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Exelon Corporation
EXC
#539
Rank
S$57.53 B
Marketcap
๐Ÿ‡บ๐Ÿ‡ธ United States
Country
S$56.96
Share price
0.83%
Change (1 day)
8.19%
Change (1 year)
๐Ÿ”‹ Electricity
Categories
  1. Exelon Corporation
  2. Quarterly Reports (10-Q)
  3. Submitted on 2025-05-01

Exelon Corporation - 10-Q quarterly report FY


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March 31, 2025March 31, 2025March 31, 2025March 31, 2025March 31, 2025March 31, 2025March 31, 2025March 31, 2025falsefalsefalsefalsefalsefalsefalsefalse20252025202520252025202520252025Q1Q1Q1Q1Q1Q1Q1Q1December 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, 2025
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, 2025 was:
Exelon Corporation Common Stock, without par value1,009,535,664
Commonwealth Edison Company Common Stock, $12.50 par value127,021,418
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
57
4. Segment Information
58
5. Accounts Receivable
64
6. Income Taxes
66
7. Retirement Benefits
68
8. Derivative Financial Instruments
69
9. Debt and Credit Agreements
72
10. Fair Value of Financial Assets and Liabilities
74
11. Commitments and Contingencies
75
12. Shareholders' Equity
81
13. Changes in Accumulated Other Comprehensive Income
82
14. Supplemental Financial Information
82
15. Related Party Transactions
86
2




Page No.
88
Exelon Corporation
88
Executive Overview
88
Financial Results of Operations
88
Significant 2025 Transactions and Developments
89
Other Key Business Drivers and Management Strategies
92
Critical Accounting Policies and Estimates
93
Results of Operations By Registrant
94
Commonwealth Edison Company
94
PECO Energy Company
97
Baltimore Gas and Electric Company
101
Pepco Holdings LLC
104
Potomac Electric Power Company
105
Delmarva Power & Light Company
108
Atlantic City Electric Company
112
Liquidity and Capital Resources
115
123
124
124
124
124
125
125
128
128
129
130
131
132
133
134
135
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
PHI CorporatePHI in its corporate capacity as a holding company
PHISCOPHI Service Company
Former Related Entities
ConstellationConstellation Energy Corporation
GenerationConstellation Energy Generation, LLC (formerly Exelon Generation Company, LLC, a subsidiary of Exelon prior to separation on February 1, 2022)
4



GLOSSARY OF TERMS AND ABBREVIATIONS
Other Terms and Abbreviations
Note - of the 2024 Form 10-K
Reference to specific Combined Note to Consolidated Financial Statements within Exelon's 2024 Annual Report on Form 10-K
ABOAccumulated Benefit Obligation
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
CMCCarbon Mitigation Credit
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
DSIC
Distribution System Improvement Charge
EDITExcess Deferred Income Taxes
EIMAEnergy Infrastructure Modernization Act (Illinois Senate Bill 1652 and Illinois House Bill 3036)
EPAUnited States Environmental Protection Agency
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
mmcfMillion Cubic Feet
MRPMulti-Year Rate Plan
MWhMegawatt hour
5



GLOSSARY OF TERMS AND ABBREVIATIONS
Other Terms and Abbreviations
N/ANot Applicable
NAVNet Asset Value
NJBPUNew Jersey Board of Public Utilities
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
PPAPower Purchase Agreement
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
RiderReconcilable Surcharge Recovery Mechanism
ROEReturn on Equity
ROURight-of-use
RTORegional Transmission Organization
SECUnited States Securities and Exchange Commission
SOFR Secured Overnight Financing Rate
SOSStandard Offer Service
TCJATax Cuts and Jobs Act
TSCTransmission Service Charge
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;
•adverse impact of the activities associated with the past DPA and now-resolved SEC investigation on Exelon’s and ComEd’s reputation and relationships with legislators, regulators, and customers;
•physical security and cybersecurity risks;
•extreme weather events, natural disasters, operational accidents such as wildfires or natural, gas explosions, war, acts and threats of terrorism, public health crises, epidemics, pandemics, or other significant events;
•disruptions or cost increases in the supply chain, including shortages in labor, materials or parts, or significant increases in relevant tariffs;
•lack of sufficient capacity to meet actual or forecasted demand or disruptions at power generation facilities owned by third parties;
•emerging technologies that could affect or transform the energy industry;
•instability in capital and credit markets;
•a downgrade of any Registrant’s credit ratings or other failure to satisfy the credit standards in the Registrants’ agreements or regulatory financial requirements;
•significant economic downturns or increases in customer rates;
•impacts of climate change and weather on energy usage and maintenance and capital costs; and
7



•impairment of long-lived assets, goodwill, and other assets.
New factors emerge from time to time, and it is impossible for us to predict all of such factors, nor can we assess the impact of each such factor on the business or the extent to which any factor, or combination of factors, may cause actual results to differ materially from those contained in any forward-looking statements. For more information, see those factors discussed in the 2024 Form 10-K filed by the Registrants, including in Part I, ITEM 1A. Risk Factors, and this Report including in Part II, ITEM 1A. Risk Factors.
Investors are cautioned not to place undue reliance on these forward-looking statements, which apply only as of the date of this Report. None of the Registrants undertakes any obligation to publicly release any revision to its forward-looking statements to reflect events or circumstances after the date of this Report.
WHERE TO FIND MORE INFORMATION
The SEC maintains an Internet site at www.sec.gov that contains reports, proxy and information statements, and other information that the Registrants file electronically with the SEC. These documents are also available to the public from commercial document retrieval services and free of charge at the Registrants' website at www.exeloncorp.com. Information contained on the Registrants' website shall not be deemed incorporated into, or to be a part of, this Report.
8



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)20252024
Operating revenues
Electric operating revenues$5,816 $5,198 
Natural gas operating revenues1,024 739 
Revenues from alternative revenue programs(126)106 
Total operating revenues6,714 6,043 
Operating expenses
Purchased power2,184 2,197 
Purchased fuel338 213 
Operating and maintenance1,347 1,271 
Depreciation and amortization903 879 
Taxes other than income taxes405 371 
Total operating expenses5,177 4,931 
(Loss) gain on sale of assets(1)2 
Operating income1,536 1,114 
Other income and (deductions)
Interest expense, net(504)(462)
Interest expense to affiliates, net(6)(6)
Other, net52 75 
Total other income and (deductions)(458)(393)
Income before income taxes1,078 721 
Income taxes170 63 
Net income attributable to common shareholders$908 $658 
Comprehensive income, net of income taxes
Net income$908 $658 
Other comprehensive income, net of income taxes
Pension and non-pension postretirement benefit plans:
Actuarial losses reclassified to periodic benefit cost5 5 
Pension and non-pension postretirement benefit plans valuation adjustments5 (24)
Unrealized (loss) gain on cash flow hedges(8)33 
Other comprehensive income2 14 
Comprehensive income attributable to common shareholders$910 $672 
Average shares of common stock outstanding:
Basic1,008 1,000 
Assumed exercise and/or distributions of stock-based awards(a)
1 1 
Diluted1,009 1,001 
Earnings per average common share
Basic$0.90 $0.66 
Diluted$0.90 $0.66 
__________
(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)20252024
Cash flows from operating activities
Net income$908 $658 
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation, amortization, and accretion905 880 
Loss (gain) on sales of assets1 (2)
Deferred income taxes and amortization of investment tax credits121 46 
Net fair value changes related to derivatives1 1 
Other non-cash operating activities344 39 
Changes in assets and liabilities:
Accounts receivable(402)(309)
Inventories17 12 
Accounts payable and accrued expenses(397)(238)
Collateral received, net44 7 
Income taxes59 21 
Regulatory assets and liabilities, net86 252 
Pension and non-pension postretirement benefit contributions(292)(111)
Other assets and liabilities(195)(264)
Net cash flows provided by operating activities1,200 992 
Cash flows from investing activities
Capital expenditures(1,946)(1,767)
Proceeds from sales of assets— 2 
Other investing activities4 (2)
Net cash flows used in investing activities(1,942)(1,767)
Cash flows from financing activities
Changes in short-term borrowings(775)(317)
Proceeds from short-term borrowings with maturities greater than 90 days— 150 
Repayments on short-term borrowings with maturities greater than 90 days— (150)
Issuance of long-term debt2,425 2,625 
Retirement of long-term debt— (901)
Issuance of common stock173 — 
Dividends paid on common stock(403)(381)
Proceeds from employee stock plans— 11 
Other financing activities(35)(55)
Net cash flows provided by financing activities1,385 982 
Increase in cash, restricted cash, and cash equivalents643 207 
Cash, restricted cash, and cash equivalents at beginning of period939 1,101 
Cash, restricted cash, and cash equivalents at end of period$1,582 $1,308 
Supplemental cash flow information
Decrease in capital expenditures not paid(216)(117)
See the Combined Notes to Consolidated Financial Statements
11



Exelon Corporation and Subsidiary Companies
Consolidated Balance Sheets
(Unaudited)
(In millions)March 31, 2025December 31, 2024
ASSETS
Current assets
Cash and cash equivalents$1,004 $357 
Restricted cash and cash equivalents578 541 
Accounts receivable
Customer accounts receivable3,4883,144
Customer allowance for credit losses(486)(406)
Customer accounts receivable, net3,002 2,738 
Other accounts receivable1,1271,123
Other allowance for credit losses(113)(107)
Other accounts receivable, net1,014 1,016 
Inventories, net
Fossil fuel29 72 
Materials and supplies804 781 
Regulatory assets1,605 1,940 
Prepaid renewable energy credits240 494 
Other523 445 
Total current assets8,799 8,384 
Property, plant, and equipment (net of accumulated depreciation and amortization of $18,958 and $18,445 as of March 31, 2025 and December 31, 2024, respectively)
79,177 78,182 
Deferred debits and other assets
Regulatory assets8,859 8,710 
Goodwill6,630 6,630 
Receivable related to Regulatory Agreement Units4,110 4,026 
Investments289 290 
Other1,620 1,562 
Total deferred debits and other assets21,508 21,218 
Total assets$109,484 $107,784 
See the Combined Notes to Consolidated Financial Statements
12



Exelon Corporation and Subsidiary Companies
Consolidated Balance Sheets
(Unaudited)
(In millions)March 31, 2025December 31, 2024
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities
Short-term borrowings$1,084 $1,859 
Long-term debt due within one year1,454 1,453 
Accounts payable2,693 2,994 
Accrued expenses1,186 1,468 
Payables to affiliates5 5 
Customer deposits465 446 
Regulatory liabilities464 411 
Mark-to-market derivative liabilities25 29 
Unamortized energy contract liabilities5 5 
Renewable energy credit obligations215 429 
Other507 512 
Total current liabilities8,103 9,611 
Long-term debt45,342 42,947 
Long-term debt to financing trusts390 390 
Deferred credits and other liabilities
Deferred income taxes and unamortized investment tax credits13,081 12,793 
Regulatory liabilities10,289 10,198 
Pension obligations1,475 1,745 
Non-pension postretirement benefit obligations480 472 
Asset retirement obligations305 301 
Mark-to-market derivative liabilities130 103 
Unamortized energy contract liabilities20 21 
Other2,262 2,282 
Total deferred credits and other liabilities28,042 27,915 
Total liabilities81,877 80,863 
Commitments and contingencies
Shareholders’ equity
Common stock (No par value, 2,000 shares authorized, 1,009 shares and 1,005 shares outstanding as of March 31, 2025 and December 31, 2024, respectively)
21,517 21,338 
Treasury stock, at cost (2 shares as of March 31, 2025 and December 31, 2024)
(123)(123)
Retained earnings6,931 6,426 
Accumulated other comprehensive loss, net(718)(720)
Total shareholders’ equity27,607 26,921 
Total liabilities and shareholders’ equity$109,484 $107,784 

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, 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 

Three Months Ended March 31, 2024
(In millions, shares
in thousands)		Issued
Shares		Common
Stock		Treasury
Stock		Retained
Earnings		Accumulated
Other
Comprehensive
Loss, net		Total Shareholders'
Equity
Balance at December 31, 20231,001,249 $21,114 $(123)$5,490 $(726)$25,755 
Net income— — — 658 — 658 
Long-term incentive plan activity333 2 — — — 2 
Employee stock purchase plan activity276 13 — — — 13 
Common stock dividends
($0.38/common share)
— — — (381)— (381)
Other comprehensive income, net of income taxes— — — — 14 14 
Balance at March 31, 20241,001,858 $21,129 $(123)$5,767 $(712)$26,061 












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)20252024
Operating revenues
Electric operating revenues$2,142 $2,074 
Revenues from alternative revenue programs(85)19 
Operating revenues from affiliates8 2 
Total operating revenues2,065 2,095 
Operating expenses
Purchased power689 907 
Operating and maintenance323 318 
Operating and maintenance from affiliates100 100 
Depreciation and amortization380 362 
Taxes other than income taxes99 94 
Total operating expenses1,591 1,781 
Operating income474 314 
Other income and (deductions)
Interest expense, net(125)(119)
Interest expense to affiliates, net(3)(3)
Other, net21 20 
Total other income and (deductions)(107)(102)
Income before income taxes367 212 
Income taxes65 19 
Net income$302 $193 
Comprehensive income$302 $193 

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)20252024
Cash flows from operating activities
Net income$302 $193 
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation and amortization380 362 
Deferred income taxes and amortization of investment tax credits(8)(1)
Other non-cash operating activities141 (6)
Changes in assets and liabilities:
Accounts receivable(111)(133)
Receivables from and payables to affiliates, net(21)— 
Inventories3 (11)
Accounts payable and accrued expenses (189)(116)
Collateral received, net5 8 
Income taxes72 21 
Regulatory assets and liabilities, net76 315 
Pension and non-pension postretirement benefit contributions(189)(5)
Other assets and liabilities(102)(67)
Net cash flows provided by operating activities359 560 
Cash flows from investing activities
Capital expenditures(590)(594)
Other investing activities1 1 
Net cash flows used in investing activities(589)(593)
Cash flows from financing activities
Changes in short-term borrowings311 128 
Dividends paid on common stock(203)(194)
Contributions from parent87 39 
Other financing activities— 1 
Net cash flows provided by (used in) financing activities195 (26)
Decrease in cash, restricted cash, and cash equivalents(35)(59)
Cash, restricted cash, and cash equivalents at beginning of period632 686 
Cash, restricted cash, and cash equivalents at end of period$597 $627 
Supplemental cash flow information
Decrease in capital expenditures not paid$(25)$(74)
See the Combined Notes to Consolidated Financial Statements
16



Commonwealth Edison Company and Subsidiary Companies
Consolidated Balance Sheets
(Unaudited)
(In millions)March 31, 2025December 31, 2024
ASSETS
Current assets
   Cash and cash equivalents$96 $105 
   Restricted cash and cash equivalents501 486 
   Accounts receivable
   Customer accounts receivable1,079994
   Customer allowance for credit losses(125)(109)
       Customer accounts receivable, net954 885 
   Other accounts receivable291290
   Other allowance for credit losses(34)(34)
       Other accounts receivable, net 257 256 
   Receivables from affiliates8 4 
   Inventories, net287 292 
   Regulatory assets905 1,159 
   Other154 141 
   Total current assets3,162 3,328 
Property, plant, and equipment (net of accumulated depreciation and amortization of $7,824 and $7,619 as of March 31, 2025 and December 31, 2024, respectively)
30,493 30,211 
Deferred debits and other assets
   Regulatory assets2,662 2,562 
   Goodwill2,625 2,625 
   Receivable related to Regulatory Agreement Units3,798 3,780 
   Investments6 6 
   Prepaid pension asset1,335 1,165 
   Other1,118 1,073 
   Total deferred debits and other assets11,544 11,211 
Total assets$45,199 $44,750 
See the Combined Notes to Consolidated Financial Statements
17



Commonwealth Edison Company and Subsidiary Companies
Consolidated Balance Sheets
(Unaudited)
(In millions)March 31, 2025December 31, 2024
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities
   Short-term borrowings$347 $36 
   Accounts payable656 748 
   Accrued expenses403 463 
   Payables to affiliates60 77 
   Customer deposits147 134 
   Regulatory liabilities181 197 
   Mark-to-market derivative liabilities25 29 
   Other245 270 
   Total current liabilities2,064 1,954 
Long-term debt12,031 12,030 
Long-term debt to financing trust206 206 
Deferred credits and other liabilities
   Deferred income taxes and unamortized investment tax credits5,646 5,601 
   Regulatory liabilities8,490 8,421 
   Asset retirement obligations169 167 
   Non-pension postretirement benefit obligations158 156 
   Mark-to-market derivative liabilities126 103 
   Other1,243 1,232 
   Total deferred credits and other liabilities15,832 15,680 
   Total liabilities30,133 29,870 
Commitments and contingencies
Shareholders’ equity
   Common stock 1,588 1,588 
   Other paid-in capital10,715 10,628 
   Retained earnings2,763 2,664 
   Total shareholders’ equity15,066 14,880 
Total liabilities and shareholders’ equity$45,199 $44,750 
    
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, 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 
Three Months Ended March 31, 2024
(In millions)Common
Stock		Other
Paid-In
Capital		Retained
Earnings		Total
Shareholders’
Equity
Balance at December 31, 2023$1,588 $10,401 $2,374 $14,363 
Net income— — 193 193 
Common stock dividends— — (194)(194)
Contributions from parent— 39 — 39 
Balance at March 31, 2024$1,588 $10,440 $2,373 $14,401 
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)20252024
Operating revenues
Electric operating revenues$963 $782 
Natural gas operating revenues376 272 
Revenues from alternative revenue programs(9)(2)
Operating revenues from affiliates3 2 
Total operating revenues1,333 1,054 
Operating expenses
Purchased power 361 306 
Purchased fuel141 97 
Operating and maintenance266 235 
Operating and maintenance from affiliates61 58 
Depreciation and amortization109 104 
Taxes other than income taxes60 51 
Total operating expenses998 851 
Gain on sales of assets — 2 
Operating income335 205 
Other income and (deductions)
Interest expense, net(59)(52)
Interest expense to affiliates(4)(3)
Other, net8 9 
Total other income and (deductions)(55)(46)
Income before income taxes280 159 
Income taxes14 10 
Net income$266 $149 
Comprehensive income$266 $149 
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)20252024
Cash flows from operating activities
Net income$266 $149 
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation and amortization109 104 
Gain on sales of assets— (2)
Deferred income taxes and amortization of investment tax credits(18)(8)
Other non-cash operating activities54 20 
Changes in assets and liabilities:
Accounts receivable(148)(75)
Receivables from and payables to affiliates, net(4)4 
Inventories15 19 
Accounts payable and accrued expenses (25)(63)
Collateral (paid) received, net12 — 
Income taxes32 19 
Regulatory assets and liabilities, net27 (20)
Pension and non-pension postretirement benefit contributions(9)(2)
Other assets and liabilities(117)(104)
Net cash flows provided by operating activities194 41 
Cash flows from investing activities
Capital expenditures(424)(361)
Other investing activities2 2 
Net cash flows used in investing activities(422)(359)
Cash flows from financing activities
Changes in short-term borrowings(192)(165)
Dividends paid on common stock(137)(100)
Contributions from parent563 580 
Net cash flows provided by financing activities234 315 
Increase (decrease) in cash, restricted cash, and cash equivalents6 (3)
Cash, restricted cash, and cash equivalents at beginning of period48 51 
Cash, restricted cash, and cash equivalents at end of period$54 $48 
Supplemental cash flow information
(Decrease) increase in capital expenditures not paid$(20)$5 
See the Combined Notes to Consolidated Financial Statements
21



PECO Energy Company and Subsidiary Companies
Consolidated Balance Sheets
(Unaudited)
(In millions)March 31, 2025December 31, 2024
ASSETS
Current assets
Cash and cash equivalents$54 $48 
Accounts receivable
Customer accounts receivable788670
Customer allowance for credit losses(160)(133)
Customer accounts receivable, net628 537 
Other accounts receivable170145
Other allowance for credit losses(22)(18)
Other accounts receivable, net148 127 
Inventories, net
Fossil fuel15 37 
Materials and supplies83 79 
Prepaid utility taxes116 2 
Prepaid renewable energy credits31 51 
Regulatory assets61 65 
Other66 27 
Total current assets1,202 973 
Property, plant, and equipment (net of accumulated depreciation and amortization of $4,089 and $4,042 as of March 31, 2025 and December 31, 2024, respectively)
14,691 14,392 
Deferred debits and other assets
Regulatory assets1,068 1,003 
Receivable related to Regulatory Agreement Units311 247 
Investments39 41 
Prepaid pension asset443 435 
Other35 32 
Total deferred debits and other assets1,896 1,758 
Total assets$17,789 $17,123 
See the Combined Notes to Consolidated Financial Statements
22



PECO Energy Company and Subsidiary Companies
Consolidated Balance Sheets
(Unaudited)
(In millions)March 31, 2025December 31, 2024
LIABILITIES AND SHAREHOLDER'S EQUITY
Current liabilities
Short-term borrowings$— $192 
Long-term debt due within one year350 350 
Accounts payable631 639 
Accrued expenses169 166 
Payables to affiliates37 41 
Customer deposits84 80 
Regulatory liabilities151 122 
Other120 80 
Total current liabilities1,542 1,670 
Long-term debt5,354 5,354 
Long-term debt to financing trusts184 184 
Deferred credits and other liabilities
Deferred income taxes and unamortized investment tax credits2,485 2,433 
Regulatory liabilities317 253 
Asset retirement obligations28 27 
Non-pension postretirement benefit obligations288 287 
Other84 100 
Total deferred credits and other liabilities3,202 3,100 
Total liabilities10,282 10,308 
Commitments and contingencies
Shareholder’s equity
Common stock5,208 4,645 
Retained earnings2,299 2,170 
Total shareholder’s equity7,507 6,815 
Total liabilities and shareholder's equity$17,789 $17,123 
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, 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 
Three Months Ended March 31, 2024
(In millions)Common
Stock		Retained
Earnings		Total
Shareholder's
Equity
Balance at December 31, 2023$4,050 $2,019 $6,069 
Net income— 149 149 
Common stock dividends— (100)(100)
Contributions from parent580 — 580 
Balance at March 31, 2024$4,630 $2,068 $6,698 
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)20252024
Operating revenues
Electric operating revenues$1,021 $857 
Natural gas operating revenues560 395 
Revenues from alternative revenue programs(29)43 
Operating revenues from affiliates2 2 
Total operating revenues1,554 1,297 
Operating expenses
Purchased power450 377 
Purchased fuel159 87 
Operating and maintenance242 205 
Operating and maintenance from affiliates63 59 
Depreciation and amortization164 150 
Taxes other than income taxes96 89 
Total operating expenses1,174 967 
Operating income380 330 
Other income and (deductions)
Interest expense, net(58)(50)
Other, net9 8 
Total other income and (deductions)(49)(42)
Income before income taxes331 288 
Income taxes71 24 
Net income$260 $264 
Comprehensive income$260 $264 
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)20252024
Cash flows from operating activities
Net income$260 $264 
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation and amortization164 150 
Deferred income taxes and amortization of investment tax credits35 (4)
Other non-cash operating activities55 (21)
Changes in assets and liabilities:
Accounts receivable(153)(95)
Receivables from and payables to affiliates, net(10)2 
Inventories20 14 
Accounts payable and accrued expenses(15)21 
Collateral received, net1 — 
Income taxes36 29 
Regulatory assets and liabilities, net14 — 
Pension and non-pension postretirement benefit contributions(34)(25)
Other assets and liabilities49 (18)
Net cash flows provided by operating activities422 317 
Cash flows from investing activities
Capital expenditures(406)(324)
Other investing activities3 8 
Net cash flows used in investing activities(403)(316)
Cash flows from financing activities
Changes in short-term borrowings62 70 
Dividends paid on common stock(98)(92)
Net cash flows used in financing activities(36)(22)
Decrease in cash, restricted cash, and cash equivalents(17)(21)
Cash, restricted cash, and cash equivalents at beginning of period34 48 
Cash, restricted cash, and cash equivalents at end of period$17 $27 
Supplemental cash flow information
Decrease in capital expenditures not paid$(48)$(8)
See the Combined Notes to Consolidated Financial Statements
26



Baltimore Gas and Electric Company
Balance Sheets
(Unaudited)
(In millions)March 31, 2025December 31, 2024
ASSETS
Current assets
Cash and cash equivalents$14 $33 
Restricted cash and cash equivalents3 1 
Accounts receivable
Customer accounts receivable805654
Customer allowance for credit losses (72)(56)
Customer accounts receivable, net733 598 
Other accounts receivable 109113
Other allowance for credit losses(6)(6)
Other accounts receivable, net103 107 
Inventories, net
Fossil fuel12 29 
Materials and supplies81 84 
Prepaid utility taxes58 115 
Regulatory assets156 207 
Prepaid renewable energy credits52 157 
Other17 17 
Total current assets1,229 1,348 
Property, plant, and equipment (net of accumulated depreciation and amortization of $5,079 and $5,005 as of March 31, 2025 and December 31, 2024, respectively)
13,358 13,134 
Deferred debits and other assets
Regulatory assets798 788 
Investments10 10 
Prepaid pension asset231 218 
Other51 44 
Total deferred debits and other assets1,090 1,060 
Total assets$15,677 $15,542 
See the Combined Notes to Consolidated Financial Statements
27



Baltimore Gas and Electric Company
Balance Sheets
(Unaudited)
(In millions)March 31, 2025December 31, 2024
LIABILITIES AND SHAREHOLDER'S EQUITY
Current liabilities
Short-term borrowings$237 $175 
Accounts payable445 515 
Accrued expenses211 176 
Payables to affiliates38 48 
Customer deposits119 118 
Regulatory liabilities34 12 
Renewable energy credit obligations53 160 
Other39 39 
Total current liabilities1,176 1,243 
Long-term debt5,396 5,395 
Deferred credits and other liabilities
Deferred income taxes and unamortized investment tax credits2,161 2,099 
Regulatory liabilities615 636 
Asset retirement obligations36 36 
Non-pension postretirement benefit obligations145 150 
Other100 97 
Total deferred credits and other liabilities3,057 3,018 
Total liabilities9,629 9,656 
Commitments and contingencies
Shareholder's equity
Common stock3,483 3,483 
Retained earnings2,565 2,403 
Total shareholder's equity6,048 5,886 
Total liabilities and shareholder's equity$15,677 $15,542 

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, 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 
Three Months Ended March 31, 2024
(In millions)Common
Stock		Retained
Earnings		Total
Shareholder's
Equity
Balance at December 31, 2023$3,246 $2,244 $5,490 
Net income— 264 264 
Common stock dividends— (92)(92)
Balance at March 31, 2024$3,246 $2,416 $5,662 
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)20252024
Operating revenues
Electric operating revenues$1,691 $1,485 
Natural gas operating revenues88 72 
Revenues from alternative revenue programs(3)46 
Operating revenues from affiliates2 3 
Total operating revenues1,778 1,606 
Operating expenses
Purchased power684 607 
Purchased fuel38 29 
Operating and maintenance296 274 
Operating and maintenance from affiliates53 51 
Depreciation and amortization234 246 
Taxes other than income taxes140 128 
Total operating expenses1,445 1,335 
Loss on sale of assets(1)— 
Operating income332 271 
Other income and (deductions)
Interest expense, net(99)(90)
Interest expense to affiliates, net(1)— 
Other, net19 27 
Total other income and (deductions)(81)(63)
Income before income taxes 251 208 
Income taxes57 40 
Net income$194 $168 
Comprehensive income$194 $168 
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)20252024
Cash flows from operating activities
Net income$194 $168 
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation and amortization234 246 
Loss on sales of assets1 — 
Deferred income taxes and amortization of investment tax credits32 16 
Other non-cash operating activities69 9 
Changes in assets and liabilities:
Accounts receivable6 1 
Receivables from and payables to affiliates, net(9)— 
Inventories(24)(11)
Accounts payable and accrued expenses(84)(23)
Collateral received, net27 — 
Income taxes25 24 
Regulatory assets and liabilities, net(14)(42)
Pension and non-pension postretirement benefit contributions(42)(72)
Other assets and liabilities(13)(27)
Net cash flows provided by operating activities402 289 
Cash flows from investing activities
Capital expenditures(513)(453)
Net cash flows used in investing activities(513)(453)
Cash flows from financing activities
Changes in short-term borrowings(530)(394)
Issuance of long-term debt425 925 
Retirement of long-term debt— (400)
Changes in Exelon intercompany money pool11 8 
Distributions to member(132)(118)
Contributions from member352 487 
Other financing activities(8)(21)
Net cash flows provided by financing activities118 487 
Increase in cash, restricted cash, and cash equivalents7 323 
Cash, restricted cash, and cash equivalents at beginning of period163 204 
Cash, restricted cash, and cash equivalents at end of period$170 $527 
Supplemental cash flow information
Decrease in capital expenditures not paid$(109)$(11)
See the Combined Notes to Consolidated Financial Statements
31



Pepco Holdings LLC and Subsidiary Companies
Consolidated Balance Sheets
(Unaudited)
(In millions)March 31, 2025December 31, 2024
ASSETS
Current assets
Cash and cash equivalents$127 $139 
Restricted cash and cash equivalents43 24 
Accounts receivable
Customer accounts receivable815827
Customer allowance for credit losses(129)(108)
Customer accounts receivable, net686 719 
Other accounts receivable281284
Other allowance for credit losses(51)(49)
Other accounts receivable, net230 235 
Receivables from affiliates8 8 
Inventories, net
Fossil fuel2 7 
Materials and supplies354 325 
Prepaid utility taxes39 70 
Regulatory assets297 323 
Prepaid renewable energy credits58 194 
Other56 36 
Total current assets1,900 2,080 
Property, plant, and equipment (net of accumulated depreciation and amortization of $3,892 and $3,728 as of March 31, 2025 and December 31, 2024, respectively)
20,258 20,053 
Deferred debits and other assets
Regulatory assets1,577 1,570 
Goodwill4,005 4,005 
Investments152 152 
Prepaid pension asset266 252 
Other191 185 
Total deferred debits and other assets6,191 6,164 
Total assets$28,349 $28,297 
See the Combined Notes to Consolidated Financial Statements
32



Pepco Holdings LLC and Subsidiary Companies
Consolidated Balance Sheets
(Unaudited)
(In millions)March 31, 2025December 31, 2024
LIABILITIES AND MEMBER'S EQUITY
Current liabilities
Short-term borrowings$— $530 
Long-term debt due within one year292 290 
Accounts payable605 721 
Accrued expenses317 367 
Payables to affiliates57 66 
Borrowings from Exelon intercompany money pool74 63 
Customer deposits116 113 
Regulatory liabilities 87 69 
Unamortized energy contract liabilities5 5 
Renewable energy credit obligations86 217 
Other128 124 
Total current liabilities1,767 2,565 
Long-term debt9,249 8,834 
Deferred credits and other liabilities
Deferred income taxes and unamortized investment tax credits3,239 3,190 
Regulatory liabilities778 794 
Asset retirement obligations68 67 
Non-pension postretirement benefit obligations28 31 
Unamortized energy contract liabilities20 21 
Other464 473 
Total deferred credits and other liabilities4,597 4,576 
Total liabilities15,613 15,975 
Commitments and contingencies
Member's equity
Membership interest12,914 12,562 
Undistributed losses(178)(240)
Total member's equity12,736 12,322 
Total liabilities and member's equity$28,349 $28,297 
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, 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 

Three Months Ended March 31, 2024
(In millions)Membership InterestUndistributed (Losses)/GainsTotal Member's Equity
Balance at December 31, 2023$12,057 $(275)$11,782 
Net income— 168 168 
Distributions to member— (118)(118)
Contributions from member487 — 487 
Balance at March 31, 2024$12,544 $(225)$12,319 
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)20252024
Operating revenues
Electric operating revenues$855 728 
Revenues from alternative revenue programs2 29 
Operating revenues from affiliates2 2 
Total operating revenues859 759 
Operating expenses
Purchased power318 281 
Operating and maintenance96 86 
Operating and maintenance from affiliates63 64 
Depreciation and amortization105 107 
Taxes other than income taxes113 102 
Total operating expenses695 640 
Loss on sale of assets(1)— 
Operating income163 119 
Other income and (deductions)
Interest expense, net(52)(45)
Other, net11 15 
Total other income and (deductions)(41)(30)
Income before income taxes122 89 
Income taxes25 14 
Net income$97 $75 
Comprehensive income$97 $75 
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)20252024
Cash flows from operating activities
Net income$97 $75 
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation and amortization105 107 
Deferred income taxes and amortization of investment tax credits10 3 
Loss on sales of assets1 — 
Other non-cash operating activities12 (13)
Changes in assets and liabilities:
Accounts receivable(14)21 
Receivables from and payables to affiliates, net(2)6 
Inventories(20)(10)
Accounts payable and accrued expenses (28)— 
Collateral received (paid), net10 (1)
Income taxes15 12 
Regulatory assets and liabilities, net13 6 
Pension and non-pension postretirement benefit contributions(4)(4)
Other assets and liabilities(3)(19)
Net cash flows provided by operating activities192 183 
Cash flows from investing activities
Capital expenditures(240)(229)
Changes in PHI intercompany money pool— (134)
Net cash flows used in investing activities(240)(363)
Cash flows from financing activities
Changes in short-term borrowings(200)(132)
Issuance of long-term debt200 675 
Retirement of long-term debt— (400)
Dividends paid on common stock(66)(51)
Contributions from parent157 251 
Other financing activities(5)(15)
Net cash flows provided by financing activities86 328 
Increase in cash, restricted cash, and cash equivalents38 148 
Cash, restricted cash, and cash equivalents at beginning of period51 72 
Cash, restricted cash, and cash equivalents at end of period$89 $220 
Supplemental cash flow information
Decrease in capital expenditures not paid$(49)$(11)
See the Combined Notes to Consolidated Financial Statements
36



Potomac Electric Power Company
Balance Sheets
(Unaudited)
(In millions)March 31, 2025December 31, 2024
ASSETS
Current assets
Cash and cash equivalents$58 $30 
Restricted cash and cash equivalents31 21 
Accounts receivable
Customer accounts receivable404395
Customer allowance for credit losses(69)(59)
Customer accounts receivable, net335 336 
Other accounts receivable147142
Other allowance for credit losses(27)(27)
Other accounts receivable, net120 115 
Receivables from affiliates— 1 
Inventories, net189 169 
Regulatory assets136 157 
Prepaid renewable energy credits49 165 
Other37 55 
Total current assets955 1,049 
Property, plant, and equipment (net of accumulated depreciation and amortization of $4,593 and $4,522 as of March 31, 2025 and December 31, 2024, respectively)
10,205 10,097 
Deferred debits and other assets
Regulatory assets442 446 
Investments136 135 
Prepaid pension asset216 222 
Other57 51 
Total deferred debits and other assets851 854 
Total assets$12,011 $12,000 
See the Combined Notes to Consolidated Financial Statements
37



Potomac Electric Power Company
Balance Sheets
(Unaudited)
(In millions)March 31, 2025December 31, 2024
LIABILITIES AND SHAREHOLDER'S EQUITY
Current liabilities
Short-term borrowings$— $200 
Long-term debt due within one year6 6 
Accounts payable303 360 
Accrued expenses192 201 
Payables to affiliates34 37 
Customer deposits57 55 
Regulatory liabilities 16 17 
Merger related obligation21 22 
Renewable energy credit obligations50 169 
Other43 51 
Total current liabilities722 1,118 
Long-term debt4,553 4,356 
Deferred credits and other liabilities
Deferred income taxes and unamortized investment tax credits1,530 1,509 
Regulatory liabilities 301 310 
Asset retirement obligations50 49 
Other232 223 
Total deferred credits and other liabilities2,113 2,091 
Total liabilities7,388 7,565 
Commitments and contingencies
Shareholder's equity
Common stock 3,492 3,335 
Retained earnings1,131 1,100 
Total shareholder's equity4,623 4,435 
Total liabilities and shareholder's equity$12,011 $12,000 
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, 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 

Three Months Ended March 31, 2024
(In millions)Common StockRetained EarningsTotal Shareholder's Equity
Balance at December 31, 2023$3,075 $1,069 $4,144 
Net income— 75 75 
Common stock dividends— (51)(51)
Contributions from parent251 — 251 
Balance at March 31, 2024$3,326 $1,093 $4,419 

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)20252024
Operating revenues
Electric operating revenues$463 $413 
Natural gas operating revenues88 72 
Revenues from alternative revenue programs(5)4 
Operating revenues from affiliates2 2 
Total operating revenues548 491 
Operating expenses
Purchased power209 186 
Purchased fuel38 29 
Operating and maintenance60 51 
Operating and maintenance from affiliates 46 44 
Depreciation and amortization63 61 
Taxes other than income taxes21 20 
Total operating expenses437 391 
Operating income111 100 
Other income and (deductions)
Interest expense, net(25)(22)
Other, net4 5 
Total other income and (deductions)(21)(17)
Income before income taxes90 83 
Income taxes21 17 
Net income$69 $66 
Comprehensive income$69 $66 
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)20252024
Cash flows from operating activities
Net income$69 $66 
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation and amortization63 61 
Deferred income taxes and amortization of investment tax credits9 6 
Other non-cash operating activities21 12 
Changes in assets and liabilities:
Accounts receivable(1)(7)
Receivables from and payables to affiliates, net(4)— 
Inventories(4)1 
Accounts payable and accrued expenses(9)16 
Collateral received, net9 — 
Income taxes13 10 
Regulatory assets and liabilities, net2 (1)
Other assets and liabilities7 6 
Net cash flows provided by operating activities175 170 
Cash flows from investing activities
Capital expenditures(156)(134)
Changes in PHI intercompany money pool(12)— 
Net cash flows used in investing activities(168)(134)
Cash flows from financing activities
Changes in short-term borrowings(144)(63)
Issuance of long-term debt125 175 
Dividends paid on common stock(46)(45)
Contributions from parent99 154 
Other financing activities(3)(3)
Net cash flows provided by financing activities31 218 
Increase in cash, restricted cash, and cash equivalents38 254 
Cash, restricted cash, and cash equivalents at beginning of period23 16 
Cash, restricted cash, and cash equivalents at end of period$61 $270 
Supplemental cash flow information
Decrease in capital expenditures not paid$(47)$(6)
    
See the Combined Notes to Consolidated Financial Statements
41



Delmarva Power & Light Company
Balance Sheets
(Unaudited)
(In millions)March 31, 2025December 31, 2024
ASSETS
Current assets
Cash and cash equivalents$50 $21 
Restricted cash and cash equivalents11 2 
Accounts receivable
Customer accounts receivable215210
Customer allowance for credit losses(23)(17)
Customer accounts receivable, net192 193 
Other accounts receivable5363
Other allowance for credit losses(9)(9)
Other accounts receivable, net44 54 
Receivables from affiliates1 — 
Receivable from PHI intercompany pool12 — 
Inventories, net
Fossil fuel2 6 
Materials and supplies103 95 
Prepaid utility taxes13 26 
Regulatory assets49 60 
Prepaid renewable energy credits9 29 
Other21 16 
Total current assets507 502 
Property, plant, and equipment (net of accumulated depreciation and amortization of $2,121 and $2,075 as of March 31, 2025 and December 31, 2024, respectively)
5,595 5,540 
Deferred debits and other assets
Regulatory assets220 215 
Prepaid pension asset116 120 
Other46 44 
Total deferred debits and other assets382 379 
Total assets$6,484 $6,421 
See the Combined Notes to Consolidated Financial Statements
42



Delmarva Power & Light Company
Balance Sheets
(Unaudited)
(In millions)March 31, 2025December 31, 2024
LIABILITIES AND SHAREHOLDER'S EQUITY
Current liabilities
Short-term borrowings$— $144 
Long-term debt due within one year131 130 
Accounts payable131 187 
Accrued expenses65 55 
Payables to affiliates23 26 
Customer deposits34 34 
Regulatory liabilities 46 42 
Renewable energy credit obligations37 48 
Other27 22 
Total current liabilities494 688 
Long-term debt2,215 2,090 
Deferred credits and other liabilities
Deferred income taxes and unamortized investment tax credits960 946 
Regulatory liabilities323 325 
Asset retirement obligations13 13 
Non-pension postretirement benefit obligations3 3 
Other112 114 
Total deferred credits and other liabilities1,411 1,401 
Total liabilities4,120 4,179 
Commitments and contingencies
Shareholder's equity
Common stock 1,714 1,615 
Retained earnings650 627 
Total shareholder's equity2,364 2,242 
Total liabilities and shareholder's equity$6,484 $6,421 
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, 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 

Three Months Ended March 31, 2024
(In millions)Common Stock Retained EarningsTotal Shareholder's Equity
Balance at December 31, 2023$1,455 $638 $2,093 
Net income— 66 66 
Common stock dividends— (45)(45)
Contributions from parent154 — 154 
Balance at March 31, 2024$1,609 $659 $2,268 

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)20252024
Operating revenues
Electric operating revenues$372 $344 
Revenues from alternative revenue programs— 13 
Operating revenues from affiliates1 1 
Total operating revenues373 358 
Operating expenses
Purchased power157 140 
Operating and maintenance51 47 
Operating and maintenance from affiliates39 40 
Depreciation and amortization64 74 
Taxes other than income taxes2 2 
Total operating expenses313 303 
Operating income60 55 
Other income and (deductions)
Interest expense, net(21)(20)
Other, net3 5 
Total other income and (deductions)(18)(15)
Income before income taxes42 40 
Income taxes11 11 
Net income$31 $29 
Comprehensive income$31 $29 
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)20252024
Cash flows from operating activities
Net income$31 $29 
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation and amortization64 74 
Deferred income taxes and amortization of investment tax credits8 7 
Other non-cash operating activities25 2 
Changes in assets and liabilities:
Accounts receivable21 (12)
Receivables from and payables to affiliates, net(2)(5)
Inventories— (3)
Accounts payable and accrued expenses(8)(1)
Collateral received, net6 1 
Income taxes3 3 
Regulatory assets and liabilities, net(28)(47)
Pension and non-pension postretirement benefit contributions(3)(7)
Other assets and liabilities(5)(13)
Net cash flows provided by operating activities112 28 
Cash flows from investing activities
Capital expenditures(105)(89)
Net cash flows used in investing activities(105)(89)
Cash flows from financing activities
Changes in short-term borrowings(186)(199)
Issuance of long-term debt100 75 
Changes in PHI intercompany money pool12 134 
Dividends paid on common stock(20)(22)
Contributions from parent94 81 
Other financing activities(2)(2)
Net cash flows (used in) provided by financing activities(2)67 
Increase in cash and cash equivalents5 6 
Cash and cash equivalents at beginning of period14 21 
Cash and cash equivalents at end of period$19 $27 
Supplemental cash flow information
(Decrease) increase in capital expenditures not paid$(12)$4 
See the Combined Notes to Consolidated Financial Statements
46



Atlantic City Electric Company and Subsidiary Company
Consolidated Balance Sheets
(Unaudited)
(In millions)March 31, 2025December 31, 2024
ASSETS
Current assets
Cash and cash equivalents$18 $14 
Restricted cash and cash equivalents1 — 
Accounts receivable
Customer accounts receivable196223
Customer allowance for credit losses(37)(32)
Customer accounts receivable, net159 191 
Other accounts receivable8179
Other allowance for credit losses(15)(13)
Other accounts receivable, net66 66 
Receivables from affiliates7 7 
Inventories, net62 62 
Regulatory assets107 101 
Other8 6 
Total current assets428 447 
Property, plant, and equipment (net of accumulated depreciation and amortization of $1,839 and $1,798 as of March 31, 2025 and December 31, 2024, respectively)
4,407 4,366 
Deferred debits and other assets
Regulatory assets515 502 
Prepaid pension asset2 1 
Other35 33 
Total deferred debits and other assets552 536 
Total assets$5,387 $5,349 
See the Combined Notes to Consolidated Financial Statements
47



Atlantic City Electric Company and Subsidiary Company
Consolidated Balance Sheets
(Unaudited)
(In millions)March 31, 2025December 31, 2024
LIABILITIES AND SHAREHOLDER'S EQUITY
Current liabilities
Short-term borrowings$— $186 
Long-term debt due within one year154 154 
Accounts payable162 163 
Accrued expenses43 52 
Payables to affiliates20 22 
Borrowings from PHI intercompany money pool12 — 
Customer deposits24 24 
Regulatory liabilities25 10 
Other18 10 
Total current liabilities458 621 
Long-term debt1,879 1,779 
Deferred credits and other liabilities
Deferred income taxes and unamortized investment tax credits825 816 
Regulatory liabilities141 146 
Other54 62 
Total deferred credits and other liabilities1,020 1,024 
Total liabilities3,357 3,424 
Commitments and contingencies
Shareholder's equity
Common stock2,009 1,915 
Retained earnings21 10 
Total shareholder's equity2,030 1,925 
Total liabilities and shareholder's equity$5,387 $5,349 

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, 2025
(In millions)Common StockRetained (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 

Three Months Ended March 31, 2024
(In millions)Common Stock Retained (Deficit) EarningsTotal Shareholder's Equity
Balance at December 31, 2023$1,830 $(18)$1,812 
Net income— 29 29 
Common stock dividends— (22)(22)
Contributions from parent81 — 81 
Balance at March 31, 2024$1,911 $(11)$1,900 

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
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
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 Registrant’s Consolidated Financial Statements includes the accounts of its subsidiaries. All intercompany transactions have been eliminated.
Through its business services subsidiary, BSC, Exelon provides its subsidiaries with a variety of support services at cost, including legal, human resources, financial, information technology, and supply management services. PHI also has a business services subsidiary, PHISCO, which provides a variety of support services at cost, including legal, finance, engineering, customer operations, transmission and distribution planning, asset management, system operations, and power procurement, to PHI operating Registrants. The costs of BSC and PHISCO are directly charged or allocated to the applicable subsidiaries. The results of Exelon’s corporate operations are presented as “Other” within the consolidated financial statements and include intercompany eliminations unless otherwise disclosed.
The accompanying consolidated financial statements as of March 31, 2025 and for the three months ended March 31, 2025 and 2024 are unaudited but, in the opinion of each Registrant's management, the Registrants include all adjustments that are considered necessary for a fair statement of the Registrants’ respective financial statements in accordance with GAAP. All adjustments are of a normal, recurring nature, except as otherwise disclosed. The December 31, 2024 Consolidated Balance Sheets were derived from audited financial statements. The interim financial statements are to be read in conjunction with prior annual financial statements and notes. Additionally, financial results for interim periods are not necessarily indicative of results that may be expected for any other interim period or for the fiscal year ending December 31, 2025. These Combined Notes to Consolidated Financial Statements have been prepared pursuant to the rules and regulations of the SEC for Quarterly Reports on Form 10-Q. Certain information and note disclosures normally included in financial
50


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

Note 1 — Significant Accounting Policies
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, 2025: The following new authoritative accounting guidance issued by the FASB has not yet been adopted and reflected by the Registrants in their consolidated financial statements as of March 31, 2025. Unless otherwise indicated, the Registrants are currently assessing the impacts such guidance may have (which could be material) in their Consolidated Balance Sheets, Consolidated Statements of Operations and Comprehensive Income, Consolidated Statements of Cash Flows and disclosures, as well as the potential to early adopt where applicable. The Registrants have assessed other FASB issuances of new standards which are not listed below given the current expectation that such standards will not significantly impact the Registrants' financial reporting.
Improvement to Income Tax Disclosures (Issued December 2023). Provides additional disclosure requirements related to the effective tax rate reconciliation and income taxes paid. Under the revised guidance for the effective tax reconciliations, entities would be required to disclose: (1) eight specific categories in the effective tax rate reconciliation in both percentages and reporting currency amount, (2) additional information for reconciling items over a certain threshold, (3) explanation of individual reconciling items disclosed, and (4) provide a qualitative description of the state and local jurisdictions that contribute to the majority of the state income tax expense. For each annual period presented, the new standard requires disclosure of the year-to-date amount of income taxes paid (net of refunds received) disaggregated by federal, state, and foreign. It also requires additional disaggregated information on income taxes paid (net of refunds received) to an individual jurisdiction equal to or greater than 5% of total income taxes paid (net of refunds received). The standard is effective for annual periods beginning January 1, 2025, with early adoption permitted.
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. The Registrants are currently assessing the impacts of this standard.
2. Regulatory Matters (All Registrants)
As discussed in Note 3 — Regulatory Matters of the 2024 Form 10-K, the Registrants are involved in rate and regulatory proceedings at FERC and their state commissions. The following discusses developments in 2025 and updates to the 2024 Form 10-K.
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 2025.
Completed Distribution Base Rate Case Proceedings
Registrant/JurisdictionFiling DateServiceRequested Revenue Requirement IncreaseApproved Revenue Requirement IncreaseApproved ROEApproval DateRate Effective Date
ComEd - Illinois
January 17, 2023(a)
Electric$1,487 $1,045 8.905%December 19, 2024January 1, 2024
April 26, 2024 (amended on September 11, 2024)(b)
Electric$624 $623 9.89%October 31, 2024January 1, 2025
PECO - PennsylvaniaMarch 28, 2024
Electric(c)(d)
$464 $354 
N/A(e)
December 12, 2024January 1, 2025
Natural Gas(d)
$111 $78 
BGE - Maryland(f)
February 17, 2023Electric$313 $179 9.50%December 14, 2023January 1, 2024
Natural Gas$289 $229 9.45%
Pepco - District of Columbia(g)
April 13, 2023 (amended February 27, 2024)Electric$186 $123 9.50%November 26, 2024January 1, 2025
Pepco - Maryland(h)
May 16, 2023 (amended February 23, 2024)Electric$111 $45 9.50%June 10, 2024April 1, 2024
DPL - Maryland(i)
May 19, 2022Electric$38 $29 9.60%December 14, 2022January 1, 2023
DPL - Delaware(j)
December 15, 2022 (amended September 29, 2023)Electric$39 $28 9.60%April 18, 2024July 15, 2023
ACE - New Jersey(k)
February 15, 2023 (amended August 21, 2023)Electric$92 $45 9.60%November 17, 2023December 1, 2023
__________
(a)Reflects a four-year cumulative multi-year rate plan for January 1, 2024 to December 31, 2027. The MRP was originally approved by the ICC on December 14, 2023 and was subsequently amended on January 10, 2024, April 18, 2024 and December 19, 2024. The December 19, 2024 order provided a total revenue requirement increase of $1.045 billion inclusive of rate increases of approximately $752 million in 2024, $80 million in 2025, $102 million in 2026, and $111 million in 2027. On March 20, 2025, ComEd filed its annual revenue balancing reconciliation for 2024. This reconciliation, which is a component of revenue decoupling, reflected a revenue reduction of $55 million, effective January 1, 2026. On April 29, 2025, ComEd filed its 2024 MRP Reconciliation reflecting a revenue increase of $268 million, which includes the tax benefit of NOLCs. While NOLCs were included in the MRP Reconciliation, the impacts of the NOLCs will not be reflected in the financial statements until the PLR is received from the IRS. See Note 6 — Income Taxes for additional information on NOLCs.
(b)On October 31, 2024, the Delivery Reconciliation Amount for 2023 defined in Rider Delivery Service Pricing Reconciliation (Rider DSPR) was approved. Rider DSPR allows for the reconciliation of the revenue requirement in effect in the final years in which formula rates are determined and until such time as new rates are established under ComEd's approved MRP. The 2024 order reconciled the delivery service rates in effect in 2023 with the actual delivery service costs incurred in 2023. The reconciliation revenue requirement provides for a weighted average debt and equity return on distribution rate base of 7.02%, inclusive of an allowed ROE of 9.89%, reflecting the monthly yields on 30-year treasury bonds plus 580 basis points.
52


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

Note 2 — Regulatory Matters
(c)PECO’s approved annual electric revenue requirement increase of $354 million is partially offset by a one-time credit of $64 million in 2025. In addition, the PAPUC approved the recovery of storm damage costs incurred by PECO in January 2024, up to $23 million, subject to review for reasonableness and prudency in PECO’s next distribution rate case.
(d)On December 12, 2024, the PAPUC issued their Opinions and Orders which approved the non-unanimous partial settlements with limited modifications for both the electric and natural gas base rate cases, and denied the Weather Normalization Adjustment requested in the natural gas base rate case.
(e)The PECO electric and natural gas base rate case proceedings were resolved through settlement agreements, which did not specify an approved ROE.
(f)Reflects a three-year cumulative multi-year plan for January 1, 2024 through December 31, 2026. The MDPSC awarded BGE electric revenue requirement increases of $41 million, $113 million, and $25 million in 2024, 2025, and 2026, respectively, and natural gas revenue requirement increases of $126 million, $62 million, and $41 million in 2024, 2025, and 2026, respectively. Requested revenue requirement increases will be used to recover capital investments designed to increase the resilience of the electric and gas distribution systems and support Maryland's climate and regulatory initiatives. The MDPSC also approved a portion of the requested 2021 and 2022 reconciliation amounts, which will be recovered through separate electric and gas riders between March 2024 through February 2025. As such, the reconciliation amounts are not included in the approved revenue requirement increases. The 2021 reconciliation amounts are $13 million and $7 million for electric and gas, respectively, and the 2022 reconciliation amounts are $39 million and $15 million for electric and gas, respectively. In April 2024, BGE filed with the MDPSC its request for recovery of the 2023 reconciliation amounts of $79 million and $73 million for electric and gas, respectively, with supporting testimony and schedules.
(g)Reflects a two-year cumulative multi-year plan for January 1, 2025, through December 31, 2026. The DCPSC awarded Pepco electric incremental revenue requirement increases of $99 million and $24 million for 2025 and 2026, respectively.
(h)Reflects the amounts requested (before offsets) and awarded for a one-year multi-year plan for April 1, 2024 through March 31, 2025. The MDPSC awarded Pepco an electric incremental revenue requirement increase of $45 million for the 12-month period ending March 31, 2025. The MDPSC did not adopt the requested revenue requirement increases of $80 million (before offsets), $51 million, and $14 million as filed for 2025, 2026, and the 2027 nine-month extension period, respectively. The MDPSC also approved the requested reconciliation amounts for the 12-month periods ending March 31, 2022, and March 31, 2023, which will be recovered through a rider between August 2024 through March 2026. As such, the reconciliation amounts are not included in the approved revenue requirement increases. The reconciliation amounts are $1 million and $7 million, for the 12-month periods ending March 31, 2022, and March 31, 2023, respectively. In July 2024, Pepco filed its request with the MDPSC for recovery of $31 million for the 12-month period ended March 31, 2024, with supporting testimony and schedules.
(i)Reflects a three-year cumulative multi-year plan for January 1, 2023 through December 31, 2025. The MDPSC awarded DPL electric incremental revenue requirement increases of $17 million, $6 million, and $6 million for 2023, 2024, and 2025, respectively.
(j)On April 18, 2024, the DEPSC approved the Significant Storm Expense Rate Rider (Rider SSER) which will allow DPL to recover expenses associated with qualified storms. A qualified storm will be an individual storm for which DPL incurs expenses between $5 million and $15 million. The Rider SSER allows DPL to recover significant storm damage expenses for the previous 12-month period over a future 24-month period. For individual storm events for which DPL incurs expenses of more than $15 million, the future recovery period will be evaluated on a case-by-case basis and the unamortized balance will earn a return at DPL's authorized long-term cost of debt. The Rider SSER will have an annual true-up filing, subject to DEPSC review and approval.
(k)Requested and approved increases are before New Jersey sales and use tax. The NJBPU awarded ACE electric revenue requirement increases of $36 million and $9 million effective December 1, 2023 and February 1, 2024, respectively.
Pending Distribution Base Rate Case Proceedings
Registrant/JurisdictionFiling DateServiceRequested Revenue Requirement IncreaseRequested ROEExpected Approval Timing
DPL - Delaware(a)
September 20, 2024 (amended February 28, 2025)Natural Gas$42 10.65%First quarter of 2026
ACE - New Jersey(b)
November 21, 2024Electric109 10.70%Fourth quarter of 2025
__________
(a)DPL implemented interim rates on April 20, 2025, subject to refund. Interim rates are not to exceed 10% of interstate operating revenues.
(b)Requested increases are before New Jersey sales and use tax. ACE intends to put rates into effect on August 21, 2025, subject to refund.
53


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

Note 2 — Regulatory Matters
Transmission Formula Rates
The Utility Registrants' transmission rates are each established based on a FERC-approved formula. ComEd, BGE, Pepco, DPL, and ACE are required to file an annual update to the FERC-approved formula on or before May 15, and PECO is required to file on or before May 31, with the resulting rates effective on June 1 of the same year. The annual update for BGE is based on prior year actual costs and current year projected capital additions, accumulated depreciation, depreciation and amortization expense, and accumulated deferred income taxes. The update for BGE also reconciles any differences between the actual costs and actual revenues for the calendar year (annual reconciliation).
For 2025, the following increase was included in the Utility Registrant's electric transmission formula rate update:
Registrant(a)
Initial Revenue Requirement IncreaseAnnual Reconciliation Increase
Total Revenue Requirement Increase(b)
Allowed Return on Rate Base(c)
Allowed ROE(d)
BGE$21 $21 $35 (e)7.53 %10.50 %
__________
(a)All rates are effective June 1, 2025 - May 31, 2026, subject to review by interested parties pursuant to review protocols of BGE's tariffs.
(b)While the transmission filing reflects the tax benefit of NOLCs, the impacts of the NOLCs will not be reflected in the financial statements until the PLR is received from the IRS. See Note 6 — Income Taxes for additional information on NOLCs.
(c)Represents the weighted average debt and equity return on transmission rate base.
(d)The rate of return on common equity for BGE includes a 50-basis-point incentive adder for being a member of an RTO.
(e)The increase in BGE's transmission revenue requirement includes a $7 million reduction related to a FERC-approved dedicated facilities charge to recover the costs of providing transmission service to specifically designated load by BGE.
Other State Regulatory Matters
Illinois Regulatory Matters
CEJA (Exelon and ComEd). On September 15, 2021, the Governor of Illinois signed into law CEJA. CEJA includes, among other features, (1) procurement of CMCs from qualifying nuclear-powered generating facilities, (2) a requirement to file a general rate case or a new four-year MRP no later than January 20, 2023 to establish rates effective after ComEd’s existing performance-based distribution formula rate sunsets, (3) requirements that ComEd and the ICC initiate and conduct various regulatory proceedings on subjects including ethics, spending, grid investments, and performance metrics.
ComEd Electric Distribution Rates
Beginning in 2024, ComEd recovers from retail customers, subject to certain exceptions, the costs it incurs to provide electric delivery services either through its electric distribution rate or other recovery mechanisms authorized by CEJA. On January 17, 2023, ComEd filed a petition with the ICC seeking approval of a MRP for 2024-2027. The MRP supports a multi-year grid plan (Grid Plan), also filed on January 17, covering planned investments on the electric distribution system within ComEd’s service area through 2027. Costs incurred during each year of the MRP are subject to ICC review and the plan’s revenue requirement for each year will be reconciled with the actual costs that the ICC determines are prudently and reasonably incurred for that year. The reconciliation is subject to adjustment for certain costs, including a limitation on recovery of costs that are more than 105% of certain costs in the previously approved MRP revenue requirement, absent a modification of the rate plan itself. Thus, for example, the rate adjustments necessary to reconcile 2024 revenues to ComEd’s actual 2024 costs incurred would take effect in January 2026 after the ICC’s review during 2025.
On December 14, 2023, the ICC issued a final order. The ICC rejected ComEd’s Grid Plan as non-compliant with certain requirements of CEJA and required ComEd to file a revised Grid Plan. In the absence of an approved Grid Plan, the ICC set ComEd’s forecast revenue requirements for 2024-2027 based on ComEd's approved year-end 2022 rate base. This resulted in a total cumulative revenue requirement increase of $501 million, a $986 million total revenue reduction from the requested cumulative revenue requirement increase but remained subject to annual reconciliation in accordance with CEJA. The final order approved the process and formulas associated with the MRP reconciliation mechanisms. The ICC's December 2023 order also denied ComEd's ability to earn a return on its pension asset.
54


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

Note 2 — Regulatory Matters
On December 22, 2023, ComEd filed an application for rehearing on several findings in the final order including the use of the 2022 year-end rate base to establish forecast revenue requirements for 2024-2027, ROE, pension asset return, and capital structure. On January 10, 2024, ComEd’s application for rehearing was denied on all issues except for the order’s use of the 2022 year-end rate base. On April 18, 2024, the ICC issued its final order on rehearing, which approved the use of the forecasted year-end 2023 rate base that resulted in increased revenue requirements for 2024-2027. These revenue requirements determined during the rehearing process established base revenue requirements until the ICC approved the Refiled Grid Plan on December 19, 2024.
On January 10, 2024, ComEd filed an appeal in the Illinois Appellate Court of the issues on which rehearing was denied, including but not limited to the allowed ROE, 50% equity ratio, and denial of a return on ComEd’s pension asset. There is no deadline by when the appellate court must rule. On March 13, 2024, ComEd filed its Refiled Grid Plan with supporting testimony and schedules with the ICC and subsequently on March 15, 2024, ComEd also filed a petition to adjust its MRP to authorize increased rates consistent with the Refiled Grid Plan. On December 19, 2024, the ICC approved the Refiled Grid Plan and adjusted the approved MRP with rates effective on January 1, 2025. The final approved MRP, as adjusted, which reflects the Refiled Grid Plan, resulted in a total cumulative revenue requirement increase of $1.045 billion over the 2024-2027 plan years and remains subject to annual reconciliations in accordance with CEJA. ComEd filed timely requests for rehearing and an appeal of the MRP order, again limited to the issues on which rehearing of the December 2023 order was denied, including the allowed ROE, 50% equity ratio, and denial of a return on ComEd's pension asset.
In January 2022, ComEd filed a request with the ICC proposing performance metrics that would be used in determining ROE incentives and penalties in the event ComEd filed a MRP in January 2023. On September 27, 2022, the ICC issued a final order approving seven performance metrics that provide symmetrical performance adjustments of 32 total basis points to ComEd’s rate of return on common equity based on the extent to which ComEd achieves the annual performance goals. On November 10, 2022, the ICC granted ComEd's application for rehearing, in part. On April 5, 2023, the ICC issued its final order on rehearing for the performance and tracking metrics proceeding, in which the ICC declined to adopt ComEd's proposed modifications to the reliability and peak load reduction performance metrics.
Carbon Mitigation Credit
CEJA establishes decarbonization requirements for Illinois as well as programs to support the retention and development of emissions-free sources of electricity. ComEd is required to purchase CMCs from participating nuclear power generating facilities between June 1, 2022 and May 31, 2027. The price to be paid for each CMC was established through a competitive bidding process that included consumer-protection measures that capped the maximum acceptable bid amount and a formula that reduces CMC prices by an energy price index, the base residual auction capacity price in the ComEd zone of PJM, and the monetized value of any federal tax credit or other subsidy if applicable. The seller has not provided notification to ComEd or the IPA that any subsidies or tax credits, such as nuclear production tax credits that became available for electricity generated beginning January 1, 2024, have been monetized and the IPA did not adjust the CMC price paid by ComEd in 2024. The consumer protection measures contained in CEJA will result in net payments to ComEd ratepayers if the energy index, the capacity price and applicable federal tax credits or subsidy exceed the CMC contract price. Beginning with the June 2022 monthly billing period, ComEd began issuing credits and/or charges to its retail customers under its CMC rider, the Rider Carbon-Free Resource Adjustment (Rider CFRA). A regulatory asset is recorded for the difference between ComEd's costs associated with the procurement of CMCs from participating nuclear power generating facilities and revenues received from customers. The balance as of March 31, 2025 is $17 million.
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 in 2023 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.
Other Federal Regulatory Matters
55


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

Note 2 — Regulatory Matters
FERC Audit (Exelon and ComEd). The Utility Registrants are subject to periodic audits and investigations by FERC. FERC’s Division of Audits and Accounting initiated a nonpublic audit of ComEd in April 2021 evaluating ComEd’s compliance with (1) approved terms, rates and conditions of its federally regulated service; (2) accounting requirements of the Uniform System of Accounts; (3) reporting requirements of the FERC Form 1; and (4) the requirements for record retention. The audit period extended back to January 1, 2017.
On July 27, 2023, FERC published a final audit report which included, among other things, findings and recommendations related to ComEd's methodology regarding the allocation of certain overhead costs to capitalized construction costs under FERC regulations, including a suggestion that refunds may be due to customers for amounts collected in previous years. ComEd responded to that report and on August 28, 2023, ComEd filed a formal notice of the issues it contested within the audit report. On December 14, 2023, FERC appointed a settlement judge for the contested overhead allocation findings and set the matter for a trial-type hearing. That hearing process was held in abeyance while a formal settlement process, which began in February 2024, took place.
On July 30, 2024, ComEd reached an agreement in principle on the contested overhead allocation finding. As a result of the settlement process, ComEd recorded a charge for the probable disallowance of $70 million of certain currently capitalized construction costs to operating expenses, which are not expected to be recovered in future rates. The existing loss estimate was reflected in Exelon and ComEd's financial statements as of December 31, 2024. ComEd and FERC staff jointly filed the settlement agreement with FERC for approval on February 11, 2025. The settlement was approved by FERC on April 4, 2025.
Regulatory Assets and Liabilities
The Utility Registrants' regulatory assets and liabilities have not changed materially since December 31, 2024, unless noted below. See Note 3 — Regulatory Matters of the 2024 Form 10-K for additional information on the specific regulatory assets and liabilities.
PECO. Regulatory assets increased $61 million primarily due to an increase of $71 million in the Deferred Income Taxes regulatory asset. Regulatory liabilities increased $93 million primarily due to an increase of $64 million in the Decommissioning the Regulatory Agreement Units and an increase of $32 million in the Electric energy and natural gas costs regulatory liabilities.
ACE. Regulatory liabilities increased $10 million primarily due to an increase of $8 million in the Transmission formula rate annual reconciliations regulatory liability.
Capitalized Ratemaking Amounts Not Recognized
The following table presents authorized amounts capitalized for ratemaking purposes related to earnings on shareholders' investment that are not recognized for financial reporting purposes in the Registrants' Consolidated Balance Sheets. These amounts will be recognized as revenues in the related Consolidated Statements of Operations and Comprehensive Income in the periods they are billable to the Utility Registrants' customers. PECO had no related amounts at March 31, 2025 and December 31, 2024.
Exelon
ComEd(a)
BGE(b)
PHI
Pepco(c)
DPL(d)
ACE(e)
March 31, 2025$87 $38 $9 $40 $24 $1 $15 
December 31, 2024117 46 16 55 40 1 14 
__________
(a)Reflects ComEd's unrecognized equity returns earned for ratemaking purposes on its electric distribution rates and formula rates regulatory assets.
(b)BGE's amount capitalized for ratemaking purposes primarily relates to earnings on shareholders' investment on AMI programs and investments in rate base included in the multi-year plan reconciliations.
(c)Pepco's authorized amounts capitalized for ratemaking purposes relate to earnings on shareholders' investment on AMI programs, Energy efficiency and demand response programs, investments in rate base and revenues included in the multi-year plan reconciliations, and a portion of Pepco District of Columbia's revenue decoupling.
(d)DPL's authorized amounts capitalized for ratemaking purposes relate to earnings on shareholders' investment on AMI programs and Energy efficiency and demand response programs.
(e)ACE's authorized amounts capitalized for ratemaking purposes primarily relate to earnings on shareholders' investment on AMI programs.
56


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

Note 3 — Revenue from Contracts with Customers
3. Revenue from Contracts with Customers (All Registrants)
The Registrants recognize revenue from contracts with customers to depict the transfer of goods or services to customers at an amount that the entities expect to be entitled to in exchange for those goods or services. The primary sources of revenue include regulated electric and gas tariff sales, distribution, and transmission services.
See Note 4 — Revenue from Contracts with Customers of the 2024 Form 10-K for additional information regarding the primary sources of revenue for the Registrants.
Contract Liabilities
The Registrants record contract liabilities when consideration is received or due prior to the satisfaction of the performance obligations. The Registrants record contract liabilities in Other current liabilities and Other noncurrent deferred credits and other liabilities in their Consolidated Balance Sheets.
For Pepco, DPL, and ACE these contract liabilities primarily relate to upfront consideration received in the third quarter of 2020 for a collaborative arrangement ("Agreement") with an unrelated owner and manager of communication infrastructure, as well as additional consideration received for the payment option amendment ("Amendment") executed during the fourth quarter of 2023, which is discussed in further detail within Note 4 — Revenue from Contracts with Customers of the 2024 Form 10-K. The contract liability balance attributable to the Agreement and the Amendment is being recognized as Electric operating revenues over a 35 year period and 31 year period, respectively.
The following table provides a rollforward of the contract liabilities reflected in Exelon's, PHI's, Pepco's, DPL's, and ACE's Consolidated Balance Sheets for the three months ended March 31, 2025 and 2024. At March 31, 2025 and December 31, 2024, ComEd's, PECO's, and BGE's contract liabilities were immaterial.
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 
Exelon(a)
PHI(a)
Pepco(a)
DPLACE
Balance at December 31, 2023$133 $133 $107 $13 $13 
Revenues recognized(2)(2)(2)— — 
Balance at March 31, 2024$131 $131 $105 $13 $13 
__________
(a)Revenues recognized in the three months ended March 31, 2025 and 2024, were included in the contract liabilities at December 31, 2024 and 2023, respectively.
Transaction Price Allocated to Remaining Performance Obligations
The following table shows the amounts of future revenues expected to be recorded in each year for performance obligations that are unsatisfied or partially unsatisfied as of March 31, 2025. This disclosure only includes contracts for which the total consideration is fixed and determinable at contract inception. The average contract term varies by customer type and commodity but ranges from one month to several years.
This disclosure excludes the Utility Registrants' gas and electric tariff sales contracts and transmission revenue contracts as they generally have an original expected duration of one year or less and, therefore, do not contain any future, unsatisfied performance obligations to be included in this disclosure.
57


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

Note 3 — Revenue from Contracts with Customers
YearExelonPHIPepcoDPLACE
2025$4 $4 $4 $— $— 
20266 6 5 1 — 
20275 5 5 — — 
20285 5 5 — — 
2029 and thereafter106 106 81 12 13 
Total$126 $126 $100 $13 $13 
Revenue Disaggregation
The Registrants disaggregate revenue recognized from contracts with customers into categories that depict how the nature, amount, timing, and uncertainty of revenue and cash flows are affected by economic factors. See Note 4 — Segment Information for the presentation of the Registrants' revenue disaggregation.
4. Segment Information (All Registrants)
Operating segments for each of the Registrants are determined based on information used by the CODMs in deciding how to evaluate performance and allocate resources at each of the Registrants. The Chief Executive Officer is the CODM for Exelon. For PHI and each of the Utility Registrants, CODM responsibilities are shared by Exelon's Chief Operating Officer and the Utility Registrant's Chief Executive Officer.
Exelon has six reportable segments, which include ComEd, PECO, BGE, and PHI's three reportable segments consisting of Pepco, DPL, and ACE. ComEd, PECO, BGE, Pepco, DPL, and ACE each represent a single reportable segment, and as such, no separate segment information is provided for these Registrants. Exelon, ComEd, PECO, BGE, PHI, Pepco, DPL, and ACE's CODMs rely on a variety of business considerations, including net income, in evaluating segment performance, determining reinvestment of profits, and establishing the amounts of dividend distributions.
An analysis and reconciliation of the Registrants’ reportable segment information to the respective information in the consolidated financial statements for the three months ended March 31, 2025 and 2024 is as follows:
ComEdPECOBGEPHI
Other(a)
Intersegment
Eliminations		Exelon
Operating revenues(b):
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 
2024
Electric revenues$2,095 $782 $881 $1,532 $— $(6)$5,284 
Natural gas revenues— 272 416 72 — (1)759 
Shared service and other revenues— — — 2 459 (461)— 
Total operating revenues$2,095 $1,054 $1,297 $1,606 $459 $(468)$6,043 
Less:
Purchased power
2025$689 $361 $450 $684 $— $— $2,184 
2024907 306 377 607 — — 2,197 
Purchased fuel
2025$— $141 $159 $38 $— $— $338 
2024— 97 87 29 — — 213 
58


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

Note 4 — Segment Information
ComEdPECOBGEPHI
Other(a)
Intersegment
Eliminations		Exelon
Operating and maintenance
2025$323 $266 $242 $296 $429 $(209)$1,347 
2024318 235 205 274 438 (199)1,271 
Operating and maintenance from affiliates
2025$100 $61 $63 $53 $11 $(288)$— 
2024100 58 59 51 9 (277)— 
Depreciation and amortization
2025$380 $109 $164 $234 $16 $— $903 
2024362 104 150 246 17 — 879 
Taxes other than income taxes
2025$99 $60 $96 $140 $10 $— $405 
202494 51 89 128 9 — 371 
(Gain) loss on sale of assets
2025$— $— $— $1 $— $— $1 
2024— (2)— — — — (2)
Interest expense, net(c)
2025$125 $59 $58 $99 $163 $— $504 
2024119 52 50 90 151 — 462 
Interest expense from affiliates, net(c)
2025$3 $4 $— $1 $(1)$(1)$6 
20243 3 — — — — 6 
Other, net
2025$(21)$(8)$(9)$(19)$(11)$16 $(52)
2024(20)(9)(8)(27)(19)8 (75)
Income taxes
2025$65 $14 $71 $57 $(37)$— $170 
202419 10 24 40 (30)— 63 
Net income (loss) attributable to common shareholders
2025$302 $266 $260 $194 $(114)$— $908 
2024193 149 264 168 (116)— 658 
Supplemental segment information
Intersegment revenues(d)
2025$8 $3 $2 $2 $463 $(478)$— 
20242 2 2 3 457 (466)— 
Capital expenditures
2025$590 $424 $406 $513 $13 $— $1,946 
2024594 361 324 453 35 — 1,767 
Total assets
March 31, 2025$45,199 $17,789 $15,677 $28,349 $6,530 $(4,060)$109,484 
December 31, 202444,750 17,123 15,542 28,297 6,012 (3,940)107,784 
__________
(a)Other primarily includes Exelon’s corporate operations, shared service entities, and other financing and investment activities.
(b)Includes gross utility tax receipts from customers. The offsetting remittance of utility taxes to the governing bodies is recorded in Taxes other than income taxes in the Registrants’ Consolidated Statements of Operations and Comprehensive Income. See Note 14 — Supplemental Financial Information for additional information on total utility taxes.
59


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

Note 4 — Segment Information
(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):
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 
2024
Electric revenues$759 $419 $358 $— $(4)$1,532 
Natural gas revenues— 72 — — — 72 
Shared service and other revenues— — — 109 (107)2 
Total operating revenues$759 $491 $358 $109 $(111)$1,606 
Less:
Purchased power
2025$318 $209 $157 $— $— $684 
2024281 186 140 — — 607 
Purchased fuel
2025$— $38 $— $— $— $38 
2024— 29 — — — 29 
Operating and maintenance
2025$96 $60 $51 $89 $— $296 
202486 51 47 90 — 274 
Operating and maintenance from affiliates
2025$63 $46 $39 $13 $(108)$53 
202464 44 40 14 (111)51 
Depreciation and amortization
2025$105 $63 $64 $2 $— $234 
2024107 61 74 4 — 246 
Taxes other than income taxes
2025$113 $21 $2 $4 $— $140 
2024102 20 2 4 — 128 
Loss on sale of assets
2025$1 $— $— $— $— $1 
2024— — — — — — 
Interest expense, net(c)
2025$52 $25 $21 $1 $— $99 
202445 22 20 3 — 90 
Interest expense to affiliates, net(c)
2025$— $— $— $1 $— $1 
2024— — — — — — 
Other, net
2025$(11)$(4)$(3)$(1)$— $(19)
2024(15)(5)(5)(2)— (27)
60


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

Note 4 — Segment Information
Income taxes
2025$25 $21 $11 $— $— $57 
202414 17 11 (2)— 40 
Net income (loss) attributable to common shareholders
2025$97 $69 $31 $(3)$— $194 
202475 66 29 (2)— 168 
Supplemental segment information
Intersegment revenues(d)
2025$2 $2 $1 $106 $(109)$2 
20242 2 1 109 (111)3 
Capital expenditures
2025$240 $156 $105 $12 $— $513 
2024229 134 89 1 — 453 
Total assets
March 31, 2025$12,011 $6,484 $5,387 $4,521 $(54)$28,349 
December 31, 202412,000 6,421 5,349 4,567 (40)28,297 
__________
(a)Other primarily includes PHI’s corporate operations, shared service entities, and other financing and investment activities.
(b)Includes gross utility tax receipts from customers. The offsetting remittance of utility taxes to the governing bodies is recorded in Taxes other than income taxes in the Registrants’ Consolidated Statements of Operations and Comprehensive Income. See Note 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.
61


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 
62


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, 2024
Revenues from contracts with customersComEdPECOBGEPHIPepcoDPLACE
Electric revenues
Residential$918 $520 $534 $775 $345 $256 $174 
Small commercial & industrial594 126 90 158 46 62 50 
Large commercial & industrial320 57 132 340 262 29 49 
Public authorities & electric railroads17 7 7 20 11 4 5 
Other(a)
227 74 93 192 64 63 67 
Total electric revenues(b)
$2,076 $784 $856 $1,485 $728 $414 $345 
Natural gas revenues
Residential$— $193 $271 $46 $— $46 $— 
Small commercial & industrial— 64 47 17 — 17 — 
Large commercial & industrial— — 72 2 — 2 — 
Transportation— 8 — 5 — 5 — 
Other(c)
— 7 5 2 — 2 — 
Total natural gas revenues(d)
$— $272 $395 $72 $— $72 $— 
Total revenues from contracts with customers$2,076 $1,056 $1,251 $1,557 $728 $486 $345 
Other revenues
Revenues from alternative revenue programs$19 $(2)$43 $46 $29 $4 $13 
Other electric revenues(e)
— — 2 3 2 1 — 
Other natural gas revenues(e)
— — 1 — — — — 
Total other revenues$19 $(2)$46 $49 $31 $5 $13 
Total revenues for reportable segments$2,095 $1,054 $1,297 $1,606 $759 $491 $358 
__________
(a)Includes transmission revenue from PJM, wholesale electric revenue, and mutual assistance revenue.
(b)Includes operating revenues from affiliates in 2025 and 2024 respectively of:
•$8 million, $2 million at ComEd
•$2 million, $2 million at PECO
•$1 million, $1 million at BGE
•$2 million, $3 million at PHI
•$2 million, $2 million at Pepco
•$2 million, $2 million at DPL
•$1 million, $1 million at ACE
(c)Includes revenues from off-system natural gas sales.
(d)Includes operating revenues from affiliates in 2025 and 2024 respectively of:
•$1 million, less than $1 million at PECO
•$1 million, $1 million at BGE
(e)Includes late payment charge revenues.

63


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, 2025
ExelonComEdPECOBGEPHIPepcoDPLACE
Balance at December 31, 2024$406 $109 $133 $56 $108 $59 $17 $32 
Plus: Current period provision for expected credit losses(a)
133 33 41 23 36 17 10 9 
Less: Write-offs(b), net of recoveries(c)
53 17 14 7 15 7 4 4 
Balance at March 31, 2025$486 $125 $160 $72 $129 $69 $23 $37 
Three Months Ended March 31, 2024
ExelonComEdPECOBGEPHIPepcoDPLACE
Balance at December 31, 2023$317 $69 $95 $46 $107 $52 $19 $36 
Plus: Current period provision for expected credit losses
79 22 23 15 19 12 3 4 
Less: Write-offs, net of recoveries
50 9 11 9 21 12 5 4 
Balance at March 31, 2024$346 $82 $107 $52 $105 $52 $17 $36 
_________
(a)For ComEd, PECO, BGE, Pepco, DPL, and ACE, the increase is primarily a result of increased receivable balances.
(b)For Pepco, the decrease is primarily attributable to favorable customer payment behavior.
(c)Recoveries were not material to the Registrants.
The following tables present the rollforward of Allowance for Credit Losses on Other Accounts Receivable.
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(a)
15 2 9 1 3 — — 3 
Less: Write-offs(b), net of recoveries(c)
9 2 5 1 1 — — 1 
Balance at March 31, 2025$113 $34 $22 $6 $51 $27 $9 $15 
Three Months Ended March 31, 2024
ExelonComEdPECOBGEPHIPepcoDPLACE
Balance at December 31, 2023$82 $17 $8 $7 $50 $28 $8 $14 
Plus: Current period provision for expected credit losses
18 3 5 2 8 7 — 1 
Less: Write-offs, net of recoveries
4 1 — 2 1 — — 1 
Balance at March 31, 2024$96 $19 $13 $7 $57 $35 $8 $14 
_________
(a)For Pepco, the decrease is primarily a result of changes in customer risk profile.
(b)For PECO, the increase is primarily a result of increased terminations.
(c)Recoveries were not material to the Registrants.
64


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, 2025 and December 31, 2024.
Unbilled customer revenues(a)
ExelonComEdPECOBGEPHIPepcoDPLACE
March 31, 2025$961 $366 $235 $171 $189 $95 $51 $43 
December 31, 20241,114 335 254 257 268 121 76 71 
__________
(a)Unbilled customer revenues are classified in Customer accounts receivable, net in the Registrants' Consolidated Balance Sheets.
Other Purchases of Customer and Other Accounts Receivables
For the three months ended March 31, 2025 and 2024, the Utility Registrants were required, under separate legislation and regulations in Illinois, Pennsylvania, Maryland, District of Columbia, Delaware, and New Jersey, to purchase certain receivables from alternative retail electric and, as applicable, natural gas suppliers that participated in the utilities' consolidated billing. The following table presents the total receivables purchased.
Total receivables purchased
ExelonComEdPECOBGEPHIPepcoDPLACE
Three months ended March 31, 2025$1,138 $253 $334 $225 $326 $201 $68 $57 
Three months ended March 31, 20241,060 235 297 219 309 194 60 55 
65


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

Note 6 — Income Taxes
6. Income Taxes (All Registrants)
Rate Reconciliation
The effective income tax rate from continuing operations varies from the U.S. federal statutory rate principally due to the following:
Three Months Ended March 31, 2025(a)
Exelon
ComEd(b)
PECO(c)
BGEPHIPepcoDPLACE
U.S. Federal statutory rate21.0 %21.0 %21.0 %21.0 %21.0 %21.0 %21.0 %21.0 %
Increase (decrease) due to:
State income taxes, net of federal income tax benefit
5.1 7.6 (3.5)6.2 6.5 6.4 6.4 7.0 
Plant basis differences(3.8)(1.0)(11.1)(1.5)(0.7)(1.0)(0.5)(0.3)
Excess deferred tax amortization(6.5)(9.4)(1.6)(4.1)(3.9)(5.3)(3.3)(1.4)
Amortization of investment tax credit, including deferred taxes on basis difference— (0.1)— — — — (0.1)(0.1)
Tax credits(0.5)(0.7)— (0.3)(0.3)(0.3)(0.3)(0.3)
Other0.5 0.3 0.2 0.2 0.1 (0.3)0.1 0.3 
Effective income tax rate15.8 %17.7 %5.0 %21.5 %22.7 %20.5 %23.3 %26.2 %
Three Months Ended March 31, 2024(a)
Exelon
ComEd(d)
PECO(c)
BGE(d)
PHI
Pepco
DPL
ACE
U.S. Federal statutory rate21.0 %21.0 %21.0 %21.0 %21.0 %21.0 %21.0 %21.0 %
Increase (decrease) due to:
State income taxes, net of federal income tax benefit
6.4 7.8 (0.6)6.3 6.4 6.2 6.2 7.1 
Plant basis differences(3.8)(0.9)(12.2)(1.2)(0.9)(1.3)(1.1)0.1 
Excess deferred tax amortization(14.7)(18.9)(2.3)(17.5)(6.8)(9.9)(5.4)(1.3)
Amortization of investment tax credit, including deferred taxes on basis difference(0.1)(0.1)— — (0.1)— (0.1)(0.1)
Tax credits(0.4)(0.3)— (0.4)(0.3)(0.3)(0.3)(0.3)
Other
0.3 0.4 0.4 0.1 (0.1)— 0.2 1.0 
Effective income tax rate8.7 %9.0 %6.3 %8.3 %19.2 %15.7 %20.5 %27.5 %
__________
(a)Positive percentages represent income tax expense. Negative percentages represent income tax benefit.
(b)For ComEd, the lower effective tax rate is primarily due to CEJA which resulted in the acceleration of certain income tax benefits.
(c)For PECO, the lower effective tax rate is primarily related to plant basis differences attributable to tax repair deductions.
(d)For ComEd, the lower effective tax rate is primarily due to CEJA which resulted in the acceleration of certain income tax benefits. For BGE, the lower effective tax rate is primarily due to the Maryland multi-year plan which resulted in the acceleration of certain income tax benefits.
66


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

Note 6 — Income Taxes
Unrecognized Tax Benefits
Exelon, PHI and DPL have the following unrecognized tax benefits at March 31, 2025 and December 31, 2024. ComEd's, PECO's, BGE's, Pepco's, and ACE's amounts are not material.
Exelon(a)
PHIDPL
March 31, 2025$100 $51 $15 
December 31, 202496 48 12 
__________
(a)At March 31, 2025 and December 31, 2024, Exelon's unrecognized tax benefits is inclusive of $31 million related to Constellation's share of unrecognized tax benefits for periods prior to the separation. Exelon reflected an offsetting receivable of $31 million in Other deferred debits and other assets in the Consolidated Balance Sheet for these amounts.
Other Tax Matters
Tax Matters Agreement (Exelon)
In connection with the separation, Exelon entered into a TMA with Constellation. The TMA governs the respective rights, responsibilities, and obligations between Exelon and Constellation after the separation with respect to tax liabilities, refunds and attributes for open tax years that Constellation was part of Exelon’s consolidated group for U.S. federal, state, and local tax purposes.
Indemnification for Taxes. As a former subsidiary of Exelon, Constellation has joint and several liability with Exelon to the IRS and certain state jurisdictions relating to the taxable periods prior to the separation. The TMA specifies that Constellation is liable for their share of taxes required to be paid by Exelon with respect to taxable periods prior to the separation to the extent Constellation would have been responsible for such taxes under the existing Exelon tax sharing agreement. At March 31, 2025, there is no balance due to or from Constellation.
Tax Refunds. The TMA specifies that Constellation is entitled to their share of any future tax refunds claimed by Exelon with respect to taxable periods prior to the separation to the extent that Constellation would have received such tax refunds under the existing Exelon tax sharing agreement. At March 31, 2025, there is no balance due to or from Constellation.
Tax Attributes. At the date of separation certain tax attributes, primarily pre-closing tax credit carryforwards, that were generated by Constellation were required by law to be allocated to Exelon. The TMA also provides that Exelon will reimburse Constellation when those allocated tax attribute carryforwards are utilized. At March 31, 2025, Exelon recorded a payable of $141 million and $198 million in Other current liabilities and Other deferred credits and other liabilities, respectively, in the Consolidated Balance Sheet for tax attribute carryforwards that are expected to be utilized and reimbursed to Constellation.
Corporate Alternative Minimum Tax (All Registrants)
On August 16, 2022, the IRA was signed into law and implements a new corporate alternative minimum tax (CAMT) that imposes a 15.0% tax on modified GAAP net income. Corporations are entitled to a tax credit (minimum tax credit) to the extent the CAMT liability exceeds the regular tax liability. This amount can be carried forward indefinitely and used in future years when regular tax exceeds the CAMT.
Beginning in 2023, based on the existing statute, Exelon and each of the Utility Registrants will be subject to and will report the CAMT on a separate Registrant basis in the Consolidated Statements of Operations and Comprehensive Income and the Consolidated Balance Sheets. The deferred tax asset related to the minimum tax credit carryforward will be realized to the extent Exelon’s consolidated deferred tax liabilities exceed the minimum tax credit carryforward. Exelon’s deferred tax liabilities are expected to exceed the minimum tax credit carryforward for the foreseeable future and thus no valuation allowance is required.
On September 12, 2024, the U.S. Treasury issued proposed regulations providing further guidance addressing the implementation of CAMT. The proposed regulations are consistent with Exelon’s prior interpretation and therefore there are no financial statement impacts. Exelon will continue to monitor and assess the potential financial statement impacts of final regulations or other guidance when issued.
67


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

Note 6 — Income Taxes
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 2025 pension benefit cost for the Exelon-sponsored plans is calculated using an expected long-term rate of return on plan assets of 7.00% and a discount rate of 5.68%. The majority of the 2025 OPEB cost is calculated using an expected long-term rate of return on plan assets of 6.50% for funded plans and a discount rate of 5.64%.
During the first quarter of 2025, Exelon received an updated valuation of its pension and OPEB to reflect actual census data as of January 1, 2025. This valuation resulted in an increase to the pension obligation of $1 million and an increase to the OPEB obligation and asset of $6 million and $2 million, respectively. Additionally, AOCI decreased by $5 million (after-tax) and regulatory assets increased by $8 million and liabilities decreased by $3 million.
A portion of the net periodic benefit cost for all plans is capitalized within the Consolidated Balance Sheets. The following table presents the components of Exelon's net periodic benefit costs, prior to capitalization, for the three months ended March 31, 2025 and 2024.

Pension BenefitsOPEB
Three Months Ended March 31,Three Months Ended March 31,
2025202420252024
Components of net periodic benefit cost
Service cost$38 $42 $6 $7 
Interest cost146 141 25 24 
Expected return on assets(178)(184)(21)(21)
Amortization of:
Prior service cost (credit)1 1 (2)(2)
Actuarial loss53 53 — — 
Net periodic benefit cost$60 $53 $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.
68


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

Note 7 — Retirement Benefits
 Three Months Ended March 31,
Pension and OPEB Costs20252024
Exelon$68 $61 
ComEd21 17 
PECO2 — 
BGE16 15 
PHI25 23 
Pepco8 9 
DPL4 4 
ACE3 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, 2025 and 2024.
Three Months Ended March 31,
Savings Plan Employer Contributions20252024
Exelon$26 $22 
ComEd10 10 
PECO4 3 
BGE3 3 
PHI5 2 
Pepco1 1 
DPL1 1 
ACE1 — 
8. Derivative Financial Instruments (All Registrants)
The Registrants use derivative instruments to manage commodity price risk and interest rate risk related to ongoing business operations. The Registrants do not execute derivatives for speculative or proprietary trading purposes.
Authoritative guidance requires that derivative instruments be recognized as either assets or liabilities at fair value, with changes in fair value of the derivative recognized in earnings immediately. Other accounting treatments are available through special election and designation, provided they meet specific, restrictive criteria both at the time of designation and on an ongoing basis. These alternative permissible accounting treatments include NPNS, cash flow hedges, and fair value hedges. At ComEd, derivative economic hedges related to commodities are recorded at fair value and offset by a corresponding regulatory asset or liability. For all NPNS derivative instruments, accounts receivable or accounts payable are recorded when derivatives settle and revenue or expense is recognized in earnings as the underlying physical commodity is sold or consumed. At Exelon, derivative hedges that qualify and are designated as cash flow hedges are recorded at fair value and offsets are recorded to AOCI.
Commodity Price Risk
The Utility Registrants employ established policies and procedures to manage their risks associated with market fluctuations in commodity prices by entering into physical and financial derivative contracts, which are either determined to be non-derivative or classified as economic hedges. The Utility Registrants procure electric and natural gas supply through a competitive procurement process approved by each of the respective state utility commissions. The Utility Registrants’ hedging programs are intended to reduce exposure to energy and natural gas price volatility and have no direct earnings impact as the costs are fully recovered from customers through
69


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

Note 8 — Derivative Financial Instruments
regulatory-approved recovery mechanisms. The following table provides a summary of the Utility Registrants’ primary derivative hedging instruments, listed by commodity and accounting treatment.
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 3 — Regulatory Matters of the 2024 Form 10-K for additional information.
(b)The fair value of the DPL economic hedge is not material at March 31, 2025 and December 31, 2024.
The fair value of derivative economic hedges is presented in Other current assets and current and noncurrent Mark-to-market derivative liabilities in Exelon's and ComEd's Consolidated Balance Sheets.
Interest Rate Risk (Exelon)
Exelon Corporate uses a combination of fixed-rate and variable-rate debt to manage interest rate exposure. Exelon Corporate may utilize interest rate derivatives to lock in rate levels in anticipation of future financings, which are typically designated as cash flow hedges. A hypothetical 50 basis point change in the interest rates associated with Exelon's interest rate swaps as of March 31, 2025 would result in an immaterial impact to Exelon's Consolidated Net Income.
70


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

Note 8 — Derivative Financial Instruments
Below is a summary of the interest rate hedge balances at March 31, 2025 and December 31, 2024.
Derivatives Designated
as Hedging Instruments
March 31, 2025December 31, 2024
Other current assets$— $14 
Other deferred debits (noncurrent assets)4 12 
Total derivative assets4 26 
Mark-to-market derivative liabilities (current liabilities)— (1)
Mark-to-market derivative liabilities (noncurrent liabilities)(4)— 
Total mark-to-market derivative liabilities(4)(1)
Total mark-to-market derivative net assets$— $25 
Cash Flow Hedges (Interest Rate Risk)
For derivative instruments that qualify and are designated as cash flow hedges, the changes in fair value each period are initially recorded in AOCI and reclassified into earnings when the underlying transaction affects earnings.
In February 2025, Exelon terminated the previously issued floating-to-fixed swaps with a total notional of $765 million upon issuance of $1 billion of debt. See Note 9 – Debt and Credit Agreements for additional information on the debt issuance. The settlements resulted in a cash receipt of $16 million. The accumulated AOCI gain of $13 million (net of tax) is being amortized into Interest expense in Exelon's Consolidated Statement of Operations and Comprehensive Income over the 5-year and 10-year terms of the swaps. The following table provides the notional amounts outstanding held by Exelon at March 31, 2025 and December 31, 2024.
March 31, 2025December 31, 2024
5-year maturity floating-to-fixed swaps$275 $657 
10-year maturity floating-to-fixed swaps275 658 
Total$550 $1,315 
The related AOCI derivative loss for the three months ended March 31, 2025 was $9 million (net of tax). The related AOCI derivative gain for the three months ended March 31, 2024 was immaterial. See Note 13 – Changes in Accumulated Other Comprehensive Income (Loss) for additional information.
Credit Risk
The Registrants would be exposed to credit-related losses in the event of non-performance by counterparties on executed derivative instruments. The credit exposure of derivative contracts, before collateral, is represented by the fair value of contracts at the reporting date. The Utility Registrants have contracts to procure electric and natural gas supply that provide suppliers with a certain amount of unsecured credit. If the exposure on the supply contract exceeds the amount of unsecured credit, the suppliers may be required to post collateral. The net credit exposure is mitigated primarily by the ability to recover procurement costs through customer rates. The amount of cash collateral received from external counterparties remained relatively consistent as of March 31, 2025. Cash collateral held by ComEd, PECO, BGE, Pepco, DPL, and ACE must be deposited in an unaffiliated major U.S. commercial bank or foreign bank with a U.S. branch office that meets certain qualifications. The following table reflects the Registrants' cash collateral held from external counterparties, which is recorded in Other current liabilities on their respective Consolidated Balance Sheets, as of March 31, 2025 and December 31, 2024:
71


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

Note 8 — Derivative Financial Instruments
March 31, 2025December 31, 2024
Exelon$225 $181 
ComEd181 176 
PECO(a)
12 — 
BGE1 1 
PHI31 4 
Pepco11 1 
DPL11 2 
ACE(a)
6 — 
__________
(a)PECO and ACE had less than one million in cash collateral held from external parties at December 31, 2024.
The Utility Registrants’ electric supply procurement contracts do not contain provisions that would require them to post collateral. PECO’s, BGE’s, and DPL’s natural gas procurement contracts contain provisions that could require PECO, BGE, and DPL to post collateral in the form of cash or credit support, which vary by contract and counterparty. As of March 31, 2025, PECO, BGE, and DPL were not required to post collateral for any of these agreements. If PECO, BGE, or DPL lost their investment grade credit rating as of March 31, 2025, they could have been required to post collateral to their counterparties of $45 million, $51 million, and $15 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, 2025 and December 31, 2024.
Outstanding Commercial
Paper at		Average Interest Rate on
Commercial Paper Borrowings at
Commercial Paper IssuerMarch 31, 2025December 31, 2024March 31, 2025December 31, 2024
Exelon(a)
$584 $1,359 4.62 %4.66 %
ComEd$347 $36 4.61 %4.55 %
PECO$— $192 — %4.65 %
BGE$237 $175 4.63 %4.61 %
PHI(b)
$— $530 — %4.70 %
Pepco$— $200 — %4.69 %
DPL$— $144 — %4.74 %
ACE$— $186 — %4.67 %
__________
(a)Exelon Corporate had no outstanding commercial paper borrowings at March 31, 2025 and $426 million in outstanding commercial paper borrowings at December 31, 2024.
(b)Represents the consolidated amounts of Pepco, DPL, and ACE.
72


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

Note 9 — Debt and Credit Agreements
Revolving Credit Agreements
On August 29, 2024, Exelon Corporate and each of the Utility Registrants amended and restated their respective syndicated revolving credit facility, extending the maturity date to August 29, 2029. The following table reflects the credit agreements:
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, 2025.
The Utility Registrants have credit facility agreements, arranged at community banks, which may be utilized to issue letters of credit. The facility agreements have aggregate commitments of $40 million, $40 million, $15 million, $15 million, $15 million, and $15 million, at ComEd, PECO, BGE, Pepco, DPL, and ACE, respectively. These facilities expire on October 3, 2025.
See Note 16 — Debt and Credit Agreements of the 2024 Form 10-K for additional information on the Registrants' credit facilities.
Short-Term Loan Agreements
On March 14, 2024, Exelon Corporate amended and bifurcated the $500 million term loan agreement into two tranches of $350 million and $150 million. The loan agreements were renewed in the first quarter of 2025, extending the expiration date to March 13, 2026. Pursuant to the loan agreements, loans made thereunder bear interest at a variable rate equal to SOFR plus 1.00% and all indebtedness thereunder is unsecured. The loan agreements are reflected in Exelon's Consolidated Balance Sheets within Short-term borrowings.


















73


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

Note 9 — Debt and Credit Agreements
Long-Term Debt
Issuance of Long-Term Debt
During the three months ended March 31, 2025, the following long-term debt was issued:
CompanyTypeInterest RateMaturityAmountUse of Proceeds
Exelon
Junior Subordinated Notes(a)
6.50%March 15, 2055$1,000Repay outstanding commercial paper obligations, and for general corporate purposes.
ExelonNotes5.125%March 15, 2031$500Repay outstanding commercial paper obligations, and for general corporate purposes.
ExelonNotes5.875%March 15, 2055$500Repay outstanding commercial paper obligations, and for general corporate purposes.
Pepco(b)
First Mortgage Bonds5.48%March 26, 2040$200Repay existing indebtedness and for general corporate purposes.
DPLFirst Mortgage Bonds5.28%March 26, 2035$125Repay existing indebtedness and for general corporate purposes.
ACE(c)
First Mortgage Bonds5.28%March 26, 2035$100Repay existing indebtedness and for general corporate purposes.
__________
(a)The Junior Subordinated Notes bear interest at 6.50% per annum, commencing February 19, 2025 to, but excluding March 15, 2035. Thereafter, the interest rate resets every five years on March 15 and will be set at a rate per annum equal to the Five-year U.S. Treasury Rate plus a spread of 1.975%.
(b)On March 26, 2025, Pepco entered into a purchase agreement of First Mortgage Bonds of $75 million at 5.78% due on September 17, 2055. The closing date of the issuance is expected to occur in September 2025.
(c)On March 26, 2025, ACE entered into a purchase agreement of First Mortgage Bonds of $75 million and $75 million at 5.54% and 5.81% due on November 19, 2040 and November 19, 2055, respectively. The closing date of the issuance is expected to occur in November 2025.
Debt Covenants
As of March 31, 2025, the Registrants are in compliance with debt covenants.
10. Fair Value of Financial Assets and Liabilities (All Registrants)
Exelon measures and classifies fair value measurements in accordance with the hierarchy as defined by GAAP. The hierarchy prioritizes the inputs to valuation techniques used to measure fair value into three levels as follows:
•Level 1 — quoted prices (unadjusted) in active markets for identical assets or liabilities that the Registrants have the ability to liquidate as of the reporting date.
•Level 2 — inputs other than quoted prices included within Level 1 that are directly observable for the asset or liability or indirectly observable through corroboration with observable market data.
•Level 3 — unobservable inputs, such as internally developed pricing models or third-party valuations for the asset or liability due to little or no market activity for the asset or liability.
Exelon’s valuation techniques used to measure the fair value of the assets and liabilities shown in the tables below are in accordance with the policies discussed in Note 17 — Fair Value of Financial Assets and Liabilities of the 2024 Form 10-K.
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, 2025 and December 31, 2024. The Registrants have no financial liabilities measured using the NAV practical expedient.
The carrying amounts of the Registrants’ short-term liabilities as presented in their Consolidated Balance Sheets are representative of their fair value (Level 2) because of the short-term nature of these instruments.
March 31, 2025December 31, 2024
Carrying AmountFair ValueCarrying AmountFair Value
Level 1Level 2Level 3TotalLevel 1Level 2Level 3Total
Long-Term Debt, including amounts due within one year(a)
Exelon$46,796 $— $37,601 $4,159 $41,760 $44,400 $— $35,337 $3,720 $39,057 
ComEd12,031 — 10,330 — 10,330 12,030 — 10,260 — 10,260 
PECO5,704 — 4,827 — 4,827 5,704 — 4,816 — 4,816 
BGE5,396 — 4,726 — 4,726 5,395 — 4,702 — 4,702 
PHI9,541 — 4,145 4,159 8,304 9,124 — 4,093 3,720 7,813 
Pepco4,559 — 2,499 1,750 4,249 4,362 — 2,475 1,544 4,019 
DPL2,346 — 641 1,378 2,019 2,220 — 623 1,250 1,873 
ACE2,033 — 793 1,031 1,824 1,933 — 787 925 1,712 
Long-Term Debt to Financing Trusts
Exelon$390 $— $— $393 $393 $390 $— $— $396 $396 
ComEd206 — — 206 206 206 — — 208 208 
PECO184 — — 187 187 184 — — 188 188 
__________
(a)Includes unamortized debt issuance costs, unamortized debt discount and premium, net, purchase accounting fair value adjustments, and finance lease liabilities which are not fair valued. Refer to Note 16 — Debt and Credit Agreements of the 2024 Form 10-K for unamortized debt issuance costs, unamortized debt discount and premium, net, and purchase accounting fair value adjustments and Note 10 — Leases of the 2024 Form 10-K for finance lease liabilities.

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, 2025 and December 31, 2024. Exelon and the Utility Registrants have immaterial and no financial assets or liabilities measured using the NAV practical expedient, respectively:
Exelon
At March 31, 2025At December 31, 2024
Level 1Level 2Level 3TotalLevel 1 Level 2Level 3Total
Assets
Cash equivalents(a)
$1,190 $— $— $1,190 $544 $— $— $544 
Rabbi trust investments
Cash equivalents95 — — 95 94 — — 94 
Mutual funds63 — — 63 65 — — 65 
Fixed income— 6 — 6 — 6 — 6 
Life insurance contracts — 72 22 94 — 73 22 95 
Rabbi trust investments subtotal158 78 22 258 159 79 22 260 
Interest rate derivative assets
Derivatives designated as hedging instruments— 4 — 4 — 26 — 26 
Economic hedges— — — — — — — — 
Interest rate derivative assets subtotal— 4 — 4 — 26 — 26 
Total assets1,348 82 22 1,452 703 105 22 830 
Liabilities
Commodity derivative liabilities— — (151)(151)— — (132)(132)
Interest rate derivative liabilities
Derivatives designated as hedging instruments— (4)— (4)— (1)— (1)
Economic hedges— — — — — — — — 
Interest rate derivative liabilities subtotal — (4)— (4)— (1)— (1)
Deferred compensation obligation— (69)— (69)— (74)— (74)
Total liabilities— (73)(151)(224)— (75)(132)(207)
Total net assets (liabilities)$1,348 $9 $(129)$1,228 $703 $30 $(110)$623 
__________    
(a)Exelon excludes cash of $210 million and $219 million at March 31, 2025 and December 31, 2024, respectively, and restricted cash of $182 million and $176 million at March 31, 2025 and December 31, 2024, respectively, and includes long-term restricted cash of zero and $41 million at March 31, 2025 and December 31, 2024, respectively, which is reported in Other deferred debits and other assets in the Consolidated Balance Sheets.

ComEd, PECO, and BGE
ComEdPECOBGE
At March 31, 2025Level 1Level 2Level 3TotalLevel 1Level 2Level 3TotalLevel 1Level 2Level 3Total
Assets
Cash equivalents(a)
$345 $— $— $345 $2 $— $— $2 $3 $— $— $3 
Rabbi trust investments
Mutual funds— — — — 11 — — 11 10 — — 10 
Life insurance contracts — — — — — 21 — 21 — — — — 
Rabbi trust investments subtotal— — — — 11 21 — 32 10 — — 10 
Total assets345 — — 345 13 21 — 34 13 — — 13 
Liabilities
Commodity derivative liabilities(b)
— — (151)(151)— — — — — — — — 
Deferred compensation obligation— (8)— (8)— (7)— (7)— (4)— (4)
Total liabilities— (8)(151)(159)— (7)— (7)— (4)— (4)
Total net assets (liabilities)$345 $(8)$(151)$186 $13 $14 $— $27 $13 $(4)$— $9 
ComEdPECOBGE
At December 31, 2024Level 1Level 2Level 3TotalLevel 1Level 2Level 3TotalLevel 1Level 2Level 3Total
Assets
Cash equivalents(a)
$390 $— $— $390 $29 $— $— $29 $1 $— $— $1 
Rabbi trust investments
Mutual funds— — — — 12 — — 12 10 — — 10 
Life insurance contracts — — — — — 22 — 22 — — — — 
Rabbi trust investments subtotal— — — — 12 22 — 34 10 — — 10 
Total assets390 — — 390 41 22 — 63 11 — — 11 
Liabilities
Commodity derivative liabilities(b)
— — (132)(132)— — — — — — — — 
Deferred compensation obligation— (8)— (8)— (7)— (7)— (4)— (4)
Total liabilities— (8)(132)(140)— (7)— (7)— (4)— (4)
Total net assets (liabilities)$390 $(8)$(132)$250 $41 $15 $— $56 $11 $(4)$— $7 
__________
(a)ComEd excludes cash of $71 million and $66 million at March 31, 2025 and December 31, 2024, respectively, and restricted cash of $181 million and $176 million at March 31, 2025 and December 31, 2024, respectively. Additionally, ComEd includes long-term restricted cash of zero and $41 million at March 31, 2025 and December 31, 2024, respectively, which is reported in Other deferred debits and other assets in the Consolidated Balance Sheets. PECO
excludes cash of $52 million and $19 million at March 31, 2025 and December 31, 2024, respectively. BGE excludes cash of $14 million and $33 million at March 31, 2025 and December 31, 2024, respectively.
(b)The Level 3 balance consists of the current and noncurrent liability of $25 million and $126 million, respectively, at March 31, 2025 and $29 million and $103 million, respectively, at December 31, 2024 related to floating-to-fixed energy swap contracts with unaffiliated suppliers.

PHI, Pepco, DPL, and ACE
At March 31, 2025At December 31, 2024
PHI Level 1Level 2Level 3TotalLevel 1Level 2Level 3Total
Assets
Cash equivalents(a)
$118 $— $— $118 $93 $— $— $93 
Rabbi trust investments
Cash equivalents93 — — 93 92 — — 92 
Mutual funds9 — — 9 9 — — 9 
Fixed income— 6 — 6 — 6 — 6 
Life insurance contracts— 23 21 44 — 23 21 44 
Rabbi trust investments subtotal102 29 21 152 101 29 21 151 
Total assets220 29 21 270 194 29 21 244 
Liabilities
Deferred compensation obligation— (10)— (10)— (12)— (12)
Total liabilities— (10)— (10)— (12)— (12)
Total net assets$220 $19 $21 $260 $194 $17 $21 $232 
PepcoDPLACE
At March 31, 2025Level 1Level 2Level 3TotalLevel 1Level 2Level 3TotalLevel 1Level 2Level 3Total
Assets
Cash equivalents(a)
$69 $— $— $69 $49 $— $— $49 $— $— $— $— 
Rabbi trust investments
Cash equivalents92 — — 92 — — — — — — — — 
Life insurance contracts— 23 21 44 — — — — — — — — 
Rabbi trust investments subtotal92 23 21 136 — — — — — — — — 
Total assets161 23 21 205 49 — — 49 — — — — 
Liabilities
Deferred compensation obligation— (1)— (1)— — — — — — — — 
Total liabilities— (1)— (1)— — — — — — — — 
Total net assets$161 $22 $21 $204 $49 $— $— $49 $— $— $— $— 
PepcoDPLACE
At December 31, 2024Level 1Level 2Level 3TotalLevel 1Level 2Level 3TotalLevel 1Level 2Level 3Total
Assets
Cash equivalents(a)
$21 $— $— $21 $3 $— $— $3 $— $— $— $— 
Rabbi trust investments
Cash equivalents91 — — 91 — — — — — — — — 
Life insurance contracts— 23 21 44 — — — — — — — — 
Rabbi trust investments subtotal91 23 21 135 — — — — — — — — 
Total assets112 23 21 156 3 — — 3 — — — — 
Liabilities
Deferred compensation obligation— (1)— (1)— — — — — — — — 
Total liabilities— (1)— (1)— — — — — — — — 
Total net assets$112 $22 $21 $155 $3 $— $— $3 $— $— $— $— 
__________
(a)PHI excludes cash of $51 million and $70 million at March 31, 2025 and December 31, 2024, respectively, and restricted cash of $1 million and zero at March 31, 2025 and December 31, 2024. Pepco excludes cash of $20 million and $30 million at March 31, 2025 and December 31, 2024, respectively. DPL excludes cash of $12 million and $20 million at March 31, 2025 and December 31, 2024, respectively. ACE excludes cash of $19 million and $14 million at March 31, 2025 and December 31, 2024, respectively and restricted cash of $1 million and zero at March 31, 2025 and December 31, 2024, respectively

Reconciliation of Level 3 Assets and Liabilities
The following tables present the fair value reconciliation of Level 3 assets and liabilities measured at fair value on a recurring basis during the three months ended March 31, 2025 and 2024:
ExelonComEdPHI and Pepco
Three Months Ended March 31, 2025Total Commodity
Derivatives		Life Insurance Contracts
Balance at December 31, 2024$(110)$(132)$21 
Total realized / unrealized gains (losses)
Included in net income(a)
— — — 
Included in regulatory assets/liabilities(19)(19)
(b)
— 
Purchases, sales, and settlements
Balance at March 31, 2025$(129)$(151)
(c)
$21 
The amount of total gains included in income attributed to the change in unrealized gains related to assets and liabilities at March 31, 2025$— $— $— 
ExelonComEdPHI and Pepco
Three Months Ended March 31, 2024Total Commodity
Derivatives		Life Insurance Contracts
Balance at December 31, 2023$(90)$(133)$41 
Total realized / unrealized gains (losses)
Included in net income(a)
— — — 
Included in regulatory assets/liabilities25 25 
(b)
— 
Balance at March 31, 2024$(65)$(108)$41 
The amount of total gains included in income attributed to the change in unrealized gains related to assets and liabilities at March 31, 2024$— $— $— 
(a)Classified in Operating and maintenance expense in the Consolidated Statements of Operations and Comprehensive Income.
(b)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. Includes $13 million of increases in fair value and an increase for realized gains due to settlements of $12 million recorded in Purchased power expense associated with floating-to-fixed energy swap contracts with unaffiliated suppliers for the three months ended March 31, 2024.
(c)The balance of the current and noncurrent asset was effectively zero as of March 31, 2025. The balance consists of a current and noncurrent liability of $25 million and $126 million, respectively, as of March 31, 2025.
Commodity Derivatives (Exelon and ComEd)
The table below discloses the significant unobservable inputs to the forward curve used to value mark-to-market derivatives.
Type of tradeFair Value at March 31, 2025Fair Value at December 31, 2024Valuation
Technique		Unobservable
Input		2025 Range & Arithmetic Average2024 Range & Arithmetic Average
Commodity derivatives$(151)$(132)Discounted
Cash Flow
Forward power price(a)
$28.45-$62.87$38.62$30.31-$59.88$42.08
________
(a)An increase to the forward power price would increase the fair value.

74


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 18 — Commitments and Contingencies of the 2024 Form 10-K.
Commitments
PHI Merger Commitments (Exelon, PHI, Pepco, DPL, and ACE). Approval of the PHI Merger in Delaware, New Jersey, Maryland, and the District of Columbia was conditioned upon Exelon and PHI agreeing to certain commitments. The following amounts represent total commitment costs that have been recorded since the acquisition date and the total remaining obligations for Exelon, PHI, Pepco, DPL, and ACE at March 31, 2025:
DescriptionExelon PHI Pepco DPLACE
Total commitments$513 $320 $120 $89 $111 
Remaining commitments(a)
26 23 22 1 — 
__________
(a)Remaining commitments extend through 2026 and include escrow funds, charitable contributions, and rate credits.
75


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, 2025, representing commitments potentially triggered by future events were as follows:
Expiration within
Total202520262027202820292030 and beyond
Exelon
Letters of credit(a)
$55 $47 $8 $— $— $— $— 
Surety bonds(b)
275 182 13 2 78 — — 
Financing trust guarantees(c)
378 — — — 78 — 300 
Guaranteed lease residual values(d)
24 — 3 4 6 4 7 
Total commercial commitments $732 $229 $24 $6 $162 $4 $307 
ComEd
Letters of credit(a)
$18 $15 $3 $— $— $— $— 
Surety bonds(b)
37 32 3 2 — — — 
Financing trust guarantees(c)
200 — — — — — 200 
Total commercial commitments $255 $47 $6 $2 $— $— $200 
PECO
Letters of credit(a)
$4 $1 $3 $— $— $— $— 
Surety bonds(b)
3 2 1 — — — — 
Financing trust guarantees(c)
178 — — — 78 — 100 
Total commercial commitments $185 $3 $4 $— $78 $— $100 
BGE
Letters of credit(a)
$27 $27 $— $— $— $— $— 
Surety bonds(b)
3 2 1 — — — — 
Total commercial commitments $30 $29 $1 $— $— $— $— 
PHI
Letters of credit(a)
$3 $3 $— $— $— $— $— 
Surety bonds(b)
173 91 4 — 78 — — 
Guaranteed lease residual values(d)
24 — 3 4 6 4 7 
Total commercial commitments $200 $94 $7 $4 $84 $4 $7 
Pepco
Letters of credit(a)
$2 $2 $— $— $— $— $— 
Surety bonds(b)
162 84 — — 78 — — 
Guaranteed lease residual values(d)
8 — 1 1 2 1 3 
Total commercial commitments $172 $86 $1 $1 $80 $1 $3 
DPL
Letters of credit(a)
$1 $1 $— $— $— $— $— 
Surety bonds(b)
6 3 3 — — — — 
Guaranteed lease residual values(d)
9 — 1 2 2 2 2 
Total commercial commitments $16 $4 $4 $2 $2 $2 $2 
ACE
Surety bonds(b)
$5 $4 $1 $— $— $— $— 
Guaranteed lease residual values(d)
7 — 1 1 2 1 2 
Total commercial commitments $12 $4 $2 $1 $2 $1 $2 
76


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 $55 million guaranteed by Exelon and PHI, of which $18 million, $21 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 2031.
•PECO has 6 sites currently under some degree of active study and/or remediation. PECO expects the majority of the remediation at these sites to continue through at least 2028.
•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.

77


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, 2025 and December 31, 2024, the Registrants had accrued the following undiscounted amounts for environmental liabilities in Accrued expenses, Other current liabilities, and Other deferred credits and other liabilities in their respective Consolidated Balance Sheets:
March 31, 2025December 31, 2024
Total Environmental
Investigation and
Remediation Liabilities		Portion of Total Related to
MGP Investigation and
Remediation		Total Environmental
Investigation and
Remediation Liabilities		Portion of Total Related to
MGP Investigation and
Remediation
Exelon$396 $319 $403 $322 
ComEd282 282 285 284 
PECO29 27 29 28 
BGE14 10 13 10 
PHI70 — 75 — 
Pepco68 — 73 — 
DPL1 — 1 — 
ACE1 — 1 — 
Benning Road Site (Exelon, PHI, and Pepco). In September 2010, PHI received a letter from the EPA identifying the Benning Road site as one of six land-based sites potentially contributing to contamination of the lower Anacostia River. A portion of the site, which is owned by Pepco, was formerly the location of an electric generating facility owned by Pepco subsidiary, Pepco Energy Services (PES), which became a part of Generation following the 2016 merger between PHI and Exelon. This generating facility was deactivated in June 2012. The remaining portion of the site consists of a Pepco transmission and distribution service center that remains in operation. In December 2011, the U.S. District Court for the District of Columbia approved a Consent Decree entered into by Pepco and Pepco Energy Services (hereinafter "Pepco Entities") with the DOEE, which requires the Pepco Entities to conduct a Remedial Investigation and Feasibility Study (RI/FS) for the Benning Road site and an approximately 10 to 15-acre portion of the adjacent Anacostia River. The purpose of this RI/FS is to define the nature and extent of contamination from the Benning Road site and to evaluate remedial alternatives.
Pursuant to an internal agreement between the Pepco Entities, since 2013, Pepco has performed the work required by the Consent Decree and has been reimbursed for that work by an agreed upon allocation of costs between the Pepco Entities. In September 2019, the Pepco Entities issued a draft “final” RI report which the DOEE approved on February 3, 2020. In October 2022, the DOEE approved dividing the work to complete the landside portion of the FS from the waterside portion to expedite the overall schedule for completion of the project. The landside FS was approved by the DOEE on March 15th, 2024, and the waterside FS was approved by the DOEE on December 16, 2024. On October 3, 2023, 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 a proposed plan for the landside area, which was approved and issued by the DOEE for public comment on December 16, 2024. The landside area public comment period closed on April 18, 2025. Pepco will submit a matrix of proposed responses to the public comments and a proposed Record of Decision (ROD) to the DOEE for the landside area before August 18, 2025. Pepco also submitted a draft proposed plan to the DOEE for the waterside area on April 15, 2025. The DOEE will review Pepco’s draft and issue a final proposed plan for public comment. After the waterside area public comment period closes, 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 ROD(s) identifying the remedial actions determined to be necessary for the landside and waterside areas.
As part of the separation between Exelon and Constellation in February 2022, the internal agreement between the Pepco Entities for completion and payment for the remaining Consent Decree work was memorialized in a formal agreement for post-separation activities. A second post-separation assumption agreement between Exelon and Constellation transferred any of the potential remaining remediation liability, if any, of PES/Generation 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.
78


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. On October 3, 2023, Pepco and the District entered into another consent decree (the “Anacostia River Consent Decree”) pursuant to which Pepco agreed to pay $47 million to resolve its liability to the District for all past costs to perform the riverwide RI/FS and all future costs to complete the work required by the Interim ROD. This amount was agreed to be paid in four equal annual installments beginning a year after the effective date of the Anacostia River Consent Decree. Pepco paid the first installment of $12 million on April 9, 2025. The funds were deposited into the DOEE’s Clean Land Fund for the District’s costs of the Interim ROD work. The Anacostia River Consent Decree caps Pepco’s liability for these costs and provides Pepco with the right to seek contributions from other PRPs. The Anacostia River Consent Decree was signed by the judge for the U.S. District Court for the District of Columbia and became effective on April 11, 2024. Exelon, PHI, and Pepco have accrued a liability for Pepco’s payment obligations under the Anacostia Consent Decree and management's best estimate of its share of any other future Anacostia River response costs. Pepco has concluded that incremental exposure remains reasonably possible, but management cannot reasonably estimate a range of loss beyond the amounts recorded, which are included in the table above.
In addition to the activities associated with the remedial process outlined above, CERCLA separately requires federal and state (here including Washington, D.C.) Natural Resource Trustees (federal or state agencies designated by the President or the relevant state, respectively, or Indian tribes) to conduct an assessment of any damages to natural resources within their jurisdiction as a result of the contamination that is being remediated. The Trustees can seek compensation from responsible parties for such damages, including restoration costs. During the second quarter of 2018, Pepco became aware that the Trustees are in the beginning stages of a NRD assessment, a process that often takes many years beyond the remedial decision to complete. Pepco has concluded that a loss associated with the eventual NRD assessment is reasonably possible. Due to the early stage of the NRD process, Pepco cannot reasonably estimate the final range of loss potentially resulting from this process. Pepco has become aware, however, that the District is pursuing claims against other parties. Specifically, in January 2025, D.C. OAG filed a lawsuit against the United States seeking to declare the United States liable under CERCLA and the District of Columbia’s Brownfield Revitalization Act of 2000 and to recover the District’s response costs associated with its investigation and remediation of the river and for future NRDs. This lawsuit is in the early stages. Pepco is monitoring this lawsuit and considering its legal options.
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.
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. On October 3, 2023, Pepco entered into a Consent Order with the District of Columbia to resolve the alleged
79


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

Note 11 — Commitments and Contingencies
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 court signed and entered the Consent Order, and it became effective on February 2, 2024. 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.
In addition, subsequent to Exelon announcing the receipt of the USAO subpoenas, several shareholders sent letters to the Exelon Board of Directors demanding, among other things, that the Exelon Board of Directors investigate and address alleged breaches of fiduciary duties and other alleged violations by Exelon and ComEd officers and directors related to the conduct described in the DPA. In the first quarter of 2021, the Exelon Board of Directors appointed a Special Litigation Committee (SLC) consisting of disinterested and independent parties to investigate and address these shareholders’ allegations and make recommendations to the Exelon Board of Directors based on the outcome of the SLC’s investigation. In July 2021, one of the demand letter shareholders filed a derivative action against current and former Exelon and ComEd officers and directors, and against Exelon, as nominal defendant, asserting the same claims made in its demand letter. Since that date, multiple parties have filed separate derivative lawsuits that were subsequently consolidated. On October 12, 2021, the parties filed an agreed motion to stay the litigation for 120 days in order to allow the SLC to continue its investigation, which the court granted. The stay was extended several times. Through mediation efforts, a settlement of the derivative claims was reached by the SLC, the Independent Review Committee of the Board (which had been formed in the third quarter of 2022, to ensure the Board’s consideration of any SLC recommendations would be independent and objective), the Board, and certain of the derivative shareholders. On June 16, 2023, the SLC filed a motion for preliminary approval of the settlement, attaching the Stipulation and Agreement of Settlement (Stipulation), which contained the terms of the proposed settlement. The proposed settlement terms include but are not limited to: a payment of $40 million to Exelon by Exelon’s insurers of which $10 million constitutes the attorneys’ fee award to be paid to the Settling Shareholders’ counsel; various compliance and disclosure-related reforms; and certain changes in Board and Committee composition. The non-settling shareholders objected to the settlement and opposed preliminary approval. On September 20, 2024, the court denied without prejudice the SLC’s motion for preliminary approval. The court’s order provided that if the SLC can substantiate or otherwise revise the attorneys’ fees aspect of the settlement, then the SLC could renew its motion for preliminary approval by October 21, 2024. On October 21, 2024, the SLC filed its second renewed motion for preliminary approval, and the Settling Shareholders filed a brief in support of the SLC's second renewed motion for preliminary approval. On November 20, 2024, the non-settling plaintiffs filed an opposition to the renewed motion for preliminary approval. On December 18, 2024, the SLC and Settling Shareholders filed replies in support of the renewed motion for preliminary approval.
80


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

Note 11 — Commitments and Contingencies
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.
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 property, plant, and equipment 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 August 4, 2022, Exelon executed an equity distribution agreement (“Equity Distribution Agreement”), with certain sales agents and forward sellers and certain forward purchasers, establishing an ATM equity distribution program under which it may offer and sell shares of its Common stock, having an aggregate gross sales price of up to $1 billion. Exelon has no obligation to offer or sell any shares of Common stock under the Equity Distribution Agreement and may, at any time, suspend or terminate offers and sales under the Equity Distribution Agreement.
During the first quarter 2025, Exelon issued approximately 4.0 million shares of Common stock at an average gross price of $43.42 per share. The net proceeds from the issuance were $173 million, which were used for general corporate purposes.
In the first quarter of 2025, Exelon entered into two separate forward sale agreements for 1.7 million shares and 4.0 million shares of Common stock, with an initial forward price of $42.81 and $43.42 per share, respectively. The forward sale agreements require Exelon to, at its election prior to December 15, 2025, either (i) physically settle the transactions by issuing shares of its Common stock to the forward counterparties in exchange for net proceeds at the then-applicable forward sale price specified by the agreements or (ii) net settle the transactions in whole or in part through the delivery to the forward counterparties or receipt from the forward counterparties of cash or shares in accordance with the provisions of the agreements. 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, 2025, approximately 5.6 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.
81


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

Note 12 — Shareholders' Equity
Inclusive of the impact of the forward sale agreements, $283 million of Common stock remained available for sale pursuant to the ATM program as of March 31, 2025.
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, 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)
Three Months Ended March 31, 2024 Cash Flow Hedges
Pension and Non-Pension Postretirement Benefit Plan Items(a)
Total
Balance at December 31, 2023$(3)$(723)$(726)
OCI before reclassifications34 (24)10 
Amounts reclassified from AOCI(1)5 4 
Net current-period OCI33 (19)14 
Balance at March 31, 2024$30 $(742)$(712)
__________
(a)This AOCI component is included in the computation of net periodic pension and OPEB cost. See Note 14 — Retirement Benefits and Note 7 — Retirement Benefits of the 2024 Form 10-K for additional information. See Exelon's Statements of Operations and Comprehensive Income for individual components of AOCI.

The following table presents Income tax benefit (expense) allocated to each component of Exelon's Other comprehensive income (loss):
Three Months Ended March 31,
20252024
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(2)8 
Unrealized gains on cash flow hedges3 (10)
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:
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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
Taxes other than income taxes
ExelonComEdPECOBGEPHIPepcoDPLACE
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 
Three Months Ended March 31, 2024
Utility taxes(a)
$229 $75 $41 $31 $82 $74 $8 $— 
Property105 9 4 53 38 26 11 1 
Payroll34 9 5 5 7 2 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, 2025
AFUDC — Equity$39 $12 $7 $9 $11 $8 $2 $1 
Non-service net periodic benefit cost(13)— — — — — — — 
Three Months Ended March 31, 2024
AFUDC — Equity$40 $10 $8 $7 $15 $12 $3 $— 
Non-service net periodic benefit cost(7)— — — — — — — 
Supplemental Cash Flow Information
The following tables provide additional information about material items recorded in the Registrants' Consolidated Statements of Cash Flows.

83


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, 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 
Three Months Ended March 31, 2024
Property, plant, and equipment(a)
$711 $284 $101 $122 $190 $81 $52 $53 
Amortization of regulatory assets and liabilities, net(a)
166 78 3 28 56 26 9 21 
Amortization of intangible assets, net(a)
2 — — — — — — — 
ARO accretion(b)
1 — — — — — — — 
Total depreciation and amortization$880 $362 $104 $150 $246 $107 $61 $74 
__________
(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, 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)
Three Months Ended March 31, 2024
Pension and OPEB costs$61 $17 $— $15 $23 $9 $4 $3 
Allowance for credit losses63 2 27 12 22 16 3 3 
True-up adjustments to decoupling mechanisms and formula rates(a)
(91)(19)2 (43)(31)(29)4 (6)
Amortization of operating ROU asset9 — — 2 6 1 2 1 
AFUDC — Equity(40)(10)(8)(7)(15)(12)(3)— 
__________
(a)For ComEd, reflects the true-up adjustments in Regulatory assets and liabilities associated with its distribution MRP and distribution, energy efficiency, distributed generation, and transmission formula rates. For PECO, reflects the change in Regulatory assets and liabilities associated with its transmission formula rates. For BGE, Pepco, DPL, and ACE, reflects the change in Regulatory assets and liabilities associated with their decoupling mechanisms and transmission formula rates. See Note 3 — Regulatory Matters of the 2024 Form 10-K for additional information.
84


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, 2025
Cash and cash equivalents$1,004 $96 $54 $14 $127 $58 $50 $18 
Restricted cash and cash equivalents578 501 — 3 43 31 11 1 
Restricted cash included in Other deferred debits and other assets— — — — — — — — 
Total cash, restricted cash, and cash equivalents$1,582 $597 $54 $17 $170 $89 $61 $19 
Balance at December 31, 2024
Cash and cash equivalents$357 $105 $48 $33 $139 $30 $21 $14 
Restricted cash and cash equivalents541 486 — 1 24 21 2 — 
Restricted cash included in Other deferred debits and other assets41 41 — — — — — — 
Total cash, restricted cash, and cash equivalents$939 $632 $48 $34 $163 $51 $23 $14 
Balance at March 31, 2024
Cash and cash equivalents$720 $100 $39 $27 $504 $198 $269 $27 
Restricted cash and cash equivalents489 428 9 — 23 22 1 — 
Restricted cash included in Other deferred debits and other assets99 99 — — — — — — 
Total cash, restricted cash, and cash equivalents$1,308 $627 $48 $27 $527 $220 $270 $27 
For additional information on restricted cash see Note 1 — Significant Accounting Policies of the 2024 Form 10-K.
Supplemental Balance Sheet Information
The following table provides additional information about material items recorded in the Registrants' Consolidated Balance Sheets.
85


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

Note 14 — Supplemental Financial Information
Accrued expenses
ExelonComEdPECOBGEPHIPepcoDPLACE
Balance at March 31, 2025
Compensation-related accruals(a)
$377 $115 $53 $51 $64 $19 $13 $9 
Taxes accrued222 148 31 81 138 116 21 12 
Interest accrued440 89 56 77 83 37 27 17 
Balance at December 31, 2024
Compensation-related accruals(a)
$679 $197 $87 $88 $132 $38 $26 $18 
Taxes accrued217 96 13 34 110 92 11 11 
Interest accrued468 150 60 50 83 44 16 18 
__________
(a)Primarily includes accrued payroll, bonuses and other incentives, vacation, and benefits.
15. Related Party Transactions (All Registrants)
Service Company Costs for Corporate Support
The Registrants receive a variety of corporate support services from BSC. Pepco, DPL, and ACE also receive corporate support services from PHISCO. See Note 1 — Significant Accounting Policies for additional information regarding BSC and PHISCO.

The following table presents the service company costs allocated to the Registrants:
Operating and maintenance from affiliatesCapitalized costs
Three Months Ended March 31,Three Months Ended March 31,
2025202420252024
Exelon
   BSC$160 $158 
   PHISCO25 29 
ComEd
   BSC$100 $100 62 71 
PECO
   BSC59 58 27 29 
BGE
   BSC63 59 33 24 
PHI
   BSC52 50 39 34 
   PHISCO— — 25 29 
Pepco
   BSC32 31 17 17 
   PHISCO31 33 10 12 
DPL
   BSC20 19 12 12 
   PHISCO25 25 8 9 
ACE
   BSC16 16 8 5 
   PHISCO23 23 7 8 
86


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, 2025
Receivables from affiliates:
Payables to affiliates:ComEdPECOBGEPepcoDPLACEBSCPHISCOOtherTotal
ComEd$— $— $— $— $— $58 $— $2 $60 
PECO$1 — — — — 30 — 6 37 
BGE1 — — — — 36 — 1 38 
PHI1 — — — — — 7 — 11 19 
Pepco— — — — — 17 16 1 34 
DPL1 — — — — 11 12 (1)23 
ACE— — — — — 10 11 (1)20 
Other4 — — — 1 7 — — 12 
Total$8 $— $— $— $1 $7 $169 $39 $19 $243 
December 31, 2024
Receivables from affiliates:
Payables to affiliates:ComEdPECOBGEPepcoDPLACEBSCPHISCOOtherTotal
ComEd$— $— $— $— $— $67 $— $10 $77 
PECO$— — — — — 37 — 4 41 
BGE— — — — — 47 — 1 48 
PHI— — — — — — 7 1 10 18 
Pepco— — — — — 21 15 1 37 
DPL— — — — — 14 11 1 26 
ACE— — — — — 11 10 1 22 
Other4 — — 1 — 7 — — 12 
Total$4 $— $— $1 $— $7 $204 $37 $28 $281 
Borrowings from Exelon/PHI intercompany money pool
To provide an additional short-term borrowing option that will generally be more favorable to the borrowing participants than the cost of external financing both Exelon and PHI operate an intercompany money pool. PECO and PHI Corporate participate in the Exelon 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, 2025December 31, 2024
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 it's 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, 2025 compared to the same period in 2024. For additional information regarding the financial results for the three months ended March 31, 2025 and 2024, see the discussions of Results of Operations by Registrant.
Three Months Ended March 31,Favorable (Unfavorable) Variance
20252024
Exelon$908 $658 $250 
ComEd302 193 109 
PECO266 149 117 
BGE260 264 (4)
PHI194 168 26 
Pepco97 75 22 
DPL69 66 3 
ACE31 29 2 
Other(a)
(114)(116)2 
__________
(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, 2025 Compared to Three Months Ended March 31, 2024. Net income attributable to common shareholders increased by $250 million and diluted earnings per average common share increased to $0.90 in 2025 from 0.66 in 2024 primarily due to:
•Timing of distribution earnings at ComEd;
•Favorable impacts of rate increases at ComEd, PECO, BGE and PHI;
•Normal weather at PECO compared to unfavorable weather in the prior period;
•Timing of income tax expense at PECO; and
•Higher return on regulatory assets at ComEd.
The increases were partially offset by:
88



•Higher interest expense at PECO, BGE and PHI; and
•Lower transmission peak load due to lower energy demand at ComEd.
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, 2025 compared to the same period in 2024:
Three Months Ended March 31,
20252024
(In millions, except per share data)Earnings per
Diluted Share		Earnings per
Diluted Share
Net income attributable to common shareholders$908 $0.90 $658 $0.66 
Regulatory matters (net of taxes of $7)(a)
22 0.02 — — 
Change in FERC audit liability (net of taxes of $1 and $9, respectively)
2 — 27 0.03 
Cost management charge (net of taxes of $0)(b)
(1)— — — 
Adjusted (non-GAAP) operating earnings$932 $0.92 $685 $0.68 
__________
Note:
Amounts may not sum due to rounding.
Unless otherwise noted, the income tax impact of each reconciling item between GAAP Net income attributable to common shareholders and Adjusted (non-GAAP) operating earnings is based on the marginal statutory federal and state income tax rates for each Registrant, taking into account whether the income or expense item is taxable or deductible, respectively, in whole or in part. The marginal statutory income tax rates for 2025 and 2024 ranged from 24.0% to 29.0%.

(a)Represents the probable disallowance of certain capitalized costs.
(b)Primarily represents severance and reorganization costs related to cost management.
Significant 2025 Transactions and Developments
Distribution Base Rate Case Proceedings
The Utility Registrants file base rate cases with their regulatory commissions seeking increases or decreases to their electric transmission and distribution, and gas distribution rates to recover their costs and earn a fair return on their investments. The outcomes of these regulatory proceedings impact the Utility Registrants’ current and future financial statements.
The following tables show the Utility Registrants’ completed and pending distribution base rate case proceedings in 2025. See Note 2 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.
89



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/A(e)
December 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
ACE - New JerseyFebruary 15, 2023 (amended August 21, 2023)Electric$92 $45 9.60 %November 17, 2023December 1, 2023
90



Pending Distribution Base Rate Case Proceedings
Registrant/JurisdictionFiling DateServiceRequested Revenue Requirement IncreaseRequested ROEExpected Approval Timing
DPL - DelawareSeptember 20, 2024 (amended February 28, 2025)Natural Gas$42 10.65 %First quarter of 2026
ACE - New JerseyNovember 21, 2024Electric109 10.70%Fourth quarter of 2025
Transmission Formula Rates
For 2025, the following total increase was included in the Utility Registrant's electric transmission formula rate update. See Note 2 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.
RegistrantInitial Revenue Requirement IncreaseAnnual Reconciliation
Increase		Total Revenue Requirement IncreaseAllowed Return on Rate BaseAllowed ROE
BGE$21 $21 $35 7.53 %10.50 %
ComEd's FERC Audit
The Utility Registrants are subject to periodic audits and investigations by FERC. FERC’s Division of Audits and Accounting initiated a nonpublic audit of ComEd in April 2021 evaluating ComEd’s compliance with (1) approved terms, rates and conditions of its federally regulated service; (2) accounting requirements of the Uniform System of Accounts; (3) reporting requirements of the FERC Form 1; and (4) the requirements for record retention. The audit period extended back to January 1, 2017.
On July 27, 2023, FERC published a final audit report which included, among other things, findings and recommendations related to ComEd's methodology regarding the allocation of certain overhead costs to capitalized construction costs under FERC regulations, including a suggestion that refunds may be due to customers for amounts collected in previous years. ComEd responded to that report and on August 28, 2023, ComEd filed a formal notice of the issues it contested within the audit report. On December 14, 2023, FERC appointed a settlement judge for the contested overhead allocation findings and set the matter for a trial-type hearing. That hearing process was held in abeyance while a formal settlement process, which began in February 2024, took place.
On July 30, 2024, ComEd reached an agreement in principle on the contested overhead allocation finding. As a result of the settlement process, ComEd recorded a charge for the probable disallowance of $70 million of certain currently capitalized construction costs to operating expenses, which are not expected to be recovered in future rates. The existing loss estimate was reflected in Exelon and ComEd's financial statements as of December 31, 2024. ComEd and FERC staff jointly filed the settlement agreement with FERC for approval on February 11, 2025. The settlement was approved by FERC on April 4, 2025.
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Other Key Business Drivers and Management Strategies
The following discussion of other key business drivers and management strategies includes current developments of previously disclosed matters and new issues arising during the period that may impact future financial statements. This section should be read in conjunction with ITEM 1. Business in the 2024 Form 10-K, ITEM 7. Management's Discussion and Analysis of Financial Condition and Results of Operations — Other Key Business Drivers and Management Strategies in the 2024 Form 10-K, and Note 11 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements in this report for additional information on various environmental matters.
Allocation of Income Taxes to Regulated Utilities (All Registrants)
In Q2 2024, the IRS issued a series of PLRs, to another taxpayer, providing guidance with respect to the application of the tax normalization rules to the allocation of consolidated tax benefits among the members of a consolidated group associated with NOLC for ratemaking purposes. The rulings provide that for ratemaking purposes the tax benefit of NOLC should be reflected on a separate company basis not taking into consideration the utilization of losses by other affiliates. A PLR issued to another taxpayer may not be relied on as precedent.
For the Registrants, except for PECO, the methodology prescribed by the IRS in these PLRs could result in a reduction of the regulatory liability established for EDITs arising from the TCJA corporate tax rate change that is 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 purpose. The Utility Registrants will record the impact, if any, upon receiving the PLR from the IRS.
Legislative and Regulatory Developments
Infrastructure Investment and Jobs Act
On November 15, 2021, President Biden signed the $1.2 trillion IIJA into law. IIJA provides for approximately $550 billion in new federal spending. Categories of funding include funding for a variety of infrastructure needs, including but not limited to: (1) power and grid reliability and resilience, (2) resilience for cybersecurity to address critical infrastructure needs, and (3) electric vehicle charging infrastructure for alternative fuel corridors. The Registrants continue to evaluate programs under the legislation and consider possible opportunities to apply for funding, either directly or in potential collaborations with state and/or local agencies and key stakeholders. The Registrants cannot predict the ultimate timing and success of securing funding from programs under IIJA.
The Trump Administration has issued numerous Executive Orders (EOs), including the Unleashing American Energy Order on January 20, 2025, which requires an immediate pause in the disbursement of funds appropriated through the IRA and IIJA during a 90-day review period, which is still in effect. Exelon is currently evaluating this EO and others to determine what, if any, impact they might have on awards selected or received from the Department of Energy in 2024.
Next Generation Energy Act
On April 7, 2025, the Maryland General Assembly, passed legislation that addresses several matters pertaining to electric and gas utilities, including affirming that the MDPSC may approve the use of multi-year rate plans that are proven to be beneficial to customers, among other things. It also prohibits utilities from filing after January 1, 2025, for the reconciliation of actuals costs and revenues to amounts approved within the multi-year plans. As of March 31, 2025, BGE has a regulatory asset of $10 million and a regulatory liability of $10 million for multi-year plan reconciliations yet to be filed. DPL has a regulatory liability of $7 million for multi-year reconciliations yet to be filed. Multi-year plan reconciliations filed prior to January 1, 2025, remain lawful and will be resolved in their respective proceedings. The legislation is pending the signature of the Governor. Exelon, BGE, Pepco, and DPL are in the process of assessing the potential impacts of the pending legislation.
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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, 2025, the Registrants’ critical accounting policies and estimates had not changed significantly from December 31, 2024. See ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS — Critical Accounting Policies and Estimates in the 2024 Form 10-K for further information.
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Results of Operations by Registrant
Results of Operations — ComEd
Three Months Ended
March 31,		(Unfavorable) Favorable Variance
20252024
Operating revenues$2,065 $2,095 $(30)
Operating expenses
Purchased power689 907 218 
Operating and maintenance423 418 (5)
Depreciation and amortization380 362 (18)
Taxes other than income taxes99 94 (5)
Total operating expenses1,591 1,781 190 
Operating income474 314 160 
Other income and (deductions)
Interest expense, net(128)(122)(6)
Other, net21 20 1 
Total other income and (deductions)(107)(102)(5)
Income before income taxes367 212 155 
Income taxes 65 19 (46)
Net income $302 $193 $109 
Three Months Ended March 31, 2025 Compared to Three Months Ended March 31, 2024. Net income increased by $109 million as compared to the same period in 2024, primarily due to timing of distribution earnings, higher distribution and transmission rate base, and higher return on regulatory assets primarily due to an increase in asset balances. These were partially offset by lower transmission peak load.
The changes in Operating revenues consisted of the following:
Three Months Ended
March 31, 2025
Increase (Decrease)
Distribution$129 
Transmission22 
Energy efficiency10 
Other9 
170 
Regulatory required programs (200)
Total decrease$(30)
Revenue Decoupling. The demand for electricity is affected by weather and customer usage. Operating revenues are not impacted by abnormal weather, usage per customer, or number of customers as a result of revenue decoupling mechanisms.
Distribution Revenue. Starting in 2024, distribution revenues are under a MRP. The MRP requires an annual reconciliation of the revenue requirement in effect to the actual costs the ICC determines are prudently and reasonably incurred. Electric distribution revenue varies from year to year based upon fluctuations in the underlying costs, (e.g., severe weather and storm restoration), investments being recovered, and allowed ROE. Electric distribution revenues increased for the three months ended March 31, 2025 as compared to the same period in 2024, primarily due to differences in the timing of distribution earnings and higher rate base.
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
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ComEd
for the three months ended March 31, 2025 as compared to the same period in 2024, primarily due to higher fully recoverable costs and the impacts of higher rate base, partially offset by lower transmission peak load.
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, 2025 as compared to the same periods in 2024, primarily due to increased regulatory asset amortization, which is fully recoverable.
Other Revenue primarily includes assistance provided to other utilities through mutual assistance programs. Other revenues increased for the three months ended March 31, 2025 as compared to the same periods in 2024, 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 such as recoveries under the credit loss expense tariff, environmental costs associated with MGP sites, ETAC, and costs related to electricity, ZEC, CMC, and REC procurement. ETAC is a retail customer surcharge collected and remitted to an Illinois state agency for programs to support clean energy jobs and training. The riders are designed to provide full and current cost recovery. The costs of these programs are included in Purchased power expense, Operating and maintenance expense, Depreciation and amortization expense, and Taxes other than income taxes. Customers have the choice to purchase electricity from competitive electric generation suppliers. Customer choice programs do not impact the volume of deliveries as ComEd remains the distribution service provider for all customers and charges a regulated rate for distribution service, which is recorded in Operating revenues. For customers that choose to purchase electric generation from competitive suppliers, ComEd either acts as the billing agent or the competitive supplier separately bills its own customers, and therefore does not record Operating revenues or Purchased power expense related to the electricity. For customers that choose to purchase electric generation from ComEd, ComEd is permitted to recover the electricity, ZEC, CMC, and REC procurement costs without mark-up and therefore records equal and offsetting amounts in Operating revenues and Purchased power expense related to the electricity, ZECs, CMCs, and RECs.
See Note 4 — Segment Information of the Combined Notes to Consolidated Financial Statements for the presentation of ComEd's revenue disaggregation.
The $218 million decrease in Purchased power expense for the three months ended March 31, 2025 compared to the same periods in 2024 is offset in Operating revenues as part of regulatory required programs.
The changes in Operating and maintenance expense consisted of the following:
Three Months Ended
March 31, 2025
(Decrease) Increase
Labor, other benefits, contracting, and materials$(27)
Storm-related costs(6)
Pension and non-pension postretirement benefits expense2 
Other40 
9 
Regulatory required programs(4)
Total increase$5 


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ComEd
The changes in Depreciation and amortization expense consisted of the following:
Three Months Ended
March 31, 2025
Increase
Depreciation and amortization(a)
$18 
Total increase$18 
__________
(a)Reflects ongoing capital expenditures.
Effective income tax rates were 17.7% and 9.0% for the three months ended March 31, 2025 and 2024, respectively. See Note 6 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the effective income tax rates.
96



PECO
Results of Operations — PECO
Three Months Ended
March 31,		Favorable (Unfavorable) Variance
20252024
Operating revenues$1,333 $1,054 $279 
Operating expenses
Purchased power and fuel502 403 (99)
Operating and maintenance327 293 (34)
Depreciation and amortization109 104 (5)
Taxes other than income taxes60 51 (9)
Total operating expenses998 851 (147)
Gain on sales of assets — 2 (2)
Operating income335 205 130 
Other income and (deductions)
Interest expense, net(63)(55)(8)
Other, net8 9 (1)
Total other income and (deductions)(55)(46)(9)
Income before income taxes280 159 121 
Income taxes14 10 (4)
Net income$266 $149 $117 
Three Months Ended March 31, 2025 Compared to Three Months Ended March 31, 2024. Net income increased by $117 million, due to an increase in revenue as a result of an increase in electric and gas distribution rates coupled with relatively normal weather compared to unfavorable weather in the same period last year and a decrease in income tax expense due to timing of tax repairs deduction, partially offset by an increase in credit loss expense and interest expense.
The changes in Operating revenues consisted of the following:
Three Months Ended
March 31, 2025
Increase (Decrease)
ElectricGasTotal
Weather$23 $21 $44 
Volume9 2 11 
Pricing73 38 111 
Transmission(6)— (6)
Other5 3 8 
104 64 168 
Regulatory required programs71 40 111 
Total increase$175 $104 $279 
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, 2025 compared to the same period in 2024, Operating revenues related to weather increased due to relatively normal weather compared to unfavorable weather conditions in PECO's service territory.
Heating and cooling degree-days are quantitative indices that reflect the demand for energy needed to heat or cool a home or business. Normal weather is determined based on historical average heating and cooling degree-days for a 30-year period in PECO's service territory. The changes in heating and cooling degree-days in
97



PECO
PECO’s service territory for the three months ended March 31, 2025 compared to the same period in 2024 and normal weather consisted of the following:
Three Months Ended March 31,% Change
PECO Service Territory20252024Normal2025 vs. 20242025 vs. Normal
Heating Degree-Days2,351 2,0892,38812.5 %(1.5)%
Cooling Degree-Days1 —1N/A— %
Volume. Electric volume, exclusive of the effects of weather, for the three months ended March 31, 2025 compared to the same period in 2024, remained relatively consistent. Natural gas volume for the three months ended March 31, 2025 compared to the same period in 2024, remained relatively consistent.
Electric Retail Deliveries to Customers (in GWhs)Three Months Ended March 31,% Change
Weather -
Normal
% Change(b)
20252024
Residential3,8593,45511.7 %3.3 %
Small commercial & industrial1,9461,8912.9 %(1.0)%
Large commercial & industrial3,4253,3552.1 %(0.4)%
Public authorities & electric railroads1891795.6 %5.6 %
Total electric retail deliveries(a)
9,4198,8806.1 %1.1 %

At March 31,
Number of Electric Customers20252024
Residential1,540,4531,540,491
Small commercial & industrial155,131156,475
Large commercial & industrial3,1513,160
Public authorities & electric railroads10,70310,713
Total1,709,4381,710,839
__________
(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)
20252024
Residential21,83418,89515.6 %(0.3)%
Small commercial & industrial10,4059,4889.7 %(2.2)%
Large commercial & industrial1216(25.0)%— %
Transportation7,2426,8995.0 %1.0 %
Total natural gas retail deliveries(a)
39,49335,29811.9 %(0.6)%

 At March 31,
Number of Natural Gas Customers20252024
Residential509,773508,429
Small commercial & industrial44,86945,038
Large commercial & industrial77
Transportation623646
Total555,272554,120
__________
(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.
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PECO
(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, 2025 compared to the same period in 2024 increased primarily due to an increase in electric and gas distribution rates charged to customers.
Transmission Revenue. Under a FERC-approved formula, transmission revenue varies from year to year based upon fluctuations in the underlying costs and capital investments being recovered. Transmission revenue decreased for the three months ended March 31, 2025 compared to the same period in 2024 primarily due to decreases in underlying costs and capital investments.
Other revenue primarily includes revenue related to late payment charges. Other revenue for the three months ended March 31, 2025 compared to the same period in 2024 remained relatively consistent.
Regulatory Required Programs represents revenues collected under approved riders to recover costs incurred for regulatory programs such as energy efficiency, PGC, TSC, and the GSA. The riders are designed to provide full and current cost recovery, and in some cases, a return. The costs of these programs are included in Purchased power and fuel expense, Operating and maintenance expense, Depreciation and amortization expense, and Income taxes. Customers have the choice to purchase electricity and natural gas from competitive electric generation and natural gas suppliers. Customer choice programs do not impact the volume of deliveries as PECO remains the distribution service provider for all customers and charges a regulated rate for distribution service, which is recorded in Operating revenues. For customers that choose to purchase electric generation or natural gas from competitive suppliers, PECO either acts as the billing agent or the competitive supplier separately bills its own customers and therefore PECO does not record Operating revenues or Purchased power and fuel expense related to the electricity and/or natural gas. For customers that choose to purchase electric generation or natural gas from PECO, PECO is permitted to recover the electricity, natural gas, and REC procurement costs without mark-up and therefore records equal and offsetting amounts in Operating revenues and Purchased power and fuel expense related to the electricity, natural gas, and RECs.     
See Note 4 — Segment Information of the Combined Notes to Consolidated Financial Statements for the presentation of PECO's revenue disaggregation.
The increase of $99 million for the three months ended March 31, 2025 compared to the same period in 2024, in Purchased power and fuel expense is offset in Operating revenues as part of regulatory required programs.
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PECO
The changes in Operating and maintenance expense consisted of the following:
Three Months Ended
March 31, 2025
Increase (Decrease)
Credit loss expense$17 
Labor, other benefits, contracting and materials9 
BSC costs
1 
Pension and non-pension postretirement benefit expense1 
Storm-related costs(4)
Other(1)
23 
Regulatory required programs11 
Total increase$34 
The changes in Depreciation and amortization expense consisted of the following:
Three Months Ended
March 31, 2025
Increase (Decrease)
Depreciation and amortization(a)
$7 
Regulatory asset amortization(2)
Total increase$5 
__________
(a)Depreciation and amortization increased primarily due to ongoing capital expenditures.


Taxes other than income taxes increased by $9 million for the three months ended March 31, 2025, compared to the same period in 2024, primarily due to higher Pennsylvania gross receipts tax.
Interest expense, net increased $8 million for the three months ended March 31, 2025, compared to the same period in 2024, primarily due to an increase in interest rates and higher outstanding debt.
Effective income tax rates were 5.0% and 6.3% for the three months ended March 31, 2025 and 2024, respectively. See Note 6 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the effective income tax rates.
100



BGE

Results of Operations — BGE
Three Months Ended
March 31,		Favorable (Unfavorable) Variance
20252024
Operating revenues$1,554 $1,297 $257 
Operating expenses
Purchased power and fuel 609 464 (145)
Operating and maintenance305 264 (41)
Depreciation and amortization164 150 (14)
Taxes other than income taxes96 89 (7)
Total operating expenses1,174 967 (207)
Operating income380 330 50 
Other income and (deductions)
Interest expense, net(58)(50)(8)
Other, net9 8 1 
Total other income and (deductions)(49)(42)(7)
Income before income taxes331 288 43 
Income taxes71 24 (47)
Net income$260 $264 $(4)
Three Months Ended March 31, 2025 Compared to Three Months Ended March 31, 2024. Net Income decreased $4 million primarily due to an increase in various operating expenses and an increase in interest expense, partially offset by favorable distribution rates.
The changes in Operating revenues consisted of the following:
Three Months Ended
March 31, 2025
Increase (Decrease)
ElectricGasTotal
Distribution$33 $44 $77 
Transmission7 — 7 
Other2 (1)1 
42 43 85 
Regulatory required programs88 84 172 
Total increase$130 $127 $257 
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 Customers20252024
Residential1,220,769 1,213,063 
Small commercial & industrial115,359 115,406 
Large commercial & industrial13,302 13,110 
Public authorities & electric railroads258 261 
Total1,349,688 1,341,840 

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BGE

At March 31,
Number of Natural Gas Customers20252024
Residential661,195 658,818 
Small commercial & industrial37,945 37,982 
Large commercial & industrial6,380 6,336 
Total705,520 703,136 
Distribution Revenue increased for the three months ended March 31, 2025, compared to the same period in 2024, due to favorable impacts of the multi-year plans.
Transmission Revenue. Under a FERC-approved formula, transmission revenue varies from year to year based upon fluctuations in the underlying costs and capital investments being recovered. Transmission revenue increased for the three months ended March 31, 2025, compared to the same period in 2024, primarily due to increases in underlying costs and capital investments.
Other Revenue includes revenue related to late payment charges, mutual assistance, off-system sales, and service application fees. Other Revenue remained relatively consistent for the three months ended March 31, 2025 compared to the same period in 2024.
Regulatory Required Programs represent revenues collected under approved riders to recover costs incurred for regulatory programs such as conservation, demand response, and the POLR mechanism. The riders are designed to provide full and current cost recovery, as well as a return in certain instances. The costs of these programs are included in Purchased power and fuel expense, Operating and maintenance expense, Depreciation and amortization expense, and Taxes other than income taxes. Customers have the choice to purchase electricity and natural gas from competitive electric generation and natural gas suppliers. Customer choice programs do not impact the volume of deliveries as BGE remains the distribution service provider for all customers and charges a regulated rate for distribution service, which is recorded in Operating revenues. For customers that choose to purchase electric generation or natural gas from competitive suppliers, BGE acts as the billing agent and therefore does not record Operating revenues or Purchased power and fuel expense related to the electricity and/or natural gas. For customers that choose to purchase electric generation or natural gas from BGE, BGE is permitted to recover the electricity and natural gas procurement costs from customers and therefore records the amounts related to the electricity and/or natural gas in Operating revenues and Purchased power and fuel expense. BGE recovers electricity and natural gas procurement costs from customers with a slight mark-up.
See Note 4 — Segment Information of the Combined Notes to Consolidated Financial Statements for the presentation of BGE's revenue disaggregation.
The increase of $145 million for the three months ended March 31, 2025 compared to the same period in 2024, in Purchased power and fuel expense is fully offset in Operating revenues as part of regulatory required programs.

102



BGE

The changes in Operating and maintenance expense consisted of the following:
Three Months Ended
March 31, 2025
 Increase (Decrease)
Labor, other benefits, contracting, and materials12 
BSC costs3 
Credit loss expense2 
Pension and non-pension postretirement benefits expense1 
Storm-related costs(5)
Other5 
18 
Regulatory required programs(a)
23 
Total increase$41 
__________
(a)Increase due to the cost recovery associated with EmPOWER Maryland. Please refer to 2024 10-K Note 3 — Regulatory Matters for additional information.
The changes in Depreciation and amortization expense consisted of the following:
Three Months Ended
March 31, 2025
Increase
Depreciation and amortization$2 
Regulatory required programs(a)
6 
Regulatory asset amortization6 
Total increase$14 
__________
(a)Increase due to the cost recovery associated with EmPOWER Maryland. Please refer to 2024 10-K Note 3 — Regulatory Matters for additional information.

Interest expense, net increased by $8 million for the three months ended March 31, 2025 compared to the same period in 2024, primarily due to the issuance of debt in the second quarter of 2024.
Taxes other than income taxes increased by $7 million for the three months ended March 31, 2025 compared to the same period in 2024, primarily due to increased property taxes.
Effective income tax rates were 21.5% and 8.3% for the three months ended March 31, 2025 and 2024, respectively. See Note 6 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the effective income tax rates.
103



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, 2025 compared to the same period in 2024. See the Results of Operations for Pepco, DPL, and ACE for additional information.
Three Months Ended
March 31,		Favorable (Unfavorable) Variance
20252024
PHI$194 $168 $26 
Pepco97 75 22 
DPL
69 66 3 
ACE31 29 2 
Other(a)
(3)(2)(1)
__________
(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, 2025 Compared to Three Months Ended March 31, 2024. Net Income increased by $26 million primarily due to favorable impacts from the Maryland and District of Columbia multi-year plans, higher DPL Delaware electric and gas DISC rates, higher transmission rates at Pepco and DPL, favorable weather conditions at DPL, partially offset by an increase in interest and depreciation expense at Pepco and DPL.
104



Pepco

Results of Operations — Pepco
Three Months Ended March 31,Favorable (Unfavorable) Variance
20252024
Operating revenues$859 $759 $100 
Operating expenses
Purchased power 318 281 (37)
Operating and maintenance159 150 (9)
Depreciation and amortization105 107 2 
Taxes other than income taxes113 102 (11)
Total operating expenses695 640 (55)
Gain on sales of assets(1)— (1)
Operating income 163 119 44 
Other income and (deductions)
Interest expense, net(52)(45)(7)
Other, net11 15 (4)
Total other income and (deductions)(41)(30)(11)
Income before income taxes122 89 33 
Income taxes25 14 (11)
Net income$97 $75 $22 
Three Months Ended March 31, 2025 Compared to Three Months Ended March 31, 2024. Net Income increased by $22 million primarily due to favorable impacts from the Maryland and District of Columbia multi-year plans and higher transmission rates, partially offset by an increase in interest and depreciation expense.
The changes in Operating revenues consisted of the following:
Three Months Ended
March 31, 2025
Increase (Decrease)
Distribution$45 
Transmission6 
Other(3)
48 
Regulatory required programs52 
Total increase$100 
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 Maryland20252024
Residential557,672 552,215 
Small commercial & industrial30,555 30,760 
Large commercial & industrial18,986 18,944 
Public authorities & electric railroads177 179 
Total607,390 602,098 
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Pepco

Distribution Revenue increased for the three months ended March 31, 2025 compared to the same period in 2024 primarily due to favorable impacts of the Maryland and District of Columbia multi-year plans and customer growth in Maryland.
Transmission Revenue. Under a FERC-approved formula, transmission revenue varies from year to year based upon fluctuations in the underlying costs and capital investments being recovered. Transmission revenue increased for the three months ended March 31, 2025, compared to the same period in 2024, primarily due to increases in underlying costs and capital investments.
Other Revenue includes rental revenue, revenue related to late payment charges, mutual assistance revenues, and recoveries of other taxes.
Regulatory Required Programs represent revenues collected under approved riders to recover costs incurred for regulatory programs such as energy efficiency programs, DC PLUG, and SOS procurement and administrative costs. The riders are designed to provide full and current cost recovery as well as a return in certain instances. The costs of these programs are included in Purchased power expense, Operating and maintenance expense, Depreciation and amortization expense, and Taxes other than income taxes. Customers have the choice to purchase electricity from competitive electric generation suppliers. Customer choice programs do not impact the volume of deliveries, as Pepco remains the distribution service provider for all customers and charges a regulated rate for distribution service, which is recorded in Operating revenues. For customers that choose to purchase electric generation from competitive suppliers, Pepco acts as the billing agent and therefore, Pepco does not record Operating revenues or Purchased power expense related to the electricity. For customers that choose to purchase electric generation from Pepco, Pepco is permitted to recover the electricity and REC procurement costs from customers and therefore records the amounts related to the electricity and RECs in Operating revenues and Purchased power expense. Pepco recovers electricity and REC procurement costs from customers with a slight mark-up.
See Note 4 — Segment Information of the Combined Notes to Consolidated Financial Statements for the presentation of Pepco's revenue disaggregation.
The increase of $37 million for the three months ended March 31, 2025, compared to the same period in 2024, in Purchased power expense is fully offset in Operating revenues as part of regulatory required programs.
The changes in Operating and maintenance expense consisted of the following:
Three Months Ended
March 31, 2025
(Decrease) Increase
Labor, other benefits, contracting and materials$(6)
Credit loss expense(5)
BSC and PHISCO costs(2)
Other 5 
(8)
Regulatory required programs(a)
17 
Total increase$9 
_________
(a)Increase primarily due to the cost recovery associated with EmPOWER Maryland. Please refer to 2024 10-K Note 3 — 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, 2025
Increase (Decrease)
Depreciation and amortization(a)
$7 
Regulatory asset amortization1 
Regulatory required programs(b)
(10)
Total decrease$(2)
__________
(a)Depreciation and amortization increased primarily due to ongoing capital expenditures.
(b)Decrease includes the cost recovery associated with EmPOWER Maryland. Please refer to 2024 10-K Note 3 — Regulatory Matters additional information.
Taxes other than income taxes increased $11 million for the three months ended March 31, 2025, compared to the same period in 2024, primarily due to increases in utility taxes, which are offset in revenues, and property taxes.
Effective income tax rates were 20.5% and 15.7% for the three months ended March 31, 2025 and 2024. See Note 6 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the effective income tax rates.
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Table of Contents
DPL

Results of Operations — DPL
Three Months Ended March 31,Favorable (Unfavorable) Variance
20252024
Operating revenues$548 $491 $57 
Operating expenses
Purchased power and fuel 247 215 (32)
Operating and maintenance106 95 (11)
Depreciation and amortization63 61 (2)
Taxes other than income taxes21 20 (1)
Total operating expenses437 391 (46)
Operating income111 100 11 
Other income and (deductions)
Interest expense, net(25)(22)(3)
Other, net4 5 (1)
Total other income and (deductions)(21)(17)(4)
Income before income taxes90 83 7 
Income taxes21 17 (4)
Net income $69 $66 $3 
Three Months Ended March 31, 2025 Compared to Three Months Ended March 31, 2024. Net income increased $3 million primarily due to favorable weather conditions at Delaware electric and natural gas service territories, higher Delaware electric and gas DSIC rates, and higher transmission rates, partially offset by an increase in depreciation and interest expense.
The changes in Operating revenues consisted of the following:
Three Months Ended
March 31, 2025
Increase
ElectricGasTotal
Weather$4 $2 $6 
Volume— 3 3 
Distribution5 1 6 
Transmission3 — 3 
12 6 18 
Regulatory required programs30 9 39 
Total increase$42 $15 $57 
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, 2025 compared to the same period in 2024, Operating revenues related to weather increased due to favorable weather conditions in DPL's Delaware electric and natural gas service territories.
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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, 2025, compared to same period in 2024 and normal weather consisted of the following:
Three Months Ended March 31,% Change
Delaware Electric Service Territory20252024Normal2025 vs. 20242025 vs. Normal
Heating Degree-Days2,399 2,204 2,420 8.8 %(0.9)%
Cooling Degree-Days9 — 1 — %800.0 %
Three Months Ended March 31,% Change
Delaware Natural Gas Service Territory20252024Normal2025 vs. 20242025 vs. Normal
Heating Degree-Days2,399 2,204 2,454 8.8 %(2.2)%
Volume, exclusive of the effects of weather, increased for the three months ended March 31, 2025 compared to the same period in 2024, primarily due to an increase in customer usage and customer growth.
Electric Retail Deliveries to Delaware Customers (in GWhs)Three Months Ended
March 31,		% Change
Weather - Normal
% Change(b)
20252024
Residential930 857 8.5 %1.9 %
Small commercial & industrial354 339 4.4 %2.0 %
Large commercial & industrial690 718 (3.9)%(4.7)%
Public authorities & electric railroads7 7 — %1.9 %
Total electric retail deliveries(a)
1,981 1,921 3.1 %(0.5)%
At March 31,
Number of Total Electric Customers (Maryland and Delaware)20252024
Residential491,907 486,950 
Small commercial & industrial64,999 64,338 
Large commercial & industrial1,251 1,260 
Public authorities & electric railroads617 593 
Total558,774 553,141 
__________
(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)
20252024
Residential4,590 3,913 17.3 %8.7 %
Small commercial & industrial1,970 1,717 14.7 %5.1 %
Large commercial & industrial428 428 — %— %
Transportation2,106 1,960 7.4 %2.9 %
Total natural gas deliveries(a)
9,094 8,018 13.4 %6.1 %
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DPL

At March 31,
Number of Delaware Natural Gas Customers20252024
Residential131,716 130,427 
Small commercial & industrial10,254 10,182 
Large commercial & industrial15 16 
Transportation161 163 
Total142,146 140,788 
__________
(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, 2025 compared to the same period in 2024 primarily due to higher electric and natural gas DSIC rates in Delaware that became effective January 2025.
Transmission Revenue. Under a FERC-approved formula, transmission revenue varies from year to year based upon fluctuations in the underlying costs and capital investments being recovered. During the three months ended March 31, 2025 compared to the same period in 2024, transmission revenue increased due to increases in underlying costs and capital investments.
Other Revenue includes rental revenue, service connection fees, and mutual assistance revenues.
Regulatory Required Programs represent revenues collected under approved riders to recover costs incurred for regulatory programs such as energy efficiency programs, DE Renewable Portfolio Standards, SOS procurement and administrative costs, and GCR costs. The riders are designed to provide full and current cost recovery as well as a return in certain instances. The costs of these programs are included in Purchased power and fuel expense, Operating and maintenance expense, Depreciation and amortization expense, and Taxes other than income taxes. All customers have the choice to purchase electricity from competitive electric generation suppliers; however, only certain commercial and industrial customers have the choice to purchase natural gas from competitive natural gas suppliers. Customer choice programs do not impact the volume of deliveries as DPL remains the distribution service provider for all customers and charges a regulated rate for distribution service, which is recorded in Operating revenues. For customers that choose to purchase electric generation or natural gas from competitive suppliers, DPL either acts as the billing agent or the competitive supplier separately bills its own customers, and therefore does not record Operating revenues or Purchased power and fuel expense related to the electricity and/or natural gas. For customers that choose to purchase electric generation or natural gas from DPL, DPL is permitted to recover the electricity, natural gas, and REC procurement costs from customers and therefore records the amounts related to the electricity, natural gas, and RECs in Operating revenues and Purchased power and fuel expense. DPL recovers electricity and REC procurement costs from customers with a slight mark-up, and natural gas costs without mark-up.
See Note 4 — Segment Information of the Combined Notes to Consolidated Financial Statements for the presentation of DPL's revenue disaggregation.
The increase of $32 million for the three months ended March 31, 2025, compared to the same period in 2024, respectively, in Purchased power and fuel expense is fully offset in Operating revenues as part of regulatory required programs.
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DPL

The changes in Operating and maintenance expense consisted of the following:
Three Months Ended
March 31, 2025
Increase (Decrease)
Credit loss expense$4 
BSC and PHISCO costs1 
Storm-related costs(3)
Labor and contracting(3)
Other
1 
— 
Regulatory required programs(a)
11 
Total increase$11 
__________
(a)Increase primarily due to the cost recovery associated with EmPOWER Maryland. Please refer to 2024 10-K Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.
The changes in Depreciation and amortization expense consisted of the following:
Three Months Ended
March 31, 2025
Increase (Decrease)
Depreciation and amortization(a)
$4 
Regulatory asset amortization— 
Regulatory required programs(b)
(2)
Total increase$2 
__________
(a)Depreciation and amortization increased primarily due to ongoing capital expenditures.
(b)Decrease includes the cost recovery associated with EmPOWER Maryland. Please refer to 2024 10-K Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information
Effective income tax rates were 23.3% and 20.5% for the three months ended March 31, 2025 and 2024, respectively. See Note 6 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the effective income tax rates.
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ACE

Results of Operations — ACE
Three Months Ended March 31,Favorable (Unfavorable) Variance
20252024
Operating revenues$373 $358 $15 
Operating expenses
Purchased power 157 140 (17)
Operating and maintenance90 87 (3)
Depreciation and amortization64 74 10 
Taxes other than income taxes2 2 — 
Total operating expenses313 303 (10)
Operating income 60 55 5 
Other income and (deductions)
Interest expense, net(21)(20)(1)
Other, net3 5 (2)
Total other income and (deductions)(18)(15)(3)
Income before income taxes42 40 2 
Income taxes11 11 — 
Net income $31 $29 $2 

Three Months Ended March 31, 2025 Compared to Three Months Ended March 31, 2024. Net income remained relatively consistent.
The changes in Operating revenues consisted of the following:
Three Months Ended
March 31, 2025
Increase (Decrease)
Distribution$2 
Transmission(2)
— 
Regulatory required programs15 
Total increase$15 
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 became effective, prospectively, in the third quarter of 2021. The CIP compares current distribution revenues by customer class to approved target revenues established in ACE’s most recent distribution base rate case. The CIP is calculated annually, and recovery is subject to certain conditions, including an earnings test and ceilings on customer rate increases. 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 Customers20252024
Residential508,354 505,793 
Small commercial & industrial62,861 62,704 
Large commercial & industrial2,824 2,893 
Public authorities & electric railroads723 728 
Total574,762 572,118 
Distribution Revenue remained relatively consistent for the three months ended March 31, 2025 compared to the same period in 2024.
Transmission Revenues Under a FERC-approved formula, transmission revenue varies from year to year based upon fluctuations in the underlying costs and capital investments being recovered. Transmission revenue remained relatively consistent for the three months ended March 31, 2025 compared to the same period in 2024.
Other Revenue includes rental revenue, revenue related to late payment charges, mutual assistance revenues, and recoveries of other taxes.
Regulatory Required Programs represent revenues collected under approved riders to recover costs incurred for regulatory programs such as energy efficiency programs, Societal Benefits Charge, Transition Bonds, and BGS procurement and administrative costs. The riders are designed to provide full and current cost recovery as well as a return in certain instances. The costs of these programs are included in Purchased power expense, Operating and maintenance expense, Depreciation and amortization expense, and Taxes other than income taxes. Customers have the choice to purchase electricity from competitive electric generation suppliers. Customer choice programs do not impact the volume of deliveries, as ACE remains the distribution service provider for all customers and charges a regulated rate for distribution service, which is recorded in Operating revenues. For customers that choose to purchase electric generation from competitive suppliers, ACE acts as the billing agent and therefore, ACE does not record Operating revenues or Purchased power expense related to the electricity. For customers that choose to purchase electric generation from ACE, ACE is permitted to recover the electricity, ZEC, and REC procurement costs without mark-up and therefore records equal and offsetting amounts in Operating revenues and Purchased power expense related to the electricity, ZECs, and RECs.
See Note 4 — Segment Information of the Combined Notes to Consolidated Financial Statements for the presentation of ACE's revenue disaggregation.
The increase of $17 million for the three months ended March 31, 2025, respectively, compared to the same period in 2024 in Purchased power expense is fully offset in Operating revenues as part of regulatory required programs.
The changes in Operating and maintenance expense consisted of the following:
Three Months Ended
March 31, 2025
Increase (Decrease)
Storm-related costs$1 
Credit Loss Expense1 
BSC and PHISCO costs(1)
Labor and contracting(2)
Other(3)
(4)
Regulatory required programs7 
Total increase$3 
__________

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ACE

The changes in Depreciation and amortization expense consisted of the following:
Three Months Ended
March 31, 2025
Increase (Decrease)
Depreciation and amortization(a)
$2 
Regulatory asset amortization(3)
Regulatory required programs(9)
Total decrease$(10)
__________
(a)Depreciation and amortization increased primarily due to ongoing capital expenditures.
Effective income tax rates were 26.2% and 27.5% for the three months ended March 31, 2025 and 2024, respectively. See Note 6 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the effective income tax rates.
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Liquidity and Capital Resources (All Registrants)
All results included throughout the liquidity and capital resources section are presented on a GAAP basis.
The Registrants’ operating and capital expenditures requirements are provided by internally generated cash flows from operations, as well as funds from external sources in the capital markets and through bank borrowings. The Registrants’ businesses are capital intensive and require considerable capital resources. Each of the Registrants annually evaluates its financing plan, dividend practices, and credit line sizing, focusing on maintaining its investment grade ratings while meeting its cash needs to fund capital requirements, including construction expenditures, retire debt, pay dividends, and fund pension and OPEB obligations. The Registrants spend a significant amount of cash on capital improvements and construction projects that have a long-term return on investment. Additionally, the Utility Registrants operate in rate-regulated environments in which the amount of new investment recovery may be delayed or limited and where such recovery takes place over an extended period of time. Each Registrant’s access to external financing on reasonable terms depends on its credit ratings and current overall capital market business conditions, including that of the utility industry in general. If these conditions deteriorate to the extent that the Registrants no longer have access to the capital markets at reasonable terms, the Registrants have access to credit facilities with aggregate bank commitments of $4.0 billion. The Registrants utilize their credit facilities to support their commercial paper programs, provide for other short-term borrowings, and to issue letters of credit. See the “Credit Matters and Cash Requirements” section below for additional information. The Registrants expect cash flows to be sufficient to meet operating expenses, financing costs, and capital expenditure requirements. See Note 9 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information on the Registrants’ debt and credit agreements.
Cash Flows from Operating Activities
The Utility Registrants' cash flows from operating activities primarily result from the transmission and distribution of electricity and, in the case of PECO, BGE, and DPL, gas distribution services. The Utility Registrants' distribution services are provided to an established and diverse base of retail customers. The Utility Registrants' future cash flows may be affected by the economy, weather conditions, future legislative initiatives, future regulatory proceedings with respect to their rates or operations, and their ability to achieve operating cost reductions. Additionally, ComEd is required to purchase CMCs from participating nuclear-powered generating facilities for a five-year period that began in June 2022, and all of its costs of doing so will be recovered through a rider. The price to be paid for each CMC is established through a competitive bidding process. ComEd will provide net payments to, or collect net payments from, customers for the difference between customer credits issued and the credit to be received from the participating nuclear-powered generating facilities. ComEd’s cash flows are affected by the establishment of CMC prices and the timing of recovering costs through the CMC regulatory asset.
See Note 3 — Regulatory Matters of the 2024 Form 10-K and Notes 2 — Regulatory Matters and 11 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for additional information on regulatory and legal proceedings and proposed legislation.
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The following table provides a summary of the change in cash flows from operating activities for the three months ended March 31, 2025 and 2024 by Registrant:
Increase (decrease) in cash flows from operating activitiesExelonComEdPECOBGE PHIPepcoDPLACE
Net income (loss)$250 $109 $117 $(4)$26 $22 $3 $2 
Adjustments to reconcile net income to cash:
Non-cash operating activities408 158 31 129 65 31 14 14 
Collateral received, net37 (3)12 1 27 11 9 5 
Income taxes38 51 13 7 1 3 3 — 
Pension and non-pension postretirement benefit contributions(181)(184)(7)(9)30 — — 4 
Regulatory assets and liabilities, net(166)(239)47 14 28 7 3 19 
Changes in working capital and other assets and liabilities(178)(93)(60)(33)(64)(65)(27)40 
Increase (decrease) in cash flows from operating activities$208 $(201)$153 $105 $113 $9 $5 $84 
Changes in the Registrants' cash flows from operations were generally consistent with changes in each Registrant’s respective results of operations, as adjusted by changes in working capital in the normal course of business, except as discussed below. Significant operating cash flow impacts for the Registrants for the three months ended March 31, 2025 and 2024 were as follows:
•See Note 14 — Supplemental Financial Information of the Combined Notes to Consolidated Financial Statements and the Registrants’ Consolidated Statements of Cash Flows for additional information on non-cash operating activities.
•Changes in collateral depended upon whether the Registrant was in a net mark-to-market liability or asset position, and collateral may have been required to be posted with or collected from its counterparties. In addition, the collateral posting and collection requirements differed depending on whether the transactions were on an exchange or in the over-the-counter markets. Changes in collateral for the Registrants are dependent upon the credit exposure of procurement contracts that may require suppliers to post collateral. The amount of cash collateral received from external counterparties remained relatively consistent comparing the three months ended March 31, 2025 to the three months ended March 31, 2024. See Note 8 — Derivative Financial Instruments for additional information.
•See Note 6 — Income Taxes of the Combined Notes to Consolidated Financial Statements and the Registrants' Consolidated Statements of Cash Flows for additional information on income taxes.
•Changes in Pension and non-pension postretirement benefit contributions relates to Exelon's increased contributions to the Qualified Plans during the three months ended March 31, 2025. See Note 14 — Retirement Benefits of the 2024 Form 10-K for additional information.
•Changes in regulatory assets and liabilities, net, are due to the timing of cash payments for costs recoverable, or cash receipts for costs recovered, under our regulatory mechanisms differing from the recovery period of those costs. Included within the changes is energy efficiency spend for ComEd of $84 million and $80 million for the three months ended March 31, 2025 and 2024, respectively. Also included within the changes is energy efficiency and demand response programs spend for BGE, Pepco, DPL and ACE of $22 million, $6 million, $3 million, and $5 million for the three months ended March 31, 2025 and $28 million, $10 million, $4 million, and $8 million for the three months ended March 31, 2024, respectively. PECO had no energy efficiency and demand response programs spend recorded to the regulatory asset for the three months ended March 31, 2025 and 2024. See Note 2 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.
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•Changes in working capital and other assets and liabilities for the Utility Registrants and Exelon Corporate totaled $(238) million and $(178) million, respectively. The change in working capital and other noncurrent assets and liabilities for Exelon Corporate and the Utility Registrants is dependent upon the normal course of operations for all Registrants. For ComEd, it is also dependent upon whether the participating nuclear-powered generating facilities are owed money from ComEd as a result of the established pricing for CMCs. For the three months ended March 31, 2025, the established pricing resulted in both a receivable from, and payable to, nuclear-powered generating facilities. The change in receivable from nuclear-powered generating facilities, and the change in payable to nuclear-powered generating facilities, are reflected as a change in accounts receivable and a change in accounts payable and accrued expenses, respectively, within the cash flows from operations.
Cash Flows from Investing Activities
The following table provides a summary of the change in cash flows from investing activities for the three months ended March 31, 2025 and 2024 by Registrant:
(Decrease) increase in cash flows from investing activitiesExelonComEdPECOBGE PHIPepcoDPLACE
Capital expenditures$(179)$4 $(63)$(82)$(60)$(11)$(22)$(16)
Proceeds from sales of assets(2)— — — — — — — 
Changes in intercompany money pool— — — — — 134 (12)— 
Other investing activities6 — — (5)— — — — 
(Decrease) increase in cash flows from investing activities$(175)$4 $(63)$(87)$(60)$123 $(34)$(16)
Significant investing cash flow impacts for the Registrants for three months ended March 31, 2025 and 2024 were as follows:
•Changes in capital expenditures are primarily due to the timing of cash expenditures for capital projects. See the "Credit Matters and Cash Requirements" section below for additional information on projected capital expenditure spending for the Utility Registrants.
•Changes in intercompany money pool are driven by short-term borrowing needs. Refer to more information regarding the intercompany money pool below.
Cash Flows from Financing Activities
The following table provides a summary of the change in cash flows from financing activities for the three months ended March 31, 2025 and 2024 by Registrant:
Increase (decrease) in cash flows from financing activitiesExelonComEdPECOBGE PHIPepcoDPLACE
Changes in short-term borrowings, net$(458)$183 $(27)$(8)$(136)$(68)$(81)$13 
Long-term debt, net701 — — — (100)(75)(50)25 
Changes in intercompany money pool— — — — 3 — — (122)
Issuance of common stock173 — — — — — — — 
Dividends paid on common stock(22)(9)(37)(6)— (15)(1)2 
Distributions to member— — — — (14)— — — 
Contributions from parent/member— 48 (17)— (135)(94)(55)13 
Other financing activities9 (1)— — 13 10 — — 
Increase (decrease) in cash flows from financing activities$403 $221 $(81)$(14)$(369)$(242)$(187)$(69)
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Significant financing cash flow impacts for the Registrants for the three months ended March 31, 2025 and 2024 were as follows:
•Changes in short-term borrowings, net, is driven by repayments on and issuances of notes due in less than 365 days. See Note 9 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information on short-term borrowings for the Registrants.
•Long-term debt, net, varies due to debt issuances and redemptions each year. See Note 9 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information on debt issuances. Refer to the "Debt" section below for additional information.
•Changes in intercompany money pool are driven by short-term borrowing needs. Refer below for more information regarding the intercompany money pool.
•Issuance of common stock relates to issuances of Exelon common stock during the first quarter of 2025. See Note 12 — Shareholders' Equity of the Combined Notes to Consolidated Financial Statements for additional information.
•Exelon’s ability to pay dividends on its common stock depends on the receipt of dividends paid by its operating subsidiaries. The payments of dividends to Exelon by its subsidiaries in turn depend on their results of operations and cash flows and other items affecting retained earnings. See Note 18 — Commitments and Contingencies of the 2024 Form 10-K for additional information on dividend restrictions. See below for quarterly dividends declared.
Debt
See Note 9 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information on the Registrants’ debt issuances.
During the three months ended March 31, 2025, no long-term debt was retired and/or redeemed.
Dividends
Quarterly dividends declared by the Exelon Board of Directors during the three months ended March 31, 2025 and for the second quarter of 2025 were as follows:
PeriodDeclaration DateShareholder of Record DateDividend Payable Date
Cash per Share(a)
First Quarter 2025February 12, 2025February 24, 2025March 14, 2025$0.4000 
Second Quarter 2025April 29, 2025May 12, 2025June 13, 2025$0.4000 
__________
(a)Exelon's Board of Directors approved an updated dividend policy for 2025. The 2025 quarterly dividend will be $0.40 per share.
Credit Matters and Cash Requirements
The Registrants fund liquidity needs for capital investment, working capital, energy hedging, and other financial commitments through cash flows from continuing operations, public debt offerings, commercial paper markets, and large, diversified credit facilities. The credit facilities include $4.0 billion in aggregate total commitments of which $3.4 billion was available to support additional commercial paper as of March 31, 2025, 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, 2025 to fund their short-term liquidity needs, when necessary. Exelon Corporate and the Utility Registrants each have a 5-year revolving credit facility. See Note 9 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information. The Registrants routinely review the sufficiency of their liquidity position, including appropriate sizing of credit facility commitments, by performing various stress test scenarios, such as commodity price movements, increases in margin-related transactions, changes in hedging levels, and the impacts of hypothetical credit downgrades. The Registrants
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have continued to closely monitor events in the financial markets and the financial institutions associated with the credit facilities, including monitoring credit ratings and outlooks, credit default swap levels, capital raising, and merger activity. See PART I. ITEM 1A. RISK FACTORS of the 2024 Form 10-K for additional information regarding the effects of uncertainty in the capital and credit markets.
The Registrants believe their cash flows from operating activities, access to credit markets, and their credit facilities provide sufficient liquidity to support the estimated future cash requirements.
On August 4, 2022, Exelon executed an equity distribution agreement (“Equity Distribution Agreement”), with certain sales agents and forward sellers and certain forward purchasers, establishing an ATM equity distribution program under which it may offer and sell shares of its Common stock, having an aggregate gross sales price of up to $1.0 billion. Exelon has no obligation to offer or sell any shares of Common stock under the Equity Distribution Agreement and may, at any time, suspend or terminate offers and sales under the Equity Distribution Agreement.
During the first quarter 2025, Exelon issued approximately 4.0 million shares of Common stock at an average gross price of $43.42 per share. The net proceeds from the issuance were $173 million, which were used for general corporate purposes.
In the first quarter of 2025, Exelon entered into two separate forward sale agreements for 1.7 million shares and 4.0 million shares of Common stock, with an initial forward price of $42.81 and $43.42 per share, respectively. The forward sale agreements require Exelon to, at its election prior to December 15, 2025, either (i) physically settle the transactions by issuing shares of its Common stock to the forward counterparties in exchange for net proceeds at the then-applicable forward sale price specified by the agreements or (ii) net settle the transactions in whole or in part through the delivery to the forward counterparties or receipt from the forward counterparties of cash or shares in accordance with the provisions of the agreements. 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, 2025, approximately 5.6 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, $283 million of Common stock remained available for sale pursuant to the ATM program as of March 31, 2025.
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, 2025 and available credit facility capacity prior to any incremental collateral at March 31, 2025:
PJM Credit Policy Collateral
Other Incremental Collateral Required(a)
Available Credit Facility Capacity Prior to Any Incremental Collateral
ComEd$13 $— $638 
PECO— 45 596 
BGE— 51 338 
Pepco— — 298 
DPL— 15 300 
ACE— — 300 
__________
(a)Represents incremental collateral related to natural gas procurement contracts.
Capital Expenditure Spending
As of March 31, 2025, the most recent estimates of capital expenditures for plant additions and improvements for 2025 are as follows:        
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(In millions)TransmissionDistributionGas
Total(a)
ExelonN/AN/AN/A$8,900 
ComEd950 2,250 N/A3,200 
PECO200 1,300 375 1,875 
BGE700 625 525 1,850 
PHI650 1,400 100 2,150 
Pepco250 700 N/A950 
DPL175 300 75 550 
ACE200 250 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
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 $275 million in 2025. Unlike the qualified pension plans, Exelon’s non-qualified pension plans are not funded, given that they are not subject to statutory minimum contribution requirements.
While OPEB plans are also not subject to statutory minimum contribution requirements, Exelon does fund certain of its plans. For Exelon's funded OPEB plans, contributions generally equal accounting costs, however, Exelon’s management has historically considered several factors in determining the level of contributions to its OPEB plans, including liabilities management, levels of benefit claims paid, and regulatory implications (amounts deemed prudent to meet regulatory expectations and best assure continued rate recovery).
To the extent interest rates decline significantly or the pension and OPEB plans earn less than the expected asset returns, annual pension contribution requirements in future years could increase. Conversely, to the extent interest rates increase significantly or the pension and OPEB plans earn greater than the expected asset returns, annual pension and OPEB contribution requirements in future years could decrease. Additionally, expected contributions could change if Exelon changes its pension or OPEB funding strategy.
See Note 14 — Retirement Benefits of the Combined Notes to Consolidated Financial Statements of the 2024 Form 10-K for additional information on pension and OPEB contributions.
Credit Facilities
Exelon Corporate, ComEd, and BGE meet their short-term liquidity requirements primarily through the issuance of commercial paper. PECO meets its short-term liquidity requirements primarily through the issuance of commercial paper and borrowings from the Exelon intercompany money pool. Pepco, DPL, and ACE meet their short-term liquidity requirements primarily through the issuance of commercial paper and borrowings from the PHI intercompany money pool. PHI Corporate meets its short-term liquidity requirements primarily through the issuance of short-term notes and the Exelon intercompany money pool. The Registrants may use their respective credit facilities for general corporate purposes, including meeting short-term funding requirements and the issuance of letters of credit.
See Note 9 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information on the Registrants’ credit facilities and short term borrowing activity.
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Security Ratings
The Registrants’ access to the capital markets, including the commercial paper market, and their respective financing costs in those markets, may depend on the securities ratings of the entity that is accessing the capital markets.
The Registrants’ borrowings are not subject to default or prepayment as a result of a downgrading of securities, although such a downgrading of a Registrant’s securities could increase fees and interest charges under that Registrant’s credit agreements.
As part of the normal course of business, the Registrants enter into contracts that contain express provisions or otherwise permit the Registrants and their counterparties to demand adequate assurance of future performance when there are reasonable grounds for doing so. In accordance with the contracts and applicable contracts law, if the Registrants are downgraded by a credit rating agency, it is possible that a counterparty would attempt to rely on such a downgrade as a basis for making a demand for adequate assurance of future performance, which could include the posting of collateral. See Note 8 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information on collateral provisions.
The credit ratings for ComEd, BGE, PHI, Pepco, DPL, and ACE did not change for the three months ended March 31, 2025. On January 17, 2025, Fitch Ratings affirmed and withdrew the long-term and short-term issuer default ratings along with individual securities ratings of the Registrants for commercial reasons. On February 7, 2025, S&P raised its long-term issuer credit rating for Exelon and PECO from 'BBB+' to 'A-', and raised its rating on Exelon’s senior unsecured debt from ‘BBB’ to 'BBB+'. S&P also affirmed its short-term issuer and commercial paper rating for Exelon and PECO of 'A-2'.
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, 2025, are presented in the following table:
During the Three Months Ended March 31, 2025At March 31, 2025
Exelon Intercompany Money PoolMaximum
Contributed		Maximum
Borrowed		Contributed
(Borrowed)
Exelon Corporate$578 $— $295 
PECO— (253)— 
BSC— (378)(281)
PHI Corporate— (85)(74)
PCI60 — 60 
During the Three Months Ended March 31, 2025At March 31, 2025
PHI Intercompany Money PoolMaximum
Contributed		Maximum
Borrowed
Contributed
(Borrowed)
Pepco$1 $— $— 
DPL12 (1)12 
ACE— (12)(12)
Shelf Registration Statements
On February 21, 2024, PECO and BGE, as co-registrants, filed with the SEC a standalone automatically effective shelf registration statement, unlimited in amount, which can be used to issue PECO and BGE debt securities through the expiration date of February 20, 2027. On February 13, 2025, as most recently amended on March 27, 2025, Exelon Corporation and ComEd, as co-registrants filed a shelf registration statement with the SEC ("Exelon and ComEd Shelf Registration") for authorization of up to $12,575 million in additional security registration, to be used to issue Exelon Corporate debt securities and equity securities, as well as ComEd debt securities. The Exelon and ComEd Shelf Registration was declared effective by the SEC on April 8, 2025, and is
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effective through April 8, 2028. The ability of Exelon Corporation, ComEd, PECO and BGE to sell securities off their corresponding registration Statements, or to access the private placement markets, will depend on a number of factors at the time of the proposed sale, including other required regulatory approvals, as applicable, the current financial condition of the Registrant, its securities ratings and market conditions.
Pepco, DPL and ACE periodically issue securities through the private placement markets. Pepco, DPL and ACE's ability to access the private placement markets will depend on a number of factors at the time of the proposed sale, including other required regulatory approvals, as applicable, current financial condition, securities ratings and market conditions.
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, 2025
Short-term Financing AuthorityRemaining Long-term Financing Authority
CommissionExpiration DateAmountCommissionExpiration DateAmount
ComEdFERCDecember 31, 2025$2,500 ICCJanuary 1, 2027 & May 1, 2027$2,318 
PECOFERCDecember 31, 20251,500 PAPUCDecember 31, 20272,900 
BGE(b)
FERCDecember 31, 2025700 MDPSCN/A2,500 
Pepco(a)
FERCDecember 31, 2025500 MDPSC / DCPSCDecember 31, 2025175 
DPL(a)
FERCDecember 31, 2025500 MDPSC / DEPSCDecember 31, 2025250 
ACENJBPUDecember 31, 2025350 NJBPUDecember 31, 2026775 
__________

(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, 2025.
(b)On February 20, 2025, BGE received approval from the MDPSC for $2.2 billion in additional long-term financing authority. The additional financing authority has an effective date of February 20, 2025.
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ITEM 3.    QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK
The Registrants hold commodity and financial instruments that are exposed to the following market risks:
•Commodity price risk, which is discussed further below.
•Counterparty credit risk associated with non-performance by counterparties on executed derivative instruments and participation in all, or some of the established, wholesale spot energy markets that are administered by PJM. The credit policies of PJM may, under certain circumstances, require that losses arising from the default of one member on spot energy market transactions be shared by the remaining participants. See Note 8 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for a detailed discussion of counterparty credit risk related to derivative instruments.
•Equity price and interest rate risk associated with Exelon’s pension and OPEB plan trusts. See Note 7 — Retirement Benefits of the 2024 Form 10-K for additional information.
•Interest rate risk associated with changes in interest rates for the Registrants’ outstanding long-term debt. This risk is significantly reduced as substantially all of the Registrants’ outstanding debt has fixed interest rates. There is inherent interest rate risk related to refinancing maturing debt by issuing new long-term debt. The Registrants use a combination of fixed-rate and variable-rate debt to manage interest rate exposure. See Note 9 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information. In addition, Exelon may utilize interest rate derivatives to lock in rate levels in anticipation of future financings, which are typically designated as cash flow hedges. See Note 8 – Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information.
The Registrants operate primarily under cost-based rate regulation limiting exposure to the effects of market risk. Hedging programs are utilized to reduce exposure to energy and natural gas price volatility and have no direct earnings impacts as the costs are fully recovered through regulatory-approved recovery mechanisms.
Exelon manages these risks through risk management policies and objectives for risk assessment, control and valuation, counterparty credit approval, and the monitoring and reporting of risk exposures. Risk management issues are reported to Exelon’s Executive Committee, the Risk Management Committees of each Utility Registrant, and the Audit and Risk Committee of Exelon’s Board of Directors.
Commodity Price Risk
Commodity price risk is associated with price movements resulting from changes in supply and demand, fuel costs, market liquidity, weather conditions, governmental regulatory and environmental policies, and other factors. To the extent the total amount of energy Exelon purchases differs from the amount of energy it has contracted to sell, Exelon is exposed to market fluctuations in commodity prices. Exelon seeks to mitigate its commodity price risk through the sale and purchase of electricity and natural gas.
ComEd entered into 20-year floating-to-fixed renewable energy swap contracts beginning in June 2012, which are considered an economic hedge and have changes in fair value recorded to an offsetting regulatory asset or liability. ComEd has block energy contracts to procure electric supply that are executed through a competitive procurement process, which are considered derivatives and qualify for NPNS, and as a result are accounted for on an accrual basis of accounting. PECO, BGE, Pepco, DPL, and ACE have contracts to procure electric supply that are executed through a competitive procurement process. PECO, BGE, Pepco, DPL, and ACE have certain full requirements contracts, which are considered derivatives and qualify for NPNS, and as a result are accounted for on an accrual basis of accounting. Other full requirements contracts are not derivatives.
PECO, BGE, and DPL also have executed derivative natural gas contracts, which qualify for NPNS, to hedge their long-term price risk in the natural gas market. The hedging programs for natural gas procurement have no direct impact on their financial statements.
For additional information on these contracts, see Note 8 — Derivative Financial Instruments and Note 10 — Fair Value of Financial Assets and Liabilities of the Combined Notes to Consolidated Financial Statements.
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The following table presents the maturity and source of fair value for Exelon’s and ComEd’s mark-to-market commodity contract net liabilities. These net liabilities are associated with ComEd’s floating-to-fixed energy swap contracts with unaffiliated suppliers. The table provides two fundamental pieces of information. First, the table provides the source of fair value used in determining the carrying amount of Exelon's and ComEd's total mark-to-market net liabilities. Second, the table shows the maturity, by year, of Exelon's and ComEd's commodity contract net liabilities giving an indication of when these mark-to-market amounts will settle and either generate or require cash. See Note 10 — Fair Value of Financial Assets and Liabilities of the Combined Notes to Consolidated Financial Statements for additional information regarding fair value measurements and the fair value hierarchy.
Maturities WithinTotal Fair
Value
Commodity derivative contracts(a):
202520262027202820292030 and Beyond
Prices based on model or other valuation methods (Level 3)$(17)$(18)$(21)$(22)$(21)$(52)$(151)
_________
(a)Represents ComEd's net liabilities associated with the floating-to-fixed energy swap contracts with unaffiliated suppliers.
ITEM 4.    CONTROLS AND PROCEDURES
During the first quarter of 2025, each of the Registrants' management, including its principal executive officer and principal financial officer, evaluated its disclosure controls and procedures related to the recording, processing, summarizing, and reporting of information in its periodic reports that it files with the SEC. These disclosure controls and procedures have been designed by the Registrants to ensure that (a) material information relating to that Registrant, including its consolidated subsidiaries, is accumulated and made known to that Registrant's management, including its principal executive officer and principal financial officer, by other employees of that Registrant and its subsidiaries as appropriate to allow timely decisions regarding required disclosure, and (b) this information is recorded, processed, summarized, evaluated, and reported, as applicable, within the time periods specified in the SEC’s rules and forms. Due to the inherent limitations of control systems, not all misstatements may be detected. These inherent limitations include the realities that judgments in decision-making can be faulty and that breakdowns can occur because of simple error or mistake. Additionally, controls could be circumvented by the individual acts of some persons or by collusion of two or more people.
Accordingly, as of March 31, 2025, the principal executive officer and principal financial officer of each of the Registrants concluded that such Registrant’s disclosure controls and procedures were effective to accomplish its objectives. The Registrants continually strive to improve their disclosure controls and procedures to enhance the quality of its financial reporting and to maintain dynamic systems that change as conditions warrant. There were no changes in internal control over financial reporting during the first quarter of 2025 that materially affected, or are reasonably likely to materially affect, any of the Registrants' internal control over financial reporting.
PART II — OTHER INFORMATION
ITEM 1.    LEGAL PROCEEDINGS
The Registrants are parties to various lawsuits and regulatory proceedings in the ordinary course of their respective businesses. For information regarding material lawsuits and proceedings, see (a) ITEM 3. LEGAL PROCEEDINGS of the 2024 Form 10-K, (b) Notes 3 — Regulatory Matters and 18 — Commitments and Contingencies of the 2024 Form 10-K, and (c) Notes 2 — Regulatory Matters and 11 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements in PART I, ITEM 1. FINANCIAL STATEMENTS of this Report. Such descriptions are incorporated herein by these references.
ITEM 1A.    RISK FACTORS
Risks Related to All Registrants
At March 31, 2025, the Registrants' risk factors were consistent with the risk factors described in the Registrants' combined 2024 Form 10-K in ITEM 1A. RISK FACTORS.
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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, 2025.
ITEM 6.    EXHIBITS
Certain of the following exhibits are incorporated herein by reference under Rule 12b-32 of the Securities and Exchange Act of 1934, as amended. Certain other instruments which would otherwise be required to be listed below have not been so listed because such instruments do not authorize securities in an amount which exceeds 10% of the total assets of the applicable Registrant and its subsidiaries on a consolidated basis, and the applicable Registrant agrees to furnish a copy of any such instrument to the Commission upon request.
(4) Instruments Defining the Rights of Securities Holders, Including Indentures
Exelon Corporation
Exhibit No.DescriptionLocation
Third Supplemental Indenture, dated as of February 1, 2025, among Exelon Corporation and The Bank of New York Mellon Trust Company, N.A., as trustee
Eighth Supplemental Indenture, dated as of February 1, 2025, among Exelon Corporation and The Bank of New York Mellon Trust Company, N.A., as trustee
Atlantic City Electric Company
Exhibit No.DescriptionLocation
ACE Supplemental Indenture to the Mortgage and Deed of Trust, dated as of March 1, 2025

Delmarva Power & Light Company
Exhibit No.DescriptionLocation
DPL Supplemental Indenture to the Mortgage and Deed of Trust, dated as of March 1, 2025

Potomac Electric Power Company
Exhibit No.DescriptionLocation
Pepco Supplemental Indenture to the Mortgage and Deed of Trust, dated as of March 1, 2025
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, 2025 filed by the following officers for the following companies:
125


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
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, 2025 filed by the following officers for the following companies:
126


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)
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SIGNATURES

Pursuant to requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
EXELON CORPORATION
 
/s/    CALVIN G. BUTLER, JR./s/    JEANNE M. JONES
Calvin G. Butler, Jr.Jeanne M. Jones
President, Chief Executive Officer
(Principal Executive Officer) and Director		Executive Vice President and Chief Financial Officer
(Principal Financial Officer)
/s/ ROBERT A. KLECZYNSKI
Robert A. Kleczynski
Senior Vice President, Corporate Controller and Tax
(Principal Accounting Officer)
May 1, 2025
128


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 1, 2025
129


Pursuant to requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
PECO ENERGY COMPANY
 
/s/   DAVID M. VELAZQUEZ/s/    MARISSA E. HUMPHREY
David M. VelazquezMarissa E. Humphrey
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 1, 2025

130


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/    CARIM V. KHOUZAMI/s/ MICHAEL J. CLOYD
Carim V. KhouzamiMichael 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 1, 2025

131


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/    DAVID M. VAHOS
J. Tyler AnthonyDavid M. Vahos
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 1, 2025

132


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/    DAVID M. VAHOS
J. Tyler AnthonyDavid M. Vahos
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 1, 2025

133


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/    DAVID M. VAHOS
J. Tyler AnthonyDavid M. Vahos
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 1, 2025

134


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/    DAVID M. VAHOS
J. Tyler AnthonyDavid M. Vahos
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 1, 2025
135


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