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Exelon Corporation
EXC
#539
Rank
C$61.56 B
Marketcap
๐Ÿ‡บ๐Ÿ‡ธ United States
Country
C$60.96
Share price
0.83%
Change (1 day)
7.99%
Change (1 year)
๐Ÿ”‹ Electricity
Categories
  1. Exelon Corporation
  2. Quarterly Reports (10-Q)
  3. Submitted on 2024-08-01

Exelon Corporation - 10-Q quarterly report FY


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Cumulative Preferred Security, Series DJune 30, 2024June 30, 2024June 30, 2024June 30, 2024June 30, 2024June 30, 2024June 30, 2024June 30, 2024falsefalsefalsefalsefalsefalsefalsefalse20242024202420242024202420242024Q2Q2Q2Q2Q2Q2Q2Q2December 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 June 30, 2024
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 June 30, 2024 was:
Exelon Corporation Common Stock, without par value1,000,498,207
Commonwealth Edison Company Common Stock, $12.50 par value127,021,416
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
7
8
8
Exelon Corporation
Consolidated Statements of Operations and Comprehensive Income
9
Consolidated Statements of Cash Flows
10
Consolidated Balance Sheets
11
Consolidated Statements of Changes in Shareholders’ Equity
13
Commonwealth Edison Company
Consolidated Statements of Operations and Comprehensive Income
14
Consolidated Statements of Cash Flows
15
Consolidated Balance Sheets
16
Consolidated Statements of Changes in Shareholders' Equity
18
PECO Energy Company
Consolidated Statements of Operations and Comprehensive Income
19
Consolidated Statements of Cash Flows
20
Consolidated Balance Sheets
21
Consolidated Statements of Changes in Shareholder's Equity
23
Baltimore Gas and Electric Company
Statements of Operations and Comprehensive Income
24
Statements of Cash Flows
25
Balance Sheets
26
Statements of Changes in Shareholder's Equity
28
Pepco Holdings LLC
Consolidated Statements of Operations and Comprehensive Income
29
Consolidated Statements of Cash Flows
30
Consolidated Balance Sheets
31
Consolidated Statements of Changes in Member's Equity
33
1




Page No.
Potomac Electric Power Company
Statements of Operations and Comprehensive Income
34
Statements of Cash Flows
35
Balance Sheets
36
Statements of Changes in Shareholder's Equity
38
Delmarva Power & Light Company
Statements of Operations and Comprehensive Income
39
Statements of Cash Flows
40
Balance Sheets
41
Statements of Changes in Shareholder’s Equity
43
Atlantic City Electric Company
Consolidated Statements of Operations and Comprehensive Income
44
Consolidated Statements of Cash Flows
45
Consolidated Balance Sheets
46
Consolidated Statements of Changes in Shareholder’s Equity
48
Combined Notes to Consolidated Financial Statements
1. Significant Accounting Policies
49
2. Regulatory Matters
50
3. Revenue from Contracts with Customers
58
4. Segment Information
60
5. Accounts Receivable
69
6. Income Taxes
72
7. Retirement Benefits
74
8. Derivative Financial Instruments
76
9. Debt and Credit Agreements
80
10. Fair Value of Financial Assets and Liabilities
83
11. Commitments and Contingencies
90
12. Shareholders' Equity
97
13. Changes in Accumulated Other Comprehensive Income
97
14. Supplemental Financial Information
98
15. Related Party Transactions
102
2




Page No.
104
Exelon Corporation
104
Executive Overview
104
Financial Results of Operations
104
Significant 2024 Transactions and Developments
106
Other Key Business Drivers and Management Strategies
109
Critical Accounting Policies and Estimates
110
Results of Operations By Registrant
111
Commonwealth Edison Company
111
PECO Energy Company
114
Baltimore Gas and Electric Company
118
Pepco Holdings LLC
121
Potomac Electric Power Company
122
Delmarva Power & Light Company
125
Atlantic City Electric Company
129
Liquidity and Capital Resources
132
140
141
141
141
141
142
142
145
145
146
147
148
149
150
151
152
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 2023 Form 10-KReference to specific Combined Note to Consolidated Financial Statements within Exelon's 2023 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
POLRProvider of Last Resort
PPAPower Purchase Agreement
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 contractual elimination under regulatory accounting
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
ZECZero Emission Credit or Zero Emission Certificate
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.
The factors that could cause actual results to differ materially from the forward-looking statements made by the Registrants include those factors discussed herein, as well as the items discussed in (1) the 2023 Form 10-K in (a) Part I, ITEM 1A. Risk Factors, (b) Part II, ITEM 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations, and (c) Part II, ITEM 8. Financial Statements and Supplementary Data: Note 18, Commitments and Contingencies; (2) this Quarterly Report on Form 10-Q in (a) Part II, ITEM 1A. Risk Factors, (b) Part I, ITEM 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations, and (c) Part I, ITEM 1. Financial Statements: Note 11, Commitments and Contingencies; and (3) other factors discussed in filings with the SEC by the Registrants.
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.
7



PART I. FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
8




EXELON CORPORATION AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME
(Unaudited)
Three Months Ended
June 30,		Six Months Ended
June 30,
(In millions, except per share data)2024202320242023
Operating revenues
Electric operating revenues$5,169 $4,434 $10,367 $8,896 
Natural gas operating revenues272 258 1,011 1,080 
Revenues from alternative revenue programs(80)126 25 404 
Total operating revenues5,361 4,818 11,403 10,380 
Operating expenses
Purchased power1,938 1,669 4,134 3,402 
Purchased fuel54 58 267 416 
Operating and maintenance1,209 1,197 2,481 2,347 
Depreciation and amortization894 866 1,773 1,727 
Taxes other than income taxes360 324 731 679 
Total operating expenses4,455 4,114 9,386 8,571 
Gain on sale of assets7 — 9 — 
Operating income913 704 2,026 1,809 
Other income and (deductions)
Interest expense, net(476)(421)(938)(828)
Interest expense to affiliates(7)(6)(12)(12)
Other, net64 139 139 249 
Total other income and (deductions)(419)(288)(811)(591)
Income before income taxes494 416 1,215 1,218 
Income taxes46 73 109 206 
Net income attributable to common shareholders$448 $343 $1,106 $1,012 
Comprehensive income, net of income taxes
Net income$448 $343 $1,106 $1,012 
Other comprehensive income, net of income taxes
Pension and non-pension postretirement benefit plans:
Actuarial losses reclassified to periodic benefit cost5 3 10 6 
Pension and non-pension postretirement benefit plans valuation adjustments(2)(3)(26)(13)
Unrealized (loss) gain on cash flow hedges(3)9 30 15 
Other comprehensive income— 9 14 8 
Comprehensive income attributable to common shareholders$448 $352 $1,120 $1,020 
Average shares of common stock outstanding:
Basic1,001 995 1,001 995 
Assumed exercise and/or distributions of stock-based awards(a)
— 1 — 1 
Diluted1,001 996 1,001 996 
Earnings per average common share
Basic$0.45 $0.34 $1.11 $1.02 
Diluted$0.45 $0.34 $1.10 $1.02 
__________
(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
9



EXELON CORPORATION AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
Six Months Ended
June 30,
(In millions)20242023
Cash flows from operating activities
Net income$1,106 $1,012 
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation, amortization, and accretion1,774 1,727 
Gain on sales of assets(9)— 
Deferred income taxes and amortization of investment tax credits72 94 
Net fair value changes related to derivatives— 4 
Other non-cash operating activities246 (222)
Changes in assets and liabilities:
Accounts receivable(443)387 
Inventories(25)44 
Accounts payable and accrued expenses(120)(734)
Collateral received (paid), net13 (187)
Income taxes(39)97 
Regulatory assets and liabilities, net265 (516)
Pension and non-pension postretirement benefit contributions(125)(85)
Other assets and liabilities(261)140 
Net cash flows provided by operating activities2,454 1,761 
Cash flows from investing activities
Capital expenditures(3,466)(3,685)
Other investing activities(1)10 
Net cash flows used in investing activities(3,467)(3,675)
Cash flows from financing activities
Changes in short-term borrowings(670)(1,600)
Proceeds from short-term borrowings with maturities greater than 90 days150 400 
Repayments on short-term borrowings with maturities greater than 90 days(549)(150)
Issuance of long-term debt4,225 5,200 
Retirement of long-term debt(903)(1,209)
Dividends paid on common stock(761)(717)
Proceeds from employee stock plans22 19 
Other financing activities(67)(84)
Net cash flows provided by financing activities1,447 1,859 
Increase (decrease) in cash, restricted cash, and cash equivalents434 (55)
Cash, restricted cash, and cash equivalents at beginning of period1,101 1,090 
Cash, restricted cash, and cash equivalents at end of period$1,535 $1,035 
Supplemental cash flow information
Decrease in capital expenditures not paid$(74)$(164)
See the Combined Notes to Consolidated Financial Statements
10



EXELON CORPORATION AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
(Unaudited)
(In millions)June 30, 2024December 31, 2023
ASSETS
Current assets
Cash and cash equivalents$934 $445 
Restricted cash and cash equivalents530 482 
Accounts receivable
Customer accounts receivable3,0532,659
Customer allowance for credit losses(372)(317)
Customer accounts receivable, net2,681 2,342 
Other accounts receivable1,1361,101
Other allowance for credit losses(108)(82)
Other accounts receivable, net1,028 1,019 
Inventories, net
Fossil fuel53 94 
Materials and supplies771 707 
Regulatory assets1,945 2,215 
Other615 473 
Total current assets8,557 7,777 
Property, plant, and equipment (net of accumulated depreciation and amortization of $18,160 and $17,251 as of June 30, 2024 and December 31, 2023, respectively)
75,646 73,593 
Deferred debits and other assets
Regulatory assets8,703 8,698 
Goodwill6,630 6,630 
Receivable related to Regulatory Agreement Units3,840 3,232 
Investments270 251 
Other1,467 1,365 
Total deferred debits and other assets20,910 20,176 
Total assets$105,113 $101,546 
See the Combined Notes to Consolidated Financial Statements
11



EXELON CORPORATION AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
(Unaudited)
(In millions)June 30, 2024December 31, 2023
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities
Short-term borrowings$1,454 $2,523 
Long-term debt due within one year1,308 1,403 
Accounts payable2,810 2,846 
Accrued expenses1,241 1,375 
Payables to affiliates5 5 
Customer deposits425 411 
Regulatory liabilities433 389 
Mark-to-market derivative liabilities23 74 
Unamortized energy contract liabilities7 8 
Other569 557 
Total current liabilities8,275 9,591 
Long-term debt43,039 39,692 
Long-term debt to financing trusts390 390 
Deferred credits and other liabilities
Deferred income taxes and unamortized investment tax credits12,358 11,956 
Regulatory liabilities10,198 9,576 
Pension obligations1,562 1,571 
Non-pension postretirement benefit obligations524 527 
Asset retirement obligations272 267 
Mark-to-market derivative liabilities121 106 
Unamortized energy contract liabilities23 27 
Other2,199 2,088 
Total deferred credits and other liabilities27,257 26,118 
Total liabilities78,961 75,791 
Commitments and contingencies
Shareholders’ equity
Common stock (No par value, 2,000 shares authorized, 1,000 shares and 999 shares outstanding as of June 30, 2024 and December 31, 2023, respectively)
21,152 21,114 
Treasury stock, at cost (2 shares as of June 30, 2024 and December 31, 2023)
(123)(123)
Retained earnings5,835 5,490 
Accumulated other comprehensive loss, net(712)(726)
Total shareholders’ equity26,152 25,755 
Total liabilities and shareholders’ equity$105,113 $101,546 

See the Combined Notes to Consolidated Financial Statements
12



EXELON CORPORATION AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS’ EQUITY
(Unaudited)
Six Months Ended June 30, 2024
(In millions, shares
in thousands)		Issued
Shares		Common
Stock		Treasury
Stock		Retained
Earnings		Accumulated
Other
Comprehensive
Loss, net		Total Shareholders'
Equity
Balance at December 31, 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 issuances276 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 
Net income— — — 448 — 448 
Long-term incentive plan activity76 11 — — — 11 
Employee stock purchase plan issuances396 12 — — — 12 
Common stock dividends
($0.38/common share)
— — — (380)— (380)
Balance at June 30, 20241,002,330 $21,152 $(123)$5,835 $(712)$26,152 

Six Months Ended June 30, 2023
(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, 2022995,830 $20,908 $(123)$4,597 $(638)$24,744 
Net income— — — 669 — 669 
Long-term incentive plan activity306 1 — — — 1 
Employee stock purchase plan issuances266 12 — — — 12 
Common stock dividends
($0.36/common share)
— — — (359)— (359)
Other comprehensive loss, net of income taxes— — — — (1)(1)
Balance at March 31, 2023996,402 $20,921 $(123)$4,907 $(639)$25,066 
Net income— — — 343 — 343 
Long-term incentive plan activity372 9 — — — 9 
Employee stock purchase plan issuances278 11 — — — 11 
Common stock dividends
($0.36/common share)
— — — (359)— (359)
Other comprehensive income, net of income taxes— — — — 9 9 
Balance at June 30, 2023997,052 $20,941 $(123)$4,891 $(630)$25,079 











See the Combined Notes to Consolidated Financial Statements
13




COMMONWEALTH EDISON COMPANY AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME
(Unaudited)
Three Months Ended
June 30,		Six Months Ended
June 30,
(In millions)2024202320242023
Operating revenues
Electric operating revenues$2,120 $1,781 $4,194 $3,293 
Revenues from alternative revenue programs(43)118 (24)270 
Operating revenues from affiliates2 2 4 5 
Total operating revenues2,079 1,901 4,174 3,568 
Operating expenses
Purchased power763 685 1,670 1,172 
Operating and maintenance345 267 663 521 
Operating and maintenance from affiliates104 88 204 171 
Depreciation and amortization374 350 737 688 
Taxes other than income taxes94 88 188 182 
Total operating expenses1,680 1,478 3,462 2,734 
Gain on sale of assets5 — 5 — 
Operating income404 423 717 834 
Other income and (deductions)
Interest expense, net(120)(117)(239)(230)
Interest expense to affiliates(3)(3)(7)(7)
Other, net20 17 41 34 
Total other income and (deductions)(103)(103)(205)(203)
Income before income taxes301 320 512 631 
Income taxes31 71 49 142 
Net income$270 $249 $463 $489 
Comprehensive income$270 $249 $463 $489 

See the Combined Notes to Consolidated Financial Statements
14



COMMONWEALTH EDISON COMPANY AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
Six Months Ended
June 30,
(In millions)20242023
Cash flows from operating activities
Net income$463 $489 
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation and amortization737 688 
Gain on sales of assets(5)— 
Deferred income taxes and amortization of investment tax credits(8)106 
Other non-cash operating activities69 (260)
Changes in assets and liabilities:
Accounts receivable(278)(30)
Receivables from and payables to affiliates, net3 (3)
Inventories(16)(43)
Accounts payable and accrued expenses (73)(311)
Collateral received, net12 25 
Income taxes(108)16 
Regulatory assets and liabilities, net446 (459)
Pension and non-pension postretirement benefit contributions(10)(24)
Other assets and liabilities70 110 
Net cash flows provided by operating activities1,302 304 
Cash flows from investing activities
Capital expenditures(1,111)(1,262)
Other investing activities11 3 
Net cash flows used in investing activities(1,100)(1,259)
Cash flows from financing activities
Changes in short-term borrowings(124)(130)
Proceeds from short-term borrowings with maturities greater than 90 days— 400 
Repayments on short-term borrowings with maturities greater than 90 days(400)(150)
Issuance of long-term debt800 975 
Dividends paid on common stock(388)(374)
Contributions from parent78 372 
Other financing activities(11)(13)
Net cash flows (used in) provided by financing activities(45)1,080 
Increase in cash, restricted cash, and cash equivalents157 125 
Cash, restricted cash, and cash equivalents at beginning of period686 511 
Cash, restricted cash, and cash equivalents at end of period$843 $636 
Supplemental cash flow information
Decrease in capital expenditures not paid$(70)$(7)
See the Combined Notes to Consolidated Financial Statements
15



COMMONWEALTH EDISON COMPANY AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
(Unaudited)
(In millions)June 30, 2024December 31, 2023
ASSETS
Current assets
   Cash and cash equivalents$326 $110 
   Restricted cash and cash equivalents446 402 
   Accounts receivable
   Customer accounts receivable1,132860
   Customer allowance for credit losses(112)(69)
       Customer accounts receivable, net1,020 791 
   Other accounts receivable251242
   Other allowance for credit losses(29)(17)
       Other accounts receivable, net 222 225 
   Receivables from affiliates4 3 
   Inventories, net294 279 
   Regulatory assets1,089 1,335 
   Other147 123 
   Total current assets3,548 3,268 
Property, plant, and equipment (net of accumulated depreciation and amortization of $7,577 and $7,222 as of June 30, 2024 and December 31, 2023, respectively)
29,642 29,088 
Deferred debits and other assets
   Regulatory assets2,701 2,794 
   Goodwill2,625 2,625 
   Receivable related to Regulatory Agreement Units3,566 2,954 
   Investments6 6 
   Prepaid pension asset1,194 1,217 
   Other966 875 
   Total deferred debits and other assets11,058 10,471 
Total assets$44,248 $42,827 
See the Combined Notes to Consolidated Financial Statements
16



COMMONWEALTH EDISON COMPANY AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
(Unaudited)
(In millions)June 30, 2024December 31, 2023
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities
   Short-term borrowings$78 $602 
   Long-term debt due within one year250 250 
   Accounts payable806 867 
   Accrued expenses393 576 
   Payables to affiliates76 72 
   Customer deposits123 118 
   Regulatory liabilities241 191 
   Mark-to-market derivative liabilities23 27 
   Other251 219 
   Total current liabilities2,241 2,922 
Long-term debt12,026 11,236 
Long-term debt to financing trust206 205 
Deferred credits and other liabilities
   Deferred income taxes and unamortized investment tax credits5,453 5,327 
   Regulatory liabilities8,245 7,493 
   Asset retirement obligations152 149 
   Non-pension postretirement benefits obligations164 161 
   Mark-to-market derivative liabilities116 106 
   Other1,129 865 
   Total deferred credits and other liabilities15,259 14,101 
   Total liabilities29,732 28,464 
Commitments and contingencies
Shareholders’ equity
   Common stock 1,588 1,588 
   Other paid-in capital10,479 10,401 
   Retained earnings2,449 2,374 
   Total shareholders’ equity14,516 14,363 
Total liabilities and shareholders’ equity$44,248 $42,827 
    
See the Combined Notes to Consolidated Financial Statements
17



COMMONWEALTH EDISON COMPANY AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS’ EQUITY
(Unaudited)
Six Months Ended June 30, 2024
(In millions)Common
Stock		Other
Paid-In
Capital		Retained
Earnings		Total
Shareholders’
Equity
Balance at December 31, 2023$1,588 $10,401 $2,374 $14,363 
Net income— — 193 193 
Common stock dividends— — (194)(194)
Contributions from parent— 39 — 39 
Balance at March 31, 2024$1,588 $10,440 $2,373 $14,401 
Net income— — 270 270 
Common stock dividends— — (194)(194)
Contributions from parent— 39 — 39 
Balance at June 30, 2024$1,588 $10,479 $2,449 $14,516 
Six Months Ended June 30, 2023
(In millions)Common
Stock		Other
Paid-In
Capital		Retained
Earnings		Total
Shareholders’
Equity
Balance at December 31, 2022$1,588 $9,746 $2,030 $13,364 
Net income— — 241 241 
Common stock dividends— — (187)(187)
Contributions from parent— 186 — 186 
Balance at March 31, 2023$1,588 $9,932 $2,084 $13,604 
Net income— — 249 249 
Common stock dividends— — (187)(187)
Contributions from parent— 186 — 186 
Balance at June 30, 2023$1,588 $10,118 $2,146 $13,852 
See the Combined Notes to Consolidated Financial Statements
18




PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME
(Unaudited)
 Three Months Ended
June 30,		Six Months Ended
June 30,
(In millions)2024202320242023
Operating revenues
Electric operating revenues$795 $723 $1,576 $1,521 
Natural gas operating revenues94 108 367 425 
Revenues from alternative revenue programs— (5)(2)(10)
Operating revenues from affiliates2 2 4 4 
Total operating revenues891 828 1,945 1,940 
Operating expenses
Purchased power 298 267 604 597 
Purchased fuel25 35 123 189 
Operating and maintenance209 186 444 405 
Operating and maintenance from affiliates61 53 119 105 
Depreciation and amortization107 99 210 197 
Taxes other than income taxes52 47 103 97 
Total operating expenses752 687 1,603 1,590 
Gain on sales of assets 2 — 4 — 
Operating income141 141 346 350 
Other income and (deductions)
Interest expense, net(54)(45)(106)(90)
Interest expense to affiliates(3)(3)(6)(7)
Other, net9 6 18 15 
Total other income and (deductions)(48)(42)(94)(82)
Income before income taxes93 99 252 268 
Income taxes3 2 13 5 
Net income$90 $97 $239 $263 
Comprehensive income$90 $97 $239 $263 
See the Combined Notes to Consolidated Financial Statements
19



PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
Six Months Ended
June 30,
(In millions)20242023
Cash flows from operating activities
Net income$239 $263 
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation and amortization210 197 
Gain on sales of assets(4)— 
Deferred income taxes and amortization of investment tax credits(14)(26)
Other non-cash operating activities37 12 
Changes in assets and liabilities:
Accounts receivable(83)182 
Receivables from and payables to affiliates, net1 (3)
Inventories13 52 
Accounts payable and accrued expenses (57)(167)
Income taxes(19)56 
Regulatory assets and liabilities, net(15)14 
Pension and non-pension postretirement benefit contributions(3)(1)
Other assets and liabilities(65)(34)
Net cash flows provided by operating activities240 545 
Cash flows from investing activities
Capital expenditures(743)(707)
Changes in Exelon intercompany money pool— (225)
Other investing activities5 — 
Net cash flows used in investing activities(738)(932)
Cash flows from financing activities
Changes in short-term borrowings95 (239)
Issuance of long-term debt— 575 
Retirement of long-term debt— (50)
Dividends paid on common stock(200)(202)
Contributions from parent580 330 
Other financing activities— (4)
Net cash flows provided by financing activities475 410 
(Decrease) increase in cash, restricted cash, and cash equivalents(23)23 
Cash, restricted cash, and cash equivalents at beginning of period51 68 
Cash, restricted cash, and cash equivalents at end of period$28 $91 
Supplemental cash flow information
Increase in capital expenditures not paid$21 $3 
See the Combined Notes to Consolidated Financial Statements
20



PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
(Unaudited)
(In millions)June 30, 2024December 31, 2023
ASSETS
Current assets
Cash and cash equivalents$19 $42 
Restricted cash and cash equivalents9 9 
Accounts receivable
Customer accounts receivable578527
Customer allowance for credit losses(112)(95)
Customer accounts receivable, net466 432 
Other accounts receivable143117
Other allowance for credit losses(20)(8)
Other accounts receivable, net123 109 
Receivables from affiliates1 2 
Inventories, net
Fossil fuel27 50 
Materials and supplies77 67 
Prepaid utility taxes90 2 
Regulatory assets115 127 
Other93 63 
Total current assets1,020 903 
Property, plant, and equipment (net of accumulated depreciation and amortization of $4,189 and $4,097 as of June 30, 2024 and December 31, 2023, respectively)
13,699 13,128 
Deferred debits and other assets
Regulatory assets861 793 
Receivable related to Regulatory Agreement Units274 278 
Investments37 35 
Prepaid pension asset433 429 
Other30 29 
Total deferred debits and other assets1,635 1,564 
Total assets$16,354 $15,595 
See the Combined Notes to Consolidated Financial Statements
21



PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
(Unaudited)
(In millions)June 30, 2024December 31, 2023
LIABILITIES AND SHAREHOLDER'S EQUITY
Current liabilities
Short-term borrowings$260 $165 
Accounts payable522 512 
Accrued expenses184 236 
Payables to affiliates39 39 
Customer deposits78 79 
Renewable energy credit obligation72 36 
Regulatory liabilities79 92 
Other34 23 
Total current liabilities1,268 1,182 
Long-term debt5,135 5,134 
Long-term debt to financing trusts184 184 
Deferred credits and other liabilities
Deferred income taxes and unamortized investment tax credits2,367 2,321 
Regulatory liabilities311 314 
Asset retirement obligations27 26 
Non-pension postretirement benefits obligations287 286 
Other87 79 
Total deferred credits and other liabilities3,079 3,026 
Total liabilities9,666 9,526 
Commitments and contingencies
Shareholder’s equity
Common stock4,630 4,050 
Retained earnings2,058 2,019 
Total shareholder’s equity6,688 6,069 
Total liabilities and shareholder's equity$16,354 $15,595 
See the Combined Notes to Consolidated Financial Statements
22



PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDER’S EQUITY
(Unaudited)
Six Months Ended June 30, 2024
(In millions)Common
Stock		Retained
Earnings		Total
Shareholder's
Equity
Balance at December 31, 2023$4,050 $2,019 $6,069 
Net income— 149 149 
Common stock dividends— (100)(100)
Contributions from parent580 — 580 
Balance at March 31, 2024$4,630 $2,068 $6,698 
Net income— 90 90 
Common stock dividends— (100)(100)
Balance at June 30, 2024$4,630 $2,058 $6,688 
Six Months Ended June 30, 2023
(In millions)Common
Stock		Retained
Earnings		Total
Shareholder's
Equity
Balance at December 31, 2022$3,702 $1,861 $5,563 
Net income— 166 166 
Common stock dividends— (101)(101)
Contributions from parent330 — 330 
Balance at March 31, 2023$4,032 $1,926 $5,958 
Net income— 97 97 
Common stock dividends— (101)(101)
Balance at June 30, 2023$4,032 $1,922 $5,954 
See the Combined Notes to Consolidated Financial Statements
23




BALTIMORE GAS AND ELECTRIC COMPANY
STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME
(Unaudited)
Three Months Ended
June 30,		Six Months Ended
June 30,
(In millions)2024202320242023
Operating revenues
Electric operating revenues$799 $670 $1,656 $1,449 
Natural gas operating revenues150 121 545 530 
Revenues from alternative revenue programs(23)4 19 70 
Operating revenues from affiliates2 2 5 4 
Total operating revenues928 797 2,225 2,053 
Operating expenses
Purchased power323 261 700 604 
Purchased fuel20 11 107 160 
Operating and maintenance188 144 392 311 
Operating and maintenance from affiliates62 54 122 108 
Depreciation and amortization162 158 312 325 
Taxes other than income taxes80 76 169 159 
Total operating expenses835 704 1,802 1,667 
Operating income93 93 423 386 
Other income and (deductions)
Interest expense, net(53)(44)(103)(88)
Other, net8 5 16 8 
Total other income and (deductions)(45)(39)(87)(80)
Income before income taxes48 54 336 306 
Income taxes4 12 28 65 
Net income$44 $42 $308 $241 
Comprehensive income$44 $42 $308 $241 
See the Combined Notes to Consolidated Financial Statements
24



BALTIMORE GAS AND ELECTRIC COMPANY
STATEMENTS OF CASH FLOWS
(Unaudited)
Six Months Ended
June 30,
(In millions)20242023
Cash flows from operating activities
Net income$308 $241 
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation and amortization312 325 
Deferred income taxes and amortization of investment tax credits(4)38 
Other non-cash operating activities15 (36)
Changes in assets and liabilities:
Accounts receivable(20)185 
Receivables from and payables to affiliates, net3 (8)
Inventories3 51 
Accounts payable and accrued expenses5 (114)
Collateral paid, net— (22)
Income taxes(43)8 
Regulatory assets and liabilities, net(32)(83)
Pension and non-pension postretirement benefit contributions(30)(11)
Other assets and liabilities53 37 
Net cash flows provided by operating activities570 611 
Cash flows from investing activities
Capital expenditures(668)(656)
Other investing activities9 4 
Net cash flows used in investing activities(659)(652)
Cash flows from financing activities
Changes in short-term borrowings(336)(408)
Issuance of long-term debt800 700 
Retirement of long-term debt— (300)
Dividends paid on common stock(184)(158)
Contributions from parent197 237 
Other financing activities(8)(7)
Net cash flows provided by financing activities469 64 
Increase in cash, restricted cash, and cash equivalents380 23 
Cash, restricted cash, and cash equivalents at beginning of period48 67 
Cash, restricted cash, and cash equivalents at end of period$428 $90 
Supplemental cash flow information
Increase (decrease) in capital expenditures not paid$32 $(60)
See the Combined Notes to Consolidated Financial Statements
25



BALTIMORE GAS AND ELECTRIC COMPANY
BALANCE SHEETS
(Unaudited)
(In millions)June 30, 2024December 31, 2023
ASSETS
Current assets
Cash and cash equivalents$428 $47 
Restricted cash and cash equivalents— 1 
Accounts receivable
Customer accounts receivable539527
Customer allowance for credit losses (45)(46)
Customer accounts receivable, net494 481 
Other accounts receivable 100106
Other allowance for credit losses(5)(7)
Other accounts receivable, net95 99 
Inventories, net
Fossil fuel22 35 
Materials and supplies84 74 
Prepaid utility taxes— 56 
Regulatory assets208 229 
Other20 25 
Total current assets1,351 1,047 
Property, plant, and equipment (net of accumulated depreciation and amortization of $4,905 and $4,744 as of June 30, 2024 and December 31, 2023, respectively)
12,544 12,102 
Deferred debits and other assets
Regulatory assets751 727 
Investments9 9 
Prepaid pension asset241 248 
Other49 51 
Total deferred debits and other assets1,050 1,035 
Total assets$14,945 $14,184 
See the Combined Notes to Consolidated Financial Statements
26



BALTIMORE GAS AND ELECTRIC COMPANY
BALANCE SHEETS
(Unaudited)
(In millions)June 30, 2024December 31, 2023
LIABILITIES AND SHAREHOLDER'S EQUITY
Current liabilities
Short-term borrowings$— $336 
Accounts payable395 344 
Accrued expenses144 203 
Payables to affiliates37 35 
Customer deposits117 114 
Regulatory liabilities21 27 
Other31 34 
Total current liabilities745 1,093 
Long-term debt5,394 4,602 
Deferred credits and other liabilities
Deferred income taxes and unamortized investment tax credits2,029 1,945 
Regulatory liabilities690 773 
Asset retirement obligations32 32 
Non-pension postretirement benefits obligations152 158 
Other92 91 
Total deferred credits and other liabilities2,995 2,999 
Total liabilities9,134 8,694 
Commitments and contingencies
Shareholder's equity
Common stock3,443 3,246 
Retained earnings2,368 2,244 
Total shareholder's equity5,811 5,490 
Total liabilities and shareholder's equity$14,945 $14,184 

See the Combined Notes to Consolidated Financial Statements
27



BALTIMORE GAS AND ELECTRIC COMPANY
STATEMENTS OF CHANGES IN SHAREHOLDER'S EQUITY
(Unaudited)
Six Months Ended June 30, 2024
(In millions)Common
Stock		Retained
Earnings		Total
Shareholder's
Equity
Balance at December 31, 2023$3,246 $2,244 $5,490 
Net income— 264 264 
Common stock dividends— (92)(92)
Balance at March 31, 2024$3,246 $2,416 $5,662 
Net income— 44 44 
Common stock dividends— (92)(92)
Contributions from parent197 — 197 
Balance at June 30, 2024$3,443 $2,368 $5,811 
Six Months Ended June 30, 2023
(In millions)Common
Stock		Retained
Earnings		Total
Shareholder's
Equity
Balance at December 31, 2022$2,861 $2,075 $4,936 
Net income— 200 200 
Common stock dividends— (80)(80)
Contributions from parent237 — 237 
Balance at March 31, 2023$3,098 $2,195 $5,293 
Net income— 42 42 
Common stock dividends— (79)(79)
Balance at June 30, 2023$3,098 $2,158 $5,256 
See the Combined Notes to Consolidated Financial Statements
28




PEPCO HOLDINGS LLC AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME
(Unaudited)
Three Months Ended
June 30,		Six Months Ended
June 30,
(In millions)2024202320242023
Operating revenues
Electric operating revenues$1,455 $1,265 $2,941 $2,637 
Natural gas operating revenues28 29 100 126 
Revenues from alternative revenue programs(14)9 32 74 
Operating revenues from affiliates2 2 4 4 
Total operating revenues1,471 1,305 3,077 2,841 
Operating expenses
Purchased power553 455 1,160 1,027 
Purchased fuel9 12 37 67 
Operating and maintenance231 260 506 527 
Operating and maintenance from affiliates50 44 101 86 
Depreciation and amortization235 243 481 484 
Taxes other than income taxes126 112 254 232 
Total operating expenses1,204 1,126 2,539 2,423 
Operating income267 179 538 418 
Other income and (deductions)
Interest expense, net(92)(81)(183)(157)
Other, net29 25 57 51 
Total other income and (deductions)(63)(56)(126)(106)
Income before income taxes 204 123 412 312 
Income taxes46 20 86 54 
Net income$158 $103 $326 $258 
Comprehensive income$158 $103 $326 $258 
See the Combined Notes to Consolidated Financial Statements
29



PEPCO HOLDINGS LLC AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
Six Months Ended
June 30,
(In millions)20242023
Cash flows from operating activities
Net income$326 $258 
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation and amortization481 484 
Deferred income taxes and amortization of investment tax credits26 26 
Other non-cash operating activities47 20 
Changes in assets and liabilities:
Accounts receivable(77)55 
Receivables from and payables to affiliates, net3 (8)
Inventories(25)(14)
Accounts payable and accrued expenses90 (25)
Collateral received (paid), net2 (191)
Income taxes(54)6 
Regulatory assets and liabilities, net(126)8 
Pension and non-pension postretirement benefit contributions(75)(11)
Other assets and liabilities(81)(80)
Net cash flows provided by operating activities537 528 
Cash flows from investing activities
Capital expenditures(903)(1,022)
Other investing activities— 8 
Net cash flows used in investing activities(903)(1,014)
Cash flows from financing activities
Changes in short-term borrowings(394)(377)
Issuance of long-term debt925 450 
Retirement of long-term debt(400)— 
Changes in Exelon intercompany money pool(8)8 
Distributions to member(282)(212)
Contributions from member487 405 
Other financing activities(25)(25)
Net cash flows provided by financing activities303 249 
Decrease in cash, restricted cash, and cash equivalents(63)(237)
Cash, restricted cash, and cash equivalents at beginning of period204 373 
Cash, restricted cash, and cash equivalents at end of period$141 $136 
Supplemental cash flow information
Decrease in capital expenditures not paid$(25)$(91)
See the Combined Notes to Consolidated Financial Statements
30



PEPCO HOLDINGS LLC AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
(Unaudited)
(In millions)June 30, 2024December 31, 2023
ASSETS
Current assets
Cash and cash equivalents$119 $180 
Restricted cash and cash equivalents22 24 
Accounts receivable
Customer accounts receivable805745
Customer allowance for credit losses(103)(107)
Customer accounts receivable, net702 638 
Other accounts receivable302310
Other allowance for credit losses(54)(50)
Other accounts receivable, net248 260 
Receivables from affiliates3 3 
Inventories, net
Fossil fuel5 9 
Materials and supplies316 287 
Regulatory assets343 337 
Other95 100 
Total current assets1,853 1,838 
Property, plant, and equipment (net of accumulated depreciation and amortization of $3,443 and $3,175 as of June 30, 2024 and December 31, 2023, respectively)
19,379 18,851 
Deferred debits and other assets
Regulatory assets1,620 1,587 
Goodwill4,005 4,005 
Investments149 143 
Prepaid pension asset293 268 
Other202 211 
Total deferred debits and other assets6,269 6,214 
Total assets$27,501 $26,903 
See the Combined Notes to Consolidated Financial Statements
31



PEPCO HOLDINGS LLC AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
(Unaudited)
(In millions)June 30, 2024December 31, 2023
LIABILITIES AND MEMBER'S EQUITY
Current liabilities
Short-term borrowings$— $394 
Long-term debt due within one year244 644 
Accounts payable716 683 
Accrued expenses309 338 
Payables to affiliates62 59 
Borrowings from Exelon intercompany money pool57 65 
Customer deposits107 100 
Regulatory liabilities 82 71 
Unamortized energy contract liabilities6 8 
PPA termination obligation20 49 
Other106 138 
Total current liabilities1,709 2,549 
Long-term debt8,904 8,004 
Deferred credits and other liabilities
Deferred income taxes and unamortized investment tax credits3,100 3,031 
Regulatory liabilities863 904 
Asset retirement obligations57 55 
Non-pension postretirement benefit obligations36 40 
Unamortized energy contract liabilities23 27 
Other496 511 
Total deferred credits and other liabilities4,575 4,568 
Total liabilities15,188 15,121 
Commitments and contingencies
Member's equity
Membership interest12,544 12,057 
Undistributed losses(231)(275)
Total member's equity12,313 11,782 
Total liabilities and member's equity$27,501 $26,903 
See the Combined Notes to Consolidated Financial Statements
32



PEPCO HOLDINGS LLC AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF CHANGES IN MEMBER'S EQUITY
(Unaudited)
Six Months Ended June 30, 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 
Net income— 158 158 
Distributions to member— (164)(164)
Balance at June 30, 2024$12,544 $(231)$12,313 

Six Months Ended June 30, 2023
(In millions)Membership InterestUndistributed (Losses)/GainsTotal Member's Equity
Balance at December 31, 2022$11,582 $(352)$11,230 
Net income— 155 155 
Distributions to member— (112)(112)
Contributions from member405 — 405 
Balance at March 31, 2023$11,987 $(309)$11,678 
Net income— 103 103 
Distributions to member— (100)(100)
Balance at June 30, 2023$11,987 $(306)$11,681 
See the Combined Notes to Consolidated Financial Statements
33




POTOMAC ELECTRIC POWER COMPANY
STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME
(Unaudited)
Three Months Ended
June 30,		Six Months Ended
June 30,
(In millions)2024202320242023
Operating revenues
Electric operating revenues$691 $633 $1,419 $1,302 
Revenues from alternative revenue programs7 7 37 46 
Operating revenues from affiliates2 2 3 3 
Total operating revenues700 642 1,459 1,351 
Operating expenses
Purchased power234 204 514 462 
Operating and maintenance37 82 123 175 
Operating and maintenance from affiliates65 58 129 115 
Depreciation and amortization98 109 205 216 
Taxes other than income taxes100 88 203 183 
Total operating expenses534 541 1,174 1,151 
Operating income166 101 285 200 
Other income and (deductions)
Interest expense, net(46)(43)(92)(81)
Other, net16 16 32 33 
Total other income and (deductions)(30)(27)(60)(48)
Income before income taxes136 74 225 152 
Income taxes28 10 42 22 
Net income$108 $64 $183 $130 
Comprehensive income$108 $64 $183 $130 
See the Combined Notes to Consolidated Financial Statements
34



POTOMAC ELECTRIC POWER COMPANY
STATEMENTS OF CASH FLOWS
(Unaudited)
Six Months Ended
June 30,
(In millions)20242023
Cash flows from operating activities
Net income$183 $130 
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation and amortization205 216 
Deferred income taxes and amortization of investment tax credits10 12 
Other non-cash operating activities(23)3 
Changes in assets and liabilities:
Accounts receivable(30)12 
Receivables from and payables to affiliates, net7 (2)
Inventories(12)(10)
Accounts payable and accrued expenses 47 (21)
Collateral paid, net— (26)
Income taxes(45)(1)
Regulatory assets and liabilities, net(48)(6)
Pension and non-pension postretirement benefit contributions(5)(8)
Other assets and liabilities(34)7 
Net cash flows provided by operating activities255 306 
Cash flows from investing activities
Capital expenditures(454)(483)
Changes in PHI intercompany money pool(57)— 
Other investing activities— 8 
Net cash flows used in investing activities(511)(475)
Cash flows from financing activities
Changes in short-term borrowings(132)(299)
Issuance of long-term debt675 250 
Retirement of long-term debt(400)— 
Changes in PHI intercompany money pool— 52 
Dividends paid on common stock(153)(115)
Contributions from parent251 243 
Other financing activities(17)(19)
Net cash flows provided by financing activities224 112 
Decrease in cash, restricted cash, and cash equivalents(32)(57)
Cash, restricted cash, and cash equivalents at beginning of period72 99 
Cash, restricted cash, and cash equivalents at end of period$40 $42 
Supplemental cash flow information
Decrease in capital expenditures not paid$(18)$(43)
See the Combined Notes to Consolidated Financial Statements
35



POTOMAC ELECTRIC POWER COMPANY
BALANCE SHEETS
(Unaudited)
(In millions)June 30, 2024December 31, 2023
ASSETS
Current assets
Cash and cash equivalents$19 $48 
Restricted cash and cash equivalents21 24 
Accounts receivable
Customer accounts receivable392369
Customer allowance for credit losses(53)(52)
Customer accounts receivable, net339 317 
Other accounts receivable164166
Other allowance for credit losses(34)(28)
Other accounts receivable, net130 138 
Receivables from affiliates— 2 
Receivable from PHI intercompany money pool57 — 
Inventories, net171 159 
Regulatory assets151 150 
Other17 51 
Total current assets905 889 
Property, plant, and equipment (net of accumulated depreciation and amortization of $4,399 and $4,284 as of June 30, 2024 and December 31, 2023, respectively)
9,730 9,430 
Deferred debits and other assets
Regulatory assets488 450 
Investments130 124 
Prepaid pension asset234 246 
Other55 55 
Total deferred debits and other assets907 875 
Total assets$11,542 $11,194 
See the Combined Notes to Consolidated Financial Statements
36



POTOMAC ELECTRIC POWER COMPANY
BALANCE SHEETS
(Unaudited)
(In millions)June 30, 2024December 31, 2023
LIABILITIES AND SHAREHOLDER'S EQUITY
Current liabilities
Short-term borrowings$— $132 
Long-term debt due within one year6 405 
Accounts payable309 321 
Accrued expenses174 191 
Payables to affiliates37 32 
Customer deposits52 47 
Regulatory liabilities 16 15 
Merger related obligation22 25 
Other39 61 
Total current liabilities655 1,229 
Long-term debt4,356 3,691 
Deferred credits and other liabilities
Deferred income taxes and unamortized investment tax credits1,468 1,431 
Regulatory liabilities 354 382 
Asset retirement obligations38 37 
Other246 280 
Total deferred credits and other liabilities2,106 2,130 
Total liabilities7,117 7,050 
Commitments and contingencies
Shareholder's equity
Common stock 3,326 3,075 
Retained earnings1,099 1,069 
Total shareholder's equity4,425 4,144 
Total liabilities and shareholder's equity$11,542 $11,194 
See the Combined Notes to Consolidated Financial Statements
37



POTOMAC ELECTRIC POWER COMPANY
STATEMENTS OF CHANGES IN SHAREHOLDER'S EQUITY
(Unaudited)
Six Months Ended June 30, 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 
Net income— 108 108 
Common stock dividends— (102)(102)
Balance at June 30, 2024$3,326 $1,099 $4,425 

Six Months Ended June 30, 2023
(In millions)Common StockRetained EarningsTotal Shareholder's Equity
Balance at December 31, 2022$2,767 $1,015 $3,782 
Net income— 65 65 
Common stock dividends— (48)(48)
Contributions from parent243 — 243 
Balance at March 31, 2023$3,010 $1,032 $4,042 
Net income— 64 64 
Common stock dividends— (67)(67)
Balance at June 30, 2023$3,010 $1,029 $4,039 

See the Combined Notes to Consolidated Financial Statements
38




DELMARVA POWER & LIGHT COMPANY
STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME
(Unaudited)
Three Months Ended
June 30,		Six Months Ended
June 30,
(In millions)2024202320242023
Operating revenues
Electric operating revenues$361 $315 $773 $682 
Natural gas operating revenues28 29 100 126 
Revenues from alternative revenue programs— 3 4 12 
Operating revenues from affiliates1 2 3 3 
Total operating revenues390 349 880 823 
Operating expenses
Purchased power147 127 333 293 
Purchased fuel9 12 37 67 
Operating and maintenance50 45 101 91 
Operating and maintenance from affiliates 46 43 91 84 
Depreciation and amortization61 60 122 121 
Taxes other than income taxes19 18 39 37 
Total operating expenses332 305 723 693 
Operating income58 44 157 130 
Other income and (deductions)
Interest expense, net(24)(18)(46)(36)
Other, net8 4 15 8 
Total other income and (deductions)(16)(14)(31)(28)
Income before income taxes42 30 126 102 
Income taxes8 5 25 17 
Net income$34 $25 $101 $85 
Comprehensive income$34 $25 $101 $85 
See the Combined Notes to Consolidated Financial Statements
39



DELMARVA POWER & LIGHT COMPANY
STATEMENTS OF CASH FLOWS
(Unaudited)
Six Months Ended
June 30,
(In millions)20242023
Cash flows from operating activities
Net income$101 $85 
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation and amortization122 121 
Deferred income taxes and amortization of investment tax credits7 3 
Other non-cash operating activities15 2 
Changes in assets and liabilities:
Accounts receivable4 48 
Receivables from and payables to affiliates, net2 1 
Inventories(10)5 
Accounts payable and accrued expenses38 (9)
Collateral paid, net— (121)
Income taxes(24)11 
Regulatory assets and liabilities, net(26)25 
Other assets and liabilities21 10 
Net cash flows provided by operating activities250 181 
Cash flows from investing activities
Capital expenditures(268)(258)
Changes in PHI intercompany money pool(125)(102)
Net cash flows used in investing activities(393)(360)
Cash flows from financing activities
Changes in short-term borrowings(63)(115)
Issuance of long-term debt175 125 
Dividends paid on common stock(84)(60)
Contributions from parent154 99 
Other financing activities(4)(4)
Net cash flows provided by financing activities178 45 
Increase (decrease) in cash, restricted cash, and cash equivalents35 (134)
Cash, restricted cash, and cash equivalents at beginning of period16 152 
Cash, restricted cash, and cash equivalents at end of period$51 $18 
Supplemental cash flow information
Decrease in capital expenditures not paid$(2)$(3)
    
See the Combined Notes to Consolidated Financial Statements
40



DELMARVA POWER & LIGHT COMPANY
BALANCE SHEETS
(Unaudited)
(In millions)June 30, 2024December 31, 2023
ASSETS
Current assets
Cash and cash equivalents$50 $16 
Restricted cash and cash equivalents1 — 
Accounts receivable
Customer accounts receivable172183
Customer allowance for credit losses(16)(19)
Customer accounts receivable, net156 164 
Other accounts receivable5352
Other allowance for credit losses(7)(8)
Other accounts receivable, net46 44 
Receivables from affiliates— 1 
Receivable from PHI intercompany pool125 — 
Inventories, net
Fossil fuel5 9 
Materials and supplies86 72 
Prepaid utility taxes— 24 
Regulatory assets69 54 
Other25 14 
Total current assets563 398 
Property, plant, and equipment (net of accumulated depreciation and amortization of $2,003 and $1,925 as of June 30, 2024 and December 31, 2023, respectively)
5,324 5,165 
Deferred debits and other assets
Regulatory assets214 218 
Prepaid pension asset128 135 
Other48 50 
Total deferred debits and other assets390 403 
Total assets$6,277 $5,966 
See the Combined Notes to Consolidated Financial Statements
41



DELMARVA POWER & LIGHT COMPANY
BALANCE SHEETS
(Unaudited)
(In millions)June 30, 2024December 31, 2023
LIABILITIES AND SHAREHOLDER'S EQUITY
Current liabilities
Short-term borrowings$— $63 
Long-term debt due within one year85 84 
Accounts payable191 159 
Accrued expenses45 64 
Payables to affiliates26 25 
Customer deposits33 31 
Regulatory liabilities 60 50 
Other18 21 
Total current liabilities458 497 
Long-term debt2,169 1,996 
Deferred credits and other liabilities
Deferred income taxes and unamortized investment tax credits923 904 
Regulatory liabilities343 365 
Asset retirement obligations13 12 
Non-pension postretirement benefits obligations6 6 
Other102 93 
Total deferred credits and other liabilities1,387 1,380 
Total liabilities4,014 3,873 
Commitments and contingencies
Shareholder's equity
Common stock 1,609 1,455 
Retained earnings654 638 
Total shareholder's equity2,263 2,093 
Total liabilities and shareholder's equity$6,277 $5,966 
See the Combined Notes to Consolidated Financial Statements
42



DELMARVA POWER & LIGHT COMPANY
STATEMENTS OF CHANGES IN SHAREHOLDER'S EQUITY
(Unaudited)
Six Months Ended June 30, 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 
Net income— 34 34 
Common stock dividends— (39)(39)
Balance at June 30, 2024$1,609 $654 $2,263 

Six Months Ended June 30, 2023
(In millions)Common Stock Retained EarningsTotal Shareholder's Equity
Balance at December 31, 2022$1,356 $594 $1,950 
Net income— 60 60 
Common stock dividends— (42)(42)
Contributions from parent99 — 99 
Balance at March 31, 2023$1,455 $612 $2,067 
Net income— 25 25 
Common stock dividends— (18)(18)
Balance at June 30, 2023$1,455 $619 $2,074 

See the Combined Notes to Consolidated Financial Statements
43




ATLANTIC CITY ELECTRIC COMPANY AND SUBSIDIARY COMPANY
CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME
(Unaudited)
Three Months Ended
June 30,		Six Months Ended
June 30,
(In millions)2024202320242023
Operating revenues
Electric operating revenues$403 $317 $748 $653 
Revenues from alternative revenue programs(21)(1)(9)16 
Operating revenues from affiliates1 1 1 1 
Total operating revenues383 317 740 670 
Operating expenses
Purchased power172 124 312 273 
Operating and maintenance50 48 97 91 
Operating and maintenance from affiliates42 37 81 74 
Depreciation and amortization72 68 146 135 
Taxes other than income taxes2 3 5 4 
Total operating expenses338 280 641 577 
Operating income45 37 99 93 
Other income and (deductions)
Interest expense, net(20)(17)(39)(34)
Other, net4 4 8 9 
Total other income and (deductions)(16)(13)(31)(25)
Income before income taxes29 24 68 68 
Income taxes8 6 18 17 
Net income$21 $18 $50 $51 
Comprehensive income$21 $18 $50 $51 
See the Combined Notes to Consolidated Financial Statements
44



ATLANTIC CITY ELECTRIC COMPANY AND SUBSIDIARY COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
Six Months Ended
June 30,
(In millions)20242023
Cash flows from operating activities
Net income$50 $51 
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation and amortization146 135 
Deferred income taxes and amortization of investment tax credits12 12 
Other non-cash operating activities30 (3)
Changes in assets and liabilities:
Accounts receivable(50)(5)
Receivables from and payables to affiliates, net(2)(5)
Inventories(3)(9)
Accounts payable and accrued expenses26 15 
Collateral received (paid), net2 (45)
Income taxes(10)(4)
Regulatory assets and liabilities, net(51)(12)
Pension and non-pension postretirement benefit contributions(8)— 
Other assets and liabilities(60)(89)
Net cash flows provided by operating activities82 41 
Cash flows from investing activities
Capital expenditures(180)(275)
Net cash flows used in investing activities(180)(275)
Cash flows from financing activities
Changes in short-term borrowings(199)37 
Issuance of long-term debt75 75 
Changes in PHI intercompany money pool182 50 
Dividends paid on common stock(44)(36)
Contributions from parent81 63 
Other financing activities(3)(3)
Net cash flows provided by financing activities92 186 
Decrease in cash and cash equivalents(6)(48)
Cash and cash equivalents at beginning of period21 72 
Cash and cash equivalents at end of period$15 $24 
Supplemental cash flow information
Decrease in capital expenditures not paid$(5)$(44)
See the Combined Notes to Consolidated Financial Statements
45



ATLANTIC CITY ELECTRIC COMPANY AND SUBSIDIARY COMPANY
CONSOLIDATED BALANCE SHEETS
(Unaudited)
(In millions)June 30, 2024December 31, 2023
ASSETS
Current assets
Cash and cash equivalents$15 $21 
Accounts receivable
Customer accounts receivable241194
Customer allowance for credit losses(34)(36)
Customer accounts receivable, net207 158 
Other accounts receivable9292
Other allowance for credit losses(13)(14)
Other accounts receivable, net79 78 
Receivables from affiliates3 3 
Inventories, net58 55 
Prepaid utility taxes41 — 
Regulatory assets116 125 
Other7 5 
Total current assets526 445 
Property, plant, and equipment (net of accumulated depreciation and amortization of $1,728 and $1,684 as of June 30, 2024 and December 31, 2023, respectively)
4,268 4,192 
Deferred debits and other assets
Regulatory assets497 483 
Prepaid pension asset2 3 
Other34 34 
Total deferred debits and other assets533 520 
Total assets$5,327 $5,157 
See the Combined Notes to Consolidated Financial Statements
46



ATLANTIC CITY ELECTRIC COMPANY AND SUBSIDIARY COMPANY
CONSOLIDATED BALANCE SHEETS
(Unaudited)
(In millions)June 30, 2024December 31, 2023
LIABILITIES AND SHAREHOLDER'S EQUITY
Current liabilities
Short-term borrowings$— $199 
Long-term debt due within one year154 154 
Accounts payable206 192 
Accrued expenses45 42 
Payables to affiliates24 25 
Borrowings from PHI intercompany money pool182 — 
Customer deposits22 23 
Regulatory liabilities6 6 
PPA termination obligation20 49 
Other10 12 
Total current liabilities669 702 
Long-term debt1,755 1,679 
Deferred credits and other liabilities
Deferred income taxes and unamortized investment tax credits785 771 
Regulatory liabilities150 140 
Non-pension postretirement benefit obligations2 4 
Other67 49 
Total deferred credits and other liabilities1,004 964 
Total liabilities3,428 3,345 
Commitments and contingencies
Shareholder's equity
Common stock1,911 1,830 
Retained deficit(12)(18)
Total shareholder's equity1,899 1,812 
Total liabilities and shareholder's equity$5,327 $5,157 

See the Combined Notes to Consolidated Financial Statements
47



ATLANTIC CITY ELECTRIC COMPANY AND SUBSIDIARY COMPANY
CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDER'S EQUITY
(Unaudited)
Six Months Ended June 30, 2024
(In millions)Common StockRetained (Deficit)Total Shareholder's Equity
Balance at December 31, 2023$1,830 $(18)$1,812 
Net income— 29 29 
Common stock dividends— (22)(22)
Contributions from parent81 — 81 
Balance at March 31, 2024$1,911 $(11)$1,900 
Net income— 21 21 
Common stock dividends— (22)(22)
Balance at June 30, 2024$1,911 $(12)$1,899 

Six Months Ended June 30, 2023
(In millions)Common Stock Retained (Deficit) EarningsTotal Shareholder's Equity
Balance at December 31, 2022$1,765 $(12)$1,753 
Net income— 33 33 
Common stock dividends— (21)(21)
Contributions from parent63 — 63 
Balance at March 31, 2023$1,828 $— $1,828 
Net income— 18 18 
Common stock dividends— (15)(15)
Balance at June 30, 2023$1,828 $3 $1,831 

See the Combined Notes to Consolidated Financial Statements
48



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
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
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, distribution and transmission planning, asset management, system operations, and power procurement, to PHI operating companies. 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” in the consolidated financial statements and include intercompany eliminations unless otherwise disclosed.
The accompanying consolidated financial statements as of June 30, 2024 and for the three and six months ended June 30, 2024 and 2023 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, 2023 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, 2024. 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
49


COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in millions, except per share data, unless otherwise noted)

Note 1 — Significant Accounting Policies
financial statements prepared in accordance with GAAP have been condensed or omitted pursuant to such rules and regulations.
New Accounting Standards (All Registrants)
New Accounting Standards Issued and Not Yet Adopted as of June 30, 2024: The following new authoritative accounting guidance issued by the FASB has not yet been adopted and reflected by the Registrants in their consolidated financial statements as of June 30, 2024. 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.

Segment Reporting (Issued November 2023). Improves reportable segment disclosure requirements, primarily through enhanced disclosures about significant segment expenses. The objective of the revised guidance is to introduce a new requirement to disclose significant segment expenses regularly provided to the CODM, extend certain annual disclosures to interim periods, clarify single reportable segment entities must apply ASC 280 in its entirety, permit more than one measure of segment profit or loss to be reported under certain conditions, and require disclosure of the title and position of the CODM. The standard is effective for annual periods beginning January 1, 2024 and interim periods beginning January 1, 2025, with early adoption permitted. The standard will be applied retrospectively.

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 January 1, 2025, with early adoption permitted.
2. Regulatory Matters (All Registrants)
As discussed in Note 3 — Regulatory Matters of the 2023 Form 10-K, the Registrants are involved in rate and regulatory proceedings at FERC and their state commissions. The following discusses developments in 2024 and updates to the 2023 Form 10-K.
50


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 2024.
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 $501 8.905%
December 14, 2023(a)
January 1, 2024
$838 $810 8.905%
April 18, 2024(b)
May 1, 2024
April 21, 2023(c)
Electric$247 $259 8.91%November 30, 2023January 1, 2024
BGE - Maryland(d)
February 17, 2023Electric$313 $179 9.50%December 14, 2023January 1, 2024
Natural Gas$289 $229 9.45%
Pepco - Maryland
October 26, 2020 (amended March 31, 2021)(e)
Electric$104 $52 9.55%June 28, 2021June 28, 2021
May 16, 2023 (amended February 23, 2024)(f)
Electric$111 $45 9.50%June 10, 2024April 1, 2024
DPL - Maryland(g)
May 19, 2022Electric$38 $29 9.60%December 14, 2022January 1, 2023
DPL - Delaware(h)
December 15, 2022 (amended September 29, 2023)Electric$39 $28 9.60%April 18, 2024July 15, 2023
ACE - New Jersey(i)
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. On December 14, 2023, the ICC approved year-over-year distribution revenue requirement increases in 2024-2027, with an amendatory order on January 10, 2024, of approximately $451 million effective January 1, 2024, $14 million effective January 1, 2025, $6 million effective January 1, 2026, and $30 million effective January 1, 2027, based on an ROE of 8.905%, an equity ratio of 50%, and year end 2022 rate base. The ICC rejected ComEd’s Grid Plan, requiring ComEd to file a revised Grid Plan by March 13, 2024, 90 days after the issuance of the December final order. The ICC also directed that the revised Grid Plan would be reviewed through further formal proceedings in that docket. On January 10, 2024, the ICC granted one portion of ComEd’s application for rehearing of the December 14, 2023 final order, and directed that a rehearing process extending no more than 150 days reconsider certain components of the revenue requirements for the test years (2024-2027), absent an approved Grid Plan. On January 10, 2024, ComEd also filed with the Illinois appellate court an appeal of various aspects of the ICC’s final order on which rehearing was denied, including the 8.905% ROE and 50% equity ratio and denial of any return on ComEd’s pension asset. On March 13, 2024, ComEd filed its revised Grid Plan (Refiled Grid Plan) with supporting testimony and schedules with the ICC. On March 15, 2024, ComEd filed a petition to adjust its MRP to authorize increased rates consistent with the Refiled Grid Plan.
(b)Reflects four-year cumulative increase to the revenue requirement approved on December 14, 2023 and amended on January 10, 2024 of $810 million for January 1, 2024 to December 31, 2027 resulting from the rehearing on certain components of the rate plan. On February 16, 2024, ComEd filed a revised revenue request for an $838 million increase in its 2024-2027 revenue requirements based on the ICC’s limited scope for rehearing which included the value of the 2023 forecasted year-end rate base. On April 18, 2024, the ICC issued an order on the rehearing filing which increased the revenue requirements previously approved by the ICC in its January 10, 2024, amendatory order by $150 million in 2024, $186 million in 2025, $221 million in 2026 and $253 million in 2027. ComEd anticipates that the revenue
51


COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)

Note 2 — Regulatory Matters
requirements determined during the rehearing process will be further adjusted upon approval of the Refiled Grid Plan and the pending petition to adjust rates.
(c)On November 30, 2023, the Delivery Reconciliation Amount for 2022 defined in Rider Delivery Service Pricing Reconciliation (Rider DSPR) was approved. The delivery reconciliation amount 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 2023 filing reconciled the delivery service rates in effect in 2022 with the actual delivery service costs incurred in 2022. The reconciliation revenue requirement provides for a weighted average debt and equity return on distribution rate base of 6.48%, inclusive of an allowed ROE of 8.91%, reflecting the monthly yields on 30-year treasury bonds plus 580 basis points.
(d)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.
(e)Reflects a three-year cumulative multi-year plan for April 1, 2021 through March 31, 2024. The MDPSC awarded Pepco electric incremental revenue requirement increases of $21 million, $16 million, and $15 million, before offsets, for the 12-month periods ending March 31, 2022, 2023, and 2024, respectively. Pepco proposed to utilize certain tax benefits to fully offset the increase through 2023 and partially offset customer rate increases in 2024. However, the MDPSC only utilized the acceleration of refunds for certain tax benefits to fully offset the increases such that customer rates remain unchanged through March 31, 2022. On February 23, 2022, the MDPSC chose to offset 25% of the cumulative revenue requirement increase for the 12-month period ending March 31, 2023. In 2021, the MDPSC deferred a decision on whether to use certain tax benefits to offset the revenue requirement increases for the 12-month period ending March 31, 2024. In December 2022 Pepco proposed that tax benefits not be used to offset the revenue requirement increases for this period. On January 25, 2023, the MDPSC accepted Pepco’s recommendations not to use tax benefits to offset revenue requirement increases for the 12-month period ending March 31, 2024.
(f)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 order allows for Pepco to perform an annual reconciliation after the 2024 rate year. 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.
(g)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.
(h)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.
(i)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.
52


COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)

Note 2 — Regulatory Matters
Pending Distribution Base Rate Case Proceedings
Registrant/JurisdictionFiling DateServiceRequested Revenue Requirement IncreaseRequested ROEExpected Approval Timing
ComEd - IllinoisMarch 15, 2024 (amended June 20, 2024)
Electric(a)
$682 8.905%December 2024
April 26, 2024
Electric(b)
$627 9.89%December 2024
PECO - PennsylvaniaMarch 28, 2024
Electric(c)
$464 10.95%Fourth quarter of 2024
Natural Gas$111 11.15%
Pepco - District of Columbia(d)
April 13, 2023 (amended February 27, 2024)Electric$186 10.50%Fourth quarter of 2024
__________
(a)On March 13, 2024, ComEd filed its Refiled Grid Plan with the ICC and on March 15, 2024, ComEd filed a petition to adjust its multi-year rate plan to be aligned with ComEd’s Refiled Grid Plan. The adjusted rate plan incorporates changes in the Refiled Grid Plan, which was updated in ComEd's rebuttal testimony on June 20, 2024, to request a $682 million increase in revenue requirements over four years above those granted in the ICC’s January 10, 2024, amendatory order. The requested year-over-year increases are $308 million in 2024, $96 million in 2025, $135 million in 2026, and $143 million in 2027. A final order on both the Refiled Grid Plan and the adjusted rate plan petition is expected by December 2024 with new rates effective on or before January 1, 2025.
(b)On April 26, 2024, ComEd filed its proposed Delivery Reconciliation Amount of $627 million under Rider DSPR which allows for the reconciliation of the revenue requirement in effect. The 2024 filing reconciles those rates with the actual delivery service costs incurred in 2023. The final order is expected by December 2024 and the reconciliation amount will adjust customer rates in 2025.
(c)PECO requested an annual electric revenue requirement increase of $464 million, which is partially offset by a one-time credit of $64 million in 2025.
(d)Reflects a three-year cumulative multi-year plan for January 1, 2024 through December 31, 2026 submitted to the DCPSC. Pepco requested total electric revenue requirement increases of $116 million, $35 million, and $35 million in 2024, 2025, and 2026, respectively. Requested revenue requirement increases will be used to recover capital investments designed to advance system-readiness and support the District of Columbia’s climate and clean energy goals.
Transmission Formula Rates
The Utility Registrants' transmission rates are each established based on a FERC-approved formula. ComEd, BGE, Pepco, DPL, and ACE are required to file an annual update to the FERC-approved formula on or before May 15, and PECO is required to file on or before May 31, with the resulting rates effective on June 1 of the same year. The annual update for ComEd is based on prior year actual costs and current year projected capital additions (initial year revenue requirement). The update for ComEd also reconciles any differences between the revenue requirement in effect beginning June 1 of the prior year and actual costs incurred for that year (annual reconciliation). The annual update for PECO is based on prior year actual costs and current year projected capital additions, accumulated depreciation and accumulated deferred income taxes. The annual update for BGE, Pepco, DPL, and ACE is based on prior year actual costs and current year projected capital additions, accumulated depreciation, depreciation and amortization expense, and accumulated deferred income taxes. The update for PECO, BGE, Pepco, DPL, and ACE also reconciles any differences between the actual costs and actual revenues for the calendar year (annual reconciliation).
53


COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)

Note 2 — Regulatory Matters
For 2024, the following increases/(decreases) were included in the Utility Registrants' electric transmission formula rate updates:
Registrant(a)
Initial Revenue Requirement IncreaseAnnual Reconciliation (Decrease)
Increase		Total Revenue Requirement Increase
Allowed Return on Rate Base(b)
Allowed ROE(c)
ComEd$32 $(12)$20 8.14 %11.50 %
PECO$2 $3 $5 7.45 %10.35 %
BGE$42 $13 $53 (d)7.47 %10.50 %
Pepco$58 $15 $73 7.62 %10.50 %
DPL$7 $17 $24 7.23 %10.50 %
ACE$14 $18 $32 7.11 %10.50 %
__________
(a)All rates are effective June 1, 2024 - May 31, 2025, subject to review by interested parties pursuant to review protocols of each Utility Registrants' tariffs.
(b)Represents the weighted average debt and equity return on transmission rate bases. For PECO, the common equity component of the ratio used to calculate the weighted average debt and equity return on the transmission formula rate base is currently capped at 55.75%.
(c)The rate of return on common equity for each Utility Registrant includes a 50-basis-point incentive adder for being a member of an RTO.
(d)The increase in BGE's transmission revenue requirement includes a $2 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
ComEd filed, and received approval for, its last performance-based electric distribution formula rate update under EIMA in 2022; those rates were in effect throughout 2023.
On February 3, 2022, the ICC approved a tariff that establishes the process under which ComEd reconciled its 2022 and 2023 rate year revenue requirements with actual costs. Those reconciliation amounts are determined using the same process used for prior reconciliations under the performance-based electric distribution formula rate. Using that process, for the rate years 2022 and 2023 ComEd will ultimately collect revenues from customers reflecting each year’s actual recoverable costs, year-end rate base, and a weighted average debt and equity return on distribution rate base, with the ROE component based on the annual average of the monthly yields of the 30-year U.S. Treasury bonds plus 580 basis points. In April 2023, ComEd filed its first petition with the ICC to reconcile its 2022 actual costs with the approved revenue requirement that was in effect in 2022; the final order was issued on November 30, 2023, for rates beginning January 2024. On April 26, 2024, ComEd filed with the ICC its 2023 actual costs with the approved revenue requirement that was in effect in 2023; the final order is expected by December 2024, for rates beginning January 2025.
Beginning in 2024, ComEd will recover 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
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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)

Note 2 — Regulatory Matters
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 by March 13, 2024, 90 days after the issuance of the final order. 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 remains subject to annual reconciliation in accordance with CEJA. The final order approved the process and formulas associated with the MRP reconciliation mechanisms. The ICC did not approve a previously proposed phase-in of the ICC's approved year-over-year revenue increases, and it also denied ComEd's ability to earn a return on its pension asset.
On December 22, 2023, ComEd filed an application for rehearing on several findings in the final order including the use of the 2022 year-end rate base to establish forecast revenue requirements for 2024-2027, ROE, pension asset return, and capital structure. On January 10, 2024, ComEd’s application for rehearing was denied on all issues except for the order’s use of the 2022 year-end rate base. On January 31, 2024, the ICC granted ComEd's motion seeking additional clarification on the scope on rehearing, generally accepting ComEd's proposal and confirming that the rehearing will determine if the forecasted year-end 2023 rate base should be used to set rates for 2024 through 2027 until a refiled Grid Plan is approved. On April 18, 2024, the ICC issued its final order on rehearing and approved increased revenue requirements for 2024-2027.

On January 10, 2024, ComEd also filed an appeal in the Illinois Appellate Court of the issues on which rehearing was denied, including but not limited to the allowed ROE and denial of a return on ComEd’s pension asset. There is no deadline by when the appellate court must rule. On March 7, 2024, the ICC adopted an interim order on scheduling, which confirmed that it intends to issue a final order on ComEd’s Refiled Grid Plan by the end of 2024 and that it will implement rates that will go into effect January 1, 2025, inclusive of a Grid Plan. On March 13, 2024, ComEd filed its Refiled Grid Plan with supporting testimony and schedules with the ICC. The Refiled Grid Plan is designed to meet or exceed every requirement identified by the ICC in its December order that rejected ComEd’s initial Grid Plan. On March 15, 2024, ComEd filed a petition to adjust its MRP to authorize increased rates consistent with the Refiled Grid Plan. Staff and Intervenor direct testimony was filed in May 2024. ComEd filed rebuttal and surrebuttal testimony in June and July, respectively, which provided, among other things, defense of its Refiled Grid Plan capital investments. Evidentiary hearings are scheduled for mid-August. ComEd has completed and placed in service additional utility plant assets in 2023 and 2024 and will continue to complete and place in service additional utility plant assets prior to the approval of the new Grid Plan. There are still significant unknowns, but ComEd does not currently believe that it is probable that the initially uncollected depreciation or return on the recently completed plant will ultimately be disallowed.
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. Efforts are underway to implement the performance metrics, which took effect on January 1, 2024. ComEd will make its initial filing in 2025 to assess performance achieved under the metrics in 2024, and to determine any ROE adjustment, which would take effect in 2026.
Carbon Mitigation Credit
CEJA establishes decarbonization requirements for Illinois as well as programs to support the retention and development of emissions-free sources of electricity. ComEd is required to purchase CMCs from participating nuclear-powered 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 consumer protection measures contained in CEJA will result in net
55


COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)

Note 2 — Regulatory Matters
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 new CMC rider. 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 June 30, 2024 is $304 million.
Under CEJA, the costs of procuring CMCs, including carrying costs, are recovered through a rider, the Rider Carbon-Free Resource Adjustment (Rider CFRA). As originally approved by the ICC, Rider CFRA provides for an annual reconciliation and true-up to actual costs incurred or credits received by ComEd to purchase CMCs, with any difference to be credited to or collected from ComEd’s retail customers in subsequent periods. The difference between the net payments to (or receivables from) ComEd ratepayers and the credits received by ComEd to purchase CMCs is recorded to Purchased power expense with an offset to the regulatory asset (or regulatory liability). On December 21, 2022, ComEd filed an amendment to Rider CFRA proposing that it recover costs or provide credits faster than the tariff allows, implement monthly reconciliations, and allow ComEd to adjust Rider CFRA rates based not only on anticipated differences but also past payments or credits, and implement monthly reconciliations beginning with the June 2023 delivery period. The ICC approved the proposal on January 19, 2023. In addition, on March 24, 2023, ComEd submitted revisions to Rider CFRA which clarified the methodology for calculating interest to be included in the annual reconciliation associated with the June 2022 through May 2023 delivery year. The ICC approved the proposal on April 20, 2023. On February 2, 2024, ComEd filed a petition with the ICC to initiate the reconciliation proceeding for the costs incurred in connection with the procurement of CMCs during the delivery year beginning June 1, 2022 and extending through May 31, 2023.
Beneficial Electrification Plan
On March 23, 2023, the ICC issued its final order approving the beneficial electrification plan (BE Plan) for ComEd. The ICC rejected ComEd’s request to treat a large portion of beneficial electrification costs as a regulatory asset and ordered ComEd to seek cost recovery through the multi-year rate plan filing for 2024 and 2025, and the final formula rate reconciliation docket for 2023, rather than through a separate charge. The order also authorized an overall annual budget of $77 million per year for the three-year plan period (2023 through 2025), with flexibility to roll forward unused funds to future years within the same plan period. On April 18, 2023, ComEd filed an application for rehearing in the beneficial electrification plan docket. The Chicago Transit Authority and City of Chicago, jointly, and the Office of the Illinois Attorney General (ILAG) also filed applications for rehearing. On April 27, 2023, ICC staff filed a motion for clarification, seeking clarification from the ICC on the precise budget described in the final order. On May 8, 2023, the ICC denied all applications for rehearing, and entered an amendatory order regarding the annual beneficial electrification plan budgets. ComEd has been directed to use good faith efforts to spend $77 million annually. ComEd subsequently filed its compliance filing in May 2023, detailing project related spending, clarifying the procedure that will be used to seek stakeholder feedback related to beneficial electrification pilot programs, and including the timeline for tariff changes required to implement the programs. ComEd and the ILAG both filed appeals of the ICC’s interim order that addressed the permissible scope of utility beneficial electrification programs outside of transportation and the rate impact cap. The ILAG also filed an appeal seeking reversal of portions of the ICC’s final decision. The final order partly mooted ComEd’s appeal of the interim order and ComEd has decided not to pursue the other issues. As such, ComEd moved to voluntarily dismiss its appeal and the appellate court granted that request. The ILAG consolidated their appeals and filed their opening brief on April 16, 2024. ComEd filed its reply brief on July 30, 2024. Any ruling on the appeals, even a negative ruling removing programs from the BE Plan or lowering the overall budget of the BE Plan, will only impact forward-looking costs.
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 will be deferred as a separate regulatory asset that will be recovered through the energy efficiency formula rate over the weighted average useful life, as approved by the ICC, of the related energy efficiency measures.
Energy Efficiency Formula Rate (Exelon and ComEd). ComEd filed its annual energy efficiency formula rate update with the ICC on May 30, 2024. The filing establishes the revenue requirement used to set the rates that
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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)

Note 2 — Regulatory Matters
will take effect in January 2025 after the ICC's review and approval. The requested revenue requirement update is based on a reconciliation of the 2023 actual costs plus projected 2025 expenditures.
Initial Revenue Requirement IncreaseAnnual Reconciliation DecreaseTotal Revenue Requirement Increase
Requested Return on Rate Base(a)
Requested ROE
$66 $(8)$58 7.02 %9.89 %
__________
(a)The requested revenue requirement increase provides for a weighted average debt and equity return on the energy efficiency regulatory asset and rate base of 7.02% inclusive of an allowed ROE of 9.89%, reflecting the monthly average yields for 30-year treasury bonds plus 580 basis points. For the 2023 reconciliation year, the requested revenue requirement provides for a weighted average debt and equity return on the energy efficiency regulatory asset and rate base of 7.25% inclusive of an allowed ROE of 10.34%, which includes an upward performance adjustment that increased the ROE. The performance adjustment can either increase or decrease the ROE based upon the achievement of energy efficiency savings goals.
New Jersey Regulatory Matters
Termination of Energy Procurement Provisions of PPAs (Exelon, PHI, and ACE). On December 22, 2021, ACE filed with the NJBPU a petition to terminate the provisions in the PPAs to purchase electricity from two coal-powered generation facilities located in the state of New Jersey. The petition was approved by the NJBPU on March 23, 2022. Upon closing of the transaction on March 31, 2022, ACE recognized a liability of $203 million for the contract termination fee, which is to be paid by the end of 2024, and recognized a corresponding regulatory asset of $203 million.
As of June 30, 2024, the $20 million liability for the contract termination fee is included in Other current liabilities in Exelon's Consolidated Balance Sheet and PPA termination obligation in PHI's and ACE's Consolidated Balance Sheets. For the six months ended June 30, 2024 and 2023, ACE has respectively paid $30 million and $43 million of the liability, which is recorded in Changes in Other assets and liabilities in Exelon's, PHI's, and ACE's Consolidated Statements of Cash Flows.
Other Federal Regulatory Matters
FERC Audit (Exelon and ComEd). The Utility Registrants are subject to periodic audits and investigations by FERC. FERC’s Division of Audits and Accounting initiated a nonpublic audit of ComEd in April 2021 evaluating ComEd’s compliance with (1) approved terms, rates and conditions of its federally regulated service; (2) accounting requirements of the Uniform System of Accounts; (3) reporting requirements of the FERC Form 1; and (4) the requirements for record retention. The audit period extends back to January 1, 2017.
On July 27, 2023, FERC issued a final audit report which included, among other things, findings and recommendations related to ComEd's methodology regarding the allocation of certain overhead costs to capitalized construction costs under FERC regulations, including a suggestion that refunds may be due to customers for amounts collected in previous years. On August 28, 2023, ComEd filed a formal notice of the issues it will contest. 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 has been held in abeyance while a formal settlement process, which began in February 2024, takes 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 final settlement is subject to FERC approval. The existing estimates of loss have been updated and reflected in Exelon and ComEd financial statements as of June 30, 2024.
57


COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)

Note 2 — Regulatory Matters
Regulatory Assets and Liabilities
The Utility Registrants' regulatory assets and liabilities have not changed materially since December 31, 2023, unless noted below. See Note 3 — Regulatory Matters of the 2023 Form 10-K for additional information on the specific regulatory assets and liabilities.
ComEd. Regulatory assets decreased $339 million primarily due to a decrease of $369 million in the CMC regulatory asset. Regulatory liabilities increased $802 million primarily due to an increase of $612 million in the Decommissioning the Regulatory Agreement Units regulatory liability.
PECO. Regulatory assets increased $56 million primarily due to an increase of $60 million in the Deferred Income Taxes regulatory asset.
BGE. Regulatory liabilities decreased $89 million primarily due to a decrease of $88 million in the Deferred income taxes regulatory liability.
Pepco. Regulatory assets increased $39 million primarily due to an increase of $25 million in the Multi-year plan reconciliations regulatory asset and an increase of $12 million in the Revenue deferral mechanism regulatory asset, as a result of the Pepco Maryland multi-year plan order issued on June 10, 2024. Regulatory liabilities decreased $27 million primarily due to a decrease of $26 million in the Deferred income taxes regulatory liability.
ACE. Regulatory liabilities increased $10 million primarily due to an increase of $13 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 June 30, 2024 and December 31, 2023.
Exelon
ComEd(a)
BGE(b)
PHI
Pepco(c)
DPL(d)
ACE(e)
June 30, 2024$134 $40 $43 $51 $38 $1 $12 
December 31, 2023110 32 33 45 34 1 10 
__________
(a)Reflects ComEd's unrecognized equity returns earned for ratemaking purposes on its electric distribution and energy efficiency formula rate regulatory assets.
(b)BGE's amount capitalized for ratemaking purposes primarily relates to earnings on shareholders' investment on their AMI programs, investments in rate base included in the multi-year plan reconciliations, and revenue decoupling.
(c)Pepco's authorized amounts capitalized for ratemaking purposes relate to earnings on shareholders' investment on AMI programs, Energy efficiency and demand response programs, investments in rate base and revenues included in the multi-year plan reconciliations, and a portion of Pepco District of Columbia's revenue decoupling.
(d)DPL's authorized amounts capitalized for ratemaking purposes relate to earnings on shareholders' investment on AMI programs and Energy efficiency and demand response programs.
(e)ACE's authorized amounts capitalized for ratemaking purposes primarily relate to earnings on shareholders' investment on AMI programs.
3. Revenue from Contracts with Customers (All Registrants)
The Registrants recognize revenue from contracts with customers to depict the transfer of goods or services to customers at an amount that the entities expect to be entitled to in exchange for those goods or services. The primary sources of revenue include regulated electric and gas tariff sales, distribution, and transmission services.
See Note 4 — Revenue from Contracts with Customers of the 2023 Form 10-K for additional information regarding the primary sources of revenue for the Registrants.
Contract Liabilities
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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)

Note 3 — Revenue from Contracts with Customers
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 2023 Form 10-K. The contract liability balance attributable to the Agreement and the Amendment is being recognized as Electric operating revenues over a 35 year period and 31 year period, respectively.
The following table provides a rollforward of the contract liabilities reflected in Exelon's, PHI's, Pepco's, DPL's, and ACE's Consolidated Balance Sheets for the three and six months ended June 30, 2024 and 2023. At June 30, 2024 and December 31, 2023, ComEd's, PECO's, and BGE's contract liabilities were immaterial.
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 
Revenues recognized(1)(1)(1)— — 
Balance at June 30, 2024$130 $130 $104 $13 $13 
Exelon(a)
PHI(a)
Pepco(a)
DPLACE
Balance at December 31, 2022$101 $101 $81 $10 $10 
Revenues recognized(1)(1)(1)— — 
Balance at March 31, 2023$100 $100 $80 $10 $10 
Revenues recognized(2)(2)(2)— — 
Balance at June 30, 2023$98 $98 $78 $10 $10 
__________
(a)Revenues recognized in the three and six months ended June 30, 2024 and 2023, were included in the contract liabilities at December 31, 2023 and 2022, respectively.
Transaction Price Allocated to Remaining Performance Obligations
The following table shows the amounts of future revenues expected to be recorded in each year for performance obligations that are unsatisfied or partially unsatisfied as of June 30, 2024. This disclosure only includes contracts for which the total consideration is fixed and determinable at contract inception. The average contract term varies by customer type and commodity but ranges from one month to several years.
This disclosure excludes the Utility Registrants' gas and electric tariff sales contracts and transmission revenue contracts as they generally have an original expected duration of one year or less and, therefore, do not contain any future, unsatisfied performance obligations to be included in this disclosure.
YearExelonPHIPepcoDPLACE
2024$3 $3 $3 $— $— 
20257 7 5 1 1 
20266 6 5 1 — 
20275 5 5 — — 
2028 and thereafter109 109 86 11 12 
Total$130 $130 $104 $13 $13 
59


COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)

Note 3 — Revenue from Contracts with Customers
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.
Exelon has six reportable segments, which include ComEd, PECO, BGE, and PHI's three reportable segments consisting of Pepco, DPL, and ACE. ComEd, PECO, BGE, Pepco, DPL, and ACE each represent a single reportable segment, and as such, no separate segment information is provided for these Registrants. Exelon, ComEd, PECO, BGE, Pepco, DPL, and ACE's CODMs evaluate the performance of and allocate resources to the segments based on net income.
An analysis and reconciliation of the Registrants’ reportable segment information to the respective information in the consolidated financial statements for the three and six months ended June 30, 2024 and 2023 is as follows:

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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)

Note 4 — Segment Information
Three Months Ended June 30, 2024 and 2023
ComEdPECOBGEPHI
Other(a)
Intersegment
Eliminations		Exelon
Operating revenues(b):
2024
Electric revenues$2,079 $797 $782 $1,441 $— $(6)$5,093 
Natural gas revenues— 94 146 28 — — 268 
Shared service and other revenues— — — 2 468 (470)— 
Total operating revenues$2,079 $891 $928 $1,471 $468 $(476)$5,361 
2023
Electric revenues$1,901 $719 $672 $1,274 $— $(10)$4,556 
Natural gas revenues— 109 125 29 — (1)262 
Shared service and other revenues— — — 2 434 (436)— 
Total operating revenues$1,901 $828 $797 $1,305 $434 $(447)$4,818 
Intersegment revenues(c):
2024$2 $2 $2 $2 $466 $(474)$— 
20232 2 2 2 432 (440)— 
Depreciation and amortization:
2024$374 $107 $162 $235 $16 $— $894 
2023350 99 158 243 16 — 866 
Operating expenses:
2024$1,680 $752 $835 $1,204 $471 $(487)$4,455 
20231,478 687 704 1,126 561 (442)4,114 
Interest expense, net:
2024$123 $57 $53 $92 $158 $— $483 
2023120 48 44 81 134 — 427 
Income Taxes:
2024$31 $3 $4 $46 $(38)$— $46 
202371 2 12 20 (32)— 73 
Net income (loss):
2024$270 $90 $44 $158 $(114)$— $448 
2023249 97 42 103 (142)(6)343 
Capital Expenditures:
2024$517 $382 $344 $450 $6 $— $1,699 
2023645 372 306 461 20 — 1,804 
______________
(a)Other primarily includes Exelon’s corporate operations, shared service entities, and other financing and investment activities.
(b)Includes gross utility tax receipts from customers. The offsetting remittance of utility taxes to the governing bodies is recorded in Taxes other than income taxes in the Registrants’ Consolidated Statements of Operations and Comprehensive Income. See Note 14 — Supplemental Financial Information for additional information on total utility taxes.
(c)See Note 15 — Related Party Transactions for additional information on intersegment revenues.




PHI:
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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)

Note 4 — Segment Information
PepcoDPLACE
Other(a)
Intersegment
Eliminations		PHI
Operating revenues(b):
2024
Electric revenues$700 $362 $383 $— $(4)$1,441 
Natural gas revenues— 28 — — — 28 
Shared service and other revenues— — — 115 (113)2 
Total operating revenues$700 $390 $383 $115 $(117)$1,471 
2023
Electric revenues$642 $320 $317 $— $(5)$1,274 
Natural gas revenues— 29 — — — 29 
Shared service and other revenues— — — 105 (103)2 
Total operating revenues$642 $349 $317 $105 $(108)$1,305 
Intersegment revenues(c):
2024$2 $1 $1 $115 $(117)$2 
20232 2 1 104 (107)2 
Depreciation and amortization:
2024$98 $61 $72 $4 $— $235 
2023109 60 68 6 — 243 
Operating expenses:
2024$534 $332 $338 $117 $(117)$1,204 
2023541 305 280 108 (108)1,126 
Interest expense, net:
2024$46 $24 $20 $2 $— $92 
202343 18 17 3 — 81 
Income Taxes:
2024$28 $8 $8 $2 $— $46 
202310 5 6 (1)— 20 
Net income (loss):
2024$108 $34 $21 $(5)$— $158 
202364 25 18 (5)1 103 
Capital Expenditures:
2024$225 $134 $91 $— $— $450 
2023219 124 114 4 — 461 
__________
(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)Includes intersegment revenues with ComEd, PECO, and BGE, which are eliminated at Exelon.











Electric and Gas Revenue by Customer Class (Utility Registrants):
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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)

Note 4 — Segment Information
The following tables disaggregate the Registrants' revenues recognized from contracts with customers into categories that depict how the nature, amount, timing, and uncertainty of revenue and cash flows are affected by economic factors. For the Utility Registrants, the disaggregation of revenues reflects the two primary utility services of electric sales and natural gas sales (where applicable), with further disaggregation of these tariff sales provided by major customer groups. Exelon’s disaggregated revenues are consistent with the Utility Registrants, but exclude any intercompany revenues.
Three Months Ended June 30, 2024
Revenues from contracts with customersComEdPECOBGEPHIPepcoDPLACE
Electric revenues
Residential$982 $522 $464 $746 $315 $202 $229 
Small commercial & industrial560 128 88 158 43 60 55 
Large commercial & industrial269 61 139 329 251 31 47 
Public authorities & electric railroads14 7 8 16 7 4 5 
Other(a)
298 75 101 205 75 64 68 
Total electric revenues(b)
$2,123 $793 $800 $1,454 $691 $361 $404 
Natural gas revenues
Residential$— $63 $89 $15 $— $15 $— 
Small commercial & industrial— 25 17 7 — 7 — 
Large commercial & industrial— — 40 1 — 1 — 
Transportation— 5 — 4 — 4 — 
Other(c)
— — 4 1 — 1 — 
Total natural gas revenues(d)
$— $93 $150 $28 $— $28 $— 
Total revenues from contracts with customers$2,123 $886 $950 $1,482 $691 $389 $404 
Other revenues
Revenues from alternative revenue programs$(43)$— $(23)$(14)$7 $— $(21)
Other electric revenues(e)
(1)4 1 3 2 1 — 
Other natural gas revenues(e)
— 1 — — — — — 
Total other revenues$(44)$5 $(22)$(11)$9 $1 $(21)
Total revenues for reportable segments$2,079 $891 $928 $1,471 $700 $390 $383 
63


COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)

Note 4 — Segment Information
Three Months Ended June 30, 2023
Revenues from contracts with customersComEdPECOBGEPHIPepcoDPLACE
Electric revenues
Residential$861 $444 $363 $583 $267 $161 $155 
Small commercial & industrial461 132 75 144 41 57 46 
Large commercial & industrial205 64 119 337 254 33 50 
Public authorities & electric railroads13 8 7 15 7 4 4 
Other(a)
234 71 103 185 64 61 63 
Total electric revenues(b)
$1,774 $719 $667 $1,264 $633 $316 $318 
Natural gas revenues
Residential$— $69 $71 $16 $— $16 $— 
Small commercial & industrial— 32 15 7 — 7 — 
Large commercial & industrial— — 30 1 — 1 — 
Transportation— 5 — 4 — 4 — 
Other(c)
— 2 5 1 — 1 — 
Total natural gas revenues(d)
$— $108 $121 $29 $— $29 $— 
Total revenues from contracts with customers$1,774 $827 $788 $1,293 $633 $345 $318 
Other revenues
Revenues from alternative revenue programs$118 $(5)$4 $9 $7 $3 $(1)
Other electric revenues(e)
9 5 4 3 2 1 — 
Other natural gas revenues(e)
— 1 1 — — — — 
Total other revenues$127 $1 $9 $12 $9 $4 $(1)
Total revenues for reportable segments$1,901 $828 $797 $1,305 $642 $349 $317 
__________
(a)Includes revenues from transmission revenue from PJM, wholesale electric revenue and mutual assistance revenue.
(b)Includes operating revenues from affiliates in 2024 and 2023 respectively of:
•$2 million, $2 million at ComEd
•$2 million, $1 million at PECO
•$2 million, $1 million at BGE
•$2 million, $2 million at PHI
•$2 million, $2 million at Pepco
•$1 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 2024 and 2023 respectively of:
•less than $1 million, $1 million at PECO
•less than $1 million, $1 million at BGE
(e)Includes late payment charge revenues.













64


COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)

Note 4 — Segment Information
Six Months Ended June 30, 2024 and 2023

ComEdPECOBGEPHI
Other(a)
Intersegment
Eliminations		Exelon
Operating revenues(b):
2024
Electric revenues$4,174 $1,577 $1,664 $2,973 $— $(11)$10,377 
Natural gas revenues— 368 561 100 — (3)1,026 
Shared service and other revenues— — — 4 928 (932)— 
Total operating revenues$4,174 $1,945 $2,225 $3,077 $928 $(946)$11,403 
2023
Electric revenues$3,568 $1,514 $1,485 $2,711 $— $(14)$9,264 
Natural gas revenues— 426 568 126 — (4)1,116 
Shared service and other revenues— — — 4 871 (875)— 
Total operating revenues$3,568 $1,940 $2,053 $2,841 $871 $(893)$10,380 
Intersegment revenues(c):
2024$4 $4 $5 $4 $924 $(941)$— 
20235 4 4 4 867 (884)— 
Depreciation and amortization:
2024$737 $210 $312 $481 $33 $— $1,773 
2023688 197 325 484 31 2 1,727 
Operating expenses:
2024$3,462 $1,603 $1,802 $2,539 $943 $(963)$9,386 
20232,734 1,590 1,667 2,423 1,046 (889)8,571 
Interest expense, net:
2024$246 $112 $103 $183 $308 $(2)$950 
2023237 97 88 157 263 (2)840 
Income taxes:
2024$49 $13 $28 $86 $(67)$— $109 
2023142 5 65 54 (60)— 206 
Net income (loss):
2024$463 $239 $308 $326 $(230)$— $1,106 
2023489 263 241 258 (235)(4)1,012 
Capital expenditures:
2024$1,111 $743 $668 $903 $41 $— $3,466 
20231,262 707 656 1,022 38 — 3,685 
Total assets:
June 30, 2024$44,248 $16,354 $14,945 $27,501 $6,077 $(4,012)$105,113 
December 31, 202342,827 15,595 14,184 26,903 6,374 (4,337)101,546 
__________
(a)Other primarily includes Exelon’s corporate operations, shared service entities, and other financing and investment activities.
(b)Includes gross utility tax receipts from customers. The offsetting remittance of utility taxes to the governing bodies is recorded in Taxes other than income taxes in the Registrants’ Consolidated Statements of Operations and Comprehensive Income. See Note 14 — Supplemental Financial Information for additional information on total utility taxes.
(c)See Note 15 — Related Party Transactions for additional information on intersegment revenues.



65


COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)

Note 4 — Segment Information
PHI:
PepcoDPLACE
Other(a)
Intersegment
Eliminations		PHI
Operating revenues(b):
2024
Electric revenues$1,459 $780 $740 $— $(6)$2,973 
Natural gas revenues— 100 — — — 100 
Shared service and other revenues— — — 224 (220)4 
Total operating revenues$1,459 $880 $740 $224 $(226)$3,077 
2023
Electric revenues$1,351 $697 $670 $— $(7)$2,711 
Natural gas revenues— 126 — — — 126 
Shared service and other revenues— — — 207 (203)4 
Total operating revenues$1,351 $823 $670 $207 $(210)$2,841 
Intersegment revenues(c):
2024$3 $3 $1 $224 $(227)$4 
20233 3 1 206 (209)4 
Depreciation and amortization:
2024$205 $122 $146 $8 $— $481 
2023216 121 135 12 — 484 
Operating expenses:
2024$1,174 $723 $641 $228 $(227)$2,539 
20231,151 693 577 212 (210)2,423 
Interest expense, net:
2024$92 $46 $39 $6 $— $183 
202381 36 34 6 — 157 
Income taxes:
2024$42 $25 $18 $1 $— $86 
202322 17 17 (2)— 54 
Net income (loss):
2024$183 $101 $50 $(8)$— $326 
2023130 85 51 (8)— 258 
Capital expenditures:
2024$454 $268 $180 $1 $— $903 
2023483 258 275 6 — 1,022 
Total assets:
June 30, 2024$11,542 $6,277 $5,327 $4,764 $(409)$27,501 
December 31, 202311,194 5,966 5,157 4,627 (41)26,903 
__________
(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)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
66


COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)

Note 4 — Segment Information
sales provided by major customer groups. Exelon’s disaggregated revenues are consistent with the Utility Registrants, but exclude any intercompany revenues.
Six Months Ended June 30, 2024
Revenues from contracts with customersComEdPECOBGEPHIPepcoDPLACE
Electric revenues
Residential$1,900 $1,042 $999 $1,521 $659 $458 $404 
Small commercial & industrial1,154 254 178 316 89 122 105 
Large commercial & industrial589 118 271 669 513 60 96 
Public authorities & electric railroads32 14 15 36 18 8 10 
Other(a)
523 147 194 396 138 126 134 
Total electric revenues(b)
$4,198 $1,575 $1,657 $2,938 $1,417 $774 $749 
Natural gas revenues
Residential$— $256 $360 $61 $— $61 $— 
Small commercial & industrial— 89 65 24 — 24 — 
Large commercial & industrial— — 112 3 — 3 — 
Transportation— 13 — 9 — 9 — 
Other(c)
— 9 8 3 — 3 — 
Total natural gas revenues(d)
$— $367 $545 $100 $— $100 $— 
Total revenues from contracts with customers$4,198 $1,942 $2,202 $3,038 $1,417 $874 $749 
Other revenues
Revenues from alternative revenue programs$(24)$(2)$19 $32 $37 $4 $(9)
Other electric revenues(e)
— 4 3 7 5 2 — 
Other natural gas revenues(e)
— 1 1 — — — — 
Total other revenues$(24)$3 $23 $39 $42 $6 $(9)
Total revenues for reportable segments$4,174 $1,945 $2,225 $3,077 $1,459 $880 $740 
67


COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)

Note 4 — Segment Information
Six Months Ended June 30, 2023
Revenues from contracts with customersComEdPECOBGEPHIPepcoDPLACE
Electric revenues
Residential$1,698 $963 $796 $1,221 $549 $371 $301 
Small commercial & industrial823 267 167 304 80 119 105 
Large commercial & industrial290 129 268 714 535 66 113 
Public authorities & electric railroads22 16 14 33 16 8 9 
Other(a)
450 139 198 362 120 119 126 
Total electric revenues(b)
$3,283 $1,514 $1,443 $2,634 $1,300 $683 $654 
Natural gas revenues
Residential$— $292 $349 $76 $— $76 $— 
Small commercial & industrial— 107 56 33 — 33 — 
Large commercial & industrial— 1 100 2 — 2 — 
Transportation— 13 — 8 — 8 — 
Other(c)
— 11 24 7 — 7 — 
Total natural gas revenues(d)
$— $424 $529 $126 $— $126 $— 
Total revenues from contracts with customers$3,283 $1,938 $1,972 $2,760 $1,300 $809 $654 
Other revenues
Revenues from alternative revenue programs$270 $(10)$70 $74 $46 $12 $16 
Other electric revenues(e)
15 10 8 7 5 2 — 
Other natural gas revenues(e)
— 2 3 — — — — 
Total other revenues$285 $2 $81 $81 $51 $14 $16 
Total revenues for reportable segments$3,568 $1,940 $2,053 $2,841 $1,351 $823 $670 
__________
(a)Includes revenues from transmission revenue from PJM, wholesale electric revenue and mutual assistance revenue.
(b)Includes operating revenues from affiliates in 2024 and 2023 respectively of:
•$4 million, $5 million at ComEd
•$3 million, $3 million at PECO
•$4 million, $2 million at BGE
•$4 million, $4 million at PHI
•$3 million, $3 million at Pepco
•$3 million, $3 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 2024 and 2023 respectively of:
•$1 million, $1 million at PECO
•$1 million, $2 million at BGE
(e)Includes late payment charge revenues.

68


COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)

Note 5 — Accounts Receivable
5. Accounts Receivable (All Registrants)
Allowance for Credit Losses on Accounts Receivable
The following tables present the rollforward of Allowance for Credit Losses on Customer Accounts Receivable.
Three Months Ended June 30, 2024
ExelonComEdPECOBGEPHIPepcoDPLACE
Balance at March 31, 2024$346 $82 $107 $52 $105 $52 $17 $36 
Plus: Current period provision (benefit) for expected credit losses(a)(b)(c)
55 38 11 (1)7 5 1 1 
Less: Write-offs, net of recoveries(d)
29 8 6 6 9 4 2 3 
Balance at June 30, 2024$372 $112 $112 $45 $103 $53 $16 $34 
Three Months Ended June 30, 2023
ExelonComEdPECOBGEPHIPepcoDPLACE
Balance at March 31, 2023$389 $74 $130 $73 $112 $49 $26 $37 
Plus: Current period (benefit) provision for expected credit losses
(35)(1)(20)(16)2 4 (3)1 
Less: Write-offs, net of recoveries
31 6 9 7 9 3 2 4 
Balance at June 30, 2023$323 $67 $101 $50 $105 $50 $21 $34 
Six Months Ended June 30, 2024
ExelonComEdPECOBGEPHIPepcoDPLACE
Balance at December 31, 2023$317 $69 $95 $46 $107 $52 $19 $36 
Plus: Current period provision for expected credit losses(a)(e)
135 60 34 14 27 18 4 5 
Less: Write-offs(f)(g), net of recoveries(d)
80 17 17 15 31 17 7 7 
Balance at June 30, 2024$372 $112 $112 $45 $103 $53 $16 $34 
Six Months Ended June 30, 2023
ExelonComEdPECOBGEPHIPepcoDPLACE
Balance at December 31, 2022$327 $59 $105 $54 $109 $47 $21 $41 
Plus: Current period provision for expected credit losses
71 21 18 14 18 13 4 1 
Less: Write-offs, net of recoveries
75 13 22 18 22 10 4 8 
Balance at June 30, 2023$323 $67 $101 $50 $105 $50 $21 $34 
_________
(a)For PECO and ComEd, the increase is primarily a result of increased aging of receivables.
(b)For BGE, the increase is primarily a result of changes in customer risk profile.
(c)For DPL, the increase is primarily a result of increased receivable balances.
(d)Recoveries were not material to the Registrants.
(e)For Pepco and ACE, the increase is primarily a result of increased receivable balances.
(f)For PECO, the decrease is primarily a result of decreased disconnection activities.
(g)For Pepco and DPL, the increase is primarily attributable to unfavorable customer payment behavior.

69


COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)

Note 5 — Accounts Receivable
The following tables present the rollforward of Allowance for Credit Losses on Other Accounts Receivable.
Three Months Ended June 30, 2024
ExelonComEdPECOBGEPHIPepcoDPLACE
Balance at March 31, 2024$96 $19 $13 $7 $57 $35 $8 $14 
Plus: Current period provision (benefit) for expected credit losses(a)(b)
16 11 9 (1)(3)(1)(1)(1)
Less: Write-offs, net of recoveries(c)
4 1 2 1 — — — — 
Balance at June 30, 2024$108 $29 $20 $5 $54 $34 $7 $13 
Three Months Ended June 30, 2023
ExelonComEdPECOBGEPHIPepcoDPLACE
Balance at March 31, 2023$91 $18 $11 $12 $50 $28 $8 $14 
Plus: Current period provision (benefit) for expected credit losses
1 1 (2)(2)4 3 1 — 
Less: Write-offs, net of recoveries
5 1 1 2 1 — — 1 
Balance at June 30, 2023$87 $18 $8 $8 $53 $31 $9 $13 
Six Months Ended June 30, 2024
ExelonComEdPECOBGEPHIPepcoDPLACE
Balance at December 31, 2023$82 $17 $8 $7 $50 $28 $8 $14 
Plus: Current period provision (benefit) for expected credit losses(a)
36 14 15 1 6 6 (1)1 
Less: Write-offs, net of recoveries(c)
10 2 3 3 2 — — 2 
Balance at June 30, 2024$108 $29 $20 $5 $54 $34 $7 $13 
Six Months Ended June 30, 2023
ExelonComEdPECOBGEPHIPepcoDPLACE
Balance at December 31, 2022$82 $17 $9 $10 $46 $25 $7 $14 
Plus: Current period provision for expected credit losses
15 3 1 2 9 6 2 1 
Less: Write-offs, net of recoveries
10 2 2 4 2 — — 2 
Balance at June 30, 2023$87 $18 $8 $8 $53 $31 $9 $13 
_________
(a)For PECO and ComEd, the increase is primarily a result of increased aging of receivables.
(b)For Pepco, the decrease is primarily a result of decreased receivable balances.
(c)Recoveries were not material to the Registrants.












70


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 at June 30, 2024 and December 31, 2023.
Unbilled customer revenues(a)
ExelonComEdPECOBGEPHIPepcoDPLACE
June 30, 2024$1,059 $425 $204 $179 $251 $110 $50 $91 
December 31, 2023991 351 185 208 247 109 64 74 
__________
(a)Unbilled customer revenues are classified in Customer accounts receivable, net in the Registrants' Consolidated Balance Sheets.
Other Purchases of Customer and Other Accounts Receivables
For the six months ended June 30, 2024 and 2023 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
Six months ended June 30, 2024$1,961 $450 $527 $393 $591 $375 $115 $101 
Six months ended June 30, 20231,979 445 546 420 568 371 107 90 
71


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 June 30, 2024(a)
Exelon
ComEd(b)
PECO(c)
BGE(b)
PHIPepcoDPLACE
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
5.0 7.8 (1.3)6.4 6.6 6.1 6.2 7.6 
Plant basis differences(3.9)(0.8)(13.0)(1.8)(0.9)(1.5)(0.9)0.2 
Excess deferred tax amortization(13.2)(17.4)(2.3)(17.5)(3.8)(4.8)(6.6)(1.6)
Amortization of investment tax credit, including deferred taxes on basis difference(0.1)(0.1)— — (0.1)— (0.1)(0.1)
Tax credits(0.5)(0.5)— (0.5)(0.4)(0.4)(0.3)(0.2)
Other1.0 0.3 (1.2)0.7 0.1 0.2 (0.3)0.7 
Effective income tax rate9.3 %10.3 %3.2 %8.3 %22.5 %20.6 %19.0 %27.6 %
Three Months Ended June 30, 2023(a)
Exelon
ComEd
PECO(c)
BGE
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
6.5 7.8 (1.2)6.8 6.2 5.6 6.3 7.1 
Plant basis differences(4.8)(0.6)(15.8)0.1 (1.6)(2.6)(1.1)— 
Excess deferred tax amortization(7.4)(5.6)(2.4)(5.3)(8.0)(9.9)(9.9)(2.0)
Amortization of investment tax credit, including deferred taxes on basis difference(0.1)(0.1)— (0.1)(0.1)— (0.1)(0.1)
Tax credits(0.5)(0.3)— (0.4)(0.9)(1.1)(0.4)(0.3)
Other
2.8 — 0.4 0.1 (0.3)0.5 0.9 (0.7)
Effective income tax rate17.5 %22.2 %2.0 %22.2 %16.3 %13.5 %16.7 %25.0 %
__________
(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. 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.
(c)For PECO, the lower effective tax rate is primarily related to plant basis differences attributable to tax repair deductions.


72


COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)

Note 6 — Income Taxes
Six Months Ended June 30, 2024(a)
Exelon
ComEd(b)
PECO(c)
BGE(b)
PHIPepcoDPLACE
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
5.8 7.8 (0.9)6.3 6.5 6.1 6.2 7.4 
Plant basis differences(3.9)(0.8)(12.5)(1.3)(0.9)(1.4)(1.0)0.1 
Excess deferred tax amortization(14.1)(18.0)(2.3)(17.5)(5.3)(6.8)(5.8)(1.5)
Amortization of investment tax credit, including deferred taxes on basis difference(0.1)(0.1)— — (0.1)— (0.1)(0.1)
Tax credits(0.5)(0.5)— (0.4)(0.4)(0.4)(0.3)(0.3)
Other0.8 0.2 (0.1)0.2 0.1 0.2 (0.2)(0.1)
Effective income tax rate9.0 %9.6 %5.2 %8.3 %20.9 %18.7 %19.8 %26.5 %
Six Months Ended June 30, 2023(a)
Exelon
ComEd
PECO(c)
BGE
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
6.2 7.8 (1.3)6.4 6.1 5.5 6.3 6.9 
Plant basis differences(4.3)(0.4)(15.4)(0.6)(1.7)(2.6)(1.0)(0.6)
Excess deferred tax amortization(6.7)(5.6)(2.4)(5.4)(7.4)(9.1)(9.2)(2.0)
Amortization of investment tax credit, including deferred taxes on basis difference(0.1)(0.1)— (0.1)(0.1)— (0.1)(0.1)
Tax credits(0.5)(0.3)— (0.4)(0.6)(0.8)(0.4)(0.3)
Other
1.3 0.1 — 0.3 — 0.5 0.1 0.1 
Effective income tax rate16.9 %22.5 %1.9 %21.2 %17.3 %14.5 %16.7 %25.0 %
__________
(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. 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.
(c)For PECO, the lower effective tax rate is primarily related to plant basis differences attributable to tax repair deductions.
Unrecognized Tax Benefits
Exelon, PHI and ACE have the following unrecognized tax benefits at June 30, 2024 and December 31, 2023. ComEd's, PECO's, BGE's, Pepco's, and DPL's amounts are not material.
Exelon(a)
PHIACE
June 30, 2024$95 $51 $15 
December 31, 202394 51 15 
__________
(a)At June 30, 2024 and December 31, 2023, 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
73


COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)

Note 6 — Income Taxes
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.
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.
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 provides that Exelon will reimburse Constellation when those allocated tax credit carryforwards are utilized. As of June 30, 2024, Exelon recorded a payable of $137 million and $193 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. Exelon is continuing to assess the financial statement impacts of the IRA and will update estimates based on future guidance issued by the U.S. Treasury.
Allocation of Income Taxes to Regulated Utilities
In Q2 2024, the IRS issued a series of private letter rulings (PLR), 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 any payments received for the utilization of losses by other affiliates under a tax sharing agreement.
For the Registrants, the impact of 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 that reduce rate base for ratemaking purposes.
A PLR issued to another taxpayer may not be relied on as precedent. However, Management is analyzing this guidance and plans to work collaboratively with Exelon's regulatory commissions to address potential impacts. The Registrants will record the impact, if any, after either obtaining approval from their regulatory commissions or upon receiving their own PLRs from the IRS.
7. Retirement Benefits (All Registrants)
Defined Benefit Pension and OPEB
74


COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)

Note 7 — Retirement Benefits
The majority of the 2024 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 5.19%. The majority of the 2024 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 5.17%.
During the first quarter of 2024, Exelon received an updated valuation of its pension and OPEB to reflect actual census data as of January 1, 2024. This valuation resulted in an increase to the pension obligation of $98 million and a decrease to the OPEB obligation of $1 million. Additionally, AOCI increased by $25 million (after-tax) and regulatory assets and liabilities increased by $66 million and $2 million, respectively.
A portion of the net periodic benefit cost for all plans is capitalized within the Consolidated Balance Sheets. The following tables present the components of Exelon's net periodic benefit costs, prior to capitalization, for the three and six months ended June 30, 2024 and 2023.
Pension BenefitsOPEB
Three Months Ended June 30,Three Months Ended June 30,
2024202320242023
Components of net periodic benefit cost
Service cost$40 $38 $7 $6 
Interest cost141 144 24 26 
Expected return on assets(184)(188)(21)(21)
Amortization of:
Prior service credit— — (2)(3)
Actuarial loss (gain)54 43 — (1)
Net periodic benefit cost$51 $37 $8 $7 
Pension BenefitsOPEB
Six Months Ended June 30,Six Months Ended June 30,
2024202320242023
Components of net periodic benefit cost
Service cost$82 $77 $14 $12 
Interest cost282 289 48 51 
Expected return on assets(368)(377)(42)(42)
Amortization of:
Prior service cost (credit)1 1 (4)(5)
Actuarial loss (gain)107 84 — (1)
Net periodic benefit cost$104 $74 $16 $15 
The amounts below represent the Registrants' allocated pension and OPEB costs. For Exelon, the service cost component is included in Operating and maintenance expense and Property, plant, and equipment, net while the non-service cost components are included in Other, net and Regulatory assets. For 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.
75


COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)

Note 7 — Retirement Benefits
 Three Months Ended June 30,Six Months Ended June 30,
Pension and OPEB Costs (Benefit)2024202320242023
Exelon$59 $44 $120 $89 
ComEd19 7 36 13 
PECO— (4)— (7)
BGE16 14 31 28 
PHI23 25 46 49 
Pepco7 9 16 17 
DPL3 5 7 9 
ACE4 3 7 7 
Defined Contribution Savings Plan
The Registrants participate in a 401(k) defined contribution savings plan that is sponsored by Exelon. The plan is qualified under applicable sections of the IRC and allows employees to contribute a portion of their pre-tax and/or after-tax income in accordance with specified guidelines. All Registrants match a percentage of the employee contributions up to certain limits. The following table presents the employer contributions and employer matching contributions to the savings plan for the three and six months ended June 30, 2024 and 2023.
Three Months Ended June 30,Six Months Ended June 30,
Savings Plan Employer Contributions2024202320242023
Exelon$29 $26 $51 $47 
ComEd10 10 20 19 
PECO5 4 8 7 
BGE3 3 6 5 
PHI6 5 8 8 
Pepco1 1 2 2 
DPL1 1 2 2 
ACE1 1 1 1 
8. Derivative Financial Instruments (All Registrants)
The Registrants use derivative instruments to manage commodity price risk and interest rate risk related to ongoing business operations. The Registrants do not execute derivatives for speculative or proprietary trading purposes.
Authoritative guidance requires that derivative instruments be recognized as either assets or liabilities at fair value, with changes in fair value of the derivative recognized in earnings immediately. Other accounting treatments are available through special election and designation, provided they meet specific, restrictive criteria both at the time of designation and on an ongoing basis. These alternative permissible accounting treatments include NPNS, cash flow hedges, and fair value hedges. At ComEd, derivative economic hedges related to commodities are recorded at fair value and offset by a corresponding regulatory asset or liability. At Exelon, derivative economic hedges related to interest rates are recorded at fair value and offsets are recorded to Electric operating revenues or Interest expense based on the activity the transaction is economically hedging. 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.
ComEd’s use of cash collateral is generally unrestricted unless ComEd is downgraded below investment grade. Cash collateral held by 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.
76


COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)

Note 8 — Derivative Financial Instruments
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 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 2023 Form 10-K for additional information.
(b)The fair value of the DPL economic hedge is not material at June 30, 2024 and December 31, 2023.
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 and Other 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. In addition, Exelon Corporate utilized interest rate swaps to manage interest rate exposure and manage potential fluctuations in Electric operating revenues at the corporate level in consolidation. These interest rate swaps are accounted for as economic hedges. A hypothetical 50 basis point change in the interest rates associated with Exelon's interest rate swaps as of June 30, 2024 would result in an immaterial impact to Exelon's Consolidated Net Income.
77


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 June 30, 2024 and December 31, 2023.
June 30, 2024
Derivatives Designated
as Hedging Instruments		Economic HedgesTotal
Other deferred debits (noncurrent assets)$4 $— $4 
Total derivative assets4 — 4 
Mark-to-market derivative liabilities (noncurrent liabilities)(5)— (5)
Total mark-to-market derivative liabilities(5)— (5)
Total mark-to-market derivative net liabilities$(1)$— $(1)
December 31, 2023
Derivatives Designated
as Hedging Instruments		Economic HedgesTotal
Other current assets$11 $1 $12 
Total derivative assets11 1 12 
Mark-to-market derivative liabilities (current liabilities)(24)(22)(46)
Total mark-to-market derivative liabilities(24)(22)(46)
Total mark-to-market derivative net liabilities$(13)$(21)$(34)
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 2024, Exelon terminated the previously issued floating-to-fixed swaps with a total notional of $1.3 billion upon issuance of $1.7 billion of debt. See Note 9 – Debt and Credit Agreements for additional information on the debt issuance. Prior to the termination, the 2024 year-to-date AOCI derivative gain was $33 million (net of tax). The settlements resulted in a cash receipt of $30 million. The accumulated AOCI gain of $23 million (net of tax) is being amortized into Interest expense in Exelon's Consolidated Statement of Operations and Comprehensive Income over the 5-year and 10-year terms of the swaps. During the second quarter of 2024, Exelon Corporate entered into $252 million notional of 5-year maturity floating-to-fixed swaps and $253 million notional of 10-year maturity floating-to-fixed swaps, for a total notional of $505 million designated as cash flow hedges. The following table provides the notional amounts outstanding held by Exelon at June 30, 2024 and December 31, 2023.
June 30, 2024December 31, 2023
5-year maturity floating-to-fixed swaps$397 $655 
10-year maturity floating-to-fixed swaps398 655 
Total$795 $1,310 
The related AOCI derivative gains for the three and six months ended June 30, 2024 and 2023 were immaterial, respectively. See Note 13 – Changes in Accumulated Other Comprehensive Income (Loss) for additional information.
Economic Hedges (Interest Rate and Other Risk)
Exelon Corporate executes derivative instruments to mitigate exposure to fluctuations in interest rates but for which the fair value or cash flow hedge elections were not made. For derivatives intended to serve as economic hedges, fair value is recorded on the balance sheet and changes in fair value each period are recognized in earnings or as a regulatory asset or liability, if regulatory requirements are met, each period.
78


COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)

Note 8 — Derivative Financial Instruments
Exelon Corporate entered into floating-to-fixed interest rate cap swaps to manage a portion of interest rate exposure in connection with existing borrowings. As of December 31, 2023, Exelon held $1,000 million notional of floating-to-fixed interest rate cap swaps, which matured in March 2024. Exelon received payments on the interest rate cap when the floating rate exceeded the fixed rate. Settlements received were immaterial.
Additionally, to manage potential fluctuations in Electric operating revenues related to ComEd's distribution formula rate, Exelon Corporate entered into a total $4,875 million of notional of 30-year constant maturity treasury interest rate (Corporate 30-year treasury) swaps from 2022 through 2023. The Corporate 30-year treasury swaps matured on December 31, 2023 and Exelon recorded a Mark-to-market liability of $22 million for the final settlement amount, which was paid in January 2024.
Exelon Corporate recognized the following net pre-tax mark-to-market (losses) which are also recognized in Net fair value changes related to derivatives in Exelon's Consolidated Statements of Cash Flows.
Six Months Ended June 30, 2024Six Months Ended June 30, 2023
Income Statement LocationGain (Loss)Gain (Loss)
Electric operating revenues$— $(6)
Interest expense— 2 
Total$— $(4)
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 June 30, 2024 due to stable energy prices. 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 June 30, 2024 and December 31, 2023:
June 30, 2024December 31, 2023
Exelon$161 $148 
ComEd158 146 
PECO(a)
— — 
BGE1 1 
PHI3 1 
Pepco1 1 
DPL(b)
— — 
ACE2 — 
__________
(a)PECO had less than one million in cash collateral held with external parties at June 30, 2024 and December 31, 2023.
(b)DPL had less than one million in cash collateral held with external parties at June 30, 2024 and December 31, 2023
The Utility Registrants’ electric supply procurement contracts do not contain provisions that would require them to post collateral. PECO’s, BGE’s, and DPL’s natural gas procurement contracts contain provisions that could require PECO, BGE, and DPL to post collateral in the form of cash or credit support, which vary by contract and counterparty, with thresholds contingent upon PECO’s, BGE's, and DPL’s credit rating. As of June 30, 2024, PECO, BGE, and DPL were not required to post collateral for any of these agreements. If PECO, BGE, or DPL lost their investment grade credit rating as of June 30, 2024, they could have been required to post collateral to their counterparties of $27 million, $43 million, and $10 million, respectively.
79


COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)

Note 9 — Debt and Credit Agreements
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 June 30, 2024 and December 31, 2023.
Outstanding Commercial
Paper at		Average Interest Rate on
Commercial Paper Borrowings at
Commercial Paper IssuerJune 30, 2024December 31, 2023June 30, 2024December 31, 2023
Exelon(a)
$954 $1,624 5.51 %5.58 %
ComEd$78 $202 5.41 %5.53 %
PECO$260 $165 5.43 %5.57 %
BGE$— $336 — %5.59 %
PHI(b)
$— $394 — %5.60 %
Pepco$— $132 — %5.59 %
DPL$— $63 — %5.60 %
ACE$— $199 — %5.60 %
__________
(a)Exelon Corporate had $616 million and $527 million in outstanding commercial paper borrowings at June 30, 2024 and December 31, 2023, respectively.
(b)Represents the consolidated amounts of Pepco, DPL, and ACE.
Revolving Credit Agreements
Exelon Corporate and the Utility Registrants each have a 5-year revolving credit facility. The following table reflects the credit agreements:
BorrowerAggregate Bank CommitmentInterest Rate
Exelon Corporate$900 SOFR plus 1.275 %
ComEd$1,000 SOFR plus 1.000 %
PECO$600 SOFR plus 0.900 %
BGE$600 SOFR plus 0.900 %
Pepco$300 SOFR plus 1.075 %
DPL$300 SOFR plus 1.000 %
ACE$300 SOFR plus 1.000 %
Exelon Corporate and the Utility Registrants had no outstanding amounts on the revolving credit facilities as of June 30, 2024.
The Utility Registrants have credit facility agreements, arranged at minority and community banks, which are solely 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 4, 2024.
80


COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)

Note 9 — Debt and Credit Agreements
See Note 16 — Debt and Credit Agreements of the 2023 Form 10-K for additional information on the Registrants' credit facilities.
Short-Term Loan Agreements
On March 23, 2017, Exelon Corporate entered into a term loan agreement for $500 million. The loan agreement was renewed in the first quarter of 2024 and was bifurcated into two tranches of $350 million and $150 million on March 14, 2024. The agreements will expire on March 14, 2025. Pursuant to the loan agreements, loans made thereunder bear interest at a variable rate equal to SOFR plus 1.05% and all indebtedness thereunder is unsecured. The loan agreement is reflected in Exelon's Consolidated Balance Sheets within Short-term borrowings.
On May 9, 2023, ComEd entered into a 364-day term loan agreement for $400 million with a variable rate equal to SOFR plus 1.00% and an expiration date of May 7, 2024. On May 1, 2024, ComEd entered into an agreement to extend the loan through the expiration date of June 28, 2024. The original proceeds from the loan were used to repay outstanding commercial paper obligations and for general corporate purposes. The balance of the loan was repaid on May 16, 2024. Refer to the Issuance of Long-term Debt Table below for further information.

81


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 six months ended June 30, 2024, the following long-term debt was issued:
CompanyTypeInterest RateMaturityAmountUse of Proceeds
ExelonNotes5.15%March 15, 2029$650Repay Exelon SMBC Term Loan, outstanding commercial paper, and for general corporate purposes.
ExelonNotes5.45%March 15, 2034$650Repay Exelon SMBC Term Loan, outstanding commercial paper, and for general corporate purposes.
ExelonNotes5.60%March 15, 2053$400Repay Exelon SMBC Term Loan, outstanding commercial paper, and for general corporate purposes.
ComEdFirst Mortgage Bonds5.30%June 1, 2034$400Repay existing indebtedness, repay outstanding commercial paper obligations, and to fund other general corporate purposes.
ComEdFirst Mortgage Bonds5.65%June 1, 2054$400Repay existing indebtedness, repay outstanding commercial paper obligations, and to fund other general corporate purposes.
BGENotes5.30%June 1, 2034$400Repay outstanding commercial paper obligations and for general corporate purposes
BGENotes5.65%June 1, 2054$400Repay outstanding commercial paper obligations and for general corporate purposes
PepcoFirst Mortgage Bonds5.20%March 15, 2034$375Refinance existing indebtedness, refinance outstanding commercial paper obligations, and for general corporate purposes.
PepcoFirst Mortgage Bonds5.50%March 15, 2054$300Refinance existing indebtedness, refinance outstanding commercial paper obligations, and for general corporate purposes.
DPLFirst Mortgage Bonds5.24%March 20, 2034$100Repay existing indebtedness and for general corporate purposes.
DPLFirst Mortgage Bonds5.55%March 20, 2054$75Repay existing indebtedness and for general corporate purposes.
ACE(a)
First Mortgage Bonds5.55%March 20, 2054$75Repay existing indebtedness and for general corporate purposes.
__________
(a)On March 20, 2024, ACE entered into a purchase agreement of First Mortgage Bonds of $75 million and $100 million at 5.29% and 5.49% due on August 28, 2034 and August 28, 2039, respectively. The closing date of the issuance is expected to occur in August 2024.
Debt Covenants
As of June 30, 2024, the Registrants are in compliance with debt covenants.
82


COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)

Note 10 — Fair Value of Financial Assets and Liabilities
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 2023 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 June 30, 2024 and December 31, 2023. The Registrants have no financial liabilities measured using the NAV practical expedient.
The carrying amounts of the Registrants’ short-term liabilities as presented in their Consolidated Balance Sheets are representative of their fair value (Level 2) because of the short-term nature of these instruments.
June 30, 2024December 31, 2023
Carrying AmountFair ValueCarrying AmountFair Value
Level 1Level 2Level 3TotalLevel 1Level 2Level 3Total
Long-Term Debt, including amounts due within one year(a)
Exelon$44,347 $— $35,380 $3,559 $38,939 $41,095 $— $33,804 $3,442 $37,246 
ComEd12,276 — 10,530 — 10,530 11,486 — 10,210 — 10,210 
PECO5,135 — 4,289 — 4,289 5,134 — 4,562 — 4,562 
BGE5,394 — 4,693 — 4,693 4,602 — 4,145 — 4,145 
PHI9,148 — 4,288 3,559 7,847 8,648 — 4,160 3,442 7,602 
Pepco4,362 — 2,489 1,545 4,034 4,096 — 2,311 1,600 3,911 
DPL2,254 — 661 1,257 1,918 2,080 — 694 1,134 1,828 
ACE1,909 — 929 757 1,686 1,833 — 939 708 1,647 
Long-Term Debt to Financing Trusts
Exelon$390 $— $— $390 $390 $390 $— $— $390 $390 
ComEd206 — — 203 203 205 — — 208 208 
PECO184 — — 187 187 184 — — 182 182 
__________
(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 2023 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 2023 Form 10-K for finance lease liabilities.

83


COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)

Note 10 — Fair Value of Financial Assets and Liabilities
Recurring Fair Value Measurements
The following tables present assets and liabilities measured and recorded at fair value in the Registrants' Consolidated Balance Sheets on a recurring basis and their level within the fair value hierarchy at June 30, 2024 and December 31, 2023. Exelon and the Utility Registrants have immaterial and no financial assets or liabilities measured using the NAV practical expedient, respectively:
Exelon
At June 30, 2024At December 31, 2023
Level 1Level 2Level 3TotalLevel 1 Level 2Level 3Total
Assets
Cash equivalents(a)
$1,226 $— $— $1,226 $618 $— $— $618 
Rabbi trust investments
Cash equivalents90 — — 90 67 — — 67 
Mutual funds59 — — 59 53 — — 53 
Fixed income— 7 — 7 — 7 — 7 
Life insurance contracts — 67 23 90 — 61 43 104 
Rabbi trust investments subtotal149 74 23 246 120 68 43 231 
Interest rate derivative assets
Derivatives designated as hedging instruments— 4 — 4 — 11 — 11 
Economic hedges— — — — — 1 — 1 
Interest rate derivative assets subtotal— 4 — 4 — 12 — 12 
Total assets1,375 78 23 1,476 738 80 43 861 
Liabilities
Commodity derivative liabilities— — (139)(139)— — (133)(133)
Interest rate derivative liabilities
Derivatives designated as hedging instruments— (5)— (5)— (24)— (24)
Economic hedges— — — — — (22)— (22)
Interest rate derivative liabilities subtotal — (5)— (5)— (46)— (46)
Deferred compensation obligation— (69)— (69)— (75)— (75)
Total liabilities— (74)(139)(213)— (121)(133)(254)
Total net assets (liabilities)$1,375 $4 $(116)$1,263 $738 $(41)$(90)$607 
__________    
(a)Exelon excludes cash of $151 million and $334 million at June 30, 2024 and December 31, 2023, respectively, and restricted cash of $158 million and $149 million at June 30, 2024 and December 31, 2023, respectively, and includes long-term restricted cash of $71 million and $174 million at June 30, 2024 and December 31, 2023, respectively, which is reported in Other deferred debits and other assets in the Consolidated Balance Sheets.

84


COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)

Note 10 — Fair Value of Financial Assets and Liabilities
ComEd, PECO, and BGE
ComEdPECOBGE
At June 30, 2024Level 1Level 2Level 3TotalLevel 1Level 2Level 3TotalLevel 1Level 2Level 3Total
Assets
Cash equivalents(a)
$634 $— $— $634 $11 $— $— $11 $418 $— $— $418 
Rabbi trust investments
Mutual funds— — — — 10 — — 10 9 — — 9 
Life insurance contracts — — — — — 19 — 19 — — — — 
Rabbi trust investments subtotal— — — — 10 19 — 29 9 — — 9 
Total assets634 — — 634 21 19 — 40 427 — — 427 
Liabilities
Commodity derivative liabilities(b)
— — (139)(139)— — — — — — — — 
Deferred compensation obligation— (8)— (8)— (7)— (7)— (4)— (4)
Total liabilities— (8)(139)(147)— (7)— (7)— (4)— (4)
Total net assets (liabilities)$634 $(8)$(139)$487 $21 $12 $— $33 $427 $(4)$— $423 
ComEdPECOBGE
At December 31, 2023Level 1Level 2Level 3TotalLevel 1Level 2Level 3TotalLevel 1Level 2Level 3Total
Assets
Cash equivalents(a)
$453 $— $— $453 $9 $— $— $9 $— $— $— $— 
Rabbi trust investments
Mutual funds— — — — 9 — — 9 9 — — 9 
Life insurance contracts — — — — — 18 — 18 — — — — 
Rabbi trust investments subtotal— — — — 9 18 — 27 9 — — 9 
Total assets453 — — 453 18 18 — 36 9 — — 9 
Liabilities
Commodity derivative liabilities(b)
— — (133)(133)— — — — — — — — 
Deferred compensation obligation— (8)— (8)— (8)— (8)— (4)— (4)
Total liabilities— (8)(133)(141)— (8)— (8)— (4)— (4)
Total net assets (liabilities)$453 $(8)$(133)$312 $18 $10 $— $28 $9 $(4)$— $5 
__________
(a)ComEd excludes cash of $51 million and $86 million at June 30, 2024 and December 31, 2023, respectively, and restricted cash of $158 million and $147 million at June 30, 2024 and December 31, 2023, respectively. Additionally, ComEd includes long-term restricted cash of $71 million and $174 million at June 30, 2024 and December 31, 2023, respectively, which is reported in Other deferred debits and other assets in the Consolidated Balance Sheets. PECO excludes cash of $17 million and $42 million at June 30, 2024 and December 31, 2023, respectively. BGE excludes cash
85


COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)

Note 10 — Fair Value of Financial Assets and Liabilities
of $10 million and $47 million at June 30, 2024 and December 31, 2023, respectively, and restricted cash of zero and $1 million at June 30, 2024 and December 31, 2023, respectively.
(b)The Level 3 balance consists of the current and noncurrent liability of $23 million and $116 million, respectively, at June 30, 2024 and $27 million and $106 million, respectively, at December 31, 2023 related to floating-to-fixed energy swap contracts with unaffiliated suppliers.

86


COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)

Note 10 — Fair Value of Financial Assets and Liabilities
PHI, Pepco, DPL, and ACE
At June 30, 2024At December 31, 2023
PHI Level 1Level 2Level 3TotalLevel 1Level 2Level 3Total
Assets
Cash equivalents(a)
$97 $— $— $97 $107 $— $— $107 
Rabbi trust investments
Cash equivalents87 — — 87 64 — — 64 
Mutual funds10 — — 10 9 — — 9 
Fixed income— 7 — 7 — 7 — 7 
Life insurance contracts— 22 22 44 — 21 41 62 
Rabbi trust investments subtotal97 29 22 148 73 28 41 142 
Total assets194 29 22 245 180 28 41 249 
Liabilities
Deferred compensation obligation— (11)— (11)— (13)— (13)
Total liabilities— (11)— (11)— (13)— (13)
Total net assets$194 $18 $22 $234 $180 $15 $41 $236 
PepcoDPLACE
At June 30, 2024Level 1Level 2Level 3TotalLevel 1Level 2Level 3TotalLevel 1Level 2Level 3Total
Assets
Cash equivalents(a)
$21 $— $— $21 $45 $— $— $45 $— $— $— $— 
Rabbi trust investments
Cash equivalents87 — — 87 — — — — — — — — 
Life insurance contracts— 22 22 44 — — — — — — — — 
Rabbi trust investments subtotal87 22 22 131 — — — — — — — — 
Total assets108 22 22 152 45 — — 45 — — — — 
Liabilities
Deferred compensation obligation— (1)— (1)— — — — — — — — 
Total liabilities— (1)— (1)— — — — — — — — 
Total net assets$108 $21 $22 $151 $45 $— $— $45 $— $— $— $— 
87


COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)

Note 10 — Fair Value of Financial Assets and Liabilities
PepcoDPLACE
At December 31, 2023Level 1Level 2Level 3TotalLevel 1Level 2Level 3TotalLevel 1Level 2Level 3Total
Assets
Cash equivalents(a)
$23 $— $— $23 $1 $— $— $1 $— $— $— $— 
Rabbi trust investments
Cash equivalents63 — — 63 — — — — — — — — 
Life insurance contracts— 21 41 62 — — — — — — — — 
Rabbi trust investments subtotal63 21 41 125 — — — — — — — — 
Total assets86 21 41 148 1 — — 1 — — — — 
Liabilities
Deferred compensation obligation— (1)— (1)— — — — — — — — 
Total liabilities— (1)— (1)— — — — — — — — 
Total net assets$86 $20 $41 $147 $1 $— $— $1 $— $— $— $— 
__________
(a)PHI excludes cash of $44 million and $96 million at June 30, 2024 and December 31, 2023, respectively, and restricted cash of zero and $1 million at June 30, 2024 and December 31, 2023, respectively. Pepco excludes cash of $19 million and $48 million at June 30, 2024 and December 31, 2023, respectively, and restricted cash of zero and $1 million at June 30, 2024 and December 31, 2023, respectively. DPL excludes cash of $6 million and $15 million at June 30, 2024 and December 31, 2023, respectively. ACE excludes cash of $15 million and $21 million at June 30, 2024 and December 31, 2023, respectively.

Reconciliation of Level 3 Assets and Liabilities
The following tables present the fair value reconciliation of Level 3 assets and liabilities measured at fair value on a recurring basis during the three and six months ended June 30, 2024 and 2023:
ExelonComEdPHI and Pepco
Three Months Ended June 30, 2024Total Commodity
Derivatives		Life Insurance Contracts
Balance at March 31, 2024$(65)$(108)$41 
Total realized / unrealized gains (losses)
Included in net income(a)
1 — 2 
Included in regulatory assets/liabilities(31)(31)
(b)
— 
Purchases, sales, and settlements
Settlements(21)— (21)
Balance at June 30, 2024$(116)$(139)
(c)
$22 
The amount of total gains included in income attributed to the change in unrealized gains related to assets and liabilities at June 30, 2024$2 $— $2 
88


COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)

Note 10 — Fair Value of Financial Assets and Liabilities
ExelonComEdPHI and Pepco
Three Months Ended June 30, 2023Total Commodity
Derivatives		Life Insurance Contracts
Balance at March 31, 2023$(57)$(98)$41 
Total realized / unrealized gains (losses)
Included in net income(a)
1 — 1 
Included in regulatory assets/liabilities(35)(35)
(b)
— 
Balance at June 30, 2023$(91)$(133)$42 
The amount of total gains included in income attributed to the change in unrealized gains related to assets and liabilities at June 30, 2023$1 $— $1 
ExelonComEdPHI and Pepco
Six Months Ended June 30, 2024Total Commodity
Derivatives		Life Insurance Contracts
Balance at December 31, 2023$(90)$(133)$41 
Total realized / unrealized gains (losses)
Included in net income(a)
1 — 2 
Included in regulatory assets/liabilities(6)(6)
(b)
— 
Purchases, sales, and settlements
Settlements(21)— (21)
Balance at June 30, 2024$(116)$(139)
(c)
$22 
The amount of total gains included in income attributed to the change in unrealized gains related to assets and liabilities at June 30, 2024$2 $— $2 

ExelonComEdPHI and Pepco
Six Months Ended June 30, 2023Total Commodity
Derivatives		Life Insurance Contracts
Balance at December 31, 2022$(44)$(84)$40 
Total realized / unrealized gains (losses)
Included in net income(a)
2 — 2 
Included in regulatory assets/liabilities(49)(49)
(b)
— 
Balance at June 30, 2023$(91)$(133)$42 
The amount of total gains included in income attributed to the change in unrealized gain related to assets and liabilities at June 30, 2023$2 $— $2 
__________
(a)Classified in Operating and maintenance expense in the Consolidated Statements of Operations and Comprehensive Income.
(b)Includes $43 million of decreases in fair value and an increase for realized gains due to settlements of $12 million recorded in Purchased power expense associated with floating-to-fixed energy swap contracts with unaffiliated suppliers for the three months ended June 30, 2024. Includes $43 million of decreases in fair value and an increase for realized gains due to settlements of $8 million recorded in Purchased power expense associated with floating-to-fixed energy swap contracts with unaffiliated suppliers for the three months ended June 30, 2023. Includes $30 million of decreases in fair value and an increase for realized gains due to settlements of $24 million recorded in Purchased power expense associated with floating-to-fixed energy swap contracts with unaffiliated suppliers for the six months ended June 30, 2024. Includes $68 million of decreases in fair value and an increase for realized losses due to settlements of $19 million recorded in Purchased power expense associated with floating-to-fixed energy swap contracts with unaffiliated suppliers for the six months ended June 30, 2023.
(c)The balance of the current and noncurrent asset was effectively zero as of June 30, 2024. The balance consists of a current and noncurrent liability of $23 million and $116 million, respectively, as of June 30, 2024.
89


COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)

Note 10 — Fair Value of Financial Assets and Liabilities
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 June 30, 2024Fair Value at December 31, 2023Valuation
Technique		Unobservable
Input		2024 Range & Arithmetic Average2023 Range & Arithmetic Average
Commodity derivatives$(139)$(133)Discounted
Cash Flow
Forward power price(a)
$22.68-$58.69$40.49$30.27-$73.71$43.35
________
(a)An increase to the forward power price would increase the fair value.

11. Commitments and Contingencies (All Registrants)
The following is an update to the current status of commitments and contingencies set forth in Note 18 — Commitments and Contingencies of the 2023 Form 10-K.
Commitments
PHI Merger Commitments (Exelon, PHI, Pepco, DPL, and ACE). Approval of the PHI Merger in Delaware, New Jersey, Maryland, and the District of Columbia was conditioned upon Exelon and PHI agreeing to certain commitments. The following amounts represent total commitment costs that have been recorded since the acquisition date and the total remaining obligations for Exelon, PHI, Pepco, DPL, and ACE at June 30, 2024:
DescriptionExelon PHI Pepco DPLACE
Total commitments$513 $320 $120 $89 $111 
Remaining commitments(a)
31 28 25 2 1 
__________
(a)Remaining commitments extend through 2026 and include escrow funds, charitable contributions, and rate credits.

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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (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 June 30, 2024, representing commitments potentially triggered by future events were as follows:
Expiration within
Total202420252026202720282029 and beyond
Exelon
Letters of credit(a)
$30 $17 $13 $— $— $— $— 
Surety bonds(b)
194 160 32 — 2 — — 
Financing trust guarantees(c)
378 — — — — 78 300 
Guaranteed lease residual values(d)
26 — 3 5 4 6 8 
Total commercial commitments $628 $177 $48 $5 $6 $84 $308 
ComEd
Letters of credit(a)
$17 $9 $8 $— $— $— $— 
Surety bonds(b)
36 29 5 — 2 — — 
Financing trust guarantees(c)
200 — — — — — 200 
Total commercial commitments $253 $38 $13 $— $2 $— $200 
PECO
Letters of credit(a)
$2 $— $2 $— $— $— $— 
Surety bonds(b)
2 1 1 — — — — 
Financing trust guarantees(c)
178 — — — — 78 100 
Total commercial commitments $182 $1 $3 $— $— $78 $100 
BGE
Letters of credit(a)
$8 $6 $2 $— $— $— $— 
Surety bonds(b)
3 1 2 — — — — 
Total commercial commitments $11 $7 $4 $— $— $— $— 
PHI
Surety bonds(b)
$96 $77 $19 $— $— $— $— 
Guaranteed lease residual values(d)
26 — 3 5 4 6 8 
Total commercial commitments $122 $77 $22 $5 $4 $6 $8 
Pepco
Surety bonds(a)
$85 $71 $14 $— $— $— $— 
Guaranteed lease residual values(d)
9 — 1 2 1 2 3 
Total commercial commitments $94 $71 $15 $2 $1 $2 $3 
DPL
Surety bonds(b)
$6 $3 $3 $— $— $— $— 
Guaranteed lease residual values(d)
10 — 1 2 2 2 3 
Total commercial commitments $16 $3 $4 $2 $2 $2 $3 
ACE
Surety bonds(b)
$5 $3 $2 $— $— $— $— 
Guaranteed lease residual values(d)
7 — 1 1 1 2 2 
Total commercial commitments $12 $3 $3 $1 $1 $2 $2 
__________
(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.
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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)

Note 11 — Commitments and Contingencies
(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 $59 million guaranteed by Exelon and PHI, of which $20 million, $23 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 that are 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 that are 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 2025.
•BGE has 4 sites that currently require some level of remediation and/or ongoing activity. BGE expects the majority of the remediation at these sites to continue through at least 2025.
•DPL has 1 site that is 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 completion of any significant clean up, each site remediation plan is approved by the appropriate state environmental agency.
ComEd, pursuant to an ICC order, and PECO, pursuant to a PAPUC order, are currently recovering environmental remediation costs of former MGP facility sites through customer rates. While BGE and DPL do not have riders for MGP clean-up costs, they have historically received recovery of actual clean-up costs in distribution rates.
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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)

Note 11 — Commitments and Contingencies
At June 30, 2024 and December 31, 2023, the Registrants had accrued the following undiscounted amounts for environmental liabilities in Accrued expenses, Other current liabilities, and Other deferred credits and other liabilities in their respective Consolidated Balance Sheets:
June 30, 2024December 31, 2023
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$406 $319 $428 $338 
ComEd284 283 303 302 
PECO27 25 27 25 
BGE14 11 14 11 
PHI75 — 81 — 
Pepco74 — 79 — 
DPL1 — 1 — 
ACE— — 1 — 
Benning Road Site (Exelon, PHI, and Pepco). In September 2010, PHI received a letter from the EPA identifying the Benning Road site as one of six land-based sites potentially contributing to contamination of the lower Anacostia River. A portion of the site, which is owned by Pepco, was formerly the location of an electric generating facility owned by Pepco subsidiary, Pepco Energy Services (PES), which became a part of 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. The Pepco Entities are completing a FS to evaluate possible remedial alternatives for submission to the DOEE. 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 15, 2024, and the waterside FS is scheduled to be complete and approved by the DOEE by the end of the fourth quarter of 2024. Following the completion of each FS, the DOEE will issue a Proposed Plan for public comment and then issue a Record of Decision (ROD) identifying the remedial actions determined to be necessary for the area in question. 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.
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.
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
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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)

Note 11 — Commitments and Contingencies
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 will be paid in four equal annual installments beginning a year after the effective date of the Anacostia River Consent Decree. The funds will be 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 potentially responsible parties. 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 very early stage of the NRD process, Pepco cannot reasonably estimate the final range of loss potentially resulting from this process.
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 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 penalty payments and for the projected costs for the required environmental assessments and remediation. Pepco has concluded that incremental exposure is reasonably possible, but the range of loss cannot be reasonably estimated beyond the amounts included in the table above.
94


COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)

Note 11 — Commitments and Contingencies
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. On October 22, 2019, the SEC notified Exelon and ComEd that it had also opened an investigation into their lobbying activities. On July 17, 2020, ComEd entered into a DPA with the USAO to resolve the USAO investigation, 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.
On September 28, 2023, Exelon and ComEd reached a settlement with the SEC, concluding and resolving in its entirety the SEC investigation, which related to the conduct identified in the DPA that was entered into by ComEd in July 2020 and successfully exited in July 2023. Under the terms of the settlement, Exelon has agreed to pay a civil penalty of $46.2 million and Exelon and ComEd have agreed to cease and desist from committing or causing any violations and any future violations of specified provisions of the federal securities laws and rules promulgated thereunder. Exelon recorded an accrual for the full amount of the penalty in the second quarter of 2023, which was reflected in Operating and maintenance expense within Exelon's Consolidated Statements of Operations and Comprehensive Income and in Accrued expenses on the Consolidated Balance Sheets. Exelon paid the civil penalty in full on October 4, 2023.
Subsequent to Exelon announcing the receipt of the USAO subpoenas, various lawsuits were filed, and various demand letters were received related to the subject of the subpoenas, the conduct described in the DPA and the SEC's investigation, including:
•Four putative class action lawsuits against ComEd and Exelon were filed in federal court on behalf of ComEd customers in the third quarter of 2020 alleging, among other things, civil violations of federal racketeering laws. The court granted ComEd and Exelon's motion to dismiss these actions in 2021 and that dismissal was affirmed on appeal in 2022. Plaintiffs have no further appeal rights and therefore the dismissal is final.
•Three putative class action lawsuits against ComEd and Exelon were filed in Illinois state court in the third quarter of 2020 seeking restitution and compensatory damages on behalf of ComEd customers. The cases were consolidated into a single action in October of 2020. ComEd and Exelon filed a motion to dismiss on January 11, 2021. On December 23, 2021, the state court granted ComEd and Exelon's motion to dismiss with prejudice. Plaintiffs appealed the court's ruling dismissing their complaint to the First District Court of Appeals. On February 15, 2022, ComEd and Exelon moved to dismiss the federal plaintiffs' refiled state law claims, seeking dismissal on the same legal grounds asserted in their motion to dismiss the original state court plaintiffs' complaint. The court granted dismissal of the refiled state claims on February 16, 2022. The original federal plaintiffs appealed that dismissal on February 18, 2022. The two state appeals were consolidated on March 21, 2022. On September 8, 2023, the appellate court affirmed the dismissal. On December 22, 2023, plaintiffs filed a petition for leave to appeal to the Illinois Supreme Court, which ComEd and Exelon responded to on January 12, 2024. On March 27, 2024, the Illinois Supreme Court denied plaintiffs' petition for leave to appeal. The dismissal of this action is final.
•On November 3, 2022, a plaintiff filed a putative class action complaint in Lake County, Illinois Circuit Court against ComEd and Exelon for unjust enrichment and deceptive business practices in connection with the conduct giving rise to the DPA. Plaintiff seeks an accounting and disgorgement of any benefits ComEd allegedly obtained from said conduct. ComEd and Exelon filed a motion to dismiss the Complaint on February 3, 2023. On June 16, 2023, the court granted ComEd and Exelon's motion to dismiss the action with prejudice. Plaintiff filed its notice of appeal of that dismissal on July 17, 2023. On April 12, 2024, the appellate court issued its decision affirming dismissal of the action. On June 3, 2024, plaintiff filed a petition for leave to appeal the dismissal to the Illinois Supreme Court, which is a discretionary appeal. ComEd and Exelon filed its response to that petition on July 19, 2024.
95


COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)

Note 11 — Commitments and Contingencies
•A putative class action lawsuit against Exelon and certain officers of Exelon and ComEd was filed in federal court in December 2019 alleging misrepresentations and omissions in Exelon’s SEC filings related to ComEd’s lobbying activities and the related investigations. The complaint was amended on September 16, 2020, to dismiss two of the original defendants and add other defendants, including ComEd. Defendants filed a motion to dismiss in November 2020. The court denied the motion in April 2021. Following mediation, the parties reached a settlement of the lawsuit, under which defendants agreed to pay plaintiffs $173 million. On May 26, 2023, plaintiffs filed a motion for preliminary approval of the settlement, which the court granted on June 9, 2023. The court granted final settlement approval on September 7, 2023. The settlement was fully covered by insurance and has been paid in full.    
•Several shareholders have sent letters to the Exelon Board of Directors since 2020 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 has been 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 contains 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. On June 30, 2023, the court granted the non-settling shareholders’ request for limited discovery into the settlement. Following that discovery, on October 26, 2023, the SLC filed its renewed motion for preliminary approval with supporting submissions filed by the Independent Review Committee, Exelon, and the settling shareholders on that same day. The parties briefing on preliminary approval was completed on January 18, 2024.
In August 2022, the ICC concluded its investigation initiated on August 12, 2021 into rate impacts of conduct admitted in the DPA, including the costs recovered from customers related to the DPA and Exelon's funding of the fine paid by ComEd. On August 17, 2022, the ICC issued its final order accepting ComEd's voluntary customer refund offer of approximately $38 million (of which about $31 million is ICC jurisdictional; the remaining balance is FERC jurisdictional) that resolves the question of whether customer funds were used for DPA related activities. The customer refund includes the cost of every individual or entity that was either (i) identified in the DPA or (ii) identified by ComEd as an associate of the former Speaker of the Illinois House of Representatives in the ICC proceeding. The ICC’s DPA investigation is now closed. The ICC jurisdictional refund was made to customers during the April 2023 billing cycle, as required by the ICC. The FERC jurisdictional refund was completed as of May 2024 as part of ComEd's transmission formula rate update proceeding, submitted on May 12, 2023. The customer refund was not recovered in rates or charged to customers and ComEd will not seek or accept reimbursement or indemnification from any source other than Exelon.
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,
96


COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)

Note 11 — Commitments and Contingencies
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 $1.0 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. In November and December 2023, Exelon issued approximately 3.6 million shares of Common stock at an average gross price of $39.58 per share. The net proceeds from these issuances were $140 million, which were used for general corporate purposes. As of June 30, 2024, $858 million of Common stock remained available for sale pursuant to the ATM program.
13. Changes in Accumulated Other Comprehensive Income (Loss) (Exelon)
The following table presents changes in Exelon's AOCI, net of tax, by component:
Three Months Ended June 30, 2024 Cash Flow Hedges
Pension and
Non-Pension
Postretirement
Benefit Plan
Items(a)
Total
Balance at March 31, 2024$30 $(742)$(712)
OCI before reclassifications(2)(2)(4)
Amounts reclassified from AOCI(1)5 4 
Net current-period OCI(3)3 — 
Balance at June 30, 2024$27 $(739)$(712)
Three Months Ended June 30, 2023 Cash Flow Hedges
Pension and
Non-Pension
Postretirement
Benefit Plan
Items(a)
Total
Balance at March 31, 2023$8 $(647)$(639)
OCI before reclassifications9 (3)6 
Amounts reclassified from AOCI— 3 3 
Net current-period OCI9 — 9 
Balance at June 30, 2023$17 $(647)$(630)

Six Months Ended June 30, 2024 Cash Flow Hedges
Pension and Non-Pension Postretirement Benefit Plan Items(a)
Total
Balance at December 31, 2023$(3)$(723)$(726)
OCI before reclassifications32 (26)6 
Amounts reclassified from AOCI(2)10 8 
Net current-period OCI30 (16)14 
Balance at June 30, 2024$27 $(739)$(712)

97


COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)

Note 13 — Changes in Accumulated Other Comprehensive Income
Six Months Ended June 30, 2023Cash Flow Hedges
Pension and Non-Pension Postretirement Benefit Plan Items(a)
Total
Balance at December 31, 2022$2 $(640)$(638)
OCI before reclassifications15 (13)2 
Amounts reclassified from AOCI— 6 6 
Net current-period OCI$15 $(7)$8 
Balance at June 30, 2023$17 $(647)$(630)
__________
(a)This AOCI component is included in the computation of net periodic pension and OPEB cost. See Note 14 — Retirement Benefits of the 2023 Form 10-K and Note 7 — Retirement Benefits for additional information. See Exelon's Statements of Operations and Comprehensive Income for individual components of AOCI.

The following table presents Income tax benefit (expense) allocated to each component of Exelon's Other comprehensive income (loss):
Three Months Ended June 30,Six Months Ended June 30,
2024202320242023
Pension and non-pension postretirement benefit plans:
Actuarial losses reclassified to periodic benefit cost$(2)$(1)$(4)$(2)
Pension and non-pension postretirement benefit plans valuation adjustments— 1 8 4 
Unrealized gains on cash flow hedges— (3)(10)(4)
14. Supplemental Financial Information (All Registrants)
Supplemental Statement of Operations Information
The following tables provide additional information about material items recorded in the Registrants' Consolidated Statements of Operations and Comprehensive Income:
98


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 June 30, 2024
Utility taxes(a)
$226 $73 $42 $31 $80 $72 $6 $— 
Property107 10 5 53 39 26 12 1 
Payroll33 9 4 5 7 2 1 1 
Three Months Ended June 30, 2023
Utility taxes(a)
$201 $71 $38 $22 $70 $63 $6 $1 
Property96 8 4 49 35 24 10 1 
Payroll31 7 4 5 7 2 1 1 
Six Months Ended June 30, 2024
Utility taxes(a)
$447 $148 $83 $54 $162 $146 $14 $2 
Property212 18 9 107 78 53 23 1 
Payroll67 18 9 9 14 4 2 2 
Six Months Ended June 30, 2023
Utility taxes(a)
$421 $146 $78 $50 $147 $131 $14 $2 
Property196 18 8 100 70 48 21 1 
Payroll63 14 9 9 14 4 2 2 
_________
(a)The Registrants' utility taxes represent municipal and state utility taxes and gross receipts taxes related to their operating revenues. The offsetting collection of utility taxes from customers is recorded in revenues in the Registrants’ Consolidated Statements of Operations and Comprehensive Income.
Other, net
ExelonComEdPECOBGE PHIPepcoDPLACE
Three Months Ended June 30, 2024
AFUDC — Equity$38 $9 $8 $6 $15 $12 $3 $— 
Non-service net periodic benefit cost(11)— — — — — — — 
Three Months Ended June 30, 2023
AFUDC — Equity$34 $7 $6 $4 $17 $13 $2 $2 
Non-service net periodic benefit cost(1)— — — — — — — 
Six Months Ended June 30, 2024
AFUDC — Equity$78 $19 $16 $13 $30 $23 $6 $1 
Non-service net periodic benefit cost(17)— — — — — — — 
Six Months Ended June 30, 2023
AFUDC — Equity$71 $17 $12 $7 $35 $27 $4 $4 
Non-service net periodic benefit cost(2)— — — — — — — 
Supplemental Cash Flow Information
The following tables provide additional information about material items recorded in the Registrants' Consolidated Statements of Cash Flows.
99


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
Six Months Ended June 30, 2024
Property, plant, and equipment(a)
$1,436 $573 $203 $247 $383 $164 $107 $105 
Amortization of regulatory assets and liabilities, net(a)
333 164 7 65 97 41 15 41 
Amortization of intangible assets, net(a)
4 — — — — — — — 
ARO accretion(b)
1 — — — 1 — — — 
Total depreciation, amortization and accretion$1,774 $737 $210 $312 $481 $205 $122 $146 
Six Months Ended June 30, 2023
Property, plant, and equipment(a)
$1,370 $540 $190 $249 $364 $152 $104 $96 
Amortization of regulatory assets and liabilities, net(a)
352 148 7 76 120 64 17 39 
Amortization of intangible assets, net(a)
4 — — — — — — — 
ARO accretion(b)
1 — — — — — — — 
Total depreciation and amortization$1,727 $688 $197 $325 $484 $216 $121 $135 
__________
(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
Six Months Ended June 30, 2024
Pension and OPEB costs$120 $36 $— $31 $46 $16 $7 $7 
Allowance for credit losses93 8 47 11 27 16 3 7 
True-up adjustments to decoupling mechanisms and formula rates(a)
(15)24 2 (19)(22)(37)4 11 
Amortization of operating ROU asset19 — — 3 13 3 3 2 
AFUDC — Equity(78)(19)(16)(13)(30)(23)(6)(1)
Six Months Ended June 30, 2023
Pension and OPEB costs (benefit)$89 $13 $(7)$28 $49 $17 $9 $7 
Allowance for credit losses46 1 19 4 22 13 3 6 
True-up adjustments to decoupling mechanisms and formula rates(a)
(410)(270)10 (70)(80)(46)(15)(19)
Long-term incentive plan13 — — — — — — — 
Amortization of operating ROU asset19 1 — 2 14 2 4 2 
Change in environmental liabilities37 — — — 37 37 — — 
AFUDC — Equity(71)(17)(12)(7)(35)(27)(4)(4)
__________
(a)For ComEd, reflects the true-up adjustments in Regulatory assets and liabilities associated with its 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
100


COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)

Note 14 — Supplemental Financial Information
Regulatory assets and liabilities associated with their decoupling mechanisms and transmission formula rates. See Note 3 — Regulatory Matters of the 2023 Form 10-K for additional information.
The following tables provide a reconciliation of cash, cash equivalents, and restricted cash reported within the Registrants’ Consolidated Balance Sheets that sum to the total of the same amounts in their Consolidated Statements of Cash Flows.
Cash, cash equivalents, and restricted cash
ExelonComEdPECOBGEPHIPepcoDPLACE
Balance at June 30, 2024
Cash and cash equivalents$934 $326 $19 $428 $119 $19 $50 $15 
Restricted cash and cash equivalents530 446 9 — 22 21 1 — 
Restricted cash included in Other deferred debits and other assets71 71 — — — — — — 
Total cash, restricted cash, and cash equivalents$1,535 $843 $28 $428 $141 $40 $51 $15 
Balance at December 31, 2023
Cash and cash equivalents$445 $110 $42 $47 $180 $48 $16 $21 
Restricted cash and cash equivalents482 402 9 1 24 24 — — 
Restricted cash included in Other deferred debits and other assets174 174 — — — — — — 
Total cash, restricted cash, and cash equivalents$1,101 $686 $51 $48 $204 $72 $16 $21 
Balance at June 30, 2023
Cash and cash equivalents$399 $74 $82 $89 $110 $16 $18 $24 
Restricted cash and cash equivalents435 361 9 1 26 26 — — 
Restricted cash included in Other deferred debits and other assets201 201 — — — — — — 
Total cash, restricted cash, and cash equivalents$1,035 $636 $91 $90 $136 $42 $18 $24 
Balance at December 31, 2022
Cash and cash equivalents$407 $67 $59 $43 $198 $45 $31 $72 
Restricted cash and cash equivalents566 327 9 24 175 54 121 — 
Restricted cash included in Other deferred debits and other assets117 117 — — — — — — 
Total cash, restricted cash, and cash equivalents$1,090 $511 $68 $67 $373 $99 $152 $72 
For additional information on restricted cash see Note 1 — Significant Accounting Policies of the 2023 Form 10-K.
Supplemental Balance Sheet Information
The following table provides additional information about material items recorded in the Registrants' Consolidated Balance Sheets.
101


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 June 30, 2024
Compensation-related accruals(a)
$476 $124 $72 $66 $92 $27 $18 $13 
Taxes accrued183 91 56 26 90 74 7 9 
Interest accrued469 153 50 48 85 47 17 17 
Balance at December 31, 2023
Compensation-related accruals(a)
$661 $206 $87 $81 $107 $27 $17 $12 
Taxes accrued221 204 96 75 137 116 30 10 
Interest accrued414 148 49 44 72 38 13 15 
__________
(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 June 30,Six Months Ended June 30,Three Months Ended June 30,Six Months Ended June 30,
20242023202420232024202320242023
Exelon
   BSC$159 $165 $317 $340 
   PHISCO29 25 58 49 
ComEd
   BSC$104 $88 $204 $171 63 78 134 159 
PECO
   BSC61 54 119 105 29 30 58 60 
BGE
   BSC62 54 121 108 25 22 49 46 
PHI
   BSC49 43 99 85 42 35 76 75 
   PHISCO— — — — 29 25 58 49 
Pepco
   BSC32 28 63 55 18 14 35 28 
   PHISCO33 30 66 60 12 10 24 21 
DPL
   BSC20 18 39 35 13 10 25 20 
   PHISCO26 25 51 49 8 8 17 15 
ACE
   BSC16 15 32 29 10 12 15 26 
   PHISCO25 22 48 44 9 7 17 13 
102


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:
June 30, 2024
Receivables from affiliates:
Payables to affiliates:ComEdPECOBGEPepcoDPLACEBSCPHISCOOtherTotal
ComEd$1 $— $— $— $— $67 $— $8 $76 
PECO$— — — — — 35 — 4 39 
BGE— — — — — 36 — 1 37 
PHI— — — — — — 7 1 10 18 
Pepco— — — — — 20 17 — 37 
DPL— — — — — 12 13 1 26 
ACE— — — — — 10 12 2 24 
Other4 — — — — 3 — — 7 
Total$4 $1 $— $— $— $3 $187 $43 $26 $264 
December 31, 2023
Receivables from affiliates:
Payables to affiliates:ComEdPECOBGEPepcoDPLACEBSCPHISCOOtherTotal
ComEd$— $— $— $— $— $64 $— $8 $72 
PECO$— — — — — 36 — 3 39 
BGE— — — — — 33 — 2 35 
PHI— — — — — — 5 — 10 15 
Pepco— — — — — 17 14 1 32 
DPL— 1 — — — 12 11 1 25 
ACE— 1 — 1 1 11 11 — 25 
Other3 — — 1 — 3 1 — 8 
Total$3 $2 $— $2 $1 $3 $179 $36 $25 $251 
Borrowings from Exelon/PHI intercompany money pool
To provide an additional short-term borrowing option that will generally be more favorable to the borrowing participants than the cost of external financing both Exelon and PHI operate an intercompany money pool. PECO and PHI Corporate participate in the Exelon intercompany money pool. Pepco, DPL, and ACE participate in the PHI intercompany money pool.
Long-term debt to financing trusts
The following table presents Long-term debt to financing trusts:
June 30, 2024December 31, 2023
ExelonComEdPECOExelonComEdPECO
ComEd Financing III$206 $206 $— $206 $205 $— 
PECO Trust III81 — 81 81 — 81 
PECO Trust IV103 — 103 103 — 103 
Total$390 $206 $184 $390 $205 $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 and six months ended June 30, 2024 compared to the same period in 2023. For additional information regarding the financial results for the three and six months ended June 30, 2024 and 2023, see the discussions of Results of Operations by Registrant.
Three Months Ended June 30,Favorable (Unfavorable) VarianceSix Months Ended June 30,Favorable (Unfavorable) Variance
2024202320242023
Exelon$448 $343 $105 $1,106 $1,012 $94 
ComEd270 249 21 463 489 (26)
PECO90 97 (7)239 263 (24)
BGE44 42 2 308 241 67 
PHI158 103 55 326 258 68 
Pepco108 64 44 183 130 53 
DPL34 25 9 101 85 16 
ACE21 18 3 50 51 (1)
Other(a)
(114)(148)34 (230)(239)9 
__________
(a)Other primarily includes eliminating and consolidating adjustments, Exelon’s corporate operations, shared service entities, and other financing and investment activities.
Three Months Ended June 30, 2024 Compared to Three Months Ended June 30, 2023. Net income attributable to common shareholders increased by $105 million and diluted earnings per average common share increased to $0.45 in 2024 from $0.34 in 2023 primarily due to:
•The favorable impacts of rate increases at BGE and PHI;
•Favorable weather at PECO;
•Favorable impacts of the multi-year plans including the recognition of the reconciliations at Pepco; and
•Higher transmission peak load due to higher energy demand at ComEd.
The increases were partially offset by:
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•Higher interest expense at PECO, BGE, and Exelon Corporate; and
•Higher depreciation expense at PECO and PHI.
Six Months Ended June 30, 2024 Compared to Six Months Ended June 30, 2023. Net income attributable to common shareholders increased by $94 million and diluted earnings per average common share increased to $1.10 in 2024 from $1.02 in 2023 primarily due to:
•The favorable impacts of rate increases at BGE and PHI;
•Favorable weather at PECO;
•Favorable impacts of the multi-year plans including the recognition of the reconciliations at Pepco; and
•Higher transmission peak load due to higher energy demand at ComEd.
The increases were partially offset by:
•Higher interest expense at PECO, BGE, PHI, and Exelon Corporate;
•Higher storm costs at PECO and BGE;
•Higher depreciation expense at PECO and PHI;
•Lower electric distribution earnings from lower ROE and the absence of a return on the pension asset at ComEd; and
•Lower carrying costs related to the CMC regulatory assets 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 that are considered by management to be not directly related to the ongoing operations of the business. In addition, this information is among the primary indicators management uses as a basis for evaluating performance, allocating resources, setting incentive compensation targets, and planning and forecasting of future periods. Adjusted (non-GAAP) operating earnings is not a presentation defined under GAAP and may not be comparable to other companies’ presentations or deemed more useful than the GAAP information provided elsewhere in this report.
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The following table provides a reconciliation between GAAP Net income attributable to common shareholders and Adjusted (non-GAAP) operating earnings for the three and six months ended June 30, 2024 compared to the same period in 2023:
Three Months Ended June 30,
20242023
(In millions, except per share data)Earnings per
Diluted Share		Earnings per
Diluted Share
Net income attributable to common shareholders$448 $0.45 $343 $0.34 
Mark-to-market impact of economic hedging activities (net of taxes of $1)
— — 3 — 
Change in environmental liabilities (net of taxes of $0 and $1, respectively)
(1)— 11 0.01 
SEC matter loss contingency (net of taxes of $0)
— — 46 0.05 
Change in FERC audit liability (net of taxes of $5)
15 0.01 — — 
Separation costs (net of taxes of $2)(a)
— — 5 0.01 
Cost management charge (net of taxes of $3)(b)
9 0.01 — — 
Adjusted (non-GAAP) operating earnings$472 $0.47 $408 $0.41 

Six Months Ended June 30,
20242023
(In millions, except per share data)Earnings per
Diluted Share		Earnings per
Diluted Share
Net income attributable to common shareholders$1,106 $1.10 $1,012 $1.02 
Mark-to-market impact of economic hedging activities (net of taxes of $0)
— — 2 — 
Change in environmental liabilities (net of taxes of $0 and $8, respectively)
(1)— 29 0.03 
SEC matter loss contingency (net of taxes of $0)
— — 46 0.05 
Change in FERC audit liability (net of taxes of $13 and $4, respectively)
42 0.04 11 0.01 
Separation costs (net of taxes of $1)(a)
— — 4 — 
Cost management charge (net of taxes of $3)(b)
9 0.01 — — 
Adjusted (non-GAAP) operating earnings$1,156 $1.16 $1,104 $1.11 
__________
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 2024 and 2023 ranged from 24.0% to 29.0%.

(a)Represents costs related to the separation primarily comprised of system-related costs, third-party costs paid to advisors, consultants, lawyers, and other experts assisting in the separation, and employee-related severance costs, which are recorded in Operating and maintenance expense and Other, net.
(b)Primarily represents severance and reorganization costs related to cost management.
Significant 2024 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.
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The following tables show the Utility Registrants’ completed and pending distribution base rate case proceedings in 2024. See Note 2 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.
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 $501 8.905%December 14, 2023January 1, 2024
$838 $810 8.905%April 18, 2024May 1, 2024
April 21, 2023Electric$247 $259 8.91%November 30, 2023January 1, 2024
BGE - MarylandFebruary 17, 2023Electric$313 $179 9.50 %December 14, 2023January 1, 2024
Natural Gas$289 $229 9.45 %
Pepco - MarylandOctober 26, 2020 (amended March 31, 2021)Electric$104 $52 9.55 %June 28, 2021June 28, 2021
May 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
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Pending Distribution Base Rate Case Proceedings
Registrant/JurisdictionFiling DateServiceRequested Revenue Requirement IncreaseRequested ROEExpected Approval Timing
ComEd - IllinoisMarch 15, 2024 (amended June 20, 2024)Electric$682 8.905%December 2024
April 26, 2024Electric$627 9.89%December 2024
PECO - PennsylvaniaMarch 28, 2024Electric$464 10.95%Fourth quarter of 2024
Natural Gas$111 11.15%
Pepco - District of ColumbiaApril 13, 2023 (amended February 27, 2024)Electric$186 10.50 %Fourth quarter of 2024
Transmission Formula Rates
For 2024, the following total increases/(decreases) were included in the Utility Registrant's electric transmission formula rate updates. See Note 2 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.
RegistrantInitial Revenue Requirement IncreaseAnnual Reconciliation (Decrease)
Increase		Total Revenue Requirement IncreaseAllowed Return on Rate BaseAllowed ROE
ComEd$32 $(12)$20 8.14 %11.50 %
PECO$2 $3 $5 7.45 %10.35 %
BGE$42 $13 $53 7.47 %10.50 %
Pepco$58 $15 $73 7.62 %10.50 %
DPL$7 $17 $24 7.23 %10.50 %
ACE$14 $18 $32 7.11 %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 extends back to January 1, 2017.
On July 27, 2023, FERC issued a final audit report which included, among other things, findings and recommendations related to ComEd's methodology regarding the allocation of certain overhead costs to capitalized construction costs under FERC regulations, including a suggestion that refunds may be due to customers for amounts collected in previous years. On August 28, 2023, ComEd filed a formal notice of the issues it will contest. 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 has been held in abeyance while a formal settlement process, which began in February 2024, takes 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 final settlement is subject to FERC approval. The existing estimates of loss have been updated and reflected in Exelon and ComEd financial statements as of June 30, 2024.
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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 2023 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 2023 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.
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. Federal agencies are developing guidelines to implement spending programs under IIJA. The time needed to develop these guidelines will vary with some limited program applications opened as early as the first quarter of 2022. 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.
In March 2023, Exelon, ComEd, and PHI submitted three applications related to the Smart Grid Grants program under section 40107 of IIJA. These applications are focused on replacing existing Advanced Distribution Management Systems (ADMS) in support of distributed energy resources (DERs) and grid-edged technologies, strengthening interoperability and data architecture of systems in support of two-way power flows and accelerating advanced metering deployment in disadvantaged communities. In October 2023, ComEd’s project, Deployment of a Community-Oriented Interoperable Control Framework for Aggregating and Integrating Distributed Energy Resources and Other Grid-Edge Devices, was recommended by the Grid Deployment Office (GDO) for negotiation of a final award up to $50 million. This project will enable ComEd and its local partners to deploy the next generation of grid technologies that support the growth of solar and electric vehicles (EVs), while piloting new local workforce training initiatives to support job creation connected to the clean energy transition. The award negotiation process is currently ongoing.
In April 2023, ComEd, PECO, BGE, and PHI submitted seven applications related to the Grid Resilience Grants program under section 40101(c) of IIJA. These applications are broadly focused on improving grid resilience with an emphasis on disadvantaged communities, relief of capacity constraints and modernizing infrastructure, deployment of DER and microgrid technologies and providing improved resilience through storm hardening projects. In October 2023, PECO’s project, Creating a Resilient, Equitable, and Accessible Transformation in Energy for Greater Philadelphia (CREATE), was recommended by the GDO for negotiation of a final award up to $100 million. This project will support critical electric infrastructure investments to help reduce the impact of extreme weather and historic flooding on the Registrants' electric distribution system. The award negotiation process is currently ongoing.
The Registrants are supporting three different Regional Clean Hydrogen Hub opportunities, covering all five states that Exelon operates in plus Washington D.C. under a program that will create networks of hydrogen producers, consumers, and local connective infrastructure to accelerate the use of hydrogen as a clean energy carrier that can deliver or store energy. Applications for the three opportunities under this program were submitted in April 2023. In October 2023 the DOE announced it selected two of the projects for further negotiation: (1) the Mid-Atlantic Clean Hydrogen Hub (MACH2), which is being supported by PECO and PHI, and (2) the Midwest Alliance for Clean Hydrogen (MachH2), which is being supported by ComEd.
In November 2023, the GDO announced up to $3.9 billion available through the second-round funding opportunity of the Grid Resilience and Innovation Partnerships (GRIP) Program for fiscal years 2024 and 2025. This funding opportunity focuses on projects that will improve electric transmission by increasing funding and advancing interconnection processes for faster build out of energy projects, create comprehensive solutions that link grid communications systems and operations to increase resilience and reduce power outages and threats,
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and deploy advanced technologies such as distributed energy resources and battery systems to provide essential grid services to ensure American communities across the country have access to affordable, reliable, clean electricity. In March 2024, Exelon, BGE, PHI, Pepco, DPL, and ACE submitted five application for Topic Area 2 (Smart Grid Grants). These applications focus on improving resilience of the electric grid and deployment of technologies to enhance grid flexibility and deliver benefits to customers across the Exelon footprint. In April 2024, ACE in coordination with the NJBPU Division of Clean Energy submitted an application for Topic Area 3 (Grid Innovation Program) to expand DER hosting capacity through integrated grid enhancing technologies. The GDO is expected to announce award notification in the second half of 2024. Exelon, BGE, PHI, Pepco, DPL, and ACE cannot predict if their applications will be selected for negotiation of a final award.
PJM Regional Transmission Expansion
On July 11, 2024, BGE submitted an application to the MDPSC for a Certificate of Public Convenience and Necessity for certain overhead transmission system upgrades necessitated due to the planned retirement of the Brandon Shores Generating Station. The total estimated costs of all work by BGE directed by PJM in connection with the retirement of the Brandon Shores Generating Station is approximately $1.1 billion.
Critical Accounting Policies and Estimates
Management of each of the Registrants makes a number of significant estimates, assumptions, and judgments in the preparation of its financial statements. As of June 30, 2024, the Registrants’ critical accounting policies and estimates had not changed significantly from December 31, 2023. See ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS — Critical Accounting Policies and Estimates in the 2023 Form 10-K for further information.
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Results of Operations by Registrant
Results of Operations — ComEd
Three Months Ended
June 30,		Favorable (Unfavorable) VarianceSix Months Ended
June 30,		Favorable (Unfavorable) Variance
2024202320242023
Operating revenues$2,079 $1,901 $178 $4,174 $3,568 $606 
Operating expenses
Purchased power763 685 (78)1,670 1,172 (498)
Operating and maintenance449 355 (94)867 692 (175)
Depreciation and amortization374 350 (24)737 688 (49)
Taxes other than income taxes94 88 (6)188 182 (6)
Total operating expenses1,680 1,478 (202)3,462 2,734 (728)
Gain on sales of assets5 — 5 5 — 5 
Operating income404 423 (19)717 834 (117)
Other income and (deductions)
Interest expense, net(123)(120)(3)(246)(237)(9)
Other, net20 17 3 41 34 7 
Total other income and (deductions)(103)(103)— (205)(203)(2)
Income before income taxes301 320 (19)512 631 (119)
Income taxes 31 71 40 49 142 93 
Net income $270 $249 $21 $463 $489 $(26)
Three Months Ended June 30, 2024 Compared to Three Months Ended June 30, 2023. Net income increased by $21 million as compared to the same period in 2023, primarily due to timing of distribution earnings, higher transmission peak loads, and higher rate base. These were partially offset by a lower allowed ROE and the absence of a return on the pension asset.
Six Months Ended June 30, 2024 Compared to Six Months Ended June 30, 2023. Net income decreased by $26 million as compared to the same period in 2023, primarily due to a lower allowed ROE and the absence of a return on the pension asset. These were partially offset by higher transmission peak loads and higher rate base.
The changes in Operating revenues consisted of the following:
Three Months Ended
June 30, 2024		Six Months Ended
June 30, 2024
IncreaseIncrease (Decrease)
Distribution$109 $143 
Transmission55 57 
Energy efficiency10 30 
Other3 (2)
177 228 
Regulatory required programs 1 378 
Total increase$178 $606 
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. Distribution revenues were under a performance-based formula rate through 2023. Starting in 2024, distribution revenues are under a MRP. Both the performance-based formula rate and the MRP require annual reconciliations of the revenue requirement in effect to the actual costs the ICC determines are prudently and reasonably incurred with certain limitations for the MRP reconciliations. Electric distribution
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ComEd
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 June 30, 2024 as compared to the same period in 2023, primarily due to differences in the timing of distribution earnings and higher rate base, partially offset by lower allowed ROE and the absence of a return on the pension asset. Electric distribution revenues increased for the six months ended June 30, 2024 as compared to the same period in 2023, primarily due to higher fully recoverable costs and higher rate base, partially offset by lower allowed ROE and the absence of a return on the pension asset.
Transmission Revenue. Under a FERC-approved formula, transmission revenue varies from year to year based upon fluctuations in the underlying costs, capital investments being recovered, and the highest daily peak load, which is updated annually in January based on the prior calendar year. Transmission revenues increased for the three months ended June 30, 2024 as compared to the same period in 2023, primarily due to the reclassification of the FERC audit liability, higher peak load, and and increases in underlying costs and capital investments. The favorable impacts due to the reclassification of the FERC audit liability are fully offset within Operating and maintenance expenses of the Consolidated Statements of Operations and Comprehensive Income. See Note 2 — Regulatory Matters for additional information regarding the FERC audit liability. Transmission revenues increased for the six months ended June 30, 2024 as compared to the same period in 2023, primarily due to higher peak load and increases in underlying costs and capital investments.
Energy Efficiency Revenue. Energy efficiency revenues are under a performance-based formula rate, which requires an annual reconciliation of the revenue requirement in effect to the actual costs the ICC determines are prudently and reasonably incurred in a given year. Energy efficiency revenue varies from year to year based upon fluctuations in the underlying costs, investments being recovered, and allowed ROE. Energy efficiency revenues increased for the three and six months ended June 30, 2024 as compared to the same periods in 2023, 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 June 30, 2024 and decreased for the six months ended June 30, 2024 as compared to the same periods in 2023, which primarily reflects increased and decreased mutual assistance revenues, respectively, 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. 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 increase in Purchased power expense of $78 million and $498 million for the three and six months ended June 30, 2024 compared to the same periods in 2023 is offset in Operating revenues as part of regulatory required programs.
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ComEd
The changes in Operating and maintenance expense consisted of the following:
Three Months Ended
June 30, 2024		Six Months Ended
June 30, 2024
Increase (Decrease)Increase (Decrease)
Labor, other benefits, contracting and materials(a)
$27 $72 
BSC costs16 33 
Storm-related costs(3)2 
Pension and non-pension postretirement benefits expense6 12 
Other(b)
80 84 
126 203 
Regulatory required programs(c)
(32)(28)
Total increase$94 $175 
__________
(a)Primarily reflects an updated rate of capitalization of certain overhead costs.
(b)Primarily reflects the reclassification and increase of the FERC audit liability during the current period and an increase in credit loss expense. See Note 2 — Regulatory Matters for additional information regarding the FERC audit liability.
(c)ComEd is allowed to recover from or refund to customers the difference between its annual credit loss expense and the amounts collected in rates annually through a rider mechanism.
The changes in Depreciation and amortization expense consisted of the following:
Three Months Ended
June 30, 2024		Six Months Ended
June 30, 2024
IncreaseIncrease
Depreciation and amortization(a)
$17 $34 
Regulatory asset amortization(b)
7 15 
Total increase$24 $49 
__________
(a)Reflects ongoing capital expenditures.
(b)Includes amortization of ComEd's energy efficiency formula rate regulatory asset.
Effective income tax rates were 10.3% and 22.2% for the three months ended June 30, 2024 and 2023, respectively, and 9.6% and 22.5% for the six months ended June 30, 2024 and 2023, respectively. See Note 6 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the effective income tax rates.
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PECO
Results of Operations — PECO
Three Months Ended
June 30,		Favorable (Unfavorable) VarianceSix Months Ended
June 30,		Favorable (Unfavorable) Variance
2024202320242023
Operating revenues$891 $828 $63 $1,945 $1,940 $5 
Operating expenses
Purchased power and fuel323 302 (21)727 786 59 
Operating and maintenance270 239 (31)563 510 (53)
Depreciation and amortization107 99 (8)210 197 (13)
Taxes other than income taxes52 47 (5)103 97 (6)
Total operating expenses752 687 (65)1,603 1,590 (13)
Gain on sales of assets 2 — 2 4 — 4 
Operating income141 141 (2)346 350 (4)
Other income and (deductions)
Interest expense, net(57)(48)(9)(112)(97)(15)
Other, net9 6 3 18 15 3 
Total other income and (deductions)(48)(42)(6)(94)(82)(12)
Income before income taxes93 99 (6)252 268 (16)
Income taxes3 2 (1)13 5 (8)
Net income$90 $97 $(7)$239 $263 $(24)
Three Months Ended June 30, 2024 Compared to Three Months Ended June 30, 2023. Net income decreased by $7 million, due to an increase in interest expense, depreciation expense, and credit loss expense, partially offset by an increase in revenue as a result of favorable weather.
Six Months Ended June 30, 2024 Compared to Six Months Ended June 30, 2023. Net income decreased by $24 million, due to an increase in storm costs, interest expense, depreciation expense, and credit loss expense, partially offset by an increase in revenue as a result of less unfavorable weather impact relative to the same period last year.
The changes in Operating revenues consisted of the following:
Three Months Ended
June 30, 2024		Six Months Ended
June 30, 2024
Increase (Decrease)Increase (Decrease)
ElectricGasTotalElectricGasTotal
Weather$45 $1 $46 $57 $13 $70 
Volume13 (2)11 9 (4)5 
Pricing(7)(3)(10)(4)— (4)
Transmission7 — 7 15 — 15 
Other(2)— (2)(6)(3)(9)
56 (4)52 71 6 77 
Regulatory required programs21 (10)11 (8)(64)(72)
Total increase$77 $(14)$63 $63 $(58)$5 
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 June 30, 2024 compared to the same period in 2023, Operating revenues related to weather increased due to favorable weather conditions in PECO's service territory. During the six months ended June 30, 2024 compared to the same period in 2023, Operating revenues related to weather increased due to less unfavorable weather conditions in PECO's service territory.
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PECO
Heating and cooling degree-days are quantitative indices that reflect the demand for energy needed to heat or cool a home or business. Normal weather is determined based on historical average heating and cooling degree-days for a 30-year period in PECO's service territory. The changes in heating and cooling degree-days in PECO’s service territory for the three and six months ended June 30, 2024 compared to the same period in 2023 and normal weather consisted of the following:
Three Months Ended June 30,% Change
PECO Service Territory20242023Normal2024 vs. 20232024 vs. Normal
Heating Degree-Days3513304216.4 %(16.6)%
Cooling Degree-Days537233391130.5 %37.3 %
Six Months Ended June 30,% Change
20242023Normal2024 vs. 20232024 vs. Normal
Heating Degree-Days2,440 2,2182,83110.0 %(13.8)%
Cooling Degree-Days537 233392130.5 %37.0 %
Volume. Electric volume, exclusive of the effects of weather, for the three and six months ended June 30, 2024 compared to the same period in 2023, remained relatively consistent. Natural gas volume for the three and six months ended June 30, 2024 compared to the same period in 2023, remained relatively consistent.
Electric Retail Deliveries to Customers (in GWhs)Three Months Ended
June 30,		% Change
Weather -
Normal
% Change(b)
Six Months Ended June 30,% Change
Weather -
Normal
% Change(b)
2024202320242023
Residential3,2962,69422.3 %3.8 %6,7516,05211.5 %1.0 %
Small commercial & industrial1,8561,7039.0 %3.5 %3,7473,5465.7 %0.8 %
Large commercial & industrial3,4083,3312.3 %(0.9)%6,7636,5683.0 %0.8 %
Public authorities & electric railroads135144(6.3)%(6.3)%3143120.6 %0.9 %
Total electric retail deliveries(a)
8,6957,87210.5 %1.7 %17,57516,4786.7 %0.9 %
At June 30,
Number of Electric Customers20242023
Residential1,533,9091,529,499
Small commercial & industrial156,036155,845
Large commercial & industrial3,1623,112
Public authorities & electric railroads10,71210,423
Total1,703,8191,698,879
__________
(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
June 30,		% Change
Weather -
Normal
% Change(b)
Six Months Ended
June 30,		% Change
Weather -
Normal
% Change(b)
2024202320242023
Residential4,5254,3733.5 %0.4 %23,42021,5638.6 %0.6 %
Small commercial & industrial3,3213,743(11.3)%(12.3)%12,80912,4422.9 %(3.8)%
Large commercial & industrial—6(100.0)%(10.7)%1635(54.3)%(11.6)%
Transportation5,1175,190(1.4)%(3.5)%12,01612,204(1.5)%(3.2)%
Total natural gas retail deliveries(a)
12,96313,312(2.6)%(4.6)%48,26146,2444.4 %(1.6)%
115



PECO
 At June 30,
Number of Natural Gas Customers20242023
Residential506,193504,723
Small commercial & industrial44,69744,793
Large commercial & industrial710
Transportation644642
Total551,541550,168
__________
(a)Reflects delivery volumes from customers purchasing natural gas directly from PECO and customers purchasing natural gas from a competitive natural gas supplier as all customers are assessed distribution charges.
(b)Reflects the change in delivery volumes assuming normalized weather based on the historical 30-year average.
Pricing for the three and six months ended June 30, 2024 compared to the same period in 2023 remained relatively consistent.
Transmission Revenue. Under a FERC-approved formula, transmission revenue varies from year to year based upon fluctuations in the underlying costs and capital investments being recovered.
Other revenue primarily includes revenue related to late payment charges. Other revenue for the three and six months ended June 30, 2024 compared to the same period in 2023 remained relatively consistent.
Regulatory Required Programs represents revenues collected under approved riders to recover costs incurred for regulatory programs such as energy efficiency, PGC, and the GSA. The riders are designed to provide full and current cost recovery as well as 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 $21 million and decrease of $59 million for the three and six months ended June 30, 2024 compared to the same period in 2023, in Purchased power and fuel expense is offset in Operating revenues as part of regulatory required programs.
116



PECO
The changes in Operating and maintenance expense consisted of the following:
Three Months Ended
June 30, 2024		Six Months Ended
June 30, 2024
Increase (Decrease)Increase (Decrease)
Credit loss expense$38 $28 
Storm-related costs(2)23 
BSC costs7 14 
Pension and non-pension postretirement benefit expense2 4 
Labor, other benefits, contracting and materials(1)(6)
Other(4)1 
40 64 
Regulatory required programs(9)(11)
Total increase$31 $53 
The changes in Depreciation and amortization expense consisted of the following:
Three Months Ended June 30, 2024Six Months Ended
June 30, 2024
IncreaseIncrease
Depreciation and amortization(a)
$8 $13 
Regulatory asset amortization— — 
Total increase$8 $13 
__________
(a)Depreciation and amortization increased primarily due to ongoing capital expenditures.

Interest expense, net increased $9 million and $15 million for the three and six months ended June 30, 2024, compared to the same period in 2023, primarily due to an increase in interest rates and the issuance of debt in the second quarter of 2023.
Effective income tax rates were 3.2% and 2.0% for the three months ended June 30, 2024 and 2023, respectively, and 5.2% and 1.9% for the six months ended June 30, 2024 and 2023, 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.
117



BGE

Results of Operations — BGE
Three Months Ended
June 30,		Favorable (Unfavorable) VarianceSix Months Ended
June 30,		Favorable (Unfavorable) Variance
2024202320242023
Operating revenues$928 $797 $131 $2,225 $2,053 $172 
Operating expenses
Purchased power and fuel 343 272 (71)807 764 (43)
Operating and maintenance250 198 (52)514 419 (95)
Depreciation and amortization162 158 (4)312 325 13 
Taxes other than income taxes80 76 (4)169 159 (10)
Total operating expenses835 704 (131)1,802 1,667 (135)
Operating income93 93 — 423 386 37 
Other income and (deductions)
Interest expense, net(53)(44)(9)(103)(88)(15)
Other, net8 5 3 16 8 8 
Total other income and (deductions)(45)(39)(6)(87)(80)(7)
Income before income taxes48 54 (6)336 306 30 
Income taxes4 12 8 28 65 37 
Net income$44 $42 $2 $308 $241 $67 
Three Months Ended June 30, 2024 Compared to Three Months Ended June 30, 2023. Net Income increased $2 million primarily due to favorable distribution rates, partially offset by an increase in various operating expenses, and an increase in interest expense. See Note 2 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information on the three-year electric and natural gas distribution multi-year plans.
Six Months Ended June 30, 2024 Compared to Six Months Ended June 30, 2023. Net Income increased $67 million primarily due to favorable distribution rates, partially offset by an increase in storm costs, an increase in various operating expenses, and an increase in interest expense. See Note 2 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information on the three-year electric and natural gas distribution multi-year plans.
The changes in Operating revenues consisted of the following:
Three Months Ended
June 30, 2024		Six Months Ended
June 30, 2024
IncreaseIncrease (Decrease)
ElectricGasTotalElectricGasTotal
Distribution$21 $17 $38 $44 $60 $104 
Transmission4 — 4 3 — 3 
Other2 — 2 1 (2)(1)
27 17 44 48 58 106 
Regulatory required programs82 5 87 131 (65)66 
Total increase (decrease)$109 $22 $131 $179 $(7)$172 
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.
118



BGE

 At June 30,
Number of Electric Customers20242023
Residential1,212,331 1,206,763 
Small commercial & industrial115,384 115,594 
Large commercial & industrial13,156 12,975 
Public authorities & electric railroads260 265 
Total1,341,131 1,335,597 
At June 30,
Number of Natural Gas Customers20242023
Residential656,690 655,181 
Small commercial & industrial37,859 38,077 
Large commercial & industrial6,340 6,275 
Total700,889 699,533 
Distribution Revenue increased for the three and six months ended June 30, 2024, compared to the same period in 2023, 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 and six months ended June 30, 2024, compared to the same period in 2023, 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 the same for the three and six months ended June 30, 2024 compared to the same period in 2023.
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 $71 million and $43 million for the three and six months ended June 30, 2024 compared to the same period in 2023, in Purchased power and fuel expense is fully offset in Operating revenues as part of regulatory required programs.

119



BGE

The changes in Operating and maintenance expense consisted of the following:
Three Months Ended
June 30, 2024		Six Months Ended
June 30, 2024
 IncreaseIncrease
Storm-related costs— 10 
BSC costs8 14 
Credit loss expense14 8 
Labor, other benefits, contracting, and materials3 — 
25 32 
Regulatory required programs(a)
27 63 
Total increase$52 $95 
__________
(a)Increase due to the cost recovery associated with EmPOWER Maryland. Please refer to 2023 10-K Note 3 — Regulatory Matters for additional information.
The changes in Depreciation and amortization expense consisted of the following:
Three Months Ended
June 30, 2024		Six Months Ended
June 30, 2024
Increase (Decrease)Increase (Decrease)
Depreciation and amortization$3 $4 
Regulatory required programs(a)
(14)(39)
Regulatory asset amortization15 22 
Total increase (decrease)$4 $(13)
__________
(a)Decrease due to the cost recovery associated with EmPOWER Maryland. Please refer to 2023 10-K Note 3 — Regulatory Matters for additional information.

Interest expense, net increased by $9 million and $15 million for the three and six months ended June 30, 2024 , respectively compared to the same period in 2023, primarily due to an increase in interest rates and the issuance of debt in the second quarter of 2024 and 2023.
Taxes other than income taxes increased by $4 million and $10 million for the three and six months ended June 30, 2024, respectively, compared to the same period in 2023, primarily due to increased property taxes.
Effective income tax rates were 8.3% and 22.2% for the three months ended June 30, 2024 and 2023, respectively, and 8.3% and 21.2% for the six months ended June 30, 2024 and 2023, 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.
120



PHI
Results of Operations — PHI
PHI’s Results of Operations include the results of its three reportable segments, Pepco, DPL, and ACE. PHI also has a business services subsidiary, PHISCO, which provides a variety of support services, and the costs are directly charged or allocated to the applicable subsidiaries. Additionally, the results of PHI’s corporate operations include interest costs from various financing activities. All material intercompany accounts and transactions have been eliminated in consolidation. The following table sets forth PHI's GAAP consolidated Net income, by Registrant, for the three and six months ended June 30, 2024 compared to the same period in 2023. See the Results of Operations for Pepco, DPL, and ACE for additional information.
Three Months Ended
June 30,		Favorable (Unfavorable) VarianceSix Months Ended June 30,Favorable (Unfavorable) Variance
2024202320242023
PHI$158 $103 $55 $326 $258 $68 
Pepco108 64 44 183 130 53 
DPL
34 25 9 101 85 16 
ACE21 18 3 50 51 (1)
Other(a)
(5)(4)(1)(8)(8)— 
__________
(a)Primarily includes eliminating and consolidating adjustments, PHI's corporate operations, shared service entities, and other financing and investment activities.

Three Months Ended June 30, 2024 Compared to Three Months Ended June 30, 2023. Net Income increased by $55 million primarily due to the favorable impacts of the Pepco Maryland multi-year plans including the recognition of the reconciliations, the absence of an increase in environmental liabilities at Pepco, higher ACE and DPL Delaware electric distribution rates, and higher transmission rates at Pepco and DPL, partially offset by increases in depreciation expense and various operating expenses.
Six Months Ended June 30, 2024 Compared to Six Months Ended June 30, 2023. Net Income increased by $68 million primarily due to the favorable impacts of the Pepco Maryland multi-year plans including the recognition of the reconciliations, the absence of an increase in environmental liabilities at Pepco, higher ACE and DPL Delaware electric distribution rates, and higher transmission rates at Pepco and DPL, partially offset by increases in interest expense, depreciation expense, and various operating expenses.
121



Pepco

Results of Operations — Pepco
Three Months Ended June 30,Favorable (Unfavorable) VarianceSix Months Ended June 30,Favorable (Unfavorable) Variance
2024202320242023
Operating revenues$700 $642 $58 $1,459 $1,351 $108 
Operating expenses
Purchased power 234 204 (30)514 462 (52)
Operating and maintenance102 140 38 252 290 38 
Depreciation and amortization98 109 11 205 216 11 
Taxes other than income taxes100 88 (12)203 183 (20)
Total operating expenses534 541 7 1,174 1,151 (23)
Operating income 166 101 65 285 200 85 
Other income and (deductions)
Interest expense, net(46)(43)(3)(92)(81)(11)
Other, net16 16 — 32 33 (1)
Total other income and (deductions)(30)(27)(3)(60)(48)(12)
Income before income taxes136 74 62 225 152 73 
Income taxes28 10 (18)42 22 (20)
Net income$108 $64 $44 $183 $130 $53 
Three Months Ended June 30, 2024 Compared to Three Months Ended June 30, 2023. Net Income increased by $44 million primarily due to the favorable impacts of the Maryland multi-year plans including the recognition of the reconciliations, the absence of an increase in environmental liabilities, higher transmission rates, and customer growth, partially offset by increases in depreciation expense and interest expense.
Six Months Ended June 30, 2024 Compared to Six Months Ended June 30, 2023. Net Income increased by $53 million primarily due to the favorable impacts of the Maryland multi-year plans including the recognition of the reconciliations, the absence of an increase in environmental liabilities, higher transmission rates, and customer growth, partially offset by increases in depreciation expense and interest expense.
The changes in Operating revenues consisted of the following:
Three Months Ended
June 30, 2024		Six Months Ended
June 30, 2024
IncreaseIncrease
Distribution$7 $16 
Transmission14 24 
21 40 
Regulatory required programs37 68 
Total increase$58 $108 
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 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 are not impacted by abnormal weather or usage per customer, they are impacted by changes in the number of customers.
122



Pepco

At June 30,
Number of Electric Customers20242023
Residential871,009 860,014 
Small commercial & industrial54,080 54,016 
Large commercial & industrial23,057 22,904 
Public authorities & electric railroads207 204 
Total948,353 937,138 
Distribution Revenue increased for the three and six months ended June 30, 2024 compared to the same period in 2023 primarily due to favorable impacts of the Maryland multi-year plans and customer growth.
Transmission Revenue. Under a FERC-approved formula, transmission revenue varies from year to year based upon fluctuations in the underlying costs and capital investments being recovered. Transmission revenue increased for the three and six months ended June 30, 2024, compared to the same period in 2023, primarily due to increases in underlying costs and capital investment.
Other Revenue includes rental revenue, revenue related to late payment charges, mutual assistance revenues, and recoveries of other taxes.
Regulatory Required Programs represent revenues collected under approved riders to recover costs incurred for regulatory programs such as energy efficiency programs, DC PLUG, and SOS procurement and administrative costs. The riders are designed to provide full and current cost recovery as well as a return in certain instances. The costs of these programs are included in Purchased power expense, Operating and maintenance expense, Depreciation and amortization expense, and Taxes other than income taxes. Customers have the choice to purchase electricity from competitive electric generation suppliers. Customer choice programs do not impact the volume of deliveries, as Pepco remains the distribution service provider for all customers and charges a regulated rate for distribution service, which is recorded in Operating revenues. For customers that choose to purchase electric generation from competitive suppliers, Pepco acts as the billing agent and therefore, Pepco does not record Operating revenues or Purchased power expense related to the electricity. For customers that choose to purchase electric generation from Pepco, Pepco is permitted to recover the electricity and REC procurement costs from customers and therefore records the amounts related to the electricity and RECs in Operating revenues and Purchased power expense. Pepco recovers electricity and REC procurement costs from customers with a slight mark-up.
See Note 4 — Segment Information of the Combined Notes to Consolidated Financial Statements for the presentation of Pepco's revenue disaggregation.
The increase of $30 million and $52 million for the three and six months ended June 30, 2024, respectively, compared to the same period in 2023, in Purchased power expense is fully offset in Operating revenues as part of regulatory required programs.
123



Pepco

The changes in Operating and maintenance expense consisted of the following:
Three Months Ended
June 30, 2024		Six Months Ended
June 30, 2024
Increase (Decrease)Increase (Decrease)
BSC and PHISCO costs$7 $14 
Credit loss expense(7)(1)
Storm-related costs(1)(1)
Pension and non-pension postretirement benefits expense(1)(1)
Labor, other benefits, contracting and materials(a)
(5)(28)
Pepco Maryland multi-year plan reconciliations(b)
(25)(25)
Other (c)
(21)(19)
(53)(61)
Regulatory required programs(d)
15 23 
Total decrease$(38)$(38)
_________
(a)Primarily reflects the absence of an increase in environmental liabilities for the six months ended June 30, 2024 compared to the same period in 2023.
(b)See Note 2 — Regulatory Matters for additional information on multi-year plan reconciliations.
(c)Primarily relates to a revenue deferral mechanism approved by the MDPSC to capture rate increases attributable to April 1, 2024 through June 30, 2024.
(d)Increase primarily due to the cost recovery associated with EmPOWER Maryland. Please refer to 2024 10-K Note 2 — Regulatory Matters for additional information.

The changes in Depreciation and amortization expense consisted of the following:
Three Months Ended
June 30, 2024		Six Months Ended
June 30, 2024
Increase (Decrease)Increase (Decrease)
Depreciation and amortization(a)
$6 $12 
Regulatory asset amortization— — 
Regulatory required programs(17)(23)
Total decrease$(11)$(11)
__________
(a)Depreciation and amortization increased primarily due to ongoing capital expenditures.
Taxes other than income taxes increased $12 million and $20 million for the three and six months ended June 30, 2024, respectively, compared to the same period in 2023, primarily due to increases in utility taxes, which are offset in revenues, and property taxes.
Interest expense, net increased by $3 million and $11 million for the three and six months ended June 30, 2024, respectively, compared to the same period in 2023, primarily due to increases in interest rates and the issuance of debt in 2023 and 2024.
Effective income tax rates were 20.6% and 13.5% for the three months ended June 30, 2024 and 2023, respectively, and 18.7% and 14.5% for the six months ended June 30, 2024 and 2023, 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.
124



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DPL

Results of Operations — DPL
Three Months Ended June 30,Favorable (Unfavorable) VarianceSix Months Ended June 30,Favorable (Unfavorable) Variance
2024202320242023
Operating revenues$390 $349 $41 $880 $823 $57 
Operating expenses
Purchased power and fuel 156 139 (17)370 360 (10)
Operating and maintenance96 88 (8)192 175 (17)
Depreciation and amortization61 60 (1)122 121 (1)
Taxes other than income taxes19 18 (1)39 37 (2)
Total operating expenses332 305 (27)723 693 (30)
Operating income58 44 14 157 130 27 
Other income and (deductions)
Interest expense, net(24)(18)(6)(46)(36)(10)
Other, net8 4 4 15 8 7 
Total other income and (deductions)(16)(14)(2)(31)(28)(3)
Income before income taxes42 30 12 126 102 24 
Income taxes8 5 (3)25 17 (8)
Net income $34 $25 $9 $101 $85 $16 
Three Months Ended June 30, 2024 Compared to Three Months Ended June 30, 2023. Net income increased $9 million primarily due to higher Delaware electric distribution rates, favorable weather conditions at Delaware electric and natural gas service territories, and higher transmission rates, partially offset by an increase in various operating expenses.
Six Months Ended June 30, 2024 Compared to Six Months Ended June 30, 2023. Net income increased $16 million primarily due to higher Delaware electric and natural gas distribution rates, favorable weather conditions at Delaware electric and natural gas service territories, and higher transmission rates, partially offset by increases in interest and various operating expenses.
The changes in Operating revenues consisted of the following:
Three Months Ended
June 30, 2024		Six Months Ended
June 30, 2024
Increase (Decrease)Increase (Decrease)
ElectricGasTotalElectricGasTotal
Weather$7 $1 $8 $10 $4 $14 
Volume— — — (1)(1)(2)
Distribution12 1 13 22 2 24 
Transmission6 — 6 13 — 13 
Other— — — 2 — 2 
25 2 27 46 5 51 
Regulatory required programs17 (3)14 38 (32)6 
Total increase (decrease)$42 $(1)$41 $84 $(27)$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 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
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DPL

businesses, very cold weather in winter months are referred to as "favorable weather conditions” because these weather conditions result in increased deliveries of electricity and natural gas. Conversely, mild weather reduces demand. During the three and six months ended June 30, 2024 compared to the same period in 2023, Operating revenues related to weather increased due to favorable weather conditions in Delaware electric and natural gas service territories.
Heating and cooling degree days are quantitative indices that reflect the demand for energy needed to heat or cool a home or business. Normal weather is determined based on historical average heating and cooling degree days for a 20-year period in the Delaware electric service territory and a 30-year period in the Delaware natural gas service territory. The changes in heating and cooling degree days in the Delaware service territory for the three and six months ended June 30, 2024, compared to same period in 2023 and normal weather consisted of the following:
Three Months Ended June 30,% Change
Delaware Electric Service Territory20242023Normal2024 vs. 20232024 vs. Normal
Heating Degree-Days404 318 450 27.0 %(10.2)%
Cooling Degree-Days400 253 340 58.1 %17.6 %
Six Months Ended June 30,% Change
Delaware Electric Service Territory20242023Normal2024 vs. 20232024 vs. Normal
Heating Degree-Days2,608 2,269 2,896 14.9 %(9.9)%
Cooling Degree-Days400 253 341 58.1 %17.3 %
Three Months Ended June 30,% Change
Delaware Natural Gas Service Territory20242023Normal2024 vs. 20232024 vs. Normal
Heating Degree-Days404 318 483 27.0 %(16.4)%
Six Months Ended June 30,% Change
Delaware Natural Gas Service Territory20242023Normal2024 vs. 20232024 vs. Normal
Heating Degree-Days2,608 2,269 2,959 14.9 %(11.9)%
Volume, exclusive of the effects of weather, remained relatively consistent for the three and six months ended June 30, 2024 compared to the same period in 2023, respectively.
Electric Retail Deliveries to Delaware Customers (in GWhs)Three Months Ended
June 30,		% Change
Weather - Normal
% Change(b)
Six Months Ended
June 30,		% Change
Weather - Normal
% Change(b)
2024202320242023
Residential698 610 14.4 %(1.0)%1,555 1,407 10.5 %(0.6)%
Small commercial & industrial353 349 1.1 %(4.1)%691 676 2.2 %(2.2)%
Large commercial & industrial756 780 (3.1)%(5.4)%1,474 1,500 (1.7)%(3.3)%
Public authorities & electric railroads8 8 — %1.4 %14 17 (17.6)%(12.4)%
Total electric retail deliveries(a)
1,815 1,747 3.9 %(-3.5)%3,734 3,600 3.7 %(2.0)%
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DPL

At June 30,
Number of Total Electric Customers (Maryland and Delaware)20242023
Residential488,089 483,760 
Small commercial & industrial64,549 63,913 
Large commercial & industrial1,256 1,234 
Public authorities & electric railroads595 594 
Total554,489 549,501 
__________
(a)Reflects delivery volumes from customers purchasing electricity directly from DPL and customers purchasing electricity from a competitive electric generation supplier as all customers are assessed distribution charges.
(b)Reflects the change in delivery volumes assuming normalized weather based on the historical 20-year average.
Natural Gas Retail Deliveries to Delaware Customers (in mmcf)Three Months Ended
June 30,		% Change
Weather - Normal
% Change(b)
Six Months Ended
June 30,		% Change
Weather - Normal
% Change(b)
2024202320242023
Residential852 794 7.3 %(6.7)%4,764 4,368 9.1 %(2.3)%
Small commercial & industrial531 497 6.8 %(5.4)%2,244 2,142 4.8 %(6.5)%
Large commercial & industrial402 371 8.4 %8.5 %834 787 6.0 %5.8 %
Transportation1,340 1,328 0.9 %(1.5)%3,301 3,231 2.2 %(1.7)%
Total natural gas deliveries(a)
3,125 2,990 4.5 %(2.7)%11,143 10,528 5.8 %(2.5)%
At June 30,
Number of Delaware Natural Gas Customers20242023
Residential130,678 129,538 
Small commercial & industrial10,100 10,060 
Large commercial & industrial14 16 
Transportation163 163 
Total140,955 139,777 
__________
(a)Reflects delivery volumes from customers purchasing natural gas directly from DPL and customers purchasing natural gas from a competitive natural gas supplier as all customers are assessed distribution charges.
(b)Reflects the change in delivery volumes assuming normalized weather based on the historical 30-year average.
Distribution Revenue increased for the three and six months ended June 30, 2024 compared to the same period in 2023 primarily due to favorable impacts of the higher electric distribution rates in Delaware that became effective July 2023, and higher natural gas DSIC rates in Delaware that became effective in January 2024, partially offset by lower electric DSIC rates in Delaware that became effective in January 2024.
Transmission Revenue. Under a FERC-approved formula, transmission revenue varies from year to year based upon fluctuations in the underlying costs and capital investments being recovered. During the three and six months ended June 30, 2024 compared to the same period in 2023, transmission revenue increased primarily due to increases in underlying costs and capital investment.
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
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Table of Contents
DPL

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 $17 million and $10 million for the three and six months ended June 30, 2024, compared to the same period in 2023, respectively, in Purchased power and fuel expense is fully offset in Operating revenues as part of regulatory required programs.
The changes in Operating and maintenance expense consisted of the following:
Three Months Ended
June 30, 2024		Six Months Ended
June 30, 2024
Increase (Decrease)Increase (Decrease)
BSC and PHISCO costs$4 $7 
Labor and contracting2 4 
Credit loss expense1 (1)
Pension and non-pension postretirement benefits expense— (1)
Storm-related Costs(2)5 
Other
(1)(2)
4 12 
Regulatory required programs4 5 
Total increase$8 $17 
The changes in Depreciation and amortization expense consisted of the following:
Three Months Ended
June 30, 2024		Six Months Ended
June 30, 2024
Increase (Decrease)Increase (Decrease)
Depreciation and amortization(a)
$2 $3 
Regulatory required programs(2)(3)
Regulatory asset amortization1 1 
Total increase$1 $1 
__________
(a)Depreciation and amortization increased primarily due to ongoing capital expenditures.
Interest expense, net increased by $6 million and $10 million for the three and six months ended June 30, 2024 compared to the same period in 2023, respectively, primarily due to an increase in interest rates and the issuance of debt in 2023 and 2024.
Other, net increased by $4 million and $7 million for the three and six months ended June 30, 2024 compared to the same period in 2023, respectively, primarily due to higher AFUDC equity.
Effective income tax rates were 19.0% and 16.7% for the three months ended June 30, 2024 and 2023, respectively, and 19.8% and 16.7% for the six months ended June 30, 2024 and 2023, respectively. See Note 6 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the effective income tax rates.
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ACE

Results of Operations — ACE
Three Months Ended June 30,Favorable (Unfavorable) VarianceSix Months Ended June 30,Favorable (Unfavorable) Variance
2024202320242023
Operating revenues$383 $317 $66 $740 $670 $70 
Operating expenses
Purchased power 172 124 (48)312 273 (39)
Operating and maintenance92 85 (7)178 165 (13)
Depreciation and amortization72 68 (4)146 135 (11)
Taxes other than income taxes2 3 1 5 4 (1)
Total operating expenses338 280 (58)641 577 (64)
Operating income 45 37 8 99 93 6 
Other income and (deductions)
Interest expense, net(20)(17)(3)(39)(34)(5)
Other, net4 4 — 8 9 (1)
Total other income and (deductions)(16)(13)(3)(31)(25)(6)
Income before income taxes29 24 5 68 68 — 
Income taxes8 6 (2)18 17 (1)
Net income $21 $18 $3 $50 $51 $(1)

Three Months Ended June 30, 2024 Compared to Three Months Ended June 30, 2023. Net income increased by $3 million primarily due to higher distribution rates partially offset by increases in interest expense and depreciation expense.

Six Months Ended June 30, 2024 Compared to Six Months Ended June 30, 2023. Net income decreased by $1 million primarily due to increases in depreciation expense and interest expense partially offset by higher distribution rates.
The changes in Operating revenues consisted of the following:
Three Months Ended
June 30, 2024		Six Months Ended
June 30, 2024
Increase (Decrease)Increase
Distribution$18 $29 
Transmission(2)— 
16 29 
Regulatory required programs50 41 
Total increase$66 $70 
Revenue Decoupling. The demand for electricity is affected by weather and customer usage. However, Operating revenues from electric distribution in New Jersey are not 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 June 30,
Number of Electric Customers20242023
Residential506,358 503,918 
Small commercial & industrial62,717 62,307 
Large commercial & industrial2,878 3,007 
Public authorities & electric railroads701 727 
Total572,654 569,959 
Distribution Revenue increased for the three and six months ended June 30, 2024 compared to the same period in 2023 due to higher distribution rates that became effective December 2023 and the expiration of customer credits related to the TCJA tax benefits.
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 stayed relatively consistent for the three and six months ended June 30, 2024 compared to the same period in 2023.
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 Bond Charge, 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 decrease of $48 million and $39 million for the three and six months ended June 30, 2024, respectively, compared to the same period in 2023 in Purchased power expense is fully offset in Operating revenues as part of regulatory required programs.
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ACE

The changes in Operating and maintenance expense consisted of the following:
Three Months Ended
June 30, 2024		Six Months Ended
June 30, 2024
Increase (Decrease)Increase (Decrease)
BSC and PHISCO costs$4 $7 
Labor and contracting(2)(2)
Storm-related costs2 4 
Other— 1 
4 10 
Regulatory required programs(a)
3 3 
Total increase$7 $13 
__________
(a)ACE is allowed to recover from or refund to customers the difference between its annual credit loss expense and the amounts collected in rates annually through the Societal Benefits Charge.
The changes in Depreciation and amortization expense consisted of the following:
Three Months Ended
June 30, 2024		Six Months Ended
June 30, 2024
Increase (Decrease)Increase
Depreciation and amortization(a)
$4 $8 
Regulatory asset amortization1 3 
Regulatory required programs(1)— 
Total increase$4 $11 
__________
(a)Depreciation and amortization increased primarily due to ongoing capital expenditures.
Interest expense, net increased $3 million and $5 million for the three and six months ended June 30, 2024, respectively, compared to the same period in 2023 primarily due to increases in interest rates and the issuance of debt in 2023 and 2024.
Effective income tax rates were 27.6% and 25.0% for the three months ended June 30, 2024 and 2023, respectively, and 26.5% and 25.0% for the six months ended June 30, 2024 and 2023, 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 2023 Form 10-K and Notes 2 — Regulatory Matters and 11 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for additional information on regulatory and legal proceedings and proposed legislation.
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The following table provides a summary of the change in cash flows from operating activities for the six months ended June 30, 2024 and 2023 by Registrant:
Increase (decrease) in cash flows from operating activitiesExelonComEdPECOBGE PHIPepcoDPLACE
Net income (loss)$94 $(26)$(24)$67 $68 $53 $16 $(1)
Adjustments to reconcile net income to cash:
Non-cash operating activities480 259 46 (4)24 (39)18 44 
Collateral received (paid), net200 (13)— 22 193 26 121 47 
Income taxes(136)(124)(75)(51)(60)(44)(35)(6)
Pension and non-pension postretirement benefit contributions(40)14 (2)(19)(64)3 — (8)
Regulatory assets and liabilities, net781 905 (29)51 (134)(42)(51)(39)
Changes in working capital and other assets and liabilities(686)(17)(221)(107)(18)(8)— 4 
Increase (decrease) in cash flows from operating activities$693 $998 $(305)$(41)$9 $(51)$69 $41 
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 six months ended June 30, 2024 and 2023 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 change in Collateral received (paid), net, when comparing the six month ended June 30, 2024 to the six month ended June 30, 2023, is due to stable energy prices for the current year. See Note 8 — Derivative Financial Instruments for additional information.
•See Note 6 — Income Taxes of the Combined Notes to Consolidated Financial Statements and the Registrants' Consolidated Statements of Cash Flows for additional information on income taxes.
•Changes in Pension and non-pension postretirement benefit contributions relates to Exelon's increased contributions to the Qualified Plans during the six months ended June 30, 2024. See Note 14 — Retirement Benefits of the 2023 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 differs from the recovery period of those costs. Included within the changes is energy efficiency spend for ComEd of $170 million and $192 million for the six months ended June 30, 2024 and 2023, respectively. Also included within the changes is energy efficiency and demand response programs spend for BGE, Pepco, DPL and ACE of $54 million, $19 million, $9 million, and $14 million for the six months ended June 30, 2024 and $66 million, $32 million, $12 million, and $8 million for the six months ended June 30, 2023, respectively. PECO had no energy efficiency and demand response programs spend recorded to the regulatory asset for the six months ended June 30, 2024 and 2023. 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 $(349) million and $(686) million, respectively. The change in working capital and other noncurrent assets and liabilities for Exelon Corporate and the Utility Registrants is dependent upon the normal course of operations for all Registrants. For ComEd, it is also dependent upon whether the participating nuclear-powered generating facilities are owed money from ComEd as a result of the established pricing for CMCs. For the six months ended June 30, 2024, the established pricing resulted in ComEd owing payments to nuclear-powered generating facilities, which is reported within the cash flows from operations as a change in accounts payable and accrued expense.
Cash Flows from Investing Activities
The following table provides a summary of the change in cash flows from investing activities for the six months ended June 30, 2024 and 2023 by Registrant:
Increase (decrease) in cash flows from investing activitiesExelonComEdPECOBGE PHIPepcoDPLACE
Capital expenditures$219 $151 $(36)$(12)$119 $29 $(10)$95 
Changes in intercompany money pool— — 225 — — (57)(23)— 
Other investing activities(11)8 5 5 (8)(8)— — 
Increase (decrease) in cash flows from investing activities$208 $159 $194 $(7)$111 $(36)$(33)$95 
Significant investing cash flow impacts for the Registrants for six months ended June 30, 2024 and 2023 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 six months ended June 30, 2024 and 2023 by Registrant:
(Decrease) increase in cash flows from financing activitiesExelonComEdPECOBGE PHIPepcoDPLACE
Changes in short-term borrowings, net$281 $(644)$334 $72 $(17)$167 $52 $(236)
Long-term debt, net(669)(175)(525)400 75 25 50 — 
Changes in intercompany money pool— — — — (16)(52)— 132 
Dividends paid on common stock(44)(14)2 (26)— (38)(24)(8)
Distributions to member— — — — (70)— — — 
Contributions from parent/member— (294)250 (40)82 8 55 18 
Other financing activities20 2 4 (1)— 2 — — 
(Decrease) increase in cash flows from financing activities$(412)$(1,125)$65 $405 $54 $112 $133 $(94)
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Significant financing cash flow impacts for the Registrants for the six months ended June 30, 2024 and 2023 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 redemptions table 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.
•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 2023 Form 10-K for additional information on dividend restrictions. See below for quarterly dividends declared.
Debt
See Note 9 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information on the Registrants’ debt issuances.
During the six months ended June 30, 2024, the following long-term debt was retired and/or redeemed:
Company(a)
TypeInterest RateMaturityAmount
ExelonSMBC Term Loan AgreementSOFR plus 0.85%April 8, 2024$500 
ExelonSoftware Licensing Agreement3.62 %December 1, 2025$1 
ExelonSoftware Licensing Agreement3.95 %May 1, 2024$2 
PepcoFirst Mortgage Bonds3.60 %March 15, 2024$400 
__________
(a)DPL repaid $33 million of its unsecured tax-exempt bonds on the maturity date of July 1, 2024. On August 1, 2024, ComEd redeemed $250 million of its 3.10% First Mortgage Bonds originally due on November 1, 2024.
Dividends
Quarterly dividends declared by the Exelon Board of Directors during the six months ended June 30, 2024 and for the third quarter of 2024 were as follows:
PeriodDeclaration DateShareholder of Record DateDividend Payable Date
Cash per Share(a)
First Quarter 2024February 21, 2024March 4, 2024March 15, 2024$0.3800 
Second Quarter 2024April 30, 2024May 13, 2024June 14, 2024$0.3800 
Third Quarter 2024July 30, 2024August 12, 2024September 13, 2024$0.3800 
__________
(a)Exelon's Board of Directors approved an updated dividend policy for 2024. The 2024 quarterly dividend will be $0.38 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 $3.0 billion was available to support additional commercial paper as of June 30, 2024, and of which no financial institution has more than 6% of the aggregate commitments for the Registrants. The Registrants had
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access to the commercial paper markets and had availability under their revolving credit facilities during the six months ended June 30, 2024 to fund their short-term liquidity needs, when necessary. Exelon Corporate and the Utility Registrants each have a 5-year revolving credit facility. See Note 9 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information. The Registrants routinely review the sufficiency of their liquidity position, including appropriate sizing of credit facility commitments, by performing various stress test scenarios, such as commodity price movements, increases in margin-related transactions, changes in hedging levels, and the impacts of hypothetical credit downgrades. The Registrants have continued to closely monitor events in the financial markets and the financial institutions associated with the credit facilities, including monitoring credit ratings and outlooks, credit default swap levels, capital raising, and merger activity. See PART I. ITEM 1A. RISK FACTORS of the 2023 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. As of June 30, 2024, $858 million of Common stock remained available for sale pursuant to the ATM program.
The following table presents the incremental collateral that each Utility Registrant would have been required to provide in the event each Utility Registrant lost its investment grade credit rating at June 30, 2024 and available credit facility capacity prior to any incremental collateral at June 30, 2024:
PJM Credit Policy Collateral
Other Incremental Collateral Required(a)
Available Credit Facility Capacity Prior to Any Incremental Collateral
ComEd$— $— $912 
PECO— 27 339 
BGE— 43 594 
Pepco— — 300 
DPL— 10 300 
ACE— — 300 
__________
(a)Represents incremental collateral related to natural gas procurement contracts.
Capital Expenditure Spending
As of June 30, 2024, the most recent estimates of capital expenditures for plant additions and improvements for 2024 are as follows:        
(In millions)TransmissionDistributionGas
Total(a)
ExelonN/AN/AN/A$7,425 
ComEd450 1,700 N/A2,150 
PECO75 1,225 400 1,700 
BGE450 650 500 1,600 
PHI550 1,325 100 1,975 
Pepco225 750 N/A975 
DPL200 300 100 625 
ACE125 275 N/A400 
__________
(a)Numbers rounded to the nearest $25M and may not sum due to rounding.
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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 $93 million in 2024. 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 2023 Form 10-K for additional information on pension and OPEB contributions.
Credit Facilities
Exelon Corporate, ComEd, and BGE meet their short-term liquidity requirements primarily through the issuance of commercial paper. PECO meets its short-term liquidity requirements primarily through the issuance of commercial paper and borrowings from the Exelon intercompany money pool. Pepco, DPL, and ACE meet their short-term liquidity requirements primarily through the issuance of commercial paper and borrowings from the PHI intercompany money pool. PHI Corporate meets its short-term liquidity requirements primarily through the issuance of short-term notes and the Exelon intercompany money pool. The Registrants may use their respective credit facilities for general corporate purposes, including meeting short-term funding requirements and the issuance of letters of credit.
See Note 9 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information on the Registrants’ credit facilities and short term borrowing activity.
Security Ratings
The Registrants’ access to the capital markets, including the commercial paper market, and their respective financing costs in those markets, may depend on the securities ratings of the entity that is accessing the capital markets.
The Registrants’ borrowings are not subject to default or prepayment as a result of a downgrading of securities, although such a downgrading of a Registrant’s securities could increase fees and interest charges under that Registrant’s credit agreements.
As part of the normal course of business, the Registrants enter into contracts that contain express provisions or otherwise permit the Registrants and their counterparties to demand adequate assurance of future performance when there are reasonable grounds for doing so. In accordance with the contracts and applicable contracts law, if the Registrants are downgraded by a credit rating agency, it is possible that a counterparty would attempt to rely
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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 the Registrants did not change for the six months ended June 30, 2024.
Intercompany Money Pool
To provide an additional short-term borrowing option that will generally be more favorable to the borrowing participants than the cost of external financing, both Exelon and PHI operate an intercompany money pool. Maximum amounts contributed to and borrowed from the money pool by participant and the net contribution or borrowing as of June 30, 2024, are presented in the following table:
During the Six Months Ended June 30, 2024At June 30, 2024
Exelon Intercompany Money PoolMaximum
Contributed		Maximum
Borrowed		Contributed
(Borrowed)
Exelon Corporate$626 $— $321 
PECO55 (255)— 
BSC— (420)(309)
PHI Corporate— (86)(57)
PCI45 — 45 
During the Six Months Ended June 30, 2024At June 30, 2024
PHI Intercompany Money PoolMaximum
Contributed		Maximum
Borrowed
Contributed
(Borrowed)
Pepco$171 $— $57 
DPL130 (33)125 
ACE— (197)(182)
Shelf Registration Statements
As of January 1st, 2024 Exelon and the Utility Registrants had an effective combined shelf registration statement, unlimited in amount (“Legacy Registration Statement”). On February 20, 2024, Exelon Corporation filed with the SEC Post-Effective Amendment 1 to its Legacy Registration Statement to remove and withdraw registration of all registered securities of ACE, DPL, PECO and BGE.
On February 21, 2024, Exelon Corporation, together with Pepco and ComEd as co-registrants, filed with the SEC Post-Effective Amendment 2 to its Legacy Registration Statement. Post-Effective Amendment 2 amends the Legacy Registration Statement to include an authorized limit of $7,200 million, which can be used to issue Exelon Corporation debt securities and equity securities, as well as Pepco and ComEd debt securities, through the expiration date of August 3, 2025. The amended Legacy Registration Statement was declared effective by the SEC on April 30, 2024. On February 21, 2024, PECO and BGE filed with the SEC a standalone automatically effective shelf registration statement, unlimited in amount, which can be used to issue PECO and BGE debt securities through the expiration date of February 20, 2027. The ability of Exelon Corporation, ComEd, Pepco, 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.
As a result of Post-Effect Amendment 1, DPL and ACE filed to deregister all securities that remain unsold. DPL and ACE periodically issue securities through the private placement markets. 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.

138


Regulatory Authorizations
The Utility Registrants are required to obtain short-term and long-term financing authority from Federal and State Commissions as follows:
At June 30, 2024
Short-term Financing AuthorityRemaining Long-term Financing Authority
CommissionExpiration DateAmountCommissionExpiration DateAmount
ComEd(a)
FERCDecember 31, 2025$2,500 ICCJanuary 1, 2027 & May 1, 2027$2,318 
PECOFERCDecember 31, 20251,500 PAPUCDecember 31, 2024550 
BGEFERCDecember 31, 2025700 MDPSCN/A300 
Pepco(b)
FERCDecember 31, 2025500 MDPSC / DCPSCDecember 31, 2025375 
DPL(b)
FERCDecember 31, 2025500 MDPSC / DEPSCDecember 31, 2025375 
ACE(c)
NJBPUDecember 31, 2025350 NJBPUDecember 31, 2024550 
__________
(a)ComEd had $500 million available in long-term debt refinancing authority and $1.8 billion available in new money long-term debt financing authority from the ICC as of June 30, 2024. The financing authorities have an expiration date of May 1, 2027 and January 1, 2027, respectively.
(b)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.
(c)On June 24, 2024, ACE filed an application with the NJBPU for renewal of their long-term financing authority through December 31, 2026. ACE expects approval of their application by December 31, 2024.
139


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 2023 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, or to lock in rate levels on borrowings, which are typically designated as economic 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.
140


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):
202420252026202720282029 and Beyond
Prices based on model or other valuation methods (Level 3)$(12)$(21)$(19)$(18)$(18)$(51)$(139)
_________
(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 second quarter of 2024, 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 June 30, 2024, 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. In the first quarter of 2024, ComEd and PECO implemented a new customer care and billing information system replacing the existing system. ComEd and PECO expect the new system to further automate, enhance and standardize the processes by which they engage with their customers. As part of this system implementation, ComEd and PECO appropriately considered the impacts to internal controls over financial reporting. There were no other changes in internal control over financial reporting that occurred during the three and six months ended June 30, 2024, that have materially affected, or are reasonably likely to materially affect, any of the Registrants' internal control over financial reporting.
PART II — OTHER INFORMATION
ITEM 1.    LEGAL PROCEEDINGS
The Registrants are parties to various lawsuits and regulatory proceedings in the ordinary course of their respective businesses. For information regarding material lawsuits and proceedings, see (a) ITEM 3. LEGAL PROCEEDINGS of the 2023 Form 10-K, (b) Notes 3 — Regulatory Matters and 18 — Commitments and Contingencies of the 2023 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
141


At June 30, 2024, the Registrants' risk factors were consistent with the risk factors described in the Registrants' combined 2023 Form 10-K in ITEM 1A. RISK FACTORS.
ITEM 5.    OTHER INFORMATION
All Registrants
None.
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 relevant. Registrant agrees to furnish a copy of any such instrument to the Commission upon request.
(3) Recently Amended Articles and Bylaws
Exelon Corporation
Exhibit No.DescriptionLocation
Amended and Restated Articles of Incorporation of Exelon Corporation, as amended April 30, 2024
Amended and Restated Bylaws of Exelon Corporation, as amended on April 30, 2024
(4) Instruments Defining the Rights of Securities Holders, Including Indentures
Baltimore Gas and Electric Company
Exhibit No.DescriptionLocation
Form of 5.300% Note due June 1, 2034 issued June 6, 2024 by Baltimore Gas and Electric Company


Form of 5.650% Note due June 1, 2054 issued June 6, 2024 by Baltimore Gas and Electric Company
Commonwealth Edison Company
Exhibit No.DescriptionLocation
Supplemental Indenture to Commonwealth Edison Company Mortgage dated as of May 1, 2024
Certifications Pursuant to Rule 13a-14(a) and 15d-14(a) of the Securities and Exchange Act of 1934 as to the Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2024 filed by the following officers for the following companies:
142


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 June 30, 2024 filed by the following officers for the following companies:
143


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)
144


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)
August 1, 2024
145


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/    STEVEN J. CICHOCKI
Steven J. Cichocki
Director, Accounting
(Principal Accounting Officer)
August 1, 2024
146


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/    CAROLINE FULGINITI
Caroline Fulginiti
Director, Accounting
(Principal Accounting Officer)
August 1, 2024

147


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		Vice President, Chief Financial Officer and Treasurer
(Principal Financial Officer)
 /s/ JASON T. JONES
Jason T. Jones
Director, Accounting
(Principal Accounting Officer)
August 1, 2024

148


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/ JULIE E. GIESE
Julie E. Giese
Director, Accounting
(Principal Accounting Officer)
August 1, 2024

149


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/ JULIE E. GIESE
Julie E. Giese
Director, Accounting
(Principal Accounting Officer)
August 1, 2024

150


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/ JULIE E. GIESE
Julie E. Giese
Director, Accounting
(Principal Accounting Officer)
August 1, 2024

151


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/ JULIE E. GIESE
Julie E. Giese
Director, Accounting
(Principal Accounting Officer)
August 1, 2024
152


What is the market capitalization of a company?

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