $263 $232 
Year ended December 31, 2024
4,128 964 1,111 778 1,275 799 252 224 

194



Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)

Note 6 — Property, Plant, and Equipment
6. Property, Plant, and Equipment (All Registrants)
The following tables present a summary of property, plant, and equipment by asset category at December 31, 2025 and 2024:
Asset CategoryExelonComEdPECOBGEPHIPepcoDPLACE
December 31, 2025
Electric—transmission and distribution$84,282 $38,370 $13,314 $11,687 $22,614 $14,420 $6,423 $6,247 
Gas—transportation and distribution10,499 — 4,649 5,190 940 — 1,094 — 
Common—electric and gas(a)
2,954 — 1,135 1,430 460 — 251 — 
Construction work in progress5,755 1,997 836 1,236 1,629 1,087 290 238 
Other property, plant, and equipment(b)
908 179 119 76 84 24 38 27 
Total property, plant, and equipment104,398 40,546 20,053 19,619 25,727 15,531 8,096 6,512 
Less: accumulated depreciation20,080 8,291 4,131 5,234 4,350 4,784 2,241 1,956 
Property, plant, and equipment, net$84,318 $32,255 $15,922 $14,385 $21,377 $10,747 $5,855 $4,556 
December 31, 2024
Electric—transmission and distribution$79,283 $36,493 $12,234 $11,131 $21,130 $13,593 $6,086 $5,947 
Gas—transportation and distribution9,599 — 4,247 4,796 821 — 976 — 
Common—electric and gas2,630 — 1,064 1,385 272 — 241 — 
Construction work in progress4,306 1,219 813 779 1,472 1,002 275 187 
Other property, plant and equipment(a)
809 118 76 48 86 24 37 30 
Total property, plant and equipment96,627 37,830 18,434 18,139 23,781 14,619 7,615 6,164 
Less: accumulated depreciation18,445 7,619 4,042 5,005 3,728 4,522 2,075 1,798 
Property, plant, and equipment, net$78,182 $30,211 $14,392 $13,134 $20,053 $10,097 $5,540 $4,366 
__________
(a)On April 15, 2025, PHI purchased an office building and land in the District of Columbia for $177 million which it had been leasing. The lease was terminated on April 15, 2025, in conjunction with the purchase (See Note 9 — Leases for additional information).
(b)Primarily composed of land and non-utility property.

195



Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)

Note 6 — Property, Plant, and Equipment
The following table presents the average service life for each asset category in number of years:
Average Service Life (years)
Asset CategoryExelonComEdPECOBGEPHIPepcoDPLACE
Electric - transmission and distribution5-805-805-705-805-755-755-755-75
Gas - transportation and distribution5-80N/A5-805-805-75N/A5-75N/A
Common - electric and gas4-75N/A5-534-455-75N/A5-75N/A
Other property, plant, and equipment4-6128-505020-5010-4310-3310-4310-43
The following table presents the annual depreciation rates for each asset category.
Annual Depreciation Rates
ExelonComEdPECOBGEPHIPepcoDPLACE
December 31, 2025
Electric—transmission and distribution2.85%3.07%2.33%2.56%2.89%2.51%3.09%3.62%
Gas—transportation and distribution2.08%N/A1.94%2.37%1.29%N/A1.29%N/A
Common—electric and gas6.14%N/A6.37%7.08%2.88%N/A5.53%N/A
December 31, 2024
Electric—transmission and distribution2.83%3.06%2.30%2.55%2.87%2.49%2.99%3.41%
Gas—transportation and distribution2.12%N/A1.96%2.42%1.38%N/A1.38%N/A
Common—electric and gas7.00%N/A6.73%7.81%4.82%N/A6.14%N/A
December 31, 2023
Electric—transmission and distribution2.90%3.02%2.30%2.89%3.03%2.51%3.29%3.66%
Gas—transportation and distribution2.15%N/A1.85%2.56%1.44%N/A1.44%N/A
Common—electric and gas7.77%N/A6.87%8.68%7.18%N/A8.79%N/A
AFUDC
The following table summarizes credits to AFUDC by year:
For the Years Ended December 31,
202520242023
Exelon$275 $251 $256 
ComEd94 75 72 
PECO54 48 46 
BGE58 39 25 
PHI69 89 113 
Pepco49 62 85 
DPL11 19 16 
ACE8 8 12 
See Note 1 — Significant Accounting Policies for additional information regarding property, plant and equipment policies. See Note 14 — Debt and Credit Agreements for additional information regarding Exelon’s, ComEd’s, PECO's, Pepco's, DPL's, and ACE’s property, plant and equipment subject to mortgage liens.
196



Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)

Note 7 — Jointly Owned Electric Utility Plant
7. Jointly Owned Electric Utility Plant (Exelon, PECO, PHI, DPL, and ACE)
PECO's, DPL's, and ACE's material undivided ownership interests in transmission facilities jointly owned with non-affiliated utilities as of December 31, 2025 and 2024 were as follows:
Transmission
NJ/DE(a)
OperatorPSEG/DPL
Ownership interestvarious
Exelon’s share at December 31, 2025:
Plant in service$119 
Accumulated depreciation55 
Construction work in progress16 
Exelon’s share at December 31, 2024:
Plant in service$105 
Accumulated depreciation57 
Construction work in progress4 
__________
(a)PECO, DPL, and ACE own a 42.55%, 1%, and 13.9% share, respectively, in 151.3 miles of 500kV lines located in New Jersey and in the Salem substation. PECO, DPL, and ACE also own a 42.55%, 7.45%, and 7.45% share, respectively, in 2.5 miles of 500kV line located over the Delaware River. ACE also has a 21.78% share in a 500kV New Freedom Switching substation.
Certain facilities are fully owned by Exelon through its 100% ownership in PECO, DPL, and ACE. These facilities are operated by Exelon Registrants. PECO's, DPL's, and ACE's material undivided ownership interests in Exelon owned facilities as of December 31, 2025 and 2024 were as follows:
PECOPHIDPLACE
Ownership interest56 %44 %27 %17 %
Registrant's share at December 31, 2025:
Plant in service$82 $73 $45 $28 
Accumulated depreciation4 6 4 2 
Construction work in progress— — — — 
Registrant's share at December 31, 2024:
Plant in service$84 $72 $44 $28 
Accumulated depreciation2 3 3 — 
Construction work in progress— — — — 
PECO's, DPL's, and ACE's undivided ownership interests presented in the tables above are financed with their funds and all operations are accounted for as if such participating interests were wholly owned facilities. PECO's, DPL's, and ACE's share of direct expenses of the jointly owned plants are included in Operating and maintenance expenses in Exelon's, PECO's, PHI's, DPL's, and ACE's Consolidated Statements of Operations and Comprehensive Income.

197



Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)

Note 8 — Asset Retirement Obligations
8. Asset Retirement Obligations (All Registrants)
The Registrants have AROs primarily associated with the abatement and disposal of equipment and buildings contaminated with asbestos and PCBs. See Note 1 — Significant Accounting Policies for additional information on the Registrants’ accounting policy for AROs. 
The following table provides a rollforward of the AROs reflected in the Registrants’ Consolidated Balance Sheets from December 31, 2023 to December 31, 2025:
ExelonComEdPECOBGEPHIPepcoDPLACE
AROs at December 31, 2023$269 $150 $27 $32 $56 $37 $13 $6 
Revisions in estimates of cash flows26 12 1 3 10 10 — — 
Accretion expense(a)
11 7 1 1 2 2 — — 
Payments(2)(1)(1)— — — — — 
AROs at December 31, 2024$304 $168 $28 $36 $68 $49 $13 $6 
Revisions in estimates of cash flows15 19 — (1)(3)(1)(1)(1)
Accretion expense(a)
13 8 1 1 3 3 — — 
Payments(8)(1)(2)— (5)(5)— — 
AROs at December 31, 2025$324 $194 $27 $36 $63 $46 $12 $5 
__________
(a)For ComEd, PECO, BGE, DPL and ACE, the majority of the accretion is recorded as an increase to a regulatory asset due to the associated regulatory treatment.
9. Leases (All Registrants)
Lessee
The Registrants have operating and finance leases for which they are the lessees. The following tables outline the significant types of leases at each of the Registrants and other terms and conditions of the lease agreements as of December 31, 2025. Exelon, ComEd, PECO, and BGE did not have material finance leases in 2025, 2024, or 2023.
Exelon ComEdPECOBGE PHIPepcoDPLACE
Real estate●●●●●●●●
Vehicles and equipment●●●●●●
(in years)Exelon ComEdPECOBGEPHIPepcoDPLACE
Remaining lease terms1-801-271-91-801-71-71-71-7
Options to extend the term3-30N/AN/A3-53-3053-30N/A
Options to terminate within2-7N/AN/A2N/AN/AN/AN/A
198



Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)

Note 9 — Leases
The components of operating lease costs were as follows:
Exelon ComEdPECOBGEPHIPepcoDPLACE
For the year ended December 31, 2025
Operating lease costs$47 $— $— $7 $31 $12 $9 $6 
Variable lease costs7 — — — 1 — 1 — 
Total lease costs(a)
$54 $— $— $7 $32 $12 $10 $6 
For the year ended December 31, 2024
Operating lease costs$57 $— $— $8 $41 $10 $10 $5 
Variable lease costs9 — — — 3 1 1 1 
Total lease costs(a)
$66 $— $— $8 $44 $11 $11 $6 
For the year ended December 31, 2023
Operating lease costs$58 $1 $— $5 $43 $11 $11 $6 
Variable lease costs9 1 — — 3 1 1 1 
Total lease costs(a)
$67 $2 $— $5 $46 $12 $12 $7 
__________
(a)Excludes sublease income recorded at Exelon, PHI, and DPL of $4 million for the years ended December 31, 2025, 2024, and 2023.
The components of financing lease costs were as follows:
PHIPepcoDPLACE
For the year ended December 31, 2025
Amortization of ROU asset$21 $7 $8 $6 
Interest on lease liabilities6 2 2 2 
Total finance lease cost$27 $9 $10 $8 
For the year ended December 31, 2024
Amortization of ROU asset$18 $7 $7 $4 
Interest on lease liabilities6 2 2 2 
Total finance lease cost$24 $9 $9 $6 
For the year ended December 31, 2023
Amortization of ROU asset$16 $6 $6 $4 
Interest on lease liabilities6 2 2 1 
Total finance lease cost$22 $8 $8 $5 








199



Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)

Note 9 — Leases
The following tables provide additional information regarding the presentation of operating and finance lease ROU assets and lease liabilities within the Registrants’ Consolidated Balance Sheets:
Operating Leases
Exelon ComEdPECOBGE
PHI(a)
PepcoDPLACE
At December 31, 2025
Operating lease ROU assets
Other deferred debits and other assets$139 $— $1 $17 $54 $22 $23 $5 
Operating lease liabilities
Other current liabilities$19 $— $— $3 $10 $4 $5 $1 
Other deferred credits and other liabilities146 — 1 13 55 22 28 5 
Total operating lease liabilities$165 $— $1 $16 $65 $26 $33 $6 
At December 31, 2024
Operating lease ROU assets
Other deferred debits and other assets$224 $— $— $24 $127 $26 $27 $7 
Operating lease liabilities
Other current liabilities$38 $— $— $3 $30 $5 $6 $3 
Other deferred credits and other liabilities217 — — 16 116 25 32 5 
Total operating lease liabilities$255 $— $— $19 $146 $30 $38 $8 
__________
(a)On April 15, 2025, PHI purchased an office building and land in the District of Columbia for $177 million which it had been leasing. PHI's operating lease liability and operating lease ROU asset amounts for the office building and land were $64 million and $47 million, respectively, at the time of the purchase. In conjunction with the purchase, the lease has been terminated and the difference of $17 million between the operating lease liability and operating lease ROU asset were recorded as an adjustment to the carrying value of the purchased assets.

Finance Leases
PHIPepcoDPLACE
At December 31, 2025
Finance lease ROU assets
Plant, property and equipment, net$68 $23 $25 $20 
Finance lease liabilities
Long-term debt due within one year$19 $7 $7 $5 
Long-term debt53 18 20 15 
Total finance lease liabilities$72 $25 $27 $20 
At December 31, 2024
Finance lease ROU assets
Plant, property and equipment, net$72 $26 $26 $20 
Finance lease liabilities
Long-term debt due within one year$17 $6 $7 $4 
Long-term debt58 21 21 16 
Total finance lease liabilities$75 $27 $28 $20 
200



Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)

Note 9 — Leases
Future minimum lease payments for operating and finance leases as of December 31, 2025 were as follows:
Operating Leases
YearExelon ComEdPECOBGEPHIPepcoDPLACE
2026$26 $— $1 $4 $13 $5 $6 $2 
202724 — — 2 12 4 7 2 
202824 — — 3 11 4 6 1 
202924 — — 3 11 4 6 1 
203024 — — 3 11 4 6 1 
Remaining years91 — — 18 21 9 12 — 
Total213 — 1 33 79 30 43 7 
Interest48 — — 17 14 4 10 1 
Total operating lease liabilities$165 $— $1 $16 $65 $26 $33 $6 

Finance Leases
YearPHIPepcoDPLACE
2026$21 $8 $8 $6 
202719 7 7 5 
202815 5 6 4 
202912 4 5 2 
20307 2 2 2 
Remaining years6 1 2 3 
Total80 27 30 22 
Interest8 2 3 2 
Total finance lease liabilities$72 $25 $27 $20 
The weighted average remaining lease terms, in years, for operating and finance leases were as follows:
Operating Leases
Exelon ComEdPECOBGEPHIPepcoDPLACE
At December 31, 20259.3—6.419.26.26.66.33.2
At December 31, 20248.21.75.317.45.37.16.93.1
Finance Leases
PHIPepcoDPLACE
At December 31, 20254.14.03.94.4
At December 31, 20244.44.44.24.5
The weighted average discount rates for operating and finance leases were as follows:
Operating Leases
ExelonComEdPECOBGEPHIPepcoDPLACE
At December 31, 20253.9 %— %4.4 %5.0 %4.2 %4.2 %4.2 %4.2 %
At December 31, 20244.0 %0.8 %2.8 %5.0 %4.2 %4.1 %4.1 %3.9 %
Finance Leases
PHIPepcoDPLACE
At December 31, 20253.8 %3.8 %3.6 %3.9 %
At December 31, 20243.4 %3.5 %3.1 %3.5 %
201



Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)

Note 9 — Leases
Cash paid for amounts included in the measurement of operating and finance lease liabilities were as follows:
Operating Cash Flows from Operating Leases
ExelonComEdPECOBGEPHIPepcoDPLACE
For the year ended December 31, 2025$35 $— $— $4 $22 $6 $7 $3 
For the year ended December 31, 202448 — — 4 35 7 7 3 
For the year ended December 31, 202365 2 — 15 37 7 9 3 
Financing Cash Flows from Finance Leases
PHIPepcoDPLACE
For the year ended December 31, 2025$20 $7 $8 $5 
For the year ended December 31, 202417 6 7 4 
For the year ended December 31, 202315 5 6 4 
ROU assets obtained in exchange for operating and finance lease obligations were as follows:
Operating Leases
ExelonComEdPECOBGEPHIPepcoDPLACE
For the year ended December 31, 2025$3 $— $— $— $3 $1 $2 $— 
For the year ended December 31, 20248 — — 1 5 1 2 2 
For the year ended December 31, 202335 — — 32 3 — 1 2 
Finance Leases
PHIPepcoDPLACE
For the year ended December 31, 2025$15 $4 $6 $5 
For the year ended December 31, 202415 7 4 4 
For the year ended December 31, 202311 5 3 3 
Lessor
The Registrants have operating leases for which they are the lessors. The following tables outline the significant types of leases at each of the Registrants and other terms and conditions of their lease agreements as of December 31, 2025. ACE did not have any operating leases for which they are the lessors for the years ended December 31, 2025, 2024, and 2023.
Exelon ComEdPECOBGEPHIPepcoDPL
Real estate●●●●●●●
(in years)Exelon ComEdPECOBGEPHIPepcoDPL
Remaining lease terms1-771-111-77171-716-7
Options to extend the term1-795-791-50N/AN/AN/AN/A
202



Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)

Note 9 — Leases
The components of lease income were as follows:
Exelon ComEdPECOBGEPHIPepcoDPL
For the year ended December 31, 2025
Operating lease income$5 $— $— $— $4 $— $4 
Variable lease income1 — — — 1 — 1 
For the year ended December 31, 2024
Operating lease income$4 $— $— $— $4 $— $3 
Variable lease income1 — — — 1 — 1 
For the year ended December 31, 2023
Operating lease income$5 $— $— $— $4 $— $3 
Variable lease income1 — — — 1 — 1 
Future minimum lease payments to be recovered under operating leases as of December 31, 2025 were as follows:
YearExelon ComEdPECOBGEPHIPepcoDPL
2026$7 $1 $1 $— $5 $— $4 
20277 — 2 — 5 — 4 
20286 — 1 — 5 — 5 
20296 — 1 — 4 — 5 
20305 — 1 — 4 — 4 
Remaining years17 — 7 1 9 — 9 
Total $48 $1 $13 $1 $32 $— $31 
10. Intangible Assets
Goodwill (Exelon, ComEd, PHI, Pepco, DPL, and ACE)
The following table presents the gross amount, accumulated impairment loss, and carrying amount of Goodwill at Exelon, ComEd, and PHI at December 31, 2025 and 2024. There were no additions or impairments during the years ended December 31, 2025, 2024, and 2023.
Gross AmountAccumulated Impairment LossCarrying Amount
Exelon$8,613 $1,983 $6,630 
ComEd(a)
4,608 1,983 2,625 
PHI(b)
4,005 — 4,005 
__________
(a)Reflects goodwill recorded in 2000 from the PECO/Unicom merger (predecessor parent company of ComEd).
(b)Reflects goodwill recorded in 2016 from the PHI merger.
Goodwill is not amortized, but is subject to an assessment for impairment at least annually, or more frequently if events occur or circumstances change that would more likely than not reduce the fair value of ComEd's and PHI's reporting units below their carrying amounts. A reporting unit is an operating segment or one level below an operating segment (known as a component) and is the level at which goodwill is assessed for impairment. A component of an operating segment is a reporting unit if the component constitutes a business for which discrete financial information is available and its operating results are regularly reviewed by segment management. ComEd has a single operating segment. PHI's operating segments are Pepco, DPL, and ACE. See Note 4 — Segment Information for additional information. There is no level below these operating segments for which operating results are regularly reviewed by segment management. Therefore, the ComEd, Pepco, DPL, and ACE operating segments are also considered reporting units for goodwill impairment assessment purposes. Exelon's and ComEd's $2.6 billion of goodwill has been assigned entirely to the ComEd reporting unit, while Exelon's and
203



Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)

Note 10 — Intangible Assets
PHI's $4.0 billion of goodwill has been assigned to the Pepco, DPL, and ACE reporting units in the amounts of $2.1 billion, $1.4 billion, and $0.5 billion, respectively.
Entities assessing goodwill for impairment have the option of first performing a qualitative assessment to determine whether a quantitative assessment is necessary. As part of the qualitative assessments, Exelon, ComEd, and PHI evaluate, among other things, management's best estimate of projected operating and capital cash flows for their businesses, outcomes of recent regulatory proceedings, changes in certain market conditions, including the discount rate and regulated utility peer EBITDA multiples, and the passing margin from their last quantitative assessments performed. If an entity bypasses the qualitative assessment, a quantitative, fair value-based assessment is performed, which compares the fair value of the reporting unit to its carrying amount, including goodwill. If the carrying amount of the reporting unit exceeds its fair value, the entity recognizes an impairment charge, which is limited to the amount of goodwill allocated to the reporting unit.
Application of the goodwill impairment assessment requires management judgment, including the identification of reporting units and determining the fair value of the reporting unit, which management estimates using a weighted combination of a discounted cash flow analysis and a market multiples analysis. Significant assumptions used in these fair value analyses include discount and growth rates, utility sector market performance and transactions, projected operating and capital cash flows for ComEd's, Pepco's, DPL's, and ACE's businesses, and the fair value of debt.
2025 and 2024 Goodwill Impairment Assessment. ComEd and PHI qualitatively determined that it was more likely than not that the fair values of their reporting units exceeded their carrying values and, therefore, did not perform quantitative assessments as of November 1, 2025 and 2024. The last quantitative assessments performed for PHI was as of November 1, 2018. On December 14, 2023, due to the issuance of the ICC's final order rejecting ComEd’s proposed Grid Plan and establishing retail rates for 2024-2027 as further discussed in Note 2 — Regulatory Matters, Exelon’s stock price decreased approximately 10% triggering an interim quantitative assessment for potential goodwill impairment at ComEd. ComEd performed a quantitative assessment as of December 31, 2023, comparing the estimated fair value of ComEd to its carrying value, and determined there was no indication of goodwill impairment.
While the annual and interim assessments indicated no impairments, certain assumptions used to estimate reporting unit fair values are highly sensitive to changes. Adverse regulatory actions or changes in significant assumptions could potentially result in future impairments of Exelon's, ComEd's, and PHI’s goodwill, which could be material.
Other Intangible Assets and Liabilities (Exelon and PHI)
Exelon’s other intangible assets, included in Other current assets and Other deferred debits and other assets in the Consolidated Balance Sheets, consisted of the following at December 31, 2025 and 2024. Exelon's and PHI's other intangible liabilities, included in current and noncurrent Unamortized energy contract liabilities in their Consolidated Balance Sheets, consisted of the following at December 31, 2025 and 2024. The intangible assets and liabilities shown below are amortized on a straight-line basis, except for unamortized energy contracts which are amortized in relation to the expected realization of the underlying cash flows:
December 31, 2025December 31, 2024
GrossAccumulated AmortizationNetGrossAccumulated AmortizationNet
Exelon
Unamortized Energy Contracts$(1,515)$1,494 $(21)$(1,515)$1,489 $(26)
Software License81 (81)— 81 (78)3 
Exelon Total$(1,434)$1,413 $(21)$(1,434)$1,411 $(23)
PHI
Unamortized Energy Contracts$(1,515)$1,494 $(21)$(1,515)$1,489 $(26)


204



Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)

Note 10 — Intangible Assets
The following table summarizes the amortization expense related to intangible assets and liabilities for each of the years ended December 31, 2025, 2024, and 2023:
For the Years Ended December 31,
Exelon(a)
PHI(a)
2025$(2)$(5)
2024(1)(9)
2023(1)(10)
__________
(a)For PHI unamortized energy contracts, the amortization of the fair value adjustment amounts and the corresponding offsetting regulatory asset amounts are amortized through Purchased power and fuel expense in their Consolidated Statements of Operations and Comprehensive Income resulting in no effect to net income.
11. Income Taxes (All Registrants)
Components of Income Tax Expense or Benefit
Income tax expense (benefit) from continuing operations is comprised of the following components:
For the Year Ended December 31, 2025
 ExelonComEdPECOBGEPHIPepcoDPLACE
Included in operations:
Federal
Current$119 $143 $97 $74 $91 $47 $28 $20 
Deferred169 (16)(45)28 60 18 16 24 
Investment tax credit amortization(1)(1)— — — — — — 
State
Current13 80 — — 16 7 8 — 
Deferred223 55 (23)57 72 34 17 23 
Total$523 $261 $29 $159 $239 $106 $69 $67 
For the Year Ended December 31, 2024
 ExelonComEdPECOBGEPHIPepcoDPLACE
Included in operations:
Federal
Current$42 $76 $51 $45 $97 $50 $29 $16 
Deferred(27)(76)(46)(42)21 3 3 20 
Investment tax credit amortization(2)(1)— — (1)— — — 
State
Current37 60 — — 19 17 4 — 
Deferred157 57 (17)46 53 20 13 19 
Total$207 $116 $(12)$49 $189 $90 $49 $55 
205



Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)

Note 11 — Income Taxes
For the Year Ended December 31, 2023
 ExelonComEdPECOBGEPHIPepcoDPLACE
Included in operations:
Federal
Current$51 $130 $63 $67 $71 $54 $25 $9 
Deferred193 45 (36)16 (8)(28)(6)13 
Investment tax credit amortization(2)(1)— — (1)— — — 
State
Current4 (13)— — 15 12 6 — 
Deferred128 153 (7)50 39 13 10 14 
Total$374 $314 $20 $133 $116 $51 $35 $36 

Rate Reconciliation
The effective income tax rate from continuing operations varies from the U.S. federal statutory rate principally due to the following:
For the Year Ended December 31, 2025(a)(b)
Exelon
ComEd(c)
PECO(d)
BGE
U.S. Federal Statutory Tax Rate$691 21.0 %$296 21.0 %$177 21.0 %$155 21.0 %
Increase (decrease) due to:
State income taxes, net of Federal income tax benefit187 5.7 107 7.6 (18)(2.1)45 6.1 
Tax credits(13)(0.4)(6)(0.4)— — (3)(0.4)
Nontaxable or nondeductible items13 0.4 1 0.1 1 0.1 1 0.2 
Other Adjustments
Plant basis differences(145)(4.4)(13)(1.0)(117)(13.9)(11)(1.5)
Excess deferred tax(208)(6.3)(123)(8.7)(14)(1.7)(28)(3.8)
Amortization of ITC, net deferred taxes(2)(0.1)(1)(0.1)— — — — 
Effective Tax Rate$523 15.9 %$261 18.5 %$29 3.4 %$159 21.6 %
For the Year Ended December 31, 2025(a)(b)
PHIPEPCODPLACE
U.S. Federal Statutory Tax Rate$218 21.0 %$106 21.0 %$62 21.0 %$53 21.0 %
Increase (decrease) due to:
State income taxes, net of Federal income tax benefit70 6.7 32 6.3 20 6.8 18 7.1 
Tax credits(4)(0.4)(2)(0.4)(1)(0.3)(1)(0.4)
Nontaxable or nondeductible items3 0.3 2 0.3 (1)(0.3)1 0.2 
Other Adjustments
Plant basis differences(5)(0.5)(3)(0.6)(1)(0.3)(1)(0.4)
Excess deferred tax(42)(4.0)(29)(5.7)(10)(3.4)(3)(1.2)
Amortization of ITC, net deferred taxes(1)(0.1)— — — — — — 
Effective Tax Rate$239 23.0 %$106 20.9 %$69 23.5 %$67 26.3 %
206



Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)

Note 11 — Income Taxes
For the Year Ended December 31, 2024(a)(b)
Exelon
ComEd(c)
PECO(d)
BGE(e)
U.S. Federal Statutory Tax Rate$560 21.0 %$248 21.0 %$113 21.0 %$121 21.0 %
Increase (decrease) due to:
State income taxes, net of Federal income tax benefit153 5.7 92 7.8 (13)(2.4)36 6.3 
Tax credits(19)(0.6)(13)(1.1)— — (2)(0.3)
Nontaxable or nondeductible items6 0.2 2 0.2 — — 1 0.1 
Other Adjustments
Plant basis differences(120)(4.5)(8)(0.7)(96)(17.8)(8)(1.4)
Excess deferred tax(371)(13.9)(204)(17.3)(16)(3.0)(99)(17.2)
Amortization of ITC, net deferred taxes(2)(0.1)(1)(0.1)— — — — 
Effective Tax Rate$207 7.8 %$116 9.8 %$(12)(2.2)%$49 8.5 %
For the Year Ended December 31, 2024(a)(b)
PHIPEPCODPLACE
U.S. Federal Statutory Tax Rate$195 21.0 %$101 21.0 %$54 21.0 %$44 21.0 %
Increase (decrease) due to:
State income taxes, net of Federal income tax benefit57 6.1 29 6.0 13 5.0 15 7.1 
Tax credits(4)(0.4)(2)(0.4)(1)(0.4)(1)(0.5)
Nontaxable or nondeductible items1 0.1 — — 1 0.4 — — 
Other Adjustments
Plant basis differences(7)(0.8)(5)(1.0)(3)(1.2)1 0.5 
Excess deferred tax(52)(5.6)(33)(6.8)(15)(5.8)(4)(1.9)
Amortization of ITC, net deferred taxes(1)(0.1)— — — — — — 
Effective Tax Rate$189 20.3 %$90 18.8 %$49 19.0 %$55 26.2 %
For the Year Ended December 31, 2023(a)(b)
ExelonComEd
PECO(d)
BGE
U.S. Federal Statutory Tax Rate$567 21.0 %$295 21.0 %$122 21.0 %$130 21.0 %
Increase (decrease) due to:
State income taxes, net of Federal income tax benefit104 3.8 111 7.9 (6)(1.0)40 6.5 
Tax credits(16)(0.6)(8)(0.6)— — (3)(0.5)
Nontaxable or nondeductible items7 0.3 1 0.2 2 0.2 — — 
Other Adjustments
Plant basis differences(106)(3.9)(7)(0.5)(84)(14.4)(6)(1.0)
Excess deferred tax(180)(6.7)(77)(5.5)(14)(2.4)(28)(4.5)
Amortization of ITC, net deferred taxes(2)(0.1)(1)(0.1)— — — — 
Effective Tax Rate$374 13.8 %$314 22.4 %$20 3.4 %$133 21.5 %
207



Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)

Note 11 — Income Taxes
For the Year Ended December 31, 2023(a)(b)
PHIPEPCODPLACE
U.S. Federal Statutory Tax Rate$148 21.0 %$75 21.0 %$45 21.0 %$33 21.0 %
Increase (decrease) due to:
State income taxes, net of Federal income tax benefit43 6.1 20 5.5 13 6.1 11 7.1 
Tax credits(3)(0.6)(3)(0.7)(1)(0.4)(1)(0.6)
Nontaxable or nondeductible items— 0.1 1 0.3 — — 1 0.7 
Other Adjustments
Plant basis differences(10)(1.5)(8)(2.2)(2)(0.8)(1)(0.6)
Excess deferred tax(61)(8.6)(34)(9.6)(20)(9.4)(7)(4.5)
Amortization of ITC, net deferred taxes(1)(0.1)— — — — — — 
Effective Tax Rate$116 16.4 %$51 14.3 %$35 16.5 %$36 23.1 %
__________
(a)Positive percentages represent income tax expense. Negative percentages represent income tax benefit.
(b)Exelon and Registrants had no adjustments related to the following disclosure categories: Foreign Tax Effects, Effects of Changes in Tax law or Rates Enacted in the Current Period, Effects of Cross-Border Tax Laws, Changes in Valuation Allowances, and Changes in Unrecognized Tax Benefits.
(c)For ComEd, the lower effective tax rate is primarily due to CEJA which resulted in the acceleration of certain income tax benefits being provided to customers.
(d)For PECO, the lower effective tax rate is primarily related to state income taxes, net of federal income tax benefit and plant basis differences attributable to tax repair deductions.
(e)For BGE, the lower effective tax rate is primarily due to the Maryland Multi-year plan which resulted in the acceleration of certain tax benefits being provided to customers.

State and local Income Tax (Major Jurisdictions)
The state and local jurisdictions that comprise the majority of the effect of the state and local income tax, net of federal income taxes category by Registrant are presented below:
202520242023
ExelonIL, MDIL, MDMD, IL
ComEdILILIL
PECOPAPAPA
BGEMDMDMD
PHIMD, NJMD, NJMD, NJ
PepcoMDMDMD
DPLDEDEDE
ACENJNJNJ
208



Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)

Note 11 — Income Taxes
Tax Differences and Carryforwards
The tax effects of temporary differences and carryforwards, which give rise to significant portions of the deferred tax assets (liabilities), at December 31, 2025 and 2024 are presented below:
At December 31, 2025
ExelonComEdPECOBGEPHIPepcoDPLACE
Plant basis differences$(13,989)$(5,231)$(2,676)$(2,411)$(3,596)$(1,628)$(1,033)$(936)
Accrual based contracts18 — — — 5 — — — 
Derivatives and other financial instruments26 36 — — 1 — — — 
Deferred pension and postretirement obligation506 (382)(41)(20)(60)(57)(28)— 
Deferred debt refinancing costs101 (4)— (2)91 (2)(1)(1)
Regulatory assets and liabilities(1,756)(490)(324)(39)(122)(36)29 (25)
Tax loss carryforward, net of valuation allowances275 — 72 63 67 — 14 53 
Tax credit carryforward— — — — — — — — 
Corporate Alternative Minimum Tax553 — 289 142 71 44 17 20 
Investment in partnerships(28)— — — — — — — 
Other, net601 250 86 26 166 76 9 23 
Deferred income tax liabilities (net)(13,693)(5,821)(2,594)(2,241)(3,377)(1,603)(993)(866)
Unamortized investment tax credits(15)(7)— (1)(7)(1)(3)(3)
Total deferred income tax liabilities (net) and unamortized investment tax credits$(13,708)$(5,828)$(2,594)$(2,242)$(3,384)$(1,604)$(996)$(869)

209



Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)

Note 11 — Income Taxes
At December 31, 2024
ExelonComEdPECOBGEPHIPepcoDPLACE
Plant basis differences$(13,150)$(5,069)$(2,446)$(2,232)$(3,371)$(1,512)$(975)$(881)
Accrual based contracts19 — — — 6 — — — 
Derivatives and other financial instruments21 36 — — 1 — — — 
Deferred pension and postretirement obligation512 (339)(39)(24)(68)(64)(32)— 
Deferred debt refinancing costs108 (4)— (2)98 (3)(1)(1)
Regulatory assets and liabilities(1,665)(515)(254)(37)(96)(16)33 (18)
Tax loss carryforward, net of valuation allowances283 — 63 78 68 — 16 51 
Tax credit carryforward142 — — — — — — — 
Corporate Alternative Minimum Tax369 47 166 95 2 2 4 8 
Investment in partnerships(27)— — — — — — — 
Other, net612 249 77 24 180 85 10 27 
Deferred income tax liabilities (net)(12,776)(5,595)(2,433)(2,098)(3,180)(1,508)(945)(814)
Unamortized investment tax credits(10)(6)— (1)(3)(1)(1)(2)
Total deferred income tax liabilities (net) and
unamortized investment tax credits		$(12,786)$(5,601)$(2,433)$(2,099)$(3,183)$(1,509)$(946)$(816)
The following table provides federal and state tax attribute carryforwards at December 31, 2025 for Exelon, ComEd, PECO, BGE, PHI, Pepco, DPL, and ACE. The state net operating loss carryforwards and any corresponding valuation allowance are presented on a post-apportioned basis.
ExelonComEdPECOBGEPHIPepcoDPLACE
Federal
Federal general business credits carryforwards$— $— $— $— $— $— $— $— 
Corporate Alternative Minimum Tax credit carryforward(a)
$553 $— $289 $142 $71 $44 $17 $20 
State
State net operating loss carryforwards$6,684 $— $1,944 $972 $1,387 $— $635 $752 
Deferred taxes on state tax attributes (net of federal taxes)$381 $— $76 $63 $96 $— $43 $53 
Valuation allowance on state tax attributes (net of federal taxes)(b)
$106 $— $4 $— $29 $— $29 $— 
Year in which net operating loss or credit carryforwards will begin to expire(c)
2031N/A203120332031N/A20332031
__________
(a)For Exelon, PECO, BGE, PHI, Pepco, DPL, and ACE, the Corporate Alternative Minimum Tax credit carryforward has an indefinite carryforward period.
(b)For Exelon, a full valuation allowance has been recorded against certain separate company state net operating loss carryforwards that are expected to expire before realization. For PECO, a valuation allowance has been recorded against Pennsylvania net operating losses that are expected to expire before realization. For DPL, a full valuation allowance has
210



Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)

Note 11 — Income Taxes
been recorded against Delaware net operating losses carryforwards due to a change in Delaware tax law that limits the ability of corporate taxpayers to monetize net operating losses.
(c)A portion of Exelon's, BGE's, and DPL's Maryland state net operating loss carryforward have an indefinite carryforward period.
Tabular Reconciliation of Unrecognized Tax Benefits
The following table presents changes in unrecognized tax benefits, for Exelon, PHI, DPL, and ACE. Amounts for ComEd, PECO, BGE, and Pepco are not material.
Exelon(a)
PHIDPLACE
Balance at January 1, 2023$148 $59 $4 $17 
Change to positions that only affect timing(57)(9)(2)(2)
Increases based on tax positions related to 20233 1 — — 
Increases based on tax positions prior to 20231 — — — 
Decreases based on tax positions prior to 2023(1)— — — 
Balance at December 31, 2023$94 $51 $2 $15 
Change to positions that only affect timing10 10 — — 
Increases based on tax positions related to 20244 1 10 — 
Increases based on tax positions prior to 20242 — — — 
Decreases based on tax positions prior to 2024(14)(14)— (14)
Balance at December 31, 2024$96 $48 $12 $1 
Change to positions that only affect timing— (1)— — 
Increases based on tax positions related to 20253 1 — — 
Increases based on tax positions prior to 20251 — — — 
Decreases based on tax positions prior to 2025— — — — 
Balance at December 31, 2025$100 $48 $12 $1 
______
(a)At December 31, 2025 and 2024, Exelon recorded a receivable of $31 million and $31 million, respectively, in noncurrent Other assets in the Consolidated Balance Sheet for Constellation’s share of unrecognized tax benefits for periods prior to the separation of Exelon and Constellation in February 2022.
Unrecognized Tax Benefits
The following table presents Exelon's unrecognized tax benefits that, if recognized, would decrease the effective tax rate. The Utility Registrants' amounts are not material.
Exelon
December 31, 2025$83 
December 31, 202469 
December 31, 202371 
At December 31, 2025 Exelon, PHI, and DPL have approximately $65 million, $6 million, and $1 million, respectively, of unrecognized federal tax benefits that could significantly change within the 12 months after the reporting date based on the outcome of pending refund claims that impacts the effective tax rate.
Total Amounts of Interest and Penalties Recognized
The following table represents the net interest and penalties receivable (payable) related to tax positions reflected in Exelon's Consolidated Balance Sheets. The Utility Registrants' amounts are not material.
Net interest and penalties receivable atExelon
December 31, 2025 (a)
$61 
December 31, 2024 (b)
76 
211



Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)

Note 11 — Income Taxes
__________
(a)At December 31, 2025, Exelon classified $7 million and $54 million of the interest receivable as current and noncurrent, respectively, based on the expected timing for settlement in cash. At December 31, 2025, Exelon recorded a receivable of $12 million in noncurrent Other assets in the Consolidated Balance Sheet for Constellation's share of net interest for periods prior to the separation of Exelon and Constellation in February 2022.
(b)At December 31, 2024, Exelon classified $27 million and $49 million of the interest receivable as current and noncurrent, respectively, based on the expected timing for settlement in cash. At December 31, 2024, Exelon recorded a receivable of $9 million in noncurrent Other assets in the Consolidated Balance Sheet for Constellation's share of net interest for periods prior to the separation of Exelon and Constellation in February 2022.
The Registrants did not record material interest or penalties related to tax positions reflected in their Consolidated Balance Sheets. Interest and penalties are recorded in Interest expense, net and Other, net, respectively, in Other income and deductions in the Registrants' Consolidated Statements of Operations and Comprehensive Income.
Description of Tax Years Open to Assessment by Major Jurisdiction
Major JurisdictionOpen YearsRegistrants Impacted
Federal consolidated income tax returns(a)
2010-2024
All Registrants
Delaware separate corporate income tax returns
2010-2024
DPL
District of Columbia combined corporate income tax returns
2022-2024
Exelon, PHI, Pepco
Illinois unitary corporate income tax returns
2012-2024
Exelon, ComEd
Maryland separate company corporate net income tax returns
2010-2024
BGE, Pepco, DPL
New Jersey combined corporate income tax returns
2021-2024
Exelon
New Jersey separate corporate income tax returns
2021-2024
ACE
Pennsylvania separate corporate income tax returns
2021-2024
Exelon
Pennsylvania separate corporate income tax returns
2021-2024
PECO
__________
(a)Certain registrants are only open to assessment for tax years since joining the Exelon federal consolidated group; BGE beginning in 2012 and PHI, Pepco, DPL, and ACE beginning in 2016.

212



Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)

Note 11 — Income Taxes
Tax Payments (Refunds) by Major Jurisdiction
For the Year Ended December 31, 2025
 ExelonComEdPECOBGEPHIPepcoDPLACE
Federal(a)
$— $128 $(186)$(95)$88 $69 $13 $11 
Delaware8 — — — 8 — 7 — 
District of Columbia— — — — 4 6 — — 
Illinois(1)96 — — — — — — 
Maryland14 — — — 14 13 — — 
Pennsylvania(10)— — — — — — — 
Other States1 — — — — — — — 
Total Payments (Refunds)$12 $224 $(186)$(95)$114 $88 $20 $11 
For the Year Ended December 31, 2024
 ExelonComEdPECOBGEPHIPepcoDPLACE
Federal$54 $188 $128 $100 $119 $62 $43 $20 
Delaware13 — — — 13 — 13 — 
District of Columbia— — — — 5 21 — — 
Illinois— 62 — — — — — — 
Maryland13 — — — 13 13 — — 
Pennsylvania— — — — — — — — 
Other States1 — — — — — 1 — 
Total Payments$81 $250 $128 $100 $150 $96 $57 $20 
For the Year Ended December 31, 2023
 ExelonComEdPECOBGEPHIPepcoDPLACE
Federal$18 $40 $(24)$29 $25 $14 $6 $9 
Delaware2 — — — 2 — — — 
District of Columbia— — — — (6)(8)— — 
Illinois— (28)— — — — — — 
Maryland1 — — — — — — — 
Pennsylvania(1)— — — — — — — 
Other States(10)(1)— — — — — — 
Total Payments (Refunds)$10 $11 $(24)$29 $21 $6 $6 $9 
__________
(a)In 2025, Exelon received a one-time federal refund claim that reduced current year federal tax payments to a net zero.

Other Tax Matters
Tax Matters Agreement (Exelon)
In February 2022, in connection with the separation between Exelon and Constellation, the parties entered into a TMA. The TMA governs the respective rights, responsibilities, and obligations between Exelon and Constellation after the separation with respect to tax liabilities, refunds and attributes for open tax years that Constellation was part of Exelon’s consolidated group for U.S. federal, state, and local tax purposes.
Indemnification for Taxes. As a former subsidiary of Exelon, Constellation has joint and several liability with Exelon to the IRS and certain state jurisdictions relating to the taxable periods prior to the separation. The TMA specifies that Constellation is liable for their share of taxes required to be paid by Exelon with respect to taxable periods prior to the separation to the extent Constellation would have been responsible for such taxes under the existing Exelon tax sharing agreement when Constellation was included in Exelon's consolidated group. At December 31, 2025, there is no balance due to or from Constellation.
213



Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)

Note 11 — Income Taxes
Tax Refunds. The TMA specifies that Constellation is entitled to their share of any future tax refunds claimed by Exelon with respect to taxable periods prior to the separation to the extent that Constellation would have received such tax refunds under the existing Exelon tax sharing agreement when Constellation was included in Exelon's consolidated group. At December 31, 2025, there is no balance due to or from Constellation.
Tax Attributes. At the date of separation certain tax attributes, primarily tax credit carryforwards, that were generated by Constellation prior to the separation, were required by law to be allocated to Exelon. The TMA also provides that Exelon will reimburse Constellation when those allocated tax attribute carryforwards are utilized. In 2025, Exelon remitted $143 million of payments to Constellation for the utilization of pre-separation tax credit carryforwards. At December 31, 2025, Exelon recorded a payable of $175 million and $21 million in Other current liabilities and Other deferred credits and other liabilities, respectively, in the Consolidated Balance Sheet for tax attribute carryforwards that are expected to be utilized and reimbursed to Constellation.
Corporate Alternative Minimum Tax (All Registrants)
On August 16, 2022, the IRA was signed into law and implemented a new corporate alternative minimum tax (CAMT) that imposes a 15.0% tax on modified GAAP net income. Corporations will now pay the greater of 15.0% of financial statement pre-tax income (with certain adjustments) or their regular federal tax liability, which is federal taxable income x 21.0% federal corporate tax rate. Corporations are entitled to a tax credit (minimum tax credit) to the extent the CAMT liability exceeds the regular tax liability. This amount can be carried forward indefinitely and used in future years when regular tax exceeds the CAMT.
Beginning in 2023, based on the existing statue, Exelon and each of the Utility Registrants will be subject to and will report the CAMT on a separate Registrant basis in the Consolidated Statements of Operations and Comprehensive Income and the Consolidated Balance Sheets. The deferred tax asset related to the minimum tax credit carryforward will be realized to the extent Exelon’s consolidated deferred tax liabilities exceed the minimum tax credit carryforward. Exelon’s deferred tax liabilities are expected to exceed the minimum tax credit carryforward for the foreseeable future and thus no valuation allowance is required.
On September 12, 2024, the U.S. Treasury issued proposed regulations providing further guidance addressing the implementation of CAMT. The proposed regulations are consistent with Exelon’s prior interpretation and therefore there are no financial statement impacts. Exelon will continue to monitor and assess the potential financial statement impacts of final regulations or other guidance when issued.
On September 30, 2025, the U.S. Treasury issued interim guidance addressing the implementation of CAMT in the form of a notice. The guidance allows entities with regulated operations a repairs adjustment for CAMT purposes, however the provision was drafted in a manner that does not achieve that intended result. Thus, the guidance does not benefit Exelon and has no financial statement impact. Exelon will continue to monitor and assess the potential financial statement impacts of future regulations or other guidance when issued.
Allocation of Income Taxes to Regulated Utilities (All Registrants)
In Q2 2024, the IRS issued a series of PLRs, to another taxpayer, providing guidance with respect to the application of the tax normalization rules to the allocation of consolidated tax benefits among the members of a consolidated group associated with NOLC for ratemaking purposes. The rulings provide that for ratemaking purposes the tax benefit of NOLC should be reflected on a separate company basis not taking into consideration the utilization of losses by other affiliates. A PLR issued to another taxpayer may not be relied on as precedent.
For the Registrants, except for PECO, the methodology prescribed by the IRS in these PLRs could result in a material reduction of the regulatory liability established for EDITs arising from the TCJA corporate tax rate change that are being amortized and flowed through to customers as well as a reduction in the accumulated deferred income taxes included in rate base for ratemaking purposes. The 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.
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
214



Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)

Note 11 — Income Taxes
of certain 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.
Long-Term Marginal State Income Tax Rate (All Registrants)
Quarterly, Exelon reviews and updates its marginal state income tax rates for material changes in state tax laws and state apportionment. The Registrants remeasure their existing deferred income tax balances to reflect the changes in marginal rates, which results in either an increase or a decrease to their net deferred income tax liability balances. Utility Registrants record corresponding regulatory liabilities or assets to the extent such amounts are probable of settlement or recovery through customer rates and an adjustment to income tax expense for all other amounts. In the third quarter of 2023, Exelon updated its marginal state income tax rates for changes in state apportionment. The changes in marginal rates in the third quarter resulted in a decrease of $54 million to the deferred tax liability at Exelon, and a corresponding adjustment to income tax expense, net of federal taxes. There were no impacts to ComEd, BGE, PHI, Pepco, DPL, and ACE for the year ended December 31, 2023. There were no impacts to Exelon, ComEd, BGE, PHI, Pepco, DPL, and ACE for the years ended December 31, 2025 and 2024.
December 31, 2025Exelon
Decrease to Deferred Income Tax Liability and Income Tax Expense, Net of Federal Taxes$— 
December 31, 2024
Decrease to Deferred Income Tax Liability and Income Tax Expense, Net of Federal Taxes— 
December 31, 2023
Decrease to Deferred Income Tax Liability and Income Tax Expense, Net of Federal Taxes(54)
Allocation of Tax Benefits (All Registrants)
The Utility Registrants are party to an agreement with Exelon and other subsidiaries of Exelon that provides for the allocation of consolidated tax liabilities and benefits (Tax Sharing Agreement). The Tax Sharing Agreement provides that each party is allocated an amount of tax similar to that which would be owed had the party been separately subject to tax. In addition, any net federal and state benefits attributable to Exelon are reallocated to the other Registrants. That allocation is treated as a contribution from Exelon to the party receiving the benefit.
The following table presents the allocation of tax benefits from Exelon under the Tax Sharing Agreement, for the year ended December 31, 2025, 2024, and 2023.
ComEdPECOBGEPHIPepcoDPLACE
December 31, 2025$20 $14 $12 $23 $12 $7 $4 
December 31, 202430 15 14 16 9 5 2 
December 31, 2023(a)
13 19 — 10 4 — 2 
__________
(a)BGE and DPL did not record an allocation of federal tax benefits from Exelon under the Tax Sharing Agreement as a result of a tax net operating loss.

12. Retirement Benefits (All Registrants)
Exelon sponsors defined benefit pension and OPEB plans. Substantially all non-union employees hired on or after January 1, 2001, participate in cash balance pension plans. Effective January 1, 2009, substantially all newly-hired union-represented employees participate in cash balance pension plans. Effective February 1, 2018, most newly-hired BSC non-represented, non-craft employees are not eligible to participate in defined benefit pension plans; January 1, 2021, most newly hired utility management employees are not eligible; and certain newly-hired union employees, pursuant to their collective bargaining agreements, are not eligible. In lieu of pension participation, affected employees are eligible to receive an automatic company contribution in an Exelon defined contribution savings plan. Effective January 1, 2018, most newly hired non-represented, non-craft employees are not eligible for OPEB benefits. Effective January 1, 2021, most non-represented, non-craft employees who are under the age of 40 are not eligible for retiree health care benefits. Certain union represented employees are not eligible for retiree healthcare benefits pursuant to their collective bargaining
215



Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)

Note 12 — Retirement Benefits
agreements. Effective January 1, 2022, management employees retiring on or after that date are no longer eligible for retiree life insurance benefits.
The tables below show the pension and OPEB plans in which current and former employees of each operating company participated as of December 31, 2025:
Operating Company(a)
Name of Plan:ComEdPECOBGEPHIPepcoDPLACE
Qualified Pension Plans:
Exelon Corporation Retirement Program (ECRP)XXXXXXX
Exelon Corporation Pension Plan for Bargaining Unit Employees (PPBU)X
Exelon Pension Plan (EPP)XXXXXXX
Pepco Holdings LLC Retirement Plan (PHI Qualified)XXXXXXX
Non-Qualified Pension Plans:
Exelon Corporation Supplemental Pension Benefit Plan and 2000 Excess Benefit PlanXXX
Exelon Corporation Supplemental Management Retirement PlanXXXX
Constellation Energy Group, Inc. Senior Executive Supplemental PlanXX
Constellation Energy Group, Inc. Supplemental Pension PlanXX
Constellation Energy Group, Inc. Benefits Restoration PlanXXX
Baltimore Gas & Electric Company Executive Benefit PlanX
Baltimore Gas & Electric Company Manager Benefit PlanXX
Pepco Holdings LLC 2011 Supplemental Executive Retirement PlanXXXXX
Conectiv Supplemental Executive Retirement PlanXXX
Pepco Holdings LLC Combined Executive Retirement PlanXX
Operating Company(a)
Name of Plan: ComEdPECOBGEPHIPepcoDPLACE
OPEB Plans:
PECO Energy Company Retiree Medical Plan (East)XXXXXXX
Exelon Corporation Health Care Program (West)XXXXXXX
Pepco Holdings LLC Welfare Plan for Retirees (PHI PRW)XXXXXX
Exelon Corporation Employees’ Life Insurance PlanXXX
Exelon Corporation Health Reimbursement Arrangement PlanXXX
BGE Retiree Medical PlanXXXXXXX
BGE Retiree Dental PlanX
Exelon Retiree Medical Plan of Constellation Energy Nuclear Group, LLCXXX
Exelon Retiree Dental Plan of Constellation Energy Nuclear Group, LLCXXX
__________
(a)Employees generally remain in their legacy benefit plans when transferring between operating companies.

216



Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)

Note 12 — Retirement Benefits
Exelon’s traditional and cash balance pension plans are intended to be tax-qualified defined benefit plans. Exelon has elected that the trusts underlying these plans be treated as qualified trusts under the IRC. If certain conditions are met, Exelon can deduct payments made to the qualified trusts, subject to certain IRC limitations.
Benefit Obligations, Plan Assets, and Funded Status
During the first quarter of 2025, Exelon received an updated valuation of its pension and OPEB to reflect actual census data as of January 1, 2025. This valuation resulted in an increase to the pension obligation of $1 million and an increase to the OPEB obligation and asset of $6 million and $2 million, respectively. Additionally, AOCI decreased by $5 million (after-tax) and regulatory assets increased by $8 million and liabilities decreased by $3 million.
The following tables provide a rollforward of the changes in the benefit obligations and plan assets of Exelon for the most recent two years for all plans combined:
Pension BenefitsOPEB
2025202420252024
Change in benefit obligation:
Net benefit obligation as of the beginning of the year$10,545 $10,988 $1,837 $1,908 
Service cost154 166 25 27 
Interest cost586 565 101 96 
Plan participants’ contributions— — 26 27 
Actuarial loss (gain)⁽ᵃ⁾294 (331)112 (32)
Settlements(5)(22)— — 
Gross benefits paid(837)(821)(189)(189)
Net benefit obligation as of the end of the year$10,737 $10,545 $1,912 $1,837 
 Pension BenefitsOPEB
2025202420252024
Change in plan assets:
Fair value of net plan assets as of the beginning of the year$8,785 $9,402 $1,355 $1,355 
Actual return on plan assets739 100 151 108 
Employer contributions293 126 49 54 
Plan participants’ contributions— — 26 27 
Gross benefits paid(837)(821)(189)(189)
Settlements(5)(22)— — 
Fair value of net plan assets as of the end of the year$8,975 $8,785 $1,392 $1,355 
__________
(a)The pension and OPEB loss in 2025 primarily reflect a decrease in the discount rate. The pension and OPEB gains in 2024 primarily reflect an increase in the discount rate.

217



Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)

Note 12 — Retirement Benefits
Exelon presents its benefit obligations and plan assets net on its Consolidated Balance Sheets within the following line items:
 Pension BenefitsOPEB
2025202420252024
Other noncurrent assets$— $— $44 $10 
Other current liabilities(13)(15)(18)(20)
Pension obligations(1,749)(1,745)— — 
Non-pension postretirement benefit obligations— — (546)(472)
Unfunded status, net (net benefit obligation less plan assets)$(1,762)$(1,760)$(520)$(482)
The following table provides the ABO and fair value of plan assets for all pension plans with an ABO in excess of plan assets. Information for pension and OPEB plans with projected benefit obligations (PBO) and accumulated postretirement benefit obligations (APBO), respectively, in excess of plan assets have been disclosed in the Obligations and Plan Assets table above as all pension and a majority of the OPEB plans are underfunded.
Exelon
20252024
ABO$10,294 $10,076 
Fair value of net plan assets8,975 8,785 
Components of Net Periodic Benefit Costs
The majority of the 2025 pension benefit cost for the Exelon-sponsored plans is calculated using an expected long-term rate of return on plan assets of 7.00% and a discount rate of 5.68%. The majority of the 2025 OPEB cost is calculated using an expected long-term rate of return on plan assets of 6.50% for funded plans and a discount rate of 5.64%.
A portion of the net periodic benefit cost for all plans is capitalized in the Consolidated Balance Sheets. The following table presents the components of Exelon’s net periodic benefit costs, prior to capitalization, for the years ended December 31, 2025, 2024, and 2023.
Pension BenefitsOPEB
202520242023202520242023
Components of net periodic benefit cost:
Service cost$154 $166 $155 $25 $27 $26 
Interest cost586 565 578 101 96 101 
Expected return on assets(713)(736)(755)(84)(84)(83)
Amortization of:
Prior service cost (credit)2 2 2 (8)(8)(10)
Actuarial loss (gain)212 214 166 (3)— (2)
Settlement and other charges3 10 20 — — — 
Net periodic benefit cost$244 $221 $166 $31 $31 $32 


218



Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)

Note 12 — Retirement Benefits
Cost Allocation to Exelon Subsidiaries
PHI and each of the Utility Registrants account for their participation in Exelon’s pension and OPEB plans by applying multi-employer accounting. Exelon allocates costs related to its pension and OPEB plans to its subsidiaries based on both active and retired employee participation in each plan.
The amounts below represent the Registrants' allocated pension and OPEB costs (benefits). For Exelon, the service cost component is included in Operating and maintenance expense and Property, plant, and equipment, net while the non-service cost components are included in Other, net and Regulatory assets. For PHI and each of the Utility Registrants, which apply multi-employer accounting, the service cost and non-service cost components are included in Operating and maintenance expense and Property, plant, and equipment, net in their consolidated financial statements.
For the Years Ended December 31,ExelonComEdPECOBGEPHIPepcoDPLACE
2025$273 $85 $7 $62 $96 $35 $17 $13 
2024252 72 (1)59 93 32 15 12 
2023198 26 (14)56 99 34 18 13 
Components of AOCI and Regulatory Assets
Exelon recognizes the overfunded or underfunded status of defined benefit pension and OPEB plans as an asset or liability on its Consolidated Balance Sheets, with offsetting entries to AOCI and Regulatory assets (liabilities). A portion of current year actuarial (gains) losses and prior service costs (credits) are capitalized in Exelon’s Consolidated Balance Sheets to reflect the expected regulatory recovery of these amounts, which would otherwise be recorded to AOCI. The following tables provide the components of AOCI and Regulatory assets (liabilities) for Exelon for the years ended December 31, 2025, 2024, and 2023 for all plans combined.
 Pension BenefitsOPEB
202520242023202520242023
Changes in plan assets and benefit obligations recognized in AOCI and Regulatory assets (liabilities):
Current year actuarial loss (gain)$268 $305 $523 $45 $(56)$30 
Amortization of actuarial (loss) gain(212)(214)(166)3 — 2 
Current year prior service cost— — 4 — — — 
Amortization of prior service (cost) credit(2)(2)(2)8 8 10 
Settlements(3)(10)(20)— — — 
Total recognized in AOCI and Regulatory assets (liabilities)$51 $79 $339 $56 $(48)$42 
Total recognized in AOCI$32 $56 $99 $8 $(1)$4 
Total recognized in Regulatory assets (liabilities)$19 $23 $240 $48 $(47)$38 
219



Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)

Note 12 — Retirement Benefits
The following table provides the components of gross AOCI and Regulatory assets (liabilities) for Exelon that have not been recognized as components of periodic benefit cost as of December 31, 2025 and 2024 for all plans combined:
 Pension BenefitsOPEB
2025202420252024
Prior service cost (credit)$16 $19 $(28)$(37)
Actuarial loss (gain)4,082 4,029 (109)(157)
Total$4,098 $4,048 $(137)$(194)
Total included in AOCI$1,060 $1,028 $(10)$(18)
Total included in Regulatory assets (liabilities)$3,038 $3,020 $(127)$(176)
Average Remaining Service Period
For pension benefits, Exelon amortizes its unrecognized prior service costs (credits) and certain actuarial (gains) losses, as applicable, based on participants’ average remaining service periods.
For OPEB, Exelon amortizes its unrecognized prior service costs (credits) over participants’ average remaining service period to benefit eligibility age and amortizes certain actuarial (gains) losses over participants’ average remaining service period to expected retirement. The resulting average remaining service periods for pension and OPEB were as follows:
202520242023
Pension plans12.4 12.5 12.6 
OPEB plans:
Benefit Eligibility Age7.7 7.8 8.1 
Expected Retirement8.7 9.0 9.3 
Assumptions
The measurement of the plan obligations and costs of providing benefits under Exelon’s defined benefit and OPEB plans involves various factors, including the development of valuation assumptions and inputs and accounting policy elections. The measurement of benefit obligations and costs is impacted by several assumptions and inputs, as shown below, among other factors. When developing the required assumptions, Exelon considers historical information as well as future expectations.
Expected Rate of Return. In determining the EROA, Exelon considers historical economic indicators (including inflation and GDP growth) that impact asset returns, as well as expectations regarding future long-term capital market performance, weighted by Exelon’s target asset class allocations.
Mortality. The mortality assumption is composed of a base table that represents the current expectation of life expectancy of the population adjusted by an improvement scale that attempts to anticipate future improvements in life expectancy. For the years ended December 31, 2025 and 2024, Exelon’s mortality assumption utilizes the SOA 2019 base table (Pri-2012) and MP-2021 improvement scale adjusted to use Proxy SSA ultimate improvement rates.
For Exelon, the following assumptions were used to determine the benefit obligations for the plans as of December 31, 2025 and 2024. Assumptions used to determine year-end benefit obligations are the assumptions used to estimate the subsequent year’s net periodic benefit costs.
220



Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)

Note 12 — Retirement Benefits
 Pension BenefitsOPEB
2025 2024 2025 2024
Discount rate(a)
5.42 %5.68 %5.34 %5.64 %
Investment crediting rate(b) 
5.92 %

5.69 %N/AN/A
Rate of compensation increase3.75 %3.75 %3.75 %3.75 %
Mortality tablePri-2012 table with MP- 2021 improvement scale (adjusted)Pri-2012 table with MP- 2021 improvement scale (adjusted)Pri-2012 table with MP- 2021 improvement scale (adjusted) Pri-2012 table with MP- 2021 improvement scale (adjusted)
Health care cost trend on covered chargesN/AN/A
Initial trend rate of 6.50% and ultimate trend rate of 5.00%

Initial and ultimate trend rate of 5.00%
__________
(a)The discount rates above represent the blended rates used to determine the majority of Exelon’s pension and OPEB obligations. Certain benefit plans used individual rates, which range from 5.21% - 5.54% and 5.27% - 5.34% for pension and OPEB plans, respectively, as of December 31, 2025 and 5.56% - 5.76% and 5.60% - 5.64% for pension and OPEB plans, respectively, as of December 31, 2024.
(b)The investment crediting rate above represents a weighted average rate.

The following assumptions were used to determine the net periodic benefit cost for Exelon for the years ended December 31, 2025, 2024 and 2023: 
 Pension Benefits OPEB
2025 2024 2023 2025 2024 2023
Discount rate(a)
5.68 %5.19 %5.53 %5.64 %5.17 %5.51 %
Investment crediting rate(b)
5.69 %5.03 %5.07 %N/A
 
N/A
 
N/A
Expected return on plan assets(c) 
7.00 %7.00 %7.00 %6.50 %6.50 %6.50 %
Rate of compensation increase3.75 %

3.75 %

3.75 %
 
3.75 %
 
3.75 %
 
3.75 %
Mortality tablePri-2012 table with MP- 2021 improvement scale (adjusted)Pri-2012 table with MP- 2021 improvement scale (adjusted)Pri-2012 table with MP- 2021 improvement scale (adjusted)Pri-2012 table with MP- 2021 improvement scale (adjusted)Pri-2012 table with MP- 2021 improvement scale (adjusted)Pri-2012 table with MP- 2021 improvement scale (adjusted)
Health care cost trend on covered chargesN/AN/AN/A
Initial and ultimate rate
of 5.00%
Initial and ultimate rate of 5.00%
Initial and ultimate rate of 5.00%
__________
(a)The discount rates above represent the blended rates used to establish the majority of Exelon’s pension and OPEB costs. Certain benefit plans used individual rates, which range from 5.56%-5.76% and 5.60%-5.64% for pension and OPEB plans, respectively, for the year ended December 31, 2025; 5.11%-5.27% and 5.15%-5.17% for pension and OPEB plans; respectively, for the year ended December 31, 2024; and 5.46%-5.60% and 5.49%-5.51% for pension and OPEB plans, respectively, for the year ended December 31, 2023.
(b)The investment crediting rate above represents a weighted average rate.
(c)Not applicable to pension and OPEB plans that do not have plan assets.
Contributions
Exelon allocates contributions related to its ECRP and PPBU pension plans and East and West OPEB plans to its subsidiaries based on accounting cost. For the EPP pension plan, PHI Qualified, and PHI PRW plans, pension
221



Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)

Note 12 — Retirement Benefits
and OPEB contributions are allocated to the subsidiaries based on employee participation (both active and retired). The following table provides contributions to the pension and OPEB plans:
 Pension BenefitsOPEB
 2025202420232025 2024 2023
Exelon$293 $126 $75 $49 $54 $54 
ComEd189 7 24 20 18 17 
PECO11 3 1 2 1 — 
BGE26 17 — 18 20 19 
PHI42 74 8 8 12 16 
Pepco 1 1 1 8 8 11 
DPL 1 1 2 — 2 2 
ACE 4 7 — — 2 3 
Management considers various factors when making pension funding decisions, including actuarially determined minimum contribution requirements under ERISA, contributions required to avoid benefit restrictions and at-risk status as defined by the Pension Protection Act of 2006 (the Act), management of the pension obligation, and regulatory implications. The Act requires the attainment of certain funding levels to avoid benefit restrictions (such as an inability to pay lump sums or to accrue benefits prospectively), and at-risk status (which triggers higher minimum contribution requirements and participant notification). The projected contributions below reflect a funding strategy to make annual contributions with the objective of achieving 100% funded status on an ABO basis over time. This funding strategy helps minimize volatility of future period required pension contributions. Based on this funding strategy and current market conditions, which are subject to change, Exelon’s estimated annual qualified pension contributions will be approximately $325 million in 2026. Unlike the qualified pension plans, Exelon’s non-qualified pension plans are not funded, given they are not subject to statutory minimum contribution requirements.
While OPEB plans are also not subject to statutory minimum contribution requirements, Exelon does fund certain of its plans. For Exelon's funded OPEB plans, contributions generally equal accounting costs, however, Exelon’s management has historically considered several factors in determining the level of contributions to its OPEB plans, including liabilities management, levels of benefit claims paid, and regulatory implications (amounts deemed prudent to meet regulatory expectations and best assure continued rate recovery). The amounts below include benefit payments related to unfunded plans.
The following table provides all Registrants planned contributions to the qualified pension plans, planned benefit payments to non-qualified pension plans, and planned contributions to OPEB plans in 2026:
Qualified Pension PlansNon-Qualified Pension PlansOPEB
Exelon$325 $19 $48 
ComEd217 3 22 
PECO9 1 4 
BGE32 2 14 
PHI48 7 6 
Pepco1 — 6 
DPL1 — — 
ACE14 — — 
222



Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)

Note 12 — Retirement Benefits
Estimated Future Benefit Payments
Estimated future benefit payments to participants in all of the pension plans and postretirement benefit plans as of December 31, 2025 were:
Pension BenefitsOPEB
2026$812 $156 
2027816 155 
2028813 154 
2029817 152 
2030807 151 
2031 through 20353,985 724 
Total estimated future benefits payments through 2035$8,050 $1,492 
Plan Assets
Investment Strategy. On a regular basis, Exelon evaluates its investment strategy to ensure plan assets will be sufficient to pay plan benefits when due. As part of this ongoing evaluation, Exelon may make changes to its targeted asset allocation and investment strategy.
Exelon has developed and implemented a liability hedging investment strategy for its qualified pension plans that has reduced the volatility of its pension assets relative to its pension liabilities. Exelon is likely to continue to gradually increase the liability hedging portfolio as the funded status of its plans improves. The overall objective is to achieve attractive risk-adjusted returns that will balance the liquidity requirements of the plans’ liabilities while striving to minimize the risk of significant losses. Trust assets for Exelon’s OPEB plans are managed in a diversified investment strategy that prioritizes maximizing liquidity and returns while minimizing asset volatility.
Actual asset returns have an impact on the costs reported for the Exelon-sponsored pension and OPEB plans. The actual asset returns across Exelon’s pension and OPEB plans for the year ended December 31, 2025 were 8.95% and 12.59%, respectively, compared to an expected long-term return assumption of 7.00% and 6.50%, respectively. Exelon used an EROA of 7.00% and 6.50% to estimate its 2026 pension and OPEB costs, respectively.
Exelon’s pension and OPEB plan target asset allocations as of December 31, 2025 and 2024 were as follows:
December 31, 2025December 31, 2024
Asset CategoryPension BenefitsOPEBPension BenefitsOPEB
Equity securities24 %42 %28 %44 %
Fixed income securities43 %48 %44 %41 %
Alternative investments(a)
33 %10 %28 %15 %
Total100 %100 %100 %100 %
__________
(a)Alternative investments include private equity, hedge funds, real estate, and private credit.
Concentrations of Credit Risk. Exelon evaluated its pension and OPEB plans’ asset portfolios for the existence of significant concentrations of credit risk as of December 31, 2025. Types of concentrations that were evaluated include, but are not limited to, investment concentrations in a single entity, type of industry, foreign country, and individual fund. As of December 31, 2025, there were no significant concentrations (defined as greater than 10% of plan assets) of risk in Exelon’s pension and OPEB plan assets.

223



Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)

Note 12 — Retirement Benefits
Fair Value Measurements
The following tables present pension and OPEB plan assets measured and recorded at fair value in Exelon's Consolidated Balance Sheets on a recurring basis and their level within the fair value hierarchy as of December 31, 2025 and 2024:
December 31, 2025December 31, 2024
Level 1Level 2Level 3Not Subject to LevelingTotalLevel 1Level 2Level 3Not Subject to LevelingTotal
Pension plan assets(a)
Cash and cash equivalents$225 $— $— $— $225 $205 $— $— $— $205 
Equities(b)
1,113 — — 1,438 2,551 1,127 — 1 1,361 2,489 
Fixed income:
U.S. Treasury and agencies1,306 206 — — 1,512 1,333 199 — — 1,532 
State and municipal debt— 30 — — 30 — 32 — — 32 
Corporate debt— 1,622 12 — 1,634 — 1,551 16 — 1,567 
Other(b)
— 223 — 608 831 — 25 — 618 643 
Fixed income subtotal1,306 2,081 12 608 4,007 1,333 1,807 16 618 3,774 
Private equity— — 17 1,237 1,254 — — — 1,249 1,249 
Hedge funds— — — 341 341 — — — 464 464 
Real estate— — — 719 719 — — — 730 730 
Private credit— — — 539 539 — — — 544 544 
Pension plan assets subtotal $2,644 $2,081 $29 $4,882 $9,636 $2,665 $1,807 $17 $4,966 $9,455 
OPEB plan assets(a)
Cash and cash equivalents$34 $— $— $— $34 $44 $— $— $— $44 
Equities464 1 — 136 601 437 1 — 188 626 
Fixed income:
U.S. Treasury and agencies42 31 — — 73 18 34 — — 52 
State and municipal debt— 98 — — 98 — 2 — — 2 
Corporate debt— 26 — — 26 — 32 — — 32 
Other1 21 — 394 416 166 2 — 262 430 
Fixed income subtotal43 176 — 394 613 184 70 — 262 516 
Hedge funds— — — 36 36 — — — 75 75 
Real estate— — — 92 92 — — — 78 78 
Private credit— — — 13 13 — — — 16 16 
OPEB plan assets subtotal$541 $177 $— $671 $1,389 $665 $71 $— $619 $1,355 
Total pension and OPEB plan assets(c)
$3,185 $2,258 $29 $5,553 $11,025 $3,330 $1,878 $17 $5,585 $10,810 
224



Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)

Note 12 — Retirement Benefits
__________
(a)See Note 15—Fair Value of Financial Assets and Liabilities for a description of levels within the fair value hierarchy.
(b)Includes derivative instruments of $(12) million and $(21) million for the years ended December 31, 2025 and 2024, respectively, which have total notional amounts of $5,284 million and $5,123 million as of December 31, 2025 and 2024, respectively. The notional principal amounts for these instruments provide one measure of the transaction volume outstanding as of the fiscal years ended and do not represent the amount of Exelon's exposure to credit or market loss.
(c)Excludes net liabilities of $658 million and $670 million as of December 31, 2025 and 2024, respectively, which include certain derivative assets that have notional amounts of $60 million and $41 million as of December 31, 2025 and 2024, respectively. These items are required to reconcile to the fair value of net plan assets and consist primarily of receivables or payables related to pending securities sales and purchases, interest and dividends receivable, and repurchase agreement obligations. The repurchase agreements generally have maturities ranging from 0 - 6 months.

The following table presents the reconciliation of Level 3 assets and liabilities for Exelon measured at fair value for pension and OPEB plans for the years ended December 31, 2025 and 2024:
Fixed IncomeEquitiesPrivate EquityTotal
Pension Assets
Balance as of January 1, 2025$16 $1 $— $17 
Actual return on plan assets:
Relating to assets still held as of the reporting date— (1)— (1)
Purchases, sales and settlements:
Settlements(4)— — (4)
Level 3 transfers in— — 17 17 
Balance as of December 31, 2025$12 $— $17 $29 
Fixed IncomeEquitiesPrivate EquityTotal
Pension Assets
Balance as of January 1, 2024$9 $1 $— $10 
Actual return on plan assets:
Relating to assets still held as of the reporting date(1)— — (1)
Purchases, sales and settlements:
Purchases2 — — 2 
Level 3 transfers in6 — — 6 
Balance as of December 31, 2024$16 $1 $— $17 
_
Valuation Techniques Used to Determine Fair Value
The techniques used to fair value the pension and OPEB assets invested in cash equivalents are the same as the valuation techniques used to determine the fair value of financial assets. See Cash Equivalents in Note 15 — Fair Value of Financial Assets and Liabilities for further information. Below outlines the techniques used to fair value the pension and OPEB assets invested in equities, fixed income, derivative instruments, private credit, private equity, real estate, and hedge funds.
Equities. These investments consist of individually held equity securities, equity mutual funds, and equity commingled funds in domestic and foreign markets. With respect to individually held equity securities, the trustees obtain prices from pricing services, whose prices are generally obtained from direct feeds from market exchanges, which Exelon is able to independently corroborate. Equity securities held individually, including real estate investment trusts, rights, and warrants, are primarily traded on exchanges that contain only actively traded securities due to the volume trading requirements imposed by these exchanges. The equity securities that are held directly by the trust funds are valued based on quoted prices in active markets and categorized as Level 1. Certain equity securities have been categorized as Level 2 because they are based on evaluated prices that reflect observable market information, such as actual trade information or similar securities. Certain private
225



Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)

Note 12 — Retirement Benefits
placement equity securities are categorized as Level 3 because they are not publicly traded and are priced using significant unobservable inputs.
Equity commingled funds and mutual funds are maintained by investment companies, and fund investments are held in accordance with a stated set of fund objectives. The values of some of these funds are publicly quoted. For mutual funds which are publicly quoted, the funds are valued based on quoted prices in active markets and have been categorized as Level 1. For equity commingled funds and mutual funds that are not publicly quoted, the fund administrators value the funds using the NAV per fund share, derived from the quoted prices in active markets on the underlying securities and are not classified within the fair value hierarchy. These investments can typically be redeemed monthly or more frequently, with 30 or less days of notice and without further restrictions.
Fixed income. Fixed income investments include a broad range of debt securities such as corporate, government, municipal, and asset and mortgage‑backed securities, as well as fixed income commingled funds and mutual funds. The trustees obtain multiple prices from pricing vendors whenever possible, which enables cross-provider validations in addition to checks for unusual daily movements. A primary price source is identified based on asset type, class, or issue for each security. With respect to individually held fixed income securities, the trustees monitor prices supplied by pricing services and may use a supplemental price source or change the primary price source of a given security if the portfolio managers challenge an assigned price and the trustees determine another price source is considered to be preferable. Exelon has obtained an understanding of how these prices are derived, including the nature and observability of the inputs used in deriving such prices. Additionally, Exelon selectively corroborates the fair values of securities by comparison to other market-based price sources. Investments in U.S. Treasury securities have been categorized as Level 1 because they trade in highly liquid and transparent markets. Certain private placement fixed income securities have been categorized as Level 3 because they are priced using certain significant unobservable inputs and are typically illiquid. The remaining fixed income securities, including certain other fixed income investments, are based on evaluated prices that reflect observable market information, such as actual trade information of similar securities, adjusted for observable differences and are categorized as Level 2.
Other fixed income investments include fixed income commingled funds and mutual funds, which are maintained by investment companies and hold fund investments in accordance with a stated set of fund objectives. The values of some of these funds are publicly quoted. For mutual funds which are publicly quoted, the funds are valued based on quoted prices in active markets and have been categorized as Level 1. For fixed income commingled funds and mutual funds that are not publicly quoted, the fund administrators value the funds using the NAV per fund share, derived from the quoted prices in active markets of the underlying securities and are not classified within the fair value hierarchy. These investments typically can be redeemed monthly or more frequently, with 30 or less days of notice and without further restrictions.
Derivative instruments. These instruments, consisting primarily of futures and swaps to manage risk, are recorded at fair value. Over-the-counter derivatives are valued daily, based on quoted prices in active markets and trade in open markets, and have been categorized as Level 1. Derivative instruments other than over-the-counter derivatives are valued based on external price data of comparable securities and have been categorized as Level 2.
Private credit. Private credit investments primarily consist of investments in private debt strategies. These investments are generally less liquid assets with an underlying term of 3 to 5 years and are intended to be held to maturity. The fair value of these investments is determined by the fund manager or administrator using a combination of valuation models including cost models, market models, and income models and typically cannot be redeemed until maturity of the term loan. Managed private credit fund investments are not classified within the fair value hierarchy because their fair value is determined using NAV or its equivalent as a practical expedient.
Private equity. These investments include those in limited partnerships that invest in operating companies that are not publicly traded on a stock exchange such as leveraged buyouts, growth capital, venture capital, distressed investments, and investments in natural resources. These investments typically cannot be redeemed and are generally liquidated over a period of 8 to 10 years from the initial investment date, which is based on Exelon's understanding of the investment funds. Private equity valuations are reported by the fund manager and are based on the valuation of the underlying investments, which include unobservable inputs such as cost, operating results, discounted future cash flows, and market based comparable data. The fair value of private equity investments is determined using NAV or its equivalent as a practical expedient, and therefore, these investments are not classified within the fair value hierarchy. Includes certain private equity investments
226



Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)

Note 12 — Retirement Benefits
previously measured at fair value using NAV or its equivalent as a practical expedient and transferred to Level 3 primarily due to changes in market liquidity or data.
Real estate. These investments are funds with a direct investment in pools of real estate properties. These funds are reported by the fund manager and are generally based on independent appraisals of the underlying investments from sources with professional qualifications, typically using a combination of market-based comparable data and discounted cash flows. These valuation inputs are unobservable. Certain real estate investments cannot be redeemed and are generally liquidated over a period of 8 to 10 years from the initial investment date, which is based on Exelon's understanding of the investment funds. The remaining liquid real estate investments are generally redeemable from the investment vehicle quarterly, with 30 to 90 days of notice. The fair value of real estate investments is determined using NAV or its equivalent as a practical expedient, and therefore, these investments are not classified within the fair value hierarchy.
Hedge funds. Hedge fund investments include those that employ a broad range of strategies to enhance returns and provide additional diversification. The fair value of hedge funds is determined using NAV or its equivalent as a practical expedient, and therefore, hedge funds are not classified within the fair value hierarchy. Exelon has the ability to redeem these investments at NAV or its equivalent subject to certain restrictions that may include a lock-up period or a gate.
Defined Contribution Savings Plan
The Registrants participate in a 401(k) defined contribution savings plan that is sponsored by Exelon. The plan is qualified under applicable sections of the IRC and allows employees to contribute a portion of their pre-tax and/or after-tax income in accordance with specified guidelines. All Registrants match a percentage of the employee contributions up to certain limits. The following table presents the employer contributions and employer matching contributions to the savings plan for the years ended December 31, 2025, 2024, and 2023:
For the Years Ended December 31,ExelonComEdPECOBGEPHIPepcoDPLACE
2025$121 $48 $16 $16 20 $5 $4 $3 
2024112 46 15 12 19 5 5 3 
2023109 47 15 12 16 4 3 2 

13. Derivative Financial Instruments (All Registrants)
The Registrants use derivative instruments to manage commodity price risk and interest rate risk related to ongoing business operations. The Registrants do not execute derivatives for speculative or proprietary trading purposes.
Authoritative guidance requires that derivative instruments be recognized as either assets or liabilities at fair value, with changes in fair value of the derivative recognized in earnings immediately. Other accounting treatments are available through special election and designation, provided they meet specific, restrictive criteria both at the time of designation and on an ongoing basis. These alternative permissible accounting treatments include NPNS, cash flow hedges, and fair value hedges. At ComEd, derivative economic hedges related to commodities are recorded at fair value and offset by a corresponding regulatory asset or liability. For all NPNS derivative instruments, accounts receivable or accounts payable are recorded when derivatives settle and revenue or expense is recognized in earnings as the underlying physical commodity is sold or consumed. At Exelon, derivative hedges that qualify and are designated as cash flow hedges are recorded at fair value and offsets are recorded to AOCI.
Commodity Price Risk
The Utility Registrants employ established policies and procedures to manage their risks associated with market fluctuations in commodity prices by entering into physical and financial derivative contracts, which are either determined to be non-derivative or classified as economic hedges. The Utility Registrants procure electric and natural gas supply through a competitive procurement process approved by each of the respective state utility commissions. The Utility Registrants’ hedging programs are intended to reduce exposure to energy and natural gas price volatility and have no direct earnings impact as the costs are fully recovered from customers through
227



Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)

Note 13 — Derivative Financial Instruments
regulatory-approved recovery mechanisms. The following table provides a summary of the Utility Registrants’ primary derivative hedging instruments, listed by commodity and accounting treatment.
RegistrantCommodityAccounting TreatmentHedging Instrument
ComEdElectricityNPNSFixed price contracts based on all requirements in the IPA procurement plans.
Electricity
Changes in fair value of economic hedge recorded to an offsetting regulatory asset or liability(a)
20-year floating-to-fixed energy swap contracts beginning June 2012 based on the renewable energy resource procurement requirements in the Illinois Settlement Legislation of approximately 1.3 million MWhs per year.
PECOElectricityNPNSFixed price contracts for default supply requirements through full requirements contracts.
GasNPNS
Fixed price contracts to cover about 10% of planned natural gas purchases in support of projected firm sales.
BGEElectricityNPNSFixed price contracts for all SOS requirements through full requirements contracts.
GasNPNSFixed price purchases associated with forecasted gas supply requirements.
PepcoElectricityNPNSFixed price contracts for all SOS requirements through full requirements contracts.
DPLElectricityNPNSFixed price contracts for all SOS requirements through full requirements contracts.
GasNPNSFixed and index priced contracts through full requirements contracts.
Gas
Changes in fair value of economic hedge recorded to an offsetting regulatory asset or liability(b)
Exchange traded future contracts for up to 50% of estimated monthly purchase requirements each month, including purchases for storage injections.
ACEElectricityNPNSFixed price contracts for all BGS requirements through full requirements contracts.
_________
(a)See Note 2—Regulatory Matters for additional information.
(b)The fair value of the DPL economic hedge is not material as of December 31, 2025 and 2024.
The fair value of derivative economic hedges is presented in Other current assets and current and noncurrent Mark-to-market derivative liabilities in Exelon's and ComEd's Consolidated Balance Sheets.
Interest Rate Risk (Exelon)
Exelon Corporate uses a combination of fixed-rate and variable-rate debt to manage interest rate exposure. Exelon Corporate may utilize interest rate derivatives to lock in rate levels in anticipation of future financings, which are typically designated as cash flow hedges. A hypothetical 50 basis point change in the interest rates associated with Exelon's interest rate swaps as of December 31, 2025 would result in an immaterial impact to Exelon's Consolidated Net Income.
Below is a summary of the interest rate hedge balances at December 31, 2025 and 2024.
Derivatives Designated
as Hedging Instruments
December 31, 2025December 31, 2024
Other current assets$3 $14 
Other deferred debits (noncurrent assets)— 12 
Total derivative assets3 26 
Mark-to-market derivative liabilities (current liabilities)(4)(1)
Total mark-to-market derivative liabilities(4)(1)
Total mark-to-market derivative net (liabilities) assets$(1)$25 
228



Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)

Note 13 — Derivative Financial Instruments
Cash Flow Hedges (Interest Rate Risk)
For derivative instruments that qualify and are designated as cash flow hedges, the changes in fair value each period are initially recorded in AOCI and reclassified into earnings when the underlying transaction affects earnings. The gains and losses reclassified out of AOCI for the years ended December 31, 2025, 2024, and 2023 are immaterial.
In February 2025, Exelon terminated the previously issued floating-to-fixed swaps with a total notional of $765 million upon issuance of $1 billion of debt. See Note 14 — Debt and Credit Agreements for additional information on the debt issuance. The settlements resulted in a cash receipt of $16 million. The accumulated AOCI gain of $13 million (net of tax) is being amortized into Interest expense in Exelon's Consolidated Statement of Operations and Comprehensive Income over the 5-year and 10-year terms of the swaps. During the fourth quarter of 2025, Exelon Corporate entered into $30 million notional of 10-year maturity floating-to-fixed swaps designated as cash flow hedges. The following table provides the notional amounts outstanding held by Exelon at December 31, 2025 and 2024.
December 31, 2025December 31, 2024
5-year maturity floating-to-fixed swaps$335 $657 
10-year maturity floating-to-fixed swaps365 658 
Total$700 $1,315 
The AOCI derivative loss (net of tax) was $9 million for the year ended December 31, 2025 and gain was $19 million for the year ended December 31, 2024, respectively. See Note 19 – Changes in Accumulated Other Comprehensive Income (Loss) for additional information.
Credit Risk
The Registrants would be exposed to credit-related losses in the event of non-performance by counterparties on executed derivative instruments. The credit exposure of derivative contracts, before collateral, is represented by the fair value of contracts at the reporting date. The Utility Registrants have contracts to procure electric and natural gas supply that provide suppliers with a certain amount of unsecured credit. If the exposure on the supply contract exceeds the amount of unsecured credit, the suppliers may be required to post collateral. The net credit exposure is mitigated primarily by the ability to recover procurement costs through customer rates. The amount of cash collateral received from external counterparties remained relatively consistent as of December 31, 2025. Cash collateral held by ComEd, PECO, BGE, Pepco, DPL, and ACE must be deposited in an unaffiliated major U.S. commercial or foreign bank with a U.S. branch office that meets certain qualifications. The following table reflects the Registrants' cash collateral held from external counterparties, which is recorded in Other current liabilities on their respective Consolidated Balance Sheets, at December 31, 2025 and 2024
December 31, 2025December 31, 2024
Exelon$223 $181 
ComEd192 176 
PECO(a)
6 — 
BGE4 1 
PHI21 4 
Pepco13 1 
DPL3 2 
ACE(a)
5 — 
__________
(a)PECO and ACE had less than one million in cash collateral held with external parties as of December 31, 2024.
The Utility Registrants’ electric supply procurement contracts do not contain provisions that would require them to post collateral. PECO’s, BGE’s, and DPL’s natural gas procurement contracts contain provisions that could require PECO, BGE, and DPL to post collateral in the form of cash or credit support, which vary by contract and counterparty, with thresholds contingent upon PECO’s, BGE's, and DPL’s credit rating. As of December 31, 2025,
229



Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)

Note 13 — Derivative Financial Instruments
PECO, BGE, and DPL were not required to post collateral for any of these agreements. If PECO, BGE, or DPL lost their investment grade credit rating as of December 31, 2025, they could have been required to post collateral to their counterparties of $58 million, $43 million, and $14 million, respectively.

14. Debt and Credit Agreements (All Registrants)
Short-Term Borrowings
Exelon Corporate, ComEd, and BGE meet their short-term liquidity requirements primarily through the issuance of commercial paper. PECO meets its short-term liquidity requirements primarily through the issuance of commercial paper and borrowings from the Exelon intercompany money pool. Pepco, DPL, and ACE meet their short-term liquidity requirements primarily through the issuance of commercial paper and borrowings from the PHI intercompany money pool. PHI Corporate meets its short-term liquidity requirements primarily through the issuance of short-term notes and borrowings from the Exelon intercompany money pool. The Registrants may use their respective credit facilities for general corporate purposes, including meeting short-term funding requirements and the issuance of letters of credit.
Commercial Paper
The following table reflects the Registrants' commercial paper programs supported by the revolving credit agreements at December 31, 2025 and 2024:
Credit Facility Size
at December 31,		Outstanding Commercial
Paper at December 31,		Average Interest Rate on
Commercial Paper Borrowings
at December 31,
Commercial Paper Issuer
2025(a)
2024(a)
2025202420252024
Exelon(b)
$4,000 $4,000 $612 $1,359 3.94 %4.66 %
ComEd$1,000 $1,000 $— $36 — %4.55 %
PECO$600 $600 $— $192 — %4.65 %
BGE$600 $600 $— $175 — %4.61 %
PHI(c)
$900 $900 $612 $530 3.94 %4.70 %
Pepco$360 
(d)
$300 $303 $200 3.93 %4.69 %
DPL$300 
(d)
$300 $161 $144 3.94 %4.74 %
ACE$240 
(d)
$300 $148 $186 3.94 %4.67 %
__________
(a)Excludes credit facility agreements arranged at community banks. See below for additional information.
(b)Includes revolving credit agreements at Exelon Corporate with a maximum program size of $900 million as of December 31, 2025 and December 31, 2024. Exelon Corporate had no outstanding commercial paper as of December 31, 2025 and $426 million outstanding commercial paper as of December 31, 2024.
(c)Represents the consolidated amounts of Pepco, DPL, and ACE.
(d)The standard maximum program size for revolving credit facilities is $300 million each for Pepco, DPL, and ACE based on the credit agreements in place. However, the facilities at Pepco, DPL, and ACE have the ability to flex to $500 million, $500 million, and $350 million, respectively. The borrowing capacity may be increased or decreased during the term of the facility, except that (i) the sum of the borrowing capacity must equal the total amount of the facility, and (ii) the aggregate amount of credit used at any given time by each of Pepco, DPL, or ACE may not exceed $900 million or the maximum amount of short-term debt the company is permitted to have outstanding by its regulatory authorities. The total number of the borrowing reallocations may not exceed eight per year during the term of the facility. This ability was utilized to increase Pepco's program size to $360 million, effective December 11, 2025. As a result, the program size for DPL did not change and ACE was decreased to $240 million, which prevents the aggregate amount of outstanding short-term debt from exceeding the $900 million limit.
In order to maintain their respective commercial paper programs in the amounts indicated above, each Registrant must have credit facilities in place, at least equal to the amount of its commercial paper program. A registrant does not issue commercial paper in an aggregate amount exceeding the then available capacity under its credit facility.
230



Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)

Note 14 — Debt and Credit Agreements
At December 31, 2025, the Registrants had the following aggregate bank commitments, credit facility borrowings, and available capacity under their respective credit facilities:
Available Capacity at December 31, 2025
BorrowerFacility Type
Aggregate Bank
Commitment(a)
Facility DrawsOutstanding
Letters of Credit		Actual
To Support
Additional
Commercial
Paper(b)
Exelon(b)
Syndicated Revolver$4,000 $— $51 $3,949 $3,338 
ComEdSyndicated Revolver1,000 — 15 985 985 
PECOSyndicated Revolver600 — 5 595 595 
BGESyndicated Revolver600 — 25 575 575 
PHI(c)
Syndicated Revolver900 — 2 898 286 
PepcoSyndicated Revolver360 — 2 358 55 
DPLSyndicated Revolver300 — — 300 139 
ACESyndicated Revolver240 — — 240 92 
__________
(a)Excludes credit facility agreements arranged at community banks. See below for additional information.
(b)Includes $900 million aggregate bank commitment related to Exelon Corporate. Exelon Corporate had $3 million outstanding letters of credit as of December 31, 2025. Exelon Corporate had $897 million in available capacity to support additional commercial paper as of December 31, 2025.
(c)Represents the consolidated amounts of Pepco, DPL, and ACE.
The following table reflects the Registrants' credit facility agreements arranged at community banks at December 31, 2025 and 2024. These are excluded from the Maximum Program Size and Aggregate Bank Commitment amounts within the two tables above and the facilities may be used to issue letters of credit.
Aggregate Bank CommitmentsOutstanding Letters of Credit
Borrower
2025(a)
202420252024
Exelon(b)
$140 $140 $5 $5 
ComEd40 40 3 3 
PECO40 40 — — 
BGE15 15 2 2 
PHI(c)
45 45 — — 
Pepco15 15 — — 
DPL 15 15 — — 
ACE15 15 — — 
__________
(a)These facilities were entered into on October 3, 2025 and expire on October 1, 2027. Previously structured as one-year arrangements, the facilities are now two-year terms.
(b)Represents the consolidated amounts of ComEd, PECO, BGE, Pepco, DPL, and ACE.
(c)Represents the consolidated amounts of Pepco, DPL, and ACE.







231



Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)

Note 14 — Debt and Credit Agreements
Revolving Credit Agreements
On August 29, 2024, Exelon Corporate and each of the Utility Registrants amended and restated their respective syndicated revolving credit facility, extending the maturity date to August 29, 2029. The following table reflects the credit agreements:
BorrowerAggregate Bank CommitmentInterest Rate
Exelon Corporate$900 
SOFR plus 1.075%
ComEd$1,000 
SOFR plus 1.000%
PECO$600 
SOFR plus 0.900%
BGE$600 
SOFR plus 0.900%
Pepco$300 
SOFR plus 1.000%
DPL $300 
SOFR plus 1.000%
ACE$300 
SOFR plus 1.000%
Borrowings under Exelon’s, ComEd’s, PECO’s, BGE's, Pepco's, DPL's, and ACE's revolving credit agreements bear interest at a rate based upon either the prime rate or a SOFR-based rate, plus an adder based upon the particular Registrant’s credit rating. The adders for the prime based borrowings and SOFR-based borrowings as of December 31, 2025 are presented in the following table:
Exelon(a)
ComEdPECOBGEPepcoDPLACE
Prime based borrowings
0 - 7.5
——————
SOFR-based borrowings
90.0 - 107.5
100.090.090.0100.0100.0100.0
__________
(a)Includes interest rate adders at Exelon Corporate of 7.5 basis points and 107.5 basis points for prime and SOFR-based borrowings, respectively.
If any Registrant loses its investment grade rating, the maximum adders for prime rate borrowings and SOFR-based rate borrowings would be 65 basis points and 165 basis points, respectively. The credit agreements also require the borrower to pay a facility fee based upon the aggregate commitments. The fee varies depending upon the respective credit ratings of the borrower. Exelon Corporate and the Utility Registrants had no outstanding amounts on the revolving credit facilities as of December 31, 2025.
Short-Term Loan Agreements
On March 23, 2017, Exelon Corporate entered into a term loan agreement for $500 million. The loan agreement was renewed in the first quarter of 2024 and was bifurcated into two tranches of $350 million and $150 million on March 14, 2024. The loan agreements were renewed in the first quarter of 2025, extending the expiration date to March 13, 2026 with a variable interest rate equal to SOFR plus 1.00%. Exelon Corporate repaid the term loan on December 5, 2025.
Variable Rate Demand Bonds
DPL has outstanding obligations in respect of Variable Rate Demand Bonds (VRDB). VRDBs are subject to repayment on the demand of the holders and, for this reason, are accounted for as short-term debt in accordance with GAAP. However, these bonds may be converted to a fixed-rate, fixed-term option to establish a maturity which corresponds to the date of final maturity of the bonds. On this basis, PHI views VRDBs as a source of long-term financing. As of December 31, 2025 and December 31, 2024, $46 million and $46 million in variable rate demand bonds issued by DPL were outstanding and are included in the Long-term debt due within one year in Exelon's, PHI's, and DPL's Consolidated Balance Sheets.




232



Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)

Note 14 — Debt and Credit Agreements
Long-Term Debt
The following tables present the outstanding long-term debt at the Registrants at December 31, 2025 and 2024:
Exelon
Maturity
Date		December 31,
Rates20252024
Long-term debt
First mortgage bonds(a)
2.20 %-7.90 %2026 - 2055$28,376 $26,451 
Senior unsecured notes2.75 %-7.60 %2026 - 205513,473 12,280 
Unsecured notes2.25 %-6.35 %2026 - 20546,100 5,450 
Notes payable and other1.64 %-7.49 %2025 - 205379 83 
Junior subordinated notes6.50 %20551,000 — 
Long-term software licensing agreement2.30 %2025— 4 
Medium-terms notes (unsecured)7.72 %202710 10 
Total long-term debt49,038 44,278 
Unamortized debt discount and premium, net(93)(94)
Unamortized debt issuance costs (369)(326)
Fair value adjustment502 542 
Long-term debt due within one year(1,665)(1,453)
Long-term debt$47,413 $42,947 
Long-term debt to financing trusts(b)
Subordinated debentures to ComEd Financing III6.35 %2033$206 $206 
Subordinated debentures to PECO Trust III7.38 %-8.75 %202881 81 
Subordinated debentures to PECO Trust IV5.75 %2033103 103 
Total long-term debt to financing trusts$390 $390 
__________
(a)Substantially all of ComEd’s assets other than expressly excluded property and substantially all of PECO’s, Pepco's, DPL's, and ACE's assets are subject to the liens of their respective mortgage indentures.
(b)Amounts owed to these financing trusts are recorded as Long-term debt to financing trusts within Exelon’s Consolidated Balance Sheets.
233



Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)

Note 14 — Debt and Credit Agreements
ComEd
Maturity
Date		December 31,
Rates20252024
Long-term debt
First mortgage bonds(a)
2.20 %-6.45 %2026 - 2055$12,879 $12,154 
Other7.49 %20537 8 
Total long-term debt12,886 12,162 
Unamortized debt discount and premium, net(29)(31)
Unamortized debt issuance costs(104)(101)
Long-term debt due within one year(500)— 
Long-term debt$12,253 $12,030 
Long-term debt to financing trust(b)
Subordinated debentures to ComEd Financing III6.35 %2033$206 $206 
Long-term debt to financing trusts $206 $206 
__________
(a)Substantially all of ComEd’s assets, other than expressly excluded property, are subject to the lien of its mortgage indenture.
(b)Amount owed to this financing trust is recorded as Long-term debt to financing trust within ComEd’s Consolidated Balance Sheets.
PECO
Maturity
Date		December 31,
Rates20252024
Long-term debt
First mortgage bonds(a)
2.80 %-5.95 %2033 - 2055$6,475 $5,775 
Total long-term debt6,475 5,775 
Unamortized debt discount and premium, net(25)(25)
Unamortized debt issuance costs(54)(46)
Long-term debt due within one year— (350)
Long-term debt$6,396 $5,354 
Long-term debt to financing trusts(b)
Subordinated debentures to PECO Trust III7.38 %-8.75 %2028$81 $81 
Subordinated debentures to PECO Trust IV5.75 %2033103 103 
Long-term debt to financing trusts $184 $184 
__________
(a)Substantially all of PECO’s assets are subject to the lien of its mortgage indenture.
(b)Amounts owed to this financing trust are recorded as Long-term debt to financing trusts within PECO’s Consolidated Balance Sheets.
BGE
Maturity
Date		December 31,
Rates20252024
Long-term debt
Unsecured notes2.25 %-6.35 %2026 - 2054$6,100 $5,450 
Total long-term debt6,100 5,450 
Unamortized debt discount and premium, net(14)(13)
Unamortized debt issuance costs(45)(42)
Long-term debt due within one year(350)— 
Long-term debt$5,691 $5,395 
234



Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)

Note 14 — Debt and Credit Agreements
PHI
Maturity
Date		December 31,
Rates20252024
Long-term debt
First mortgage bonds(a)
2.25 %-7.90 %2028 - 2055$9,022 $8,522 
Senior unsecured notes
7.45 %2032185 185 
Medium-terms notes (unsecured)7.72 %202710 10 
Finance leases5.62 %2026 - 203372 75 
Total long-term debt9,289 8,792 
Unamortized debt discount and premium, net(2)(2)
Unamortized debt issuance costs(71)(66)
Fair value adjustment374 400 
Long-term debt due within one year(64)(290)
Long-term debt$9,526 $8,834 
_________
(a)Substantially all of Pepco's, DPL's, and ACE's assets are subject to the liens of their respective mortgage indentures.
Pepco
Maturity
Date		December 31,
Rates20252024
Long-term debt
First mortgage bonds(a)
2.32 %-7.90 %2029 - 2055$4,675 $4,400 
Finance leases5.62 %2026 - 203325 27 
Total long-term debt4,700 4,427 
Unamortized debt discount and premium, net(1)— 
Unamortized debt issuance costs(67)(65)
Long-term debt due within one year(6)(6)
Long-term debt$4,626 $4,356 
________
(a)Substantially all of Pepco's assets are subject to the lien of its mortgage indenture.
DPL
Maturity
Date		December 31,
Rates20252024
Long-term debt
First mortgage bonds(a)
2.53 %-5.72 %2028 - 2054$2,324 $2,198 
Medium-terms notes (unsecured)
7.72 %202710 10 
Finance leases5.62 %2026 - 203327 28 
Total long-term debt2,361 2,236 
Unamortized debt issuance costs(17)(16)
Long-term debt due within one year(53)(130)
Long-term debt$2,291 $2,090 
__________
(a)Substantially all of DPL's assets are subject to the lien of its mortgage indenture.

235



Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)

Note 14 — Debt and Credit Agreements
ACE
Maturity
Date		December 31,
Rates20252024
Long-term debt
First mortgage bonds(a)
2.25 %-5.81 %2028 - 2055$2,023 $1,923 
Finance leases5.62 %2026 - 203320 20 
Total long-term debt2,043 1,943 
Unamortized debt issuance costs(10)(10)
Long-term debt due within one year(5)(154)
Long-term debt$2,028 $1,779 
__________
(a)Substantially all of ACE's assets are subject to the lien of its mortgage indenture.

Long-term debt maturities at the Registrants in the periods 2026 through 2030 and thereafter are as follows:
YearExelon ComEdPECOBGEPHIPepcoDPLACE
2026$1,665 $500 $— $350  $64 $6 $53 $5 
20271,028 350 — —  28 7 17 5 
20281,996 550 81 —  365 5 6 354 
20291,933 — — —  284 153 4 126 
20301,856 350 — —  257 153 103 2 
Thereafter40,950 
(a)
11,342 
(b)
6,578 
(c)
5,750 8,291 4,376 2,178 1,551 
Total$49,428 $13,092 $6,659 $6,100 $9,289 $4,700 $2,361 $2,043 
__________
(a)Includes $390 million due to ComEd and PECO financing trusts.
(b)Includes $206 million due to ComEd financing trust.
(c)Includes $184 million due to PECO financing trusts.
Convertible Senior Notes
On December 4, 2025, Exelon Corporation issued $1 billion aggregate principal amount of 3.25% Convertible Senior Notes due 2029 (Convertible Senior Notes). The Convertible Senior Notes are reflected as Long-term debt on Exelon’s Consolidated Balance Sheet.

The Convertible Senior Notes are senior, unsecured notes that bear interest at a fixed rate of 3.25% per year, payable semiannually in arrears on March 15 and September 15 of each year, beginning on September 15, 2026. The Convertible Senior Notes will mature on March 15, 2029, unless earlier converted or repurchased in accordance with their terms.

Under the following circumstances, holders may convert the Convertible Senior Notes at their option prior to the close of business on the business day preceding December 15, 2028:
•during any calendar quarter beginning after the quarter ending on March 31, 2026, if the last reported sale price of Exelon’s common stock for at least 20 trading days (whether consecutive or not) during the period of 30 consecutive trading days ending on, and including, the last trading day of the immediately preceding calendar quarter is greater than or equal the stock was trading at greater than or equal to 130% of the conversion price on each applicable trading day as determined by Exelon;
•during the five business day period after any ten consecutive trading day period (measurement period) in which the applicable trading price per $1,000 principal amount of notes for each trading day of the measurement period was less than 98% of the product of the last reported sale price of the common stock and the conversion rate on each such trading day;
•upon the occurrence of certain corporate events specified in the respective supplemental indentures governing the Convertible Senior Notes.

236



Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)

Note 14 — Debt and Credit Agreements
On or after December 15, 2028, a holder may convert for all, or any portion of its Convertible Senior Notes at any time prior to the close of business on the business day immediately preceding the applicable maturity date regardless of the foregoing conditions.

Exelon will settle conversions of the Convertible Senior Notes by paying cash up to the aggregate principal amount to be converted and paying or delivering, as the case may be, cash, shares of common stock, or a combination of cash and shares of common stock, at Exelon’s discretion, in respect of the remainder, if any, of Exelon's conversion obligation in excess of the aggregate principal amount of the Convertible Senior Notes being converted. The Convertible Senior Notes are initially convertible at 17.5093 shares per $1,000 principal amount, which is equivalent to an initial conversion price of approximately $57.11 per share of common stock. The initial conversion price of the Convertible Senior Notes represents a premium of approximately 25% over the last reported sale price of Exelon’s common stock on the Nasdaq Global Select Market on December 1, 2025. These conversions will be subject to adjustment upon the occurrence of certain specified events but will not be adjusted for accrued and unpaid interest. In addition, upon the occurrence of a make-whole fundamental change (as defined in the indenture) Exelon will, in certain circumstances, increase the applicable conversion rate by a number of additional shares of common stock for conversions in connection with the make-whole fundamental change.
EPS Impact
Diluted earnings per common shares will also reflect the dilutive effect of potential common shares from share-based awards and convertible notes. The dilutive effect of the Convertible Senior Notes is computed using the if-converted method. For the year ended December 31, 2025, no incremental shares were assumed converted or included in the diluted earnings per common share. resulting from the Convertible Senior Notes.
Debt Extinguishment
During the twelve months ended December 31, 2024, Exelon repurchased a portion of its Senior unsecured notes with a principal balance of $244 million outstanding in exchange for cash of $215 million. The repurchase was accounted for as a debt extinguishment and resulted in a pre-tax gain of $28 million, which is reflected on Exelon's Consolidated Statement of Operations and Comprehensive income within Interest expense, net.
Reoffering of Tax-Exempt Bonds
On July 1, 2025, DPL completed the reoffering of $78.4 million aggregate principal amount of its Delaware Economic Development Authority’s Gas Facilities Refunding Revenue Bonds (Delmarva Power & Light Company Project) 2020 Series A (Non-AMT) (the Bonds). In connection with the reoffering of the Bonds, the interest rate was modified to 3.60% per annum, and the maturity date was modified to January 1, 2031. DPL did not directly receive any proceeds from the reoffering.
Debt Covenants
As of December 31, 2025, the Registrants are in compliance with debt covenants.

15. Fair Value of Financial Assets and Liabilities (All Registrants)
Exelon measures and classifies fair value measurements in accordance with the hierarchy as defined by GAAP. The hierarchy prioritizes the inputs to valuation techniques used to measure fair value into three levels as follows:
•Level 1 — quoted prices (unadjusted) in active markets for identical assets or liabilities that the Registrants have the ability to liquidate as of the reporting date.
•Level 2 — inputs other than quoted prices included within Level 1 that are directly observable for the asset or liability or indirectly observable through corroboration with observable market data.
•Level 3 — unobservable inputs, such as internally developed pricing models or third-party valuations for the asset or liability due to little or no market activity for the asset or liability.
237



Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)

Note 15 — Fair Value of Financial Assets and Liabilities
Fair Value of Financial Liabilities Recorded at Amortized Cost
The following tables present the carrying amounts and fair values of the Registrants’ short-term liabilities, long-term debt, and trust preferred securities (long-term debt to financing trusts or junior subordinated debentures) at December 31, 2025 and 2024. The Registrants have no financial liabilities measured using the NAV practical expedient.
The carrying amounts of the Registrants’ short-term liabilities as presented in their Consolidated Balance Sheets are representative of their fair value (Level 2) because of the short-term nature of these instruments.
December 31, 2025December 31, 2024
Carrying AmountFair ValueCarrying AmountFair Value
Level 1Level 2Level 3TotalLevel 1Level 2Level 3Total
Long-Term Debt, including amounts due within one year(a)
Exelon (b)
$49,078 $— $40,637 $4,318 $44,955 $44,400 $— $35,337 $3,720 $39,057 
ComEd12,753 — 11,291 — 11,291 12,030 — 10,260 — 10,260 
PECO6,396 — 5,593 — 5,593 5,704 — 4,816 — 4,816 
BGE6,041 — 5,510 — 5,510 5,395 — 4,702 — 4,702 
PHI9,590 — 4,236 4,318 8,554 9,124 — 4,093 3,720 7,813 
Pepco4,632 — 2,546 1,861 4,407 4,362 — 2,475 1,544 4,019 
DPL2,344 — 657 1,410 2,067 2,220 — 623 1,250 1,873 
ACE2,033 — 819 1,047 1,866 1,933 — 787 925 1,712 
Long-Term Debt to Financing Trusts
Exelon$390 $— $— $403 $403 $390 $— $— $396 $396 
ComEd206 — — 216 216 206 — — 208 208 
PECO184 — — 187 187 184 — — 188 188 
__________
(a)Includes unamortized debt issuance costs, unamortized debt discount and premium, net, purchase accounting fair value adjustments, and finance lease liabilities which are not fair valued. Refer to Note 14 — Debt and Credit Agreements for unamortized debt issuance costs, unamortized debt discount and premium, net, and purchase accounting fair value adjustments and Note 9 — Leases for finance lease liabilities.
(b)Includes the net carrying amount and the estimated fair value (Level 2) of the Convertible Senior Notes of $988 million and $1 billion for the year ended December 31, 2025, respectively.

238



Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)

Note 15 — Fair Value of Financial Assets and Liabilities
Exelon uses the following methods and assumptions to estimate fair value of financial liabilities recorded at carrying cost:

TypeLevelRegistrantsValuation
Long-Term Debt, including amounts due within one year
Taxable Debt Securities2AllThe fair value is determined by a valuation model that is based on a conventional discounted cash flow methodology and utilizes assumptions of current market pricing curves. Exelon obtains credit spreads based on trades of existing Exelon debt securities as well as other issuers in the utility sector with similar credit ratings. The yields are then converted into discount rates of various tenors that are used for discounting the respective cash flows of the same tenor for each bond or note.
Variable Rate Financing Debt2Exelon, DPLDebt rates are reset on a regular basis and the carrying value approximates fair value.
Non-Government Backed Fixed Rate Nonrecourse Debt2ExelonFair value is based on market and quoted prices for its own and other nonrecourse debt with similar risk profiles. Given the low trading volume in the nonrecourse debt market, the price quotes used to determine fair value will reflect certain qualitative factors, such as market conditions, investor demand, new developments that might significantly impact the project cash flows or off-taker credit, and other circumstances related to the project.
Taxable Private Placement Debt Securities3Exelon, Pepco, DPL, ACERates are obtained similar to the process for taxable debt securities. Due to low trading volume and qualitative factors such as market conditions, low volume of investors, and investor demand, these debt securities are Level 3.
Long-Term Debt to Financing Trusts
Long Term Debt to Financing Trusts3Exelon, ComEd, PECOFair value is based on publicly traded securities issued by the financing trusts. Due to low trading volume of these securities and qualitative factors, such as market conditions, investor demand, and circumstances related to each issue, this debt is classified as Level 3.

239



Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)

Note 15 — Fair Value of Financial Assets and Liabilities
Recurring Fair Value Measurements
The following tables present assets and liabilities measured and recorded at fair value in the Registrants' Consolidated Balance Sheets on a recurring basis and their level within the fair value hierarchy at December 31, 2025 and 2024. Exelon and the Utility Registrants have immaterial and no financial assets or liabilities measured using the NAV practical expedient, respectively.
Exelon
At December 31, 2025At December 31, 2024
Level 1Level 2Level 3TotalLevel 1Level 2Level 3Total
Assets
Cash equivalents(a)
$825 $— $— $825 $544 $— $— $544 
Rabbi trust investments
Cash equivalents101 — — 101 94 — — 94 
Mutual funds71 — — 71 65 — — 65 
Fixed income— 6 — 6 — 6 — 6 
Life insurance contracts— 79 21 100 — 73 22 95 
Rabbi trust investments subtotal172 85 21 278 159 79 22 260 
Interest rate derivative assets
Derivatives designated as hedging instruments— 3 — 3 — 26 — 26 
Interest rate derivative assets subtotal— 3 — 3 — 26 — 26 
Total assets997 88 21 1,106 703 105 22 830 
Liabilities
Commodity derivative liabilities— — (131)(131)— — (132)(132)
Interest rate derivative liabilities
Derivatives designated as hedging instruments— (4)— (4)— (1)— (1)
Interest rate derivative liabilities subtotal— (4)— (4)— (1)— (1)
Deferred compensation obligation— (71)— (71)— (74)— (74)
Total liabilities— (75)(131)(206)— (75)(132)(207)
Total net assets (liabilities)$997 $13 $(110)$900 $703 $30 $(110)$623 
__________
(a)Excludes cash of $180 million and $219 million at December 31, 2025 and 2024, respectively, and restricted cash of $196 million and $176 million at December 31, 2025 and 2024, respectively, and includes long-term restricted cash of $50 million and $41 million at December 31, 2025 and 2024, respectively, which is reported in Other deferred debits in the Consolidated Balance Sheets.
240



Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)

Note 15 — Fair Value of Financial Assets and Liabilities
ComEd, PECO, and BGE
ComEdPECOBGE
At December 31, 2025Level 1Level 2Level 3TotalLevel 1Level 2Level 3TotalLevel 1Level 2Level 3Total
Assets
Cash equivalents(a)
$393 $— $— $393 $93 $— $— $93 $205 $— $— $205 
Rabbi trust investments
Mutual funds— — — — 13 — — 13 10 — — 10 
Life insurance contracts— — — — — 25 — 25 — — — — 
Rabbi trust investments subtotal— — — — 13 25 — 38 10 — — 10 
Total assets393 — — 393 106 25 — 131 215 — — 215 
Liabilities
Commodity derivative liabilities(b)
— — (131)(131)— — — — — — — — 
Deferred compensation obligation— (9)— (9)— (8)— (8)— (4)— (4)
Total liabilities— (9)(131)(140)— (8)— (8)— (4)— (4)
Total net assets (liabilities)$393 $(9)$(131)$253 $106 $17 $— $123 $215 $(4)$— $211 
ComEdPECOBGE
At December 31, 2024Level 1Level 2Level 3TotalLevel 1Level 2Level 3TotalLevel 1Level 2Level 3Total
Assets
Cash equivalents(a)
$390 $— $— $390 $29 $— $— $29 $1 $— $— $1 
Rabbi trust investments
Mutual funds— — — — 12 — — 12 10 — — 10 
Life insurance contracts— — — — — 22 — 22 — — — — 
Rabbi trust investments subtotal— — — — 12 22 — 34 10 — — 10 
Total assets390 — — 390 41 22 — 63 11 — — 11 
Liabilities
Commodity derivative liabilities(b)
— — (132)(132)— — — — — — — — 
Deferred compensation obligation— (8)— (8)— (7)— (7)— (4)— (4)
Total liabilities— (8)(132)(140)— (7)— (7)— (4)— (4)
Total net assets (liabilities)$390 $(8)$(132)$250 $41 $15 $— $56 $11 $(4)$— $7 
__________
(a)ComEd excludes cash of $77 million and $66 million at December 31, 2025 and 2024, respectively, and restricted cash of $193 million and $176 million at December 31, 2025 and 2024, respectively, and includes long-term restricted cash of $50 million and $41 million at December 31, 2025 and 2024, respectively, which is reported in Other deferred debits in the Consolidated Balance Sheets. PECO excludes cash of $23 million and $19 million at December 31, 2025 and 2024, respectively. BGE excludes cash of $15 million and $33 million at December 31, 2025 and 2024, respectively.
(b)The Level 3 balance consists of the current and noncurrent liability of $25 million and $106 million, respectively, at December 31, 2025, and $29 million and $103 million, respectively, at December 31, 2024 related to floating-to-fixed energy swap contracts with unaffiliated suppliers.





241



Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)

Note 15 — Fair Value of Financial Assets and Liabilities
PHI, Pepco, DPL, and ACE
At December 31, 2025At December 31, 2024
PHILevel 1Level 2Level 3TotalLevel 1Level 2Level 3Total
Assets
Cash equivalents(a)
$83 $— $— $83 $93 $— $— $93 
Rabbi trust investments
Cash equivalents99 — — 99 92 — — 92 
Mutual funds9 — — 9 9 — — 9 
Fixed income— 6 — 6 — 6 — 6 
Life insurance contracts— 23 20 43 — 23 21 44 
Rabbi trust investments subtotal108 29 20 157 101 29 21 151 
Total assets191 29 20 240 194 29 21 244 
Liabilities
Deferred compensation obligation— (9)— (9)— (12)— (12)
Total liabilities— (9)— (9)— (12)— (12)
Total net assets$191 $20 $20 $231 $194 $17 $21 $232 
PepcoDPLACE
At December 31, 2025Level 1Level 2Level 3TotalLevel 1Level 2Level 3TotalLevel 1Level 2Level 3Total
Assets
Cash equivalents(a)
$33 $— $— $33 $3 $— $— $3 $— $— $— $— 
Rabbi trust investments
Cash equivalents98 — — 98 — — — — — — — — 
Life insurance contracts— 23 20 43 — — — — — — — — 
Rabbi trust investments subtotal98 23 20 141 — — — — — — — — 
Total assets131 23 20 174 3 — — 3 — — — — 
Liabilities
Deferred compensation obligation— (1)— (1)— — — — — — — — 
Total liabilities— (1)— (1)— — — — — — — — 
Total net assets$131 $22 $20 $173 $3 $— $— $3 $— $— $— $— 
PepcoDPLACE
At December 31, 2024Level 1Level 2Level 3TotalLevel 1Level 2Level 3TotalLevel 1Level 2Level 3Total
Assets
Cash equivalents(a)
$21 $— $— $21 $3 $— $— $3 $— $— $— $— 
Rabbi trust investments
Cash equivalents91 — — 91 — — — — — — — — 
Life insurance contracts— 23 21 44 — — — — — — — — 
Rabbi trust investments subtotal91 23 21 135 — — — — — — — — 
Total assets112 23 21 156 3 — — 3 — — — — 
Liabilities
Deferred compensation obligation— (1)— (1)— — — — — — — — 
Total liabilities— (1)— (1)— — — — — — — — 
Total net assets$112 $22 $21 $155 $3 $— $— $3 $— $— $— $— 
__________
(a)PHI excludes cash of $56 million and $70 million at December 31, 2025 and 2024, respectively, and restricted cash of $2 million and zero at December 31, 2025 and 2024, respectively. Pepco excludes cash of $22 million and $30 million at December 31, 2025 and 2024, respectively. DPL excludes cash of $9 million and $20 million at December 31, 2025 and 2024, respectively. ACE excludes cash of $22 million and $14 million at December 31, 2025 and 2024, respectively, and restricted cash of $2 million and zero at December 31, 2025 and 2024, respectively.

242



Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)

Note 15 — Fair Value of Financial Assets and Liabilities
Reconciliation of Level 3 Assets and Liabilities
The following tables present the fair value reconciliation of Level 3 assets and liabilities measured at fair value on a recurring basis during the years ended December 31, 2025 and 2024:
ExelonComEdPHI and Pepco
For the year ended December 31, 2025TotalCommodity
Derivatives		Life Insurance Contracts
Balance at December 31, 2024$(110)$(132)$21 
Total realized / unrealized gains (losses)
Included in net income(a)
1 — 1 
Included in regulatory assets/liabilities(b)
1 1 — 
Settlements(2)— (2)
Balance at December 31, 2025(c)
$(110)$(131)$20 
The amount of total gains included in income attributed to the change in unrealized gains (losses) related to assets and liabilities as of December 31, 2025
$1 $— $1 
ExelonComEdPHI and Pepco
For the year ended December 31, 2024TotalCommodity
Derivatives		Life Insurance Contracts
Balance at December 31, 2023$(90)$(133)$41 
Total realized / unrealized gains (losses)
Included in net income(a)
1 — 2 
Included in regulatory assets/liabilities (b)
1 1 — 
Settlements(22)— (22)
Balance at December 31, 2024(c)
$(110)$(132)$21 
The amount of total gains included in income attributed to the change in unrealized gains (losses) related to assets and liabilities as of December 31, 2024
$1 $— $2 
__________
(a)Classified in Operating and maintenance expense in the Consolidated Statements of Operations and Comprehensive Income.
(b)For ComEd, this includes $45 million of decreases in fair value and an increase for realized gains due to settlements of $46 million recorded in Purchased power expense associated with floating-to-fixed energy swap contracts with unaffiliated suppliers for the year ended December 31, 2025. Includes $40 million of decreases in fair value and an increase for realized gains due to settlements of $40 million recorded in Purchased power expense associated with floating-to-fixed energy swap contracts with unaffiliated suppliers for the year ended December 31, 2024.
(c)For ComEd, the balance of the current and noncurrent asset was zero as of December 31, 2025. The balance consists of a current and noncurrent liability of $25 million and $106 million, respectively, as of December 31, 2025.
Valuation Techniques Used to Determine Fair Value
Cash Equivalents (All Registrants). Investments with original maturities of three months or less when purchased, including mutual and money market funds, are considered cash equivalents. The fair values are based on observable market prices and, therefore, are included in the recurring fair value measurements hierarchy as Level 1.
Rabbi Trust Investments (Exelon, PECO, BGE, PHI, and Pepco). The Rabbi trusts were established to hold assets related to deferred compensation plans existing for certain active and retired members of Exelon’s executive management and directors. The Rabbi trusts' assets are included in Investments in the Registrants’ Consolidated Balance Sheets and consist primarily of money market funds, mutual funds, fixed income securities, and life insurance policies. Money market funds and mutual funds are publicly quoted and have been categorized as Level 1 given the clear observability of the prices. The fair values of fixed income securities are based on evaluated prices that reflect observable market information, such as actual trade information or similar securities, adjusted for observable differences and are categorized in Level 2. The life insurance policies are
243



Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)

Note 15 — Fair Value of Financial Assets and Liabilities
valued using the cash surrender value of the policies, net of loans against those policies, which is provided by a third-party. Certain life insurance policies, which consist primarily of mutual funds that are priced based on observable market data, have been categorized as Level 2 because the life insurance policies can be liquidated at the reporting date for the value of the underlying assets. Life insurance policies that are valued using unobservable inputs have been categorized as Level 3, where the fair value is determined based on the cash surrender value of the policy, which contains unobservable inputs and assumptions. Because Exelon relies on its third-party insurance provider to develop the inputs without adjustment for the valuations of its Level 3 investments, quantitative information about significant unobservable inputs used in valuing these investments is not reasonably available to Exelon. Therefore, Exelon has not disclosed such inputs.
Interest Rate Derivatives (Exelon). Exelon may utilize fixed-to-floating or floating-to-fixed interest rate swaps as a means to manage interest rate risk and to lock in interest levels in anticipation of future financings. These interest rate derivatives are typically designated as cash flow hedges. Exelon determines the current fair value by calculating the net present value of expected payments and receipts under the swap agreement, based on and discounted by the market's expectation of future interest rates. Additional inputs to the net present value calculation may include the contract terms, counterparty credit risk and other market parameters. As these inputs are based on observable data and valuations of similar instruments, the interest rate swaps are categorized as Level 2 in the fair value hierarchy. See Note 13 — Derivative Financial Instruments for additional information on mark-to-market derivatives.
Deferred Compensation Obligations (All Registrants). The Registrants’ deferred compensation plans allow participants to defer certain cash compensation into a notional investment account. The Registrants include such plans in other current and noncurrent liabilities in their Consolidated Balance Sheets. The value of the Registrants’ deferred compensation obligations is based on the market value of the participants’ notional investment accounts. The underlying notional investments are comprised primarily of equities, mutual funds, commingled funds, and fixed income securities which are based on directly and indirectly observable market prices. Since the deferred compensation obligations themselves are not exchanged in an active market, they are categorized as Level 2 in the fair value hierarchy.
The value of certain employment agreement obligations (which are included with the Deferred Compensation Obligation in the tables above) are based on a known and certain stream of payments to be made over time and are categorized as Level 2 within the fair value hierarchy.
Commodity Derivatives (Exelon and ComEd). On December 17, 2010, ComEd entered into several 20-year floating to fixed energy swap contracts with unaffiliated suppliers for the procurement of long-term renewable energy and associated RECs. Delivery under the contracts began in June 2012. The fair value of these swaps has been designated as a Level 3 valuation due to the long tenure of the positions and the internal modeling assumptions. The modeling assumptions include using forward power prices. See Note 13 — Derivative Financial Instruments for additional information on mark-to-market derivatives.
The following table discloses the significant unobservable inputs to the forward curve used to value mark-to-market derivatives:
Type of tradeFair Value as of December 31, 2025Fair Value as of December 31, 2024Valuation
Technique		Unobservable
Input
2025 Range & Arithmetic Average
2024 Range & Arithmetic Average
Commodity derivatives$(131)$(132)Discounted Cash Flow
Forward power price(a)
$29.75 -$61.84 $41.95 $30.31 -$59.88 $42.08 
__________
(a)An increase to the forward power price would increase the fair value.
16. Commitments and Contingencies (All Registrants)
Commitments
PHI Merger Commitments (Exelon, PHI, Pepco, DPL, and ACE). Approval of the PHI Merger in Delaware, New Jersey, Maryland, and the District of Columbia was conditioned upon Exelon and PHI agreeing to certain commitments. The following amounts represent total commitment costs that have been recorded since the
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Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)

Note 16 — Commitments and Contingencies
acquisition date and the total remaining obligations for Exelon, PHI, Pepco, DPL, and ACE at December 31, 2025:
DescriptionExelonPHIPepcoDPLACE
Total commitments$513 $320 $120 $89 $111 
Remaining commitments(a)
22 20 20 — — 
__________
(a)Remaining commitments extend through 2026 and include escrow funds, charitable contributions, and rate credits.
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Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)

Note 16 — Commitments and Contingencies
Commercial Commitments (All Registrants). The Registrants' commercial commitments at December 31, 2025, representing commitments potentially triggered by future events were as follows:
Expiration within
ExelonTotal202620272028202920302031 and beyond
Letters of credit(a)
$56  $54  $2  $—  $—  $— $— 
Surety bonds(b)
279 199 2 78 — — — 
Financing trust guarantees(c)
378  — — 78 — — 300 
Guaranteed lease residual values(d)
24 — 4 6 4 4 6 
Total commercial commitments $737  $253  $8  $162  $4 $4 $306 
ComEd
Letters of credit(a)
$18 $16 $2 $— $— $— $— 
Surety bonds(b)
42 40 2 — — — — 
Financing trust guarantees(c)
200 — — — — — 200 
Total commercial commitments $260  $56  $4  $—  $— $— $200 
PECO
Letters of credit(a)
$5 $5 $— $— $— $— $— 
Surety bonds(b)
2 2 — — — — — 
Financing trust guarantees(c)
178 — — 78 — — 100 
Total commercial commitments $185  $7  $—  $78  $— $— $100 
BGE
Letters of credit(a)
$27 $27 $— $— $— $— $— 
Surety bonds(b)
3 3 — — — — — 
Total commercial commitments $30  $30  $—  $—  $— $— $— 
PHI
Letters of credit(a)
$4 $4 $— $— $— $— $— 
Surety bonds(b)
173 95 — 78 — — — 
Guaranteed lease residual values(d)
24 — 4 6 4 4 6 
Total commercial commitments $201  $99  $4  $84  $4 $4 $6 
Pepco
Letters of credit(a)
$2 $2 $— $— $— $— $— 
Surety bonds(b)
160 82 — 78 — — — 
Guaranteed lease residual values(d)
8 — 1 2 1 2 2 
Total commercial commitments $170  $84  $1  $80  $1 $2 $2 
DPL
Letters of credit(a)
$1 $1 $— $— $— $— $— 
Surety bonds(b)
7 7 — — — — — 
Guaranteed lease residual values(d)
9 — 2 2 2 1 2 
Total commercial commitments $17  $8  $2  $2  $2 $1 $2 
ACE
Letters of credit(a)
$1 $1 $— $— $— $— $— 
Surety bonds(b)
6 6 — — — — — 
Guaranteed lease residual values(d)
7 — 1 2 1 1 2 
Total commercial commitments $14  $7  $1  $2  $1 $1 $2 
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Note 16 — Commitments and Contingencies
__________
(a)Exelon and certain of its subsidiaries maintain non-debt letters of credit to provide credit support for certain transactions as requested by third parties.
(b)Surety bonds—Guarantees issued related to contract and commercial agreements, excluding bid bonds. Historically, payments under the guarantees have not been made and the likelihood of payments being required is remote.
(c)Reflects guarantee of ComEd and PECO securities held by ComEd Financing III, PECO Trust III, and PECO Trust IV.
(d)Represents the maximum potential obligation in the event the fair value of certain leased equipment and fleet vehicles is zero at the end of the maximum lease term. The lease term associated with these assets ranges from 1 to 8 years. The maximum potential obligation at the end of the minimum lease term would be $54 million guaranteed by Exelon and PHI, of which $18 million, $20 million, and $16 million is guaranteed by Pepco, DPL, and ACE, respectively. Historically, payments under the guarantees have not been made and PHI believes the likelihood of payments being required under the guarantees is remote.
Environmental Remediation Matters
General (All Registrants). The Registrants’ operations have in the past, and may in the future, require substantial expenditures to comply with environmental laws. Additionally, under federal and state environmental laws, the Registrants are generally liable for the costs of remediating environmental contamination of property now or formerly owned by them and of property contaminated by hazardous substances generated by them. The Registrants own or lease a number of real estate parcels, including parcels on which their operations or the operations of others may have resulted in contamination by substances that are considered hazardous under environmental laws. In addition, the Registrants are currently involved in a number of proceedings relating to sites where hazardous substances have been deposited and may be subject to additional proceedings in the future. Unless otherwise disclosed, the Registrants cannot reasonably estimate whether they will incur significant liabilities for additional investigation and remediation costs at these or additional sites identified by the Registrants, environmental agencies, or others, or whether such costs will be recoverable from third parties, including customers. Additional costs could have a material, unfavorable impact on the Registrants' financial statements.
MGP Sites (All Registrants). ComEd, PECO, BGE, and DPL have identified sites where former MGP or gas purification activities have or may have resulted in actual site contamination. For some sites, there are additional PRPs that may share responsibility for the ultimate remediation of each location.
•ComEd has 16 sites currently under some degree of active study and/or remediation. ComEd expects the majority of the remediation at these sites to continue through at least 2033.
•PECO has 6 sites currently under some degree of active study and/or remediation. PECO expects the majority of the remediation at these sites to continue through at least 2030.
•BGE has 4 sites currently requiring some level of remediation and/or ongoing activity. BGE expects the majority of the remediation at these sites to continue through at least 2026.
•DPL has 1 site currently under study and the required cost at the site is not expected to be material.
The historical nature of the MGP and gas purification sites, and the fact that many of the sites have been buried and built over, impacts the ability to determine a precise estimate of the ultimate costs prior to initial sampling and determination of the exact scope and method of remedial activity. Management determines its best estimate of remediation costs using all available information at the time of each study, including probabilistic and deterministic modeling for ComEd and PECO, and the remediation standards currently required by the applicable state environmental agency. Prior to performing of any significant clean up, each site remediation plan is approved by the appropriate state environmental agency.
ComEd, pursuant to an ICC order, and PECO, pursuant to a PAPUC order, are currently recovering environmental remediation costs of former MGP facility sites through customer rates. While BGE and DPL do not have riders for MGP clean-up costs, they have historically received recovery of actual clean-up costs in distribution rates.
In 2025, ComEd and PECO completed an annual study of their future estimated MGP remediation requirements. ComEd's study resulted in a $12 million increase to the environmental liability and related Regulatory asset, primarily due to increased costs resulting from inflation, adjustments to unit costs, and changes in remediation
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Note 16 — Commitments and Contingencies
plans. PECO's study resulted in a $2 million decrease to the environmental liability and related Regulatory asset, primarily due to decreased costs resulting from changes in remediation plans.
At December 31, 2025 and 2024, the Registrants had accrued the following undiscounted amounts for environmental liabilities in Accrued expenses, Other current liabilities, and Other deferred credits and other liabilities in their respective Consolidated Balance Sheets:
December 31, 2025December 31, 2024
Total Environmental
Investigation and
Remediation Liabilities		Portion of Total Related to
MGP Investigation and
Remediation		Total Environmental
Investigation and
Remediation Liabilities		Portion of Total Related to
MGP Investigation and
Remediation
Exelon$386 $321 $403 $322 
ComEd289 289 285 284 
PECO23 22 29 28 
BGE13 10 13 10 
PHI 57 — 75 — 
Pepco55 — 73 — 
DPL1 — 1 — 
ACE1 — 1 — 
Benning Road Site (Exelon, PHI, and Pepco). In September 2010, PHI received a letter from the EPA identifying the Benning Road site as one of six land-based sites potentially contributing to contamination of the lower Anacostia River. A portion of the site, which is owned by Pepco, was formerly the location of an electric generating facility owned by Pepco subsidiary, Pepco Energy Services (PES), which became a part of Constellation following the 2016 merger between PHI and Exelon. This generating facility was deactivated in June 2012. The remaining portion of the site consists of a Pepco transmission and distribution service center that remains in operation. In December 2011, the U.S. District Court for the District of Columbia approved a Consent Decree entered into by Pepco and Pepco Energy Services (hereinafter Pepco Entities) with the DOEE, which requires the Pepco Entities to conduct a Remedial Investigation and Feasibility Study (RI/FS) for the Benning Road site and an approximately 10 to 15-acre portion of the adjacent Anacostia River. The purpose of this RI/FS is to define the nature and extent of contamination from the Benning Road site and to evaluate remedial alternatives.
Pursuant to an internal agreement between the Pepco Entities, since 2013, Pepco has performed the work required by the Consent Decree and has been reimbursed for that work by an agreed upon allocation of costs between the Pepco Entities. In September 2019, the Pepco Entities issued a draft “final” RI report which the DOEE approved on February 3, 2020. In October 2022, the DOEE approved dividing the work to complete the landside portion of the FS from the waterside portion to expedite the overall schedule for completion of the project. The landside FS was approved by the DOEE on March 15th, 2024, and the waterside FS was approved by the DOEE on December 16, 2024. The DOEE and Pepco entered into an addendum to the Benning Consent Decree pursuant to which Pepco has agreed to fund or perform the remedial actions to be selected by the DOEE for the landside and waterside areas. This addendum to the Benning Consent Decree was entered by the Court on February 27, 2024 and became effective on that date. Pepco drafted separate proposed plans for the landside and waterside areas, which were approved and issued by the DOEE for public comment on December 16, 2024 and September 4, 2025, respectively. The public comment period for the landside and waterside areas closed on April 18, 2025 and October 31, 2025, respectively. Pepco submitted a matrix of proposed responses to the public comments and a proposed Record of Decision (ROD) to the DOEE for the landside area on August 15, 2025. Following the close of the waterside area comment period, Pepco will submit a matrix of proposed responses to the public comments and a proposed ROD to the DOEE for the waterside area. The DOEE will issue RODs identifying the remedial actions determined to be necessary for the landside and waterside areas, which will be implemented by Pepco in accordance with the Benning Consent Decree.
As part of the separation between Exelon and Constellation in February 2022, the internal agreement between the Pepco Entities for completion and payment for the remaining Consent Decree work was memorialized in a formal agreement for post-separation activities. A second post-separation assumption agreement between Exelon and Constellation transferred any of the potential remaining remediation liability, if any, of PES/Constellation to a non-utility subsidiary of Exelon which going forward will be responsible for those liabilities.
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(Dollars in millions, except per share data unless otherwise noted)

Note 16 — Commitments and Contingencies
Exelon, PHI, and Pepco have determined that a loss associated with this matter is probable and have accrued an estimated liability, which is included in the table above.
Anacostia River Tidal Reach (Exelon, PHI, and Pepco). Contemporaneous with the Benning Road site RI/FS being performed by the Pepco Entities, the DOEE and NPS have been conducting a separate RI/FS focused on the entire tidal reach of the Anacostia River extending from just north of the Maryland-District of Columbia boundary line to the confluence of the Anacostia and Potomac Rivers. The riverwide RI incorporated the results of the river sampling performed by the Pepco Entities as part of the Benning RI/FS, as well as similar sampling efforts conducted by owners of other sites adjacent to this segment of the river and supplemental river sampling conducted by the DOEE’s contractor.
On September 30, 2020, the DOEE released its Interim ROD for the Anacostia River sediments. The Interim ROD reflects an adaptive management approach which will require several identified “hot spots” in the river to be addressed first while continuing to conduct studies and to monitor the river to evaluate improvements and determine potential future remediation plans. The adaptive management process chosen by the DOEE is less intrusive, provides more long-term environmental certainty, is less costly, and allows for site specific remediation plans already underway, including the plan for the Benning Road site to proceed to conclusion.
On July 15, 2022, Pepco received a letter from the District of Columbia's Office of the Attorney General (D.C. OAG) on behalf of the DOEE conveying a settlement offer to resolve all PRPs' liability to the District of Columbia (District) for their past costs and their anticipated future costs to complete the work for the Interim ROD. Pepco responded on July 27, 2022 agreeing to enter into settlement discussions. Pepco and the District entered into another consent decree (the “Anacostia River Consent Decree”) pursuant to which Pepco agreed to pay $47 million to resolve its liability to the District for all past costs to perform the riverwide RI/FS and all future costs to complete the work required by the Interim ROD. This amount was agreed to be paid in four equal annual installments beginning a year after the effective date of the Anacostia River Consent Decree. Pepco paid the first installment of $12 million on April 9, 2025. The funds were deposited into the DOEE’s Clean Land Fund for the District’s costs of the Interim ROD work. The Anacostia River Consent Decree caps Pepco’s liability for these costs and provides Pepco with the right to seek contributions from other PRPs. The Anacostia River Consent Decree was signed by the judge for the U.S. District Court for the District of Columbia and became effective on April 11, 2024. Exelon, PHI, and Pepco have accrued a liability for Pepco’s payment obligations under the Anacostia Consent Decree and management's best estimate of its share of any other future Anacostia River response costs. Pepco has concluded that incremental exposure remains reasonably possible, but management cannot reasonably estimate a range of loss beyond the amounts recorded, which are included in the table above.
In addition to the activities associated with the remedial process outlined above, CERCLA separately requires federal and state (here including Washington, D.C.) Natural Resource Trustees (federal or state agencies designated by the President or the relevant state, respectively, or Indian tribes) to conduct an assessment of any damages to natural resources within their jurisdiction as a result of the contamination that is being remediated. The Trustees can seek compensation from responsible parties for such damages, including restoration costs. During the second quarter of 2018, Pepco became aware that the Trustees are in the beginning stages of a NRD assessment, a process that often takes many years beyond the remedial decision to complete. Pepco has concluded that a loss associated with the eventual NRD assessment is reasonably possible. Due to the early stage of the NRD process, Pepco cannot reasonably estimate the final range of loss potentially resulting from this process. Pepco has become aware, however, that the District is pursuing claims against other parties. Specifically, in January 2025, D.C. OAG filed a lawsuit against the United States seeking to declare the United States liable under CERCLA and the District of Columbia’s Brownfield Revitalization Act of 2000 and to recover the District’s response costs associated with its investigation and remediation of Anacostia River sediment contamination and for future NRDs. Pepco is not a party to this suit, but Pepco, the United States, and the District of Columbia have entered mediation discussions to resolve their respective claims against one another under CERCLA and the Brownfield Revitalization Act with respect to the river. The court has put the case on hold pending the outcome of the mediation.
As noted in the Benning Road Site disclosure above, as part of the separation of Exelon and Constellation in February 2022, an assumption agreement was executed transferring any potential future remediation liabilities associated with the Benning Site remediation to a non-utility subsidiary of Exelon. Similarly, any potential future liability associated with the Anacostia River Sediment Project was also assumed by this entity.
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Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)

Note 16 — Commitments and Contingencies
Buzzard Point Site (Exelon, PHI, and Pepco). On December 8, 2022, Pepco received a letter from the D.C. OAG, alleging wholly past violations of the District's stormwater discharge and waste disposal requirements related to operations at the Buzzard Point facility, a 9-acre parcel of waterfront property in Washington, D.C. occupied by an active substation and former steam plant building. The letter also alleged wholly past violations by Pepco of stormwater discharge requirements related to its district-wide system of underground vaults. Pepco entered into a Consent Order with the District of Columbia to resolve the alleged violations without any admission of liability. The Consent Order requires Pepco to pay a civil penalty of $10 million. In addition, Pepco has agreed to assess the environmental conditions at its Buzzard Point facility and conduct any remedial actions deemed necessary as a result of the assessment, and also to assess potential environmental impacts associated with the operation of its underground vaults. The Superior Court for the District of Columbia signed and entered the Consent Order, and it became effective on February 2, 2024. Pepco is proceeding through the multi-step environmental investigation and response as outlined in the consent order. Specifically, the DOEE approved Pepco's Preliminary Site Assessment in July 2025. In September 2025, Pepco timely submitted its work plan for the second stage, the Supplemental Investigation Plan, which the DOEE approved in November 2025. Pepco also submitted an environmental assessment to the DOEE of the vault system pursuant to the Consent Order in July 2024. In response to the DOEE's comments, Pepco made revised submissions in May 2025, September 2025, and January 2026. The DOEE approved Pepco's vault system report on February 2, 2026. Exelon, PHI, and Pepco have accrued a liability for the projected costs for the required environmental assessments and remediation. In January 2025, Pepco paid the last installment of the civil penalty. Pepco has concluded that incremental exposure remains reasonably possible, but management cannot reasonably estimate a range of loss beyond the amounts recorded, which are included in the table above.
Litigation and Regulatory Matters
Fund Transfer Restrictions (All Registrants). Under applicable law, Exelon may borrow or receive an extension of credit from its subsidiaries. Under the terms of Exelon’s intercompany money pool agreement, Exelon can lend to, but not borrow from the money pool.
Under applicable law, ComEd, PECO, BGE, PHI, Pepco, DPL, and ACE can pay dividends only from retained, undistributed or current earnings. A significant loss recorded at ComEd, PECO, BGE, PHI, Pepco, DPL, or ACE may limit the dividends that these Registrants can distribute to Exelon.
ComEd has agreed in connection with financings arranged through ComEd Financing III that it will not declare dividends on any shares of its capital stock in the event that: (1) it exercises its right to extend the interest payment periods on the subordinated debt securities issued to ComEd Financing III; (2) it defaults on its guarantee of the payment of distributions on the preferred trust securities of ComEd Financing III; or (3) an event of default occurs under the Indenture under which the subordinated debt securities are issued. No such event has occurred.
PECO has agreed in connection with financings arranged through PEC L.P. and PECO Trust IV that PECO will not declare dividends on any shares of its capital stock in the event that: (1) it exercises its right to extend the interest payment periods on the subordinated debentures, which were issued to PEC L.P. or PECO Trust IV; (2) it defaults on its guarantee of the payment of distributions on the Series D Preferred Securities of PEC L.P. or the preferred trust securities of PECO Trust IV; or (3) an event of default occurs under the Indenture under which the subordinated debentures are issued. No such event has occurred.
BGE is subject to restrictions established by the MDPSC that prohibit BGE from paying a dividend on its common shares if (1) after the dividend payment, BGE’s equity ratio would be below 48% as calculated pursuant to the MDPSC’s ratemaking precedents or (2) 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 (1) after the dividend payment, Pepco's equity ratio would be below 48% as calculated pursuant to the MDPSC's and DCPSC's ratemaking precedents, of or (2) 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 (1) after the dividend payment, DPL's equity
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Combined Notes to Consolidated Financial Statements
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Note 16 — Commitments and Contingencies
ratio would be below 48% as calculated pursuant to the DEPSC's and MDPSC's ratemaking precedents, or (2) 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 (1) after the dividend payment, ACE's common equity ratio would be below 48% as calculated pursuant to the NJBPU's ratemaking precedents, or (2) ACE's senior corporate issuer or senior unsecured credit rating is rated by one of the three major credit rating agencies below investment grade. ACE is also subject to a dividend restriction which requires ACE to notify and obtain the prior approval of the NJBPU before dividends can be paid if its equity as a percent of its total capitalization, excluding securitization debt, falls below 30%. No such events have occurred.
DPA and Related Matters (Exelon and ComEd). Exelon and ComEd received a grand jury subpoena in the second quarter of 2019 from the U.S. Attorney’s Office for the Northern District of Illinois (USAO) requiring production of information concerning their lobbying activities in the State of Illinois. On October 4, 2019, Exelon and ComEd received a second grand jury subpoena from the USAO requiring production of records of any communications with certain individuals and entities. The Companies cooperated fully with the USAO and any government requests or inquiries. On July 17, 2020, ComEd entered into a DPA with the USAO to resolve the USAO investigation into its historical state legislative lobbying and related practices in Illinois. The agreement resolved the Department of Justice, investigation into both ComEd and Exelon. which included a payment to the U.S. Treasury of $200 million, which was paid in November 2020. The three-year term of the DPA ended on July 17, 2023, and on that same date the court granted the USAO’s motion to dismiss the pending charge against ComEd that had been deferred by the DPA.
Subsequent to Exelon announcing the receipt of the USAO subpoenas, various lawsuits were filed related to the subject of the subpoenas, and the conduct described in the DPA. Several putative class actions were brought in federal and state court by ComEd customers. These actions were dismissed prior to discovery or trial and those dismissals were affirmed on appeal. A putative class action alleging misrepresentations and omissions in Exelon’s SEC filings related to ComEd’s lobbying activities and the related investigations was also brought in federal court against Exelon and ComEd, which was subsequently settled.
In addition, subsequent to Exelon announcing the receipt of the USAO subpoenas, several shareholders sent letters to the Exelon Board of Directors demanding, among other things, that the Exelon Board of Directors investigate and address alleged breaches of fiduciary duties and other alleged violations by Exelon and ComEd officers and directors related to the conduct described in the DPA. In the first quarter of 2021, the Exelon Board of Directors appointed a Special Litigation Committee (SLC) consisting of disinterested and independent parties to investigate and address these shareholders’ allegations and make recommendations to the Exelon Board of Directors based on the outcome of the SLC’s investigation. In July 2021, one of the demand letter shareholders filed a derivative action against current and former Exelon and ComEd officers and directors, and against Exelon, as nominal defendant, asserting the same claims made in its demand letter. Since that date, multiple parties have filed separate derivative lawsuits that were subsequently consolidated. On October 12, 2021, the parties filed an agreed motion to stay the litigation for 120 days in order to allow the SLC to continue its investigation, which the court granted. The stay was extended several times. Through mediation efforts, a settlement of the derivative claims was reached by the SLC, the Independent Review Committee of the Board (which had been formed in the third quarter of 2022, to ensure the Board’s consideration of any SLC recommendations would be independent and objective), the Board, and certain of the derivative shareholders. On June 16, 2023, the SLC filed a motion for preliminary approval of the settlement, attaching the Stipulation and Agreement of Settlement (Stipulation), which contained the terms of the proposed settlement. The proposed settlement terms include but are not limited to: a payment of $40 million to Exelon by Exelon’s insurers of which $10 million constitutes the attorneys’ fee award to be paid to the Settling Shareholders’ counsel; various compliance and disclosure-related reforms; and certain changes in Board and Committee composition. The non-settling shareholders objected to the settlement and opposed preliminary approval. On September 20, 2024, the court denied without prejudice the SLC’s motion for preliminary approval. The court’s order provided that if the SLC can substantiate or otherwise revise the attorneys’ fees aspect of the settlement, then the SLC could renew its motion for preliminary approval by October 21, 2024. On October 21, 2024, the SLC filed its second renewed motion for preliminary approval, and the Settling Shareholders filed a brief in support of the SLC's second renewed motion for preliminary approval. On November 20, 2024, the non-settling plaintiffs filed an opposition to the renewed motion for preliminary approval. On December 18, 2024, the SLC and Settling Shareholders filed replies in support of the
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Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)

Note 16 — Commitments and Contingencies
renewed motion for preliminary approval. The court granted the renewed motion for preliminary approval on November 17, 2025, and set the final settlement approval hearing for March 18, 2026.

Maryland Sales and Use Tax Refund Claim (Exelon, BGE, PHI, Pepco, and DPL). Maryland imposes a 6% sales and use tax on the purchase of most goods and services. BGE, Pepco, and DPL have filed or plan to file protective refund claims, totaling an estimated $100 million, treating electric transmission and distribution machinery and equipment as nontaxable pursuant to the manufacturing exemption available under the Maryland sales and use tax law. The Maryland Comptroller has initially denied the refund claim and litigation is pending.
On November 22, 2024, the Appellate Court of Maryland, in a case involving a regulated electric utility operating in Maryland, ruled the purchase of certain transmission and distribution equipment qualify for the sales tax manufacturing exemption. On December 20, 2024, the Maryland Attorney General, on behalf of the Maryland Comptroller, filed a motion for reconsideration with the Appellate Court of Maryland of its ruling. The motion for reconsideration was denied on February 3, 2025.
On February 18, 2025, the Maryland Attorney General, on behalf of the Maryland Comptroller, filed a petition with the Maryland Supreme Court requesting review of the Appellate Court of Maryland's ruling. On April 24, 2025, the Maryland Supreme Court granted the petition to review the ruling. On October 1, 2025, the Maryland Supreme Court heard oral arguments in the case.
In the event transmission and distribution equipment is determined to be exempt, Exelon, BGE, PHI, Pepco, and DPL will record estimated receivables of $100 million, $65 million, $35 million, $25 million, and $10 million, respectively. The sales tax payments were primarily capitalized; therefore, the refund would be recorded as a reduction to PP&E included in rate base.
General (All Registrants). The Registrants are involved in various other litigation matters that are being defended and handled in the ordinary course of business. The Registrants are also from time to time subject to audits and investigations by the FERC and other regulators. The assessment of whether a loss is probable or reasonably possible, and whether the loss or a range of loss is estimable, often involves a series of complex judgments about future events. The Registrants maintain accruals for such losses that are probable of being incurred and subject to reasonable estimation. Management is sometimes unable to estimate an amount or range of reasonably possible loss, particularly where (1) the damages sought are indeterminate, (2) the proceedings are in the early stages, or (3) the matters involve novel or unsettled legal theories. In such cases, there is considerable uncertainty regarding the timing or ultimate resolution of such matters, including a possible eventual loss.

252



Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)

Note 17 — Shareholders' Equity
17. Shareholders' Equity (All Registrants)
At-the-Market Program (Exelon)
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 the following shares of Common stock in the years ended December 31, 2025, 2024, and 2023:

Effective Period
Shares Issued
(in millions)
Weighted-Average Price (a)
Net Proceeds (b)
(in millions)
2025 (c)
16.0$43.24 $691 
20244.0$37.60 $148 
20233.6$39.58 $140 
_________
(a)The 2025 weighted-average price is a net weighted-average price. The 2024 and 2023 weighted-average prices are the gross weighted-average prices as previously disclosed in the 2024 Form 10-K. The 2024 and 2023 weighted-average net prices are $37.04 and $38.99, respectively.
(b)Proceeds were used for general corporate purposes.
(c)In Q4 2025, Exelon settled the entire forward sale agreements with a December 15, 2025 maturity date that had been entered into by various forward sellers under the ATM program as outlined below.

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. The following forward sale agreements were entered into under Exelon’s ATM programs in 2025:
Effective PeriodShares Available
(in millions)		Weighted-Average Net PriceMaturity Date
Q1 20255.7$43.24 December 15, 2025
Q2 20256.2$43.51 December 15, 2025
Q2 20253.6$43.17 November 16, 2026
Q3 202511.5$43.73 December 15, 2026
Q4 20250.8$45.42 December 15, 2026
No amounts have been or will be recorded on Exelon's balance sheet 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.

253



Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)

Note 17 — Shareholders' Equity

ComEd Common Stock Warrants
The following table presents warrants outstanding to purchase ComEd common stock and shares of common stock reserved for the conversion of warrants. The warrants entitle the holders to convert such warrants into common stock of ComEd at a conversion rate of one share of common stock for three warrants.
December 31,
20252024
Warrants outstanding
59,960 59,970 
Common Stock reserved for conversion19,987 19,990 
Share Repurchases
There currently is no Exelon Board of Director authority to repurchase shares. Any previous shares repurchased are held as treasury shares, at cost, unless cancelled or reissued at the discretion of Exelon’s management.
Preferred and Preference Securities
The following table presents Exelon, ComEd, PECO, BGE, Pepco, and ACE's shares of preferred securities authorized, none of which were outstanding, as of December 31, 2025 and 2024. There are no shares of preferred securities authorized for DPL.
Preferred Securities Authorized
Exelon100,000,000 
ComEd850,000 
PECO15,000,000 
BGE1,000,000 
Pepco6,000,000 
ACE(a)
2,799,979 
_________
(a)Includes 799,979 shares of cumulative preferred stock and 2,000,000 of no par value preferred stock as of December 31, 2025 and 2024.
The following table presents ComEd, BGE, and ACE's preference securities authorized, none of which were outstanding as of December 31, 2025 and 2024. There are no shares of preference securities authorized for Exelon, PECO, Pepco, and DPL.
Preference Securities Authorized
ComEd6,810,451 
BGE(a)
6,500,000 
ACE3,000,000 
__________
(a)Includes 4,600,000 shares of unclassified preference securities and 1,900,000 shares of previously redeemed preference securities as of December 31, 2025 and 2024.

254



Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)

Note 18 — Stock-Based Compensation Plans
18. Stock-Based Compensation Plans (All Registrants)
Stock-Based Compensation Plans
Exelon grants stock-based awards through its LTIP, which primarily includes performance share awards and restricted stock units. At December 31, 2025, there were approximately 32 million shares authorized for issuance under the LTIP. For the years ended December 31, 2025, 2024, and 2023, exercised and distributed stock-based awards were primarily issued from authorized but unissued Common stock shares.
The Registrants grant cash awards. The following table does not include expense related to these plans as they are not considered stock-based compensation plans under the applicable authoritative guidance.
The following table presents the stock-based compensation expense included in Exelon's Consolidated Statements of Operations and Comprehensive Income. The Utility Registrants' stock-based compensation expense for the years ended December 31, 2025, 2024, and 2023 was not material.
Year Ended December 31,
Exelon202520242023
Total stock-based compensation expense included in Operating and maintenance expense$41 $34 $21 
Income tax benefit(10)(8)(5)
Total after-tax stock-based compensation expense$31 $26 $16 
Exelon receives a tax deduction based on the intrinsic value of the award on the distribution date for performance share awards and restricted stock units. For each award, throughout the requisite service period, Exelon recognizes the tax benefit related to compensation costs. The following table presents information regarding Exelon’s realized tax benefit when distributed:
Year Ended December 31,
202520242023
Performance share awards$6 $9 $8 
Restricted stock units3 4 6 
Performance Share Awards
Performance share awards are granted under the LTIP. The performance share awards granted in 2025 and 2024 are settled in common stock at the end of the three-year performance period. The performance share awards granted prior to 2024 are settled 50% in common stock and 50% in cash at the end of the three-year performance period, except for awards that are settled 100% in cash if certain ownership requirements are satisfied.
The common stock portion of the performance share awards is considered an equity award and is valued based on Exelon's stock price on the grant date. The cash portion of the performance share awards is considered a liability award which is remeasured each reporting period based on Exelon’s current stock price. As the value of the common stock and cash portions of the awards are based on Exelon’s stock price during the performance period, coupled with changes in the total shareholder return modifier and expected payout of the award, the compensation costs are subject to volatility until payout is established.
For nonretirement-eligible employees, stock-based compensation costs are recognized over the vesting period of three years using the straight-line method. For performance share awards granted to retirement-eligible employees, the value of the performance shares is recognized ratably over the vesting period, which is the year of grant for the employee who is retirement eligible prior to December 31 of the grant year or through the date of which the employee reaches retirement eligibility. Exelon processes forfeitures as they occur for employees who do not complete the requisite service period.
255



Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)

Note 18 — Stock-Based Compensation Plans
The following table summarizes Exelon’s nonvested performance share awards activity:
SharesWeighted Average
Grant Date Fair
Value (per share)
Nonvested at December 31, 2024(a)
611,525 $39.66 
Granted636,717 42.45 
Change in performance 150,204 39.29 
Vested(167,063)43.09 
Forfeited(139,898)40.22 
Undistributed vested awards(b)
(450,924)41.71 
Nonvested at December 31, 2025(a)
640,561 $39.87 
__________
(a)Excludes 1,083,128 and 635,526 of performance share awards issued to retirement-eligible employees as of December 31, 2025 and 2024, respectively, as they are fully vested.
(b)Represents performance share awards that vested but were not distributed to retirement-eligible employees during 2025.

The following table summarizes the weighted average grant date fair value and the total fair value of performance share awards vested.
Year Ended December 31,
2025(a)
20242023
Weighted average grant date fair value (per share)$42.45 $35.29 $41.82 
Total fair value of performance shares vested 25 27 17 
Total fair value of performance shares settled in cash16 27 26 
__________
(a)As of December 31, 2025, $8 million of total unrecognized compensation costs related to nonvested performance shares are expected to be recognized over the remaining weighted-average period of 1.8 years.
Restricted Stock Units
Restricted stock units are granted under the LTIP with the majority being settled in a specific number of shares of common stock after the service condition has been met. The corresponding cost of services is measured based on the grant date fair value of the restricted stock unit issued.
The value of the restricted stock units is expensed over the requisite service period using the straight-line method. The requisite service period for restricted stock units is generally three to five years. However, certain restricted stock unit awards become fully vested upon the employee reaching retirement-eligibility. For restricted stock units granted to retirement-eligible employees, the value of the restricted stock units is either recognized ratably over the first six months in the year of grant if the employee reaches retirement eligibility prior to July 1st of the grant year or through the date of which the employee reaches retirement eligibility. Exelon processes forfeitures as they occur for employees who do not complete the requisite service period.
256



Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)

Note 18 — Stock-Based Compensation Plans
The following table summarizes Exelon’s nonvested restricted stock unit activity:
SharesWeighted Average
Grant Date Fair
Value (per share)
Nonvested at December 31, 2024(a)
293,589 $39.29 
Granted338,787 40.47 
Vested (163,374)40.59 
Forfeited(63,960)39.05 
Undistributed vested awards(b)
(199,280)40.41 
Nonvested at December 31, 2025(a)
205,762 $39.19 
__________
(a)Excludes 363,156 and 126,732 of restricted stock units issued to retirement-eligible employees as of December 31, 2025 and 2024, respectively, as they are fully vested.
(b)Represents restricted stock units that vested but were not distributed to retirement-eligible employees during 2025.
The following table summarizes the weighted average grant date fair value and the total fair value of restricted stock units vested.
Year Ended December 31,
2025(a)
20242023
Weighted average grant date fair value (per share)$40.47 $35.54 $41.84 
Total fair value of restricted stock units vested15 21 15 
__________
(a)As of December 31, 2025, $4 million of total unrecognized compensation costs related to nonvested restricted stock units are expected to be recognized over the remaining weighted-average period of 1.8 years.


19. Changes in Accumulated Other Comprehensive Income (Loss) (Exelon)
The following table presents changes in Exelon's AOCI, net of tax, by component:
Cash Flow
Hedges
Pension and
Non-Pension
Postretirement
Benefit Plan
Items (a)
Total
Balance at December 31, 2022$2 $(640)

$(638)
OCI before reclassifications(4)(109)(113)
Amounts reclassified from AOCI(1)26 25 
Net current-period OCI$(5)$(83)$(88)
Balance at December 31, 2023$(3)$(723)$(726)
OCI before reclassifications52 (70)(18)
Amounts reclassified from AOCI(4)28 24 
Net current-period OCI$48 $(42)$6 
Balance at December 31, 2024$45 $(765)$(720)
OCI before reclassifications(7)(52)(59)
Amounts reclassified from AOCI(5)22 17 
Net current-period OCI$(12)$(30)$(42)
Balance at December 31, 2025$33 $(795)$(762)
__________ 
(a)This AOCI component is included in the computation of net periodic pension and OPEB cost. See Note 12 — Retirement Benefits for additional information. See Exelon's Statements of Operations and Comprehensive Income for individual components of AOCI.
257




Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)

Note 19 — Changes in Accumulated Other Comprehensive Income (Loss)
The following table presents Income tax benefit (expense) allocated to each component of Exelon's Other comprehensive income (loss):
 For the Years Ended December 31,
 202520242023
Pension and non-pension postretirement benefit plans:
Actuarial losses reclassified to periodic benefit cost$(9)$(10)$(8)
Pension and non-pension postretirement benefit plans valuation adjustments15 23 33 
Unrealized gains on cash flow hedges2 (15)2 
20. Supplemental Financial Information (All Registrants)
Supplemental Statement of Operations Information
The following tables provide additional information about material items recorded in the Registrants' Consolidated Statements of Operations and Comprehensive Income.
Taxes other than income taxes
ExelonComEdPECOBGEPHIPepcoDPLACE
For the Year Ended December 31, 2025
Utility(a)
$1,003 $319 $202 $112 $369 $335 $30 $4 
Property474 45 19 239 170 113 54 2 
Payroll135 37 18 18 29 6 4 3 
For the Year Ended December 31, 2024
Utility(a)
$925 $300 $179 $105 $341 $310 $27 $4 
Property431 32 19 221 159 108 48 3 
Payroll134 37 17 19 28 6 4 3 
For the Year Ended December 31, 2023
Utility(a)
$875 $299 $166 $97 $313 $283 $26 $4 
Property401 33 16 205 147 101 44 2 
Payroll124 31 17 18 27 6 5 3 
__________
(a)The Registrants’ utility taxes represents municipal and state utility taxes and gross receipts taxes related to their operating revenues. The offsetting collection of utility taxes from customers is recorded in revenues in the Registrants’ Consolidated Statements of Operations and Comprehensive Income.
Other, net
ExelonComEdPECOBGEPHIPepcoDPLACE
For the Year Ended December 31, 2025
AFUDC—Equity$183 $66 $36 $40 $41 $31 $6 $4 
Non-service net periodic benefit cost(52)— — — — — — — 
For the Year Ended December 31, 2024
AFUDC—Equity$157 $46 $32 $25 $54 $40 $12 $2 
Non-service net periodic benefit cost(38)— — — — — — — 
For the Year Ended December 31, 2023
AFUDC—Equity$151 $33 $31 $16 $71 $54 $10 $7 
Non-service net periodic benefit cost(18)— — — — — — — 

258



Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)

Note 20 — Supplemental Financial Information
Supplemental Cash Flow Information
The following tables provide additional information about material items recorded in the Registrants' Consolidated Statements of Cash Flows.
Depreciation, amortization, and accretion
ExelonComEdPECOBGEPHIPepcoDPLACE
For the Year Ended December 31, 2025
Property, plant, and equipment(a)
$3,043 $1,223 $451 $503 $810 $360 $226 $223 
Amortization of regulatory assets(a)
594 337 3 129 125 73 26 25 
Amortization of intangible assets, net(a)
3 — — — — — — — 
ARO accretion(b)
3 — — — 2 2 — — 
Total depreciation, amortization, and accretion$3,643 $1,560 $454 $632 $937 $435 $252 $248 
For the Year Ended December 31, 2024
Property, plant, and equipment(a)
$2,910 $1,167 $414 $490 $782 $336 $218 $211 
Amortization of regulatory assets(a)
676 347 14 148 164 70 27 67 
Amortization of intangible assets, net(a)
8 — — — — — — — 
ARO accretion(b)
2 — — — 1 1 — — 
Total depreciation and amortization$3,596 $1,514 $428 $638 $947 $407 $245 $278 
For the Year Ended December 31, 2023
Property, plant, and equipment(a)
$2,778 $1,095 $383 $509 $737 $311 $208 $195 
Amortization of regulatory assets(a)
720 308 14 145 253 130 36 88 
Amortization of intangible assets, net(a)
8 — — — — — — — 
Total depreciation, amortization, and accretion$3,506 $1,403 $397 $654 $990 $441 $244 $283 
__________
(a)Included in Depreciation and amortization expense in the Registrants' Consolidated Statements of Operations and Comprehensive Income.
(b)Included in Operating and maintenance expense in Exelon's Consolidated Statements of Operations and Comprehensive Income.
Cash paid (refunded) during the year
ExelonComEdPECOBGEPHIPepcoDPLACE
For the Year Ended December 31, 2025
Interest (net of amount capitalized)$2,021 $511 $242 $231 $392 $205 $96 $78 
Income taxes (net of refunds)12 224 (186)(95)114 88 20 11 
For the Year Ended December 31, 2024
Interest (net of amount capitalized)$1,849 $485 $218 $198 $355 $183 $89 $74 
Income taxes (net of refunds)81 250 128 100 150 96 57 20 
For the Year Ended December 31, 2023
Interest (net of amount capitalized)$1,616 $441 $200 $171 $301 $153 $69 $68 
Income taxes (net of refunds)10 11 (24)29 21 6 6 9 

259



Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)

Note 20 — Supplemental Financial Information
Other non-cash operating activities
ExelonComEdPECOBGEPHIPepcoDPLACE
For the Year Ended December 31, 2025
Pension and OPEB costs$273 $85 $7 $62 $96 $35 $17 $13 
Allowance for credit losses256 55 97 26 78 37 17 24 
True-up adjustments to decoupling mechanisms and formula rates(a)
746 596 — 87 63 49 16 (2)
Amortization of operating ROU asset28 — — 7 16 5 6 2 
Change in environmental liabilities — — — — 1 1 — — 
AFUDC - Equity(183)(66)(36)(41)(41)(31)(5)(4)
For the Year Ended December 31, 2024
Pension and OPEB costs (benefit)$252 $72 $(1)$59 $93 $32 $15 $12 
Allowance for credit losses208 23 91 25 69 30 10 28 
True-up adjustments to decoupling mechanisms and formula rates(a)
109 151 (6)(52)16 (15)10 21 
Amortization of operating ROU asset38 — — 6 26 6 6 3 
Change in environmental liabilities— — — — — — — — 
AFUDC - Equity(157)(46)(32)(25)(54)(40)(12)(2)
For the Year Ended December 31, 2023
Pension and OPEB costs (benefit)$198 $26 $(14)$56 $99 $34 $18 $13 
Allowance for credit losses125 4 45 16 60 33 10 17 
True-up adjustments to decoupling mechanisms and formula rates(a)
(708)(556)7 (84)(77)(22)(21)(34)
Amortization of operating ROU asset39 2 — 5 28 6 8 3 
Change in environmental liabilities37 — — — 37 37 — — 
AFUDC - Equity(151)(33)(31)(16)(71)(54)(10)(7)
__________
(a)For ComEd, reflects the true-up adjustments in Regulatory assets and liabilities associated with its distribution MRP and distribution, energy efficiency, distributed generation, and transmission formula rates. For PECO, reflects the change in Regulatory assets and liabilities associated with its transmission formula rate. For BGE, Pepco, DPL, and ACE, reflects the change in Regulatory assets and liabilities associated with their decoupling mechanisms and transmission formula rates. See Note 2 — Regulatory Matters for additional information.











260



Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)

Note 20 — Supplemental Financial Information
The following tables provide a reconciliation of cash, restricted cash, and cash equivalents reported within the Registrants' Consolidated Balance Sheets that sum to the total of the same amounts in their Consolidated Statements of Cash Flows.
Cash, restricted cash, and cash equivalents
ExelonComEdPECOBGEPHIPepcoDPLACE
Balance at December 31, 2025
Cash and cash equivalents$626 $159 $116 $217 $103 $22 $9 $22 
Restricted cash and cash equivalents525 454 — 3 38 33 3 2 
Restricted cash included in Other deferred debits and other assets50 50 — — — — — — 
Total cash, restricted cash, and cash equivalents$1,201 $663 $116 $220 $141 $55 $12 $24 
Balance at December 31, 2024
Cash and cash equivalents$357 $105 $48 $33 $139 $30 $21 $14 
Restricted cash and cash equivalents541 486 — 1 24 21 2 — 
Restricted cash included in Other deferred debits and other assets41 41 — — — — — — 
Total cash, restricted cash, and cash equivalents$939 $632 $48 $34 $163 $51 $23 $14 
Balance at December 31, 2023
Cash and cash equivalents$445 $110 $42 $47 $180 $48 $16 $21 
Restricted cash and cash equivalents482 402 9 1 24 24 — — 
Restricted cash included in Other deferred debits and other assets174 174 — — — — — — 
Total cash, restricted cash, and cash equivalents$1,101 $686 $51 $48 $204 $72 $16 $21 
Balance at December 31, 2022
Cash and cash equivalents$407 $67 $59 $43 $198 $45 $31 $72 
Restricted cash and cash equivalents566 327 9 24 175 54 121 — 
Restricted cash included in Other deferred debits and other assets117 117 — — — — — — 
Total cash, restricted cash, and cash equivalents$1,090 $511 $68 $67 $373 $99 $152 $72 
For additional information on restricted cash, see Note 1 — Significant Accounting Policies.
261



Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)

Note 20 — Supplemental Financial Information
Supplemental Balance Sheet Information
The following tables provide additional information about material items recorded in the Registrants' Consolidated Balance Sheets.
Investments
ExelonComEdPECOBGEPHIPepco
Balance at December 31, 2025
Rabbi trust investments(a)
$278 $— $38 $10 $157 $141 
Equity method investments15 6 7 — 1 — 
Other investments19 — — — — — 
Total investments$312 $6 $45 $10 $158 $141 
Balance at December 31, 2024
Rabbi trust investments(a)
$260 $— $34 $10 $151 $135 
Equity method investments15 6 7 — 1 — 
Other investments15 — — — — — 
Total investments$290 $6 $41 $10 $152 $135 
__________
(a)The Registrants’ debt and equity security investments and life insurance contracts are recorded at fair market value.

Accrued expenses
ExelonComEdPECOBGEPHIPepcoDPLACE
Balance at December 31, 2025
Compensation-related accruals(a)
$705 $209 $96 $99 $125 $35 $24 $17 
Taxes accrued242 94 306 191 107 69 25 18 
Interest accrued538 155 75 55 92 49 18 20 
Balance at December 31, 2024
Compensation-related accruals(a)
$679 $197 $87 $88 $132 $38 $26 $18 
Taxes accrued217 96 13 34 110 92 11 11 
Interest accrued468 150 60 50 83 44 16 18 
__________
(a)Primarily includes accrued payroll, bonuses and other incentives, vacation, and benefits.

262



Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)

Note 21 — Related Party Transactions
21. Related Party Transactions (All Registrants)
Service Company Costs for Corporate Support
The Registrants receive a variety of corporate support services from BSC. Pepco, DPL, and ACE also receive corporate support services from PHISCO. See Note 1 — Significant Accounting Policies for additional information regarding BSC and PHISCO.
The following table presents the service company costs allocated to the Registrants:
Operating and maintenance from affiliatesCapitalized costs from affiliates
For the years ended December 31,For the years ended December 31,
202520242023202520242023
Exelon
   BSC$683 $633 $670 
   PHISCO109 114 96 
ComEd
   BSC$404 $418 $353 279 254 307 
PECO
   BSC246 243 213 105 112 120 
BGE
   BSC251 246 221 123 110 90 
PHI
   BSC200 200 177 176 157 153 
   PHISCO— — — 109 114 95 
Pepco
   BSC126 125 114 76 70 59 
   PHISCO119 125 122 47 50 39 
DPL
   BSC80 78 73 52 49 43 
   PHISCO98 103 98 33 34 29 
ACE
   BSC64 64 59 40 32 47 
   PHISCO91 97 92 29 30 26 
Current Receivables from/Payables to Affiliates
The following tables present current Receivables from affiliates and current Payables to affiliates:
December 31, 2025
Receivables from affiliates:
Payables to affiliates:ComEdPECOBGEPepcoDPLACEBSCPHISCOOtherTotal
ComEd$— $— $— $— $— $76 $— $5 $81 
PECO$— — — — — 33 — 2 35 
BGE— — — — — 39 — — 39 
PHI— — — — — — 5 2 11 18 
Pepco— — — — — 25 11 1 37 
DPL— — — — — 15 10 — 25 
ACE— — — — — 14 10 — 24 
Other5 — 1 — 2 12 — — 20 
Total$5 $— $1 $— $2 $12 $207 $33 $19 $279 
263



Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)

Note 21 — Related Party Transactions
December 31, 2024
Receivables from affiliates:
Payables to affiliates:ComEdPECOBGEPepcoDPLACEBSCPHISCOOtherTotal
ComEd$— $— $— $— $— $67 $— $10 $77 
PECO$— — — — — 37 — 4 41 
BGE— — — — — 47 — 1 48 
PHI— — — — — — 7 1 10 18 
Pepco— — — — — 21 15 1 37 
DPL— — — — — 14 11 1 26 
ACE— — — — — 11 10 1 22 
Other4 — — 1 — 7 — — 12 
Total$4 $— $— $1 $— $7 $204 $37 $28 $281 
Borrowings from Exelon/PHI Intercompany Money Pool
To provide an additional short-term borrowing option that will generally be more favorable to the borrowing participants than the cost of external financing both Exelon and PHI operate an intercompany money pool. PECO and PHI Corporate participate in the Exelon money pool. Pepco, DPL, and ACE participate in the PHI intercompany money pool.
Long-term Debt to Financing Trusts
The following table presents Long-term debt to financing trusts:
At December 31,
20252024
ExelonComEdPECOExelonComEdPECO
ComEd Financing III$206 $206 $— $206 $206 $— 
PECO Trust III81 — 81 81 — 81 
PECO Trust IV103 — 103 103 — 103 
Total$390 $206 $184 $390 $206 $184 
Charitable Contributions
In December 2025, Exelon Corporation made an unconditional promise to give $30 million to the Exelon Foundation. The contribution was recorded in Operating and maintenance expense within the Consolidated Statements of Operations and Comprehensive Income with the offset in Other current liabilities on the Consolidated Balance Sheets.

264





ITEM 9.CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
All Registrants
None.
ITEM 9A.CONTROLS AND PROCEDURES
All Registrants—Disclosure Controls and Procedures
During the fourth quarter of 2025, each of the Registrant's management, including its principal executive officer and principal financial officer, evaluated disclosure controls and procedures (as defined in Exchange Act Rules 13a‑15(e) and 15d‑15(e)) as of the end of the period covered by this report, pursuant to Exchange Act Rules 13a‑15(b) and 15d‑15(b). These disclosure controls and procedures have been designed by the Registrants to ensure that (a) material information relating to that Registrant, including its consolidated subsidiaries, is accumulated and made known to that Registrant’s management, including its principal executive officer and principal financial officer, by other employees of that Registrant and its subsidiaries as appropriate to allow timely decisions regarding required disclosure, and (b) this information is recorded, processed, summarized, evaluated, and reported, as applicable, within the time periods specified in the SEC’s rules and forms. Due to the inherent limitations of control systems, not all misstatements may be detected. These inherent limitations include the realities that judgments in decision-making can be faulty and that breakdowns can occur because of simple error or mistake. Additionally, controls could be circumvented by the individual acts of some persons or by collusion of two or more people.
Accordingly, as of December 31, 2025, the principal executive officer and principal financial officer of each of the Registrants concluded that such Registrant’s disclosure controls and procedures were effective. (Item 307 of Regulation S‑K).
All Registrants—Changes in Internal Control Over Financial Reporting
Each Registrant continually strives to improve its disclosure controls and procedures to enhance the quality of its financial reporting and to maintain dynamic systems that change as conditions warrant. However, there were no changes in internal control over financial reporting (as defined in Exchange Act Rules 13a‑15(d) and 15d‑15(d)) that occurred during the fourth quarter of 2025 that have materially affected, or are reasonably likely to materially affect, any of the Registrants' internal control over financial reporting.
All Registrants—Internal Control Over Financial Reporting
Management is required to assess and report on the effectiveness of its internal control over financial reporting (as defined in Exchange Act Rules 13a‑15(f)) as of December 31, 2025. As a result of that assessment, management determined that there were no material weaknesses as of December 31, 2025 and therefore concluded that each Registrant’s internal control over financial reporting was effective. Management’s Report on Internal Control Over Financial Reporting is included in ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.

ITEM 9B.OTHER INFORMATION
All Registrants
None of our officers or directors, as defined in Rule 16a-1(f) of the Securities Exchange Act of 1934, adopted, modified, or terminated a “Rule 10b5-1 trading arrangement” or a “non-Rule 10b5-1 trading arrangement,” as defined in Item 408 of Regulation S-K, during the three months ended December 31, 2025.

265



ITEM 9C.DISCLOSURE REGARDING FOREIGN JURISDICTIONS THAT PREVENT INSPECTIONS
Not Applicable
266



PART III 
PECO, BGE, PHI, Pepco, DPL, and ACE meet the conditions set forth in General Instruction (I)(1)(a) and (b) of Form 10-K for a reduced disclosure format. Accordingly, all items in this section relating to PECO, BGE, PHI, Pepco, DPL, and ACE are not presented.

ITEM 10.DIRECTORS, EXECUTIVE OFFICERS, AND CORPORATE GOVERNANCE
Executive Officers
The information required by ITEM 10 relating to executive officers is set forth above in ITEM 1. BUSINESS—Executive Officers of the Registrants as of February 12, 2026.
Directors, Director Nomination Process and Audit Committee
The information required under ITEM 10 concerning directors and nominees for election as directors at the annual meeting of shareholders (Item 401 of Regulation S-K), compliance with Section 16(a) of the Exchange Act (Item 405 of Regulation S-K), the director nomination process (Item 407(c)(3)), and the audit committee (Item 407(d)(4) and (d)(5)) is incorporated herein by reference to information to be contained in Exelon’s Proxy Statement for the 2026 Annual Meeting of Shareholders (2026 Exelon Proxy Statement) and the ComEd information statement (2026 ComEd Information Statement) to be filed with the SEC on or before April 30, 2026 pursuant to Regulation 14A or 14C, as applicable, under the Securities Exchange Act of 1934.
Code of Ethics
Exelon’s Code of Business Conduct is the code of ethics that applies to all directors, officers, and employees of the Registrants and their subsidiaries. The Code of Business Conduct is filed as Exhibit 14 to this report and is available on Exelon’s website at www.exeloncorp.com. The Code of Business Conduct will be made available, without charge, in print to any shareholder who requests such document from Exelon's Corporate Secretary, 10 South Dearborn Street, P.O. Box 805398, Chicago, Illinois 60680-5398.
If any substantive amendments to the Code of Business Conduct are made or any waivers are granted, including any implicit waiver, from a provision of the Code of Business Conduct, to its Chief Executive Officer, Chief Financial Officer or Corporate Controller, Exelon will disclose the nature of such amendment or waiver on Exelon’s website, www.exeloncorp.com, or in a report on Form 8-K.
Insider Trading Policy
Exelon has adopted insider trading policies and procedures governing transactions in securities of the Registrants and their subsidiaries by directors, officers, and employees, or the Registrants themselves, that are reasonably designed to promote compliance with insider trading laws, rules and regulations, and any listing standards applicable to the Registrants. A copy of the Exelon Insider Trading Policy is filed as Exhibit 19.1 to this Annual Report on Form 10-K.

267



ITEM 11.EXECUTIVE COMPENSATION
The information required by this item will be set forth under the sections captioned "Compensation Discussion and Analysis" and "Talent Management and Compensation Committee Report" in the 2026 Exelon Proxy Statement or the section captioned "Executive Compensation" in the 2026 ComEd Information Statement, which are incorporated herein by reference.

268



ITEM 12.SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS
The additional information required by this item will be set forth under Ownership of Exelon Stock in the 2026 Exelon Proxy Statement or the 2026 ComEd Information Statement, which are incorporated herein by reference.

No ComEd securities are authorized for issuance under equity compensation plans.
Securities Authorized for Issuance under Exelon Equity Compensation Plans
[A][B][C]
Plan CategoryNumber of securities to
be issued upon
exercise of outstanding
Options, warrants and
rights (Note 1)		Weighted-average
price of outstanding
Options, warrants
and rights (Note 2)		Number of securities
remaining available
for future issuance
under equity
compensation plans
(excluding securities
reflected in
column [A]) (Note 3)
Equity compensation plans approved by security holders3,786,845 $— 37,917,762 
__________
(1)The equity compensation plans approved by the Company’s shareholders are the Exelon Corporation 2020 Long-Term Incentive Plan and the Exelon Corporation Employee Stock Purchase Plan, as amended and restated effective September 25, 2019. See Note 18 — Stock-Based Compensation Plans of the Combined Notes to Consolidated Financial Statements for additional information about the material features of the plans.
The number in column (A) includes: (i) 586,598 unvested restricted stock units and 2,906,398 unvested performance shares that were granted under the Exelon LTIP or predecessor company plans (including shares awarded under those plans and deferred into the stock deferral plan), both including accrued and reinvested dividends, and (ii) 293,849 deferred stock units granted to directors as part of their compensation.
For reporting purposes, the number of unvested performance shares includes: (i) the 2023-2025 performance share awards at maximum payout, assuming half of the shares are settled in cash and half in Exelon stock; and (ii) the 2024-2026 and 2025-2027 performance share awards at maximum payout, assuming settlement all in Exelon stock, pursuant to the terms of the long-term incentive program. Performance share awards may be paid between 0% and 200% of target, depending on the achievement of performance goals established for such awards.
(2)There are no outstanding stock options. The weighted-average price reported in column B does not take the performance shares and shares credited to deferred compensation plans into account.
(3)Includes 9,200,672 shares remaining available for issuance from the employee stock purchase plan.


269



ITEM 13.CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR INDEPENDENCE
The additional information required by this item will be set forth under the sections captioned "Related Person Transactions" and "Director Independence" in the 2026 Exelon Proxy Statement or the sections captioned "Related Person Transactions," "Independence Standards," and "Director Nominees" in the 2026 ComEd Information Statement, which are incorporated herein by reference.

270



ITEM 14.PRINCIPAL ACCOUNTING FEES AND SERVICES
The information required by this item will be set forth under the section captioned "Ratification of PricewaterhouseCoopers LLP as Exelon’s Independent Auditor for 2026" in the 2026 Exelon Proxy Statement and the section captioned "Audit Matters" in the 2026 ComEd Information Statement, which are incorporated herein by reference.
271



PART IV
ITEM 15.EXHIBITS, FINANCIAL STATEMENT SCHEDULES
(a)The following documents are filed as a part of this report:
(1) Exelon
(i)Financial Statements (Item 8):
  
Report of Independent Registered Public Accounting Firm dated February 12, 2026 of PricewaterhouseCoopers LLP (PCAOB ID 238)
  Consolidated Statements of Operations and Comprehensive Income for the Years Ended December 31, 2025, 2024, and 2023
  Consolidated Statements of Cash Flows for the Years Ended December 31, 2025, 2024, and 2023
  Consolidated Balance Sheets at December 31, 2025 and 2024
  Consolidated Statements of Changes in Equity for the Years Ended December 31, 2025, 2024, and 2023
  Notes to Consolidated Financial Statements
(ii)  Financial Statement Schedules:
  Schedule I—Condensed Financial Information of Parent (Exelon Corporate) at December 31, 2025 and 2024 and for the Years Ended December 31, 2025, 2024, and 2023
  Schedule II—Valuation and Qualifying Accounts for the Years Ended December 31, 2025, 2024, and 2023
  Schedules not included are omitted because of the absence of conditions under which they are required or because the required information is provided in the consolidated financial statements, including the notes thereto.
272



Exelon Corporation and Subsidiary Companies
 Schedule I – Condensed Financial Information of Parent (Exelon Corporate)
Condensed Statements of Operations and Other Comprehensive Income
 
 For the Years Ended December 31,
(In millions)202520242023
Operating expenses
Operating and maintenance$92 $7 $88 
Operating and maintenance from affiliates8 8 7 
Other1 1 1 
Total operating expenses101 16 96 
Operating loss(101)(16)(96)
Other income and (deductions)
Interest expense, net(684)(593)(544)
Equity in earnings of investments3,335 2,887 2,728 
Interest income from affiliates, net11 15 9 
Other, net28 22 19 
Total other income and (deductions)2,690 2,331 2,212 
Income from before income taxes2,589 2,315 2,116 
Income taxes(179)(145)(212)
Net income$2,768 $2,460 $2,328 
Other comprehensive income (loss), net of income taxes
Pension and non-pension postretirement benefit plans:
Actuarial losses reclassified to periodic benefit cost22 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$2,726 $2,466 $2,240 

See the Notes to Financial Statements

273
Exelon Corporation and Subsidiary Companies
Schedule I – Condensed Financial Information of Parent (Exelon Corporate)
Condensed Statements of Cash Flows
 
 For the Years Ended December 31,
(In millions)202520242023
Net cash flows provided by operating activities$1,775 $2,022 $1,486 
Cash flows from investing activities
Changes in Exelon intercompany money pool(33)8 (43)
Investment in affiliates(2,055)(1,568)(1,864)
Other investing activities(1)(2)(1)
Net cash flows used in investing activities(2,089)(1,562)(1,908)
Cash flows from financing activities
Changes in short-term borrowings(427)(99)78 
Proceeds from short-term borrowings with maturities greater than 90 days— 150 — 
Repayments on short-term borrowings with maturities greater than 90 days(500)(150)— 
Issuance of long-term debt3,000 1,700 2,500 
Retirement of long-term debt(810)(715)(850)
Issuance of common stock691 148 140 
Dividends paid on common stock(1,615)(1,523)(1,433)
Proceeds from employee stock plans35 43 41 
Other financing activities(40)(36)(39)
Net cash flows provided by (used in) financing activities334 (482)437 
Increase (decrease) in cash, restricted cash, and cash equivalents20 (22)15 
Cash, restricted cash, and cash equivalents at beginning of period4 26 11 
Cash, restricted cash, and cash equivalents at end of period$24 $4 $26 
See the Notes to Financial Statements

274
Exelon Corporation and Subsidiary Companies
Schedule I – Condensed Financial Information of Parent (Exelon Corporate)
Condensed Balance Sheets
 
 December 31,
(In millions)20252024
ASSETS
Current assets
Cash and cash equivalents$24 $4 
Accounts receivable, net
Other accounts receivable622 288 
Accounts receivable from affiliates10 19 
Notes receivable from affiliates250 217 
Regulatory assets165 186 
Other7 19 
Total current assets1,078 733 
Property, plant, and equipment, net45 45 
Deferred debits and other assets
Regulatory assets2,925 2,851 
Investments in affiliates43,670 40,741 
Deferred income taxes546 747 
Non-pension postretirement benefit asset128 186 
Other136 149 
Total deferred debits and other assets47,405 44,674 
Total assets$48,528 $45,452 
See the Notes to Financial Statements

275
Exelon Corporation and Subsidiary Companies
Schedule I – Condensed Financial Information of Parent (Exelon Corporate)
Condensed Balance Sheets
 
 December 31,
(In millions)20252024
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities
Short-term borrowings$— $927 
Long-term debt due within one year750 807 
Accounts payable177 142 
Accrued expenses188 155 
Payables to affiliates361 360 
Regulatory liabilities8 11 
Pension obligations36 40 
Other46 3 
Total current liabilities1,566 2,445 
Long-term debt13,547 11,334 
Deferred credits and other liabilities
Regulatory liabilities89 94 
Pension obligations4,398 4,346 
Deferred income taxes53 50 
Other77 262 
Total deferred credits and other liabilities4,617 4,752 
Total liabilities19,730 18,531 
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 earnings7,577 6,426 
Accumulated other comprehensive loss, net(762)(720)
Total shareholders’ equity28,798 26,921 
Total liabilities and shareholders’ equity$48,528 $45,452 

See the Notes to Financial Statements

276
 Exelon Corporation and Subsidiary Companies 
Schedule I – Condensed Financial Information of Parent (Exelon Corporate)
 Notes to Financial Statements
1. Basis of Presentation
Exelon Corporate is a holding company that conducts substantially all of its business operations through its subsidiaries. These condensed financial statements and related footnotes have been prepared in accordance with Rule 12-04, Schedule I of Regulation S-X. These statements should be read in conjunction with the consolidated financial statements, and notes thereto, of Exelon Corporation.
As of December 31, 2025, 2024, and 2023, Exelon Corporate owned 100% of all of its significant subsidiaries, either directly or indirectly, except for Commonwealth Edison Company (ComEd), of which Exelon Corporate owns more than 99%.
2. Regulatory Matters and Retirement Benefits
See Note 2—Regulatory Matters and Note 12—Retirement Benefits of the Combined Notes to Consolidated Financial Statements for Exelon Corporate’s regulatory assets and retirement benefits.
3. Derivative Financial Instruments
See Note 13—Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for Exelon Corporate’s derivatives.
4. Debt and Credit Agreements
Short-Term Borrowings
Exelon Corporate meets its short-term liquidity requirements primarily through the issuance of commercial paper. Exelon Corporate had no outstanding commercial paper borrowings as of December 31, 2025 and $426 million outstanding commercial paper as of December 31, 2024.
Revolving Credit Agreements
On August 29, 2024, Exelon Corporate entered into a revolving credit facility with an aggregate bank commitment of $900 million at a variable interest rate of SOFR plus 1.075%, which replaced its existing $900 million syndicated revolving credit facility, and extended the maturity date to August 29, 2029.
As of December 31, 2025, Exelon Corporate had a $900 million aggregate bank commitment under its existing syndicated revolving facility in which $897 million was available to support additional commercial paper as of December 31, 2025. Exelon Corporate had $3 million outstanding letters of credit as of December 31, 2025. See Note 14 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information regarding Exelon Corporate’s credit agreement.
Exelon Corporate had no outstanding amounts on the revolving credit facilities as of December 31, 2025.
Short-Term Loan Agreements
On March 23, 2017, Exelon Corporate entered into a term loan agreement for $500 million. The loan agreement was renewed in the first quarter of 2024 and was bifurcated into two tranches of $350 million and $150 million on March 14, 2024. The loan agreements were renewed in the first quarter of 2025, extending the expiration date to March 13, 2026 with a variable interest rate equal to SOFR plus 1.00%. Exelon Corporate repaid the term loan on December 5, 2025.
277

Exelon Corporation and Subsidiary Companies 
Schedule I – Condensed Financial Information of Parent (Exelon Corporate)
 Notes to Financial Statements
Convertible Senior Notes
On December 4, 2025, Exelon Corporation issued $1 billion aggregate principal amount of 3.25% Convertible Senior Notes due 2029. The Convertible Senior Notes bear interest at 3.25% per year, payable semiannually, and mature on March 15, 2029. The Convertible Notes are convertible into cash or a combination of cash and shares of common stock at Exelon's discretion, with an initial conversion price of approximately $57.11 per share. See Note 14 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information on the Convertible Senior Notes.
Debt Extinguishment
During the twelve months ended December 31, 2024, Exelon Corporate repurchased a portion of its Senior unsecured notes with a principal balance of $244 million outstanding in exchange for cash of $215 million. The repurchase was accounted for as a debt extinguishment and resulted in a pre-tax gain of $28 million, which is reflected on Exelon Corporate's Condensed Statement of Operations and Comprehensive income within Interest expense, net.
Long-Term Debt
The following tables present the outstanding long-term debt for Exelon Corporate at December 31, 2025 and December 31, 2024:
 Maturity
Date		December 31,
 Rates20252024
Long-term debt
Senior unsecured notes2.75 %-7.60 %2026 - 2055$13,288 $12,095 
Junior subordinated notes6.50 %20551,000 — 
Total long-term debt14,288 12,095 
Unamortized debt discount and premium, net(24)(24)
Unamortized debt issuance costs(96)(71)
Fair value adjustment129 141 
Long-term debt due within one year(a)
(750)(807)
Long-term debt$13,547 $11,334 

The long-term debt maturities for Exelon Corporate for the periods 2026 through 2030 and thereafter are as follows:
2026$750 
2027650 
20281,000 
20291,650 
20301,250 
Thereafter8,988 
Total long-term debt$14,288 
5. Commitments and Contingencies
See Note 16—Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for Exelon Corporate’s commitments and contingencies.

6. Related Party Transactions
278

Exelon Corporation and Subsidiary Companies 
Schedule I – Condensed Financial Information of Parent (Exelon Corporate)
 Notes to Financial Statements
The financial statements of Exelon Corporate include related party transactions as presented in the tables below:
 For the Years Ended December 31,
(In millions)202520242023
Operating and maintenance from affiliates:
        BSC(a)
$8 $8 $7 
Total operating and maintenance from affiliates:$8 $8 $7 
Interest income (expense) from affiliates, net:
BSC$8 $11 $6 
EEDC(b)
3 4 3 
Total interest income from affiliates, net:$11 $15 $9 
Equity in earnings (losses) of investments:
EEDC(b)
$3,339 $2,886 $2,727 
PCI3 3 2 
Connectiv, LLC(1)(2)— 
Exelon Enterprises1 — 1 
Exelon InQB8R— — (2)
Exelon Transmission Company(6)— — 
Other(1)— — 
Total equity in earnings of investments:$3,335 $2,887 $2,728 
Cash contributions received from affiliates$2,464 $2,250 $1,978 

279

Exelon Corporation and Subsidiary Companies 
Schedule I – Condensed Financial Information of Parent (Exelon Corporate)
 Notes to Financial Statements
 At December 31,
(in millions)20252024
Accounts receivable from affiliates (current):
BSC$2 $2 
ComEd1 5 
PECO— 3 
BGE— 2 
PHISCO7 7 
Total accounts receivable from affiliates (current):$10 $19 
Notes receivable from affiliates (current):
BSC(a)
$170 $154 
PHI
80 63 
Total notes receivable from affiliates (current):$250 $217 
Investments in affiliates:
BSC(a)
$384 $384 
EEDC(b)
42,847 39,905 
PCI60 57 
UII360 365 
Voluntary Employee Beneficiary Association trust5 — 
Exelon Enterprises5 4 
Conectiv13 14 
Exelon InQB8R— 13 
Other(4)(1)
Total investments in affiliates:$43,670 $40,741 
Accounts payable to affiliates (current):
UII$361 $360 
BSC(a)
— — 
Total accounts payable to affiliates (current):$361 $360 
__________
(a)Exelon Corporate receives a variety of corporate support services from BSC, including legal, human resources, financial, information technology, and supply management services. All services are provided at cost, including applicable overhead.
(b)EEDC consists of ComEd, PECO, BGE, PHI, Pepco, DPL, and ACE.

Charitable Contributions
In December 2025, Exelon Corporation made an unconditional promise to give $30 million to the Exelon Foundation. The contribution was recorded in Operating and maintenance expense within the Condensed Statements of Operations and Comprehensive Income with the offset in Other current liabilities on the Condensed Balance Sheets.

280

Exelon Corporation and Subsidiary Companies 
Schedule II – Valuation and Qualifying Accounts
Column AColumn BColumn CColumn DColumn E
Additions and adjustments
DescriptionBalance at
Beginning
of Period		Charged to
Costs and
Expenses		Charged
to Other
Accounts		DeductionsBalance at
End
of Period
(In millions)
For the year ended December 31, 2025
Allowance for credit losses(a)
$513 

$290 
(b)
$23 $297 
(c)
$529 
Deferred tax valuation allowance120 

— 

20 — 140 
For the year ended December 31, 2024



Allowance for credit losses(a)
$399 

$271 
(b)
$22 

$179 
(c)
$513 
Deferred tax valuation allowance114 

— 

6 — 120 
For the year ended December 31, 2023



Allowance for credit losses(a)
$409 

$171 
(b)
$20 $201 
(c)
$399 
Deferred tax valuation allowance94 

— 

20 

— 114 
__________
(a)Excludes the noncurrent Allowance for credit losses related to PECO’s installment plan receivables of $13 million, $13 million, and $6 million for the years ended December 31, 2025, 2024, and 2023, respectively.
(b)The amount charged to costs and expenses includes the amount reclassified to Regulatory assets/liabilities under different mechanisms applicable to the different jurisdictions in which the Utility Registrants operate.
(c)Primarily reflects write-offs, net of recoveries, of individual accounts receivable.


281

Commonwealth Edison Company and Subsidiary Companies
(2) ComEd
(i)Financial Statements (Item 8):
Report of Independent Registered Public Accounting Firm dated February 12, 2026 of PricewaterhouseCoopers LLP (PCAOB ID 238)
Consolidated Statements of Operations and Comprehensive Income for the Years Ended December 31, 2025, 2024, and 2023
Consolidated Statements of Cash Flows for the Years Ended December 31, 2025, 2024, and 2023
Consolidated Balance Sheets at December 31, 2025 and 2024
Consolidated Statements of Changes in Shareholders’ Equity for the Years Ended December 31, 2025, 2024, and 2023
Notes to Consolidated Financial Statements
(ii)Financial Statement Schedule:
Schedule II—Valuation and Qualifying Accounts for the Years Ended December 31, 2025, 2024, and 2023
Schedules not included are omitted because of the absence of conditions under which they are required or because the required information is provided in the consolidated financial statements, including the notes thereto
282

Commonwealth Edison Company and Subsidiary Companies
Schedule II – Valuation and Qualifying Accounts
Column AColumn BColumn CColumn DColumn E
Additions and adjustments
DescriptionBalance at
Beginning
of Period		Charged to
Costs and
Expenses		Charged
to Other
Accounts		DeductionsBalance at
End
of Period
(In millions)
For the year ended December 31, 2025
Allowance for credit losses$143 $80 
(a)
$20 $105 
(b)
$138 
For the year ended December 31, 2024

Allowance for credit losses$86 $71 
(a)
$28 $42 
(b)
$143 
For the year ended December 31, 2023

Allowance for credit losses$76 $45 
(a)
$13 $48 
(b)
$86 
__________
(a)ComEd is allowed to recover from or refund to customers the difference between its annual credit loss expense and the amounts collected in rates annually through a rider mechanism. The amount charged to costs and expenses includes the amount that was reclassified to Regulatory assets/liabilities under such mechanism. See Note 2 – Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.
(b)Write-offs, net of recoveries of individual accounts receivable.
283

PECO Energy Company and Subsidiary Companies
(3) PECO
(i)Financial Statements (Item 8):
Report of Independent Registered Public Accounting Firm dated February 12, 2026 of PricewaterhouseCoopers LLP (PCAOB ID 238)
Consolidated Statements of Operations and Comprehensive Income for the Years Ended December 31, 2025, 2024, and 2023
Consolidated Statements of Cash Flows for the Years Ended December 31, 2025, 2024, and 2023
Consolidated Balance Sheets at December 31, 2025 and 2024
Consolidated Statements of Changes in Shareholder's Equity for the Years Ended December 31, 2025, 2024, and 2023
Notes to Consolidated Financial Statements
(ii)Financial Statement Schedule:
Schedule II—Valuation and Qualifying Accounts for the Years Ended December 31, 2025, 2024, and 2023
Schedules not included are omitted because of the absence of conditions under which they are required or because the required information is provided in the consolidated financial statements, including the notes thereto
284

PECO Energy Company and Subsidiary Companies
Schedule II – Valuation and Qualifying Accounts
Column AColumn BColumn CColumn DColumn E
  Additions and adjustments
DescriptionBalance at
Beginning
of Period		Charged to
Costs and
Expenses		Charged
to Other
Accounts		DeductionsBalance at
End
of Period
(In millions)
For the year ended December 31, 2025
Allowance for credit losses(a)
$151 

$98 $7 $101 
(c)
$155 
Deferred tax valuation allowance6 — — — 6 
For the year ended December 31, 2024

Allowance for credit losses(a)
$103 $88 $(1)$39 
(c)
$151 
Deferred tax valuation allowance7 — (1)— 6 
For the year ended December 31, 2023

Allowance for credit losses(a)
$114 $43 
(b) 
$9 $63 
(c)
$103 
Deferred tax valuation allowance7 — — — 7 
__________
(a)Excludes the noncurrent Allowance for credit losses related to PECO’s installment plan receivables of $13 million, $13 million, and $6 million for the years ended December 31, 2025, 2024, and 2023, respectively.
(b)The amount charged to costs and expenses includes the amount that was reclassified to the COVID-19 regulatory asset. See Note 2 – Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.
(c)Write-offs, net of recoveries of individual accounts receivable.

285

Baltimore Gas and Electric Company
(4) BGE
(i)Financial Statements (Item 8):
Report of Independent Registered Public Accounting Firm dated February 12, 2026 of PricewaterhouseCoopers LLP (PCAOB ID 238)
Statements of Operations and Comprehensive Income for the Years Ended December 31, 2025, 2024 and 2023
Statements of Cash Flows for the Years Ended December 31, 2025, 2024 and 2023
Balance Sheets at December 31, 2025 and 2024
Statements of Changes in Shareholder's Equity for the Years Ended December 31, 2025, 2024 and 2023
Notes to Financial Statements
(ii)Financial Statement Schedule:
Schedule II—Valuation and Qualifying Accounts for the Years Ended December 31, 2025, 2024, and 2023
Schedules not included are omitted because of the absence of conditions under which they are required or because the required information is provided in the consolidated financial statements, including the notes thereto
286

Baltimore Gas and Electric Company
Schedule II – Valuation and Qualifying Accounts
Column AColumn BColumn CColumn DColumn E
Additions and adjustments
DescriptionBalance at
Beginning
of Period		Charged to
Costs and
Expenses		Charged
to Other
Accounts		DeductionsBalance at
End
of Period
(In millions)
For the year ended December 31, 2025
Allowance for credit losses$62 

$44 
(a)
$(3)

$31 
(b)
$72 
Deferred tax valuation allowance3 

— — 

— 3 
For the year ended December 31, 2024


Allowance for credit losses$53 $39 
(a)
$4 

$34 
(b)
$62 
Deferred tax valuation allowance3 — — 

— 3 
For the year ended December 31, 2023


Allowance for credit losses$64 $26 
(a)
$5 

$42 
(b)
$53 
Deferred tax valuation allowance3 — — — 3 
__________
(a)The amount charged to costs and expenses includes the amount that was reclassified to Regulatory assets/liabilities under different mechanisms as approved by the MDPSC.
(b)Write-offs, net of recoveries of individual accounts receivable.

287

Pepco Holdings LLC and Subsidiary Companies
(5) PHI
(i)Financial Statements (Item 8):
Report of Independent Registered Public Accounting Firm dated February 12, 2026 of PricewaterhouseCoopers LLP (PCAOB ID 238)
Consolidated Statements of Operations and Comprehensive Income for the Years Ended December 31, 2025, 2024, and 2023
Consolidated Statements of Cash Flows for the Years Ended December 31, 2025, 2024, and 2023
Consolidated Balance Sheets at December 31, 2025 and 2024
Consolidated Statements of Changes in Member's Equity for the Years Ended December 31, 2025, 2024, and 2023
Notes to Consolidated Financial Statements
(ii)Financial Statement Schedule:
Schedule II—Valuation and Qualifying Accounts for the Years Ended December 31, 2025, 2024, and 2023
Schedules not included are omitted because of the absence of conditions under which they are required or because the required information is provided in the consolidated financial statements, including the notes thereto
288

Pepco Holdings LLC and Subsidiary Companies
Schedule II – Valuation and Qualifying Accounts
Column AColumn BColumn CColumn DColumn E
Additions and adjustments
DescriptionBalance at
Beginning
of Period		Charged to
Costs and
Expenses		Charged
to Other
Accounts		DeductionsBalance at
End
of Period
(In millions)
For the year ended December 31, 2025
Allowance for credit losses$157 $68 
(a)
$(1)$60 
(b)
$164 
Deferred tax valuation allowance32 — — — 32 
For the year ended December 31, 2024
Allowance for credit losses$157 $73 
(a)
$(9)$64 
(b)
$157 
Deferred tax valuation allowance35 — (3)— 32 
For the year ended December 31, 2023
Allowance for credit losses$155 $57 
(a)
$(7)$48 
(b)
$157 
Deferred tax valuation allowance35 — — 

— 35 
__________
(a)The amount charged to costs and expenses includes the amount that was reclassified to Regulatory assets/liabilities under different mechanisms applicable to the different jurisdictions Pepco, DPL, and ACE operate in.
(b)Write-offs, net of recoveries of individual accounts receivable.

289

Potomac Electric Power Company
(6) Pepco
(i)Financial Statements (Item 8):
Report of Independent Registered Public Accounting Firm dated February 12, 2026 of PricewaterhouseCoopers LLP (PCAOB ID 238)
Statements of Operations and Comprehensive Income for the Years Ended December 31, 2025, 2024 and 2023
Statements of Cash Flows for the Years Ended December 31, 2025, 2024 and 2023
Balance Sheets at December 31, 2025 and 2024
Statements of Changes in Shareholder's Equity for the Years Ended December 31, 2025, 2024 and 2023
Notes to Financial Statements
(ii)Financial Statement Schedule:
Schedule II—Valuation and Qualifying Accounts for the Years Ended December 31, 2025, 2024, and 2023
Schedules not included are omitted because of the absence of conditions under which they are required or because the required information is provided in the consolidated financial statements, including the notes thereto
290

Potomac Electric Power Company
Schedule II – Valuation and Qualifying Accounts
Column AColumn BColumn CColumn DColumn E
Additions and adjustments
DescriptionBalance at
Beginning
of Period		Charged to
Costs and
Expenses		Charged
to Other
Accounts		DeductionsBalance at
End
of Period
(In millions)
For the year ended December 31, 2025
Allowance for credit losses$86 $42 
(a)
$(2)$31 
(b)
$95 
For the year ended December 31, 2024
Allowance for credit losses$80 $48 
(a)
$(10)$32 
(b)
$86 
For the year ended December 31, 2023
Allowance for credit losses$72 $31 
(a)
$(5)$18 
(b)
$80 
__________
(a)The amount charged to costs and expenses includes the amount that was reclassified to Regulatory assets/liabilities under different mechanisms as approved by the DCPSC and MDPSC.
(b)Write-offs, net of recoveries of individual accounts receivable.

291

Delmarva Power & Light Company
(7) DPL
(i)Financial Statements (Item 8):
Report of Independent Registered Public Accounting Firm dated February 12, 2026 of PricewaterhouseCoopers LLP (PCAOB ID 238)
Statements of Operations and Comprehensive Income for the Years Ended December 31, 2025, 2024 and 2023
Statements of Cash Flows for the Years Ended December 31, 2025, 2024 and 2023
Balance Sheets at December 31, 2025 and 2024
Statements of Changes in Shareholder's Equity for the Years Ended December 31, 2025, 2024 and 2023
Notes to Financial Statements
(ii)Financial Statement Schedule:
Schedule II—Valuation and Qualifying Accounts for the Years Ended December 31, 2025, 2024, and 2023
Schedules not included are omitted because of the absence of conditions under which they are required or because the required information is provided in the consolidated financial statements, including the notes thereto
292

Delmarva Power & Light Company
Schedule II – Valuation and Qualifying Accounts
Column AColumn BColumn CColumn DColumn E
Additions and adjustments
DescriptionBalance at
Beginning
of Period		Charged to
Costs and
Expenses		Charged
to Other
Accounts		DeductionsBalance at
End
of Period
(In millions)
For the year ended December 31, 2025
Allowance for credit losses$26 $17 
(a)
$— $14 
(b)
$29 
Deferred tax valuation allowance29 — — 

— 29 
For the year ended December 31, 2024
Allowance for credit losses$27 $11 
(a)
$— $12 
(b)
$26 
Deferred tax valuation allowance32 — (3)— 29 
For the year ended December 31, 2023
Allowance for credit losses$28 $10 
(a)
$— $11 
(b)
$27 
Deferred tax valuation allowance32 — — — 32 
__________
(a)The amount charged to costs and expenses includes the amount that was reclassified to Regulatory assets/liabilities under different mechanisms as approved by the DEPSC and MDPSC.
(b)Write-offs, net of recoveries of individual accounts receivable.

293

Atlantic City Electric Company and Subsidiary Company
(8) ACE
(i)Financial Statements (Item 8):
Report of Independent Registered Public Accounting Firm dated February 12, 2026 of PricewaterhouseCoopers LLP (PCAOB ID 238)
Consolidated Statements of Operations and Comprehensive Income for the Years Ended December 31, 2025, 2024, and 2023
Consolidated Statements of Cash Flows for the Years Ended December 31, 2025, 2024, and 2023
Consolidated Balance Sheets at December 31, 2025 and 2024
Consolidated Statements of Changes in Shareholder's Equity for the Years Ended December 31, 2025, 2024, and 2023
Notes to Consolidated Financial Statements
(ii)Financial Statement Schedule:
Schedule II—Valuation and Qualifying Accounts for the Years Ended December 31, 2025, 2024, and 2023
Schedules not included are omitted because of the absence of conditions under which they are required or because the required information is provided in the consolidated financial statements, including the notes thereto
294

Atlantic City Electric Company and Subsidiary Company
Schedule II – Valuation and Qualifying Accounts
Column AColumn BColumn CColumn DColumn E
Additions and adjustments
DescriptionBalance at
Beginning
of Period		Charged to
Costs and
Expenses		Charged
to Other
Accounts		DeductionsBalance at
End
of Period
(In millions)
For the year ended December 31, 2025
Allowance for credit losses$45 $9 
(a)
$1 $15 
(b)
$40 
For the year ended December 31, 2024
Allowance for credit losses$50 $14 
(a)
1 $20 
(b)
$45 
For the year ended December 31, 2023
Allowance for credit losses$55 $16 
(a)
$(2)$19 
(b)
$50 
__________
(a)ACE is allowed to recover from or refund to customers the difference between its annual credit loss expense and the amounts collected in rates annually through the Societal Benefits Charge. The amount charged to costs and expenses includes the amount that was reclassified to Regulatory assets/liabilities under such mechanism. See Note 2 – Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.
(b)Write-offs, net of recoveries of individual accounts receivable.
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Exhibits required by Item 601 of Regulation S-K:
Certain of the following exhibits are incorporated herein by reference under Rule 12b-32 of the Securities and Exchange Act of 1934, as amended. Certain other instruments which would otherwise be required to be listed below have not been so listed because such instruments do not authorize securities in an amount which exceeds 10% of the total assets of the applicable registrant and its subsidiaries on a consolidated basis and the relevant registrant agrees to furnish a copy of any such instrument to the Commission upon request.
(2) Plans of acquisition, reorganization, arrangement, liquidation, or succession
Exhibit No.DescriptionLocation
Separation Agreement, dated January 31, 2022, between Exelon Corporation and Constellation Energy Corporation
(3) Articles of Incorporation and Bylaws
Exelon Corporation
Exhibit No.DescriptionLocation
Amended and Restated Articles of Incorporation of Exelon Corporation, as amended April 30, 2024
Amended and Restated Bylaws of Exelon Corporation, as amended on April 30, 2024
Baltimore Gas and Electric Company
Exhibit No.DescriptionLocation
Articles of Restatement to the Charter of Baltimore Gas and Electric Company, restated as of August 16, 1996
Articles of Amendment to the Charter of Baltimore Gas and Electric Company as of February 2, 2010
Amended and Restated Bylaws of Baltimore Gas and Electric Company dated August 3, 2020
296
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Commonwealth Edison Company
Exhibit No.DescriptionLocation
Restated Articles of Incorporation of Commonwealth Edison Company Effective February 20, 1985, including Statements of Resolution Establishing Series, relating to the establishment of three new series of Commonwealth Edison Company preference stock known as the “$9.00 Cumulative Preference Stock,” the “$6.875 Cumulative Preference Stock” and the “$2.425 Cumulative Preference Stock”
Amended and Restated Bylaws of Commonwealth Edison Company, Effective February 22, 2021
PECO Energy Company
Exhibit No.DescriptionLocation
Amended and Restated Articles of Incorporation of PECO Energy Company
Amended and Restated Bylaws of PECO Energy Company dated August 3, 2020
Pepco Holdings LLC
Exhibit No.DescriptionLocation
Certificate of Formation of Pepco Holdings LLC, dated March 23, 2016
Amended and Restated Limited Liability Company Agreement of Pepco Holdings LLC, dated August 3, 2020
Atlantic City Electric Company
Exhibit No.DescriptionLocation
Restated Certificate of Incorporation of Atlantic City Electric Company (filed in New Jersey on August 9, 2002)
Bylaws of Atlantic City Electric Company
Delmarva Power & Light Company
Exhibit No.DescriptionLocation
Restated Certificate and Articles of Incorporation of Delmarva Power & Light Company (as filed in Delaware and Virginia)
Bylaws of Delmarva Power & Light Company
297
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Potomac Electric Power Company
Exhibit No.DescriptionLocation
Restated Articles of Incorporation of Potomac Electric Power Company (as filed in the District of Columbia)
Restated Articles of Incorporation and Articles of Restatement of Potomac Electric Power Company (as filed in Virginia)
Bylaws of Potomac Electric Power Company
(4) Instruments Defining the Rights of Securities Holders, Including Indentures
Exelon Corporation
Exhibit No.DescriptionLocation
Exelon Corporation Direct Stock Purchase Plan
Indenture dated May 1, 2001 between Exelon Corporation and The Bank of New York Mellon Trust Company, N.A., as trustee
Form of $500,000,000 5.625% senior notes due 2035 dated June 9, 2005 issued by Exelon Corporation
Indenture, dated as of June 17, 2014, between Exelon Corporation and The Bank of New York Mellon Trust Company, N.A., as Trustee
Third Supplemental Indenture, dated as of February 1, 2025, between Exelon Corporation and The Bank of New York Mellon Trust Company, N.A., as Trustee
Indenture, dated as of June 11, 2015, among Exelon Corporation and The Bank of New York Mellon Trust Company, N.A., as trustee
First Supplemental Indenture, dated as of June 11, 2015, among Exelon Corporation and The Bank of New York Mellon Trust Company, N.A., as trustee
Second Supplemental Indenture, dated as of December 2, 2015, among Exelon Corporation and The Bank of New York Mellon Trust Company, N.A., as trustee
Third Supplemental Indenture, dated as of April 7, 2016, among Exelon Corporation and The Bank of New York Mellon Trust Company, N.A., as trustee
298
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Exhibit No.DescriptionLocation
Fourth Supplemental Indenture, dated as of April 1, 2020, among Exelon Corporation and The Bank of New York Mellon Trust Company, N.A., as trustee
Fifth Supplemental Indenture, dated as of March 7, 2022, among Exelon Corporation and The Bank of New York Mellon Trust Company, N.A., as trustee
Sixth Supplemental Indenture, dated as of February 1, 2023, among Exelon Corporation and The Bank of New York Mellon Trust Company, N.A., as trustee
Seventh Supplemental Indenture, dated as of February 27, 2024, among Exelon Corporation and The Bank of New York Mellon Trust Company, N.A., as trustee
Eighth Supplemental Indenture, dated as of February 1, 2025, among Exelon Corporation and The Bank of New York Mellon Trust Company, N.A., as trustee


Indenture, dated as of December 4, 2025, between Exelon Corporation and The Bank of New York Mellon Trust Company, N.A., as trustee


Equity Distribution Agreement, dated May 2, 2025, by and among the Company, Barclays Capital Inc., BNP Paribas Securities Corp., BofA Securities, Inc., Citigroup Global Markets Inc., Credit Agricole Securities (USA) Inc., Goldman Sachs & Co. LLC, J.P. Morgan Securities LLC, Mizuho Securities USA LLC, Morgan Stanley & Co. LLC, MUFG Securities Americas Inc., RBC Capital Markets, LLC, Scotia Capital (USA) Inc. and Wells Fargo Securities, LLC, each as sales agents and as forward sellers, and Bank of America, N.A., Barclays Bank PLC, BNP Paribas, Citibank, N.A., Crédit Agricole Corporate and Investment Bank, Goldman Sachs & Co. LLC, JPMorgan Chase Bank, National Association, Mizuho Markets Americas LLC, Morgan Stanley & Co. LLC, MUFG Securities EMEA plc, Royal Bank of Canada, The Bank of Nova Scotia and Wells Fargo Bank, National Association, each as forward purchasers.


Description of Exelon Securities
299
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Baltimore Gas and Electric Company
Exhibit No.DescriptionLocation
Indenture dated as of July 24, 2006 between Baltimore Gas and Electric Company and Deutsche Bank Trust Company Americas, as trustee
Form of 2.400% notes due 2026 issued August 18, 2016 by Baltimore Gas and Electric Company
Form of 3.500% Note due 2046 issued August 18, 2016 by Baltimore Gas and Electric Company
Form of 3.750% Note due 2047 issued August 24, 2017 by Baltimore Gas and Electric Company
Form of 4.550% Note due 2052 issued June 6, 2022 by Baltimore Gas and Electric Company
Form of 5.400% Note due 2053 issued May 10, 2023 by Baltimore Gas and Electric
Form of 5.300% Note due 2034 issued June 1, 2024 by Baltimore Gas and Electric


Form of 5.650% Note due 2054 issued June 1, 2024 by Baltimore Gas and Electric
Form of 5.450% Note due 2035 issued May 16, 2025 by Baltimore Gas and Electric
Indenture, dated as of September 1, 2019, between Baltimore Gas and Electric Company and U.S. Bank N.A., as trustee


Commonwealth Edison Company
Exhibit No.DescriptionLocation
4-16Mortgage of Commonwealth Edison Company to Illinois Merchants Trust Company, Trustee (BNY Mellon Trust Company of Illinois, as current successor Trustee), dated July 1, 1923, as supplemented and amended by Supplemental Indenture thereto dated August 1, 1944
Registration No. 2-60201, Form S-7, Exhibit 2-1(a)
Supplemental Indenture to Commonwealth Edison Company Mortgage dated as of January 13, 2003
300
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Exhibit No.DescriptionLocation
Supplemental Indenture to Commonwealth Edison Company Mortgage dated as of February 22, 2006
Supplemental Indenture to Commonwealth Edison Company Mortgage dated as of March 1, 2007
Supplemental Indenture to Commonwealth Edison Company Mortgage dated as of December 20, 2007
Supplemental Indenture to Commonwealth Edison Company Mortgage dated as of September 17, 2012
Supplemental Indenture to Commonwealth Edison Company Mortgage dated as of August 1, 2013
Supplemental Indenture to Commonwealth Edison Company Mortgage dated as of January 2, 2014
Supplemental Indenture to Commonwealth Edison Company Mortgage dated as of February 18, 2015
Supplemental Indenture to Commonwealth Edison Company Mortgage dated as of November 4, 2015
Supplemental Indenture to Commonwealth Edison Company Mortgage dated as of June 15, 2016
Supplemental Indenture to Commonwealth Edison Company Mortgage dated as of August 9, 2017
Supplemental Indenture to Commonwealth Edison Company Mortgage dated as of February 6, 2018
Supplemental Indenture to Commonwealth Edison Company Mortgage dated as of July 26, 2018
Supplemental Indenture to Commonwealth Edison Company Mortgage dated as of February 7, 2019
Supplemental Indenture to Commonwealth Edison Company Mortgage dated as of October 29, 2019
Supplemental Indenture to Commonwealth Edison Company Mortgage dated as of February 10, 2020
301
Table of Contents

Exhibit No.DescriptionLocation
Supplemental Indenture to Commonwealth Edison Company Mortgage dated as of February 16, 2021
Supplemental Indenture to Commonwealth Edison Company Mortgage dated as of August 2, 2021
Supplemental Indenture to Commonwealth Edison Company Mortgage dated as of February 23, 2022
Supplemental Indenture to Commonwealth Edison Company Mortgage dated as of December 21, 2022
Supplemental Indenture to Commonwealth Edison Company Mortgage dated as of May 1, 2024


Supplemental Indenture to Commonwealth Edison Company Mortgage dated as of May 1, 2025
Instrument of Resignation, Appointment and Acceptance dated as of February 20, 2002, under the provisions of the Mortgage of Commonwealth Edison Company dated July 1, 1923, and Indentures Supplemental thereto, regarding corporate trustee
Instrument dated as of January 31, 1996, under the provisions of the Mortgage of Commonwealth Edison Company dated July 1, 1923 and Indentures Supplemental thereto, regarding individual
Description of ComEd Securities
PECO Energy Company
Exhibit No.DescriptionLocation
4-19First and Refunding Mortgage dated May 1, 1923 between The Counties Gas and Electric Company (predecessor to PECO Energy Company) and Fidelity Trust Company, Trustee (U.S. Bank N.A., as current successor trustee)
Registration No. 2-2281, Exhibit B-1(a)
4-19-1Supplemental Indenture to PECO Energy Company’s First and Refunding Mortgage dated as of December 1, 1941
Registration No. 2-4863, Exhibit B-1(h)(a)
302
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Exhibit No.DescriptionLocation
Supplemental Indenture to PECO Energy Company’s First and Refunding Mortgage dated as of April 15, 2004
Supplemental Indenture to PECO Energy Company’s First and Refunding Mortgage dated as of September 15, 2006
Supplemental Indenture to PECO Energy Company’s First and Refunding Mortgage dated as of March 1, 2007
Supplemental Indenture to PECO Energy Company’s First and Refunding Mortgage dated as of September 1, 2014
Supplemental Indenture to PECO Energy Company’s First and Refunding Mortgage dated as of September 1, 2017
Supplemental Indenture to PECO Energy Company’s First and Refunding Mortgage dated as of February 1, 2018
Supplemental Indenture to PECO Energy Company’s First and Refunding Mortgage dated as of September 1, 2018
Supplemental Indenture to PECO Energy Company’s First and Refunding Mortgage dated as of August 15, 2019
Supplemental Indenture to PECO Energy Company’s First and Refunding Mortgage dated as of June 1, 2020
Supplemental Indenture to PECO Energy Company’s First and Refunding Mortgage dated as of February 15, 2021
Supplemental Indenture to PECO Energy Company’s First and Refunding Mortgage dated as of September 1, 2021
Supplemental Indenture to PECO Energy Company’s First and Refunding Mortgage dated as of May 1, 2022
Supplemental Indenture to PECO Energy Company’s First and Refunding Mortgage dated as of August 1, 2022
Supplemental Indenture to PECO Energy Company's First and Refunding Mortgage dated as of June 1, 2023
303
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Exhibit No.DescriptionLocation
Supplemental Indenture to PECO Energy Company's First and Refunding Mortgage dated as of August 15, 2024
Supplemental Indenture to PECO Energy Company's First and Refunding Mortgage dated as of August 15, 2025


Indenture to Subordinated Debt Securities dated as of June 24, 2003 between PECO Energy Company, as Issuer, and U.S. Bank N.A., as Trustee
Preferred Securities Guarantee Agreement between PECO Energy Company, as Guarantor, and U.S. Bank N.A., as Trustee, dated as of June 24, 2003
PECO Energy Capital Trust IV Amended and Restated Declaration of Trust among PECO Energy Company, as Sponsor, U.S. Bank Trust N.A., as Delaware Trustee and Property Trustee, and J. Barry Mitchell, George R. Shicora and Charles S. Walls as Administrative Trustees dated as of June 24, 2003

304
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Atlantic City Electric Company
Exhibit No.DescriptionLocation
4-23Mortgage and Deed of Trust, dated January 15, 1937, between Atlantic City Electric Company and The Bank of New York Mellon (formerly Irving Trust Company), as trustee
2-66280, Registration Statement dated December 21, 1979, Exhibit 2(a)(a)
4-23-1Supplemental Indenture to Atlantic City Electric Company Mortgage dated as of June 1, 1949
2-66280, Registration Statement dated December 21, 1979, Exhibit 2(b)(a)
4-23-2Supplemental Indenture to Atlantic City Electric Company Mortgage dated as of March 1, 1991
Form 10-K dated March 28, 1991, Exhibit 4(d)(1)(a)
Supplemental Indenture to Atlantic City Electric Company Mortgage dated as of April 1, 2004
Supplemental Indenture to Atlantic City Electric Company Mortgage dated as of March 8, 2006
Supplemental Indenture to Atlantic City Electric Company Mortgage dated as of October 9, 2018
Supplemental Indenture to Atlantic City Electric Company Mortgage dated as of May 2, 2019
Supplemental Indenture to Atlantic City Electric Company Mortgage dated as of June 1, 2020
Supplemental Indenture to Atlantic City Electric Company Mortgage dated as of February 15, 2021
Supplemental Indenture to Atlantic City Electric Company Mortgage dated as of November 1, 2021
Supplemental Indenture to Atlantic City Electric Company Mortgage dated as of February 1, 2022
Supplemental Indenture to the Atlantic City Electric Company Mortgage and Deed of Trust, dated as of March 1, 2023
Supplemental Indenture to the Atlantic City Electric Company Mortgage and Deed of Trust, dated as of March 1, 2024


Supplemental Indenture to the Atlantic City Electric Company Mortgage and Deed of Trust, dated as of March 1, 2025



Pollution Control Facilities Loan Agreement, dated as of June 1, 2020, between The Pollution Control Financing Authority of Salem County and Atlantic City Electric
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Delmarva Power & Light Company
Exhibit No.DescriptionLocation
4-25Mortgage and Deed of Trust of Delaware Power & Light Company to The Bank of New York Mellon (ultimate successor to the New York Trust Company), as trustee, dated as of October 1, 1943, and copies of the First through Sixty-Eighth Supplemental Indentures thereto
33-1763, Registration Statement dated November 27, 1985, Exhibit 4-(A)(a)
4-25-1Supplemental Indenture to Delmarva Power & Light Company Mortgage dated as of October 1, 1993
33-53855, Registration Statement dated January 30, 1995, Exhibit 4-L(a)
4-25-2Supplemental Indenture to Delmarva Power & Light Company Mortgage dated as of October 1, 1994
33-53855, Registration Statement dated January 30, 1995, Exhibit 4-N(a)
Supplemental Indenture to Delmarva Power & Light Company Mortgage dated as of May 4, 2015
Supplemental Indenture to Delmarva Power & Light Company Mortgage dated as of December 5, 2016
Supplemental Indenture to Delmarva Power & Light Company Mortgage dated as of June 1, 2018
Supplemental Indenture to Delmarva Power & Light Company Mortgage dated as of May 2, 2019
Supplemental Indenture to Delmarva Power & Light Company Mortgage dated as of January 1, 2020
Supplemental Indenture to Delmarva Power & Light Company Mortgage dated as of June 1, 2020
Supplemental Indenture to Delmarva Power & Light Company Mortgage dated as of February 15, 2021
Supplemental Indenture to Delmarva Power & Light Company Mortgage dated as of February 1, 2022
Supplemental Indenture to Delmarva Power & Light Company Mortgage dated as of January 1, 2022
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Exhibit No.DescriptionLocation
Supplemental Indenture to the Delmarva Power & Light Company Mortgage and Deed of Trust, dated as of March 1, 2023
Supplemental Indenture to the Delmarva Power & Light Company Mortgage and Deed of Trust, dated as of March 1, 2024


Supplemental Indenture to the Delmarva Power & Light Company Mortgage and Deed of Trust, dated as of March 1, 2025



Gas Facilities Loan Agreement, dated as of July 1, 2020, between The Delaware Economic Development Authority and Delmarva Power & Light Company
Potomac Electric Power Company
Exhibit No.DescriptionLocation
4-27Mortgage and Deed of Trust, dated July 1, 1936, of Potomac Electric Power Company to The Bank of New York Mellon as successor trustee, securing First Mortgage Bonds of Potomac Electric Power Company, and Supplemental Indenture dated July 1, 1936
File No. 2-2232, Registration Statement dated June 19, 1936, Exhibit B-4(a)
4-27-1Supplemental Indenture to Potomac Electric Power Company Mortgage dated as of December 10, 1939
8-K dated January 3, 1940, Exhibit B(a)
Supplemental Indenture to Potomac Electric Power Company Mortgage dated as of March 16, 2004
Supplemental Indenture to Potomac Electric Power Company Mortgage dated as of May 24, 2005
Supplemental Indenture to Potomac Electric Power Company Mortgage dated as of November 13, 2007
Supplemental Indenture to Potomac Electric Power Company Mortgage dated as of March 24, 2008
Supplemental Indenture to Potomac Electric Power Company Mortgage dated as of December 3, 2008
Supplemental Indenture to Potomac Electric Power Company Mortgage dated as of March 11, 2013
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Exhibit No.DescriptionLocation
Supplemental Indenture to Potomac Electric Power Company Mortgage dated as of November 14, 2013
Supplemental Indenture to Potomac Electric Power Company Mortgage dated as of March 9, 2015
Supplemental Indenture to Potomac Electric Power Company Mortgage dated as of May 15, 2017
Supplemental Indenture to Potomac Electric Power Company Mortgage dated as of June 1, 2018
Supplemental Indenture to Potomac Electric Power Company Mortgage dated as of May 2, 2019
Supplemental Indenture to Potomac Electric Power Company Mortgage dated as of February 12, 2020
Supplemental Indenture to Potomac Electric Power Company Mortgage dated as of February 15, 2021
Supplemental Indenture to Potomac Electric Power Company Mortgage dated as of March 1, 2022
Supplemental Indenture to the Potomac Electric Power Company Mortgage and Deed of Trust, dated as of March 1, 2023
Supplemental Indenture to the Potomac Electric Power Company Mortgage and Deed of Trust, dated as of February 15, 2024
Supplemental Indenture to the Potomac Electric Power Company Mortgage and Deed of Trust, dated as of March 1, 2025


Exempt Facilities Loan Agreement dated as of June 1, 2019 between the Maryland Economic Development Corporation and Potomac Electric Power Company
(10) Material Contracts
Exelon Corporation
Exhibit No.DescriptionLocation
Transition Services Agreement, dated January 31, 2022, between Exelon Corporation and Constellation Energy Corporation
308
Table of Contents

Exhibit No.DescriptionLocation
Tax Matters Agreement, dated January 31, 2022, between Exelon Corporation and Constellation Energy Corporation
Employee Matters Agreement, dated January 31, 2022, between Exelon Corporation and Constellation Energy Corporation
Amended and Restated Credit Agreement for $900,000,000 dated August 29, 2024, between Exelon Corporation and various financial institutions
Exelon Corporation Non-Employee Directors’ Restricted Stock Unit Plan (Effective January 1, 2026)
Exelon Corporation Supplemental Management Retirement Plan (As Amended and Restated Effective January 1, 2009) *
Exelon Corporation Employee Stock Purchase Plan, as amended and restated effective September 25, 2019
Exelon Corporation Employee Stock Purchase Plan for Unincorporated Subsidiaries, as amended and restated effective September 25, 2019
Exelon Corporation 2020 Long-Term Incentive Plan (Effective April 28, 2020)
Exelon Corporation 2020 Long-Term Incentive Plan Prospectus, dated May 27, 2020
Form of Restricted Stock Unit Award Notice and Agreement under the Exelon Corporation 2020 Long-Term Incentive Plan
Form of Performance Share Award Notice and Agreement under the Exelon Corporation 2020 Long-Term Incentive Plan
Exelon Corporation Senior Management Severance Plan as Amended and Restated effective February 1, 2024
Form of Separation Agreement under Exelon Corporation Senior Management Severance Plan (As Amended and Restated Effective January 1, 2020)
309
Table of Contents

Exhibit No.DescriptionLocation
Exelon Corporation Executive Death Benefits Plan dated as of January 1, 2003 *
First Amendment to Exelon Corporation Executive Death Benefits Plan, Effective January 1, 2006 *
Exelon Corporation Deferred Compensation Plan (As Amended and Restated Effective December 1, 2025)
Exelon Corporation Stock Deferral Plan (As Amended and Restated Effective September 25, 2019)
2023 Amendment to Certain Plans of Exelon Corporation
Constellation Energy Group Benefits Restoration Plan (As Amended and Restated Effective January 1, 2025)
Exelon Corporation Unfunded Deferred Compensation Plan for Directors (As Amended and Restated Effective January 1, 2026)
Commonwealth Edison Company
Exhibit No.DescriptionLocation
Deferred Prosecution Agreement, dated July 17, 2020, between Commonwealth Edison Company and the U.S. Department of Justice and the U.S. Attorney for the Northern District of Illinois
Amended and Restated Credit Agreement for $1,000,000,000 dated August 29, 2024, between Commonwealth Edison Company and various financial institutions


Baltimore Gas and Electric Company
Exhibit No.DescriptionLocation
Amended and Restated Credit Agreement for $600,000,000 dated August 29, 2024, between Baltimore Gas and Electric Company and various financial institutions
310
Table of Contents

PECO Energy Company
Exhibit No.DescriptionLocation
PECO Energy Company Supplemental Pension Benefit Plan (As Amended and Restated Effective January 1, 2009)
Amended and Restated Credit Agreement for $600,000,000 dated August 29, 2024, between PECO Energy Company and various financial institutions
Atlantic City Electric Company, Potomac Electric Power Company, Delmarva Power & Light Company
Exhibit No.DescriptionLocation
Bond Purchase Agreement, dated December 1, 2015, among Atlantic City Electric Company and the purchasers signatory thereto
Amended and Restated Credit Agreement for $900,000,000 dated August 29, 2024, between Potomac Electric Power Company, Delmarva Power & Light Company, Atlantic City Electric Company and various financial institutions

(14) Code of Ethics
Exelon Corporation
Exhibit No.DescriptionLocation
Exelon Code of Conduct, as amended January 05, 2026
(19) Insider trading policies and procedures
Exelon Corporation
Exhibit No.DescriptionLocation
Exelon Insider Trading Policy
(97) Policy Relating to Recovery of Erroneously Awarded Compensation
Exelon Corporation
Exhibit No.DescriptionLocation
Exelon Financial Restatement Compensation Recoupment Policy
311
Table of Contents

Exhibit No.Description
Consent of Independent Registered Public Accountants
Power of Attorney (Exelon Corporation)
Power of Attorney (Commonwealth Edison Company)
Power of Attorney (PECO Energy Company)
312
Table of Contents

Exhibit No.Description
Power of Attorney (Baltimore Gas and Electric Company)
Power of Attorney (Pepco Holdings LLC)
Power of Attorney (Potomac Electric Power Company)
Power of Attorney (Delmarva Power & Light Company)
Power of Attorney (Atlantic City Electric Company)

313
Table of Contents

Certifications Pursuant to Rule 13a-14(a) and 15d-14(a) of the Securities and Exchange Act of 1934 as to the Annual Report on Form 10-K for the year ended December 31, 2025 filed by the following officers for the following registrants:
Exhibit No.Description
Certifications Pursuant to Section 1350 of Chapter 63 of Title 18 United States Code as to the Annual Report on Form 10-K for the year ended December 31, 2025 filed by the following officers for the following registrants:
Exhibit No.Description
314
Table of Contents

Exhibit No.Description
101.INS
Inline XBRL Instance Document - the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document.
101.SCHInline XBRL Taxonomy Extension Schema Document.
101.CALInline XBRL Taxonomy Extension Calculation Linkbase Document.
101.DEFInline XBRL Taxonomy Extension Definition Linkbase Document.
101.LABInline XBRL Taxonomy Extension Labels Linkbase Document.
101.PREInline XBRL Taxonomy Extension Presentation Linkbase Document.
104Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101)

__________
* Compensatory plan or arrangements in which directors or officers of the applicable registrant participate and which are not available to all employees.
(a)These filings are not available electronically on the SEC website as they were filed in paper previous to the electronic system that is currently in place.
315

ITEM 16.FORM 10-K SUMMARY
All Registrants
None.
316


SIGNATURES
 
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of Chicago and State of Illinois on the 12th day of February, 2026.
 
EXELON CORPORATION
By: /s/ CALVIN G. BUTLER JR.
Name: Calvin G. Butler Jr.
Title: President and Chief Executive Officer
 
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed by the following persons on behalf of the Registrant and in the capacities indicated on the 12th day of February, 2026.
 
Signature  Title
/s/ CALVIN G. BUTLER JR.  President, Chief Executive Officer (Principal Executive Officer), and Director
Calvin G. Butler Jr.
/s/    JEANNE M. JONES  Executive Vice President, Chief Finance Officer, Audit and Risk (Principal Financial Officer)
Jeanne M. Jones
/s/ ROBERT A. KLECZYNSKI  Senior Vice President, Controller and Tax (Principal Accounting Officer)
Robert A. Kleczynski
 
This annual report has also been signed below by Colette D. Honorable, Attorney-in-Fact, on behalf of the following Directors on the date indicated:
 
Anna Richo  Linda P. Jojo
W. Paul BowersCharisse R. Lillie
Marjorie Rodgers CheshireBryan Segedi
Matthew RogersDavid G. DeWalt
 
By:  /s/ COLETTE D. HONORABLE  February 12, 2026
Name:  Colette D. Honorable   
317

SIGNATURES
 
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of Chicago and State of Illinois on the 12th day of February, 2026.
 
COMMONWEALTH EDISON COMPANY
By: /s/ GIL C. QUINIONES
Name: Gil C. Quiniones
Title: President and Chief Executive Officer
 
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed by the following persons on behalf of the Registrant and in the capacities indicated on the 12th day of February, 2026.
 
Signature  Title
/s/ GIL C. QUINIONES  President, Chief Executive Officer (Principal Executive Officer), and Director
Gil C. Quiniones
/s/ JOSHUA S. LEVIN  Senior Vice President, Chief Financial Officer and Treasurer (Principal Financial Officer)
Joshua S. Levin
/s/    ERIN V. WHITE  Director, Accounting (Principal Accounting Officer)
Erin V. White
 
This annual report has also been signed below by Gil C. Quiniones, Attorney-in-Fact, on behalf of the following Directors on the date indicated:
 
Michael A. Innocenzo  Ricardo Estrada
Elizabeth BuchananZaldwaynaka Scott
Stephen BowmanSmita Shah
 
By:  /s/ GIL C. QUINIONES  February 12, 2026
Name:  Gil C. Quiniones   
318

SIGNATURES
 
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of Chicago and State of Illinois on the 12th day of February, 2026.
 
PECO ENERGY COMPANY
By: /s/ DAVID M. VAHOS
Name: David M. Vahos
Title: President and Chief Executive Officer
 
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed by the following persons on behalf of the Registrant and in the capacities indicated on the 12th day of February, 2026.
 
Signature  Title
/s/ DAVID M. VAHOS  President, Chief Executive Officer (Principal Executive Officer), and Director
David M. Vahos
/s/ MARISSA E. HUMPHREY  Senior Vice President, Chief Financial Officer and Treasurer (Principal Financial Officer)
Marissa E. Humphrey
/s/ MARIANA HUFFORD  Director, Accounting (Principal Accounting Officer)
Mariana Hufford
 
This annual report has also been signed below by David M. Vahos, Attorney-in-Fact, on behalf of the following Directors on the date indicated:
 
Michael A. Innocenzo  Michael Nutter
John S. GradyMichelle Hong
Sharmain Matlock-TurnerRoberto E. Perez
 
By:  /s/ DAVID M. VAHOS  February 12, 2026
Name:  David M. Vahos   
319

SIGNATURES
 
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of Chicago and State of Illinois on the 12th day of February, 2026.
 
BALTIMORE GAS AND ELECTRIC COMPANY
By: /s/ TAMLA A. OLIVIER
Name: Tamla A. Olivier
Title: President and Chief Executive Officer
 
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed by the following persons on behalf of the Registrant and in the capacities indicated on the 12th day of February, 2026.
 
Signature  Title
/s/ TAMLA A. OLIVIER  President, Chief Executive Officer (Principal Executive Officer), and Director
Tamla A. Olivier
/s/ MICHAEL J. CLOYD  Senior Vice President, Chief Financial Officer and Treasurer (Principal Financial Officer)
Michael J. Cloyd
/s/ DAMON M. SCOLERI  Director, Accounting (Principal Accounting Officer)
Damon M. Scoleri
 
This annual report has also been signed below by Tamla A. Olivier, Attorney-in-Fact, on behalf of the following Directors on the date indicated:
 
Michael A. Innocenzo  Tim Regan
Keith LeeAmy Seto
Rachel Garbow MonroeMaria Harris Tildon
Byron Marchant
 
By:  /s/ TAMLA A. OLIVIER  February 12, 2026
Name:  Tamla A. Olivier   
    
320

SIGNATURES
 
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of Chicago and State of Illinois on the 12th day of February, 2026.
 
PEPCO HOLDINGS LLC
By: /s/ J. TYLER ANTHONY
Name: J. Tyler Anthony
Title: President and Chief Executive Officer
 
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed by the following persons on behalf of the Registrant and in the capacities indicated on the 12th day of February, 2026.
 
Signature  Title
/s/ J. TYLER ANTHONY  President, Chief Executive Officer (Principal Executive Officer), and Director
J. Tyler Anthony
/s/ ELIZABETH MORGAN DOWNS O'DONNELL  Senior Vice President, Chief Financial Officer and Treasurer (Principal Financial Officer)
Elizabeth Morgan Downs O'Donnell
/s/ JASON T. JONES  Director, Accounting (Principal Accounting Officer)
Jason T. Jones
 
This annual report has also been signed below by J. Tyler Anthony, Attorney-in-Fact, on behalf of the following Directors on the date indicated:
 
Antoine Allen  Benjamin Wu
Michael A. InnocenzoLinda W. Cropp
Debra P. DiLorenzoRosie Allen-Herring
 
By:  /s/ J. TYLER ANTHONY  February 12, 2026
Name:  J. Tyler Anthony   
321

SIGNATURES
 
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of Chicago and State of Illinois on the 12th day of February, 2026.
 
POTOMAC ELECTRIC POWER COMPANY
By: /s/ J. TYLER ANTHONY
Name: J. Tyler Anthony
Title: President and Chief Executive Officer
 
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed by the following persons on behalf of the Registrant and in the capacities indicated on the 12th day of February, 2026.
 
Signature  Title
/s/ J. TYLER ANTHONY  President, Chief Executive Officer (Principal Executive Officer), and Director
J. Tyler Anthony
/s/ ELIZABETH MORGAN DOWNS O'DONNELL  Senior Vice President, Chief Financial Officer and Treasurer (Principal Financial Officer), and Director
Elizabeth Morgan Downs O'Donnell
/s/ JASON T. JONES  Director, Accounting (Principal Accounting Officer)
Jason T. Jones
 
This annual report has also been signed below by J. Tyler Anthony, Attorney-in-Fact, on behalf of the following Directors on the date indicated:
 
Michael A. Innocenzo  Jacyln Cantler
Rodney OddoyeAnne C. Bancroft
Amber Perry
 
By:  /s/ J. TYLER ANTHONY  February 12, 2026
Name:  J. Tyler Anthony   

322

SIGNATURES
 
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of Chicago and State of Illinois on the 12th day of February, 2026.
 
DELMARVA POWER & LIGHT COMPANY
By: /s/ J. TYLER ANTHONY
Name: J. Tyler Anthony
Title: President and Chief Executive Officer
 
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed by the following persons on behalf of the Registrant and in the capacities indicated on the 12th day of February, 2026.
 
Signature  Title
/s/ J. TYLER ANTHONY  President, Chief Executive Officer (Principal Executive Officer), and Director
J. Tyler Anthony
/s/ ELIZABETH MORGAN DOWNS O'DONNELL  Senior Vice President, Chief Financial Officer and Treasurer (Principal Financial Officer)
Elizabeth Morgan Downs O'Donnell
/s/ JASON T. JONES  Director, Accounting (Principal Accounting Officer)
Jason T. Jones
 
This annual report has also been signed below by J. Tyler Anthony, Attorney-in-Fact, on behalf of the following Directors on the date indicated:
 
Michael A. Innocenzo  
 
By:  /s/ J. TYLER ANTHONY  February 12, 2026
Name:  J. Tyler Anthony   

323

SIGNATURES
 
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of Chicago and State of Illinois on the 12th day of February, 2026.
 
ATLANTIC CITY ELECTRIC COMPANY
By: /s/ J. TYLER ANTHONY
Name: J. Tyler Anthony
Title: President and Chief Executive Officer
 
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed by the following persons on behalf of the Registrant and in the capacities indicated on the 12th day of February, 2026.
 
Signature  Title
/s/ J. TYLER ANTHONY  President, Chief Executive Officer (Principal Executive Officer), and Director
J. Tyler Anthony
/s/ ELIZABETH MORGAN DOWNS O'DONNELL  Senior Vice President, Chief Financial Officer and Treasurer (Principal Financial Officer)
Elizabeth Morgan Downs O'Donnell
/s/ JASON T. JONES  Director, Accounting (Principal Accounting Officer)
Jason T. Jones
324

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