Companies: 10,822     total market cap: NZ$250.466 T
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Exelon Corporation
EXC
#557
Rank
NZ$76.11 B
Marketcap
๐Ÿ‡บ๐Ÿ‡ธ United States
Country
NZ$74.39
Share price
-2.16%
Change (1 day)
4.33%
Change (1 year)
๐Ÿ”‹ Electricity
Categories
  1. Exelon Corporation
  2. Quarterly Reports (10-Q)
  3. Submitted on 2026-05-06

Exelon Corporation - 10-Q quarterly report FY


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March 31, 2026March 31, 2026March 31, 2026March 31, 2026March 31, 2026March 31, 2026March 31, 2026March 31, 2026falsefalsefalsefalsefalsefalsefalsefalse20262026202620262026202620262026Q1Q1Q1Q1Q1Q1Q1Q1December 31December 31December 31December 31December 31December 31December 31December 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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 March 31, 2026
or
☐ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
Commission File NumberName of Registrant; State or Other Jurisdiction of Incorporation; Address of Principal Executive Offices; and Telephone NumberIRS Employer Identification Number
001-16169EXELON CORPORATION23-2990190
(a Pennsylvania corporation)
10 South Dearborn Street
P.O. Box 805379
Chicago, Illinois 60680-5379
(800) 483-3220
001-01839COMMONWEALTH EDISON COMPANY36-0938600
(an Illinois corporation)
10 South Dearborn Street
Chicago, Illinois 60603-2300
(312) 394-4321
000-16844PECO ENERGY COMPANY23-0970240
(a Pennsylvania corporation)
2301 Market Street
P.O. Box 8699
Philadelphia, Pennsylvania 19101-8699
(215) 841-4000
001-01910BALTIMORE GAS AND ELECTRIC COMPANY52-0280210
(a Maryland corporation)
2 Center Plaza
110 West Fayette Street
Baltimore, Maryland 21201-3708
(410) 234-5000
001-31403PEPCO HOLDINGS LLC52-2297449
(a Delaware limited liability company)
701 Ninth Street, N.W.
Washington, District of Columbia 20068-0001
(202) 872-2000
001-01072POTOMAC ELECTRIC POWER COMPANY53-0127880
(a District of Columbia and Virginia corporation)
701 Ninth Street, N.W.
Washington, District of Columbia 20068-0001
(202) 872-2000
001-01405DELMARVA POWER & LIGHT COMPANY51-0084283
(a Delaware and Virginia corporation)
500 North Wakefield Drive
Newark, Delaware 19702-5440
(202) 872-2000
001-03559ATLANTIC CITY ELECTRIC COMPANY21-0398280
(a New Jersey corporation)
500 North Wakefield Drive
Newark, Delaware 19702-5440
(202) 872-2000


Securities registered pursuant to Section 12(b) of the Act:
Title of each classTrading Symbol(s)Name of each exchange on which registered
EXELON CORPORATION:
Common stock, without par valueEXCThe Nasdaq Stock Market LLC

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 CorporationLarge Accelerated FilerxAccelerated Filer
☐
Non-accelerated Filer
☐
Smaller Reporting Company
☐
Emerging Growth Company
☐
Commonwealth Edison CompanyLarge Accelerated Filer
☐
Accelerated Filer
☐
Non-accelerated FilerxSmaller Reporting Company
☐
Emerging Growth Company
☐
PECO Energy CompanyLarge Accelerated Filer
☐
Accelerated Filer
☐
Non-accelerated FilerxSmaller Reporting Company
☐
Emerging Growth Company
☐
Baltimore Gas and Electric CompanyLarge Accelerated Filer
☐
Accelerated Filer
☐
Non-accelerated FilerxSmaller Reporting Company
☐
Emerging Growth Company
☐
Pepco Holdings LLCLarge Accelerated Filer
☐
Accelerated Filer
☐
Non-accelerated FilerxSmaller Reporting Company
☐
Emerging Growth Company
☐
Potomac Electric Power CompanyLarge Accelerated Filer
☐
Accelerated Filer
☐
Non-accelerated FilerxSmaller Reporting Company
☐
Emerging Growth Company
☐
Delmarva Power & Light CompanyLarge Accelerated Filer
☐
Accelerated Filer
☐
Non-accelerated FilerxSmaller Reporting Company
☐
Emerging Growth Company
☐
Atlantic City Electric CompanyLarge Accelerated Filer
☐
Accelerated Filer
☐
Non-accelerated FilerxSmaller Reporting Company
☐
Emerging Growth Company
☐

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

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 March 31, 2026 was:
Exelon Corporation Common Stock, without par value1,023,208,142
Commonwealth Edison Company Common Stock, $12.50 par value127,021,425
PECO Energy Company Common Stock, without par value170,478,507
Baltimore Gas and Electric Company Common Stock, without par value1,000
Pepco Holdings LLCnot applicable
Potomac Electric Power Company Common Stock, $0.01 par value100
Delmarva Power & Light Company Common Stock, $2.25 par value1,000
Atlantic City Electric Company Common Stock, $3.00 par value8,546,017


TABLE OF CONTENTS
Page No.
4
7
7
8
9
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
58
4. Segment Information
60
5. Accounts Receivable
65
6. Income Taxes
66
7. Retirement Benefits
69
8. Derivative Financial Instruments
71
9. Debt and Credit Agreements
73
10. Fair Value of Financial Assets and Liabilities
76
11. Commitments and Contingencies
84
12. Shareholders' Equity
90
13. Changes in Accumulated Other Comprehensive Income
91
14. Supplemental Financial Information
92
15. Related Party Transactions
94
2




Page No.
97
Exelon Corporation
97
Executive Overview
97
Financial Results of Operations
97
Significant 2026 Transactions and Developments
98
Other Key Business Drivers and Management Strategies
100
Critical Accounting Policies and Estimates
101
Results of Operations By Registrant
102
Commonwealth Edison Company
102
PECO Energy Company
105
Baltimore Gas and Electric Company
109
Pepco Holdings LLC
112
Potomac Electric Power Company
113
Delmarva Power & Light Company
116
Atlantic City Electric Company
120
Liquidity and Capital Resources
123
132
133
134
134
134
134
134
138
138
139
140
141
142
143
144
145
3



GLOSSARY OF TERMS AND ABBREVIATIONS
Exelon Corporation and Related Entities
ExelonExelon Corporation
ComEdCommonwealth Edison Company
PECOPECO Energy Company
BGEBaltimore Gas and Electric Company
Pepco Holdings or PHIPepco Holdings LLC
PepcoPotomac Electric Power Company
DPLDelmarva Power & Light Company
ACEAtlantic City Electric Company
RegistrantsExelon, ComEd, PECO, BGE, PHI, Pepco, DPL, and ACE, collectively
Utility RegistrantsComEd, PECO, BGE, Pepco, DPL, and ACE, collectively
BSCExelon Business Services Company, LLC
Exelon CorporateExelon in its corporate capacity as a holding company
PCIPotomac Capital Investment Corporation and its subsidiaries
PECO Trust IIIPECO Energy Capital Trust III
PECO Trust IVPECO Energy Capital Trust IV
Pepco Energy Services or PESPepco Energy Services, Inc. and its subsidiaries
PHI CorporatePHI in its corporate capacity as a holding company
PHISCOPHI Service Company
Former Related Entities
ConstellationConstellation Energy Corporation and Constellation Energy Generation, LLC (formerly Exelon Generation Company, LLC, a subsidiary of Exelon as of December 31, 2021 prior to separation on February 1, 2022)
4



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
ABOAccumulated Benefit Obligation
AECsAlternative Energy Credits that are issued for each megawatt hour of generation from a qualified alternative energy source
AFUDCAllowance for Funds Used During Construction
AMIAdvanced Metering Infrastructure
AOCIAccumulated Other Comprehensive Income (Loss)
AROAsset Retirement Obligation
ATMAt the market
BGSBasic Generation Service
BSABill Stabilization Adjustment
CEJAClimate and Equitable Jobs Act; Illinois Public Act 102-0662 signed into law on September 15, 2021
CERCLAComprehensive Environmental Response, Compensation, and Liability Act of 1980, as amended
CIPConservation Incentive Program
Convertible Senior NotesExelon's 3.25% Convertible Senior Notes due 2029
CMCCarbon Mitigation Credit
CRGAClean and Reliable Grid Affordability Act
CODMsChief Operating Decision Makers
DC PLUGDistrict of Columbia Power Line Undergrounding Initiative
DCPSCPublic Service Commission of the District of Columbia
DEPSCDelaware Public Service Commission
DOEEDistrict of Columbia Department of Energy & Environment
DPADeferred Prosecution Agreement
DPPDeferred Purchase Price
DSIC
Distribution System Improvement Charge
EDITExcess Deferred Income Taxes
EPAUnited States Environmental Protection Agency
ERCOTElectric Reliability Council of Texas
ERISAEmployee Retirement Income Security Act of 1974, as amended
ETACEnergy Transition Assistance Charge
FERCFederal Energy Regulatory Commission
GAAPGenerally Accepted Accounting Principles in the United States
GCRGas Cost Rate
GSAGeneration Supply Adjustment
GWhsGigawatt hours
ICCIllinois Commerce Commission
IIJAInfrastructure Investment and Jobs Act
Illinois Settlement LegislationLegislation enacted in 2007 affecting electric utilities in Illinois
IPAIllinois Power Agency
IRAInflation Reduction Act
IRCInternal Revenue Code
IRSInternal Revenue Service
MDPSCMaryland Public Service Commission
MGPManufactured Gas Plant
5



GLOSSARY OF TERMS AND ABBREVIATIONS
Other Terms and Abbreviations
mmcfMillion Cubic Feet
MRPMulti-Year Rate Plan
MWhMegawatt hour
N/ANot Applicable
NAVNet Asset Value
NDTNuclear Decommissioning Trust
NJBPUNew Jersey Board of Public Utilities
Non-Regulatory Agreement UnitsNuclear generating units or portions thereof whose decommissioning-related activities are not subject to contractual elimination under regulatory accounting
NOLCTax Net Operating Loss Carryforward
NPNSNormal Purchase Normal Sale scope exception
NPSNational Park Service
NRDNatural Resources Damages
OCIOther Comprehensive Income
OPEBOther Postretirement Employee Benefits
PAPUCPennsylvania Public Utility Commission
PGCPurchased Gas Cost Clause
PJMPJM Interconnection, LLC
PLRPrivate Letter Ruling
POLRProvider of Last Resort
PP&EProperty, Plant, and Equipment
PRPsPotentially Responsible Parties
RECRenewable Energy Credit which is issued for each megawatt hour of generation from a qualified renewable energy source
Regulatory Agreement UnitsNuclear generating units or portions thereof whose decommissioning-related activities are subject to regulatory agreements with the ICC and PAPUC
RFPRequest for Proposal
RiderReconcilable Surcharge Recovery Mechanism
ROEReturn on Equity
ROURight-of-use
RTORegional Transmission Organization
RUBCResidential Universal Bill Credit
S&PStandard & Poor’s Ratings Services
SECUnited States Securities and Exchange Commission
SOFR Secured Overnight Financing Rate
SOSStandard Offer Service
TCJATax Cuts and Jobs Act
TSCTransmission Service Charge
Transition BondsTransition Bonds issued by Atlantic City Electric Transition Funding LLC
USAOUnited States Attorney's Office for the Northern District of Illinois
ZECZero Emission Credit
6



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.
7



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



PART I. FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
9




Exelon Corporation and Subsidiary Companies
Consolidated Statements of Operations and Comprehensive Income
(Unaudited)
Three Months Ended
March 31,
(In millions, except per share data)20262025
Operating revenues
Electric operating revenues$6,157 $5,816 
Natural gas operating revenues1,117 1,024 
Revenues from alternative revenue programs(32)(126)
Total operating revenues7,242 6,714 
Operating expenses
Purchased power2,382 2,184 
Purchased fuel394 338 
Operating and maintenance1,466 1,347 
Depreciation and amortization952 903 
Taxes other than income taxes443 405 
Total operating expenses5,637 5,177 
Loss on sale of assets— (1)
Operating income1,605 1,536 
Other income and (deductions)
Interest expense, net(548)(504)
Interest expense to affiliates(7)(6)
Other, net69 52 
Total other income and (deductions)(486)(458)
Income before income taxes1,119 1,078 
Income taxes200 170 
Net income attributable to common shareholders$919 $908 
Comprehensive income, net of income taxes
Net income$919 $908 
Other comprehensive income, net of income taxes
Pension and non-pension postretirement benefit plans:
Actuarial losses reclassified to periodic benefit cost7 5 
Pension and non-pension postretirement benefit plans valuation adjustments4 5 
Unrealized (loss) on cash flow hedges(5)(8)
Other comprehensive income6 2 
Comprehensive income attributable to common shareholders$925 $910 
Average shares of common stock outstanding:
Basic1,024 1,008 
Assumed exercise and/or distributions of stock-based awards(a)
2 1 
Diluted1,026 1,009 
Earnings per average common share
Basic$0.90 $0.90 
Diluted$0.90 $0.90 
__________
(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



Exelon Corporation and Subsidiary Companies
Consolidated Statements of Cash Flows
(Unaudited)
Three Months Ended
March 31,
(In millions)20262025
Cash flows from operating activities
Net income$919 $908 
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation, amortization, and accretion953 905 
Loss on sales of assets— 1 
Deferred income taxes and amortization of investment tax credits345 121 
Net fair value changes related to derivatives— 1 
Other non-cash operating activities222 344 
Changes in assets and liabilities:
Accounts receivable395 (402)
Inventories20 17 
Accounts payable and accrued expenses(632)(397)
Collateral received, net45 44 
Income taxes(144)59 
Regulatory assets and liabilities, net(329)86 
Pension and non-pension postretirement benefit contributions(346)(292)
Other assets and liabilities276 (195)
Net cash flows provided by operating activities1,724 1,200 
Cash flows from investing activities
Capital expenditures(2,358)(1,946)
Other investing activities2 4 
Net cash flows used in investing activities(2,356)(1,942)
Cash flows from financing activities
Changes in short-term borrowings(447)(775)
Proceeds from short-term borrowings with maturities greater than 90 days500 — 
Issuance of long-term debt1,120 2,425 
Issuance of common stock— 173 
Dividends paid on common stock(430)(403)
Proceeds from employee stock plans12 — 
Other financing activities(27)(35)
Net cash flows provided by financing activities728 1,385 
Increase in cash, restricted cash, and cash equivalents96 643 
Cash, restricted cash, and cash equivalents at beginning of period1,201 939 
Cash, restricted cash, and cash equivalents at end of period$1,297 $1,582 
Supplemental cash flow information
Decrease in capital expenditures not paid(373)(216)
See the Combined Notes to Consolidated Financial Statements
11



Exelon Corporation and Subsidiary Companies
Consolidated Balance Sheets
(Unaudited)
(In millions)March 31, 2026December 31, 2025
ASSETS
Current assets
Cash and cash equivalents$713 $626 
Restricted cash and cash equivalents560 525 
Accounts receivable
Customer accounts receivable3,6363,732
Customer allowance for credit losses(522)(435)
Customer accounts receivable, net3,114 3,297 
Other accounts receivable1,6801,879
Other allowance for credit losses(102)(94)
Other accounts receivable, net1,578 1,785 
Inventories, net
Fossil fuel35 88 
Materials and supplies811 780 
Regulatory assets1,373 1,359 
Prepaid renewable energy credits314 563 
Other504 523 
Total current assets9,002 9,546 
Property, plant, and equipment (net of accumulated depreciation and amortization of $20,694 and $20,080 as of March 31, 2026 and December 31, 2025, respectively)
85,564 84,318 
Deferred debits and other assets
Regulatory assets9,322 9,214 
Goodwill6,630 6,630 
Receivable related to Regulatory Agreement Units4,830 4,755 
Investments317 312 
Other1,880 1,795 
Total deferred debits and other assets22,979 22,706 
Total assets$117,545 $116,570 
See the Combined Notes to Consolidated Financial Statements
12



Exelon Corporation and Subsidiary Companies
Consolidated Balance Sheets
(Unaudited)
(In millions)March 31, 2026December 31, 2025
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities
Short-term borrowings$665 $612 
Long-term debt due within one year2,326 1,665 
Accounts payable3,119 3,721 
Accrued expenses1,203 1,582 
Payables to affiliates5 5 
Customer deposits565 533 
Regulatory liabilities910 1,128 
Mark-to-market derivative liabilities21 30 
Unamortized energy contract liabilities5 5 
Renewable energy credit obligations222 473 
Other547 577 
Total current liabilities9,588 10,331 
Long-term debt47,859 47,413 
Long-term debt to financing trusts390 390 
Deferred credits and other liabilities
Deferred income taxes and unamortized investment tax credits14,201 13,715 
Regulatory liabilities11,186 11,016 
Pension obligations1,426 1,749 
Non-pension postretirement benefit obligations558 546 
Asset retirement obligations321 321 
Mark-to-market derivative liabilities112 106 
Unamortized energy contract liabilities16 16 
Other2,573 2,169 
Total deferred credits and other liabilities30,393 29,638 
Total liabilities88,230 87,772 
Commitments and contingencies
Shareholders’ equity
Common stock (No par value, 2,000 shares authorized, 1,023 shares outstanding as of March 31, 2026 and December 31, 2025)
22,129 22,106 
Treasury stock, at cost (2 shares as of March 31, 2026 and December 31, 2025)
(123)(123)
Retained earnings8,065 7,577 
Accumulated other comprehensive loss, net(756)(762)
Total shareholders’ equity29,315 28,798 
Total liabilities and shareholders’ equity$117,545 $116,570 

See the Combined Notes to Consolidated Financial Statements
13



Exelon Corporation and Subsidiary Companies
Consolidated Statements of Changes in Shareholders' Equity
(Unaudited)
Three Months Ended March 31, 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, 20251,024,401$22,106 $(123)$7,577 $(762)$28,798 
Net income— — — 919 — 919 
Long-term incentive plan activity338 10 — — — 10 
Employee stock purchase plan activity302 13 — — — 13 
Common stock dividends
($0.42/common share)
— — — (431)— (431)
Other comprehensive income, net of income taxes— — — — 6 6 
Balance at March 31, 20261,025,041$22,129 $(123)$8,065 $(756)$29,315 

Three Months Ended March 31, 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, 20241,007,046 $21,338 $(123)$6,426 $(720)$26,921 
Net income— — — 908 — 908 
Long-term incentive plan activity299 4 — — — 4 
Employee stock purchase plan activity(8)2 — — — 2 
Issuance of Common Stock4,031 173 — — — 173 
Common stock dividends
($0.40/common share)
— — — (403)— (403)
Other comprehensive income, net of income taxes— — — — 2 2 
Balance at March 31, 20251,011,368 $21,517 $(123)$6,931 $(718)$27,607 










See the Combined Notes to Consolidated Financial Statements
14



Commonwealth Edison Company and Subsidiary Companies
Consolidated Statements of Operations and Comprehensive Income
(Unaudited)
Three Months Ended
March 31,
(In millions)20262025
Operating revenues
Electric operating revenues$1,894 $2,142 
Revenues from alternative revenue programs8 (85)
Operating revenues from affiliates11 8 
Total operating revenues1,913 2,065 
Operating expenses
Purchased power451 689 
Operating and maintenance335 323 
Operating and maintenance from affiliates103 100 
Depreciation and amortization404 380 
Taxes other than income taxes105 99 
Total operating expenses1,398 1,591 
Operating income515 474 
Other income and (deductions)
Interest expense, net(132)(125)
Interest expense to affiliates, net(3)(3)
Other, net31 21 
Total other income and (deductions)(104)(107)
Income before income taxes411 367 
Income taxes101 65 
Net income$310 $302 
Comprehensive income$310 $302 

See the Combined Notes to Consolidated Financial Statements
15



Commonwealth Edison Company and Subsidiary Companies
Consolidated Statements of Cash Flows
(Unaudited)
Three Months Ended
March 31,
(In millions)20262025
Cash flows from operating activities
Net income$310 $302 
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation and amortization404 380 
Deferred income taxes and amortization of investment tax credits71 (8)
Other non-cash operating activities21 141 
Changes in assets and liabilities:
Accounts receivable559 (111)
Receivables from and payables to affiliates, net(11)(21)
Inventories(7)3 
Accounts payable and accrued expenses (108)(189)
Collateral received, net52 5 
Income taxes29 72 
Regulatory assets and liabilities, net(350)76 
Pension and non-pension postretirement benefit contributions(220)(189)
Other assets and liabilities(6)(102)
Net cash flows provided by operating activities744 359 
Cash flows from investing activities
Capital expenditures(885)(590)
Other investing activities— 1 
Net cash flows used in investing activities(885)(589)
Cash flows from financing activities
Changes in short-term borrowings46 311 
Dividends paid on common stock(218)(203)
Contributions from parent256 87 
Net cash flows provided by financing activities84 195 
Decrease in cash, restricted cash, and cash equivalents(57)(35)
Cash, restricted cash, and cash equivalents at beginning of period663 632 
Cash, restricted cash, and cash equivalents at end of period$606 $597 
Supplemental cash flow information
Decrease in capital expenditures not paid$(133)$(25)
See the Combined Notes to Consolidated Financial Statements
16



Commonwealth Edison Company and Subsidiary Companies
Consolidated Balance Sheets
(Unaudited)
(In millions)March 31, 2026December 31, 2025
ASSETS
Current assets
   Cash and cash equivalents$95 $159 
   Restricted cash and cash equivalents487 454 
   Accounts receivable
   Customer accounts receivable8651,058
   Customer allowance for credit losses(130)(115)
       Customer accounts receivable, net735 943 
   Other accounts receivable7801,155
   Other allowance for credit losses(27)(23)
       Other accounts receivable, net 753 1,132 
   Receivables from affiliates7 5 
   Inventories, net274 268 
   Regulatory assets687 595 
   Other189 217 
   Total current assets3,227 3,773 
Property, plant, and equipment (net of accumulated depreciation and amortization of $8,514 and $8,219 as of March 31, 2026 and December 31, 2025, respectively)
32,738 32,255 
Deferred debits and other assets
   Regulatory assets2,750 2,687 
   Goodwill2,625 2,625 
   Receivable related to Regulatory Agreement Units4,297 4,313 
   Investments6 6 
   Prepaid pension asset1,480 1,284 
   Other1,355 1,342 
   Total deferred debits and other assets12,513 12,257 
Total assets$48,478 $48,285 
See the Combined Notes to Consolidated Financial Statements
17



Commonwealth Edison Company and Subsidiary Companies
Consolidated Balance Sheets
(Unaudited)
(In millions)March 31, 2026December 31, 2025
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities
   Short-term borrowings$46 $— 
   Long-term debt due within one year500 500 
   Accounts payable927 1,033 
   Accrued expenses369 474 
   Payables to affiliates72 81 
   Customer deposits214 192 
   Regulatory liabilities603 846 
   Mark-to-market derivative liabilities22 25 
   Other295 288 
   Total current liabilities3,048 3,439 
Long-term debt12,255 12,253 
Long-term debt to financing trust206 206 
Deferred credits and other liabilities
   Deferred income taxes and unamortized investment tax credits5,918 5,828 
   Regulatory liabilities9,268 9,163 
   Asset retirement obligations195 193 
   Non-pension postretirement benefit obligations154 151 
   Mark-to-market derivative liabilities111 106 
   Other1,370 1,341 
   Total deferred credits and other liabilities17,016 16,782 
   Total liabilities32,525 32,680 
Commitments and contingencies
Shareholders’ equity
   Common stock 1,588 1,588 
   Other paid-in capital11,275 11,019 
   Retained earnings3,090 2,998 
   Total shareholders’ equity15,953 15,605 
Total liabilities and shareholders’ equity$48,478 $48,285 
    
See the Combined Notes to Consolidated Financial Statements
18



Commonwealth Edison Company and Subsidiary Companies
Consolidated Statements of Changes in Shareholders' Equity
(Unaudited)
Three Months Ended March 31, 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 
Three Months Ended March 31, 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 
See the Combined Notes to Consolidated Financial Statements
19




PECO Energy Company and Subsidiary Companies
Consolidated Statements of Operations and Comprehensive Income
(Unaudited)
 Three Months Ended
March 31,
(In millions)20262025
Operating revenues
Electric operating revenues$1,073 $963 
Natural gas operating revenues410 376 
Revenues from alternative revenue programs5 (9)
Operating revenues from affiliates4 3 
Total operating revenues1,492 1,333 
Operating expenses
Purchased power 451 361 
Purchased fuel161 141 
Operating and maintenance271 266 
Operating and maintenance from affiliates66 61 
Depreciation and amortization121 109 
Taxes other than income taxes69 60 
Total operating expenses1,139 998 
Operating income353 335 
Other income and (deductions)
Interest expense, net(69)(59)
Interest expense to affiliates, net(2)(4)
Other, net11 8 
Total other income and (deductions)(60)(55)
Income before income taxes293 280 
Income taxes15 14 
Net income$278 $266 
Comprehensive income$278 $266 
See the Combined Notes to Consolidated Financial Statements
20



PECO Energy Company and Subsidiary Companies
Consolidated Statements of Cash Flows
(Unaudited)
Three Months Ended
March 31,
(In millions)20262025
Cash flows from operating activities
Net income$278 $266 
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation and amortization121 109 
Deferred income taxes and amortization of investment tax credits278 (18)
Other non-cash operating activities34 54 
Changes in assets and liabilities:
Accounts receivable(87)(148)
Receivables from and payables to affiliates, net4 (4)
Inventories23 15 
Accounts payable and accrued expenses (122)(25)
Collateral (paid) received, net— 12 
Income taxes(262)32 
Regulatory assets and liabilities, net(55)27 
Pension and non-pension postretirement benefit contributions(12)(9)
Other assets and liabilities(120)(117)
Net cash flows provided by operating activities80 194 
Cash flows from investing activities
Capital expenditures(469)(424)
Changes in Exelon intercompany money pool(5)— 
Other investing activities(1)2 
Net cash flows used in investing activities(475)(422)
Cash flows from financing activities
Changes in short-term borrowings— (192)
Dividends paid on common stock(137)(137)
Contributions from parent567 563 
Net cash flows provided by financing activities430 234 
Increase in cash, restricted cash, and cash equivalents35 6 
Cash, restricted cash, and cash equivalents at beginning of period116 48 
Cash, restricted cash, and cash equivalents at end of period$151 $54 
Supplemental cash flow information
Decrease in capital expenditures not paid$(33)$(20)
See the Combined Notes to Consolidated Financial Statements
21



PECO Energy Company and Subsidiary Companies
Consolidated Balance Sheets
(Unaudited)
(In millions)March 31, 2026December 31, 2025
ASSETS
Current assets
Cash and cash equivalents$151 $116 
Accounts receivable
Customer accounts receivable861811
Customer allowance for credit losses(160)(137)
Customer accounts receivable, net701 674 
Other accounts receivable178144
Other allowance for credit losses(22)(18)
Other accounts receivable, net156 126 
Receivables from affiliates2 — 
Fossil fuel16 43 
Materials and supplies87 83 
Prepaid utility taxes127 2 
Prepaid renewable energy credits80 55 
Regulatory assets128 72 
Other29 32 
Total current assets1,477 1,203 
Property, plant, and equipment (net of accumulated depreciation and amortization of $4,211 and $4,131 as of March 31, 2026 and December 31, 2025, respectively)
16,245 15,922 
Deferred debits and other assets
Regulatory assets1,351 1,275 
Receivable related to Regulatory Agreement Units533 442 
Investments45 45 
Prepaid pension asset450 441 
Other92 34 
Total deferred debits and other assets2,471 2,237 
Total assets$20,193 $19,362 
See the Combined Notes to Consolidated Financial Statements
22



PECO Energy Company and Subsidiary Companies
Consolidated Balance Sheets
(Unaudited)
(In millions)March 31, 2026December 31, 2025
LIABILITIES AND SHAREHOLDER'S EQUITY
Current liabilities
Accounts payable$758 $811 
Accrued expenses132 483 
Payables to affiliates41 35 
Customer deposits97 93 
Renewable energy credit obligations81 56 
Regulatory liabilities138 140 
Other42 40 
Total current liabilities1,289 1,658 
Long-term debt6,397 6,396 
Long-term debt to financing trusts184 184 
Deferred credits and other liabilities
Deferred income taxes and unamortized investment tax credits2,944 2,594 
Regulatory liabilities539 449 
Asset retirement obligations26 26 
Non-pension postretirement benefit obligations288 286 
Other158 109 
Total deferred credits and other liabilities3,955 3,464 
Total liabilities11,825 11,702 
Commitments and contingencies
Shareholder’s equity
Common stock5,789 5,222 
Retained earnings2,579 2,438 
Total shareholder’s equity8,368 7,660 
Total liabilities and shareholder's equity$20,193 $19,362 
See the Combined Notes to Consolidated Financial Statements
23



PECO Energy Company and Subsidiary Companies
Consolidated Statements of Changes in Shareholders' Equity
(Unaudited)
Three Months Ended March 31, 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 parent567 — 567 
Balance at March 31, 2026$5,789 $2,579 $8,368 
Three Months Ended March 31, 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 parent563 — 563 
Balance at March 31, 2025$5,208 $2,299 $7,507 
See the Combined Notes to Consolidated Financial Statements
24




Baltimore Gas and Electric Company
Statements of Operations and Comprehensive Income
(Unaudited)
Three Months Ended
March 31,
(In millions)20262025
Operating revenues
Electric operating revenues$1,257 $1,021 
Natural gas operating revenues590 560 
Revenues from alternative revenue programs(22)(29)
Operating revenues from affiliates3 2 
Total operating revenues1,828 1,554 
Operating expenses
Purchased power630 450 
Purchased fuel178 159 
Operating and maintenance260 242 
Operating and maintenance from affiliates67 63 
Depreciation and amortization167 164 
Taxes other than income taxes104 96 
Total operating expenses1,406 1,174 
Operating income422 380 
Other income and (deductions)
Interest expense, net(62)(58)
Other, net17 9 
Total other income and (deductions)(45)(49)
Income before income taxes377 331 
Income taxes79 71 
Net income$298 $260 
Comprehensive income$298 $260 
See the Combined Notes to Consolidated Financial Statements
25



Baltimore Gas and Electric Company
Statements of Cash Flows
(Unaudited)
Three Months Ended
March 31,
(In millions)20262025
Cash flows from operating activities
Net income$298 $260 
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation and amortization167 164 
Deferred income taxes and amortization of investment tax credits191 35 
Other non-cash operating activities44 55 
Changes in assets and liabilities:
Accounts receivable(134)(153)
Receivables from and payables to affiliates, net(7)(10)
Inventories16 20 
Accounts payable and accrued expenses(63)(15)
Collateral received, net4 1 
Income taxes(111)36 
Regulatory assets and liabilities, net71 14 
Pension and non-pension postretirement benefit contributions(40)(34)
Other assets and liabilities71 49 
Net cash flows provided by operating activities507 422 
Cash flows from investing activities
Capital expenditures(437)(406)
Other investing activities4 3 
Net cash flows used in investing activities(433)(403)
Cash flows from financing activities
Changes in short-term borrowings— 62 
Dividends paid on common stock(114)(98)
Net cash flows used in financing activities(114)(36)
Decrease in cash, restricted cash, and cash equivalents(40)(17)
Cash, restricted cash, and cash equivalents at beginning of period220 34 
Cash, restricted cash, and cash equivalents at end of period$180 $17 
Supplemental cash flow information
Decrease in capital expenditures not paid$(95)$(48)
See the Combined Notes to Consolidated Financial Statements
26



Baltimore Gas and Electric Company
Balance Sheets
(Unaudited)
(In millions)March 31, 2026December 31, 2025
ASSETS
Current assets
Cash and cash equivalents$173 $217 
Restricted cash and cash equivalents7 3 
Accounts receivable
Customer accounts receivable1,012887
Customer allowance for credit losses (101)(68)
Customer accounts receivable, net911 819 
Other accounts receivable 116100
Other allowance for credit losses(4)(4)
Other accounts receivable, net112 96 
Receivables from affiliates1 1 
Inventories, net
Fossil fuel15 36 
Materials and supplies78 74 
Prepaid utility taxes64 126 
Regulatory assets90 175 
Prepaid renewable energy credits50 189 
Other18 14 
Total current assets1,519 1,750 
Property, plant, and equipment (net of accumulated depreciation and amortization of $5,351 and $5,234 as of March 31, 2026 and December 31, 2025, respectively)
14,593 14,385 
Deferred debits and other assets
Regulatory assets787 804 
Investments11 10 
Prepaid pension asset221 194 
Other40 41 
Total deferred debits and other assets1,059 1,049 
Total assets$17,171 $17,184 
See the Combined Notes to Consolidated Financial Statements
27



Baltimore Gas and Electric Company
Balance Sheets
(Unaudited)
(In millions)March 31, 2026December 31, 2025
LIABILITIES AND SHAREHOLDER'S EQUITY
Current liabilities
Long-term debt due within one year$350 $350 
Accounts payable470 640 
Accrued expenses252 352 
Payables to affiliates32 39 
Customer deposits126 125 
Regulatory liabilities45 31 
Renewable energy credit obligations54 194 
Other57 39 
Total current liabilities1,386 1,770 
Long-term debt5,692 5,691 
Deferred credits and other liabilities
Deferred income taxes and unamortized investment tax credits2,464 2,242 
Regulatory liabilities565 595 
Asset retirement obligations36 36 
Non-pension postretirement benefit obligations138 144 
Other104 104 
Total deferred credits and other liabilities3,307 3,121 
Total liabilities10,385 10,582 
Commitments and contingencies
Shareholder's equity
Common stock4,014 4,014 
Retained earnings2,772 2,588 
Total shareholder's equity6,786 6,602 
Total liabilities and shareholder's equity$17,171 $17,184 

See the Combined Notes to Consolidated Financial Statements
28



Baltimore Gas and Electric Company
Statements of Changes in Shareholder's Equity
(Unaudited)
Three Months Ended March 31, 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 
Three Months Ended March 31, 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 
See the Combined Notes to Consolidated Financial Statements
29




Pepco Holdings LLC and Subsidiary Companies
Consolidated Statements of Operations and Comprehensive Income
(Unaudited)
Three Months Ended
March 31,
(In millions)20262025
Operating revenues
Electric operating revenues$1,934 $1,691 
Natural gas operating revenues116 88 
Revenues from alternative revenue programs(23)(3)
Operating revenues from affiliates3 2 
Total operating revenues2,030 1,778 
Operating expenses
Purchased power850 684 
Purchased fuel55 38 
Operating and maintenance365 296 
Operating and maintenance from affiliates59 53 
Depreciation and amortization246 234 
Taxes other than income taxes151 140 
Total operating expenses1,726 1,445 
Loss on sale of assets— (1)
Operating income304 332 
Other income and (deductions)
Interest expense, net(105)(99)
Interest expense to affiliates, net(1)(1)
Other, net18 19 
Total other income and (deductions)(88)(81)
Income before income taxes 216 251 
Income taxes47 57 
Net income$169 $194 
Comprehensive income$169 $194 
See the Combined Notes to Consolidated Financial Statements
30



Pepco Holdings LLC and Subsidiary Companies
Consolidated Statements of Cash Flows
(Unaudited)
Three Months Ended
March 31,
(In millions)20262025
Cash flows from operating activities
Net income$169 $194 
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation, amortization, and accretion246 234 
Loss on sales of assets— 1 
Deferred income taxes and amortization of investment tax credits92 32 
Other non-cash operating activities86 69 
Changes in assets and liabilities:
Accounts receivable62 6 
Receivables from and payables to affiliates, net(28)(9)
Inventories(9)(24)
Accounts payable and accrued expenses(54)(84)
Collateral (paid) received, net(10)27 
Income taxes(45)25 
Regulatory assets and liabilities, net9 (14)
Pension and non-pension postretirement benefit contributions(52)(42)
Other assets and liabilities10 (13)
Net cash flows provided by operating activities476 402 
Cash flows from investing activities
Capital expenditures(558)(513)
Net cash flows used in investing activities(558)(513)
Cash flows from financing activities
Changes in short-term borrowings(493)(530)
Issuance of long-term debt345 425 
Changes in Exelon intercompany money pool40 11 
Distributions to member(139)(132)
Contributions from member275 352 
Other financing activities(7)(8)
Net cash flows provided by financing activities21 118 
(Decrease) increase in cash, restricted cash, and cash equivalents(61)7 
Cash, restricted cash, and cash equivalents at beginning of period141 163 
Cash, restricted cash, and cash equivalents at end of period$80 $170 
Supplemental cash flow information
Decrease in capital expenditures not paid$(117)$(109)
See the Combined Notes to Consolidated Financial Statements
31



Pepco Holdings LLC and Subsidiary Companies
Consolidated Balance Sheets
(Unaudited)
(In millions)March 31, 2026December 31, 2025
ASSETS
Current assets
Cash and cash equivalents$49 $103 
Restricted cash and cash equivalents31 38 
Accounts receivable
Customer accounts receivable897975
Customer allowance for credit losses(131)(115)
Customer accounts receivable, net766 860 
Other accounts receivable319292
Other allowance for credit losses(49)(49)
Other accounts receivable, net270 243 
Receivables from affiliates15 14 
Inventories, net
Fossil fuel4 9 
Materials and supplies371 357 
Prepaid utility taxes43 77 
Regulatory assets302 352 
Prepaid renewable energy credits59 201 
Other46 34 
Total current assets1,956 2,288 
Property, plant, and equipment (net of accumulated depreciation and amortization of $4,529 and $4,350 as of March 31, 2026 and December 31, 2025, respectively)
21,605 21,377 
Deferred debits and other assets
Regulatory assets1,560 1,556 
Goodwill4,005 4,005 
Investments159 158 
Prepaid pension asset227 199 
Other145 132 
Total deferred debits and other assets6,096 6,050 
Total assets$29,657 $29,715 
See the Combined Notes to Consolidated Financial Statements
32



Pepco Holdings LLC and Subsidiary Companies
Consolidated Balance Sheets
(Unaudited)
(In millions)March 31, 2026December 31, 2025
LIABILITIES AND MEMBER'S EQUITY
Current liabilities
Short-term borrowings$119 $612 
Long-term debt due within one year75 64 
Accounts payable707 816 
Accrued expenses277 359 
Payables to affiliates44 71 
Borrowings from Exelon intercompany money pool120 80 
Customer deposits128 123 
Regulatory liabilities 115 103 
Unamortized energy contract liabilities5 5 
Renewable energy credit obligations87 223 
Other102 121 
Total current liabilities1,779 2,577 
Long-term debt9,853 9,526 
Deferred credits and other liabilities
Deferred income taxes and unamortized investment tax credits3,500 3,391 
Regulatory liabilities726 722 
Asset retirement obligations60 62 
Non-pension postretirement benefit obligations20 24 
Unamortized energy contract liabilities15 16 
Other420 418 
Total deferred credits and other liabilities4,741 4,633 
Total liabilities16,373 16,736 
Commitments and contingencies
Member's equity
Membership interest13,405 13,130 
Undistributed losses(121)(151)
Total member's equity13,284 12,979 
Total liabilities and member's equity$29,657 $29,715 
See the Combined Notes to Consolidated Financial Statements
33



Pepco Holdings LLC and Subsidiary Companies
Consolidated Statements of Changes in Member's Equity
(Unaudited)
Three Months Ended March 31, 2026
(In millions)Membership InterestUndistributed (Losses)/GainsTotal Member's Equity
Balance at December 31, 2025$13,130 $(151)$12,979 
Net income— 169 169 
Distributions to member— (139)(139)
Contributions from member275 — 275 
Balance at March 31, 2026$13,405 $(121)$13,284 

Three Months Ended March 31, 2025
(In millions)Membership InterestUndistributed (Losses)/GainsTotal Member's Equity
Balance at December 31, 2024$12,562 $(240)$12,322 
Net income— 194 194 
Distributions to member— (132)(132)
Contributions from member352 — 352 
Balance at March 31, 2025$12,914 $(178)$12,736 
See the Combined Notes to Consolidated Financial Statements
34




Potomac Electric Power Company
Statements of Operations and Comprehensive Income
(Unaudited)
Three Months Ended
March 31,
(In millions)20262025
Operating revenues
Electric operating revenues$986 $855 
Revenues from alternative revenue programs1 2 
Operating revenues from affiliates2 2 
Total operating revenues989 859 
Operating expenses
Purchased power411 318 
Operating and maintenance151 96 
Operating and maintenance from affiliates67 63 
Depreciation and amortization114 105 
Taxes other than income taxes118 113 
Total operating expenses861 695 
Loss on sale of assets— (1)
Operating income128 163 
Other income and (deductions)
Interest expense, net(55)(52)
Other, net11 11 
Total other income and (deductions)(44)(41)
Income before income taxes84 122 
Income taxes16 25 
Net income$68 $97 
Comprehensive income$68 $97 
See the Combined Notes to Consolidated Financial Statements
35



Potomac Electric Power Company
Statements Of Cash Flows
(Unaudited)
Three Months Ended
March 31,
(In millions)20262025
Cash flows from operating activities
Net income$68 $97 
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation, amortization, and accretion114 105 
Loss on sales of assets— 1 
Deferred income taxes and amortization of investment tax credits44 10 
Other non-cash operating activities27 12 
Changes in assets and liabilities:
Accounts receivable24 (14)
Receivables from and payables to affiliates, net(6)(2)
Inventories(14)(20)
Accounts payable and accrued expenses 4 (28)
Collateral (paid) received, net(12)10 
Income taxes(28)15 
Regulatory assets and liabilities, net35 13 
Pension and non-pension postretirement benefit contributions(4)(4)
Other assets and liabilities6 (3)
Net cash flows provided by operating activities258 192 
Cash flows from investing activities
Capital expenditures(285)(240)
Net cash flows used in investing activities(285)(240)
Cash flows from financing activities
Changes in short-term borrowings(230)(200)
Issuance of long-term debt170 200 
Dividends paid on common stock(64)(66)
Contributions from parent139 157 
Other financing activities(3)(5)
Net cash flows provided by financing activities12 86 
(Decrease) increase in cash, restricted cash, and cash equivalents(15)38 
Cash, restricted cash, and cash equivalents at beginning of period55 51 
Cash, restricted cash, and cash equivalents at end of period$40 $89 
Supplemental cash flow information
Decrease in capital expenditures not paid$(83)$(49)
See the Combined Notes to Consolidated Financial Statements
36



Potomac Electric Power Company
Balance Sheets
(Unaudited)
(In millions)March 31, 2026December 31, 2025
ASSETS
Current assets
Cash and cash equivalents$20 $22 
Restricted cash and cash equivalents20 33 
Accounts receivable
Customer accounts receivable454484
Customer allowance for credit losses(76)(69)
Customer accounts receivable, net378 415 
Other accounts receivable173154
Other allowance for credit losses(26)(26)
Other accounts receivable, net147 128 
Receivables from affiliates1 — 
Inventories, net188 174 
Regulatory assets145 182 
Prepaid renewable energy credits49 171 
Other40 59 
Total current assets988 1,184 
Property, plant, and equipment (net of accumulated depreciation and amortization of $4,861 and $4,784 as of March 31, 2026 and December 31, 2025, respectively)
10,850 10,747 
Deferred debits and other assets
Regulatory assets400 405 
Investments142 141 
Prepaid pension asset189 194 
Other63 57 
Total deferred debits and other assets794 797 
Total assets$12,632 $12,728 
See the Combined Notes to Consolidated Financial Statements
37



Potomac Electric Power Company
Balance Sheets
(Unaudited)
(In millions)March 31, 2026December 31, 2025
LIABILITIES AND SHAREHOLDER'S EQUITY
Current liabilities
Short-term borrowings$73 $303 
Long-term debt due within one year7 6 
Accounts payable352 418 
Accrued expenses149 173 
Payables to affiliates32 37 
Customer deposits64 61 
Regulatory liabilities 13 13 
Renewable energy credit obligations50 174 
Other62 84 
Total current liabilities802 1,269 
Long-term debt4,795 4,626 
Deferred credits and other liabilities
Deferred income taxes and unamortized investment tax credits1,658 1,604 
Regulatory liabilities 271 268 
Asset retirement obligations42 45 
Other219 214 
Total deferred credits and other liabilities2,190 2,131 
Total liabilities7,787 8,026 
Commitments and contingencies
Shareholder's equity
Common stock 3,667 3,528 
Retained earnings1,178 1,174 
Total shareholder's equity4,845 4,702 
Total liabilities and shareholder's equity$12,632 $12,728 
See the Combined Notes to Consolidated Financial Statements
38



Potomac Electric Power Company
Statements Of Changes In Shareholder's Equity
(Unaudited)
Three Months Ended March 31, 2026
(In millions)Common StockRetained EarningsTotal 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 parent139 — 139 
Balance at March 31, 2026$3,667 $1,178 $4,845 

Three Months Ended March 31, 2025
(In millions)Common StockRetained EarningsTotal 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 parent157 — 157 
Balance at March 31, 2025$3,492 $1,131 $4,623 

See the Combined Notes to Consolidated Financial Statements
39




Delmarva Power & Light Company
Statements of Operations and Comprehensive Income
(Unaudited)
Three Months Ended
March 31,
(In millions)20262025
Operating revenues
Electric operating revenues$510 $463 
Natural gas operating revenues116 88 
Revenues from alternative revenue programs(6)(5)
Operating revenues from affiliates2 2 
Total operating revenues622 548 
Operating expenses
Purchased power234 209 
Purchased fuel55 38 
Operating and maintenance71 60 
Operating and maintenance from affiliates 47 46 
Depreciation and amortization66 63 
Taxes other than income taxes26 21 
Total operating expenses499 437 
Operating income123 111 
Other income and (deductions)
Interest expense, net(27)(25)
Other, net4 4 
Total other income and (deductions)(23)(21)
Income before income taxes100 90 
Income taxes23 21 
Net income$77 $69 
Comprehensive income$77 $69 
See the Combined Notes to Consolidated Financial Statements
40



Delmarva Power & Light Company
Statements Of Cash Flows
(Unaudited)
Three Months Ended
March 31,
(In millions)20262025
Cash flows from operating activities
Net income$77 $69 
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation and amortization66 63 
Deferred income taxes and amortization of investment tax credits26 9 
Other non-cash operating activities19 21 
Changes in assets and liabilities:
Accounts receivable24 (1)
Receivables from and payables to affiliates, net— (4)
Inventories6 (4)
Accounts payable and accrued expenses(29)(9)
Collateral received, net7 9 
Income taxes(3)13 
Regulatory assets and liabilities, net3 2 
Pension and non-pension postretirement benefit contributions(1)— 
Other assets and liabilities10 7 
Net cash flows provided by operating activities205 175 
Cash flows from investing activities
Capital expenditures(147)(156)
Changes in PHI intercompany money pool— (12)
Net cash flows used in investing activities(147)(168)
Cash flows from financing activities
Changes in short-term borrowings(115)(144)
Issuance of long-term debt75 125 
Dividends paid on common stock(50)(46)
Contributions from parent45 99 
Other financing activities(3)(3)
Net cash flows (used in) provided by financing activities(48)31 
Increase in cash, restricted cash, and cash equivalents10 38 
Cash, restricted cash, and cash equivalents at beginning of period12 23 
Cash, restricted cash, and cash equivalents at end of period$22 $61 
Supplemental cash flow information
Decrease in capital expenditures not paid$(25)$(47)
    
See the Combined Notes to Consolidated Financial Statements
41



Delmarva Power & Light Company
Balance Sheets
(Unaudited)
(In millions)March 31, 2026December 31, 2025
ASSETS
Current assets
Cash and cash equivalents$12 $9 
Restricted cash and cash equivalents10 3 
Accounts receivable
Customer accounts receivable228253
Customer allowance for credit losses(24)(19)
Customer accounts receivable, net204 234 
Other accounts receivable7375
Other allowance for credit losses(11)(10)
Other accounts receivable, net62 65 
Receivables from affiliates2 2 
Inventories, net
Fossil fuel5 9 
Materials and supplies105 107 
Prepaid utility taxes16 29 
Regulatory assets78 72 
Prepaid renewable energy credits10 30 
Other20 13 
Total current assets524 573 
Property, plant, and equipment (net of accumulated depreciation and amortization of $2,289 and $2,241 as of March 31, 2026 and December 31, 2025, respectively)
5,921 5,855 
Deferred debits and other assets
Regulatory assets208 214 
Other145 147 
Total deferred debits and other assets353 361 
Total assets$6,798 $6,789 
See the Combined Notes to Consolidated Financial Statements
42



Delmarva Power & Light Company
Balance Sheets
(Unaudited)
(In millions)March 31, 2026December 31, 2025
LIABILITIES AND SHAREHOLDER'S EQUITY
Current liabilities
Short-term borrowings$46 $161 
Long-term debt due within one year63 53 
Accounts payable163 218 
Accrued expenses66 70 
Payables to affiliates25 25 
Customer deposits37 36 
Regulatory liabilities 49 42 
Renewable energy credit obligations37 49 
Other29 22 
Total current liabilities515 676 
Long-term debt2,358 2,291 
Deferred credits and other liabilities
Deferred income taxes and unamortized investment tax credits1,028 996 
Regulatory liabilities318 316 
Asset retirement obligations13 12 
Other123 127 
Total deferred credits and other liabilities1,482 1,451 
Total liabilities4,355 4,418 
Commitments and contingencies
Shareholder's equity
Common stock 1,767 1,722 
Retained earnings676 649 
Total shareholder's equity2,443 2,371 
Total liabilities and shareholder's equity$6,798 $6,789 
See the Combined Notes to Consolidated Financial Statements
43



Delmarva Power & Light Company
Statements Of Changes In Shareholder's Equity
(Unaudited)
Three Months Ended March 31, 2026
(In millions)Common Stock Retained EarningsTotal Shareholder's Equity
Balance at December 31, 2025$1,722 $649 $2,371 
Net income— 77 77 
Common stock dividends— (50)(50)
Contributions from parent45 — 45 
Balance at March 31, 2026$1,767 $676 $2,443 

Three Months Ended March 31, 2025
(In millions)Common Stock Retained EarningsTotal Shareholder's Equity
Balance at December 31, 2024$1,615 $627 $2,242 
Net income— 69 69 
Common stock dividends— (46)(46)
Contributions from parent99 — 99 
Balance at March 31, 2025$1,714 $650 $2,364 

See the Combined Notes to Consolidated Financial Statements
44




Atlantic City Electric Company and Subsidiary Company
Consolidated Statements of Operations and Comprehensive Income
(Unaudited)
Three Months Ended
March 31,
(In millions)20262025
Operating revenues
Electric operating revenues$438 $372 
Revenues from alternative revenue programs(18)— 
Operating revenues from affiliates1 1 
Total operating revenues421 373 
Operating expenses
Purchased power205 157 
Operating and maintenance50 51 
Operating and maintenance from affiliates43 39 
Depreciation and amortization65 64 
Taxes other than income taxes2 2 
Total operating expenses365 313 
Operating income56 60 
Other income and (deductions)
Interest expense, net(22)(21)
Other, net2 3 
Total other income and (deductions)(20)(18)
Income before income taxes36 42 
Income taxes9 11 
Net income$27 $31 
Comprehensive income$27 $31 
See the Combined Notes to Consolidated Financial Statements
45



Atlantic City Electric Company and Subsidiary Company
Statements Of Cash Flows
(Unaudited)
Three Months Ended
March 31,
(In millions)20262025
Cash flows from operating activities
Net income$27 $31 
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation and amortization65 64 
Deferred income taxes and amortization of investment tax credits30 8 
Other non-cash operating activities34 25 
Changes in assets and liabilities:
Accounts receivable15 21 
Receivables from and payables to affiliates, net(4)(2)
Inventories(2)— 
Accounts payable and accrued expenses(1)(8)
Collateral (paid) received, net(5)6 
Income taxes(21)3 
Regulatory assets and liabilities, net(32)(28)
Pension and non-pension postretirement benefit contributions(13)(3)
Other assets and liabilities1 (5)
Net cash flows provided by operating activities94 112 
Cash flows from investing activities
Capital expenditures(122)(105)
Net cash flows used in investing activities(122)(105)
Cash flows from financing activities
Changes in short-term borrowings(148)(186)
Issuance of long-term debt100 100 
Changes in PHI intercompany money pool— 12 
Dividends paid on common stock(25)(20)
Contributions from parent91 94 
Other financing activities(1)(2)
Net cash flows provided by (used in) financing activities17 (2)
(Decrease) increase in cash and cash equivalents(11)5 
Cash and cash equivalents at beginning of period24 14 
Cash and cash equivalents at end of period$13 $19 
Supplemental cash flow information
Decrease in capital expenditures not paid$(8)$(12)
See the Combined Notes to Consolidated Financial Statements
46



Atlantic City Electric Company and Subsidiary Company
Consolidated Balance Sheets
(Unaudited)
(In millions)March 31, 2026December 31, 2025
ASSETS
Current assets
Cash and cash equivalents$12 $22 
Restricted cash and cash equivalents1 2 
Accounts receivable
Customer accounts receivable216239
Customer allowance for credit losses(31)(27)
Customer accounts receivable, net185 212 
Other accounts receivable8064
Other allowance for credit losses(12)(13)
Other accounts receivable, net68 51 
Receivables from affiliates12 12 
Inventories, net78 76 
Regulatory assets74 93 
Other8 8 
Total current assets438 476 
Property, plant, and equipment (net of accumulated depreciation and amortization of $2,003 and $1,956 as of March 31, 2026 and December 31, 2025, respectively)
4,615 4,556 
Deferred debits and other assets
Regulatory assets582 559 
Other50 41 
Total deferred debits and other assets632 600 
Total assets$5,685 $5,632 
See the Combined Notes to Consolidated Financial Statements
47



Atlantic City Electric Company and Subsidiary Company
Consolidated Balance Sheets
(Unaudited)
(In millions)March 31, 2026December 31, 2025
LIABILITIES AND SHAREHOLDER'S EQUITY
Current liabilities
Short-term borrowings$— $148 
Long-term debt due within one year5 5 
Accounts payable180 168 
Accrued expenses43 64 
Payables to affiliates20 24 
Customer deposits26 26 
Regulatory liabilities52 48 
Other9 13 
Total current liabilities335 496 
Long-term debt2,128 2,028 
Deferred credits and other liabilities
Deferred income taxes and unamortized investment tax credits900 869 
Regulatory liabilities135 137 
Other66 74 
Total deferred credits and other liabilities1,101 1,080 
Total liabilities3,564 3,604 
Commitments and contingencies
Shareholder's equity
Common stock2,104 2,013 
Retained earnings17 15 
Total shareholder's equity2,121 2,028 
Total liabilities and shareholder's equity$5,685 $5,632 

See the Combined Notes to Consolidated Financial Statements
48



Atlantic City Electric Company and Subsidiary Company
Consolidated Statements Of Changes In Shareholder's Equity
(Unaudited)
Three Months Ended March 31, 2026
(In millions)Common StockRetained (Deficit) EarningsTotal Shareholder's Equity
Balance at December 31, 2025$2,013 $15 $2,028 
Net income— 27 27 
Common stock dividends— (25)(25)
Contributions from parent91 — 91 
Balance at March 31, 2026$2,104 $17 $2,121 

Three Months Ended March 31, 2025
(In millions)Common Stock Retained (Deficit) EarningsTotal Shareholder's Equity
Balance at December 31, 2024$1,915 $10 $1,925 
Net income— 31 31 
Common stock dividends— (20)(20)
Contributions from parent94 — 94 
Balance at March 31, 2025$2,009 $21 $2,030 

See the Combined Notes to Consolidated Financial Statements
49



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 CompanyPurchase and regulated retail sale of electricityNorthern 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 CompanyPurchase and regulated retail sale of electricity and natural gasSoutheastern Pennsylvania, including the City of Philadelphia (electricity)
Transmission and distribution of electricity and distribution of natural gas to retail customersPennsylvania counties surrounding the City of Philadelphia (natural gas)
Baltimore Gas and Electric CompanyPurchase and regulated retail sale of electricity and natural gasCentral Maryland, including the City of Baltimore (electricity and natural gas)
Transmission and distribution of electricity and distribution of natural gas to retail customers
Pepco Holdings LLCUtility services holding company engaged, through its reportable segments Pepco, DPL, and ACEService Territories of Pepco, DPL, and ACE
Potomac Electric 
Power Company		  Purchase and regulated retail sale of electricity  District of Columbia, and major portions of Montgomery and Prince George’s Counties, Maryland
Transmission and distribution of electricity to retail customers
Delmarva Power &
Light Company		Purchase and regulated retail sale of electricity and natural gasPortions of Delaware and Maryland (electricity)
Transmission and distribution of electricity and distribution of natural gas to retail customersPortions of New Castle County, Delaware (natural gas)
Atlantic City Electric CompanyPurchase and regulated retail sale of electricityPortions 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
50

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 March 31, 2026 and for the three months ended March 31, 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 March 31, 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 March 31, 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.
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.
51

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/JurisdictionFiling DateServiceRequested Revenue Requirement IncreaseApproved Revenue Requirement IncreaseApproved ROEApproval DateRate Effective Date
ComEd - IllinoisJanuary 17, 2023Electric$1,487 $1,045 8.905%December 19, 2024January 1, 2024
April 26, 2024 (amended on September 11, 2024)Electric$624 $623 9.89%October 31, 2024January 1, 2025
PECO - PennsylvaniaMarch 28, 2024Electric$464 $354 N/ADecember 12, 2024January 1, 2025
Natural Gas$111 $78 
BGE - MarylandFebruary 17, 2023Electric$313 $179 9.50%December 14, 2023January 1, 2024
Natural Gas$289 $229 9.45%
Pepco - District of ColumbiaApril 13, 2023 (amended February 27, 2024)Electric$186 $123 9.50%November 26, 2024January 1, 2025
Pepco - MarylandMay 16, 2023 (amended February 23, 2024)Electric$111 $45 9.50%June 10, 2024April 1, 2024
DPL - MarylandMay 19, 2022Electric$38 $29 9.60%December 14, 2022January 1, 2023
DPL - DelawareDecember 15, 2022 (amended September 29, 2023)Electric$39 $28 9.60%April 18, 2024July 15, 2023
September 20, 2024 (amended September 5, 2025)Natural Gas$37 $22 9.60%December 17, 2025January 1, 2026
ACE - New JerseyNovember 21, 2024Electric$109 $54 9.60%November 21, 2025December 1, 2025

Pending Distribution Base Rate Case Proceedings
Registrant/JurisdictionFiling DateServiceRequested Revenue Requirement IncreaseRequested ROEExpected 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, 2025Electric$45 10.50%Third quarter of 2027
__________
(a)On April 14, 2026, Pepco notified the MDPSC of pursuing a traditional base rate case.
(b)DPL can implement interim rates on July 9, 2026, subject to refund.

52

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

Note 2 — Regulatory Matters
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 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.
On March 20, 2026, ComEd filed its annual revenue balancing reconciliation for 2025. This reconciliation, which is a component of revenue decoupling, reflected a revenue reduction of $128 million. The reconciliation is effective January 1, 2027, subject to regulatory approval.
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 January 20, 2026, the Illinois Attorney General filed an Application for Rehearing of the December 18 order, which focuses solely on NOLCs. On February 5, 2026, the ICC denied the Illinois Attorney General's Application for Rehearing.
PECO Distribution Base Rate Case Proceedings
On December 12, 2024, the PAPUC issued their Opinions and Orders which approved the non-unanimous partial settlements with limited modifications for both the electric and natural gas base rate cases, and denied the Weather Normalization Adjustment requested in the natural gas base rate case.
PECO’s approved annual electric revenue requirement increase of $354 million is partially offset by a one-time credit of $64 million in 2025. In addition, the PAPUC approved the recovery of storm damage costs incurred by PECO in January 2024, up to $23 million, subject to review for reasonableness and prudency in PECO’s next distribution rate case.
BGE Distribution Base Rate Case Proceedings
In February 2023, BGE filed its three-year cumulative multi-year plan for January 1, 2024 through December 31, 2026 to the MDPSC, which was approved in December 2023 and went into effect on January 1, 2024. The MDSPC awarded BGE electric revenue requirement increases of $41 million, $113 million, and $25 million with an approved ROE of 9.50% in 2024, 2025, and 2026, respectively, and natural gas revenue requirement increases of $126 million, $62 million, and $41 million with an approved ROE of 9.45% in 2024, 2025, and 2026, respectively. The requested revenue requirement increases will be used to recover capital investments designed to increase the resilience of the electric and gas distribution systems and support Maryland's climate and regulatory initiatives.
The MDPSC also approved a portion of the requested 2021 and 2022 reconciliation amounts, which were recovered through separate electric and gas riders between March 2024 and February 2025. As such, the reconciliation amounts are not included in the approved revenue increases. The 2021 reconciliation amounts are $13 million and $7 million for electric and gas, respectively, and the 2022 reconciliation amounts are $39 million and $15 million for electric and gas, respectively. In April 2024, BGE filed with the MDPSC its request for recovery of the 2023 reconciliation amounts of $79 million and $73 million for electric and gas, respectively, with supporting testimony and schedules. In December 2025, the MDPSC authorized BGE to recover $31 million and $46 million for electric and gas, respectively, beginning in February 2026 and extending through December 2027, in the reconciliation rider. In addition to the amounts approved in the reconciliation rider, the MDPSC provided for additional regulatory assets related to minor storms of $24 million (to be recovered over 5 years) and the Baltimore City conduit of $4 million (to be reviewed along with a cost-benefit analysis in BGE’s next rate case).
Pepco District of Columbia Distribution Base Rate Case Proceedings
53

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

Note 2 — Regulatory Matters
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 March 27, 2026, the DCPSC issued an order adopting a procedural schedule and requested supplemental briefing on what interim rates should be in effect during the remand period but did not order any refunds for previous amounts collected. 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 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
54

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

Note 2 — Regulatory Matters
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.
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
55

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

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 liability as of March 31, 2026 is $434 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.
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.

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.

The energy efficiency provisions of CRGA are effective June 1, 2026. In advance of the effective date, ComEd has begun undertaking implementation activities, including regulatory filings and planning efforts.
56

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

Note 2 — Regulatory Matters
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.
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 petitions for rehearing or clarification.
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 $155 million primarily due to an increase of $127 million in the Electric energy and natural gas costs regulatory asset.
PECO. Regulatory assets increased $132 million primarily due to an increase of $72 million in the Deferred income taxes regulatory asset. Regulatory liabilities increased $88 million primarily due to an increase of $91 million in the Decommissioning the Regulatory Agreement Units.
BGE. Regulatory assets decreased $102 million primarily due to a decrease of $45 million in the Electric energy and natural gas costs regulatory asset and a decrease of $42 million in the Energy efficiency and demand response programs regulatory asset. Regulatory liabilities decreased $16 million primarily due to a decrease of $31 million in the Deferred income taxes regulatory liability.
Pepco. Regulatory assets decreased $42 million primarily due to a decrease of $27 million in the Energy efficiency and demand response programs regulatory asset.
DPL. Regulatory assets remained consistent primarily due to a decrease of $15 million in the Energy efficiency and demand response programs regulatory asset, partially offset by an increase of $8 million in the Electric energy and natural gas costs regulatory asset and an increase of $4 million in the Transmission formula rate annual reconciliations regulatory asset.
ACE. Regulatory liabilities increased $2 million primarily due to an increase of $13 million in the Electric energy and natural gas costs regulatory liability, partially offset by a decrease of $4 million in the Transmission formula rate annual reconciliations regulatory liability and a decrease of $4 million in the Over-recovered credit loss expense regulatory liability.
57

Combined Notes to Consolidated Financial Statements — (Continued)
(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 March 31, 2026 and December 31, 2025.
Exelon
ComEd(a)
BGE(b)
PHI
Pepco(c)
DPL(d)
ACE(e)
March 31, 2026$79 $10 $39 $30 $14 $— $16 
December 31, 202598 12 47 39 22 1 16 
__________
(a)For the three months ended March 31, 2026 reflects ComEd's unrecognized equity returns earned for ratemaking purposes on its electric distribution rate regulatory asset. 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 months ended March 31, 2026 and 2025. At March 31, 2026 and December 31, 2025, ComEd's, PECO's, and BGE's contract liabilities were immaterial.
58

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

Note 3 — Revenue from Contracts with Customers
Exelon(a)
PHI(a)
Pepco(a)
DPLACE
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 
Exelon(a)
PHI(a)
Pepco(a)
DPLACE
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 
__________
(a)Revenues recognized in the three months ended March 31, 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 March 31, 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.
YearExelonPHIPepcoDPLACE
2026$4 $4 $4 $— $— 
20276 6 5 1 — 
20286 6 5 — 1 
20297 7 6 1 — 
2030 and thereafter95 95 74 10 11 
Total$118 $118 $94 $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.
59

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

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 months ended March 31, 2026 and 2025 is as follows:
ComEdPECOBGEPHI
Other(a)
Intersegment
Eliminations		Exelon
Operating revenues(b):
2026
Electric revenues$1,913 $1,082 $1,245 $1,911 $— $(17)$6,134 
Natural gas revenues— 410 583 116 — (1)1,108 
Shared service and other revenues— — — 3 489 (492)— 
Total operating revenues$1,913 $1,492 $1,828 $2,030 $489 $(510)$7,242 
2025
Electric revenues$2,065 $956 $1,012 $1,687 $— $(11)$5,709 
Natural gas revenues— 377 542 88 — (2)1,005 
Shared service and other revenues— — — 3 466 (469)— 
Total operating revenues$2,065 $1,333 $1,554 $1,778 $466 $(482)$6,714 
Less:
Purchased power
2026$451 $451 $630 $850 $— $— $2,382 
2025689 361 450 684 — — 2,184 
Purchased fuel
2026$— $161 $178 $55 $— $— $394 
2025— 141 159 38 — — 338 
Operating and maintenance
2026$335 $271 $260 $365 $447 $(212)$1,466 
2025323 266 242 296 429 (209)1,347 
Operating and maintenance from affiliates
2026$103 $66 $67 $59 $12 $(307)$— 
2025100 61 63 53 11 (288)— 
Depreciation and amortization
2026$404 $121 $167 $246 $14 $— $952 
2025380 109 164 234 16 — 903 
60

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

Note 4 — Segment Information
Taxes other than income taxes
2026$105 $69 $104 $151 $14 $— $443 
202599 60 96 140 10 — 405 
Loss on sale of assets
2026$— $— $— $— $— $— $— 
2025— — — 1 — — 1 
Interest expense, net(c)
2026$132 $69 $62 $105 $180 $— $548 
2025125 59 58 99 163 — 504 
Interest expense to affiliates, net(c)
2026$3 $2 $— $1 $— $1 $7 
20253 4 — 1 (1)(1)6 
Other, net
2026$(31)$(11)$(17)$(18)$— $8 $(69)
2025(21)(8)(9)(19)(11)16 (52)
Income taxes
2026$101 $15 $79 $47 $(42)$— $200 
202565 14 71 57 (37)— 170 
Net income (loss) attributable to common shareholders
2026$310 $278 $298 $169 $(136)$— $919 
2025302 266 260 194 (114)— 908 
Supplemental segment information
Intersegment revenues(d)
2026$11 $4 $3 $3 $486 $(507)$— 
20258 3 2 2 463 (478)— 
Capital expenditures
2026$885 $469 $437 $558 $9 $— $2,358 
2025590 424 406 513 13 — 1,946 
Total assets
March 31, 2026$48,478 $20,193 $17,171 $29,657 $6,380 $(4,334)$117,545 
December 31, 202548,285 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:
PepcoDPLACE
Other(a)
Intersegment
Eliminations		PHI
Operating revenues(b):
2026
Electric revenues$989 $506 $421 $— $(5)$1,911 
Natural gas revenues— 116 — — — 116 
Shared service and other revenues— — — 110 (107)3 
61

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

Note 4 — Segment Information
Total operating revenues$989 $622 $421 $110 $(112)$2,030 
2025
Electric revenues$859 $460 $373 $— $(5)$1,687 
Natural gas revenues— 88 — — — 88 
Shared service and other revenues— — — 106 (103)3 
Total operating revenues$859 $548 $373 $106 $(108)$1,778 
Less:
Purchased power
2026$411 $234 $205 $— $— $850 
2025318 209 157 — — 684 
Purchased fuel
2026$— $55 $— $— $— $55 
2025— 38 — — — 38 
Operating and maintenance
2026$151 $71 $50 $93 $— $365 
202596 60 51 89 — 296 
Operating and maintenance from affiliates
2026$67 $47 $43 $14 $(112)$59 
202563 46 39 13 (108)53 
Depreciation and amortization
2026$114 $66 $65 $1 $— $246 
2025105 63 64 2 — 234 
Taxes other than income taxes
2026$118 $26 $2 $5 $— $151 
2025113 21 2 4 — 140 
Loss on sale of assets
2026$— $— $— $— $— $— 
20251 — — — — 1 
Interest expense, net(c)
2026$55 $27 $22 $1 $— $105 
202552 25 21 1 — 99 
Interest expense to affiliates, net(c)
2026$— $— $— $1 $— $1 
2025— — — 1 — 1 
Other, net
2026$(11)$(4)$(2)$(1)$— $(18)
2025(11)(4)(3)(1)— (19)
Income taxes
2026$16 $23 $9 $(1)$— $47 
202525 21 11 — — 57 
Net income (loss) attributable to common shareholders
2026$68 $77 $27 $(3)$— $169 
202597 69 31 (3)— 194 
Supplemental segment information
Intersegment revenues(d)
2026$2 $2 $1 $110 $(112)$3 
20252 2 1 106 (109)2 
Capital expenditures
62

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

Note 4 — Segment Information
2026$285 $147 $122 $4 $— $558 
2025240 156 105 12 — 513 
Total assets
March 31, 2026$12,632 $6,798 $5,685 $4,618 $(76)$29,657 
December 31, 202512,728 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.
Three Months Ended March 31, 2026
Revenues from contracts with customersComEdPECOBGEPHIPepcoDPLACE
Electric revenues
Residential$1,024 $725 $818 $1,096 $507 $331 $258 
Small commercial & industrial484 172 130 191 54 69 68 
Large commercial & industrial120 87 180 395 321 30 44 
Public authorities & electric railroads12 8 8 19 10 4 5 
Other(a)
249 77 117 232 93 77 64 
Total electric revenues(b)
$1,889 $1,069 $1,253 $1,933 $985 $511 $439 
Natural gas revenues
Residential$— $286 $401 $74 $— $74 $— 
Small commercial & industrial— 96 63 29 — 29 — 
Large commercial & industrial— — 93 4 — 4 — 
Transportation— 20 — 5 — 5 — 
Other(c)
— 7 31 4 — 4 — 
Total natural gas revenues(d)
$— $409 $588 $116 $— $116 $— 
Total revenues from contracts with customers$1,889 $1,478 $1,841 $2,049 $985 $627 $439 
Other revenues
Revenues from alternative revenue programs$8 $5 $(22)$(23)$1 $(6)$(18)
Other electric revenues(e)
16 8 6 4 3 1 — 
Other natural gas revenues(e)
— 1 3 — — — — 
Total other revenues$24 $14 $(13)$(19)$4 $(5)$(18)
Total revenues for reportable segments$1,913 $1,492 $1,828 $2,030 $989 $622 $421 
63

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

Note 4 — Segment Information
Three Months Ended March 31, 2025
Revenues from contracts with customersComEdPECOBGEPHIPepcoDPLACE
Electric revenues
Residential$993 $631 $648 $918 $424 $298 $196 
Small commercial & industrial600 162 109 169 51 64 54 
Large commercial & industrial296 84 144 367 289 28 50 
Public authorities & electric railroads17 8 8 17 8 4 5 
Other(a)
236 76 113 223 86 71 68 
Total electric revenues(b)
$2,142 $961 $1,022 $1,694 $858 $465 $373 
Natural gas revenues
Residential$— $267 $378 $56 $— $56 $— 
Small commercial & industrial— 86 63 21 — 21 — 
Large commercial & industrial— — 96 3 — 3 — 
Transportation— 13 — 5 — 5 — 
Other(c)
— 10 24 3 — 3 — 
Total natural gas revenues(d)
$— $376 $561 $88 $— $88 $— 
Total revenues from contracts with customers$2,142 $1,337 $1,583 $1,782 $858 $553 $373 
Other revenues
Revenues from alternative revenue programs$(85)$(9)$(29)$(3)$2 $(5)$— 
Other electric revenues(e)
8 4 — (1)(1)— — 
Other natural gas revenues(e)
— 1 — — — — — 
Total other revenues$(77)$(4)$(29)$(4)$1 $(5)$— 
Total revenues for reportable segments$2,065 $1,333 $1,554 $1,778 $859 $548 $373 
__________
(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:
•$11 million, $8 million at ComEd
•$4 million, $2 million at PECO
•$2 million, $1 million at BGE
•$3 million, $2 million at PHI
•$2 million, $2 million at Pepco
•$2 million, $2 million at DPL
•$1 million, $1 million at ACE
(c)Includes revenues from off-system natural gas sales.
(d)Includes operating revenues from affiliates in 2026 and 2025 respectively of:
•less than $1 million, $1 million at PECO
•$1 million, $1 million at BGE
(e)Includes late payment charge revenues.

64

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 March 31, 2026
ExelonComEdPECO
BGE(b)
PHIPepco
DPL(c)
ACE
Balance at December 31, 2025$435 $115 $137 $68 $115 $69 $19 $27 
Plus: Current period provision for expected credit losses
148 32 39 43 34 17 8 9 
Less: Write-offs, net of recoveries(a)
61 17 16 10 18 10 3 5 
Balance at March 31, 2026$522 $130 $160 $101 $131 $76 $24 $31 
Three Months Ended March 31, 2025
ExelonComEdPECOBGEPHIPepcoDPLACE
Balance at December 31, 2024$406 $109 $133 $56 $108 $59 $17 $32 
Plus: Current period provision for expected credit losses
133 33 41 23 36 17 10 9 
Less: Write-offs, net of recoveries
53 17 14 7 15 7 4 4 
Balance at March 31, 2025$486 $125 $160 $72 $129 $69 $23 $37 
_________
(a)Recoveries were not material to the Registrants.
(b)For BGE, the increase in current period provision for expected credit losses when comparing to the three months ended March 31, 2025, is primarily a result of increased receivable balances.
(c)For DPL, the decrease in current period provision for expected credit losses when comparing to the three months ended March 31, 2025, is primarily a result of favorable customer payment behavior.
The following tables present the rollforward of Allowance for Credit Losses on Other Accounts Receivable.
Three Months Ended March 31, 2026
ExelonComEdPECOBGEPHIPepcoDPL
ACE(b)
Balance at December 31, 2025$94 $23 $18 $4 $49 $26 $10 $13 
Plus: Current period provision for expected credit losses
17 8 6 1 2 1 1 — 
Less: Write-offs, net of recoveries(a)
9 4 2 1 2 1 — 1 
Balance at March 31, 2026$102 $27 $22 $4 $49 $26 $11 $12 
Three Months Ended March 31, 2025
ExelonComEdPECOBGEPHIPepcoDPLACE
Balance at December 31, 2024$107 $34 $18 $6 $49 $27 $9 $13 
Plus: Current period provision for expected credit losses
15 2 9 1 3 — — 3 
Less: Write-offs, net of recoveries
9 2 5 1 1 — — 1 
Balance at March 31, 2025$113 $34 $22 $6 $51 $27 $9 $15 
_________
(a)Recoveries were not material to the Registrants.
(b)For ACE, the decrease in current period provision for expected credit losses when comparing to the three months ended March 31, 2025, is primarily a result of decreased aged receivables.

65

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 March 31, 2026 and December 31, 2025.
Unbilled customer revenues(a)
ExelonComEdPECOBGEPHIPepcoDPLACE
March 31, 2026$873 $246 $206 $211 $210 $107 $59 $44 
December 31, 20251,231 301 278 325 327 155 100 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 three months ended March 31, 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
ExelonComEdPECOBGEPHIPepcoDPLACE
Three months ended March 31, 2026$1,310 $304 $411 $188 $407 $262 $76 $69 
Three months ended March 31, 20251,138 253 334 225 326 201 68 57 
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 March 31, 2026(a)(b)
ExelonComEd
PECO(c)
BGE
U.S. Federal statutory rate$235 21.0 %$86 21.0 %$62 21.0 %$79 21.0 %
Increase (decrease) due to:
State income taxes, net of Federal income tax benefit
64 5.7 30 7.3 (3)(1.0)23 6.1 
Tax credits(3)(0.3)(1)(0.2)— — (1)(0.3)
Change in Unrecognized Tax Benefits
(17)(1.5)(2)(0.5)— — (1)(0.3)
Nontaxable or nondeductible items
10 0.9 1 0.1 — — — — 
Other Adjustments
Plant Basis differences(53)(4.7)(5)(1.2)(39)(13.2)(8)(2.1)
Excess deferred tax
(35)(3.1)(8)(1.9)(5)(1.7)(13)(3.4)
Amortization of ITC, net deferred taxes
(1)(0.1)— — — — — — 
Effective Tax Rate
$200 17.9 %$101 24.6 %$15 5.1 %$79 21.0 %
66

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

Note 6 — Income Taxes
Three Months Ended March 31, 2026(a)(b)
PHIPEPCODPLACE
U.S. Federal statutory rate$45 21.0 %$18 21.0 %$21 21.0 %$8 21.0 %
Increase (decrease) due to:
State income taxes, net of Federal income tax benefit
14 6.5 5 6.0 6 6.0 3 8.3 
Tax credits(1)(0.5)— — — — — — 
Change in Unrecognized Tax Benefits
— — — — — — — 
Nontaxable or nondeductible items
— — — — — — — — 
Other Adjustments
Plant Basis differences(2)(0.9)(1)(1.2)(1)(1.0)— — 
Excess deferred tax
(9)(4.3)(6)(6.8)(3)(3.0)(2)(4.3)
Amortization of ITC, net deferred taxes
— — — — — — — — 
Effective Tax Rate
$47 21.8 %$16 19.0 %$23 23.0 %$9 25.0 %

Three Months Ended March 31, 2025(a)(b)
Exelon
ComEd(d)
PECO(c)
BGE
U.S. Federal statutory rate$227 21.0 %$77 21.0 %$59 21.0 %$70 21.0 %
Increase (decrease) due to:
State income taxes, net of Federal income tax benefit
57 5.3 28 7.6 (10)(3.6)21 6.3 
Tax credits(5)(0.5)(2)(0.5)— — (1)(0.3)
Nontaxable or nondeductible items
4 0.5 1 0.2 — — — — 
Other Adjustments
Plant Basis differences(42)(3.9)(4)(1.1)(31)(11.0)(5)(1.5)
Excess deferred tax
(70)(6.5)(35)(9.5)(4)(1.4)(14)(4.0)
Amortization of ITC, net deferred taxes
(1)(0.1)— — — — — — 
Effective Tax Rate
$170 15.8 %$65 17.7 %$14 5.0 %$71 21.5 %

Three Months Ended March 31, 2025(a)(b)
PHIPEPCODPLACE
U.S. Federal statutory rate$53 21.0 %$26 21.0 %$19 21.0 %$9 21.0 %
Increase (decrease) due to:
State income taxes, net of Federal income tax benefit
16 6.4 8 6.6 6 6.7 3 7.1 
Tax credits(1)(0.4)(1)(0.8)— — — — 
Nontaxable or nondeductible items
1 0.5 — — — — — — 
Other Adjustments
Plant Basis differences(2)(0.8)(1)(0.8)(1)(1.1)— 0.5 
Excess deferred tax
(10)(4.0)(7)(5.5)(3)(3.3)(1)(2.4)
Amortization of ITC, net deferred taxes
— — — — — — — — 
Effective Tax Rate
$57 22.7 %$25 20.5 %$21 23.3 %$11 26.2 %

__________
(a)Positive percentages represent income tax expense. Negative 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 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.
67

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

Note 6 — Income Taxes

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:
20262025
ExelonIL, MDIL, MD
ComEdILIL
PECOPAPA
BGEMDMD
PHIMD, NJMD, NJ
PepcoMDMD
DPLDEDE
ACENJNJ

Unrecognized Tax Benefits
Exelon, PHI and DPL have the following unrecognized tax benefits at March 31, 2026 and December 31, 2025. ComEd's, PECO's, BGE's, Pepco's, and ACE's amounts are not material.
Exelon(a)
PHIDPL
March 31, 2026$85 $50 $14 
December 31, 2025100 48 12 
__________
(a)At March 31, 2026 and December 31, 2025, Exelon's unrecognized tax benefits is inclusive of $20 million related to Constellation's share of unrecognized tax benefits for periods prior to the separation. Exelon reflected an offsetting receivable of $20 million in Other deferred debits and other assets in the Consolidated Balance Sheet for these amounts.
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 March 31, 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 March 31, 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 2026, Exelon received $235 million of payments from Constellation as reimbursement for a reduction in previously utilized pre-separation tax credit carryforwards due to amended federal tax returns filed in Q1 2026. At March 31, 2026, Exelon recorded a payable of $58 million and $373 million in Other current liabilities and Other deferred credits
68

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

Note 6 — Income Taxes
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 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 months ended March 31, 2026 and 2025.
69

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

Note 7 — Retirement Benefits

Pension BenefitsOPEB
Three Months Ended March 31,Three Months Ended March 31,
2026202520262025
Components of net periodic benefit cost
Service cost$40 $38 $7 $6 
Interest cost143 146 25 25 
Expected return on assets(176)(178)(22)(21)
Amortization of:
Prior service cost (credit)1 1 (2)(2)
Actuarial loss50 53 — — 
Net periodic benefit cost$58 $60 $8 $8 
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.
 Three Months Ended March 31,
Pension and OPEB Costs20262025
Exelon$65 $68 
ComEd27 21 
PECO4 2 
BGE7 16 
PHI20 25 
Pepco7 8 
DPL4 4 
ACE2 3 
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 months ended March 31, 2026 and 2025.
Three Months Ended March 31,
Savings Plan Employer Contributions20262025
Exelon$32 $26 
ComEd11 10 
PECO4 4 
BGE3 3 
PHI5 5 
Pepco1 1 
DPL1 1 
ACE1 1 
70

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

Note 8 — Derivative Financial Instruments
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 regulatory-approved recovery mechanisms. The following table provides a summary of the Utility Registrants’ primary derivative hedging instruments, listed by commodity and accounting treatment.
RegistrantCommodityAccounting TreatmentHedging Instrument
ComEdElectricityNPNSFixed price contracts based on all requirements in the IPA procurement plans.
Electricity
Changes in fair value of economic hedge recorded to an offsetting regulatory asset or liability(a)
20-year floating-to-fixed energy swap contracts beginning June 2012 based on the renewable energy resource procurement requirements in the Illinois Settlement Legislation of approximately 1.3 million MWhs per year.
PECOElectricityNPNSFixed price contracts for default supply requirements through full requirements contracts.
GasNPNS
Fixed price contracts to cover about 10% of planned natural gas purchases in support of projected firm sales.
BGEElectricityNPNSFixed price contracts for all SOS requirements through full requirements contracts.
GasNPNSFixed price purchases associated with forecasted gas supply requirements.
PepcoElectricityNPNSFixed price contracts for all SOS requirements through full requirements contracts.
DPLElectricityNPNSFixed price contracts for all SOS requirements through full requirements contracts.
GasNPNSFixed and index priced contracts through full requirements contracts.
Gas
Changes in fair value of economic hedge recorded to an offsetting regulatory asset or liability(b)
Exchange traded future contracts for up to 50% of estimated monthly purchase requirements each month, including purchases for storage injections.
ACEElectricityNPNSFixed price contracts for all BGS requirements through full requirements contracts.
__________
(a)See Note 2 — Regulatory Matters of the 2025 Form 10-K for additional information.
71

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

Note 8 — Derivative Financial Instruments
(b)The fair value of the DPL economic hedge is not material at March 31, 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 March 31, 2026 would result in an immaterial impact to Exelon's Consolidated Net income.
Below is a summary of the interest rate hedge balances at March 31, 2026 and December 31, 2025.
Derivatives Designated
as Hedging Instruments
March 31, 2026December 31, 2025
Other current assets$— $3 
Other deferred debits (noncurrent assets)2 — 
Total derivative assets2 3 
Mark-to-market derivative liabilities (current liabilities)— (4)
Mark-to-market derivative liabilities (noncurrent liabilities)(1)— 
Total mark-to-market derivative liabilities(1)(4)
Total mark-to-market derivative net assets (liabilities)$1 $(1)
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 months ended March 31, 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 first 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 March 31, 2026 and December 31, 2025.
March 31, 2026December 31, 2025
5-year maturity floating-to-fixed swaps$60 $335 
10-year maturity floating-to-fixed swaps120 365 
Total$180 $700 
The related AOCI derivative gain for the three months ended March 31, 2026 was $1 million (net of tax). The related AOCI derivative loss for the three months ended March 31, 2025 was $9 million (net of tax). 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
72

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

Note 8 — Derivative Financial Instruments
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 March 31, 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 March 31, 2026 and December 31, 2025:
March 31, 2026December 31, 2025
Exelon$217 $223 
ComEd192 192 
PECO6 6 
BGE8 4 
PHI11 21 
Pepco1 13 
DPL10 3 
ACE(a)
— 5 
__________
(a)ACE had less than one million in cash collateral with external parties at March 31, 2026.
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 March 31, 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 March 31, 2026, they could have been required to post collateral to their counterparties of $38 million, $20 million, and $23 million, respectively.
9. Debt and Credit Agreements (All Registrants)
Short-Term Borrowings
Exelon Corporate, ComEd, and BGE meet their short-term liquidity requirements primarily through the issuance of commercial paper. PECO meets its short-term liquidity requirements primarily through the issuance of commercial paper and borrowings from the Exelon intercompany money pool. Pepco, DPL, and ACE meet their short-term liquidity requirements primarily through the issuance of commercial paper and borrowings from the PHI intercompany money pool. PHI Corporate meets its short-term liquidity requirements primarily through the issuance of short-term notes and borrowings from the Exelon intercompany money pool. The Registrants may use their respective credit facilities for general corporate purposes, including meeting short-term funding requirements and the issuance of letters of credit.
Commercial Paper
The following table reflects the Registrants' commercial paper programs supported by the revolving credit agreements at March 31, 2026 and December 31, 2025.
Outstanding Commercial
Paper at		Average Interest Rate on
Commercial Paper Borrowings at
Commercial Paper IssuerMarch 31, 2026December 31, 2025March 31, 2026December 31, 2025
Exelon(a)
$165 $612 3.94 %3.94 %
ComEd$46 $— 3.93 %— %
PECO$— $— — %— %
BGE$— $— — %— %
PHI(b)
$119 $612 3.95 %3.94 %
Pepco$73 $303 3.94 %3.93 %
DPL$46 $161 3.96 %3.94 %
ACE$— $148 — %3.94 %
73

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

Note 9 — Debt and Credit Agreements
__________
(a)Exelon Corporate had no outstanding commercial paper borrowings at March 31, 2026 and no outstanding commercial paper borrowings at December 31, 2025.
(b)Represents the consolidated amounts of Pepco, DPL, and ACE.
Revolving Credit Agreements
On August 29, 2024, Exelon Corporate and each of the Utility Registrants amended and restated their respective syndicated revolving credit facility, extending the maturity date to August 29, 2029. The following table reflects the credit agreements:
BorrowerAggregate Bank CommitmentInterest Rate
Exelon Corporate$900 
SOFR plus 1.075%
ComEd$1,000 
SOFR plus 1.000%
PECO$600 
SOFR plus 0.900%
BGE$600 
SOFR plus 0.900%
Pepco$300 
SOFR plus 1.000%
DPL$300 
SOFR plus 1.000%
ACE$300 
SOFR plus 1.000%
Exelon Corporate and the Utility Registrants had no outstanding amounts on the revolving credit facilities as of March 31, 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 14, 2024, Exelon Corporate amended and bifurcated the $500 million term loan agreement into two tranches of $350 million and $150 million. The loan agreements were renewed in the first quarter of 2025, extending the expiration date to March 13, 2026. Exelon Corporate repaid the term loans on December 5, 2025.
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.
Long-Term Debt
Issuance of Long-Term Debt
74

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

Note 9 — Debt and Credit Agreements
During the three months ended March 31, 2026, the following long-term debt was issued:
CompanyTypeInterest RateMaturityAmountUse of Proceeds
ExelonSenior Notes4.95%March 15, 2036$775Repay existing indebtedness and for general corporate purposes.
PepcoFirst Mortgage Bonds5.00%March 19, 2036110Repay existing indebtedness and for general corporate purposes.
PepcoFirst Mortgage Bonds5.30%March 19, 204160Repay existing indebtedness and for general corporate purposes.
DPLFirst Mortgage Bonds5.74%March 19, 205675Repay existing indebtedness and for general corporate purposes.
ACEFirst Mortgage Bonds4.95%March 19, 2036100Repay existing indebtedness and for general corporate purposes.
Convertible Senior Notes
On December 4, 2025, Exelon Corporation issued $1 billion aggregate principal amount of 3.25% Convertible Senior Notes due 2029 (Convertible Senior Notes). The Convertible Senior Notes are reflected as Long-term debt on Exelon’s Consolidated Balance Sheet.

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

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

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

Exelon will settle conversions of the Convertible Senior Notes by paying cash up to the aggregate principal amount to be converted and paying or delivering, as the case may be, cash, shares of common stock, or a combination of cash and shares of common stock, at Exelon’s discretion, in respect of the remainder, if any, of Exelon's conversion obligation in excess of the aggregate principal amount of the Convertible Senior Notes being converted. The Convertible Senior Notes are initially convertible at 17.5093 shares per $1,000 principal amount, which is equivalent to an initial conversion price of approximately 57.11 per share of common stock. The initial conversion price of the Convertible Senior Notes represents a premium of approximately 25% over the last reported sale price of Exelon’s common stock on the Nasdaq Global Select Market on December 1, 2025. These conversions will be subject to adjustment upon the occurrence of certain specified events but will not be adjusted for accrued and unpaid interest. In addition, upon the occurrence of a make-whole fundamental change (as defined in the indenture) Exelon will, in certain circumstances, increase the applicable conversion rate by a number of additional shares of common stock for conversions in connection with the make-whole fundamental change.

As of March 31, 2026, no shares of the Convertible Senior Notes have been converted.
75

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

Note 9 — Debt and Credit Agreements
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 period ended March 31, 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 March 31, 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 March 31, 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.
76

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

Note 10 — Fair Value of Financial Assets and Liabilities
Fair Value of Financial Liabilities Recorded at Amortized Cost
The following tables present the carrying amounts and fair values of the Registrants’ short-term liabilities, long-term debt, and trust preferred securities (long-term debt to financing trusts or junior subordinated debentures) as of March 31, 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.
March 31, 2026December 31, 2025
Carrying AmountFair ValueCarrying AmountFair Value
Level 1Level 2Level 3TotalLevel 1Level 2Level 3Total
Long-Term Debt, including amounts due within one year(a)
Exelon (b)
$50,185 $— $40,580 $4,558 $45,138 $49,078 $— $40,637 $4,318 $44,955 
ComEd12,755 — 11,019 — 11,019 12,753 — 11,291 — 11,291 
PECO6,397 — 5,471 — 5,471 6,396 — 5,593 — 5,593 
BGE6,042 — 5,390 — 5,390 6,041 — 5,510 — 5,510 
PHI9,928 — 4,151 4,558 8,709 9,590 — 4,236 4,318 8,554 
Pepco4,802 — 2,484 1,990 4,474 4,632 — 2,546 1,861 4,407 
DPL2,421 — 644 1,446 2,090 2,344 — 657 1,410 2,067 
ACE2,133 — 812 1,123 1,935 2,033 — 819 1,047 1,866 
Long-Term Debt to Financing Trusts
Exelon$390 $— $— $398 $398 $390 $— $— $403 $403 
ComEd206 — — 212 212 206 — — 216 216 
PECO184 — — 186 186 184 — — 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 March 31, 2026, respectively.

77

Combined Notes to Consolidated Financial Statements — (Continued)
(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 March 31, 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 March 31, 2026At December 31, 2025
Level 1Level 2Level 3TotalLevel 1 Level 2Level 3Total
Assets
Cash equivalents(a)
$945 $— $— $945 $825 $— $— $825 
Rabbi trust investments
Cash equivalents103 — — 103 101 — — 101 
Mutual funds72 — — 72 71 — — 71 
Fixed income— 6 — 6 — 6 — 6 
Life insurance contracts — 80 21 101 — 79 21 100 
Rabbi trust investments subtotal175 86 21 282 172 85 21 278 
Interest rate derivative assets
Derivatives designated as hedging instruments— 2 — 2 — 3 — 3 
Interest rate derivative assets subtotal— 2 — 2 — 3 — 3 
Total assets1,120 88 21 1,229 997 88 21 1,106 
Liabilities
Commodity derivative liabilities— — (133)(133)— — (131)(131)
Interest rate derivative liabilities
Derivatives designated as hedging instruments— (1)— (1)— (4)— (4)
Interest rate derivative liabilities subtotal — (1)— (1)— (4)— (4)
Deferred compensation obligation— (68)— (68)— (71)— (71)
Total liabilities— (69)(133)(202)— (75)(131)(206)
Total net assets (liabilities)$1,120 $19 $(112)$1,027 $997 $13 $(110)$900 
__________    
(a)Exelon excludes cash of $157 million and $180 million at March 31, 2026 and December 31, 2025, respectively, and restricted cash of $195 million and $196 million at March 31, 2026 and December 31, 2025, respectively, and includes long-term restricted cash of $24 million and $50 million at March 31, 2026 and December 31, 2025, respectively, which is reported in Other deferred debits and other assets in the Consolidated Balance Sheets.

78

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

Note 10 — Fair Value of Financial Assets and Liabilities
ComEd, PECO, and BGE
ComEdPECOBGE
At March 31, 2026Level 1Level 2Level 3TotalLevel 1Level 2Level 3TotalLevel 1Level 2Level 3Total
Assets
Cash equivalents(a)
$343 $— $— $343 $125 $— $— $125 $172 $— $— $172 
Rabbi trust investments
Mutual funds— — — — 13 — — 13 11 — — 11 
Life insurance contracts — — — — — 25 — 25 — — — — 
Rabbi trust investments subtotal— — — — 13 25 — 38 11 — — 11 
Total assets343 — — 343 138 25 — 163 183 — — 183 
Liabilities
Commodity derivative liabilities(b)
— — (133)(133)— — — — — — — — 
Deferred compensation obligation— (9)— (9)— (8)— (8)— (4)— (4)
Total liabilities— (9)(133)(142)— (8)— (8)— (4)— (4)
Total net assets (liabilities)$343 $(9)$(133)$201 $138 $17 $— $155 $183 $(4)$— $179 
ComEdPECOBGE
At December 31, 2025Level 1Level 2Level 3TotalLevel 1Level 2Level 3TotalLevel 1Level 2Level 3Total
Assets
Cash equivalents(a)
$393 $— $— $393 $93 $— $— $93 $205 $— $— $205 
Rabbi trust investments
Mutual funds— — — — 13 — — 13 10 — — 10 
Life insurance contracts — — — — — 25 — 25 — — — — 
Rabbi trust investments subtotal— — — — 13 25 — 38 10 — — 10 
Total assets393 — — 393 106 25 — 131 215 — — 215 
Liabilities
Commodity derivative liabilities(b)
— — (131)(131)— — — — — — — — 
Deferred compensation obligation— (9)— (9)— (8)— (8)— (4)— (4)
Total liabilities— (9)(131)(140)— (8)— (8)— (4)— (4)
Total net assets (liabilities)$393 $(9)$(131)$253 $106 $17 $— $123 $215 $(4)$— $211 
__________
(a)ComEd excludes cash of $69 million and $77 million at March 31, 2026 and December 31, 2025, respectively, and restricted cash of $194 million and $193 million at March 31, 2026 and December 31, 2025, respectively. Additionally, ComEd includes long-term restricted cash of $24 million and $50 million at March 31, 2026 and December 31, 2025, respectively, which is reported in Other deferred debits and other assets in the Consolidated Balance Sheets. PECO
79

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

Note 10 — Fair Value of Financial Assets and Liabilities
excludes cash of $26 million and $23 million at March 31, 2026 and December 31, 2025, respectively. BGE excludes cash of $8 million and $15 million at March 31, 2026 and December 31, 2025, respectively.
(b)The Level 3 balance consists of the current and noncurrent liability of $22 million and $111 million, respectively, at March 31, 2026 and $25 million and $106 million, respectively, at December 31, 2025 related to floating-to-fixed energy swap contracts with unaffiliated suppliers.

80

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

Note 10 — Fair Value of Financial Assets and Liabilities
PHI, Pepco, DPL, and ACE
At March 31, 2026At December 31, 2025
PHI Level 1Level 2Level 3TotalLevel 1Level 2Level 3Total
Assets
Cash equivalents(a)
$35 $— $— $35 $83 $— $— $83 
Rabbi trust investments
Cash equivalents101 — — 101 99 — — 99 
Mutual funds9 — — 9 9 — — 9 
Fixed income— 6 — 6 — 6 — 6 
Life insurance contracts— 23 20 43 — 23 20 43 
Rabbi trust investments subtotal110 29 20 159 108 29 20 157 
Total assets145 29 20 194 191 29 20 240 
Liabilities
Deferred compensation obligation— (9)— (9)— (9)— (9)
Total liabilities— (9)— (9)— (9)— (9)
Total net assets$145 $20 $20 $185 $191 $20 $20 $231 
PepcoDPLACE
At March 31, 2026Level 1Level 2Level 3TotalLevel 1Level 2Level 3TotalLevel 1Level 2Level 3Total
Assets
Cash equivalents(a)
$20 $— $— $20 $10 $— $— $10 $5 $— $— $5 
Rabbi trust investments
Cash equivalents100 — — 100 — — — — — — — — 
Life insurance contracts— 23 20 43 — — — — — — — — 
Rabbi trust investments subtotal100 23 20 143 — — — — — — — — 
Total assets120 23 20 163 10 — — 10 5 — — 5 
Liabilities
Deferred compensation obligation— (1)— (1)— — — — — — — — 
Total liabilities— (1)— (1)— — — — — — — — 
Total net assets$120 $22 $20 $162 $10 $— $— $10 $5 $— $— $5 
81

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

Note 10 — Fair Value of Financial Assets and Liabilities
PepcoDPLACE
At December 31, 2025Level 1Level 2Level 3TotalLevel 1Level 2Level 3TotalLevel 1Level 2Level 3Total
Assets
Cash equivalents(a)
$33 $— $— $33 $3 $— $— $3 $— $— $— $— 
Rabbi trust investments
Cash equivalents98 — — 98 — — — — — — — — 
Life insurance contracts— 23 20 43 — — — — — — — — 
Rabbi trust investments subtotal98 23 20 141 — — — — — — — — 
Total assets131 23 20 174 3 — — 3 — — — — 
Liabilities
Deferred compensation obligation— (1)— (1)— — — — — — — — 
Total liabilities— (1)— (1)— — — — — — — — 
Total net assets$131 $22 $20 $173 $3 $— $— $3 $— $— $— $— 
__________
(a)PHI excludes cash of $44 million and $56 million at March 31, 2026 and December 31, 2025, respectively, and restricted cash of $1 million and $2 million at March 31, 2026 and December 31, 2025. Pepco excludes cash of $20 million and $22 million at March 31, 2026 and December 31, 2025, respectively. DPL excludes cash of $12 million and $9 million at March 31, 2026 and December 31, 2025, respectively. ACE excludes cash of $7 million and $22 million at March 31, 2026 and December 31, 2025, respectively and restricted cash of $1 million and $2 million at March 31, 2026 and December 31, 2025, respectively.

82

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

Note 10 — Fair Value of Financial Assets and Liabilities
Reconciliation of Level 3 Assets and Liabilities
The following tables present the fair value reconciliation of Level 3 assets and liabilities measured at fair value on a recurring basis during the three months ended March 31, 2026 and 2025:
ExelonComEdPHI and Pepco
Three Months Ended March 31, 2026Total 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)
(2)(2)— 
Balance at March 31, 2026(c)
$(112)$(133)$20 
The amount of total gains included in income attributed to the change in unrealized gains related to assets and liabilities at March 31, 2026$— $— $— 
ExelonComEdPHI and Pepco
Three Months Ended March 31, 2025Total Commodity
Derivatives		Life Insurance Contracts
Balance at December 31, 2024$(110)$(132)$21 
Total realized / unrealized gains (losses)
Included in net income(a)
— — — 
Included in regulatory assets/liabilities(b)
(19)(19)— 
Balance at March 31, 2025(c)
$(129)$(151)$21 
The amount of total gains included in income attributed to the change in unrealized gains related to assets and liabilities at March 31, 2025$— $— $— 
__________
(a)Classified in Operating and maintenance expense in the Consolidated Statements of Operations and Comprehensive Income.
(b)For ComEd, this includes $10 million of decreases in fair value and an increase for realized gains due to settlements of $8 million recorded in Purchased power expense associated with floating-to-fixed energy swap contracts with unaffiliated suppliers for the three months ended March 31, 2026. Includes $30 million of decreases 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 March 31, 2025.
(c)For ComEd, the balance of the current and noncurrent asset was zero as of March 31, 2026. The balance consists of a current and noncurrent liability of $22 million and $111 million, respectively, as of March 31, 2026.
Commodity Derivatives (Exelon and ComEd)
The table below discloses the significant unobservable inputs to the forward curve used to value mark-to-market derivatives.
Type of tradeFair Value at March 31, 2026Fair Value at December 31, 2025Valuation
Technique		Unobservable
Input		2026 Range & Arithmetic Average2025 Range & Arithmetic Average
Commodity derivatives$(133)$(131)Discounted
Cash Flow
Forward power price(a)
$26.72-$57.33$40.28$28.45-$62.87$38.62
________
(a)An increase to the forward power price would increase the fair value.

83

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

Note 11 — Commitments and Contingencies
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 March 31, 2026:
DescriptionExelon PHI Pepco DPLACE
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.
84

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

Note 11 — Commitments and Contingencies
Commercial Commitments (All Registrants). The Registrants’ commercial commitments at March 31, 2026, representing commitments potentially triggered by future events were as follows:
Expiration within
Total202620272028202920302031 and beyond
Exelon
Letters of credit(a)
$57 $38 $19 $— $— $— $— 
Surety bonds(b)
465 185 115 165 — — — 
Financing trust guarantees(c)
378 — — 78 — — 300 
Guaranteed lease residual values(d)
23 — 2 6 4 4 7 
Total commercial commitments $923 $223 $136 $249 $4 $4 $307 
ComEd
Letters of credit(a)
$18 $15 $3 $— $— $— $— 
Surety bonds(b)
131 37 94 — — — — 
Financing trust guarantees(c)
200 — — — — — 200 
Total commercial commitments $349 $52 $97 $— $— $— $200 
PECO
Letters of credit(a)
$5 $3 $2 $— $— $— $— 
Surety bonds(b)
10 1 9 — — — — 
Financing trust guarantees(c)
178 — — 78 — — 100 
Total commercial commitments $193 $4 $11 $78 $— $— $100 
BGE
Letters of credit(a)
$27 $16 $11 $— $— $— $— 
Surety bonds(b)
92 2 3 87 — — — 
Total commercial commitments $119 $18 $14 $87 $— $— $— 
PHI
Letters of credit(a)
$4 $2 $2 $— $— $— $— 
Surety bonds(b)
173 90 5 78 — — — 
Guaranteed lease residual values(d)
23 — 2 6 4 4 7 
Total commercial commitments $200 $92 $9 $84 $4 $4 $7 
Pepco
Letters of credit(a)
$2 $2 $— $— $— $— $— 
Surety bonds(b)
161 82 1 78 — — — 
Guaranteed lease residual values(d)
8 — 1 2 1 2 2 
Total commercial commitments $171 $84 $2 $80 $1 $2 $2 
DPL
Letters of credit(a)
$1 $— $1 $— $— $— $— 
Surety bonds(b)
6 3 3 — — — — 
Guaranteed lease residual values(d)
9 — 1 2 2 1 3 
Total commercial commitments $16 $3 $5 $2 $2 $1 $3 
ACE
Letters of credit(a)
$1 $— $1 $— $— $— $— 
Surety bonds(b)
6 5 1 — — — — 
Guaranteed lease residual values(d)
6 — — 2 1 1 2 
Total commercial commitments $13 $5 $2 $2 $1 $1 $2 
85

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

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 $53 million guaranteed by Exelon and PHI, of which $17 million, $20 million, and $16 million is guaranteed by Pepco, DPL, and ACE, respectively. Historically, payments under the guarantees have not been made and PHI believes the likelihood of payments being required under the guarantees is remote.
Environmental Remediation Matters
General (All Registrants). The Registrants’ operations have in the past, and may in the future, require substantial expenditures to comply with environmental laws. Additionally, under federal and state environmental laws, the Registrants are generally liable for the costs of remediating environmental contamination of property now or formerly owned by them and of property contaminated by hazardous substances generated by them. The Registrants own or lease a number of real estate parcels, including parcels on which their operations or the operations of others may have resulted in contamination by substances that are considered hazardous under environmental laws. In addition, the Registrants are currently involved in a number of proceedings relating to sites where hazardous substances have been deposited and may be subject to additional proceedings in the future. Unless otherwise disclosed, the Registrants cannot reasonably estimate whether they will incur significant liabilities for additional investigation and remediation costs at these or additional sites identified by the Registrants, environmental agencies, or others, or whether such costs will be recoverable from third parties, including customers. Additional costs could have a material, unfavorable impact on the Registrants' financial statements.
MGP Sites (All Registrants). ComEd, PECO, BGE, and DPL have identified sites where former MGP or gas purification activities have or may have resulted in actual site contamination. For some sites, there are additional PRPs that may share responsibility for the ultimate remediation of each location.
•ComEd has 16 sites currently under some degree of active study and/or remediation. ComEd expects the majority of the remediation at these sites to continue through at least 2033.
•PECO has 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 2026.
•DPL has 1 site currently under study and the required cost at the site is not expected to be material.
The historical nature of the MGP and gas purification sites, and the fact that many of the sites have been buried and built over, impacts the ability to determine a precise estimate of the ultimate costs prior to initial sampling and determination of the exact scope and method of remedial activity. Management determines its best estimate of remediation costs using all available information at the time of each study, including probabilistic and deterministic modeling for ComEd and PECO, and the remediation standards currently required by the applicable state environmental agency. Prior to performing any significant clean up, each site remediation plan is approved by the appropriate state environmental agency.
ComEd, pursuant to an ICC order, and PECO, pursuant to a PAPUC order, are currently recovering environmental remediation costs of former MGP facility sites through customer rates. While BGE and DPL do not have riders for MGP clean-up costs, they have historically received recovery of actual clean-up costs in distribution rates.
86

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

Note 11 — Commitments and Contingencies
At March 31, 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:
March 31, 2026December 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$381 $318 $386 $321 
ComEd289 288 289 289 
PECO22 20 23 22 
BGE13 10 13 10 
PHI57 — 57 — 
Pepco55 — 55 — 
DPL1 — 1 — 
ACE1 — 1 — 
Benning Road Site (Exelon, PHI, and Pepco). In September 2010, PHI received a letter from the EPA identifying the Benning Road site as one of six land-based sites potentially contributing to contamination of the lower Anacostia River. A portion of the site, which is owned by Pepco, was formerly the location of an electric generating facility owned by Pepco subsidiary, Pepco Energy Services (PES), which became a part of Constellation following the 2016 merger between PHI and Exelon. This generating facility was deactivated in June 2012. The remaining portion of the site consists of a Pepco transmission and distribution service center that remains in operation. In December 2011, the U.S. District Court for the District of Columbia approved a Consent Decree entered into by Pepco and Pepco Energy Services (hereinafter "Pepco Entities") with the DOEE, which requires the Pepco Entities to conduct a Remedial Investigation and Feasibility Study (RI/FS) for the Benning Road site and an approximately 10 to 15-acre portion of the adjacent Anacostia River. The purpose of this RI/FS is to define the nature and extent of contamination from the Benning Road site and to evaluate remedial alternatives.
Pursuant to an internal agreement between the Pepco Entities, since 2013, Pepco has performed the work required by the Consent Decree and has been reimbursed for that work by an agreed upon allocation of costs between the Pepco Entities. In September 2019, the Pepco Entities issued a draft “final” RI report which the DOEE approved on February 3, 2020. In October 2022, the DOEE approved dividing the work to complete the landside portion of the FS from the waterside portion to expedite the overall schedule for completion of the project. The landside FS was approved by the DOEE on March 15th, 2024, and the waterside FS was approved by the DOEE on December 16, 2024. The DOEE and Pepco entered into an addendum to the Benning Consent Decree pursuant to which Pepco has agreed to fund or perform the remedial actions to be selected by the DOEE for the landside and waterside areas. This addendum to the Benning Consent Decree was entered by the Court on February 27, 2024 and became effective on that date. Pepco drafted separate proposed plans for the landside and waterside areas, which were approved and issued by the DOEE for public comment on December 16, 2024 and September 4, 2025, respectively. The public comment period for the landside and waterside areas closed on April 18, 2025 and October 31, 2025, respectively. Pepco submitted a matrix of proposed responses to the public comments and a proposed Record of Decision (ROD) to the DOEE for the landside area on August 15, 2025. Following the close of the waterside area comment period, Pepco will submit a matrix of proposed responses to the public comments and a proposed ROD to the DOEE for the waterside area. The DOEE will issue RODs identifying the remedial actions determined to be necessary for the landside and waterside areas, which will be implemented by Pepco in accordance with the Benning Consent Decree.
As part of the separation between Exelon and Constellation in February 2022, the internal agreement between the Pepco Entities for completion and payment for the remaining Consent Decree work was memorialized in a formal agreement for post-separation activities. A second post-separation assumption agreement between Exelon and Constellation transferred any of the potential remaining remediation liability, if any, of PES/Constellation to a non-utility subsidiary of Exelon which going forward will be responsible for those liabilities. 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.
87

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

Note 11 — Commitments and Contingencies
Anacostia River Tidal Reach (Exelon, PHI, and Pepco). Contemporaneous with the Benning Road site RI/FS being performed by the Pepco Entities, the DOEE and NPS have been conducting a separate RI/FS focused on the entire tidal reach of the Anacostia River extending from just north of the Maryland-District of Columbia boundary line to the confluence of the Anacostia and Potomac Rivers. The riverwide RI incorporated the results of the river sampling performed by the Pepco Entities as part of the Benning RI/FS, as well as similar sampling efforts conducted by owners of other sites adjacent to this segment of the river and supplemental river sampling conducted by the DOEE’s contractor.
On September 30, 2020, the DOEE released its Interim ROD for the Anacostia River sediments. The Interim ROD reflects an adaptive management approach which will require several identified “hot spots” in the river to be addressed first while continuing to conduct studies and to monitor the river to evaluate improvements and determine potential future remediation plans. The adaptive management process chosen by the DOEE is less intrusive, provides more long-term environmental certainty, is less costly, and allows for site specific remediation plans already underway, including the plan for the Benning Road site to proceed to conclusion.
On July 15, 2022, Pepco received a letter from the District of Columbia's Office of the Attorney General (D.C. OAG) on behalf of the DOEE conveying a settlement offer to resolve all PRPs' liability to the District of Columbia (District) for their past costs and their anticipated future costs to complete the work for the Interim ROD. Pepco responded on July 27, 2022 agreeing to enter into settlement discussions. Pepco and the District entered into another consent decree (the “Anacostia River Consent Decree”) pursuant to which Pepco agreed to pay $47 million to resolve its liability to the District for all past costs to perform the riverwide RI/FS and all future costs to complete the work required by the Interim ROD. This amount was agreed to be paid in four equal annual installments beginning a year after the effective date of the Anacostia River Consent Decree. Pepco paid the first installment of $12 million on April 9, 2025, 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.
88

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

Note 11 — Commitments and Contingencies
Buzzard Point Site (Exelon, PHI, and Pepco). On December 8, 2022, Pepco received a letter from the D.C. OAG, alleging wholly past violations of the District's stormwater discharge and waste disposal requirements related to operations at the Buzzard Point facility, a 9-acre parcel of waterfront property in Washington, D.C. occupied by an active substation and former steam plant building. The letter also alleged wholly past violations by Pepco of stormwater discharge requirements related to its district-wide system of underground vaults. Pepco entered into a Consent Order with the District of Columbia to resolve the alleged violations without any admission of liability. The Consent Order requires Pepco to pay a civil penalty of $10 million. In addition, Pepco has agreed to assess the environmental conditions at its Buzzard Point facility and conduct any remedial actions deemed necessary as a result of the assessment, and also to assess potential environmental impacts associated with the operation of its underground vaults. The Superior Court for the District of Columbia signed and entered the Consent Order, and it became effective on February 2, 2024. Pepco is proceeding through the multi-step environmental investigation and response as outlined in the consent order. Specifically, the DOEE approved Pepco's Preliminary Site Assessment in July 2025. In September 2025, Pepco timely submitted its work plan for the second stage, the Supplemental Investigation Plan, 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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Combined Notes to Consolidated Financial Statements — (Continued)
(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 and use tax on the purchase of most goods and services. BGE, Pepco, and DPL have filed or plan to file protective refund claims, totaling an estimated $100 million, treating electric transmission and distribution machinery and equipment as nontaxable pursuant to the manufacturing exemption available under the Maryland sales and use tax law. The Maryland Comptroller has initially denied the refund claim and litigation is pending.
On November 22, 2024, the Appellate Court of Maryland, in a case involving a regulated electric utility operating in Maryland, ruled the purchase of certain transmission and distribution equipment qualify for the sales tax manufacturing exemption. On December 20, 2024, the Maryland Attorney General, on behalf of the Maryland Comptroller, filed a motion for reconsideration with the Appellate Court of Maryland of its ruling. The motion for reconsideration was denied on February 3, 2025.
On February 18, 2025, the Maryland Attorney General, on behalf of the Maryland Comptroller, filed a petition with the Maryland Supreme Court requesting review of the Appellate Court of Maryland’s ruling. On April 24, 2025, the Maryland Supreme Court granted the petition to review the ruling. On October 1, 2025, the Maryland Supreme Court heard oral arguments in the case.
In the event transmission and distribution equipment is determined to be exempt, Exelon, BGE, PHI, Pepco, and DPL will record estimated receivables of $100 million, $65 million, $35 million, $25 million, and $10 million, respectively. The sales tax payments were primarily capitalized; therefore, the refund would be recorded as a reduction to PP&E included in rate base.
General (All Registrants). The Registrants are involved in various other litigation matters that are being defended and handled in the ordinary course of business. The Registrants are also from time to time subject to audits and investigations by the FERC and other regulators. The assessment of whether a loss is probable or reasonably possible, and whether the loss or a range of loss is estimable, often involves a series of complex judgments about future events. The Registrants maintain accruals for such losses that are probable of being incurred and subject to reasonable estimation. Management is sometimes unable to estimate an amount or range of reasonably possible loss, particularly where (1) the damages sought are indeterminate, (2) the proceedings are in the early stages, or (3) the matters involve novel or unsettled legal theories. In such cases, there is considerable uncertainty regarding the timing or ultimate resolution of such matters, including a possible eventual loss.
12. Shareholders' Equity (Exelon)
At-the-Market 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.
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
90

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

Note 12 — Shareholders' Equity
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 PeriodShares Available
(in millions)		Weighted-Average Net PriceMaturity Date
Q1 20265.4$47.67 July 30, 2027
Q1 20266.4$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 PeriodShares Available
(in millions)		Weighted-Average Net PriceMaturity Date
Q2 20253.6$43.17 November 16, 2026
Q3 202511.5$43.73 December 15, 2026
Q4 20250.8$45.42 December 15, 2026
No amounts have been or will be recorded on Exelon's balance sheet with respect to the equity offerings until the equity forward sale agreements have been settled. Each initial forward sale price is subject to adjustment on a daily basis based on a floating interest rate factor and will decrease by other fixed amounts specified in the agreements. Until settlement of the equity forward, earnings per share dilution resulting from the agreement, if any, will be determined under the treasury stock method. For the three months ended March 31, 2026, approximately 26.5 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 March 31, 2026.
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 March 31, 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(3)4 1 
Amounts reclassified from AOCI(2)7 5 
Net current-period OCI(5)11 6 
Balance at March 31, 2026$28 $(784)$(756)
Three Months Ended March 31, 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(6)5 (1)
Amounts reclassified from AOCI(2)5 3 
Net current-period OCI(8)10 2 
Balance at March 31, 2025$37 $(755)$(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 March 31,
20262025
Pension and non-pension postretirement benefit plans:
Actuarial losses reclassified to periodic benefit cost$(2)$(2)
Pension and non-pension postretirement benefit plans valuation adjustments(1)(2)
Unrealized gains on cash flow hedges1 3 
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
ExelonComEdPECOBGEPHIPepcoDPLACE
Three Months Ended March 31, 2026
Utility taxes(a)
$275 $86 $57 $36 $96 $86 $9 $1 
Property125 10 5 63 47 31 15 1 
Payroll34 8 5 4 8 2 1 1 
Three Months Ended March 31, 2025
Utility taxes(a)
$258 $81 $50 $34 $93 $84 $8 $1 
Property111 9 5 57 40 28 12 — 
Payroll33 8 5 5 7 1 1 1 
_________
(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.
Other, net
ExelonComEdPECOBGE PHIPepcoDPLACE
Three Months Ended March 31, 2026
AFUDC — Equity$57 $21 $10 $15 $11 $9 $1 $1 
Non-service net periodic benefit cost(10)— — — — — — — 
Three Months Ended March 31, 2025
AFUDC — Equity$39 $12 $7 $9 $11 $8 $2 $1 
Non-service net periodic benefit cost(13)— — — — — — — 
Supplemental Cash Flow Information
The following tables provide additional information about material items recorded in the Registrants' Consolidated Statements of Cash Flows.
92

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

Note 14 — Supplemental Financial Information
Depreciation, amortization, and accretion
ExelonComEdPECOBGEPHIPepcoDPLACE
Three Months Ended March 31, 2026
Property, plant, and equipment(a)
$794 $317 $120 $132 $211 $94 $59 `$57 
Amortization of regulatory assets and liabilities, net(a)
158 87 1 35 35 20 7 8 
Amortization of intangible assets, net(a)
— — — — — — — — 
ARO accretion(b)
1 — — — — — — — 
Total depreciation, amortization, and accretion$953 $404 $121 $167 $246 $114 $66 $65 
Three Months Ended March 31, 2025
Property, plant, and equipment(a)
$750 $302 $108 $124 $201 $88 $57 $55 
Amortization of regulatory assets and liabilities, net(a)
152 78 1 40 33 17 6 9 
Amortization of intangible assets, net(a)
2 — — — — — — — 
ARO accretion(b)
1 — — — — — — — 
Total depreciation, amortization, and accretion$905 $380 $109 $164 $234 $105 $63 $64 
__________
(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.
Other non-cash operating activities
ExelonComEdPECOBGEPHIPepcoDPLACE
Three Months Ended March 31, 2026
Pension and OPEB costs$65 $27 $4 $7 $20 $7 $4 $2 
Allowance for credit losses109 17 43 26 23 11 7 5 
True-up adjustments to decoupling mechanisms and formula rates(a)
40 (8)(5)22 31 (1)6 26 
Amortization of operating ROU asset6 — — 2 3 1 1 1 
AFUDC — Equity(57)(21)(10)(15)(11)(9)(1)(1)
Three Months Ended March 31, 2025
Pension and OPEB costs$68 $21 $2 $16 $25 $8 $4 $3 
Allowance for credit losses97 11 43 14 29 10 9 10 
True-up adjustments to decoupling mechanisms and formula rates(a)
136 85 9 29 13 (2)5 10 
Amortization of operating ROU asset9 — — 2 6 1 2 2 
AFUDC — Equity(39)(12)(7)(9)(11)(8)(2)(1)
__________
(a)For ComEd, reflects the true-up adjustments in Regulatory assets and liabilities associated with its distribution MRP and distribution, energy efficiency, distributed generation, and transmission formula rates. For PECO, reflects the change in Regulatory assets and liabilities associated with its transmission formula rates. For BGE, Pepco, DPL, and ACE, reflects the change in Regulatory assets and liabilities associated with their decoupling mechanisms and transmission formula rates. See Note 2 — Regulatory Matters of the 2025 Form 10-K for additional information.
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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
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.
Cash, cash equivalents, and restricted cash
ExelonComEdPECOBGEPHIPepcoDPLACE
Balance at March 31, 2026
Cash and cash equivalents$713 $95 $151 $173 $49 $20 $12 $12 
Restricted cash and cash equivalents560 487 — 7 31 20 10 1 
Restricted cash included in Other deferred debits and other assets24 24 — — — — — — 
Total cash, restricted cash, and cash equivalents$1,297 $606 $151 $180 $80 $40 $22 $13 
Balance at December 31, 2025
Cash and cash equivalents$626 $159 $116 $217 $103 $22 $9 $22 
Restricted cash and cash equivalents525 454 — 3 38 33 3 2 
Restricted cash included in Other deferred debits and other assets50 50 — — — — — — 
Total cash, restricted cash, and cash equivalents$1,201 $663 $116 $220 $141 $55 $12 $24 
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.
Accrued expenses
ExelonComEdPECOBGEPHIPepcoDPLACE
Balance at March 31, 2026
Compensation-related accruals(a)
$395 $130 $55 $52 $66 $20 $14 $10 
Taxes accrued249 118 20 105 96 71 21 10 
Interest accrued466 105 55 91 85 37 28 19 
Balance at December 31, 2025
Compensation-related accruals(a)
$705 $209 $96 $99 $125 $35 $24 $17 
Taxes accrued242 94 306 191 107 69 25 18 
Interest accrued538 155 75 55 92 49 18 20 
__________
(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.
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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

The following table presents the service company costs allocated to the Registrants:
Operating and maintenance from affiliatesCapitalized costs
Three Months Ended March 31,Three Months Ended March 31,
2026202520262025
Exelon
   BSC$134 $160 
   PHISCO25 25 
ComEd
   BSC$103 $100 61 62 
PECO
   BSC65 59 21 27 
BGE
   BSC66 63 21 33 
PHI
   BSC58 52 30 39 
   PHISCO— — 25 25 
Pepco
   BSC35 32 13 17 
   PHISCO32 31 10 10 
DPL
   BSC22 20 9 12 
   PHISCO24 25 7 8 
ACE
   BSC17 16 7 8 
   PHISCO26 23 7 7 
95

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

Note 15 — Related Party Transactions

Current Receivables from/Payables to Affiliates
The following tables present current Receivables from affiliates and current Payables to affiliates:
March 31, 2026
Receivables from affiliates:
Payables to affiliates:ComEdPECOBGEPepcoDPLACEBSCPHISCOOtherTotal
ComEd$— $— $— $— $— $70 $— $2 $72 
PECO$— — — — — 36 — 5 41 
BGE— — — — — 31 — 1 32 
PHI(a)
— — — — — — 2 — 5 7 
Pepco— — — — — 15 16 1 32 
DPL— — — — — 10 14 1 25 
ACE3 — — — — 6 10 1 20 
Other4 2 1 1 2 12 (1)— 21 
Total$7 $2 $1 $1 $2 $12 $169 $40 $16 $250 
December 31, 2025
Receivables from affiliates:
Payables to affiliates:ComEdPECOBGEPepcoDPLACEBSCPHISCOOtherTotal
ComEd$— $— $— $— $— $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 
Other5 — 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:
March 31, 2026December 31, 2025
ExelonComEdPECOExelonComEdPECO
ComEd Financing III$206 $206 $— $206 $206 $— 
PECO Trust III81 — 81 81 — 81 
PECO Trust IV103 — 103 103 — 103 
Total$390 $206 $184 $390 $206 $184 
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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 months ended March 31, 2026 compared to the same period in 2025. For additional information regarding the financial results for the three months ended March 31, 2026 and 2025, see the discussions of Results of Operations by Registrant.
Three Months Ended March 31,Favorable (Unfavorable) Variance
20262025
Exelon$919 $908 $11 
ComEd310 302 8 
PECO278 266 12 
BGE298 260 38 
PHI169 194 (25)
Pepco68 97 (29)
DPL77 69 8 
ACE27 31 (4)
Other(a)
(136)(114)(22)
__________
(a)Other primarily includes eliminating and consolidating adjustments, Exelon’s corporate operations, shared service entities, and other financing and investment activities.

Three Months Ended March 31, 2026 Compared to Three Months Ended March 31, 2025. Net income attributable to common shareholders increased by $11 million and diluted earnings per average common share remained relatively consistent to the prior year at $0.90 primarily due to:
•Favorable impacts of approved rate increases at ComEd, BGE and PHI;
•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;
97


•Higher depreciation expense at PECO and PHI;
•Higher interest expense at PECO and Exelon Corporate;
•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.
The following table provides a reconciliation between GAAP Net income attributable to common shareholders and Adjusted (non-GAAP) operating earnings for the three months ended March 31, 2026 compared to the same period in 2025:
Three Months Ended March 31,
20262025
(In millions, except per share data)Earnings per
Diluted Share		Earnings per
Diluted Share
Net income attributable to common shareholders$919 $0.90 $908 $0.90 
Change in FERC audit liability (net of taxes of $1)
— — 2 — 
Cost management charge (net of taxes of $0)(a)
— — (1)— 
Regulatory matters (net of taxes of $4 and $7, respectively)(b)
11 0.01 22 0.02 
Adjusted (non-GAAP) operating earnings$930 $0.91 $932 $0.92 
__________
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 and reorganization costs related to cost management.
(b)Represents the disallowance of certain capitalized costs.
Significant 2026 Transactions and Developments
Distribution Base Rate Case Proceedings
The Utility Registrants file base rate cases with their regulatory commissions seeking increases or decreases to their electric transmission and distribution, and gas distribution rates to recover their costs and earn a fair return on their investments. The outcomes of these regulatory proceedings impact the Utility Registrants’ current and future financial statements.
The following tables show the Utility Registrants’ completed and pending distribution base rate case proceedings in 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/JurisdictionFiling DateServiceRequested Revenue Requirement IncreaseApproved Revenue Requirement IncreaseApproved ROEApproval DateRate Effective Date
ComEd - IllinoisJanuary 17, 2023Electric$1,487 $1,045 8.905%December 19, 2024January 1, 2024
April 26, 2024 (amended on September 11, 2024)Electric$624 $623 9.89%October 31, 2024January 1, 2025
PECO - PennsylvaniaMarch 28, 2024Electric$464 $354 N/ADecember 12, 2024January 1, 2025
Natural Gas$111 $78 
BGE - MarylandFebruary 17, 2023Electric$313 $179 9.50%December 14, 2023January 1, 2024
Natural Gas$289 $229 9.45%
Pepco - District of ColumbiaApril 13, 2023 (amended February 27, 2024)Electric$186 $123 9.50%November 26, 2024January 1, 2025
Pepco - MarylandMay 16, 2023 (amended February 23, 2024)Electric$111 $45 9.50%June 10, 2024April 1, 2024
DPL - MarylandMay 19, 2022Electric$38 $29 9.60%December 14, 2022January 1, 2023
DPL - DelawareDecember 15, 2022 (amended September 29, 2023)Electric$39 $28 9.60%April 18, 2024July 15, 2023
September 20, 2024 (amended September 5, 2025)Natural Gas$37 $22 9.60%December 17, 2025January 1, 2026
ACE - New JerseyNovember 21, 2024Electric$109 $54 9.60%November 21, 2025December 1, 2025
Pending Distribution Base Rate Case Proceedings
Registrant/JurisdictionFiling DateServiceRequested Revenue Requirement IncreaseRequested ROEExpected Approval Timing
Pepco - MarylandOctober 14, 2025 (amended April 16, 2026)Electric$120 10.50%Third quarter of 2026
DPL - DelawareDecember 9, 2025Electric$45 10.50%Third quarter of 2027

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.
99



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.
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.
Allocation of Income Taxes to Regulated Utilities (All Registrants)
In Q2 2024, the IRS issued a series of PLRs, to another taxpayer, providing guidance with respect to the application of the tax normalization rules to the allocation of consolidated tax benefits among the members of a consolidated group associated with NOLC for ratemaking purposes. The rulings provide that for ratemaking purposes the tax benefit of NOLC should be reflected on a separate company basis not taking into consideration the utilization of losses by other affiliates. A PLR issued to another taxpayer may not be relied on as precedent.
For the Utility Registrants, except for PECO, the methodology prescribed by the IRS in these PLRs could result in a material reduction of the regulatory liability established for EDITs arising from the TCJA corporate tax rate change that are being amortized and flowed through to customers as well as a reduction in the accumulated deferred income taxes included in rate base for ratemaking purposes of approximately $1.2 billion - $1.7 billion.
The Utility Registrants, except for PECO, filed PLR requests with the IRS confirming the treatment of the NOLC for ratemaking purposes. The Utility Registrants will record the impact, if any, upon receiving the PLR from the IRS.
100


Legislative and Regulatory Developments

Maryland Utility Relief Act
On April 13, 2026, the Maryland Utility RELIEF Act (Utility RELIEF Act) was passed through the Maryland General Assembly and awaits the Governor’s signature to become law. If and when the Utility RELIEF Act becomes law, it will modify the regulatory framework and rules governing recovery of certain costs in utility ratemaking in Maryland. Exelon, BGE, Pepco, and DPL are in the process of assessing the potential impacts of the pending legislation.
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 petitions for rehearing or clarification.
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.
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 March 31, 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.
101


Results of Operations by Registrant
Results of Operations — ComEd
Three Months Ended
March 31,		(Unfavorable) Favorable Variance
20262025
Operating revenues$1,913 $2,065 $(152)
Operating expenses
Purchased power451 689 238 
Operating and maintenance438 423 (15)
Depreciation and amortization404 380 (24)
Taxes other than income taxes105 99 (6)
Total operating expenses1,398 1,591 193 
Operating income515 474 41 
Other income and (deductions)
Interest expense, net(135)(128)(7)
Other, net31 21 10 
Total other income and (deductions)(104)(107)3 
Income before income taxes411 367 44 
Income taxes 101 65 (36)
Net income $310 $302 $8 
Three Months Ended March 31, 2026 Compared to Three Months Ended March 31, 2025. Net Income increased by $8 million as compared to the same period in 2025 primarily due to higher distribution and transmission rate base driven by incremental investments to serve customers and higher AFUDC, offset by the timing of distribution earnings.
The changes in Operating revenues consisted of the following:
Three Months Ended
March 31, 2026
(Decrease) Increase
Distribution$(8)
Transmission20 
Energy efficiency8 
Other3 
23 
Regulatory required programs (175)
Total decrease$(152)
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 decreased for the three months ended March 31, 2026 as compared to the same period in 2025, primarily due to lower fully recoverable costs.
Transmission Revenue. Under a FERC-approved formula, transmission revenue varies from year to year based upon fluctuations in the underlying costs, capital investments being recovered, and the highest daily peak load, which is updated annually in January based on the prior calendar year. Transmission revenues increased
102


ComEd
for the three months ended March 31, 2026 compared to the same period in 2025, primarily due to higher fully recoverable costs and higher rate base.
Energy Efficiency Revenue. Energy efficiency revenues are under a performance-based formula rate, which requires an annual reconciliation of the revenue requirement in effect to the actual costs the ICC determines are prudently and reasonably incurred in a given year. Energy efficiency revenue varies from year to year based upon fluctuations in the underlying costs, investments being recovered, and allowed ROE. Energy efficiency revenues increased for the three months ended March 31, 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 increased for the three months ended March 31, 2026 as compared to the same periods in 2025, which primarily reflects increased 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 decrease of $238 million for the three months ended March 31, 2026 compared to the same period 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
March 31, 2026
Increase (Decrease)
Labor, other benefits, contracting, and materials$21 
Storm-related costs12 
BSC costs3 
Pension and non-pension postretirement benefits expense2 
Other(a)
(20)
18 
Regulatory required programs(3)
Total increase$15 
__________
(a)Primarily reflects the probable disallowance of certain capitalized costs in regulatory matters during the three months ended March 31, 2025.

103


ComEd
The changes in Depreciation and amortization expense consisted of the following:
Three Months Ended
March 31, 2026
Increase
Depreciation and amortization(a)
$15 
Regulatory asset amortization9 
Total increase$24 
__________
(a)Reflects ongoing capital expenditures.
Other, net increased $10 million for the three months ended March 31, 2026 compared to the same period in 2025, primarily due to higher AFUDC equity.
Effective income tax rates were 24.6% and 17.7% for the three months ended March 31, 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.
104


PECO
Results of Operations — PECO
Three Months Ended
March 31,		Favorable (Unfavorable) Variance
20262025
Operating revenues$1,492 $1,333 $159 
Operating expenses
Purchased power and fuel612 502 (110)
Operating and maintenance337 327 (10)
Depreciation and amortization121 109 (12)
Taxes other than income taxes69 60 (9)
Total operating expenses1,139 998 (141)
Operating income353 335 18 
Other income and (deductions)
Interest expense, net(71)(63)(8)
Other, net11 8 3 
Total other income and (deductions)(60)(55)(5)
Income before income taxes293 280 13 
Income taxes15 14 (1)
Net income$278 $266 $12 
Three Months Ended March 31, 2026 Compared to Three Months Ended March 31, 2025. Net income increased by $12 million due to an increase in revenue as a result of the absence of surcharge credits to customers, favorable weather relative to the same period last year, and tax repairs, some of which is timing, partially offset by an increase in depreciation and interest expense.
The changes in Operating revenues consisted of the following:
Three Months Ended
March 31, 2026
Increase (Decrease)
ElectricGasTotal
Weather$8 $8 $16 
Volume(4)1 (3)
Pricing5 2 7 
Transmission12 — 12 
Other(a)
25 4 29 
46 15 61 
Regulatory required programs79 19 98 
Total increase$125 $34 $159 
__________
(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 months ended March 31, 2026, compared to the same period in 2025, Operating revenues related to weather increased due to favorable weather conditions in PECO's service territory.
Heating and cooling degree-days are quantitative indices that reflect the demand for energy needed to heat or cool a home or business. Normal weather is determined based on historical average heating and cooling degree-days for a 30-year period in PECO's service territory. The changes in heating and cooling degree-days in
105


PECO
PECO’s service territory for the three months ended March 31, 2026, compared to the same period in 2025, and normal weather consisted of the following:
Three Months Ended March 31,% Change
PECO Service Territory20262025Normal2026 vs. 20252026 vs. Normal
Heating Degree-Days2,399 2,3512,3592.0 %1.7 %
Cooling Degree-Days10 11900.0 %900.0 %
Volume. Electric volume, exclusive of the effects of weather, for the three months ended March 31, 2026 compared to the same period in 2025, remained relatively consistent. Natural gas volume for the three months ended March 31, 2026, compared to the same period in 2025, remained relatively consistent.
Electric Retail Deliveries to Customers (in GWhs)Three Months Ended March 31,% Change
Weather -
Normal
% Change(b)
20262025
Residential3,9523,8592.4 %0.1 %
Small commercial & industrial2,0101,9463.3 %1.0 %
Large commercial & industrial3,1323,425(8.6)%(10.0)%
Public authorities & electric railroads176189(6.9)%(7.0)%
Total electric retail deliveries(a)
9,2709,419(1.6)%(3.5)%

At March 31,
Number of Electric Customers20262025
Residential1,544,8811,540,453
Small commercial & industrial154,634155,131
Large commercial & industrial3,1493,151
Public authorities & electric railroads10,10810,703
Total1,712,7721,709,438
__________
(a)Reflects delivery volumes from customers purchasing electricity directly from PECO and customers purchasing electricity from a competitive electric generation supplier as all customers are assessed distribution charges.
(b)Reflects the change in delivery volumes assuming normalized weather based on the historical 30-year average.

Natural Gas Deliveries to Customers (in mmcf)Three Months Ended
March 31,		% Change
Weather -
Normal
% Change(b)
20262025
Residential22,43621,8342.8 %(0.9)%
Small commercial & industrial11,35110,4059.1 %6.2 %
Large commercial & industrial(10)12(183.3)%(20.0)%
Transportation7,1427,242(1.4)%(2.2)%
Total natural gas deliveries(a)
40,91939,4933.6 %0.7 %

 At March 31,
Number of Natural Gas Customers20262025
Residential511,085509,773
Small commercial & industrial44,64244,869
Large commercial & industrial77
Transportation606623
Total556,340555,272
106


PECO
__________
(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 months ended March 31, 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 months ended March 31, 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 months ended March 31, 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 $110 million for the three months ended March 31, 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.
The changes in Operating and maintenance expense consisted of the following:
Three Months Ended
March 31, 2026
Increase (Decrease)
Labor, other benefits, contracting and materials$17 
BSC costs6 
Pension and non-pension postretirement benefit expense1 
Credit loss expense(2)
Storm-related costs(6)
Other13 
29 
Regulatory required programs(19)
Total increase$10 

107


PECO
The changes in Depreciation and amortization expense consisted of the following:
Three Months Ended
March 31, 2026
Increase
Depreciation and amortization(a)
$12 
Total increase$12 
__________
(a)Depreciation and amortization expense increased primarily due to ongoing capital expenditures.
Effective income tax rates were 5.1% and 5.0% for the three months ended March 31, 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.
108


BGE

Results of Operations — BGE
Three Months Ended
March 31,		Favorable (Unfavorable) Variance
20262025
Operating revenues$1,828 $1,554 $274 
Operating expenses
Purchased power and fuel 808 609 (199)
Operating and maintenance327 305 (22)
Depreciation and amortization167 164 (3)
Taxes other than income taxes104 96 (8)
Total operating expenses1,406 1,174 (232)
Operating income422 380 42 
Other income and (deductions)
Interest expense, net(62)(58)(4)
Other, net17 9 8 
Total other income and (deductions)(45)(49)4 
Income before income taxes377 331 46 
Income taxes79 71 (8)
Net income$298 $260 $38 
Three Months Ended March 31, 2026 Compared to Three Months Ended March 31, 2025. Net income increased $38 million primarily due to approved distribution rates and a decrease in various operating expenses, partially offset by an increase in credit loss expense.
The changes in Operating revenues consisted of the following:
Three Months Ended
March 31, 2026
Increase (Decrease)
ElectricGasTotal
Distribution$4 $22 $26 
Transmission(2)— (2)
Other9 2 11 
11 24 35 
Regulatory required programs223 16 239 
Total increase$234 $40 $274 
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.
 At March 31,
Number of Electric Customers20262025
Residential1,226,941 1,220,769 
Small commercial & industrial115,253 115,359 
Large commercial & industrial13,372 13,302 
Public authorities & electric railroads251 258 
Total1,355,817 1,349,688 

109


BGE

At March 31,
Number of Natural Gas Customers20262025
Residential663,324 661,195 
Small commercial & industrial37,735 37,945 
Large commercial & industrial6,421 6,380 
Total707,480 705,520 
Distribution Revenue increased for the three months ended March 31, 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 months ended March 31, 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 months ended March 31, 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 $199 million for the three months ended March 31, 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.

The changes in Operating and maintenance expense consisted of the following:
Three Months Ended
March 31, 2026
 Increase (Decrease)
Credit loss expense$11 
BSC costs3 
Pension and non-pension postretirement benefits expense(5)
Labor, other benefits, contracting and materials(16)
Other1 
(6)
Regulatory required programs(a)
28 
Total increase$22 
__________
(a)Reflects the cost recovery associated with EmPOWER Maryland. Please refer to 2025 10-K Note 2 — Regulatory Matters for additional information.
110


BGE

The changes in Depreciation and amortization expense consisted of the following:
Three Months Ended
March 31, 2026
Increase (Decrease)
Depreciation and amortization$9 
Regulatory required programs(a)
3 
Regulatory asset amortization(9)
Total increase$3 
__________
(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 $8 million for the three months ended March 31, 2026, compared to the same period in 2025, primarily due to increased property taxes.
Effective income tax rates were 21.0% and 21.5% for the three months ended March 31, 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.
111


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 months ended March 31, 2026 compared to the same period in 2025. See the Results of Operations for Pepco, DPL, and ACE for additional information.
Three Months Ended March 31,(Unfavorable) Favorable Variance
20262025
PHI$169 $194 $(25)
Pepco68 97 (29)
DPL
77 69 8 
ACE27 31 (4)
Other(a)
(3)(3)— 
__________
(a)Primarily includes eliminating and consolidating adjustments, PHI's corporate operations, shared service entities, and other financing and investing activities.
Three Months Ended March 31, 2026 Compared to Three Months Ended March 31, 2025. Net Income decreased by $25 million primarily due to unfavorable impacts of the Pepco Maryland multi-year plan reconciliation and related disallowance of capitalized costs, an increase in depreciation expense, storm costs, and interest expense, partially offset by approved transmission rates, favorable weather conditions at DPL and approved Delaware electric DSIC and natural gas rates.
112


Pepco

Results of Operations — Pepco
Three Months Ended March 31,Favorable (Unfavorable) Variance
20262025
Operating revenues$989 $859 $130 
Operating expenses
Purchased power 411 318 (93)
Operating and maintenance218 159 (59)
Depreciation and amortization114 105 (9)
Taxes other than income taxes118 113 (5)
Total operating expenses861 695 (166)
Loss on sale of assets— (1)1 
Operating income 128 163 (35)
Other income and (deductions)
Interest expense, net(55)(52)(3)
Other, net11 11 — 
Total other income and (deductions)(44)(41)(3)
Income before income taxes84 122 (38)
Income taxes16 25 9 
Net income$68 $97 $(29)
Three Months Ended March 31, 2026 Compared to Three Months Ended March 31, 2025. Net Income decreased by $29 million primarily due to unfavorable impacts of the Pepco Maryland multi-year plan reconciliation and related disallowance of capitalized costs, and increases in depreciation and interest expense.
The changes in Operating revenues consisted of the following:
Three Months Ended
March 31, 2026
Increase
Distribution$2 
Transmission3 
Other6 
11 
Regulatory required programs119 
Total increase$130 
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.
At March 31,
Number of Electric Customers in Maryland20262025
Residential560,946 557,672 
Small commercial & industrial30,637 30,555 
Large commercial & industrial19,058 18,986 
Public authorities & electric railroads181 177 
Total610,822 607,390 
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Pepco

Distribution Revenue increased for the three months ended March 31, 2026 compared to the same period 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 months ended March 31, 2026, compared to the same period 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.
See Note 4 — Segment Information of the Combined Notes to Consolidated Financial Statements for the presentation of Pepco's revenue disaggregation.
The increase of $93 million for the three months ended March 31, 2026, respectively, compared to the same period 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
March 31, 2026
Increase (Decrease)
Maryland multi-year plan reconciliation(a)
$26 
Labor, other benefits, contracting, and materials9
BSC and PHISCO costs5
Storm-related costs1 
Other(3)
38 
Regulatory required programs(b)
21 
Total increase$59 
_________
(a)Reflects unfavorable impacts of the Pepco Maryland multi-year plan reconciliation. See Note 2 — Regulatory Matters for additional information.
(b)Reflects the cost recovery associated with EmPOWER Maryland. Please refer to 2025 10-K Note 2 — Regulatory Matters for additional information.

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Pepco

The changes in Depreciation and amortization expense consisted of the following:
Three Months Ended
March 31, 2026
Increase
Depreciation and amortization(a)
$6 
Regulatory asset amortization1 
Regulatory required programs(b)
2 
Total increase$9 
__________
(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.
Effective income tax rates were 19.0% and 20.5% for the three months ended March 31, 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 March 31,Favorable (Unfavorable) Variance
20262025
Operating revenues$622 $548 $74 
Operating expenses
Purchased power and fuel 289 247 (42)
Operating and maintenance118 106 (12)
Depreciation and amortization66 63 (3)
Taxes other than income taxes26 21 (5)
Total operating expenses499 437 (62)
Operating income123 111 12 
Other income and (deductions)
Interest expense, net(27)(25)(2)
Other, net4 4 — 
Total other income and (deductions)(23)(21)(2)
Income before income taxes100 90 10 
Income taxes23 21 (2)
Net income $77 $69 $8 
Three Months Ended March 31, 2026 Compared to Three Months Ended March 31, 2025. Net income increased by $8 million primarily due to approved Delaware electric DSIC and natural gas rates, favorable weather conditions at Delaware electric and natural gas service territories, partially offset by an increase in storm costs.
The changes in Operating revenues consisted of the following:
Three Months Ended
March 31, 2026
Increase (Decrease)
ElectricGasTotal
Weather$3 $2 $5 
Volume1 (1)— 
Distribution6 10 16 
Transmission2 — 2 
Other— — — 
12 11 23 
Regulatory required programs33 18 51 
Total increase$45 $29 $74 
Revenue Decoupling. The demand for electricity is affected by weather and customer usage. However, Operating revenues from electric distribution in Maryland are not impacted by abnormal weather or usage per customer as a result of a BSA that provides for a fixed distribution charge per customer by customer class. While Operating revenues from electric distribution customers in Maryland are not intended to be impacted by abnormal weather or usage per customer, they are impacted by changes in the number of customers.
Weather. The demand for electricity and natural gas in Delaware is affected by weather conditions. With respect to the electric business, very warm weather in summer months and, with respect to the electric and natural gas businesses, very cold weather in winter months are referred to as "favorable weather conditions” because these weather conditions result in increased deliveries of electricity and natural gas. Conversely, mild weather reduces demand. During the three months ended March 31, 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.
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DPL

Heating and cooling degree days are quantitative indices that reflect the demand for energy needed to heat or cool a home or business. Normal weather is determined based on historical average heating and cooling degree days for a 20-year period in DPL's Delaware electric service territory and a 30-year period in DPL's Delaware natural gas service territory. The changes in heating and cooling degree days in DPL's Delaware service territory for the three months ended March 31, 2026, compared to same period in 2025 and normal weather consisted of the following:
Three Months Ended March 31,% Change
Delaware Electric Service Territory20262025Normal2026 vs. 20252026 vs. Normal
Heating Degree-Days2,531 2,399 2,406 5.5 %5.2 %
Cooling Degree-Days9 9 1 — %800.0 %
Three Months Ended March 31,% Change
Delaware Natural Gas Service Territory20262025Normal2026 vs. 20252026 vs. Normal
Heating Degree-Days2,531 2,399 2,449 5.5 %3.3 %
Volume, exclusive of the effects of weather, remained relatively consistent for the three months ended March 31, 2026 compared to the same period in 2025.
Electric Retail Deliveries to Delaware Customers (in GWhs)Three Months Ended
March 31,		% Change
Weather - Normal
% Change(b)
20262025
Residential974 930 4.7 %1.1 %
Small commercial & industrial367 354 3.7 %1.8 %
Large commercial & industrial687 690 (0.4)%(1.0)%
Public authorities & electric railroads7 7 — %(2.8)%
Total electric retail deliveries(a)
2,035 1,981 2.7 %0.5 %
At March 31,
Number of Total Electric Customers (Maryland and Delaware)20262025
Residential496,074 491,907 
Small commercial & industrial65,604 64,999 
Large commercial & industrial1,288 1,251 
Public authorities & electric railroads628 617 
Total563,594 558,774 
__________
(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
March 31,		% Change
Weather - Normal
% Change(b)
20262025
Residential4,678 4,590 1.9 %(2.3)%
Small commercial & industrial2,128 1,970 8.0 %3.0 %
Large commercial & industrial429 428 0.2 %0.2 %
Transportation2,027 2,106 (3.8)%(6.1)%
Total natural gas deliveries(a)
9,262 9,094 1.8 %(1.9)%
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DPL

At March 31,
Number of Delaware Natural Gas Customers20262025
Residential132,419 131,716 
Small commercial & industrial10,285 10,254 
Large commercial & industrial14 15 
Transportation159 161 
Total142,877 142,146 
__________
(a)Reflects delivery volumes from customers purchasing natural gas directly from DPL and customers purchasing natural gas from a competitive natural gas supplier as all customers are assessed distribution charges.
(b)Reflects the change in delivery volumes assuming normalized weather based on the historical 30-year average.
Distribution Revenue increased for the three months ended March 31, 2026 compared to the same period in 2025 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 months ended March 31, 2026 compared to the same period in 2025, transmission revenue remained relatively consistent.
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.
See Note 4 — Segment Information of the Combined Notes to Consolidated Financial Statements for the presentation of DPL's revenue disaggregation.
The increase of $42 million for the three months ended March 31, 2026, respectively, 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.
The changes in Operating and maintenance expense consisted of the following:
Three Months Ended
March 31, 2026
Increase (Decrease)
Storm-related costs$5 
Labor, other benefits, contracting, and materials2 
Credit loss expense(2)
5 
Regulatory required programs(a)
7 
Total increase$12 
__________
(a)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.
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DPL

The changes in Depreciation and amortization expense consisted of the following:
Three Months Ended
March 31, 2026
Increase
Depreciation and amortization(a)
$2 
Regulatory asset amortization— 
Regulatory required programs(b)
1 
Total increase$3 
__________
(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 $5 million for the three months ended March 31, 2026, respectively, compared to the same period in 2025 primarily due to an increase in property taxes.
Effective income tax rates were 23.0% and 23.3% for the three months ended March 31, 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 March 31,Favorable (Unfavorable) Variance
20262025
Operating revenues$421 $373 $48 
Operating expenses
Purchased power 205 157 (48)
Operating and maintenance93 90 (3)
Depreciation and amortization65 64 (1)
Taxes other than income taxes2 2 — 
Total operating expenses365 313 (52)
Operating income 56 60 (4)
Other income and (deductions)
Interest expense, net(22)(21)(1)
Other, net2 3 (1)
Total other income and (deductions)(20)(18)(2)
Income before income taxes36 42 (6)
Income taxes9 11 2 
Net income $27 $31 $(4)

Three Months Ended March 31, 2026 Compared to Three Months Ended March 31, 2025. Net income decreased by $4 million primarily due to an increase in storms costs and depreciation expense, partially offset by an increase in approved transmission rates.
The changes in Operating revenues consisted of the following:
Three Months Ended
March 31, 2026
(Decrease) Increase
Distribution$(1)
Transmission3 
2 
Regulatory required programs46 
Total increase$48 
Revenue Decoupling. The demand for electricity is affected by weather and customer usage. However, Operating revenues from electric distribution in New Jersey are not intended to be impacted by abnormal weather or usage per customer as a result of the CIP which compares current distribution revenues by customer class to approved target revenues established in ACE’s most recent distribution base rate case. The CIP is calculated annually, and recovery is subject to certain conditions, including an earnings test and ceilings on customer rate increases. While Operating revenues are not impacted by abnormal weather or usage per customer, they are impacted by changes in the number of customers.
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ACE

At March 31,
Number of Electric Customers20262025
Residential510,569 508,354 
Small commercial & industrial63,174 62,861 
Large commercial & industrial2,660 2,824 
Public authorities & electric railroads756 723 
Total577,159 574,762 
Distribution Revenue remained relatively consistent for the three months ended March 31, 2026 compared to the same period in 2025.
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 months ended March 31, 2026 compared to the same period 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 $48 million for the three months ended March 31, 2026, respectively, compared to the same period 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
March 31, 2026
(Decrease) Increase
Storm-related costs$4 
Credit Loss Expense(2)
Other(1)
1 
Regulatory required programs2 
Total increase$3 

The changes in Depreciation and amortization expense consisted of the following:
Three Months Ended
March 31, 2026
Increase (Decrease)
Depreciation and amortization(a)
$2 
Regulatory asset amortization4 
Regulatory required programs(5)
Total increase$1 
__________
(a)Depreciation and amortization increased primarily due to ongoing capital expenditures.

Effective income tax rates were 25.0% and 26.2% for the three months ended March 31, 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 three months ended March 31, 2026 and 2025 by Registrant:
Increase (decrease) in cash flows from operating activitiesExelonComEdPECOBGE PHIPepcoDPLACE
Net income (loss)$11 $8 $12 $38 $(25)$(29)$8 $(4)
Adjustments to reconcile net income to cash:
Non-cash operating activities148 (17)288 148 88 57 18 32 
Collateral received, net1 47 (12)3 (37)(22)(2)(11)
Income taxes(203)(43)(294)(147)(70)(43)(16)(24)
Pension and non-pension postretirement benefit contributions(54)(31)(3)(6)(10)— (1)(10)
Regulatory assets and liabilities, net(415)(426)(82)57 23 22 1 (4)
Changes in working capital and other assets and liabilities1,036 847 (23)(8)105 81 22 3 
Increase (decrease) in cash flows from operating activities$524 $385 $(114)$85 $74 $66 $30 $(18)
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 three months ended March 31, 2026 to the three months ended March 31, 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 three months ended March 31, 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 $236 million and a reduction in regulatory assets of $162 million related to carbon mitigation credits for the three months ended March 31, 2026 and 2025, respectively. 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 $84 million for the three months ended March 31, 2026 and 2025, respectively. Additionally, ComEd recognized changes in the distributed generation rebates programs of $29 million and $19 million for the three months ended March 31, 2026 and 2025, respectively. Also included within the changes is energy efficiency and demand response programs spend for DPL and ACE of $1 million and $15 million for the three
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months ended March 31, 2026 and $3 million, and $5 million for the three months ended March 31, 2025, respectively. BGE and Pepco had no energy efficiency and demand response programs spend recorded to the regulatory asset for the three months ended March 31, 2026 and $22 million and $6 million for three months ended March 31, 2025. PECO had no energy efficiency and demand response programs spend recorded to the regulatory asset for the three months ended March 31, 2026 and 2025.
•Changes in working capital and other assets and liabilities for the Utility Registrants and Exelon Corporate totaled $922 million and $1,036 million, respectively. The change in working capital and other noncurrent assets and liabilities for Exelon Corporate and the Utility Registrants is dependent upon the normal course of operations for all Registrants. For ComEd, it is also dependent upon whether the participating nuclear-powered generating facilities are owed money from ComEd as a result of the established pricing for CMCs. For the three months ended March 31, 2026, the established pricing has resulted in ComEd receiving payments from nuclear-powered generating facilities, which is reported within the cash flows from operations as a change in Accounts receivable. This change corresponds to a decrease in the Carbon mitigation credit regulatory liability. See Note 2 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.
Cash Flows from Investing Activities
The following table provides a summary of the change in cash flows from investing activities for the three months ended March 31, 2026 and 2025 by Registrant:
(Decrease) increase in cash flows from investing activitiesExelonComEdPECOBGE PHIPepcoDPLACE
Capital expenditures$(412)$(295)$(45)$(31)$(45)$(45)$9 $(17)
Proceeds from sales of assets— — — — — — — — 
Changes in intercompany money pool— — (5)— — — 12 — 
Other investing activities(2)(1)(3)1 — — — — 
(Decrease) increase in cash flows from investing activities$(414)$(296)$(53)$(30)$(45)$(45)$21 $(17)
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 three months ended March 31, 2026 and 2025 by Registrant:
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(Decrease) increase in cash flows from financing activitiesExelonComEdPECOBGE PHIPepcoDPLACE
Changes in short-term borrowings, net$828 $(265)$192 $(62)$37 $(30)$29 $38 
Long-term debt, net(1,305)— — — (80)(30)(50)— 
Changes in intercompany money pool— — — — 29 — — (12)
Issuance of common stock(173)— — — — — — — 
Dividends paid on common stock(27)(15)— (16)— 2 (4)(5)
Distributions to member— — — — (7)— — — 
Contributions from parent/member— 169 4 — (77)(18)(54)(3)
Other financing activities20 — — — 1 2 — 1 
(Decrease) increase in cash flows from financing activities$(657)$(111)$196 $(78)$(97)$(74)$(79)$19 
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 first quarter of 2025. See Note 12 — Shareholders' Equity of the Combined Notes to Consolidated Financial Statements for additional information.
•Exelon’s ability to pay dividends on its common stock depends on the receipt of dividends paid by its operating subsidiaries. The payments of dividends to Exelon by its subsidiaries in turn depend on their results of operations and cash flows and other items affecting retained earnings. See Note 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 three months ended March 31, 2026, no long-term debt was retired and/or redeemed. Exelon repaid $750 million of its Senior Notes on the maturity date of April 15, 2026.
Dividends
Quarterly dividends declared by the Exelon Board of Directors during the three months ended March 31, 2026 and for the second quarter of 2026 were as follows:

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PeriodDeclaration DateShareholder of Record DateDividend Payable Date
Cash per Share(a)
First Quarter 2026February 12, 2026March 2, 2026March 13, 2026$0.4200 
Second Quarter 2026April 28, 2026June 4, 2026June 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 $3.8 billion was available to support additional commercial paper as of March 31, 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 three months ended March 31, 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.
In the first quarter of 2026, Exelon entered into various forward sale agreements under the 2025 ATM programs. The forward sale agreements require Exelon to, at its election prior to the maturity date, either (i) physically settle the transactions by issuing shares of its Common stock to the forward counterparties in exchange for net proceeds at the then-applicable forward sale price specified by the agreements or (ii) net settle the transactions in whole or in part through the delivery to the forward counterparties or receipt from the forward counterparties of cash or shares in accordance with the provisions of the agreements. The following forward sale agreements were entered into under Exelon’s ATM program in the first quarter of 2026:
Effective PeriodShares Available
(in millions)		Weighted-Average Net PriceMaturity Date
Q1 20265.4$47.67 July 30, 2027
Q1 20266.4$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:
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Effective PeriodShares Available
(in millions)		Weighted-Average Net PriceMaturity Date
Q2 20253.6$43.17 November 16, 2026
Q3 202511.5$43.73 December 15, 2026
Q4 20250.8$45.42 December 15, 2026
No amounts have been or will be recorded on Exelon's balance sheet with respect to the equity offerings until the equity forward sale agreements have been settled. Each initial forward sale price is subject to adjustment on a daily basis based on a floating interest rate factor and will decrease by other fixed amounts specified in the agreements. Until settlement of the equity forward, earnings per share dilution resulting from the agreement, if any, will be determined under the treasury stock method. For the three months ended March 31, 2026, approximately 26.5 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 March 31, 2026.
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 March 31, 2026 and available credit facility capacity prior to any incremental collateral at March 31, 2026:
PJM Credit Policy Collateral
Other Incremental Collateral Required(a)
Available Credit Facility Capacity Prior to Any Incremental Collateral
ComEd$19 $— $936 
PECO4 38 595 
BGE5 20 573 
Pepco— — 225 
DPL— 23 253 
ACE— — 299 
__________
(a)Represents incremental collateral related to natural gas procurement contracts.
Capital Expenditure Spending
As of March 31, 2026, the most recent estimates of capital expenditures for plant additions and improvements for 2026 are as follows:        
(In millions)TransmissionDistributionGas
Total(a)
ExelonN/AN/AN/A$9,900 
ComEd1,100 2,400 N/A3,500 
PECO450 1,325 400 2,175 
BGE1,075 575 525 2,175 
PHI725 1,250 50 2,050 
Pepco325 650 N/A975 
DPL225 325 50 625 
ACE175 275 N/A450 
__________
(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
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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 requirements primarily through the issuance of commercial paper. PECO meets its short-term liquidity requirements primarily through the issuance of commercial paper and borrowings from the Exelon intercompany money pool. Pepco, DPL, and ACE meet their short-term liquidity requirements primarily through the issuance of commercial paper and borrowings from the PHI intercompany money pool. PHI Corporate meets its short-term liquidity requirements primarily through the issuance of short-term notes and the Exelon intercompany money pool. The Registrants may use their respective credit facilities for general corporate purposes, including meeting short-term funding requirements and the issuance of letters of credit.
See Note 9 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information on the Registrants’ credit facilities and short term borrowing activity.
Security Ratings
The Registrants’ access to the capital markets, including the commercial paper market, and their respective financing costs in those markets, may depend on the securities ratings of the entity that is accessing the capital markets.
The Registrants’ borrowings are not subject to default or prepayment as a result of a downgrading of securities, although such a downgrading of a Registrant’s securities could increase fees and interest charges under that Registrant’s credit agreements.
As part of the normal course of business, the Registrants enter into contracts that contain express provisions or otherwise permit the Registrants and their counterparties to demand adequate assurance of future performance when there are reasonable grounds for doing so. In accordance with the contracts and applicable contracts law, if the Registrants are downgraded by a credit rating agency, it is possible that a counterparty would attempt to rely on such a downgrade as a basis for making a demand for adequate assurance of future performance, which could include the posting of collateral. See Note 8 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information on collateral provisions.
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The credit ratings for the Registrants did not change for the three months ended March 31, 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-'. S&P also lowered its short-term and commercial paper rating for BGE from 'A-1' to 'A-2'.
Intercompany Money Pool
To provide an additional short-term borrowing option that will generally be more favorable to the borrowing participants than the cost of external financing, both Exelon and PHI operate an intercompany money pool. Maximum amounts contributed to and borrowed from the money pool by participant and the net contribution or borrowing as of March 31, 2026, are presented in the following table:
During the Three Months Ended March 31, 2026At March 31, 2026
Exelon Intercompany Money PoolMaximum
Contributed		Maximum
Borrowed		Contributed
(Borrowed)
Exelon Corporate$502 $— $373 
PECO343 (63)5 
BSC— (461)(322)
PHI Corporate— (134)(120)
PCI64 — 64 
During the Three Months Ended March 31, 2026At March 31, 2026
PHI Intercompany Money PoolMaximum
Contributed		Maximum
Borrowed
Contributed
(Borrowed)
Pepco$6 $— $— 
DPL— (6)— 
ACE— — — 
Shelf Registration Statements
On February 13, 2025, Exelon and ComEd filed a combined shelf registration statement on Form S-3 registering $12.6 billion in aggregate amount of securities, which was declared effective by the SEC on April 8, 2025. The shelf registration statement may be used to issue Exelon debt and equity securities as well as ComEd debt securities through the expiration date of April 8, 2028. On February 21, 2024, PECO and BGE filed with the SEC a standalone automatically effective shelf registration statement, unlimited in amount, which can be used to issue PECO and BGE debt securities through the expiration date of February 20, 2027. The ability of Exelon, ComEd, PECO and BGE to sell securities off their corresponding registration statements will depend on a number of factors at the time of the proposed sale, including other required regulatory approvals, as applicable, the current financial condition of the Registrant, its securities ratings, and market conditions.
Pepco, DPL, and ACE periodically issue securities through the private placement markets. Pepco, DPL and ACE's ability to access the private placement markets will depend on a number of factors at the time of the proposed sale, including other required regulatory approvals, as applicable, current financial condition, securities ratings and market conditions.
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Regulatory Authorizations
The Utility Registrants are required to obtain short-term and long-term financing authority from Federal and State Commissions as follows:
At March 31, 2026
Short-term Financing AuthorityRemaining Long-term Financing Authority
CommissionExpiration DateAmountCommissionExpiration DateAmount
ComEdFERCDecember 31, 2027$2,500 ICCJanuary 1, 2027, May 1, 2027, & January 1, 2029$4,393 
PECOFERCDecember 31, 20271,500 PAPUCDecember 31, 20271,850 
BGEFERCDecember 31, 2027900 MDPSCN/A1,850 
Pepco(a)
FERCDecember 31, 2027700 MDPSC / DCPSCDecember 31, 2028930 
DPL(a)
FERCDecember 31, 2027700 MDPSC / DEPSCDecember 31, 2028625 
ACENJBPUJanuary 1, 2028350 NJBPUDecember 31, 2026525 
__________

(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.

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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 WithinTotal Fair
Value
Commodity derivative contracts(a):
202620272028202920302031 and Beyond
Prices based on model or other valuation methods (Level 3)$(15)$(22)$(22)$(23)$(21)$(30)$(133)
_________
(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 March 31, 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 first 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 March 31, 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
133

over financial reporting. There have been no other changes in internal control over financial reporting that occurred during the first quarter of 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 March 31, 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 March 31, 2026, except as follows:
On March 13, 2026, Calvin G. Butler, Jr., President and Chief Executive Officer, Exelon Corporation, adopted a Rule 10b5-1 trading arrangement that is intended to satisfy the affirmative defense of Rule 10b5-1(c) for the sale of up to 246,000 shares of Exelon's common stock in multiple transactions, subject to certain price limitations set forth in the trading arrangement. Mr. Butler's 10b5-1 trading arrangement will terminate on December 19, 2026, unless sooner terminated according to 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
Exelon Corporation
Exhibit No.DescriptionLocation
Ninth Supplemental Indenture, dated as of February 1, 2026, among Exelon Corporation and The Bank of New York Mellon Trust Company, N.A., as trustee


134

Table of Contents
Atlantic City Electric Company
Exhibit No.DescriptionLocation
ACE Supplemental Indenture to the Mortgage and Deed of Trust, dated as of March 1, 2026


Delmarva Power & Light Company
Exhibit No.DescriptionLocation
DPL Supplemental Indenture to the Mortgage and Deed of Trust, dated as of March 1, 2026


Potomac Electric Power Company
Exhibit No.DescriptionLocation
Pepco Supplemental Indenture to the Mortgage and Deed of Trust, dated as of March 1, 2026


(10) Material Contracts
Exelon Corporation
Exhibit No.DescriptionLocation
Form of Restricted Stock Unit Award Notice and Agreement under the Non-Employee Directors’ Restricted Stock Unit Program
135

Table of Contents

Certifications Pursuant to Rule 13a-14(a) and 15d-14(a) of the Securities and Exchange Act of 1934 as to the Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2026 filed by the following officers for the following companies:
Exelon Corporation
Exhibit No.Description
Commonwealth Edison Company
Exhibit No.Description
PECO Energy Company
Exhibit No.Description
Baltimore Gas and Electric Company
Exhibit No.Description
Pepco Holdings LLC
Exhibit No.Description
Potomac Electric Power Company
Exhibit No.Description
Delmarva Power & Light Company
Exhibit No.Description
Atlantic City Electric Company
Exhibit No.Description
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 March 31, 2026 filed by the following officers for the following companies:
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Table of Contents
Exelon Corporation
Exhibit No.Description
Commonwealth Edison Company
Exhibit No.Description
PECO Energy Company
Exhibit No.Description
Baltimore Gas and Electric Company
Exhibit No.Description
Pepco Holdings LLC
Exhibit No.Description
Potomac Electric Power Company
Exhibit No.Description
Delmarva Power & Light Company
Exhibit No.Description
Atlantic City Electric Company
Exhibit No.Description
101.INSInline XBRL Instance Document - the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document.
101.SCHInline XBRL Taxonomy Extension Schema Document
101.CALInline XBRL Taxonomy Extension Calculation Linkbase Document
101.DEFInline XBRL Taxonomy Extension Definition Linkbase Document
101.LABInline XBRL Taxonomy Extension Labels Linkbase Document
101.PREInline XBRL Taxonomy Extension Presentation Linkbase Document
104Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101)
137

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)
May 6, 2026
138

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. QuinionesJoshua 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)
May 6, 2026
139

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. InnocenzoMarissa E. Humphrey
Interim President, Chief Executive Officer (Principal Executive Officer), and DirectorSenior Vice President, Chief Financial Officer and Treasurer
(Principal Financial Officer)
/s/    MARIANA HUFFORD
Mariana Hufford
Director, Accounting
(Principal Accounting Officer)
May 6, 2026

140

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. OlivierMichael J. Cloyd
President, Chief Executive Officer
(Principal Executive Officer), and Director		Senior Vice President, Chief Financial Officer and Treasurer
(Principal Financial Officer)
 /s/ DAMON M. SCOLERI
Damon M. Scoleri
Director, Accounting
(Principal Accounting Officer)
May 6, 2026

141

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 AnthonyElizabeth 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)
May 6, 2026

142

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 AnthonyElizabeth 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)
May 6, 2026

143

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 AnthonyElizabeth 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)
May 6, 2026

144

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 AnthonyElizabeth 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)
May 6, 2026
145

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