Companies: 10,651     total market cap: $139.941 T
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Exelon Corporation
EXC
#539
Rank
$45.22 B
Marketcap
๐Ÿ‡บ๐Ÿ‡ธ United States
Country
$44.78
Share price
0.83%
Change (1 day)
14.97%
Change (1 year)
๐Ÿ”‹ Electricity
Categories
  1. Exelon Corporation
  2. Quarterly Reports (10-Q)
  3. Submitted on 2024-05-02

Exelon Corporation - 10-Q quarterly report FY


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Cumulative Preferred Security, Series DMarch 31, 2024March 31, 2024March 31, 2024March 31, 2024March 31, 2024March 31, 2024March 31, 2024March 31, 2024falsefalsefalsefalsefalsefalsefalsefalse20242024202420242024202420242024Q1Q1Q1Q1Q1Q1Q1Q1December 31December 31December 31December 31December 31December 31December 31December 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UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
☒ QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the Quarterly Period Ended March 31, 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
PECO ENERGY COMPANY:
Trust Receipts of PECO Energy Capital Trust III, each representing a 7.38% Cumulative Preferred Security, Series D, $25 stated value, issued by PECO Energy Capital, L.P. and unconditionally guaranteed by PECO Energy Company
N/AN/A

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.  Yes  x  No  o

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).  Yes  x  No  o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and "emerging growth company" in Rule 12b-2 of the Exchange Act.
Exelon CorporationLarge Accelerated FilerxAccelerated Filer
☐
Non-accelerated Filer
☐
Smaller Reporting Company
☐
Emerging Growth Company
☐
Commonwealth Edison CompanyLarge Accelerated Filer
☐
Accelerated Filer
☐
Non-accelerated FilerxSmaller Reporting Company
☐
Emerging Growth Company
☐
PECO Energy CompanyLarge Accelerated Filer
☐
Accelerated Filer
☐
Non-accelerated FilerxSmaller Reporting Company
☐
Emerging Growth Company
☐
Baltimore Gas and Electric CompanyLarge Accelerated Filer
☐
Accelerated Filer
☐
Non-accelerated FilerxSmaller Reporting Company
☐
Emerging Growth Company
☐
Pepco Holdings LLCLarge Accelerated Filer
☐
Accelerated Filer
☐
Non-accelerated FilerxSmaller Reporting Company
☐
Emerging Growth Company
☐
Potomac Electric Power CompanyLarge Accelerated Filer
☐
Accelerated Filer
☐
Non-accelerated FilerxSmaller Reporting Company
☐
Emerging Growth Company
☐
Delmarva Power & Light CompanyLarge Accelerated Filer
☐
Accelerated Filer
☐
Non-accelerated FilerxSmaller Reporting Company
☐
Emerging Growth Company
☐
Atlantic City Electric CompanyLarge Accelerated Filer
☐
Accelerated Filer
☐
Non-accelerated FilerxSmaller Reporting Company
☐
Emerging Growth Company
☐

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

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

The number of shares outstanding of each registrant’s common stock as of March 31, 2024 was:
Exelon Corporation Common Stock, without par value1,000,025,124
Commonwealth Edison Company Common Stock, $12.50 par value127,021,409
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
57
4. Segment Information
58
5. Accounts Receivable
63
6. Income Taxes
65
7. Retirement Benefits
66
8. Derivative Financial Instruments
68
9. Debt and Credit Agreements
72
10. Fair Value of Financial Assets and Liabilities
74
11. Commitments and Contingencies
81
12. Shareholders' Equity
88
13. Changes in Accumulated Other Comprehensive Income
88
14. Supplemental Financial Information
89
15. Related Party Transactions
92
2




Page No.
94
Exelon Corporation
94
Executive Overview
94
Financial Results of Operations
94
Significant 2024 Transactions and Developments
95
Other Key Business Drivers and Management Strategies
98
Critical Accounting Policies and Estimates
99
Results of Operations By Registrant
100
Commonwealth Edison Company
100
PECO Energy Company
103
Baltimore Gas and Electric Company
107
Pepco Holdings LLC
110
Potomac Electric Power Company
111
Delmarva Power & Light Company
114
Atlantic City Electric Company
118
Liquidity and Capital Resources
121
129
130
130
130
130
131
131
134
134
135
136
137
138
139
140
141
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
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
N/ANot applicable
NAVNet Asset Value
5



GLOSSARY OF TERMS AND ABBREVIATIONS
Other Terms and Abbreviations
NJBPUNew Jersey Board of Public Utilities
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
March 31,
(In millions, except per share data)20242023
Operating revenues
Electric operating revenues$5,198 $4,462 
Natural gas operating revenues739 822 
Revenues from alternative revenue programs106 279 
Total operating revenues6,043 5,563 
Operating expenses
Purchased power2,197 1,733 
Purchased fuel213 358 
Operating and maintenance1,271 1,151 
Depreciation and amortization879 860 
Taxes other than income taxes371 355 
Total operating expenses4,931 4,457 
Gain on sale of assets and businesses2 — 
Operating income1,114 1,106 
Other income and (deductions)
Interest expense, net(462)(406)
Interest expense to affiliates(6)(6)
Other, net75 109 
Total other income and (deductions)(393)(303)
Income before income taxes721 803 
Income taxes63 134 
Net income attributable to common shareholders$658 $669 
Comprehensive income, net of income taxes
Net income$658 $669 
Other comprehensive income (loss), net of income taxes
Pension and non-pension postretirement benefit plans:
Actuarial losses reclassified to periodic benefit cost5 3 
Pension and non-pension postretirement benefit plans valuation adjustments(24)(10)
Unrealized gains on cash flow hedges33 6 
Other comprehensive income (loss)14 (1)
Comprehensive income attributable to common shareholders$672 $668 
Average shares of common stock outstanding:
Basic1,000 995 
Assumed exercise and/or distributions of stock-based awards(a)
1 1 
Diluted1,001 996 
Earnings per average common share
Basic$0.66 $0.67 
Diluted$0.66 $0.67 
__________
(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)
Three Months Ended
March 31,
(In millions)20242023
Cash flows from operating activities
Net income$658 $669 
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation, amortization, and accretion880 860 
Gain on sales of assets and businesses(2)— 
Deferred income taxes and amortization of investment tax credits46 113 
Net fair value changes related to derivatives1 — 
Other non-cash operating activities39 (138)
Changes in assets and liabilities:
Accounts receivable(309)106 
Inventories12 102 
Accounts payable and accrued expenses(238)(482)
Collateral received (paid), net7 (214)
Income taxes21 23 
Regulatory assets and liabilities, net252 (324)
Pension and non-pension postretirement benefit contributions(111)(44)
Other assets and liabilities(264)(187)
Net cash flows provided by operating activities992 484 
Cash flows from investing activities
Capital expenditures(1,767)(1,881)
Proceeds from sales of assets and businesses2 — 
Other investing activities(2)10 
Net cash flows used in investing activities(1,767)(1,871)
Cash flows from financing activities
Changes in short-term borrowings(317)(1,130)
Proceeds from short-term borrowings with maturities greater than 90 days150 — 
Repayments on short-term borrowings with maturities greater than 90 days(150)(150)
Issuance of long-term debt2,625 3,925 
Retirement of long-term debt(901)(857)
Dividends paid on common stock(381)(358)
Proceeds from employee stock plans11 10 
Other financing activities(55)(60)
Net cash flows provided by financing activities982 1,380 
Increase (decrease) in cash, restricted cash, and cash equivalents207 (7)
Cash, restricted cash, and cash equivalents at beginning of period1,101 1,090 
Cash, restricted cash, and cash equivalents at end of period$1,308 $1,083 
Supplemental cash flow information
Decrease in capital expenditures not paid$(117)$(201)
See the Combined Notes to Consolidated Financial Statements
10



EXELON CORPORATION AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
(Unaudited)
(In millions)March 31, 2024December 31, 2023
ASSETS
Current assets
Cash and cash equivalents$720 $445 
Restricted cash and cash equivalents489 482 
Accounts receivable
Customer accounts receivable2,8962,659
Customer allowance for credit losses(346)(317)
Customer accounts receivable, net2,550 2,342 
Other accounts receivable1,1311,101
Other allowance for credit losses(96)(82)
Other accounts receivable, net1,035 1,019 
Inventories, net
Fossil fuel37 94 
Materials and supplies751 707 
Regulatory assets2,035 2,215 
Other595 473 
Total current assets8,212 7,777 
Property, plant, and equipment (net of accumulated depreciation and amortization of $17,711 and $17,251 as of March 31, 2024 and December 31, 2023, respectively)
74,604 73,593 
Deferred debits and other assets
Regulatory assets8,701 8,698 
Goodwill6,630 6,630 
Receivable related to Regulatory Agreement Units3,382 3,232 
Investments263 251 
Other1,419 1,365 
Total deferred debits and other assets20,395 20,176 
Total assets$103,211 $101,546 
See the Combined Notes to Consolidated Financial Statements
11



EXELON CORPORATION AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
(Unaudited)
(In millions)March 31, 2024December 31, 2023
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities
Short-term borrowings$2,206 $2,523 
Long-term debt due within one year503 1,403 
Accounts payable2,814 2,846 
Accrued expenses1,076 1,375 
Payables to affiliates5 5 
Customer deposits419 411 
Regulatory liabilities400 389 
Mark-to-market derivative liabilities29 74 
Unamortized energy contract liabilities7 8 
Other516 557 
Total current liabilities7,975 9,591 
Long-term debt42,271 39,692 
Long-term debt to financing trusts390 390 
Deferred credits and other liabilities
Deferred income taxes and unamortized investment tax credits12,199 11,956 
Regulatory liabilities9,706 9,576 
Pension obligations1,569 1,571 
Non-pension postretirement benefit obligations523 527 
Asset retirement obligations270 267 
Mark-to-market derivative liabilities80 106 
Unamortized energy contract liabilities25 27 
Other2,142 2,088 
Total deferred credits and other liabilities26,514 26,118 
Total liabilities77,150 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 March 31, 2024 and December 31, 2023, respectively)
21,129 21,114 
Treasury stock, at cost (2 shares as of March 31, 2024 and December 31, 2023)
(123)(123)
Retained earnings5,767 5,490 
Accumulated other comprehensive loss, net(712)(726)
Total shareholders’ equity26,061 25,755 
Total liabilities and shareholders’ equity$103,211 $101,546 

See the Combined Notes to Consolidated Financial Statements
12



EXELON CORPORATION AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS’ EQUITY
(Unaudited)
Three Months Ended March 31, 2024
(In millions, shares
in thousands)		Issued
Shares		Common
Stock		Treasury
Stock		Retained
Earnings		Accumulated
Other
Comprehensive
Loss, net		Total Shareholders'
Equity
Balance at December 31, 20231,001,249 $21,114 $(123)$5,490 $(726)$25,755 
Net income— — — 658 — 658 
Long-term incentive plan activity333 2 — — — 2 
Employee stock purchase plan 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 

Three Months Ended March 31, 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 





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
March 31,
(In millions)20242023
Operating revenues
Electric operating revenues$2,074 $1,511 
Revenues from alternative revenue programs19 153 
Operating revenues from affiliates2 3 
Total operating revenues2,095 1,667 
Operating expenses
Purchased power907 488 
Operating and maintenance318 254 
Operating and maintenance from affiliates100 83 
Depreciation and amortization362 338 
Taxes other than income taxes94 93 
Total operating expenses1,781 1,256 
Operating income314 411 
Other income and (deductions)
Interest expense, net(119)(114)
Interest expense to affiliates(3)(3)
Other, net20 18 
Total other income and (deductions)(102)(99)
Income before income taxes212 312 
Income taxes19 71 
Net income$193 $241 
Comprehensive income$193 $241 

See the Combined Notes to Consolidated Financial Statements
14



COMMONWEALTH EDISON COMPANY AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
Three Months Ended
March 31,
(In millions)20242023
Cash flows from operating activities
Net income$193 $241 
Adjustments to reconcile net income to net cash flows provided by (used in) operating activities:
Depreciation and amortization362 338 
Deferred income taxes and amortization of investment tax credits(1)55 
Other non-cash operating activities(6)(153)
Changes in assets and liabilities:
Accounts receivable(133)96 
Receivables from and payables to affiliates, net— 10 
Inventories(11)(21)
Accounts payable and accrued expenses (116)(306)
Collateral received (paid), net8 (4)
Income taxes21 15 
Regulatory assets and liabilities, net315 (338)
Pension and non-pension postretirement benefit contributions(5)(23)
Other assets and liabilities(67)(22)
Net cash flows provided by (used in) operating activities560 (112)
Cash flows from investing activities
Capital expenditures(594)(617)
Other investing activities1 1 
Net cash flows used in investing activities(593)(616)
Cash flows from financing activities
Changes in short-term borrowings128 (18)
Repayments on short-term borrowings with maturities greater than 90 days— (150)
Issuance of long-term debt— 975 
Dividends paid on common stock(194)(187)
Contributions from parent39 186 
Other financing activities1 (11)
Net cash flows (used in) provided by financing activities(26)795 
(Decrease) increase in cash, restricted cash, and cash equivalents(59)67 
Cash, restricted cash, and cash equivalents at beginning of period686 511 
Cash, restricted cash, and cash equivalents at end of period$627 $578 
Supplemental cash flow information
Decrease in capital expenditures not paid$(74)$(35)
See the Combined Notes to Consolidated Financial Statements
15



COMMONWEALTH EDISON COMPANY AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
(Unaudited)
(In millions)March 31, 2024December 31, 2023
ASSETS
Current assets
   Cash and cash equivalents$100 $110 
   Restricted cash and cash equivalents428 402 
   Accounts receivable
   Customer accounts receivable1,003860
   Customer allowance for credit losses(82)(69)
       Customer accounts receivable, net921 791 
   Other accounts receivable230242
   Other allowance for credit losses(19)(17)
       Other accounts receivable, net 211 225 
   Receivables from affiliates3 3 
   Inventories, net289 279 
   Regulatory assets1,137 1,335 
   Other141 123 
   Total current assets3,230 3,268 
Property, plant, and equipment (net of accumulated depreciation and amortization of $7,409 and $7,222 as of March 31, 2024 and December 31, 2023, respectively)
29,371 29,088 
Deferred debits and other assets
   Regulatory assets2,706 2,794 
   Goodwill2,625 2,625 
   Receivable related to Regulatory Agreement Units3,078 2,954 
   Investments6 6 
   Prepaid pension asset1,207 1,217 
   Other909 875 
   Total deferred debits and other assets10,531 10,471 
Total assets$43,132 $42,827 
See the Combined Notes to Consolidated Financial Statements
16



COMMONWEALTH EDISON COMPANY AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
(Unaudited)
(In millions)March 31, 2024December 31, 2023
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities
   Short-term borrowings$730 $602 
   Long-term debt due within one year250 250 
   Accounts payable859 867 
   Accrued expenses414 576 
   Payables to affiliates72 72 
   Customer deposits122 118 
   Regulatory liabilities191 191 
   Mark-to-market derivative liabilities29 27 
   Other214 219 
   Total current liabilities2,881 2,922 
Long-term debt11,237 11,236 
Long-term debt to financing trust205 205 
Deferred credits and other liabilities
   Deferred income taxes and unamortized investment tax credits5,384 5,327 
   Regulatory liabilities7,697 7,493 
   Asset retirement obligations150 149 
   Non-pension postretirement benefits obligations163 161 
   Mark-to-market derivative liabilities79 106 
   Other935 865 
   Total deferred credits and other liabilities14,408 14,101 
   Total liabilities28,731 28,464 
Commitments and contingencies
Shareholders’ equity
   Common stock 1,588 1,588 
   Other paid-in capital10,440 10,401 
   Retained earnings2,373 2,374 
   Total shareholders’ equity14,401 14,363 
Total liabilities and shareholders’ equity$43,132 $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)
Three Months Ended March 31, 2024
(In millions)Common
Stock		Other
Paid-In
Capital		Retained
Earnings		Total
Shareholders’
Equity
Balance at December 31, 2023$1,588 $10,401 $2,374 $14,363 
Net income— — 193 193 
Common stock dividends— — (194)(194)
Contributions from parent— 39 — 39 
Balance at March 31, 2024$1,588 $10,440 $2,373 $14,401 
Three Months Ended March 31, 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 
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
March 31,
(In millions)20242023
Operating revenues
Electric operating revenues$782 $798 
Natural gas operating revenues272 316 
Revenues from alternative revenue programs(2)(4)
Operating revenues from affiliates2 2 
Total operating revenues1,054 1,112 
Operating expenses
Purchased power 306 330 
Purchased fuel97 154 
Operating and maintenance235 219 
Operating and maintenance from affiliates58 51 
Depreciation and amortization104 98 
Taxes other than income taxes51 50 
Total operating expenses851 902 
Gain on sales of assets 2 — 
Operating income205 210 
Other income and (deductions)
Interest expense, net(52)(45)
Interest expense to affiliates(3)(3)
Other, net9 8 
Total other income and (deductions)(46)(40)
Income before income taxes159 170 
Income taxes10 4 
Net income$149 $166 
Comprehensive income$149 $166 
See the Combined Notes to Consolidated Financial Statements
19



PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
Three Months Ended
March 31,
(In millions)20242023
Cash flows from operating activities
Net income$149 $166 
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation and amortization104 98 
Gain on sales of assets(2)— 
Deferred income taxes and amortization of investment tax credits(8)(16)
Other non-cash operating activities20 32 
Changes in assets and liabilities:
Accounts receivable(75)36 
Receivables from and payables to affiliates, net4 8 
Inventories19 60 
Accounts payable and accrued expenses (63)(176)
Income taxes19 20 
Regulatory assets and liabilities, net(20)15 
Pension and non-pension postretirement benefit contributions(2)— 
Other assets and liabilities(104)(75)
Net cash flows provided by operating activities41 168 
Cash flows from investing activities
Capital expenditures(361)(335)
Other investing activities2 — 
Net cash flows used in investing activities(359)(335)
Cash flows from financing activities
Changes in short-term borrowings(165)(94)
Dividends paid on common stock(100)(101)
Contributions from parent580 330 
Net cash flows provided by financing activities315 135 
Decrease in cash, restricted cash, and cash equivalents(3)(32)
Cash, restricted cash, and cash equivalents at beginning of period51 68 
Cash, restricted cash, and cash equivalents at end of period$48 $36 
Supplemental cash flow information
Increase (decrease) in capital expenditures not paid$5 $(9)
See the Combined Notes to Consolidated Financial Statements
20



PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
(Unaudited)
(In millions)March 31, 2024December 31, 2023
ASSETS
Current assets
Cash and cash equivalents$39 $42 
Restricted cash and cash equivalents9 9 
Accounts receivable
Customer accounts receivable562527
Customer allowance for credit losses(107)(95)
Customer accounts receivable, net455 432 
Other accounts receivable160117
Other allowance for credit losses(13)(8)
Other accounts receivable, net147 109 
Receivables from affiliates— 2 
Inventories, net
Fossil fuel22 50 
Materials and supplies76 67 
Prepaid utility taxes128 2 
Regulatory assets128 127 
Other78 63 
Total current assets1,082 903 
Property, plant, and equipment (net of accumulated depreciation and amortization of $4,149 and $4,097 as of March 31, 2024 and December 31, 2023, respectively)
13,399 13,128 
Deferred debits and other assets
Regulatory assets834 793 
Receivable related to Regulatory Agreement Units304 278 
Investments37 35 
Prepaid pension asset432 429 
Other28 29 
Total deferred debits and other assets1,635 1,564 
Total assets$16,116 $15,595 
See the Combined Notes to Consolidated Financial Statements
21



PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
(Unaudited)
(In millions)March 31, 2024December 31, 2023
LIABILITIES AND SHAREHOLDER'S EQUITY
Current liabilities
Short-term borrowings$— $165 
Accounts payable524 512 
Accrued expenses198 236 
Payables to affiliates41 39 
Customer deposits78 79 
Renewable energy credit obligation54 36 
Regulatory liabilities83 92 
Other31 23 
Total current liabilities1,009 1,182 
Long-term debt5,134 5,134 
Long-term debt to financing trusts184 184 
Deferred credits and other liabilities
Deferred income taxes and unamortized investment tax credits2,349 2,321 
Regulatory liabilities340 314 
Asset retirement obligations27 26 
Non-pension postretirement benefits obligations287 286 
Other88 79 
Total deferred credits and other liabilities3,091 3,026 
Total liabilities9,418 9,526 
Commitments and contingencies
Shareholder’s equity
Common stock4,630 4,050 
Retained earnings2,068 2,019 
Total shareholder’s equity6,698 6,069 
Total liabilities and shareholder's equity$16,116 $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)
Three Months Ended March 31, 2024
(In millions)Common
Stock		Retained
Earnings		Total
Shareholder's
Equity
Balance at December 31, 2023$4,050 $2,019 $6,069 
Net income— 149 149 
Common stock dividends— (100)(100)
Contributions from parent580 — 580 
Balance at March 31, 2024$4,630 $2,068 $6,698 
Three Months Ended March 31, 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 
See the Combined Notes to Consolidated Financial Statements
23




BALTIMORE GAS AND ELECTRIC COMPANY
STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME
(Unaudited)
Three Months Ended
March 31,
(In millions)20242023
Operating revenues
Electric operating revenues$857 $780 
Natural gas operating revenues395 409 
Revenues from alternative revenue programs43 65 
Operating revenues from affiliates2 3 
Total operating revenues1,297 1,257 
Operating expenses
Purchased power377 343 
Purchased fuel87 149 
Operating and maintenance205 168 
Operating and maintenance from affiliates59 54 
Depreciation and amortization150 167 
Taxes other than income taxes89 83 
Total operating expenses967 964 
Operating income330 293 
Other income and (deductions)
Interest expense, net(50)(44)
Other, net8 3 
Total other income and (deductions)(42)(41)
Income before income taxes288 252 
Income taxes24 52 
Net income$264 $200 
Comprehensive income$264 $200 
See the Combined Notes to Consolidated Financial Statements
24



BALTIMORE GAS AND ELECTRIC COMPANY
STATEMENTS OF CASH FLOWS
(Unaudited)
Three Months Ended
March 31,
(In millions)20242023
Cash flows from operating activities
Net income$264 $200 
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation and amortization150 167 
Deferred income taxes and amortization of investment tax credits(4)24 
Other non-cash operating activities(21)(32)
Changes in assets and liabilities:
Accounts receivable(95)43 
Receivables from and payables to affiliates, net2 (3)
Inventories14 62 
Accounts payable and accrued expenses21 (96)
Collateral paid, net— (22)
Income taxes29 29 
Regulatory assets and liabilities, net— (31)
Pension and non-pension postretirement benefit contributions(25)(8)
Other assets and liabilities(18)(24)
Net cash flows provided by operating activities317 309 
Cash flows from investing activities
Capital expenditures(324)(350)
Other investing activities8 3 
Net cash flows used in investing activities(316)(347)
Cash flows from financing activities
Changes in short-term borrowings70 (165)
Dividends paid on common stock(92)(80)
Contributions from parent— 237 
Net cash flows used in financing activities(22)(8)
Decrease in cash, restricted cash, and cash equivalents(21)(46)
Cash, restricted cash, and cash equivalents at beginning of period48 67 
Cash, restricted cash, and cash equivalents at end of period$27 $21 
Supplemental cash flow information
Decrease in capital expenditures not paid$(8)$(70)
See the Combined Notes to Consolidated Financial Statements
25



BALTIMORE GAS AND ELECTRIC COMPANY
BALANCE SHEETS
(Unaudited)
(In millions)March 31, 2024December 31, 2023
ASSETS
Current assets
Cash and cash equivalents$27 $47 
Restricted cash and cash equivalents— 1 
Accounts receivable
Customer accounts receivable618527
Customer allowance for credit losses (52)(46)
Customer accounts receivable, net566 481 
Other accounts receivable 104106
Other allowance for credit losses(7)(7)
Other accounts receivable, net97 99 
Inventories, net
Fossil fuel13 35 
Materials and supplies82 74 
Prepaid utility taxes54 56 
Regulatory assets237 229 
Other18 25 
Total current assets1,094 1,047 
Property, plant, and equipment (net of accumulated depreciation and amortization of $4,817 and $4,744 as of March 31, 2024 and December 31, 2023, respectively)
12,291 12,102 
Deferred debits and other assets
Regulatory assets742 727 
Investments10 9 
Prepaid pension asset253 248 
Other54 51 
Total deferred debits and other assets1,059 1,035 
Total assets$14,444 $14,184 
See the Combined Notes to Consolidated Financial Statements
26



BALTIMORE GAS AND ELECTRIC COMPANY
BALANCE SHEETS
(Unaudited)
(In millions)March 31, 2024December 31, 2023
LIABILITIES AND SHAREHOLDER'S EQUITY
Current liabilities
Short-term borrowings$406 $336 
Accounts payable338 344 
Accrued expenses249 203 
Payables to affiliates37 35 
Customer deposits115 114 
Regulatory liabilities26 27 
Other24 34 
Total current liabilities1,195 1,093 
Long-term debt4,602 4,602 
Deferred credits and other liabilities
Deferred income taxes and unamortized investment tax credits2,016 1,945 
Regulatory liabilities699 773 
Asset retirement obligations32 32 
Non-pension postretirement benefits obligations153 158 
Other85 91 
Total deferred credits and other liabilities2,985 2,999 
Total liabilities8,782 8,694 
Commitments and contingencies
Shareholder's equity
Common stock3,246 3,246 
Retained earnings2,416 2,244 
Total shareholder's equity5,662 5,490 
Total liabilities and shareholder's equity$14,444 $14,184 

See the Combined Notes to Consolidated Financial Statements
27



BALTIMORE GAS AND ELECTRIC COMPANY
STATEMENTS OF CHANGES IN SHAREHOLDER'S EQUITY
(Unaudited)
Three Months Ended March 31, 2024
(In millions)Common
Stock		Retained
Earnings		Total
Shareholder's
Equity
Balance at December 31, 2023$3,246 $2,244 $5,490 
Net income— 264 264 
Common stock dividends— (92)(92)
Balance at March 31, 2024$3,246 $2,416 $5,662 
Three Months Ended March 31, 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 
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
March 31,
(In millions)20242023
Operating revenues
Electric operating revenues$1,485 $1,371 
Natural gas operating revenues72 97 
Revenues from alternative revenue programs46 65 
Operating revenues from affiliates3 3 
Total operating revenues1,606 1,536 
Operating expenses
Purchased power607 572 
Purchased fuel29 55 
Operating and maintenance274 267 
Operating and maintenance from affiliates51 42 
Depreciation and amortization246 241 
Taxes other than income taxes128 120 
Total operating expenses1,335 1,297 
Operating income271 239 
Other income and (deductions)
Interest expense, net(90)(76)
Other, net27 26 
Total other income and (deductions)(63)(50)
Income before income taxes 208 189 
Income taxes40 34 
Net income$168 $155 
Comprehensive income$168 $155 
See the Combined Notes to Consolidated Financial Statements
29



PEPCO HOLDINGS LLC AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
Three Months Ended
March 31,
(In millions)20242023
Cash flows from operating activities
Net income$168 $155 
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation and amortization246 241 
Deferred income taxes and amortization of investment tax credits16 13 
Other non-cash operating activities9 (7)
Changes in assets and liabilities:
Accounts receivable1 98 
Inventories(11)4 
Accounts payable and accrued expenses(23)(88)
Collateral paid, net— (189)
Income taxes24 20 
Regulatory assets and liabilities, net(42)27 
Pension and non-pension postretirement benefit contributions(72)(7)
Other assets and liabilities(27)(11)
Net cash flows provided by operating activities289 256 
Cash flows from investing activities
Capital expenditures(453)(561)
Other investing activities— 8 
Net cash flows used in investing activities(453)(553)
Cash flows from financing activities
Changes in short-term borrowings(394)(414)
Issuance of long-term debt925 450 
Retirement of long-term debt(400)— 
Changes in Exelon intercompany money pool8 8 
Distributions to member(118)(112)
Contributions from member487 405 
Other financing activities(21)(17)
Net cash flows provided by financing activities487 320 
Increase in cash, restricted cash, and cash equivalents323 23 
Cash, restricted cash, and cash equivalents at beginning of period204 373 
Cash, restricted cash, and cash equivalents at end of period$527 $396 
Supplemental cash flow information
Decrease in capital expenditures not paid$(11)$(76)
See the Combined Notes to Consolidated Financial Statements
30



PEPCO HOLDINGS LLC AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
(Unaudited)
(In millions)March 31, 2024December 31, 2023
ASSETS
Current assets
Cash and cash equivalents$504 $180 
Restricted cash and cash equivalents23 24 
Accounts receivable
Customer accounts receivable714745
Customer allowance for credit losses(105)(107)
Customer accounts receivable, net609 638 
Other accounts receivable321310
Other allowance for credit losses(57)(50)
Other accounts receivable, net264 260 
Receivables from affiliates4 3 
Inventories, net
Fossil fuel3 9 
Materials and supplies304 287 
Regulatory assets342 337 
Other82 100 
Total current assets2,135 1,838 
Property, plant, and equipment (net of accumulated depreciation and amortization of $3,302 and $3,175 as of March 31, 2024 and December 31, 2023, respectively)
19,121 18,851 
Deferred debits and other assets
Regulatory assets1,606 1,587 
Goodwill4,005 4,005 
Investments145 143 
Prepaid pension asset314 268 
Other209 211 
Total deferred debits and other assets6,279 6,214 
Total assets$27,535 $26,903 
See the Combined Notes to Consolidated Financial Statements
31



PEPCO HOLDINGS LLC AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
(Unaudited)
(In millions)March 31, 2024December 31, 2023
LIABILITIES AND MEMBER'S EQUITY
Current liabilities
Short-term borrowings$— $394 
Long-term debt due within one year244 644 
Accounts payable668 683 
Accrued expenses344 338 
Payables to affiliates60 59 
Borrowings from Exelon intercompany money pool73 65 
Customer deposits104 100 
Regulatory liabilities 89 71 
Unamortized energy contract liabilities7 8 
PPA termination obligation31 49 
Other108 138 
Total current liabilities1,728 2,549 
Long-term debt8,909 8,004 
Deferred credits and other liabilities
Deferred income taxes and unamortized investment tax credits3,071 3,031 
Regulatory liabilities878 904 
Asset retirement obligations56 55 
Non-pension postretirement benefit obligations37 40 
Unamortized energy contract liabilities25 27 
Other512 511 
Total deferred credits and other liabilities4,579 4,568 
Total liabilities15,216 15,121 
Commitments and contingencies
Member's equity
Membership interest12,544 12,057 
Undistributed losses(225)(275)
Total member's equity12,319 11,782 
Total liabilities and member's equity$27,535 $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)
Three Months Ended March 31, 2024
(In millions)Membership InterestUndistributed (Losses)/GainsTotal Member's Equity
Balance at December 31, 2023$12,057 $(275)$11,782 
Net income— 168 168 
Distributions to member— (118)(118)
Contributions from member487 — 487 
Balance at March 31, 2024$12,544 $(225)$12,319 

Three Months Ended March 31, 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 
See the Combined Notes to Consolidated Financial Statements
33




POTOMAC ELECTRIC POWER COMPANY
STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME
(Unaudited)
Three Months Ended
March 31,
(In millions)20242023
Operating revenues
Electric operating revenues$728 $670 
Revenues from alternative revenue programs29 39 
Operating revenues from affiliates2 1 
Total operating revenues759 710 
Operating expenses
Purchased power281 258 
Operating and maintenance86 93 
Operating and maintenance from affiliates64 57 
Depreciation and amortization107 108 
Taxes other than income taxes102 94 
Total operating expenses640 610 
Operating income119 100 
Other income and (deductions)
Interest expense, net(45)(39)
Other, net15 16 
Total other income and (deductions)(30)(23)
Income before income taxes89 77 
Income taxes14 12 
Net income$75 $65 
Comprehensive income$75 $65 
See the Combined Notes to Consolidated Financial Statements
34



POTOMAC ELECTRIC POWER COMPANY
STATEMENTS OF CASH FLOWS
(Unaudited)
Three Months Ended
March 31,
(In millions)20242023
Cash flows from operating activities
Net income$75 $65 
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation and amortization107 108 
Deferred income taxes and amortization of investment tax credits3 3 
Other non-cash operating activities(13)(10)
Changes in assets and liabilities:
Accounts receivable21 52 
Receivables from and payables to affiliates, net6 3 
Inventories(10)(3)
Accounts payable and accrued expenses — (27)
Collateral paid, net(1)(25)
Income taxes12 8 
Regulatory assets and liabilities, net6 (3)
Pension and non-pension postretirement benefit contributions(4)(4)
Other assets and liabilities(19)11 
Net cash flows provided by operating activities183 178 
Cash flows from investing activities
Capital expenditures(229)(264)
Changes in PHI intercompany money pool(134)— 
Other investing activities— 8 
Net cash flows used in investing activities(363)(256)
Cash flows from financing activities
Changes in short-term borrowings(132)(299)
Issuance of long-term debt675 250 
Retirement of long-term debt(400)— 
Dividends paid on common stock(51)(48)
Contributions from parent251 243 
Other financing activities(15)(14)
Net cash flows provided by financing activities328 132 
Increase in cash, restricted cash, and cash equivalents148 54 
Cash, restricted cash, and cash equivalents at beginning of period72 99 
Cash, restricted cash, and cash equivalents at end of period$220 $153 
Supplemental cash flow information
Decrease in capital expenditures not paid$(11)$(43)
See the Combined Notes to Consolidated Financial Statements
35



POTOMAC ELECTRIC POWER COMPANY
BALANCE SHEETS
(Unaudited)
(In millions)March 31, 2024December 31, 2023
ASSETS
Current assets
Cash and cash equivalents$198 $48 
Restricted cash and cash equivalents22 24 
Accounts receivable
Customer accounts receivable349369
Customer allowance for credit losses(52)(52)
Customer accounts receivable, net297 317 
Other accounts receivable156166
Other allowance for credit losses(35)(28)
Other accounts receivable, net121 138 
Receivables from affiliates1 2 
Receivable from PHI intercompany money pool134 — 
Inventories, net169 159 
Regulatory assets133 150 
Other35 51 
Total current assets1,110 889 
Property, plant, and equipment (net of accumulated depreciation and amortization of $4,341 and $4,284 as of March 31, 2024 and December 31, 2023, respectively)
9,584 9,430 
Deferred debits and other assets
Regulatory assets467 450 
Investments127 124 
Prepaid pension asset240 246 
Other57 55 
Total deferred debits and other assets891 875 
Total assets$11,585 $11,194 
See the Combined Notes to Consolidated Financial Statements
36



POTOMAC ELECTRIC POWER COMPANY
BALANCE SHEETS
(Unaudited)
(In millions)March 31, 2024December 31, 2023
LIABILITIES AND SHAREHOLDER'S EQUITY
Current liabilities
Short-term borrowings$— $132 
Long-term debt due within one year5 405 
Accounts payable304 321 
Accrued expenses209 191 
Payables to affiliates37 32 
Customer deposits49 47 
Regulatory liabilities 23 15 
Merger related obligation23 25 
Other35 61 
Total current liabilities685 1,229 
Long-term debt4,354 3,691 
Deferred credits and other liabilities
Deferred income taxes and unamortized investment tax credits1,448 1,431 
Regulatory liabilities 368 382 
Asset retirement obligations38 37 
Other273 280 
Total deferred credits and other liabilities2,127 2,130 
Total liabilities7,166 7,050 
Commitments and contingencies
Shareholder's equity
Common stock 3,326 3,075 
Retained earnings1,093 1,069 
Total shareholder's equity4,419 4,144 
Total liabilities and shareholder's equity$11,585 $11,194 
See the Combined Notes to Consolidated Financial Statements
37



POTOMAC ELECTRIC POWER COMPANY
STATEMENTS OF CHANGES IN SHAREHOLDER'S EQUITY
(Unaudited)
Three Months Ended March 31, 2024
(In millions)Common StockRetained EarningsTotal Shareholder's Equity
Balance at December 31, 2023$3,075 $1,069 $4,144 
Net income— 75 75 
Common stock dividends— (51)(51)
Contributions from parent251 — 251 
Balance at March 31, 2024$3,326 $1,093 $4,419 

Three Months Ended March 31, 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 

See the Combined Notes to Consolidated Financial Statements
38




DELMARVA POWER & LIGHT COMPANY
STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME
(Unaudited)
Three Months Ended
March 31,
(In millions)20242023
Operating revenues
Electric operating revenues$413 $366 
Natural gas operating revenues72 97 
Revenues from alternative revenue programs4 9 
Operating revenues from affiliates2 2 
Total operating revenues491 474 
Operating expenses
Purchased power186 166 
Purchased fuel29 55 
Operating and maintenance51 46 
Operating and maintenance from affiliates 44 41 
Depreciation and amortization61 60 
Taxes other than income taxes20 20 
Total operating expenses391 388 
Operating income100 86 
Other income and (deductions)
Interest expense, net(22)(17)
Other, net5 3 
Total other income and (deductions)(17)(14)
Income before income taxes83 72 
Income taxes17 12 
Net income$66 $60 
Comprehensive income$66 $60 
See the Combined Notes to Consolidated Financial Statements
39



DELMARVA POWER & LIGHT COMPANY
STATEMENTS OF CASH FLOWS
(Unaudited)
Three Months Ended
March 31,
(In millions)20242023
Cash flows from operating activities
Net income$66 $60 
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation and amortization61 60 
Deferred income taxes and amortization of investment tax credits6 3 
Other non-cash operating activities12 (1)
Changes in assets and liabilities:
Accounts receivable(7)23 
Receivables from and payables to affiliates, net— 4 
Inventories1 10 
Accounts payable and accrued expenses16 (16)
Collateral paid, net— (120)
Income taxes10 9 
Regulatory assets and liabilities, net(1)27 
Other assets and liabilities6 1 
Net cash flows provided by operating activities170 60 
Cash flows from investing activities
Capital expenditures(134)(134)
Net cash flows used in investing activities(134)(134)
Cash flows from financing activities
Changes in short-term borrowings(63)(115)
Issuance of long-term debt175 125 
Dividends paid on common stock(45)(42)
Contributions from parent154 99 
Other financing activities(3)(2)
Net cash flows provided by financing activities218 65 
Increase (decrease) in cash, restricted cash, and cash equivalents254 (9)
Cash, restricted cash, and cash equivalents at beginning of period16 152 
Cash, restricted cash, and cash equivalents at end of period$270 $143 
Supplemental cash flow information
Decrease in capital expenditures not paid$(6)$(3)
    
See the Combined Notes to Consolidated Financial Statements
40



DELMARVA POWER & LIGHT COMPANY
BALANCE SHEETS
(Unaudited)
(In millions)March 31, 2024December 31, 2023
ASSETS
Current assets
Cash and cash equivalents$269 $16 
Restricted cash and cash equivalents1 — 
Accounts receivable
Customer accounts receivable186183
Customer allowance for credit losses(17)(19)
Customer accounts receivable, net169 164 
Other accounts receivable5152
Other allowance for credit losses(8)(8)
Other accounts receivable, net43 44 
Receivables from affiliates— 1 
Inventories, net
Fossil fuel3 9 
Materials and supplies77 72 
Prepaid utility taxes13 24 
Regulatory assets56 54 
Other20 14 
Total current assets651 398 
Property, plant, and equipment (net of accumulated depreciation and amortization of $1,961 and $1,925 as of March 31, 2024 and December 31, 2023, respectively)
5,245 5,165 
Deferred debits and other assets
Regulatory assets212 218 
Prepaid pension asset132 135 
Other51 50 
Total deferred debits and other assets395 403 
Total assets$6,291 $5,966 
See the Combined Notes to Consolidated Financial Statements
41



DELMARVA POWER & LIGHT COMPANY
BALANCE SHEETS
(Unaudited)
(In millions)March 31, 2024December 31, 2023
LIABILITIES AND SHAREHOLDER'S EQUITY
Current liabilities
Short-term borrowings$— $63 
Long-term debt due within one year85 84 
Accounts payable157 159 
Accrued expenses86 64 
Payables to affiliates25 25 
Customer deposits32 31 
Regulatory liabilities 61 50 
Other18 21 
Total current liabilities464 497 
Long-term debt2,169 1,996 
Deferred credits and other liabilities
Deferred income taxes and unamortized investment tax credits919 904 
Regulatory liabilities356 365 
Asset retirement obligations13 12 
Non-pension postretirement benefits obligations5 6 
Other97 93 
Total deferred credits and other liabilities1,390 1,380 
Total liabilities4,023 3,873 
Commitments and contingencies
Shareholder's equity
Common stock 1,609 1,455 
Retained earnings659 638 
Total shareholder's equity2,268 2,093 
Total liabilities and shareholder's equity$6,291 $5,966 
See the Combined Notes to Consolidated Financial Statements
42



DELMARVA POWER & LIGHT COMPANY
STATEMENTS OF CHANGES IN SHAREHOLDER'S EQUITY
(Unaudited)
Three Months Ended March 31, 2024
(In millions)Common Stock Retained EarningsTotal Shareholder's Equity
Balance at December 31, 2023$1,455 $638 $2,093 
Net income— 66 66 
Common stock dividends— (45)(45)
Contributions from parent154 — 154 
Balance at March 31, 2024$1,609 $659 $2,268 

Three Months Ended March 31, 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 

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
March 31,
(In millions)20242023
Operating revenues
Electric operating revenues$344 $335 
Revenues from alternative revenue programs13 17 
Operating revenues from affiliates1 1 
Total operating revenues358 353 
Operating expenses
Purchased power140 148 
Operating and maintenance47 44 
Operating and maintenance from affiliates40 37 
Depreciation and amortization74 67 
Taxes other than income taxes2 2 
Total operating expenses303 298 
Operating income55 55 
Other income and (deductions)
Interest expense, net(20)(16)
Other, net5 5 
Total other income and (deductions)(15)(11)
Income before income taxes40 44 
Income taxes11 11 
Net income$29 $33 
Comprehensive income$29 $33 
See the Combined Notes to Consolidated Financial Statements
44



ATLANTIC CITY ELECTRIC COMPANY AND SUBSIDIARY COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
Three Months Ended
March 31,
(In millions)20242023
Cash flows from operating activities
Net income$29 $33 
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation and amortization74 67 
Deferred income taxes and amortization of investment tax credits7 6 
Other non-cash operating activities2 (9)
Changes in assets and liabilities:
Accounts receivable(12)24 
Receivables from and payables to affiliates, net(5)(1)
Inventories(3)(3)
Accounts payable and accrued expenses(1)(15)
Collateral received (paid), net1 (44)
Income taxes3 5 
Regulatory assets and liabilities, net(47)3 
Pension and non-pension postretirement benefit contributions(7)(1)
Other assets and liabilities(13)(21)
Net cash flows provided by operating activities28 44 
Cash flows from investing activities
Capital expenditures(89)(161)
Net cash flows used in investing activities(89)(161)
Cash flows from financing activities
Changes in short-term borrowings(199)— 
Issuance of long-term debt75 75 
Changes in PHI intercompany money pool134 — 
Dividends paid on common stock(22)(21)
Contributions from parent81 63 
Other financing activities(2)(1)
Net cash flows provided by financing activities67 116 
Increase (decrease) in cash and cash equivalents6 (1)
Cash and cash equivalents at beginning of period21 72 
Cash and cash equivalents at end of period$27 $71 
Supplemental cash flow information
Increase (decrease) in capital expenditures not paid$4 $(30)
See the Combined Notes to Consolidated Financial Statements
45



ATLANTIC CITY ELECTRIC COMPANY AND SUBSIDIARY COMPANY
CONSOLIDATED BALANCE SHEETS
(Unaudited)
(In millions)March 31, 2024December 31, 2023
ASSETS
Current assets
Cash and cash equivalents$27 $21 
Accounts receivable
Customer accounts receivable178194
Customer allowance for credit losses(36)(36)
Customer accounts receivable, net142 158 
Other accounts receivable11592
Other allowance for credit losses(14)(14)
Other accounts receivable, net101 78 
Receivables from affiliates4 3 
Inventories, net58 55 
Regulatory assets145 125 
Other7 5 
Total current assets484 445 
Property, plant, and equipment (net of accumulated depreciation and amortization of $1,702 and $1,684 as of March 31, 2024 and December 31, 2023, respectively)
4,232 4,192 
Deferred debits and other assets
Regulatory assets497 483 
Prepaid pension asset6 3 
Other34 34 
Total deferred debits and other assets537 520 
Total assets$5,253 $5,157 
See the Combined Notes to Consolidated Financial Statements
46



ATLANTIC CITY ELECTRIC COMPANY AND SUBSIDIARY COMPANY
CONSOLIDATED BALANCE SHEETS
(Unaudited)
(In millions)March 31, 2024December 31, 2023
LIABILITIES AND SHAREHOLDER'S EQUITY
Current liabilities
Short-term borrowings$— $199 
Long-term debt due within one year154 154 
Accounts payable195 192 
Accrued expenses45 42 
Payables to affiliates22 25 
Borrowings from PHI intercompany money pool134 — 
Customer deposits23 23 
Regulatory liabilities5 6 
PPA termination obligation31 49 
Other11 12 
Total current liabilities620 702 
Long-term debt1,755 1,679 
Deferred credits and other liabilities
Deferred income taxes and unamortized investment tax credits780 771 
Regulatory liabilities137 140 
Non-pension postretirement benefit obligations3 4 
Other58 49 
Total deferred credits and other liabilities978 964 
Total liabilities3,353 3,345 
Commitments and contingencies
Shareholder's equity
Common stock1,911 1,830 
Retained deficit(11)(18)
Total shareholder's equity1,900 1,812 
Total liabilities and shareholder's equity$5,253 $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)
Three Months Ended March 31, 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 

Three Months Ended March 31, 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 

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 March 31, 2024 and for the three months ended March 31, 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 financial
49


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

Note 1 — Significant Accounting Policies
statements prepared in accordance with GAAP have been condensed or omitted pursuant to such rules and regulations.
New Accounting Standards (All Registrants)
New Accounting Standards Issued and Not Yet Adopted as of March 31, 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 March 31, 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.
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

50


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

Note 2 — Regulatory Matters
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(e)
October 26, 2020 (amended March 31, 2021)Electric$104 $52 9.55%June 28, 2021June 28, 2021
DPL - Maryland(f)
May 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 Jersey(g)
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 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,
51


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

Note 2 — Regulatory Matters
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 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.
(g)Requested and approved increases are before New Jersey sales and use tax. The NJBPU awarded ACE electric revenue requirement increases of $36 million and $9 million effective December 1, 2023 and February 1, 2024, respectively.
Pending Distribution Base Rate Case Proceedings
Registrant/JurisdictionFiling DateServiceRequested Revenue Requirement IncreaseRequested ROEExpected Approval Timing
ComEd - IllinoisMarch 15, 2024
Electric(a)
$670 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%Third quarter of 2024
Pepco - Maryland(e)
May 16, 2023 (amended February 23, 2024)Electric$186 10.50%Second 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 seeks a $670 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 $302 million in 2024, $89 million in 2025, $136 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 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. 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.
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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
(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.
(e)Reflects a three-year cumulative multi-year plan for April 1, 2024 through March 31, 2027 submitted to the MDPSC. Pepco requested total electric revenue requirement increases of $68 million, $53 million, and $51 million effective April 1, 2024, April 1, 2025, and April 1, 2026, respectively through its surrebuttal filing made on February 23, 2024. The plan contains a proposed nine-month extension period with a requested revenue requirement increase of $14 million effective April 1, 2027 through December 31, 2027. Requested revenue requirement increases will be used to recover capital investments designed to advance system-readiness and support Maryland's climate and clean energy goals. On August 7, 2023, the MDPSC issued an order approving a settlement agreement which allows Pepco to establish a revenue deferral mechanism to recover its full Commission-authorized year 1 increase between July 1, 2024 through March 31, 2025 and extend the procedural schedule to address intervenor resource constraints.
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 BGE is based on prior year actual costs and current year projected capital additions, accumulated depreciation, depreciation and amortization expense, and accumulated deferred income taxes. The update for BGE also reconciles any differences between the actual costs and actual revenues for the calendar year (annual reconciliation).
For 2024, the following increases/(decreases) were included in ComEd's and BGE's 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 %
BGE$42 $13 $53 (d)7.47 %10.50 %
__________
(a)All rates are effective June 1, 2024 - May 31, 2025, subject to review by interested parties pursuant to review protocols of ComEd's and BGE's tariffs.
(b)Represents the weighted average debt and equity return on transmission rate bases.
(c)The rate of return on common equity for ComEd and BGE includes a 50-basis-point incentive adder for being a member of a 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.
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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
On February 3, 2022, the ICC approved a tariff that establishes the process under which ComEd reconciled its 2022 and will reconcile its 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 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 May 22, 2023, direct testimony was filed by ICC staff and more than a dozen intervenors and intervenor groups. The testimonies addressed a wide variety of topics, including rate of return on equity, capital structure, grid planning, various distribution grid and information technology investments, and affordability and customer service. ComEd filed rebuttal testimony in June, which provided, among other things, defense of ComEd’s planned 2024-2027 capital investment and proposed cost of equity. ComEd also made voluntary adjustments and, per the ICC’s final beneficial electrification order requiring ComEd to recover beneficial electrification costs through the MRP, increased its total revenue requirement request from $1.472 billion to $1.545 billion. ComEd filed its reply brief on September 27, 2023, to adjust its total requested revenue requirement increase to $1.487 billion.
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 results 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. A final rehearing order on that topic is statutorily required by early June 2024. 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
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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
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. 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 payments to ComEd ratepayers if the energy index, the capacity price and applicable federal tax credits or subsidy exceed the CMC contract price. In the June 2022 billing period, ComEd began issuing credits to its retail customers under its new CMC rider. A regulatory asset is recorded for the difference between customer credits issued and the credit to be received from the participating nuclear-powered generating facilities. The balance as of March 31, 2024 is $405 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 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 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
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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
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. 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.
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 March 31, 2024, the $31 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 three months ended March 31, 2024 and 2023, ACE has respectively paid $18 million and $19 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. Based on the preliminary findings and the ongoing settlement process, ComEd determined that a loss was probable and recorded its regulatory liability to reflect its best estimate of that loss. The final outcome and resolution of any contested audit issues as well as a reasonable estimate of potential future losses cannot be accurately estimated at this stage; however, the final resolution of these matters could result in recognition of future losses, above the amounts currently accrued, that could be material to the Exelon and ComEd financial statements.
56


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 $286 million primarily due to a decrease of $268 million in the CMC regulatory asset.
PECO. Regulatory liabilities increased $17 million primarily due to an increase of $26 million in the Decommissioning the regulatory agreement units regulatory liability.
BGE. Regulatory liabilities decreased $75 million primarily due to a decrease of $75 million in the Deferred income taxes regulatory liability.
ACE. Regulatory assets increased $34 million primarily due to an increase of $13 million in the Under-recovered revenue decoupling regulatory asset, an increase of $8 million in the Energy efficiency and demand response programs regulatory asset, and an increase of $8 million in the Deferred storm costs regulatory asset.
Capitalized Ratemaking Amounts Not Recognized
The following table presents authorized amounts capitalized for ratemaking purposes related to earnings on shareholders' investment that are not recognized for financial reporting purposes in the Registrants' Consolidated Balance Sheets. These amounts will be recognized as revenues in the related Consolidated Statements of Operations and Comprehensive Income in the periods they are billable to the Utility Registrants' customers. PECO had no related amounts at March 31, 2024 and December 31, 2023.
Exelon
ComEd(a)
BGE(b)
PHI
Pepco(c)
DPL(c)
ACE(d)
March 31, 2024$106 $36 $30 $40 $27 $1 $12 
December 31, 2023110 32 33 45 34 1 10 
__________
(a)Reflects ComEd's unrecognized equity returns earned for ratemaking purposes on its energy efficiency and electric distribution formula rate regulatory assets.
(b)BGE's amount capitalized for ratemaking purposes primarily relates to earnings on shareholders' investment on their AMI programs and on investments in rate base included in the multi-year plan reconciliations.
(c)Pepco's and DPL's authorized amounts capitalized for ratemaking purposes relate to earnings on shareholders' investment on their respective AMI programs and Energy efficiency and demand response programs, and for Pepco District of Columbia revenue decoupling program. The earnings on energy efficiency are on Pepco District of Columbia and DPL Delaware programs only.
(d)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
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
57


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

Note 3 — Revenue from Contracts with Customers
("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 months ended March 31, 2024 and 2023. At March 31, 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 
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 
__________
(a)Revenues recognized in the three months ended March 31, 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 March 31, 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$4 $4 $4 $— $— 
20257 7 5 1 1 
20266 6 5 1 — 
20275 5 5 — — 
2028 and thereafter109 109 86 11 12 
Total$131 $131 $105 $13 $13 
Revenue Disaggregation
The Registrants disaggregate revenue recognized from contracts with customers into categories that depict how the nature, amount, timing, and uncertainty of revenue and cash flows are affected by economic factors. See Note 4 — Segment Information for the presentation of the Registrants' revenue disaggregation.
4. Segment Information (All Registrants)
Operating segments for each of the Registrants are determined based on information used by the CODMs in deciding how to evaluate performance and allocate resources at each of the Registrants.
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,
58


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

Note 4 — Segment Information
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 months ended March 31, 2024 and 2023 is as follows:
ComEdPECOBGEPHI
Other(a)
Intersegment
Eliminations		Exelon
Operating revenues(b):
2024
Electric revenues$2,095 $782 $881 $1,532 $— $(6)$5,284 
Natural gas revenues— 272 416 72 — (1)759 
Shared service and other revenues— — — 2 459 (461)— 
Total operating revenues$2,095 $1,054 $1,297 $1,606 $459 $(468)$6,043 
2023
Electric revenues$1,667 $795 $814 $1,436 $— $(5)$4,707 
Natural gas revenues— 317 443 97 — (1)856 
Shared service and other revenues— — — 3 437 (440)— 
Total operating revenues$1,667 $1,112 $1,257 $1,536 $437 $(446)$5,563 
Intersegment revenues(c):
2024$2 $2 $2 $3 $457 $(466)$— 
20233 2 3 3 434 (445)— 
Depreciation and amortization:
2024$362 $104 $150 $246 $17 $— $879 
2023338 98 167 241 16 — 860 
Operating expenses:
2024$1,781 $851 $967 $1,335 $472 $(475)$4,931 
20231,256 902 964 1,297 485 (447)4,457 
Interest expense, net:
2024$122 $55 $50 $90 $151 $— $468 
2023117 48 44 76 127 — 412 
Income taxes:
2024$19 $10 $24 $40 $(30)$— $63 
202371 4 52 34 (27)— 134 
Net income (loss):
2024$193 $149 $264 $168 $(116)$— $658 
2023241 166 200 155 (93)— 669 
Capital expenditures:
2024$594 $361 $324 $453 $35 $— $1,767 
2023617 335 350 561 18 — 1,881 
Total assets:
March 31, 2024$43,132 $16,116 $14,444 $27,535 $6,376 $(4,392)$103,211 
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.
59


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

Note 4 — Segment Information
(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:
PepcoDPLACE
Other(a)
Intersegment
Eliminations		PHI
Operating revenues(b):
2024
Electric revenues$759 $419 $358 $— $(4)$1,532 
Natural gas revenues— 72 — — — 72 
Shared service and other revenues— — — 109 (107)2 
Total operating revenues$759 $491 $358 $109 $(111)$1,606 
2023
Electric revenues$710 $377 $353 $— $(4)$1,436 
Natural gas revenues— 97 — — — 97 
Shared service and other revenues— — — 102 (99)3 
Total operating revenues$710 $474 $353 $102 $(103)$1,536 
Intersegment revenues(c):
2024$2 $2 $1 $109 $(111)$3 
20231 2 1 102 (103)3 
Depreciation and amortization:
2024$107 $61 $74 $4 $— $246 
2023108 60 67 6 — 241 
Operating expenses:
2024$640 $391 $303 $111 $(110)$1,335 
2023610 388 298 104 (103)1,297 
Interest expense, net:
2024$45 $22 $20 $3 $— $90 
202339 17 16 4 — 76 
Income taxes:
2024$14 $17 $11 $(2)$— $40 
202312 12 11 (1)— 34 
Net income (loss):
2024$75 $66 $29 $(2)$— $168 
202365 60 33 (3)— 155 
Capital expenditures:
2024$229 $134 $89 $1 $— $453 
2023264 134 161 2 — 561 
Total assets:
March 31, 2024$11,585 $6,291 $5,253 $4,718 $(312)$27,535 
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.
60


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

Note 4 — Segment Information
Electric and Gas Revenue by Customer Class (Utility Registrants):
The following tables disaggregate the Registrants' revenues recognized from contracts with customers into categories that depict how the nature, amount, timing, and uncertainty of revenue and cash flows are affected by economic factors. For the Utility Registrants, the disaggregation of revenues reflects the two primary utility services of electric sales and natural gas sales (where applicable), with further disaggregation of these tariff sales provided by major customer groups. Exelon’s disaggregated revenues are consistent with the Utility Registrants, but exclude any intercompany revenues.
Three Months Ended March 31, 2024
Revenues from contracts with customersComEdPECOBGEPHIPepcoDPLACE
Electric revenues
Residential$918 $520 $534 $775 $345 $256 $174 
Small commercial & industrial594 126 90 158 46 62 50 
Large commercial & industrial320 57 132 340 262 29 49 
Public authorities & electric railroads17 7 7 20 11 4 5 
Other(a)
227 74 93 192 64 63 67 
Total electric revenues(b)
$2,076 $784 $856 $1,485 $728 $414 $345 
Natural gas revenues
Residential$— $193 $271 $46 $— $46 $— 
Small commercial & industrial— 64 47 17 — 17 — 
Large commercial & industrial— — 72 2 — 2 — 
Transportation— 8 — 5 — 5 — 
Other(c)
— 7 5 2 — 2 — 
Total natural gas revenues(d)
$— $272 $395 $72 $— $72 $— 
Total revenues from contracts with customers$2,076 $1,056 $1,251 $1,557 $728 $486 $345 
Other revenues
Revenues from alternative revenue programs$19 $(2)$43 $46 $29 $4 $13 
Other electric revenues(e)
— — 2 3 2 1 — 
Other natural gas revenues(e)
— — 1 — — — — 
Total other revenues$19 $(2)$46 $49 $31 $5 $13 
Total revenues for reportable segments$2,095 $1,054 $1,297 $1,606 $759 $491 $358 
61


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

Note 4 — Segment Information
Three Months Ended March 31, 2023
Revenues from contracts with customersComEdPECOBGEPHIPepcoDPLACE
Electric revenues
Residential$836 $519 $434 $639 $283 $210 $146 
Small commercial & industrial361 135 92 160 39 62 59 
Large commercial & industrial84 65 149 378 282 33 63 
Public authorities & electric railroads10 8 7 17 8 4 5 
Other(a)
217 68 96 176 56 58 63 
Total electric revenues(b)
$1,508 $795 $778 $1,370 $668 $367 $336 
Natural gas revenues
Residential$— $223 $278 $60 $— $60 $— 
Small commercial & industrial— 75 41 26 — 26 — 
Large commercial & industrial— 1 70 1 — 1 — 
Transportation— 8 — 4 — 4 — 
Other(c)
— 9 19 6 — 6 — 
Total natural gas revenues(d)
$— $316 $408 $97 $— $97 $— 
Total revenues from contracts with customers$1,508 $1,111 $1,186 $1,467 $668 $464 $336 
Other revenues
Revenues from alternative revenue programs$153 $(4)$65 $65 $39 $9 $17 
Other electric revenues(e)
6 4 4 4 3 1 — 
Other natural gas revenues(e)
— 1 2 — — — — 
Total other revenues$159 $1 $71 $69 $42 $10 $17 
Total revenues for reportable segments$1,667 $1,112 $1,257 $1,536 $710 $474 $353 
__________
(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, $3 million at ComEd
•$2 million, $1 million at PECO
•$1 million, $2 million at BGE
•$3 million, $3 million at PHI
•$2 million, $1 million at Pepco
•$2 million, $2 million at DPL
•$1 million, $1 million at ACE
(c)Includes revenues from off-system natural gas sales.
(d)Includes operating revenues from affiliates in 2024 and 2023 respectively of:
•less than $1 million, $1 million at PECO
•$1 million, $1 million at BGE
(e)Includes late payment charge revenues.

62


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

Note 5 — Accounts Receivable
5. Accounts Receivable (All Registrants)
Allowance for Credit Losses on Accounts Receivable
The following tables present the rollforward of Allowance for Credit Losses on Customer Accounts Receivable.
Three Months Ended March 31, 2024
ExelonComEdPECOBGEPHIPepcoDPLACE
Balance at December 31, 2023$317 $69 $95 $46 $107 $52 $19 $36 
Plus: Current period provision for expected credit losses(a)(b)(c)
79 22 23 15 19 12 3 4 
Less: Write-offs(d), net of recoveries(e)
50 9 11 9 21 12 5 4 
Balance at March 31, 2024$346 $82 $107 $52 $105 $52 $17 $36 
Three Months Ended March 31, 2023
ExelonComEdPECOBGEPHIPepcoDPLACE
Balance at December 31, 2022$327 $59 $105 $54 $109 $47 $21 $41 
Plus: Current period provision for expected credit losses
108 22 39 30 17 9 7 1 
Less: Write-offs, net of recoveries
46 7 14 11 14 7 2 5 
Balance at March 31, 2023$389 $74 $130 $73 $112 $49 $26 $37 
_________
(a)For PECO, the change in current period provision for expected credit losses is primarily a result of decreased receivable balances.
(b)For BGE and DPL, the change in the current period provision for expected credit losses is primarily a result of changes in customer risk profile.
(c)For ACE, the change in current period provision for expected credit losses is primarily a result of increased receivable balances.
(d)For Pepco and DPL, the change in write-offs is primarily attributable to unfavorable customer payment behavior.
(e)Recoveries were not material to the Registrants.

The following tables present the rollforward of Allowance for Credit Losses on Other Accounts Receivable.
Three Months Ended March 31, 2024
ExelonComEdPECOBGEPHIPepcoDPLACE
Balance at December 31, 2023$82 $17 $8 $7 $50 $28 $8 $14 
Plus: Current period provision for expected credit losses
18 3 5 2 8 7 — 1 
Less: Write-offs, net of recoveries(a)
4 1 — 2 1 — — 1 
Balance at March 31, 2024$96 $19 $13 $7 $57 $35 $8 $14 
Three Months Ended March 31, 2023
ExelonComEdPECOBGEPHIPepcoDPLACE
Balance at December 31, 2022$82 $17 $9 $10 $46 $25 $7 $14 
Plus: Current period provision for expected credit losses
14 2 3 4 5 3 1 1 
Less: Write-offs, net of recoveries
5 1 1 2 1 — — 1 
Balance at March 31, 2023$91 $18 $11 $12 $50 $28 $8 $14 
_________
(a)Recoveries were not material to the Registrants.


63


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 March 31, 2024 and December 31, 2023.
Unbilled customer revenues(a)
ExelonComEdPECOBGEPHIPepcoDPLACE
March 31, 2024$849 $344 $138 $171 $196 $96 $53 $47 
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
The Utility Registrants are 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 participate in the utilities' consolidated billing. The following table presents the total receivables purchased.
Total receivables purchased
ExelonComEdPECOBGEPHIPepcoDPLACE
Three months ended March 31, 2024$1,060 $235 $297 $219 $309 $194 $60 $55 
Three months ended March 31, 20231,108 240 309 245 314 210 56 48 
64


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

Note 6 — Income Taxes
6. Income Taxes (All Registrants)
Rate Reconciliation
The effective income tax rate from continuing operations varies from the U.S. federal statutory rate principally due to the following:
Three Months Ended March 31, 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
6.4 7.8 (0.6)6.3 6.4 6.2 6.2 7.1 
Plant basis differences(3.8)(0.9)(12.2)(1.2)(0.9)(1.3)(1.1)0.1 
Excess deferred tax amortization(14.7)(18.9)(2.3)(17.5)(6.8)(9.9)(5.4)(1.3)
Amortization of investment tax credit, including deferred taxes on basis difference(0.1)(0.1)— — (0.1)— (0.1)(0.1)
Tax credits(0.4)(0.3)— (0.4)(0.3)(0.3)(0.3)(0.3)
Other0.3 0.4 0.4 0.1 (0.1)— 0.2 1.0 
Effective income tax rate8.7 %9.0 %6.3 %8.3 %19.2 %15.7 %20.5 %27.5 %
Three Months Ended March 31, 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
6.0 7.9 (1.4)6.4 6.0 5.4 6.3 6.9 
Plant basis differences(4.0)(0.3)(15.2)(0.7)(1.8)(2.5)(1.0)(0.9)
Excess deferred tax amortization(6.3)(5.7)(2.4)(5.4)(7.0)(8.4)(8.8)(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)— (0.5)(0.4)(0.4)(0.4)(0.3)
Other
0.6 0.3 0.4 (0.1)0.3 0.5 (0.3)0.4 
Effective income tax rate16.7 %22.8 %2.4 %20.6 %18.0 %15.6 %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.
65


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

Note 6 — Income Taxes
Unrecognized Tax Benefits
Exelon, PHI and ACE have the following unrecognized tax benefits at March 31, 2024 and December 31, 2023. ComEd's, PECO's, BGE's, Pepco's, and DPL's amounts are not material.
Exelon(a)
PHIACE
March 31, 2024$95 $51 $15 
December 31, 202394 51 15 
__________
(a)At March 31, 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 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 March 31, 2024, Exelon recorded a payable of $183 million and $331 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 statue, 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.
7. Retirement Benefits (All Registrants)
Defined Benefit Pension and OPEB
66


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 table presents the components of Exelon's net periodic benefit costs, prior to capitalization, for the three months ended March 31, 2024 and 2023.
Pension BenefitsOPEB
Three Months Ended March 31,Three Months Ended March 31,
2024202320242023
Components of net periodic benefit cost
Service cost$42 $39 $7 $6 
Interest cost141 145 24 25 
Expected return on assets(184)(189)(21)(21)
Amortization of:
Prior service cost (credit)1 1 (2)(2)
Actuarial loss53 41 — — 
Net periodic benefit cost$53 $37 $8 $8 
The amounts below represent the Registrants' allocated pension and OPEB costs. For Exelon, the service cost component is included in Operating and maintenance expense and Property, plant, and equipment, net while the non-service cost components are included in Other, net and Regulatory assets. For 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.
67


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

Note 7 — Retirement Benefits
 Three Months Ended March 31,
Pension and OPEB Costs (Benefit)20242023
Exelon$61 $45 
ComEd17 6 
PECO— (3)
BGE15 14 
PHI23 24 
Pepco9 8 
DPL4 4 
ACE3 4 
Defined Contribution Savings Plan
The Registrants participate in a 401(k) defined contribution savings plan that is sponsored by Exelon. The plan is qualified under applicable sections of the IRC and allows employees to contribute a portion of their pre-tax and/or after-tax income in accordance with specified guidelines. All Registrants match a percentage of the employee contributions up to certain limits. The following table presents the employer contributions and employer matching contributions to the savings plan for the three months ended March 31, 2024 and 2023.
Three Months Ended March 31,
Savings Plan Employer Contributions20242023
Exelon$22 $21 
ComEd10 9 
PECO3 3 
BGE3 2 
PHI2 3 
Pepco1 1 
DPL1 1 
ACE— — 
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.
68


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.
GasNPNS
Fixed price contracts for between 10-20% of forecasted system supply requirements for flowing (i.e., non-storage) gas for the November through March period.
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 March 31, 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 March 31, 2024 would result in an immaterial impact to Exelon's Consolidated Net Income.
69


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

Note 8 — Derivative Financial Instruments
Below is a summary of the interest rate hedge balances at March 31, 2024 and December 31, 2023.
March 31, 2024
Derivatives Designated
as Hedging Instruments		Economic HedgesTotal
Other deferred debits (noncurrent assets)$2 $— $2 
Total derivative assets2 — 2 
Mark-to-market derivative liabilities (noncurrent liabilities)(1)— (1)
Total mark-to-market derivative liabilities(1)— (1)
Total mark-to-market derivative net assets$1 $— $1 
December 31, 2023
Derivatives Designated
as Hedging Instruments		Economic HedgesTotal
Other current assets$11 $1 $12 
Total derivative assets11 1 12 
Mark-to-market derivative liabilities (current liabilities)(24)(22)(46)
Total mark-to-market derivative liabilities(24)(22)(46)
Total mark-to-market derivative net assets$(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 first quarter of 2024, Exelon Corporate entered into $145 million notional of 5-year maturity floating-to-fixed swaps and $145 million notional of 10-year maturity floating-to-fixed swaps, for a total notional of $290 million designated as cash flow hedges. The following table provides the notional amounts outstanding held by Exelon at March 31, 2024 and December 31, 2023.
March 31, 2024December 31, 2023
5-year maturity floating-to-fixed swaps$145 $655 
10-year maturity floating-to-fixed swaps145 655 
Total$290 $1,310 
The related AOCI derivative gains for the three months ended March 31, 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.
70


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 are immaterial as of March 31, 2024.
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 $22 million for the final settlement amount, which was paid in January 2024.
Exelon Corporate recognized the following net pre-tax mark-to-market (losses) which are also recognized in Net fair value changes related to derivatives in Exelon's Consolidated Statements of Cash Flows.
Three Months Ended March 31, 2024Three Months Ended March 31, 2023
Income Statement LocationGain (Loss)Gain (Loss)
Electric operating revenues$— $1 
Interest expense— (1)
Total$— $— 
Credit Risk
The Registrants would be exposed to credit-related losses in the event of non-performance by counterparties on executed derivative instruments. The credit exposure of derivative contracts, before collateral, is represented by the fair value of contracts at the reporting date. The Utility Registrants have contracts to procure electric and natural gas supply that provide suppliers with a certain amount of unsecured credit. If the exposure on the supply contract exceeds the amount of unsecured credit, the suppliers may be required to post collateral. The net credit exposure is mitigated primarily by the ability to recover procurement costs through customer rates. The amount of cash collateral received from external counterparties remained relatively consistent as of March 31, 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 March 31, 2024 and December 31, 2023:

March 31, 2024December 31, 2023
Exelon$156 $148 
ComEd154 146 
PECO(a)
— — 
BGE1 1 
PHI1 1 
Pepco(b)
— 1 
DPL1 — 
ACE1 — 
__________
71


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

Note 8 — Derivative Financial Instruments
(a)PECO had less than one million in cash collateral held with external parties at March 31, 2024 and December 31, 2023.
(b)Pepco had less than one million in cash collateral held with external parties at March 31, 2024.
The Utility Registrants’ electric supply procurement contracts do not contain provisions that would require them to post collateral. PECO’s, BGE’s, and DPL’s natural gas procurement contracts contain provisions that could require PECO, BGE, and DPL to post collateral in the form of cash or credit support, which vary by contract and counterparty, with thresholds contingent upon PECO’s, BGE's, and DPL’s credit rating. As of March 31, 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 March 31, 2024, they could have been required to post collateral to their counterparties of $27 million, $47 million, and $12 million, respectively.
9. Debt and Credit Agreements (All Registrants)
Short-Term Borrowings
Exelon Corporate, ComEd, and BGE meet their short-term liquidity requirements primarily through the issuance of commercial paper. PECO meets its short-term liquidity requirements primarily through the issuance of commercial paper and borrowings from the Exelon intercompany money pool. Pepco, DPL, and ACE meet their short-term liquidity requirements primarily through the issuance of commercial paper and borrowings from the PHI intercompany money pool. PHI Corporate meets its short-term liquidity requirements primarily through the issuance of short-term notes and borrowings from the Exelon intercompany money pool. The Registrants may use their respective credit facilities for general corporate purposes, including meeting short-term funding requirements and the issuance of letters of credit.
Commercial Paper
The following table reflects the Registrants' commercial paper programs supported by the revolving credit agreements at March 31, 2024 and December 31, 2023.
Outstanding Commercial
Paper at		Average Interest Rate on
Commercial Paper Borrowings at
Commercial Paper IssuerMarch 31, 2024December 31, 2023March 31, 2024December 31, 2023
Exelon(a)
$1,307 $1,624 5.53 %5.58 %
ComEd$330 $202 5.43 %5.53 %
PECO$— $165 — %5.57 %
BGE$406 $336 5.57 %5.59 %
PHI(b)
$— $394 — %5.60 %
Pepco$— $132 — %5.59 %
DPL$— $63 — %5.60 %
ACE$— $199 — %5.60 %
72


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

Note 9 — Debt and Credit Agreements
__________
(a)Exelon Corporate had $571 million and $527 million in outstanding commercial paper borrowings at March 31, 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 March 31, 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.
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 $400 million term loan through the expiration date of June 28, 2024. Interest on the extended loan will be based on a variable rate equal to SOFR plus 1.00%. The original proceeds from the loan were used to repay outstanding commercial paper obligations and for general corporate purposes. The loan agreement is reflected in Exelon's and ComEd's Consolidated Balance Sheets within Short-term borrowings.

73


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

Note 9 — Debt and Credit Agreements
Long-Term Debt
Issuance of Long-Term Debt
During the three months ended March 31, 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.
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 March 31, 2024, the Registrants are in compliance with debt covenants.
10. Fair Value of Financial Assets and Liabilities (All Registrants)
Exelon measures and classifies fair value measurements in accordance with the hierarchy as defined by GAAP. The hierarchy prioritizes the inputs to valuation techniques used to measure fair value into three levels as follows:
•Level 1 — quoted prices (unadjusted) in active markets for identical assets or liabilities that the Registrants have the ability to liquidate as of the reporting date.
•Level 2 — inputs other than quoted prices included within Level 1 that are directly observable for the asset or liability or indirectly observable through corroboration with observable market data.
•Level 3 — unobservable inputs, such as internally developed pricing models or third-party valuations for the asset or liability due to little or no market activity for the asset or liability.
Exelon’s valuation techniques used to measure the fair value of the assets and liabilities shown in the tables below are in accordance with the policies discussed in Note 17 — Fair Value of Financial Assets and Liabilities of the 2023 Form 10-K.
74


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

Note 10 — Fair Value of Financial Assets and Liabilities
Fair Value of Financial Liabilities Recorded at Amortized Cost
The following tables present the carrying amounts and fair values of the Registrants’ short-term liabilities, long-term debt, and trust preferred securities (long-term debt to financing trusts or junior subordinated debentures) as of March 31, 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.
March 31, 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$42,774 $— $34,426 $3,613 $38,039 $41,095 $— $33,804 $3,442 $37,246 
ComEd11,487 — 9,910 — 9,910 11,486 — 10,210 — 10,210 
PECO5,134 — 4,391 — 4,391 5,134 — 4,562 — 4,562 
BGE4,602 — 4,015 — 4,015 4,602 — 4,145 — 4,145 
PHI9,153 — 4,356 3,613 7,969 8,648 — 4,160 3,442 7,602 
Pepco4,359 — 2,549 1,570 4,119 4,096 — 2,311 1,600 3,911 
DPL2,254 — 668 1,274 1,942 2,080 — 694 1,134 1,828 
ACE1,909 — 929 768 1,697 1,833 — 939 708 1,647 
Long-Term Debt to Financing Trusts
Exelon$390 $— $— $392 $392 $390 $— $— $390 $390 
ComEd205 — — 209 209 205 — — 208 208 
PECO184 — — 183 183 184 — — 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.

75


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

Note 10 — Fair Value of Financial Assets and Liabilities
Recurring Fair Value Measurements
The following tables present assets and liabilities measured and recorded at fair value in the Registrants' Consolidated Balance Sheets on a recurring basis and their level within the fair value hierarchy at March 31, 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 March 31, 2024At December 31, 2023
Level 1Level 2Level 3TotalLevel 1 Level 2Level 3Total
Assets
Cash equivalents(a)
$883 $— $— $883 $618 $— $— $618 
Rabbi trust investments
Cash equivalents68 — — 68 67 — — 67 
Mutual funds57 — — 57 53 — — 53 
Fixed income— 7 — 7 — 7 — 7 
Life insurance contracts — 65 43 108 — 61 43 104 
Rabbi trust investments subtotal125 72 43 240 120 68 43 231 
Interest rate derivative assets
Derivatives designated as hedging instruments— 2 — 2 — 11 — 11 
Economic hedges— — — — — 1 — 1 
Interest rate derivative assets subtotal— 2 — 2 — 12 — 12 
Total assets1,008 74 43 1,125 738 80 43 861 
Liabilities
Commodity derivative liabilities— — (108)(108)— — (133)(133)
Interest rate derivative liabilities
Derivatives designated as hedging instruments— (1)— (1)— (24)— (24)
Economic hedges— — — — — (22)— (22)
Interest rate derivative liabilities subtotal — (1)— (1)— (46)— (46)
Deferred compensation obligation— (75)— (75)— (75)— (75)
Total liabilities— (76)(108)(184)— (121)(133)(254)
Total net assets (liabilities)$1,008 $(2)$(65)$941 $738 $(41)$(90)$607 
__________    
(a)Exelon excludes cash of $271 million and $334 million at March 31, 2024 and December 31, 2023, respectively, and restricted cash of $154 million and $149 million at March 31, 2024 and December 31, 2023, respectively, and includes long-term restricted cash of $99 million and $174 million at March 31, 2024 and December 31, 2023, respectively, which is reported in Other deferred debits and other assets in the Consolidated Balance Sheets.

76


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

Note 10 — Fair Value of Financial Assets and Liabilities
ComEd, PECO, and BGE
ComEdPECOBGE
At March 31, 2024Level 1Level 2Level 3TotalLevel 1Level 2Level 3TotalLevel 1Level 2Level 3Total
Assets
Cash equivalents(a)
$398 $— $— $398 $14 $— $— $14 $— $— $— $— 
Rabbi trust investments
Mutual funds— — — — 10 — — 10 10 — — 10 
Life insurance contracts — — — — — 19 — 19 — — — — 
Rabbi trust investments subtotal— — — — 10 19 — 29 10 — — 10 
Total assets398 — — 398 24 19 — 43 10 — — 10 
Liabilities
Commodity derivative liabilities(b)
— — (108)(108)— — — — — — — — 
Deferred compensation obligation— (9)— (9)— (9)— (9)— (4)— (4)
Total liabilities— (9)(108)(117)— (9)— (9)— (4)— (4)
Total net assets (liabilities)$398 $(9)$(108)$281 $24 $10 $— $34 $10 $(4)$— $6 
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 $75 million and $86 million at March 31, 2024 and December 31, 2023, respectively, and restricted cash of $154 million and $147 million at March 31, 2024 and December 31, 2023, respectively. Additionally, ComEd includes long-term restricted cash of $99 million and $174 million at March 31, 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 $34 million and $42 million at March 31, 2024 and December 31, 2023, respectively. BGE excludes cash of $27 million and $47 million at March 31, 2024 and December 31, 2023, respectively, and restricted cash of zero and $1 million at March 31, 2024 and December 31, 2023, respectively.
(b)The Level 3 balance consists of the current and noncurrent liability of $29 million and $79 million, respectively, at March 31, 2024 and $27 million and $106 million, respectively, at December 31, 2023 related to floating-to-fixed energy swap contracts with unaffiliated suppliers.

77


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

Note 10 — Fair Value of Financial Assets and Liabilities
PHI, Pepco, DPL, and ACE
At March 31, 2024At December 31, 2023
PHI Level 1Level 2Level 3TotalLevel 1Level 2Level 3Total
Assets
Cash equivalents(a)
$438 $— $— $438 $107 $— $— $107 
Rabbi trust investments
Cash equivalents65 — — 65 64 — — 64 
Mutual funds9 — — 9 9 — — 9 
Fixed income— 7 — 7 — 7 — 7 
Life insurance contracts— 22 41 63 — 21 41 62 
Rabbi trust investments subtotal74 29 41 144 73 28 41 142 
Total assets512 29 41 582 180 28 41 249 
Liabilities
Deferred compensation obligation— (12)— (12)— (13)— (13)
Total liabilities— (12)— (12)— (13)— (13)
Total net assets$512 $17 $41 $570 $180 $15 $41 $236 
PepcoDPLACE
At March 31, 2024Level 1Level 2Level 3TotalLevel 1Level 2Level 3TotalLevel 1Level 2Level 3Total
Assets
Cash equivalents(a)
$192 $— $— $192 $241 $— $— $241 $— $— $— $— 
Rabbi trust investments
Cash equivalents64 — — 64 — — — — — — — — 
Life insurance contracts— 22 41 63 — — — — — — — — 
Rabbi trust investments subtotal64 22 41 127 — — — — — — — — 
Total assets256 22 41 319 241 — — 241 — — — — 
Liabilities
Deferred compensation obligation— (1)— (1)— — — — — — — — 
Total liabilities— (1)— (1)— — — — — — — — 
Total net assets$256 $21 $41 $318 $241 $— $— $241 $— $— $— $— 
78


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

Note 10 — Fair Value of Financial Assets and Liabilities
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 $89 million and $96 million at March 31, 2024 and December 31, 2023, respectively, and restricted cash of zero and $1 million at March 31, 2024 and December 31, 2023, respectively. Pepco excludes cash of $28 million and $48 million at March 31, 2024 and December 31, 2023, respectively, and restricted cash of zero and $1 million at March 31, 2024 and December 31, 2023, respectively. DPL excludes cash of $29 million and $15 million at March 31, 2024 and December 31, 2023, respectively. ACE excludes cash of $27 million and $21 million at March 31, 2024 and December 31, 2023, respectively.

79


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

Note 10 — Fair Value of Financial Assets and Liabilities
Reconciliation of Level 3 Assets and Liabilities
The following tables present the fair value reconciliation of Level 3 assets and liabilities measured at fair value on a recurring basis during the three months ended March 31, 2024 and 2023:
ExelonComEdPHI and Pepco
Three Months Ended March 31, 2024Total Commodity
Derivatives		Life Insurance Contracts
Balance at December 31, 2023$(90)$(133)$41 
Total realized / unrealized gains (losses)
Included in net income(a)
— — — 
Included in regulatory assets/liabilities25 25 
(b)
— 
Balance at March 31, 2024$(65)$(108)
(c)
$41 
The amount of total gains included in income attributed to the change in unrealized gains related to assets and liabilities at March 31, 2024$— $— $— 

ExelonComEdPHI and Pepco
Three Months Ended March 31, 2023Total Commodity
Derivatives		Life Insurance Contracts
Balance at December 31, 2022$(44)$(84)$40 
Total realized / unrealized gains (losses)
Included in net income(a)
1 — 1 
Included in regulatory assets/liabilities(14)(14)
(b)
— 
Balance at March 31, 2023$(57)$(98)$41 
The amount of total gains included in income attributed to the change in unrealized gain related to assets and liabilities at March 31, 2023$1 $— $1 
__________
(a)Classified in Operating and maintenance expense in the Consolidated Statements of Operations and Comprehensive Income.
(b)Includes $13 million of increases in fair value and an increase for realized gains due to settlements of $12 million recorded in Purchased power expense associated with floating-to-fixed energy swap contracts with unaffiliated suppliers for the three months ended March 31, 2024. Includes $25 million of decreases in fair value and an increase for realized losses due to settlements of $11 million recorded in Purchased power expense associated with floating-to-fixed energy swap contracts with unaffiliated suppliers for the three months ended March 31, 2023.
(c)The balance of the current and noncurrent asset was effectively zero as of March 31, 2024. The balance consists of a current and noncurrent liability of $29 million and $79 million, respectively, as of March 31, 2024.
Commodity Derivatives (Exelon and ComEd)
The table below discloses the significant unobservable inputs to the forward curve used to value mark-to-market derivatives.
Type of tradeFair Value at March 31, 2024Fair Value at December 31, 2023Valuation
Technique		Unobservable
Input		2024 Range & Arithmetic Average2023 Range & Arithmetic Average
Commodity derivatives$(108)$(133)Discounted
Cash Flow
Forward power price(a)
$22.68-$84.62$46.94$30.27-$73.71$43.35
________
(a)An increase to the forward power price would increase the fair value.

80


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

Note 11 — Commitments and Contingencies
11. Commitments and Contingencies (All Registrants)
The following is an update to the current status of commitments and contingencies set forth in Note 18 — Commitments and Contingencies of the 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 March 31, 2024:
DescriptionExelon PHI Pepco DPLACE
Total commitments$513 $320 $120 $89 $111 
Remaining commitments(a)
35 31 28 2 1 
__________
(a)Remaining commitments extend through 2026 and include escrow funds, charitable contributions, and rate credits.

81


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

Note 11 — Commitments and Contingencies
Commercial Commitments (All Registrants). The Registrants’ commercial commitments at March 31, 2024, representing commitments potentially triggered by future events were as follows:
Expiration within
Total202420252026202720282029 and beyond
Exelon
Letters of credit(a)
$32 $24 $8 $— $— $— $— 
Surety bonds(b)
194 181 13 — — — — 
Financing trust guarantees(c)
378 — — — — 78 300 
Guaranteed lease residual values(d)
25 — 3 5 4 6 7 
Total commercial commitments $629 $205 $24 $5 $4 $84 $307 
ComEd
Letters of credit(a)
$17 $14 $3 $— $— $— $— 
Surety bonds(b)
36 34 2 — — — — 
Financing trust guarantees(c)
200 — — — — — 200 
Total commercial commitments $253 $48 $5 $— $— $— $200 
PECO
Letters of credit(a)
$3 $— $3 $— $— $— $— 
Surety bonds(b)
2 1 1 — — — — 
Financing trust guarantees(c)
178 — — — — 78 100 
Total commercial commitments $183 $1 $4 $— $— $78 $100 
BGE
Letters of credit(a)
$7 $7 $— $— $— $— $— 
Surety bonds(b)
3 2 1 — — — — 
Total commercial commitments $10 $9 $1 $— $— $— $— 
PHI
Surety bonds(b)
$96 $91 $5 $— $— $— $— 
Guaranteed lease residual values(d)
25 — 3 5 4 6 7 
Total commercial commitments $121 $91 $8 $5 $4 $6 $7 
Pepco
Surety bonds(a)
$85 $84 $1 $— $— $— $— 
Guaranteed lease residual values(d)
8 — 1 2 1 2 2 
Total commercial commitments $93 $84 $2 $2 $1 $2 $2 
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 $4 $1 $— $— $— $— 
Guaranteed lease residual values(d)
7 — 1 1 1 2 2 
Total commercial commitments $12 $4 $2 $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 that 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 $57 million guaranteed by Exelon and PHI, of which $19 million, $22 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.
83


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

Note 11 — Commitments and Contingencies
At March 31, 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:
March 31, 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$413 $328 $428 $338 
ComEd293 292 303 302 
PECO27 25 27 25 
BGE14 11 14 11 
PHI76 — 81 — 
Pepco74 — 79 — 
DPL1 — 1 — 
ACE1 — 1 — 
Benning Road Site (Exelon, PHI, and Pepco). In September 2010, PHI received a letter from 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 DOEE approved on February 3, 2020. The Pepco Entities are completing a FS to evaluate possible remedial alternatives for submission to DOEE. In October 2022, 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 DOEE on March 15, 2024, and the waterside FS is scheduled to be complete and approved by DOEE by the end of the fourth quarter of 2024. Following the completion of each FS, 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, 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 DOEE for the landslide and water 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, 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 river-wide RI incorporated the results of the river sampling performed by the Pepco Entities as part of the Benning RI/FS, as well as similar sampling efforts
84


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

Note 11 — Commitments and Contingencies
conducted by owners of other sites adjacent to this segment of the river and supplemental river sampling conducted by DOEE’s contractor.
On September 30, 2020, 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 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 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 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 river-wide 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 contribution 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 (ARSP) 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 Consent Order was lodged with the District of Columbia Superior Court in January 2024. 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.
85


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. On September 9, 2021, the federal court granted ComEd and Exelon’s motion to dismiss and dismissed plaintiffs’ federal law claim with prejudice. The federal court also dismissed the related state law claims made by the federal plaintiffs on jurisdictional grounds. Plaintiffs appealed dismissal of the federal law claim to the Seventh Circuit Court of Appeals, and refiled their state law claims in state court. On August 22, 2022, the Seventh Circuit affirmed the dismissal of the consolidated federal cases in their entirety. The time to further appeal has passed and the Seventh Circuit’s decision 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.
86


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 included in ComEd's transmission formula rate update proceeding, filed on May 12, 2023. The filed transmission rate, inclusive of the FERC jurisdictional DPA refund, will appear on ComEd retail customers' bills for the June 2023 through May 2024 monthly billing periods, in the line designated as "Transmission Services Charge." The customer refund will not be recovered in rates or charged to customers and ComEd will not seek or accept reimbursement or indemnification from any source other than Exelon. An accrual for the amount of the customer refund has been recorded in Regulatory assets in Exelon’s and ComEd’s Consolidated Balance Sheets as of March 31, 2024.
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
87


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

Note 11 — Commitments and Contingencies
incurred and subject to reasonable estimation. Management is sometimes unable to estimate an amount or range of reasonably possible loss, particularly where (1) the damages sought are indeterminate, (2) the proceedings are in the early stages, or (3) the matters involve novel or unsettled legal theories. In such cases, there is considerable uncertainty regarding the timing or ultimate resolution of such matters, including a possible eventual loss.
12. Shareholders' Equity (Exelon)
At-the-Market Program
On August 4, 2022, Exelon executed an equity distribution agreement (“Equity Distribution Agreement”), with certain sales agents and forward sellers and certain forward purchasers, establishing an ATM equity distribution program under which it may offer and sell shares of its Common stock, having an aggregate gross sales price of up to $1.0 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 March 31, 2024, $858 million of Common stock remained available for sale pursuant to the ATM program.
13. Changes in Accumulated Other Comprehensive Income (Loss) (Exelon)
The following table presents changes in Exelon's AOCI, net of tax, by component:
Three Months Ended March 31, 2024 Cash Flow Hedges
Pension and Non-Pension Postretirement Benefit Plan Items(a)
Total
Balance at December 31, 2023$(3)$(723)$(726)
OCI before reclassifications34 (24)10 
Amounts reclassified from AOCI(1)5 4 
Net current-period OCI$33 $(19)$14 
Balance at March 31, 2024$30 $(742)$(712)

Three Months Ended March 31, 2023Cash Flow Hedges
Pension and Non-Pension Postretirement Benefit Plan Items(a)
Total
Balance at December 31, 2022$2 $(640)$(638)
OCI before reclassifications6 (10)(4)
Amounts reclassified from AOCI— 3 3 
Net current-period OCI$6 $(7)$(1)
Balance at March 31, 2023$8 $(647)$(639)
__________
(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.
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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)

Note 13 — Changes in Accumulated Other Comprehensive Income
The following table presents Income tax benefit (expense) allocated to each component of Exelon's Other comprehensive income (loss):
Three Months Ended March 31,
20242023
Pension and non-pension postretirement benefit plans:
Actuarial losses reclassified to periodic benefit cost$(2)$(1)
Pension and non-pension postretirement benefit plans valuation adjustments8 3 
Unrealized gains on cash flow hedges(10)(1)
14. Supplemental Financial Information (All Registrants)
Supplemental Statement of Operations Information
The following tables provide additional information about material items recorded in the Registrants' Consolidated Statements of Operations and Comprehensive Income:
Taxes other than income taxes
ExelonComEdPECOBGEPHIPepcoDPLACE
Three Months Ended March 31, 2024
Utility taxes(a)
$229 $75 $41 $31 $82 $74 $8 $— 
Property105 9 4 53 38 26 11 1 
Payroll34 9 5 5 7 2 1 1 
Three Months Ended March 31, 2023
Utility taxes(a)
$220 $74 $40 $29 $77 $68 $8 $1 
Property99 10 4 50 35 24 11 — 
Payroll32 7 5 5 7 2 1 1 
_________
(a)The Registrants' utility taxes represent municipal and state utility taxes and gross receipts taxes related to their operating revenues. The offsetting collection of utility taxes from customers is recorded in revenues in the Registrants’ Consolidated Statements of Operations and Comprehensive Income.
Other, net
ExelonComEdPECOBGE PHIPepcoDPLACE
Three Months Ended March 31, 2024
AFUDC — Equity$40 $10 $8 $7 $15 $12 $3 $— 
Non-service net periodic benefit cost(7)— — — — — — — 
Three Months Ended March 31, 2023
AFUDC — Equity$38 $10 $6 $3 $19 $14 $2 $3 
Non-service net periodic benefit cost(1)— — — — — — — 
Supplemental Cash Flow Information
The following tables provide additional information about material items recorded in the Registrants' Consolidated Statements of Cash Flows.
89


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

Note 14 — Supplemental Financial Information
Depreciation, amortization, and accretion
ExelonComEdPECOBGEPHIPepcoDPLACE
Three Months Ended March 31, 2024
Property, plant, and equipment(a)
$711 $284 $101 $122 $190 $81 $52 $53 
Amortization of regulatory assets and liabilities, net(a)
166 78 3 28 56 26 9 21 
Amortization of intangible assets, net(a)
2 — — — — — — — 
ARO accretion(b)
1 — — — — — — — 
Total depreciation, amortization and accretion$880 $362 $104 $150 $246 $107 $61 $74 
Three Months Ended March 31, 2023
Property, plant, and equipment(a)
$680 $267 $95 $124 $180 $76 $51 $47 
Amortization of regulatory assets and liabilities, net(a)
178 71 3 43 61 32 9 20 
Amortization of intangible assets, net(a)
2 — — — — — — — 
Total depreciation and amortization$860 $338 $98 $167 $241 $108 $60 $67 
__________
(a)Included in Depreciation and amortization expense in the Registrants' Consolidated Statements of Operations and Comprehensive Income.
(b)Included in Operating and maintenance expense in Exelon's Consolidated Statements of Operations and Comprehensive Income.
Other non-cash operating activities
ExelonComEdPECOBGEPHIPepcoDPLACE
Three Months Ended March 31, 2024
Pension and OPEB costs$61 $17 $— $15 $23 $9 $4 $3 
Allowance for credit losses63 2 27 12 22 16 3 3 
True-up adjustments to decoupling mechanisms and formula rates(a)
(91)(19)2 (43)(31)(29)4 (6)
Amortization of operating ROU asset9 — — 2 6 1 2 1 
AFUDC — Equity(40)(10)(8)(7)(15)(12)(3)— 
Three Months Ended March 31, 2023
Pension and OPEB costs (benefit)$45 $6 $(3)$14 $24 $8 $4 $4 
Allowance for credit losses70 — 37 18 15 7 5 3 
True-up adjustments to decoupling mechanisms and formula rates(a)
(282)(153)4 (65)(68)(39)(11)(18)
Long-term incentive plan2 — — — — — — — 
Amortization of operating ROU asset10 1 — 1 7 1 2 1 
Change in environmental liabilities25 — — — 25 25 — — 
AFUDC — Equity(38)(10)(6)(3)(19)(14)(2)(3)
__________
90


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

Note 14 — Supplemental Financial Information
(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 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 March 31, 2024
Cash and cash equivalents$720 $100 $39 $27 $504 $198 $269 $27 
Restricted cash and cash equivalents489 428 9 — 23 22 1 — 
Restricted cash included in Other deferred debits and other assets99 99 — — — — — — 
Total cash, restricted cash, and cash equivalents$1,308 $627 $48 $27 $527 $220 $270 $27 
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 March 31, 2023
Cash and cash equivalents$522 $75 $27 $20 $367 $126 $142 $71 
Restricted cash and cash equivalents381 323 9 1 29 27 1 — 
Restricted cash included in Other deferred debits and other assets180 180 — — — — — — 
Total cash, restricted cash, and cash equivalents$1,083 $578 $36 $21 $396 $153 $143 $71 
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.
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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)

Note 14 — Supplemental Financial Information
Accrued expenses
ExelonComEdPECOBGEPHIPepcoDPLACE
Balance at March 31, 2024
Compensation-related accruals(a)
$349 $102 $46 $46 $59 $19 $12 $8 
Taxes accrued237 214 93 140 170 135 42 16 
Interest accrued408 80 54 59 87 40 29 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 March 31,Three Months Ended March 31,
2024202320242023
Exelon
   BSC$158 $175 
   PHISCO29 24 
ComEd
   BSC$100 $83 71 81 
PECO
   BSC58 51 29 30 
BGE
   BSC59 54 24 24 
PHI
   BSC50 42 34 40 
   PHISCO— — 29 24 
Pepco
   BSC31 27 17 14 
   PHISCO33 30 12 11 
DPL
   BSC19 17 12 10 
   PHISCO25 24 9 7 
ACE
   BSC16 14 5 14 
   PHISCO23 22 8 6 
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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)

Note 15 — Related Party Transactions

Current Receivables from/Payables to Affiliates
The following tables present current Receivables from affiliates and current Payables to affiliates:
March 31, 2024
Receivables from affiliates:
Payables to affiliates:ComEdPECOBGEPepcoDPLACEBSCPHISCOOtherTotal
ComEd$— $— $— $— $— $66 $— $6 $72 
PECO$— — — — — 33 — 8 41 
BGE— — — — — 35 — 2 37 
PHI— — — — — — 6 — 11 17 
Pepco— — — — — 19 17 1 37 
DPL— — — — — 13 12 — 25 
ACE— — — — — 10 12 — 22 
Other3 — — 1 — 4 — 8 
Total$3 $— $— $1 $— $4 $182 $41 $28 $259 
December 31, 2023
Receivables from affiliates:
Payables to affiliates:ComEdPECOBGEPepcoDPLACEBSCPHISCOOtherTotal
ComEd$— $— $— $— $— $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:
March 31, 2024December 31, 2023
ExelonComEdPECOExelonComEdPECO
ComEd Financing III$206 $205 $— $206 $205 $— 
PECO Trust III81 — 81 81 — 81 
PECO Trust IV103 — 103 103 — 103 
Total$390 $205 $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 months ended March 31, 2024 compared to the same period in 2023. For additional information regarding the financial results for the three months ended March 31, 2024 and 2023, see the discussions of Results of Operations by Registrant.
Three Months Ended March 31,(Unfavorable) Favorable Variance
20242023
Exelon$658 $669 $(11)
ComEd193 241 (48)
PECO149 166 (17)
BGE264 200 64 
PHI168 155 13 
Pepco75 65 10 
DPL66 60 6 
ACE29 33 (4)
Other(a)
(116)(93)(23)
__________
(a)Other primarily includes eliminating and consolidating adjustments, Exelon’s corporate operations, shared service entities, and other financing and investment activities.
Three Months Ended March 31, 2024 Compared to Three Months Ended March 31, 2023. Net income attributable to common shareholders decreased by $11 million and diluted earnings per average common share decreased to $0.66 in 2024 from $0.67 in 2023 primarily due to:
•Higher interest expense at PECO, PHI, and Exelon Corporate;
•Higher storm costs at PECO and BGE;
•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.
The decreases were partially offset by:
94



•The favorable impacts of rate increases at BGE and PHI; and
•Less unfavorable weather impacts at PECO.
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.
The following table provides a reconciliation between GAAP Net income attributable to common shareholders and Adjusted (non-GAAP) operating earnings for the three months ended March 31, 2024 compared to the same period in 2023:
Three Months Ended March 31,
20242023
(In millions, except per share data)Earnings per
Diluted Share		Earnings per
Diluted Share
Net income attributable to common shareholders$658 $0.66 $669 $0.67 
Mark-to-market impact of economic hedging activities (net of taxes of $0)
— — (1)— 
Change in environmental liabilities (net of taxes of $7)
— — 18 0.02 
Separation costs (net of taxes of $0)(a)
— — (1)— 
Change in FERC audit liability (net of taxes of $9 and $4, respectively )
27 0.03 11 0.01 
Adjusted (non-GAAP) operating earnings$685 $0.68 $696 $0.70 
__________
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.
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.
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.
95



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
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, 2024Electric$670 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 %Third quarter of 2024
Pepco - MarylandMay 16, 2023 (amended February 23, 2024)Electric$186 10.50 %Second quarter of 2024
Transmission Formula Rates
For 2024, the following total increases/(decreases) were included in ComEd's and BGE'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 %
BGE$42 $13 $53 7.47 %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. Based on the preliminary findings and the ongoing settlement process, ComEd determined that a loss was probable and recorded its regulatory liability to reflect its best estimate of that loss. The final outcome and resolution of any contested audit issues as well as a reasonable estimate of potential future losses cannot be accurately estimated at this stage; however, the final resolution of these matters could result in recognition of future losses, above the amounts currently accrued, that could be material to the Exelon and ComEd financial statements.
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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
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link grid communications systems and operations to increase resilience and reduce power outages and threats, 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 January 2024, Exelon, ComEd, BGE, PHI, Pepco, DPL, and ACE submitted seven concept papers in response to the second round of the GRIP program. The concept papers were focused on improving the resilience of the electric grid and deployment of technologies to enhance grid flexibility and deliver benefits to customers and communities across the Exelon footprint. Six of the seven concept papers submitted received notifications of encouragement to submit a full application. Exelon, BGE, PHI, Pepco, DPL, and ACE are in the process of evaluating the development and submission of final applications. Formal applications for Topic Area 1 (Grid Resilience) and Topic Area 3 (Grid Innovation) were due on April 17, 2024. ACE in coordination with the NJBPU Division of Clean Energy submitted an application for Topic Area 3 to expand DER hosting capacity through integrated grid enhancing technologies. Formal applications for Topic Area 2 (Smart Grid Grants) are due on May 22, 2024. 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.
Critical Accounting Policies and Estimates
Management of each of the Registrants makes a number of significant estimates, assumptions, and judgments in the preparation of its financial statements. As of March 31, 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
March 31,		Favorable (Unfavorable) Variance
20242023
Operating revenues$2,095 $1,667 $428 
Operating expenses
Purchased power907 488 (419)
Operating and maintenance418 337 (81)
Depreciation and amortization362 338 (24)
Taxes other than income taxes94 93 (1)
Total operating expenses1,781 1,256 (525)
Operating income314 411 (97)
Other income and (deductions)
Interest expense, net(122)(117)(5)
Other, net20 18 2 
Total other income and (deductions)(102)(99)(3)
Income before income taxes212 312 (100)
Income taxes 19 71 52 
Net income $193 $241 $(48)
Three Months Ended March 31, 2024 Compared to Three Months Ended March 31, 2023. Net income decreased by $48 million as compared to the same period in 2023, primarily due to decreases in electric distribution earnings reflecting lower allowed ROE.
The changes in Operating revenues consisted of the following:
Three Months Ended
March 31, 2024
Increase (Decrease)
Distribution$34 
Transmission2 
Energy efficiency20 
Other(5)
51 
Regulatory required programs 377 
Total increase$428 
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 that the ICC determines are prudently and reasonably incurred with certain limitations for the MRP reconciliations. Electric distribution revenue varies from year to year based upon fluctuations in the underlying costs, (e.g., severe weather and storm restoration), investments being recovered, and allowed ROE. Electric distribution revenue increased for the three months ended March 31, 2024 as compared to the same period in 2023, due to higher fully recoverable costs offset by lower allowed ROE.
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
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ComEd
load, which is updated annually in January based on the prior calendar year. Transmission revenue increased for the three months ended March 31, 2024 as compared to the same period in 2023, primarily due to higher peak load.
Energy Efficiency Revenue. Energy efficiency revenues are under a performance-based formula rate, which requires an annual reconciliation of the revenue requirement in effect to the actual costs that 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 revenue increased for the three months ended March 31, 2024 as compared to the same period 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 revenue decreased for the three months ended March 31, 2024 as compared to the same period in 2023, which primarily reflects less mutual assistance revenues associated with storm restoration efforts.
Regulatory Required Programs represents revenues collected under approved riders to recover costs incurred for regulatory programs such as recoveries under the credit loss expense tariff, environmental costs associated with MGP sites, ETAC, and costs related to electricity, ZEC, CMC, and REC procurement. ETAC is a retail customer surcharge collected and remitted to an Illinois state agency for programs to support clean energy jobs and training. The riders are designed to provide full and current cost recovery. The costs of these programs are included in Purchased power expense, Operating and maintenance expense, Depreciation and amortization expense and Taxes other than income. 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 of $419 million for the three months ended March 31, 2024 compared to the same period in 2023, in Purchased power expense is offset in Operating revenues as part of regulatory required programs.
The changes in Operating and maintenance expense consisted of the following:
Three Months Ended
March 31, 2024
Increase
Labor, other benefits, contracting and materials$45 
BSC costs17 
Storm-related costs6 
Pension and non-pension postretirement benefits expense6 
Other3 
77 
Regulatory required programs(a)
4 
Total increase$81 
__________
(a)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.
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ComEd
The changes in Depreciation and amortization expense consisted of the following:
Three Months Ended
March 31, 2024
Increase
Depreciation and amortization(a)
$16 
Regulatory asset amortization(b)
8 
Total increase$24 
__________
(a)Reflects ongoing capital expenditures.
(b)Includes amortization of ComEd's energy efficiency formula rate regulatory asset.
Effective income tax rates were 9.0% and 22.8% for the three months ended March 31, 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
March 31,		(Unfavorable) Favorable Variance
20242023
Operating revenues$1,054 $1,112 $(58)
Operating expenses
Purchased power and fuel403 484 81 
Operating and maintenance293 270 (23)
Depreciation and amortization104 98 (6)
Taxes other than income taxes51 50 (1)
Total operating expenses851 902 51 
Gain on sales of assets 2 — 2 
Operating income205 210 (5)
Other income and (deductions)
Interest expense, net(55)(48)(7)
Other, net9 8 1 
Total other income and (deductions)(46)(40)(6)
Income before income taxes159 170 (11)
Income taxes10 4 (6)
Net income$149 $166 $(17)
Three Months Ended March 31, 2024 Compared to Three Months Ended March 31, 2023. Net income decreased by $17 million, due to an increase in operating expenses as a result of higher storm costs and an increase in interest 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
March 31, 2024
Increase (Decrease)
ElectricGasTotal
Weather$12 $12 $24 
Volume(2)(2)(4)
Pricing1 3 4 
Transmission8 — 8 
Other(4)(3)(7)
15 10 25 
Regulatory required programs(30)(53)(83)
Total decrease$(15)$(43)$(58)
Weather. The demand for electricity and natural gas is affected by weather conditions. With respect to the electric business, very warm weather in summer months and, with respect to the electric and natural gas businesses, very cold weather in winter months are referred to as “favorable weather conditions” because these weather conditions result in increased deliveries of electricity and natural gas. Conversely, mild weather reduces demand. During the three months ended March 31, 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.
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
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PECO
PECO’s service territory for the three months ended March 31, 2024 compared to the same period in 2023 and normal weather consisted of the following:
Three Months Ended March 31,% Change
PECO Service Territory20242023Normal2024 vs. 20232024 vs. Normal
Heating Degree-Days2,089 1,8882,41010.6 %(13.3)%
Cooling Degree-Days— —1N/A(100.0)%
Volume. Electric volume, exclusive of the effects of weather, for the three months ended March 31, 2024 compared to the same period in 2023, remained relatively consistent. Natural gas volume for the three months ended March 31, 2024 compared to the same period in 2023, remained relatively consistent.
Electric Retail Deliveries to Customers (in GWhs)Three Months Ended March 31,% Change
Weather -
Normal
% Change(b)
20242023
Residential3,4553,3582.9 %(1.2)%
Small commercial & industrial1,8911,8432.6 %(1.7)%
Large commercial & industrial3,3553,2373.6 %2.5 %
Public authorities & electric railroads1791686.5 %7.1 %
Total electric retail deliveries(a)
8,8808,6063.2 %0.2 %
At March 31,
Number of Electric Customers20242023
Residential1,540,4911,529,779
Small commercial & industrial156,475155,846
Large commercial & industrial3,1603,118
Public authorities & electric railroads10,71310,401
Total1,710,8391,699,144
__________
(a)Reflects delivery volumes from customers purchasing electricity directly from PECO and customers purchasing electricity from a competitive electric generation supplier as all customers are assessed distribution charges.
(b)Reflects the change in delivery volumes assuming normalized weather based on the historical 30-year average.
Natural Gas Deliveries to Customers (in mmcf)Three Months Ended
March 31,		% Change
Weather -
Normal
% Change(b)
20242023
Residential18,89517,1909.9 %0.6 %
Small commercial & industrial9,4888,6999.1 %(0.8)%
Large commercial & industrial1629(44.8)%(12.2)%
Transportation6,8997,014(1.6)%(3.0)%
Total natural gas retail deliveries(a)
35,29832,9327.2 %(0.5)%
 At March 31,
Number of Natural Gas Customers20242023
Residential508,429504,181
Small commercial & industrial45,03845,003
Large commercial & industrial79
Transportation646650
Total554,120549,843
__________
(a)Reflects delivery volumes from customers purchasing natural gas directly from PECO and customers purchasing natural gas from a competitive natural gas supplier as all customers are assessed distribution charges.
(b)Reflects the change in delivery volumes assuming normalized weather based on the historical 30-year average.
Pricing for the three months ended March 31, 2024 compared to the same period in 2023 remained relatively consistent.
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PECO
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 months ended March 31, 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 decrease of $81 million for the three months ended March 31, 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.
The changes in Operating and maintenance expense consisted of the following:
Three Months Ended
March 31, 2024
Increase (Decrease)
Storm-related costs$25 
BSC costs7 
Pension and non-pension postretirement benefit expense2 
Labor, other benefits, contracting and materials(6)
Credit loss expense(10)
Other7 
25 
Regulatory required programs(2)
Total increase$23 
The changes in Depreciation and amortization expense consisted of the following:
Three Months Ended
March 31, 2024
Increase
Depreciation and amortization(a)
$6 
Regulatory asset amortization— 
Total increase$6 
__________
(a)Depreciation and amortization increased primarily due to ongoing capital expenditures.


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PECO
Interest expense, net increased $7 million for the three months ended March 31, 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 6.3% and 2.4% for the three months ended March 31, 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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BGE

Results of Operations — BGE
Three Months Ended
March 31,		Favorable (Unfavorable) Variance
20242023
Operating revenues$1,297 $1,257 $40 
Operating expenses
Purchased power and fuel 464 492 28 
Operating and maintenance264 222 (42)
Depreciation and amortization150 167 17 
Taxes other than income taxes89 83 (6)
Total operating expenses967 964 (3)
Operating income330 293 37 
Other income and (deductions)
Interest expense, net(50)(44)(6)
Other, net8 3 5 
Total other income and (deductions)(42)(41)(1)
Income before income taxes288 252 36 
Income taxes24 52 28 
Net income$264 $200 $64 
Three Months Ended March 31, 2024 Compared to Three Months Ended March 31, 2023. Net Income increased $64 million primarily due to favorable impacts of the multi-year plans, partially offset by an increase in storm costs, an increase in property tax expense, 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
March 31, 2024
Increase (Decrease)
ElectricGasTotal
Distribution$23 $44 $67 
Transmission(1)— (1)
Other(1)(2)(3)
21 42 63 
Regulatory required programs47 (70)(23)
Total increase (decrease)$68 $(28)$40 
Revenue Decoupling. The demand for electricity and natural gas is affected by weather and customer usage. However, Operating revenues are not impacted by abnormal weather or usage per customer as a result of a monthly rate adjustment that provides for fixed distribution revenue per customer by customer class. While Operating revenues are not impacted by abnormal weather or usage per customer, they are impacted by changes in the number of customers.
 At March 31,
Number of Electric Customers20242023
Residential1,213,063 1,207,486 
Small commercial & industrial115,406 115,658 
Large commercial & industrial13,110 12,911 
Public authorities & electric railroads261 266 
Total1,341,840 1,336,321 
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BGE

At March 31,
Number of Natural Gas Customers20242023
Residential658,818 656,583 
Small commercial & industrial37,982 38,260 
Large commercial & industrial6,336 6,261 
Total703,136 701,104 
Distribution Revenue increased for the three months ended March 31, 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 remained relatively the same for the three months ended March 31, 2024, compared to the same period in 2023.
Other Revenue includes revenue related to late payment, charges, mutual assistance, off-system sales, and service application fees. Other Revenue decreased for the three months ended March 31, 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 decrease of $28 million for the three months ended March 31, 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.

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BGE

The changes in Operating and maintenance expense consisted of the following:
Three Months Ended
March 31, 2024
 Increase (Decrease)
Storm-related costs10 
BSC costs5 
Credit loss expense(6)
Labor, other benefits, contracting, and materials(3)
6 
Regulatory required programs(a)
36 
Total increase$42 
__________
(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
March 31, 2024
Increase (Decrease)
Depreciation and amortization$1 
Regulatory required programs(a)
(25)
Regulatory asset amortization7 
Total decrease$(17)
__________
(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 $6 million for the three months ended March 31, 2024, respectively compared to the same period in 2023, primarily due to the issuance of debt during the second quarter of 2023.
Taxes other than income taxes increased by $6 million for the three months ended March 31, 2024, respectively, compared to the same period in 2023, primarily due to increased property taxes.
Effective income tax rates were 8.3% and 20.6% for the three months ended March 31, 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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PHI
Results of Operations — PHI
PHI’s Results of Operations include the results of its three reportable segments, Pepco, DPL, and ACE. PHI also has a business services subsidiary, PHISCO, which provides a variety of support services, and the costs are directly charged or allocated to the applicable subsidiaries. Additionally, the results of PHI’s corporate operations include interest costs from various financing activities. All material intercompany accounts and transactions have been eliminated in consolidation. The following table sets forth PHI's GAAP consolidated Net income, by Registrant, for the three months ended March 31, 2024 compared to the same period in 2023. See the Results of Operations for Pepco, DPL, and ACE for additional information.
Three Months Ended
March 31,		Favorable (Unfavorable) Variance
20242023
PHI$168 $155 $13 
Pepco75 65 10 
DPL
66 60 6 
ACE29 33 (4)
Other(a)
(2)(3)1 
__________
(a)Primarily includes eliminating and consolidating adjustments, PHI's corporate operations, shared service entities, and other financing and investment activities.

Three Months Ended March 31, 2024 Compared to Three Months Ended March 31, 2023. Net Income increased by $13 million primarily due to the absence of an increase environmental liabilities, an increase in ACE and DPL Delaware electric distribution rates, favorable impacts of the Pepco Maryland and DPL Maryland multi-year plans, and higher transmission rates at Pepco and DPL, partially offset by an increase in interest expense and various operating expenses.

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Pepco

Results of Operations — Pepco
Three Months Ended March 31,Favorable (Unfavorable) Variance
20242023
Operating revenues$759 $710 $49 
Operating expenses
Purchased power 281 258 (23)
Operating and maintenance150 150 — 
Depreciation and amortization107 108 1 
Taxes other than income taxes102 94 (8)
Total operating expenses640 610 (30)
Operating income 119 100 19 
Other income and (deductions)
Interest expense, net(45)(39)(6)
Other, net15 16 (1)
Total other income and (deductions)(30)(23)(7)
Income before income taxes89 77 12 
Income taxes14 12 (2)
Net income$75 $65 $10 
Three Months Ended March 31, 2024 Compared to Three Months Ended March 31, 2023. Net Income increased by $10 million primarily due to the absence of an increase in environmental liabilities, favorable impacts of the Maryland multi-year plan, customer growth, and higher transmission rates, partially offset by an increase in interest expense, credit loss expense, and depreciation expense.
The changes in Operating revenues consisted of the following:
Three Months Ended
March 31, 2024
Increase
Distribution$9 
Transmission9 
Other— 
18 
Regulatory required programs31 
Total increase$49 
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.
At March 31,
Number of Electric Customers20242023
Residential869,606 859,207 
Small commercial & industrial54,177 54,089 
Large commercial & industrial22,992 22,858 
Public authorities & electric railroads207 201 
Total946,982 936,355 
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Pepco

Distribution Revenue increased for the three months ended March 31, 2024 compared to the same period in 2023 primarily due to favorable impacts of the Maryland multi-year plan, 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 months ended March 31, 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 $23 million for the three months ended March 31, 2024 compared to the same period in 2023, in Purchased power expense is fully offset in Operating revenues as part of regulatory required programs.
The changes in Operating and maintenance expense consisted of the following:
Three Months Ended
March 31, 2024
Increase (Decrease)
BSC and PHISCO costs$7 
Credit loss expense7 
Pension and non-pension postretirement benefits expense(1)
Labor, other benefits, contracting and materials(a)
(22)
Other1 
(8)
Regulatory required programs(b)
8 
Total increase$— 
__________
(a)Primarily reflects the absence of an increase in environmental liabilities for the three months ended March 31, 2024 compared to the same period in 2023.
(b)Increase due to the cost recovery associated with Empower Maryland. Please refer to 2023 10-K Note 3 — Regulatory Matters for additional information.

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Pepco

The changes in Depreciation and amortization expense consisted of the following:
Three Months Ended
March 31, 2024
Increase (Decrease)
Depreciation and amortization(a)
$5 
Regulatory asset amortization— 
Regulatory required programs(6)
Total decrease$(1)
__________
(a)Depreciation and amortization increased primarily due to ongoing capital expenditures.
Taxes other than income taxes increased $8 million for the or the three months ended March 31, 2024 compared to the same period in 2023, primarily due to an increase in property taxes.
Interest expense, net increased by $6 million for the three months ended March 31, 2024 compared to the same period in 2023, primarily due to an increase in interest rates and the issuance of debt in 2023 and 2024.
Effective income tax rates were 15.7% and 15.6% for the three months ended March 31, 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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DPL

Results of Operations — DPL
Three Months Ended March 31,Favorable (Unfavorable) Variance
20242023
Operating revenues$491 $474 $17 
Operating expenses
Purchased power and fuel 215 221 6 
Operating and maintenance95 87 (8)
Depreciation and amortization61 60 (1)
Taxes other than income taxes20 20 — 
Total operating expenses391 388 (3)
Operating income100 86 14 
Other income and (deductions)
Interest expense, net(22)(17)(5)
Other, net5 3 2 
Total other income and (deductions)(17)(14)(3)
Income before income taxes83 72 11 
Income taxes17 12 (5)
Net income $66 $60 $6 

Three Months Ended March 31, 2024 Compared to Three Months Ended March 31, 2023. Net income increased $6 million primarily due to an increase in Delaware electric distribution rates, higher transmission rates, and favorable impacts of the Maryland multi-year plan, partially offset by an increase in interest expense.
The changes in Operating revenues consisted of the following:
Three Months Ended
March 31, 2024
Increase (Decrease)
ElectricGasTotal
Weather$3 $3 $6 
Volume(1)(1)(2)
Distribution10 1 11 
Transmission7 — 7 
Other2 — 2 
21 3 24 
Regulatory required programs21 (28)(7)
Total increase (decrease)$42 $(25)$17 
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 businesses, very cold weather in winter months are referred to as "favorable weather conditions” because these weather conditions result in increased deliveries of electricity and natural gas. Conversely, mild weather reduces demand. During the three months ended March 31, 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.
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DPL

Heating and cooling degree days are quantitative indices that reflect the demand for energy needed to heat or cool a home or business. Normal weather is determined based on historical average heating and cooling degree days for a 20-year period in 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 months ended March 31, 2024 compared to same period in 2023 and normal weather consisted of the following:
Three Months Ended March 31,% Change
Delaware Electric Service Territory20242023Normal2024 vs. 20232024 vs. Normal
Heating Degree-Days2,204 1,952 2,447 12.9 %(9.9)%
Cooling Degree-Days— — 1 — %(100.0)%
Three Months Ended March 31,% Change
Delaware Natural Gas Service Territory20242023Normal2024 vs. 20232024 vs. Normal
Heating Degree-Days2,204 1,952 2,476 12.9 %(11.0)%
Volume, exclusive of the effects of weather, remained relatively consistent for the three months ended March 31, 2024 compared to the same period in 2023.
Electric Retail Deliveries to Delaware Customers (in GWhs)Three Months Ended
March 31,		% Change
Weather - Normal
% Change(b)
20242023
Residential857 797 7.5 %(0.4)%
Small commercial & industrial339 327 3.7 %(0.3)%
Large commercial & industrial718 719 (0.1)%(1.0)%
Public authorities & electric railroads7 9 (22.2)%(24.7)%
Total electric retail deliveries(a)
1,921 1,852 3.7 %(0.7)%
At March 31,
Number of Total Electric Customers (Maryland and Delaware)20242023
Residential486,950 482,979 
Small commercial & industrial64,338 63,794 
Large commercial & industrial1,260 1,236 
Public authorities & electric railroads593 595 
Total553,141 548,604 
__________
(a)Reflects delivery volumes from customers purchasing electricity directly from DPL and customers purchasing electricity from a competitive electric generation supplier as all customers are assessed distribution charges.
(b)Reflects the change in delivery volumes assuming normalized weather based on the historical 20-year average.
Natural Gas Retail Deliveries to Delaware Customers (in mmcf)Three Months Ended
March 31,		% Change
Weather - Normal
% Change(b)
20242023
Residential3,913 3,581 9.3 %(1.2)%
Small commercial & industrial1,717 1,652 3.9 %(6.8)%
Large commercial & industrial428 414 3.4 %3.5 %
Transportation1,960 1,900 3.2 %(1.9)%
Total natural gas deliveries(a)
8,018 7,547 6.2 %(2.4)%
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DPL

At March 31,
Number of Delaware Natural Gas Customers20242023
Residential130,427 129,791 
Small commercial & industrial10,182 10,158 
Large commercial & industrial16 16 
Transportation163 158 
Total140,788 140,123 
__________
(a)Reflects delivery volumes from customers purchasing natural gas directly from DPL and customers purchasing natural gas from a competitive natural gas supplier as all customers are assessed distribution charges.
(b)Reflects the change in delivery volumes assuming normalized weather based on the historical 30-year average.

Distribution Revenue increased for the three months ended March 31, 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, favorable impacts of the Maryland multi-year plan that became effective in January 2024, 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 months ended March 31, 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 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 decrease of $6 million for the three months ended March 31, 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.
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DPL

The changes in Operating and maintenance expense consisted of the following:
Three Months Ended
March 31, 2024
Increase (Decrease)
Storm-related Costs$6 
BSC and PHISCO costs3 
Labor and contracting2 
Credit loss expense(2)
Other
(1)
8 
Regulatory required programs— 
Total increase$8 
The changes in Depreciation and amortization expense consisted of the following:
Three Months Ended
March 31, 2024
Increase
Depreciation and amortization(a)
$1 
Regulatory required programs— 
Regulatory asset amortization— 
Total increase$1 
__________
(a)Depreciation and amortization increased primarily due to ongoing capital expenditures.
Interest expense, net increased by $5 million for the three months ended March 31, 2024 compared to the same period in 2023, primarily due to an increase in interest rates and the issuance of debt in 2023 and 2024.
Effective income tax rates were 20.5% and 16.7% for the three months ended March 31, 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 March 31,Favorable (Unfavorable) Variance
20242023
Operating revenues$358 $353 $5 
Operating expenses
Purchased power 140 148 8 
Operating and maintenance87 81 (6)
Depreciation and amortization74 67 (7)
Taxes other than income taxes2 2 — 
Total operating expenses303 298 (5)
Operating income 55 55 — 
Other income and (deductions)
Interest expense, net(20)(16)(4)
Other, net5 5 — 
Total other income and (deductions)(15)(11)(4)
Income before income taxes40 44 (4)
Income taxes11 11 — 
Net income $29 $33 $(4)
Three Months Ended March 31, 2024 Compared to Three Months Ended March 31, 2023. Net income decreased by $4 million primarily due to an increase in various operating expenses, depreciation expense, and interest expense, partially offset by an increase in distribution rates.
The changes in Operating revenues consisted of the following:
Three Months Ended
March 31, 2024
Increase (Decrease)
Distribution$11 
Transmission2 
Other1 
14 
Regulatory required programs(9)
Total increase$5 
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 March 31,
Number of Electric Customers20242023
Residential505,793 503,260 
Small commercial & industrial62,704 62,230 
Large commercial & industrial2,893 3,030 
Public authorities & electric railroads728 726 
Total572,118 569,246 
Distribution Revenue increased for the three months ended March 31, 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 increased for the three months ended March 31, 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, 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 $8 million for the three months ended March 31, 2024 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
March 31, 2024
Increase
BSC and PHISCO costs$3 
Storm-related costs2 
Other1 
6 
Regulatory required programs(a)
— 
Total increase$6 
__________
(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
March 31, 2024
Increase
Depreciation and amortization(a)
$5 
Regulatory asset amortization2 
Regulatory required programs— 
Total increase$7 
__________
(a)Depreciation and amortization increased primarily due to ongoing capital expenditures.
Interest expense, net increased $4 million for the year ended March 31, 2024 compared to the same period in 2023 primarily due to an increase in interest rates and the issuance of debt in 2023 and 2024.
Effective income tax rates were 27.5% and 25.0% for the three months ended March 31, 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 three months ended March 31, 2024 and 2023 by Registrant:
Increase (decrease) in cash flows from operating activitiesExelonComEdPECOBGE PHIPepcoDPLACE
Net income (loss)$(11)$(48)$(17)$64 $13 $10 $6 $(4)
Adjustments to reconcile net income to cash:
Non-cash operating activities129 115 — (34)24 (4)17 19 
Collateral received (paid), net221 12 — 22 189 24 120 45 
Income taxes(2)6 (1)— 4 4 1 (2)
Pension and non-pension postretirement benefit contributions(67)18 (2)(17)(65)— — (6)
Regulatory assets and liabilities, net576 653 (35)31 (69)9 (28)(50)
Changes in working capital and other assets and liabilities(338)(84)(72)(58)(63)(38)(6)(18)
Increase (decrease) in cash flows from operating activities$508 $672 $(127)$8 $33 $5 $110 $(16)
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. See above for additional information related to cash flows from Generation. Significant operating cash flow impacts for the Registrants and Generation for the three months ended March 31, 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 three month ended March 31, 2024 to the three month ended March 31, 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 three months ended March 31, 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 $80 million and $72 million for the three months ended March 31, 2024 and 2023, respectively. Also included within the changes is energy efficiency and demand response programs spend for BGE, Pepco, DPL and ACE of $28 million, $10 million, $4 million, and $8 million for the three months ended March 31, 2024 and $33 million, $14 million, $5 million, and $4 million for the three months ended March 31, 2023, respectively. PECO had no energy efficiency and demand response programs spend recorded to the regulatory asset for the three months ended March 31,
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2024 and 2023. See Note 2 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.
•Changes in working capital and other assets and liabilities for the Utility Registrants and Exelon Corporate totaled $(276) million and $(338) million, respectively. The change in working capital and other noncurrent assets and liabilities for Exelon Corporate and the Utility Registrants is dependent upon the normal course of operations for all Registrants. For ComEd, it is also dependent upon whether the participating nuclear-powered generating facilities are owed money from ComEd as a result of the established pricing for CMCs. For the three months ended March 31, 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 three months ended March 31, 2024 and 2023 by Registrant:
Increase (decrease) in cash flows from investing activitiesExelonComEdPECOBGE PHIPepcoDPLACE
Capital expenditures$114 $23 $(26)$26 $108 $35 $— $72 
Proceeds from sales of assets and businesses2 — — — — — — — 
Changes in intercompany money pool— — — — — (134)— — 
Other investing activities(12)— 2 5 (8)(8)— — 
Increase (decrease) in cash flows from investing activities$104 $23 $(24)$31 $100 $(107)$— $72 
Significant investing cash flow impacts for the Registrants for three months ended March 31, 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. See Note — Discontinued Operations of the Combined Notes to Consolidated Financial Statements for capital expenditures related to Generation prior to the separation.
•Changes in intercompany money pool are driven by short-term borrowing needs. Refer to more information regarding the intercompany money pool below.
Cash Flows from Financing Activities
The following table provides a summary of the change in cash flows from financing activities for the three months ended March 31, 2024 and 2023 by Registrant:
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(Decrease) increase in cash flows from financing activitiesExelonComEdPECOBGE PHIPepcoDPLACE
Changes in short-term borrowings, net$963 $296 $(71)$235 $20 $167 $52 $(199)
Long-term debt, net(1,344)(975)— — 75 25 50 — 
Changes in intercompany money pool— — — — — — — 134 
Dividends paid on common stock(23)(7)1 (12)— (3)(3)(1)
Distributions to member— — — — (6)— — — 
Contributions from parent/member— (147)250 (237)82 8 55 18 
Other financing activities6 12 — — (4)(1)(1)(1)
(Decrease) increase in cash flows from financing activities$(398)$(821)$180 $(14)$167 $196 $153 $(49)
Significant financing cash flow impacts for the Registrants for the three months ended March 31, 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 three months ended March 31, 2024, the following long-term debt was retired and/or redeemed:
CompanyTypeInterest RateMaturityAmount
ExelonSMBC Term Loan AgreementSOFR plus 0.85%April 8, 2024$500 
ExelonSoftware Licensing Agreement3.62 %December 1, 2025$1 
PepcoFirst Mortgage Bonds3.60 %March 15, 2024$400 
Dividends
Quarterly dividends declared by the Exelon Board of Directors during the three months ended March 31, 2024 and for the second 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 
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__________
(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 $2.7 billion was available to support additional commercial paper as of March 31, 2024, and of which no financial institution has more than 6% of the aggregate commitments for the Registrants. The Registrants had access to the commercial paper markets and had availability under their revolving credit facilities during the three months ended March 31, 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 December 31, 2023, $858 million of Common stock remained available for sale pursuant to the ATM program. For the period ended March 31, 2024, Exelon did not issue any shares of common stock under the ATM program and did not enter into any forward sale agreements.
The following table presents the incremental collateral that each Utility Registrant would have been required to provide in the event each Utility Registrant lost its investment grade credit rating at March 31, 2024 and available credit facility capacity prior to any incremental collateral at March 31, 2024:
PJM Credit Policy Collateral
Other Incremental Collateral Required(a)
Available Credit Facility Capacity Prior to Any Incremental Collateral
ComEd$— $— $660 
PECO— 27 598 
BGE— 47 188 
Pepco— — 300 
DPL— 12 300 
ACE— — 300 
__________
(a)Represents incremental collateral related to natural gas procurement contracts.
Capital Expenditure Spending
As of March 31, 2024, the most recent estimates of capital expenditures for plant additions and improvements for 2024 are as follows:        
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(In millions)TransmissionDistributionGas
Total(a)
ExelonN/AN/AN/A$7,425 
ComEd475 1,675 N/A2,150 
PECO75 1,225 400 1,700 
BGE475 625 500 1,600 
PHI575 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.
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.
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Security Ratings
The Registrants’ access to the capital markets, including the commercial paper market, and their respective financing costs in those markets, may depend on the securities ratings of the entity that is accessing the capital markets.
The Registrants’ borrowings are not subject to default or prepayment as a result of a downgrading of securities, although such a downgrading of a Registrant’s securities could increase fees and interest charges under that Registrant’s credit agreements.
As part of the normal course of business, the Registrants enter into contracts that contain express provisions or otherwise permit the Registrants and their counterparties to demand adequate assurance of future performance when there are reasonable grounds for doing so. In accordance with the contracts and applicable contracts law, if the Registrants are downgraded by a credit rating agency, it is possible that a counterparty would attempt to rely on such a downgrade as a basis for making a demand for adequate assurance of future performance, which could include the posting of collateral. See Note 8 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information on collateral provisions.
The credit ratings for the Registrants did not change for the three months ended March 31, 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 March 31, 2024, are presented in the following table:
During the Three Months Ended March 31, 2024At March 31, 2024
Exelon Intercompany Money PoolMaximum
Contributed		Maximum
Borrowed		Contributed
(Borrowed)
Exelon Corporate$626 $— $330 
PECO55 (255)— 
BSC— (420)(302)
PHI Corporate— (86)(73)
PCI45 — 45 
During the Three Months Ended March 31, 2024At March 31, 2024
PHI Intercompany Money PoolMaximum
Contributed		Maximum
Borrowed
(Borrowed)
Contributed
Pepco$171 $— $134 
DPL— (33)— 
ACE— (171)(134)
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. On February 21, 2024, PECO and BGE filed with the SEC a standalone 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,
127


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.
Regulatory Authorizations
The Utility Registrants are required to obtain short-term and long-term financing authority from Federal and State Commissions as follows:
At March 31, 2024
Short-term Financing Authority (e)
Remaining Long-term Financing Authority
CommissionExpiration DateAmountCommissionExpiration DateAmount
ComEd(a) (b)
FERCDecember 31, 2025$2,500 ICCJanuary 1, 2027$2,368 
PECOFERCDecember 31, 20251,500 PAPUCDecember 31, 2024550 
BGE(c)
FERCDecember 31, 2025700 MDPSCN/A1,100 
PepcoFERCDecember 31, 2025500 MDPSC / DCPSCDecember 31, 2025375 
DPLFERCDecember 31, 2025500 MDPSC / DEPSCDecember 31, 2025375 
ACENJBPUDecember 31, 2025350 NJBPUDecember 31, 2024550 
__________
(a)On June 29, 2023, ComEd filed an application for $2 billion in new money long-term debt financing authority from the ICC and received approval on January 1, 2024.
(b)On February 20, 2024, ComEd filed an application for $750 million in refinancing authority from the ICC, which was approved on April 18, 2024. The refinancing authority under the approved application has an effective date of May 1, 2024, and extends the expiration date to May 1, 2027.
(c)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.
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ITEM 3.    QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK
The Registrants hold commodity and financial instruments that are exposed to the following market risks:
•Commodity price risk, which is discussed further below.
•Counterparty credit risk associated with non-performance by counterparties on executed derivative instruments and participation in all, or some of the established, wholesale spot energy markets that are administered by PJM. The credit policies of PJM may, under certain circumstances, require that losses arising from the default of one member on spot energy market transactions be shared by the remaining participants. See Note 8 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for a detailed discussion of counterparty credit risk related to derivative instruments.
•Equity price and interest rate risk associated with Exelon’s pension and OPEB plan trusts. See Note 7 — Retirement Benefits of the 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.
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The following table presents the maturity and source of fair value for Exelon’s and ComEd’s mark-to-market commodity contract net liabilities. These net liabilities are associated with ComEd’s floating-to-fixed energy swap contracts with unaffiliated suppliers. The table provides two fundamental pieces of information. First, the table provides the source of fair value used in determining the carrying amount of Exelon's and ComEd's total mark-to-market net liabilities. Second, the table shows the maturity, by year, of Exelon's and ComEd's commodity contract net liabilities giving an indication of when these mark-to-market amounts will settle and either generate or require cash. See Note 10 — Fair Value of Financial Assets and Liabilities of the Combined Notes to Consolidated Financial Statements for additional information regarding fair value measurements and the fair value hierarchy.
Maturities WithinTotal Fair
Value
Commodity derivative contracts(a):
202420252026202720282029 and Beyond
Prices based on model or other valuation methods (Level 3)$(24)$(17)$(14)$(14)$(14)$(25)$(108)
_________
(a)Represents ComEd's net liabilities associated with the floating-to-fixed energy swap contracts with unaffiliated suppliers.
ITEM 4.    CONTROLS AND PROCEDURES
During the first quarter of 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 March 31, 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 months ended March 31, 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
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At March 31, 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.
(4) Instruments Defining the Rights of Securities Holders, Including Indentures
Exelon Corporation
Exhibit No.DescriptionLocation
Seventh Supplemental Indenture, dated as of February 27, 2024, among Exelon Corporation and The Bank of New York Mellon Trust Company, N.A., as trustee
Potomac Electric Power Company
Exhibit No.DescriptionLocation
Pepco Supplemental Indenture to the Mortgage and Deed of Trust, dated as of February 15, 2024
Atlantic City Electric Company
Exhibit No.DescriptionLocation
ACE Supplemental Indenture to the Mortgage and Deed of Trust, dated as of March 1, 2024
Delmarva Power & Light Company
DPL Supplemental Indenture to the Mortgage and Deed of Trust, dated as of March 1, 2024
(10) Material Contracts
Exelon Corporation
Exhibit No.DescriptionLocation
Exelon Corporation Senior Management Severance Plan, as amended and restated effective February 1, 2024.
Exelon Corporation Long-Term Incentive Program, as amended and restated effective February 1, 2024.
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Table of Contents
Certifications Pursuant to Rule 13a-14(a) and 15d-14(a) of the Securities and Exchange Act of 1934 as to the Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2024 filed by the following officers for the following companies:
Exelon Corporation
Exhibit No.Description
Commonwealth Edison Company
Exhibit No.Description
PECO Energy Company
Exhibit No.Description
Baltimore Gas and Electric Company
Exhibit No.Description
Pepco Holdings LLC
Exhibit No.Description
Potomac Electric Power Company
Exhibit No.Description
Delmarva Power & Light Company
Exhibit No.Description
Atlantic City Electric Company
Exhibit No.Description
Certifications Pursuant to Section 1350 of Chapter 63 of Title 18 United States Code (Sarbanes-Oxley Act of 2002) as to the Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2024 filed by the following officers for the following companies:
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Table of Contents
Exelon Corporation
Exhibit No.Description
Commonwealth Edison Company
Exhibit No.Description
PECO Energy Company
Exhibit No.Description
Baltimore Gas and Electric Company
Exhibit No.Description
Pepco Holdings LLC
Exhibit No.Description
Potomac Electric Power Company
Exhibit No.Description
Delmarva Power & Light Company
Exhibit No.Description
Atlantic City Electric Company
Exhibit No.Description
101.INSInline XBRL Instance Document - the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document.
101.SCHInline XBRL Taxonomy Extension Schema Document
101.CALInline XBRL Taxonomy Extension Calculation Linkbase Document
101.DEFInline XBRL Taxonomy Extension Definition Linkbase Document
101.LABInline XBRL Taxonomy Extension Labels Linkbase Document
101.PREInline XBRL Taxonomy Extension Presentation Linkbase Document
104Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101)
133


SIGNATURES

Pursuant to requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
EXELON CORPORATION
 
/s/    CALVIN G. BUTLER, JR./s/    JEANNE M. JONES
Calvin G. Butler, Jr.Jeanne M. Jones
President, Chief Executive Officer
(Principal Executive Officer) and Director		Executive Vice President and Chief Financial Officer
(Principal Financial Officer)
/s/ ROBERT A. KLECZYNSKI
Robert A. Kleczynski
Senior Vice President, Corporate Controller and Tax
(Principal Accounting Officer)
May 2, 2024
134


Pursuant to requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
COMMONWEALTH EDISON COMPANY
 
/s/ GIL C. QUINIONES/s/ JOSHUA S. LEVIN
Gil C. QuinionesJoshua S. Levin
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)
May 2, 2024
135


Pursuant to requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
PECO ENERGY COMPANY
 
/s/   MICHAEL A. INNOCENZO/s/    MARISSA HUMPHREY
Michael A. InnocenzoMarissa 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)
May 2, 2024

136


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/ DAVID M. VAHOS
Carim V. KhouzamiDavid M. Vahos
President, Chief Executive Officer
(Principal Executive Officer) and Director		Senior Vice President, Chief Financial Officer and Treasurer
(Principal Financial Officer)
 /s/ JASON T. JONES
Jason T. Jones
Director, Accounting
(Principal Accounting Officer)
May 2, 2024

137


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/    PHILLIP S. BARNETT
J. Tyler AnthonyPhillip S. Barnett
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)
May 2, 2024

138


Pursuant to requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
POTOMAC ELECTRIC POWER COMPANY
/s/ J. TYLER ANTHONY/s/    PHILLIP S. BARNETT
J. Tyler AnthonyPhillip S. Barnett
President, Chief Executive Officer
(Principal Executive Officer) and Director		Senior Vice President, Chief Financial Officer, Treasurer
(Principal Financial Officer) and Director
/s/ JULIE E. GIESE
Julie E. Giese
Director, Accounting
(Principal Accounting Officer)
May 2, 2024

139


Pursuant to requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
DELMARVA POWER & LIGHT COMPANY
/s/ J. TYLER ANTHONY/s/    PHILLIP S. BARNETT
J. Tyler AnthonyPhillip S. Barnett
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)
May 2, 2024

140


Pursuant to requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
ATLANTIC CITY ELECTRIC COMPANY
/s/ J. TYLER ANTHONY/s/    PHILLIP S. BARNETT
J. Tyler AnthonyPhillip S. Barnett
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)
May 2, 2024
141


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