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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 June 30, 2026
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 June 30, 2026 was:

Exelon Corporation Common Stock, without par value 1,032,253,967
Commonwealth Edison Company Common Stock, $12.50 par value 127,021,427
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
15

Consolidated Statements of Cash Flows
16

Consolidated Balance Sheets
17

Consolidated Statements of Changes in Shareholders' Equity
19

PECO Energy Company

Consolidated Statements of Operations and Comprehensive Income
20

Consolidated Statements of Cash Flows
21

Consolidated Balance Sheets
22

Consolidated Statements of Changes in Shareholder's Equity
24

Baltimore Gas and Electric Company

Statements of Operations and Comprehensive Income
25

Statements of Cash Flows
26

Balance Sheets
27

Statements of Changes in Shareholder's Equity
29

Pepco Holdings LLC

Consolidated Statements of Operations and Comprehensive Income
30

Consolidated Statements of Cash Flows
31

Consolidated Balance Sheets
32

Consolidated Statements of Changes in Member's Equity
34

1

Page No.
Potomac Electric Power Company

Statements of Operations and Comprehensive Income
35

Statements of Cash Flows
36

Balance Sheets
37

Statements of Changes in Shareholder's Equity
39

Delmarva Power & Light Company

Statements of Operations and Comprehensive Income
40

Statements of Cash Flows
41

Balance Sheets
42

Statements of Changes in Shareholder’s Equity
44

Atlantic City Electric Company

Consolidated Statements of Operations and Comprehensive Income
45

Consolidated Statements of Cash Flows
46

Consolidated Balance Sheets
47

Consolidated Statements of Changes in Shareholder’s Equity
49

Combined Notes to Consolidated Financial Statements

1. Significant Accounting Policies
50

2. Regulatory Matters
51

3. Revenue from Contracts with Customers
60

4. Segment Information
62

5. Accounts Receivable
72

6. Income Taxes
74

7. Retirement Benefits
79

8. Derivative Financial Instruments
81

9. Debt and Credit Agreements
84

10. Fair Value of Financial Assets and Liabilities
87

11. Commitments and Contingencies
95

12. Shareholders' Equity
101

13. Changes in Accumulated Other Comprehensive Income
103

14. Supplemental Financial Information
104

15. Related Party Transactions
108

2

Page No.

ITEM 2.
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
110

Exelon Corporation
110

Executive Overview
110

Financial Results of Operations
110

Significant 2026 Transactions and Developments
112

Other Key Business Drivers and Management Strategies
115

Critical Accounting Policies and Estimates
116

Results of Operations By Registrant
117

Commonwealth Edison Company
117

PECO Energy Company
120

Baltimore Gas and Electric Company
124

Pepco Holdings LLC
127

Potomac Electric Power Company
128

Delmarva Power & Light Company
131

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
149

ITEM 1.
LEGAL PROCEEDINGS
149

ITEM 1A.
RISK FACTORS
149

ITEM 5.
OTHER INFORMATION
149

ITEM 6.
EXHIBITS
149

SIGNATURES
153

Exelon Corporation
153

Commonwealth Edison Company
154

PECO Energy Company
155

Baltimore Gas and Electric Company
156

Pepco Holdings LLC
157

Potomac Electric Power Company
158

Delmarva Power & Light Company
159

Atlantic City Electric Company
160

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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
Pepco Energy Services or PES Pepco Energy Services, Inc. and its subsidiaries
PHI Corporate PHI in its corporate capacity as a holding company
PHISCO PHI Service Company
Former Related Entities
Constellation Constellation Energy Corporation and Constellation Energy Generation, LLC (formerly Exelon Generation Company, LLC, a subsidiary of Exelon as of December 31, 2021 prior to separation on February 1, 2022)

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GLOSSARY OF TERMS AND ABBREVIATIONS
Other Terms and Abbreviations
Note - of the 2025 Form 10-K
Reference to specific Combined Note to Consolidated Financial Statements within Exelon's 2025 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
Convertible Senior Notes Exelon's 3.25% Convertible Senior Notes due 2029
CMC Carbon Mitigation Credit
CRGA Clean and Reliable Grid Affordability Act
CODMs Chief Operating Decision Makers
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
FERC Federal Energy Regulatory Commission
GAAP Generally Accepted Accounting Principles in the United States
GWhs Gigawatt hours
ICC Illinois Commerce Commission
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
NJBPU New Jersey Board of Public Utilities
NOLC Tax Net Operating Loss Carryforward
NPNS Normal Purchase Normal Sale scope exception

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GLOSSARY OF TERMS AND ABBREVIATIONS
Other Terms and Abbreviations
NPS National Park Service
NRD Natural Resources Damages
OCI Other Comprehensive Income
OPEB Other Postretirement Employee Benefits
PAPUC Pennsylvania Public Utility Commission
PJM PJM Interconnection, LLC
PLR Private Letter Ruling
PP&E Property, Plant, and Equipment
PRPs Potentially Responsible Parties
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
S&P Standard & Poor’s Ratings Services
SEC United States Securities and Exchange Commission
SOFR Secured Overnight Financing Rate
SOS Standard Offer Service
TCJA Tax Cuts and Jobs Act
USAO United States Attorney's Office for the Northern District of Illinois

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;
• physical security and cybersecurity risks;
• extreme weather events, natural disasters, operational accidents such as wildfires or natural gas explosions, war, acts and threats of terrorism, public health crises, epidemics, pandemics, or other significant events;
• disruptions or cost increases in the supply chain, including shortages in labor, materials or parts, or significant increases in relevant tariffs;
• lack of sufficient power generation resources to meet actual or forecasted demand or disruptions at generation facilities owned by third parties;
• emerging technologies that could affect or transform the energy industry;
• instability in capital and credit markets;
• a downgrade of any Registrant’s credit ratings or other failure to satisfy the credit standards in the Registrants’ agreements or regulatory financial requirements;
• significant economic downturns or increases in customer rates;
• impacts of climate change and weather on energy usage and maintenance and capital costs; and
• impairment of long-lived assets, goodwill, and other assets.
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New factors emerge from time to time, and it is impossible for us to predict all of such factors, nor can we assess the impact of each such factor on the business or the extent to which any factor, or combination of factors, may cause actual results to differ materially from those contained in any forward-looking statements. For more information, see those factors discussed in the 2025 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
June 30, Six Months Ended
June 30,
(In millions, except per share data) 2026 2025 2026 2025
Operating revenues
Electric operating revenues $ 5,710   $ 5,365   $ 11,868   $ 11,182  
Natural gas operating revenues 327   337   1,443   1,361  
Revenues from alternative revenue programs ( 70 ) ( 275 ) ( 102 ) ( 402 )
Total operating revenues 5,967   5,427   13,209   12,141  
Operating expenses
Purchased power 2,132   1,811   4,515   3,995  
Purchased fuel 79   85   472   423  

Operating and maintenance 1,386   1,321   2,852   2,668  
Depreciation and amortization 968   902   1,920   1,805  
Taxes other than income taxes 423   383   866   788  
Total operating expenses 4,988   4,502   10,625   9,679  

Gain on sale of assets —   2   —   1  

Operating income 979   927   2,584   2,463  
Other income and (deductions)
Interest expense, net ( 568 ) ( 524 ) ( 1,116 ) ( 1,028 )
Interest expense to affiliates ( 6 ) ( 7 ) ( 12 ) ( 12 )
Other, net 90   65   159   117  
Total other income and (deductions) ( 484 ) ( 466 ) ( 969 ) ( 923 )
Income before income taxes 495   461   1,615   1,540  
Income taxes 99   70   300   240  

Net income attributable to common shareholders $ 396   $ 391   $ 1,315   $ 1,300  

Comprehensive income, net of income taxes
Net income $ 396   $ 391   $ 1,315   $ 1,300  
Other comprehensive income, net of income taxes
Pension and non-pension postretirement benefit plans:

Actuarial losses reclassified to periodic benefit cost 7   5   14   11  
Pension and non-pension postretirement benefit plans valuation adjustments ( 1 ) 1   3   5  
Unrealized (loss) on cash flow hedges —   ( 6 ) ( 5 ) ( 14 )

Other comprehensive income 6   —   12   2  

Comprehensive income attributable to common shareholders $ 402   $ 391   $ 1,327   $ 1,302  

Average shares of common stock outstanding:
Basic 1,025   1,010   1,025   1,009  
Assumed exercise and/or distributions of stock-based awards (a)
3   2   2   2  
Diluted 1,028   1,012   1,027   1,011  

Earnings per average common share
Basic $ 0.39   $ 0.39   $ 1.28   $ 1.29  
Diluted $ 0.39   $ 0.39   $ 1.28   $ 1.29  

__________
(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)
Six Months Ended
June 30,
(In millions) 2026 2025
Cash flows from operating activities
Net income $ 1,315   $ 1,300  
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation, amortization, and accretion 1,921   1,806  

Deferred income taxes and amortization of investment tax credits 432   165  
Net fair value changes related to derivatives —   3  

Other non-cash operating activities 464   734  
Changes in assets and liabilities:
Accounts receivable 787   ( 460 )
Inventories ( 29 ) ( 20 )
Accounts payable and accrued expenses ( 210 ) ( 38 )

Collateral received, net 72   14  
Income taxes ( 140 ) ( 3 )
Regulatory assets and liabilities, net ( 874 ) ( 294 )
Pension and non-pension postretirement benefit contributions ( 356 ) ( 302 )
Other assets and liabilities 287   ( 194 )
Net cash flows provided by operating activities 3,669   2,711  
Cash flows from investing activities
Capital expenditures ( 4,558 ) ( 3,959 )

Proceeds from sales of assets —   2  

Other investing activities ( 2 ) ( 5 )
Net cash flows used in investing activities ( 4,560 ) ( 3,962 )
Cash flows from financing activities
Changes in short-term borrowings 131   ( 750 )
Proceeds from short-term borrowings with maturities greater than 90 days 500   —  

Issuance of long-term debt 3,600   3,800  
Retirement of long-term debt ( 1,600 ) ( 807 )

Issuance of common stock 382   173  

Dividends paid on common stock ( 860 ) ( 808 )
Proceeds from employee stock plans 24   11  

Other financing activities ( 57 ) ( 56 )
Net cash flows provided by financing activities 2,120   1,563  
Increase in cash, restricted cash, and cash equivalents 1,229   312  
Cash, restricted cash, and cash equivalents at beginning of period 1,201   939  
Cash, restricted cash, and cash equivalents at end of period $ 2,430   $ 1,251  

Supplemental cash flow information
Decrease in capital expenditures not paid ( 253 ) ( 100 )

See the Combined Notes to Consolidated Financial Statements
11

Table of Contents

Exelon Corporation and Subsidiary Companies
Consolidated Balance Sheets
(Unaudited)

(In millions) June 30, 2026 December 31, 2025
ASSETS
Current assets
Cash and cash equivalents $ 1,813   $ 626  
Restricted cash and cash equivalents 608   525  

Accounts receivable
Customer accounts receivable 3,567 3,732
Customer allowance for credit losses ( 508 ) ( 435 )
Customer accounts receivable, net 3,059   3,297  
Other accounts receivable 1,294 1,879
Other allowance for credit losses ( 94 ) ( 94 )
Other accounts receivable, net 1,200   1,785  
Inventories, net
Fossil fuel 62   88  
Materials and supplies 832   780  
Regulatory assets 1,352   1,359  
Prepaid renewable energy credits 381   563  
Other 490   523  
Total current assets 9,797   9,546  
Property, plant, and equipment (net of accumulated depreciation and amortization of $ 21,230 and $ 20,080 as of June 30, 2026 and December 31, 2025, respectively)
87,123   84,318  
Deferred debits and other assets
Regulatory assets 9,412   9,214  
Goodwill 6,630   6,630  
Receivable related to Regulatory Agreement Units 5,280   4,755  
Investments 327   312  
Other 1,936   1,795  
Total deferred debits and other assets 23,585   22,706  
Total assets $ 120,505   $ 116,570  

See the Combined Notes to Consolidated Financial Statements
12

Table of Contents

Exelon Corporation and Subsidiary Companies
Consolidated Balance Sheets
(Unaudited)

(In millions) June 30, 2026 December 31, 2025
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities
Short-term borrowings $ 1,243   $ 612  
Long-term debt due within one year 727   1,665  
Accounts payable 3,475   3,721  
Accrued expenses 1,447   1,582  
Payables to affiliates 5   5  
Customer deposits 589   533  
Regulatory liabilities 573   1,128  
Mark-to-market derivative liabilities 23   30  
Unamortized energy contract liabilities 4   5  
Renewable energy credit obligations 332   473  
Other 590   577  
Total current liabilities 9,008   10,331  
Long-term debt 50,313   47,413  
Long-term debt to financing trusts 390   390  
Deferred credits and other liabilities
Deferred income taxes and unamortized investment tax credits 14,348   13,715  
Regulatory liabilities 11,727   11,016  
Pension obligations 1,429   1,749  
Non-pension postretirement benefit obligations 564   546  
Asset retirement obligations 322   321  
Mark-to-market derivative liabilities 105   106  
Unamortized energy contract liabilities 14   16  
Other 2,587   2,169  
Total deferred credits and other liabilities 31,096   29,638  
Total liabilities 90,807   87,772  
Commitments and contingencies

Shareholders’ equity
Common stock ( No par value, 2,000 shares authorized, 1,032 shares and 1,023 shares outstanding as of June 30, 2026 and December 31, 2025, respectively)
22,540   22,106  
Treasury stock, at cost ( 2 shares as of June 30, 2026 and December 31, 2025)
( 123 ) ( 123 )
Retained earnings 8,031   7,577  
Accumulated other comprehensive loss, net ( 750 ) ( 762 )
Total shareholders’ equity 29,698   28,798  

Total liabilities and shareholders’ equity $ 120,505   $ 116,570  

See the Combined Notes to Consolidated Financial Statements
13

Table of Contents

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

Six Months Ended June 30, 2026
(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, 2025 1,024,401 $ 22,106   $ ( 123 ) $ 7,577   $ ( 762 ) $ 28,798  
Net income —  —  —  919   —  919  
Long-term incentive plan activity 338   10   —  —  —  10  
Employee stock purchase plan activity 302   13   —  —  —  13  

Common stock dividends
($ 0.42 /common share)
—  —  —  ( 431 ) —  ( 431 )
Other comprehensive income, net of income taxes —  —  —  —  6   6  

Balance at March 31, 2026 1,025,041 $ 22,129   $ ( 123 ) $ 8,065   $ ( 756 ) $ 29,315  
Net income —  —  —  396   —  396  
Long-term incentive plan activity 51   14   —  —  —  14  
Employee stock purchase plan activity 317   15   —  —  —  15  
Issuance of Common Stock 8,682   382   —  —  —  382  

Common stock dividends
($ 0.42 /common share)
—  —  —  ( 430 ) —  ( 430 )
Other comprehensive income, net of income taxes —  —  —  —  6   6  

Balance at June 30, 2026 1,034,091 $ 22,540   $ ( 123 ) $ 8,031   $ ( 750 ) $ 29,698  

Six Months Ended June 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  

See the Combined Notes to Consolidated Financial Statements
14

Table of Contents

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

Three Months Ended
June 30, Six Months Ended
June 30,
(In millions) 2026 2025 2026 2025
Operating revenues
Electric operating revenues $ 2,038   $ 2,060   $ 3,931   $ 4,203  
Revenues from alternative revenue programs ( 55 ) ( 234 ) ( 46 ) ( 319 )
Operating revenues from affiliates 2   10   13   17  
Total operating revenues 1,985   1,836   3,898   3,901  
Operating expenses
Purchased power 579   550   1,031   1,239  

Operating and maintenance 339   322   674   645  
Operating and maintenance from affiliates 110   100   212   200  
Depreciation and amortization 416   387   820   767  
Taxes other than income taxes 107   97   212   196  
Total operating expenses 1,551   1,456   2,949   3,047  

Operating income 434   380   949   854  
Other income and (deductions)
Interest expense, net ( 140 ) ( 128 ) ( 272 ) ( 253 )
Interest expense to affiliates, net ( 3 ) ( 3 ) ( 7 ) ( 7 )
Other, net 41   31   73   53  
Total other income and (deductions) ( 102 ) ( 100 ) ( 206 ) ( 207 )
Income before income taxes 332   280   743   647  
Income taxes 83   52   184   117  
Net income $ 249   $ 228   $ 559   $ 530  
Comprehensive income $ 249   $ 228   $ 559   $ 530  

See the Combined Notes to Consolidated Financial Statements
15

Table of Contents

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

Six Months Ended
June 30,
(In millions) 2026 2025
Cash flows from operating activities
Net income $ 559   $ 530  
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation and amortization 820   767  

Deferred income taxes and amortization of investment tax credits 126   6  

Other non-cash operating activities 115   401  
Changes in assets and liabilities:
Accounts receivable 748   ( 252 )
Receivables from and payables to affiliates, net ( 6 ) ( 19 )
Inventories ( 15 ) 8  
Accounts payable and accrued expenses 102   ( 31 )
Collateral received (paid), net 81   ( 3 )
Income taxes ( 4 ) 7  
Regulatory assets and liabilities, net ( 862 ) ( 158 )
Pension and non-pension postretirement benefit contributions ( 222 ) ( 190 )
Other assets and liabilities 79   ( 25 )
Net cash flows provided by operating activities 1,521   1,041  
Cash flows from investing activities
Capital expenditures ( 1,671 ) ( 1,189 )

Other investing activities 3   1  
Net cash flows used in investing activities ( 1,668 ) ( 1,188 )
Cash flows from financing activities
Changes in short-term borrowings —   ( 36 )

Issuance of long-term debt 1,425   725  
Retirement of long-term debt ( 500 ) —  
Dividends paid on common stock ( 437 ) ( 407 )
Contributions from parent 256   87  
Other financing activities ( 14 ) ( 7 )
Net cash flows provided by financing activities 730   362  
Increase in cash, restricted cash, and cash equivalents 583   215  
Cash, restricted cash, and cash equivalents at beginning of period 663   632  
Cash, restricted cash, and cash equivalents at end of period $ 1,246   $ 847  

Supplemental cash flow information
(Decrease) increase in capital expenditures not paid $ ( 54 ) $ 17  

See the Combined Notes to Consolidated Financial Statements
16

Table of Contents

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

(In millions) June 30, 2026 December 31, 2025
ASSETS
Current assets
   Cash and cash equivalents $ 704   $ 159  
   Restricted cash and cash equivalents 533   454  
   Accounts receivable
   Customer accounts receivable 972 1,058
   Customer allowance for credit losses ( 102 ) ( 115 )
       Customer accounts receivable, net 870   943  
   Other accounts receivable 458 1,155
   Other allowance for credit losses ( 25 ) ( 23 )
       Other accounts receivable, net 433   1,132  

   Receivables from affiliates 5   5  

   Inventories, net 282   268  

   Regulatory assets 644   595  

   Other 196   217  
   Total current assets 3,667   3,773  
Property, plant, and equipment (net of accumulated depreciation and amortization of $ 8,731 and $ 8,291 as of June 30, 2026 and December 31, 2025, respectively)
33,316   32,255  
Deferred debits and other assets
   Regulatory assets 2,861   2,687  

   Goodwill 2,625   2,625  

   Receivable related to Regulatory Agreement Units 4,638   4,313  
   Investments 7   6  
   Prepaid pension asset 1,458   1,284  

   Other 1,375   1,342  
   Total deferred debits and other assets 12,964   12,257  
Total assets $ 49,947   $ 48,285  

See the Combined Notes to Consolidated Financial Statements
17

Table of Contents

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

(In millions) June 30, 2026 December 31, 2025
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities

   Long-term debt due within one year $ —   $ 500  
   Accounts payable 1,146   1,033  
   Accrued expenses 415   474  
   Payables to affiliates 75   81  
   Customer deposits 230   192  
   Regulatory liabilities 243   846  
   Mark-to-market derivative liabilities 23   25  

   Other 338   288  
   Total current liabilities 2,470   3,439  
Long-term debt 13,665   12,253  
Long-term debt to financing trust 206   206  
Deferred credits and other liabilities
   Deferred income taxes and unamortized investment tax credits 5,988   5,828  
   Regulatory liabilities 9,694   9,163  
   Asset retirement obligations 197   193  

   Non-pension postretirement benefit obligations 157   151  

   Mark-to-market derivative liabilities 105   106  

   Other 1,482   1,341  
   Total deferred credits and other liabilities 17,623   16,782  
   Total liabilities 33,964   32,680  
Commitments and contingencies
Shareholders’ equity
   Common stock 1,588   1,588  

   Other paid-in capital 11,275   11,019  
   Retained earnings 3,120   2,998  

   Total shareholders’ equity 15,983   15,605  
Total liabilities and shareholders’ equity $ 49,947   $ 48,285  
    
See the Combined Notes to Consolidated Financial Statements
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Table of Contents

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

Six Months Ended June 30, 2026
(In millions) Common
Stock Other
Paid-In
Capital Retained
Earnings Total
Shareholders’
Equity
Balance at December 31, 2025 $ 1,588   $ 11,019   $ 2,998   $ 15,605  
Net income —  —  310   310  
Common stock dividends —  —  ( 218 ) ( 218 )
Contributions from parent —  256   —  256  
Balance at March 31, 2026 $ 1,588   $ 11,275   $ 3,090   $ 15,953  
Net income —  —  249   249  
Common stock dividends —  —  ( 219 ) ( 219 )
Contributions from parent —  —   —  —  
Balance at June 30, 2026 $ 1,588   $ 11,275   $ 3,120   $ 15,983  

Six Months Ended June 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  

See the Combined Notes to Consolidated Financial Statements
19

Table of Contents

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

  Three Months Ended
June 30, Six Months Ended
June 30,
(In millions) 2026 2025 2026 2025
Operating revenues
Electric operating revenues $ 934   $ 876   $ 2,007   $ 1,839  
Natural gas operating revenues 120   120   530   496  
Revenues from alternative revenue programs 5   1   10   ( 8 )
Operating revenues from affiliates 3   3   7   6  
Total operating revenues 1,062   1,000   2,554   2,333  
Operating expenses
Purchased power 352   304   803   665  
Purchased fuel 37   35   198   176  

Operating and maintenance 232   242   502   507  
Operating and maintenance from affiliates 68   63   134   124  
Depreciation and amortization 125   112   247   221  
Taxes other than income taxes 62   54   131   115  
Total operating expenses 876   810   2,015   1,808  

Operating income 186   190   539   525  
Other income and (deductions)
Interest expense, net ( 70 ) ( 57 ) ( 139 ) ( 117 )
Interest expense to affiliates, net ( 2 ) ( 3 ) ( 5 ) ( 7 )
Other, net 13   10   25   18  
Total other income and (deductions) ( 59 ) ( 50 ) ( 119 ) ( 106 )
Income before income taxes 127   140   420   419  
Income taxes 8   4   23   17  

Net income $ 119   $ 136   $ 397   $ 402  
Comprehensive income $ 119   $ 136   $ 397   $ 402  

See the Combined Notes to Consolidated Financial Statements
20

Table of Contents

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

Six Months Ended
June 30,
(In millions) 2026 2025
Cash flows from operating activities
Net income $ 397   $ 402  
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation and amortization 247   221  

Deferred income taxes and amortization of investment tax credits 285   ( 32 )
Other non-cash operating activities 44   53  
Changes in assets and liabilities:
Accounts receivable 30   ( 101 )
Receivables from and payables to affiliates, net 1   4  
Inventories 7   2  
Accounts payable and accrued expenses ( 79 ) 2  
Collateral (paid) received, net —   6  
Income taxes ( 277 ) 3  
Regulatory assets and liabilities, net ( 51 ) 21  
Pension and non-pension postretirement benefit contributions ( 13 ) ( 9 )
Other assets and liabilities ( 70 ) ( 66 )
Net cash flows provided by operating activities 521   506  
Cash flows from investing activities
Capital expenditures ( 964 ) ( 832 )

Other investing activities ( 9 ) 2  
Net cash flows used in investing activities ( 973 ) ( 830 )
Cash flows from financing activities

Changes in short-term borrowings 81   11  

Dividends paid on common stock ( 273 ) ( 273 )
Contributions from parent 567   563  

Net cash flows provided by financing activities 375   301  
Decrease in cash, restricted cash, and cash equivalents ( 77 ) ( 23 )
Cash, restricted cash, and cash equivalents at beginning of period 116   48  
Cash, restricted cash, and cash equivalents at end of period $ 39   $ 25  

Supplemental cash flow information
(Decrease) increase in capital expenditures not paid $ ( 2 ) $ 95  

See the Combined Notes to Consolidated Financial Statements
21

Table of Contents

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

(In millions) June 30, 2026 December 31, 2025
ASSETS
Current assets
Cash and cash equivalents $ 39   $ 116  

Accounts receivable
Customer accounts receivable 741 811
Customer allowance for credit losses ( 142 ) ( 137 )
Customer accounts receivable, net 599   674  
Other accounts receivable 154 144
Other allowance for credit losses ( 18 ) ( 18 )
Other accounts receivable, net 136   126  

Inventories, net
Fossil fuel 25   43  
Materials and supplies 94   83  
Prepaid utility taxes 79   —  
Prepaid renewable energy credits 60   55  
Regulatory assets 116   72  

Other 66   34  
Total current assets 1,214   1,203  
Property, plant, and equipment (net of accumulated depreciation and amortization of $ 4,262 and $ 4,131 as of June 30, 2026 and December 31, 2025, respectively)
16,655   15,922  
Deferred debits and other assets
Regulatory assets 1,382   1,275  

Receivable related to Regulatory Agreement Units 642   442  
Investments 48   45  
Prepaid pension asset 448   441  

Other 106   34  
Total deferred debits and other assets 2,626   2,237  
Total assets $ 20,495   $ 19,362  

See the Combined Notes to Consolidated Financial Statements
22

Table of Contents

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

(In millions) June 30, 2026 December 31, 2025
LIABILITIES AND SHAREHOLDER'S EQUITY
Current liabilities
Short-term borrowings $ 81   $ —  

Accounts payable 788   811  
Accrued expenses 171   483  
Payables to affiliates 36   35  

Customer deposits 102   93  
Renewable energy credit obligations 101   56  
Regulatory liabilities 130   140  

Other 50   40  
Total current liabilities 1,459   1,658  
Long-term debt 6,398   6,396  
Long-term debt to financing trusts 184   184  
Deferred credits and other liabilities
Deferred income taxes and unamortized investment tax credits 2,980   2,594  
Regulatory liabilities 648   449  
Asset retirement obligations 26   26  
Non-pension postretirement benefit obligations 289   286  

Other 160   109  
Total deferred credits and other liabilities 4,103   3,464  
Total liabilities 12,144   11,702  
Commitments and contingencies
Shareholder’s equity
Common stock 5,789   5,222  

Retained earnings 2,562   2,438  

Total shareholder’s equity 8,351   7,660  
Total liabilities and shareholder's equity $ 20,495   $ 19,362  

See the Combined Notes to Consolidated Financial Statements
23

Table of Contents

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

Six Months Ended June 30, 2026
(In millions) Common
Stock Retained
Earnings Total
Shareholder's
Equity
Balance at December 31, 2025 $ 5,222   $ 2,438   $ 7,660  
Net income —  278   278  
Common stock dividends —  ( 137 ) ( 137 )
Contributions from parent 567   —  567  
Balance at March 31, 2026 $ 5,789   $ 2,579   $ 8,368  
Net income —  119   119  
Common stock dividends —  ( 136 ) ( 136 )
Contributions from parent —   —  —  
Balance at June 30, 2026 $ 5,789   $ 2,562   $ 8,351  

Six Months Ended June 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  

See the Combined Notes to Consolidated Financial Statements
24

Table of Contents

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

Three Months Ended
June 30, Six Months Ended
June 30,
(In millions) 2026 2025 2026 2025
Operating revenues
Electric operating revenues $ 1,044   $ 856   $ 2,302   $ 1,877  
Natural gas operating revenues 166   184   757   745  
Revenues from alternative revenue programs 5   ( 13 ) ( 18 ) ( 43 )
Operating revenues from affiliates 3   2   5   4  
Total operating revenues 1,218   1,029   3,046   2,583  
Operating expenses
Purchased power 522   367   1,152   818  
Purchased fuel 23   39   201   198  

Operating and maintenance 222   201   481   443  
Operating and maintenance from affiliates 71   63   138   125  
Depreciation and amortization 166   154   334   318  
Taxes other than income taxes 96   85   200   181  
Total operating expenses 1,100   909   2,506   2,083  

Operating income 118   120   540   500  
Other income and (deductions)
Interest expense, net ( 68 ) ( 61 ) ( 129 ) ( 120 )
Other, net 22   11   38   20  
Total other income and (deductions) ( 46 ) ( 50 ) ( 91 ) ( 100 )
Income before income taxes 72   70   449   400  
Income taxes 17   15   96   85  
Net income $ 55   $ 55   $ 353   $ 315  
Comprehensive income $ 55   $ 55   $ 353   $ 315  

See the Combined Notes to Consolidated Financial Statements
25

Table of Contents

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

Six Months Ended
June 30,
(In millions) 2026 2025
Cash flows from operating activities
Net income $ 353   $ 315  
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation and amortization 334   318  

Deferred income taxes and amortization of investment tax credits 198   43  

Other non-cash operating activities 79   89  
Changes in assets and liabilities:
Accounts receivable ( 16 ) ( 21 )
Receivables from and payables to affiliates, net ( 3 ) ( 11 )
Inventories ( 4 ) 8  
Accounts payable and accrued expenses ( 100 ) ( 43 )
Collateral (paid) received, net ( 2 ) 5  
Income taxes ( 160 ) 15  
Regulatory assets and liabilities, net 45   ( 61 )
Pension and non-pension postretirement benefit contributions ( 44 ) ( 37 )
Other assets and liabilities 117   114  
Net cash flows provided by operating activities 797   734  
Cash flows from investing activities
Capital expenditures ( 822 ) ( 804 )

Other investing activities 5   5  
Net cash flows used in investing activities ( 817 ) ( 799 )
Cash flows from financing activities
Changes in short-term borrowings —   ( 175 )
Issuance of long-term debt 925   650  
Retirement of long-term debt ( 350 ) —  

Dividends paid on common stock ( 227 ) ( 196 )
Contributions from parent 474   —  
Other financing activities ( 8 ) ( 7 )
Net cash flows provided by financing activities 814   272  
Increase in cash, restricted cash, and cash equivalents 794   207  
Cash, restricted cash, and cash equivalents at beginning of period 220   34  
Cash, restricted cash, and cash equivalents at end of period $ 1,014   $ 241  

Supplemental cash flow information
Decrease in capital expenditures not paid $ ( 20 ) $ ( 50 )

See the Combined Notes to Consolidated Financial Statements
26

Table of Contents

Baltimore Gas and Electric Company
Balance Sheets
(Unaudited)

(In millions) June 30, 2026 December 31, 2025
ASSETS
Current assets
Cash and cash equivalents $ 1,010   $ 217  
Restricted cash and cash equivalents 4   3  
Accounts receivable
Customer accounts receivable 926 887
Customer allowance for credit losses ( 136 ) ( 68 )
Customer accounts receivable, net 790   819  
Other accounts receivable 91 100
Other allowance for credit losses ( 3 ) ( 4 )
Other accounts receivable, net 88   96  

Receivables from affiliates —   1  

Inventories, net
Fossil fuel 30   36  
Materials and supplies 83   74  
Prepaid utility taxes —   126  
Regulatory assets 101   175  
Prepaid renewable energy credits 86   189  
Other 18   14  
Total current assets 2,210   1,750  
Property, plant, and equipment (net of accumulated depreciation and amortization of $ 5,446 and $ 5,234 as of June 30, 2026 and December 31, 2025, respectively)
14,918   14,385  
Deferred debits and other assets
Regulatory assets 774   804  
Investments 16   10  

Prepaid pension asset 217   194  

Other 38   41  
Total deferred debits and other assets 1,045   1,049  
Total assets $ 18,173   $ 17,184  

See the Combined Notes to Consolidated Financial Statements
27

Table of Contents

Baltimore Gas and Electric Company
Balance Sheets
(Unaudited)

(In millions) June 30, 2026 December 31, 2025
LIABILITIES AND SHAREHOLDER'S EQUITY
Current liabilities

Long-term debt due within one year $ —   $ 350  
Accounts payable 548   640  
Accrued expenses 176   352  
Payables to affiliates 39   39  
Customer deposits 126   125  
Regulatory liabilities 34   31  

Renewable energy credit obligations 92   194  
Other 31   39  
Total current liabilities 1,046   1,770  
Long-term debt 6,609   5,691  
Deferred credits and other liabilities
Deferred income taxes and unamortized investment tax credits 2,476   2,242  
Regulatory liabilities 559   595  
Asset retirement obligations 37   36  
Non-pension postretirement benefit obligations 137   144  

Other 107   104  
Total deferred credits and other liabilities 3,316   3,121  
Total liabilities 10,971   10,582  
Commitments and contingencies
Shareholder's equity
Common stock 4,488   4,014  

Retained earnings 2,714   2,588  

Total shareholder's equity 7,202   6,602  

Total liabilities and shareholder's equity $ 18,173   $ 17,184  

See the Combined Notes to Consolidated Financial Statements
28

Table of Contents

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

Six Months Ended June 30, 2026
(In millions) Common
Stock Retained
Earnings Total
Shareholder's
Equity
Balance at December 31, 2025 $ 4,014   $ 2,588   $ 6,602  
Net income —  298   298  
Common stock dividends —  ( 114 ) ( 114 )

Balance at March 31, 2026 $ 4,014   $ 2,772   $ 6,786  
Net income —  55   55  
Common stock dividends —  ( 113 ) ( 113 )
Contributions from parent 474   —  474  
Balance at June 30, 2026 $ 4,488   $ 2,714   $ 7,202  

Six Months Ended June 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 )

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  

See the Combined Notes to Consolidated Financial Statements
29

Table of Contents

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

Three Months Ended
June 30, Six Months Ended
June 30,
(In millions) 2026 2025 2026 2025
Operating revenues
Electric operating revenues $ 1,694   $ 1,573   $ 3,628   $ 3,264  
Natural gas operating revenues 40   33   157   120  
Revenues from alternative revenue programs ( 24 ) ( 29 ) ( 48 ) ( 32 )
Operating revenues from affiliates 2   2   5   5  
Total operating revenues 1,712   1,579   3,742   3,357  
Operating expenses
Purchased power 679   590   1,529   1,273  
Purchased fuel 19   11   73   49  

Operating and maintenance 337   291   702   586  
Operating and maintenance from affiliates 58   49   118   103  
Depreciation and amortization 245   233   491   467  
Taxes other than income taxes 145   136   296   276  
Total operating expenses 1,483   1,310   3,209   2,754  

Gain on sale of assets —   2   —   1  
Operating income 229   271   533   604  
Other income and (deductions)
Interest expense, net ( 107 ) ( 102 ) ( 213 ) ( 201 )
Interest expense to affiliates, net ( 1 ) ( 1 ) ( 2 ) ( 2 )
Other, net 20   17   39   35  
Total other income and (deductions) ( 88 ) ( 86 ) ( 176 ) ( 168 )
Income before income taxes 141   185   357   436  
Income taxes 32   42   79   99  

Net income $ 109   $ 143   $ 278   $ 337  

Comprehensive income $ 109   $ 143   $ 278   $ 337  

See the Combined Notes to Consolidated Financial Statements
30

Table of Contents

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

Six Months Ended
June 30,
(In millions) 2026 2025
Cash flows from operating activities
Net income $ 278   $ 337  
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation, amortization, and accretion 491   467  

Deferred income taxes and amortization of investment tax credits 100   47  

Other non-cash operating activities 150   128  
Changes in assets and liabilities:
Accounts receivable 20   ( 80 )
Receivables from and payables to affiliates, net ( 1 ) ( 14 )
Inventories ( 16 ) ( 37 )
Accounts payable and accrued expenses 27   39  

Collateral (paid) received, net ( 6 ) 8  
Income taxes ( 37 ) ( 34 )
Regulatory assets and liabilities, net 9   ( 76 )
Pension and non-pension postretirement benefit contributions ( 56 ) ( 45 )
Other assets and liabilities ( 9 ) ( 39 )
Net cash flows provided by operating activities 950   701  
Cash flows from investing activities
Capital expenditures ( 1,062 ) ( 1,108 )
Proceeds from sales of long-lived assets —   2  

Other investing activities 1   —  
Net cash flows used in investing activities ( 1,061 ) ( 1,106 )
Cash flows from financing activities
Changes in short-term borrowings ( 580 ) ( 300 )

Issuance of long-term debt 475   425  

Changes in Exelon intercompany money pool 12   ( 3 )

Distributions to member ( 247 ) ( 292 )
Contributions from member 406   522  

Other financing activities ( 13 ) ( 13 )
Net cash flows provided by financing activities 53   339  
Decrease in cash, restricted cash, and cash equivalents ( 58 ) ( 66 )
Cash, restricted cash, and cash equivalents at beginning of period 141   163  
Cash, restricted cash, and cash equivalents at end of period $ 83   $ 97  

Supplemental cash flow information
Decrease in capital expenditures not paid $ ( 157 ) $ ( 137 )

See the Combined Notes to Consolidated Financial Statements
31

Table of Contents

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

(In millions) June 30, 2026 December 31, 2025
ASSETS
Current assets
Cash and cash equivalents $ 47   $ 103  
Restricted cash and cash equivalents 36   38  
Accounts receivable
Customer accounts receivable 928 975
Customer allowance for credit losses ( 128 ) ( 115 )
Customer accounts receivable, net 800   860  
Other accounts receivable 308 292
Other allowance for credit losses ( 48 ) ( 49 )
Other accounts receivable, net 260   243  

Receivables from affiliates 5   14  

Inventories, net
Fossil fuel 7   9  
Materials and supplies 374   357  

Prepaid utility taxes 54   77  
Regulatory assets 324   352  

Prepaid renewable energy credits 105   201  
Other 48   34  
Total current assets 2,060   2,288  
Property, plant, and equipment (net of accumulated depreciation and amortization of $ 4,685 and $ 4,350 as of June 30, 2026 and December 31, 2025, respectively)
21,861   21,377  
Deferred debits and other assets
Regulatory assets 1,557   1,556  
Goodwill 4,005   4,005  
Investments 160   158  

Prepaid pension asset 207   199  

Other 158   132  
Total deferred debits and other assets 6,087   6,050  
Total assets $ 30,008   $ 29,715  

See the Combined Notes to Consolidated Financial Statements
32

Table of Contents

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

(In millions) June 30, 2026 December 31, 2025
LIABILITIES AND MEMBER'S EQUITY
Current liabilities
Short-term borrowings $ 32   $ 612  
Long-term debt due within one year 76   64  
Accounts payable 703   816  
Accrued expenses 338   359  
Payables to affiliates 61   71  
Borrowings from Exelon intercompany money pool 92   80  

Customer deposits 131   123  
Regulatory liabilities 159   103  
Unamortized energy contract liabilities 4   5  

Renewable energy credit obligations 140   223  
Other 119   121  
Total current liabilities 1,855   2,577  
Long-term debt 9,978   9,526  
Deferred credits and other liabilities
Deferred income taxes and unamortized investment tax credits 3,519   3,391  
Regulatory liabilities 740   722  
Asset retirement obligations 57   62  
Non-pension postretirement benefit obligations 17   24  

Unamortized energy contract liabilities 14   16  
Other 412   418  
Total deferred credits and other liabilities 4,759   4,633  
Total liabilities 16,592   16,736  
Commitments and contingencies

Member's equity
Membership interest 13,536   13,130  

Undistributed losses ( 120 ) ( 151 )

Total member's equity 13,416   12,979  
Total liabilities and member's equity $ 30,008   $ 29,715  

See the Combined Notes to Consolidated Financial Statements
33

Table of Contents

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

Six Months Ended June 30, 2026
(In millions) Membership Interest Undistributed (Losses)/Gains Total Member's Equity
Balance at December 31, 2025 $ 13,130   $ ( 151 ) $ 12,979  
Net income —  169   169  
Distributions to member —  ( 139 ) ( 139 )
Contributions from member 275   —  275  
Balance at March 31, 2026 $ 13,405   $ ( 121 ) $ 13,284  
Net income 109   109  
Distributions to member ( 108 ) ( 108 )
Contributions from member 131   131  
Balance at June 30, 2026 $ 13,536   $ ( 120 ) $ 13,416  

Six Months Ended June 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  

See the Combined Notes to Consolidated Financial Statements
34

Table of Contents

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

Three Months Ended
June 30, Six Months Ended
June 30,
(In millions) 2026 2025 2026 2025
Operating revenues
Electric operating revenues $ 873   $ 791   $ 1,859   $ 1,645  
Revenues from alternative revenue programs ( 15 ) ( 16 ) ( 14 ) ( 14 )
Operating revenues from affiliates 1   1   4   4  
Total operating revenues 859   776   1,849   1,635  
Operating expenses
Purchased power 316   256   727   574  

Operating and maintenance 118   91   270   187  
Operating and maintenance from affiliates 72   64   139   126  
Depreciation and amortization 114   107   228   212  
Taxes other than income taxes 113   109   231   222  
Total operating expenses 733   627   1,595   1,321  

Gain on sale of assets —   2   —   1  

Operating income 126   151   254   315  
Other income and (deductions)
Interest expense, net ( 56 ) ( 54 ) ( 111 ) ( 106 )

Other, net 12   9   23   20  
Total other income and (deductions) ( 44 ) ( 45 ) ( 88 ) ( 86 )
Income before income taxes 82   106   166   229  
Income taxes 17   22   33   48  

Net income $ 65   $ 84   $ 133   $ 181  

Comprehensive income $ 65   $ 84   $ 133   $ 181  

See the Combined Notes to Consolidated Financial Statements
35

Table of Contents

Potomac Electric Power Company
Statements Of Cash Flows
(Unaudited)

Six Months Ended
June 30,
(In millions) 2026 2025
Cash flows from operating activities
Net income $ 133   $ 181  
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation, amortization, and accretion 228   212  

Deferred income taxes and amortization of investment tax credits 43   14  
Other non-cash operating activities 57   46  
Changes in assets and liabilities:
Accounts receivable ( 25 ) ( 73 )
Receivables from and payables to affiliates, net 4   —  
Inventories ( 13 ) ( 18 )
Accounts payable and accrued expenses 37   17  
Collateral received, net —   2  
Income taxes ( 19 ) ( 38 )
Regulatory assets and liabilities, net 12   ( 27 )
Pension and non-pension postretirement benefit contributions ( 4 ) ( 6 )
Other assets and liabilities 16   6  
Net cash flows provided by operating activities 469   316  
Cash flows from investing activities
Capital expenditures ( 517 ) ( 469 )
Proceeds from sales of long-lived assets —   2  

Changes in PHI intercompany money pool ( 95 ) —  

Net cash flows used in investing activities ( 612 ) ( 467 )
Cash flows from financing activities
Changes in short-term borrowings ( 303 ) ( 51 )
Issuance of long-term debt 300   200  

Dividends paid on common stock ( 121 ) ( 158 )
Contributions from parent 270   157  

Other financing activities ( 6 ) ( 4 )
Net cash flows provided by financing activities 140   144  
Decrease in cash, restricted cash, and cash equivalents ( 3 ) ( 7 )
Cash, restricted cash, and cash equivalents at beginning of period 55   51  
Cash, restricted cash, and cash equivalents at end of period $ 52   $ 44  

Supplemental cash flow information
Decrease in capital expenditures not paid $ ( 68 ) $ ( 64 )

See the Combined Notes to Consolidated Financial Statements
36

Table of Contents

Potomac Electric Power Company
Balance Sheets
(Unaudited)

(In millions) June 30, 2026 December 31, 2025
ASSETS
Current assets
Cash and cash equivalents $ 21   $ 22  
Restricted cash and cash equivalents 31   33  
Accounts receivable
Customer accounts receivable 495 484
Customer allowance for credit losses ( 77 ) ( 69 )
Customer accounts receivable, net 418   415  
Other accounts receivable 165 154
Other allowance for credit losses ( 25 ) ( 26 )
Other accounts receivable, net 140   128  

Receivable from PHI intercompany money pool 95   —  

Inventories, net 186   174  

Regulatory assets 162   182  

Prepaid renewable energy credits 89   171  
Other 17   59  
Total current assets 1,159   1,184  
Property, plant, and equipment (net of accumulated depreciation and amortization of $ 4,933 and $ 4,784 as of June 30, 2026 and December 31, 2025, respectively)
11,007   10,747  
Deferred debits and other assets
Regulatory assets 391   405  
Investments 144   141  

Prepaid pension asset 182   194  

Other 68   57  
Total deferred debits and other assets 785   797  
Total assets $ 12,951   $ 12,728  

See the Combined Notes to Consolidated Financial Statements
37

Table of Contents

Potomac Electric Power Company
Balance Sheets
(Unaudited)

(In millions) June 30, 2026 December 31, 2025
LIABILITIES AND SHAREHOLDER'S EQUITY
Current liabilities
Short-term borrowings $ —   $ 303  
Long-term debt due within one year 7   6  
Accounts payable 383   418  
Accrued expenses 172   173  
Payables to affiliates 41   37  

Customer deposits 65   61  
Regulatory liabilities 14   13  

Renewable energy credit obligations 90   174  
Other 86   84  
Total current liabilities 858   1,269  
Long-term debt 4,924   4,626  

Deferred credits and other liabilities
Deferred income taxes and unamortized investment tax credits 1,664   1,604  
Regulatory liabilities 279   268  
Asset retirement obligations 39   45  

Other 203   214  
Total deferred credits and other liabilities 2,185   2,131  
Total liabilities 7,967   8,026  
Commitments and contingencies
Shareholder's equity
Common stock 3,798   3,528  

Retained earnings 1,186   1,174  

Total shareholder's equity 4,984   4,702  
Total liabilities and shareholder's equity $ 12,951   $ 12,728  

See the Combined Notes to Consolidated Financial Statements
38

Table of Contents

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

Six Months Ended June 30, 2026
(In millions) Common Stock Retained Earnings Total Shareholder's Equity
Balance at December 31, 2025 $ 3,528   $ 1,174   $ 4,702  
Net income —  68   68  
Common stock dividends —  ( 64 ) ( 64 )
Contributions from parent 139   —  139  
Balance at March 31, 2026 $ 3,667   $ 1,178   $ 4,845  
Net income —  65   65  

Common stock dividends —  ( 57 ) ( 57 )
Contributions from parent 131   —  131  
Balance at June 30, 2026 $ 3,798   $ 1,186   $ 4,984  

Six Months Ended June 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  

See the Combined Notes to Consolidated Financial Statements
39

Table of Contents

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

Three Months Ended
June 30, Six Months Ended
June 30,
(In millions) 2026 2025 2026 2025
Operating revenues
Electric operating revenues $ 410   $ 386   $ 920   $ 850  
Natural gas operating revenues 40   33   157   120  
Revenues from alternative revenue programs 2   —   ( 5 ) ( 5 )
Operating revenues from affiliates 2   2   4   4  
Total operating revenues 454   421   1,076   969  
Operating expenses
Purchased power 176   161   410   370  
Purchased fuel 19   11   73   49  

Operating and maintenance 62   50   134   110  
Operating and maintenance from affiliates 50   45   97   91  
Depreciation and amortization 67   63   133   126  
Taxes other than income taxes 24   20   50   41  
Total operating expenses 398   350   897   787  

Operating income 56   71   179   182  
Other income and (deductions)
Interest expense, net ( 26 ) ( 25 ) ( 53 ) ( 50 )

Other, net 4   4   8   8  
Total other income and (deductions) ( 22 ) ( 21 ) ( 45 ) ( 42 )
Income before income taxes 34   50   134   140  
Income taxes 8   11   31   32  

Net income $ 26   $ 39   $ 103   $ 108  
Comprehensive income $ 26   $ 39   $ 103   $ 108  

See the Combined Notes to Consolidated Financial Statements
40

Table of Contents

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

Six Months Ended
June 30,
(In millions) 2026 2025
Cash flows from operating activities
Net income $ 103   $ 108  
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation and amortization 133   126  

Deferred income taxes and amortization of investment tax credits 28   15  

Other non-cash operating activities 29   30  
Changes in assets and liabilities:
Accounts receivable 55   11  
Receivables from and payables to affiliates, net 2   ( 3 )
Inventories 1   ( 11 )
Accounts payable and accrued expenses ( 11 ) 3  
Collateral (paid) received, net ( 1 ) 3  
Income taxes ( 14 ) ( 2 )
Regulatory assets and liabilities, net ( 4 ) ( 22 )
Pension and non-pension postretirement benefit contributions ( 1 ) ( 1 )
Other assets and liabilities 30   24  
Net cash flows provided by operating activities 350   281  
Cash flows from investing activities
Capital expenditures ( 300 ) ( 277 )

Other investing activities 1   —  
Net cash flows used in investing activities ( 299 ) ( 277 )
Cash flows from financing activities
Changes in short-term borrowings ( 129 ) ( 142 )
Issuance of long-term debt 75   125  

Changes in PHI intercompany money pool 47   —  
Dividends paid on common stock ( 86 ) ( 90 )
Contributions from parent 45   99  
Other financing activities ( 5 ) ( 5 )
Net cash flows used in financing activities ( 53 ) ( 13 )
Decrease in cash, restricted cash, and cash equivalents ( 2 ) ( 9 )
Cash, restricted cash, and cash equivalents at beginning of period 12   23  
Cash, restricted cash, and cash equivalents at end of period $ 10   $ 14  

Supplemental cash flow information
Decrease in capital expenditures not paid $ ( 60 ) $ ( 45 )

    
See the Combined Notes to Consolidated Financial Statements
41

Table of Contents

Delmarva Power & Light Company
Balance Sheets
(Unaudited)

(In millions) June 30, 2026 December 31, 2025
ASSETS
Current assets
Cash and cash equivalents $ 8   $ 9  
Restricted cash and cash equivalents 2   3  
Accounts receivable
Customer accounts receivable 196 253
Customer allowance for credit losses ( 21 ) ( 19 )
Customer accounts receivable, net 175   234  
Other accounts receivable 72 75
Other allowance for credit losses ( 11 ) ( 10 )
Other accounts receivable, net 61   65  
Receivables from affiliates 4   2  

Inventories, net
Fossil fuel 7   9  
Materials and supplies 108   107  
Prepaid utility taxes —   29  

Regulatory assets 82   72  
Prepaid renewable energy credits 16   30  
Other 26   13  
Total current assets 489   573  
Property, plant, and equipment (net of accumulated depreciation and amortization of $ 2,330 and $ 2,241 as of June 30, 2026 and December 31, 2025, respectively)
5,977   5,855  
Deferred debits and other assets
Regulatory assets 215   214  

Other 143   147  
Total deferred debits and other assets 358   361  
Total assets $ 6,824   $ 6,789  

See the Combined Notes to Consolidated Financial Statements
42

Table of Contents

Delmarva Power & Light Company
Balance Sheets
(Unaudited)

(In millions) June 30, 2026 December 31, 2025
LIABILITIES AND SHAREHOLDER'S EQUITY
Current liabilities
Short-term borrowings $ 32   $ 161  
Long-term debt due within one year 63   53  
Accounts payable 147   218  
Accrued expenses 59   70  
Payables to affiliates 28   25  
Borrowings from PHI intercompany money pool 47   —  
Customer deposits 39   36  
Regulatory liabilities 43   42  
Renewable energy credit obligations 50   49  
Other 20   22  
Total current liabilities 528   676  
Long-term debt 2,358   2,291  
Deferred credits and other liabilities
Deferred income taxes and unamortized investment tax credits 1,032   996  
Regulatory liabilities 330   316  
Asset retirement obligations 13   12  

Other 130   127  
Total deferred credits and other liabilities 1,505   1,451  
Total liabilities 4,391   4,418  
Commitments and contingencies
Shareholder's equity
Common stock 1,767   1,722  

Retained earnings 666   649  
Total shareholder's equity 2,433   2,371  
Total liabilities and shareholder's equity $ 6,824   $ 6,789  

See the Combined Notes to Consolidated Financial Statements
43

Table of Contents

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

Six Months Ended June 30, 2026
(In millions) Common Stock Retained Earnings Total Shareholder's Equity
Balance at December 31, 2025 $ 1,722   $ 649   $ 2,371  
Net income —  77   77  
Common stock dividends —  ( 50 ) ( 50 )
Contributions from parent 45   —  45  
Balance at March 31, 2026 $ 1,767   $ 676   $ 2,443  
Net income —  26   26  
Common stock dividends —  ( 36 ) ( 36 )
Contributions from parent —   —  —  
Balance at June 30, 2026 $ 1,767   $ 666   $ 2,433  

Six Months Ended June 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  

See the Combined Notes to Consolidated Financial Statements
44

Table of Contents

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

Three Months Ended
June 30, Six Months Ended
June 30,
(In millions) 2026 2025 2026 2025
Operating revenues
Electric operating revenues $ 411   $ 397   $ 849   $ 769  
Revenues from alternative revenue programs ( 11 ) ( 13 ) ( 29 ) ( 13 )
Operating revenues from affiliates 1   —   2   1  
Total operating revenues 401   384   822   757  
Operating expenses
Purchased power 187   173   392   329  

Operating and maintenance 55   55   105   106  
Operating and maintenance from affiliates 44   40   87   79  
Depreciation and amortization 63   62   128   127  
Taxes other than income taxes 3   3   5   5  
Total operating expenses 352   333   717   646  

Operating income 49   51   105   111  
Other income and (deductions)
Interest expense, net ( 22 ) ( 20 ) ( 44 ) ( 41 )

Other, net 3   2   5   6  
Total other income and (deductions) ( 19 ) ( 18 ) ( 39 ) ( 35 )
Income before income taxes 30   33   66   76  
Income taxes 8   9   17   20  

Net income $ 22   $ 24   $ 49   $ 56  
Comprehensive income $ 22   $ 24   $ 49   $ 56  

See the Combined Notes to Consolidated Financial Statements
45

Table of Contents

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

Six Months Ended
June 30,
(In millions) 2026 2025
Cash flows from operating activities
Net income $ 49   $ 56  
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation and amortization 128   127  

Deferred income taxes and amortization of investment tax credits 35   13  
Other non-cash operating activities 48   33  
Changes in assets and liabilities:
Accounts receivable ( 9 ) ( 18 )
Receivables from and payables to affiliates, net 10   ( 4 )
Inventories ( 4 ) ( 9 )
Accounts payable and accrued expenses 6   37  
Collateral (paid) received, net ( 5 ) 4  
Income taxes ( 11 ) ( 2 )
Regulatory assets and liabilities, net ( 2 ) ( 27 )
Pension and non-pension postretirement benefit contributions ( 14 ) ( 2 )
Other assets and liabilities ( 48 ) ( 49 )
Net cash flows provided by operating activities 183   159  
Cash flows from investing activities
Capital expenditures ( 240 ) ( 196 )

Other investing activities 1   —  
Net cash flows used in investing activities ( 239 ) ( 196 )
Cash flows from financing activities
Changes in short-term borrowings ( 148 ) ( 107 )

Issuance of long-term debt 100   100  

Changes in PHI intercompany money pool 48   —  
Dividends paid on common stock ( 40 ) ( 44 )
Contributions from parent 91   94  
Other financing activities ( 4 ) ( 3 )
Net cash flows provided by financing activities 47   40  
(Decrease) increase in cash and cash equivalents ( 9 ) 3  
Cash and cash equivalents at beginning of period 24   14  
Cash and cash equivalents at end of period $ 15   $ 17  

Supplemental cash flow information
Decrease in capital expenditures not paid $ ( 28 ) $ ( 28 )

See the Combined Notes to Consolidated Financial Statements
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Table of Contents

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

(In millions) June 30, 2026 December 31, 2025
ASSETS
Current assets
Cash and cash equivalents $ 13   $ 22  
Restricted cash and cash equivalents 2   2  
Accounts receivable
Customer accounts receivable 236 239
Customer allowance for credit losses ( 30 ) ( 27 )
Customer accounts receivable, net 206   212  
Other accounts receivable 70 64
Other allowance for credit losses ( 12 ) ( 13 )
Other accounts receivable, net 58   51  

Receivables from affiliates 1   12  

Inventories, net 80   76  

Prepaid utility taxes 48   —  
Regulatory assets 75   93  
Other 8   8  
Total current assets 491   476  
Property, plant, and equipment (net of accumulated depreciation and amortization of $ 2,037 and $ 1,956 as of June 30, 2026 and December 31, 2025, respectively)
4,657   4,556  
Deferred debits and other assets
Regulatory assets 588   559  

Other 59   41  
Total deferred debits and other assets 647   600  
Total assets $ 5,795   $ 5,632  

See the Combined Notes to Consolidated Financial Statements
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Table of Contents

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

(In millions) June 30, 2026 December 31, 2025
LIABILITIES AND SHAREHOLDER'S EQUITY
Current liabilities
Short-term borrowings $ —   $ 148  
Long-term debt due within one year 4   5  
Accounts payable 164   168  
Accrued expenses 54   64  
Payables to affiliates 23   24  

Borrowings from PHI intercompany money pool 48   —  
Customer deposits 27   26  
Regulatory liabilities 102   48  

Other 11   13  
Total current liabilities 433   496  
Long-term debt 2,130   2,028  
Deferred credits and other liabilities
Deferred income taxes and unamortized investment tax credits 906   869  
Regulatory liabilities 129   137  

Other 69   74  
Total deferred credits and other liabilities 1,104   1,080  
Total liabilities 3,667   3,604  
Commitments and contingencies
Shareholder's equity
Common stock 2,104   2,013  
Retained earnings 24   15  

Total shareholder's equity 2,128   2,028  
Total liabilities and shareholder's equity $ 5,795   $ 5,632  

See the Combined Notes to Consolidated Financial Statements
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Table of Contents

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

Six Months Ended June 30, 2026
(In millions) Common Stock Retained (Deficit) Earnings Total Shareholder's Equity
Balance at December 31, 2025 $ 2,013   $ 15   $ 2,028  
Net income —  27   27  
Common stock dividends —  ( 25 ) ( 25 )
Contributions from parent 91   —  91  
Balance at March 31, 2026 $ 2,104   $ 17   $ 2,121  
Net income —  22   22  
Common stock dividends —  ( 15 ) ( 15 )
Contributions from parent —   —  —  
Balance at June 30, 2026 $ 2,104   $ 24   $ 2,128  

Six Months Ended June 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  

See the Combined Notes to Consolidated Financial Statements
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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 (and, through its subsidiary ComEd of Indiana, transmission in a small portion of northwestern Indiana)
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

Prior Period Adjustments (ACE)
In the first quarter of 2026, management identified an error in the historical rate classification for a limited number of ACE customers that resulted in the overstatement of Regulatory assets and Revenues from alternative revenue programs. Management has concluded that the error was not material to previously issued or to the current period financial statements.
The impact of the error correction recognized in the first quarter of 2026 was a $ 14 million decrease to ACE’s Revenues from alternative revenue programs, a $ 4 million decrease to Income taxes, and a corresponding decrease of $ 14 million in Regulatory assets. The overall impact on ACE’s Operating income was a decrease of $ 14 million, and the impact on ACE’s Net income was $ 10 million. The error did not impact any net cash flow subtotal for the three months ended March 31, 2026.
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
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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

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.
The accompanying consolidated financial statements as of June 30, 2026 and for the three and six months ended June 30, 2026 and 2025 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, 2025 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, 2026. 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 June 30, 2026: 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 June 30, 2026. Unless otherwise indicated, the Registrants are currently assessing the impacts such guidance may have (which could be material) in their Consolidated Balance Sheets, Consolidated Statements of Operations and Comprehensive Income, Consolidated Statements of Cash Flows and disclosures, as well as the potential to early adopt where applicable. The Registrants have assessed other FASB issuances of new standards which are not listed below given the current expectation that such standards will not significantly impact the Registrants' financial reporting.
Disaggregation of Income Statement Expenses (Issued November 2024) . Provides additional disclosure requirements related to relevant expense captions of income statement expense line items. The revised guidance requires a new tabular disclosure of disaggregated income statement expenses including a break out of (1) purchases of inventory, (2) employee compensation, (3) depreciation, (4) intangible asset amortization, (5) depreciation, depletion, and amortization recognized as part of oil and gas producing activities included in each relevant expense line item on the income statement. The tabular disaggregation should include certain amounts already required to be disclosed under GAAP elsewhere. Any remaining amounts not separately disaggregated quantitatively should include a qualitative description. Additionally, on an annual basis, the standard requires disclosure of management’s definition of selling expenses and the amount of expense. The standard is effective January 1, 2027, with early adoption permitted.
Environmental Credits and Environmental Credit Obligations (Issued May 2026). Establishes guidance for the recognition, measurement, presentation and disclosure of environmental credits and compliance obligations that may be settled by using environmental credits. The guidance is effective for annual and interim periods beginning January 1, 2028 with early adoption permitted. The guidance is adopted on a retrospective basis by recognizing a cumulative effect adjustment to retained earnings at the date of initial application.

2. Regulatory Matters (All Registrants)
As discussed in Note 2 — Regulatory Matters of the 2025 Form 10-K, the Registrants are involved in rate and regulatory proceedings at FERC and their state commissions. The following discusses developments in 2026 and updates to the 2025 Form 10-K.
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Combined Notes to Consolidated Financial Statements — (Continued)
(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 2026.
Completed Distribution Base Rate Case Proceedings

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

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

Note 2 — Regulatory Matters

Pending Distribution Base Rate Case Proceedings

Registrant/Jurisdiction Filing Date Service Requested Revenue Requirement Increase Requested ROE Expected Approval Timing

Pepco - Maryland (a)
October 14, 2025 (amended April 16, 2026) Electric $ 120   10.50 % Third quarter of 2026
DPL - Delaware (b)
December 9, 2025 (amended June 1, 2026) Electric $ 45   10.50 % Third quarter of 2027
BGE - Maryland July 2, 2026 Electric $ 156   10.40 % First quarter of 2027
__________
(a) On April 14, 2026, Pepco notified the MDPSC of pursuing a traditional base rate case.
(b) DPL implemented interim rates on July 9, 2026, subject to refund.

ComEd Distribution Base Rate Case Proceedings
The ICC approved ComEd's four-year MRP for the period January 1, 2024 through December 31, 2027. The MRP was originally approved by the ICC on December 14, 2023 and was subsequently amended on January 10, 2024, April 18, 2024 and December 19, 2024. The December 19, 2024 order provided a total revenue requirement increase of $ 1.045 billion inclusive of rate increases of approximately $ 752 million in 2024, $ 80 million in 2025, $ 102 million in 2026, and $ 111 million in 2027.
On December 18, 2025, the ICC approved ComEd's 2024 MRP Reconciliation reflecting a revenue increase of $ 243 million, including the tax benefit of NOLCs. While NOLCs are included in the MRP Reconciliation per the final order, the impacts of the NOLCs will not be reflected in the financial statements until the PLR is received from the IRS. See Note 6 — Income Taxes for additional information on NOLCs.
On March 20, 2026, ComEd filed its annual revenue balancing reconciliation for 2025. The July 16, 2026 order approved the reconciliation, which is a component of revenue decoupling, reflecting a revenue reduction of $ 128 million. The reconciliation is effective January 1, 2027.
On May 1, 2026, ComEd filed its 2025 MRP Reconciliation reflecting a revenue increase of $ 234 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.
PECO Distribution Base Rate Case Proceedings
On December 12, 2024, the PAPUC issued their Opinions and Orders which approved the non-unanimous partial settlements with limited modifications for both the electric and natural gas base rate cases, and denied the Weather Normalization Adjustment requested in the natural gas base rate case.
PECO’s approved annual electric revenue requirement increase of $ 354 million is partially offset by a one-time credit of $ 64 million in 2025. In addition, the PAPUC approved the recovery of storm damage costs incurred by PECO in January 2024, up to $ 23 million, subject to review for reasonableness and prudency in PECO’s next distribution rate case.
BGE Distribution Base Rate Case Proceedings
In February 2023, BGE filed its three-year cumulative multi-year plan for January 1, 2024 through December 31, 2026 to the MDPSC, which was approved in December 2023 and went into effect on January 1, 2024. The MDSPC awarded BGE electric revenue requirement increases of $ 41 million, $ 113 million, and $ 25 million with an approved ROE of 9.50 % in 2024, 2025, and 2026, respectively, and natural gas revenue requirement increases of $ 126 million, $ 62 million, and $ 41 million with an approved ROE of 9.45 % in 2024, 2025, and 2026,
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Combined Notes to Consolidated Financial Statements — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)

Note 2 — Regulatory Matters

respectively. The requested revenue requirement increases will be used to recover capital investments designed to increase the resilience of the electric and gas distribution systems and support Maryland's climate and regulatory initiatives.
The MDPSC also approved a portion of the requested 2021 and 2022 reconciliation amounts, which were recovered through separate electric and gas riders between March 2024 and February 2025. As such, the reconciliation amounts are not included in the approved revenue increases. The 2021 reconciliation amounts are $ 13 million and $ 7 million for electric and gas, respectively, and the 2022 reconciliation amounts are $ 39 million and $ 15 million for electric and gas, respectively. In April 2024, BGE filed with the MDPSC its request for recovery of the 2023 reconciliation amounts of $ 79 million and $ 73 million for electric and gas, respectively, with supporting testimony and schedules. In December 2025, the MDPSC authorized BGE to recover $ 31 million and $ 46 million for electric and gas, respectively, beginning in February 2026 and extending through December 2027, in the reconciliation rider. In addition to the amounts approved in the reconciliation rider, the MDPSC provided for additional regulatory assets related to minor storms of $ 24 million (to be recovered over 5 years) and the Baltimore City conduit of $ 4 million. Recovery of these two regulatory assets was requested in BGE's recent MDPSC rate case filing submitted on July 2, 2026.
Pepco District of Columbia Distribution Base Rate Case Proceedings
On April 13, 2023, Pepco filed an electric base rate case with the DCPSC (amended February 27, 2024) requesting a total revenue requirement increase of $ 186 million and an ROE of 10.50 %. The DCPSC issued an order approving the two-year cumulative multi-year plan on November 26, 2024, which included a total revenue requirement increase of $ 123 million with an ROE of 9.50 % effective January 1, 2025 through December 31, 2026. The DCPSC awarded Pepco electric incremental revenue requirement increases of $ 99 million and $ 24 million for 2025 and 2026, respectively. Subsequent to DCPSC approval of the order, interveners appealed the order on several grounds including that the DCPSC did not hold evidentiary hearings. On March 5, 2026, the District of Columbia Court of Appeals remanded the November 26, 2024, order back to the DCPSC to hold evidentiary hearings. On May 8, 2026, the DCPSC issued an order adopting a revised procedural schedule which additionally reaffirmed that current rates should remain in effect during the remand period and refunds for previous amounts collected are not required at this time. On June 30, 2026, the Commission issued a subsequent order revising the procedural schedule to update the due date for final briefs. Pepco is preparing for the proceeding and will continue to monitor developments.
Pepco Maryland Distribution Base Rate Case Proceedings
On May 16, 2023, Pepco filed an electric base rate case with the MDPSC (amended February 23, 2024) requesting a total revenue requirement increase of $ 111 million (before offsets) and an ROE of 10.50 %. The MDPSC issued an order on June 10, 2024 awarding Pepco a one-year multi-year plan for April 1, 2024 through March 31, 2025 which included an incremental revenue requirement increase of $ 45 million and an ROE of 9.50 %. The MDPSC did not adopt the requested revenue requirement increases of $ 80 million (before offsets), $ 51 million, and $ 14 million as filed for 2025, 2026, and the 2027 nine-month extension period, respectively. The MDPSC also approved the requested reconciliation amounts for the 12-month periods ending March 31, 2022, and March 31, 2023, which will be recovered through a rider between August 2024 through March 2026. As such, the reconciliation amounts are not included in the approved revenue requirement increases. The reconciliation amounts are $ 1 million and $ 7 million, for the 12-month periods ending March 31, 2022, and March 31, 2023, respectively. In July 2024, Pepco filed its request with the MDPSC, for recovery of the reconciliation amounts of $ 31 million for the 12-month period ended March 31, 2024, with supporting testimony and schedules. On March 31, 2026, the MDPSC issued an order authorizing Pepco to recover approximately $ 13 million through the reconciliation rider. This will be recovered through rates between May 2026 through April 2027. Additionally, the order disallowed the recovery of various assets. The order resulted in the write off of $ 11 million of Regulatory assets and $ 15 million of Property, plant and equipment with a total of $ 26 million recorded in Operations and maintenance expense.
DPL Maryland Distribution Base Rate Case Proceedings
On May 19, 2022, DPL filed an electric base rate case with the MDPSC requesting a total revenue requirement increase of $ 38 million based on an ROE of 10.25 %. On December 14, 2022, the MDPSC issued an order awarding DPL a total revenue requirement increase of $ 29 million with an ROE of 9.60 %. The order reflects a three-year cumulative multi-year plan for January 1, 2023 through December 31, 2025, with rates remaining in
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Note 2 — Regulatory Matters

effect subsequent to the multi-year plan period. The MDPSC awarded DPL electric incremental revenue requirement increases of $ 17 million, $ 6 million, and $ 6 million for 2023, 2024, and 2025, respectively.
DPL Delaware Distribution Base Rate Case Proceedings
On December 15, 2022, DPL filed an electric base rate case with the DEPSC (amended September 29, 2023) requesting a total revenue requirement increase of $ 39 million and an ROE of 10.50 %. On April 18, 2024, the DEPSC issued an order awarding DPL a total revenue requirement increase of $ 28 million with an ROE of 9.60 %, effective July 15, 2023. As part of the approved order, the DEPSC approved the Significant Storm Expense Rate Rider (Rider SSER) which will allow DPL to recover expenses associated with qualified storms. A qualified storm will be an individual storm for which DPL incurs expenses between $ 5  million and $ 15  million. The Rider SSER allows DPL to recover significant storm damage expenses for the previous 12-month period over a future 24-month period. For individual storm events for which DPL incurs expenses of more than $ 15  million, the future recovery period will be evaluated on a case-by-case basis and the unamortized balance will earn a return at DPL's authorized long-term cost of debt. The Rider SSER will have an annual true-up filing, subject to DEPSC review and approval.
ACE New Jersey Distribution Base Rate Case Proceedings
On November 21, 2024, ACE filed an electric base rate case with the NJBPU requesting a total revenue requirement increase of $ 109 million, before NJ sales and use tax, and an ROE of 10.70 %. On November 21, 2025, the NJBPU issued an order awarding ACE an electric revenue requirement increase, before NJ sales and use tax, of $ 54 million effective December 1, 2025, with an ROE of 9.60 %. In addition, the NJBPU approved the recovery through a regulatory asset of work stoppage costs that were incurred by ACE in 2023 of $ 38 million.
Transmission Formula Rates
The Utility Registrants' transmission rates are each established based on a FERC-approved formula. ComEd, BGE, Pepco, DPL, and ACE are required to file an annual update to the FERC-approved formula on or before May 15, and PECO is required to file on or before May 31, with the resulting rates effective on June 1 of the same year. The annual update for ComEd is based on prior year actual costs and current year projected capital additions (initial year revenue requirement). The 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 ComEd, PECO, BGE, Pepco, DPL, and ACE also reconciles any differences between the actual costs and actual revenues for the calendar year (annual reconciliation).
For 2026, the following increases/(decreases) were included in the Utility Registrants' electric transmission formula rate updates:

Registrant (a)
Initial Revenue Requirement Increase (Decrease) Annual Reconciliation (Decrease) Increase Total Revenue Requirement (Decrease) Increase (b)
Allowed Return on Rate Base (c)
Allowed ROE (d)

ComEd $ 31   $ ( 52 ) $ ( 21 ) 8.15   % 11.50   %
PECO $ 20   $ 20   $ 40   7.62   % 10.35   %
BGE $ 16   $ ( 40 ) $ ( 30 ) (e) 7.51   % 10.50   %
Pepco $ 12   $ ( 21 ) $ ( 9 ) 7.72   % 10.50   %
DPL $ 3   $ 1   $ 4   7.53   % 10.50   %
ACE $ 1   $ 16   $ 17   7.26   % 10.50   %

__________
(a) All rates are effective June 1, 2026 - May 31, 2027, 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.
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Note 2 — Regulatory Matters

(d) The rate of return on common equity for each Utility Registrant includes a 50 -basis-point incentive adder for being a voluntary member of an RTO. Recently passed legislation in Maryland and New Jersey requires utilities to become a member of an RTO.
(e) The decrease in BGE's transmission revenue requirement includes a $ 6 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 (2024-2027 Grid Plan), also filed on January 17, covering planned investments on the electric distribution system within ComEd’s service area through 2027. Costs incurred during each year of the MRP are subject to ICC review and the plan’s revenue requirement for each year will be reconciled with the actual costs that the ICC determines are prudently and reasonably incurred for that year. The reconciliation is subject to adjustment for certain costs, including a limitation on recovery of costs that are more than 105 % of certain costs in the previously approved MRP revenue requirement, absent a modification of the rate plan itself. Thus, for example, the rate adjustments necessary to reconcile 2024 revenues to ComEd’s actual 2024 costs incurred would take effect in January 2026 after the ICC’s review during 2025.
On December 14, 2023, the ICC issued a final order. The ICC rejected ComEd’s 2024-2027 Grid Plan as non-compliant with certain requirements of CEJA and required ComEd to file a revised 2024-2027 Grid Plan. On January 10, 2024, ComEd filed an appeal in the Illinois Appellate Court of portions of the ICC's December 2023 order, including but not limited to the allowed ROE, 50 % equity ratio, and denial of a return on ComEd’s pension asset. There is no deadline by when the appellate court must rule. On March 13, 2024, ComEd filed its Refiled 2024-2027 Grid Plan with supporting testimony and schedules with the ICC and subsequently on March 15, 2024, ComEd also filed a petition to adjust its MRP to authorize increased rates consistent with the Refiled 2024-2027 Grid Plan. On December 19, 2024, the ICC approved the Refiled 2024-2027 Grid Plan and adjusted the approved MRP with rates effective on January 1, 2025. The final approved MRP, as adjusted, which reflects the Refiled Grid Plan, resulted in a total cumulative revenue requirement increase of $ 1.045 billion over the 2024-2027 plan years and remains subject to annual reconciliations in accordance with CEJA. ComEd filed timely requests for rehearing and an appeal of the MRP order, again limited to the issues on which rehearing of the December 2023 order was denied, including the allowed ROE, 50 % equity ratio, and denial of a return on ComEd's pension asset.
On January 16, 2026, ComEd filed a multi-year integrated grid plan (2028-2031 Grid Plan), seeking approval for planned investments on the electric distribution system within ComEd's service area in 2028-2031. The ICC must issue an order by December 15, 2026.
Carbon Mitigation Credit
CEJA establishes decarbonization requirements for Illinois as well as programs to support the retention and development of emissions-free sources of electricity. ComEd is required to purchase CMCs from participating nuclear power generating facilities between June 1, 2022 and May 31, 2027. The price to be paid for each CMC was established through a competitive bidding process that included consumer-protection measures that capped the maximum acceptable bid amount and a formula that reduces CMC prices by an energy price index, the base residual auction capacity price in the ComEd zone of PJM, and the monetized value of any federal tax credit or other subsidy if applicable. On October 31, 2025, the seller provided notification to ComEd and the IPA that it has reflected on its 2024 federal tax return $ 804 million of nuclear production tax credits associated with its
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Note 2 — Regulatory Matters

participating nuclear power generating facilities. These amounts will be collected from the seller through an adjustment to the CMC price to be paid by ComEd and returned to customers in 2026. As of December 31, 2025, Exelon and ComEd's Consolidated Balance Sheets reflected these amounts as a receivable from the seller with an offsetting balance within the Carbon mitigation credit regulatory liability. These adjustments had no net impact on Exelon and ComEd’s Consolidated Statements of Operations and Comprehensive Income. The seller has not provided notification to ComEd or the IPA that any subsidies or tax credits, such as nuclear production tax credits, have been monetized for 2025. The consumer protection measures contained in CEJA will result in net payments to ComEd ratepayers if the energy index, the capacity price and applicable federal tax credits or subsidy exceed the CMC contract price. Beginning with the June 2022 monthly billing period, ComEd began issuing credits and/or charges to its retail customers under its CMC rider, the Rider Carbon-Free Resource Adjustment (Rider CFRA). A regulatory asset or liability is recorded for the difference between ComEd's costs associated with the procurement of CMCs from participating nuclear power generating facilities and revenues received from customers. The balance of the asset as of June 30, 2026 is $ 150 million.

On February 2, 2024, ComEd filed a petition with the ICC to initiate the reconciliation proceeding for the costs incurred in connection with the procurement of CMC’s during the delivery year beginning June 1, 2022 and extending through May 31, 2023. While both Staff and the Administrative Law Judge's proposed order supported ComEd’s proposed reconciliation adjustment, on September 4, 2025, the ICC issued its final order rejecting the proposed reconciliation adjustment. Specifically, the order disallowed portions of the administrative costs as well as a portion of ComEd's interest costs on the balance of credit extended to customers under the applicable tariff that were not yet funded by payments from the generator. The CMC costs themselves were not disallowed. The order resulted in an immaterial impact to the financial statements and on October 3, 2025 ComEd filed its Application for Rehearing. On October 16, 2025, the ICC denied ComEd's Application. On October 17, 2025, ComEd filed its appeal with the Illinois Appellate Court for review of the ICC's order and its denial of rehearing.
Energy Efficiency
CEJA extends ComEd’s current cumulative annual energy efficiency MWh savings goals through 2040, adds expanded electrification measures to those goals, increases low-income commitments, and adds a new performance adjustment to the energy efficiency formula rate. ComEd expects its annual spend to increase through 2040 to achieve these energy efficiency MWh savings goals, which is deferred as a separate regulatory asset that is recovered through the energy efficiency formula rate over the weighted average useful life, as approved by the ICC, of the related energy efficiency measures.
Energy Efficiency Formula Rate (Exelon and ComEd). In 2026, Illinois enacted the CRGA, which makes certain changes to the energy efficiency framework established under CEJA.
CRGA modifies the manner in which ComEd’s energy efficiency savings goals are calculated by establishing a flat incremental annual savings requirement that applies indefinitely. CRGA also increases energy efficiency budget and low‑income commitments from levels established under CEJA, expands the categories of savings that may be credited toward annual goals, and revises the return on equity applicable to the energy efficiency regulatory asset to align with the distribution return on equity.
ComEd filed its annual energy efficiency formula rate update with the ICC on May 29, 2026. The filing establishes the revenue requirement used to set the rates that will take effect in January 2027, subject to the ICC's review and approval. The requested revenue requirement update is based on a reconciliation of the 2025 actual costs plus projected 2027 expenditures.

Initial Revenue Requirement Increase Annual Reconciliation Decrease Total Revenue Requirement Decrease Requested Return on Rate Base (a)
Requested ROE
$ 28   $ ( 56 ) $ ( 28 ) 6.62   % 8.905   %

__________
(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 6.62 % inclusive of an allowed ROE of 8.905 %. For the 2025 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 7.67 % inclusive of an allowed ROE of 11.0 %, 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.

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Note 2 — Regulatory Matters

Beginning in 2027, ComEd expects that implementation of CRGA may result in higher annual energy efficiency spending. Incremental costs incurred in advance of recovery are expected to be deferred as a regulatory asset and recovered through ComEd’s energy efficiency formula rate over the weighted‑average useful life of the related measures, subject to approval by the Illinois Commerce Commission.
Maryland Regulatory Matters
Summer and Winter Rate Mitigation (Exelon, BGE, PHI, Pepco, and DPL). As part of the passing of the Next Generation Energy Act of 2025 by the Maryland General Assembly, the MDPSC issued an order on June 26, 2025, to implement the Legislative Energy Relief Refund program under which bill credits were distributed to residential customers based on their consumption of electricity supply that was subject to the renewable energy portfolio standard. On July 24, 2025, the MDPSC issued an order accepting BGE, Pepco, and DPL's proposal for the implementation of the program. As a result, BGE, Pepco, and DPL received $ 49  million, $ 21  million, and $ 8  million, respectively, from the MDPSC on February 3, 2026. These amounts were used to reduce residential customer account receivable balances within the first quarter of 2026.
Maryland Utility Relief Act (Exelon, BGE, PHI, Pepco, and DPL). On May 12, 2026, the Governor of Maryland signed into law legislation that addresses several matters pertaining to electric and gas utilities, including a moratorium on rate cases with forecasted test years until April 1, 2027. Additionally, BGE, Pepco and DPL are required to participate as a member in an RTO effective July 1, 2026, which resulted in a complaint filed on July 2, 2026 against Maryland Transmission Operators, including BGE, Pepco, and DPL, at FERC for the removal of the 50 -basis-point incentive adder in the transmission formula rates. The final outcome and resolution of the complaint filing cannot be predicted and the results are not expected to be material to Exelon, BGE, PHI, Pepco, and DPL financial statements.
Delaware Regulatory Matters
Delaware Senate Bill 326 (Exelon, PHI, and DPL). On July 13, 2026, the Governor of Delaware signed into law legislation that addresses several matters pertaining to public utility companies. As part of the law, DPL’s non-mandatory capital spend eligible to be recovered in rates will be limited to $ 70 million in each of the years ended 2026 and 2027 unless the spend falls within an exception or the commission orders otherwise. Further, beginning in 2028, DPL’s non-mandatory capital spend eligible to be recovered in rates shall not exceed 5 % of DPL’s rate base approved in its most recent base rate case. The legislation also modifies the timing of interim rate recovery in base rate case proceedings. If the DEPSC has not issued a decision within 7 months of a filing, DPL may implement 50 % of the proposed rate increase, subject to refund. If no decision has been issued after 12 months, DPL may implement 75 % of the proposed increase, also subject to refund. DPL is continuing to evaluate the overall potential impacts of the legislation and will continue to monitor related regulatory developments.
New Jersey Regulatory Matters
New Jersey Repeal RTO Adder Bill (Exelon, PHI, and ACE). On July 7, 2026, the Governor of New Jersey signed into law legislation that addresses several matters pertaining to electric utility companies. As part of the legislation ACE is required to participate as a member in an RTO effective January 1, 2027, which could result in a complaint filed for the removal of the 50 -basis-point incentive adder in the transmission formula rates.
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Note 2 — Regulatory Matters

Other Federal Regulatory Matters
PJM Cost Allocation Methodology (All Registrants). On March 6, 2026, FERC issued an order requiring the removal of the de minimis threshold exemption in the calculation of the cost responsibility of certain transmission reliability upgrade costs allocated to the rate zones of PJM Transmission Owners, including the Utility Registrants. FERC further ordered PJM to recalculate historical cost allocations for the period beginning June 18, 2015, and to pass through additional charges or payments to PJM customers, including Utility Registrants, as applicable, with interest within 90 days. On April 29, 2026, the time for those calculations was extended until further order from FERC. The Utility Registrants expect to recover any incremental charges incurred or reimburse any payments received through prospective electric customer rates. On April 6, 2026, a number of parties filed requests for rehearing or clarification, which were denied by operation of law on May 7, 2026. On May 12, 2026, PJM Transmission Owners, including Exelon, on behalf of the Utility Registrants, filed a petition for review at the United States Court of Appeals for the D.C. Circuit.
The final impacts of the decision cannot be predicted and the results, while not reasonably estimable at this time, could be material to the financial statements.
Regulatory Assets and Liabilities
The Utility Registrants' regulatory assets and liabilities have not changed materially since December 31, 2025, unless noted below. See Note 2 — Regulatory Matters of the 2025 Form 10-K for additional information on the specific regulatory assets and liabilities.
ComEd. Regulatory assets increased $ 223 million primarily due to an increase of $ 150 million in the Carbon mitigation credit regulatory asset. Regulatory liabilities decreased $ 72 million primarily due to a decrease of $ 670 million in the Carbon mitigation credit regulatory liability, partially offset by an increase of $ 325 million in the Decommissioning the Regulatory Agreement Units regulatory liability.
PECO. Regulatory assets increased $ 151  million primarily due to an increase of $ 102  million in the Deferred income taxes regulatory asset. Regulatory liabilities increased $ 189  million primarily due to an increase of $ 200  million in the Decommissioning the Regulatory Agreement Units.
BGE. Regulatory assets decreased $ 104  million primarily due to a decrease of $ 52  million in the Electric energy and natural gas costs regulatory asset and a decrease of $ 47  million in the Energy efficiency and demand response programs regulatory asset. Regulatory liabilities decreased $ 33  million primarily due to a decrease of $ 36  million in the Deferred income taxes regulatory liability.
Pepco. Regulatory assets decreased $ 34  million primarily due to a decrease of $ 34  million in the Energy efficiency and demand response programs regulatory asset. Regulatory liabilities increased $ 12  million primarily due to an increase of $ 23  million in the Removal costs regulatory liability, partially offset by a decrease of $ 17  million in the Deferred income taxes regulatory liability.
DPL. Regulatory assets increased $ 11  million primarily due to an increase of $ 12  million in the Electric energy and natural gas costs regulatory asset and an increase of $ 10  million in the Removal costs regulatory asset, partially offset by a decrease of $ 17  million in the Energy efficiency and demand response programs regulatory asset.
ACE. Regulatory assets increased $ 11  million primarily due to an increase of $ 34  million in the Energy efficiency and demand response programs regulatory asset and an increase of $ 23  million in the Deferred storm costs regulatory asset, partially offset by a decrease of $ 38  million in the Under-recovered revenue decoupling regulatory asset. Regulatory liabilities increased $ 46  million primarily due to an increase of $ 34  million in the Zero emissions credit regulatory liability and an increase of $ 25  million in the Electric energy and natural gas costs regulatory liability, partially offset by a decrease of $ 10  million in the Transmission formula rate annual reconciliations regulatory liability.
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(Dollars in millions, except per share data, unless otherwise noted)

Note 2 — Regulatory Matters

Capitalized Ratemaking Amounts Not Recognized
The following table presents authorized amounts capitalized for ratemaking purposes related to earnings on shareholders' investment that are not recognized for financial reporting purposes in the Registrants' Consolidated Balance Sheets. These amounts will be recognized as revenues in the related Consolidated Statements of Operations and Comprehensive Income in the periods they are billable to the Utility Registrants' customers. PECO had no related amounts at June 30, 2026 and December 31, 2025.

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

June 30, 2026 $ 72   $ 10   $ 34   $ 28   $ 12   $ —   $ 16  

December 31, 2025 98   12   47   39   22   1   16  

__________
(a) For the six months ended June 30, 2026, reflects ComEd's unrecognized equity returns earned for ratemaking purposes on its electric distribution rate, distributed generation, and energy efficiency regulatory assets. For the year ended December 31, 2025, reflects ComEd's unrecognized equity returns earned for ratemaking purposes on its electric distribution rates and distributed generation regulatory assets.
(b) BGE's amount capitalized for ratemaking purposes primarily relates to 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.

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 3 — Revenue from Contracts with Customers of the 2025 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 3 — Revenue from Contracts with Customers of the 2025 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 six months ended June 30, 2026 and 2025. At June 30, 2026 and December 31, 2025, ComEd's, PECO's, and BGE's contract liabilities were immaterial.
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Note 3 — Revenue from Contracts with Customers

Exelon (a)
PHI (a)
Pepco (a)
DPL (a)
ACE
Balance at December 31, 2025 $ 119   $ 119   $ 95   $ 12   $ 12  
Revenues recognized ( 1 ) ( 1 ) ( 1 ) —   —  
Balance at March 31, 2026 $ 118   $ 118   $ 94   $ 12   $ 12  
Revenues recognized ( 1 ) ( 1 ) ( 1 ) —   —  
Balance at June 30, 2026 $ 117   $ 117   $ 93   $ 12   $ 12  

Exelon (a)
PHI (a)
Pepco (a)
DPL (a)
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  

__________
(a) Revenues recognized in the three and six months ended June 30, 2026 and 2025, were included in the contract liabilities at December 31, 2025 and 2024, 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 June 30, 2026. This disclosure only includes contracts for which the total consideration is fixed and determinable at contract inception. The average contract term varies by customer type and commodity but ranges from one month to several years.
This disclosure excludes the Utility Registrants' gas and electric tariff sales contracts and transmission revenue contracts as they generally have an original expected duration of one year or less and, therefore, do not contain any future, unsatisfied performance obligations to be included in this disclosure. This disclosure also excludes transmission service agreements as the total consideration is not fixed and determinable at contract inception.

Year Exelon PHI Pepco DPL ACE
2026 $ 3   $ 3   $ 3   $ —   $ —  
2027 6   6   5   1   —  
2028 6   6   5   —   1  
2029 7   7   6   1   —  
2030 and thereafter 95   95   74   10   11  
Total $ 117   $ 117   $ 93   $ 12   $ 12  

Revenue Disaggregation
The Registrants disaggregate revenue recognized from contracts with customers into categories that depict how the nature, amount, timing, and uncertainty of revenue and cash flows are affected by economic factors. See Note 4 — Segment Information for the presentation of the Registrants' revenue disaggregation.
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Note 4 — Segment Information

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 six months ended June 30, 2026 and 2025 is as follows:
Three Months Ended June 30, 2026 and 2025

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

2026
Electric revenues $ 1,985   $ 941   $ 1,050   $ 1,670   $ —   $ ( 7 ) $ 5,639  
Natural gas revenues —   121   168   40   —   ( 1 ) 328  
Shared service and other revenues —   —   —   2   471   ( 473 ) —  
Total operating revenues $ 1,985   $ 1,062   $ 1,218   $ 1,712   $ 471   $ ( 481 ) $ 5,967  
2025
Electric revenues $ 1,836   $ 880   $ 849   $ 1,544   $ —   $ ( 13 ) $ 5,096  
Natural gas revenues —   120   180   33   —   ( 2 ) 331  
Shared service and other revenues —   —   —   2   468   ( 470 ) —  
Total operating revenues $ 1,836   $ 1,000   $ 1,029   $ 1,579   $ 468   $ ( 485 ) $ 5,427  
Less:
Purchased power
2026 $ 579   $ 352   $ 522   $ 679   $ —   $ —   $ 2,132  
2025 550   304   367   590   —   —   1,811  
Purchased fuel
2026 $ —   $ 37   $ 23   $ 19   $ —   $ —   $ 79  
2025 —   35   39   11   —   —   85  

Operating and maintenance
2026 $ 339   $ 232   $ 222   $ 337   $ 430   $ ( 174 ) $ 1,386  
2025 322   242   201   291   477   ( 212 ) 1,321  
Operating and maintenance from affiliates
2026 $ 110   $ 68   $ 71   $ 58   $ 11   $ ( 318 ) $ —  
2025 100   63   63   49   10   ( 285 ) —  
Depreciation and amortization
2026 $ 416   $ 125   $ 166   $ 245   $ 16   $ —   $ 968  

62

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

Note 4 — Segment Information

2025 387   112   154   233   16   —   902  
Taxes other than income taxes
2026 $ 107   $ 62   $ 96   $ 145   $ 13   $ —   $ 423  
2025 97   54   85   136   11   —   383  
(Gain) on sale of assets
2026 $ —   $ —   $ —   $ —   $ —   $ —   $ —  
2025 —   —   —   ( 2 ) —   —   ( 2 )
Interest expense, net (c)

2026 $ 140   $ 70   $ 68   $ 107   $ 183   $ —   $ 568  
2025 128   57   61   102   176   —   524  
Interest expense to affiliates, net (c)

2026 $ 3   $ 2   $ —   $ 1   $ —   $ —   $ 6  
2025 3   3   —   1   —   —   7  
Other, net
2026 $ ( 41 ) $ ( 13 ) $ ( 22 ) $ ( 20 ) $ ( 5 ) $ 11   $ ( 90 )
2025 ( 31 ) ( 10 ) ( 11 ) ( 17 ) ( 8 ) 12   ( 65 )
Income Taxes
2026 $ 83   $ 8   $ 17   $ 32   $ ( 41 ) $ —   $ 99  
2025 52   4   15   42   ( 43 ) —   70  
Net income (loss) attributable to common shareholders
2026 $ 249   $ 119   $ 55   $ 109   $ ( 136 ) $ —   $ 396  
2025 228   136   55   143   ( 171 ) —   391  
Supplemental segment information
Intersegment revenues (d)

2026 $ 2   $ 3   $ 3   $ 2   $ 469   $ ( 479 ) $ —  
2025 10   3   2   2   466   ( 483 ) —  
Capital Expenditures
2026 $ 786   $ 495   $ 385   $ 504   $ 30   $ —   $ 2,200  
2025 599   408   398   595   13   —   2,013  

__________
(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) :

2026
Electric revenues $ 859   $ 414   $ 401   $ —   $ ( 4 ) $ 1,670  
Natural gas revenues —   40   —   —   —   40  
Shared service and other revenues —   —   —   120   ( 118 ) 2  
Total operating revenues $ 859   $ 454   $ 401   $ 120   $ ( 122 ) $ 1,712  
2025
Electric revenues $ 776   $ 388   $ 384   $ —   $ ( 4 ) $ 1,544  
Natural gas revenues —   33   —   —   —   33  
Shared service and other revenues —   —   —   111   ( 109 ) 2  

63

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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 $ 776   $ 421   $ 384   $ 111   $ ( 113 ) $ 1,579  
Less:
Purchased power
2026 $ 316   $ 176   $ 187   $ —   $ —   $ 679  
2025 256   161   173   —   —   590  
Purchased fuel
2026 $ —   $ 19   $ —   $ —   $ —   $ 19  
2025 —   11   —   —   —   11  

Operating and maintenance
2026 $ 118   $ 62   $ 55   $ 102   $ —   $ 337  
2025 91   50   55   95   —   291  
Operating and maintenance from affiliates
2026 $ 72   $ 50   $ 44   $ 14   $ ( 122 ) $ 58  
2025 64   45   40   13   ( 113 ) 49  
Depreciation and amortization
2026 $ 114   $ 67   $ 63   $ 1   $ —   $ 245  
2025 107   63   62   1   —   233  
Taxes other than income taxes
2026 $ 113   $ 24   $ 3   $ 5   $ —   $ 145  
2025 109   20   3   4   —   136  
(Gain) on sale of assets
2026 $ —   $ —   $ —   $ —   $ —   $ —  
2025 ( 2 ) —   —   —   —   ( 2 )
Interest expense, net (c)

2026 $ 56   $ 26   $ 22   $ 3   $ —   $ 107  
2025 54   25   20   3   —   102  
Interest expense to affiliates, net (c)

2026 $ —   $ —   $ —   $ 1   $ —   $ 1  
2025 —   —   —   1   —   1  
Other, net
2026 $ ( 12 ) $ ( 4 ) $ ( 3 ) $ ( 1 ) $ —   $ ( 20 )
2025 ( 9 ) ( 4 ) ( 2 ) ( 2 ) —   ( 17 )
Income Taxes
2026 $ 17   $ 8   $ 8   $ ( 1 ) $ —   $ 32  
2025 22   11   9   —   —   42  
Net income (loss) attributable to common shareholders
2026 $ 65   $ 26   $ 22   $ ( 4 ) $ —   $ 109  
2025 84   39   24   ( 4 ) —   143  
Supplemental segment information
Intersegment revenues (d)

2026 $ 1   $ 2   $ 1   $ 119   $ ( 121 ) $ 2  
2025 1   2   —   111   ( 112 ) 2  
Capital Expenditures
2026 $ 232   $ 153   $ 118   $ 1   $ —   $ 504  

64

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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 229   121   91   154   —   595  

__________
(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.

Three Months Ended June 30, 2026
Revenues from contracts with customers ComEd PECO BGE PHI Pepco DPL ACE
Electric revenues
Residential $ 1,101   $ 601   $ 641   $ 867   $ 396   $ 230   $ 241  
Small commercial & industrial 527   157   108   180   49   66   65  
Large commercial & industrial 131   85   161   397   321   33   43  
Public authorities & electric railroads 12   9   8   20   11   4   5  
Other (a)
255   77   121   228   94   78   58  
Total electric revenues (b)
$ 2,026   $ 929   $ 1,039   $ 1,692   $ 871   $ 411   $ 412  
Natural gas revenues
Residential $ —   $ 84   $ 93   $ 18   $ —   $ 18   $ —  
Small commercial & industrial —   29   17   9   —   9   —  
Large commercial & industrial —   —   48   1   —   1   —  
Transportation —   6   —   4   —   4   —  
Other (c)
—   1   7   8   —   8   —  
Total natural gas revenues (d)
$ —   $ 120   $ 165   $ 40   $ —   $ 40   $ —  
Total revenues from contracts with customers $ 2,026   $ 1,049   $ 1,204   $ 1,732   $ 871   $ 451   $ 412  
Other revenues
Revenues from alternative revenue programs $ ( 55 ) $ 5   $ 5   $ ( 24 ) $ ( 15 ) $ 2   $ ( 11 )
Other electric revenues (e)
14   7   7   4   3   1   —  
Other natural gas revenues (e)
—   1   2   —   —   —   —  

Total other revenues $ ( 41 ) $ 13   $ 14   $ ( 20 ) $ ( 12 ) $ 3   $ ( 11 )
Total revenues for reportable segments $ 1,985   $ 1,062   $ 1,218   $ 1,712   $ 859   $ 454   $ 401  

65

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

Note 4 — Segment Information

Three Months Ended June 30, 2025
Revenues from contracts with customers ComEd PECO BGE PHI Pepco DPL ACE
Electric revenues
Residential $ 1,094   $ 555   $ 497   $ 780   $ 348   $ 210   $ 222  
Small commercial & industrial 553   155   90   168   48   64   56  
Large commercial & industrial 177   75   140   370   292   31   47  
Public authorities & electric railroads 12   10   8   22   12   5   5  
Other (a)
224   77   118   233   91   77   67  
Total electric revenues (b)
$ 2,060   $ 872   $ 853   $ 1,573   $ 791   $ 387   $ 397  
Natural gas revenues
Residential $ —   $ 79   $ 108   $ 17   $ —   $ 17   $ —  
Small commercial & industrial —   31   23   8   —   8   —  
Large commercial & industrial —   —   46   1   —   1   —  
Transportation —   8   —   4   —   4   —  
Other (c)
—   2   7   3   —   3   —  
Total natural gas revenues (d)
$ —   $ 120   $ 184   $ 33   $ —   $ 33   $ —  
Total revenues from contracts with customers $ 2,060   $ 992   $ 1,037   $ 1,606   $ 791   $ 420   $ 397  
Other revenues
Revenues from alternative revenue programs $ ( 234 ) $ 1   $ ( 13 ) $ ( 29 ) $ ( 16 ) $ —   $ ( 13 )
Other electric revenues (e)
10   7   4   2   1   1   —  
Other natural gas revenues (e)
—   —   1   —   —   —   —  

Total other revenues $ ( 224 ) $ 8   $ ( 8 ) $ ( 27 ) $ ( 15 ) $ 1   $ ( 13 )
Total revenues for reportable segments $ 1,836   $ 1,000   $ 1,029   $ 1,579   $ 776   $ 421   $ 384  

__________
(a) Includes transmission revenue from PJM, wholesale electric revenue, and mutual assistance revenue.
(b) Includes operating revenues from affiliates in 2026 and 2025 respectively of:
• $ 2  million, $ 10  million at ComEd
• $ 2  million, $ 3  million at PECO
• $ 2  million , $ 1  million at BGE
• $ 2  million, $ 2  million at PHI
• $ 1  million, $ 1  million at Pepco
• $ 2  million, $ 2  million at DPL
• $ 1  million, less than $1 million at ACE
(c) Includes revenues from off-system natural gas sales.
(d) Includes operating revenues from affiliates in 2026 and 2025 respectively of:
• $ 1  million, less than $1 million at PECO
• $ 1  million, $ 1  million at BGE
(e) Includes late payment charge revenues

Six Months Ended June 30, 2026 and 2025

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

2026
Electric revenues $ 3,898   $ 2,023   $ 2,295   $ 3,580   $ —   $ ( 23 ) $ 11,773  
Natural gas revenues —   531   751   157   —   ( 3 ) 1,436  
Shared service and other revenues —   —   —   5   959   ( 964 ) —  
Total operating revenues $ 3,898   $ 2,554   $ 3,046   $ 3,742   $ 959   $ ( 990 ) $ 13,209  

66

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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
Electric revenues $ 3,901   $ 1,836   $ 1,861   $ 3,232   $ —   $ ( 26 ) $ 10,804  
Natural gas revenues —   497   722   120   —   ( 2 ) 1,337  
Shared service and other revenues —   —   —   5   934   ( 939 ) —  
Total operating revenues $ 3,901   $ 2,333   $ 2,583   $ 3,357   $ 934   $ ( 967 ) $ 12,141  
Less:
Purchased power
2026 $ 1,031   $ 803   $ 1,152   $ 1,529   $ —   $ —   $ 4,515  
2025 1,239   665   818   1,273   —   —   3,995  
Purchased fuel
2026 $ —   $ 198   $ 201   $ 73   $ —   $ —   $ 472  
2025 —   176   198   49   —   —   423  

Operating and maintenance
2026 $ 674   $ 502   $ 481   $ 702   $ 878   $ ( 385 ) $ 2,852  
2025 645   507   443   586   904   ( 417 ) 2,668  
Operating and maintenance from affiliates
2026 $ 212   $ 134   $ 138   $ 118   $ 23   $ ( 625 ) $ —  
2025 200   124   125   103   22   ( 574 ) —  
Depreciation and amortization
2026 $ 820   $ 247   $ 334   $ 491   $ 28   $ —   $ 1,920  

67

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

Note 4 — Segment Information

2025 767   221   318   467   32   —   1,805  
Taxes other than income taxes
2026 $ 212   $ 131   $ 200   $ 296   $ 27   $ —   $ 866  
2025 196   115   181   276   20   —   788  
(Gain) on sale of assets
2026 $ —   $ —   $ —   $ —   $ —   $ —   $ —  
2025 —   —   —   ( 1 ) —   —   ( 1 )
Interest expense, net (c)

2026 $ 272   $ 139   $ 129   $ 213   $ 363   $ —   $ 1,116  
2025 253   117   120   201   337   —   1,028  
Interest expense to affiliates, net (c)

2026 $ 7   $ 5   $ —   $ 2   $ —   $ ( 2 ) $ 12  
2025 7   7   —   2   —   ( 4 ) 12  
Other, net
2026 $ ( 73 ) $ ( 25 ) $ ( 38 ) $ ( 39 ) $ ( 6 ) $ 22   $ ( 159 )
2025 ( 53 ) ( 18 ) ( 20 ) ( 35 ) ( 19 ) 28   ( 117 )
Income taxes
2026 $ 184   $ 23   $ 96   $ 79   $ ( 82 ) $ —   $ 300  
2025 117   17   85   99   ( 78 ) —   240  
Net income (loss) attributable to common shareholders
2026 $ 559   $ 397   $ 353   $ 278   $ ( 272 ) $ —   $ 1,315  
2025 530   402   315   337   ( 284 ) —   1,300  
Supplemental segment information
Intersegment revenues (d)

2026 $ 13   $ 7   $ 5   $ 5   $ 954   $ ( 984 ) $ —  
2025 17   6   4   5   929   ( 961 ) —  
Capital expenditures
2026 $ 1,671   $ 964   $ 822   $ 1,062   $ 39   $ —   $ 4,558  
2025 1,189   832   804   1,108   26   —   3,959  
Total assets
June 30, 2026 $ 49,947   $ 20,495   $ 18,173   $ 30,008   $ 6,086   $ ( 4,204 ) $ 120,505  
December 31, 2025 48,285   19,362   17,184   29,715   6,170   ( 4,146 ) 116,570  

__________
(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) :

2026
Electric revenues $ 1,849   $ 919   $ 822   $ —   $ ( 10 ) $ 3,580  
Natural gas revenues —   157   —   —   —   157  

68

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

Note 4 — Segment Information

Shared service and other revenues —   —   —   229   ( 224 ) 5  
Total operating revenues $ 1,849   $ 1,076   $ 822   $ 229   $ ( 234 ) $ 3,742  
2025
Electric revenues $ 1,635   $ 849   $ 757   $ —   $ ( 9 ) $ 3,232  
Natural gas revenues —   120   —   —   —   120  
Shared service and other revenues —   —   —   217   ( 212 ) 5  
Total operating revenues $ 1,635   $ 969   $ 757   $ 217   $ ( 221 ) $ 3,357  
Less:
Purchased power
2026 $ 727   $ 410   $ 392   $ —   $ —   $ 1,529  
2025 574   370   329   —   —   1,273  
Purchased fuel
2026 $ —   $ 73   $ —   $ —   $ —   $ 73  
2025 —   49   —   —   —   49  

Operating and maintenance
2026 $ 270   $ 134   $ 105   $ 193   $ —   $ 702  
2025 187   110   106   183   —   586  
Operating and maintenance from affiliates
2026 $ 139   $ 97   $ 87   $ 29   $ ( 234 ) $ 118  
2025 126   91   79   28   ( 221 ) 103  
Depreciation and amortization
2026 $ 228   $ 133   $ 128   $ 2   $ —   $ 491  
2025 212   126   127   2   —   467  
Taxes other than income taxes
2026 $ 231   $ 50   $ 5   $ 10   $ —   $ 296  
2025 222   41   5   8   —   276  
(Gain) on sale of assets
2026 $ —   $ —   $ —   $ —   $ —   $ —  
2025 ( 1 ) —   —   —   —   ( 1 )
Interest expense, net (c)

2026 $ 111   $ 53   $ 44   $ 5   $ —   $ 213  
2025 106   50   41   4   —   201  
Interest expense to affiliates, net (c)

2026 $ —   $ —   $ —   $ 2   $ —   $ 2  
2025 —   —   —   2   —   2  
Other, net
2026 $ ( 23 ) $ ( 8 ) $ ( 5 ) $ ( 3 ) $ —   $ ( 39 )
2025 ( 20 ) ( 8 ) ( 6 ) ( 1 ) —   ( 35 )
Income taxes
2026 $ 33   $ 31   $ 17   $ ( 2 ) $ —   $ 79  
2025 48   32   20   ( 1 ) —   99  
Net income (loss) attributable to common shareholders
2026 $ 133   $ 103   $ 49   $ ( 7 ) $ —   $ 278  
2025 181   108   56   ( 8 ) —   337  
Supplemental segment information
Intersegment revenues (d)

2026 $ 4   $ 4   $ 2   $ 229   $ ( 234 ) $ 5  
2025 4   4   1   217   ( 221 ) 5  

69

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

Note 4 — Segment Information

Capital expenditures
2026 $ 517   $ 300   $ 240   $ 5   $ —   $ 1,062  
2025 469   277   196   166   —   1,108  
Total assets
June 30, 2026 $ 12,951   $ 6,824   $ 5,795   $ 4,586   $ ( 148 ) $ 30,008  
December 31, 2025 12,728   6,789   5,632   4,602   ( 36 ) 29,715  

__________
(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.

Six Months Ended June 30, 2026
Revenues from contracts with customers ComEd PECO BGE PHI Pepco DPL ACE
Electric revenues
Residential $ 2,126   $ 1,326   $ 1,459   $ 1,960   $ 902   $ 559   $ 499  
Small commercial & industrial 1,011   329   238   373   103   137   133  
Large commercial & industrial 251   172   342   793   642   64   87  
Public authorities & electric railroads 23   17   17   40   21   9   10  
Other (a)
504   154   237   458   188   153   122  
Total electric revenues (b)
$ 3,915   $ 1,998   $ 2,293   $ 3,624   $ 1,856   $ 922   $ 851  
Natural gas revenues
Residential $ —   $ 369   $ 494   $ 92   $ —   $ 92   $ —  
Small commercial & industrial —   125   80   38   —   38   —  
Large commercial & industrial —   —   141   5   —   5   —  
Transportation —   26   —   10   —   10   —  
Other (c)
—   9   38   12   —   12   —  
Total natural gas revenues (d)
$ —   $ 529   $ 753   $ 157   $ —   $ 157   $ —  
Total revenues from contracts with customers $ 3,915   $ 2,527   $ 3,046   $ 3,781   $ 1,856   $ 1,079   $ 851  
Other revenues
Revenues from alternative revenue programs $ ( 46 ) $ 10   $ ( 18 ) $ ( 48 ) $ ( 14 ) $ ( 5 ) $ ( 29 )
Other electric revenues (e)
29   15   13   9   7   2   —  
Other natural gas revenues (e)
—   2   5   —   —   —   —  

Total other revenues $ ( 17 ) $ 27   $ —   $ ( 39 ) $ ( 7 ) $ ( 3 ) $ ( 29 )
Total revenues for reportable segments $ 3,898   $ 2,554   $ 3,046   $ 3,742   $ 1,849   $ 1,076   $ 822  

70

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

Note 4 — Segment Information

Six Months Ended June 30, 2025
Revenues from contracts with customers ComEd PECO BGE PHI Pepco DPL ACE
Electric revenues
Residential $ 2,087   $ 1,186   $ 1,145   $ 1,698   $ 772   $ 508   $ 418  
Small commercial & industrial 1,153   317   199   338   99   128   111  
Large commercial & industrial 472   159   284   738   581   60   97  
Public authorities & electric railroads 29   18   17   39   20   9   10  
Other (a)
461   153   230   454   176   148   134  
Total electric revenues (b)
$ 4,202   $ 1,833   $ 1,875   $ 3,267   $ 1,648   $ 853   $ 770  
Natural gas revenues
Residential $ —   $ 346   $ 486   $ 73   $ —   $ 73   $ —  
Small commercial & industrial —   117   86   28   —   28   —  
Large commercial & industrial —   —   142   4   —   4   —  
Transportation —   21   —   9   —   9   —  
Other (c)
—   12   31   6   —   6   —  
Total natural gas revenues (d)
$ —   $ 496   $ 745   $ 120   $ —   $ 120   $ —  
Total revenues from contracts with customers $ 4,202   $ 2,329   $ 2,620   $ 3,387   $ 1,648   $ 973   $ 770  
Other revenues
Revenues from alternative revenue programs $ ( 319 ) $ ( 8 ) $ ( 43 ) $ ( 32 ) $ ( 14 ) $ ( 5 ) $ ( 13 )
Other electric revenues (e)
18   11   5   2   1   1   —  
Other natural gas revenues (e)
—   1   1   —   —   —   —  

Total other revenues $ ( 301 ) $ 4   $ ( 37 ) $ ( 30 ) $ ( 13 ) $ ( 4 ) $ ( 13 )
Total revenues for reportable segments $ 3,901   $ 2,333   $ 2,583   $ 3,357   $ 1,635   $ 969   $ 757  

__________
(a) Includes transmission revenue from PJM, wholesale electric revenue, and mutual assistance revenue.
(b) Includes operating revenues from affiliates in 2026 and 2025 respectively of:
• $ 13 million, $ 17 million at ComEd
• $ 6  million, $ 5  million at PECO
• $ 4  million, $ 3  million at BGE
• $ 5  million, $ 5 million at PHI
• $ 4  million, $ 4  million at Pepco
• $ 4  million, $ 4 million at DPL
• $ 2  million, $ 1 million at ACE
(c) Includes revenues from off-system natural gas sales.
(d) Includes operating revenues from affiliates in 2026 and 2025 respectively of:
• $ 1 million, $ 1 million at PECO
• $ 1  million, $ 1 million at BGE
(e) Includes late payment charge revenues.

71

Table of Contents
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 June 30, 2026
Exelon ComEd (b)
PECO (b)(c)
BGE (d)
PHI Pepco DPL ACE
Balance at March 31, 2026 $ 522   $ 130   $ 160   $ 101   $ 131   $ 76   $ 24   $ 31  
Plus: Current period provision (benefit) for expected credit losses
46   ( 6 ) ( 1 ) 45   8   8   ( 1 ) 1  
Less: Write-offs, net of recoveries (a)
60   22   17   10   11   7   2   2  
Balance at June 30, 2026 $ 508   $ 102   $ 142   $ 136   $ 128   $ 77   $ 21   $ 30  

Three Months Ended June 30, 2025
Exelon ComEd PECO BGE PHI Pepco DPL ACE
Balance at March 31, 2025 $ 486   $ 125   $ 160   $ 72   $ 129   $ 69   $ 23   $ 37  
Plus: Current period provision (benefit) for expected credit losses
9   ( 4 ) 5   3   5   7   —   ( 2 )
Less: Write-offs, net of recoveries
30   ( 1 ) 11   9   11   7   2   2  
Balance at June 30, 2025 $ 465   $ 122   $ 154   $ 66   $ 123   $ 69   $ 21   $ 33  

_________
(a) Recoveries were not material to the Registrants.
(b) For ComEd and PECO, the increase in write-offs, net of recoveries when comparing to three months ended June 30, 2025, is primarily the result of increased disconnection activities.
(c) For PECO, the decrease in current period provision for expected credit losses when comparing to three months ended June 30, 2025, is primarily the result of decreased receivable balances.
(d) For BGE, the increase in current period provision for expected credit losses when comparing to three months ended June 30, 2025, is primarily the result of increased receivable balances.

Six Months Ended June 30, 2026
Exelon ComEd (b)
PECO (b)(c)
BGE (d)
PHI Pepco DPL (e)
ACE (f)

Balance at December 31, 2025 $ 435   $ 115   $ 137   $ 68   $ 115   $ 69   $ 19   $ 27  
Plus: Current period provision for expected credit losses
192   26   37   88   41   25   7   9  
Less: Write-offs, net of recoveries (a)
119   39   32   20   28   17   5   6  
Balance at June 30, 2026 $ 508   $ 102   $ 142   $ 136   $ 128   $ 77   $ 21   $ 30  

Six Months Ended June 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
142   29   46   26   41   24   10   7  
Less: Write-offs, net of recoveries
83   16   25   16   26   14   6   6  
Balance at June 30, 2025 $ 465   $ 122   $ 154   $ 66   $ 123   $ 69   $ 21   $ 33  

_________
(a) Recoveries were not material to the Registrants.
(b) For ComEd and PECO, the increase in write-offs, net of recoveries when comparing to six months ended June 30, 2025, is primarily the 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

(c) For PECO, the decrease in current provision for expected credit losses when comparing to six months ended June 30, 2025, is primarily the result of decreased receivable balances.
(d) For BGE, the increase in current provision for expected credit losses when comparing to six months ended June 30, 2025 , is primarily the result of increased receivable balances.
(e) For DPL, the decrease in current provision for expected credit losses when comparing to six months ended June 30, 2025, is primarily the result of favorable customer behavior.
(f) For ACE, the increase in current provision for expected credit losses when comparing to six months ended June 30, 2025, is primarily the result of increased aging of receivables.
The following tables present the rollforward of Allowance for Credit Losses on Other Accounts Receivable.

Three Months Ended June 30, 2026
Exelon ComEd PECO BGE PHI Pepco DPL ACE (b)

Balance at March 31, 2026 $ 102   $ 27   $ 22   $ 4   $ 49   $ 26   $ 11   $ 12  
Plus: Current period provision (benefit) for expected credit losses
1   —   ( 2 ) 1   2   ( 1 ) 1   2  
Less: Write-offs, net of recoveries (a)
9   2   2   2   3   —   1   2  
Balance at June 30, 2026 $ 94   $ 25   $ 18   $ 3   $ 48   $ 25   $ 11   $ 12  

Three Months Ended June 30, 2025
Exelon ComEd PECO BGE PHI Pepco DPL ACE
Balance at March 31, 2025 $ 113   $ 34   $ 22   $ 6   $ 51   $ 27   $ 9   $ 15  
Plus: Current period (benefit) provision for expected credit losses
( 7 ) ( 3 ) ( 2 ) ( 3 ) 1   1   —   —  
Less: Write-offs, net of recoveries
( 1 ) —   1   ( 2 ) —   —   —   —  
Balance at June 30, 2025 $ 107   $ 31   $ 19   $ 5   $ 52   $ 28   $ 9   $ 15  

_________
(a) Recoveries were not material to the Registrants.
(b) For ACE, the increase in current provision for expected credit losses when comparing to three months ended June 30, 2025, is primarily the result of increased aging of receivables.

Six Months Ended June 30, 2026
Exelon ComEd PECO BGE PHI Pepco DPL (b)
ACE
Balance at December 31, 2025 $ 94   $ 23   $ 18   $ 4   $ 49   $ 26   $ 10   $ 13  
Plus: Current period provision for expected credit losses
18   8   4   2   4   —   2   2  
Less: Write-offs, net of recoveries (a)
18   6   4   3   5   1   1   3  
Balance at June 30, 2026 $ 94   $ 25   $ 18   $ 3   $ 48   $ 25   $ 11   $ 12  

Six Months Ended June 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
8   ( 1 ) 7   ( 2 ) 4   1   —   3  
Less: Write-offs, net of recoveries
8   2   6   ( 1 ) 1   —   —   1  
Balance at June 30, 2025 $ 107   $ 31   $ 19   $ 5   $ 52   $ 28   $ 9   $ 15  

_________
(a) Recoveries were not material to the Registrants.
(b) For DPL, the increase in current provision for expected credit losses when comparing to six months ended June 30, 2025, is primarily due to changes in risk profile.
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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 June 30, 2026 and December 31, 2025.

Unbilled customer revenues (a)

Exelon ComEd PECO BGE PHI Pepco DPL ACE
June 30, 2026 $ 1,073   $ 367   $ 211   $ 206   $ 289   $ 147   $ 67   $ 75  
December 31, 2025 1,231   301   278   325   327   155   100   72  

__________
(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 six months ended June 30, 2026 and 2025, 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
Six months ended June 30, 2026 $ 2,333   $ 571   $ 707   $ 325   $ 730   $ 472   $ 132   $ 126  
Six months ended June 30, 2025 2,054   464   598   375   617   383   126   108  

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 June 30, 2026 (a)(b)

Exelon ComEd PECO (c)
BGE
U.S. Federal statutory rate $ 104   21.0   % $ 70   21.0   % $ 26   21.0   % $ 15   21.0   %
Increase (decrease) due to:
State income taxes, net of Federal income tax benefit
31   6.3   25   7.5   ( 1 ) ( 0.8 ) 4   5.6  
Tax credits ( 2 ) ( 0.4 ) ( 2 ) ( 0.6 ) —   —   —   —  
Change in Unrecognized Tax Benefits
—   —   —   —   —   —   —   —  
Nontaxable or nondeductible items
5   0.9   —   —   1   0.3   1   1.2  
Other Adjustments
Plant Basis differences ( 22 ) ( 4.4 ) ( 4 ) ( 1.2 ) ( 16 ) ( 12.6 ) —   —  
Excess deferred tax
( 17 ) ( 3.4 ) ( 6 ) ( 1.7 ) ( 2 ) ( 1.6 ) ( 3 ) ( 4.2 )
Amortization of ITC, net deferred taxes
—   —   —   —   —   —   —   —  
Effective Tax Rate
$ 99   20.0   % $ 83   25.0   % $ 8   6.3   % $ 17   23.6   %

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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

Three Months Ended June 30, 2026 (a)(b)

PHI PEPCO DPL ACE
U.S. Federal statutory rate $ 30   21.0   % $ 17   21.0   % $ 7   21.0   % $ 6   21.0   %
Increase (decrease) due to:
State income taxes, net of Federal income tax benefit
9   6.4   5   6.1   3   8.8   2   5.7  
Tax credits —   —   —   —   —   —   —   —  
Change in Unrecognized Tax Benefits
—   —   —   —   —   —   —   —  
Nontaxable or nondeductible items
1   1.0   —   —   —   —   —   —  
Other Adjustments
Plant Basis differences ( 1 ) ( 0.7 ) ( 1 ) ( 1.2 ) —   —   —   —  
Excess deferred tax
( 7 ) ( 5.0 ) ( 4 ) ( 5.2 ) ( 2 ) ( 6.3 ) —   —  
Amortization of ITC, net deferred taxes
—   —   —   —   —   —   —   —  
Effective Tax Rate
$ 32   22.7   % $ 17   20.7   % $ 8   23.5   % $ 8   26.7   %

Three Months Ended June 30, 2025 (a)(b)

Exelon ComEd (d)
PECO (c)
BGE
U.S. Federal statutory rate $ 96   21.0   % $ 59   21.0   % $ 29   21.0   % $ 15   21.0   %
Increase (decrease) due to:
State income taxes, net of Federal income tax benefit
28   6.1   21   7.6   ( 2 ) ( 1.4 ) 4   5.9  
Tax credits ( 2 ) ( 0.4 ) ( 2 ) ( 0.7 ) —   —   ( 1 ) ( 1.4 )
Nontaxable or nondeductible items
1   0.2   ( 1 ) ( 0.4 ) 1   0.7   —   —  
Other Adjustments
Plant Basis differences ( 24 ) ( 5.2 ) ( 2 ) ( 0.7 ) ( 22 ) ( 16.0 ) ( 1 ) ( 1.4 )
Excess deferred tax
( 29 ) ( 6.4 ) ( 23 ) ( 8.2 ) ( 2 ) ( 1.4 ) ( 2 ) ( 2.7 )
Amortization of ITC, net deferred taxes
—   ( 0.1 ) —   —   —   —   —   —  
Effective Tax Rate
$ 70   15.2   % $ 52   18.6   % $ 4   2.9   % $ 15   21.4   %

Three Months Ended June 30, 2025 (a)(b)

PHI PEPCO DPL ACE
U.S. Federal statutory rate $ 39   21.0   % $ 22   21.0   % $ 10   21.0   % $ 7   21.0   %
Increase (decrease) due to:
State income taxes, net of Federal income tax benefit
13   7.0   6   5.7   3   5.0   2   6.3  
Tax credits ( 1 ) ( 0.5 ) —   —   —   —   —   —  
Nontaxable or nondeductible items
—   —   —   —   —   —   —   —  
Other Adjustments
Plant Basis differences ( 1 ) ( 0.5 ) ( 1 ) ( 0.9 ) —   —   —   —  
Excess deferred tax
( 8 ) ( 4.3 ) ( 5 ) ( 5.0 ) ( 2 ) ( 4.0 ) —   —  
Amortization of ITC, net deferred taxes
—   —   —   —   —   —   —   —  
Effective Tax Rate
$ 42   22.7   % $ 22   20.8   % $ 11   22.0   % $ 9   27.3   %

__________
(a) Positive amounts and percentages represent income tax expense. Negative amounts and percentages represent income tax benefit.
(b) Exelon and Registrants had no adjustments to the following disclosure categories: Foreign Tax Effects, Effects of Changes in Tax Law or Rates Enacted in the Current Period, Effects of Cross-Border Tax Laws, and Changes in Valuation Allowances.
(c) F or PECO, the lower effective tax rate is primarily related to state income taxes, net of federal income tax benefit and plant basis differences attributable to tax repair deductions.
(d) For ComEd, the lower effective tax rate is primarily due to CEJA which resulted in the acceleration of certain income tax benefits being provided to customers.
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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

Six Months Ended June 30, 2026 (a)(b)

Exelon ComEd PECO (c)
BGE
U.S. Federal statutory rate $ 339   21.0   % $ 156   21.0   % $ 88   21.0   % $ 94   21.0   %
Increase (decrease) due to:
State income taxes, net of Federal income tax benefit
95   5.9   55   7.4   ( 4 ) ( 1.0 ) 27   6.0  
Tax credits ( 5 ) ( 0.3 ) ( 3 ) ( 0.4 ) —   —   ( 1 ) ( 0.2 )
Change in Unrecognized Tax Benefits
( 17 ) ( 1.1 ) ( 2 ) ( 0.3 ) —   —   ( 1 ) ( 0.2 )
Nontaxable or nondeductible items
16   1.0   1   0.2   1   0.3   1   0.2  
Other Adjustments
Plant Basis differences ( 75 ) ( 4.6 ) ( 9 ) ( 1.2 ) ( 55 ) ( 13.1 ) ( 8 ) ( 1.8 )
Excess deferred tax
( 52 ) ( 3.2 ) ( 14 ) ( 1.9 ) ( 7 ) ( 1.7 ) ( 16 ) ( 3.6 )
Amortization of ITC, net deferred taxes
( 1 ) ( 0.1 ) —   —   —   —   —   —  
Effective Tax Rate
$ 300   18.6   % $ 184   24.8   % $ 23   5.5   % $ 96   21.4   %

Six Months Ended June 30, 2026 (a)(b)

PHI PEPCO DPL ACE
U.S. Federal statutory rate $ 75   21.0   % $ 35   21.0   % $ 28   21.0   % $ 14   21.0   %
Increase (decrease) due to:
State income taxes, net of Federal income tax benefit
23   6.4   10   6.0   9   6.7   5   7.6  
Tax credits ( 1 ) ( 0.3 ) —   —   —   —   —   —  
Change in Unrecognized Tax Benefits
—   —   —   —   —   —   —   —  
Nontaxable or nondeductible items
1   0.3   —   —   —   —   —   —  
Other Adjustments
Plant Basis differences ( 3 ) ( 0.8 ) ( 2 ) ( 1.2 ) ( 1 ) ( 0.8 ) —   —  
Excess deferred tax
( 16 ) ( 4.5 ) ( 10 ) ( 5.9 ) ( 5 ) ( 3.8 ) ( 2 ) ( 2.8 )
Amortization of ITC, net deferred taxes
—   —   —   —   —   —   —   —  
Effective Tax Rate
$ 79   22.1   % $ 33   19.9   % $ 31   23.1   % $ 17   25.8   %

Six Months Ended June 30, 2025 (a)(b)

Exelon ComEd (d)
PECO (c)
BGE
U.S. Federal statutory rate $ 323   21.0   % $ 136   21.0   % $ 88   21.0   % $ 84   21.0   %
Increase (decrease) due to:
State income taxes, net of Federal income tax benefit
85   5.5   49   7.6   ( 12 ) ( 2.9 ) 25   6.3  
Tax credits ( 7 ) ( 0.5 ) ( 4 ) ( 0.6 ) —   —   ( 2 ) ( 0.5 )
Nontaxable or nondeductible items
5   0.4   —   —   1   0.3   —   —  
Other Adjustments
Plant Basis differences ( 66 ) ( 4.3 ) ( 6 ) ( 0.9 ) ( 54 ) ( 12.9 ) ( 6 ) ( 1.5 )
Excess deferred tax
( 99 ) ( 6.4 ) ( 58 ) ( 9.0 ) ( 6 ) ( 1.4 ) ( 16 ) ( 4.0 )
Amortization of ITC, net deferred taxes
( 1 ) ( 0.1 ) —   —   —   —   —   —  
Effective Tax Rate
$ 240   15.6   % $ 117   18.1   % $ 17   4.1   % $ 85   21.3   %

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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

Six Months Ended June 30, 2025 (a)(b)

PHI PEPCO DPL ACE
U.S. Federal statutory rate $ 92   21.0   % $ 48   21.0   % $ 29   21.0   % $ 16   21.0   %
Increase (decrease) due to:
State income taxes, net of Federal income tax benefit
29   6.7   14   6.1   9   6.3   5   6.6  
Tax credits ( 2 ) ( 0.5 ) ( 1 ) ( 0.4 ) —   —   —   —  
Nontaxable or nondeductible items
1   0.3   1   0.4   —   —   —   —  
Other Adjustments
Plant Basis differences ( 3 ) ( 0.7 ) ( 2 ) ( 0.9 ) ( 1 ) ( 0.7 ) —   —  
Excess deferred tax
( 18 ) ( 4.1 ) ( 12 ) ( 5.2 ) ( 5 ) ( 3.7 ) ( 1 ) ( 1.3 )
Amortization of ITC, net deferred taxes
—   —   —   —   —   —   —   —  
Effective Tax Rate
$ 99   22.7   % $ 48   21.0   % $ 32   22.9   % $ 20   26.3   %

__________
(a) Positive amounts and percentages represent income tax expense. Negative amounts and percentages represent income tax benefit.
(b) Exelon and Registrants had no adjustments to the following disclosure categories: Foreign Tax Effects, Effects of Changes in Tax Law or Rates Enacted in the Current Period, Effects of Cross-Border Tax Laws, and Changes in Valuation Allowances.
(c) For PECO, the lower effective tax rate is primarily related to plant basis differences attributable to tax repair deductions.
(d) For ComEd, the lower effective tax rate is primarily due to CEJA which resulted in the acceleration of certain income tax benefits.
State and local Income Tax (Major Jurisdictions)
The state and local jurisdictions that comprise the majority of the effect of the state and local income tax, net of federal income taxes category by Registrant are presented below:

2026 2025
Exelon IL, MD IL, MD
ComEd IL IL
PECO PA PA
BGE MD MD
PHI MD, NJ MD, NJ
Pepco MD MD
DPL DE DE
ACE NJ NJ

Unrecognized Tax Benefits
Exelon, PHI and DPL have the following unrecognized tax benefits at June 30, 2026 and December 31, 2025. ComEd's, PECO's, BGE's, Pepco's, and ACE's amounts are not material.

Exelon (a)
PHI DPL
June 30, 2026 $ 87   $ 52   $ 16  
December 31, 2025 100   48   12  
__________
(a) At June 30, 2026 and December 31, 2025, Exelon's unrecognized tax benefits is inclusive of $ 20 million and $ 31 million , respectively, related to Constellation's share of unrecognized tax benefits for periods prior to the separation. Exelon reflected an offsetting receivable of $ 20  million and $ 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

Other Tax Matters
Tax Matters Agreement (Exelon)
In February 2022, in connection with the separation between Exelon and Constellation, the parties entered into a TMA. The TMA governs the respective rights, responsibilities, and obligations between Exelon and Constellation after the separation with respect to tax liabilities, refunds and attributes for open tax years that Constellation was part of Exelon’s consolidated group for U.S. federal, state, and local tax purposes.
Indemnification for Taxes. As a former subsidiary of Exelon, Constellation has joint and several liability with Exelon to the IRS and certain state jurisdictions relating to the taxable periods prior to the separation. The TMA specifies that Constellation is liable for their share of taxes required to be paid by Exelon with respect to taxable periods prior to the separation to the extent Constellation would have been responsible for such taxes under the Exelon tax sharing agreement when Constellation was included in Exelon's consolidated group. At June 30, 2026, 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 June 30, 2026, there is no balance due to or from Constellation.
Tax Attributes . At the date of separation certain tax attributes, primarily pre-separation tax credit carryforwards, that were generated by Constellation were required by law to be allocated to Exelon. The TMA provides that Exelon will reimburse Constellation when those allocated tax attribute carryforwards are utilized. In Q1 2026, Exelon received $ 235 million of payments from Constellation as reimbursement for a reduction in previously utilized pre-separation tax credit carryforwards due to the filing of amended federal tax returns. In Q2 2026, Exelon remitted $ 53  million of payments to Constellation for the utilization of pre-separation tax credit carryforwards. At June 30, 2026, Exelon recorded a payable of $ 99 million and $ 279 million in Other current liabilities and Other deferred credits and other liabilities, respectively, in the Consolidated Balance Sheet for tax attribute carryforwards that are expected to be utilized and reimbursed to Constellation.
Corporate Alternative Minimum Tax (All Registrants)
On August 16, 2022, the IRA was signed into law and implements a new corporate alternative minimum tax (CAMT) that imposes a 15.0 % tax on modified GAAP net income. Corporations will now pay the greater of 15.0% of financial statement pre-tax income (with certain adjustments) or their regular federal tax liability, which is federal taxable income multiplied by 21.0% federal corporate tax rate. Corporations are entitled to a tax credit (minimum tax credit) to the extent the CAMT liability exceeds the regular tax liability. This amount can be carried forward indefinitely and used in future years when regular tax exceeds the CAMT.
For the years ended December 31, 2025, December 31, 2024, and December 31, 2023, based on the existing guidance in effect at that time, Exelon and each of the Utility Registrants were subject to and reported the CAMT on a separate Registrant basis in the Consolidated Statements of Operations and Comprehensive Income and the Consolidated Balance Sheets.
On February 18, 2026, the U.S. Treasury issued guidance addressing the implementation of CAMT in the form of a notice. The new guidance permits corporate taxpayers to deduct repair and maintenance costs in the calculation of their CAMT liabilities. The notice applies retroactively, permitting Exelon to file amended returns for both 2024 and 2023 to reduce its CAMT liability by $ 80  million. Pursuant to the TMA, Exelon received reimbursement from Constellation for $ 235  million due to the reduction in the amount of Constellation's tax credits needed to offset Exelon's CAMT liability on its amended returns.
The impact of the notice was recorded as of March 31, 2026.
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.

7. Retirement Benefits (All Registrants)
Defined Benefit Pension and OPEB
The majority of the 2026 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 5.42 %. The majority of the 2026 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 5.34 %.
During the first quarter of 2026, Exelon received an updated valuation of its pension and OPEB to reflect actual census data as of January 1, 2026. This valuation resulted in an increase to the pension obligation of $ 6 million and an increase to the OPEB obligation of $ 10 million and a decrease to the asset of $ 2 million, respectively. Additionally, AOCI decreased by $ 4 million (after-tax) and regulatory assets increased by $ 23 million and liabilities increased by $ 1 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 six months ended June 30, 2026 and 2025.

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

Note 7 — Retirement Benefits

Pension Benefits OPEB
Three Months Ended June 30, Three Months Ended June 30,
2026 2025 2026 2025
Components of net periodic benefit cost
Service cost $ 40   $ 39   $ 7   $ 6  
Interest cost 142   147   25   25  
Expected return on assets ( 176 ) ( 178 ) ( 21 ) ( 21 )
Amortization of:
Prior service credit —   —   ( 2 ) ( 2 )
Actuarial loss (gain) 50   53   ( 1 ) ( 1 )

Net periodic benefit cost $ 56   $ 61   $ 8   $ 7  

Pension Benefits OPEB
Six Months Ended June 30, Six Months Ended June 30,
2026 2025 2026 2025
Components of net periodic benefit cost
Service cost $ 80   $ 77   $ 14   $ 12  
Interest cost 285   293   50   50  
Expected return on assets ( 352 ) ( 356 ) ( 43 ) ( 42 )
Amortization of:
Prior service cost (credit) 1   1   ( 4 ) ( 4 )
Actuarial loss (gain) 100   106   ( 1 ) ( 1 )

Net periodic benefit cost $ 114   $ 121   $ 16   $ 15  

The amounts below represent the Registrants' allocated pension and OPEB costs. 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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Combined Notes to Consolidated Financial Statements — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)

Note 7 — Retirement Benefits

  Three Months Ended June 30, Six Months Ended June 30,
Pension and OPEB Costs 2026 2025 2026 2025
Exelon $ 64   $ 68   $ 129   $ 136  
ComEd 27   21   54   42  
PECO 4   1   8   3  
BGE 7   14   14   30  
PHI 21   24   41   49  
Pepco 7   10   14   18  
DPL 3   4   7   8  
ACE 3   3   5   6  

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 six months ended June 30, 2026 and 2025.

Three Months Ended June 30, Six Months Ended June 30,
Savings Plan Employer Contributions 2026 2025 2026 2025
Exelon $ 32   $ 30   $ 64   $ 56  
ComEd 13   12   24   22  
PECO 5   4   9   8  
BGE 3   3   6   6  
PHI 7   5   12   10  
Pepco 2   2   3   3  
DPL 1   1   2   2  
ACE 1   —   2   1  

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 (All Registrants)
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 2 — Regulatory Matters of the 2025 Form 10-K for additional information.
(b) The fair value of the DPL economic hedge is not material at June 30, 2026 and December 31, 2025.
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 June 30, 2026 would result in an immaterial impact to Exelon's Consolidated Net income.
Below is a summary of the interest rate hedge balances at June 30, 2026 and December 31, 2025 .

Derivatives Designated
as Hedging Instruments
June 30, 2026 December 31, 2025
Other current assets $ —   $ 3  
Other deferred debits (noncurrent assets) 3   —  
Total derivative assets 3   3  
Mark-to-market derivative liabilities (current liabilities) —   ( 4 )
Mark-to-market derivative liabilities (noncurrent liabilities) —   —  
Total mark-to-market derivative liabilities —   ( 4 )
Total mark-to-market derivative net assets (liabilities) $ 3   $ ( 1 )

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

Note 8 — Derivative Financial Instruments

Cash Flow Hedges (Interest Rate Risk)
For derivative instruments that qualify and are designated as cash flow hedges, the changes in fair value each period are initially recorded in AOCI and reclassified into earnings when the underlying transaction affects earnings. The gains and losses reclassified out of AOCI for the three and six months ended June 30, 2026 and 2025 are immaterial.
In February 2026, Exelon terminated the previously issued floating-to-fixed swaps with a total notional of $ 550  million upon issuance of $ 775  million of debt. See Note 9 – Debt and Credit Agreements for additional information on the debt issuance. The settlements resulted in a net cash payment of $ 6  million. The accumulated AOCI loss of $ 4  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 second quarter of 2026, Exelon Corporate entered into $ 30 million notional of 10-year maturity floating-to-fixed swaps designated as cash flow hedges. The following table provides the notional amounts outstanding held by Exelon at June 30, 2026 and December 31, 2025.

June 30, 2026 December 31, 2025
5-year maturity floating-to-fixed swaps $ 60   $ 335  
10-year maturity floating-to-fixed swaps 150   365  
Total $ 210   $ 700  

The related AOCI derivative gain for the three and six months ended June 30, 2026 was $ 1  million and $ 2  million (net of tax), respectively. The related AOCI derivative loss for the three and six months ended June 30, 2025 was $ 4  million and $ 13  million (net of tax), respectively. See Note 13 – Changes in Accumulated Other Comprehensive Income (Loss) for additional information.
Credit Risk (All Registrants)
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 June 30, 2026. 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, at June 30, 2026 and December 31, 2025:

June 30, 2026 December 31, 2025
Exelon $ 244   $ 223  
ComEd 221   192  
PECO 6   6  
BGE 2   4  
PHI 15   21  
Pepco 13   13  
DPL 2   3  
ACE (a)
—   5  
__________
(a) ACE had less than one million in cash collateral with external parties at June 30, 2026.
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(Dollars in millions, except per share data, unless otherwise noted)

Note 8 — Derivative Financial Instruments

The Utility Registrants’ electric supply procurement contracts do not contain provisions that would require them to post collateral. PECO’s, BGE’s, and DPL’s natural gas procurement contracts contain provisions that could require PECO, BGE, and DPL to post collateral in the form of cash or credit support, which vary by contract and counterparty, with thresholds contingent upon PECO's, BGE's, and DPL's credit rating. As of June 30, 2026, 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 June 30, 2026, they could have been required to post collateral to their counterparties of $ 26 million, $ 16 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 needs primarily through commercial paper issuances. PECO also utilizes commercial paper, supplemented by borrowings from the Exelon intercompany money pool. Pepco, DPL, and ACE similarly rely on commercial paper, along with borrowings from the PHI intercompany money pool. PHI Corporate meets its short-term liquidity needs through 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 June 30, 2026 and December 31, 2025.

Outstanding Commercial
Paper at Average Interest Rate on
Commercial Paper Borrowings at
Commercial Paper Issuer June 30, 2026 December 31, 2025 June 30, 2026 December 31, 2025
Exelon (a)
$ 743   $ 612   3.88   % 3.94   %
ComEd $ —   $ —   —   % —   %
PECO $ 81   $ —   3.80   % —   %
BGE $ —   $ —   —   % —   %
PHI (b)
$ 32   $ 612   3.95   % 3.94   %

Pepco $ —   $ 303   —   % 3.93   %
DPL $ 32   $ 161   3.95   % 3.94   %
ACE $ —   $ 148   —   % 3.94   %

__________
(a) Exelon Corporate had $ 630 million outstanding commercial paper borrowings at June 30, 2026 and no outstanding commercial paper borrowings at December 31, 2025.
(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 1.000 %

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 June 30, 2026.
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 14 — Debt and Credit Agreements of the 2025 Form 10-K for additional information on the Registrants' credit facilities.
Short-Term Loan Agreements
On March 25, 2026, Exelon Corporate entered into two term loan agreements for $ 350 million and $ 150 million. Both agreements mature on March 24, 2027. Pursuant to the loan agreements, loans made thereunder bear interest at a variable rate equal to SOFR plus 0.85 % and all indebtedness thereunder is unsecured. The loans are reflected in Exelon's Consolidated Balance Sheet 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 six months ended June 30, 2026, the following long-term debt was issued:

Company Type Interest Rate Maturity Amount Use of Proceeds
Exelon Senior Notes 4.95 % March 15, 2036 $ 775 Repay existing indebtedness and for general corporate purposes.
ComEd First Mortgage Bonds 4.55 % June 1, 2031 600 Repay existing indebtedness and for general corporate purposes.
ComEd First Mortgage Bonds 5.85 % June 1, 2056 825 Repay existing indebtedness and for general corporate purposes.
BGE Notes 5.15 % June 1, 2033 500 Repay existing indebtedness and for general corporate purposes.
BGE Notes 6.05 % June 1, 2056 425 Repay existing indebtedness and for general corporate purposes.
Pepco First Mortgage Bonds 5.00 % March 19, 2036 110 Repay existing indebtedness and for general corporate purposes.
Pepco First Mortgage Bonds 5.30 % March 19, 2041 60 Repay existing indebtedness and for general corporate purposes.
Pepco First Mortgage Bonds 5.74 % June 17, 2056 130 Repay existing indebtedness and for general corporate purposes.
DPL (a)
First Mortgage Bonds 5.74 % March 19, 2056 75 Repay existing indebtedness and for general corporate purposes.
ACE First Mortgage Bonds 4.95 % March 19, 2036 100 Repay existing indebtedness and for general corporate purposes.

__________
(a) On March 19, 2026, DPL entered into a purchase agreement of First Mortgage Bonds of $ 75 million and $ 75 million at 5.00 % and 5.74 % due on September 16, 2036 and March 19, 2056, respectively. The closing date of the 5.00 % issuance is expected to occur in September 2026.
Convertible Senior Notes
On December 4, 2025, Exelon Corporation issued $ 1 billion aggregate principal amount of 3.25 % Convertible Senior Notes due 2029 (Convertible Senior Notes). The Convertible Senior Notes are reflected as Long-term debt on Exelon’s Consolidated Balance Sheet.

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

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

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

Note 9 — Debt and Credit Agreements

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

Exelon will settle conversions of the Convertible Senior Notes by paying cash up to the aggregate principal amount to be converted and paying or delivering, as the case may be, cash, shares of common stock, or a combination of cash and shares of common stock, at Exelon’s discretion, in respect of the remainder, if any, of Exelon's conversion obligation in excess of the aggregate principal amount of the Convertible Senior Notes being converted. The Convertible Senior Notes are initially convertible at 18 shares per $ 1,000 principal amount, which is equivalent to an initial conversion price of approximately 57 per share of common stock. The initial conversion price of the Convertible Senior Notes represents a premium of approximately 25 % over the last reported sale price of Exelon’s common stock on the Nasdaq Global Select Market on December 1, 2025. These conversions will be subject to adjustment upon the occurrence of certain specified events but will not be adjusted for accrued and unpaid interest. In addition, upon the occurrence of a make-whole fundamental change (as defined in the indenture) Exelon will, in certain circumstances, increase the applicable conversion rate by a number of additional shares of common stock for conversions in connection with the make-whole fundamental change.

As of June 30, 2026, no shares of the Convertible Senior Notes have been converted.
EPS Impact
Diluted earnings per common shares will also reflect the dilutive effect of potential common shares from share-based awards and convertible notes. The dilutive effect of the Convertible Senior Notes is computed using the if-converted method. For the three and six months ended June 30, 2026, no incremental shares were assumed converted or included in the diluted earnings per common share resulting from the Convertible Senior Notes.
Tax-Exempt Bonds
As of June 30, 2026, DPL had $ 78.4 million outstanding of its 3.60 % Delaware Economic Development Authority's Gas Facilities Refunding Revenue Bonds, maturing on January 1, 2031. The bonds were previously reoffered in July 2025. There have been no material changes to the terms since December 31, 2025. See Note 14 — Debt and Credit Agreements of the 2025 Form 10-K for additional information on the DPL reoffering of tax-exempt bonds.
Debt Covenants
As of June 30, 2026, 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 15 — Fair Value of Financial Assets and Liabilities of the 2025 Form 10-K.
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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 June 30, 2026 and December 31, 2025. 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.

June 30, 2026 December 31, 2025
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 (b)
$ 51,040   $ —   $ 41,613   $ 4,723   $ 46,336   $ 49,078   $ —   $ 40,637   $ 4,318   $ 44,955  
ComEd 13,665   —   12,086   —   12,086   12,753   —   11,291   —   11,291  
PECO 6,398   —   5,526   —   5,526   6,396   —   5,593   —   5,593  
BGE 6,609   —   6,011   —   6,011   6,041   —   5,510   —   5,510  
PHI 10,054   —   4,162   4,723   8,885   9,590   —   4,236   4,318   8,554  
Pepco 4,931   —   2,492   2,129   4,621   4,632   —   2,546   1,861   4,407  
DPL 2,421   —   648   1,462   2,110   2,344   —   657   1,410   2,067  
ACE 2,134   —   813   1,132   1,945   2,033   —   819   1,047   1,866  
Long-Term Debt to Financing Trusts
Exelon $ 390   $ —   $ —   $ 399   $ 399   $ 390   $ —   $ —   $ 403   $ 403  
ComEd 206   —   —   214   214   206   —   —   216   216  
PECO 184   —   —   185   185   184   —   —   187   187  

__________
(a) Includes unamortized debt issuance costs, unamortized debt discount and premium, net, purchase accounting fair value adjustments, and finance lease liabilities which are not fair valued. Refer to Note 14 — Debt and Credit Agreements of the 2025 Form 10-K for unamortized debt issuance costs, unamortized debt discount and premium, net, and purchase accounting fair value adjustments and Note 9 — Leases of the 2025 Form 10-K for finance lease liabilities.
(b) Includes the net carrying amount and the estimated fair value (Level 2) of the Convertible Senior Notes $ 1 billion and $ 1 billion for the year ended June 30, 2026, respectively.

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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 June 30, 2026 and December 31, 2025. Exelon and the Utility Registrants have immaterial and no financial assets or liabilities measured using the NAV practical expedient, respectively:
Exelon

At June 30, 2026 At December 31, 2025
Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total
Assets
Cash equivalents (a)
$ 2,026   $ —   $ —   $ 2,026   $ 825   $ —   $ —   $ 825  
Rabbi trust investments
Cash equivalents 108   —   —   108   101   —   —   101  
Mutual funds 77   —   —   77   71   —   —   71  
Fixed income —   6   —   6   —   6   —   6  
Life insurance contracts —   81   19   100   —   79   21   100  
Rabbi trust investments subtotal 185   87   19   291   172   85   21   278  

Interest rate derivative assets
Derivatives designated as hedging instruments —   3   —   3   —   3   —   3  

Interest rate derivative assets subtotal —   3   —   3   —   3   —   3  
Total assets 2,211   90   19   2,320   997   88   21   1,106  
Liabilities
Commodity derivative liabilities —   —   ( 128 ) ( 128 ) —   —   ( 131 ) ( 131 )
Interest rate derivative liabilities
Derivatives designated as hedging instruments —   —   —   —   —   ( 4 ) —   ( 4 )

Interest rate derivative liabilities subtotal —   —   —   —   —   ( 4 ) —   ( 4 )
Deferred compensation obligation —   ( 66 ) —   ( 66 ) —   ( 71 ) —   ( 71 )
Total liabilities —   ( 66 ) ( 128 ) ( 194 ) —   ( 75 ) ( 131 ) ( 206 )
Total net assets (liabilities) $ 2,211   $ 24   $ ( 109 ) $ 2,126   $ 997   $ 13   $ ( 110 ) $ 900  

__________     
(a) Exelon excludes cash of $ 180 million and $ 180 million at June 30, 2026 and December 31, 2025, respectively, and restricted cash of $ 224 million and $ 196 million at June 30, 2026 and December 31, 2025, respectively, and includes long-term restricted cash of $ 9 million and $ 50 million at June 30, 2026 and December 31, 2025, respectively, which is reported in Other deferred debits and other assets in the Consolidated Balance Sheets.

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Note 10 — Fair Value of Financial Assets and Liabilities

ComEd, PECO, and BGE

ComEd PECO BGE
At June 30, 2026 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)
$ 949   $ —   $ —   $ 949   $ 2   $ —   $ —   $ 2   $ 1,006   $ —   $ —   $ 1,006  
Rabbi trust investments
Cash equivalents —   —   —   —   2   —   —   2   —   —   —   —  
Mutual funds —   —   —   —   14   —   —   14   16   —   —   16  
Life insurance contracts —   —   —   —   —   25   —   25   —   —   —   —  
Rabbi trust investments subtotal —   —   —   —   16   25   —   41   16   —   —   16  

Total assets 949   —   —   949   18   25   —   43   1,022   —   —   1,022  
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) $ 949   $ ( 9 ) $ ( 128 ) $ 812   $ 18   $ 18   $ —   $ 36   $ 1,022   $ ( 4 ) $ —   $ 1,018  

ComEd PECO BGE
At December 31, 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)
$ 393   $ —   $ —   $ 393   $ 93   $ —   $ —   $ 93   $ 205   $ —   $ —   $ 205  
Rabbi trust investments
Mutual funds —   —   —   —   13   —   —   13   10   —   —   10  
Life insurance contracts —   —   —   —   —   25   —   25   —   —   —   —  
Rabbi trust investments subtotal —   —   —   —   13   25   —   38   10   —   —   10  
Total assets 393   —   —   393   106   25   —   131   215   —   —   215  
Liabilities
Commodity derivative liabilities (b)
—   —   ( 131 ) ( 131 ) —   —   —   —   —   —   —   —  
Deferred compensation obligation —   ( 9 ) —   ( 9 ) —   ( 8 ) —   ( 8 ) —   ( 4 ) —   ( 4 )
Total liabilities —   ( 9 ) ( 131 ) ( 140 ) —   ( 8 ) —   ( 8 ) —   ( 4 ) —   ( 4 )
Total net assets (liabilities) $ 393   $ ( 9 ) $ ( 131 ) $ 253   $ 106   $ 17   $ —   $ 123   $ 215   $ ( 4 ) $ —   $ 211  

__________
(a) ComEd excludes cash of $ 75 million and $ 77 million at June 30, 2026 and December 31, 2025, respectively, and restricted cash of $ 222 million and $ 193 million at June 30, 2026 and December 31, 2025, respectively. Additionally,
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Note 10 — Fair Value of Financial Assets and Liabilities

ComEd includes long-term restricted cash of $ 9 million and $ 50 million at June 30, 2026 and December 31, 2025, respectively, which is reported in Other deferred debits and other assets in the Consolidated Balance Sheets. PECO excludes cash of $ 37 million and $ 23 million at June 30, 2026 and December 31, 2025, respectively. BGE excludes cash of $ 8 million and $ 15 million at June 30, 2026 and December 31, 2025, respectively.
(b) The Level 3 balance consists of the current and noncurrent liability of $ 23 million and $ 105 million, respectively, at June 30, 2026 and $ 25 million and $ 106 million, respectively, at December 31, 2025 related to floating-to-fixed energy swap contracts with unaffiliated suppliers.

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Note 10 — Fair Value of Financial Assets and Liabilities

PHI, Pepco, DPL, and ACE

At June 30, 2026 At December 31, 2025
PHI Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total
Assets
Cash equivalents (a)
$ 34   $ —   $ —   $ 34   $ 83   $ —   $ —   $ 83  
Rabbi trust investments
Cash equivalents 103   —   —   103   99   —   —   99  
Mutual funds 9   —   —   9   9   —   —   9  
Fixed income —   6   —   6   —   6   —   6  
Life insurance contracts —   23   19   42   —   23   20   43  
Rabbi trust investments subtotal 112   29   19   160   108   29   20   157  
Total assets 146   29   19   194   191   29   20   240  
Liabilities
Deferred compensation obligation —   ( 8 ) —   ( 8 ) —   ( 9 ) —   ( 9 )

Total liabilities —   ( 8 ) —   ( 8 ) —   ( 9 ) —   ( 9 )
Total net assets $ 146   $ 21   $ 19   $ 186   $ 191   $ 20   $ 20   $ 231  

Pepco DPL ACE
At June 30, 2026 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)
$ 32   $ —   $ —   $ 32   $ 2   $ —   $ —   $ 2   $ —   $ —   $ —   $ —  

Rabbi trust investments
Cash equivalents 102   —   —   102   —   —   —   —   —   —   —   —  

Life insurance contracts —   23   19   42   —   —   —   —   —   —   —   —  
Rabbi trust investments subtotal 102   23   19   144   —   —   —   —   —   —   —   —  
Total assets 134   23   19   176   2   —   —   2   —   —   —   —  
Liabilities
Deferred compensation obligation —   ( 1 ) —   ( 1 ) —   —   —   —   —   —   —   —  

Total liabilities —   ( 1 ) —   ( 1 ) —   —   —   —   —   —   —   —  
Total net assets $ 134   $ 22   $ 19   $ 175   $ 2   $ —   $ —   $ 2   $ —   $ —   $ —   $ —  

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Note 10 — Fair Value of Financial Assets and Liabilities

Pepco DPL ACE
At December 31, 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)
$ 33   $ —   $ —   $ 33   $ 3   $ —   $ —   $ 3   $ —   $ —   $ —   $ —  
Rabbi trust investments
Cash equivalents 98   —   —   98   —   —   —   —   —   —   —   —  

Life insurance contracts —   23   20   43   —   —   —   —   —   —   —   —  
Rabbi trust investments subtotal 98   23   20   141   —   —   —   —   —   —   —   —  
Total assets 131   23   20   174   3   —   —   3   —   —   —   —  
Liabilities
Deferred compensation obligation —   ( 1 ) —   ( 1 ) —   —   —   —   —   —   —   —  

Total liabilities —   ( 1 ) —   ( 1 ) —   —   —   —   —   —   —   —  
Total net assets $ 131   $ 22   $ 20   $ 173   $ 3   $ —   $ —   $ 3   $ —   $ —   $ —   $ —  

__________
(a) PHI excludes cash of $ 47 million and $ 56 million at June 30, 2026 and December 31, 2025, respectively, and restricted cash of $ 2 million and $ 2 million at June 30, 2026 and December 31, 2025. Pepco excludes cash of $ 20 million and $ 22 million at June 30, 2026 and December 31, 2025, respectively. DPL excludes cash of $ 8 million and $ 9 million at June 30, 2026 and December 31, 2025, respectively. ACE excludes cash of $ 13 million and $ 22 million at June 30, 2026 and December 31, 2025, respectively and restricted cash of $ 2 million and $ 2 million at June 30, 2026 and December 31, 2025, 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 six months ended June 30, 2026 and 2025:

Exelon ComEd PHI and Pepco
Three Months Ended June 30, 2026 Total Commodity
Derivatives Life Insurance Contracts
Balance at March 31, 2026 $ ( 112 ) $ ( 133 ) $ 20  
Total realized / unrealized gains (losses)
Included in net income (a)
—   —   —  

Included in regulatory assets/liabilities (b)
5   5   —  

Settlements ( 2 ) —   ( 1 )

Balance at June 30, 2026 (c)
$ ( 109 ) $ ( 128 ) $ 19  
The amount of total gains included in income attributed to the change in unrealized gains related to assets and liabilities at June 30, 2026 $ —   $ —   $ —  

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Note 10 — Fair Value of Financial Assets and Liabilities

Exelon ComEd PHI and Pepco
Three Months Ended June 30, 2025 Total Commodity
Derivatives Life Insurance Contracts
Balance at March 31, 2025 $ ( 129 ) $ ( 151 ) $ 21  
Total realized / unrealized gains (losses)
Included in net income (a)
1   —   1  

Included in regulatory assets/liabilities (b)
16   16   —  

Balance at June 30, 2025 (c)
$ ( 112 ) $ ( 135 ) $ 22  
The amount of total gains included in income attributed to the change in unrealized gains related to assets and liabilities at June 30, 2025 $ 1   $ —   $ 1  

Exelon ComEd PHI and Pepco
Six Months Ended June 30, 2026 Total Commodity
Derivatives Life Insurance Contracts
Balance at December 31, 2025 $ ( 110 ) $ ( 131 ) $ 20  
Total realized / unrealized gains (losses)
Included in net income (a)
—   —   —  

Included in regulatory assets/liabilities (b)
3   3   —  

Settlements ( 2 ) —   ( 1 )

Balance at June 30, 2026 (c)
$ ( 109 ) $ ( 128 ) $ 19  
The amount of total gains included in income attributed to the change in unrealized gains related to assets and liabilities at June 30, 2026 $ —   $ —   $ —  

Exelon ComEd PHI and Pepco
Six Months Ended June 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)
1   —   1  

Included in regulatory assets/liabilities (b)
( 3 ) ( 3 ) —  

Balance at June 30, 2025 (c)
$ ( 112 ) $ ( 135 ) $ 22  
The amount of total gains included in income attributed to the change in unrealized gains related to assets and liabilities at June 30, 2025 $ 1   $ —   $ 1  
__________
(a) Classified in Operating and maintenance expense in the Consolidated Statements of Operations and Comprehensive Income.
(b) For ComEd, this includes $ 7 million of decreases in fair value and an increase for realized gains due to settlements of $ 12 million recorded in Purchased power expense associated with floating-to-fixed energy swap contracts with unaffiliated suppliers for the three months ended June 30, 2026. Includes $ 5 million of increases in fair value and an increase for realized gains due to settlements of $ 11 million recorded in Purchased power expense associated with floating-to-fixed energy swap contracts with unaffiliated suppliers for the three months ended June 30, 2025. Includes $ 17 million of decreases in fair value and an increase for realized gains due to settlements of $ 20 million recorded in Purchased power expense associated with floating-to-fixed energy swap contracts with unaffiliated suppliers for the six months ended June 30, 2026. Includes $ 17 million of decreases in fair value and an increase for realized gains due to settlements of $ 20 million recorded in Purchased power expense associated with floating-to-fixed energy swap contracts with unaffiliated suppliers for the six months ended June 30, 2025.
(c) For ComEd, the balance of the current and noncurrent asset was zero as of June 30, 2026. The balance consists of a current and noncurrent liability of $ 23 million and $ 105 million, respectively, as of June 30, 2026.
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Note 10 — Fair Value of Financial Assets and Liabilities

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 June 30, 2026 Fair Value at December 31, 2025 Valuation
Technique Unobservable
Input 2026 Range & Arithmetic Average 2025 Range & Arithmetic Average
Commodity derivatives $ ( 128 ) $ ( 131 ) Discounted
Cash Flow Forward power price (a)
$ 24.82 - $ 68.10 $ 40.37 $ 29.75 - $ 61.84 $ 41.95

________
(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 16 — Commitments and Contingencies of the 2025 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 June 30, 2026:

Description Exelon PHI Pepco DPL ACE
Total commitments $ 513   $ 320   $ 120   $ 89   $ 111  
Remaining commitments (a)
21   19   19   —   —  

__________
(a) Remaining commitments extend through 2026 and include escrow funds and rate credits.
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Commercial Commitments (All Registrants). The Registrants’ commercial commitments at June 30, 2026, representing commitments potentially triggered by future events were as follows:
Expiration within
Total 2026 2027 2028 2029 2030 2031 and beyond
Exelon
Letters of credit (a)
$ 59   $ 31   $ 28   $ —   $ —   $ —   $ —  
Surety bonds (b)
468   166   137   165   —   —   —  
Financing trust guarantees (c)
378   —   —   78   —   —   300  
Guaranteed lease residual values (d)
24   —   1   6   4   4   9  
Total commercial commitments $ 929   $ 197   $ 166   $ 249   $ 4   $ 4   $ 309  

ComEd
Letters of credit (a)
$ 18   $ 13   $ 5   $ —   $ —   $ —   $ —  
Surety bonds (b)
131   34   97   —   —   —   —  
Financing trust guarantees (c)
200   —   —   —   —   —   200  
Total commercial commitments $ 349   $ 47   $ 102   $ —   $ —   $ —   $ 200  

PECO
Letters of credit (a)
$ 5   $ —   $ 5   $ —   $ —   $ —   $ —  
Surety bonds (b)
10   1   9   —   —   —   —  
Financing trust guarantees (c)
178   —   —   78   —   —   100  
Total commercial commitments $ 193   $ 1   $ 14   $ 78   $ —   $ —   $ 100  

BGE
Letters of credit (a)
$ 27   $ 14   $ 13   $ —   $ —   $ —   $ —  
Surety bonds (b)
93   1   5   87   —   —   —  
Total commercial commitments $ 120   $ 15   $ 18   $ 87   $ —   $ —   $ —  

PHI
Letters of credit (a)
$ 6   $ 2   $ 4   $ —   $ —   $ —   $ —  
Surety bonds (b)
175   76   21   78   —   —   —  
Guaranteed lease residual values (d)
24   —   1   6   4   4   9  
Total commercial commitments $ 205   $ 78   $ 26   $ 84   $ 4   $ 4   $ 9  

Pepco
Letters of credit (a)
$ 2   $ 2   $ —   $ —   $ —   $ —   $ —  
Surety bonds (b)
161   69   14   78   —   —   —  
Guaranteed lease residual values (d)
8   —   —   2   1   2   3  
Total commercial commitments $ 171   $ 71   $ 14   $ 80   $ 1   $ 2   $ 3  

DPL
Letters of credit (a)
$ 1   $ —   $ 1   $ —   $ —   $ —   $ —  
Surety bonds (b)
7   3   4   —   —   —   —  
Guaranteed lease residual values (d)
9   —   1   2   2   1   3  
Total commercial commitments $ 17   $ 3   $ 6   $ 2   $ 2   $ 1   $ 3  

ACE
Letters of credit (a)
$ 3   $ —   $ 3   $ —   $ —   $ —   $ —  
Surety bonds (b)
7   4   3   —   —   —   —  
Guaranteed lease residual values (d)
7   —   —   2   1   1   3  
Total commercial commitments $ 17   $ 4   $ 6   $ 2   $ 1   $ 1   $ 3  

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Note 11 — Commitments and Contingencies

__________
(a) Exelon and certain of its subsidiaries maintain non-debt letters of credit to provide credit support for certain transactions as requested by third parties.
(b) Surety bonds—Guarantees issued related to contract and commercial agreements, excluding bid bonds. Historically, payments under the guarantees have not been made and the likelihood of payments being required is remote.
(c) Reflects guarantee of ComEd and PECO securities held by ComEd Financing III, PECO Trust III, and PECO Trust IV.
(d) Represents the maximum potential obligation in the event the fair value of certain leased equipment and fleet vehicles is zero at the end of the maximum lease term. The lease term associated with these assets ranges from 1 to 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 $ 18 million, $ 20 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 5 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 2027.
• 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.
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At June 30, 2026 and December 31, 2025, 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:

June 30, 2026 December 31, 2025
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 $ 362   $ 311   $ 386   $ 321  
ComEd 285   285   289   289  
PECO 19   16   23   22  
BGE 13   10   13   10  
PHI 44   —   57   —  
Pepco 43   —   55   —  
DPL 1   —   1   —  
ACE —   —   1   —  

Benning Road Site (Exelon, PHI, and Pepco) . In September 2010, PHI received a letter from the EPA identifying the Benning Road site as one of six land-based sites potentially contributing to contamination of the lower Anacostia River. A portion of the site, which is owned by Pepco, was formerly the location of an electric generating facility owned by Pepco subsidiary, Pepco Energy Services (PES), which became a part of Constellation following the 2016 merger between PHI and Exelon. This generating facility was deactivated in June 2012. The remaining portion of the site consists of a Pepco transmission and distribution service center that remains in operation. In December 2011, the U.S. District Court for the District of Columbia approved a Consent Decree entered into by Pepco and Pepco Energy Services (hereinafter "Pepco Entities") with the DOEE, which requires the Pepco Entities to conduct a Remedial Investigation and Feasibility Study (RI/FS) for the Benning Road site and an approximately 10 to 15-acre portion of the adjacent Anacostia River. The purpose of this RI/FS is to define the nature and extent of contamination from the Benning Road site and to evaluate remedial alternatives.
Pursuant to an internal agreement between the Pepco Entities, since 2013, Pepco has performed the work required by the Consent Decree and has been reimbursed for that work by an agreed upon allocation of costs between the Pepco Entities. In September 2019, the Pepco Entities issued a draft “final” RI report which the DOEE approved on February 3, 2020. In October 2022, the DOEE approved dividing the work to complete the landside portion of the FS from the waterside portion to expedite the overall schedule for completion of the project. The landside FS was approved by the DOEE on March 15th, 2024, and the waterside FS was approved by the DOEE on December 16, 2024. The DOEE and Pepco entered into an addendum to the Benning Consent Decree pursuant to which Pepco has agreed to fund or perform the remedial actions to be selected by the DOEE for the landside and waterside areas. This addendum to the Benning Consent Decree was entered by the Court on February 27, 2024 and became effective on that date. Pepco drafted separate proposed plans for the landside and waterside areas, which were approved and issued by the DOEE for public comment on December 16, 2024 and September 4, 2025, respectively. The public comment period for the landside and waterside areas closed on April 18, 2025 and October 31, 2025, respectively. Pepco submitted a matrix of proposed responses to the public comments and a proposed Record of Decision (ROD) to the DOEE for the landside area on August 15, 2025. The DOEE will issue RODs identifying the remedial actions determined to be necessary for the landside and waterside areas, which will be implemented by Pepco in accordance with the Benning Consent Decree.
As part of the separation between Exelon and Constellation in February 2022, the internal agreement between the Pepco Entities for completion and payment for the remaining Consent Decree work was memorialized in a formal agreement for post-separation activities. A second post-separation assumption agreement between Exelon and Constellation transferred any of the potential remaining remediation liability, if any, of PES/Constellation to a non-utility subsidiary of Exelon which going forward will be responsible for those liabilities. 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
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Note 11 — Commitments and Contingencies

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, and the second installment of $ 12 million on April 7, 2026. 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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Buzzard Point Site (Exelon, PHI, and Pepco). On December 8, 2022, Pepco received a letter from the D.C. OAG, alleging wholly past violations of the District's stormwater discharge and waste disposal requirements related to operations at the Buzzard Point facility, a 9-acre parcel of waterfront property in Washington, D.C. occupied by an active substation and former steam plant building. The letter also alleged wholly past violations by Pepco of stormwater discharge requirements related to its district-wide system of underground vaults. Pepco entered into a Consent Order with the District of Columbia to resolve the alleged violations without any admission of liability. The Consent Order requires Pepco to pay a civil penalty of $ 10 million. In addition, Pepco has agreed to assess the environmental conditions at its Buzzard Point facility and conduct any remedial actions deemed necessary as a result of the assessment, and also to assess potential environmental impacts associated with the operation of its underground vaults. The Superior Court for the District of Columbia signed and entered the Consent Order, and it became effective on February 2, 2024. Pepco is proceeding through the multi-step environmental investigation and response as outlined in the consent order. Specifically, the DOEE approved Pepco's Preliminary Site Assessment in July 2025. In September 2025, Pepco timely submitted its work plan for the second stage, the Supplemental Investigation Plan, which the DOEE approved in November 2025. Pepco also submitted an environmental assessment to the DOEE of the vault system pursuant to the Consent Order in July 2024. In response to the DOEE's comments, Pepco made revised submissions in May 2025, September 2025, and January 2026. The DOEE approved Pepco's vault system report on February 2, 2026. Exelon, PHI, and Pepco have accrued a liability for the projected costs for the required environmental assessments and remediation. In January 2025, Pepco paid the last installment of the civil penalty. Pepco has concluded that incremental exposure remains reasonably possible, but management cannot reasonably estimate a range of loss beyond the amounts recorded, which are included in the table above.
Litigation and Regulatory Matters
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
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(Dollars in millions, except per share data, unless otherwise noted)

Note 11 — Commitments and Contingencies

(Stipulation), which contained the terms of the proposed settlement. The proposed settlement terms include but are not limited to: a payment of $ 40 million to Exelon by Exelon’s insurers of which $ 10 million constitutes the attorneys’ fee award to be paid to the Settling Shareholders’ counsel; various compliance and disclosure-related reforms; and certain changes in Board and Committee composition. The non-settling shareholders objected to the settlement and opposed preliminary approval. On September 20, 2024, the court denied without prejudice the SLC’s motion for preliminary approval. The court’s order provided that if the SLC can substantiate or otherwise revise the attorneys’ fees aspect of the settlement, then the SLC could renew its motion for preliminary approval by October 21, 2024. On October 21, 2024, the SLC filed its second renewed motion for preliminary approval, and the Settling Shareholders filed a brief in support of the SLC's second renewed motion for preliminary approval. On November 20, 2024, the non-settling plaintiffs filed an opposition to the renewed motion for preliminary approval. On December 18, 2024, the SLC and Settling Shareholders filed replies in support of the renewed motion for preliminary approval. The court granted the renewed motion for preliminary approval on November 17, 2025, and the final settlement hearing was held on May 5, 2026.
Maryland Sales and Use Tax Refund Claim (Exelon, BGE, PHI, Pepco, and DPL). Maryland imposes a 6% sales tax on the purchase of most goods and services. BGE, Pepco, and DPL have filed or plan to file refund claims that treat electric transmission and distribution machinery and equipment as nontaxable pursuant to the manufacturing exemption available under Maryland law. These claims were initially denied by the Maryland Comptroller.
On November 22, 2024, the Appellate Court of Maryland, in a case involving a regulated electric utility operating in Maryland, ruled that the purchase of certain transmission and distribution equipment qualifies 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. 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 decision, which was granted. 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.
On July 17, 2026, the Supreme Court of Maryland issued a decision affirming that purchases of certain transmission and distribution equipment qualify for the sales tax manufacturing exemption. The Supreme Court of Maryland also concluded that sales tax refund claims are eligible for interest.
As of June 30, 2026, Exelon, BGE, PHI, Pepco, and DPL have filed or plan to file refund claims including interest of $ 160 million, $ 110 million, $ 50 million, $ 30 million, and $ 20 million, respectively. The receivable will be recorded in the period that resolution is reached with taxing authorities. The sales tax payments were primarily capitalized; therefore, that portion of 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 Program
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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 May 2, 2025, Exelon executed an equity distribution agreement ("2025 Equity Distribution Agreement"), 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. Exelon has no obligation to offer or sell any shares of Common stock under the 2025 Equity Distribution Agreement and may, at any time, suspend or terminate offers and sales under the 2025 Equity Distribution Agreement. Exelon issued the following shares of Common stock in the second quarter of 2026:

Effective Period
Shares Issued
(in millions)
Weighted-Average Net Price
Net Proceeds (a)
(in millions)

Q2 2026 (b)
8.7 $ 44.03   $ 382  

_________
(a) Proceeds were used for general corporate purposes.
(b) In Q2 2026, Exelon settled all forward sale agreements with a November 16, 2026 maturity date and a portion of the forward sale agreements with December 15, 2026 and July 30, 2027 maturity dates that were entered into by various forward sellers under the ATM program as outlined below.
In the first quarter of 2026, Exelon entered into various forward sale agreements under the 2025 ATM program. The forward sale agreements require Exelon to, at its election prior to the maturity date, either (i) physically settle the transactions by issuing shares of its Common stock to the forward counterparties in exchange for net proceeds at the then-applicable forward sale price specified by the agreements or (ii) net settle the transactions in whole or in part through the delivery to the forward counterparties or receipt from the forward counterparties of cash or shares in accordance with the provisions of the agreements. The following forward sale agreements were entered into under Exelon’s ATM program in the first quarter of 2026:

Effective Period Shares Available
(in millions) Weighted-Average Net Price Maturity Date
Q1 2026 5.4 $ 47.67   July 30, 2027
Q1 2026 6.4 $ 48.68   September 2, 2027

Additionally, the following forward sale agreements were entered into during the twelve months ended 2025 under Exelon’s ATM program and were not settled as of December 31, 2025:

Effective Period Shares Available
(in millions) Weighted-Average Net Price Maturity Date
Q2 2025 3.6 $ 43.17   November 16, 2026
Q3 2025 11.5 $ 43.73   December 15, 2026
Q4 2025 0.8 $ 45.42   December 15, 2026

No amounts have been or will be recorded on Exelon's balance sheet with respect to the equity offerings until the equity forward sale agreements have been settled. Each initial forward sale price is subject to adjustment on a daily basis based on a floating interest rate factor and will decrease by other fixed amounts specified in the agreements. Until settlement of the equity forward, earnings per share dilution resulting from the agreement, if any, will be determined under the treasury stock method. For the three and six months ended June 30, 2026, approximately 18.4 million shares under the forward sale agreements were not included in the calculation of diluted earnings per share because their effect would have been antidilutive.
Inclusive of the impact of the forward sale agreements, $ 1.0 billion of Common stock remained available for sale pursuant to the ATM program as of June 30, 2026.
On July 6, 2026, Exelon settled an additional forward agreement that was entered into under the 2025 ATM program. Exelon issued approximately 2.3 million shares of Common stock at a weighted-average net price of $ 43.29 per share. The net proceeds from the issuance were $ 101 million, which will be used for general corporate purposes.

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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 June 30, 2026  Cash Flow Hedges Pension and Non-Pension Postretirement Benefit Plan Items (a)
Total
Balance at March 31, 2026 $ 28   $ ( 784 ) $ ( 756 )
OCI before reclassifications 2   ( 1 ) 1  
Amounts reclassified from AOCI ( 2 ) 7   5  
Net current-period OCI —   6   6  
Balance at June 30, 2026 $ 28   $ ( 778 ) $ ( 750 )

Three Months Ended June 30, 2025  Cash Flow Hedges Pension and Non-Pension Postretirement Benefit Plan Items (a)
Total
Balance at March 31, 2025 $ 37   $ ( 755 ) $ ( 718 )
OCI before reclassifications ( 4 ) 1   ( 3 )
Amounts reclassified from AOCI ( 2 ) 5   3  
Net current-period OCI ( 6 ) 6   —  
Balance at June 30, 2025 $ 31   $ ( 749 ) $ ( 718 )

Six Months Ended June 30, 2026  Cash Flow Hedges Pension and Non-Pension Postretirement Benefit Plan Items (a)
Total
Balance at December 31, 2025 $ 33   $ ( 795 ) $ ( 762 )
OCI before reclassifications ( 2 ) 3   1  
Amounts reclassified from AOCI ( 3 ) 14   11  
Net current-period OCI ( 5 ) 17   12  
Balance at June 30, 2026 $ 28   $ ( 778 ) $ ( 750 )

Six Months Ended June 30, 2025  Cash Flow Hedges Pension and Non-Pension Postretirement Benefit Plan Items (a)
Total
Balance at December 31, 2024 $ 45   $ ( 765 ) $ ( 720 )
OCI before reclassifications ( 11 ) 5   ( 6 )
Amounts reclassified from AOCI ( 3 ) 11   8  
Net current-period OCI ( 14 ) 16   2  
Balance at June 30, 2025 $ 31   $ ( 749 ) $ ( 718 )

______
(a) This AOCI component is included in the computation of net periodic pension and OPEB cost. See Note 12 — Retirement Benefits of the 2025 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 June 30, Six Months Ended June 30,
2026 2025 2026 2025
Pension and non-pension postretirement benefit plans:

Actuarial losses reclassified to periodic benefit cost $ ( 2 ) $ ( 2 ) $ ( 4 ) $ ( 4 )
Pension and non-pension postretirement benefit plans valuation adjustments 1   —   —   ( 2 )
Unrealized gains on cash flow hedges —   —   —   2  

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 June 30, 2026
Utility taxes (a)
$ 253   $ 86   $ 51   $ 27   $ 89   $ 81   $ 7   $ 1  
Property 124   10   5   63   46   30   15   1  
Payroll 36   9   5   4   9   2   1   1  

Three Months Ended June 30, 2025
Utility taxes (a)
$ 247   $ 79   $ 47   $ 33   $ 88   $ 80   $ 7   $ 1  
Property 111   8   4   57   40   27   12   1  
Payroll 34   9   5   5   8   2   1   1  

Six Months Ended June 30, 2026
Utility taxes (a)
$ 528   $ 171   $ 109   $ 63   $ 185   $ 167   $ 16   $ 2  
Property 250   20   10   126   93   60   31   1  
Payroll 70   18   10   8   17   4   2   2  

Six Months Ended June 30, 2025
Utility taxes (a)
$ 496   $ 159   $ 98   $ 58   $ 181   $ 164   $ 15   $ 2  
Property 222   18   9   114   80   55   24   1  
Payroll 67   16   9   10   15   3   2   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 June 30, 2026
AFUDC — Equity $ 63   $ 24   $ 11   $ 16   $ 12   $ 9   $ 2   $ 1  
Non-service net periodic benefit cost ( 11 ) —   —   —   —   —   —   —  

Three Months Ended June 30, 2025
AFUDC — Equity $ 43   $ 14   $ 10   $ 9   $ 10   $ 8   $ 1   $ 1  
Non-service net periodic benefit cost ( 13 ) —   —   —   —   —   —   —  

Six Months Ended June 30, 2026
AFUDC — Equity $ 120   $ 45   $ 21   $ 30   $ 24   $ 19   $ 3   $ 2  
Non-service net periodic benefit cost ( 21 ) —   —   —   —   —   —   —  

Six Months Ended June 30, 2025
AFUDC — Equity $ 81   $ 26   $ 17   $ 18   $ 20   $ 15   $ 3   $ 2  
Non-service net periodic benefit cost ( 26 ) —   —   —   —   —   —   —  

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
Six Months Ended June 30, 2026
Property, plant, and equipment (a)
$ 1,605   $ 639   $ 246   $ 267   $ 427   $ 189   $ 120   ` $ 116  
Amortization of regulatory assets and liabilities, net (a)
315   181   1   67   64   39   13   12  
Amortization of intangible assets, net (a)
—   —   —   —   —   —   —   —  

ARO accretion (b)
1   —   —   —   —   —   —   —  
Total depreciation, amortization, and accretion $ 1,921   $ 820   $ 247   $ 334   $ 491   $ 228   $ 133   $ 128  

Six Months Ended June 30, 2025
Property, plant, and equipment (a)
$ 1,506   $ 608   $ 219   $ 249   $ 402   $ 177   $ 113   $ 111  
Amortization of regulatory assets and liabilities, net (a)
296   159   2   69   65   35   13   16  
Amortization of intangible assets, net (a)
3   —   —   —   —   —   —   —  

ARO accretion (b)
1   —   —   —   —   —   —   —  
Total depreciation, amortization, and accretion $ 1,806   $ 767   $ 221   $ 318   $ 467   $ 212   $ 126   $ 127  

__________
(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
Six Months Ended June 30, 2026
Pension and OPEB costs $ 129   $ 54   $ 8   $ 14   $ 41   $ 14   $ 7   $ 5  
Allowance for credit losses 171   35   48   53   35   17   7   11  

True-up adjustments to decoupling mechanisms and formula rates (a)
98   46   ( 10 ) 18   44   14   5   25  

Amortization of operating ROU asset 11   —   —   3   5   1   2   1  

AFUDC — Equity ( 120 ) ( 45 ) ( 21 ) ( 30 ) ( 24 ) ( 19 ) ( 3 ) ( 2 )

Six Months Ended June 30, 2025
Pension and OPEB costs $ 136   $ 42   $ 3   $ 30   $ 49   $ 18   $ 8   $ 6  
Allowance for credit losses 137   23   50   17   47   19   11   17  

True-up adjustments to decoupling mechanisms and formula rates (a)
397   319   8   43   27   14   5   8  

Amortization of operating ROU asset 16   —   —   4   9   2   3   1  

AFUDC — Equity ( 81 ) ( 26 ) ( 17 ) ( 18 ) ( 20 ) ( 15 ) ( 3 ) ( 2 )

__________
(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 2 — Regulatory Matters of the 2025 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 June 30, 2026
Cash and cash equivalents $ 1,813   $ 704   $ 39   $ 1,010   $ 47   $ 21   $ 8   $ 13  
Restricted cash and cash equivalents 608   533   —   4   36   31   2   2  
Restricted cash included in Other deferred debits and other assets 9   9   —   —   —   —   —   —  
Total cash, restricted cash, and cash equivalents $ 2,430   $ 1,246   $ 39   $ 1,014   $ 83   $ 52   $ 10   $ 15  

Balance at December 31, 2025
Cash and cash equivalents $ 626   $ 159   $ 116   $ 217   $ 103   $ 22   $ 9   $ 22  
Restricted cash and cash equivalents 525   454   —   3   38   33   3   2  
Restricted cash included in Other deferred debits and other assets 50   50   —   —   —   —   —   —  
Total cash, restricted cash, and cash equivalents $ 1,201   $ 663   $ 116   $ 220   $ 141   $ 55   $ 12   $ 24  

Balance at June 30, 2025
Cash and cash equivalents $ 724   $ 387   $ 25   $ 236   $ 67   $ 22   $ 9   $ 15  
Restricted cash and cash equivalents 478   411   —   5   30   22   5   2  
Restricted cash included in Other deferred debits and other assets 49   49   —   —   —   —   —   —  
Total cash, restricted cash, and cash equivalents $ 1,251   $ 847   $ 25   $ 241   $ 97   $ 44   $ 14   $ 17  

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  

For additional information on restricted cash see Note 1 — Significant Accounting Policies of the 2025 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 June 30, 2026
Compensation-related accruals (a)
$ 503   $ 140   $ 77   $ 69   $ 102   $ 29   $ 21   $ 15  
Taxes accrued 224   91   6   32   88   64   10   10  
Interest accrued 583   165   75   58   99   52   20   22  

Balance at December 31, 2025
Compensation-related accruals (a)
$ 705   $ 209   $ 96   $ 99   $ 125   $ 35   $ 24   $ 17  
Taxes accrued 242   94   306   191   107   69   25   18  
Interest accrued 538   155   75   55   92   49   18   20  

__________
(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 June 30, Six Months Ended June 30, Three Months Ended June 30, Six Months Ended June 30,
2026 2025 2026 2025 2026 2025 2026 2025
Exelon
   BSC $ 117   $ 162   $ 251   $ 323  
   PHISCO 28   29   51   53  
ComEd
   BSC $ 109   $ 100   $ 212   $ 200   51   61   111   124  
PECO
   BSC 68   61   133   120   19   28   40   54  
BGE
   BSC 71   63   137   125   20   32   41   65  
PHI
   BSC 58   49   116   100   28   41   58   80  
   PHISCO —   —   —   —   28   29   51   53  
Pepco
   BSC 37   32   72   63   12   17   25   34  
   PHISCO 35   32   67   62   12   12   22   23  

DPL
   BSC 23   20   45   40   9   12   18   24  
   PHISCO 27   26   51   50   8   9   15   16  

ACE
   BSC 19   16   36   32   6   9   13   18  
   PHISCO 25   24   51   47   7   8   14   14  

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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

Receivables from/Payables to Affiliates
The following tables present Receivables from affiliates and Payables to affiliates:
June 30, 2026

Receivables from affiliates:
Payables to affiliates: ComEd PECO BGE Pepco DPL ACE BSC PHISCO Other Total
ComEd $ —   $ —   $ —   $ —   $ —   $ 69   $ —   $ 6   $ 75  
PECO $ —   —   —   —   —   33   —   3   36  
BGE —   —   —   —   —   38   —   1   39  
PHI (a)
—   —   —   —   —   —   6   —   5   11  
Pepco —   —   —   —   —   22   18   1   41  
DPL —   —   —   —   —   14   13   1   28  
ACE —   —   —   —   —   11   11   1   23  

Other 5   —   —   —   4   1   —   —   10  
Total $ 5   $ —   $ —   $ —   $ 4   $ 1   $ 193   $ 42   $ 18   $ 263  

December 31, 2025

Receivables from affiliates:
Payables to affiliates: ComEd PECO BGE Pepco DPL ACE BSC PHISCO Other Total
ComEd $ —   $ —   $ —   $ —   $ —   $ 76   $ —   $ 5   $ 81  
PECO $ —   —   —   —   —   33   —   2   35  
BGE —   —   —   —   —   39   —   —   39  
PHI (a)
—   —   —   —   —   —   5   2   11   18  
Pepco —   —   —   —   —   25   11   1   37  
DPL —   —   —   —   —   15   10   —   25  
ACE —   —   —   —   —   14   10   —   24  
Other 5   —   1   —   2   12   —   —   20  
Total $ 5   $ —   $ 1   $ —   $ 2   $ 12   $ 207   $ 33   $ 19   $ 279  

__________
(a) PHI is presented exclusive of Pepco, DPL, and ACE, which are included in the table herein.
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:

June 30, 2026 December 31, 2025
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 six months ended June 30, 2026 compared to the same period in 2025. For additional information regarding the financial results for the three and six months ended June 30, 2026 and 2025, see the discussions of Results of Operations by Registrant.

Three Months Ended June 30, Favorable (Unfavorable) Variance Six Months Ended June 30, Favorable (Unfavorable) Variance
2026 2025 2026 2025
Exelon $ 396  $ 391  $ 5  $ 1,315  $ 1,300  $ 15 
ComEd 249  228  21  559  530  29 
PECO 119  136  (17) 397  402  (5)
BGE 55  55  —  353  315  38 
PHI 109  143  (34) 278  337  (59)
Pepco 65  84  (19) 133  181  (48)
DPL 26  39  (13) 103  108  (5)
ACE 22  24  (2) 49  56  (7)
Other (a)
(136) (171) 35  (272) (284) 12 

__________
(a) Other primarily includes eliminating and consolidating adjustments, Exelon’s corporate operations, shared service entities, and other financing and investment activities.
Three Months Ended June 30, 2026 Compared to Three Months Ended June 30, 2025. Net income attributable to common shareholders increased by $5 million and diluted earnings per average common share remained relatively consistent to the prior year at $0.39 primarily due to:
• Favorable impacts of approved rate increases at ComEd, BGE and PHI;
• Absence of Customer Relief Fund contribution at Exelon Corporate;
• Absence of Customer Surcharge Credits at PECO;
• Higher AFUDC at ComEd; and
• Favorable weather at PECO.
Note that rate increases are associated with updated recovery rates for costs and investments to serve customers. The increases were partially offset by:
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• Higher depreciation expense at PECO and PHI;
• Higher interest expense at PECO and Exelon Corporate; and
• Higher credit loss expense at BGE.
Six Months Ended June 30, 2026 Compared to Six Months Ended June 30, 2025. Net income attributable to common shareholders increased by $15 million and diluted earnings per average common share decreased to $1.28 in 2026 from $1.29 in 2025 primarily due to:
• Favorable impacts of approved rate increases at ComEd, BGE and PHI;
• Absence of Customer Relief Fund contribution at Exelon Corporate;
• Absence of Customer Surcharge Credits at PECO;
• Higher AFUDC at ComEd; and
• Favorable weather at PECO;
Note that rate increases are associated with updated recovery rates for costs and investments to serve customers, driving top quartile reliability and avoiding outage costs. The increases were partially offset by:
• Timing of distribution earnings at ComEd;
• Higher interest expense at PECO, PHI, and Exelon Corporate;
• Higher depreciation expense at PECO and PHI;
• Higher credit loss expense at BGE; and
• Unfavorable impacts of the Pepco Maryland multi-year plan reconciliation 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 six months ended June 30, 2026 compared to the same period in 2025:

Three Months Ended June 30,
2026 2025
(In millions, except per share data) Earnings per
Diluted Share Earnings per
Diluted Share
Net income attributable to common shareholders $ 396   $ 0.39   $ 391   $ 0.39  

Cost management program (net of taxes of $16) (a)
42  0.04  —  — 
Income tax-related adjustments (entire amount represents tax expense) (b)
—  —  1  — 
Adjusted (non-GAAP) operating earnings $ 438   $ 0.43   $ 392   $ 0.39  

Six Months Ended June 30,
2026 2025
(In millions, except per share data) Earnings per
Diluted Share Earnings per
Diluted Share
Net income attributable to common shareholders $ 1,315   $ 1.28   $ 1,300   $ 1.29  

Change in FERC audit liability (net of taxes of $1)
—  —  2  — 

Cost management program (net of taxes of $16 and $0, respectively) (a)
42  0.04  (1) — 
Income tax-related adjustments (entire amount represents tax expense) (b)
—  —  1  — 
Regulatory matters (net of taxes of $4 and $7, respectively) (c)
11  0.01  22  0.02 

Adjusted (non-GAAP) operating earnings $ 1,368   $ 1.33   $ 1,324   $ 1.31  

__________
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 2026 and 2025 ranged from 24.0% to 29.0%.

(a) Primarily represents severance costs related to cost management program.
(b) Reflects the adjustment to state deferred income taxes due to changes in forecasted apportionment.
(c) Represents the disallowance of certain capitalized costs.

Significant 2026 Transactions and Developments
At-the-Market Program
In the second quarter of 2026, Exelon issued approximately 8.7 million shares of Common stock at a weighted-average net price of $44.03 per share. The net proceeds from the issuance were $382 million, which were used for general corporate purposes. See Note 12 — Shareholders' Equity of the Combined Notes to Consolidated Financial Statements for additional information.
Distribution Base Rate Case Proceedings
The Utility Registrants file base rate cases with their regulatory commissions seeking increases or decreases to their electric transmission and distribution, and gas distribution rates to recover their costs and earn a fair return on their investments. The outcomes of these regulatory proceedings impact the Utility Registrants’ current and future financial statements.
The following tables show the Utility Registrants’ completed and pending distribution base rate case proceedings in 2026. 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
September 20, 2024 (amended September 5, 2025) Natural Gas $ 37  $ 22  9.60% December 17, 2025 January 1, 2026
ACE - New Jersey November 21, 2024 Electric $ 109  $ 54  9.60% November 21, 2025 December 1, 2025

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Pending Distribution Base Rate Case Proceedings

Registrant/Jurisdiction Filing Date Service Requested Revenue Requirement Increase Requested ROE Expected Approval Timing

Pepco - Maryland October 14, 2025 (amended April 16, 2026) Electric $ 120  10.50% Third quarter of 2026
DPL - Delaware December 9, 2025 (amended June 1, 2026) Electric $ 45  10.50% Third quarter of 2027
BGE - Maryland July 2, 2026 Electric $ 156  10.40% First quarter of 2027

Transmission Formula Rates
For 2026, the following increases/(decreases) were included in the Utility Registrants' 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 (Decrease) Increase Total Revenue Requirement (Decrease) Increase Allowed Return on Rate Base Allowed ROE
ComEd $ 31  $ (52) $ (21) 8.15  % 11.50  %
PECO $ 20  $ 20  $ 40  7.62  % 10.35  %
BGE $ 16  $ (40) $ (30) 7.51  % 10.50  %
Pepco $ 12  $ (21) $ (9) 7.72  % 10.50  %
DPL $ 3  $ 1  $ 4  7.53  % 10.50  %
ACE $ 1  $ 16  $ 17  7.26  % 10.50  %

2026 PECO Distribution Base Rate Filing

On April 16, 2026, PECO filed a petition with the PAPUC to withdraw its previously filed electric and gas distribution rate proceedings submitted on March 30, 2026. The PAPUC approved the petition to withdraw the rate cases on April 30, 2026.

PECO will continue to evaluate the timing and approach for future capital investments and potential regulatory filings. Any decisions related to capital investments to support longer-term grid modernization will be informed by customer affordability considerations, system reliability needs, and ongoing engagement with regulators and other stakeholders. As PECO assesses longer-term grid needs, it remains committed to providing safe and reliable service.

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 will now pay the greater of 15.0% of financial statement pre-tax income (with certain adjustments) or their regular federal tax liability, which is federal taxable income multiplied by the 21.0% federal corporate tax rate. Corporations are entitled to a tax credit (minimum tax credit) to the extent the CAMT liability exceeds the regular tax liability. This amount can be carried forward indefinitely and used in future years when regular tax exceeds the CAMT.
For the years ended December 31, 2025, December 31, 2024, and December 31, 2023, based on the existing guidance in effect at that time, Exelon and each of the Utility Registrants were subject to and reported the CAMT on a separate Registrant basis in the Consolidated Statements of Operations and Comprehensive Income and the Consolidated Balance Sheets.
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On February 18, 2026, the U.S. Treasury issued guidance addressing the implementation of CAMT in the form of a notice. The new guidance permits corporate taxpayers to deduct repair and maintenance costs in the calculation of their CAMT liabilities. The notice applies retroactively, permitting Exelon to file amended returns for both 2024 and 2023 to reduce its CAMT liability by $80 million. Pursuant to the TMA, Exelon received reimbursement from Constellation for $235 million due to the reduction in the amount of Constellation's tax credits needed to offset Exelon's CAMT liability on its amended returns. See Note 6 – Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information.
The impact of the notice was recorded as of March 31, 2026.

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 2025 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 2025 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.
Exelon’s Cost Saving Strategy (All Registrants)

In May 2026, Exelon announced plans to identify approximately $350 million of operating and maintenance costs savings at Exelon and the Utility Registrants in 2027. This announcement is a result of Exelon’s continuous focus on the needs of our customers through enhanced efficiency and productivity.
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 $0.8 billion - $1.2 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

Maryland Utility Relief Act (Exelon, BGE, PHI, Pepco, and DPL)
On May 12, 2026, the Governor of Maryland signed into law legislation that addresses several matters pertaining to electric and gas utilities, including a moratorium on rate cases with forecasted test years until April 1, 2027. Additionally, BGE, Pepco and DPL are required to participate as a member in an RTO effective July 1, 2026, which resulted in a complaint filed on July 2, 2026 against Maryland Transmission Operators, including BGE, Pepco, and DPL, at FERC for the removal of the 50-basis-point incentive adder in the transmission formula rates. The final outcome and resolution of the complaint filing cannot be predicted and the results are not expected to be material to Exelon, BGE, PHI, Pepco, and DPL financial statements.
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PJM Cost Allocation Methodology (All Registrants)
On March 6, 2026, FERC issued an order requiring the removal of the de minimis threshold exemption in the calculation of the cost responsibility of certain transmission reliability upgrade costs allocated to the rate zones of PJM Transmission Owners, including the Utility Registrants. FERC further ordered PJM to recalculate historical cost allocations for the period beginning June 18, 2015, and to pass through additional charges or payments to PJM customers, including Utility Registrants, as applicable, with interest within 90 days. On April 29, 2026, the time for those calculations was extended until further order from FERC. The Utility Registrants expect to recover any incremental charges incurred or reimburse any payments received through prospective electric customer rates. On April 6, 2026, a number of parties filed requests for rehearing or clarification, which were denied by operation of law on May 7, 2026. On May 12, 2026, PJM Transmission Owners, including Exelon, on behalf of the Utility Registrants, filed a petition for review at the United States Court of Appeals for the D.C. Circuit.
The final impacts of the decision cannot be predicted and the results, while not reasonably estimable at this time, could be material to the financial statements.
New Jersey Repeal RTO Adder Bill (Exelon, PHI, and ACE)
On July 7, 2026, the Governor of New Jersey signed into law legislation that addresses several matters pertaining to electric utility companies. As part of the legislation ACE is required to participate as a member in an RTO effective January 1, 2027, which could result in a complaint filed for the removal of the 50-basis-point incentive adder in the transmission formula rates.
Delaware Senate Bill 326 (Exelon, PHI, and DPL)
On July 13, 2026, the Governor of Delaware signed into law legislation that addresses several matters pertaining to public utility companies. As part of the law, DPL’s non-mandatory capital spend eligible to be recovered in rates will be limited to $70 million in each of the years ended 2026 and 2027 unless the spend falls within an exception or the commission orders otherwise. Further, beginning in 2028, DPL’s non-mandatory capital spend eligible to be recovered in rates shall not exceed 5% of DPL’s rate base approved in its most recent base rate case. The legislation also modifies the timing of interim rate recovery in base rate case proceedings. If the DEPSC has not issued a decision within 7 months of a filing, DPL may implement 50% of the proposed rate increase, subject to refund. If no decision has been issued after 12 months, DPL may implement 75% of the proposed increase, also subject to refund. DPL is continuing to evaluate the overall potential impacts of the legislation and will continue to monitor related regulatory developments.

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 June 30, 2026, the Registrants’ critical accounting policies and estimates had not changed significantly from December 31, 2025. See ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS — Critical Accounting Policies and Estimates in the 2025 Form 10-K for further information.
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Results of Operations by Registrant

Results of Operations — ComEd

Three Months Ended
June 30, Favorable (Unfavorable) Variance Six Months Ended
June 30, (Unfavorable) Favorable Variance
2026 2025 2026 2025
Operating revenues $ 1,985  $ 1,836  $ 149  $ 3,898  $ 3,901  $ (3)
Operating expenses
Purchased power 579  550  (29) 1,031  1,239  208 
Operating and maintenance 449  422  (27) 886  845  (41)
Depreciation and amortization 416  387  (29) 820  767  (53)
Taxes other than income taxes 107  97  (10) 212  196  (16)
Total operating expenses 1,551  1,456  (95) 2,949  3,047  98 

Operating income 434  380  54  949  854  95 
Other income and (deductions)
Interest expense, net (143) (131) (12) (279) (260) (19)
Other, net 41  31  10  73  53  20 
Total other income and (deductions) (102) (100) (2) (206) (207) 1 
Income before income taxes 332  280  52  743  647  96 
Income taxes 83  52  (31) 184  117  (67)
Net income $ 249  $ 228  $ 21  $ 559  $ 530  $ 29 

Three Months Ended June 30, 2026 Compared to Three Months Ended June 30, 2025. Net Income increased by $21 million as compared to the same period in 2025, primarily due to higher distribution and transmission rate base driven by incremental investments to serve customers and higher AFUDC.
Six Months Ended June 30, 2026 Compared to Six Months Ended June 30, 2025. Net income increased by $29 million as compared to the same period in 2025, primarily due to higher distribution and transmission rate base driven by incremental investments to serve customers and higher AFUDC, offset by the timing of distribution earnings.
The changes in Operating revenues consisted of the following:

Three Months Ended
June 30, 2026 Six Months Ended
June 30, 2026
Increase (Decrease) Increase (Decrease)
Distribution $ 24  $ 16 
Transmission 13  33 
Energy efficiency 14  22 
Other (8) (5)
43  66 
Regulatory required programs 106  (69)
Total increase (decrease) $ 149  $ (3)

Revenue Decoupling. The demand for electricity is affected by weather and customer usage. Operating revenues are not intended to be impacted by abnormal weather, usage per customer, or number of customers as a result of revenue decoupling mechanisms.
Distribution Revenue. Starting in 2024, distribution revenues are under a MRP. The MRP requires an annual reconciliation of the revenue requirement in effect to the actual costs the ICC determines are prudently and reasonably incurred. Electric distribution revenue varies from year to year based upon fluctuations in the underlying costs (e.g., severe weather and storm restoration), investments being recovered, and allowed ROE. Electric distribution revenues increased for the three and six months ended June 30, 2026 as compared to the same periods in 2025, primarily due to higher rate base and higher fully recoverable costs.
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Transmission Revenue. Under a FERC-approved formula, transmission revenue varies from year to year based upon fluctuations in the underlying costs and capital investments being recovered. Transmission revenues increased for the three and six months ended June 30, 2026 compared to the same periods in 2025, primarily due to higher rate base and higher fully recoverable costs.
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 six months ended June 30, 2026 as compared to the same periods in 2025, primarily due to higher fully recoverable costs.
Other Revenue primarily includes assistance provided to other utilities through mutual assistance programs. Other revenues decreased for the three and six months ended June 30, 2026 as compared to the same periods in 2025, 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. 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, this is treated as a pass through for ComEd and therefore, financial results are not impacted if customers purchase electricity supply from these alternative suppliers. For customers that choose to purchase electric generation from ComEd, ComEd is permitted to recover costs from customers.
See Note 4 — Segment Information of the Combined Notes to Consolidated Financial Statements for the presentation of ComEd's revenue disaggregation.
The increase of $29 million for the three months ended June 30, 2026 and the decrease of $208 million for the six months ended June 30, 2026, compared to the same periods in 2025, in Purchased power expense is offset in Operating revenues as part of regulatory required programs.

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

Three Months Ended
June 30, 2026 Six Months Ended
June 30, 2026
Increase (Decrease) Increase (Decrease)
Labor, other benefits, contracting, and materials $ 19  $ 40 
Storm-related costs (3) 9 
BSC costs 9  12 
Pension and non-pension postretirement benefits expense 3  5 

Other (a)
(7) (39)
21  27 
Regulatory required programs 6  14 
Total increase $ 27  $ 41 
__________
(a) Primarily reflects the disallowance of certain capitalized costs in regulatory matters during the three months ended March 31, 2025.

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

Three Months Ended
June 30, 2026 Six Months Ended
June 30, 2026
Increase Increase
Depreciation and amortization (a)
$ 16  $ 31 
Regulatory asset amortization 13  22 

Total increase $ 29  $ 53 

__________
(a) Reflects ongoing capital expenditures.
Other , net increased $10 million and $20 million for the three and six months ended June 30, 2026, respectively, compared to the same periods in 2025, primarily due to higher AFUDC equity.
Effective income tax rat es were 25.0% and 18.6% for the three months ended June 30, 2026 and 2025, respectively, and 24.8% and 18.1% for the six months ended June 30, 2026 and 2025, 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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Results of Operations — PECO

Three Months Ended
June 30, Favorable (Unfavorable) Variance Six Months Ended
June 30, Favorable (Unfavorable) Variance
2026 2025 2026 2025
Operating revenues $ 1,062  $ 1,000  $ 62  $ 2,554  $ 2,333  $ 221 
Operating expenses
Purchased power and fuel 389  339  (50) 1,001  841  (160)
Operating and maintenance 300  305  5  636  631  (5)
Depreciation and amortization 125  112  (13) 247  221  (26)
Taxes other than income taxes 62  54  (8) 131  115  (16)
Total operating expenses 876  810  (66) 2,015  1,808  (207)

Operating income 186  190  (4) 539  525  14 
Other income and (deductions)
Interest expense, net (72) (60) (12) (144) (124) (20)
Other, net 13  10  3  25  18  7 
Total other income and (deductions) (59) (50) (9) (119) (106) (13)
Income before income taxes 127  140  (13) 420  419  1 
Income taxes 8  4  (4) 23  17  (6)

Net income $ 119  $ 136  $ (17) $ 397  $ 402  $ (5)

Three Months Ended June 30, 2026 Compared to Three Months Ended June 30, 2025. Net Income decreased by $17 million due to an increase in depreciation, interest expense, tax repairs, a portion of which is timing, and severance costs related to the cost management program, partially offset by higher revenues resulting from the absence of surcharge credits to customers, and favorable weather.
Six Months Ended June 30, 2026 Compared to Six Months Ended June 30, 2025. Net income decreased by $5 million due to an increase in depreciation, interest expense, and severance costs related to the cost management program, partially offset by higher revenues resulting from the absence of surcharge credits to customers, and favorable weather.
The changes in Operating revenues consisted of the following:

Three Months Ended
June 30, 2026 Six Months Ended
June 30, 2026
Increase (Decrease) Increase (Decrease)
Electric Gas Total Electric Gas Total
Weather $ 6  $ (1) $ 5  $ 14  $ 7  $ 21 
Volume (7) 1  (6) (10) 2  (8)
Pricing (1) (1) (2) 4  —  4 
Transmission 4  —  4  16  —  16 
Other (a)
16  (1) 15  40  4  44 
18  (2) 16  64  13  77 
Regulatory required programs 43  3  46  122  22  144 
Total increase $ 61  $ 1  $ 62  $ 186  $ 35  $ 221 
__________
(a) Other revenues increased primarily due to the absence of electric surcharge credits to customers recognized in 2025.

Weather. The demand for electricity and natural gas is affected by weather conditions. With respect to the electric business, very warm weather in summer months and, with respect to the electric and natural gas businesses, very cold weather in winter months are referred to as “favorable weather conditions” because these weather conditions result in increased deliveries of electricity and natural gas. Conversely, mild weather reduces demand. During the three and six months ended June 30, 2026 , compared to the same period in 2025, Operating revenues related to weather increased due to favorable weather conditions in PECO's service territory.
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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 six months ended June 30, 2026, compared to the same period in 2025, and normal weather consisted of the following:

Three Months Ended June 30, % Change
PECO Service Territory 2026 2025 Normal 2026 vs. 2025 2026 vs. Normal
Heating Degree-Days 321 333 415 (3.6) % (22.7) %
Cooling Degree-Days 526 425 387 23.8  % 35.9  %
Six Months Ended June 30, % Change
2026 2025 Normal 2026 vs. 2025 2026 vs. Normal
Heating Degree-Days 2,720  2,684 2,774 1.3  % (1.9) %
Cooling Degree-Days 536  426 388 25.8  % 38.1  %

Volume. Electric volume, exclusive of the effects of weather, for the three and six months ended June 30, 2026 compared to the same period in 2025, decreased due to customer load. Natural gas volume for the three and six months ended June 30, 2026, compared to the same period in 2025, remained relatively consistent.

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

2026 2025 2026 2025
Residential 3,042 3,030 0.4  % (1.8) % 6,994 6,889 1.5  % (0.7) %
Small commercial & industrial 1,742 1,832 (4.9) % (3.6) % 3,752 3,778 (0.7) % (1.2) %
Large commercial & industrial 3,426 3,314 3.4  % 2.4  % 6,558 6,739 (2.7) % (3.9) %
Public authorities & electric railroads 157 163 (3.7) % (3.6) % 333 352 (5.4) % (5.4) %
Total electric retail deliveries (a)
8,367 8,339 0.3  % (0.5) % 17,637 17,758 (0.7) % (2.1) %

At June 30,
Number of Electric Customers 2026 2025
Residential 1,540,384 1,538,280
Small commercial & industrial 154,463 154,977
Large commercial & industrial 3,141 3,155
Public authorities & electric railroads 10,133 10,343
Total 1,708,121 1,706,755

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

2026 2025 2026 2025
Residential 4,525 4,571 (1.0) % 1.9  % 26,961 26,405 2.1  % (-0.4)%
Small commercial & industrial 3,072 3,398 (9.6) % (9.0) % 14,423 13,803 4.5  % 2.3  %
Large commercial & industrial 1 2 (50.0) % 2.3  % (9) 14 (164.3) % (10.5) %
Transportation 6,578 5,436 21.0  % 25.6  % 13,720 12,678 8.2  % 9.2  %
Total natural gas deliveries (a)
14,176 13,407 5.7  % 8.1  % 55,095 52,900 4.1  % 2.5  %

  At June 30,
Number of Natural Gas Customers 2026 2025
Residential 511,121 509,671
Small commercial & industrial 44,494 44,646
Large commercial & industrial 7 7
Transportation 605 623
Total 556,227 554,947

__________
(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 six months ended June 30, 2026, compared to the same period in 2025, remained relatively consistent.
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 six months ended June 30, 2026, compared to the same period in 2025, increased primarily due to increases in the underlying costs and capital investments.
Other Revenue primarily includes revenue related to late payment charges. Other revenue for the three and six months ended June 30, 2026, compared to the same period in 2025, increased primarily due to the absence of electric surcharge credits to customers recognized in 2025.
Regulatory Required Programs represent revenues collected under approved riders to recover costs incurred for regulatory programs. 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 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. For customers that choose to purchase electric generation or natural gas from competitive suppliers, this is treated as a pass through for PECO and therefore, financial results are not impacted if customers purchase electricity or natural gas supply from these alternative suppliers. For customers that choose to purchase electric generation or natural gas from PECO, PECO is permitted to recover costs from customers.
See Note 4 — Segment Information of the Combined Notes to Consolidated Financial Statements for the presentation of PECO's revenue disaggregation.
The increase of $50 million and $160 million for the three and six months ended June 30, 2026, compared to the same period in 2025, in Purchased power and fuel expense is fully offset in Operating revenues as part of regulatory required programs.

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PECO

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

Three Months Ended
June 30, 2026 Six Months Ended
June 30, 2026
Increase (Decrease) Increase (Decrease)
Labor, other benefits, contracting and materials (a)
$ 29  $ 45 
BSC costs 8  13 
Pension and non-pension postretirement benefit expense 1  3 
Credit loss expense (2) (4)
Storm-related costs (32) (39)
Other —  15 
4  33 
Regulatory required programs (9) (28)
Total (decrease) increase $ (5) $ 5 

__________
(a) Reflects severance related to cost management program
The changes in Depreciation and amortization expense consisted of the following:

Three Months Ended June 30, 2026 Six Months Ended
June 30, 2026
Increase Increase (Decrease)
Depreciation and amortization (a)
$ 13  $ 27 
Regulatory asset amortization —  (1)

Total increase $ 13  $ 26 

__________
(a) Depreciation and amortization expense increased primarily due to ongoing capital expenditures.
Taxes other than income taxes increased by $8 million and $16 million for the three and six months ended June 30, 2026, respectively, compared to the same period in 2025, primarily due to higher Pennsylvania gross receipts tax.
Interest expense, net increased by $12 million and $20 million for the three and six months ended June 30, 2026, respectively, compared to the same period in 2025, primarily due to an increase in interest rates and higher outstanding debt.
Effective income tax rates were 6.3% and 2.9% for the three months ended June 30, 2026 and 2025, respectively, and 5.5% and 4.1% for the six months ended June 30, 2026 and 2025, 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
June 30, Favorable (Unfavorable) Variance Six Months Ended
June 30, Favorable (Unfavorable) Variance
2026 2025 2026 2025
Operating revenues $ 1,218  $ 1,029  $ 189  $ 3,046  $ 2,583  $ 463 
Operating expenses
Purchased power and fuel 545  406  (139) 1,353  1,016  (337)
Operating and maintenance 293  264  (29) 619  568  (51)
Depreciation and amortization 166  154  (12) 334  318  (16)
Taxes other than income taxes 96  85  (11) 200  181  (19)
Total operating expenses 1,100  909  (191) 2,506  2,083  (423)

Operating income 118  120  (2) 540  500  40 
Other income and (deductions)
Interest expense, net (68) (61) (7) (129) (120) (9)
Other, net 22  11  11  38  20  18 
Total other income and (deductions) (46) (50) 4  (91) (100) 9 
Income before income taxes 72  70  2  449  400  49 
Income taxes 17  15  (2) 96  85  (11)
Net income $ 55  $ 55  $ —  $ 353  $ 315  $ 38 

Three Months Ended June 30, 2026 Compared to Three Months Ended June 30, 2025 . Net income remained consistent primarily due to approved distribution rates, the absence of the derecognition of regulatory assets for multi-year plan reconciliations that occurred during the second quarter of 2025, and a decrease in various operating expenses, offset by an increase in credit loss expense and severance costs related to the cost management program.
Six Months Ended June 30, 2026 Compared to Six Months Ended June 30, 2025. Net income increased $38 million primarily due to approved distribution rates, the absence of the derecognition of regulatory assets for multi-year plan reconciliations that occurred during the second quarter of 2025, and a decrease in various operating expenses, partially offset by an increase in credit loss expense and severance costs related to the cost management program.
The changes in Operating revenues consisted of the following:

Three Months Ended
June 30, Six Months Ended
June 30,
Increase (Decrease) Increase (Decrease)
Electric Gas Total Electric Gas Total
Distribution $ 11  $ 7  $ 18  $ 15  $ 29  $ 44 
Transmission 3  —  3  1  —  1 
Other 4  —  4  13  2  15 
18  7  25  29  31  60 
Regulatory required programs 183  (19) 164  406  (3) 403 
Total increase $ 201  $ (12) $ 189  $ 435  $ 28  $ 463 

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 June 30,
Number of Electric Customers 2026 2025
Residential 1,230,523  1,219,904 
Small commercial & industrial 114,986  115,316 
Large commercial & industrial 13,430  13,345 
Public authorities & electric railroads 250  257 
Total 1,359,189  1,348,822 

At June 30,
Number of Natural Gas Customers 2026 2025
Residential 664,257  660,049 
Small commercial & industrial 37,638  37,806 
Large commercial & industrial 6,406  6,387 

Total 708,301  704,242 

Distribution Revenue increased for the three and six months ended June 30, 2026, compared to the same period in 2025, 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 for the three and six months ended June 30, 2026, compared to the same period in 2025 remained relatively consistent.
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 six months ended June 30, 2026 as compared to the same period in 2025, primarily driven by increases in late payment charges.
Regulatory Required Programs represent revenues collected under approved riders to recover costs incurred for regulatory programs. 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. For customers that choose to purchase electric generation or natural gas from competitive suppliers, this is treated as a pass through for BGE and therefore, financial results are not impacted if customers purchase electricity or natural gas supply from these alternative suppliers. For customers that choose to purchase electric generation or natural gas from BGE, BGE is permitted to recover costs from customers.
See Note 4 — Segment Information of the Combined Notes to Consolidated Financial Statements for the presentation of BGE's revenue disaggregation.
The increase of $139 million and $337 million for the three and six months ended June 30, 2026, compared to the same period in 2025, in Purchased power and fuel expense is fully offset in Operating revenues as part of regulatory required programs.

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BGE

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

Three Months Ended
June 30, 2026 Six Months Ended
June 30, 2026
  Increase (Decrease) Increase (Decrease)
Credit loss expense $ 25  $ 36 
BSC costs 8  11 
Storm-related costs (4) (4)
Pension and non-pension postretirement benefits expense (5) (10)
Labor, other benefits, contracting and materials (a)
(1) (17)
Other (b)
(19) (18)
4  (2)
Regulatory required programs (c)
25  53 

Total increase $ 29  $ 51 

__________
(a) Reflects severance related to cost management program.
(b) Reflects the absence of the derecognition of regulatory assets for multi-year plan reconciliations that occurred during the second quarter of 2025. Please refer to 2025 10-K Note 2 — Regulatory Matters for additional information.
(c) Reflects the cost recovery associated with EmPOWER Maryland. Please refer to 2025 10-K Note 2 — Regulatory Matters for additional information.
The changes in Depreciation and amortization expense consisted of the following:

Three Months Ended
June 30, 2026 Six Months Ended
June 30, 2026
Increase Increase (Decrease)
Depreciation and amortization $ 8  $ 18 
Regulatory required programs (a)
3  6 
Regulatory asset amortization 1  (8)

Total increase $ 12  $ 16 

__________
(a) Reflects the cost recovery associated with EmPOWER Maryland. Please refer to 2025 10-K Note 2 — Regulatory Matters for additional information.
Taxes other than income taxes increased by $11 million and $19 million for the three and six months ended June 30, 2026, compared to the same period in 2025, primarily due to increased property taxes.
Other, net increased by $11 million and $18 million for the three and six months ended June 30, 2026 compared to the same period in 2025, primarily due to higher AFUDC equity.
Effective income tax rates were 23.6% and 21.4% for the three months ended June 30, 2026 and 2025, and 21.4% and 21.3% for the six months ended June 30, 2026 and 2025. 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 six months ended June 30, 2026 compared to the same periods in 2025. See the Results of Operations for Pepco, DPL, and ACE for additional information.

Three Months Ended
June 30, Unfavorable Variance Six Months Ended June 30, (Unfavorable) Favorable Variance
2026 2025 2026 2025
PHI $ 109  $ 143  $ (34) $ 278  $ 337  $ (59)
Pepco 65  84  (19) 133  181  (48)
DPL
26  39  (13) 103  108  (5)
ACE 22  24  (2) 49  56  (7)
Other (a)
(4) (4) —  (7) (8) 1 

__________
(a) Primarily includes eliminating and consolidating adjustments, PHI's corporate operations, shared service entities, and other financing and investing activities.
Three Months Ended June 30, 2026 Compared to Three Months Ended June 30, 2025. Net Income decreased by $34 million primarily due to an increase in severance costs related to the cost management program, depreciation expense, property taxes at DPL, and various operating expenses, partially offset by approved Delaware electric DSIC and natural gas rates.
Six Months Ended June 30, 2026 Compared to Six Months Ended June 30, 2025. Net Income decreased by $59 million primarily due to an increase in depreciation and interest expenses, property taxes at DPL, unfavorable impacts of the Pepco Maryland multi-year plan reconciliation and related disallowance of capitalized costs, severance costs related to the cost management program, storm costs, and various operating expenses, partially offset by approved Delaware electric DSIC and natural gas rates, approved distribution and transmission rates, and favorable weather conditions at DPL.
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Pepco

Results of Operations — Pepco

Three Months Ended June 30, Favorable (Unfavorable) Variance Six Months Ended June 30, Favorable (Unfavorable) Variance
2026 2025 2026 2025
Operating revenues $ 859  $ 776  $ 83  $ 1,849  $ 1,635  $ 214 

Operating expenses
Purchased power 316  256  (60) 727  574  (153)
Operating and maintenance 190  155  (35) 409  313  (96)
Depreciation and amortization 114  107  (7) 228  212  (16)
Taxes other than income taxes 113  109  (4) 231  222  (9)
Total operating expenses 733  627  (106) 1,595  1,321  (274)
(Loss) gain on sale of assets —  2  (2) —  1  (1)
Operating income 126  151  (25) 254  315  (61)
Other income and (deductions)
Interest expense, net (56) (54) (2) (111) (106) (5)
Other, net 12  9  3  23  20  3 
Total other income and (deductions) (44) (45) 1  (88) (86) (2)
Income before income taxes 82  106  (24) 166  229  (63)
Income taxes 17  22  5  33  48  15 
Net income $ 65  $ 84  $ (19) $ 133  $ 181  $ (48)

Three Months Ended June 30, 2026 Compared to Three Months Ended June 30, 2025. Net Income decreased by $19 million primarily due to increases in severance costs related to the cost management program, depreciation, and various operating expenses.
Six Months Ended June 30, 2026 Compared to Six Months Ended June 30, 2025. Net Income decreased by $48 million primarily due to unfavorable impacts of the Pepco Maryland multi-year plan reconciliation and related disallowance of capitalized costs, increases in depreciation expense, severance costs related to the cost management program, interest, and various operating expenses.
The changes in Operating revenues consisted of the following:

Three Months Ended
June 30, 2026 Six Months Ended
June 30, 2026
Increase (Decrease) Increase
Distribution $ 7  $ 9 
Transmission 2  5 
Other (3) 3 
6  17 
Regulatory required programs 77  197 
Total increase $ 83  $ 214 

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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Pepco

At June 30,
Number of Electric Customers in Maryland 2026 2025
Residential 561,146  558,254 
Small commercial & industrial 30,546  30,512 
Large commercial & industrial 19,083  19,064 
Public authorities & electric railroads 181  177 
Total 610,956  608,007 

Distribution Revenue increased for the three and six months ended June 30, 2026 compared to the same periods in 2025 primarily due to favorable impacts of the 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 six months ended June 30, 2026, compared to the same periods in 2025, 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. 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. For customers that choose to purchase electric generation from competitive suppliers, this is treated as a pass through for Pepco and therefore, financial results are not impacted if customers purchase electricity supply from these alternative suppliers. For customers that choose to purchase electric generation from Pepco, Pepco is permitted to recover the costs from customers.
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 $60 million and $153 million for the three and six months ended June 30, 2026, respectively, compared to the same periods in 2025, in Purchased power expense is fully offset in Operating revenues as part of regulatory required programs.
The changes in Operating and maintenance expense consisted of the following:

Three Months Ended
June 30, 2026 Six Months Ended
June 30, 2026
(Decrease) Increase Increase (Decrease)
Maryland multi-year plan reconciliation (a)
$ —  $ 26 
Labor, other benefits, contracting, and materials (b)
14 25
BSC and PHISCO costs 9 13
Credit loss expense (3) (3)
Pension and non-pension postretirement benefits expense —  (1)
Storm-related costs (3) (1)
Other 4  2 
21  61 

Regulatory required programs (c)
14  35 
Total increase $ 35  $ 96 
________ _
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Pepco

(a) Reflects unfavorable impacts of the Pepco Maryland multi-year plan reconciliation. See Note 2 — Regulatory Matters for additional information.
(b) Reflects severance related to cost management program.
(c) Reflects the cost recovery associated with EmPOWER Maryland. Please refer to 2025 10-K Note 2 — Regulatory Matters for additional information.

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

Three Months Ended
June 30, 2026 Six Months Ended
June 30, 2026
Increase (Decrease) Increase
Depreciation and amortization (a)
$ 6  $ 12 
Regulatory asset amortization (1) — 
Regulatory required programs (b)
2  4 
Total increase $ 7  $ 16 

__________
(a) Depreciation and amortization increased primarily due to ongoing capital expenditures.
(b) Reflects the cost recovery associated with EmPOWER Maryland. Please refer to 2025 10-K Note 2 — Regulatory Matters additional information.
Taxes other than income taxes increased $4 million and $9 million for the three and six months ended June 30, 2026, respectively, compared to the same period 2025, primarily due to increases in utility taxes and property taxes.
Effective income tax rates were 20.7% and 20.8% for the three months ended June 30, 2026 and 2025, respectively, and 19.9% and 21.0% for the six months ended June 30, 2026 and 2025, 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 June 30, Favorable (Unfavorable) Variance Six Months Ended June 30, Favorable (Unfavorable) Variance
2026 2025 2026 2025
Operating revenues $ 454  $ 421  $ 33  $ 1,076  $ 969  $ 107 
Operating expenses
Purchased power and fuel 195  172  (23) 483  419  (64)
Operating and maintenance 112  95  (17) 231  201  (30)
Depreciation and amortization 67  63  (4) 133  126  (7)
Taxes other than income taxes 24  20  (4) 50  41  (9)
Total operating expenses 398  350  (48) 897  787  (110)

Operating income 56  71  (15) 179  182  (3)
Other income and (deductions)
Interest expense, net (26) (25) (1) (53) (50) (3)
Other, net 4  4  —  8  8  — 
Total other income and (deductions) (22) (21) (1) (45) (42) (3)
Income before income taxes 34  50  (16) 134  140  (6)
Income taxes 8  11  3  31  32  1 
Net income $ 26  $ 39  $ (13) $ 103  $ 108  $ (5)

Three Months Ended June 30, 2026 Compared to Three Months Ended June 30, 2025. Net income decreased by $13 million primarily due to an increase in depreciation expense, severance costs related to the cost management program, and property taxes, partially offset by approved Delaware electric DSIC and natural gas rates.
Six Months Ended June 30, 2026 Compared to Six Months Ended June 30, 2025 . Net income decreased by $5 million primarily due to an increase in property taxes, depreciation expense, severance costs related to the cost management program, storm costs and interest expense, partially offset by approved Delaware electric DSIC and natural gas rates, and favorable weather conditions at Delaware electric and natural gas service territories.
The changes in Operating revenues consisted of the following:

Three Months Ended
June 30, 2026 Six Months Ended
June 30, 2026
(Decrease) Increase Increase (Decrease)
Electric Gas Total Electric Gas Total
Weather $ —  $ —  $ —  $ 2  $ 2  $ 4 
Volume —  (1) (1) 1  (1) — 
Distribution 2  —  2  8  10  18 
Transmission 3  —  3  5  —  5 
Other —  —  —  —  1  1 
5  (1) 4  16  12  28 
Regulatory required programs 21  8  29  54  25  79 
Total increase $ 26  $ 7  $ 33  $ 70  $ 37  $ 107 

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.
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DPL

Weather. The demand for electricity and natural gas in Delaware is affected by weather conditions. With respect to the electric business, very warm weather in summer months and, with respect to the electric and natural gas businesses, very cold weather in winter months are referred to as "favorable weather conditions” because these weather conditions result in increased deliveries of electricity and natural gas. Conversely, mild weather reduces demand. During the three months ended June 30, 2026 compared to the same period in 2025, Operating revenues related to weather remained relatively consistent. During the six months ended June 30, 2026 compared to the same period in 2025, 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 six months ended June 30, 2026, compared to same periods in 2025 and normal weather consisted of the following:

Three Months Ended June 30, % Change
Delaware Electric Service Territory 2026 2025 Normal 2026 vs. 2025 2026 vs. Normal
Heating Degree-Days 376  373  439  0.8  % (14.4) %
Cooling Degree-Days 404  390  349  3.6  % 15.8  %

Six Months Ended June 30, % Change
Delaware Electric Service Territory 2026 2025 Normal 2026 vs. 2025 2026 vs. Normal
Heating Degree-Days 2,906  2,771  2,844  4.9  % 2.2  %
Cooling Degree-Days 412  399  350  3.3  % 17.7  %

Three Months Ended June 30, % Change
Delaware Natural Gas Service Territory 2026 2025 Normal 2026 vs. 2025 2026 vs. Normal
Heating Degree-Days 376  373  476  0.8  % (21.0) %

Six Months Ended June 30, % Change
Delaware Natural Gas Service Territory 2026 2025 Normal 2026 vs. 2025 2026 vs. Normal
Heating Degree-Days 2,906  2,771  2,925  4.9  % (0.6) %

Volume, exclusive of the effects of weather, remained relatively consistent for the three and six months ended June 30, 2026 compared to the same periods in 2025.

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

2026 2025 2026 2025
Residential 692  675  2.5  % 3.0  % 1,666  1,605  3.8  % 1.9  %
Small commercial & industrial 354  369  (4.1) % (3.8) % 721  723  (0.3) % (1.0) %
Large commercial & industrial 754  766  (1.6) % (1.3) % 1,441  1,456  (1.0) % (1.1) %
Public authorities & electric railroads (16) 9  (277.8) % (287.3) % (10) 15  (166.7) % (163.3) %
Total electric retail deliveries (a)
1,784  1,819  (1.9) % (1.6) % 3,818  3,799  0.5  % (0.5) %

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DPL

At June 30,
Number of Total Electric Customers (Maryland and Delaware) 2026 2025
Residential 496,515  492,999 
Small commercial & industrial 65,710  65,177 
Large commercial & industrial 1,295  1,253 
Public authorities & electric railroads 626  628 
Total 564,146  560,057 

__________
(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
June 30, % Change Weather - Normal
% Change (b)
Six Months Ended
June 30, % Change Weather - Normal
% Change (b)

2026 2025 2026 2025
Residential 729  803  (9.2) % (8.8) % 5,407  5,393  0.3  % (3.4) %
Small commercial & industrial 482  535  (9.9) % (10.0) % 2,606  2,502  4.2  % —  %
Large commercial & industrial 400  405  (1.2) % (1.3) % 833  837  (0.5) % (0.5) %
Transportation 1,270  1,282  (0.9) % (1.3) % 3,297  3,387  (2.7) % (4.3) %
Total natural gas deliveries (a)
2,881  3,025  (4.8) % (5.1) % 12,143  12,119  0.2  % (2.7) %

At June 30,
Number of Delaware Natural Gas Customers 2026 2025
Residential 131,951  131,332 
Small commercial & industrial 10,207  10,146 
Large commercial & industrial 14  14 
Transportation 160  161 
Total 142,332  141,653 

__________
(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 remained relatively consistent for the three months ended June 30, 2026 compared to the same period in 2025. During the six months ended June 30, 2026, compared to the same period in 2025, distribution revenue increased primarily due to Delaware natural gas rates that became effective in 2025 & electric DSIC rates that became effective in 2026.
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 six months ended June 30, 2026 compared to the same period in 2025, 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. The riders are designed to provide full and current cost recovery as well as a return in certain instances. All customers have the choice to purchase electricity from competitive electric generation suppliers; however, only certain commercial and industrial customers have the choice to purchase natural gas from competitive natural gas suppliers. Customer choice programs do not impact the volume of deliveries as DPL remains the distribution service provider for all customers and charges a regulated rate for distribution service. For customers that choose to purchase electric generation or natural gas from competitive suppliers, this is treated as a pass through for DPL and therefore, financial results are not impacted if customers purchase electricity or natural gas supply from these alternative suppliers. For customers that choose to purchase electric generation or natural gas from DPL, DPL is permitted to recover costs from customers.
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DPL

See Note 4 — Segment Information of the Combined Notes to Consolidated Financial Statements for the presentation of DPL's revenue disaggregation.
The decrease of $23 million and $64 million for the three and six months ended June 30, 2026, respectively, compared to the same periods in 2025 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
June 30, 2026 Six Months Ended
June 30, 2026
Increase (Decrease) Increase (Decrease)
Labor, other benefits, contracting, and materials (a)
$ 9  $ 12 
BSC and PHISCO costs
5  5 
Storm-related costs
(2) 3 
Credit loss expense (1) (3)

Other
1  2 
12  19 
Regulatory required programs (b)
5  11 
Total increase $ 17  $ 30 

__________
(a) Reflects severance related to the cost management program.
(b) Reflects the cost recovery associated with EmPOWER Maryland. Please refer to 2025 10-K Note 2 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.
The changes in Depreciation and amortization expense consisted of the following:

Three Months Ended
June 30, 2026 Six Months Ended
June 30, 2026
Increase Increase (Decrease)
Depreciation and amortization (a)
$ 4  $ 7 
Regulatory asset amortization —  (1)
Regulatory required programs (b)
—  1 
Total increase $ 4  $ 7 

__________
(a) Depreciation and amortization increased primarily due to ongoing capital expenditures.
(b) Reflects the cost recovery associated with EmPOWER Maryland. Please refer to 2025 10-K Note 2 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information

Taxes other than income taxes increased by $4 million and $9 million for the three and six months ended June 30, 2026, respectively, compared to the same periods in 2025 primarily due to an increase in property taxes.
Effective income tax rates were 23.5% and 22.0% for the three months ended June 30, 2026 and 2025, respectively, and 23.1% and 22.9% for the six months ended June 30, 2026 and 2025, 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 June 30, Favorable (Unfavorable) Variance Six Months Ended June 30, Favorable (Unfavorable) Variance
2026 2025 2026 2025
Operating revenues $ 401  $ 384  $ 17  $ 822  $ 757  $ 65 

Operating expenses
Purchased power 187  173  (14) 392  329  (63)
Operating and maintenance 99  95  (4) 192  185  (7)
Depreciation and amortization 63  62  (1) 128  127  (1)
Taxes other than income taxes 3  3  —  5  5  — 
Total operating expenses 352  333  (19) 717  646  (71)

Operating income 49  51  (2) 105  111  (6)
Other income and (deductions)
Interest expense, net (22) (20) (2) (44) (41) (3)
Other, net 3  2  1  5  6  (1)
Total other income and (deductions) (19) (18) (1) (39) (35) (4)
Income before income taxes 30  33  (3) 66  76  (10)
Income taxes 8  9  1  17  20  3 
Net income $ 22  $ 24  $ (2) $ 49  $ 56  $ (7)

Three Months Ended June 30, 2026 Compared to Three Months Ended June 30, 2025 . Net income decreased by $2 million primarily due to an increase in severance costs related to the cost management program, partially offset by an increase in approved distribution and transmission rates.

Six Months Ended June 30, 2026 Compared to Six Months Ended June 30, 2025 . Net income decreased by $7 million primarily due to an increase in depreciation and interest expense, storm costs, and severance costs related to the cost management program, partially offset by an increase in approved distribution and transmission rates.
The changes in Operating revenues consisted of the following:

Three Months Ended
June 30, 2026 Six Months Ended
June 30, 2026
Increase Increase
Distribution $ 8  $ 7 
Transmission 6  9 
Other —  — 
14  16 
Regulatory required programs 3  49 
Total increase $ 17  $ 65 

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 June 30,
Number of Electric Customers 2026 2025
Residential 511,568  508,775 
Small commercial & industrial 63,070  62,817 
Large commercial & industrial 2,665  2,803 
Public authorities & electric railroads 767  729 
Total 578,070  575,124 

Distribution Revenue increased for the three and six months ended June 30, 2026 compared to the same periods in 2025 due to approved distribution rates that became effective in December 2025 as well as 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 increased for the three and six months ended June 30, 2026 compared to the same periods in 2025 primarily due to increases in underlying costs and capital investment.
Other Revenue includes rental revenue, revenue related to late payment charges, mutual assistance revenues, and recoveries of other taxes.
Regulatory Required Programs represent revenues collected under approved riders to recover costs incurred for regulatory programs. The riders are designed to provide full and current cost recovery as well as a return in certain instances. 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. For customers that choose to purchase electric generation from competitive suppliers, this is treated as a pass through for ACE and therefore, financial results are not impacted if customers purchase electricity supply from these alternative suppliers. For customers that choose to purchase electric generation from ACE, ACE is permitted to recover costs from customers.
See Note 4 — Segment Information of the Combined Notes to Consolidated Financial Statements for the presentation of ACE's revenue disaggregation.
The increase of $14 million and $63 million for the three and six months ended June 30, 2026, respectively, compared to the same periods in 2025 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
June 30, 2026 Six Months Ended
June 30, 2026
Increase (Decrease) Increase (Decrease)
Labor, other benefits, contracting, and materials (a)
$ 8  $ 6 
BSC and PHISCO costs 3  4 
Storm-related costs (1) 3 
Pension and non-pension postretirement benefits expense —  (1)
Credit Loss Expense —  (2)
Other —  2 
10  12 

Regulatory required programs (6) (4)
Total increase $ 4  $ 8 
________ _
(a) Reflects severance related to cost management program.
The changes in Depreciation and amortization expense consisted of the following:

Three Months Ended
June 30, 2026 Six Months Ended
June 30, 2026
Increase (Decrease) Increase (Decrease)
Depreciation and amortization (a)
$ 4  $ 5 
Regulatory asset amortization 4  8 
Regulatory required programs (7) (12)
Total increase $ 1  $ 1 

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

Effective income tax rates were 26.7% and 27.3% for the three months ended June 30, 2026 and 2025, respectively, and 25.8% and 26.3% for the six months ended June 30, 2026 and 2025, 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 2 — Regulatory Matters of the 2025 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 six months ended June 30, 2026 and 2025 by Registrant:

Increase in cash flows from operating activities Exelon ComEd PECO BGE   PHI Pepco DPL ACE
Net income (loss) $ 15  $ 29  $ (5) $ 38  $ (59) $ (48) $ (5) $ (7)
Adjustments to reconcile net income to cash:
Non-cash operating activities 109  (113) 334  161  99  56  19  38 

Collateral received, net 58  84  (6) (7) (14) (2) (4) (9)
Income taxes (137) (11) (280) (175) (3) 19  (12) (9)
Pension and non-pension postretirement benefit contributions (54) (32) (4) (7) (11) 2  —  (12)
Regulatory assets and liabilities, net (580) (704) (72) 106  85  39  18  25 
Changes in working capital and other assets and liabilities 1,547  1,227  48  (53) 152  87  53  (2)
Increase in cash flows from operating activities $ 958  $ 480  $ 15  $ 63  $ 249  $ 153  $ 69  $ 24 

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 changes in cash flows from operating activities were primarily due to the following:
• 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 six months ended June 30, 2026 to the six months ended June 30, 2025. 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 six months ended June 30, 2026. See Note 12 — Retirement Benefits of the 2025 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. ComEd recognized a reduction in regulatory liabilities of $670 million and an increase in regulatory assets of $150 million related to CMCs for the six months ended June 30, 2026 and a decrease in regulatory assets of $20 million related to CMCs for the six months ended June 30, 2025. Included within the change in 2026 are payments for CMC nuclear production tax credits, which relate to a decrease in Accounts Receivable. ComEd's energy efficiency program recognized changes of $206 million and $191 million for the six months ended June 30, 2026 and 2025, respectively. Additionally, ComEd recognized changes in the distributed generation rebates programs of $70 million and $35 million for the six months ended June 30, 2026 and 2025, respectively. Also included within the changes is energy efficiency and demand response
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programs spend for DPL and ACE of $2 million and $35 million for the six months ended June 30, 2026 and $7 million, and $16 million for the six months ended June 30, 2025, respectively. BGE and Pepco had no energy efficiency and demand response programs spend recorded to the regulatory asset for the six months ended June 30, 2026 and $41 million and $16 million for six months ended June 30, 2025. PECO had no energy efficiency and demand response programs spend recorded to the regulatory asset for the six months ended June 30, 2026 and 2025.
• Changes in working capital and other assets and liabilities for the Utility Registrants and Exelon Corporate totaled $1,360 million and $1,547 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 six months ended June 30, 2026, the established pricing has resulted in ComEd receiving payments from nuclear-powered generating facilities, which is reported within the cash flows from operations as a change in Accounts receivable. This change corresponds to a change in the Carbon mitigation credit regulatory mechanism. See Note 2 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.
Cash Flows from Investing Activities
The following table provides a summary of the change in cash flows from investing activities for the six months ended June 30, 2026 and 2025 by Registrant:

(Decrease) increase in cash flows from investing activities Exelon ComEd PECO BGE   PHI Pepco DPL ACE
Capital expenditures $ (599) $ (482) $ (132) $ (18) $ 46  $ (48) $ (23) $ (44)

Proceeds from sales of assets (2) —  —  —  (2) (2) —  — 
Changes in intercompany money pool —  —  —  —  —  (95) —  — 

Other investing activities 3  2  (11) —  1  —  1  1 
(Decrease) increase in cash flows from investing activities $ (598) $ (480) $ (143) $ (18) $ 45  $ (145) $ (22) $ (43)

Significant changes in cash flows from investing activities were primarily due to the following:
• 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 six months ended June 30, 2026 and 2025 by Registrant:
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Increase (decrease) in cash flows from financing activities Exelon ComEd PECO BGE   PHI Pepco DPL ACE
Changes in short-term borrowings, net $ 1,381  $ 36  $ 70  $ 175  $ (280) $ (252) $ 13  $ (41)
Long-term debt, net (993) 200  —  (75) 50  100  (50) — 
Changes in intercompany money pool —  —  —  —  15  —  47  48 
Issuance of common stock 209  —  —  —  —  —  —  — 
Dividends paid on common stock (52) (30) —  (31) —  37  4  4 

Distributions to member —  —  —  —  45  —  —  — 
Contributions from parent/member —  169  4  474  (116) 113  (54) (3)

Other financing activities 12  (7) —  (1) —  (2) —  (1)
Increase (decrease) in cash flows from financing activities $ 557  $ 368  $ 74  $ 542  $ (286) $ (4) $ (40) $ 7 

Significant changes in cash flows from financing activities were primarily due to the following:
• 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 second quarter of 2026. 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 16 — Commitments and Contingencies of the 2025 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 six months ended June 30, 2026, the following long-term debt was retired and/or redeemed:

Company Type Interest Rate Maturity Amount
Exelon Senior Notes 3.40  % April 15, 2026 $ 750 
ComEd First Mortgage Bonds 2.55  % June 15, 2026 $ 500 
BGE Senior Notes 2.40  % August 15, 2026 $ 350 

Dividends
Quarterly dividends declared by the Exelon Board of Directors during the six months ended June 30, 2026 and for the third quarter of 2026 were as follows:
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Period Declaration Date Shareholder of Record Date Dividend Payable Date Cash per Share (a)

First Quarter 2026 February 12, 2026 March 2, 2026 March 13, 2026 $ 0.4200 
Second Quarter 2026 April 28, 2026 June 4, 2026 June 15, 2026 $ 0.4200 
Third Quarter 2026 July 28, 2026 September 4, 2026 September 15, 2026 $ 0.4200 

__________
(a) Exelon's Board of Directors approved an updated dividend policy for 2026. The 2026 quarterly dividend will be $0.42 per share.
Credit Matters and Cash Requirements
The Registrants fund liquidity needs for capital 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 $3.2 billion was available to support additional commercial paper as of June 30, 2026, and of which no financial institution has more than 6.2% of the aggregate commitments for the Registrants. The Registrants had access to the commercial paper markets and had availability under their revolving credit facilities during the six months ended June 30, 2026 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 2025 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 Program
On May 2, 2025, Exelon executed an equity distribution agreement ("2025 Equity Distribution Agreement"), 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. Exelon has no obligation to offer or sell any shares of Common stock under the 2025 Equity Distribution Agreement and may, at any time, suspend or terminate offers and sales under the 2025 Equity Distribution Agreement. Exelon issued the following shares of Common stock in the second quarter of 2026:

Effective Period
Shares Issued
(in millions)
Weighted-Average Net Price
Net Proceeds (a)
(in millions)

Q2 2026 (b)
8.7 $ 44.03  $ 382 

_________
(a) Proceeds were used for general corporate purposes.
(b) In Q2 2026, Exelon settled all forward sale agreements with a November 16, 2026 maturity date and a portion of the forward sale agreements with December 15, 2026 and July 30, 2027 maturity dates that were entered into by various forward sellers under the ATM program as outlined below.
In the first quarter of 2026, Exelon entered into various forward sale agreements under the 2025 ATM program. The forward sale agreements require Exelon to, at its election prior to the maturity date, either (i) physically settle the transactions by issuing shares of its Common stock to the forward counterparties in exchange for net proceeds at the then-applicable forward sale price specified by the agreements or (ii) net settle the transactions in whole or in part through the delivery to the forward counterparties or receipt from the forward counterparties of cash or shares in accordance with the provisions of the agreements. The following forward sale agreements were entered into under Exelon’s ATM program in the first quarter of 2026:
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Effective Period Shares Available
(in millions) Weighted-Average Net Price Maturity Date
Q1 2026 5.4 $ 47.67  July 30, 2027
Q1 2026 6.4 $ 48.68  September 2, 2027

Additionally, the following forward sale agreements were entered into during the twelve months ended 2025 under Exelon’s ATM program and were not settled as of December 31, 2025:

Effective Period Shares Available
(in millions) Weighted-Average Net Price Maturity Date
Q2 2025 3.6 $ 43.17  November 16, 2026
Q3 2025 11.5 $ 43.73  December 15, 2026
Q4 2025 0.8 $ 45.42  December 15, 2026

No amounts have been or will be recorded on Exelon's balance sheet with respect to the equity offerings until the equity forward sale agreements have been settled. Each initial forward sale price is subject to adjustment on a daily basis based on a floating interest rate factor and will decrease by other fixed amounts specified in the agreements. Until settlement of the equity forward, earnings per share dilution resulting from the agreement, if any, will be determined under the treasury stock method. For the three and six months ended June 30, 2026 June 30, 2026, approximately 18.4 million shares under the forward sale agreements were not included in the calculation of diluted earnings per share because their effect would have been antidilutive.
Inclusive of the impact of the forward sale agreements, $1.0 billion of Common stock remained available for sale pursuant to the ATM program as of June 30, 2026.
On July 6, 2026, Exelon settled an additional forward agreement that was entered into under the 2025 ATM program. Exelon issued approximately 2.3 million shares of Common stock at a weighted-average net price of $43.29 per share. The net proceeds from the issuance were $101 million, which will be used for general corporate purposes.
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 June 30, 2026 and available credit facility capacity prior to any incremental collateral at June 30, 2026:

PJM Credit Policy Collateral Other Incremental Collateral Required (a)
Available Credit Facility Capacity Prior to Any Incremental Collateral
ComEd $ 25  $ —  $ 982 
PECO 7  26  514 
BGE 3  16  573 

Pepco —  —  297 
DPL —  13  267 
ACE —  —  297 

__________
(a) Represents incremental collateral related to natural gas procurement contracts.
Capital Expenditure Spending
As of June 30, 2026, the most recent estimates of capital expenditures for plant additions and improvements for 2026 are as follows:        
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(In millions) Transmission Distribution Gas Total (a)

Exelon N/A N/A N/A $ 9,900 
ComEd 1,100  2,400  N/A 3,500 
PECO 450  1,325  400  2,175 
BGE 1,075  575  525  2,175 
PHI 725  1,250  50  2,050 
Pepco 325  650  N/A 975 
DPL 225  325  50  625 
ACE 175  275  N/A 450 

__________
(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. Exelon’s estimated annual qualified pension contributions will be $325 million in 2026. Unlike the qualified pension plans, Exelon’s non-qualified pension plans are not funded, given that they are not subject to statutory minimum contribution requirements.
While OPEB plans are also not subject to statutory minimum contribution requirements, Exelon does fund certain of its plans. For Exelon's funded OPEB plans, contributions generally equal accounting costs, however, Exelon’s management has historically considered several factors in determining the level of contributions to its OPEB plans, including liabilities management, levels of benefit claims paid, and regulatory implications (amounts deemed prudent to meet regulatory expectations and best assure continued rate recovery).
To the extent interest rates decline significantly or the pension and OPEB plans earn less than the expected asset returns, annual pension contribution requirements in future years could increase. Conversely, to the extent interest rates increase significantly or the pension and OPEB plans earn greater than the expected asset returns, annual pension and OPEB contribution requirements in future years could decrease. Additionally, expected contributions could change if Exelon changes its pension or OPEB funding strategy.
See Note 12 — Retirement Benefits of the Combined Notes to Consolidated Financial Statements of the 2025 Form 10-K for additional information on pension and OPEB contributions.
Credit Facilities
Exelon Corporate, ComEd, and BGE meet their short-term liquidity needs primarily through commercial paper issuances. PECO also utilizes commercial paper, supplemented by borrowings from the Exelon intercompany money pool. Pepco, DPL, and ACE similarly rely on commercial paper, along with borrowings from the PHI intercompany money pool. PHI Corporate meets its short-term liquidity needs through 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.
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.
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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 Exelon, ComEd, PECO, PHI, Pepco, DPL, and ACE did not change for the six months ended June 30, 2026. On April 30, 2026, S&P lowered its long-term issuer credit rating and senior unsecured debt rating for BGE from 'A' to 'A-', and its short-term commercial paper rating for BGE from 'A-1' to 'A-2'. On July 15, 2026, Moody's lowered PECO's long-term issuer rating from 'A2' to 'A3', its senior secured debt rating from 'Aa3' to 'A1', and short-term commercial paper rating from 'P-1' to 'P-2'.
Intercompany Money Pool
To provide an additional short-term borrowing option that will generally be more favorable to the borrowing participants than the cost of external financing, both Exelon and PHI operate an intercompany money pool. Maximum amounts contributed to and borrowed from the money pool by participant and the net contribution or borrowing as of June 30, 2026, are presented in the following table:

During the Six Months Ended June 30, 2026 At June 30, 2026
Exelon Intercompany Money Pool Maximum
Contributed Maximum
Borrowed Contributed
(Borrowed)
Exelon Corporate $ 502  $ —  $ 399 
PECO 343  (63) — 
BSC —  (461) (360)
PHI Corporate —  (134) (92)
PCI 65  —  53 

During the Six Months Ended June 30, 2026 At June 30, 2026
PHI Intercompany Money Pool Maximum
Contributed Maximum
Borrowed
Contributed
(Borrowed)
Pepco $ 116  $ —  $ 95 
DPL —  (85) (47)
ACE —  (66) (48)

Shelf Registration Statements
On February 13, 2025, Exelon and ComEd filed a combined shelf registration statement on Form S-3 registering $12.6 billion in aggregate amount of securities, which was declared effective by the SEC on April 8, 2025. The shelf registration statement may be used to issue Exelon debt and equity securities as well as ComEd debt securities through the expiration date of April 8, 2028. On February 21, 2024, PECO and BGE filed with the SEC a standalone automatically effective shelf registration statement, unlimited in amount, which can be used to issue PECO and BGE debt securities through the expiration date of February 20, 2027. The ability of Exelon, ComEd, PECO and BGE to sell securities off their corresponding registration statements will depend on a number of
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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.
Regulatory Authorizations
The Utility Registrants are required to obtain short-term and long-term financing authority from Federal and State Commissions as follows:

At June 30, 2026
Short-term Financing Authority Remaining Long-term Financing Authority
Commission Expiration Date Amount Commission Expiration Date Amount
ComEd FERC December 31, 2027 $ 2,500  ICC January 1, 2027, May 1, 2027, & January 1, 2029 $ 2,968 
PECO FERC December 31, 2027 1,500  PAPUC December 31, 2027 1,850 
BGE FERC December 31, 2027 900  MDPSC N/A 925 
Pepco (a)
FERC December 31, 2027 700  MDPSC / DCPSC December 31, 2028 800 
DPL (a)
FERC December 31, 2027 700  MDPSC / DEPSC December 31, 2028 625 
ACE (b)
NJBPU January 1, 2028 350  NJBPU December 31, 2026 525 

__________

(a) The financing authority filed with MDPSC does not have an expiration date, while the financing authority filed with DCPSC and DEPSC have an expiration date of December 31, 2028.
(b) On June 4, 2026, ACE filed an application with the NJBPU to extend their long-term financing authority through December 31, 2028. ACE expects approval of their application by November 20, 2026.

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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 12 — Retirement Benefits of the 2025 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 hybrid, convertible, 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 Corporate may utilize interest rate derivatives to lock in rate levels in anticipation of future financings, which are typically designated as cash flow hedges. See Note 8 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information.
The Utility Registrants operate primarily under cost-based rate regulation limiting exposure to the effects of market risk. Hedging programs are utilized to reduce exposure to energy and natural gas price volatility and have no direct earnings impacts as the costs are fully recovered through regulatory-approved recovery mechanisms.
Exelon manages these risks through risk management policies and objectives for risk assessment, control and valuation, counterparty credit approval, and the monitoring and reporting of risk exposures. Risk management issues are reported to Exelon’s Board of Directors, Exelon's Audit and Risk Committee, and/or the applicable Utility Board Registrant. The Registrants do not execute derivatives for speculative or proprietary trading purposes.
Commodity Price Risk (All Registrants)
Commodity price risk is associated with price movements resulting from changes in supply and demand, fuel costs, market liquidity, weather conditions, governmental regulatory and environmental policies, and other factors. To the extent the total amount of energy Exelon purchases differs from the amount of energy it has contracted to sell, Exelon is exposed to market fluctuations in commodity prices. Exelon seeks to mitigate its commodity price risk through the sale and purchase of electricity and natural gas.
ComEd entered into 20-year floating-to-fixed renewable energy swap contracts beginning in June 2012, which are considered an economic hedge and have changes in fair value recorded to an offsetting regulatory asset or liability. ComEd has block energy contracts to procure electric supply that are executed through a competitive procurement process, which are considered derivatives and qualify for NPNS, and as a result are accounted for on an accrual basis of accounting. PECO, BGE, Pepco, DPL, and ACE have contracts to procure electric supply that are executed through a competitive procurement process. PECO, BGE, Pepco, DPL, and ACE have certain full requirements contracts, which are considered derivatives and qualify for NPNS, and as a result are accounted for on an accrual basis of accounting. Other full requirements contracts are not derivatives.
PECO, BGE, and DPL also have executed derivative natural gas contracts, which qualify for NPNS, to hedge their long-term price risk in the natural gas market.
For additional information on these contracts, see Note 2 — Regulatory Matters and Note 8 — Derivative Financial Instruments 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 liabilities. Second, the table shows the maturity, by year, of Exelon's and ComEd's commodity contract liabilities giving an indication of when these mark-to-market amounts will settle and require cash. See Note 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) :
2026 2027 2028 2029 2030 2031 and Beyond
Prices based on model or other valuation methods (Level 3) $ (9) $ (23) $ (23) $ (23) $ (22) $ (28) $ (128)
_________
(a) Represents ComEd's net liabilities associated with the floating-to-fixed energy swap contracts with unaffiliated suppliers.
Credit Risk (All Registrants)
Credit risk for the Utility Registrants is governed by credit and collection policies, which are aligned with state regulatory requirements. The Utility Registrants are currently obligated to provide service to all electric customers within their franchised territories. The Utility Registrants record an allowance for credit losses, based upon historical experience, current information, and forward-looking risk factors, to provide for the potential loss from nonpayment by these customers. The Utility Registrants will monitor nonpayment from customers and will make any necessary adjustments to the allowance for credit losses. See Note 1 — Significant Accounting Policies of the Combined Notes to Consolidated Financial Statements of the 2025 Form 10-K for the allowance for credit losses policy. The Utility Registrants did not have any customers representing over 10% of their revenues as of June 30, 2026. See Note 2 — Regulatory Matters of the Combined Notes to the Consolidated Financial Statements for additional information.

ITEM 4.    CONTROLS AND PROCEDURES
During the second quarter of 2026, each of the Registrants' management, including its principal executive officer and principal financial officer, evaluated its disclosure controls and procedures (as defined in Exchange Act Rules 13a‑15(e) and 15d‑15(e)) as of the end of the period covered by this report, pursuant to Exchange Act Rules 13a‑15(b) and 15d‑15(b). These disclosure controls and procedures have been designed by the Registrants to ensure that (a) material information relating to that Registrant, including its consolidated subsidiaries, is accumulated and made known to that Registrant's management, including its principal executive officer and principal financial officer, by other employees of that Registrant and its subsidiaries as appropriate to allow timely decisions regarding required disclosure, and (b) this information is recorded, processed, summarized, evaluated, and reported, as applicable, within the time periods specified in the SEC’s rules and forms. Due to the inherent limitations of control systems, not all misstatements may be detected. These inherent limitations include the realities that judgments in decision-making can be faulty and that breakdowns can occur because of simple error or mistake. Additionally, controls could be circumvented by the individual acts of some persons or by collusion of two or more people.
Accordingly, as of June 30, 2026, the principal executive officer and principal financial officer of each of the Registrants concluded that such Registrant’s disclosure controls and procedures were effective (Item 307 of Regulation S‑K).
Changes in Internal Control Over Financial Reporting
The Registrants continually strive to improve disclosure controls and procedures to enhance the quality of financial reporting and to maintain dynamic systems that change as conditions warrant. During the first quarter of 2026, a new ERP system was implemented for a majority of the financial accounting systems, which is expected to improve the efficiency of certain financial and related transaction processes. As part of the implementation of the ERP, the Registrants modified certain existing internal controls and implemented certain new controls in order to align the financial accounting processes with the new ERP system. The Registrants do not believe that any of these modifications or new controls have materially affected, or are reasonably likely to affect, internal control
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over financial reporting. There have been no other changes in internal control over financial reporting that occurred during the three and six months ended June 30, 2026, that have 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 2025 Form 10-K, (b) Notes 2 — Regulatory Matters and 16 — Commitments and Contingencies of the 2025 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 June 30, 2026, the Registrants' risk factors were consistent with the risk factors described in the Registrants' combined 2025 Form 10-K in ITEM 1A. RISK FACTORS.

ITEM 5.    OTHER INFORMATION
All Registrants
None of our officers or directors , as defined in Rule 16a-1(f) of the Securities Exchange Act of 1934, adopted , modified, or terminated a “ Rule 10b5-1 trading arrangement” or a “ non-Rule 10b5-1 trading arrangement,” as defined in Item 408 of Regulation S-K, during the three months ended June 30, 2026, except as follows:
On June 9, 2026 , Calvin G. Butler, Jr. , President and Chief Executive Officer, Exelon Corporation, terminated a Rule 10b5-1 trading arrangement he had previously adopted on March 13, 2026 , which was intended to satisfy the affirmative defense of Rule 10b5-1(c). As of the date of termination of the trading arrangement, Mr. Butler had not sold any shares of common stock under its terms.

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
Commonwealth Edison Company
Exhibit No. Description Location
4-1
Supplemental Indenture dated as of May 1, 2026, from ComEd to The Bank of New York Mellon Trust Company, N.A., as trustee File No. 001-01839, Form 8-K dated May 14, 2026, Exhibit 4.1

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Baltimore Gas and Electric Company
Exhibit No. Description Location
4-2
Form of 5.150% Notes due 2033 issued May 22, 2026 by Baltimore Gas and Electric Company File No. 001-01910, Form 8-K dated May 22 , 2026, Exhibit 4.1

4-3
Form of 6.050% Notes due 2056 issued May 22, 2026 by Baltimore Gas and Electric Company File No. 001-01910, Form 8-K dated May 22, 2026, Exhibit 4.2

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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 June 30, 2026 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 Michael A. Innocenzo 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 June 30, 2026 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 Michael A. Innocenzo 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, Chief Finance Officer, Audit and Risk (Principal Financial Officer)

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

July 30, 2026
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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)

July 30, 2026
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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/   MICHAEL A. INNOCENZO /s/    MARISSA E. HUMPHREY
Michael A. Innocenzo Marissa E. Humphrey
Interim 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)

July 30, 2026

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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/ CAROLINE FULGINITI
Caroline Fulginiti
Vice President and Assistant Controller, Exelon (Principal Accounting Officer, BGE)

July 30, 2026

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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)

July 30, 2026

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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)

July 30, 2026

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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)

July 30, 2026

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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)

July 30, 2026
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