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UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM  10-Q

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

For the Quarterly Period Ended September 30, 2025
or

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

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

001-16169 EXELON CORPORATION 23-2990190
(a Pennsylvania corporation)
10 South Dearborn Street
P.O. Box 805379
Chicago , Illinois 60680-5379
(800)   483-3220

001-01839 COMMONWEALTH EDISON COMPANY 36-0938600
(an Illinois corporation)
10 South Dearborn Street
Chicago , Illinois 60603-2300
(312)   394-4321

000-16844 PECO ENERGY COMPANY 23-0970240
(a Pennsylvania corporation)
2301 Market Street
P.O. Box 8699
Philadelphia , Pennsylvania 19101-8699
(215)   841-4000

001-01910 BALTIMORE GAS AND ELECTRIC COMPANY 52-0280210
(a Maryland corporation)
2 Center Plaza
110 West Fayette Street
Baltimore , Maryland 21201-3708
(410) 234-5000

001-31403 PEPCO HOLDINGS LLC 52-2297449
(a Delaware limited liability company)
701 Ninth Street, N.W.
Washington , District of Columbia 20068-0001
(202) 872-2000

001-01072 POTOMAC ELECTRIC POWER COMPANY 53-0127880
(a District of Columbia and Virginia corporation)
701 Ninth Street, N.W.
Washington , District of Columbia 20068-0001
(202) 872-2000

001-01405 DELMARVA POWER & LIGHT COMPANY 51-0084283
(a Delaware and Virginia corporation)
500 North Wakefield Drive
Newark , Delaware 19702-5440
(202) 872-2000

001-03559 ATLANTIC CITY ELECTRIC COMPANY 21-0398280
(a New Jersey corporation)
500 North Wakefield Drive
Newark , Delaware 19702-5440
(202) 872-2000

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

Title of each class Trading Symbol(s) Name of each exchange on which registered
EXELON CORPORATION:
Common stock, without par value EXC The Nasdaq Stock Market LLC

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    x   No   o

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    x   No   o

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

Exelon Corporation Large Accelerated Filer x Accelerated Filer ☐
Non-accelerated Filer ☐
Smaller Reporting Company ☐
Emerging Growth Company ☐

Commonwealth Edison Company Large Accelerated Filer ☐
Accelerated Filer ☐
Non-accelerated Filer x Smaller Reporting Company ☐
Emerging Growth Company ☐

PECO Energy Company Large Accelerated Filer ☐
Accelerated Filer ☐
Non-accelerated Filer x Smaller Reporting Company ☐
Emerging Growth Company ☐

Baltimore Gas and Electric Company Large Accelerated Filer ☐
Accelerated Filer ☐
Non-accelerated Filer x Smaller Reporting Company ☐
Emerging Growth Company ☐

Pepco Holdings LLC Large Accelerated Filer ☐
Accelerated Filer ☐
Non-accelerated Filer x Smaller Reporting Company ☐
Emerging Growth Company ☐

Potomac Electric Power Company Large Accelerated Filer ☐
Accelerated Filer ☐
Non-accelerated Filer x Smaller Reporting Company ☐
Emerging Growth Company ☐

Delmarva Power & Light Company Large Accelerated Filer ☐
Accelerated Filer ☐
Non-accelerated Filer x Smaller Reporting Company ☐
Emerging Growth Company ☐

Atlantic City Electric Company Large Accelerated Filer ☐
Accelerated Filer ☐
Non-accelerated Filer x Smaller Reporting Company ☐
Emerging Growth Company ☐

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act.  ☐

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act).  Yes   ☐   No   x

The number of shares outstanding of each registrant’s common stock as of September 30, 2025 was:

Exelon Corporation Common Stock, without par value 1,010,290,316
Commonwealth Edison Company Common Stock, $12.50 par value 127,021,419
PECO Energy Company Common Stock, without par value 170,478,507
Baltimore Gas and Electric Company Common Stock, without par value 1,000
Pepco Holdings LLC not applicable
Potomac Electric Power Company Common Stock, $0.01 par value 100
Delmarva Power & Light Company Common Stock, $2.25 par value 1,000
Atlantic City Electric Company Common Stock, $3.00 par value 8,546,017

TABLE OF CONTENTS

Page No.
GLOSSARY OF TERMS AND ABBREVIATIONS
4

FILING FORMAT
7

CAUTIONARY STATEMENTS REGARDING FORWARD-LOOKING INFORMATION
7

WHERE TO FIND MORE INFORMATION
8

PART I.
FINANCIAL INFORMATION
9

ITEM 1.
FINANCIAL STATEMENTS
9

Exelon Corporation

Consolidated Statements of Operations and Comprehensive Income
10

Consolidated Statements of Cash Flows
11

Consolidated Balance Sheets
12

Consolidated Statements of Changes in Shareholders’ Equity
14

Commonwealth Edison Company

Consolidated Statements of Operations and Comprehensive Income
16

Consolidated Statements of Cash Flows
17

Consolidated Balance Sheets
18

Consolidated Statements of Changes in Shareholders' Equity
20

PECO Energy Company

Consolidated Statements of Operations and Comprehensive Income
21

Consolidated Statements of Cash Flows
22

Consolidated Balance Sheets
23

Consolidated Statements of Changes in Shareholder's Equity
25

Baltimore Gas and Electric Company

Statements of Operations and Comprehensive Income
26

Statements of Cash Flows
27

Balance Sheets
28

Statements of Changes in Shareholder's Equity
30

Pepco Holdings LLC

Consolidated Statements of Operations and Comprehensive Income
31

Consolidated Statements of Cash Flows
32

Consolidated Balance Sheets
33

Consolidated Statements of Changes in Member's Equity
35

1

Page No.
Potomac Electric Power Company

Statements of Operations and Comprehensive Income
36

Statements of Cash Flows
37

Balance Sheets
38

Statements of Changes in Shareholder's Equity
40

Delmarva Power & Light Company

Statements of Operations and Comprehensive Income
41

Statements of Cash Flows
42

Balance Sheets
43

Statements of Changes in Shareholder’s Equity
45

Atlantic City Electric Company

Consolidated Statements of Operations and Comprehensive Income
46

Consolidated Statements of Cash Flows
47

Consolidated Balance Sheets
48

Consolidated Statements of Changes in Shareholder’s Equity
50

Combined Notes to Consolidated Financial Statements

1. Significant Accounting Policies
51

2. Regulatory Matters
52

3. Revenue from Contracts with Customers
60

4. Segment Information
61

5. Accounts Receivable
72

6. Income Taxes
75

7. Retirement Benefits
78

8. Derivative Financial Instruments
80

9. Debt and Credit Agreements
83

10. Fair Value of Financial Assets and Liabilities
86

11. Commitments and Contingencies
94

12. Shareholders' Equity
100

13. Changes in Accumulated Other Comprehensive Income
102

14. Supplemental Financial Information
103

15. Related Party Transactions
107

2

Page No.

ITEM 2.
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
109

Exelon Corporation
109

Executive Overview
109

Financial Results of Operations
109

Significant 2025 Transactions and Developments
111

Other Key Business Drivers and Management Strategies
114

Critical Accounting Policies and Estimates
115

Results of Operations By Registrant
116

Commonwealth Edison Company
116

PECO Energy Company
119

Baltimore Gas and Electric Company
123

Pepco Holdings LLC
126

Potomac Electric Power Company
127

Delmarva Power & Light Company
130

Atlantic City Electric Company
135

Liquidity and Capital Resources
138

ITEM 3.
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
147

ITEM 4.
CONTROLS AND PROCEDURES
148

PART II.
OTHER INFORMATION
148

ITEM 1.
LEGAL PROCEEDINGS
148

ITEM 1A.
RISK FACTORS
148

ITEM 5.
OTHER INFORMATION
148

ITEM 6.
EXHIBITS
149

SIGNATURES
152

Exelon Corporation
152

Commonwealth Edison Company
153

PECO Energy Company
154

Baltimore Gas and Electric Company
155

Pepco Holdings LLC
156

Potomac Electric Power Company
157

Delmarva Power & Light Company
158

Atlantic City Electric Company
159

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GLOSSARY OF TERMS AND ABBREVIATIONS
Exelon Corporation and Related Entities
Exelon Exelon Corporation
ComEd Commonwealth Edison Company
PECO PECO Energy Company
BGE Baltimore Gas and Electric Company
Pepco Holdings or PHI Pepco Holdings LLC
Pepco Potomac Electric Power Company
DPL Delmarva Power & Light Company
ACE Atlantic City Electric Company
Registrants Exelon, ComEd, PECO, BGE, PHI, Pepco, DPL, and ACE, collectively
Utility Registrants ComEd, PECO, BGE, Pepco, DPL, and ACE, collectively

BSC Exelon Business Services Company, LLC
Exelon Corporate Exelon in its corporate capacity as a holding company
PCI Potomac Capital Investment Corporation and its subsidiaries
PECO Trust III PECO Energy Capital Trust III
PECO Trust IV PECO Energy Capital Trust IV

PHI Corporate PHI in its corporate capacity as a holding company
PHISCO PHI Service Company
Former Related Entities
Constellation Constellation Energy Corporation
Generation Constellation Energy Generation, LLC (formerly Exelon Generation Company, LLC, a subsidiary of Exelon prior to separation on February 1, 2022)

4

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GLOSSARY OF TERMS AND ABBREVIATIONS
Other Terms and Abbreviations
Note - of the 2024 Form 10-K
Reference to specific Combined Note to Consolidated Financial Statements within Exelon's 2024 Annual Report on Form 10-K

ABO Accumulated Benefit Obligation
AFUDC Allowance for Funds Used During Construction
AMI Advanced Metering Infrastructure
AOCI Accumulated Other Comprehensive Income (Loss)
ARO Asset Retirement Obligation
ATM At the market
BGS Basic Generation Service
BSA Bill Stabilization Adjustment
CEJA Climate and Equitable Jobs Act; Illinois Public Act 102-0662 signed into law on September 15, 2021
CERCLA Comprehensive Environmental Response, Compensation, and Liability Act of 1980, as amended
CIP Conservation Incentive Program
CMC Carbon Mitigation Credit
CODMs Chief Operating Decision Makers
DC PLUG District of Columbia Power Line Undergrounding Initiative
DCPSC Public Service Commission of the District of Columbia
DEPSC Delaware Public Service Commission
DOEE District of Columbia Department of Energy & Environment
DPA Deferred Prosecution Agreement
DSIC Distribution System Improvement Charge

EDIT Excess Deferred Income Taxes
EPA United States Environmental Protection Agency
ERISA Employee Retirement Income Security Act of 1974, as amended
ETAC Energy Transition Assistance Charge
FERC Federal Energy Regulatory Commission
GAAP Generally Accepted Accounting Principles in the United States
GCR Gas Cost Rate
GSA Generation Supply Adjustment
GWhs Gigawatt hours
ICC Illinois Commerce Commission
IIJA Infrastructure Investment and Jobs Act
Illinois Settlement Legislation Legislation enacted in 2007 affecting electric utilities in Illinois
IPA Illinois Power Agency
IRA Inflation Reduction Act
IRC Internal Revenue Code
IRS Internal Revenue Service
MDPSC Maryland Public Service Commission
MGP Manufactured Gas Plant
mmcf Million Cubic Feet
MRP Multi-Year Rate Plan
MWh Megawatt hour
N/A Not Applicable
NAV Net Asset Value

5

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GLOSSARY OF TERMS AND ABBREVIATIONS
Other Terms and Abbreviations
NJBPU New Jersey Board of Public Utilities
NOLC Tax Net Operating Loss Carryforward
NPNS Normal Purchase Normal Sale scope exception
NPS National Park Service
NRD Natural Resources Damages
OBBBA One Big Beautiful Bill Act
OCI Other Comprehensive Income
OPEB Other Postretirement Employee Benefits
PAPUC Pennsylvania Public Utility Commission
PGC Purchased Gas Cost Clause
PJM PJM Interconnection, LLC
PLR Private Letter Ruling
POLR Provider of Last Resort
PP&E Property, Plant, and Equipment
PRPs Potentially Responsible Parties
REC Renewable Energy Credit which is issued for each megawatt hour of generation from a qualified renewable energy source
Regulatory Agreement Units Nuclear generating units or portions thereof whose decommissioning-related activities are subject to regulatory agreements with the ICC and PAPUC
Rider Reconcilable Surcharge Recovery Mechanism
ROE Return on Equity
ROU Right-of-use
RTO Regional Transmission Organization
RUBC Residential Universal Bill Credit
SEC United States Securities and Exchange Commission
SOFR Secured Overnight Financing Rate
SOS Standard Offer Service
TCJA Tax Cuts and Jobs Act
TSC Transmission Service Charge
ZEC Zero Emission Credit

6

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

CAUTIONARY STATEMENTS REGARDING FORWARD-LOOKING INFORMATION
This Report contains certain forward-looking statements within the meaning of federal securities laws that are subject to risks and uncertainties. Words such as “could,” “may,” “expects,” “anticipates,” “will,” “targets,” “goals,” “projects,” “intends,” “plans,” “believes,” “seeks,” “estimates,” “predicts,” "should," and variations on such words, and similar expressions that reflect our current views with respect to future events and operational, economic and financial performance, are intended to identify such forward-looking statements. Accordingly, any such statements are qualified in their entirety by reference to, and are accompanied by, the following important factors that may cause our actual results or outcomes to differ materially from those contained in our forward-looking statements, including, but not limited to:
• unfavorable legislative and/or regulatory actions;
• uncertainty as to outcomes and timing of regulatory approval proceedings and/or negotiated settlements thereof;
• environmental liabilities and remediation costs;
• state and federal legislation requiring use of low-emission, renewable, and/or alternate fuel sources and/or mandating implementation of energy conservation programs requiring implementation of new technologies;
• challenges to tax positions taken, tax law changes, and difficulty in quantifying potential tax effects of business decisions;
• negative outcomes in legal proceedings;
• adverse impact of the activities associated with the past DPA and now-resolved SEC investigation on Exelon’s and ComEd’s reputation and relationships with legislators, regulators, and customers;
• physical security and cybersecurity risks;
• extreme weather events, natural disasters, operational accidents such as wildfires or natural gas explosions, war, acts and threats of terrorism, public health crises, epidemics, pandemics, or other significant events;
• disruptions or cost increases in the supply chain, including shortages in labor, materials or parts, or significant increases in relevant tariffs;
• lack of sufficient capacity to meet actual or forecasted demand or disruptions at power generation facilities owned by third parties;
• emerging technologies that could affect or transform the energy industry;
• instability in capital and credit markets;
• a downgrade of any Registrant’s credit ratings or other failure to satisfy the credit standards in the Registrants’ agreements or regulatory financial requirements;
• significant economic downturns or increases in customer rates;
• impacts of climate change and weather on energy usage and maintenance and capital costs; and
7

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• impairment of long-lived assets, goodwill, and other assets.
New factors emerge from time to time, and it is impossible for us to predict all of such factors, nor can we assess the impact of each such factor on the business or the extent to which any factor, or combination of factors, may cause actual results to differ materially from those contained in any forward-looking statements. For more information, see those factors discussed in the 2024 Form 10-K filed by the Registrants, including in Part I, ITEM 1A. Risk Factors, and this Report including in Part II, ITEM 1A. Risk Factors.
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.
8

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PART I. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS
9

Table of Contents

Exelon Corporation and Subsidiary Companies
Consolidated Statements of Operations and Comprehensive Income
(Unaudited)

Three Months Ended
September 30, Nine Months Ended
September 30,
(In millions, except per share data) 2025 2024 2025 2024
Operating revenues
Electric operating revenues $ 6,690   $ 6,012   $ 17,872   $ 16,379  
Natural gas operating revenues 235   196   1,595   1,207  
Revenues from alternative revenue programs ( 220 ) ( 54 ) ( 621 ) ( 29 )
Total operating revenues 6,705   6,154   18,846   17,557  
Operating expenses
Purchased power 2,645   2,349   6,640   6,483  
Purchased fuel 47   34   471   301  

Operating and maintenance 1,172   1,275   3,840   3,756  
Depreciation and amortization 912   908   2,717   2,681  
Taxes other than income taxes 429   395   1,216   1,127  
Total operating expenses 5,205   4,961   14,884   14,348  

Gain on sale of assets —   3   1   12  

Operating income 1,500   1,196   3,963   3,221  
Other income and (deductions)
Interest expense, net ( 531 ) ( 490 ) ( 1,560 ) ( 1,428 )
Interest expense to affiliates, net ( 7 ) ( 6 ) ( 18 ) ( 18 )
Other, net 68   57   185   196  
Total other income and (deductions) ( 470 ) ( 439 ) ( 1,393 ) ( 1,250 )
Income before income taxes 1,030   757   2,570   1,971  
Income taxes 155   50   396   158  

Net income attributable to common shareholders $ 875   $ 707   $ 2,174   $ 1,813  

Comprehensive income, net of income taxes
Net income $ 875   $ 707   $ 2,174   $ 1,813  
Other comprehensive income (loss), net of income taxes
Pension and non-pension postretirement benefit plans:

Actuarial losses reclassified to periodic benefit cost 5   5   16   15  
Pension and non-pension postretirement benefit plans valuation adjustments —   —   5   ( 26 )
Unrealized (loss) gain on cash flow hedges ( 2 ) ( 29 ) ( 16 ) 1  

Other comprehensive income (loss) 3   ( 24 ) 5   ( 10 )

Comprehensive income attributable to common shareholders $ 878   $ 683   $ 2,179   $ 1,803  

Average shares of common stock outstanding:
Basic 1,011   1,003   1,010   1,002  
Assumed exercise and/or distributions of stock-based awards (a)
2   1   1   —  
Diluted 1,013   1,004   1,011   1,002  

Earnings per average common share
Basic $ 0.87   $ 0.70   $ 2.15   $ 1.81  
Diluted $ 0.86   $ 0.70   $ 2.15   $ 1.81  

__________
(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
10

Table of Contents

Exelon Corporation and Subsidiary Companies
Consolidated Statements of Cash Flows
(Unaudited)
Nine Months Ended
September 30,
(In millions) 2025 2024
Cash flows from operating activities
Net income $ 2,174   $ 1,813  
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation, amortization, and accretion 2,719   2,683  

Gain on sales of assets ( 1 ) ( 12 )

Deferred income taxes and amortization of investment tax credits 293   102  
Net fair value changes related to derivatives 3   1  

Other non-cash operating activities 1,088   441  
Changes in assets and liabilities:
Accounts receivable ( 422 ) ( 489 )
Inventories ( 41 ) ( 57 )
Accounts payable and accrued expenses 165   ( 309 )

Collateral (paid) received, net ( 25 ) 21  
Income taxes 19   ( 18 )
Regulatory assets and liabilities, net ( 390 ) 194  
Pension and non-pension postretirement benefit contributions ( 313 ) ( 140 )
Other assets and liabilities ( 259 ) ( 87 )
Net cash flows provided by operating activities 5,010   4,143  
Cash flows from investing activities
Capital expenditures ( 6,095 ) ( 5,161 )

Proceeds from sales of assets 2   38  

Other investing activities ( 7 ) 9  
Net cash flows used in investing activities ( 6,100 ) ( 5,114 )
Cash flows from financing activities
Changes in short-term borrowings ( 779 ) ( 1,093 )
Proceeds from short-term borrowings with maturities greater than 90 days —   150  
Repayments on short-term borrowings with maturities greater than 90 days —   ( 549 )
Issuance of long-term debt 4,925   4,975  
Retirement of long-term debt ( 807 ) ( 1,336 )

Issuance of common stock 173   148  

Dividends paid on common stock ( 1,212 ) ( 1,142 )
Proceeds from employee stock plans 24   33  

Other financing activities ( 75 ) ( 83 )
Net cash flows provided by financing activities 2,249   1,103  
Increase in cash, restricted cash, and cash equivalents 1,159   132  
Cash, restricted cash, and cash equivalents at beginning of period 939   1,101  
Cash, restricted cash, and cash equivalents at end of period $ 2,098   $ 1,233  

Supplemental cash flow information
(Decrease) increase in capital expenditures not paid ( 12 ) 6  

(Decrease) increase in PP&E related to ARO update ( 5 ) 16  

See the Combined Notes to Consolidated Financial Statements
11

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Exelon Corporation and Subsidiary Companies
Consolidated Balance Sheets
(Unaudited)

(In millions) September 30, 2025 December 31, 2024
ASSETS
Current assets
Cash and cash equivalents $ 1,533   $ 357  
Restricted cash and cash equivalents 516   541  

Accounts receivable
Customer accounts receivable 3,356 3,144
Customer allowance for credit losses ( 451 ) ( 406 )
Customer accounts receivable, net 2,905   2,738  
Other accounts receivable 1,192 1,123
Other allowance for credit losses ( 98 ) ( 107 )
Other accounts receivable, net 1,094   1,016  
Inventories, net
Fossil fuel 100   72  
Materials and supplies 788   781  
Regulatory assets 1,489   1,940  
Prepaid renewable energy credits 445   494  
Other 359   445  
Total current assets 9,229   8,384  
Property, plant, and equipment (net of accumulated depreciation and amortization of $ 19,606 and $ 18,445 as of September 30, 2025 and December 31, 2024, respectively)
82,100   78,182  
Deferred debits and other assets
Regulatory assets 8,881   8,710  
Goodwill 6,630   6,630  
Receivable related to Regulatory Agreement Units 4,658   4,026  
Investments 307   290  
Other 1,734   1,562  
Total deferred debits and other assets 22,210   21,218  
Total assets $ 113,539   $ 107,784  

See the Combined Notes to Consolidated Financial Statements
12

Table of Contents

Exelon Corporation and Subsidiary Companies
Consolidated Balance Sheets
(Unaudited)

(In millions) September 30, 2025 December 31, 2024
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities
Short-term borrowings $ 1,080   $ 1,859  
Long-term debt due within one year 2,168   1,453  
Accounts payable 3,240   2,994  
Accrued expenses 1,414   1,468  
Payables to affiliates 5   5  
Customer deposits 507   446  
Regulatory liabilities 507   411  
Mark-to-market derivative liabilities 28   29  
Unamortized energy contract liabilities 5   5  
Renewable energy credit obligations 352   429  
Other 519   512  
Total current liabilities 9,825   9,611  
Long-term debt 46,283   42,947  
Long-term debt to financing trusts 390   390  
Deferred credits and other liabilities
Deferred income taxes and unamortized investment tax credits 13,519   12,793  
Regulatory liabilities 10,904   10,198  
Pension obligations 1,480   1,745  
Non-pension postretirement benefit obligations 493   472  
Asset retirement obligations 303   301  
Mark-to-market derivative liabilities 109   103  
Unamortized energy contract liabilities 18   21  
Other 2,102   2,282  
Total deferred credits and other liabilities 28,928   27,915  
Total liabilities 85,426   80,863  
Commitments and contingencies

Shareholders’ equity
Common stock ( No par value, 2,000 shares authorized, 1,010 shares and 1,005 shares outstanding as of September 30, 2025 and December 31, 2024, respectively)
21,564   21,338  
Treasury stock, at cost ( 2 shares as of September 30, 2025 and December 31, 2024)
( 123 ) ( 123 )
Retained earnings 7,387   6,426  
Accumulated other comprehensive loss, net ( 715 ) ( 720 )
Total shareholders’ equity 28,113   26,921  

Total liabilities and shareholders’ equity $ 113,539   $ 107,784  

See the Combined Notes to Consolidated Financial Statements
13

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Exelon Corporation and Subsidiary Companies
Consolidated Statements of Changes in Shareholders' Equity
(Unaudited)

Nine Months Ended September 30, 2025
(In millions, shares
in thousands) Issued
Shares Common
Stock Treasury
Stock Retained
Earnings Accumulated
Other
Comprehensive
Loss, net Total Shareholders'
Equity
Balance at December 31, 2024 1,007,046 $ 21,338   $ ( 123 ) $ 6,426   $ ( 720 ) $ 26,921  
Net income —  —  —  908   —  908  
Long-term incentive plan activity 299   4   —  —  —  4  
Employee stock purchase plan activity ( 8 ) 2   —  —  —  2  
Issuance of Common Stock 4,031   173   —  —  —  173  

Common stock dividends
($ 0.40 /common share)
—  —  —  ( 403 ) —  ( 403 )
Other comprehensive income, net of income taxes —  —  —  —  2   2  

Balance at March 31, 2025 1,011,368 $ 21,517   $ ( 123 ) $ 6,931   $ ( 718 ) $ 27,607  
Net income —  —  —  391   —  391  
Long-term incentive plan activity 118   14   —  —  —  14  
Employee stock purchase plan activity 334   13   —  —  —  13  

Common stock dividends
($ 0.40 /common share)
—  —  —  ( 405 ) —  ( 405 )

Balance at June 30, 2025 1,011,820 $ 21,544   $ ( 123 ) $ 6,917   $ ( 718 ) $ 27,620  
Net income —  —  —  875   —  875  
Long-term incentive plan activity 4   6   —  —  —  6  
Employee stock purchase plan activity 299   14   —  —  —  14  

Common stock dividends
($ 0.40 /common share)
—  —  —  ( 405 ) —  ( 405 )
Other comprehensive income, net of income taxes —  —  —  —  3   3  
Balance at September 30, 2025 1,012,123 $ 21,564   $ ( 123 ) $ 7,387   $ ( 715 ) $ 28,113  

See the Combined Notes to Consolidated Financial Statements
14

Table of Contents

Nine Months Ended September 30, 2024
(In millions, shares
in thousands) Issued
Shares Common
Stock Treasury
Stock Retained
Earnings Accumulated
Other
Comprehensive
Loss, net Total Shareholders'
Equity
Balance at December 31, 2023 1,001,249   $ 21,114   $ ( 123 ) $ 5,490   $ ( 726 ) $ 25,755  
Net income —  —  —  658   —  658  
Long-term incentive plan activity 333   2   —  —  —  2  
Employee stock purchase plan activity 276   13   —  —  —  13  

Common stock dividends
($ 0.38 /common share)
—  —  —  ( 381 ) —  ( 381 )
Other comprehensive income, net of income taxes —  —  —  —  14   14  

Balance at March 31, 2024 1,001,858   $ 21,129   $ ( 123 ) $ 5,767   $ ( 712 ) $ 26,061  
Net income —  —  —  448   —  448  
Long-term incentive plan activity 76   11   —  —  —  11  
Employee stock purchase plan activity 396   12   —  —  —  12  

Common stock dividends
($ 0.38 /common share)
—  —  —  ( 380 ) —  ( 380 )

Balance at June 30, 2024 1,002,330   $ 21,152   $ ( 123 ) $ 5,835   $ ( 712 ) $ 26,152  
Net Income —  —  —  707   —  707  
Long-term incentive plan activity 7   7   —  —  —  7  
Employee stock purchase plan activity 349   13   —  —  —  13  
Issuance of common stock 3,980   148   —  148  

Common stock dividends
($ 0.38 /common share)
—  —  —  ( 381 ) —  ( 381 )
Other comprehensive income, net of income taxes —  —  —  —  ( 24 ) ( 24 )
Balance at September 30, 2024 1,006,666   $ 21,320   $ ( 123 ) $ 6,161   $ ( 736 ) $ 26,622  

See the Combined Notes to Consolidated Financial Statements
15

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Commonwealth Edison Company and Subsidiary Companies
Consolidated Statements of Operations and Comprehensive Income
(Unaudited)

Three Months Ended
September 30, Nine Months Ended
September 30,
(In millions) 2025 2024 2025 2024
Operating revenues
Electric operating revenues $ 2,479   $ 2,303   $ 6,682   $ 6,497  
Revenues from alternative revenue programs ( 206 ) ( 76 ) ( 525 ) ( 100 )
Operating revenues from affiliates 2   2   19   6  
Total operating revenues 2,275   2,229   6,176   6,403  
Operating expenses
Purchased power 806   835   2,044   2,504  

Operating and maintenance 313   307   958   970  
Operating and maintenance from affiliates 96   103   296   307  
Depreciation and amortization 395   387   1,162   1,124  
Taxes other than income taxes 107   99   303   287  
Total operating expenses 1,717   1,731   4,763   5,192  
Gain on sale of assets —   —   —   5  
Operating income 558   498   1,413   1,216  
Other income and (deductions)
Interest expense, net ( 132 ) ( 125 ) ( 385 ) ( 364 )
Interest expense to affiliates, net ( 3 ) ( 3 ) ( 10 ) ( 10 )
Other, net 33   26   86   66  
Total other income and (deductions) ( 102 ) ( 102 ) ( 309 ) ( 308 )
Income before income taxes 456   396   1,104   908  
Income taxes 83   36   201   85  
Net income $ 373   $ 360   $ 903   $ 823  
Comprehensive income $ 373   $ 360   $ 903   $ 823  

See the Combined Notes to Consolidated Financial Statements
16

Table of Contents

Commonwealth Edison Company and Subsidiary Companies
Consolidated Statements of Cash Flows
(Unaudited)

Nine Months Ended
September 30,
(In millions) 2025 2024
Cash flows from operating activities
Net income $ 903   $ 823  
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation and amortization 1,162   1,124  
Gain on sales of assets —   ( 5 )
Deferred income taxes and amortization of investment tax credits 21   ( 16 )

Other non-cash operating activities 634   161  
Changes in assets and liabilities:
Accounts receivable ( 347 ) ( 327 )
Receivables from and payables to affiliates, net ( 16 ) 43  
Inventories 12   ( 17 )
Accounts payable and accrued expenses 112   ( 207 )
Collateral (paid) received, net ( 31 ) 21  
Income taxes 66   ( 109 )
Regulatory assets and liabilities, net ( 128 ) 422  
Pension and non-pension postretirement benefit contributions ( 192 ) ( 11 )
Other assets and liabilities ( 136 ) 134  
Net cash flows provided by operating activities 2,060   2,036  
Cash flows from investing activities
Capital expenditures ( 1,970 ) ( 1,619 )

Other investing activities 5   8  
Net cash flows used in investing activities ( 1,965 ) ( 1,611 )
Cash flows from financing activities
Changes in short-term borrowings ( 36 ) ( 129 )

Repayments on short-term borrowings with maturities greater than 90 days —   ( 400 )
Issuance of long-term debt 725   800  
Retirement of long-term debt —   ( 250 )
Dividends paid on common stock ( 610 ) ( 582 )
Contributions from parent 108   117  
Other financing activities ( 7 ) ( 12 )
Net cash flows provided by (used in) financing activities 180   ( 456 )
Increase (decrease) in cash, restricted cash, and cash equivalents 275   ( 31 )
Cash, restricted cash, and cash equivalents at beginning of period 632   686  
Cash, restricted cash, and cash equivalents at end of period $ 907   $ 655  

Supplemental cash flow information
Increase (decrease) in capital expenditures not paid $ 74   $ ( 31 )

See the Combined Notes to Consolidated Financial Statements
17

Table of Contents

Commonwealth Edison Company and Subsidiary Companies
Consolidated Balance Sheets
(Unaudited)

(In millions) September 30, 2025 December 31, 2024
ASSETS
Current assets
   Cash and cash equivalents $ 405   $ 105  
   Restricted cash and cash equivalents 453   486  
   Accounts receivable
   Customer accounts receivable 1,205 994
   Customer allowance for credit losses ( 115 ) ( 109 )
       Customer accounts receivable, net 1,090   885  
   Other accounts receivable 353 290
   Other allowance for credit losses ( 25 ) ( 34 )
       Other accounts receivable, net 328   256  

   Receivables from affiliates 4   4  

   Inventories, net 274   292  

   Regulatory assets 705   1,159  

   Other 201   141  
   Total current assets 3,460   3,328  
Property, plant, and equipment (net of accumulated depreciation and amortization of $ 8,134 and $ 7,619 as of September 30, 2025 and December 31, 2024, respectively)
31,446   30,211  
Deferred debits and other assets
   Regulatory assets 2,646   2,562  

   Goodwill 2,625   2,625  

   Receivable related to Regulatory Agreement Units 4,231   3,780  
   Investments 7   6  
   Prepaid pension asset 1,301   1,165  

   Other 1,294   1,073  
   Total deferred debits and other assets 12,104   11,211  
Total assets $ 47,010   $ 44,750  

See the Combined Notes to Consolidated Financial Statements
18

Table of Contents

Commonwealth Edison Company and Subsidiary Companies
Consolidated Balance Sheets
(Unaudited)

(In millions) September 30, 2025 December 31, 2024
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities
   Short-term borrowings $ —   $ 36  
   Long-term debt due within one year 500   —  
   Accounts payable 992   748  
   Accrued expenses 460   463  
   Payables to affiliates 61   77  
   Customer deposits 178   134  
   Regulatory liabilities 221   197  
   Mark-to-market derivative liabilities 28   29  

   Other 278   270  
   Total current liabilities 2,718   1,954  
Long-term debt 12,251   12,030  
Long-term debt to financing trust 206   206  
Deferred credits and other liabilities
   Deferred income taxes and unamortized investment tax credits 5,773   5,601  
   Regulatory liabilities 9,041   8,421  
   Asset retirement obligations 172   167  

   Non-pension postretirement benefit obligations 164   156  

   Mark-to-market derivative liabilities 100   103  

   Other 1,304   1,232  
   Total deferred credits and other liabilities 16,554   15,680  
   Total liabilities 31,729   29,870  
Commitments and contingencies
Shareholders’ equity
   Common stock 1,588   1,588  

   Other paid-in capital 10,736   10,628  
   Retained earnings 2,957   2,664  

   Total shareholders’ equity 15,281   14,880  
Total liabilities and shareholders’ equity $ 47,010   $ 44,750  
    
See the Combined Notes to Consolidated Financial Statements
19

Table of Contents

Commonwealth Edison Company and Subsidiary Companies
Consolidated Statements of Changes in Shareholders' Equity
(Unaudited)

Nine Months Ended September 30, 2025
(In millions) Common
Stock Other
Paid-In
Capital Retained
Earnings Total
Shareholders’
Equity
Balance at December 31, 2024 $ 1,588   $ 10,628   $ 2,664   $ 14,880  
Net income —  —  302   302  
Common stock dividends —  —  ( 203 ) ( 203 )
Contributions from parent —  87   —  87  
Balance at March 31, 2025 $ 1,588   $ 10,715   $ 2,763   $ 15,066  
Net income —  —  228   228  
Common stock dividends —  —  ( 204 ) ( 204 )
Contributions from parent —  —   —  —  
Balance at June 30, 2025 $ 1,588   $ 10,715   $ 2,787   $ 15,090  
Net income —  —  373   373  
Common stock dividends —  —  ( 203 ) ( 203 )
Contributions from parent —  21   —  21  
Balance at September 30, 2025 $ 1,588   $ 10,736   $ 2,957   $ 15,281  

Nine Months Ended September 30, 2024
(In millions) Common
Stock Other
Paid-In
Capital Retained
Earnings Total
Shareholders’
Equity
Balance at December 31, 2023 $ 1,588   $ 10,401   $ 2,374   $ 14,363  
Net income —  —  193   193  
Common stock dividends —  —  ( 194 ) ( 194 )
Contributions from parent —  39   —  39  
Balance at March 31, 2024 $ 1,588   $ 10,440   $ 2,373   $ 14,401  
Net income —  —  270   270  
Common stock dividends —  —  ( 194 ) ( 194 )
Contributions from parent —  39   —  39  
Balance at June 30, 2024 $ 1,588   $ 10,479   $ 2,449   $ 14,516  
Net income —  —  360   360  
Common stock dividends —  —  ( 194 ) ( 194 )
Contributions from parent —  39   —  39  
Balance at September 30, 2024 $ 1,588   $ 10,518   $ 2,615   $ 14,721  

See the Combined Notes to Consolidated Financial Statements
20

Table of Contents

PECO Energy Company and Subsidiary Companies
Consolidated Statements of Operations and Comprehensive Income
(Unaudited)

  Three Months Ended
September 30, Nine Months Ended
September 30,
(In millions) 2025 2024 2025 2024
Operating revenues
Electric operating revenues $ 1,093   $ 952   $ 2,932   $ 2,529  
Natural gas operating revenues 82   69   578   436  
Revenues from alternative revenue programs 2   5   ( 6 ) 3  
Operating revenues from affiliates 3   4   9   7  
Total operating revenues 1,180   1,030   3,513   2,975  
Operating expenses
Purchased power 428   372   1,093   977  
Purchased fuel 18   14   195   136  

Operating and maintenance 183   251   690   695  
Operating and maintenance from affiliates 58   62   182   181  
Depreciation and amortization 115   108   336   318  
Taxes other than income taxes 69   61   183   164  
Total operating expenses 871   868   2,679   2,471  
Gain on sales of assets —   —   —   4  
Operating income 309   162   834   508  
Other income and (deductions)
Interest expense, net ( 63 ) ( 55 ) ( 179 ) ( 161 )
Interest expense to affiliates, net ( 2 ) ( 3 ) ( 9 ) ( 9 )
Other, net 11   9   29   27  
Total other income and (deductions) ( 54 ) ( 49 ) ( 159 ) ( 143 )
Income before income taxes 255   113   675   365  
Income taxes 5   ( 4 ) 23   9  

Net income $ 250   $ 117   $ 652   $ 356  
Comprehensive income $ 250   $ 117   $ 652   $ 356  

See the Combined Notes to Consolidated Financial Statements
21

Table of Contents

PECO Energy Company and Subsidiary Companies
Consolidated Statements of Cash Flows
(Unaudited)

Nine Months Ended
September 30,
(In millions) 2025 2024
Cash flows from operating activities
Net income $ 652   $ 356  
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation and amortization 336   318  

Gain on sales of assets —   ( 4 )
Deferred income taxes and amortization of investment tax credits ( 60 ) ( 27 )
Other non-cash operating activities 69   58  
Changes in assets and liabilities:
Accounts receivable ( 94 ) ( 75 )
Receivables from and payables to affiliates, net ( 8 ) ( 2 )
Inventories ( 8 ) ( 2 )
Accounts payable and accrued expenses ( 4 ) ( 65 )
Collateral (paid) received, net 6   —  
Income taxes 13   ( 55 )
Regulatory assets and liabilities, net ( 26 ) 17  
Pension and non-pension postretirement benefit contributions ( 11 ) ( 3 )
Other assets and liabilities ( 10 ) ( 19 )
Net cash flows provided by operating activities 855   497  
Cash flows from investing activities
Capital expenditures ( 1,334 ) ( 1,125 )
Changes in Exelon intercompany money pool ( 222 ) ( 89 )

Other investing activities 1   5  
Net cash flows used in investing activities ( 1,555 ) ( 1,209 )
Cash flows from financing activities

Changes in short-term borrowings ( 192 ) ( 165 )
Issuance of long-term debt 1,050   575  

Dividends paid on common stock ( 410 ) ( 300 )
Contributions from parent 578   595  

Other financing activities ( 10 ) ( 7 )
Net cash flows provided by financing activities 1,016   698  
Increase (decrease) in cash, restricted cash, and cash equivalents 316   ( 14 )
Cash, restricted cash, and cash equivalents at beginning of period 48   51  
Cash, restricted cash, and cash equivalents at end of period $ 364   $ 37  

Supplemental cash flow information
Increase in capital expenditures not paid $ 81   $ 60  

See the Combined Notes to Consolidated Financial Statements
22

Table of Contents

PECO Energy Company and Subsidiary Companies
Consolidated Balance Sheets
(Unaudited)

(In millions) September 30, 2025 December 31, 2024
ASSETS
Current assets
Cash and cash equivalents $ 364   $ 48  

Accounts receivable
Customer accounts receivable 697 670
Customer allowance for credit losses ( 145 ) ( 133 )
Customer accounts receivable, net 552   537  
Other accounts receivable 156 145
Other allowance for credit losses ( 17 ) ( 18 )
Other accounts receivable, net 139   127  

Receivables from affiliates 2   —  
Receivable from Exelon intercompany money pool 222   —  

Inventories, net
Fossil fuel 46   37  
Materials and supplies 76   79  
Prepaid utility taxes 18   2  
Prepaid renewable energy credits 36   51  
Regulatory assets 66   65  

Other 31   27  
Total current assets 1,552   973  
Property, plant, and equipment (net of accumulated depreciation and amortization of $ 4,080 and $ 4,042 as of September 30, 2025 and December 31, 2024, respectively)
15,490   14,392  
Deferred debits and other assets
Regulatory assets 1,231   1,003  

Receivable related to Regulatory Agreement Units 428   247  
Investments 43   41  
Prepaid pension asset 443   435  

Other 40   32  
Total deferred debits and other assets 2,185   1,758  
Total assets $ 19,227   $ 17,123  

See the Combined Notes to Consolidated Financial Statements
23

Table of Contents

PECO Energy Company and Subsidiary Companies
Consolidated Balance Sheets
(Unaudited)

(In millions) September 30, 2025 December 31, 2024
LIABILITIES AND SHAREHOLDER'S EQUITY
Current liabilities
Short-term borrowings $ —   $ 192  
Long-term debt due within one year 350   350  
Accounts payable 753   639  
Accrued expenses 150   166  
Payables to affiliates 35   41  

Customer deposits 87   80  
Renewable energy credit obligations 37   52  
Regulatory liabilities 154   122  

Other 50   28  
Total current liabilities 1,616   1,670  
Long-term debt 6,396   5,354  
Long-term debt to financing trusts 184   184  
Deferred credits and other liabilities
Deferred income taxes and unamortized investment tax credits 2,557   2,433  
Regulatory liabilities 433   253  
Asset retirement obligations 26   27  
Non-pension postretirement benefit obligations 288   287  

Other 92   100  
Total deferred credits and other liabilities 3,396   3,100  
Total liabilities 11,592   10,308  
Commitments and contingencies
Shareholder’s equity
Common stock 5,223   4,645  

Retained earnings 2,412   2,170  

Total shareholder’s equity 7,635   6,815  
Total liabilities and shareholder's equity $ 19,227   $ 17,123  

See the Combined Notes to Consolidated Financial Statements
24

Table of Contents

PECO Energy Company and Subsidiary Companies
Consolidated Statements of Changes in Shareholders' Equity
(Unaudited)

Nine Months Ended September 30, 2025
(In millions) Common
Stock Retained
Earnings Total
Shareholder's
Equity
Balance at December 31, 2024 $ 4,645   $ 2,170   $ 6,815  
Net income —  266   266  
Common stock dividends —  ( 137 ) ( 137 )
Contributions from parent 563   —  563  
Balance at March 31, 2025 $ 5,208   $ 2,299   $ 7,507  
Net income —  136   136  
Common stock dividends —  ( 136 ) ( 136 )
Contributions from parent —   —  —  
Balance at June 30, 2025 $ 5,208   $ 2,299   $ 7,507  
Net income —  250   250  
Common stock dividends —  ( 137 ) ( 137 )
Contributions from parent 15   —  15  
Balance at September 30, 2025 $ 5,223   $ 2,412   $ 7,635  

Nine Months Ended September 30, 2024
(In millions) Common
Stock Retained
Earnings Total
Shareholder's
Equity
Balance at December 31, 2023 $ 4,050   $ 2,019   $ 6,069  
Net income —  149   149  
Common stock dividends —  ( 100 ) ( 100 )
Contributions from parent 580   —  580  
Balance at March 31, 2024 $ 4,630   $ 2,068   $ 6,698  
Net income —  90   90  
Common stock dividends —  ( 100 ) ( 100 )

Balance at June 30, 2024 $ 4,630   $ 2,058   $ 6,688  
Net income —  117   117  
Common stock dividends —  ( 100 ) ( 100 )
Contributions from parent 15   —  15  
Balance at September 30, 2024 $ 4,645   $ 2,075   $ 6,720  

See the Combined Notes to Consolidated Financial Statements
25

Table of Contents

Baltimore Gas and Electric Company
Statements of Operations and Comprehensive Income
(Unaudited)

Three Months Ended
September 30, Nine Months Ended
September 30,
(In millions) 2025 2024 2025 2024
Operating revenues
Electric operating revenues $ 1,102   $ 928   $ 2,978   $ 2,585  
Natural gas operating revenues 125   104   870   648  
Revenues from alternative revenue programs ( 20 ) 9   ( 63 ) 28  
Operating revenues from affiliates 2   3   6   7  
Total operating revenues 1,209   1,044   3,791   3,268  
Operating expenses
Purchased power 547   407   1,365   1,108  
Purchased fuel 21   13   219   120  

Operating and maintenance 179   221   621   613  
Operating and maintenance from affiliates 60   60   186   182  
Depreciation and amortization 155   162   473   474  
Taxes other than income taxes 93   86   273   254  
Total operating expenses 1,055   949   3,137   2,751  

Operating income 154   95   654   517  
Other income and (deductions)
Interest expense, net ( 64 ) ( 57 ) ( 183 ) ( 159 )
Other, net 15   11   35   27  
Total other income and (deductions) ( 49 ) ( 46 ) ( 148 ) ( 132 )
Income before income taxes 105   49   506   385  
Income taxes 23   4   108   32  
Net income $ 82   $ 45   $ 398   $ 353  
Comprehensive income $ 82   $ 45   $ 398   $ 353  

See the Combined Notes to Consolidated Financial Statements
26

Table of Contents

Baltimore Gas and Electric Company
Statements of Cash Flows
(Unaudited)

Nine Months Ended
September 30,
(In millions) 2025 2024
Cash flows from operating activities
Net income $ 398   $ 353  
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation and amortization 473   474  

Deferred income taxes and amortization of investment tax credits 53   ( 5 )

Other non-cash operating activities 127   49  
Changes in assets and liabilities:
Accounts receivable 34   25  
Receivables from and payables to affiliates, net ( 15 ) 14  
Inventories ( 10 ) ( 6 )
Accounts payable and accrued expenses 88   37  
Collateral received, net 2   —  
Income taxes 19   ( 51 )
Regulatory assets and liabilities, net ( 114 ) ( 69 )
Pension and non-pension postretirement benefit contributions ( 40 ) ( 34 )
Other assets and liabilities 116   102  
Net cash flows provided by operating activities 1,131   889  
Cash flows from investing activities
Capital expenditures ( 1,211 ) ( 1,033 )

Other investing activities 7   10  
Net cash flows used in investing activities ( 1,204 ) ( 1,023 )
Cash flows from financing activities
Changes in short-term borrowings ( 175 ) ( 336 )
Issuance of long-term debt 650   800  

Dividends paid on common stock ( 294 ) ( 276 )
Contributions from parent 531   237  
Other financing activities ( 8 ) ( 9 )
Net cash flows provided by financing activities 704   416  
Increase in cash, restricted cash, and cash equivalents 631   282  
Cash, restricted cash, and cash equivalents at beginning of period 34   48  
Cash, restricted cash, and cash equivalents at end of period $ 665   $ 330  

Supplemental cash flow information
(Decrease) increase in capital expenditures not paid $ ( 46 ) $ 38  

See the Combined Notes to Consolidated Financial Statements
27

Table of Contents

Baltimore Gas and Electric Company
Balance Sheets
(Unaudited)

(In millions) September 30, 2025 December 31, 2024
ASSETS
Current assets
Cash and cash equivalents $ 663   $ 33  
Restricted cash and cash equivalents 2   1  
Accounts receivable
Customer accounts receivable 625 654
Customer allowance for credit losses ( 68 ) ( 56 )
Customer accounts receivable, net 557   598  
Other accounts receivable 91 113
Other allowance for credit losses ( 5 ) ( 6 )
Other accounts receivable, net 86   107  

Receivables from affiliates 1   —  

Inventories, net
Fossil fuel 45   29  
Materials and supplies 78   84  
Prepaid utility taxes 1   115  
Regulatory assets 199   207  
Prepaid renewable energy credits 143   157  
Other 18   17  
Total current assets 1,793   1,348  
Property, plant, and equipment (net of accumulated depreciation and amortization of $ 5,132 and $ 5,005 as of September 30, 2025 and December 31, 2024, respectively)
13,890   13,134  
Deferred debits and other assets
Regulatory assets 799   788  
Investments 10   10  

Prepaid pension asset 206   218  

Other 44   44  
Total deferred debits and other assets 1,059   1,060  
Total assets $ 16,742   $ 15,542  

See the Combined Notes to Consolidated Financial Statements
28

Table of Contents

Baltimore Gas and Electric Company
Balance Sheets
(Unaudited)

(In millions) September 30, 2025 December 31, 2024
LIABILITIES AND SHAREHOLDER'S EQUITY
Current liabilities
Short-term borrowings $ —   $ 175  
Long-term debt due within one year 350   —  
Accounts payable 483   515  
Accrued expenses 263   176  
Payables to affiliates 33   48  
Customer deposits 122   118  
Regulatory liabilities 6   12  

Renewable energy credit obligations 146   160  
Other 45   39  
Total current liabilities 1,448   1,243  
Long-term debt 5,691   5,395  
Deferred credits and other liabilities
Deferred income taxes and unamortized investment tax credits 2,193   2,099  
Regulatory liabilities 614   636  
Asset retirement obligations 36   36  
Non-pension postretirement benefit obligations 144   150  

Other 96   97  
Total deferred credits and other liabilities 3,083   3,018  
Total liabilities 10,222   9,656  
Commitments and contingencies
Shareholder's equity
Common stock 4,014   3,483  

Retained earnings 2,506   2,403  

Total shareholder's equity 6,520   5,886  

Total liabilities and shareholder's equity $ 16,742   $ 15,542  

See the Combined Notes to Consolidated Financial Statements
29

Table of Contents

Baltimore Gas and Electric Company
Statements of Changes in Shareholder's Equity
(Unaudited)

Nine Months Ended September 30, 2025
(In millions) Common
Stock Retained
Earnings Total
Shareholder's
Equity
Balance at December 31, 2024 $ 3,483   $ 2,403   $ 5,886  
Net income —  260   260  
Common stock dividends —  ( 98 ) ( 98 )
Contributions from parent —   —  —  
Balance at March 31, 2025 $ 3,483   $ 2,565   $ 6,048  
Net income —  55   55  
Common stock dividends —  ( 98 ) ( 98 )
Contributions from parent —   —  —  
Balance at June 30, 2025 $ 3,483   $ 2,522   $ 6,005  
Net income —  82   82  
Common stock dividends —  ( 98 ) ( 98 )
Contributions from parent 531   —  531  
Balance at September 30, 2025 $ 4,014   $ 2,506   $ 6,520  

Nine Months Ended September 30, 2024
(In millions) Common
Stock Retained
Earnings Total
Shareholder's
Equity
Balance at December 31, 2023 $ 3,246   $ 2,244   $ 5,490  
Net income —  264   264  
Common stock dividends —  ( 92 ) ( 92 )
Contributions from parent —   —  —  
Balance at March 31, 2024 $ 3,246   $ 2,416   $ 5,662  
Net income —  44   44  
Common stock dividends —  ( 92 ) ( 92 )
Contributions from parent 197   —  197  
Balance at June 30, 2024 $ 3,443   $ 2,368   $ 5,811  
Net income —  45   45  
Common stock dividends —  ( 92 ) ( 92 )
Contributions from parent 40   —  40  
Balance at September 30, 2024 $ 3,483   $ 2,321   $ 5,804  

See the Combined Notes to Consolidated Financial Statements
30

Table of Contents

Pepco Holdings LLC and Subsidiary Companies
Consolidated Statements of Operations and Comprehensive Income
(Unaudited)

Three Months Ended
September 30, Nine Months Ended
September 30,
(In millions) 2025 2024 2025 2024
Operating revenues
Electric operating revenues $ 2,016   $ 1,828   $ 5,280   $ 4,769  
Natural gas operating revenues 27   23   148   122  
Revenues from alternative revenue programs 6   8   ( 27 ) 40  
Operating revenues from affiliates 2   3   7   7  
Total operating revenues 2,051   1,862   5,408   4,938  
Operating expenses
Purchased power 864   735   2,138   1,895  
Purchased fuel 8   7   57   44  

Operating and maintenance 290   275   876   780  
Operating and maintenance from affiliates 45   47   148   147  
Depreciation and amortization 234   235   701   716  
Taxes other than income taxes 150   140   426   395  
Total operating expenses 1,591   1,439   4,346   3,977  

Gain on sale of assets —   —   1   —  
Operating income 460   423   1,063   961  
Other income and (deductions)
Interest expense, net ( 102 ) ( 95 ) ( 303 ) ( 279 )
Interest expense to affiliates, net —   —   ( 2 ) —  
Other, net 18   22   54   79  
Total other income and (deductions) ( 84 ) ( 73 ) ( 251 ) ( 200 )
Income before income taxes 376   350   812   761  
Income taxes 85   72   184   158  

Net income $ 291   $ 278   $ 628   $ 603  

Comprehensive income $ 291   $ 278   $ 628   $ 603  

See the Combined Notes to Consolidated Financial Statements
31

Table of Contents

Pepco Holdings LLC and Subsidiary Companies
Consolidated Statements of Cash Flows
(Unaudited)

Nine Months Ended
September 30,
(In millions) 2025 2024
Cash flows from operating activities
Net income $ 628   $ 603  
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation, amortization, and accretion 703   716  

Gain on sales of assets ( 1 ) —  
Deferred income taxes and amortization of investment tax credits 93   56  

Other non-cash operating activities 172   96  
Changes in assets and liabilities:
Accounts receivable ( 28 ) ( 116 )
Receivables from and payables to affiliates, net ( 17 ) ( 8 )
Inventories ( 36 ) ( 32 )
Accounts payable and accrued expenses 21   37  

Collateral received, net 1   1  
Income taxes ( 13 ) ( 55 )
Regulatory assets and liabilities, net ( 88 ) ( 158 )
Pension and non-pension postretirement benefit contributions ( 47 ) ( 79 )
Other assets and liabilities ( 20 ) ( 74 )
Net cash flows provided by operating activities 1,368   987  
Cash flows from investing activities
Capital expenditures ( 1,552 ) ( 1,343 )
Proceeds from sales of long-lived assets 2   —  

Net cash flows used in investing activities ( 1,550 ) ( 1,343 )
Cash flows from financing activities
Changes in short-term borrowings ( 364 ) ( 176 )

Issuance of long-term debt 500   1,100  
Retirement of long-term debt —   ( 583 )
Changes in Exelon intercompany money pool 1   10  

Distributions to member ( 548 ) ( 549 )
Contributions from member 569   505  

Other financing activities ( 19 ) ( 33 )
Net cash flows provided by financing activities 139   274  
Decrease in cash, restricted cash, and cash equivalents ( 43 ) ( 82 )
Cash, restricted cash, and cash equivalents at beginning of period 163   204  
Cash, restricted cash, and cash equivalents at end of period $ 120   $ 122  

Supplemental cash flow information
Decrease in capital expenditures not paid $ ( 92 ) $ ( 27 )

See the Combined Notes to Consolidated Financial Statements
32

Table of Contents

Pepco Holdings LLC and Subsidiary Companies
Consolidated Balance Sheets
(Unaudited)

(In millions) September 30, 2025 December 31, 2024
ASSETS
Current assets
Cash and cash equivalents $ 93   $ 139  
Restricted cash and cash equivalents 27   24  
Accounts receivable
Customer accounts receivable 829 827
Customer allowance for credit losses ( 123 ) ( 108 )
Customer accounts receivable, net 706   719  
Other accounts receivable 281 284
Other allowance for credit losses ( 51 ) ( 49 )
Other accounts receivable, net 230   235  

Receivables from affiliates 13   8  

Inventories, net
Fossil fuel 9   7  
Materials and supplies 360   325  

Prepaid utility taxes 17   70  
Regulatory assets 333   323  

Prepaid renewable energy credits 155   194  
Other 31   36  
Total current assets 1,974   2,080  
Property, plant, and equipment (net of accumulated depreciation and amortization of $ 4,196 and $ 3,728 as of September 30, 2025 and December 31, 2024, respectively)
20,925   20,053  
Deferred debits and other assets
Regulatory assets 1,531   1,570  
Goodwill 4,005   4,005  
Investments 156   152  

Prepaid pension asset 222   252  

Other 134   185  
Total deferred debits and other assets 6,048   6,164  
Total assets $ 28,947   $ 28,297  

See the Combined Notes to Consolidated Financial Statements
33

Table of Contents

Pepco Holdings LLC and Subsidiary Companies
Consolidated Balance Sheets
(Unaudited)

(In millions) September 30, 2025 December 31, 2024
LIABILITIES AND MEMBER'S EQUITY
Current liabilities
Short-term borrowings $ 166   $ 530  
Long-term debt due within one year 214   290  
Accounts payable 671   721  
Accrued expenses 343   367  
Payables to affiliates 54   66  
Borrowings from Exelon intercompany money pool 64   63  

Customer deposits 120   113  
Regulatory liabilities 115   69  
Unamortized energy contract liabilities 5   5  

Renewable energy credit obligations 169   217  
Other 97   124  
Total current liabilities 2,018   2,565  
Long-term debt 9,385   8,834  
Deferred credits and other liabilities
Deferred income taxes and unamortized investment tax credits 3,337   3,190  
Regulatory liabilities 731   794  
Asset retirement obligations 65   67  
Non-pension postretirement benefit obligations 26   31  

Unamortized energy contract liabilities 17   21  
Other 397   473  
Total deferred credits and other liabilities 4,573   4,576  
Total liabilities 15,976   15,975  
Commitments and contingencies

Member's equity
Membership interest 13,131   12,562  

Undistributed losses ( 160 ) ( 240 )

Total member's equity 12,971   12,322  
Total liabilities and member's equity $ 28,947   $ 28,297  

See the Combined Notes to Consolidated Financial Statements
34

Table of Contents

Pepco Holdings LLC and Subsidiary Companies
Consolidated Statements of Changes in Member's Equity
(Unaudited)

Nine Months Ended September 30, 2025
(In millions) Membership Interest Undistributed (Losses)/Gains Total Member's Equity
Balance at December 31, 2024 $ 12,562   $ ( 240 ) $ 12,322  
Net income —  194   194  
Distributions to member —  ( 132 ) ( 132 )
Contributions from member 352   —  352  
Balance at March 31, 2025 $ 12,914   $ ( 178 ) $ 12,736  
Net income —  143   143  
Distributions to member —  ( 160 ) ( 160 )
Contributions from member 170   —  170  
Balance at June 30, 2025 $ 13,084   $ ( 195 ) $ 12,889  
Net income —  291   291  
Distributions to member —  ( 256 ) ( 256 )
Contributions from member 47   —  47  

Balance at September 30, 2025 $ 13,131   $ ( 160 ) $ 12,971  

Nine Months Ended September 30, 2024
(In millions) Membership Interest Undistributed (Losses)/Gains Total Member's Equity
Balance at December 31, 2023 $ 12,057   $ ( 275 ) $ 11,782  
Net income —  168   168  
Distributions to member —  ( 118 ) ( 118 )
Contributions from member 487   —  487  
Balance at March 31, 2024 $ 12,544   $ ( 225 ) $ 12,319  
Net income —  158   158  
Distributions to member —  ( 164 ) ( 164 )
Contributions from member —   —  —  
Balance at June 30, 2024 $ 12,544   $ ( 231 ) $ 12,313  
Net income —  278   278  
Distributions to member —  ( 267 ) ( 267 )
Contributions from member 18   —  18  
Balance at September 30, 2024 $ 12,562   $ ( 220 ) $ 12,342  

See the Combined Notes to Consolidated Financial Statements
35

Table of Contents

Potomac Electric Power Company
Statements of Operations and Comprehensive Income
(Unaudited)

Three Months Ended
September 30, Nine Months Ended
September 30,
(In millions) 2025 2024 2025 2024
Operating revenues
Electric operating revenues $ 995   854   $ 2,641   $ 2,273  
Revenues from alternative revenue programs ( 5 ) 5   ( 19 ) 42  
Operating revenues from affiliates 2   2   4   5  
Total operating revenues 992   861   2,626   2,320  
Operating expenses
Purchased power 367   294   942   808  

Operating and maintenance 95   82   282   206  
Operating and maintenance from affiliates 59   58   184   186  
Depreciation and amortization 110   102   321   307  
Taxes other than income taxes 122   114   344   317  
Total operating expenses 753   650   2,073   1,824  

Gain on sale of assets —   —   1   —  

Operating income 239   211   554   496  
Other income and (deductions)
Interest expense, net ( 53 ) ( 50 ) ( 159 ) ( 142 )

Other, net 11   11   31   43  
Total other income and (deductions) ( 42 ) ( 39 ) ( 128 ) ( 99 )
Income before income taxes 197   172   426   397  
Income taxes 41   32   89   74  

Net income $ 156   $ 140   $ 337   $ 323  

Comprehensive income $ 156   $ 140   $ 337   $ 323  

See the Combined Notes to Consolidated Financial Statements
36

Table of Contents

Potomac Electric Power Company
Statements Of Cash Flows
(Unaudited)

Nine Months Ended
September 30,
(In millions) 2025 2024
Cash flows from operating activities
Net income $ 337   $ 323  
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation, amortization, and accretion 322   307  
Gain on sales of assets ( 1 ) —  
Deferred income taxes and amortization of investment tax credits 34   22  

Other non-cash operating activities 62   ( 11 )
Changes in assets and liabilities:
Accounts receivable ( 58 ) ( 37 )
Receivables from and payables to affiliates, net —   1  
Inventories ( 11 ) ( 10 )
Accounts payable and accrued expenses 20   61  
Collateral received (paid), net 2   ( 1 )
Income taxes ( 27 ) ( 45 )
Regulatory assets and liabilities, net ( 39 ) ( 54 )
Pension and non-pension postretirement benefit contributions ( 7 ) ( 7 )
Other assets and liabilities ( 5 ) ( 56 )
Net cash flows provided by operating activities 629   493  
Cash flows from investing activities
Capital expenditures ( 690 ) ( 672 )
Proceeds from sales of long-lived assets 2   —  

Net cash flows used in investing activities ( 688 ) ( 672 )
Cash flows from financing activities
Changes in short-term borrowings ( 137 ) ( 83 )
Issuance of long-term debt 275   675  
Retirement of long-term debt —   ( 400 )

Dividends paid on common stock ( 267 ) ( 286 )
Contributions from parent 192   260  

Other financing activities ( 8 ) ( 19 )
Net cash flows provided by financing activities 55   147  
Decrease in cash, restricted cash, and cash equivalents ( 4 ) ( 32 )
Cash, restricted cash, and cash equivalents at beginning of period 51   72  
Cash, restricted cash, and cash equivalents at end of period $ 47   $ 40  

Supplemental cash flow information
Decrease in capital expenditures not paid $ ( 34 ) $ ( 27 )

See the Combined Notes to Consolidated Financial Statements
37

Table of Contents

Potomac Electric Power Company
Balance Sheets
(Unaudited)

(In millions) September 30, 2025 December 31, 2024
ASSETS
Current assets
Cash and cash equivalents $ 25   $ 30  
Restricted cash and cash equivalents 22   21  
Accounts receivable
Customer accounts receivable 431 395
Customer allowance for credit losses ( 72 ) ( 59 )
Customer accounts receivable, net 359   336  
Other accounts receivable 149 142
Other allowance for credit losses ( 28 ) ( 27 )
Other accounts receivable, net 121   115  

Receivables from affiliates 1   1  

Inventories, net 181   169  

Regulatory assets 166   157  

Prepaid renewable energy credits 132   165  
Other 21   55  
Total current assets 1,028   1,049  
Property, plant, and equipment (net of accumulated depreciation and amortization of $ 4,719 and $ 4,522 as of September 30, 2025 and December 31, 2024, respectively)
10,493   10,097  
Deferred debits and other assets
Regulatory assets 408   446  
Investments 139   135  

Prepaid pension asset 201   222  

Other 57   51  
Total deferred debits and other assets 805   854  
Total assets $ 12,326   $ 12,000  

See the Combined Notes to Consolidated Financial Statements
38

Table of Contents

Potomac Electric Power Company
Balance Sheets
(Unaudited)

(In millions) September 30, 2025 December 31, 2024
LIABILITIES AND SHAREHOLDER'S EQUITY
Current liabilities
Short-term borrowings $ 63   $ 200  
Long-term debt due within one year 6   6  
Accounts payable 351   360  
Accrued expenses 167   201  
Payables to affiliates 33   37  

Customer deposits 60   55  
Regulatory liabilities 12   17  
Merger related obligation 20   22  

Renewable energy credit obligations 134   169  
Other 46   51  
Total current liabilities 892   1,118  
Long-term debt 4,626   4,356  

Deferred credits and other liabilities
Deferred income taxes and unamortized investment tax credits 1,581   1,509  
Regulatory liabilities 276   310  
Asset retirement obligations 48   49  

Other 206   223  
Total deferred credits and other liabilities 2,111   2,091  
Total liabilities 7,629   7,565  
Commitments and contingencies
Shareholder's equity
Common stock 3,527   3,335  

Retained earnings 1,170   1,100  

Total shareholder's equity 4,697   4,435  
Total liabilities and shareholder's equity $ 12,326   $ 12,000  

See the Combined Notes to Consolidated Financial Statements
39

Table of Contents

Potomac Electric Power Company
Statements Of Changes In Shareholder's Equity
(Unaudited)

Nine Months Ended September 30, 2025
(In millions) Common Stock Retained Earnings Total Shareholder's Equity
Balance at December 31, 2024 $ 3,335   $ 1,100   $ 4,435  
Net income —  97   97  
Common stock dividends —  ( 66 ) ( 66 )
Contributions from parent 157   —  157  
Balance at March 31, 2025 $ 3,492   $ 1,131   $ 4,623  
Net income —  84   84  

Common stock dividends —  ( 92 ) ( 92 )
Contributions from parent —   —  —  
Balance at June 30, 2025 $ 3,492   $ 1,123   $ 4,615  
Net income —  156   156  

Common stock dividends —  ( 109 ) ( 109 )
Contributions from parent 35   —  35  
Balance at September 30, 2025 $ 3,527   $ 1,170   $ 4,697  

Nine Months Ended September 30, 2024
(In millions) Common Stock Retained Earnings Total Shareholder's Equity
Balance at December 31, 2023 $ 3,075   $ 1,069   $ 4,144  
Net income —  75   75  
Common stock dividends —  ( 51 ) ( 51 )
Contributions from parent 251   —  251  
Balance at March 31, 2024 $ 3,326   $ 1,093   $ 4,419  
Net income —  108   108  

Common stock dividends —  ( 102 ) ( 102 )
Contributions from parent —   —  —  
Balance at June 30, 2024 $ 3,326   $ 1,099   $ 4,425  
Net income —  140   140  

Common stock dividends —  ( 133 ) ( 133 )
Contributions from parent 9   —  9  
Balance at September 30, 2024 $ 3,335   $ 1,106   $ 4,441  

See the Combined Notes to Consolidated Financial Statements
40

Table of Contents

Delmarva Power & Light Company
Statements of Operations and Comprehensive Income
(Unaudited)

Three Months Ended
September 30, Nine Months Ended
September 30,
(In millions) 2025 2024 2025 2024
Operating revenues
Electric operating revenues $ 467   $ 440   $ 1,316   $ 1,215  
Natural gas operating revenues 27   23   148   122  
Revenues from alternative revenue programs ( 5 ) ( 3 ) ( 10 ) 1  
Operating revenues from affiliates 2   2   6   5  
Total operating revenues 491   462   1,460   1,343  
Operating expenses
Purchased power 211   196   580   529  
Purchased fuel 8   7   57   44  

Operating and maintenance 51   49   162   151  
Operating and maintenance from affiliates 43   43   134   133  
Depreciation and amortization 63   62   189   183  
Taxes other than income taxes 21   20   63   59  
Total operating expenses 397   377   1,185   1,099  

Operating income 94   85   275   244  
Other income and (deductions)
Interest expense, net ( 26 ) ( 22 ) ( 75 ) ( 69 )

Other, net 4   6   12   20  
Total other income and (deductions) ( 22 ) ( 16 ) ( 63 ) ( 49 )
Income before income taxes 72   69   212   195  
Income taxes 17   14   49   39  

Net income $ 55   $ 55   $ 163   $ 156  
Comprehensive income $ 55   $ 55   $ 163   $ 156  

See the Combined Notes to Consolidated Financial Statements
41

Table of Contents

Delmarva Power & Light Company
Statements Of Cash Flows
(Unaudited)

Nine Months Ended
September 30,
(In millions) 2025 2024
Cash flows from operating activities
Net income $ 163   $ 156  
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation and amortization 189   183  

Deferred income taxes and amortization of investment tax credits 24   12  

Other non-cash operating activities 42   29  
Changes in assets and liabilities:
Accounts receivable 20   ( 1 )
Receivables from and payables to affiliates, net ( 3 ) ( 3 )
Inventories ( 16 ) ( 17 )
Accounts payable and accrued expenses 15   14  
Collateral received, net —   2  
Income taxes ( 1 ) ( 25 )
Regulatory assets and liabilities, net ( 32 ) ( 41 )
Pension and non-pension postretirement benefit contributions ( 1 ) ( 1 )
Other assets and liabilities 23   19  
Net cash flows provided by operating activities 423   327  
Cash flows from investing activities
Capital expenditures ( 402 ) ( 404 )

Net cash flows used in investing activities ( 402 ) ( 404 )
Cash flows from financing activities
Changes in short-term borrowings ( 111 ) ( 63 )
Issuance of long-term debt 125   175  
Retirement of long-term debt —   ( 33 )

Dividends paid on common stock ( 149 ) ( 162 )
Contributions from parent 107   160  
Other financing activities ( 8 ) ( 6 )
Net cash flows (used in) provided by financing activities ( 36 ) 71  
Decrease in cash, restricted cash, and cash equivalents ( 15 ) ( 6 )
Cash, restricted cash, and cash equivalents at beginning of period 23   16  
Cash, restricted cash, and cash equivalents at end of period $ 8   $ 10  

Supplemental cash flow information
(Decrease) increase in capital expenditures not paid $ ( 40 ) $ 9  

    
See the Combined Notes to Consolidated Financial Statements
42

Table of Contents

Delmarva Power & Light Company
Balance Sheets
(Unaudited)

(In millions) September 30, 2025 December 31, 2024
ASSETS
Current assets
Cash and cash equivalents $ 6   $ 21  
Restricted cash and cash equivalents 2   2  
Accounts receivable
Customer accounts receivable 178 210
Customer allowance for credit losses ( 20 ) ( 17 )
Customer accounts receivable, net 158   193  
Other accounts receivable 67 63
Other allowance for credit losses ( 9 ) ( 9 )
Other accounts receivable, net 58   54  
Receivables from affiliates 1   —  

Inventories, net
Fossil fuel 9   6  
Materials and supplies 108   95  
Prepaid utility taxes —   26  

Regulatory assets 69   60  
Prepaid renewable energy credits 22   29  
Other 10   16  
Total current assets 443   502  
Property, plant, and equipment (net of accumulated depreciation and amortization of $ 2,196 and $ 2,075 as of September 30, 2025 and December 31, 2024, respectively)
5,733   5,540  
Deferred debits and other assets
Regulatory assets 212   215  

Prepaid pension asset 107   120  
Other 45   44  
Total deferred debits and other assets 364   379  
Total assets $ 6,540   $ 6,421  

See the Combined Notes to Consolidated Financial Statements
43

Table of Contents

Delmarva Power & Light Company
Balance Sheets
(Unaudited)

(In millions) September 30, 2025 December 31, 2024
LIABILITIES AND SHAREHOLDER'S EQUITY
Current liabilities
Short-term borrowings $ 33   $ 144  
Long-term debt due within one year 53   130  
Accounts payable 147   187  
Accrued expenses 71   55  
Payables to affiliates 23   26  

Customer deposits 35   34  
Regulatory liabilities 38   42  
Renewable energy credit obligations 35   48  
Other 18   22  
Total current liabilities 453   688  
Long-term debt 2,291   2,090  
Deferred credits and other liabilities
Deferred income taxes and unamortized investment tax credits 983   946  
Regulatory liabilities 316   325  
Asset retirement obligations 12   13  

Non-pension postretirement benefit obligations 2   3  
Other 120   114  
Total deferred credits and other liabilities 1,433   1,401  
Total liabilities 4,177   4,179  
Commitments and contingencies
Shareholder's equity
Common stock 1,722   1,615  

Retained earnings 641   627  
Total shareholder's equity 2,363   2,242  
Total liabilities and shareholder's equity $ 6,540   $ 6,421  

See the Combined Notes to Consolidated Financial Statements
44

Table of Contents

Delmarva Power & Light Company
Statements Of Changes In Shareholder's Equity
(Unaudited)

Nine Months Ended September 30, 2025
(In millions) Common Stock Retained Earnings Total Shareholder's Equity
Balance at December 31, 2024 $ 1,615   $ 627   $ 2,242  
Net income —  69   69  
Common stock dividends —  ( 46 ) ( 46 )
Contributions from parent 99   —  99  
Balance at March 31, 2025 $ 1,714   $ 650   $ 2,364  
Net income —  39   39  
Common stock dividends —  ( 44 ) ( 44 )
Contributions from parent —   —  —  
Balance at June 30, 2025 $ 1,714   $ 645   $ 2,359  
Net income —  55   55  
Common stock dividends —  ( 59 ) ( 59 )
Contributions from parent 8   —  8  
Balance at September 30, 2025 $ 1,722   $ 641   $ 2,363  

Nine Months Ended September 30, 2024
(In millions) Common Stock Retained Earnings Total Shareholder's Equity
Balance at December 31, 2023 $ 1,455   $ 638   $ 2,093  
Net income —  66   66  
Common stock dividends —  ( 45 ) ( 45 )
Contributions from parent 154   —  154  
Balance at March 31, 2024 $ 1,609   $ 659   $ 2,268  
Net income —  34   34  
Common stock dividends —  ( 39 ) ( 39 )

Balance at June 30, 2024 $ 1,609   $ 654   $ 2,263  
Net income —  55   55  
Common stock dividends —  ( 78 ) ( 78 )
Contributions from parent 6   —  6  
Balance at September 30, 2024 $ 1,615   $ 631   $ 2,246  

See the Combined Notes to Consolidated Financial Statements
45

Table of Contents

Atlantic City Electric Company and Subsidiary Company
Consolidated Statements of Operations and Comprehensive Income
(Unaudited)

Three Months Ended
September 30, Nine Months Ended
September 30,
(In millions) 2025 2024 2025 2024
Operating revenues
Electric operating revenues $ 553   $ 533   $ 1,323   $ 1,281  
Revenues from alternative revenue programs 16   6   2   ( 3 )
Operating revenues from affiliates 1   1   3   2  
Total operating revenues 570   540   1,328   1,280  
Operating expenses
Purchased power 286   245   616   557  

Operating and maintenance 55   58   161   155  
Operating and maintenance from affiliates 37   38   116   119  
Depreciation and amortization 61   67   188   214  
Taxes other than income taxes 2   2   7   7  
Total operating expenses 441   410   1,088   1,052  

Operating income 129   130   240   228  
Other income and (deductions)
Interest expense, net ( 20 ) ( 21 ) ( 62 ) ( 59 )

Other, net 2   4   8   12  
Total other income and (deductions) ( 18 ) ( 17 ) ( 54 ) ( 47 )
Income before income taxes 111   113   186   181  
Income taxes 29   30   48   48  

Net income $ 82   $ 83   $ 138   $ 133  
Comprehensive income $ 82   $ 83   $ 138   $ 133  

See the Combined Notes to Consolidated Financial Statements
46

Table of Contents

Atlantic City Electric Company and Subsidiary Company
Statements Of Cash Flows
(Unaudited)

Nine Months Ended
September 30,
(In millions) 2025 2024
Cash flows from operating activities
Net income $ 138   $ 133  
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation and amortization 188   214  
Deferred income taxes and amortization of investment tax credits 32   33  
Other non-cash operating activities 42   49  
Changes in assets and liabilities:
Accounts receivable 9   ( 77 )
Receivables from and payables to affiliates, net ( 8 ) ( 8 )
Inventories ( 10 ) ( 5 )
Accounts payable and accrued expenses 5   ( 18 )

Income taxes 3   ( 2 )
Regulatory assets and liabilities, net ( 14 ) ( 62 )
Pension and non-pension postretirement benefit contributions ( 3 ) ( 7 )
Other assets and liabilities ( 21 ) ( 39 )
Net cash flows provided by operating activities 361   211  
Cash flows from investing activities
Capital expenditures ( 292 ) ( 265 )

Net cash flows used in investing activities ( 292 ) ( 265 )
Cash flows from financing activities
Changes in short-term borrowings ( 116 ) ( 30 )

Issuance of long-term debt 100   250  
Retirement of long-term debt —   ( 150 )

Dividends paid on common stock ( 132 ) ( 100 )
Contributions from parent 98   85  
Other financing activities ( 5 ) ( 5 )
Net cash flows (used in) provided by financing activities ( 55 ) 50  
Increase (decrease) in cash and cash equivalents 14   ( 4 )
Cash and cash equivalents at beginning of period 14   21  
Cash and cash equivalents at end of period $ 28   $ 17  

Supplemental cash flow information
Decrease in capital expenditures not paid $ ( 19 ) $ ( 10 )

See the Combined Notes to Consolidated Financial Statements
47

Table of Contents

Atlantic City Electric Company and Subsidiary Company
Consolidated Balance Sheets
(Unaudited)

(In millions) September 30, 2025 December 31, 2024
ASSETS
Current assets
Cash and cash equivalents $ 25   $ 14  
Restricted cash and cash equivalents 3   —  
Accounts receivable
Customer accounts receivable 221 223
Customer allowance for credit losses ( 31 ) ( 32 )
Customer accounts receivable, net 190   191  
Other accounts receivable 64 79
Other allowance for credit losses ( 14 ) ( 13 )
Other accounts receivable, net 50   66  

Receivables from affiliates 11   7  

Inventories, net 72   62  

Prepaid utility taxes 7   —  
Regulatory assets 94   101  
Other 8   6  
Total current assets 460   447  
Property, plant, and equipment (net of accumulated depreciation and amortization of $ 1,917 and $ 1,798 as of September 30, 2025 and December 31, 2024, respectively)
4,484   4,366  
Deferred debits and other assets
Regulatory assets 526   502  

Prepaid pension asset 3   1  

Other 43   33  
Total deferred debits and other assets 572   536  
Total assets $ 5,516   $ 5,349  

See the Combined Notes to Consolidated Financial Statements
48

Table of Contents

Atlantic City Electric Company and Subsidiary Company
Consolidated Balance Sheets
(Unaudited)

(In millions) September 30, 2025 December 31, 2024
LIABILITIES AND SHAREHOLDER'S EQUITY
Current liabilities
Short-term borrowings $ 70   $ 186  
Long-term debt due within one year 155   154  
Accounts payable 164   163  
Accrued expenses 47   52  
Payables to affiliates 18   22  

Customer deposits 25   24  
Regulatory liabilities 66   10  

Other 10   10  
Total current liabilities 555   621  
Long-term debt 1,880   1,779  
Deferred credits and other liabilities
Deferred income taxes and unamortized investment tax credits 851   816  
Regulatory liabilities 138   146  

Other 64   62  
Total deferred credits and other liabilities 1,053   1,024  
Total liabilities 3,488   3,424  
Commitments and contingencies
Shareholder's equity
Common stock 2,013   1,915  
Retained earnings 15   10  

Total shareholder's equity 2,028   1,925  
Total liabilities and shareholder's equity $ 5,516   $ 5,349  

See the Combined Notes to Consolidated Financial Statements
49

Table of Contents

Atlantic City Electric Company and Subsidiary Company
Consolidated Statements Of Changes In Shareholder's Equity
(Unaudited)

Nine Months Ended September 30, 2025
(In millions) Common Stock Retained (Deficit) Earnings Total Shareholder's Equity
Balance at December 31, 2024 $ 1,915   $ 10   $ 1,925  
Net income —  31   31  
Common stock dividends —  ( 20 ) ( 20 )
Contributions from parent 94   —  94  
Balance at March 31, 2025 $ 2,009   $ 21   $ 2,030  
Net income —  24   24  
Common stock dividends —  ( 24 ) ( 24 )
Contributions from parent —   —  —  
Balance at June 30, 2025 $ 2,009   $ 21   $ 2,030  
Net income —  82   82  
Common stock dividends —  ( 88 ) ( 88 )
Contributions from parent 4   —  4  
Balance at September 30, 2025 $ 2,013   $ 15   $ 2,028  

Nine Months Ended September 30, 2024
(In millions) Common Stock Retained (Deficit) Earnings Total Shareholder's Equity
Balance at December 31, 2023 $ 1,830   $ ( 18 ) $ 1,812  
Net income —  29   29  
Common stock dividends —  ( 22 ) ( 22 )
Contributions from parent 81   —  81  
Balance at March 31, 2024 $ 1,911   $ ( 11 ) $ 1,900  
Net income —  21   21  
Common stock dividends —  ( 22 ) ( 22 )

Balance at June 30, 2024 $ 1,911   $ ( 12 ) $ 1,899  
Net income —  83   83  
Common stock dividends —  ( 56 ) ( 56 )
Contributions from parent 4   —  4  
Balance at September 30, 2024 $ 1,915   $ 15   $ 1,930  

See the Combined Notes to Consolidated Financial Statements
50

Table of Contents
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 electricity Northern Illinois, including the City of Chicago
Transmission and distribution of electricity to retail customers
PECO Energy Company Purchase and regulated retail sale of electricity and natural gas Southeastern Pennsylvania, including the City of Philadelphia (electricity)
Transmission and distribution of electricity and distribution of natural gas to retail customers Pennsylvania counties surrounding the City of Philadelphia (natural gas)
Baltimore Gas and Electric Company Purchase and regulated retail sale of electricity and natural gas Central Maryland, including the City of Baltimore (electricity and natural gas)
Transmission and distribution of electricity and distribution of natural gas to retail customers
Pepco Holdings LLC Utility services holding company engaged, through its reportable segments Pepco, DPL, and ACE Service Territories of Pepco, DPL, and ACE

Potomac Electric 
Power Company    Purchase and regulated retail sale of electricity    District of Columbia, and major portions of Montgomery and Prince George’s Counties, Maryland
Transmission and distribution of electricity to retail customers
Delmarva Power &
Light Company Purchase and regulated retail sale of electricity and natural gas Portions of Delaware and Maryland (electricity)
Transmission and distribution of electricity and distribution of natural gas to retail customers Portions of New Castle County, Delaware (natural gas)
Atlantic City Electric Company Purchase and regulated retail sale of electricity Portions of Southern New Jersey
Transmission and distribution of electricity to retail customers

Basis of Presentation (All Registrants)
This is a combined quarterly 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.
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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

The accompanying consolidated financial statements as of September 30, 2025 and for the three and nine months ended September 30, 2025 and 2024 are unaudited but, in the opinion of each Registrant's management, the Registrants include all adjustments that are considered necessary for a fair statement of the Registrants’ respective financial statements in accordance with GAAP. All adjustments are of a normal, recurring nature, except as otherwise disclosed. The December 31, 2024 Consolidated Balance Sheets were derived from audited financial statements. The interim financial statements are to be read in conjunction with prior annual financial statements and notes. Additionally, financial results for interim periods are not necessarily indicative of results that may be expected for any other interim period or for the fiscal year ending December 31, 2025. These Combined Notes to Consolidated Financial Statements have been prepared pursuant to the rules and regulations of the SEC for Quarterly Reports on Form 10-Q. Certain information and note disclosures normally included in financial statements prepared in accordance with GAAP have been condensed or omitted pursuant to such rules and regulations.
New Accounting Standards (All Registrants)
New Accounting Standards Issued and Not Yet Adopted as of September 30, 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 September 30, 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.
Improvement to Income Tax Disclosures (Issued December 2023). Provides additional disclosure requirements related to the effective tax rate reconciliation and income taxes paid. Under the revised guidance for the effective tax reconciliations, entities would be required to disclose: (1) eight specific categories in the effective tax rate reconciliation in both percentages and reporting currency amount, (2) additional information for reconciling items over a certain threshold, (3) explanation of individual reconciling items disclosed, and (4) provide a qualitative description of the state and local jurisdictions that contribute to the majority of the state income tax expense. For each annual period presented, the new standard requires disclosure of the year-to-date amount of income taxes paid (net of refunds received) disaggregated by federal, state, and foreign. It also requires additional disaggregated information on income taxes paid (net of refunds received) to an individual jurisdiction equal to or greater than 5% of total income taxes paid (net of refunds received). The standard is effective for annual periods beginning January 1, 2025.
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.

2. Regulatory Matters (All Registrants)
As discussed in Note 3 — Regulatory Matters of the 2024 Form 10-K, the Registrants are involved in rate and regulatory proceedings at FERC and their state commissions. The following discusses developments in 2025 and updates to the 2024 Form 10-K.
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(Dollars in millions, except per share data, unless otherwise noted)

Note 2 — Regulatory Matters

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

__________
(a) Reflects a four-year cumulative multi-year rate plan for January 1, 2024 to December 31, 2027. The MRP was originally approved by the ICC on December 14, 2023 and was subsequently amended on January 10, 2024, April 18, 2024 and December 19, 2024. The December 19, 2024 order provided a total revenue requirement increase of $ 1.045 billion inclusive of rate increases of approximately $ 752 million in 2024, $ 80 million in 2025, $ 102 million in 2026, and $ 111 million in 2027. 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 April 29, 2025, ComEd filed its 2024 MRP Reconciliation reflecting a revenue increase of $ 268 million, which includes the tax benefit of NOLCs. While NOLCs were included in the MRP Reconciliation, the impacts of the NOLCs will not be reflected in the financial statements until the PLR is received from the IRS. See Note 6 — Income Taxes for additional information on NOLCs.
(b) On October 31, 2024, the Delivery Reconciliation Amount for 2023 defined in Rider Delivery Service Pricing Reconciliation (Rider DSPR) was approved. Rider DSPR allows for the reconciliation of the revenue requirement in effect in the final years in which formula rates are determined and until such time as new rates are established under ComEd's approved MRP. The 2024 order reconciled the delivery service rates in effect in 2023 with the actual delivery service costs incurred in 2023. The reconciliation revenue requirement provides for a weighted average debt and equity return on distribution rate base of 7.02 %, inclusive of an allowed ROE of 9.89 %, reflecting the monthly yields on 30-year treasury bonds plus 580 basis points.
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Note 2 — Regulatory Matters

(c) PECO’s approved annual electric revenue requirement increase of $ 354 million is partially offset by a one-time credit of $ 64 million in 2025. In addition, the PAPUC approved the recovery of storm damage costs incurred by PECO in January 2024, up to $ 23 million, subject to review for reasonableness and prudency in PECO’s next distribution rate case.
(d) On December 12, 2024, the PAPUC issued their Opinions and Orders which approved the non-unanimous partial settlements with limited modifications for both the electric and natural gas base rate cases, and denied the Weather Normalization Adjustment requested in the natural gas base rate case.
(e) The PECO electric and natural gas base rate case proceedings were resolved through settlement agreements, which did not specify an approved ROE.
(f) Reflects a three-year cumulative multi-year plan for January 1, 2024 through December 31, 2026. The MDPSC awarded BGE electric revenue requirement increases of $ 41  million, $ 113  million, and $ 25 million in 2024, 2025, and 2026, respectively, and natural gas revenue requirement increases of $ 126  million, $ 62  million, and $ 41  million in 2024, 2025, and 2026, respectively. Requested revenue requirement increases will be used to recover capital investments designed to increase the resilience of the electric and gas distribution systems and support Maryland's climate and regulatory initiatives. The MDPSC also approved a portion of the requested 2021 and 2022 reconciliation amounts, which was recovered through separate electric and gas riders between March 2024 through February 2025. As such, the reconciliation amounts are not included in the approved revenue requirement increases. The 2021 reconciliation amounts are $ 13  million and $ 7  million for electric and gas, respectively, and the 2022 reconciliation amounts are $ 39  million and $ 15  million for electric and gas, respectively. In April 2024, BGE filed with the MDPSC its request for recovery of the 2023 reconciliation amounts of $ 79  million and $ 73  million for electric and gas, respectively, with supporting testimony and schedules.
(g) Reflects a two-year cumulative multi-year plan for January 1, 2025, through December 31, 2026. The DCPSC awarded Pepco electric incremental revenue requirement increases of $ 99  million and $ 24  million for 2025 and 2026, respectively.
(h) Reflects the amounts requested (before offsets) and awarded for a one-year multi-year plan for April 1, 2024 through March 31, 2025. The MDPSC awarded Pepco an electric incremental revenue requirement increase of $ 45  million for the 12-month period ending March 31, 2025. The MDPSC did not adopt the requested revenue requirement increases of $ 80  million (before offsets), $ 51  million, and $ 14  million as filed for 2025, 2026, and the 2027 nine-month extension period, respectively. The MDPSC also approved the requested reconciliation amounts for the 12-month periods ending March 31, 2022, and March 31, 2023, which will be recovered through a rider between August 2024 through March 2026. As such, the reconciliation amounts are not included in the approved revenue requirement increases. The reconciliation amounts are $ 1  million and $ 7  million, for the 12-month periods ending March 31, 2022, and March 31, 2023, respectively. In July 2024, Pepco filed its request with the MDPSC for recovery of $ 31  million for the 12-month period ended March 31, 2024, with supporting testimony and schedules.
(i) Reflects a three-year cumulative multi-year plan for January 1, 2023 through December 31, 2025. The MDPSC awarded DPL electric incremental revenue requirement increases of $ 17 million, $ 6 million, and $ 6 million for 2023, 2024, and 2025, respectively.
(j) On April 18, 2024, the DEPSC approved the Significant Storm Expense Rate Rider (Rider SSER) which will allow DPL to recover expenses associated with qualified storms. A qualified storm will be an individual storm for which DPL incurs expenses between $ 5  million and $ 15  million. The Rider SSER allows DPL to recover significant storm damage expenses for the previous 12-month period over a future 24-month period. For individual storm events for which DPL incurs expenses of more than $ 15  million, the future recovery period will be evaluated on a case-by-case basis and the unamortized balance will earn a return at DPL's authorized long-term cost of debt. The Rider SSER will have an annual true-up filing, subject to DEPSC review and approval.
(k) Requested and approved increases are before New Jersey sales and use tax. The NJBPU awarded ACE electric revenue requirement increases of $ 36  million and $ 9  million effective December 1, 2023 and February 1, 2024, respectively.
Pending Distribution Base Rate Case Proceedings

Registrant/Jurisdiction Filing Date Service Requested Revenue Requirement Increase Requested ROE Expected Approval Timing
Pepco - Maryland October 14, 2025 Electric $ 133   10.50 % Third quarter of 2026
DPL - Delaware (a)
September 20, 2024 (amended September 5, 2025) Natural Gas $ 37   10.65 % First quarter of 2026
ACE - New Jersey (b)
November 21, 2024 Electric $ 109   10.70 % Fourth quarter of 2025
__________
(a) DPL implemented interim rates on April 20, 2025, subject to refund.
(b) Requested increases are before New Jersey sales and use tax. ACE may implement interim rates, subject to refund.
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Note 2 — Regulatory Matters

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 filing reflects 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 6 — 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, (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 (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
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Note 2 — Regulatory Matters

reconciliation is subject to adjustment for certain costs, including a limitation on recovery of costs that are more than 105 % of certain costs in the previously approved MRP revenue requirement, absent a modification of the rate plan itself. Thus, for example, the rate adjustments necessary to reconcile 2024 revenues to ComEd’s actual 2024 costs incurred would take effect in January 2026 after the ICC’s review during 2025.
On December 14, 2023, the ICC issued a final order. The ICC rejected ComEd’s Grid Plan as non-compliant with certain requirements of CEJA and required ComEd to file a revised Grid Plan. In the absence of an approved Grid Plan, the ICC set ComEd’s forecast revenue requirements for 2024-2027 based on ComEd's approved year-end 2022 rate base. This resulted in a total cumulative revenue requirement increase of $ 501  million, a $ 986  million total revenue reduction from the requested cumulative revenue requirement increase but 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 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 Grid Plan with supporting testimony and schedules with the ICC and subsequently on March 15, 2024, ComEd also filed a petition to adjust its MRP to authorize increased rates consistent with the Refiled Grid Plan. On December 19, 2024, the ICC approved the Refiled Grid Plan and adjusted the approved MRP with rates effective on January 1, 2025. The final approved MRP, as adjusted, which reflects the Refiled Grid Plan, resulted in a total cumulative revenue requirement increase of $ 1.045 billion over the 2024-2027 plan years and remains subject to annual reconciliations in accordance with CEJA. 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.
In January 2022, ComEd filed a request with the ICC proposing performance metrics that would be used in determining ROE incentives and penalties in the event ComEd filed a MRP in January 2023. On September 27, 2022, the ICC issued a final order approving seven performance metrics that provide symmetrical performance adjustments of 32 total basis points to ComEd’s rate of return on common equity based on the extent to which ComEd achieves the annual performance goals. On November 10, 2022, the ICC granted ComEd's application for rehearing, in part. On April 5, 2023, the ICC issued its final order on rehearing for the performance and tracking metrics proceeding, in which the ICC declined to adopt ComEd's proposed modifications to the reliability and peak load reduction performance metrics.
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 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. As of September 30, 2025, the seller had not provided notification to ComEd or the IPA that any subsidies or tax credits, such as nuclear production tax credits that became available for electricity generated beginning January 1, 2024, have been monetized and the IPA has not adjusted the CMC price paid by ComEd. The consumer protection measures contained in CEJA will result in net payments to ComEd ratepayers if the energy index, the capacity price and applicable federal tax credits or subsidy exceed the CMC contract price. Beginning with the June 2022 monthly billing period, ComEd began issuing credits and/or charges to its retail customers under its CMC rider, the Rider Carbon-Free Resource Adjustment (Rider CFRA). A regulatory asset is recorded for the difference between ComEd's costs associated with the procurement of CMCs from
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Note 2 — Regulatory Matters

participating nuclear power generating facilities and revenues received from customers. The balance as of September 30, 2025 is $ 94 million. On October 31, 2025, the seller provided notification to ComEd and the IPA that it has reflected on its 2024 federal income 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 and returned to customers. In the fourth quarter of 2025, Exelon and ComEd’s Consolidated Balance Sheets will reflect these amounts as a receivable from the seller with an offsetting regulatory liability.
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). ComEd filed its annual energy efficiency formula rate update with the ICC on May 23, 2025. The revenue requirement is used to set the rates that will take effect in January 2026, subject to the ICC's review and approval. The requested revenue requirement update is based on a reconciliation of the 2024 actual costs plus projected 2026 expenditures.

Initial Revenue Requirement Increase Annual Reconciliation Decrease Total Revenue Requirement Increase Requested Return on Rate Base (a)
Requested ROE
$ 24   $ ( 4 ) $ 20   7.24   % 10.21   %

__________
(a) The requested revenue requirement increase provides for a weighted average debt and equity return on the energy efficiency regulatory asset and rate base of 7.24 % inclusive of an allowed ROE of 10.21 %, reflecting the monthly average yields for 30-year treasury bonds plus 580 basis points. For the 2024 reconciliation year, the requested revenue requirement provides for a weighted average debt and equity return on the energy efficiency regulatory asset and rate base of 7.51 % 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.
Maryland Regulatory Matters
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 will no longer be filed. DPL also derecognized Regulatory liabilities of $ 0.4  million during the second quarter of 2025 for multi-year reconciliations yet to be filed. Multi-year plan reconciliations filed prior to January 1, 2025, remain lawful and will be resolved in their respective proceedings.
Summer 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 will be distributed to residential customers
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Note 2 — Regulatory Matters

based on their consumption of electricity supply that is 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. An additional disbursement from the state of Maryland is expected in the first quarter of 2026, which will also be used to reduce residential customer receivables upon receipt.
New Jersey Regulatory Matters
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 a Regulatory asset. 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.
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 will be funded by the NJBPU. The program will provide 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 $ 25 million in bill credits to residential customers in September 2025 reducing the Regulatory liability to $ 26  million as of September 30, 2025. The remaining funds were disbursed in October 2025.
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. ComEd responded to that report and on August 28, 2023, ComEd filed a formal notice of the issues it contested within the audit report. On December 14, 2023, FERC appointed a settlement judge for the contested overhead allocation findings and set the matter for a trial-type hearing. That hearing process was held in abeyance while a formal settlement process, which began in February 2024, took place.
On July 30, 2024, ComEd reached an agreement in principle on the contested overhead allocation finding. As a result of the settlement process, ComEd recorded a charge for the probable disallowance of $ 70  million of certain currently capitalized construction costs to operating expenses, which are not expected to be recovered in future rates. The 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.
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Note 2 — Regulatory Matters

Regulatory Assets and Liabilities
The Utility Registrants' regulatory assets and liabilities have not changed materially since December 31, 2024, unless noted below. See Note 3 — Regulatory Matters of the 2024 Form 10-K for additional information on the specific regulatory assets and liabilities.
ComEd. Regulatory assets decreased $ 370 million primarily due to a decrease of $ 453 million in the Electric distribution formula rate annual reconciliations, partially offset by an increase of $ 73 million in the Zero emission credit regulatory assets. Regulatory liabilities increased $ 644 million primarily due to an increase of $ 451 million in the Decommissioning the Regulatory Agreement Units and an increase of $ 193 million in Renewable portfolio standards costs regulatory liabilities.
PECO. Regulatory assets increased $ 229  million primarily due to an increase of $ 184  million in the Deferred income taxes regulatory asset and an increase of $ 53  million in the Deferred storm cost regulatory asset. Regulatory liabilities increased $ 212  million primarily due to an increase of $ 181  million in the Decommissioning the Regulatory Agreement Units and an increase of $ 44  million in the Electric energy and natural gas costs regulatory liabilities.
BGE. Regulatory liabilities decreased $ 28  million primarily due to a decrease of $ 41  million in the Deferred income taxes regulatory liability, partially offset by an increase of $ 10  million in the Transmission formula rate annual reconciliations regulatory liability.
Pepco. Regulatory liabilities decreased $ 39  million primarily due to a decrease of $ 37  million in the Deferred income taxes regulatory liability.
DPL. Regulatory assets increased $ 6  million primarily due to an increase of $ 16  million in the Electric energy and natural gas costs regulatory asset, partially offset by a decrease of $ 8  million in the Transmission formula rate annual reconciliations regulatory asset.
ACE. Regulatory assets increased $ 17  million primarily due to an increase of $ 26  million in the Summer rate mitigation regulatory asset. Regulatory liabilities increased $ 48  million primarily due to an increase of $ 26  million in the RUBC regulatory liability, an increase of $ 12  million in the Transmission formula rate annual reconciliations regulatory liability, and an increase of $ 6  million in the Electric energy and natural gas costs regulatory liability.
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 September 30, 2025 and December 31, 2024.

Exelon ComEd (a)
BGE (b)
PHI Pepco (c)
DPL (d)
ACE (e)

September 30, 2025 $ 67   $ 21   $ 5   $ 41   $ 23   $ 1   $ 17  

December 31, 2024 117   46   16   55   40   1   14  

__________
(a) Reflects ComEd's unrecognized equity returns earned for ratemaking purposes on its electric distribution rates and formula rates regulatory assets.
(b) BGE's amount capitalized for ratemaking purposes primarily relates to earnings on shareholders' investment on AMI programs and investments in rate base included in the multi-year plan reconciliations.
(c) Pepco's authorized amounts capitalized for ratemaking purposes relate to earnings on shareholders' investment on AMI programs, Energy efficiency and demand response programs, 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.
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Combined Notes to Consolidated Financial Statements — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)

Note 3 — Revenue from Contracts with Customers

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.
See Note 4 — Revenue from Contracts with Customers of the 2024 Form 10-K for additional information regarding the primary sources of revenue for the Registrants.
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 deferred credits and other liabilities in their Consolidated Balance Sheets.
For Pepco, DPL, and ACE these contract liabilities primarily relate to upfront consideration received in the third quarter of 2020 for a collaborative arrangement ("Agreement") with an unrelated owner and manager of communication infrastructure, as well as additional consideration received for the payment option amendment ("Amendment") executed during the fourth quarter of 2023, which is discussed in further detail within Note 4 — Revenue from Contracts with Customers of the 2024 Form 10-K. The contract liability balance attributable to the Agreement and the Amendment is being recognized as Electric operating revenues over a 35 year period and 31 year period, respectively.
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 for the three and nine months ended September 30, 2025 and 2024. At September 30, 2025 and December 31, 2024, ComEd's, PECO's, and BGE's contract liabilities were immaterial.

Exelon (a)
PHI (a)
Pepco (a)
DPL ACE
Balance at December 31, 2024 $ 127   $ 127   $ 101   $ 13   $ 13  
Revenues recognized ( 1 ) ( 1 ) ( 1 ) —   —  
Balance at March 31, 2025 $ 126   $ 126   $ 100   $ 13   $ 13  
Revenues recognized ( 3 ) ( 3 ) ( 2 ) ( 1 ) —  
Balance at June 30, 2025 $ 123   $ 123   $ 98   $ 12   $ 13  
Revenues recognized ( 1 ) ( 1 ) ( 1 ) —   —  
Balance at September 30, 2025 $ 122   $ 122   $ 97   $ 12   $ 13  

Exelon (a)
PHI (a)
Pepco (a)
DPL ACE
Balance at December 31, 2023 $ 133   $ 133   $ 107   $ 13   $ 13  
Revenues recognized ( 2 ) ( 2 ) ( 2 ) —   —  
Balance at March 31, 2024 $ 131   $ 131   $ 105   $ 13   $ 13  
Revenues recognized ( 1 ) ( 1 ) ( 1 ) —   —  
Balance at June 30, 2024 $ 130   $ 130   $ 104   $ 13   $ 13  
Revenues recognized ( 2 ) ( 2 ) ( 2 ) —   —  
Balance at September 30, 2024 $ 128   $ 128   $ 102   $ 13   $ 13  
__________
(a) Revenues recognized in the three and nine months ended September 30, 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 September 30, 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.
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Combined Notes to Consolidated Financial Statements — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)

Note 3 — Revenue from Contracts with Customers

This disclosure excludes the Utility Registrants' gas and electric tariff sales contracts and transmission revenue contracts as they generally have an original expected duration of one year or less and, therefore, do not contain any future, unsatisfied performance obligations to be included in this disclosure.

Year Exelon PHI Pepco DPL ACE
2025 $ 3   $ 3   $ 2   $ —   $ 1  
2026 5   5   5   —   —  
2027 6   6   5   1   —  
2028 6   6   5   —   1  
2029 and thereafter 102   102   80   11   11  
Total $ 122   $ 122   $ 97   $ 12   $ 13  

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 Registrants' 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, PHI, 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.
An analysis and reconciliation of the Registrants’ reportable segment information to the respective information in the consolidated financial statements for the three and nine months ended September 30, 2025 and 2024 is as follows:
Three Months Ended September 30, 2025 and 2024

ComEd PECO BGE PHI Other (a)
Intersegment
Eliminations Exelon
Operating revenues (b) :

2025
Electric revenues $ 2,275   $ 1,097   $ 1,091   $ 2,021   $ —   $ ( 6 ) $ 6,478  
Natural gas revenues —   83   118   27   —   ( 1 ) 227  
Shared service and other revenues —   —   —   3   447   ( 450 ) —  
Total operating revenues $ 2,275   $ 1,180   $ 1,209   $ 2,051   $ 447   $ ( 457 ) $ 6,705  
2024
Electric revenues $ 2,229   $ 960   $ 925   $ 1,836   $ —   $ ( 6 ) $ 5,944  
Natural gas revenues —   70   119   23   —   ( 2 ) 210  
Shared service and other revenues —   —   —   3   441   ( 444 ) —  
Total operating revenues $ 2,229   $ 1,030   $ 1,044   $ 1,862   $ 441   $ ( 452 ) $ 6,154  
Less:
Purchased power
2025 $ 806   $ 428   $ 547   $ 864   $ —   $ —   $ 2,645  

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

Note 4 — Segment Information

2024 835   372   407   735   —   —   2,349  
Purchased fuel
2025 $ —   $ 18   $ 21   $ 8   $ —   $ —   $ 47  
2024 —   14   13   7   —   —   34  

Operating and maintenance
2025 $ 313   $ 183   $ 179   $ 290   $ 409   $ ( 202 ) $ 1,172  
2024 307   251   221   275   404   ( 183 ) 1,275  
Operating and maintenance from affiliates
2025 $ 96   $ 58   $ 60   $ 45   $ 11   $ ( 270 ) $ —  
2024 103   62   60   47   11   ( 283 ) —  
Depreciation and amortization
2025 $ 395   $ 115   $ 155   $ 234   $ 13   $ —   $ 912  
2024 387   108   162   235   16   —   908  
Taxes other than income taxes
2025 $ 107   $ 69   $ 93   $ 150   $ 10   $ —   $ 429  
2024 99   61   86   140   9   —   395  
(Gain) on sale of assets
2025 $ —   $ —   $ —   $ —   $ —   $ —   $ —  
2024 —   —   —   —   ( 3 ) —   ( 3 )
Interest expense, net (c)

2025 $ 132   $ 63   $ 64   $ 102   $ 170   $ —   $ 531  
2024 125   55   57   95   158   —   490  
Interest expense to affiliates, net (c)

2025 $ 3   $ 2   $ —   $ —   $ —   $ 2   $ 7  
2024 3   3   —   —   —   —   6  
Other, net
2025 $ ( 33 ) $ ( 11 ) $ ( 15 ) $ ( 18 ) $ ( 4 ) $ 13   $ ( 68 )
2024 ( 26 ) ( 9 ) ( 11 ) ( 22 ) ( 3 ) 14   ( 57 )
Income Taxes
2025 $ 83   $ 5   $ 23   $ 85   $ ( 41 ) $ —   $ 155  
2024 36   ( 4 ) 4   72   ( 58 ) —   50  
Net income (loss) attributable to common shareholders
2025 $ 373   $ 250   $ 82   $ 291   $ ( 121 ) $ —   $ 875  
2024 360   117   45   278   ( 93 ) —   707  
Supplemental segment information
Intersegment revenues (d)

2025 $ 2   $ 3   $ 2   $ 2   $ 444   $ ( 453 ) $ —  
2024 2   4   3   3   438   ( 450 ) —  
Capital Expenditures
2025 $ 781   $ 502   $ 407   $ 444   $ 2   $ —   $ 2,136  
2024 508   382   365   440   —   —   1,695  

__________
(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 14 — 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 15 — Related Party Transactions for additional information on intersegment revenues.

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

Note 4 — Segment Information

PHI:

Pepco DPL ACE Other (a)
Intersegment
Eliminations PHI
Operating revenues (b) :

2025
Electric revenues $ 992   $ 464   $ 570   $ —   $ ( 5 ) $ 2,021  
Natural gas revenues —   27   —   —   —   27  
Shared service and other revenues —   —   —   106   ( 103 ) 3  
Total operating revenues $ 992   $ 491   $ 570   $ 106   $ ( 108 ) $ 2,051  
2024
Electric revenues $ 861   $ 439   $ 540   $ —   $ ( 4 ) $ 1,836  
Natural gas revenues —   23   —   —   —   23  
Shared service and other revenues —   —   —   103   ( 100 ) 3  
Total operating revenues $ 861   $ 462   $ 540   $ 103   $ ( 104 ) $ 1,862  
Less:
Purchased power
2025 $ 367   $ 211   $ 286   $ —   $ —   $ 864  
2024 294   196   245   —   —   735  
Purchased fuel
2025 $ —   $ 8   $ —   $ —   $ —   $ 8  
2024 —   7   —   —   —   7  

Operating and maintenance
2025 $ 95   $ 51   $ 55   $ 89   $ —   $ 290  
2024 82   49   58   86   —   275  
Operating and maintenance from affiliates
2025 $ 59   $ 43   $ 37   $ 14   $ ( 108 ) $ 45  
2024 58   43   38   12   ( 104 ) 47  
Depreciation and amortization
2025 $ 110   $ 63   $ 61   $ —   $ —   $ 234  
2024 102   62   67   4   —   235  
Taxes other than income taxes
2025 $ 122   $ 21   $ 2   $ 5   $ —   $ 150  
2024 114   20   2   4   —   140  
Loss on sale of assets
2025 $ —   $ —   $ —   $ —   $ —   $ —  
2024 —   —   —   —   —   —  
Interest expense, net (c)

2025 $ 53   $ 26   $ 20   $ 3   $ —   $ 102  
2024 50   22   21   2   —   95  
Interest expense to affiliates, net (c)

2025 $ —   $ —   $ —   $ —   $ —   $ —  
2024 —   —   —   1   ( 1 ) —  
Other, net
2025 $ ( 11 ) $ ( 4 ) $ ( 2 ) $ ( 1 ) $ —   $ ( 18 )
2024 ( 11 ) ( 6 ) ( 4 ) ( 2 ) 1   ( 22 )
Income Taxes
2025 $ 41   $ 17   $ 29   $ ( 2 ) $ —   $ 85  
2024 32   14   30   ( 4 ) —   72  
Net income (loss) attributable to common shareholders

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

Note 4 — Segment Information

2025 $ 156   $ 55   $ 82   $ ( 2 ) $ —   $ 291  
2024 140   55   83   —   —   278  
Supplemental segment information
Intersegment revenues (d)

2025 $ 2   $ 2   $ 1   $ 106   $ ( 109 ) $ 2  
2024 2   2   1   103   ( 105 ) 3  
Capital Expenditures
2025 $ 221   $ 125   $ 96   $ 2   $ —   $ 444  
2024 218   136   85   1   —   440  

__________
(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 14 — 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) Includes intersegment revenues with ComEd, PECO, and BGE, which are eliminated at Exelon.

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

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

Note 4 — Segment Information

Three Months Ended September 30, 2025
Revenues from contracts with customers ComEd PECO BGE PHI Pepco DPL ACE
Electric revenues
Residential $ 1,365   $ 735   $ 684   $ 1,147   $ 501   $ 283   $ 363  
Small commercial & industrial 645   167   113   210   56   72   82  
Large commercial & industrial 217   101   172   406   331   32   43  
Public authorities & electric railroads 14   8   8   16   8   4   4  
Other (a)
229   78   122   235   98   77   62  
Total electric revenues (b)
$ 2,470   $ 1,089   $ 1,099   $ 2,014   $ 994   $ 468   $ 554  
Natural gas revenues
Residential $ —   $ 50   $ 68   $ 13   $ —   $ 13   $ —  
Small commercial & industrial —   23   14   7   —   7   —  
Large commercial & industrial —   1   37   1   —   1   —  
Transportation —   7   —   4   —   4   —  
Other (c)
—   1   6   2   —   2   —  
Total natural gas revenues (d)
$ —   $ 82   $ 125   $ 27   $ —   $ 27   $ —  
Total revenues from contracts with customers $ 2,470   $ 1,171   $ 1,224   $ 2,041   $ 994   $ 495   $ 554  
Other revenues
Revenues from alternative revenue programs $ ( 206 ) $ 2   $ ( 20 ) $ 6   $ ( 5 ) $ ( 5 ) $ 16  
Other electric revenues (e)
11   6   4   4   3   1   —  
Other natural gas revenues (e)
—   1   1   —   —   —   —  

Total other revenues $ ( 195 ) $ 9   $ ( 15 ) $ 10   $ ( 2 ) $ ( 4 ) $ 16  
Total revenues for reportable segments $ 2,275   $ 1,180   $ 1,209   $ 2,051   $ 992   $ 491   $ 570  

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

Note 4 — Segment Information

Three Months Ended September 30, 2024
Revenues from contracts with customers ComEd PECO BGE PHI Pepco DPL ACE
Electric revenues
Residential $ 1,117   $ 641   $ 558   $ 1,016   $ 426   $ 267   $ 323  
Small commercial & industrial 603   153   96   203   52   69   82  
Large commercial & industrial 286   73   154   365   281   31   53  
Public authorities & electric railroads 11   7   8   18   9   4   5  
Other (a)
280   74   110   225   85   70   71  
Total electric revenues (b)
$ 2,297   $ 948   $ 926   $ 1,827   $ 853   $ 441   $ 534  
Natural gas revenues
Residential $ —   $ 44   $ 58   $ 11   $ —   $ 11   $ —  
Small commercial & industrial —   17   11   6   —   6   —  
Large commercial & industrial —   —   32   1   —   1   —  
Transportation —   7   —   4   —   4   —  
Other (c)
—   2   3   1   —   1   —  
Total natural gas revenues (d)
$ —   $ 70   $ 104   $ 23   $ —   $ 23   $ —  
Total revenues from contracts with customers $ 2,297   $ 1,018   $ 1,030   $ 1,850   $ 853   $ 464   $ 534  
Other revenues
Revenues from alternative revenue programs $ ( 76 ) $ 5   $ 9   $ 8   $ 5   $ ( 3 ) $ 6  
Other electric revenues (e)
8   7   4   4   3   1   —  
Other natural gas revenues (e)
—   —   1   —   —   —   —  

Total other revenues $ ( 68 ) $ 12   $ 14   $ 12   $ 8   $ ( 2 ) $ 6  
Total revenues for reportable segments $ 2,229   $ 1,030   $ 1,044   $ 1,862   $ 861   $ 462   $ 540  

__________
(a) Includes transmission revenue from PJM, wholesale electric revenue, and mutual assistance revenue.
(b) Includes operating revenues from affiliates in 2025 and 2024 respectively of:
• $ 2  million, $ 2  million at ComEd
• $ 2  million, $ 3  million at PECO
• $ 1  million , $ 2  million at BGE
• $ 2  million, $ 3  million at PHI
• $ 2  million, $ 2  million at Pepco
• $ 2  million, $ 2  million at DPL
• $ 1  million, $ 1  million at ACE
(c) Includes revenues from off-system natural gas sales.
(d) Includes operating revenues from affiliates in 2025 and 2024 respectively of:
• $ 1  million, $ 1  million at PECO
• $ 1  million, $ 1  million at BGE
(e) Includes late payment charge revenues.

Nine Months Ended September 30, 2025 and 2024

ComEd PECO BGE PHI Other (a)
Intersegment
Eliminations Exelon
Operating revenues (b) :

2025
Electric revenues $ 6,176   $ 2,933   $ 2,951   $ 5,253   $ —   $ ( 30 ) $ 17,283  
Natural gas revenues —   580   840   148   —   ( 5 ) 1,563  
Shared service and other revenues —   —   —   7   1,381   ( 1,388 ) —  
Total operating revenues $ 6,176   $ 3,513   $ 3,791   $ 5,408   $ 1,381   $ ( 1,423 ) $ 18,846  
2024

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

Note 4 — Segment Information

Electric revenues $ 6,403   $ 2,537   $ 2,588   $ 4,809   $ —   $ ( 17 ) $ 16,320  
Natural gas revenues —   438   680   122   —   ( 3 ) 1,237  
Shared service and other revenues —   —   —   7   1,369   ( 1,376 ) —  
Total operating revenues $ 6,403   $ 2,975   $ 3,268   $ 4,938   $ 1,369   $ ( 1,396 ) $ 17,557  
Less:
Purchased power
2025 $ 2,044   $ 1,093   $ 1,365   $ 2,138   $ —   $ —   $ 6,640  
2024 2,504   977   1,108   1,895   ( 1 ) —   6,483  
Purchased fuel
2025 $ —   $ 195   $ 219   $ 57   $ —   $ —   $ 471  
2024 —   136   120   44   1   —   301  

Operating and maintenance
2025 $ 958   $ 690   $ 621   $ 876   $ 1,313   $ ( 618 ) $ 3,840  
2024 970   695   613   780   1,277   ( 579 ) 3,756  
Operating and maintenance from affiliates
2025 $ 296   $ 182   $ 186   $ 148   $ 32   $ ( 844 ) $ —  
2024 307   181   182   147   29   ( 846 ) —  
Depreciation and amortization
2025 $ 1,162   $ 336   $ 473   $ 701   $ 45   $ —   $ 2,717  
2024 1,124   318   474   716   49   —   2,681  

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

Note 4 — Segment Information

Taxes other than income taxes
2025 $ 303   $ 183   $ 273   $ 426   $ 31   $ —   $ 1,216  
2024 287   164   254   395   27   —   1,127  
(Gain) on sale of assets
2025 $ —   $ —   $ —   $ ( 1 ) $ —   $ —   $ ( 1 )
2024 ( 5 ) ( 4 ) —   —   ( 3 ) —   ( 12 )
Interest expense, net (c)

2025 $ 385   $ 179   $ 183   $ 303   $ 510   $ —   $ 1,560  
2024 364   161   159   279   469   ( 4 ) 1,428  
Interest expense to affiliates, net (c)

2025 $ 10   $ 9   $ —   $ 2   $ ( 1 ) $ ( 2 ) $ 18  
2024 10   9   —   —   ( 3 ) 2   18  
Other, net
2025 $ ( 86 ) $ ( 29 ) $ ( 35 ) $ ( 54 ) $ ( 22 ) $ 41   $ ( 185 )
2024 ( 66 ) ( 27 ) ( 27 ) ( 79 ) ( 28 ) 31   ( 196 )
Income taxes
2025 $ 201   $ 23   $ 108   $ 184   $ ( 120 ) $ —   $ 396  
2024 85   9   32   158   ( 126 ) —   158  
Net income (loss) attributable to common shareholders
2025 $ 903   $ 652   $ 398   $ 628   $ ( 407 ) $ —   $ 2,174  
2024 823   356   353   603   ( 322 ) —   1,813  
Supplemental segment information
Intersegment revenues (d)

2025 $ 19   $ 9   $ 6   $ 7   $ 1,374   $ ( 1,415 ) $ —  
2024 6   7   7   7   1,362   ( 1,389 ) —  
Capital expenditures
2025 $ 1,970   $ 1,334   $ 1,211   $ 1,552   $ 28   $ —   $ 6,095  
2024 1,619   1,125   1,033   1,343   41   —   5,161  
Total assets
September 30, 2025 $ 47,010   $ 19,227   $ 16,742   $ 28,947   $ 5,365   $ ( 3,752 ) $ 113,539  
December 31, 2024 44,750   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 14 — 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 15 — Related Party Transactions for additional information on intersegment revenues.
PHI:

Pepco DPL ACE Other (a)
Intersegment
Eliminations PHI
Operating revenues (b) :

2025
Electric revenues $ 2,626   $ 1,312   $ 1,328   $ —   $ ( 13 ) $ 5,253  
Natural gas revenues —   148   —   —   —   148  
Shared service and other revenues —   —   —   323   ( 316 ) 7  

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

Note 4 — Segment Information

Total operating revenues $ 2,626   $ 1,460   $ 1,328   $ 323   $ ( 329 ) $ 5,408  
2024
Electric revenues $ 2,320   $ 1,221   $ 1,280   $ —   $ ( 12 ) $ 4,809  
Natural gas revenues —   122   —   —   —   122  
Shared service and other revenues —   —   —   328   ( 321 ) 7  
Total operating revenues $ 2,320   $ 1,343   $ 1,280   $ 328   $ ( 333 ) $ 4,938  
Less:
Purchased power
2025 $ 942   $ 580   $ 616   $ —   $ —   $ 2,138  
2024 808   529   557   1   —   1,895  
Purchased fuel
2025 $ —   $ 57   $ —   $ —   $ —   $ 57  
2024 —   44   —   —   —   44  

Operating and maintenance
2025 $ 282   $ 162   $ 161   $ 271   $ —   $ 876  
2024 206   151   155   268   —   780  
Operating and maintenance from affiliates
2025 $ 184   $ 134   $ 116   $ 43   $ ( 329 ) $ 148  
2024 186   133   119   41   ( 332 ) 147  
Depreciation and amortization
2025 $ 321   $ 189   $ 188   $ 3   $ —   $ 701  
2024 307   183   214   12   —   716  
Taxes other than income taxes
2025 $ 344   $ 63   $ 7   $ 12   $ —   $ 426  
2024 317   59   7   12   —   395  
(Gain) on sale of assets
2025 $ ( 1 ) $ —   $ —   $ —   $ —   $ ( 1 )
2024 —   —   —   —   —   —  
Interest expense, net (c)

2025 $ 159   $ 75   $ 62   $ 7   $ —   $ 303  
2024 142   69   59   7   2   279  
Interest expense to affiliates, net (c)

2025 $ —   $ —   $ —   $ 2   $ —   $ 2  
2024 —   —   —   3   ( 3 ) —  
Other, net
2025 $ ( 31 ) $ ( 12 ) $ ( 8 ) $ ( 3 ) $ —   $ ( 54 )
2024 ( 43 ) ( 20 ) ( 12 ) ( 4 ) —   ( 79 )
Income taxes
2025 $ 89   $ 49   $ 48   $ ( 2 ) $ —   $ 184  
2024 74   39   48   ( 3 ) —   158  
Net income (loss) attributable to common shareholders
2025 $ 337   $ 163   $ 138   $ ( 10 ) $ —   $ 628  
2024 323   156   133   ( 9 ) —   603  
Supplemental segment information
Intersegment revenues (d)

2025 $ 4   $ 6   $ 3   $ 323   $ ( 329 ) $ 7  
2024 5   5   2   328   ( 333 ) 7  
Capital expenditures

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

Note 4 — Segment Information

2025 $ 690   $ 402   $ 292   $ 168   $ —   $ 1,552  
2024 672   404   265   2   —   1,343  
Total assets
September 30, 2025 $ 12,326   $ 6,540   $ 5,516   $ 4,604   $ ( 39 ) $ 28,947  
December 31, 2024 12,000   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 14 — 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) Includes intersegment revenues with ComEd, PECO, and BGE, which are eliminated at Exelon.

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

Nine Months Ended September 30, 2025
Revenues from contracts with customers ComEd PECO BGE PHI Pepco DPL ACE
Electric revenues
Residential $ 3,452   $ 1,921   $ 1,829   $ 2,847   $ 1,273   $ 792   $ 782  
Small commercial & industrial 1,799   484   311   548   155   200   193  
Large commercial & industrial 689   260   456   1,144   911   92   141  
Public authorities & electric railroads 43   26   25   56   29   13   14  
Other (a)
688   231   352   688   274   224   196  
Total electric revenues (b)
$ 6,671   $ 2,922   $ 2,973   $ 5,283   $ 2,642   $ 1,321   $ 1,326  
Natural gas revenues
Residential $ —   $ 396   $ 555   $ 86   $ —   $ 86   $ —  
Small commercial & industrial —   140   100   35   —   35   —  
Large commercial & industrial —   1   178   6   —   6   —  
Transportation —   28   —   13   —   13   —  
Other (c)
—   13   37   8   —   8   —  
Total natural gas revenues (d)
$ —   $ 578   $ 870   $ 148   $ —   $ 148   $ —  
Total revenues from contracts with customers $ 6,671   $ 3,500   $ 3,843   $ 5,431   $ 2,642   $ 1,469   $ 1,326  
Other revenues
Revenues from alternative revenue programs $ ( 525 ) $ ( 6 ) $ ( 63 ) $ ( 27 ) $ ( 19 ) $ ( 10 ) $ 2  
Other electric revenues (e)
30   17   9   4   3   1   —  
Other natural gas revenues (e)
—   2   2   —   —   —   —  

Total other revenues $ ( 495 ) $ 13   $ ( 52 ) $ ( 23 ) $ ( 16 ) $ ( 9 ) $ 2  
Total revenues for reportable segments $ 6,176   $ 3,513   $ 3,791   $ 5,408   $ 2,626   $ 1,460   $ 1,328  

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

Note 4 — Segment Information

Nine Months Ended September 30, 2024
Revenues from contracts with customers ComEd PECO BGE PHI Pepco DPL ACE
Electric revenues
Residential $ 3,017   $ 1,683   $ 1,556   $ 2,537   $ 1,085   $ 725   $ 727  
Small commercial & industrial 1,755   407   274   519   141   191   187  
Large commercial & industrial 875   191   425   1,034   794   91   149  
Public authorities & electric railroads 43   21   24   52   26   12   14  
Other (a)
803   221   303   623   224   198   206  
Total electric revenues (b)
$ 6,493   $ 2,523   $ 2,582   $ 4,765   $ 2,270   $ 1,217   $ 1,283  
Natural gas revenues
Residential $ —   $ 300   $ 418   $ 72   $ —   $ 72   $ —  
Small commercial & industrial —   106   76   29   —   29   —  
Large commercial & industrial —   —   143   4   —   4   —  
Transportation —   20   —   12   —   12   —  
Other (c)
—   11   12   5   —   5   —  
Total natural gas revenues (d)
$ —   $ 437   $ 649   $ 122   $ —   $ 122   $ —  
Total revenues from contracts with customers $ 6,493   $ 2,960   $ 3,231   $ 4,887   $ 2,270   $ 1,339   $ 1,283  
Other revenues
Revenues from alternative revenue programs $ ( 100 ) $ 3   $ 28   $ 40   $ 42   $ 1   $ ( 3 )
Other electric revenues (e)
10   11   7   11   8   3   —  
Other natural gas revenues (e)
—   1   2   —   —   —   —  

Total other revenues $ ( 90 ) $ 15   $ 37   $ 51   $ 50   $ 4   $ ( 3 )
Total revenues for reportable segments $ 6,403   $ 2,975   $ 3,268   $ 4,938   $ 2,320   $ 1,343   $ 1,280  

__________
(a) Includes transmission revenue from PJM, wholesale electric revenue, and mutual assistance revenue.
(b) Includes operating revenues from affiliates in 2025 and 2024 respectively of:
• $ 19 million, $ 6 million at ComEd
• $ 7  million, $ 5  million at PECO
• $ 4  million, $ 4  million at BGE
• $ 7  million, $ 7 million at PHI
• $ 4  million, $ 5  million at Pepco
• $ 6  million, $ 5 million at DPL
• $ 3  million, $ 2 million at ACE
(c) Includes revenues from off-system natural gas sales.
(d) Includes operating revenues from affiliates in 2025 and 2024 respectively of:
• $ 2 million, $ 2 million at PECO
• $ 2  million, $ 3 million at BGE
(e) Includes late payment charge revenues.

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

Note 5 — Accounts Receivable

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.

Three Months Ended September 30, 2025
Exelon ComEd PECO BGE PHI Pepco DPL ACE
Balance at June 30, 2025 $ 465   $ 122   $ 154   $ 66   $ 123   $ 69   $ 21   $ 33  
Plus: Current period provision for expected credit losses (a)(b)
82   37   22   8   15   11   3   1  
Less: Write-offs (c)(d) , net of recoveries (e)
96   44   31   6   15   8   4   3  
Balance at September 30, 2025 $ 451   $ 115   $ 145   $ 68   $ 123   $ 72   $ 20   $ 31  

Three Months Ended September 30, 2024
Exelon ComEd PECO BGE PHI Pepco DPL ACE
Balance at June 30, 2024 $ 372   $ 112   $ 112   $ 45   $ 103   $ 53   $ 16   $ 34  
Plus: Current period provision for expected credit losses
84   16   28   20   20   12   4   4  
Less: Write-offs, net of recoveries
30   7   5   5   13   7   3   3  
Balance at September 30, 2024 $ 426   $ 121   $ 135   $ 60   $ 110   $ 58   $ 17   $ 35  

Nine Months Ended September 30, 2025
Exelon ComEd PECO BGE PHI Pepco DPL ACE
Balance at December 31, 2024 $ 406   $ 109   $ 133   $ 56   $ 108   $ 59   $ 17   $ 32  
Plus: Current period provision for expected credit losses (f)(g)(h)
224   66   68   34   56   35   13   8  
Less: Write-offs (i) , net of recoveries (e)
179   60   56   22   41   22   10   9  
Balance at September 30, 2025 $ 451   $ 115   $ 145   $ 68   $ 123   $ 72   $ 20   $ 31  

Nine Months Ended September 30, 2024
Exelon ComEd PECO BGE PHI Pepco DPL ACE
Balance at December 31, 2023 $ 317   $ 69   $ 95   $ 46   $ 107   $ 52   $ 19   $ 36  
Plus: Current period provision for expected credit losses
221   77   63   34   47   30   8   9  
Less: Write-offs, net of recoveries
112   25   23   20   44   24   10   10  
Balance at September 30, 2024 $ 426   $ 121   $ 135   $ 60   $ 110   $ 58   $ 17   $ 35  

_________
(a) For ComEd, the increase is primarily a result of increased aging of receivables.
(b) For PECO, BGE, and ACE, the decrease is primarily a result of decreased receivable balances.
(c) For ComEd, the increase is primarily a result of timing of write-offs.
(d) For PECO, the increase is primarily a result of increased disconnection activities.
(e) Recoveries were not material to the Registrants.
(f) For ComEd, the decrease is primarily a result of increased disconnection activities.
(g) For PECO, Pepco, and DPL, the increase is primarily a result of increased receivable balances.
(h) For ACE, the decrease is primarily a result of decreased receivable balances.
(i) For ComEd and PECO, the increase is primarily a result of increased disconnection activities.
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Combined Notes to Consolidated Financial Statements — (Continued)
(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.

Three Months Ended September 30, 2025
Exelon ComEd PECO BGE PHI Pepco DPL ACE
Balance at June 30, 2025 $ 107   $ 31   $ 19   $ 5   $ 52   $ 28   $ 9   $ 15  
Plus: Current period provision (benefit) for expected credit losses (a)(b)
7   5   2   1   ( 1 ) —   —   ( 1 )
Less: Write-offs (c) , net of recoveries (d)
16   11   4   1   —   —   —   —  
Balance at September 30, 2025 $ 98   $ 25   $ 17   $ 5   $ 51   $ 28   $ 9   $ 14  

Three Months Ended September 30, 2024
Exelon ComEd PECO BGE PHI Pepco DPL ACE
Balance at June 30, 2024 $ 108   $ 29   $ 20   $ 5   $ 54   $ 34   $ 7   $ 13  
Plus: Current period provision (benefit) for expected credit losses
7   10   1   3   ( 7 ) ( 8 ) —   1  
Less: Write-offs, net of recoveries
4   —   1   2   1   —   —   1  
Balance at September 30, 2024 $ 111   $ 39   $ 20   $ 6   $ 46   $ 26   $ 7   $ 13  

Nine Months Ended September 30, 2025
Exelon ComEd PECO BGE PHI Pepco DPL ACE
Balance at December 31, 2024 $ 107   $ 34   $ 18   $ 6   $ 49   $ 27   $ 9   $ 13  
Plus: Current period provision (benefit) for expected credit losses (e)(f)
15   4   9   ( 1 ) 3   1   —   2  
Less: Write-offs (g)(h) , net of recoveries (d)
24   13   10   —   1   —   —   1  
Balance at September 30, 2025 $ 98   $ 25   $ 17   $ 5   $ 51   $ 28   $ 9   $ 14  

Nine Months Ended September 30, 2024
Exelon ComEd PECO BGE PHI Pepco DPL ACE
Balance at December 31, 2023 $ 82   $ 17   $ 8   $ 7   $ 50   $ 28   $ 8   $ 14  
Plus: Current period provision (benefit) for expected credit losses
43   25   15   4   ( 1 ) ( 2 ) ( 1 ) 2  
Less: Write-offs, net of recoveries
14   3   3   5   3   —   —   3  
Balance at September 30, 2024 $ 111   $ 39   $ 20   $ 6   $ 46   $ 26   $ 7   $ 13  

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

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

Note 5 — Accounts Receivable

Unbilled Customer Revenue
The following table provides additional information about unbilled customer revenues recorded in the Registrants' Consolidated Balance Sheets as of September 30, 2025 and December 31, 2024.

Unbilled customer revenues (a)

Exelon ComEd PECO BGE PHI Pepco DPL ACE
September 30, 2025 $ 1,002   $ 401   $ 207   $ 178   $ 216   $ 111   $ 51   $ 54  
December 31, 2024 1,114   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 nine months ended September 30, 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
Exelon ComEd PECO BGE PHI Pepco DPL ACE
Nine months ended September 30, 2025 $ 3,320   $ 814   $ 954   $ 550   $ 1,002   $ 624   $ 201   $ 177  
Nine months ended September 30, 2024 3,177   750   854   606   967   607   191   169  

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

Note 6 — Income Taxes

6. Income Taxes (All Registrants)
Rate Reconciliation
The effective income tax rate from continuing operations varies from the U.S. federal statutory rate principally due to the following:

Three Months Ended September 30, 2025 (a)

Exelon ComEd (b)
PECO (c)
BGE PHI Pepco DPL ACE
U.S. Federal statutory rate 21.0   % 21.0   % 21.0   % 21.0   % 21.0   % 21.0   % 21.0   % 21.0   %
Increase (decrease) due to:
State income taxes, net of federal income tax benefit
5.7   7.4   ( 1.4 ) 6.3   6.5   6.4   6.5   7.1  
Plant basis differences ( 5.1 ) ( 0.9 ) ( 16.0 ) ( 1.3 ) ( 0.6 ) ( 0.9 ) ( 0.4 ) ( 0.1 )
Excess deferred tax amortization ( 6.4 ) ( 8.9 ) ( 1.6 ) ( 4.1 ) ( 4.0 ) ( 5.4 ) ( 3.2 ) ( 1.7 )
Amortization of investment tax credit, including deferred taxes on basis difference —   ( 0.1 ) —   —   —   —   ( 0.1 ) ( 0.1 )
Tax credits ( 0.3 ) ( 0.1 ) —   ( 0.6 ) ( 0.4 ) ( 0.2 ) ( 0.5 ) ( 0.3 )
Other 0.1   ( 0.2 ) —   0.6   0.1   ( 0.1 ) 0.3   0.2  
Effective income tax rate 15.0   % 18.2   % 2.0   % 21.9   % 22.6   % 20.8   % 23.6   % 26.1   %

Three Months Ended September 30, 2024 (a)

Exelon
ComEd (b)
PECO (c)
BGE (d)
PHI
Pepco DPL
ACE
U.S. Federal statutory rate 21.0   % 21.0   % 21.0   % 21.0   % 21.0   % 21.0   % 21.0   % 21.0   %
Increase (decrease) due to:
State income taxes, net of federal income tax benefit
5.7   7.6   ( 2.1 ) 6.5   6.5   6.2   6.3   7.4  
Plant basis differences ( 4.8 ) ( 0.8 ) ( 19.5 ) ( 0.8 ) ( 0.8 ) ( 1.2 ) ( 0.8 ) —  
Excess deferred tax amortization ( 14.0 ) ( 16.6 ) ( 2.6 ) ( 18.6 ) ( 5.5 ) ( 6.7 ) ( 5.9 ) ( 1.6 )
Amortization of investment tax credit, including deferred taxes on basis difference ( 0.1 ) ( 0.1 ) —   ( 0.1 ) ( 0.1 ) —   ( 0.1 ) ( 0.1 )
Tax credits ( 0.9 ) ( 2.6 ) —   ( 0.6 ) ( 0.6 ) ( 0.5 ) ( 0.6 ) ( 0.5 )
Other
( 0.3 ) 0.6   ( 0.3 ) 0.8   0.1   ( 0.2 ) 0.4   0.3  
Effective income tax rate 6.6   % 9.1   % ( 3.5 ) % 8.2   % 20.6   % 18.6   % 20.3   % 26.5   %

__________
(a) Positive percentages represent income tax expense. Negative percentages represent income tax benefit.
(b) For ComEd, the lower effective tax rate is primarily due to CEJA which resulted in the acceleration of certain income tax benefits.
(c) For PECO, the lower effective tax rate is primarily related to plant basis differences attributable to tax repair deductions.
(d) For BGE, the lower effective tax rate is primarily due to the Maryland multi-year plan which resulted in the acceleration of certain income tax benefits.
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Combined Notes to Consolidated Financial Statements — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)

Note 6 — Income Taxes

Nine Months Ended September 30, 2025 (a)

Exelon ComEd (b)
PECO (c)
BGE PHI Pepco DPL ACE
U.S. Federal statutory rate 21.0   % 21.0   % 21.0   % 21.0   % 21.0   % 21.0   % 21.0   % 21.0   %
Increase (decrease) due to:
State income taxes, net of federal income tax benefit
5.6   7.5   ( 2.3 ) 6.2   6.6   6.4   6.4   7.1  
Plant basis differences ( 4.6 ) ( 0.9 ) ( 14.0 ) ( 1.5 ) ( 0.6 ) ( 0.9 ) ( 0.5 ) ( 0.1 )
Excess deferred tax amortization ( 6.5 ) ( 9.0 ) ( 1.6 ) ( 4.1 ) ( 4.1 ) ( 5.4 ) ( 3.5 ) ( 1.6 )
Amortization of investment tax credit, including deferred taxes on basis difference —   ( 0.1 ) —   —   —   —   ( 0.1 ) ( 0.1 )
Tax credits ( 0.4 ) ( 0.4 ) —   ( 0.4 ) ( 0.4 ) ( 0.3 ) ( 0.3 ) ( 0.3 )
Other 0.3   0.1   0.3   0.1   0.2   0.1   0.1   ( 0.2 )
Effective income tax rate 15.4   % 18.2   % 3.4   % 21.3   % 22.7   % 20.9   % 23.1   % 25.8   %

Nine Months Ended September 30, 2024 (a)

Exelon ComEd (b)
PECO (c)
BGE (d)
PHI Pepco DPL ACE
U.S. Federal statutory rate 21.0   % 21.0   % 21.0   % 21.0   % 21.0   % 21.0   % 21.0   % 21.0   %
Increase (decrease) due to:
State income taxes, net of federal income tax benefit
5.8   7.7   ( 1.2 ) 6.3   6.5   6.2   6.2   7.4  
Plant basis differences ( 4.2 ) ( 0.8 ) ( 14.7 ) ( 1.2 ) ( 0.9 ) ( 1.3 ) ( 0.9 ) 0.1  
Excess deferred tax amortization ( 14.1 ) ( 17.4 ) ( 2.4 ) ( 17.6 ) ( 5.4 ) ( 6.8 ) ( 5.8 ) ( 1.6 )
Amortization of investment tax credit, including deferred taxes on basis difference ( 0.1 ) ( 0.1 ) —   —   ( 0.1 ) —   ( 0.1 ) ( 0.1 )
Tax credits ( 0.6 ) ( 1.4 ) —   ( 0.4 ) ( 0.5 ) ( 0.4 ) ( 0.4 ) ( 0.4 )
Other 0.2   0.4   ( 0.2 ) 0.2   0.2   ( 0.1 ) —   0.1  
Effective income tax rate 8.0   % 9.4   % 2.5   % 8.3   % 20.8   % 18.6   % 20.0   % 26.5   %

__________
(a) Positive percentages represent income tax expense. Negative percentages represent income tax benefit.
(b) For ComEd, the lower effective tax rate is primarily due to CEJA which resulted in the acceleration of certain income tax benefits.
(c) For PECO, the lower effective tax rate is primarily related to plant basis differences attributable to tax repair deductions.
(d) For BGE, the lower effective tax rate is primarily due to the Maryland multi-year plan which resulted in the acceleration of certain income tax benefits.
Unrecognized Tax Benefits
Exelon, PHI and DPL have the following unrecognized tax benefits at September 30, 2025 and December 31, 2024. ComEd's, PECO's, BGE's, Pepco's, and ACE's amounts are not material.

Exelon (a)
PHI DPL
September 30, 2025 $ 97   $ 47   $ 11  
December 31, 2024 96   48   12  
__________
(a) At September 30, 2025 and December 31, 2024, Exelon's unrecognized tax benefits is inclusive of $ 31 million related to Constellation's share of unrecognized tax benefits for periods prior to the separation. Exelon reflected an offsetting receivable of $ 31  million in Other deferred debits and other assets in the Consolidated Balance Sheet for these amounts.
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Combined Notes to Consolidated Financial Statements — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)

Note 6 — Income Taxes

Reasonably possible the total amount of unrecognized tax benefits could significantly increase or decrease within 12 months after the reporting date
At September 30, 2025, Exelon, PHI, and DPL have approximately $ 64  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.
Other Tax Matters
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.
Corporate Alternative Minimum Tax (All Registrants)
On August 16, 2022, the IRA was signed into law and implements a new corporate alternative minimum tax (CAMT) that imposes a 15.0 % tax on modified GAAP net income. Corporations are entitled to a tax credit (minimum tax credit) to the extent the CAMT liability exceeds the regular tax liability. This amount can be carried forward indefinitely and used in future years when regular tax exceeds the CAMT.
Beginning in 2023, based on the existing statute, 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.

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 Tax Benefits (All Registrants)
The Utility Registrants are party to an agreement with 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 benefit attributable to Exelon is reallocated to the Utility Registrants. That allocation is treated as a contribution to capital 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 three and nine months ended September 30, 2025, and 2024.

ComEd PECO BGE PHI Pepco DPL ACE
September 30, 2025 $ 20   $ 14   $ 12   $ 23   $ 12   $ 7   $ 4  
September 30, 2024 30   15   14   16   9   5   2  

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

Note 6 — Income Taxes

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. 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.
Tax Matters Agreement (Exelon)
In connection with the separation, Exelon entered into a TMA with Constellation. The TMA governs the respective rights, responsibilities, and obligations between Exelon and Constellation after the separation with respect to tax liabilities, refunds and attributes for open tax years that Constellation was part of Exelon’s consolidated group for U.S. federal, state, and local tax purposes.
Indemnification for Taxes. As a former subsidiary of Exelon, Constellation has joint and several liability with Exelon to the IRS and certain state jurisdictions relating to the taxable periods prior to the separation. The TMA specifies that Constellation is liable for their share of taxes required to be paid by Exelon with respect to taxable periods prior to the separation to the extent Constellation would have been responsible for such taxes under the Exelon tax sharing agreement when Constellation was included in Exelon's consolidated group. At September 30, 2025, there is no balance due to or from Constellation.
Tax Refunds. The TMA specifies that Constellation is entitled to their share of any future tax refunds claimed by Exelon with respect to taxable periods prior to the separation to the extent that Constellation would have received such tax refunds under the Exelon tax sharing agreement when Constellation was included in Exelon's consolidated group. At September 30, 2025, there is no balance due to or from Constellation.
Tax Attributes . At the date of separation certain tax attributes, primarily pre-closing tax credit carryforwards, that were generated by Constellation were required by law to be allocated to Exelon. The TMA also provides that Exelon will reimburse Constellation when those allocated tax attribute carryforwards are utilized. In 2025, Exelon remitted $ 127 million of payments to Constellation for the utilization of pre-closing tax credit carryforwards. At September 30, 2025, Exelon recorded a payable of $ 175 million and $ 38 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.

7. Retirement Benefits (All Registrants)
Defined Benefit Pension and OPEB
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 %.
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.
A portion of the net periodic benefit cost for all plans is capitalized within the Consolidated Balance Sheets. The following table presents the components of Exelon's net periodic benefit costs, prior to capitalization, for the three and nine months ended September 30, 2025 and 2024.

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

Note 7 — Retirement Benefits

Pension Benefits OPEB
Three Months Ended September 30, Three Months Ended September 30,
2025 2024 2025 2024
Components of net periodic benefit cost
Service cost $ 38   $ 43   $ 7   $ 6  
Interest cost 146   141   26   24  
Expected return on assets ( 179 ) ( 184 ) ( 21 ) ( 21 )
Amortization of:
Prior service cost (credit) 1   1   ( 2 ) ( 2 )
Actuarial loss (gain) 53   53   ( 1 ) —  

Net periodic benefit cost $ 59   $ 54   $ 9   $ 7  

Pension Benefits OPEB
Nine Months Ended September 30, Nine Months Ended September 30,
2025 2024 2025 2024
Components of net periodic benefit cost
Service cost $ 115   $ 125   $ 19   $ 20  
Interest cost 439   423   76   72  
Expected return on assets ( 535 ) ( 552 ) ( 63 ) ( 63 )
Amortization of:
Prior service cost (credit) 2   2   ( 6 ) ( 6 )
Actuarial loss (gain) 159   160   ( 2 ) —  

Net periodic benefit cost $ 180   $ 158   $ 24   $ 23  

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

Note 7 — Retirement Benefits

  Three Months Ended September 30, Nine Months Ended September 30,
Pension and OPEB Costs (Benefits) 2025 2024 2025 2024
Exelon $ 68   $ 61   $ 204   $ 181  
ComEd 22   17   64   53  
PECO 2   ( 1 ) 5   ( 1 )
BGE 16   14   46   45  
PHI 23   25   72   71  
Pepco 8   8   26   24  
DPL 4   4   12   11  
ACE 3   3   10   10  

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 three and nine months ended September 30, 2025 and 2024.

Three Months Ended September 30, Nine Months Ended September 30,
Savings Plan Employer Contributions 2025 2024 2025 2024
Exelon $ 30   $ 25   $ 86   $ 76  
ComEd 12   12   34   32  
PECO 4   3   12   11  
BGE 3   2   9   8  
PHI 5   4   15   12  
Pepco 1   1   4   3  
DPL 1   1   3   3  
ACE 1   1   2   2  

8. 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
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(Dollars in millions, except per share data, unless otherwise noted)

Note 8 — 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.

Registrant Commodity Accounting Treatment Hedging Instrument
ComEd Electricity NPNS Fixed 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.

PECO Electricity NPNS Fixed price contracts for default supply requirements through full requirements contracts.
Gas NPNS Fixed price contracts to cover about 10 % of planned natural gas purchases in support of projected firm sales.

BGE Electricity NPNS Fixed price contracts for all SOS requirements through full requirements contracts.
Gas NPNS Fixed price purchases associated with forecasted gas supply requirements.
Pepco Electricity NPNS Fixed price contracts for all SOS requirements through full requirements contracts.
DPL Electricity NPNS Fixed price contracts for all SOS requirements through full requirements contracts.
Gas NPNS Fixed and index priced contracts through full requirements contracts.
Gas Changes in fair value of economic hedge recorded to an offsetting regulatory asset or liability (b)
Exchange traded future contracts for up to 50 % of estimated monthly purchase requirements each month, including purchases for storage injections.

ACE Electricity NPNS Fixed price contracts for all BGS requirements through full requirements contracts.

__________
(a) See Note 3 — Regulatory Matters of the 2024 Form 10-K for additional information.
(b) The fair value of the DPL economic hedge is not material at September 30, 2025 and December 31, 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 September 30, 2025 would result in an immaterial impact to Exelon's Consolidated Net income.
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(Dollars in millions, except per share data, unless otherwise noted)

Note 8 — Derivative Financial Instruments

Below is a summary of the interest rate hedge balances at September 30, 2025 and December 31, 2024 .

Derivatives Designated
as Hedging Instruments
September 30, 2025 December 31, 2024
Other current assets $ —   $ 14  
Other deferred debits (noncurrent assets) 2   12  
Total derivative assets 2   26  
Mark-to-market derivative liabilities (current liabilities) —   ( 1 )
Mark-to-market derivative liabilities (noncurrent liabilities) ( 8 ) —  
Total mark-to-market derivative liabilities ( 8 ) ( 1 )
Total mark-to-market derivative net assets (liabilities) $ ( 6 ) $ 25  

Cash Flow Hedges (Interest Rate Risk)
For derivative instruments that qualify and are designated as cash flow hedges, the changes in fair value each period are initially recorded in AOCI and reclassified into earnings when the underlying transaction affects earnings.
In February 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 9 – 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 third quarter of 2025, Exelon Corporate entered into $ 30 million notional of 5-year maturity floating-to-fixed swaps and $ 30 million notional of 10-year maturity floating-to-fixed swaps, for a total notional of $ 60 million designated as cash flow hedges. The following table provides the notional amounts outstanding held by Exelon at September 30, 2025 and December 31, 2024.

September 30, 2025 December 31, 2024
5-year maturity floating-to-fixed swaps $ 335   $ 657  
10-year maturity floating-to-fixed swaps 335   658  
Total $ 670   $ 1,315  

The related AOCI derivative loss for the three and nine months ended September 30, 2025 was $ 1  million and $ 14 million (net of tax), respectively. The related AOCI derivative loss for the three and nine months ended September 30, 2024 was $ 29  million and $ 30  million (net of tax), respectively. See Note 13 – 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 September 30, 2025. Cash collateral held by ComEd, PECO, BGE, Pepco, DPL, and ACE must be deposited in an unaffiliated major U.S. commercial bank or foreign bank with a U.S. branch office that meets certain qualifications. 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, as of September 30, 2025 and December 31, 2024:
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(Dollars in millions, except per share data, unless otherwise noted)

Note 8 — Derivative Financial Instruments

September 30, 2025 December 31, 2024
Exelon $ 196   $ 181  
ComEd 184   176  
PECO (a)
6   —  
BGE 2   1  
PHI 5   4  
Pepco 3   1  
DPL 2   2  
ACE (b)
—   —  
__________
(a) PECO had less than one million in cash collateral held from external parties at December 31, 2024.
(b) ACE had less than one million in cash collateral with external parties at September 30, 2025 and 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. As of September 30, 2025, 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 September 30, 2025, they could have been required to post collateral to their counterparties of $ 40 million, $ 23 million, and $ 13 million, respectively.

9. 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 September 30, 2025 and December 31, 2024.

Outstanding Commercial
Paper at Average Interest Rate on
Commercial Paper Borrowings at
Commercial Paper Issuer September 30, 2025 December 31, 2024 September 30, 2025 December 31, 2024
Exelon (a)
$ 580   $ 1,359   4.29   % 4.66   %
ComEd $ —   $ 36   —   % 4.55   %
PECO $ —   $ 192   —   % 4.65   %
BGE $ —   $ 175   —   % 4.61   %
PHI (b)
$ 166   $ 530   4.30   % 4.70   %

Pepco $ 63   $ 200   4.30   % 4.69   %
DPL $ 33   $ 144   4.27   % 4.74   %
ACE $ 70   $ 186   4.30   % 4.67   %

__________
(a) Exelon Corporate had $ 414  million outstanding commercial paper borrowings at September 30, 2025 and $ 426  million in outstanding commercial paper borrowings at December 31, 2024.
(b) Represents the consolidated amounts of Pepco, DPL, and ACE.
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(Dollars in millions, except per share data, unless otherwise noted)

Note 9 — 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:

Borrower Aggregate Bank Commitment Interest 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 %

Exelon Corporate and the Utility Registrants had no outstanding amounts on the revolving credit facilities as of September 30, 2025.
The Utility Registrants have credit facility agreements, arranged at community banks, which may be utilized to issue letters of credit. The facility agreements have aggregate commitments of $ 40 million, $ 40 million, $ 15 million, $ 15 million, $ 15 million, and $ 15 million, at ComEd, PECO, BGE, Pepco, DPL, and ACE, respectively. On October 3, 2025, the Utility Registrants amended and extended their credit facilities at community banks. Previously structured as one-year arrangements, the facilities are now two-year terms. These facilities expire on October 1, 2027.
See Note 16 — Debt and Credit Agreements of the 2024 Form 10-K for additional information on the Registrants' credit facilities.
Short-Term Loan Agreements
On March 14, 2024, Exelon Corporate amended and bifurcated the $ 500 million term loan agreement into two tranches of $ 350  million and $ 150  million. The loan agreements were renewed in the first quarter of 2025, extending the expiration date to March 13, 2026. Pursuant to the loan agreements, loans made thereunder bear interest at a variable rate equal to SOFR plus 1.00 % and all indebtedness thereunder is unsecured. The loan agreements are reflected in Exelon's Consolidated Balance Sheets within Short-term borrowings.

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

Note 9 — Debt and Credit Agreements

Long-Term Debt
Issuance of Long-Term Debt
During the nine months ended September 30, 2025, the following long-term debt was issued:

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

__________
(a) The Junior Subordinated Notes bear interest at 6.50 % per annum, commencing February 19, 2025 to, but excluding March 15, 2035. Thereafter, the interest rate resets every five years on March 15 and will be set at a rate per annum equal to the Five-year U.S. Treasury Rate plus a spread of 1.975 %.
(b) On March 26, 2025, ACE entered into a purchase agreement of First Mortgage Bonds of $ 75  million and $ 75  million at 5.54 % and 5.81 % due on November 19, 2040 and November 19, 2055, respectively. The closing date of the issuance is expected to occur in November 2025.
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(Dollars in millions, except per share data, unless otherwise noted)

Note 9 — Debt and Credit Agreements

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 September 30, 2025, the Registrants are in compliance with debt covenants.

10. 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.
Exelon’s valuation techniques used to measure the fair value of the assets and liabilities shown in the tables below are in accordance with the policies discussed in Note 17 — Fair Value of Financial Assets and Liabilities of the 2024 Form 10-K.
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(Dollars in millions, except per share data, unless otherwise noted)

Note 10 — 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) as of September 30, 2025 and December 31, 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.

September 30, 2025 December 31, 2024
Carrying Amount Fair Value Carrying Amount Fair Value
Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total
Long-Term Debt, including amounts due within one year (a)

Exelon $ 48,451   $ —   $ 40,212   $ 4,358   $ 44,570   $ 44,400   $ —   $ 35,337   $ 3,720   $ 39,057  
ComEd 12,751   —   11,371   —   11,371   12,030   —   10,260   —   10,260  
PECO 6,746   —   6,019   —   6,019   5,704   —   4,816   —   4,816  
BGE 6,041   —   5,549   —   5,549   5,395   —   4,702   —   4,702  
PHI 9,599   —   4,240   4,358   8,598   9,124   —   4,093   3,720   7,813  
Pepco 4,632   —   2,551   1,877   4,428   4,362   —   2,475   1,544   4,019  
DPL 2,344   —   662   1,423   2,085   2,220   —   623   1,250   1,873  
ACE 2,035   —   811   1,059   1,870   1,933   —   787   925   1,712  
Long-Term Debt to Financing Trusts
Exelon $ 390   $ —   $ —   $ 403   $ 403   $ 390   $ —   $ —   $ 396   $ 396  
ComEd 206   —   —   215   215   206   —   —   208   208  
PECO 184   —   —   188   188   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 16 — Debt and Credit Agreements of the 2024 Form 10-K for unamortized debt issuance costs, unamortized debt discount and premium, net, and purchase accounting fair value adjustments and Note 10 — Leases of the 2024 Form 10-K for finance lease liabilities.

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

Note 10 — 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 September 30, 2025 and December 31, 2024. Exelon and the Utility Registrants have immaterial and no financial assets or liabilities measured using the NAV practical expedient, respectively:
Exelon

At September 30, 2025 At December 31, 2024
Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total
Assets
Cash equivalents (a)
$ 1,741   $ —   $ —   $ 1,741   $ 544   $ —   $ —   $ 544  
Rabbi trust investments
Cash equivalents 99   —   —   99   94   —   —   94  
Mutual funds 68   —   —   68   65   —   —   65  
Fixed income —   6   —   6   —   6   —   6  
Life insurance contracts —   76   23   99   —   73   22   95  
Rabbi trust investments subtotal 167   82   23   272   159   79   22   260  

Interest rate derivative assets
Derivatives designated as hedging instruments —   2   —   2   —   26   —   26  

Interest rate derivative assets subtotal —   2   —   2   —   26   —   26  
Total assets 1,908   84   23   2,015   703   105   22   830  
Liabilities
Commodity derivative liabilities —   —   ( 128 ) ( 128 ) —   —   ( 132 ) ( 132 )
Interest rate derivative liabilities
Derivatives designated as hedging instruments —   ( 8 ) —   ( 8 ) —   ( 1 ) —   ( 1 )

Interest rate derivative liabilities subtotal —   ( 8 ) —   ( 8 ) —   ( 1 ) —   ( 1 )
Deferred compensation obligation —   ( 69 ) —   ( 69 ) —   ( 74 ) —   ( 74 )
Total liabilities —   ( 77 ) ( 128 ) ( 205 ) —   ( 75 ) ( 132 ) ( 207 )
Total net assets (liabilities) $ 1,908   $ 7   $ ( 105 ) $ 1,810   $ 703   $ 30   $ ( 110 ) $ 623  

__________     
(a) Exelon excludes cash of $ 170 million and $ 219 million at September 30, 2025 and December 31, 2024, respectively, and restricted cash of $ 187 million and $ 176 million at September 30, 2025 and December 31, 2024, respectively, and includes long-term restricted cash of $ 49 million and $ 41 million at September 30, 2025 and December 31, 2024, respectively, which is reported in Other deferred debits and other assets in the Consolidated Balance Sheets.

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

Note 10 — Fair Value of Financial Assets and Liabilities

ComEd, PECO, and BGE

ComEd PECO BGE
At September 30, 2025 Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total
Assets
Cash equivalents (a)
$ 653   $ —   $ —   $ 653   $ 340   $ —   $ —   $ 340   $ 659   $ —   $ —   $ 659  
Rabbi trust investments

Mutual funds —   —   —   —   12   —   —   12   10   —   —   10  
Life insurance contracts —   —   —   —   —   23   —   23   —   —   —   —  
Rabbi trust investments subtotal —   —   —   —   12   23   —   35   10   —   —   10  

Total assets 653   —   —   653   352   23   —   375   669   —   —   669  
Liabilities
Commodity derivative liabilities (b)
—   —   ( 128 ) ( 128 ) —   —   —   —   —   —   —   —  
Deferred compensation obligation —   ( 9 ) —   ( 9 ) —   ( 7 ) —   ( 7 ) —   ( 4 ) —   ( 4 )
Total liabilities —   ( 9 ) ( 128 ) ( 137 ) —   ( 7 ) —   ( 7 ) —   ( 4 ) —   ( 4 )
Total net assets (liabilities) $ 653   $ ( 9 ) $ ( 128 ) $ 516   $ 352   $ 16   $ —   $ 368   $ 669   $ ( 4 ) $ —   $ 665  

ComEd PECO BGE
At December 31, 2024 Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total
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 assets 390   —   —   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 $ 70 million and $ 66 million at September 30, 2025 and December 31, 2024, respectively, and restricted cash of $ 184 million and $ 176 million at September 30, 2025 and December 31, 2024, respectively. Additionally, ComEd includes long-term restricted cash of $ 49 million and $ 41 million at September 30, 2025 and December 31, 2024, respectively, which is reported in Other deferred debits and other assets in the Consolidated Balance Sheets. PECO
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excludes cash of $ 24 million and $ 19 million at September 30, 2025 and December 31, 2024, respectively. BGE excludes cash of $ 6 million and $ 33 million at September 30, 2025 and December 31, 2024, respectively.
(b) The Level 3 balance consists of the current and noncurrent liability of $ 28 million and $ 100 million, respectively, at September 30, 2025 and $ 29 million and $ 103 million, respectively, at December 31, 2024 related to floating-to-fixed energy swap contracts with unaffiliated suppliers.

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PHI, Pepco, DPL, and ACE

At September 30, 2025 At December 31, 2024
PHI Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total
Assets
Cash equivalents (a)
$ 56   $ —   $ —   $ 56   $ 93   $ —   $ —   $ 93  
Rabbi trust investments
Cash equivalents 97   —   —   97   92   —   —   92  
Mutual funds 9   —   —   9   9   —   —   9  
Fixed income —   6   —   6   —   6   —   6  
Life insurance contracts —   22   21   43   —   23   21   44  
Rabbi trust investments subtotal 106   28   21   155   101   29   21   151  
Total assets 162   28   21   211   194   29   21   244  
Liabilities
Deferred compensation obligation —   ( 10 ) —   ( 10 ) —   ( 12 ) —   ( 12 )

Total liabilities —   ( 10 ) —   ( 10 ) —   ( 12 ) —   ( 12 )
Total net assets $ 162   $ 18   $ 21   $ 201   $ 194   $ 17   $ 21   $ 232  

Pepco DPL ACE
At September 30, 2025 Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total
Assets
Cash equivalents (a)
$ 22   $ —   $ —   $ 22   $ 2   $ —   $ —   $ 2   $ —   $ —   $ —   $ —  

Rabbi trust investments
Cash equivalents 97   —   —   97   —   —   —   —   —   —   —   —  

Life insurance contracts —   22   21   43   —   —   —   —   —   —   —   —  
Rabbi trust investments subtotal 97   22   21   140   —   —   —   —   —   —   —   —  
Total assets 119   22   21   162   2   —   —   2   —   —   —   —  
Liabilities
Deferred compensation obligation —   ( 1 ) —   ( 1 ) —   —   —   —   —   —   —   —  

Total liabilities —   ( 1 ) —   ( 1 ) —   —   —   —   —   —   —   —  
Total net assets $ 119   $ 21   $ 21   $ 161   $ 2   $ —   $ —   $ 2   $ —   $ —   $ —   $ —  

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Pepco DPL ACE
At December 31, 2024 Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total
Assets
Cash equivalents (a)
$ 21   $ —   $ —   $ 21   $ 3   $ —   $ —   $ 3   $ —   $ —   $ —   $ —  
Rabbi trust investments
Cash equivalents 91   —   —   91   —   —   —   —   —   —   —   —  

Life insurance contracts —   23   21   44   —   —   —   —   —   —   —   —  
Rabbi trust investments subtotal 91   23   21   135   —   —   —   —   —   —   —   —  
Total assets 112   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 $ 61 million and $ 70 million at September 30, 2025 and December 31, 2024, respectively, and restricted cash of $ 3 million and zero at September 30, 2025 and December 31, 2024. Pepco excludes cash of $ 25 million and $ 30 million at September 30, 2025 and December 31, 2024, respectively. DPL excludes cash of $ 6 million and $ 20 million at September 30, 2025 and December 31, 2024, respectively. ACE excludes cash of $ 25 million and $ 14 million at September 30, 2025 and December 31, 2024, respectively and restricted cash of $ 3 million and zero at September 30, 2025 and December 31, 2024, respectively.

Reconciliation of Level 3 Assets and Liabilities
The following tables present the fair value reconciliation of Level 3 assets and liabilities measured at fair value on a recurring basis during the three and nine months ended September 30, 2025 and 2024:

Exelon ComEd PHI and Pepco
Three Months Ended September 30, 2025 Total Commodity
Derivatives Life Insurance Contracts
Balance at June 30, 2025 $ ( 112 ) $ ( 135 ) $ 22  
Total realized / unrealized gains (losses)
Included in net income (a)
1   —   —  

Included in regulatory assets/liabilities 7   7   (b)
—  

Settlements ( 1 ) —   ( 1 )

Balance at September 30, 2025 $ ( 105 ) $ ( 128 ) (c)
$ 21  
The amount of total gains included in income attributed to the change in unrealized gains related to assets and liabilities at September 30, 2025 $ ( 1 ) $ —   $ —  

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Exelon ComEd PHI and Pepco
Three Months Ended September 30, 2024 Total Commodity
Derivatives Life Insurance Contracts
Balance at June 30, 2024 $ ( 116 ) $ ( 139 ) $ 22  
Total realized / unrealized gains (losses)
Included in net income (a)
—   —   —  

Included in regulatory assets/liabilities ( 26 ) ( 26 ) (b)
—  

Settlements ( 1 ) —   ( 1 )

Balance at September 30, 2024 $ ( 143 ) $ ( 165 ) $ 21  
The amount of total gains included in income attributed to the change in unrealized gains related to assets and liabilities at September 30, 2024 $ —   $ —   $ —  

Exelon ComEd PHI and Pepco
Nine Months Ended September 30, 2025 Total Commodity
Derivatives Life Insurance Contracts
Balance at December 31, 2024 $ ( 110 ) $ ( 132 ) $ 21  
Total realized / unrealized gains (losses)
Included in net income (a)
2   —   1  

Included in regulatory assets/liabilities 4   4   (b)
—  

Settlements ( 1 ) —   ( 1 )

Balance at September 30, 2025 $ ( 105 ) $ ( 128 ) (c)
$ 21  
The amount of total gains included in income attributed to the change in unrealized gains related to assets and liabilities at September 30, 2025 $ 1   $ —   $ 1  

  
Exelon ComEd PHI and Pepco
Nine Months Ended September 30, 2024 Total Commodity
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 ( 32 ) ( 32 ) (b)
—  

Settlements ( 22 ) —   ( 22 )

Balance at September 30, 2024 $ ( 143 ) $ ( 165 ) $ 21  
The amount of total gains included in income attributed to the change in unrealized gains related to assets and liabilities at September 30, 2024 $ 2   $ —   $ 2  
__________
(a) Classified in Operating and maintenance expense in the Consolidated Statements of Operations and Comprehensive Income.
(b) Includes $ 1 million of increases in fair value and an increase for realized gains due to settlements of $ 6 million recorded in Purchased power expense associated with floating-to-fixed energy swap contracts with unaffiliated suppliers for the three months ended September 30, 2025. Includes $ 31 million of decreases in fair value and an increase for realized gains due to settlements of $ 5 million recorded in Purchased power expense associated with floating-to-fixed energy swap contracts with unaffiliated suppliers for the three months ended September 30, 2024. Includes $ 29 million of decreases in fair value and an increase for realized gains due to settlements of $ 33 million recorded in Purchased power expense associated with floating-to-fixed energy swap contracts with unaffiliated suppliers for the nine months ended September 30, 2025. Includes $ 60 million of decreases in fair value and an increase for realized gains due to settlements of $ 28 million recorded in Purchased power expense associated with floating-to-fixed energy swap contracts with unaffiliated suppliers for the nine months ended September 30, 2024.
(c) The balance of the current and noncurrent asset was effectively zero as of September 30, 2025. The balance consists of a current and noncurrent liability of $ 28 million and $ 100 million, respectively, as of September 30, 2025.
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Commodity Derivatives (Exelon and ComEd)
The table below discloses the significant unobservable inputs to the forward curve used to value mark-to-market derivatives.

Type of trade Fair Value at September 30, 2025 Fair Value at December 31, 2024 Valuation
Technique Unobservable
Input 2025 Range & Arithmetic Average 2024 Range & Arithmetic Average
Commodity derivatives $ ( 128 ) $ ( 132 ) Discounted
Cash Flow Forward power price (a)
$ 29.88 - $ 59.41 $ 41.89 $ 30.31 - $ 59.88 $ 42.08

________
(a) An increase to the forward power price would increase the fair value.

11. Commitments and Contingencies (All Registrants)
The following is an update to the current status of commitments and contingencies set forth in Note 18 — Commitments and Contingencies of the 2024 Form 10-K.
Commitments
PHI Merger Commitments (Exelon, PHI, Pepco, DPL, and ACE). Approval of the PHI Merger in Delaware, New Jersey, Maryland, and the District of Columbia was conditioned upon Exelon and PHI agreeing to certain commitments. The following amounts represent total commitment costs that have been recorded since the acquisition date and the total remaining obligations for Exelon, PHI, Pepco, DPL, and ACE at September 30, 2025:

Description Exelon PHI Pepco DPL ACE
Total commitments $ 513   $ 320   $ 120   $ 89   $ 111  
Remaining commitments (a)
23   21   20   1   —  

__________
(a) Remaining commitments extend through 2026 and include escrow funds, charitable contributions, and rate credits.
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Commercial Commitments (All Registrants). The Registrants’ commercial commitments at September 30, 2025, representing commitments potentially triggered by future events were as follows:
Expiration within
Total 2025 2026 2027 2028 2029 2030 and beyond
Exelon
Letters of credit (a)
$ 56   $ 11   $ 45   $ —   $ —   $ —   $ —  
Surety bonds (b)
273   83   110   2   78   —   —  
Financing trust guarantees (c)
378   —   —   —   78   —   300  
Guaranteed lease residual values (d)
24   —   2   4   5   4   9  
Total commercial commitments $ 731   $ 94   $ 157   $ 6   $ 161   $ 4   $ 309  

ComEd
Letters of credit (a)
$ 18   $ 4   $ 14   $ —   $ —   $ —   $ —  
Surety bonds (b)
37   5   30   2   —   —   —  
Financing trust guarantees (c)
200   —   —   —   —   —   200  
Total commercial commitments $ 255   $ 9   $ 44   $ 2   $ —   $ —   $ 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   $ 6   $ 21   $ —   $ —   $ —   $ —  
Surety bonds (b)
3   1   2   —   —   —   —  
Total commercial commitments $ 30   $ 7   $ 23   $ —   $ —   $ —   $ —  

PHI
Letters of credit (a)
$ 4   $ —   $ 4   $ —   $ —   $ —   $ —  
Surety bonds (b)
172   73   21   —   78   —   —  
Guaranteed lease residual values (d)
24   —   2   4   5   4   9  
Total commercial commitments $ 200   $ 73   $ 27   $ 4   $ 83   $ 4   $ 9  

Pepco
Letters of credit (a)
$ 2   $ —   $ 2   $ —   $ —   $ —   $ —  
Surety bonds (b)
160   68   14   —   78   —   —  
Guaranteed lease residual values (d)
8   —   1   1   2   1   3  
Total commercial commitments $ 170   $ 68   $ 17   $ 1   $ 80   $ 1   $ 3  

DPL
Letters of credit (a)
$ 1   $ —   $ 1   $ —   $ —   $ —   $ —  
Surety bonds (b)
7   3   4   —   —   —   —  
Guaranteed lease residual values (d)
9   —   —   2   2   2   3  
Total commercial commitments $ 17   $ 3   $ 5   $ 2   $ 2   $ 2   $ 3  

ACE
Letters of credit (a)
$ 1   $ —   $ 1   $ —   $ —   $ —   $ —  
Surety bonds (b)
5   2   3   —   —   —   —  
Guaranteed lease residual values (d)
7   —   1   1   1   1   3  
Total commercial commitments $ 13   $ 2   $ 5   $ 1   $ 1   $ 1   $ 3  

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__________
(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 9 years. The maximum potential obligation at the end of the minimum lease term would be $ 55 million guaranteed by Exelon and PHI, of which $ 17 million, $ 21 million, and $ 17 million is guaranteed by Pepco, DPL, and ACE, respectively. Historically, payments under the guarantees have not been made and PHI believes the likelihood of payments being required under the guarantees is remote.
Environmental Remediation Matters
General (All Registrants). The Registrants’ operations have in the past, and may in the future, require substantial expenditures to comply with environmental laws. Additionally, under federal and state environmental laws, the Registrants are generally liable for the costs of remediating environmental contamination of property now or formerly owned by them and of property contaminated by hazardous substances generated by them. The Registrants own or lease a number of real estate parcels, including parcels on which their operations or the operations of others may have resulted in contamination by substances that are considered hazardous under environmental laws. In addition, the Registrants are currently involved in a number of proceedings relating to sites where hazardous substances have been deposited and may be subject to additional proceedings in the future. Unless otherwise disclosed, the Registrants cannot reasonably estimate whether they will incur significant liabilities for additional investigation and remediation costs at these or additional sites identified by the Registrants, environmental agencies, or others, or whether such costs will be recoverable from third parties, including customers. Additional costs could have a material, unfavorable impact on the Registrants' financial statements.
MGP Sites (All Registrants). ComEd, PECO, BGE, and DPL have identified sites where former MGP or gas purification activities have or may have resulted in actual site contamination. For some sites, there are additional PRPs that may share responsibility for the ultimate remediation of each location.
• ComEd has 16 sites currently under some degree of active study and/or remediation. ComEd expects the majority of the remediation at these sites to continue through at least 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 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.
During the third quarter of 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
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changes in remediation 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 September 30, 2025 and December 31, 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:

September 30, 2025 December 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 $ 387   $ 324   $ 403   $ 322  
ComEd 290   290   285   284  
PECO 25   24   29   28  
BGE 13   10   13   10  
PHI 57   —   75   —  
Pepco 55   —   73   —  
DPL 1   —   1   —  
ACE 1   —   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 Generation following the 2016 merger between PHI and Exelon. This generating facility was deactivated in June 2012. The remaining portion of the site consists of a Pepco transmission and distribution service center that remains in operation. In December 2011, the U.S. District Court for the District of Columbia approved a Consent Decree entered into by Pepco and Pepco Energy Services (hereinafter "Pepco Entities") with the DOEE, which requires the Pepco Entities to conduct a Remedial Investigation and Feasibility Study (RI/FS) for the Benning Road site and an approximately 10 to 15-acre portion of the adjacent Anacostia River. The purpose of this RI/FS is to define the nature and extent of contamination from the Benning Road site and to evaluate remedial alternatives.
Pursuant to an internal agreement between the Pepco Entities, since 2013, Pepco has performed the work required by the Consent Decree and has been reimbursed for that work by an agreed upon allocation of costs between the Pepco Entities. In September 2019, the Pepco Entities issued a draft “final” RI report which the DOEE approved on February 3, 2020. 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 area closed on April 18, 2025 and the public comment period for the waterside area is scheduled to close on October 31, 2025. 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/Generation
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to a non-utility subsidiary of Exelon which going forward will be responsible for those liabilities. Exelon, PHI, and Pepco have determined that a loss associated with this matter is probable and have accrued an estimated liability, which is included in the table above.
Anacostia River Tidal Reach (Exelon, PHI, and Pepco) . Contemporaneous with the Benning Road site RI/FS being performed by the Pepco Entities, the DOEE and NPS have been conducting a separate RI/FS focused on the entire tidal reach of the Anacostia River extending from just north of the Maryland-District of Columbia boundary line to the confluence of the Anacostia and Potomac Rivers. The riverwide RI incorporated the results of the river sampling performed by the Pepco Entities as part of the Benning RI/FS, as well as similar sampling efforts conducted by owners of other sites adjacent to this segment of the river and supplemental river sampling conducted by the DOEE’s contractor.
On September 30, 2020, the DOEE released its Interim ROD for the Anacostia River sediments. The Interim ROD reflects an adaptive management approach which will require several identified “hot spots” in the river to be addressed first while continuing to conduct studies and to monitor the river to evaluate improvements and determine potential future remediation plans. The adaptive management process chosen by the DOEE is less intrusive, provides more long-term environmental certainty, is less costly, and allows for site specific remediation plans already underway, including the plan for the Benning Road site to proceed to conclusion.
On July 15, 2022, Pepco received a letter from the District of Columbia's Office of the Attorney General (D.C. OAG) on behalf of the DOEE conveying a settlement offer to resolve all PRPs' liability to the District of Columbia (District) for their past costs and their anticipated future costs to complete the work for the Interim ROD. Pepco responded on July 27, 2022 agreeing to enter into settlement discussions. 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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(Dollars in millions, except per share data, unless otherwise noted)

Note 11 — 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. Pepco also submitted an environmental assessment to the DOEE of the vault system pursuant to the Consent Order in July 2024, and revisions in response to the DOEE's comments in May 2025 and September 2025. 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
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
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(Dollars in millions, except per share data, unless otherwise noted)

Note 11 — Commitments and Contingencies

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 renewed motion for preliminary approval.
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.

12. Shareholders' Equity (Exelon)
At-the-Market Programs
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Combined Notes to Consolidated Financial Statements — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)

Note 12 — Shareholders' Equity

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.
During the first quarter of 2025, Exelon issued approximately 4.0 million shares of Common stock at an average net price of $ 42.98 per share. The net proceeds from the issuance were $ 173  million, which were used for general corporate purposes.
In addition, in the first quarter of 2025, Exelon entered into forward sale agreements for 5.7 million shares of Common stock, at a weighted-average net forward price of $ 43.24 per share. The forward sale agreements require Exelon to, at its election prior to December 15, 2025, 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.
In the second quarter of 2025, Exelon entered into forward sale agreements for 6.2 million shares and 3.6 million shares of Common stock at weighted-average net forward prices of $ 43.51 and $ 43.17 per share, respectively. The forward sale agreements require Exelon to, at its election prior to December 15, 2025 and November 16, 2026, respectively, 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.
In the third quarter of 2025, Exelon entered into forward sale agreements for 11.5 million shares at a weighted-average net forward price of $ 43.73 per share. The forward sale agreements require Exelon to, at its election prior to December 15, 2026 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 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 nine months ended September 30, 2025, approximately 26.7 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, $ 1.6 billion of Common stock remained available for sale pursuant to the ATM program as of September 30, 2025.
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Combined Notes to Consolidated Financial Statements — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)

Note 13 — Changes in Accumulated Other Comprehensive Income

13. Changes in Accumulated Other Comprehensive Income (Loss) (Exelon)
The following table presents changes in Exelon's AOCI, net of tax, by component:

Three Months Ended September 30, 2025  Cash Flow Hedges Pension and Non-Pension Postretirement Benefit Plan Items (a)
Total
Balance at June 30, 2025 $ 31   $ ( 749 ) $ ( 718 )
OCI before reclassifications ( 1 ) —   ( 1 )
Amounts reclassified from AOCI ( 1 ) 5   4  
Net current-period OCI ( 2 ) 5   3  
Balance at September 30, 2025 $ 29   $ ( 744 ) $ ( 715 )

Three Months Ended September 30, 2024  Cash Flow Hedges Pension and Non-Pension Postretirement Benefit Plan Items (a)
Total
Balance at June 30, 2024 $ 27   $ ( 739 ) $ ( 712 )
OCI before reclassifications ( 28 ) —   ( 28 )
Amounts reclassified from AOCI ( 1 ) 5   4  
Net current-period OCI ( 29 ) 5   ( 24 )
Balance at September 30, 2024 $ ( 2 ) $ ( 734 ) $ ( 736 )

Nine Months Ended September 30, 2025  Cash Flow Hedges Pension and Non-Pension Postretirement Benefit Plan Items (a)
Total
December 31, 2024 $ 45   $ ( 765 ) $ ( 720 )
OCI before reclassifications ( 11 ) 5   ( 6 )
Amounts reclassified from AOCI ( 5 ) 16   11  
Net current-period OCI $ ( 16 ) $ 21   $ 5  
Balance at September 30, 2025 $ 29   $ ( 744 ) $ ( 715 )

Nine Months Ended September 30, 2024 Cash Flow Hedges Pension and Non-Pension Postretirement Benefit Plan Items (a)
Total
Balance at December 31, 2023 $ ( 3 ) $ ( 723 ) $ ( 726 )
OCI before reclassifications 4   ( 26 ) ( 22 )
Amounts reclassified from AOCI ( 3 ) 15   12  
Net current-period OCI $ 1   $ ( 11 ) $ ( 10 )
Balance at September 30, 2024 $ ( 2 ) $ ( 734 ) $ ( 736 )

__________
(a) This AOCI component is included in the computation of net periodic pension and OPEB cost. See Note 14 — Retirement Benefits of the 2024 Form 10-K and Note 7 — Retirement Benefits for additional information. See Exelon's Statements of Operations and Comprehensive Income for individual components of AOCI.

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

Note 13 — Changes in Accumulated Other Comprehensive Income

The following table presents Income tax benefit (expense) allocated to each component of Exelon's Other comprehensive income (loss):

Three Months Ended September 30, Nine Months Ended September 30,
2025 2024 2025 2024
Pension and non-pension postretirement benefit plans:

Actuarial losses reclassified to periodic benefit cost $ ( 2 ) $ ( 2 ) $ ( 6 ) $ ( 6 )
Pension and non-pension postretirement benefit plans valuation adjustments —   —   ( 2 ) 8  
Unrealized gains on cash flow hedges 2   10   4   —  

14. 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
Exelon ComEd PECO BGE PHI Pepco DPL ACE
Three Months Ended September 30, 2025
Utility taxes (a)
$ 269   $ 85   $ 58   $ 27   $ 99   $ 91   $ 7   $ 1  
Property 119   9   6   61   43   29   13   1  
Payroll 34   9   4   5   8   2   1   1  

Three Months Ended September 30, 2024
Utility taxes (a)
$ 248   $ 80   $ 51   $ 25   $ 92   $ 84   $ 7   $ 1  
Property 111   7   5   57   41   28   12   1  
Payroll 33   9   4   5   7   2   1   —  

Nine Months Ended September 30, 2025
Utility taxes (a)
$ 765   $ 244   $ 156   $ 85   $ 280   $ 255   $ 22   $ 3  
Property 341   27   15   175   123   84   37   2  
Payroll 101   26   14   14   22   5   3   2  

Nine Months Ended September 30, 2024
Utility taxes (a)
$ 695   $ 229   $ 134   $ 78   $ 254   $ 230   $ 21   $ 3  
Property 323   25   14   164   119   81   35   2  
Payroll 100   27   13   14   22   6   3   2  
_________
(a) The Registrants' utility taxes represent 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.
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Combined Notes to Consolidated Financial Statements — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)

Note 14 — Supplemental Financial Information

Other, net
Exelon ComEd PECO BGE   PHI Pepco DPL ACE
Three Months Ended September 30, 2025
AFUDC — Equity $ 49   $ 19   $ 9   $ 11   $ 10   $ 8   $ 1   $ 1  
Non-service net periodic benefit cost ( 13 ) —   —   —   —   —   —   —  

Three Months Ended September 30, 2024
AFUDC — Equity $ 38   $ 13   $ 7   $ 5   $ 12   $ 8   $ 3   $ 1  
Non-service net periodic benefit cost ( 13 ) —   —   —   —   —   —   —  

Nine Months Ended September 30, 2025
AFUDC — Equity $ 130   $ 45   $ 26   $ 29   $ 30   $ 23   $ 4   $ 3  
Non-service net periodic benefit cost ( 39 ) —   —   —   —   —   —   —  

Nine Months Ended September 30, 2024
AFUDC — Equity $ 116   $ 32   $ 24   $ 18   $ 42   $ 32   $ 9   $ 1  
Non-service net periodic benefit cost ( 29 ) —   —   —   —   —   —   —  

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
Exelon ComEd PECO BGE PHI Pepco DPL ACE
Nine Months Ended September 30, 2025
Property, plant, and equipment (a)
$ 2,270   $ 915   $ 333   $ 375   $ 606   $ 268   $ 169   ` $ 166  
Amortization of regulatory assets and liabilities, net (a)
444   247   3   98   95   53   20   22  
Amortization of intangible assets, net (a)
3   —   —   —   —   —   —   —  

ARO accretion (b)
2   —   —   —   2   1   —   —  
Total depreciation, amortization and accretion $ 2,719   $ 1,162   $ 336   $ 473   $ 703   $ 322   $ 189   $ 188  

Nine Months Ended September 30, 2024
Property, plant, and equipment (a)
$ 2,168   $ 869   $ 308   $ 369   $ 581   $ 249   $ 162   $ 158  
Amortization of regulatory assets and liabilities, net (a)
507   255   10   105   135   58   21   56  
Amortization of intangible assets, net (a)
6   —   —   —   —   —   —   —  

ARO accretion (b)
2   —   —   —   —   —   —   —  
Total depreciation and amortization $ 2,683   $ 1,124   $ 318   $ 474   $ 716   $ 307   $ 183   $ 214  

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

Note 14 — Supplemental Financial Information

Other non-cash operating activities
Exelon ComEd PECO BGE PHI Pepco DPL ACE
Nine Months Ended September 30, 2025
Pension and OPEB costs $ 204   $ 64   $ 5   $ 46   $ 72   $ 26   $ 12   $ 10  
Allowance for credit losses 202   41   75   20   66   29   13   24  

True-up adjustments to decoupling mechanisms and formula rates (a)
627   525   6   63   33   19   10   4  

Amortization of operating ROU asset 22   —   —   5   13   4   4   2  

AFUDC — Equity ( 130 ) ( 45 ) ( 26 ) ( 29 ) ( 30 ) ( 23 ) ( 4 ) ( 3 )

Nine Months Ended September 30, 2024
Pension and OPEB costs (benefit) $ 181   $ 53   $ ( 1 ) $ 45   $ 71   $ 24   $ 11   $ 10  
Allowance for credit losses 170   17   79   23   51   25   7   19  

True-up adjustments to decoupling mechanisms and formula rates (a)
49   100   ( 3 ) ( 28 ) ( 20 ) ( 42 ) 7   15  

Amortization of operating ROU asset 28   —   —   5   19   4   6   2  

AFUDC — Equity ( 116 ) ( 32 ) ( 24 ) ( 18 ) ( 42 ) ( 32 ) ( 9 ) ( 1 )

__________
(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 rates. For BGE, Pepco, DPL, and ACE, reflects the change in Regulatory assets and liabilities associated with their decoupling mechanisms and transmission formula rates. See Note 3 — Regulatory Matters of the 2024 Form 10-K for additional information.
The following tables provide a reconciliation of cash, cash equivalents, and restricted cash reported within the Registrants’ Consolidated Balance Sheets that sum to the total of the same amounts in their Consolidated Statements of Cash Flows.
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Combined Notes to Consolidated Financial Statements — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)

Note 14 — Supplemental Financial Information

Cash, cash equivalents, and restricted cash
Exelon ComEd PECO BGE PHI Pepco DPL ACE
Balance at September 30, 2025
Cash and cash equivalents $ 1,533   $ 405   $ 364   $ 663   $ 93   $ 25   $ 6   $ 25  
Restricted cash and cash equivalents 516   453   —   2   27   22   2   3  
Restricted cash included in Other deferred debits and other assets 49   49   —   —   —   —   —   —  
Total cash, restricted cash, and cash equivalents $ 2,098   $ 907   $ 364   $ 665   $ 120   $ 47   $ 8   $ 28  

Balance at December 31, 2024
Cash and cash equivalents $ 357   $ 105   $ 48   $ 33   $ 139   $ 30   $ 21   $ 14  
Restricted cash and cash equivalents 541   486   —   1   24   21   2   —  
Restricted cash included in Other deferred debits and other assets 41   41   —   —   —   —   —   —  
Total cash, restricted cash, and cash equivalents $ 939   $ 632   $ 48   $ 34   $ 163   $ 51   $ 23   $ 14  

Balance at September 30, 2024
Cash and cash equivalents $ 616   $ 109   $ 28   $ 330   $ 100   $ 20   $ 8   $ 17  
Restricted cash and cash equivalents 552   481   9   —   22   20   2   —  
Restricted cash included in Other deferred debits and other assets 65   65   —   —   —   —   —   —  
Total cash, restricted cash, and cash equivalents $ 1,233   $ 655   $ 37   $ 330   $ 122   $ 40   $ 10   $ 17  

Balance at December 31, 2023
Cash and cash equivalents $ 445   $ 110   $ 42   $ 47   $ 180   $ 48   $ 16   $ 21  
Restricted cash and cash equivalents 482   402   9   1   24   24   —   —  
Restricted cash included in Other deferred debits and other assets 174   174   —   —   —   —   —   —  

Total cash, restricted cash, and cash equivalents $ 1,101   $ 686   $ 51   $ 48   $ 204   $ 72   $ 16   $ 21  

For additional information on restricted cash see Note 1 — Significant Accounting Policies of the 2024 Form 10-K.
Supplemental Balance Sheet Information
The following table provides additional information about material items recorded in the Registrants' Consolidated Balance Sheets.
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Combined Notes to Consolidated Financial Statements — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)

Note 14 — Supplemental Financial Information

Accrued expenses
Exelon ComEd PECO BGE PHI Pepco DPL ACE
Balance at September 30, 2025
Compensation-related accruals (a)
$ 584   $ 179   $ 74   $ 73   $ 105   $ 29   $ 20   $ 13  
Taxes accrued 283   160   13   96   116   82   21   7  
Interest accrued 458   106   59   91   86   38   28   18  

Balance at December 31, 2024
Compensation-related accruals (a)
$ 679   $ 197   $ 87   $ 88   $ 132   $ 38   $ 26   $ 18  
Taxes accrued 217   96   13   34   110   92   11   11  
Interest accrued 468   150   60   50   83   44   16   18  

__________
(a) Primarily includes accrued payroll, bonuses and other incentives, vacation, and benefits.

15. 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 affiliates Capitalized costs
Three Months Ended September 30, Nine Months Ended September 30, Three Months Ended September 30, Nine Months Ended September 30,
2025 2024 2025 2024 2025 2024 2025 2024
Exelon
   BSC $ 156   $ 141   $ 478   $ 458  
   PHISCO 29   27   83   85  
ComEd
   BSC $ 95   $ 102   $ 296   $ 306   63   55   186   189  
PECO
   BSC 58   61   178   180   24   23   79   81  
BGE
   BSC 60   61   185   182   28   25   92   74  
PHI
   BSC 44   46   144   145   41   38   121   114  
   PHISCO —   —   —   —   29   27   83   85  
Pepco
   BSC 30   29   93   92   18   16   52   51  
   PHISCO 29   28   91   94   14   12   36   36  

DPL
   BSC 19   19   58   58   12   11   36   36  
   PHISCO 24   24   75   75   8   8   25   25  

ACE
   BSC 15   16   47   48   10   9   28   24  
   PHISCO 22   23   69   71   7   7   22   24  

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

Note 15 — Related Party Transactions

Current Receivables from/Payables to Affiliates
The following tables present current Receivables from affiliates and current Payables to affiliates:
September 30, 2025

Receivables from affiliates:
Payables to affiliates: ComEd PECO BGE Pepco DPL ACE BSC PHISCO Other Total
ComEd $ —   $ —   $ —   $ —   $ —   $ 60   $ —   $ 1   $ 61  
PECO $ —   —   —   —   —   30   —   5   35  
BGE —   —   —   —   —   33   —   —   33  
PHI —   —   1   —   —   —   5   —   10   16  
Pepco —   —   —   —   —   17   15   1   33  
DPL —   —   —   —   —   11   11   1   23  
ACE —   —   —   —   —   9   9   —   18  
Other 4   2   —   1   1   11   —   —   19  
Total $ 4   $ 2   $ 1   $ 1   $ 1   $ 11   $ 165   $ 35   $ 18   $ 238  

December 31, 2024

Receivables from affiliates:
Payables to affiliates: ComEd PECO BGE Pepco DPL ACE BSC PHISCO Other Total
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  
Other 4   —   —   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 intercompany 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:

September 30, 2025 December 31, 2024
Exelon ComEd PECO Exelon ComEd PECO
ComEd Financing III $ 206   $ 206   $ —   $ 206   $ 206   $ —  
PECO Trust III 81   —   81   81   —   81  
PECO Trust IV 103   —   103   103   —   103  
Total $ 390   $ 206   $ 184   $ 390   $ 206   $ 184  

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ITEM 2.    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.

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 three and nine months ended September 30, 2025 compared to the same period in 2024. For additional information regarding the financial results for the three and nine months ended September 30, 2025 and 2024, see the discussions of Results of Operations by Registrant.

Three Months Ended September 30, Favorable (Unfavorable) Variance Nine Months Ended September 30, Favorable (Unfavorable) Variance
2025 2024 2025 2024
Exelon $ 875  $ 707  $ 168  $ 2,174  $ 1,813  $ 361 
ComEd 373  360  13  903  823  80 
PECO 250  117  133  652  356  296 
BGE 82  45  37  398  353  45 
PHI 291  278  13  628  603  25 
Pepco 156  140  16  337  323  14 
DPL 55  55  —  163  156  7 
ACE 82  83  (1) 138  133  5 
Other (a)
(121) (93) (28) (407) (322) (85)

__________
(a) Other primarily includes eliminating and consolidating adjustments, Exelon’s corporate operations, shared service entities, and other financing and investment activities.
Three Months Ended September 30, 2025 Compared to Three Months Ended September 30, 2024. Net income attributable to common shareholders increased by $168 million and diluted earnings per average common share increased to $0.86 in 2025 from $0.70 in 2024 primarily due to:
• Favorable impacts of rates at ComEd, PECO, BGE, and PHI;
• Lower storm costs at PECO, due to deferral of extraordinary February and June storm costs;
• Timing of income tax expenses at PECO;
• Higher return on regulatory assets at ComEd;
• Higher AFUDC at ComEd; and
• Lower storm costs and credit loss expense at BGE.
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The increases were partially offset by:
• Timing of distribution earnings at ComEd;
• Higher depreciation expense at PECO; and
• Higher interest expense at PHI and Exelon Corporate.
Nine Months Ended September 30, 2025 Compared to Nine Months Ended September 30, 2024. Net income attributable to common shareholders increased by $361 million and diluted earnings per average common share increased to $2.15 in 2025 from $1.81 in 2024 primarily due to:
• Favorable impacts of rates at ComEd, PECO, BGE and PHI;
• Timing of income tax expenses at PECO;
• Less unfavorable weather at PECO;
• Lower storm costs at PECO and BGE;
• Higher return on regulatory assets at ComEd;
• Timing of distribution earnings at ComEd; and
• Higher AFUDC at ComEd.
The increases were partially offset by:
• Higher interest expense at PECO, BGE, PHI, and Exelon Corporate;
• Customer Relief Fund contribution at Exelon Corporate;
• Higher depreciation expense at PECO and PHI;
• Lower transmission peak load due to lower energy demand at ComEd;
• Lower impacts of the Maryland multi-year plan reconciliations at PHI; and
• Lower AFUDC at PHI.
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 GAAP Net income attributable to common shareholders and Adjusted (non-GAAP) operating earnings for the three and nine months ended September 30, 2025 compared to the same period in 2024:

Three Months Ended September 30,
2025 2024
(In millions, except per share data) Earnings per
Diluted Share Earnings per
Diluted Share
Net income attributable to common shareholders $ 875   $ 0.86   $ 707   $ 0.70  

Asset retirement obligation (net of taxes of $0 and $0, respectively)
(1) —  —  — 

Cost management charge (net of taxes of $0) (a)
—  —  1  — 

Adjusted (non-GAAP) operating earnings $ 874   $ 0.86   $ 708   $ 0.71  

Nine Months Ended September 30,
2025 2024
(In millions, except per share data) Earnings per
Diluted Share Earnings per
Diluted Share
Net income attributable to common shareholders $ 2,174   $ 2.15   $ 1,813   $ 1.81  

Asset retirement obligation (net of taxes of $0 and $0, respectively)
(1) —  —  — 

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 $3, respectively) (a)
(1) —  10  0.01 
Income tax-related adjustments (entire amount represents tax expense) (b)
1  —  —  — 
Regulatory matters (net of taxes of $7) (c)
22  0.02  —  — 
Change in environmental liabilities (net of taxes of $0)
—  —  (1) — 
Adjusted (non-GAAP) operating earnings $ 2,198   $ 2.17   $ 1,865   $ 1.86  

__________
Note:
Amounts may not sum due to rounding.
Unless otherwise noted, the income tax impact of each reconciling item between GAAP Net income attributable to common shareholders 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) Reflects the adjustment to state deferred income taxes due to changes in forecasted apportionment.
(c) Represents the probable disallowance of certain capitalized costs.

Significant 2025 Transactions and Developments
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.
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Completed Distribution Base Rate Case Proceedings

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

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Pending Distribution Base Rate Case Proceedings

Registrant/Jurisdiction Filing Date Service Requested Revenue Requirement Increase Requested ROE Expected Approval Timing
Pepco - Maryland October 14, 2025 Electric $ 133  10.50% Third quarter of 2026
DPL - Delaware September 20, 2024 (amended September 5, 2025) Natural Gas $ 37  10.65% First quarter of 2026
ACE - New Jersey November 21, 2024 Electric $ 109  10.70% Fourth quarter of 2025

Transmission Formula Rates
For 2025, the following total increases/(decreases) were included in the Utility Registrant's electric transmission formula rate updates. See Note 2 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.

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

ComEd's FERC Audit
The Utility Registrants are subject to periodic audits and investigations by FERC. FERC’s Division of Audits and Accounting initiated a nonpublic audit of ComEd in April 2021 evaluating ComEd’s compliance with (1) approved terms, rates and conditions of its federally regulated service; (2) accounting requirements of the Uniform System of Accounts; (3) reporting requirements of the FERC Form 1; and (4) the requirements for record retention. The audit period extended back to January 1, 2017.
On July 27, 2023, FERC published a final audit report which included, among other things, findings and recommendations related to ComEd's methodology regarding the allocation of certain overhead costs to capitalized construction costs under FERC regulations, including a suggestion that refunds may be due to customers for amounts collected in previous years. ComEd responded to that report and on August 28, 2023, ComEd filed a formal notice of the issues it contested within the audit report. On December 14, 2023, FERC appointed a settlement judge for the contested overhead allocation findings and set the matter for a trial-type hearing. That hearing process was held in abeyance while a formal settlement process, which began in February 2024, took place.
On July 30, 2024, ComEd reached an agreement in principle on the contested overhead allocation finding. As a result of the settlement process, ComEd recorded a charge for the probable disallowance of $70 million of certain currently capitalized construction costs to operating expenses, which are not expected to be recovered in future rates. The 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.
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Other Key Business Drivers and Management Strategies
The following discussion of other key business drivers and management strategies includes current developments of previously disclosed matters and new issues arising during the period that may impact future financial statements. This section should be read in conjunction with ITEM 1. Business in the 2024 Form 10-K, ITEM 7. Management's Discussion and Analysis of Financial Condition and Results of Operations — Other Key Business Drivers and Management Strategies in the 2024 Form 10-K, and Note 11 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements in this report for additional information on various environmental matters.
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. There are no material financial statement impacts as a result of the DOE terminations. Exelon, ComEd, 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 will no longer be filed. DPL also derecognized Regulatory liabilities of $0.4 million during the second quarter of 2025 for multi-year reconciliations yet to be filed. Multi-year plan reconciliations filed prior to January 1, 2025, remain lawful and will be resolved in their respective proceedings.
Summer Rate Mitigation (Exelon, BGE, PHI, Pepco, DPL, and ACE).
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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 will be distributed to residential customers based on their consumption of electricity supply that is 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 $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. An additional disbursement from the state of Maryland is expected in the first quarter of 2026, which will also be used to reduce residential customer receivables upon receipt.
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 a Regulatory asset. 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.
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 will be funded by the NJBPU. The program will provide 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 $25 million in bill credits to residential customers in September 2025 reducing the Regulatory liability to $26 million as of September 30, 2025. The remaining funds were disbursed in October 2025.
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
Management of each of the Registrants makes a number of significant estimates, assumptions, and judgments in the preparation of its financial statements. As of September 30, 2025, the Registrants’ critical accounting policies and estimates had not changed significantly from December 31, 2024. See ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS — Critical Accounting Policies and Estimates in the 2024 Form 10-K for further information.
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Results of Operations by Registrant

Results of Operations — ComEd

Three Months Ended
September 30, Favorable (Unfavorable) Variance Nine Months Ended
September 30, (Unfavorable) Favorable Variance
2025 2024 2025 2024
Operating revenues $ 2,275  $ 2,229  $ 46  $ 6,176  $ 6,403  $ (227)
Operating expenses
Purchased power 806  835  29  2,044  2,504  460 
Operating and maintenance 409  410  1  1,254  1,277  23 
Depreciation and amortization 395  387  (8) 1,162  1,124  (38)
Taxes other than income taxes 107  99  (8) 303  287  (16)
Total operating expenses 1,717  1,731  14  4,763  5,192  429 
Gain on sales of assets —  —  —  —  5  (5)
Operating income 558  498  60  1,413  1,216  197 
Other income and (deductions)
Interest expense, net (135) (128) (7) (395) (374) (21)
Other, net 33  26  7  86  66  20 
Total other income and (deductions) (102) (102) —  (309) (308) (1)
Income before income taxes 456  396  60  1,104  908  196 
Income taxes 83  36  (47) 201  85  (116)
Net income $ 373  $ 360  $ 13  $ 903  $ 823  $ 80 

Three Months Ended September 30, 2025 Compared to Three Months Ended September 30, 2024. Net Income increased by $13 million as compared to the same period in 2024 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 the timing of distribution earnings.
Nine Months Ended September 30, 2025 Compared to Nine Months Ended September 30, 2024. Net income increased by $80 million as compared to the same period in 2024, 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, higher AFUDC, and timing of distribution earnings, partially offset by lower transmission peak load.
The changes in Operating revenues consisted of the following:

Three Months Ended
September 30, 2025 Nine Months Ended
September 30, 2025
Increase (Decrease) Increase (Decrease)
Distribution $ 85  $ 200 
Transmission 3  (15)
Energy efficiency 9  25 
Other (30) (17)
67  193 
Regulatory required programs (21) (420)
Total increase (decrease) $ 46  $ (227)

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.
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ComEd

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 revenues increased for the three months ended September 30, 2025 as compared to the same period in 2024, primarily due to higher fully recoverable costs, higher rate base, and higher return on regulatory assets. Electric distribution revenues increased for the nine months ended September 30, 2025 as compared to the same period in 2024, primarily due to higher fully recoverable costs, higher rate base, higher return on regulatory assets, and differences in the timing of distribution earnings.
Transmission Revenue. Under a FERC-approved formula, transmission revenue varies from year to year based upon fluctuations in the underlying costs, capital investments being recovered, and the highest daily peak load, which is updated annually in January based on the prior calendar year. Transmission revenues increased for the three months ended September 30, 2025 compared to the same period in 2024, primarily due to higher fully recoverable costs and higher rate base. Transmission revenues decreased for the nine months ended September 30, 2025 as compared to the same period in 2024, primarily due to lower transmission peak load, partially offset by higher fully recoverable costs and the impacts of higher rate base.
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 revenues increased for the three and nine months ended September 30, 2025 as compared to the same periods 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 revenues decreased for the three and nine months ended September 30, 2025 as compared to the same periods 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 decrease in Purchased power expense of $29 million and $460 million for the three and nine months ended September 30, 2025, respectively, compared to the same periods in 2024 is offset in Operating revenues as part of regulatory required programs.

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ComEd

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

Three Months Ended
September 30, 2025 Nine Months Ended
September 30, 2025
Increase (Decrease) (Decrease) Increase

Labor, other benefits, contracting, and materials $ 3  $ (14)
Storm-related costs (2) (5)
BSC costs (7) (10)
Pension and non-pension postretirement benefits expense 1  4 

Other (a)
9  (33)
4  (58)
Regulatory required programs (b)
(5) 35 
Total decrease $ (1) $ (23)

__________
(a) Primarily reflects the reclassification and increase of the FERC audit liability and a decrease in credit loss expense during the nine months ended September 30, 2024. See Note 2 - Regulatory Matters for additional information regarding the FERC audit liability.
(b) 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:

Three Months Ended
September 30, 2025 Nine Months Ended
September 30, 2025
Increase (Decrease) Increase (Decrease)
Depreciation and amortization (a)
$ 12  $ 46 
Regulatory asset amortization (4) (8)

Total increase $ 8  $ 38 

__________
(a) Reflects ongoing capital expenditures.
Interest expense, net increased $7 million and $21 million for the three and nine months ended September 30, 2025, respectively, compared to the same periods in 2024, primarily due to an increase in outstanding debt.
Other , net increased $7 million and $20 million for the three and nine months ended September 30, 2025, respectively, compared to the same periods in 2024, primarily due to higher AFUDC equity.
Effective income tax rat es were 18.2% and 9.1% for the three months ended September 30, 2025 and 2024, respectively, and 18.2% and 9.4% for the nine months ended September 30, 2025 and 2024, respectively. See Note 6 — 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

Three Months Ended
September 30, Favorable (Unfavorable) Variance Nine Months Ended
September 30, Favorable (Unfavorable) Variance
2025 2024 2025 2024
Operating revenues $ 1,180  $ 1,030  $ 150  $ 3,513  $ 2,975  $ 538 
Operating expenses
Purchased power and fuel 446  386  (60) 1,288  1,113  (175)
Operating and maintenance 241  313  72  872  876  4 
Depreciation and amortization 115  108  (7) 336  318  (18)
Taxes other than income taxes 69  61  (8) 183  164  (19)
Total operating expenses 871  868  (3) 2,679  2,471  (208)
Gain on sales of assets —  —  —  —  4  (4)
Operating income 309  162  147  834  508  326 
Other income and (deductions)
Interest expense, net (65) (58) (7) (188) (170) (18)
Other, net 11  9  2  29  27  2 
Total other income and (deductions) (54) (49) (5) (159) (143) (16)
Income before income taxes 255  113  142  675  365  310 
Income taxes 5  (4) (9) 23  9  (14)

Net income $ 250  $ 117  $ 133  $ 652  $ 356  $ 296 

Three Months Ended September 30, 2025 Compared to Three Months Ended September 30, 2024. Net income increased by $133 million due to an increase in revenue as a result of electric and gas distribution rates, decrease in storm costs due to deferral of extraordinary February and June storm costs in the third quarter of 2025, and tax repairs deduction related to storms, some of which is timing, partially offset by an increase in depreciation expense.
Nine Months Ended September 30, 2025 Compared to Nine Months Ended September 30, 2024. Net income increased by $296 million due to an increase in revenue as a result of electric and gas distribution rates, coupled with less unfavorable weather relative to the same period last year, decrease in storm costs due to deferral of extraordinary February and June storm costs in the third quarter of 2025 and lower storm costs relative to the same period last year, and tax repairs deduction related to storms, some of which is timing, partially offset by an increase in depreciation expense and interest expense.
The changes in Operating revenues consisted of the following:

Three Months Ended
September 30, 2025 Nine Months Ended
September 30, 2025
Increase (Decrease) Increase (Decrease)
Electric Gas Total Electric Gas Total
Weather $ 1  $ —  $ 1  $ 18  $ 18  $ 36 
Volume (11) —  (11) (17) 2  (15)
Pricing 99  8  107  263  65  328 
Transmission —  —  —  (3) —  (3)
Other —  —  —  10  5  15 
89  8  97  271  90  361 
Regulatory required programs 48  5  53  124  53  177 
Total increase $ 137  $ 13  $ 150  $ 395  $ 143  $ 538 

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
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PECO

demand. During the three months ended September 30, 2025 compared to the same period in 2024, Operating revenues related to weather remained relatively consistent. During the nine months ended September 30, 2025 compared to the same period in 2024, Operating revenues related to weather increased due to less unfavorable weather conditions in PECO's service territory.
Heating and cooling degree-days are quantitative indices that reflect the demand for energy needed to heat or cool a home or business. Normal weather is determined based on historical average heating and cooling degree-days for a 30-year period in PECO's service territory. The changes in heating and cooling degree-days in PECO’s service territory for the three and nine months ended September 30, 2025 compared to the same period in 2024 and normal weather consisted of the following:

Three Months Ended September 30, % Change
PECO Service Territory 2025 2024 Normal 2025 vs. 2024 2025 vs. Normal
Heating Degree-Days — 1 20 (100.0) % (100.0) %
Cooling Degree-Days 1,095 1,062 1,035 3.1  % 5.8  %
Nine Months Ended September 30, % Change
2025 2024 Normal 2025 vs. 2024 2025 vs. Normal
Heating Degree-Days 2,684  2,441 2,827 10.0  % (5.1) %
Cooling Degree-Days 1,521  1,599 1,422 (4.9) % 7.0  %

Volume. Electric volume, exclusive of the effects of weather, for the three and nine months ended September 30, 2025 compared to the same period in 2024, decreased due to customer load. Natural gas volume for the three and nine months ended September 30, 2025 compared to the same period in 2024, remained relatively consistent.

Electric Retail Deliveries to Customers (in GWhs) Three Months Ended
September 30, % Change Weather -
Normal
% Change (b)
Nine Months Ended September 30, % Change Weather -
Normal
% Change (b)

2025 2024 2025 2024
Residential 4,063 4,146 (2.0) % (2.1) % 10,952 10,897 0.5  % (1.5) %
Small commercial & industrial 2,057 2,129 (3.4) % (2.0) % 5,835 5,876 (0.7) % (2.0) %
Large commercial & industrial 3,731 3,768 (1.0) % (2.3) % 10,470 10,531 (0.6) % (1.4) %
Public authorities & electric railroads 159 156 1.9  % 1.7  % 511 470 8.7  % 8.6  %
Total electric retail deliveries (a)
10,010 10,199 (1.9) % (2.1) % 27,768 27,774 —  % (1.4) %

At September 30,
Number of Electric Customers 2025 2024
Residential 1,539,345 1,529,205
Small commercial & industrial 154,955 155,126
Large commercial & industrial 3,159 3,156
Public authorities & electric railroads 10,343 10,716
Total 1,707,802 1,698,203

__________
(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.

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PECO

Natural Gas Deliveries to Customers (in mmcf) Three Months Ended
September 30, % Change Weather -
Normal
% Change (b)
Nine Months Ended
September 30, % Change Weather -
Normal
% Change (b)

2025 2024 2025 2024
Residential 2,064 2,359 (12.5) % (12.1) % 28,469 25,779 10.4  % (0.5) %
Small commercial & industrial 2,243 1,933 16.0  % 17.5  % 16,046 14,742 8.8  % 1.8  %
Large commercial & industrial — 1 (100.0) % (9.8) % 14 17 (17.6) % (3.8) %
Transportation 5,081 5,232 (2.9) % (2.6) % 17,759 17,248 3.0  % 0.4  %
Total natural gas retail deliveries (a)
9,388 9,525 (1.4) % (1.2) % 62,288 57,786 7.8  % 0.3  %

  At September 30,
Number of Natural Gas Customers 2025 2024
Residential 510,166 506,476
Small commercial & industrial 44,603 44,682
Large commercial & industrial 7 7
Transportation 619 643
Total 555,395 551,808

__________
(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 three and nine months ended September 30, 2025 compared to the same period in 2024 increased primarily due to electric and gas distribution rates charged to customers.
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 three and nine months ended September 30, 2025 compared to the same period in 2024 remained relatively consistent.
Other Revenue primarily includes revenue related to late payment charges. Other revenue for the three months ended September 30, 2025 compared to the same period in 2024 remained relatively consistent. Other revenue for the nine months ended September 30, 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.
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The increase of $60 million and increase of $175 million for the three and nine months ended September 30, 2025, respectively, 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:

Three Months Ended
September 30, 2025 Nine Months Ended
September 30, 2025
Increase (Decrease) Increase (Decrease)
Labor, other benefits, contracting and materials $ 18  $ 32 
Pension and non-pension postretirement benefit expense 1  3 
BSC costs (3) (1)
Credit loss expense (7) (3)
Storm-related costs (a)
(63) (29)
Other (7) (7)
(61) (5)
Regulatory required programs (11) 1 
Total decrease $ (72) $ (4)
__________
(a) Decrease primarily due to deferral of extraordinary February and June storm costs of $53 million in the third quarter of 2025.

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

Three Months Ended September 30, 2025 Nine Months Ended
September 30, 2025
Increase (Decrease) Increase (Decrease)
Depreciation and amortization (a)
$ 10  $ 26 
Regulatory asset amortization (3) (8)

Total increase $ 7  $ 18 

__________
(a) Depreciation and amortization expense increased primarily due to ongoing capital expenditures.
Taxes other than income taxes increased by $8 million and increased by $19 million for the three and nine months ended September 30, 2025, respectively, compared to the same period in 2024, primarily due to higher Pennsylvania gross receipts tax.
Interest expense, net increased $7 million and increased $18 million for the three and nine months ended September 30, 2025, respectively, compared to the same period in 2024, primarily due to an increase in interest rates and the issuance of debt in the third quarter of 2025.
Effective income tax rates were 2.0% and (3.5)% for the three months ended September 30, 2025 and 2024, respectively, 3.4% and 2.5% for the nine months ended September 30, 2025 and 2024, respectively. See Note 6 — 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

Three Months Ended
September 30, Favorable (Unfavorable) Variance Nine Months Ended
September 30, Favorable (Unfavorable) Variance
2025 2024 2025 2024
Operating revenues $ 1,209  $ 1,044  $ 165  $ 3,791  $ 3,268  $ 523 
Operating expenses
Purchased power and fuel 568  420  (148) 1,584  1,228  (356)
Operating and maintenance 239  281  42  807  795  (12)
Depreciation and amortization 155  162  7  473  474  1 
Taxes other than income taxes 93  86  (7) 273  254  (19)
Total operating expenses 1,055  949  (106) 3,137  2,751  (386)

Operating income 154  95  59  654  517  137 
Other income and (deductions)
Interest expense, net (64) (57) (7) (183) (159) (24)
Other, net 15  11  4  35  27  8 
Total other income and (deductions) (49) (46) (3) (148) (132) (16)
Income before income taxes 105  49  56  506  385  121 
Income taxes 23  4  (19) 108  32  (76)
Net income $ 82  $ 45  $ 37  $ 398  $ 353  $ 45 

Three Months Ended September 30, 2025 Compared to Three Months Ended September 30, 2024 . Net income increased $37 million primarily due to electric distribution rates and decreases in storm costs, credit loss expense, and various operating expenses.
Nine Months Ended September 30, 2025 Compared to Nine Months Ended September 30, 2024. Net Income increased $45 million primarily due to distribution and transmission rates 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 regarding the Next Generation Energy Act.
The changes in Operating revenues consisted of the following:

Three Months Ended
September 30, 2025 Nine Months Ended
September 30, 2025
Increase (Decrease) Increase
Electric Gas Total Electric Gas Total
Distribution $ 17  $ (9) $ 8  $ 66  $ 46  $ 112 
Transmission (1) —  (1) 10  —  10 
Other 3  —  3  11  —  11 
19  (9) 10  87  46  133 
Regulatory required programs 146  9  155  276  114  390 
Total increase $ 165  $ —  $ 165  $ 363  $ 160  $ 523 

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.
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BGE

  At September 30,
Number of Electric Customers 2025 2024
Residential 1,220,937  1,215,873 
Small commercial & industrial 115,246  115,032 
Large commercial & industrial 13,432  13,206 
Public authorities & electric railroads 254  260 
Total 1,349,869  1,344,371 

At September 30,
Number of Natural Gas Customers 2025 2024
Residential 660,241  658,485 
Small commercial & industrial 37,731  37,752 
Large commercial & industrial 6,404  6,353 

Total 704,376  702,590 

Distribution Revenue increased for the three and nine months ended September 30, 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 remained relatively consistent for the three months ended September 30, 2025 and increased for the nine months ended September 30, 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 three and nine months ended September 30, 2025 as compared to the same period in 2024, primarily driven by increases 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 $148 million and $356 million for the three and nine months ended September 30, 2025, respectively, 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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The changes in Operating and maintenance expense consisted of the following:

Three Months Ended
September 30, 2025 Nine Months Ended
September 30, 2025
  (Decrease) Increase Increase (Decrease)
Labor, other benefits, contracting, and materials (8) 8 
Credit loss expense (7) (2)
BSC costs —  4 
Pension and non-pension postretirement benefits expense —  1 
Storm-related costs (9) (16)
Other (a)
(19) (6)
(43) (11)
Regulatory required programs (b)
1  23 

Total (decrease) increase $ (42) $ 12 

__________
(a) For the three and nine months ended, reflects the absence of capital write-offs included in 2024. For the nine months ended, 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. See Note 2 — Regulatory Matters for additional information regarding the Next Generation Energy Act.
(b) Reflects the cost recovery associated with EmPOWER Maryland. Please refer to 2024 10-K Note 3 — Regulatory Matters for additional information.
The changes in Depreciation and amortization expense consisted of the following:

Three Months Ended
September 30, 2025 Nine Months Ended
September 30, 2025
Increase (Decrease) Increase (Decrease)
Depreciation and amortization $ 4  $ 7 
Regulatory required programs (a)
5  16 
Regulatory asset amortization (16) (24)

Total decrease $ (7) $ (1)

__________
(a) Reflects the cost recovery associated with EmPOWER Maryland. Please refer to 2024 10-K Note 3 — Regulatory Matters for additional information.

Interest expense, net increased $7 million and $24 million for the three and nine months ended September 30, 2025, respectively, compared to the same period in 2024, primarily due to the issuance of debt in the second quarter of 2025.
Taxes other than income taxes increased $7 million and $19 million for the three and nine months ended September 30, 2025, respectively, compared to the same period in 2024, primarily due to increased property taxes.
Effective income tax rates were 21.9% and 8.2% for the three months ended September 30, 2025 and 2024, respectively, and 21.3% and 8.3% for the nine months ended September 30, 2025 and 2024. See Note 6 — 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 three and nine months ended September 30, 2025 compared to the same periods in 2024. See the Results of Operations for Pepco, DPL, and ACE for additional information.

Three Months Ended
September 30, Favorable (Unfavorable) Variance Nine Months Ended September 30, Favorable (Unfavorable) Variance
2025 2024 2025 2024
PHI $ 291  $ 278  $ 13  $ 628  $ 603  $ 25 
Pepco 156  140  16  337  323  14 
DPL
55  55  —  163  156  7 
ACE 82  83  (1) 138  133  5 
Other (a)
(2) —  (2) (10) (9) (1)

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

Three Months Ended September 30, 2025 Compared to Three Months Ended September 30, 2024. Net Income increased by $13 million primarily due to distribution rates and transmission rates at Pepco, partially offset by increases in interest and depreciation expense at Pepco.
Nine Months Ended September 30, 2025 Compared to Nine Months Ended September 30, 2024. Net Income increased by $25 million primarily due to distribution rates at Pepco, DPL Delaware electric DSIC rates and natural gas rates, transmission rates at Pepco and DPL, and favorable weather conditions at DPL, partially offset by an increase in interest and depreciation expense and the lower impacts of the Maryland multi-year plans reconciliations at Pepco.
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Pepco

Results of Operations — Pepco

Three Months Ended September 30, Favorable (Unfavorable) Variance Nine Months Ended September 30, Favorable (Unfavorable) Variance
2025 2024 2025 2024
Operating revenues $ 992  $ 861  $ 131  $ 2,626  $ 2,320  $ 306 

Operating expenses
Purchased power 367  294  (73) 942  808  (134)
Operating and maintenance 154  140  (14) 466  392  (74)
Depreciation and amortization 110  102  (8) 321  307  (14)
Taxes other than income taxes 122  114  (8) 344  317  (27)
Total operating expenses 753  650  (103) 2,073  1,824  (249)
Loss on sale of assets —  —  —  1  —  1 
Operating income 239  211  28  554  496  58 
Other income and (deductions)
Interest expense, net (53) (50) (3) (159) (142) (17)
Other, net 11  11  —  31  43  (12)
Total other income and (deductions) (42) (39) (3) (128) (99) (29)
Income before income taxes 197  172  25  426  397  29 
Income taxes 41  32  (9) 89  74  (15)
Net income $ 156  $ 140  $ 16  $ 337  $ 323  $ 14 

Three Months Ended September 30, 2025 Compared to Three Months Ended September 30, 2024. Net Income increased by $16 million primarily due to distribution and transmission rates, partially offset by increases in depreciation and interest expense.
Nine Months Ended September 30, 2025 Compared to Nine Months Ended September 30, 2024. Net Income increased by $14 million primarily due to distribution and transmission rates, partially offset by lower impacts of the Maryland multi-year plans reconciliations and increases in depreciation and interest expense.
The changes in Operating revenues consisted of the following:

Three Months Ended
September 30, 2025 Nine Months Ended
September 30, 2025
Increase (Decrease) Increase (Decrease)
Distribution $ 42  $ 124 
Transmission 1  12 
Other (2) (7)
41  129 
Regulatory required programs 90  177 
Total increase $ 131  $ 306 

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.
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At September 30,
Number of Electric Customers in Maryland 2025 2024
Residential 559,986  555,029 
Small commercial & industrial 30,485  30,606 
Large commercial & industrial 19,086  18,987 
Public authorities & electric railroads 177  179 
Total 609,734  604,801 

Distribution Revenue increased for the three and nine months ended September 30, 2025 compared to the same periods in 2024 primarily due to 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 three and nine months ended September 30, 2025, compared to the same periods in 2024, primarily due to increases in underlying costs and capital investments.
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.
S ee Note 4 — Segment Information of the Combined Notes to Consolidated Financial Statements for the presentation of Pepco's revenue disaggregation.
The increase of $73 million and $134 million for the three and nine months ended September 30, 2025, respectively, 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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The changes in Operating and maintenance expense consisted of the following:

Three Months Ended
September 30, 2025 Nine Months Ended
September 30, 2025
Increase (Decrease) Increase (Decrease)
Maryland multi-year plan reconciliations (a)
$ 3  $ 27 
Labor, other benefits, contracting, and materials 7 3 
Storm-related costs (1) 2 
Pension and non-pension postretirement benefits expense —  1 
Credit loss expense (2) 1 
BSC and PHISCO costs 1 (2)

Other (b)
(4) 12 
4  44 

Regulatory required programs (c)
10  30 
Total increase $ 14  $ 74 
________ _
(a) See Note 2 - Regulatory Matters for additional information on multi-year plan reconciliations.
(b) Primarily relates to a revenue deferral mechanism approved by the MDPSC in 2024.
(c) Reflects the cost recovery associated with EmPOWER Maryland. Please refer to 2024 10-K Note 3 — Regulatory Matters for additional information.

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

Three Months Ended
September 30, 2025 Nine Months Ended
September 30, 2025
Increase Increase (Decrease)
Depreciation and amortization (a)
$ 6  $ 18 
Regulatory asset amortization 2  4 
Regulatory required programs (b)
—  (8)
Total increase $ 8  $ 14 

__________
(a) Depreciation and amortization increased primarily due to ongoing capital expenditures.
(b) Reflects the cost recovery associated with EmPOWER Maryland. Please refer to 2024 10-K Note 3 — Regulatory Matters additional information.
Taxes other than income taxes increased $8 million and $27 million for the three and nine months ended September 30, 2025, respectively, compared to the same periods in 2024, primarily due to increases in utility taxes, which are offset in revenues, and property taxes.
Interest expense, net increased $3 million and $17 million for the three and nine months ended September 30, 2025, respectively, compared to the same periods in 2024, primarily due to an increase in interest rates and the issuance of debt in 2024 and 2025.
Other , net decreased $12 million for the nine months ended September 30, 2025, respectively, and stayed relatively consistent for the three months ended September 30, 2025, respectively, compared to the same periods in 2024, primarily due to lower AFUDC equity.
Effective income tax rates were 20.8% and 18.6% for the three months ended September 30, 2025 and 2024, respectively, and 20.9% and 18.6% for the nine months ended September 30, 2025 and 2024, respectively. See Note 6 — 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

Three Months Ended September 30, Favorable (Unfavorable) Variance Nine Months Ended September 30, Favorable (Unfavorable) Variance
2025 2024 2025 2024
Operating revenues $ 491  $ 462  $ 29  $ 1,460  $ 1,343  $ 117 
Operating expenses
Purchased power and fuel 219  203  (16) 637  573  (64)
Operating and maintenance 94  92  (2) 296  284  (12)
Depreciation and amortization 63  62  (1) 189  183  (6)
Taxes other than income taxes 21  20  (1) 63  59  (4)
Total operating expenses 397  377  (20) 1,185  1,099  (86)

Operating income 94  85  9  275  244  31 
Other income and (deductions)
Interest expense, net (26) (22) (4) (75) (69) (6)
Other, net 4  6  (2) 12  20  (8)
Total other income and (deductions) (22) (16) (6) (63) (49) (14)
Income before income taxes 72  69  3  212  195  17 
Income taxes 17  14  (3) 49  39  (10)
Net income $ 55  $ 55  $ —  $ 163  $ 156  $ 7 

Three Months Ended September 30, 2025 Compared to Three Months Ended September 30, 2024. Net income remained relatively consistent.
Nine Months Ended September 30, 2025 Compared to Nine Months Ended September 30, 2024. Net income increased $7 million primarily due to Delaware electric DSIC rates 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:

Three Months Ended
September 30, 2025 Nine Months Ended
September 30, 2025
Increase (Decrease) Increase (Decrease)
Electric Gas Total Electric Gas Total
Weather $ 1  $ —  $ 1  $ 4  $ 2  $ 6 
Volume (5) 1  (4) (3) 3  — 
Distribution 6  3  9  14  7  21 
Transmission 2  —  2  10  —  10 
Other 1  —  1  2  —  2 
5  4  9  27  12  39 
Regulatory required programs 19  1  20  65  13  78 
Total increase $ 24  $ 5  $ 29  $ 92  $ 25  $ 117 

Revenue Decoupling. The demand for electricity is affected by weather and customer usage. However, Operating revenues from electric distribution in Maryland are not 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 intended to be impacted by abnormal weather or usage per customer, they are impacted by changes in the number of customers.
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
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DPL

demand. During the three months ended September 30, 2025 compared to the same period in 2024, Operating revenues related to weather remained relatively consistent. During the nine months ended September 30, 2025 compared to the same period in 2024, Operating revenues 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 three and nine months ended September 30, 2025, compared to same periods in 2024 and normal weather consisted of the following:

Three Months Ended September 30, % Change
Delaware Electric Service Territory 2025 2024 Normal 2025 vs. 2024 2025 vs. Normal
Heating Degree-Days 3  13  28  (76.9) % (89.3) %
Cooling Degree-Days 897  856  928  4.8  % (3.3) %

Nine Months Ended September 30, % Change
Delaware Electric Service Territory 2025 2024 Normal 2025 vs. 2024 2025 vs. Normal
Heating Degree-Days 2,774  2,620  2,896  5.9  % (4.2) %
Cooling Degree-Days 1,296  1,256  1,272  3.2  % 1.9  %

Three Months Ended September 30, % Change
Delaware Natural Gas Service Territory 2025 2024 Normal 2025 vs. 2024 2025 vs. Normal
Heating Degree-Days 3  13  34  (76.9) % (91.2) %

Nine Months Ended September 30, % Change
Delaware Natural Gas Service Territory 2025 2024 Normal 2025 vs. 2024 2025 vs. Normal
Heating Degree-Days 2,774  2,620  2,970  5.9  % (6.6) %

Volume, exclusive of the effects of weather, decreased for the three months ended September 30, 2025 compared to the same period in 2024, primarily due to a decrease in customer usage. During the nine months ended September 30, 2025, Volume remained relatively consistent compared to the same period in 2024.

Electric Retail Deliveries to Delaware Customers (in GWhs) Three Months Ended
September 30, % Change Weather - Normal
% Change (b)
Nine Months Ended
September 30, % Change Weather - Normal
% Change (b)

2025 2024 2025 2024
Residential 928  974  (4.7) % (6.1) % 2,533  2,529  0.2  % (2.1) %
Small commercial & industrial 389  402  (3.2) % (3.5) % 1,112  1,094  1.6  % 1.3  %
Large commercial & industrial 873  811  7.6  % 7.3  % 2,329  2,285  1.9  % 1.6  %
Public authorities & electric railroads 8  8  —  % (0.1) % 23  22  4.5  % 4.4  %
Total electric retail deliveries (a)
2,198  2,195  0.1  % (0.7) % 5,997  5,930  1.1  % —  %

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DPL

At September 30,
Number of Total Electric Customers (Maryland and Delaware) 2025 2024
Residential 494,232  489,634 
Small commercial & industrial 65,322  64,626 
Large commercial & industrial 1,257  1,267 
Public authorities & electric railroads 632  598 
Total 561,443  556,125 

__________
(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) Three Months Ended
September 30, % Change Weather - Normal
% Change (b)
Nine Months Ended
September 30, % Change Weather - Normal
% Change (b)

2025 2024 2025 2024
Residential 409  397  3.0  % 5.7  % 5,802  5,162  12.4  % 6.9  %
Small commercial & industrial 375  343  9.3  % 10.9  % 2,881  2,590  11.2  % 5.7  %
Large commercial & industrial 404  408  (1.0) % (1.1) % 1,237  1,239  (0.2) % (0.1) %
Transportation 1,239  1,190  4.1  % 4.3  % 4,626  4,491  3.0  % 1.4  %
Total natural gas deliveries (a)
2,427  2,338  3.8  % 4.7  % 14,546  13,482  7.9  % 4.3  %

At September 30,
Number of Delaware Natural Gas Customers 2025 2024
Residential 131,494  130,885 
Small commercial & industrial 10,134  10,110 
Large commercial & industrial 14  14 
Transportation 160  161 
Total 141,802  141,170 

__________
(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 three and nine months ended September 30, 2025 compared to the same periods 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. During the three and nine months ended September 30, 2025 compared to the same periods in 2024, transmission revenue increased due to increases in underlying costs and capital investments.
Other Revenue includes rental revenue, service connection fees, and mutual assistance revenues.
Regulatory Required Programs represent revenues collected under approved riders to recover costs incurred for regulatory programs such as energy efficiency programs, 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
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DPL

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 $16 million and $64 million for the three and nine months ended September 30, 2025, respectively, 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:

Three Months Ended
September 30, 2025 Nine Months Ended
September 30, 2025
(Decrease) Increase Increase (Decrease)
Credit loss expense $ (2) $ 3 

Storm-related costs (3) (5)
Labor, other benefits, contracting, and materials 3  (4)
Other
1  2 
(1) (4)
Regulatory required programs (a)
3  16 
Total increase $ 2  $ 12 

__________
(a) Reflects the cost recovery associated with EmPOWER Maryland. Please refer to 2024 10-K Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.
The changes in Depreciation and amortization expense consisted of the following:

Three Months Ended
September 30, 2025 Nine Months Ended
September 30, 2025
Increase Increase (Decrease)
Depreciation and amortization (a)
$ 1  $ 7 
Regulatory asset amortization —  — 
Regulatory required programs (b)
—  (1)
Total increase $ 1  $ 6 

__________
(a) Depreciation and amortization increased primarily due to ongoing capital expenditures.
(b) Reflects the cost recovery associated with EmPOWER Maryland. Please refer to 2024 10-K Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information

Taxes other than income taxes increased by $1 million and $4 million for the three and nine months ended September 30, 2025, respectively, compared to the same period in 2024 primarily due to an increase in property taxes.
Interest Expense, net increased by $4 million and $6 million for the three and nine months ended September 30, 2025, respectively, compared to the same period in 2024 primarily due to an increase in interest rates and the issuance of debt in 2024 and 2025 .
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DPL

Other, net decreased by $2 million and $8 million for the three and nine months ended September 30, 2025, respectively, compared to the same period in 2024 primarily due to a decrease in interest income and lower AFUDC equity.
Effective income tax rates were 23.6% and 20.3% for the three months ended September 30, 2025 and 2024, respectively, and 23.1% and 20.0% for the nine months ended September 30, 2025 and 2024, respectively. See Note 6 — 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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ACE

Results of Operations — ACE

Three Months Ended September 30, Favorable (Unfavorable) Variance Nine Months Ended September 30, Favorable (Unfavorable) Variance
2025 2024 2025 2024
Operating revenues $ 570  $ 540  $ 30  $ 1,328  $ 1,280  $ 48 

Operating expenses
Purchased power 286  245  (41) 616  557  (59)
Operating and maintenance 92  96  4  277  274  (3)
Depreciation and amortization 61  67  6  188  214  26 
Taxes other than income taxes 2  2  —  7  7  — 
Total operating expenses 441  410  (31) 1,088  1,052  (36)

Operating income 129  130  (1) 240  228  12 
Other income and (deductions)
Interest expense, net (20) (21) 1  (62) (59) (3)
Other, net 2  4  (2) 8  12  (4)
Total other income and (deductions) (18) (17) (1) (54) (47) (7)
Income before income taxes 111  113  (2) 186  181  5 
Income taxes 29  30  1  48  48  — 
Net income $ 82  $ 83  $ (1) $ 138  $ 133  $ 5 

Three Months Ended September 30, 2025 Compared to Three Months Ended September 30, 2024 . Net income remained relatively consistent.
Nine Months Ended September 30, 2025 Compared to Nine Months Ended September 30, 2024. Net Income increased by $5 million primarily due to an increase in customer growth and a decrease in various operating expenses, offset by an increase in interest and depreciation expense.
The changes in Operating revenues consisted of the following:

Three Months Ended
September 30, 2025 Nine Months Ended
September 30, 2025
(Decrease) Increase Increase (Decrease)
Distribution $ —  $ 4 
Transmission (2) (2)
Other —  2 
(2) 4 

Regulatory required programs 32  44 
Total increase $ 30  $ 48 

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.
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ACE

At September 30,
Number of Electric Customers 2025 2024
Residential 509,739  507,060 
Small commercial & industrial 62,923  62,761 
Large commercial & industrial 2,730  2,848 
Public authorities & electric railroads 745  707 
Total 576,137  573,376 

Distribution Revenue remained relatively consistent for the three months ended September 30, 2025 compared to the same period in 2024, and increased for the nine months ended September 30, 2025 compared to the same period in 2024, due to an increase in customer growth.
Transmission Revenues 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 three and nine months ended September 30, 2025 compared to the same periods 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 $41 million and $59 million for the three and nine months ended September 30, 2025, respectively, compared to the same periods in 2024 in Purchased power expense is fully offset in Operating revenues as part of regulatory required programs.
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ACE

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

Three Months Ended
September 30, 2025 Nine Months Ended
September 30, 2025
Increase (Decrease) Increase (Decrease)
Labor, other benefits, contracting, and materials $ 6  $ 3 
Storm-related costs (1) — 
Credit Loss Expense (1) — 

BSC and PHISCO costs (2) (5)
Other (2) (4)
—  (6)

Regulatory required programs (4) 9 
Total (decrease) increase $ (4) $ 3 

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

Three Months Ended
September 30, 2025 Nine Months Ended
September 30, 2025
Increase (Decrease) Increase (Decrease)
Depreciation and amortization (a)
$ 3  $ 9 
Regulatory asset amortization (3) (10)
Regulatory required programs (6) (25)
Total decrease $ (6) $ (26)

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

Effective income tax rates were 26.1% and 26.5% for the three months ended September 30, 2025 and 2024, respectively and 25.8% and 26.5% for the nine months ended September 30, 2025 and 2024, respectively. See Note 6 — 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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Liquidity and Capital Resources (All Registrants)
All results included throughout the liquidity and capital resources section are presented on a GAAP basis.
The Registrants’ operating and capital expenditures requirements are provided by internally generated cash flows from operations, as well as funds from external sources in the capital markets and through bank borrowings. The Registrants’ businesses are capital intensive and require considerable capital resources. Each of the Registrants annually evaluates its financing plan, dividend practices, and credit line sizing, focusing on maintaining its investment grade ratings while meeting its cash needs to fund capital requirements, including construction expenditures, retire debt, pay dividends, and fund pension and OPEB obligations. The Registrants spend a significant amount of cash on capital improvements and construction projects that have a long-term return on investment. Additionally, the Utility Registrants operate in rate-regulated environments in which the amount of new investment recovery may be delayed or limited and where such recovery takes place over an extended period of time. Each Registrant’s access to external financing on reasonable terms depends on its credit ratings and current overall capital market business conditions, including that of the utility industry in general. If these conditions deteriorate to the extent that the Registrants no longer have access to the capital markets at reasonable terms, the Registrants have access to credit facilities with aggregate bank commitments of $4.0 billion. 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 9 — 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 that began in June 2022, and all of its costs of doing so will be 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 asset.
See Note 3 — Regulatory Matters of the 2024 Form 10-K and Notes 2 — Regulatory Matters and 11 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for additional information on regulatory and legal proceedings and proposed legislation.
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The following table provides a summary of the change in cash flows from operating activities for the nine months ended September 30, 2025 and 2024 by Registrant:

Increase in cash flows from operating activities Exelon ComEd PECO BGE   PHI Pepco DPL ACE
Net income (loss) $ 361  $ 80  $ 296  $ 45  $ 25  $ 14  $ 7  $ 5 
Adjustments to reconcile net income to cash:
Non-cash operating activities 887  553  —  135  99  99  31  (34)

Collateral (paid) received, net (46) (52) 6  2  —  3  (2) — 
Income taxes 37  175  68  70  42  18  24  5 
Pension and non-pension postretirement benefit contributions (173) (181) (8) (6) 32  —  —  4 
Regulatory assets and liabilities, net (584) (550) (43) (45) 70  15  9  48 
Changes in working capital and other assets and liabilities 385  (1) 39  41  113  (13) 27  122 
Increase in cash flows from operating activities $ 867  $ 24  $ 358  $ 242  $ 381  $ 136  $ 96  $ 150 

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 nine months ended September 30, 2025 and 2024 were as follows:
• See Note 14 — Supplemental Financial Information of the Combined Notes to Consolidated Financial Statements and the Registrants’ Consolidated Statements of Cash Flows for additional information on non-cash operating activities .
• Changes in collateral depended upon whether the Registrant was in a net mark-to-market liability or asset position, and collateral may have been required to be posted with or collected from its counterparties. In addition, the collateral posting and collection requirements differed depending on whether the transactions were on an exchange or in the over-the-counter markets. Changes in collateral for the 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 comparing the nine months ended September 30, 2025 to the nine months ended September 30, 2024. See Note 8 — Derivative Financial Instruments for additional information.
• See Note 6 — 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 relates to Exelon's increased contributions to the Qualified Plans during the nine months ended September 30, 2025. See Note 14 — Retirement Benefits of the 2024 Form 10-K for additional information.
• 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. Included within the changes is energy efficiency spend for ComEd of $311 million and $266 million for the nine months ended September 30, 2025 and 2024, respectively. Also included within the changes is energy efficiency and demand response programs spend for BGE, Pepco, DPL and ACE of $64 million, $27 million, $11 million, and $37 million for the nine months ended September 30, 2025 and $94 million, $34 million, $14 million, and $24 million for the nine months ended September 30, 2024, respectively. PECO had no energy efficiency and demand response programs spend recorded to the regulatory asset for the nine months ended September 30, 2025 and 2024. See Note 2 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.
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• Changes in working capital and other assets and liabilities for the Utility Registrants and Exelon Corporate totaled $215 million and $385 million, respectively. 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 are owed money from ComEd as a result of the established pricing for CMCs. For the nine months ended September 30, 2025, the established pricing has resulted in both a receivable from, and payable to, nuclear-powered generating facilities. The change in receivable from nuclear-powered generating facilities, and the change in payable to nuclear-powered generating facilities, are reflected as a change in accounts receivable and a change in accounts payable and accrued expenses, respectively, within the cash flows from operations.
Cash Flows from Investing Activities
The following table provides a summary of the change in cash flows from investing activities for the nine months ended September 30, 2025 and 2024 by Registrant:

(Decrease) increase in cash flows from investing activities Exelon ComEd PECO BGE   PHI Pepco DPL ACE
Capital expenditures $ (934) $ (351) $ (209) $ (178) $ (209) $ (18) $ 2  $ (27)

Proceeds from sales of assets (36) —  —  —  2  2  —  — 
Changes in intercompany money pool —  —  (133) —  —  —  —  — 

Other investing activities (16) (3) (4) (3) —  —  —  — 
(Decrease) increase in cash flows from investing activities $ (986) $ (354) $ (346) $ (181) $ (207) $ (16) $ 2  $ (27)

Significant investing cash flow impacts for the Registrants for nine months ended September 30, 2025 and 2024 were as follows:
• Changes in capital expenditures are primarily due to the timing of cash expenditures for capital projects. See the "Credit Matters and Cash Requirements" section below for additional information on projected capital expenditure spending for the Utility Registrants.
• Changes in intercompany money pool are driven by short-term borrowing needs. Refer to more information regarding the intercompany money pool below.
Cash Flows from Financing Activities
The following table provides a summary of the change in cash flows from financing activities for the nine months ended September 30, 2025 and 2024 by Registrant:

Increase (decrease) in cash flows from financing activities Exelon ComEd PECO BGE   PHI Pepco DPL ACE
Changes in short-term borrowings, net $ 713  $ 493  $ (27) $ 161  $ (188) $ (54) $ (48) $ (86)
Long-term debt, net 479  175  475  (150) (17) —  (17) — 
Changes in intercompany money pool —  —  —  —  (9) —  —  — 
Issuance of common stock 25  —  —  —  —  —  —  — 
Dividends paid on common stock (70) (28) (110) (18) —  19  13  (32)

Distributions to member —  —  —  —  1  —  —  — 
Contributions from parent/member —  (9) (17) 294  64  (68) (53) 13 

Other financing activities (1) 5  (3) 1  14  11  (2) — 
Increase (decrease) in cash flows from financing activities $ 1,146  $ 636  $ 318  $ 288  $ (135) $ (92) $ (107) $ (105)

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Significant financing cash flow impacts for the Registrants for the nine months ended September 30, 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. See Note 9 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information on short-term borrowings for the Registrants.
• Long-term debt, net , varies due to debt issuances and redemptions each year. See Note 9 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information on debt issuances. Refer to the "Debt" section below for additional information.
• Changes in intercompany money pool are driven by short-term borrowing needs. Refer below for more information regarding the intercompany money pool.
• Issuance of common stock relates to issuances of Exelon common stock during the first quarter of 2025. See Note 12 — Shareholders' Equity of the Combined Notes to Consolidated Financial Statements for additional information.
• Exelon’s ability to pay dividends on its common stock depends on the receipt of dividends paid by its operating subsidiaries. The payments of dividends to Exelon by its subsidiaries in turn depend on their results of operations and cash flows and other items affecting retained earnings. See Note 18 — Commitments and Contingencies of the 2024 Form 10-K for additional information on dividend restrictions. See below for quarterly dividends declared.
Debt
See Note 9 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information on the Registrants’ debt issuances.
During the nine months ended September 30, 2025, the following long-term debt was retired and/or redeemed.

Company (a)
Type Interest Rate Maturity Amount
Exelon Senior Notes 3.95  % June 15, 2025 $ 807 

(a) On October 15, 2025, PECO redeemed $350 million of its 3.15% First Mortgage Bonds at maturity.
Dividends
Quarterly dividends declared by the Exelon Board of Directors during the nine months ended September 30, 2025 and for the fourth quarter of 2025 were as follows:

Period Declaration Date Shareholder of Record Date Dividend Payable Date Cash per Share (a)

First Quarter 2025 February 12, 2025 February 24, 2025 March 14, 2025 $ 0.4000 
Second Quarter 2025 April 29, 2025 May 12, 2025 June 13, 2025 $ 0.4000 
Third Quarter 2025 July 29, 2025 August 11, 2025 September 15, 2025 $ 0.4000 
Fourth Quarter 2025 October 29, 2025 November 10, 2025 December 15, 2025 $ 0.4000 

__________
(a) Exelon's Board of Directors approved an updated dividend policy for 2025. The 2025 quarterly dividend will be $0.40 per share.
Credit Matters and Cash Requirements
The Registrants fund liquidity needs for capital investment, working capital, energy hedging, and other financial commitments through cash flows from continuing operations, public debt offerings, commercial paper markets, and large, diversified credit facilities. The credit facilities include $4.0 billion in aggregate total commitments of which $3.4 billion was available to support additional commercial paper as of September 30, 2025, and of which
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no financial institution has more than 6.2% of the aggregate commitments for the Registrants. The Registrants had access to the commercial paper markets and had availability under their revolving credit facilities during the nine months ended September 30, 2025 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 9 — 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 have continued to 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 of the 2024 Form 10-K for additional information regarding the effects of uncertainty in the capital and credit markets.
The Registrants believe their cash flows from operating activities, access to credit markets, and their credit facilities provide sufficient liquidity to support the estimated future cash requirements.
At-the-Market Programs
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.
During the first quarter of 2025, Exelon issued approximately 4.0 million shares of Common stock at an average net price of $42.98 per share. The net proceeds from the issuance were $173 million, which were used for general corporate purposes.
In addition, in the first quarter of 2025, Exelon entered into forward sale agreements for 5.7 million shares of Common stock, at a weighted-average net forward price of $43.24 per share. The forward sale agreements require Exelon to, at its election prior to December 15, 2025, 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.
In the second quarter of 2025, Exelon entered into forward sale agreements for 6.2 million shares, and 3.6 million shares of Common stock, at a weighted-average net forward price of $43.51, and $43.17 per share, respectively. The forward sale agreements require Exelon to, at its election prior to December 15, 2025 and November 16, 2026, respectively, 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.
In the third quarter of 2025, Exelon entered into forward sale agreements for 11.5 million shares at a weighted-average net forward price of $43.73 per share. The forward sale agreements require Exelon to, at its election prior to December 15, 2026 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 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
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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 nine months ended September 30, 2025, approximately 26.7 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, $1.6 billion of Common stock remained available for sale pursuant to the ATM program as of September 30, 2025.
Incremental Collateral Requirements
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 September 30, 2025 and available credit facility capacity prior to any incremental collateral at September 30, 2025:

PJM Credit Policy Collateral Other Incremental Collateral Required (a)
Available Credit Facility Capacity Prior to Any Incremental Collateral
ComEd $ 26  $ —  $ 985 
PECO —  40  595 
BGE —  23  575 

Pepco 1  —  235 
DPL —  13  267 
ACE —  —  230 

__________
(a) Represents incremental collateral related to natural gas procurement contracts.
Capital Expenditure Spending
As of September 30, 2025, the most recent estimates of capital expenditures for plant additions and improvements for 2025 are as follows:        

(In millions) Transmission Distribution Gas Total (a)

Exelon N/A N/A N/A $ 8,975 
ComEd 950  2,250  N/A 3,200 
PECO 200  1,375  350  1,950 
BGE 650  650  525  1,850 
PHI 575  1,475  100  2,150 
Pepco 250  750  N/A 1,000 
DPL 150  325  75  525 
ACE 150  275  N/A 425 

__________
(a) Numbers rounded to the nearest $25M and may not sum due to rounding.
Projected capital expenditures and other investments are subject to periodic review and revision to reflect changes in economic conditions and other factors.
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 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.
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Exelon’s estimated annual qualified pension contributions will be $275 million in 2025. Unlike the qualified pension plans, Exelon’s non-qualified pension plans are not funded, given 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).
To the extent interest rates decline significantly or the pension and OPEB plans earn less than the expected asset returns, annual pension contribution requirements in future years could increase. Conversely, to the extent interest rates increase significantly or the pension and OPEB plans earn greater than the expected asset returns, annual pension and OPEB contribution requirements in future years could decrease. Additionally, expected contributions could change if Exelon changes its pension or OPEB funding strategy.
See Note 14 — Retirement Benefits of the Combined Notes to Consolidated Financial Statements of the 2024 Form 10-K for additional information on pension and OPEB contributions.
Credit Facilities
Exelon Corporate, ComEd, and BGE meet their short-term liquidity requirements primarily through the issuance of commercial paper. PECO meets its short-term liquidity requirements primarily through the issuance of commercial paper and borrowings from the Exelon intercompany money pool. Pepco, DPL, and ACE meet their short-term liquidity requirements primarily through the issuance of commercial paper and borrowings from the PHI intercompany money pool. PHI Corporate meets its short-term liquidity requirements primarily through the issuance of short-term notes and the Exelon intercompany money pool. The Registrants may use their respective credit facilities for general corporate purposes, including meeting short-term funding requirements and the issuance of letters of credit.
See Note 9 — 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.
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 collateral. See Note 8 — 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 nine months ended September 30, 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 September 30, 2025, are presented in the following table:

During the Nine Months Ended September 30, 2025 At September 30, 2025
Exelon Intercompany Money Pool Maximum
Contributed Maximum
Borrowed Contributed
(Borrowed)
Exelon Corporate $ 578  $ —  $ 64 
PECO 336  (253) 222 
BSC —  (413) (284)
PHI Corporate —  (85) (64)
PCI 62  —  62 

During the Nine Months Ended September 30, 2025 At September 30, 2025
PHI Intercompany Money Pool Maximum
Contributed Maximum
Borrowed
Contributed
(Borrowed)
Pepco $ 20  $ (35) $ — 
DPL 48  (1) — 
ACE —  (46) — 

Shelf Registration Statements
On February 21, 2024, PECO and BGE, as co-registrants, 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. On February 13, 2025, as most recently amended on March 27, 2025, Exelon Corporation and ComEd, as co-registrants filed a shelf registration statement with the SEC ("Exelon and ComEd Shelf Registration") for authorization of up to $12,575 million in additional security registration, to be used to issue Exelon Corporate debt securities and equity securities, as well as ComEd debt securities. The Exelon and ComEd Shelf Registration was declared effective by the SEC on April 8, 2025, and is effective through April 8, 2028. The ability of Exelon Corporation, ComEd, PECO and BGE to sell securities off their corresponding registration Statements, or to access the private placement markets, will depend on a number of factors at the time of the proposed sale, including other required regulatory approvals, as applicable, the current financial condition of the Registrant, its securities ratings and market conditions.
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 September 30, 2025
Short-term Financing Authority Remaining Long-term Financing Authority
Commission Expiration Date Amount Commission Expiration Date Amount
ComEd (a)(b)
FERC December 31, 2025 $ 2,500  ICC January 1, 2027 & May 1, 2027 $ 1,593 
PECO (c)
FERC December 31, 2025 1,500  PAPUC December 31, 2027 1,850 
BGE (d)
FERC December 31, 2025 700  MDPSC N/A 1,850 
Pepco (e)(f)(g)
FERC December 31, 2025 500  MDPSC / DCPSC December 31, 2025 100 
DPL (e)(h)(i)
FERC December 31, 2025 500  MDPSC / DEPSC December 31, 2025 172 
ACE (j)
NJBPU December 31, 2025 350  NJBPU December 31, 2026 775 

__________

(a) On September 8, 2025, ComEd filed an application with the FERC to request a new short-term financing authority for $2.5 billion through December 31, 2027. ComEd expects approval of their application by December 31, 2025.
(b) On September 19, 2025, ComEd filed an application for $2.8 billion in new money long-term debt financing authority from the ICC and expects approval of their application by December 31, 2025.
(c) On September 8, 2025, PECO filed an application with the FERC to request a new short-term financing authority for $1.5 billion through December 31, 2027. PECO expects approval of their application by December 31, 2025.
(d) On September 8, 2025, BGE filed an application with the FERC to request a new short term financing authority for $900 million through December 31, 2027. BGE expects approval of their application by December 31, 2025.
(e) 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.
(f) On July 17, 2025, Pepco filed an application with the MDPSC and DCPSC to request a new long-term financing authority for $1.1 billion through December 31, 2028. On September 3, 2025, Pepco received approval of their application from the MDSPC. Pepco expects approval of their application from the DCPSC by December 31, 2025.
(g) On September 8, 2025, Pepco filed an application with the FERC to request a new short-term financing authority for $700 million through December 31, 2027. Pepco expects approval of their application by December 31, 2025.
(h) 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.
(i) On September 8, 2025, DPL filed an application with the FERC to request a new short-term financing authority for $700 million through December 31, 2027. DPL expects approval of their application by December 31, 2025.
(j) On June 6, 2025, ACE filed an application with the NJBPU to extend their short-term financing authority through January 1, 2028. ACE expects approval of their application by December 31, 2025.

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ITEM 3.    QUANTITATIVE AND QUALITATIVE DISCLOSURE 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 8 — 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 7 — Retirement Benefits of the 2024 Form 10-K for additional information.
• Interest rate risk associated with changes in interest rates for the Registrants’ outstanding long-term debt. This risk is significantly reduced as substantially all of the Registrants’ outstanding debt has fixed interest rates. There is inherent interest rate risk related to refinancing maturing debt by issuing new long-term debt. The Registrants use a combination of fixed-rate and variable-rate debt to manage interest rate exposure. See Note 9 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information. In addition, Exelon 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 8 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information.
The 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 Executive Committee, the Risk Management Committees of each Utility Registrant, and the Audit and Risk Committee of Exelon’s Board of Directors.
Commodity Price Risk
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. The hedging programs for natural gas procurement have no direct impact on their financial statements.
For additional information on these contracts, see Note 8 — Derivative Financial Instruments and Note 10 — Fair Value of Financial Assets and Liabilities of the Combined Notes to Consolidated Financial Statements.
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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 net liabilities. Second, the table shows the maturity, by year, of Exelon's and ComEd's commodity contract net liabilities giving an indication of when these mark-to-market amounts will settle and either generate or require cash. See Note 10 — Fair Value of Financial Assets and Liabilities of the Combined Notes to Consolidated Financial Statements for additional information regarding fair value measurements and the fair value hierarchy.

Maturities Within Total Fair
Value
Commodity derivative contracts (a) :
2025 2026 2027 2028 2029 2030 and Beyond
Prices based on model or other valuation methods (Level 3) $ (10) $ (20) $ (20) $ (20) $ (19) $ (39) $ (128)
_________
(a) Represents ComEd's net liabilities associated with the floating-to-fixed energy swap contracts with unaffiliated suppliers.

ITEM 4.    CONTROLS AND PROCEDURES
During the third quarter of 2025, each of the Registrants' management, including its principal executive officer and principal financial officer, evaluated its disclosure controls and procedures related to the recording, processing, summarizing, and reporting of information in its periodic reports that it files with the SEC. These disclosure controls and procedures have been designed by the Registrants to ensure that (a) material information relating to that Registrant, including its consolidated subsidiaries, is accumulated and made known to that Registrant's management, including its principal executive officer and principal financial officer, by other employees of that Registrant and its subsidiaries as appropriate to allow timely decisions regarding required disclosure, and (b) this information is recorded, processed, summarized, evaluated, and reported, as applicable, within the time periods specified in the SEC’s rules and forms. Due to the inherent limitations of control systems, not all misstatements may be detected. These inherent limitations include the realities that judgments in decision-making can be faulty and that breakdowns can occur because of simple error or mistake. Additionally, controls could be circumvented by the individual acts of some persons or by collusion of two or more people.
Accordingly, as of September 30, 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 to accomplish its objectives. The Registrants continually strive to improve their disclosure controls and procedures to enhance the quality of its financial reporting and to maintain dynamic systems that change as conditions warrant. There were no changes in internal control over financial reporting during the third quarter of 2025 that materially affected, or are reasonably likely to materially affect, any of the Registrants' internal control over financial reporting.

PART II — OTHER INFORMATION

ITEM 1.    LEGAL PROCEEDINGS
The Registrants are parties to various lawsuits and regulatory proceedings in the ordinary course of their respective businesses. For information regarding material lawsuits and proceedings, see (a) ITEM 3. LEGAL PROCEEDINGS of the 2024 Form 10-K, (b) Notes 3 — Regulatory Matters and 18 — Commitments and Contingencies of the 2024 Form 10-K, and (c) Notes 2 — Regulatory Matters and 11 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements in PART I, ITEM 1. FINANCIAL STATEMENTS of this Report. Such descriptions are incorporated herein by these references.

ITEM 1A.    RISK FACTORS
Risks Related to All Registrants
At September 30, 2025, the Registrants' risk factors were consistent with the risk factors described in the Registrants' combined 2024 Form 10-K in ITEM 1A. RISK FACTORS.

ITEM 5.    OTHER INFORMATION
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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 September 30, 2025.

ITEM 6.     EXHIBITS
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 applicable Registrant agrees to furnish a copy of any such instrument to the Commission upon request.
(4) Instruments Defining the Rights of Securities Holders, Including Indentures
PECO Energy Company
Exhibit No. Description Location
4-1
One Hundred and Twenty-Fifth Supplemental Indenture dated as of August 15, 2025 from PECO to U.S. Bank National Association, as trustee File No. 000-16844, Form 8-K dated September 10, 2025, Exhibit 4.1

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Certifications Pursuant to Rule 13a-14(a) and 15d-14(a) of the Securities and Exchange Act of 1934 as to the Quarterly Report on Form 10-Q for the quarterly period ended September 30, 2025 filed by the following officers for the following companies:

Exelon Corporation
Exhibit No. Description
31-1
Filed by Calvin G. Butler, Jr. for Exelon Corporation

31-2
Filed by Jeanne M. Jones for Exelon Corporation

Commonwealth Edison Company
Exhibit No. Description
31-3
Filed by Gil C. Quiniones for Commonwealth Edison Company

31-4
Filed by Joshua S. Levin for Commonwealth Edison Company

PECO Energy Company
Exhibit No. Description
31-5
Filed by David M. Vahos for PECO Energy Company

31-6
Filed by Marissa E. Humphrey for PECO Energy Company

Baltimore Gas and Electric Company
Exhibit No. Description
31-7
Filed by Tamla A. Olivier for Baltimore Gas and Electric Company

31-8
Filed by Michael J. Cloyd for Baltimore Gas and Electric Company

Pepco Holdings LLC
Exhibit No. Description
31-9
Filed by J. Tyler Anthony for Pepco Holdings LLC

31-10
Filed by Elizabeth Morgan Downs O'Donnell for Pepco Holdings LLC

Potomac Electric Power Company
Exhibit No. Description
31-11
Filed by J. Tyler Anthony for Potomac Electric Power Company

31-12
Filed by Elizabeth Morgan Downs O'Donnell for Potomac Electric Power Company

Delmarva Power & Light Company
Exhibit No. Description
31-13
Filed by J. Tyler Anthony for Delmarva Power & Light Company

31-14
Filed by Elizabeth Morgan Downs O'Donnell for Delmarva Power & Light Company

Atlantic City Electric Company
Exhibit No. Description
31-15
Filed by J. Tyler Anthony for Atlantic City Electric Company

31-16
Filed by Elizabeth Morgan Downs O'Donnell for Atlantic City Electric Company

Certifications Pursuant to Section 1350 of Chapter 63 of Title 18 United States Code (Sarbanes-Oxley Act of 2002) as to the Quarterly Report on Form 10-Q for the quarterly period ended September 30, 2025 filed by the following officers for the following companies:
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Exelon Corporation
Exhibit No. Description
32-1
Filed by Calvin G. Butler, Jr. for Exelon Corporation

32-2
Filed by Jeanne M. Jones for Exelon Corporation

Commonwealth Edison Company
Exhibit No. Description
32-3
Filed by Gil C. Quiniones for Commonwealth Edison Company

32-4
Filed by Joshua S. Levin for Commonwealth Edison Company

PECO Energy Company
Exhibit No. Description
32-5
Filed by David M. Vahos for PECO Energy Company

32-6
Filed by Marissa E. Humphrey for PECO Energy Company

Baltimore Gas and Electric Company
Exhibit No. Description
32-7
Filed by Tamla A. Olivier for Baltimore Gas and Electric Company

32-8
Filed by Michael J. Cloyd for Baltimore Gas and Electric Company

Pepco Holdings LLC
Exhibit No. Description
32-9
Filed by J. Tyler Anthony for Pepco Holdings LLC

32-10
Filed by Elizabeth Morgan Downs O'Donnell for Pepco Holdings LLC

Potomac Electric Power Company
Exhibit No. Description
32-11
Filed by J. Tyler Anthony for Potomac Electric Power Company

32-12
Filed by Elizabeth Morgan Downs O'Donnell for Potomac Electric Power Company

Delmarva Power & Light Company
Exhibit No. Description
32-13
Filed by J. Tyler Anthony for Delmarva Power & Light Company

32-14
Filed by Elizabeth Morgan Downs O'Donnell for Delmarva Power & Light Company

Atlantic City Electric Company
Exhibit No. Description
32-15
Filed by J. Tyler Anthony for Atlantic City Electric Company

32-16
Filed by Elizabeth Morgan Downs O'Donnell for Atlantic City Electric Company

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.SCH Inline XBRL Taxonomy Extension Schema Document

101.CAL Inline XBRL Taxonomy Extension Calculation Linkbase Document

101.DEF Inline XBRL Taxonomy Extension Definition Linkbase Document

101.LAB Inline XBRL Taxonomy Extension Labels Linkbase Document

101.PRE Inline XBRL Taxonomy Extension Presentation Linkbase Document

104 Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101)

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SIGNATURES

Pursuant to requirements 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.
EXELON CORPORATION
 

/s/    CALVIN G. BUTLER, JR. /s/    JEANNE M. JONES
Calvin G. Butler, Jr. Jeanne M. Jones
President, Chief Executive Officer
(Principal Executive Officer), and Director Executive Vice President and Chief Financial Officer
(Principal Financial Officer)

/s/ ROBERT A. KLECZYNSKI
Robert A. Kleczynski
Senior Vice President, Corporate Controller and Tax
(Principal Accounting Officer)

November 4, 2025
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Pursuant to requirements 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.
COMMONWEALTH EDISON COMPANY
 

/s/ GIL C. QUINIONES /s/ JOSHUA S. LEVIN
Gil C. Quiniones Joshua S. Levin
President, Chief Executive Officer
(Principal Executive Officer), and Director Senior Vice President, Chief Financial Officer, and Treasurer
(Principal Financial Officer)

/s/    ERIN V. WHITE
Erin V. White
Director, Accounting
(Principal Accounting Officer)

November 4, 2025
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Pursuant to requirements 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.
PECO ENERGY COMPANY
 

/s/   DAVID M. VAHOS /s/    MARISSA E. HUMPHREY
David M. Vahos Marissa E. Humphrey
President, Chief Executive Officer (Principal Executive Officer), and Director Senior Vice President, Chief Financial Officer, and Treasurer
(Principal Financial Officer)

/s/    MARIANA HUFFORD
Mariana Hufford
Director, Accounting
(Principal Accounting Officer)

November 4, 2025

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Pursuant to requirements 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.
BALTIMORE GAS AND ELECTRIC COMPANY
 

/s/    TAMLA A. OLIVIER /s/ MICHAEL J. CLOYD
Tamla A. Olivier Michael J. Cloyd
President, Chief Executive Officer
(Principal Executive Officer), and Director Senior Vice President, Chief Financial Officer, and Treasurer
(Principal Financial Officer)

 /s/ DAMON M. SCOLERI
Damon M. Scoleri
Director, Accounting
(Principal Accounting Officer)

November 4, 2025

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Pursuant to requirements 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.
PEPCO HOLDINGS LLC

/s/ J. TYLER ANTHONY /s/   ELIZABETH MORGAN DOWNS O'DONNELL
J. Tyler Anthony Elizabeth Morgan Downs O'Donnell
President, Chief Executive Officer
(Principal Executive Officer), and Director Senior Vice President, Chief Financial Officer, and Treasurer
(Principal Financial Officer)

/s/ JASON T. JONES
Jason T. Jones
Director, Accounting
(Principal Accounting Officer)

November 4, 2025

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Pursuant to requirements 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.
POTOMAC ELECTRIC POWER COMPANY

/s/ J. TYLER ANTHONY /s/    ELIZABETH MORGAN DOWNS O'DONNELL
J. Tyler Anthony Elizabeth Morgan Downs O'Donnell
President, Chief Executive Officer
(Principal Executive Officer), and Director Senior Vice President, Chief Financial Officer, and Treasurer
(Principal Financial Officer)

/s/ JASON T. JONES
Jason T. Jones
Director, Accounting
(Principal Accounting Officer)

November 4, 2025

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Pursuant to requirements 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.
DELMARVA POWER & LIGHT COMPANY

/s/ J. TYLER ANTHONY /s/    ELIZABETH MORGAN DOWNS O'DONNELL
J. Tyler Anthony Elizabeth Morgan Downs O'Donnell
President, Chief Executive Officer
(Principal Executive Officer), and Director Senior Vice President, Chief Financial Officer, and Treasurer
(Principal Financial Officer)

/s/ JASON T. JONES
Jason T. Jones
Director, Accounting
(Principal Accounting Officer)

November 4, 2025

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Pursuant to requirements 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.
ATLANTIC CITY ELECTRIC COMPANY

/s/ J. TYLER ANTHONY /s/    ELIZABETH MORGAN DOWNS O'DONNELL
J. Tyler Anthony Elizabeth Morgan Downs O'Donnell
President, Chief Executive Officer
(Principal Executive Officer), and Director Senior Vice President, Chief Financial Officer, and Treasurer
(Principal Financial Officer)

/s/ JASON T. JONES
Jason T. Jones
Director, Accounting
(Principal Accounting Officer)

November 4, 2025
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