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Exelon Corporation
EXC
#539
Rank
C$61.56 B
Marketcap
๐Ÿ‡บ๐Ÿ‡ธ United States
Country
C$60.96
Share price
0.83%
Change (1 day)
7.99%
Change (1 year)
๐Ÿ”‹ Electricity
Categories
  1. Exelon Corporation
  2. Quarterly Reports (10-Q)
  3. Financial Year FY2023 Q3

Exelon Corporation - 10-Q quarterly report FY2023 Q3


Text size:
Cumulative Preferred Security, Series DSeptember 30, 2023false2023Q3December 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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 September 30, 2023
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)
P.O. Box 8699
2301 Market Street
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 20068-001
(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
EXC/28New York Stock Exchange

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 September 30, 2023 was:
Exelon Corporation Common Stock, without par value995,437,416
Commonwealth Edison Company Common Stock, $12.50 par value127,021,396
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
15
Consolidated Statements of Cash Flows
16
Consolidated Balance Sheets
17
Consolidated Statements of Changes in Shareholders' Equity
19
PECO Energy Company
Consolidated Statements of Operations and Comprehensive Income
20
Consolidated Statements of Cash Flows
21
Consolidated Balance Sheets
22
Consolidated Statements of Changes in Shareholder's Equity
24
Baltimore Gas and Electric Company
Statements of Operations and Comprehensive Income
25
Statements of Cash Flows
26
Balance Sheets
27
Statements of Changes in Shareholder's Equity
29
Pepco Holdings LLC
Consolidated Statements of Operations and Comprehensive Income
30
Consolidated Statements of Cash Flows
31
Consolidated Balance Sheets
32
Consolidated Statements of Changes in Member's Equity
34
1




Page No.
Potomac Electric Power Company
Statements of Operations and Comprehensive Income
35
Statements of Cash Flows
36
Balance Sheets
37
Statements of Changes in Shareholder's Equity
39
Delmarva Power & Light Company
Statements of Operations and Comprehensive Income
40
Statements of Cash Flows
41
Balance Sheets
42
Statements of Changes in Shareholder’s Equity
44
Atlantic City Electric Company
Consolidated Statements of Operations and Comprehensive Income
45
Consolidated Statements of Cash Flows
46
Consolidated Balance Sheets
47
Consolidated Statements of Changes in Shareholder’s Equity
49
Combined Notes to Consolidated Financial Statements
1. Significant Accounting Policies
50
2. Discontinued Operations
51
3. Regulatory Matters
54
4. Revenue from Contracts with Customers
62
5. Segment Information
63
6. Accounts Receivable
72
7. Income Taxes
75
8. Retirement Benefits
78
9. Derivative Financial Instruments
80
10. Debt and Credit Agreements
84
11. Fair Value of Financial Assets and Liabilities
87
12. Commitments and Contingencies
93
13. Shareholders' Equity
101
14. Changes in Accumulated Other Comprehensive Income
102
15. Supplemental Financial Information
103
16. Related Party Transactions
107
2




Page No.
110
Exelon Corporation
110
Executive Overview
110
Financial Results of Operations
110
Significant 2023 Transactions and Developments
113
Other Key Business Drivers and Management Strategies
116
Critical Accounting Policies and Estimates
118
Results of Operations By Registrant
119
Commonwealth Edison Company
119
PECO Energy Company
122
Baltimore Gas and Electric Company
126
Pepco Holdings LLC
129
Potomac Electric Power Company
130
Delmarva Power & Light Company
133
Atlantic City Electric Company
137
Liquidity and Capital Resources
140
148
149
149
149
150
150
151
154
154
155
156
157
158
159
160
161
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 2022 Form 10-KReference to specific Combined Note to Consolidated Financial Statements within Exelon's 2022 Annual Report on Form 10-K
ABOAccumulated Benefit Obligation
AECsAlternative Energy Credits that are issued for each megawatt hour of generation from a qualified alternative energy source
AFUDCAllowance for Funds Used During Construction
AMIAdvanced Metering Infrastructure
AOCIAccumulated Other Comprehensive Income (Loss)
AROAsset Retirement Obligation
ATMAt the market
BGSBasic Generation Service
BSABill Stabilization Adjustment
CEJAClimate and Equitable Jobs Act; Illinois Public Act 102-0662 signed into law on September 15, 2021
CERCLAComprehensive Environmental Response, Compensation, and Liability Act of 1980, as amended
CIPConservation Incentive Program
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
DPPDeferred Purchase Price
DSIC
Distribution System Improvement Charge
EIMAEnergy Infrastructure Modernization Act (Illinois Senate Bill 1652 and Illinois House Bill 3036)
EPAUnited States Environmental Protection Agency
ERCOTElectric Reliability Council of Texas
ERISAEmployee Retirement Income Security Act of 1974, as amended
ERPEnterprise Resource Program
ETACEnergy Transition Assistance Charge
FEJAIllinois Public Act 99-0906 or Future Energy Jobs Act
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
IIPInfrastructure Investment Program
Illinois Settlement LegislationLegislation enacted in 2007 affecting electric utilities in Illinois
IPAIllinois Power Agency
IRAInflation Reduction Act
IRCInternal Revenue Code
IRSInternal Revenue Service
5



GLOSSARY OF TERMS AND ABBREVIATIONS
Other Terms and Abbreviations
MDPSCMaryland Public Service Commission
MGPManufactured Gas Plant
mmcfMillion Cubic Feet
MMGMiddle Mile Grant
MRPMulti-Year Rate Plan
MWMegawatt
MWhMegawatt hour
N/ANot applicable
NAVNet Asset Value
NDTNuclear Decommissioning Trust
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
PP&EProperty, plant, and equipment
PRPsPotentially Responsible Parties
RECRenewable Energy Credit which is issued for each megawatt hour of generation from a qualified renewable energy source
Regulatory Agreement UnitsNuclear generating units or portions thereof whose decommissioning-related activities are subject to contractual elimination under regulatory accounting
RFPRequest for Proposal
RiderReconcilable Surcharge Recovery Mechanism
ROEReturn on equity
ROURight-of-use
RPSRenewable Energy Portfolio Standards
RTORegional Transmission Organization
SECUnited States Securities and Exchange Commission
SOFR Secured Overnight Financing Rate
SOSStandard Offer Service
STRIDEMaryland Strategic Infrastructure Development and Enhancement Program
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 2022 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 12, 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 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
September 30,		Nine Months Ended
September 30,
(In millions, except per share data)2023202220232022
Operating revenues
Electric operating revenues$5,684 $4,557 $14,579 $12,972 
Natural gas operating revenues188 224 1,268 1,348 
Revenues from alternative revenue programs108 64 513 92 
Total operating revenues5,980 4,845 16,360 14,412 
Operating expenses
Purchased power2,364 1,404 5,766 4,152 
Purchased fuel33 80 449 524 
Purchased power and fuel from affiliates— — — 159 
Operating and maintenance1,187 1,148 3,535 3,436 
Depreciation and amortization890 825 2,616 2,472 
Taxes other than income taxes383 377 1,063 1,061 
Total operating expenses4,857 3,834 13,429 11,804 
Loss on sale of assets and businesses— — — (2)
Operating income1,123 1,011 2,931 2,606 
Other income and (deductions)
Interest expense, net(431)(359)(1,259)(1,044)
Interest expense to affiliates(6)(6)(18)(19)
Other, net81 122 331 435 
Total other income and (deductions)(356)(243)(946)(628)
Income from continuing operations before income taxes767 768 1,985 1,978 
Income taxes67 92 274 356 
Net income from continuing operations after income taxes700 676 1,711 1,622 
Net income from discontinued operations after income taxes (Note 2)— — — 117 
Net income700 676 1,711 1,739 
Net income attributable to noncontrolling interests— — — 1 
Net income attributable to common shareholders$700 $676 $1,711 $1,738 
Amounts attributable to common shareholders:
Net income from continuing operations700 676 1,711 1,622 
Net income from discontinued operations— — — 116 
Net income attributable to common shareholders$700 $676 $1,711 $1,738 
Comprehensive income, net of income taxes
Net income$700 $676 $1,711 $1,739 
Other comprehensive income, net of income taxes
Pension and non-pension postretirement benefit plans:
Actuarial losses reclassified to periodic benefit cost16 9 22 33 
Pension and non-pension postretirement benefit plans valuation adjustments(3)— (16)2 
Unrealized gains on cash flow hedges21 — 36 — 
Other comprehensive income34 9 42 35 
Comprehensive income734 685 1,753 1,774 
Comprehensive income attributable to noncontrolling interests — — — 1 
Comprehensive income attributable to common shareholders$734 $685 $1,753 $1,773 
Average shares of common stock outstanding:
Basic996 988 996 983 
Assumed exercise and/or distributions of stock-based awards1 1 — 1 
Diluted997 989 996 984 
Earnings per average common share from continuing operations
Basic$0.70 $0.68 $1.72 $1.65 
Diluted$0.70 $0.68 $1.72 $1.65 
Earnings per average common share from discontinued operations
Basic$— $— $— $0.12 
Diluted$— $— $— $0.12 
See the Combined Notes to Consolidated Financial Statements
9



EXELON CORPORATION AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
Nine Months Ended
September 30,
(In millions)20232022
Cash flows from operating activities
Net income$1,711 $1,739 
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation, amortization, and accretion, including nuclear fuel and energy contract amortization2,616 2,679 
Asset impairments— 46 
Gain on sales of assets and businesses— (8)
Deferred income taxes and amortization of investment tax credits210 256 
Net fair value changes related to derivatives21 (59)
Net realized and unrealized losses on NDT funds— 205 
Net unrealized losses on equity investments— 16 
Other non-cash operating activities(237)265 
Changes in assets and liabilities:
Accounts receivable82 (1,049)
Inventories(8)(121)
Accounts payable and accrued expenses(454)823 
Option premiums paid, net— (39)
Collateral (paid) received, net(183)1,456 
Income taxes50 3 
Regulatory assets and liabilities, net(395)(689)
Pension and non-pension postretirement benefit contributions(97)(596)
Other assets and liabilities(24)(786)
Net cash flows provided by operating activities3,292 4,141 
Cash flows from investing activities
Capital expenditures(5,540)(5,179)
Proceeds from NDT fund sales— 488 
Investment in NDT funds— (516)
Collection of DPP— 169 
Proceeds from sales of assets and businesses— 16 
Other investing activities25 36 
Net cash flows used in investing activities(5,515)(4,986)
Cash flows from financing activities
Changes in short-term borrowings(1,116)(335)
Proceeds from short-term borrowings with maturities greater than 90 days400 1,150 
Repayments on short-term borrowings with maturities greater than 90 days(150)(925)
Issuance of long-term debt5,300 5,801 
Retirement of long-term debt(1,209)(2,067)
Issuance of common stock— 563 
Dividends paid on common stock(1,074)(999)
Proceeds from employee stock plans30 26 
Transfer of cash, restricted cash, and cash equivalents to Constellation— (2,594)
Other financing activities(101)(121)
Net cash flows provided by financing activities2,080 499 
Decrease in cash, restricted cash, and cash equivalents(143)(346)
Cash, restricted cash, and cash equivalents at beginning of period1,090 1,619 
Cash, restricted cash, and cash equivalents at end of period$947 $1,273 
Supplemental cash flow information
Decrease in capital expenditures not paid$(169)$(147)
Increase in DPP— 348 
(Decrease) increase in PP&E related to ARO update(4)331 
See the Combined Notes to Consolidated Financial Statements
10



EXELON CORPORATION AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
(Unaudited)
(In millions)September 30, 2023December 31, 2022
ASSETS
Current assets
Cash and cash equivalents$300 $407 
Restricted cash and cash equivalents435 566 
Accounts receivable
Customer accounts receivable2,5752,544
Customer allowance for credit losses(341)(327)
Customer accounts receivable, net2,234 2,217 
Other accounts receivable1,1681,426
Other allowance for credit losses(88)(82)
Other accounts receivable, net1,080 1,344 
Inventories, net
Fossil fuel105 208 
Materials and supplies657 547 
Regulatory assets2,307 1,641 
Other401 406 
Total current assets7,519 7,336 
Property, plant, and equipment (net of accumulated depreciation and amortization of $16,836 and $15,930 as of September 30, 2023 and December 31, 2022, respectively)
72,458 69,076 
Deferred debits and other assets
Regulatory assets8,128 8,037 
Goodwill6,630 6,630 
Receivable related to Regulatory Agreement Units2,923 2,897 
Investments246 232 
Other1,355 1,141 
Total deferred debits and other assets19,282 18,937 
Total assets$99,259 $95,349 
See the Combined Notes to Consolidated Financial Statements
11



EXELON CORPORATION AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
(Unaudited)
(In millions)September 30, 2023December 31, 2022
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities
Short-term borrowings$1,720 $2,586 
Long-term debt due within one year1,654 1,802 
Accounts payable2,684 3,382 
Accrued expenses1,315 1,226 
Payables to affiliates5 5 
Regulatory liabilities437 437 
Mark-to-market derivative liabilities44 8 
Unamortized energy contract liabilities8 10 
Other933 1,155 
Total current liabilities8,800 10,611 
Long-term debt39,431 35,272 
Long-term debt to financing trusts390 390 
Deferred credits and other liabilities
Deferred income taxes and unamortized investment tax credits11,792 11,250 
Regulatory liabilities9,236 9,112 
Pension obligations1,085 1,109 
Non-pension postretirement benefit obligations515 507 
Asset retirement obligations269 269 
Mark-to-market derivative liabilities113 83 
Unamortized energy contract liabilities29 35 
Other2,129 1,967 
Total deferred credits and other liabilities25,168 24,332 
Total liabilities73,789 70,605 
Commitments and contingencies
Shareholders’ equity
Common stock (No par value, 2,000 shares authorized, 995 shares and 994 shares outstanding as of September 30, 2023 and December 31, 2022, respectively)
20,956 20,908 
Treasury stock, at cost (2 shares as of September 30, 2023 and December 31, 2022)
(123)(123)
Retained earnings5,233 4,597 
Accumulated other comprehensive loss, net(596)(638)
Total shareholders’ equity25,470 24,744 
Total liabilities and shareholders’ equity$99,259 $95,349 

See the Combined Notes to Consolidated Financial Statements
12



EXELON CORPORATION AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS’ EQUITY
(Unaudited)
Nine Months Ended September 30, 2023
(In millions, shares
in thousands)		Issued
Shares		Common
Stock		Treasury
Stock		Retained
Earnings		Accumulated
Other
Comprehensive
Loss, net		Noncontrolling
Interests		Total Shareholders'
Equity
Balance at December 31, 2022995,830 $20,908 $(123)$4,597 $(638)$— $24,744 
Net income— — — 669 — — 669 
Long-term incentive plan activity306 1 — — — — 1 
Employee stock purchase plan issuances266 12 — — — — 12 
Common stock dividends
($0.36/common share)
— — — (359)— (359)
Other comprehensive loss, net of income taxes— — — — (1)— (1)
Balance at March 31, 2023996,402 $20,921 $(123)$4,907 $(639)$— $25,066 
Net income— — — 343 — — 343 
Long-term incentive plan activity372 9 — — — — 9 
Employee stock purchase plan issuances278 11 — — — — 11 
Common stock dividends
($0.36/common share)
— — — (359)— — (359)
Other comprehensive income, net of income taxes— — — — 9 — 9 
Balance at June 30, 2023997,052 $20,941 $(123)$4,891 $(630)$— $25,079 
Net income — — — 700 — — 700 
Long-term incentive plan activity(84)3 — — — — 3 
Employee stock purchase plan issuances302 12 — — — — 12 
Common stock dividends
($0.36/common share)
— — — (358)— — (358)
Other comprehensive income, net of income taxes— — — — 34 — 34 
Balance at September 30, 2023997,270 $20,956 $(123)$5,233 $(596)$— $25,470 















EXELON CORPORATION AND SUBSIDIARY COMPANIES
See the Combined Notes to Consolidated Financial Statements
13



CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS’ EQUITY
(Unaudited)

Nine Months Ended September 30, 2022
(In millions, shares
in thousands)		Issued
Shares		Common
Stock		Treasury
Stock		Retained
Earnings		Accumulated
Other
Comprehensive
Loss, net		Noncontrolling
Interests		Total Shareholders'
Equity
Balance at December 31, 2021981,291 $20,324 $(123)$16,942 $(2,750)$402 $34,795 
Net income— — — 597 — 1 598 
Long-term incentive plan activity540 (13)— — — — (13)
Employee stock purchase plan issuances211 9 — — — — 9 
Changes in equity of noncontrolling interests— — — — — (7)(7)
Distribution of Constellation (Note 2)— (21)— (13,179)2,023 (396)(11,573)
Common stock dividends
($0.34/common share)
— — — (332)— — (332)
Other comprehensive income, net of income taxes— — — — 14 — 14 
Balance at March 31, 2022982,042 $20,299 $(123)$4,028 $(713)$— $23,491 
Net income— — — 465 — — 465 
Long-term incentive plan activity21 10 — — — — 10 
Employee stock purchase plan issuances242 10 — — — — 10 
Common stock dividends
($0.34/common share)
— — — (332)— — (332)
Other comprehensive income, net of income taxes— — — — 12 — 12 
Balance at June 30, 2022982,305 $20,319 $(123)$4,161 $(701)$— $23,656 
Net Income— — — 676 — — 676 
Long-term incentive plan activity— 3 — — — — 3 
Employee stock purchase plan issuances275 10 — — — — 10 
Issuance of common stock12,995 563 563 
Common stock dividends
($0.34/common share)
— — — (335)— — (335)
Other comprehensive income, net of income taxes— — — — 9 — 9 
Balance at September 30, 2022995,575 $20,895 $(123)$4,502 $(692)$— $24,582 





See the Combined Notes to Consolidated Financial Statements
14



COMMONWEALTH EDISON COMPANY AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME
(Unaudited)
Three Months Ended
September 30,		Nine Months Ended
September 30,
(In millions)2023202220232022
Operating revenues
Electric operating revenues$2,124 $1,284 $5,417 $4,359 
Revenues from alternative revenue programs135 88 405 163 
Operating revenues from affiliates9 6 14 14 
Total operating revenues2,268 1,378 5,836 4,536 
Operating expenses
Purchased power896 121 2,068 982 
Purchased power from affiliate— — — 59 
Operating and maintenance293 286 814 809 
Operating and maintenance from affiliates92 69 263 236 
Depreciation and amortization357 333 1,045 982 
Taxes other than income taxes100 104 282 289 
Total operating expenses1,738 913 4,472 3,357 
Loss on sale of assets— — — (2)
Operating income530 465 1,364 1,177 
Other income and (deductions)
Interest expense, net(116)(101)(347)(298)
Interest expense to affiliates(3)(3)(10)(10)
Other, net16 14 50 40 
Total other income and (deductions)(103)(90)(307)(268)
Income before income taxes427 375 1,057 909 
Income taxes94 84 235 203 
Net income$333 $291 $822 $706 
Comprehensive income$333 $291 $822 $706 

See the Combined Notes to Consolidated Financial Statements
15



COMMONWEALTH EDISON COMPANY AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
Nine Months Ended
September 30,
(In millions)20232022
Cash flows from operating activities
Net income$822 $706 
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation and amortization1,045 982 
Deferred income taxes and amortization of investment tax credits164 192 
Other non-cash operating activities(392)(89)
Changes in assets and liabilities:
Accounts receivable(111)(351)
Receivables from and payables to affiliates, net(12)(54)
Inventories(64)(9)
Accounts payable and accrued expenses (199)226 
Collateral received, net28 69 
Income taxes50 — 
Regulatory assets and liabilities, net(248)(499)
Pension and non-pension postretirement benefit contributions(26)(179)
Other assets and liabilities(72)(152)
Net cash flows provided by operating activities985 842 
Cash flows from investing activities
Capital expenditures(1,926)(1,801)
Other investing activities8 21 
Net cash flows used in investing activities(1,918)(1,780)
Cash flows from financing activities
Changes in short-term borrowings(150)233 
Proceeds from short-term borrowings with maturities greater than 90 days400 — 
Repayments on short-term borrowings with maturities greater than 90 days(150)— 
Issuance of long-term debt975 750 
Dividends paid on common stock(560)(434)
Contributions from parent570 503 
Other financing activities(12)(10)
Net cash flows provided by financing activities1,073 1,042 
Increase in cash, restricted cash, and cash equivalents140 104 
Cash, restricted cash, and cash equivalents at beginning of period511 384 
Cash, restricted cash, and cash equivalents at end of period$651 $488 
Supplemental cash flow information
Decrease in capital expenditures not paid$(27)$(30)
See the Combined Notes to Consolidated Financial Statements
16



COMMONWEALTH EDISON COMPANY AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
(Unaudited)
(In millions)September 30, 2023December 31, 2022
ASSETS
Current assets
   Cash and cash equivalents$79 $67 
   Restricted cash and cash equivalents360 327 
   Accounts receivable
   Customer accounts receivable842558
   Customer allowance for credit losses(76)(59)
       Customer accounts receivable, net766 499 
   Other accounts receivable249441
   Other allowance for credit losses(20)(17)
       Other accounts receivable, net 229 424 
   Receivables from affiliates3 3 
   Inventories, net260 196 
   Regulatory assets1,439 775 
   Other113 92 
   Total current assets3,249 2,383 
Property, plant, and equipment (net of accumulated depreciation and amortization of $7,061 and $6,673 as of September 30, 2023 and December 31, 2022, respectively)
28,678 27,513 
Deferred debits and other assets
   Regulatory assets2,736 2,667 
   Goodwill2,625 2,625 
   Receivable related to Regulatory Agreement Units2,716 2,660 
   Investments6 6 
   Prepaid pension asset1,220 1,206 
   Other812 601 
   Total deferred debits and other assets10,115 9,765 
Total assets$42,042 $39,661 
See the Combined Notes to Consolidated Financial Statements
17



COMMONWEALTH EDISON COMPANY AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
(Unaudited)
(In millions)September 30, 2023December 31, 2022
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities
   Short-term borrowings$677 $577 
   Accounts payable850 1,010 
   Accrued expenses405 415 
   Payables to affiliates62 74 
   Customer deposits115 108 
   Regulatory liabilities189 226 
   Mark-to-market derivative liabilities21 5 
   Other201 191 
   Total current liabilities2,520 2,606 
Long-term debt11,484 10,518 
Long-term debt to financing trust205 205 
Deferred credits and other liabilities
   Deferred income taxes and unamortized investment tax credits5,269 5,021 
   Regulatory liabilities7,190 6,913 
   Asset retirement obligations151 148 
   Non-pension postretirement benefits obligations172 165 
   Mark-to-market derivative liabilities113 79 
   Other740 642 
   Total deferred credits and other liabilities13,635 12,968 
   Total liabilities27,844 26,297 
Commitments and contingencies
Shareholders’ equity
   Common stock 1,588 1,588 
   Other paid-in capital10,316 9,746 
   Retained earnings2,294 2,030 
   Total shareholders’ equity14,198 13,364 
Total liabilities and shareholders’ equity$42,042 $39,661 
    
See the Combined Notes to Consolidated Financial Statements
18



COMMONWEALTH EDISON COMPANY AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS’ EQUITY
(Unaudited)
Nine Months Ended September 30, 2023
(In millions)Common
Stock		Other
Paid-In
Capital		Retained
Earnings		Total
Shareholders’
Equity
Balance at December 31, 2022$1,588 $9,746 $2,030 $13,364 
Net income— — 241 241 
Common stock dividends— — (187)(187)
Contributions from parent— 186 — 186 
Balance at March 31, 2023$1,588 $9,932 $2,084 $13,604 
Net income— — 249 249 
Common stock dividends— — (187)(187)
Contributions from parent— 186 — 186 
Balance at June 30, 2023$1,588 $10,118 $2,146 $13,852 
Net income— — 333 333 
Common stock dividends— — (185)(185)
Contributions from parent— 198 — 198 
Balance at September 30, 2023$1,588 $10,316 $2,294 $14,198 
Nine Months Ended September 30, 2022
(In millions)Common
Stock		Other
Paid-In
Capital		Retained
Earnings		Total
Shareholders’
Equity
Balance at December 31, 2021$1,588 $9,076 $1,691 $12,355 
Net income— — 188 188 
Common stock dividends— — (144)(144)
Contributions from parent— 167 — 167 
Balance at March 31, 2022$1,588 $9,243 $1,735 $12,566 
Net income— — 227 227 
Common stock dividends— — (145)(145)
Contributions from parent— 168 — 168 
Balance at June 30, 2022$1,588 $9,411 $1,817 $12,816 
Net income— — 291 291 
Common stock dividends— — (145)(145)
Contributions from parent— 168 — 168 
Balance at September 30, 2022$1,588 $9,579 $1,963 $13,130 
See the Combined Notes to Consolidated Financial Statements
19




PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME
(Unaudited)
 Three Months Ended
September 30,		Nine Months Ended
September 30,
(In millions)2023202220232022
Operating revenues
Electric operating revenues$957 $943 $2,478 $2,384 
Natural gas operating revenues67 73 492 487 
Revenues from alternative revenue programs11 (5)1 1 
Operating revenues from affiliates2 3 6 5 
Total operating revenues1,037 1,014 2,977 2,877 
Operating expenses
Purchased power 396 377 994 850 
Purchased fuel15 26 203 210 
Purchased power from affiliate— — — 33 
Operating and maintenance217 197 622 561 
Operating and maintenance from affiliates60 46 164 144 
Depreciation and amortization100 92 297 277 
Taxes other than income taxes59 60 156 155 
Total operating expenses847 798 2,436 2,230 
Operating income190 216 541 647 
Other income and (deductions)
Interest expense, net(51)(42)(142)(120)
Interest expense to affiliates(1)(3)(7)(9)
Other, net11 8 26 23 
Total other income and (deductions)(41)(37)(123)(106)
Income before income taxes149 179 418 541 
Income taxes3 44 8 67 
Net income$146 $135 $410 $474 
Comprehensive income$146 $135 $410 $474 
See the Combined Notes to Consolidated Financial Statements
20



PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
Nine Months Ended
September 30,
(In millions)20232022
Cash flows from operating activities
Net income$410 $474 
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation and amortization297 277 
Deferred income taxes and amortization of investment tax credits(44)49 
Other non-cash operating activities2 14 
Changes in assets and liabilities:
Accounts receivable135 (49)
Receivables from and payables to affiliates, net(2)(34)
Inventories35 (59)
Accounts payable and accrued expenses (132)25 
Income taxes76 30 
Regulatory assets and liabilities, net1 (27)
Pension and non-pension postretirement benefit contributions(1)(13)
Other assets and liabilities— (31)
Net cash flows provided by operating activities777 656 
Cash flows from investing activities
Capital expenditures(1,068)(991)
Changes in Exelon intercompany money pool(51)— 
Other investing activities1 8 
Net cash flows used in investing activities(1,118)(983)
Cash flows from financing activities
Changes in short-term borrowings(239)— 
Issuance of long-term debt575 775 
Retirement of long-term debt(50)(350)
Dividends paid on common stock(303)(299)
Contributions from parent348 274 
Other financing activities(6)(14)
Net cash flows provided by financing activities325 386 
(Decrease) increase in cash, restricted cash, and cash equivalents(16)59 
Cash, restricted cash, and cash equivalents at beginning of period68 44 
Cash, restricted cash, and cash equivalents at end of period$52 $103 
Supplemental cash flow information
(Decrease) increase in capital expenditures not paid$(22)$7 
See the Combined Notes to Consolidated Financial Statements
21



PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
(Unaudited)
(In millions)September 30, 2023December 31, 2022
ASSETS
Current assets
Cash and cash equivalents$43 $59 
Restricted cash and cash equivalents9 9 
Accounts receivable
Customer accounts receivable467635
Customer allowance for credit losses(95)(105)
Customer accounts receivable, net372 530 
Other accounts receivable136153
Other allowance for credit losses(8)(9)
Other accounts receivable, net128 144 
Receivables from affiliates1 4 
Receivable from Exelon intercompany money pool51 — 
Inventories, net
Fossil fuel56 99 
Materials and supplies60 52 
Prepaid utility taxes17 — 
Regulatory assets120 80 
Other52 38 
Total current assets909 1,015 
Property, plant, and equipment (net of accumulated depreciation and amortization of $4,056 and $4,078 as of September 30, 2023 and December 31, 2022, respectively)
12,895 12,125 
Deferred debits and other assets
Regulatory assets762 652 
Receivable related to Regulatory Agreement Units206 237 
Investments34 30 
Prepaid pension asset425 413 
Other28 30 
Total deferred debits and other assets1,455 1,362 
Total assets$15,259 $14,502 
See the Combined Notes to Consolidated Financial Statements
22



PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
(Unaudited)
(In millions)September 30, 2023December 31, 2022
LIABILITIES AND SHAREHOLDER'S EQUITY
Current liabilities
Short-term borrowings$— $239 
Long-term debt due within one year— 50 
Accounts payable543 668 
Accrued expenses183 142 
Payables to affiliates37 42 
Customer deposits77 63 
Regulatory liabilities112 75 
Other49 32 
Total current liabilities1,001 1,311 
Long-term debt5,133 4,562 
Long-term debt to financing trusts184 184 
Deferred credits and other liabilities
Deferred income taxes and unamortized investment tax credits2,286 2,213 
Regulatory liabilities239 270 
Asset retirement obligations27 28 
Non-pension postretirement benefits obligations287 286 
Other85 85 
Total deferred credits and other liabilities2,924 2,882 
Total liabilities9,242 8,939 
Commitments and contingencies
Shareholder’s equity
Common stock4,050 3,702 
Retained earnings1,967 1,861 
Total shareholder’s equity6,017 5,563 
Total liabilities and shareholder's equity$15,259 $14,502 
See the Combined Notes to Consolidated Financial Statements
23



PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDER’S EQUITY
(Unaudited)
Nine Months Ended September 30, 2023
(In millions)Common
Stock		Retained
Earnings		Total
Shareholder's
Equity
Balance at December 31, 2022$3,702 $1,861 $5,563 
Net income— 166 166 
Common stock dividends— (101)(101)
Contributions from parent330 — 330 
Balance at March 31, 2023$4,032 $1,926 $5,958 
Net income— 97 97 
Common stock dividends— (101)(101)
Balance at June 30, 2023$4,032 $1,922 $5,954 
Net income— 146 146 
Common stock dividends— (101)(101)
Contributions from parent18 — 18 
Balance at September 30, 2023$4,050 $1,967 $6,017 
Nine Months Ended September 30, 2022
(In millions)Common
Stock		Retained
Earnings		Total
Shareholder's
Equity
Balance at December 31, 2021$3,428 $1,684 $5,112 
Net income— 206 206 
Common stock dividends— (100)(100)
Contributions from parent227 — 227 
Balance at March 31, 2022$3,655 $1,790 $5,445 
Net income— 133 133 
Common stock dividends— (100)(100)
Balance at June 30, 2022$3,655 $1,823 $5,478 
Net income— 135 135 
Common stock dividends— (99)(99)
Contributions from parent47 — 47 
Balance at September 30, 2022$3,702 $1,859 $5,561 
See the Combined Notes to Consolidated Financial Statements
24




BALTIMORE GAS AND ELECTRIC COMPANY
STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME
(Unaudited)
Three Months Ended
September 30,		Nine Months Ended
September 30,
(In millions)2023202220232022
Operating revenues
Electric operating revenues$856 $761 $2,306 $2,138 
Natural gas operating revenues96 114 627 699 
Revenues from alternative revenue programs(22)(8)47 (40)
Operating revenues from affiliates2 3 6 13 
Total operating revenues932 870 2,986 2,810 
Operating expenses
Purchased power371 320 975 846 
Purchased fuel9 30 170 229 
Purchased power from affiliate— — — 18 
Operating and maintenance156 185 467 506 
Operating and maintenance from affiliates58 50 165 152 
Depreciation and amortization161 148 487 470 
Taxes other than income taxes80 77 239 225 
Total operating expenses835 810 2,503 2,446 
Operating income97 60 483 364 
Other income and (deductions)
Interest expense, net(47)(39)(135)(110)
Other, net6 5 14 16 
Total other income and (deductions)(41)(34)(121)(94)
Income before income taxes56 26 362 270 
Income taxes11 (7)76 3 
Net income$45 $33 $286 $267 
Comprehensive income$45 $33 $286 $267 
See the Combined Notes to Consolidated Financial Statements
25



BALTIMORE GAS AND ELECTRIC COMPANY
STATEMENTS OF CASH FLOWS
(Unaudited)
Nine Months Ended
September 30,
(In millions)20232022
Cash flows from operating activities
Net income$286 $267 
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation and amortization487 470 
Asset impairments— 46 
Deferred income taxes and amortization of investment tax credits41 1 
Other non-cash operating activities— 101 
Changes in assets and liabilities:
Accounts receivable194 18 
Receivables from and payables to affiliates, net(7)(9)
Inventories45 (74)
Accounts payable and accrued expenses(38)15 
Collateral (paid) received, net(22)125 
Income taxes19 (20)
Regulatory assets and liabilities, net(151)(113)
Pension and non-pension postretirement benefit contributions(15)(64)
Other assets and liabilities46 14 
Net cash flows provided by operating activities885 777 
Cash flows from investing activities
Capital expenditures(986)(918)
Other investing activities6 7 
Net cash flows used in investing activities(980)(911)
Cash flows from financing activities
Changes in short-term borrowings(349)26 
Issuance of long-term debt700 500 
Retirement of long-term debt(300)(250)
Dividends paid on common stock(237)(225)
Contributions from parent237 186 
Other financing activities(7)(8)
Net cash flows provided by financing activities44 229 
(Decrease) increase in cash, restricted cash, and cash equivalents(51)95 
Cash, restricted cash, and cash equivalents at beginning of period67 55 
Cash, restricted cash, and cash equivalents at end of period$16 $150 
Supplemental cash flow information
(Decrease) increase in capital expenditures not paid$(17)$12 
See the Combined Notes to Consolidated Financial Statements
26



BALTIMORE GAS AND ELECTRIC COMPANY
BALANCE SHEETS
(Unaudited)
(In millions)September 30, 2023December 31, 2022
ASSETS
Current assets
Cash and cash equivalents$15 $43 
Restricted cash and cash equivalents1 24 
Accounts receivable
Customer accounts receivable438617
Customer allowance for credit losses (52)(54)
    Customer accounts receivable, net386 563 
Other accounts receivable 110132
Other allowance for credit losses(9)(10)
     Other accounts receivable, net101 122 
Inventories, net
Fossil fuel41 91 
Materials and supplies70 65 
Prepaid utility taxes1 52 
Regulatory assets227 177 
Other19 13 
Total current assets861 1,150 
Property, plant, and equipment (net of accumulated depreciation and amortization of $4,679 and $4,583 as of September 30, 2023 and December 31, 2022, respectively)
11,893 11,338 
Deferred debits and other assets
Regulatory assets591 527 
Investments9 7 
Prepaid pension asset259 291 
Other36 37 
Total deferred debits and other assets895 862 
Total assets$13,649 $13,350 
See the Combined Notes to Consolidated Financial Statements
27



BALTIMORE GAS AND ELECTRIC COMPANY
BALANCE SHEETS
(Unaudited)
(In millions)September 30, 2023December 31, 2022
LIABILITIES AND SHAREHOLDER'S EQUITY
Current liabilities
Short-term borrowings$59 $408 
Long-term debt due within one year— 300 
Accounts payable364 462 
Accrued expenses224 159 
Payables to affiliates33 39 
Customer deposits111 105 
Regulatory liabilities36 47 
Other34 55 
Total current liabilities861 1,575 
Long-term debt4,601 3,907 
Deferred credits and other liabilities
Deferred income taxes and unamortized investment tax credits1,905 1,832 
Regulatory liabilities787 816 
Asset retirement obligations32 30 
Non-pension postretirement benefits obligations160 166 
Other81 88 
Total deferred credits and other liabilities2,965 2,932 
Total liabilities8,427 8,414 
Commitments and contingencies
Shareholder's equity
Common stock3,098 2,861 
Retained earnings2,124 2,075 
Total shareholder's equity5,222 4,936 
Total liabilities and shareholder's equity$13,649 $13,350 

See the Combined Notes to Consolidated Financial Statements
28



BALTIMORE GAS AND ELECTRIC COMPANY
STATEMENTS OF CHANGES IN SHAREHOLDER'S EQUITY
(Unaudited)
Nine Months Ended September 30, 2023
(In millions)Common
Stock		Retained
Earnings		Total
Shareholder's
Equity
Balance at December 31, 2022$2,861 $2,075 $4,936 
Net income— 200 200 
Common stock dividends— (80)(80)
Contributions from parent237 — 237 
Balance at March 31, 2023$3,098 $2,195 $5,293 
Net income— 42 42 
Common stock dividends— (79)(79)
Balance at June 30, 2023$3,098 $2,158 $5,256 
Net income— 45 45 
Common stock dividends— (79)(79)
Balance at September 30, 2023$3,098 $2,124 $5,222 
Nine Months Ended September 30, 2022
(In millions)Common
Stock		Retained
Earnings		Total
Shareholder's
Equity
Balance at December 31, 2021$2,575 $1,995 $4,570 
Net income— 198 198 
Common stock dividends— (76)(76)
Balance at March 31, 2022$2,575 $2,117 $4,692 
Net income— 37 37 
Common stock dividends— (75)(75)
Contributions from parent186 — 186 
Balance at June 30, 2022$2,761 $2,079 $4,840 
Net income— 33 33 
Common stock dividends— (75)(75)
Balance at September 30, 2022$2,761 $2,037 $4,798 
See the Combined Notes to Consolidated Financial Statements
29




PEPCO HOLDINGS LLC AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME
(Unaudited)
Three Months Ended
September 30,		Nine Months Ended
September 30,
(In millions)2023202220232022
Operating revenues
Electric operating revenues$1,762 $1,568 $4,399 $4,090 
Natural gas operating revenues24 38 150 157 
Revenues from alternative revenue programs(15)(11)59 (33)
Operating revenues from affiliates2 3 7 9 
Total operating revenues1,773 1,598 4,615 4,223 
Operating expenses
Purchased power701 586 1,729 1,474 
Purchased fuel9 24 76 85 
Purchased power from affiliate— — — 50 
Operating and maintenance288 237 815 729 
Operating and maintenance from affiliates51 40 137 138 
Depreciation and amortization257 238 741 697 
Taxes other than income taxes134 129 366 362 
Total operating expenses1,440 1,254 3,864 3,535 
Operating income333 344 751 688 
Other income and (deductions)
Interest expense, net(80)(72)(238)(216)
Other, net28 19 80 56 
Total other income and (deductions)(52)(53)(158)(160)
Income before income taxes 281 291 593 528 
Income taxes49 2 103 10 
Net income$232 $289 $490 $518 
Comprehensive income$232 $289 $490 $518 
See the Combined Notes to Consolidated Financial Statements
30



PEPCO HOLDINGS LLC AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
Nine Months Ended
September 30,
(In millions)20232022
Cash flows from operating activities
Net income$490 $518 
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation and amortization741 697 
Deferred income taxes and amortization of investment tax credits44 (2)
Other non-cash operating activities80 112 
Changes in assets and liabilities:
Accounts receivable(160)(143)
Receivables from and payables to affiliates, net(8)(49)
Inventories(22)(35)
Accounts payable and accrued expenses23 (15)
Collateral (paid) received, net(191)230 
Income taxes37 (3)
Regulatory assets and liabilities, net(2)(82)
Pension and non-pension postretirement benefit contributions(15)(75)
Other assets and liabilities(98)(71)
Net cash flows provided by operating activities919 1,082 
Cash flows from investing activities
Capital expenditures(1,510)(1,174)
Other investing activities8 5 
Net cash flows used in investing activities(1,502)(1,169)
Cash flows from financing activities
Changes in short-term borrowings(241)(468)
Issuance of long-term debt550 925 
Retirement of long-term debt— (310)
Changes in Exelon intercompany money pool18 36 
Distributions to member(410)(625)
Contributions from member475 787 
Other financing activities(36)(18)
Net cash flows provided by financing activities356 327 
(Decrease) increase in cash, restricted cash, and cash equivalents(227)240 
Cash, restricted cash, and cash equivalents at beginning of period373 213 
Cash, restricted cash, and cash equivalents at end of period$146 $453 
Supplemental cash flow information
Decrease in capital expenditures not paid$(96)$(8)
See the Combined Notes to Consolidated Financial Statements
31



PEPCO HOLDINGS LLC AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
(Unaudited)
(In millions)September 30, 2023December 31, 2022
ASSETS
Current assets
Cash and cash equivalents$121 $198 
Restricted cash and cash equivalents25 175 
Accounts receivable
Customer accounts receivable828734
Customer allowance for credit losses(118)(109)
Customer accounts receivable, net710 625 
Other accounts receivable331300
Other allowance for credit losses(51)(46)
Other accounts receivable, net280 254 
Receivables from affiliates3 2 
Inventories, net
Fossil fuel9 18 
Materials and supplies267 236 
Regulatory assets366 455 
Other77 96 
Total current assets1,858 2,059 
Property, plant, and equipment (net of accumulated depreciation and amortization of $3,044 and $2,618 as of September 30, 2023 and December 31, 2022, respectively)
18,577 17,686 
Deferred debits and other assets
Regulatory assets1,568 1,610 
Goodwill4,005 4,005 
Investments143 138 
Prepaid pension asset289 353 
Other216 231 
Total deferred debits and other assets6,221 6,337 
Total assets$26,656 $26,082 
See the Combined Notes to Consolidated Financial Statements
32



PEPCO HOLDINGS LLC AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
(Unaudited)
(In millions)September 30, 2023December 31, 2022
LIABILITIES AND MEMBER'S EQUITY
Current liabilities
Short-term borrowings$173 $414 
Long-term debt due within one year1,146 591 
Accounts payable664 771 
Accrued expenses324 260 
Payables to affiliates59 66 
Borrowings from Exelon intercompany money pool61 44 
Customer deposits98 88 
Regulatory liabilities 87 76 
Unamortized energy contract liabilities8 10 
PPA termination obligation61 87 
Other129 330 
Total current liabilities2,810 2,737 
Long-term debt7,491 7,529 
Deferred credits and other liabilities
Deferred income taxes and unamortized investment tax credits3,023 2,895 
Regulatory liabilities924 1,011 
Asset retirement obligations54 59 
Non-pension postretirement benefit obligations45 50 
Unamortized energy contract liabilities29 35 
Other495 536 
Total deferred credits and other liabilities4,570 4,586 
Total liabilities14,871 14,852 
Commitments and contingencies
Member's equity
Membership interest12,057 11,582 
Undistributed losses(272)(352)
Total member's equity11,785 11,230 
Total liabilities and member's equity$26,656 $26,082 
See the Combined Notes to Consolidated Financial Statements
33



PEPCO HOLDINGS LLC AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF CHANGES IN MEMBER'S EQUITY
(Unaudited)
Nine Months Ended September 30, 2023
(In millions)Membership InterestUndistributed (Losses)/GainsTotal Member's Equity
Balance at December 31, 2022$11,582 $(352)$11,230 
Net income— 155 155 
Distributions to member— (112)(112)
Contributions from member405 — 405 
Balance at March 31, 2023$11,987 $(309)$11,678 
Net income— 103 103 
Distributions to member— (100)(100)
Balance at June 30, 2023$11,987 $(306)$11,681 
Net income— 232 232 
Distributions to member— (198)(198)
Contributions from member70 — 70 
Balance at September 30, 2023$12,057 $(272)$11,785 

Nine Months Ended September 30, 2022
(In millions)Membership InterestUndistributed (Losses)/GainsTotal Member's Equity
Balance at December 31, 2021$10,795 $(210)$10,585 
Net income— 130 130 
Distributions to member— (102)(102)
Contributions from member704 — 704 
Balance at March 31, 2022$11,499 $(182)$11,317 
Net income— 100 100 
Distributions to member— (293)(293)
Balance at June 30, 2022$11,499 $(375)$11,124 
Net income— 289 289 
Distributions to member— (230)(230)
Contributions from member83 — 83 
Balance at September 30, 2022$11,582 $(316)$11,266 
See the Combined Notes to Consolidated Financial Statements
34




POTOMAC ELECTRIC POWER COMPANY
STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME
(Unaudited)
Three Months Ended
September 30,		Nine Months Ended
September 30,
(In millions)2023202220232022
Operating revenues
Electric operating revenues$839 $730 $2,141 $1,930 
Revenues from alternative revenue programs(18)(8)28 (15)
Operating revenues from affiliates1 2 5 4 
Total operating revenues822 724 2,174 1,919 
Operating expenses
Purchased power288 230 750 566 
Purchased power from affiliate— — — 39 
Operating and maintenance89 69 264 214 
Operating and maintenance from affiliates60 52 176 166 
Depreciation and amortization112 99 329 312 
Taxes other than income taxes109 105 291 291 
Total operating expenses658 555 1,810 1,588 
Operating income164 169 364 331 
Other income and (deductions)
Interest expense, net(41)(37)(122)(111)
Other, net18 14 50 39 
Total other income and (deductions)(23)(23)(72)(72)
Income before income taxes141 146 292 259 
Income taxes21 1 43 (2)
Net income$120 $145 $249 $261 
Comprehensive income$120 $145 $249 $261 
See the Combined Notes to Consolidated Financial Statements
35



POTOMAC ELECTRIC POWER COMPANY
STATEMENTS OF CASH FLOWS
(Unaudited)
Nine Months Ended
September 30,
(In millions)20232022
Cash flows from operating activities
Net income$249 $261 
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation and amortization329 312 
Deferred income taxes and amortization of investment tax credits22 (5)
Other non-cash operating activities38 20 
Changes in assets and liabilities:
Accounts receivable(84)(87)
Receivables from and payables to affiliates, net(2)(31)
Inventories(12)(19)
Accounts payable and accrued expenses 33 11 
Collateral (paid) received, net(26)46 
Income taxes15 (25)
Regulatory assets and liabilities, net(7)(44)
Pension and non-pension postretirement benefit contributions(9)(9)
Other assets and liabilities(13)(29)
Net cash flows provided by operating activities533 401 
Cash flows from investing activities
Capital expenditures(710)(595)
Changes in PHI intercompany money pool(7)— 
Other investing activities8 2 
Net cash flows used in investing activities(709)(593)
Cash flows from financing activities
Changes in short-term borrowings(299)(175)
Issuance of long-term debt350 625 
Retirement of long-term debt— (310)
Changes in PHI intercompany money pool— 25 
Dividends paid on common stock(200)(400)
Contributions from parent308 465 
Other financing activities(26)(8)
Net cash flows provided by financing activities133 222 
(Decrease) increase in cash, restricted cash, and cash equivalents(43)30 
Cash, restricted cash, and cash equivalents at beginning of period99 68 
Cash, restricted cash, and cash equivalents at end of period$56 $98 
Supplemental cash flow information
(Decrease) increase in capital expenditures not paid$(39)$2 
See the Combined Notes to Consolidated Financial Statements
36



POTOMAC ELECTRIC POWER COMPANY
BALANCE SHEETS
(Unaudited)
(In millions)September 30, 2023December 31, 2022
ASSETS
Current assets
Cash and cash equivalents$31 $45 
Restricted cash and cash equivalents25 54 
Accounts receivable
Customer accounts receivable414351
Customer allowance for credit losses(56)(47)
Customer accounts receivable, net358 304 
Other accounts receivable189180
Other allowance for credit losses(29)(25)
Other accounts receivable, net160 155 
Receivable from PHI intercompany money pool7 — 
Inventories, net147 135 
Regulatory assets187 235 
Other16 53 
Total current assets931 981 
Property, plant, and equipment (net of accumulated depreciation and amortization of $4,231 and $4,067 as of September 30, 2023 and December 31, 2022, respectively)
9,274 8,794 
Deferred debits and other assets
Regulatory assets422 437 
Investments124 119 
Prepaid pension asset252 273 
Other58 53 
Total deferred debits and other assets856 882 
Total assets$11,061 $10,657 
See the Combined Notes to Consolidated Financial Statements
37



POTOMAC ELECTRIC POWER COMPANY
BALANCE SHEETS
(Unaudited)
(In millions)September 30, 2023December 31, 2022
LIABILITIES AND SHAREHOLDER'S EQUITY
Current liabilities
Short-term borrowings$— $299 
Long-term debt due within one year405 4 
Accounts payable346 382 
Accrued expenses163 125 
Payables to affiliates32 34 
Customer deposits45 39 
Regulatory liabilities 24 6 
Merger related obligation26 26 
Other49 93 
Total current liabilities1,090 1,008 
Long-term debt3,690 3,747 
Deferred credits and other liabilities
Deferred income taxes and unamortized investment tax credits1,456 1,382 
Regulatory liabilities 394 455 
Asset retirement obligations36 39 
Other256 244 
Total deferred credits and other liabilities2,142 2,120 
Total liabilities6,922 6,875 
Commitments and contingencies
Shareholder's equity
Common stock 3,075 2,767 
Retained earnings1,064 1,015 
Total shareholder's equity4,139 3,782 
Total liabilities and shareholder's equity$11,061 $10,657 
See the Combined Notes to Consolidated Financial Statements
38



POTOMAC ELECTRIC POWER COMPANY
STATEMENTS OF CHANGES IN SHAREHOLDER'S EQUITY
(Unaudited)
Nine Months Ended September 30, 2023
(In millions)Common StockRetained EarningsTotal Shareholder's Equity
Balance at December 31, 2022$2,767 $1,015 $3,782 
Net income— 65 65 
Common stock dividends— (48)(48)
Contributions from parent243 — 243 
Balance at March 31, 2023$3,010 $1,032 $4,042 
Net income— 64 64 
Common stock dividends— (67)(67)
Balance at June 30, 2023$3,010 $1,029 $4,039 
Net income— 120 120 
Common stock dividends— (85)(85)
Contributions from parent65 — 65 
Balance at September 30, 2023$3,075 $1,064 $4,139 

Nine Months Ended September 30, 2022
(In millions)Common StockRetained EarningsTotal Shareholder's Equity
Balance at December 31, 2021$2,302 $1,173 $3,475 
Net income— 46 46 
Common stock dividends— (42)(42)
Contributions from parent387 — 387 
Balance at March 31, 2022$2,689 $1,177 $3,866 
Net income— 70 70 
Common stock dividends— (258)(258)
Balance at June 30, 2022$2,689 $989 $3,678 
Net income— 145 145 
Common stock dividends— (100)(100)
Contributions from parent78 — 78 
Balance at September 30, 2022$2,767 $1,034 $3,801 

See the Combined Notes to Consolidated Financial Statements
39




DELMARVA POWER & LIGHT COMPANY
STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME
(Unaudited)
Three Months Ended
September 30,		Nine Months Ended
September 30,
(In millions)2023202220232022
Operating revenues
Electric operating revenues$426 $373 $1,108 $1,017 
Natural gas operating revenues24 38 150 157 
Revenues from alternative revenue programs(2)— 10 (3)
Operating revenues from affiliates2 1 5 5 
Total operating revenues450 412 1,273 1,176 
Operating expenses
Purchased power192 159 486 412 
Purchased fuel9 24 76 85 
Purchased power from affiliate— — — 10 
Operating and maintenance60 45 150 142 
Operating and maintenance from affiliates 44 39 128 124 
Depreciation and amortization62 59 182 172 
Taxes other than income taxes19 19 57 54 
Total operating expenses386 345 1,079 999 
Operating income64 67 194 177 
Other income and (deductions)
Interest expense, net(18)(16)(53)(48)
Other, net5 3 12 9 
Total other income and (deductions)(13)(13)(41)(39)
Income before income taxes51 54 153 138 
Income taxes8 2 25 8 
Net income$43 $52 $128 $130 
Comprehensive income$43 $52 $128 $130 
See the Combined Notes to Consolidated Financial Statements
40



DELMARVA POWER & LIGHT COMPANY
STATEMENTS OF CASH FLOWS
(Unaudited)
Nine Months Ended
September 30,
(In millions)20232022
Cash flows from operating activities
Net income$128 $130 
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation and amortization182 172 
Deferred income taxes and amortization of investment tax credits4 9 
Other non-cash operating activities11 22 
Changes in assets and liabilities:
Accounts receivable9 (3)
Receivables from and payables to affiliates, net3 (8)
Inventories2 (11)
Accounts payable and accrued expenses(1)— 
Collateral (paid) received, net(120)114 
Income taxes15 4 
Regulatory assets and liabilities, net33 (23)
Pension and non-pension postretirement benefit contributions— (1)
Other assets and liabilities8 23 
Net cash flows provided by operating activities274 428 
Cash flows from investing activities
Capital expenditures(416)(294)
Changes in PHI intercompany money pool(10)(25)
Other investing activities— 2 
Net cash flows used in investing activities(426)(317)
Cash flows from financing activities
Changes in short-term borrowings(115)(149)
Issuance of long-term debt125 125 
Dividends paid on common stock(97)(95)
Contributions from parent99 147 
Other financing activities(6)(4)
Net cash flows provided by financing activities6 24 
(Decrease) increase in cash, restricted cash, and cash equivalents(146)135 
Cash, restricted cash, and cash equivalents at beginning of period152 71 
Cash, restricted cash, and cash equivalents at end of period$6 $206 
Supplemental cash flow information
Increase in capital expenditures not paid$— $2 
    
See the Combined Notes to Consolidated Financial Statements
41



DELMARVA POWER & LIGHT COMPANY
BALANCE SHEETS
(Unaudited)
(In millions)September 30, 2023December 31, 2022
ASSETS
Current assets
Cash and cash equivalents$5 $31 
Restricted cash and cash equivalents1 121 
Accounts receivable
Customer accounts receivable179204
Customer allowance for credit losses(23)(21)
Customer accounts receivable, net156 183 
Other accounts receivable5952
Other allowance for credit losses(9)(7)
Other accounts receivable, net50 45 
Receivable from PHI intercompany pool10 — 
Inventories, net
Fossil fuel9 18 
Materials and supplies65 58 
Prepaid utility taxes30 23 
Regulatory assets55 80 
Other9 14 
Total current assets390 573 
Property, plant, and equipment (net of accumulated depreciation and amortization of $1,893 and $1,772 as of September 30, 2023 and December 31, 2022, respectively)
5,079 4,820 
Deferred debits and other assets
Regulatory assets210 202 
Prepaid pension asset140 153 
Other51 54 
Total deferred debits and other assets401 409 
Total assets$5,870 $5,802 
See the Combined Notes to Consolidated Financial Statements
42



DELMARVA POWER & LIGHT COMPANY
BALANCE SHEETS
(Unaudited)
(In millions)September 30, 2023December 31, 2022
LIABILITIES AND SHAREHOLDER'S EQUITY
Current liabilities
Short-term borrowings$— $115 
Long-term debt due within one year584 584 
Accounts payable161 172 
Accrued expenses63 41 
Payables to affiliates25 22 
Customer deposits31 29 
Regulatory liabilities 55 44 
Other21 136 
Total current liabilities940 1,143 
Long-term debt1,476 1,354 
Deferred credits and other liabilities
Deferred income taxes and unamortized investment tax credits896 869 
Regulatory liabilities368 380 
Asset retirement obligations12 13 
Non-pension postretirement benefits obligations9 9 
Other89 84 
Total deferred credits and other liabilities1,374 1,355 
Total liabilities3,790 3,852 
Commitments and contingencies
Shareholder's equity
Common stock 1,455 1,356 
Retained earnings625 594 
Total shareholder's equity2,080 1,950 
Total liabilities and shareholder's equity$5,870 $5,802 
See the Combined Notes to Consolidated Financial Statements
43



DELMARVA POWER & LIGHT COMPANY
STATEMENTS OF CHANGES IN SHAREHOLDER'S EQUITY
(Unaudited)
Nine Months Ended September 30, 2023
(In millions)Common Stock Retained EarningsTotal Shareholder's Equity
Balance at December 31, 2022$1,356 $594 $1,950 
Net income— 60 60 
Common stock dividends— (42)(42)
Contributions from parent99 — 99 
Balance at March 31, 2023$1,455 $612 $2,067 
Net income— 25 25 
Common stock dividends— (18)(18)
Balance at June 30, 2023$1,455 $619 $2,074 
Net income— 43 43 
Common stock dividends— (37)(37)
Balance at September 30, 2023$1,455 $625 $2,080 

Nine Months Ended September 30, 2022
(In millions)Common Stock Retained EarningsTotal Shareholder's Equity
Balance at December 31, 2021$1,209 $568 $1,777 
Net income— 56 56 
Common stock dividends— (41)(41)
Contributions from parent144 — 144 
Balance at March 31, 2022$1,353 $583 $1,936 
Net income— 21 21 
Common stock dividends— (15)(15)
Balance at June 30, 2022$1,353 $589 $1,942 
Net income— 52 52 
Common stock dividends— (39)(39)
Contributions from parent3 — 3 
Balance, September 30, 2022$1,356 $602 $1,958 

See the Combined Notes to Consolidated Financial Statements
44




ATLANTIC CITY ELECTRIC COMPANY AND SUBSIDIARY COMPANY
CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME
(Unaudited)
Three Months Ended
September 30,		Nine Months Ended
September 30,
(In millions)2023202220232022
Operating revenues
Electric operating revenues$497 $465 $1,150 $1,132 
Revenues from alternative revenue programs5 (3)21 (14)
Operating revenues from affiliates— — 1 2 
Total operating revenues502 462 1,172 1,120 
Operating expenses
Purchased power221 197 493 495 
Purchased power from affiliate— — — 2 
Operating and maintenance56 47 147 145 
Operating and maintenance from affiliates38 33 112 106 
Depreciation and amortization77 74 212 192 
Taxes other than income taxes2 2 7 7 
Total operating expenses394 353 971 947 
Operating income108 109 201 173 
Other income and (deductions)
Interest expense, net(19)(17)(52)(49)
Other, net5 3 13 9 
Total other income and (deductions)(14)(14)(39)(40)
Income before income taxes94 95 162 133 
Income taxes23 1 40 2 
Net income$71 $94 $122 $131 
Comprehensive income$71 $94 $122 $131 
See the Combined Notes to Consolidated Financial Statements
45



ATLANTIC CITY ELECTRIC COMPANY AND SUBSIDIARY COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
Nine Months Ended
September 30,
(In millions)20232022
Cash flows from operating activities
Net income$122 $131 
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation and amortization212 192 
Deferred income taxes and amortization of investment tax credits24 2 
Other non-cash operating activities(2)36 
Changes in assets and liabilities:
Accounts receivable(85)(53)
Receivables from and payables to affiliates, net(6)(10)
Inventories(11)(6)
Accounts payable and accrued expenses(4)(10)
Collateral (paid) received, net(45)70 
Income taxes6 7 
Regulatory assets and liabilities, net(28)(6)
Pension and non-pension postretirement benefit contributions(1)(7)
Other assets and liabilities(80)(54)
Net cash flows provided by operating activities102 292 
Cash flows from investing activities
Capital expenditures(376)(284)
Other investing activities— 1 
Net cash flows used in investing activities(376)(283)
Cash flows from financing activities
Changes in short-term borrowings173 (144)
Issuance of long-term debt75 175 
Changes in PHI intercompany money pool17 — 
Dividends paid on common stock(111)(128)
Contributions from parent65 175 
Other financing activities(3)(4)
Net cash flows provided by financing activities216 74 
(Decrease) increase in cash and cash equivalents(58)83 
Cash and cash equivalents at beginning of period72 29 
Cash and cash equivalents at end of period$14 $112 
Supplemental cash flow information
Decrease in capital expenditures not paid$(56)$(12)
See the Combined Notes to Consolidated Financial Statements
46



ATLANTIC CITY ELECTRIC COMPANY AND SUBSIDIARY COMPANY
CONSOLIDATED BALANCE SHEETS
(Unaudited)
(In millions)September 30, 2023December 31, 2022
ASSETS
Current assets
Cash and cash equivalents$14 $72 
Accounts receivable
Customer accounts receivable235179
Customer allowance for credit losses(39)(41)
Customer accounts receivable, net196 138 
Other accounts receivable8470
Other allowance for credit losses(13)(14)
Other accounts receivable, net71 56 
Receivables from affiliates3 1 
Inventories, net54 43 
Prepaid utility taxes15 — 
Regulatory assets113 130 
Other5 3 
Total current assets471 443 
Property, plant, and equipment (net of accumulated depreciation and amortization of $1,651 and $1,551 as of September 30, 2023 and December 31, 2022, respectively)
4,155 3,990 
Deferred debits and other assets
Regulatory assets490 494 
Prepaid pension asset7 18 
Other32 34 
Total deferred debits and other assets529 546 
Total assets$5,155 $4,979 
See the Combined Notes to Consolidated Financial Statements
47



ATLANTIC CITY ELECTRIC COMPANY AND SUBSIDIARY COMPANY
CONSOLIDATED BALANCE SHEETS
(Unaudited)
(In millions)September 30, 2023December 31, 2022
LIABILITIES AND SHAREHOLDER'S EQUITY
Current liabilities
Short-term borrowings$173 $— 
Long-term debt due within one year153 3 
Accounts payable149 206 
Accrued expenses51 47 
Payables to affiliates22 26 
Borrowings from PHI intercompany money pool17 — 
Customer deposits23 21 
Regulatory liabilities9 26 
PPA termination obligation61 87 
Other15 58 
Total current liabilities673 474 
Long-term debt1,680 1,754 
Deferred credits and other liabilities
Deferred income taxes and unamortized investment tax credits766 734 
Regulatory liabilities144 156 
Non-pension postretirement benefit obligations6 8 
Other57 100 
Total deferred credits and other liabilities973 998 
Total liabilities3,326 3,226 
Commitments and contingencies
Shareholder's equity
Common stock1,830 1,765 
Retained deficit(1)(12)
Total shareholder's equity1,829 1,753 
Total liabilities and shareholder's equity$5,155 $4,979 

See the Combined Notes to Consolidated Financial Statements
48




ATLANTIC CITY ELECTRIC COMPANY AND SUBSIDIARY COMPANY
CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDER'S EQUITY
(Unaudited)
Nine Months Ended September 30, 2023
(In millions)Common StockRetained (Deficit) Earnings Total Shareholder's Equity
Balance at December 31, 2022$1,765 $(12)$1,753 
Net income— 33 33 
Common stock dividends— (21)(21)
Contributions from parent63 — 63 
Balance at March 31, 2023$1,828 $— $1,828 
Net income— 18 18 
Common stock dividends— (15)(15)
Balance at June 30, 2023$1,828 $3 $1,831 
Net income— 71 71 
Common stock dividends— (75)(75)
Contributions from parent2 — 2 
Balance at September 30, 2023$1,830 $(1)$1,829 

Nine Months Ended September 30, 2022
(In millions)Common Stock Retained DeficitTotal Shareholder's Equity
Balance at December 31, 2021$1,590 $(15)$1,575 
Net income— 26 26 
Common stock dividends— (19)(19)
Contributions from parent173 — 173 
Balance at March 31, 2022$1,763 $(8)$1,755 
Net income— 11 11 
Common stock dividends— (19)(19)
Balance at June 30, 2022$1,763 $(16)$1,747 
Net income— 94 94 
Common stock dividends— (90)(90)
Contributions from parent2 — 2 
Balance, September 30, 2022$1,765 $(12)$1,753 

See the Combined Notes to Consolidated Financial Statements
49



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

Note 1 — Significant Accounting Policies

1. Significant Accounting Policies (All Registrants)
Description of Business
Exelon is a utility services holding company engaged in the energy transmission and distribution businesses through ComEd, PECO, BGE, Pepco, DPL, and ACE.
On February 21, 2021, Exelon's Board of Directors approved a plan to separate the Utility Registrants and Generation. The separation was completed on February 1, 2022, creating two publicly traded companies, Exelon and Constellation. See Note 2 — Discontinued Operations for additional information.
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, except for the historical transactions between the Utility Registrants and Generation for the purposes of presenting discontinued operations in all periods presented in the Consolidated Statements of Operations and Comprehensive Income.
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.
50


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

Note 1 — Significant Accounting Policies
The accompanying consolidated financial statements as of September 30, 2023 and for the three and nine months ended September 30, 2023 and 2022 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, 2022 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, 2023. These Combined Notes to Consolidated Financial Statements have been prepared pursuant to the rules and regulations of the SEC for Quarterly Reports on Form 10-Q. Certain information and note disclosures normally included in financial statements prepared in accordance with GAAP have been condensed or omitted pursuant to such rules and regulations.
The separation of Constellation, including Generation and its subsidiaries, met the criteria for discontinued operations and as such, results of operations are presented as discontinued operations and have been excluded from continuing operations for all periods presented. Accounting rules require that certain BSC costs previously allocated to Generation be presented as part of Exelon’s continuing operations as these costs do not qualify as expenses of the discontinued operations. Comprehensive income, shareholders' equity, and cash flows related to Constellation have not been segregated and are included in the Consolidated Statements of Operations and Comprehensive Income, Consolidated Statements of Changes in Shareholders’ Equity, and Consolidated Statements of Cash Flows, respectively, for the nine months ended September 30, 2022. See Note 2 — Discontinued Operations for additional information.
2. Discontinued Operations (Exelon)
On February 21, 2021, Exelon's Board of Directors approved a plan to separate the Utility Registrants and Generation, creating two publicly traded companies ("the separation"). Exelon completed the separation on February 1, 2022. Constellation was newly formed and incorporated in Pennsylvania on June 15, 2021 for the purposes of separation and holds Generation (including Generation's subsidiaries). Pursuant to the separation, Exelon contributed its equity ownership interest in Generation to Constellation. Exelon no longer retains any equity ownership interest in Generation or Constellation. See Note 2 — Discontinued Operations of the 2022 Form 10-K for additional information.
Continuing Involvement
In order to govern the ongoing relationships between Exelon and Constellation after the separation, and to facilitate an orderly transition, Exelon and Constellation have entered into several agreements, including the following:
•Separation Agreement – governs the rights and obligations between Exelon and Constellation regarding certain actions to be taken in connection with the separation, among others, including the allocation of assets and liabilities between Exelon and Constellation.
•Transition Services Agreement (TSA) – governs the terms and conditions of the services that Exelon provides to Constellation and Constellation provides to Exelon for an expected period of two years, provided that certain services may be longer than the term and services may be extended with approval from both parties. The services include specified accounting, finance, information technology, human resources, employee benefits and other services that have historically been provided on a centralized basis by BSC. For the three and nine months ended September 30, 2023, the amounts Exelon billed Constellation and Constellation billed Exelon for these services were $33 million and $127 million recorded in Other income, net and $4 million and $13 million recorded in Operating and maintenance expense, respectively. For the three months ended September 30, 2022, the amounts Exelon billed Constellation and Constellation billed Exelon for these services were $68 million recorded in Other income, net and $12 million recorded in Operating and maintenance expense, respectively. Additionally, for the period from February 1, 2022 to September 30, 2022, the amounts Exelon billed Constellation and Constellation billed Exelon for these services were $193 million recorded in Other income, net and $32 million recorded in Operating and maintenance expense, respectively.
51


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

Note 2 — Discontinued Operations
•Tax Matters Agreement (TMA) – governs the respective rights, responsibilities and obligations of Exelon and Constellation with respect to all tax matters, including tax liabilities and benefits, tax attributes, tax returns, tax contests and other tax sharing regarding U.S. federal, state, local and foreign income taxes, other tax matters and related tax returns. See Note 7 — Income Taxes for additional information.
In addition, the Utility Registrants will continue to incur expenses from transactions with Constellation after the separation. Prior to the separation, such expenses were primarily recorded as Purchased power from affiliates and an immaterial amount recorded as Operating and maintenance expense from affiliates at the Utility Registrants. After the separation, such expenses are primarily recorded as Purchased power and an immaterial amount recorded as Operating and maintenance expense at the Utility Registrants.
•ComEd had an ICC-approved RFP contract with Constellation to provide a portion of ComEd’s electric supply requirements. ComEd also purchased RECs and ZECs from Constellation.
•PECO received electric supply from Constellation under contracts executed through PECO’s competitive procurement process. In addition, PECO had a ten-year agreement with Constellation to sell solar AECs.
•BGE received a portion of its energy requirements from Constellation under its MDPSC-approved market-based SOS and gas commodity programs.
•Pepco received electric supply from Constellation under contracts executed through Pepco’s competitive procurement process approved by the MDPSC and DCPSC.
•DPL received a portion of its energy requirements from Constellation under its MDPSC and DEPSC approved market-based SOS commodity programs.
•ACE received electric supply from Constellation under contracts executed through ACE’s competitive procurement process approved by the NJBPU.
ComEd and PECO also have receivables with Constellation for estimated excess funds at the end of decommissioning the Regulatory Agreement Units, such amounts are due back to ComEd and PECO, as applicable, for payment to their respective customers. See Note 3 — Regulatory Matters and Note 23 — Related Party Transactions of the 2022 Form 10-K for additional information.
Discontinued Operations
The separation represented a strategic shift that would have a major effect on Exelon’s operations and financial results. Accordingly, the separation meets the criteria for discontinued operations.
There were no results from discontinued operations for the three and nine months ended September 30, 2023 and the three months ended September 30, 2022. The following table presents the results of Constellation that have been reclassified from continuing operations and included in discontinued operations within Exelon’s Consolidated Statements of Operations and Comprehensive Income for the nine months ended September 30, 2022.
These results are primarily Generation, which is comprised of Exelon’s Mid-Atlantic, Midwest, New York, ERCOT, and Other Power Regions reportable segments, and include the impact of transaction costs, certain BSC costs, including any transition costs, that were historically allocated and directly attributable to Generation, transactions between Generation and the Utility Registrants, and tax-related adjustments. Transaction costs include costs for external bankers, accountants, appraisers, lawyers, external counsels and other advisors, among others, who are involved in the negotiation, appraisal, due diligence and regulatory approval of the separation. Transition costs are primarily employee-related costs such as recruitment expenses, costs to establish certain stand-alone functions and information technology systems, professional services fees and other separation-related costs during the transition to separate Generation. For the purposes of reporting discontinued operations, these results also include transactions between Generation and the Utility Registrants that were historically eliminated within Exelon’s Consolidated Statements of Operations as these transactions will be ongoing after the separation. Certain BSC costs that were historically allocated to Generation are presented as part of continuing operations in Exelon’s Consolidated Statements of Operations as these costs do not qualify as expenses of the discontinued operations per the accounting rules.
52


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

Note 2 — Discontinued Operations
Nine Months Ended
September 30,
2022
Operating revenues
Competitive business revenues$1,855 
Competitive business revenues from affiliates161 
Total operating revenues2,016 
Operating expenses
Competitive businesses purchased power and fuel1,138 
Operating and maintenance(a)
371 
Depreciation and amortization94 
Taxes other than income taxes44 
Total operating expenses1,647 
Gain on sales of assets and businesses10 
Operating income379 
Other income and (deductions)
Interest expense, net(20)
Other, net(281)
Total other income and (deductions)(301)
Income before income taxes78 
Income taxes(40)
Equity in losses of unconsolidated affiliates(1)
Net income117 
Net income attributable to noncontrolling interests1 
Net income from discontinued operations$116 
__________
(a)Includes transaction and transition costs related to the separation of $52 million for the nine months ended September 30, 2022.
There were no assets or liabilities of discontinued operations included in Exelon's Consolidated Balance Sheet as of September 30, 2023 and December 31, 2022. Constellation had net assets of $11,573 million that separated on February 1, 2022 that resulted in a reduction to Exelon's equity during the year ended December 31, 2022. Refer to the Distribution of Constellation line in Exelon's Consolidated Statement of Changes in Shareholders' Equity for further information.
There were no discontinued operations included within Exelon’s Consolidated Statements of Cash Flows for the nine months ended September 30, 2023. The following table presents selected financial information regarding cash flows of the discontinued operations that are included within Exelon’s Consolidated Statements of Cash Flows for the nine months ended September 30, 2022.
53


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

Note 2 — Discontinued Operations
Nine Months Ended
September 30,
2022
Non-cash items included in net income from discontinued operations:
Depreciation, amortization, and accretion, including nuclear fuel and energy contract amortization$207 
Loss on sales of assets and businesses9 
Deferred income taxes and amortization of investment tax credits(143)
Net fair value changes related to derivatives(59)
Net realized and unrealized losses on NDT fund investments205 
Net unrealized losses on equity investments16 
Other decommissioning-related activity36 
Cash flows from investing activities:
Capital expenditures(227)
Collection of DPP169 
Supplemental cash flow information:
Decrease in capital expenditures not paid(128)
Increase in DPP348 
Increase in PP&E related to ARO update335 
3. Regulatory Matters (All Registrants)
As discussed in Note 3 — Regulatory Matters of the 2022 Form 10-K, the Registrants are involved in rate and regulatory proceedings at FERC and their state commissions. The following discusses developments in 2023 and updates to the 2022 Form 10-K.
Distribution Base Rate Case Proceedings
The following tables show the completed and pending distribution base rate case proceedings in 2023.
Completed Distribution Base Rate Case Proceedings

54


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

Note 3 — Regulatory Matters
Registrant/JurisdictionFiling DateServiceRequested Revenue Requirement IncreaseApproved Revenue Requirement IncreaseApproved ROEApproval DateRate Effective Date
ComEd - Illinois(a)
April 15, 2022Electric$199 $199 7.85 %November 17, 2022January 1, 2023
PECO - PennsylvaniaMarch 31, 2022Natural Gas82 55 
N/A(b)
October 27, 2022January 1, 2023
BGE - Maryland(c)
May 15, 2020 (amended September 11, 2020)Electric203 140 9.50 %December 16, 2020January 1, 2021
Natural Gas108 74 9.65 %
Pepco - Maryland(d)
October 26, 2020 (amended March 31, 2021)Electric104 52 9.55 %June 28, 2021June 28, 2021
DPL - Maryland(e)
May 19, 2022Electric38 29 9.60 %December 14, 2022January 1, 2023
__________
(a)ComEd's 2023 approved revenue requirement above reflects an increase of $144 million for the initial year revenue requirement for 2023 and an increase of $55 million related to the annual reconciliation for 2021. The revenue requirement for 2023 provides for a weighted average debt and equity return on distribution rate base of 5.94%, inclusive of an allowed ROE of 7.85%, reflecting the monthly average yields for 30-year treasury bonds plus 580 basis points. The reconciliation revenue requirement for 2021 provides for a weighted average debt and equity return on distribution rate base of 5.91%, inclusive of an allowed ROE of 7.78%, reflecting the monthly yields on 30-year treasury bonds plus 580 basis points less a performance metrics penalty of 7 basis points. This is ComEd's last performance-based electric distribution formula rate established under EIMA. See discussion of CEJA below for details on the transition away from the electric distribution formula rate.
(b)The PECO natural gas base rate case proceeding was resolved through a settlement agreement, which did not specify an approved ROE.
(c)Reflects a three-year cumulative multi-year plan for 2021 through 2023. BGE proposed to use certain tax benefits to fully offset the increases in 2021 and 2022 and partially offset the increase in 2023. The MDPSC awarded BGE electric revenue requirement increases of $59 million, $39 million, and $42 million, before offsets, in 2021, 2022, and 2023, respectively, and natural gas revenue requirement increases of $53 million, $11 million, and $10 million, before offsets, in 2021, 2022, and 2023, respectively. However, the MDPSC utilized the tax benefits to fully offset the increases in 2021 and January 2022 such that customer rates remained unchanged. For the remainder of 2022, the MDPSC chose to offset only 25% of the cumulative 2021 and 2022 electric revenue requirement increases and 50% of the cumulative gas revenue requirement increases. In 2021, the MDPSC deferred a decision on whether to use certain tax benefits to offset the revenue requirement increases in 2023 and directed BGE to make another proposal at the end of 2022. In September 2022, BGE proposed that tax benefits not be used to offset the 2023 revenue requirement increases. On October 26, 2022, the MDPSC accepted BGE's recommendation to not use tax benefits to offset the 2023 revenue requirement increases.
(d)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.
(e)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.
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Note 3 — Regulatory Matters
Pending Distribution Base Rate Case Proceedings
Registrant/JurisdictionFiling DateServiceRequested Revenue Requirement IncreaseRequested ROEExpected Approval Timing
ComEd - Illinois(a)
January 17, 2023Electric$1,487 
10.50% to 10.65%
Fourth quarter of 2023
ComEd - Illinois(b)
April 21, 2023Electric247 8.91%Fourth quarter of 2023
BGE - Maryland(c)
February 17, 2023Electric313 10.40%Fourth quarter of 2023
Natural Gas289 10.40%
Pepco - District of Columbia(d)
April 13, 2023Electric191 10.50%Second quarter of 2024
Pepco - Maryland(e)
May 16, 2023Electric214 10.50%Second quarter of 2024
DPL - Delaware(f)
December 15, 2022 (amended September 29, 2023)Electric39 10.50%Second quarter of 2024
ACE - New Jersey(g)
February 15, 2023 (amended August 21, 2023)Electric92 10.50%Fourth quarter of 2023
__________
(a)On September 27, 2023, ComEd filed its reply brief supporting its proposed multi-year rate and grid plans, as adjusted or modified by ComEd as of the evidentiary hearing on August 22, 2023. The rate plan covers the period from January 1, 2024 to December 31, 2027 and includes total requested revenue requirement increases of $968 million effective January 1, 2024, $181 million effective January 1, 2025, $163 million effective January 1, 2026, and $175 million effective January 1, 2027, based on forecasted revenue requirements. If approved, the revenue requirement will provide for a weighted average debt and equity return on distribution rate base of 7.40% in 2024, 7.47% in 2025, 7.58% in 2026, and 7.65% in 2027, inclusive of an allowed ROE of 10.50% in 2024, 10.55% in 2025, 10.60% in 2026, and 10.65% in 2027. The requested revenue requirements are based on capital structures that reflect between 50.58% and 51.19% common equity. ComEd’s MRP also includes a proposed three-tranche rate phase-in to defer approximately $339 million, of the $968 million year-over-year revenue increase for 2024 from 2024 to 2026, approximately $52 million, of the $520 million year-over-year revenue increase for 2025 from 2025 to 2027, and approximately $75 million of the $215 million year-over-year revenue increase for 2026 from 2026 to 2028.
(b)On April 21, 2023, ComEd filed its proposed Delivery Reconciliation Amount of $247 million under Rider Delivery Service Pricing Reconciliation (Rider DSPR) which 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 reconciles the delivery service rates in effect in 2022 with the actual delivery service costs incurred in 2022. Final order is expected by December 2023, and the reconciliation amount will be in customer rates beginning January 1, 2024.
(c)Reflects a three-year cumulative multi-year plan for January 1, 2024 through December 31, 2026 submitted to the MDPSC. Inclusive of the proposed acceleration of remaining electric tax benefits in 2024 and 2025, and remaining gas tax benefits in 2024, BGE requested total electric revenue requirement increases of $85 million, $103 million, and $125 million in 2024, 2025, and 2026, respectively, and natural gas revenue requirement increases of $158 million, $77 million, and $54 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 2021 and 2022 reconciliation amounts are not included in the requested revenue requirement increase, as BGE is proposing that these amounts be recovered through the separate electric and gas riders in 2024. The 2021 reconciliation amounts are $11 million and $7 million for electric and gas, respectively, and the 2022 reconciliation amounts are $44 million and $15 million for electric and gas, respectively. The requested electric revenue requirement includes approximately $25 million for a Customer Electrification Plan that the MDPSC struck from BGE's case in August 2023.
(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 $117 million, $37 million, and $37 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 $74 million, $60 million and $60 million effective April 1,
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Note 3 — Regulatory Matters
2024, April 1, 2025, and April 1, 2026, respectively. The plan contains a proposed nine-month extension period with a requested revenue requirement increase of $20 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.
(f)The rates went into effect on July 15, 2023, subject to refund.
(g)Requested increases are before New Jersey sales and use tax. ACE’s procedural schedule was suspended on September 6, 2023. On October 21, 2023, ACE filed a stipulation of settlement with the NJBPU. Subsequently, on October 24, 2023, the administrative law judge presiding over the case recommended the settlement with all parties be approved. ACE is awaiting final approval of the settlement from the NJBPU and it is expected during the fourth quarter of 2023.
Transmission Formula Rates
The Utility Registrants' transmission rates are each established based on a FERC-approved formula. ComEd, BGE, Pepco, DPL, and ACE are required to file an annual update to the FERC-approved formula on or before May 15, and PECO is required to file on or before May 31, with the resulting rates effective on June 1 of the same year. The annual update for ComEd is based on prior year actual costs and current year projected capital additions (initial year revenue requirement). The update for ComEd also reconciles any differences between the revenue requirement in effect beginning June 1 of the prior year and actual costs incurred for that year (annual reconciliation). The annual update for PECO is based on prior year actual costs and current year projected capital additions, accumulated depreciation, and accumulated deferred income taxes. The annual update for BGE, Pepco, DPL, and ACE is based on prior year actual costs and current year projected capital additions, accumulated depreciation, depreciation and amortization expense, and accumulated deferred income taxes. The update for PECO, BGE, Pepco, DPL, and ACE also reconciles any differences between the actual costs and actual revenues for the calendar year (annual reconciliation).
For 2023, the following increases/(decreases) were included in the Utility Registrants' electric transmission formula rate updates:
Registrant(a)
Initial Revenue Requirement IncreaseAnnual Reconciliation Increase (Decrease)Total Revenue Requirement Increase
Allowed Return on Rate Base(b)
Allowed ROE(c)
ComEd$20 $63 $83 8.09 %11.50 %
PECO24 23 47 7.41 %10.35 %
BGE19 (12)4 (d)7.34 %10.50 %
Pepco37 (5)32 7.57 %10.50 %
DPL32 (3)29 7.08 %10.50 %
ACE41 (12)29 7.08 %10.50 %
__________
(a)All rates are effective June 1, 2023 - May 31, 2024, subject to review by interested parties pursuant to review protocols of each Utility Registrants' tariffs.
(b)Represents the weighted average debt and equity return on transmission rate bases. For ComEd and PECO, the common equity component of the ratio used to calculate the weighted average debt and equity return on the transmission formula rate base is currently capped at 55% and 55.75%, respectively.
(c)The rate of return on common equity for each Utility Registrant 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 $3 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) an extension of and certain adjustments to ComEd’s energy efficiency MWh savings goals, (4) revisions to the Illinois RPS
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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)

Note 3 — Regulatory Matters
requirements, including expanded charges for the procurement of RECs from wind and solar generation, (5) a requirement to accelerate amortization of ComEd’s unprotected excess deferred income taxes (EDIT) that ComEd was previously directed by the ICC to amortize using the average rate assumption method which equates to approximately 39.5 years, and (6) requirements that ComEd and the ICC initiate and conduct various regulatory proceedings on subjects including ethics, spending, grid investments, and performance metrics. Regulatory or legal challenges regarding the validity or implementation of CEJA are possible and Exelon and ComEd cannot reasonably predict the outcome of any such challenges.
ComEd Electric Distribution Rates
ComEd filed, and received approval for, its last performance-based electric distribution formula rate update filing under EIMA in 2022; those rates are in effect throughout 2023.
On February 3, 2022, the ICC approved a tariff that establishes the process under which ComEd will reconcile its 2022 and 2023 rate year revenue requirements with actual costs. Those reconciliation amounts will be determined using the same process as were 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 is expected by December 2023, for rates beginning January 2024. The rate year 2023 reconciliation will be filed in 2024.
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. On July 27, 2023, ICC staff and intervenors filed rebuttal testimony, which showed little to no movement on the key issues, including ROE and large capital projects. On August 14, 2023, ComEd filed surrebuttal testimony. On August 22, 2023, evidentiary hearings were held, during which testimony and other evidence was admitted and the evidentiary phase of the hearing process was closed. ComEd filed its reply brief on September 27, 2023, to adjust its total requested revenue requirement increase to $1.487 billion. On October 23, 2023 the administrative law judges (ALJs) issued a proposed order in ComEd's MRP proceeding recommending a $317 million reduction to ComEd's requested revenue requirement increase of $1.487 billion. Significant differences between the ALJ’s proposed order and ComEd’s final position relate to the proposed return on equity and the disallowance of any return on ComEd’s pension asset. The ALJs proposed order is not final, and briefs on exception will be filed in November 2023. The Commission may also hear oral arguments prior to making its final decision. The ICC must issue its decision on both the MRP and Grid Plan by mid-December 2023, for rates to begin with the January 2024 billing cycle.
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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)

Note 3 — Regulatory Matters
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 take 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 September 30, 2023 is $862 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.
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 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
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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)

Note 3 — Regulatory Matters
ComEd’s appeal of the interim order and ComEd has decided not to pursue the other issues. As such, ComEd recently moved to voluntarily dismiss its appeal and the appellate court granted that request. The ILAG consolidated their appeals. 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 Formula Rate (Exelon and ComEd). ComEd filed its annual energy efficiency formula rate update with the ICC on May 26, 2023. The filing establishes the revenue requirement used to set the rates that will take effect in January 2024 after the ICC's review and approval. The requested revenue requirement update is based on a reconciliation of the 2022 actual costs plus projected 2024 expenditures.
Initial Revenue Requirement IncreaseAnnual Reconciliation IncreaseTotal Revenue Requirement Increase
Requested Return on Rate Base(a)
Requested ROE
$87 $31 $118 6.48 %8.91 %
__________
(a)The requested revenue requirement increase provides for a weighted average debt and equity return on the energy efficiency regulatory asset and rate base of 6.48% inclusive of an allowed ROE of 8.91%, reflecting the monthly average yields for 30-year treasury bonds plus 580 basis points. For the 2022 reconciliation year, the requested revenue requirement provides for a weighted average debt and equity return on the energy efficiency regulatory asset and rate base of 7.48% inclusive of an allowed ROE of 10.91%, which includes an upward performance adjustment that increased the ROE. The performance adjustment can either increase or decrease the ROE based upon the achievement of energy efficiency savings goals.
New Jersey Regulatory Matters
Termination of Energy Procurement Provisions of PPAs (Exelon, PHI, and ACE). On December 22, 2021, ACE filed with the NJBPU a petition to terminate the provisions in the PPAs to purchase electricity from two coal-powered generation facilities located in the state of New Jersey. The petition was approved by the NJBPU on March 23, 2022. Upon closing of the transaction on March 31, 2022, ACE recognized a liability of $203 million for the contract termination fee, which is to be paid by the end of 2024, and recognized a corresponding regulatory asset of $203 million.
As of September 30, 2023, the $71 million liability for the contract termination fee consists of $61 million and $10 million included in Other current liabilities and Other deferred credits and other liabilities, respectively, in Exelon's Consolidated Balance Sheet. The current and noncurrent liabilities are included in PPA termination obligation and Other deferred credits and other liabilities, respectively, in PHI's and ACE's Consolidated Balance Sheets. For the nine months ended September 30, 2023 and 2022, ACE has respectively paid $65 million and $45 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.
ACE Infrastructure Investment Program “Powering the Future” Filing (Exelon, PHI, and ACE). On October 31, 2022, ACE filed with the NJBPU a second IIP, called “Powering the Future”, proposing to seek recovery through a new component of ACE’s rider mechanism, totaling $379 million, over the four-year period of July 1, 2023, to June 30, 2027. The new IIP will allow ACE to invest in projects that are designed to enhance the reliability, resiliency, and safety of the service ACE provides to its customers. On June 15, 2023, ACE entered into a settlement agreement with other parties, which allows for a recovery totaling $93 million of reliability related capital investments from July 1, 2023, through June 30, 2027. ACE will have the option of seeking approval from the NJBPU to extend the end date of the IIP beyond June 30, 2027, if ACE determines an extension is necessary. On June 29, 2023, the NJBPU adopted the settlement agreement and issued an order approving the program.
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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)

Note 3 — Regulatory Matters
Other Federal Regulatory Matters
FERC Audit (Exelon and ComEd). The Utility Registrants are subject to periodic audits 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. During the first quarter of 2023, ComEd was provided with information from FERC about several potential findings, including ComEd's methodology regarding the allocation of certain overhead costs to capital under FERC regulations. Based on the preliminary findings and discussions with FERC staff, ComEd determined that a loss was probable and recorded a regulatory liability to reflect its best estimate of that loss as of March 31, 2023.
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. On August 28, 2023, ComEd filed a formal notice of the issues it will contest. 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.
Regulatory Assets and Liabilities
The Utility Registrants' regulatory assets and liabilities have not changed materially since December 31, 2022, unless noted below. See Note 3 — Regulatory Matters of the 2022 Form 10-K for additional information on the specific regulatory assets and liabilities.
ComEd. Regulatory assets increased $733 million primarily due to increases of $392 million in the Electric distribution formula rate annual reconciliations regulatory asset, $171 million in the Energy efficiency costs, and $97 million in the ZEC regulatory asset.
PECO. Regulatory assets increased $150 million primarily due to an increase of $118 million in the Deferred income taxes regulatory asset. Regulatory liabilities increased $6 million primarily due to increases of $49 million in the Electric energy and natural gas costs regulatory liability, offset by a decrease of $31 million in the Decommissioning the regulatory agreement units regulatory liability.
BGE. Regulatory assets increased $114 million primarily due to an increase of $38 million and $35 million in the Removal costs and Under-recovered revenue decoupling regulatory assets, respectively.
Pepco. Regulatory assets decreased $63 million primarily due to a decrease of $35 million in the Electric energy and natural gas costs regulatory asset. Regulatory liabilities decreased $43 million primarily due to a decrease of $52 million in the Deferred income taxes regulatory liability.
DPL. Regulatory assets decreased $17 million primarily due to a decrease of $26 million in the Electric energy and natural gas costs regulatory asset. Regulatory liabilities decreased $1 million primarily due to a decrease of $23 million in the Deferred income taxes regulatory liability, partially offset by an increase of $13 million in the Electric energy and natural gas costs regulatory liability.
ACE. Regulatory assets decreased $21 million primarily due to a decrease of $65 million in the Electric energy and natural gas costs regulatory asset as a result of the PPA termination. Regulatory liabilities decreased $29 million primarily due to a decrease of $9 million in both the Stranded costs regulatory liability and Over-recovered revenue decoupling regulatory liability.
Capitalized Ratemaking Amounts Not Recognized
The following table presents authorized amounts capitalized for ratemaking purposes related to earnings on shareholders' investment that are not recognized for financial reporting purposes in the Registrants' Consolidated Balance Sheets. These amounts will be recognized as revenues in the related Consolidated Statements of Operations and Comprehensive Income in the periods they are billable to the Utility Registrants' customers. PECO had no related amounts at September 30, 2023 and December 31, 2022.
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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)

Note 3 — Regulatory Matters
Exelon
ComEd(a)
BGE(b)
PHI
Pepco(c)
DPL(c)
ACE(b)
September 30, 2023$81 $25 $21 $35 $27 $1 $7 
December 31, 202257 8 28 21 18 2 1 
__________
(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 and ACE's authorized amounts capitalized for ratemaking purposes primarily relate to earnings on shareholder's investment on their respective AMI programs.
(c)Pepco's and DPL's authorized amounts capitalized for ratemaking purposes relate to earnings on shareholder's 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.
4. 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 2022 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 PHI, Pepco, DPL, and ACE these contract liabilities primarily relate to upfront consideration received in the third quarter of 2020 for a collaborative arrangement with an unrelated owner and manager of communication infrastructure. The revenue attributable to this arrangement will be recognized as operating revenue over the 35 years under the collaborative arrangement.
The following table provides a rollforward of the contract liabilities reflected in Exelon's, PHI's, Pepco's, DPL's, and ACE's Consolidated Balance Sheets for the three and nine months ended September 30, 2023 and 2022. At September 30, 2023 and December 31, 2022, ComEd's, PECO's, and BGE's contract liabilities were immaterial.
Exelon(a)
PHI(a)
Pepco(a)
DPL
ACE(a)
Balance at December 31, 2022$101 $101 $81 $10 $10 
Revenues recognized(1)(1)(1)— — 
Balance at March 31, 2023100 100 80 10 10 
Revenues recognized(2)(2)(2)— — 
Balance at June 30, 2023$98 $98 $78 $10 $10 
Revenues recognized(2)(2)(1)— (1)
Balance as of September 30, 2023$96 $96 $77 $10 $9 
Exelon(a)
PHI(a)
Pepco(a)
DPL(a)
ACE(a)
Balance at December 31, 2021$109 $109 $87 $11 $11 
Revenues recognized(2)(2)(2)— — 
Balance at March 31, 2022107 107 85 11 11 
Revenues recognized(2)(2)(1)— (1)
Balance at June 30, 2022$105 $105 $84 $11 $10 
Revenues recognized(2)(2)(1)(1)— 
Balance as of September 30, 2022$103 $103 $83 $10 $10 
__________
62


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

Note 4 — Revenue from Contracts with Customers
(a)Revenues recognized in the three and nine months ended September 30, 2023 and 2022, were included in the contract liabilities at December 31, 2022 and 2021, 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 September 30, 2023. 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
2023$2 $2 $2 $— $1 
20246 6 5 — — 
20255 5 5 — — 
20265 5 5 — — 
2027 and thereafter78 78 60 10 8 
Total$96 $96 $77 $10 $9 
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 5 — Segment Information for the presentation of the Registrants' revenue disaggregation.
5. Segment Information (All Registrants)
Operating segments for each of the Registrants are determined based on information used by the CODMs in deciding how to evaluate performance and allocate resources at each of the Registrants.
Exelon has six reportable segments, which include ComEd, PECO, BGE, and PHI's three reportable segments consisting of Pepco, DPL, and ACE. ComEd, PECO, BGE, Pepco, DPL, and ACE each represent a single reportable segment, and as such, no separate segment information is provided for these Registrants. Exelon, ComEd, PECO, BGE, Pepco, DPL, and ACE's CODMs evaluate the performance of and allocate resources to the segments based on net income.
An analysis and reconciliation of the Registrants’ reportable segment information to the respective information in the consolidated financial statements for the three and nine months ended September 30, 2023 and 2022 is as follows:
Three Months Ended September 30, 2023 and 2022
63


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

Note 5 — Segment Information
ComEdPECOBGEPHI
Other(a)
Intersegment
Eliminations		Exelon
Operating revenues(b):
2023
Electric revenues$2,268 $970 $836 $1,747 $— $(28)$5,793 
Natural gas revenues— 67 96 24 — — 187 
Shared service and other revenues— — — 2 445 (447)— 
Total operating revenues$2,268 $1,037 $932 $1,773 $445 $(475)$5,980 
2022
Electric revenues$1,378 $941 $757 $1,557 $— $(12)$4,621 
Natural gas revenues— 73 113 38 — — 224 
Shared service and other revenues— — — 3 381 (384)— 
Total operating revenues$1,378 $1,014 $870 $1,598 $381 $(396)$4,845 
Intersegment revenues(c):
2023$9 $2 $2 $2 $443 $(458)$— 
20226 3 3 3 378 (393)— 
Depreciation and amortization:
2023$357 $100 $161 $257 $15 $— $890 
2022333 92 148 238 14 — 825 
Operating expenses:
2023$1,738 $847 $835 $1,440 $475 $(478)$4,857 
2022913 798 810 1,254 439 (380)3,834 
Interest expense, net:
2023$119 $52 $47 $80 $139 $— $437 
2022104 45 39 72 105 — 365 
Income (loss) from continuing operations before income taxes:
2023$427 $149 $56 $281 $(130)$(16)$767 
2022375 179 26 291 (103)— 768 
Income Taxes:
2023$94 $3 $11 $49 $(90)$— $67 
202284 44 (7)2 (31)— 92 
Net income (loss) from continuing operations:
2023$333 $146 $45 $232 $(41)$(15)$700 
2022291 135 33 289 (71)(1)676 
Capital Expenditures:
2023$664 $361 $330 $488 $12 $— $1,855 
2022593 333 340 398 8 — 1,672 
__________
(a)Other primarily includes Exelon’s corporate operations, shared service entities, and other financing and investment activities.
(b)Includes gross utility tax receipts from customers. The offsetting remittance of utility taxes to the governing bodies is recorded in Taxes other than income taxes in the Registrants’ Consolidated Statements of Operations and Comprehensive Income. See Note 15 — Supplemental Financial Information for additional information on total utility taxes.
(c)See Note 16 — Related Party Transactions for additional information on intersegment revenues.




64


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

Note 5 — Segment Information
PHI:
PepcoDPLACE
Other(a)
Intersegment
Eliminations		PHI
Operating revenues(b):
2023
Electric revenues$822 $426 $502 $— $(3)$1,747 
Natural gas revenues— 24 — — — 24 
Shared service and other revenues— — — 103 (101)2 
Total operating revenues$822 $450 $502 $103 $(104)$1,773 
2022
Electric revenues$724 $374 $462 $— $(3)$1,557 
Natural gas revenues— 38 — — — 38 
Shared service and other revenues— — — 94 (91)3 
Total operating revenues$724 $412 $462 $94 $(94)$1,598 
Intersegment revenues(c):
2023$1 $2 $— $103 $(104)$2 
20222 1 — 94 (94)3 
Depreciation and amortization:
2023$112 $62 $77 $6 $— $257 
202299 59 74 6 — 238 
Operating expenses:
2023$658 $386 $394 $105 $(103)$1,440 
2022555 345 353 96 (95)1,254 
Interest expense, net:
2023$41 $18 $19 $3 $(1)$80 
202237 16 17 1 1 72 
Income (loss) before income taxes:
2023$141 $51 $94 $(4)$(1)$281 
2022146 54 95 (4)— 291 
Income Taxes:
2023$21 $8 $23 $(3)$— $49 
20221 2 1 (2)— 2 
Net income (loss):
2023$120 $43 $71 $(2)$— $232 
2022145 52 94 (2)— 289 
Capital Expenditures:
2023$227 $158 $101 $2 $— $488 
2022193 100 105 — — 398 
_________
(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 15 — Supplemental Financial Information for additional information on total utility taxes.
(c)Includes intersegment revenues with ComEd, BGE, and PECO, which are eliminated at Exelon.





65


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

Note 5 — 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 September 30, 2023
Revenues from contracts with customersComEdPECOBGEPHIPepcoDPLACE
Electric revenues
Residential$1,047 $654 $512 $959 $405 $255 $299 
Small commercial & industrial540 148 86 199 54 70 75 
Large commercial & industrial263 67 144 386 303 32 51 
Public authorities & electric railroads11 7 7 16 9 3 4 
Other(a)
265 80 104 201 67 67 68 
Total electric revenues(b)
$2,126 $956 $853 $1,761 $838 $427 $497 
Natural gas revenues
Residential$— $43 $57 $12 $— $12 $— 
Small commercial & industrial— 16 10 7 — 7 — 
Large commercial & industrial— — 25 1 — 1 — 
Transportation— 7 — 3 — 3 — 
Other(c)
— 1 4 1 — 1 — 
Total natural gas revenues(d)
$— $67 $96 $24 $— $24 $— 
Total revenues from contracts with customers$2,126 $1,023 $949 $1,785 $838 $451 $497 
Other revenues
Revenues from alternative revenue programs$135 $11 $(22)$(15)$(18)$(2)$5 
Other electric revenues(e)
7 3 4 3 2 1 — 
Other natural gas revenues(e)
— — 1 — — — — 
Total other revenues$142 $14 $(17)$(12)$(16)$(1)$5 
Total revenues for reportable segments$2,268 $1,037 $932 $1,773 $822 $450 $502 
66


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

Note 5 — Segment Information
Three Months Ended September 30, 2022
Revenues from contracts with customersComEdPECOBGEPHIPepcoDPLACE
Electric revenues
Residential$935 $620 $406 $808 $318 $207 $283 
Small commercial & industrial217 149 88 179 44 65 70 
Large commercial & industrial(117)93 158 401 303 43 55 
Public authorities & electric railroads3 8 7 16 9 4 3 
Other(a)
246 71 101 166 57 55 54 
Total electric revenues(b)
$1,284 $941 $760 $1,570 $731 $374 $465 
Natural gas revenues
Residential$— $46 $70 $10 $— $10 $— 
Small commercial & industrial— 20 13 6 — 6 — 
Large commercial & industrial— — 28 3 — 3 — 
Transportation— 5 — 3 — 3 — 
Other(c)
— 2 2 16 — 16 — 
Total natural gas revenues(d)
$— $73 $113 $38 $— $38 $— 
Total revenues from contracts with customers$1,284 $1,014 $873 $1,608 $731 $412 $465 
Other revenues
Revenues from alternative revenue programs$88 $(5)$(8)$(11)$(8)$— $(3)
Other electric revenues(e)
6 5 4 1 1 — — 
Other natural gas revenues(e)
— — 1 — — — — 
Total other revenues$94 $— $(3)$(10)$(7)$— $(3)
Total revenues for reportable segments$1,378 $1,014 $870 $1,598 $724 $412 $462 
__________
(a)Includes revenues from transmission revenue from PJM, wholesale electric revenue and mutual assistance revenue.
(b)Includes operating revenues from affiliates in 2023 and 2022 respectively of:
•$9 million, $6 million at ComEd
•$2 million, $3 million at PECO
•$1 million, $2 million at BGE
•$2 million, $3 million at PHI
•$1 million, $2 million at Pepco
•$2 million, $1 million at DPL
•less than $1 million, less than $1 million at ACE
(c)Includes revenues from off-system natural gas sales.
(d)Includes operating revenues from affiliates in 2023 and 2022 of:
•less than $1 million at PECO
•$1 million at BGE
(e)Includes late payment charge revenues.











67


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

Note 5 — Segment Information
Nine Months Ended September 30, 2023 and 2022
ComEdPECOBGEPHI
Other(a)
Intersegment
Eliminations		Exelon
Operating revenues(b):
2023
Electric revenues$5,836 $2,484 $2,322 $4,459 $— $(45)$15,056 
Natural gas revenues— 493 664 150 — (3)1,304 
Shared service and other revenues— — — 6 1,316 (1,322)— 
Total operating revenues$5,836 $2,977 $2,986 $4,615 $1,316 $(1,370)$16,360 
2022
Electric revenues$4,536 $2,390 $2,122 $4,058 $— $(24)$13,082 
Natural gas revenues— 487 688 157 — (2)1,330 
Shared service and other revenues— — — 8 1,342 (1,350)— 
Total operating revenues$4,536 $2,877 $2,810 $4,223 $1,342 $(1,376)$14,412 
Intersegment revenues(c):
2023$14 $6 $6 $7 $1,310 $(1,343)$— 
202214 5 13 9 1,342 (1,377)6 
Depreciation and amortization:
2023$1,045 $297 $487 $741 $46 $— $2,616 
2022982 277 470 697 46 — 2,472 
Operating expenses:
2023$4,472 $2,436 $2,503 $3,864 $1,521 $(1,367)$13,429 
20223,357 2,230 2,446 3,535 1,524 (1,288)11,804 
Interest expense, net:
2023$357 $149 $135 $238 $402 $(4)$1,277 
2022308 129 110 216 300 — 1,063 
Income (loss) from continuing operations before income taxes:
2023$1,057 $418 $362 $593 $(424)$(21)$1,985 
2022909 541 270 528 (228)(42)1,978 
Income taxes:
2023$235 $8 $76 $103 $(149)$1 $274 
2022203 67 3 10 82 (9)356 
Net income (loss) from continuing operations:
2023$822 $410 $286 $490 $(275)$(22)$1,711 
2022706 474 267 518 (310)(33)1,622 
Capital expenditures:
2023$1,926 $1,068 $986 $1,510 $50 $— $5,540 
20221,801 991 918 1,174 68 — 4,952 
Total assets:
September 30, 2023$42,042 $15,259 $13,649 $26,656 $5,825 $(4,172)$99,259 
December 31, 202239,661 14,502 13,350 26,082 6,014 (4,260)95,349 
__________
(a)Other primarily includes Exelon’s corporate operations, shared service entities, and other financing and investment activities.
(b)Includes gross utility tax receipts from customers. The offsetting remittance of utility taxes to the governing bodies is recorded in Taxes other than income taxes in the Registrants’ Consolidated Statements of Operations and Comprehensive Income. See Note 15 — Supplemental Financial Information for additional information on total utility taxes.
68


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

Note 5 — Segment Information
(c)See Note 16 — Related Party Transactions for additional information on intersegment revenues.
PHI:
PepcoDPLACE
Other(a)
Intersegment
Eliminations		PHI
Operating revenues(b):
2023
Electric revenues$2,174 $1,123 $1,172 $1 $(11)$4,459 
Natural gas revenues— 150 — — — 150 
Shared service and other revenues— — — 309 (303)6 
Total operating revenues$2,174 $1,273 $1,172 $310 $(314)$4,615 
2022
Electric revenues$1,919 $1,019 $1,120 $— $— $4,058 
Natural gas revenues— 157 — — — 157 
Shared service and other revenues— — — 298 (290)8 
Total operating revenues$1,919 $1,176 $1,120 $298 $(290)$4,223 
Intersegment revenues(c):
2023$5 $5 $1 $309 $(313)$7 
20224 5 2 288 (290)9 
Depreciation and amortization:
2023$329 $182 $212 $18 $— $741 
2022312 172 192 21 — 697 
Operating expenses:
2023$1,810 $1,079 $971 $318 $(314)$3,864 
20221,588 999 947 291 (290)3,535 
Interest expense, net:
2023$122 $53 $52 $9 $2 $238 
2022111 48 49 7 1 216 
Income (loss) before income taxes:
2023$292 $153 $162 $(14)$— $593 
2022259 138 133 (2)— 528 
Income taxes:
2023$43 $25 $40 $(5)$— $103 
2022(2)8 2 2 — 10 
Net income (loss):
2023$249 $128 $122 $(9)$— $490 
2022261 130 131 (4)— 518 
Capital expenditures:
2023$710 $416 $376 $8 $— $1,510 
2022595 294 284 1 — 1,174 
Total assets:
September 30, 2023$11,061 $5,870 $5,155 $4,644 $(74)$26,656 
December 31, 202210,657 5,802 4,979 4,677 (33)26,082 
__________
(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 15 — Supplemental Financial Information for additional information on total utility taxes.
(c)Includes intersegment revenues with ComEd, BGE, and PECO, which are eliminated at Exelon.
69


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

Note 5 — 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.
Nine Months Ended September 30, 2023
Revenues from contracts with customersComEdPECOBGEPHIPepcoDPLACE
Electric revenues
Residential$2,744 $1,617 $1,308 $2,181 $954 $626 $601 
Small commercial & industrial1,363 415 253 503 134 189 180 
Large commercial & industrial553 196 412 1,099 838 98 163 
Public authorities & electric railroads33 23 22 49 25 11 13 
Other(a)
716 219 303 563 187 186 194 
Total electric revenues(b)
$5,409 $2,470 $2,298 $4,395 $2,138 $1,110 $1,151 
Natural gas revenues
Residential$— $335 $406 $88 $— $88 $— 
Small commercial & industrial— 123 66 40 — 40 — 
Large commercial & industrial— 1 124 3 — 3 — 
Transportation— 20 — 11 — 11 — 
Other(c)
— 12 28 8 — 8 — 
Total natural gas revenues(d)
$— $491 $624 $150 $— $150 $— 
Total revenues from contracts with customers$5,409 $2,961 $2,922 $4,545 $2,138 $1,260 $1,151 
Other revenues
Revenues from alternative revenue programs$405 $1 $47 $59 $28 $10 $21 
Other electric revenues(e)
22 13 12 11 8 3 — 
Other natural gas revenues(e)
— 2 5 — — — — 
Total other revenues$427 $16 $64 $70 $36 $13 $21 
Total revenues for reportable segments$5,836 $2,977 $2,986 $4,615 $2,174 $1,273 $1,172 
70


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

Note 5 — Segment Information
Nine Months Ended September 30, 2022
Revenues from contracts with customersComEdPECOBGEPHIPepcoDPLACE
Electric revenues
Residential$2,610 $1,538 $1,158 $2,007 $826 $570 $611 
Small commercial & industrial953 386 239 461 117 173 171 
Large commercial & industrial48 229 418 1,056 806 99 151 
Public authorities & electric railroads22 23 20 47 25 11 11 
Other(a)
718 202 297 524 157 168 190 
Total electric revenues(b)
$4,351 $2,378 $2,132 $4,095 $1,931 $1,021 $1,134 
Natural gas revenues
Residential$— $335 $448 $77 $— $77 $— 
Small commercial & industrial— 125 77 35 — 35 — 
Large commercial & industrial— — 128 9 — 9 — 
Transportation— 19 — 11 — 11 — 
Other(c)
— 7 50 25 — 25 — 
Total natural gas revenues(d)
$— $486 $703 $157 $— $157 $— 
Total revenues from contracts with customers$4,351 $2,864 $2,835 $4,252 $1,931 $1,178 $1,134 
Other revenues
Revenues from alternative revenue programs$163 $1 $(40)$(33)$(15)$(3)$(14)
Other electric revenues(e)
22 11 11 4 3 1 — 
Other natural gas revenues(e)
— 1 4 — — — — 
Total other revenues$185 $13 $(25)$(29)$(12)$(2)$(14)
Total revenues for reportable segments$4,536 $2,877 $2,810 $4,223 $1,919 $1,176 $1,120 
__________
(a)Includes revenues from transmission revenue from PJM, wholesale electric revenue and mutual assistance revenue.
(b)Includes operating revenues from affiliates in 2023 and 2022 respectively of:
•$14 million, $14 million at ComEd
•$5 million, $5 million at PECO
•$4 million, $5 million at BGE
•$7 million, $9 million at PHI
•$5 million, $4 million at Pepco
•$5 million, $5 million at DPL
•$1 million, $2 million at ACE
(c)Includes revenues from off-system natural gas sales.
(d)Includes operating revenues from affiliates in 2023 and 2022 respectively of:
•$1 million, $1 million at PECO
•$2 million, $7 million at BGE
(e)Includes late payment charge revenues.

71


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

Note 6 — Accounts Receivable
6. 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 September 30, 2023
ExelonComEdPECOBGEPHIPepcoDPLACE
Balance at June 30, 2023$323 $67 $101 $50 $105 $50 $21 $34 
Plus: Current period provision for expected credit losses(a)
72 24 13 9 26 11 6 9 
Less: Write-offs, net of recoveries(b)
54 15 19 7 13 5 4 4 
Balance at September 30, 2023$341 $76 $95 $52 $118 $56 $23 $39 
Three Months Ended September 30, 2022
ExelonComEdPECOBGEPHIPepcoDPLACE
Balance at June 30, 2022$354 $81 $107 $57 $109 $42 $22 $45 
Plus: Current period provision for expected credit losses
38 10 12 2 14 6 1 7 
Less: Write-offs, net of recoveries
51 17 16 5 12 4 3 5 
Balance at September 30, 2022$341 $74 $103 $54 $111 $44 $20 $47 
Nine Months Ended September 30, 2023
ExelonComEdPECOBGEPHIPepcoDPLACE
Balance at December 31, 2022$327 $59 $105 $54 $109 $47 $21 $41 
Plus: Current period provision for expected credit losses(c)(d)
144 45 32 23 44 24 10 10 
Less: Write-offs, net(e)(f)(g)of recoveries(b)
130 28 42 25 35 15 8 12 
Balance at September 30, 2023$341 $76 $95 $52 $118 $56 $23 $39 
Nine Months Ended September 30, 2022
ExelonComEdPECOBGEPHIPepcoDPLACE
Balance at December 31, 2021$320 $73 $105 $38 $104 $37 $18 $49 
Plus: Current period provision for expected credit losses
141 31 33 30 47 23 8 16 
Less: Write-offs, net of recoveries
120 30 35 14 40 16 6 18 
Balance at September 30, 2022$341 $74 $103 $54 $111 $44 $20 $47 
__________
(a)For ComEd, BGE, PHI, Pepco, DPL and ACE, the change in current period provision for expected credit losses is primarily a result of increased receivable balances.
(b)Recoveries were not material to the Registrants.
(c)For ComEd and DPL, the change in current period provision for expected credit losses is primarily a result of increased receivable balances.
(d)For BGE and ACE, the change in current period provision for expected credit losses is primarily a result of changes in customer risk profile.
(e)For PECO and BGE, the change in write-offs is primarily a result of increased disconnection activities.
(f)For DPL, the change in write-offs is primarily attributable to unfavorable customer payment behavior.
(g)For ACE, the change in write-offs is primarily attributable to the termination of the moratorium in New Jersey, which beginning in March 2020, prevented customer disconnections for non-payment. Disconnection activities resumed in January 2022, driving the change in write-offs of aging accounts receivable for the nine months ended September 20, 2023.



72


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

Note 6 — Accounts Receivable

The following tables present the rollforward of Allowance for Credit Losses on Other Accounts Receivable.
Three Months Ended September 30, 2023
ExelonComEdPECOBGEPHIPepcoDPLACE
Balance at June 30, 2023$87 $18 $8 $8 $53 $31 $9 $13 
Plus: Current period provision (benefit) for expected credit losses
6 3 2 3 (2)(2)— — 
Less: Write-offs, net of recoveries(a)
5 1 2 2 — — — — 
Balance at September 30, 2023$88 $20 $8 $9 $51 $29 $9 $13 
Three Months Ended September 30, 2022
ExelonComEdPECOBGEPHIPepcoDPLACE
Balance at June 30, 2022$81 $18 $10 $11 $42 $20 $8 $14 
Plus: Current period provision (benefit) for expected credit losses
8 2 2 2 2 2 (1)1 
Less: Write-offs, net of recoveries
5 2 1 1 1 — — 1 
Balance at September 30, 2022$84 $18 $11 $12 $43 $22 $7 $14 
Nine Months Ended September 30, 2023
ExelonComEdPECOBGEPHIPepcoDPLACE
Balance at December 31, 2022$82 $17 $9 $10 $46 $25 $7 $14 
Plus: Current period provision for expected credit losses
21 6 3 5 7 4 2 1 
Less: Write-offs, net of recoveries(a)
15 3 4 6 2 — — 2 
Balance at September 30, 2023$88 $20 $8 $9 $51 $29 $9 $13 
Nine Months Ended September 30, 2022
ExelonComEdPECOBGEPHIPepcoDPLACE
Balance at December 31, 2021$72 $17 $7 $9 $39 $16 $8 $15 
Plus: Current period provision (benefit) for expected credit losses
24 5 6 6 7 6 (1)2 
Less: Write-offs, net of recoveries
12 4 2 3 3 — — 3 
Balance at September 30, 2022$84 $18 $11 $12 $43 $22 $7 $14 
__________
(a)Recoveries were not material to the Registrants.












73


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

Note 6 — Accounts Receivable

Unbilled Customer Revenue
The following table provides additional information about unbilled customer revenues recorded in the Registrants' Consolidated Balance Sheets at September 30, 2023 and December 31, 2022.
Unbilled customer revenues(a)
ExelonComEdPECOBGEPHIPepcoDPLACE
September 30, 2023$740 $279 $135 $118 $208 $100 $44 $64 
December 31, 2022912 223 219 247 223 103 74 46 
__________
(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
Nine months ended September 30, 2023$3,124 $726 $843 $628 $927 $600 $174 $153 
Nine months ended September 30, 20223,088 
(a)
753 832 607 
(a)
896 559 168 169 
__________
(a)Includes $4 million of receivables purchased from Generation prior to the separation on February 1, 2022 for the nine months ended September 30, 2022.
74


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

Note 7 — Income Taxes
7. 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 September 30, 2023(a)
ExelonComEd
PECO(b)
BGEPHIPepcoDPLACE
U.S. Federal statutory rate21.0 %21.0 %21.0 %21.0 %21.0 %21.0 %21.0 %21.0 %
Increase (decrease) due to:
State income taxes, net of federal income tax benefit(c)
(2.7)7.8 (1.2)6.6 6.2 5.5 6.1 7.0 
Plant basis differences(4.4)(0.4)(15.6)(0.2)(1.5)(2.4)(0.9)(0.5)
Excess deferred tax amortization(6.4)(5.3)(2.4)(5.4)(8.0)(9.2)(10.0)(3.1)
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)(1.2)— (2.0)(0.5)(0.6)(0.4)(0.3)
Other1.8 0.2 0.2 (0.3)0.3 0.6 — 0.5 
Effective income tax rate8.7 %22.0 %2.0 %19.6 %17.4 %14.9 %15.7 %24.5 %
Three Months Ended September 30, 2022(a)
Exelon
ComEd
PECO(d)
BGE(d)
PHI(d)
Pepco(d)
DPL(d)
ACE(d)
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
9.0 8.0 20.7 6.8 1.4 (2.7)6.5 7.0 
Plant basis differences(5.3)(0.4)(14.2)(2.6)(1.7)(2.3)(0.8)(1.0)
Excess deferred tax amortization(11.6)(5.6)(3.2)(47.3)(19.3)(14.6)(21.7)(25.5)
Amortization of investment tax credit, including deferred taxes on basis difference(0.1)(0.1)— (0.2)(0.1)— (0.2)(0.2)
Tax credits(0.6)(0.4)— (1.9)(0.9)(0.8)(1.3)(0.7)
Other
(0.4)(0.1)0.3 (2.7)0.3 0.1 0.2 0.5 
Effective income tax rate12.0 %22.4 %24.6 %(26.9)%0.7 %0.7 %3.7 %1.1 %
__________
(a)Positive percentages represent income tax expense. Negative percentages represent income tax benefit.
(b)For PECO, the lower effective tax rate is primarily related to plant basis differences attributable to tax repair deductions.
(c)For Exelon, the lower state income taxes, net of federal income tax expense, is primarily due to the long-term marginal state income tax rate change of $54 million.
(d)For PECO, the higher effective tax rate is related to a one-time state income expense, net of federal income tax benefit, of $38 million attributable to the change in the Pennsylvania corporate income tax rate partially offset by plant basis differences attributable to tax repair deductions. For BGE, PHI, Pepco, DPL, and ACE, the lower effective tax rate is primarily related to the acceleration of certain income tax benefits due to distribution and transmission rate case settlements.

75


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

Note 7 — Income Taxes
Nine Months Ended September 30, 2023(a)
ExelonComEd
PECO(b)
BGEPHIPepcoDPLACE
U.S. Federal statutory rate21.0%21.0%21.0%21.0%21.0%21.0%21.0%21.0%
Increase (decrease) due to:
State income taxes, net of federal income tax benefit(c)
2.87.8(1.3)6.56.15.56.26.9
Plant basis differences(4.3)(0.4)(15.5)(0.5)(1.6)(2.5)(1.0)(0.5)
Excess deferred tax amortization(6.6)(5.5)(2.4)(5.4)(7.7)(9.2)(9.4)(2.6)
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)(0.7)—(0.7)(0.6)(0.7)(0.4)(0.3)
Other1.50.10.10.20.30.6—0.3
Effective income tax rate13.8%22.2%1.9%21.0%17.4%14.7%16.3%24.7%

Nine Months Ended September 30, 2022(a)
Exelon
ComEd
PECO(d)
BGE(d)
PHI(d)
Pepco(d)
DPL(d)
ACE(d)
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(e)
9.57.96.62.82.0(3.2)6.56.9
Plant basis differences(4.2)(0.5)(12.2)(1.1)(1.7)(2.4)(0.7)(1.1)
Excess deferred tax amortization(11.3)(5.7)(3.2)(20.7)(18.8)(15.4)(20.4)(24.7)
Amortization of investment tax credit, including deferred taxes on basis difference(0.1)(0.1)—(0.1)(0.1)—(0.2)(0.2)
Tax credits(f)
0.3(0.3)—(0.7)(0.7)(0.6)(0.7)(0.6)
Other(g)
2.8—0.2(0.1)0.2(0.2)0.30.2
Effective income tax rate18.0%22.3%12.4%1.1%1.9%(0.8)%5.8%1.5%
__________
(a)Positive percentages represent income tax expense. Negative percentages represent income tax benefit.
(b)For PECO, the lower effective tax rate is primarily related to plant basis differences attributable to tax repair deductions.
(c)For Exelon, the lower state income taxes, net of federal income tax expense, is primarily due to the long-term marginal state income tax rate change of $54 million.
(d)For PECO, the lower effective tax rate is primarily related to plant basis differences attributable to tax repair deductions partially offset by higher state income taxes, net of federal income tax benefit, related to a one-time expense of $38 million attributable to the change in the Pennsylvania corporate income tax rate. For BGE, PHI, Pepco, DPL and ACE, the lower effective tax rate is primarily related to the acceleration of certain income tax benefits due to distribution and transmission rate case settlements.
(e)For Exelon, the higher state income taxes, net of federal income tax benefit, is primarily due to the long-term marginal state income tax rate change of approximately $67 million and the recognition of a valuation allowance of approximately $40 million against the net deferred tax asset position for certain standalone state filing jurisdictions, partially offset by a one-time impact associated with a state tax benefit of $43 million and indemnification adjustments pursuant to the Tax Matters Agreement of $4 million as a result of the separation. For PECO, the higher state income taxes, net of federal income tax benefit, related to a one-time expense of $38 million attributable to the change in the Pennsylvania corporate income tax rate.
(f)For Exelon, reflects the income tax expense related to the write-off of federal tax credits subject to recapture of approximately $15 million as a result of the separation.
(g)For Exelon, primarily reflects the nondeductible transaction costs of approximately $19 million arising as part of the separation and indemnification adjustments pursuant to the Tax Matters Agreement of $40 million.




76


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

Note 7 — Income Taxes
Unrecognized Tax Benefits
Exelon, PHI and ACE have the following unrecognized tax benefits at September 30, 2023 and December 31, 2022. ComEd's, PECO's, BGE's, Pepco's, and DPL's amounts are not material.
Exelon(a)
PHIACE
September 30, 2023$138 $56 $16 
December 31, 2022148 59 17 
__________
(a)At September 30, 2023 and December 31, 2022, Exelon reflected a receivable of $50 million in Other deferred debits and other assets in the Consolidated Balance Sheet for Constellation’s share of unrecognized tax benefits for periods prior to the separation.
Reasonably possible the total amount of unrecognized tax benefits could significantly increase or decrease within 12 months after the reporting date.
As of September 30, 2023, ACE has $14 million of unrecognized state tax benefits that could significantly decrease within the 12 months after the reporting date based on the outcome of pending court cases involving other taxpayers. The unrecognized tax benefit, if recognized, may be included in future base rates and that portion would have no impact to the effective tax rate.
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. As of September 30, 2023, Exelon recorded a payable of $15 million in Other current liabilities that is due to Constellation.
Tax Refunds. The TMA specifies that Constellation is entitled to their share of any future tax refunds claimed by Exelon with respect to taxable periods prior to the separation to the extent that Constellation would have received such tax refunds under the existing Exelon tax sharing agreement.
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 September 30, 2023, Exelon recorded a payable of $22 million and $509 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.

77


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

Note 7 — Income Taxes
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.

Long-Term Marginal State Income Tax Rate (Exelon)

In the third quarter of 2023, Exelon updated its marginal state income tax rates for changes in state apportionment. The changes in marginal rates in the third quarter of 2023 resulted in a decrease of $54 million to the deferred tax liability at Exelon, and a corresponding adjustment to income tax expense, net of federal taxes.

Allocation of Tax Benefits (All Registrants)

The Utility Registrants are party to an agreement with Exelon that provides for the allocation of consolidated tax liabilities and benefits (Tax Sharing Agreement). The Tax Sharing Agreement provides that each party is allocated an amount of tax similar to that which would be owed had the party been separately subject to tax. In addition, any net benefit attributable to Exelon is reallocated to the Utility Registrants. That allocation is treated as a contribution to capital from Exelon to the party receiving the benefit.

The following table presents the allocation of tax benefits from Exelon under the Tax Sharing Agreement, for the three and nine months ended September 30, 2023, and 2022.
ComEdPECOBGEPHIPepcoDPLACE
September 30, 2023$13 $19 $— $10 $4 $— $2 
September 30, 2022$1 $47 $— $28 23 $3 2 

8. Retirement Benefits (All Registrants)
Defined Benefit Pension and OPEB
The majority of the 2023 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 5.53%. The majority of the 2023 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 5.51%.
During the first quarter of 2023, Exelon received an updated valuation of its pension and OPEB to reflect actual census data as of January 1, 2023. This valuation resulted in an increase to the pension obligation of $27 million and an increase to the OPEB obligation of $2 million. Additionally, AOCI increased by $10 million (after-tax) and regulatory assets and liabilities increased by $18 million and $1 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 and nine months ended September 30, 2023 and 2022.
78


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

Note 8 — Retirement Benefits
Pension BenefitsOPEB
Three Months Ended September 30,Three Months Ended September 30,
2023202220232022
Components of net periodic benefit cost
Service cost$39 $58 $6 $10 
Interest cost145 110 25 19 
Expected return on assets(189)(205)(21)(25)
Amortization of:
Prior service cost (credit)1 1 (2)(5)
Actuarial loss41 73 — 4 
Settlement charges18 — — — 
Net periodic benefit cost$55 $37 $8 $3 
Pension BenefitsOPEB
Nine Months Ended September 30,Nine Months Ended September 30,
2023202220232022
Components of net periodic benefit cost
Service cost$116 $177 $18 $30 
Interest cost434 330 76 57 
Expected return on assets(566)(619)(63)(75)
Amortization of:
Prior service cost (credit)2 3 (7)(15)
Actuarial loss (gain)125 222 (1)12 
Settlement charges18 — — — 
Net periodic benefit cost$129 $113 $23 $9 
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.
79


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

Note 8 — Retirement Benefits
 Three Months Ended September 30,Nine Months Ended September 30,
Pension and OPEB Costs (Benefit)2023202220232022
Exelon$63 $40 $152 $122 
ComEd6 15 19 45 
PECO(3)(2)(10)(6)
BGE14 11 42 33 
PHI25 13 74 39 
Pepco9 2 26 6 
DPL4 1 13 3 
ACE3 3 10 9 
Defined Contribution Savings Plan
The Registrants participate in a 401(k) defined contribution savings plan that is sponsored by Exelon. The plan is qualified under applicable sections of the IRC and allows employees to contribute a portion of their pre-tax and/or after-tax income in accordance with specified guidelines. All Registrants match a percentage of the employee contributions up to certain limits. The following table presents the employer contributions and employer matching contributions to the savings plan for the three and nine months ended September 30, 2023 and 2022.
Three Months Ended September 30,Nine Months Ended September 30,
Savings Plan Employer Contributions2023202220232022
Exelon$27 $23 $74 $66 
ComEd12 11 31 29 
PECO3 3 10 9 
BGE3 2 8 7 
PHI5 4 13 11 
Pepco1 1 3 3 
DPL1 1 3 3 
ACE1 1 2 2 
9. 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.
80


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

Note 9 — Derivative Financial Instruments
Commodity Price Risk
The 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 2022 Form 10-K for additional information.
(b)The fair value of the DPL economic hedge is not material at September 30, 2023 and December 31, 2022.
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 may also utilize interest rate swaps to manage interest rate exposure and manage potential fluctuations in Electric operating revenues at the corporate level in consolidation, which are directly correlated to yields on U.S. Treasury bonds under ComEd's distribution formula rate. These interest rate swaps are accounted for as economic hedges. A hypothetical 50
81


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

Note 9 — Derivative Financial Instruments
basis point change in the interest rates associated with Exelon's interest rate swaps as of September 30, 2023 would result in an immaterial impact to Exelon's Consolidated Net Income.
Below is a summary of the interest rate hedge balances at September 30, 2023 and December 31, 2022.
September 30, 2023
Derivatives Designated
as Hedging Instruments		Economic HedgesTotal
Other current assets$— $3 $3 
Other deferred debits (noncurrent assets)41 — 41 
Total derivative assets41 3 44 
Mark-to-market derivative liabilities (current liabilities)— (23)(23)
Total mark-to-market derivative liabilities— (23)(23)
Total mark-to-market derivative net assets (liabilities)$41 $(20)$21 
December 31, 2022
Derivatives Designated
as Hedging Instruments		Economic HedgesTotal
Other deferred debits (noncurrent assets)$6 $5 $11 
Total derivative assets6 5 11 
Mark-to-market derivative liabilities (current liabilities)— (3)(3)
Mark-to-market derivative liabilities (noncurrent liabilities)(4)— (4)
Total mark-to-market derivative liabilities(4)(3)(7)
Total mark-to-market derivative net assets$2 $2 $4 
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 January 2023, Exelon Corporate entered into $115 million notional of 5-year maturity floating-to-fixed swaps and $115 million notional of 10-year maturity floating-to-fixed swaps, for a total of $230 million designated as cash flow hedges. In February 2023, Exelon terminated the previously issued floating-to-fixed swaps with a total notional of $1.5 billion upon issuance of $2.5 billion of debt. See Note 10 – Debt and Credit Agreements for additional information on the debt issuance. Prior to the termination, the AOCI derivative gain was $7 million (net of tax). The settlements resulted in a cash receipt of $10 million, which 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.
Since the termination in February 2023, Exelon has entered into additional floating-to-fixed swaps. The following table provides the notional amounts outstanding held by Exelon at September 30, 2023 and December 31, 2022.
September 30, 2023December 31, 2022
5-year maturity floating-to-fixed swaps$390 $635 
10-year maturity floating-to-fixed swaps390 635 
Total$780 $1,270 
The related AOCI derivative gain for the three and nine months ended as of September 30, 2023 was $22 million and $31 million (net of tax). See Note 14 – Changes in Accumulated Other Comprehensive Income (Loss) for additional information.
Economic Hedges (Interest Rate and Other Risk)
82


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

Note 9 — Derivative Financial Instruments
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.
Exelon Corporate enters into floating-to-fixed interest rate cap swaps to manage a portion of interest rate exposure in connection with existing borrowings. In the fourth quarter of 2022, Exelon Corporate entered into $1 billion notional of 18-month maturity floating-to-fixed interest rate cap swaps and $850 million notional of 6-month maturity floating-to-fixed interest rate cap swaps, for a total of $1.85 billion notional of floating-to-fixed interest rate cap swaps as of December 31, 2022. The 6-month maturity floating-to-fixed interest rate cap swaps of $850 million notional matured in March 2023. Exelon receives payments on the interest rate cap when the floating rate exceeds the fixed rate. Settlements received are immaterial as of September 30, 2023.
Additionally, to manage potential fluctuations in Electric operating revenues related to ComEd's distribution formula rate, Exelon Corporate enters into 30-year constant maturity treasury interest rate (Corporate 30-year treasury) swaps.
The following table provides the notional amounts outstanding held by Exelon at September 30, 2023 and December 31, 2022.
Hedging InstrumentSeptember 30, 2023December 31, 2022
Interest rate cap swaps$1,000 $1,850 
Constant maturity treasury interest rate swaps4,875 500 
Total$5,875 $2,350 
For the three and nine months ended September 30, 2023, Exelon Corporate recognized the following net pre-tax mark-to-market (losses) which are also recognized in Net fair value changes related to derivatives in Exelon's Consolidated Statements of Cash Flows. Exelon had no swaps for the three and nine months ended September 30, 2022.
Three Months Ended September 30, 2023Nine Months Ended September 30, 2023
Income Statement Location(Loss) Gain(Loss) Gain
Electric operating revenues$(16)$(21)
Interest expense— 1 
Total$(16)$(20)
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 decreased as of September 30, 2023 due to decreasing 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, at September 30, 2023 and December 31, 2022:
83


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

Note 9 — Derivative Financial Instruments
September 30, 2023December 31, 2022
Exelon$112 $297 
ComEd105 77 
PECO(a)
— — 
BGE1 23 
PHI6 197 
Pepco(b)
— 26 
DPL1 121 
ACE5 50 
__________
(a)PECO had less than one million in cash collateral held with external parties at September 30, 2023 and December 31, 2022.
(b)Pepco had less than one million in cash collateral held with external parties at September 30, 2023.
The Utility Registrants’ electric supply procurement contracts do not contain provisions that would require them to post collateral. PECO’s, BGE’s, and DPL’s natural gas procurement contracts contain provisions that could require PECO, BGE, and DPL to post collateral in the form of cash or credit support, which vary by contract and counterparty, with thresholds contingent upon PECO’s, BGE's, and DPL’s credit rating. As of September 30, 2023, 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 September 30, 2023, they could have been required to post collateral to their counterparties of $20 million, $30 million, and $9 million, respectively.
10. 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 September 30, 2023 and December 31, 2022.
Outstanding Commercial
Paper at		Average Interest Rate on
Commercial Paper Borrowings at
Commercial Paper IssuerSeptember 30, 2023December 31, 2022September 30, 2023December 31, 2022
Exelon(a)
$820 $1,938 5.44 %4.77 %
ComEd277 427 5.42 %4.71 %
PECO— 239 — %4.71 %
BGE59 409 5.43 %4.81 %
PHI(b)
173 414 5.47 %4.78 %
Pepco— 299 — %4.79 %
DPL— 115 — %4.76 %
ACE173 — 5.47 %— %
84


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

Note 10 — Debt and Credit Agreements
__________
(a)Exelon Corporate had $311 million and $449 million in outstanding commercial paper borrowings at September 30, 2023 and December 31, 2022, 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 %
ComEd1,000 SOFR plus 1.000 %
PECO600 SOFR plus 0.900 %
BGE600 SOFR plus 0.900 %
Pepco300 SOFR plus 1.075 %
DPL300 SOFR plus 1.000 %
ACE300 SOFR plus 1.075 %
Exelon Corporate and the Utility Registrants had no outstanding amounts on the revolving credit facilities as of September 30, 2023.
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 2022 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 2023 and was bifurcated into two tranches of $300 million on March 14, 2023 and $200 million on March 24, 2023. The agreements will expire on March 14, 2024 and March 22, 2024, respectively. Pursuant to the loan agreements, loans made thereunder bear interest at a variable rate equal to SOFR plus 0.90% and all indebtedness thereunder is unsecured. The loan agreement is reflected in Exelon's Consolidated Balance Sheets within Short-term borrowings.
On October 4, 2022, ComEd entered into a 364-day term loan agreement for $150 million with a variable rate equal to SOFR plus 0.75% and an expiration date of October 3, 2023. The proceeds from this loan were used to repay outstanding commercial paper obligations. The balance of the loan was repaid on January 13, 2023 in conjunction with the $400 million and $575 million First Mortgage Bond agreements that were entered into on January 3, 2023. Refer to the Issuance of Long-Term Debt table below for further information.
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. The proceeds from this 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.
85


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

Note 10 — Debt and Credit Agreements
Long-Term Debt
Issuance of Long-Term Debt
During the nine months ended September 30, 2023, the following long-term debt was issued:
CompanyTypeInterest RateMaturityAmountUse of Proceeds
ExelonNotes5.15%March 15, 2028$1,000Repay existing indebtedness and for general corporate purposes.
ExelonNotes5.30%March 15, 2033850Repay existing indebtedness and for general corporate purposes.
ExelonNotes5.60%March 15, 2053650Repay existing indebtedness and for general corporate purposes.
ComEdFirst Mortgage Bonds, Series 1344.90%February 1, 2033400Repay outstanding commercial paper obligations and to fund other general corporate purposes.
ComEdFirst Mortgage Bonds Series 1355.30%February 1, 2053575Repay outstanding commercial paper obligations and to fund other general corporate purposes.
PECOFirst and Refunding Mortgage Bonds4.90%June 15, 2033575Refinance existing indebtedness, refinance outstanding commercial paper obligations, and for general corporate purposes.
BGENotes5.40%June 1, 2053700Repay outstanding commercial paper obligations, repay existing indebtedness, and for general corporate purposes.
PepcoFirst Mortgage Bonds5.30%March 15, 203385Repay existing indebtedness and for general corporate purposes.
PepcoFirst Mortgage Bonds5.40%March 15, 203840Repay existing indebtedness and for general corporate purposes.
PepcoFirst Mortgage Bonds5.57%March 15, 2053125Repay existing indebtedness and for general corporate purposes.
PepcoFirst Mortgage Bonds5.35%September 13, 2033100Repay existing indebtedness and for general corporate purposes.
DPL(a)
First Mortgage Bonds5.30%March 15, 203360Repay existing indebtedness and for general corporate purposes.
DPLFirst Mortgage Bonds5.57%March 15, 205365Repay existing indebtedness and for general corporate purposes.
ACEFirst Mortgage Bonds5.57%March 15, 205375Repay existing indebtedness and for general corporate purposes.
__________
(a)On March 15, 2023, DPL entered into a purchase agreement of First Mortgage Bonds of $340 million, $75 million, and $110 million at 5.45%, 5.55% and 5.72% due on November 8, 2033, November 8, 2038, and November 8, 2053, respectively. The closing date of the issuance is expected to occur in November 2023.
Debt Covenants
As of September 30, 2023, the Registrants are in compliance with debt covenants.
86


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

Note 11 — Fair Value of Financial Assets and Liabilities
11. 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 2022 Form 10-K.
Fair Value of Financial Liabilities Recorded at Amortized Cost
The following tables present the carrying amounts and fair values of the Registrants’ short-term liabilities, long-term debt, and trust preferred securities (long-term debt to financing trusts or junior subordinated debentures) as of September 30, 2023 and December 31, 2022. 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.
September 30, 2023December 31, 2022
Carrying AmountFair ValueCarrying AmountFair Value
Level 1Level 2Level 3TotalLevel 1Level 2Level 3Total
Long-Term Debt, including amounts due within one year(a)
Exelon$41,085 $— $31,584 $2,675 $34,259 $37,074 $— $29,902 $2,327 $32,229 
ComEd11,484 — 9,343 — 9,343 10,518 — 9,006 — 9,006 
PECO5,133 — 4,110 — 4,110 4,612 — 3,864 50 3,914 
BGE4,601 — 3,735 — 3,735 4,207 — 3,613 — 3,613 
PHI8,637 — 4,352 2,675 7,027 8,120 — 4,507 2,277 6,784 
Pepco4,095 — 2,129 1,473 3,602 3,751 — 2,229 1,205 3,434 
DPL2,060 — 1,126 543 1,669 1,938 — 1,164 458 1,622 
ACE1,833 — 893 659 1,552 1,757 — 909 614 1,523 
Long-Term Debt to Financing Trusts
Exelon$390 $— $— $384 $384 $390 $— $— $384 $384 
ComEd205 — — 206 206 205 — — 204 204 
PECO184 — — 179 179 184 — — 180 180 
__________
(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 2022 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 2022 Form 10-K for finance lease liabilities.

87


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

Note 11 — 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 September 30, 2023 and December 31, 2022. The Registrants have no financial assets or liabilities measured using the NAV practical expedient:
Exelon
At September 30, 2023At December 31, 2022
Level 1Level 2Level 3TotalLevel 1 Level 2Level 3Total
Assets
Cash equivalents(a)
$649 $— $— $649 $664 $— $— $664 
Rabbi trust investments
Cash equivalents66 — — 66 62 — — 62 
Mutual funds53 — — 53 49 — — 49 
Fixed income— 7 — 7 — 7 — 7 
Life insurance contracts — 60 42 102 — 58 40 98 
Rabbi trust investments subtotal119 67 42 228 111 65 40 216 
Interest rate derivative assets
Derivatives designated as hedging instruments— 41 — 41 — 6 — 6 
Economic hedges— 3 — 3 — 5 — 5 
Interest rate derivative assets subtotal— 44 — 44 — 11 — 11 
Total assets768 111 42 921 775 76 40 891 
Liabilities
Commodity derivative liabilities— — (134)(134)— — (84)(84)
Interest rate derivative liabilities
Derivatives designated as hedging instruments— — — — — (4)— (4)
Economic hedges— (23)— (23)— (3)— (3)
Interest rate derivative liabilities subtotal — (23)— (23)— (7)— (7)
Deferred compensation obligation— (69)— (69)— (75)— (75)
Total liabilities— (92)(134)(226)— (82)(84)(166)
Total net assets (liabilities)$768 $19 $(92)$695 $775 $(6)$(44)$725 
__________    
(a)Exelon excludes cash of $188 million and $345 million at September 30, 2023 and December 31, 2022, respectively, and restricted cash of $110 million and $81 million at September 30, 2023 and December 31, 2022, respectively, and includes long-term restricted cash of $212 million and $117 million at September 30, 2023 and December 31, 2022, respectively, which is reported in Other deferred debits and other assets in the Consolidated Balance Sheets.

88


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

Note 11 — Fair Value of Financial Assets and Liabilities
ComEd, PECO, and BGE
ComEdPECOBGE
At September 30, 2023Level 1Level 2Level 3TotalLevel 1Level 2Level 3TotalLevel 1Level 2Level 3Total
Assets
Cash equivalents(a)
$491 $— $— $491 $29 $— $— $29 $2 $— $— $2 
Rabbi trust investments
Mutual funds— — — — 9 — — 9 9 — — 9 
Life insurance contracts — — — — — 17 — 17 — — — — 
Rabbi trust investments subtotal— — — — 9 17 — 26 9 — — 9 
Total assets491 — — 491 38 17 — 55 11 — — 11 
Liabilities
Commodity derivative liabilities(b)
— — (134)(134)— — — — — — — — 
Deferred compensation obligation— (7)— (7)— (8)— (8)— (4)— (4)
Total liabilities— (7)(134)(141)— (8)— (8)— (4)— (4)
Total net assets (liabilities)$491 $(7)$(134)$350 $38 $9 $— $47 $11 $(4)$— $7 
ComEdPECOBGE
At December 31, 2022Level 1Level 2Level 3TotalLevel 1Level 2Level 3TotalLevel 1Level 2Level 3Total
Assets
Cash equivalents(a)
$392 $— $— $392 $10 $— $— $10 $23 $— $— $23 
Rabbi trust investments
Mutual funds— — — — 7 — — 7 7 — — 7 
Life insurance contracts — — — — — 15 — 15 — — — — 
Rabbi trust investments subtotal— — — — 7 15 — 22 7 — — 7 
Total assets392 — — 392 17 15 — 32 30 — — 30 
Liabilities
Commodity derivative liabilities(b)
— — (84)(84)— — — — — — — — 
Deferred compensation obligation— (8)— (8)— (7)— (7)— (4)— (4)
Total liabilities— (8)(84)(92)— (7)— (7)— (4)— (4)
Total net assets (liabilities)$392 $(8)$(84)$300 $17 $8 $— $25 $30 $(4)$— $26 
__________
(a)ComEd excludes cash of $55 million and $42 million at September 30, 2023 and December 31, 2022, respectively, and restricted cash of $105 million and $77 million at September 30, 2023 and December 31, 2022, respectively. Additionally, ComEd includes long-term restricted cash of $212 million and $117 million at September 30, 2023 and December 31, 2022, respectively, which is reported in Other deferred debits and other assets in the Consolidated Balance Sheets. PECO excludes cash of $23 million and $58 million at September 30, 2023 and December 31, 2022, respectively. BGE excludes cash of $13 million and $43 million at September 30, 2023 and December 31, 2022, respectively, and restricted cash of $1 million and $1 million at September 30, 2023 and December 31, 2022, respectively.
(b)The Level 3 balance consists of the current and noncurrent liability of $21 million and $113 million, respectively, at September 30, 2023 and $5 million and $79 million, respectively, at December 31, 2022 related to floating-to-fixed energy swap contracts with unaffiliated suppliers.

89


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

Note 11 — Fair Value of Financial Assets and Liabilities
PHI, Pepco, DPL, and ACE
At September 30, 2023At December 31, 2022
PHI Level 1Level 2Level 3TotalLevel 1Level 2Level 3Total
Assets
Cash equivalents(a)
$83 $— $— $83 $205 $— $— $205 
Rabbi trust investments
Cash equivalents63 — — 63 59 — — 59 
Mutual funds10 — — 10 11 — — 11 
Fixed income— 7 — 7 — 7 — 7 
Life insurance contracts— 21 40 61 — 22 39 61 
Rabbi trust investments subtotal73 28 40 141 70 29 39 138 
Total assets156 28 40 224 275 29 39 343 
Liabilities
Deferred compensation obligation— (13)— (13)— (14)— (14)
Total liabilities— (13)— (13)— (14)— (14)
Total net assets$156 $15 $40 $211 $275 $15 $39 $329 
PepcoDPLACE
At September 30, 2023Level 1Level 2Level 3TotalLevel 1Level 2Level 3TotalLevel 1Level 2Level 3Total
Assets
Cash equivalents(a)
$22 $— $— $22 $1 $— $— $1 $1 $— $— $1 
Rabbi trust investments
Cash equivalents62 — — 62 — — — — — — — — 
Life insurance contracts— 21 40 61 — — — — — — — — 
Rabbi trust investments subtotal62 21 40 123 — — — — — — — — 
Total assets84 21 40 145 1 — — 1 1 — — 1 
Liabilities
Deferred compensation obligation— (1)— (1)— — — — — — — — 
Total liabilities— (1)— (1)— — — — — — — — 
Total net assets$84 $20 $40 $144 $1 $— $— $1 $1 $— $— $1 
90


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

Note 11 — Fair Value of Financial Assets and Liabilities
PepcoDPLACE
At December 31, 2022Level 1Level 2Level 3TotalLevel 1Level 2Level 3TotalLevel 1Level 2Level 3Total
Assets
Cash equivalents(a)
$51 $— $— $51 $121 $— $— $121 $1 $— $— $1 
Rabbi trust investments
Cash equivalents59 — — 59 — — — — — — — — 
Life insurance contracts— 22 38 60 — — — — — — — — 
Rabbi trust investments subtotal59 22 38 119 — — — — — — — — 
Total assets110 22 38 170 121 — — 121 1 — — 1 
Liabilities
Deferred compensation obligation— (1)— (1)— — — — — — — — 
Total liabilities— (1)— (1)— — — — — — — — 
Total net assets$110 $21 $38 $169 $121 $— $— $121 $1 $— $— $1 
__________
(a)PHI excludes cash of $60 million and $165 million at September 30, 2023 and December 31, 2022, respectively, and restricted cash of $3 million and $3 million at September 30, 2023 and December 31, 2022, respectively. Pepco excludes cash of $31 million and $45 million at September 30, 2023 and December 31, 2022, respectively, and restricted cash of $3 million and $3 million at September 30, 2023 and December 31, 2022, respectively. DPL excludes cash of $5 million and $31 million at September 30, 2023 and December 31, 2022, respectively. ACE excludes cash of $13 million and $71 million at September 30, 2023 and December 31, 2022, respectively.

91


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

Note 11 — 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 and nine months ended September 30, 2023 and 2022:
ExelonComEdPHI and Pepco
Three Months Ended September 30, 2023Total Commodity
Derivatives		Life Insurance Contracts
Balance at June 30, 2023$(91)$(133)$42 
Total realized / unrealized gains (losses)
Included in net income(a)
— — (2)
Included in regulatory assets/liabilities(1)(1)
(b)
— 
Balance at September 30, 2023$(92)$(134)
(c)
$40 
The amount of total gains included in income attributed to the change in unrealized gains related to assets and liabilities at September 30, 2023$— $— $(2)
ExelonComEdPHI and Pepco
Three Months Ended September 30, 2022Total Commodity
Derivatives		Life Insurance Contracts
Balance at June 30, 2022$(50)$(88)$37 
Total realized / unrealized gains (losses)
Included in net income(a)
1 — 1 
Included in regulatory assets/liabilities45 45 
(b)
— 
Balance at September 30, 2022$(4)$(43)
(c)
$38 
The amount of total gains included in income attributed to the change in unrealized gains related to assets and liabilities at September 30, 2022$1 $— $1 
ExelonComEdPHI and Pepco
Nine Months Ended September 30, 2023Total Commodity
Derivatives		Life Insurance Contracts
Balance at December 31, 2022$(44)$(84)$40 
Total realized / unrealized gains (losses)
Included in net income(a)
2 — — 
Included in regulatory assets/liabilities(50)(50)
(b)
— 
Balance at September 30, 2023$(92)$(134)
(c)
$40 
The amount of total gains included in income attributed to the change in unrealized gains related to assets and liabilities at September 30, 2023$2 $— $— 

ExelonComEdPHI and Pepco
Nine Months Ended September 30, 2022Total Commodity
Derivatives		Life Insurance Contracts
Balance at December 31, 2021$(182)$(219)$35 
Total realized / unrealized gains (losses)
Included in net income(a)
3 — 3 
Included in regulatory assets/liabilities176 176 
(b)
— 
Transfers out of Level 3(1)— — 
Balance at September 30, 2022$(4)$(43)
(c)
$38 
The amount of total gains included in income attributed to the change in unrealized gain related to assets and liabilities at September 30, 2022$3 $— $3 
__________
92


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

Note 11 — Fair Value of Financial Assets and Liabilities
(a)Classified in Operating and maintenance expense in the Consolidated Statements of Operations and Comprehensive Income.
(b)Includes $5 million of decreases in fair value and an increase for realized gains due to settlements of $4 million recorded in Purchased power expense associated with floating-to-fixed energy swap contracts with unaffiliated suppliers for the three months ended September 30, 2023. Includes $51 million of increases in fair value and a decrease for realized gains due to settlements of $6 million recorded in Purchased power expense associated with floating-to-fixed energy swap contracts with unaffiliated suppliers for the three months ended September 30, 2022. Includes $73 million of decreases in fair value and an increase for realized gains due to settlements of $23 million recorded in Purchased power expense associated with floating-to-fixed energy swap contracts with unaffiliated suppliers for the nine months ended September 30, 2023. Includes $179 million of increases in fair value and a decrease for realized losses due to settlements of $3 million recorded in Purchased power expense associated with floating-to-fixed energy swap contracts with unaffiliated suppliers for the nine months ended September 30, 2022.
(c)The balance consists of a current and noncurrent liability of $21 million and $113 million, respectively, at September 30, 2023. The balance consists of $24 million of current assets and current and noncurrent liability of none and $67 million, respectively at September 30, 2022.
Commodity Derivatives (Exelon and ComEd)
The table below discloses the significant unobservable inputs to the forward curve used to value mark-to-market derivatives.
Type of tradeFair Value at September 30, 2023Fair Value at December 31, 2022Valuation
Technique		Unobservable
Input		2023 Range & Arithmetic Average2022 Range & Arithmetic Average
Commodity derivatives$(134)$(84)Discounted
Cash Flow
Forward power price(a)
$30.13-$72.72$42.77$34.78-$75.71$48.44
________
(a)An increase to the forward power price would increase the fair value.

12. 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 2022 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 September 30, 2023:
DescriptionExelon PHI Pepco DPLACE
Total commitments$513 $320 $120 $89 $111 
Remaining commitments(a)
42 39 34 3 2 
__________
(a)Remaining commitments extend through 2026 and include escrow funds, charitable contributions, and rate credits.

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Commercial Commitments (All Registrants). The Registrants’ commercial commitments at September 30, 2023, representing commitments potentially triggered by future events were as follows:
Expiration within
Total202320242025202620272028 and beyond
Exelon
Letters of credit$20 $9 $11 $— $— $— $— 
Surety bonds(a)
207 85 122 — — — — 
Financing trust guarantees378 — — — — — 378 
Guaranteed lease residual values(b)
29 — 4 6 5 4 10 
Total commercial commitments $634 $94 $137 $6 $5 $4 $388 
ComEd
Letters of credit$12 $6 $6 $— $— $— $— 
Surety bonds(a)
46 5 41 — — — — 
Financing trust guarantees200 — — — — — 200 
Total commercial commitments $258 $11 $47 $— $— $— $200 
PECO
Letters of credit$1 $— $1 $— $— $— $— 
Surety bonds(a)
2 — 2 — — — — 
Financing trust guarantees178 — — — — — 178 
Total commercial commitments $181 $— $3 $— $— $— $178 
BGE
Letters of credit$4 $2 $2 $— $— $— $— 
Surety bonds(a)
3 1 2 — — — — 
Total commercial commitments $7 $3 $4 $— $— $— $— 
PHI
Surety bonds(a)
$97 $75 $22 $— $— $— $— 
Guaranteed lease residual values(b)
29 — 4 6 5 4 10 
Total commercial commitments $126 $75 $26 $6 $5 $4 $10 
Pepco
Surety bonds(a)
$85 $71 $14 $— $— $— $— 
Guaranteed lease residual values(b)
10 — 1 3 2 1 3 
Total commercial commitments $95 $71 $15 $3 $2 $1 $3 
DPL
Surety bonds(a)
$7 $2 $5 $— $— $— $— 
Guaranteed lease residual values(b)
12 — 2 2 2 2 4 
Total commercial commitments $19 $2 $7 $2 $2 $2 $4 
ACE
Surety bonds(a)
$5 $2 $3 $— $— $— $— 
Guaranteed lease residual values(b)
7 — 1 1 1 1 3 
Total commercial commitments $12 $2 $4 $1 $1 $1 $3 
__________
(a)Surety bonds — Guarantees issued related to contract and commercial agreements, excluding bid bonds.
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(b)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 $66 million guaranteed by Exelon and PHI, of which $22 million, $26 million, and $18 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 19 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.
During the third quarter of 2023, ComEd and PECO completed an annual study of their future estimated MGP remediation requirements. The study resulted in a $25 million increase to the environmental liability and related regulatory asset for ComEd. The increase was primarily due to increased costs resulting from inflation and changes in remediation plans. The study did not result in a material change to the environmental liability for PECO.
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At September 30, 2023 and December 31, 2022, 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:
September 30, 2023December 31, 2022
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$434 $345 $409 $355 
ComEd312 311 325 324 
PECO28 26 25 23 
BGE9 8 9 8 
PHI82 — 46 — 
Pepco80 — 44 — 
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. It is currently anticipated that the landside FS will be complete and approved by DOEE by the end of the first quarter of 2024 and the waterside FS will 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 has been lodged with the court. Following a 30-day public comment period, DOEE will request that the court approve this addendum to the Consent Decree, which will become effective upon the court’s approval.
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
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Note 12 — Commitments and Contingencies
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 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 has been filed with the U.S. District Court for the District of Columbia. Following a 30-day public comment period, the District will ask the court to approve the Anacostia River Consent Decree, which will become effective upon the court’s approval. 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 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 has been filed with the District of Columbia Superior Court. Following a 30-day public comment period regarding the environmental assessment work required by the Consent Order, the District will ask the court to approve the Consent Order, which will be become effective upon the court’s approval. Exelon, PHI, and Pepco have accrued
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Note 12 — Commitments and Contingencies
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.
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 Deferred Prosecution Agreement (DPA) with the USAO to resolve the USAO investigation. Under the DPA, the USAO filed a single charge alleging that ComEd improperly gave and offered to give jobs, vendor subcontracts, and payments associated with those jobs and subcontracts for the benefit of the former Speaker of the Illinois House of Representatives and the Speaker’s associates, with the intent to influence the Speaker’s action regarding legislation affecting ComEd’s interests. The DPA provided that the USAO would defer any prosecution of such charge and any other criminal or civil case against ComEd in connection with the matters identified therein for a three-year period subject to certain obligations of ComEd, including payment to the U.S. Treasury of $200 million, which was paid in November 2020. Exelon was not made a party to the DPA, and therefore the investigation by the USAO into Exelon’s activities ended with no charges being brought against Exelon. 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. In addition, the Citizens Utility Board (CUB) filed a motion to intervene in these cases on October 22, 2020 which was granted on December 23, 2020. On September 9, 2021, the federal court granted Exelon’s and ComEd’s motion to dismiss and dismissed the plaintiffs’ and CUB’s federal law claim with prejudice. The federal court also dismissed the related state law claims made by the federal plaintiffs and CUB on jurisdictional grounds. Plaintiffs appealed dismissal of the federal law claim to the Seventh Circuit Court of Appeals. Plaintiffs and CUB also refiled their state law claims in state court and moved to consolidate them with the already pending consumer state court class action, discussed below. 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. In November 2020, CUB filed a motion to intervene in the cases pursuant to an Illinois statute allowing CUB to intervene as a party or otherwise participate on behalf of utility consumers in any proceeding which affects the interest of utility consumers. On November 23, 2020, the court allowed CUB’s intervention, but denied CUB's request to stay these cases. Plaintiffs subsequently filed a consolidated complaint, and ComEd and Exelon filed a motion to dismiss on jurisdictional and substantive grounds on January 11, 2021. Briefing on that motion
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Note 12 — Commitments and Contingencies
was completed on March 2, 2021. The parties agreed, on March 25, 2021, along with the federal court plaintiffs discussed above, to jointly engage in mediation. The parties participated in a one-day mediation on June 7, 2021 but no settlement was reached. On December 23, 2021, the state court granted ComEd and Exelon's motion to dismiss with prejudice. On December 30, 2021, plaintiffs filed a motion to reconsider that dismissal and for permission to amend their complaint. The court denied the plaintiffs' motion on January 21, 2022. Plaintiffs have appealed the court's ruling dismissing their complaint to the First District Court of Appeals. On February 15, 2022, Exelon and ComEd 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 Illinois Appellate Court affirmed the dismissal. Plaintiffs may ask the Illinois Supreme Court to grant them leave to further appeal, but such appeal is not allowed as a matter of right.
•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. Plaintiff served initial discovery requests on ComEd in December 2022, to which ComEd has responded. ComEd and Exelon filed a motion to dismiss the Complaint on February 3, 2023. On June 16, 2023, the court granted Exelon and ComEd's motion to dismiss the action with prejudice. Plaintiff filed its notice of appeal of that dismissal on July 17, 2023. Plaintiff's opening appellate brief was filed on October 19, 2023.
•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. On May 26, 2021, defendants moved the court to certify its order denying the motion to dismiss for interlocutory appeal. Briefing on the motion was completed in June 2021, and that motion was denied on January 28, 2022. In May 2021, the parties each filed respective initial discovery disclosures. On June 9, 2021, defendants filed their answer and affirmative defenses to the complaint and the parties engaged thereafter in discovery. On September 9, 2021, the U.S. government moved to intervene in the lawsuit and stay discovery until the parties entered into an amendment to their protective order that would prohibit the parties from requesting discovery into certain matters, including communications with the U.S. government. The court ordered said amendment to the protective order on November 15, 2021 and discovery resumed. The court further amended the protective order on October 17, 2022 and extended it until May 15, 2023. 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. On October 12, 2021, the parties to the derivative action filed an agreed motion to stay that 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. The parties participated in a mediation in February 2023, but the matter did not resolve at that time. On April 26 and May 1, 2023, two additional demand letter shareholders each filed a separate derivative lawsuit against current and former Exelon and ComEd officers and directors, and certain third parties, and against Exelon as nominal defendant, asserting claims similar to those made in their respective demand letters. On May 25, 2023, certain demand letter shareholders (Settling
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Shareholders) filed a separate derivative lawsuit against current and former Exelon and ComEd officers and directors, and against Exelon as nominal defendant, asserting claims similar to those made in their respective demand letters. The then pending derivative lawsuits were subsequently consolidated. On May 26, 2023, prior to lawsuit consolidation, the SLC filed a Notice of Determination and Intent to Seek Court Approval of Settlement (Notice of Determination). The Notice of Determination stated that, through mediation efforts, a settlement of the derivative claims had been approved 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 the Settling Shareholders (the Settling Parties). The Notice of Determination further specified the process by which the Settling Parties would seek court approval of the proposed settlement and resolution and dismissal of all derivative claims and lawsuits, including any lawsuits or actions brought by demand letter shareholders who are not participating in the proposed settlement. In furtherance of the proposed settlement, 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 13, 2023, the non-settling derivative shareholders filed a motion asking the court to set a status conference to discuss lifting the discovery stay. On June 29, 2023, an additional shareholder filed a separate derivative lawsuit against current and former Exelon and ComEd officers and directors, and against Exelon as nominal defendant, asserting claims similar to those made in its demand letter. On June 30, 2023, the non-settling shareholders’ motion for status and the SLC’s motion for preliminary approval was heard by the court, during which the court set a briefing schedule on the appropriate standard for evaluating the settlement and the proper scope of requested discovery. Following briefing and a hearing, the court allowed the non-settling shareholders to seek certain, limited discovery, which the SLC, Independent Review Committee, and Exelon responded to on October 5. On October 11, 2023, an additional non-settling shareholder filed a separate derivative lawsuit against current and former Exelon and ComEd officers and directors, and against Exelon as a nominal defendant, asserting claims similar to those made in its demand letter. Plaintiff has informed Exelon that he will move to consolidate this matter with the other pending derivative matters. The SLC filed its renewed motion for preliminary approval on October 26, with supporting submissions filed by the Independent Review Committee, Exelon, and the settling shareholders on that same day. The non-settling plaintiffs have until November 29 to file their response to the renewed motion for preliminary approval, and the SLC has until December 21 to file its reply.
•Several shareholders have sent requests seeking review of certain Exelon books and records since August 2021. Exelon has responded to each request.
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 September 30, 2023.
Savings Plan Claim (Exelon). On December 6, 2021, seven current and former employees filed a putative ERISA class action suit in U.S. District Court for the Northern District of Illinois against Exelon, its Board of Directors, the former Board Investment Oversight Committee, the Corporate Investment Committee, individual
100


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

Note 12 — Commitments and Contingencies
defendants, and other unnamed fiduciaries of the Exelon Corporation Employee Savings Plan (Plan). The complaint alleges that the defendants violated their fiduciary duties under the Plan by including certain investment options that allegedly were more expensive than and underperformed similar passively-managed or other funds available in the marketplace and permitting a third-party administrative service provider/recordkeeper and an investment adviser to charge excessive fees for the services provided. The plaintiffs seek declaratory, equitable and monetary relief on behalf of the Plan and participants. On February 16, 2022, the court granted the parties' stipulated dismissal of the individual named defendants without prejudice. The remaining defendants filed a motion to dismiss the complaint on February 25, 2022. On March 4, 2022, the Chamber of Commerce filed a brief of amicus curiae in support of the defendants' motion to dismiss. On September 22, 2022, the court granted Exelon’s motion to dismiss without prejudice. The court granted plaintiffs leave until October 31, 2022 to file an amended complaint, which was later extended to November 30, 2022. Plaintiffs filed their amended complaint on November 30, 2022. Defendants filed their motion to dismiss the amended complaint on January 20, 2023. On September 29, 2023, the court again granted Exelon's motion to dismiss but granted plaintiffs leave until October 20, 2023 to file a second amended complaint. Plaintiffs did not file an amended complaint by the deadline. On October 25, the parties filed a joint Stipulation of Dismissal, which provides that plaintiffs agreed that they will not initiate an appeal from the dismissal of this matter, and the parties agree that each side shall bear their own costs and attorneys’ fees. Plaintiffs also acknowledge in the Stipulation that defendants have neither paid nor agreed to pay or provide any monetary or equitable remedy in connection with the dismissal of this action. On October 27, the court entered final judgment dismissing the matter with prejudice. No loss contingencies have been reflected in Exelon’s consolidated financial statements with respect to this matter.
General (All Registrants). The Registrants are involved in various other litigation matters that are being defended and handled in the ordinary course of business. The Registrants are also from time to time subject to audits and investigations by the FERC and other regulators. The assessment of whether a loss is probable or reasonably possible, and whether the loss or a range of loss is estimable, often involves a series of complex judgments about future events. The Registrants maintain accruals for such losses that are probable of being incurred and subject to reasonable estimation. Management is sometimes unable to estimate an amount or range of reasonably possible loss, particularly where (1) the damages sought are indeterminate, (2) the proceedings are in the early stages, or (3) the matters involve novel or unsettled legal theories. In such cases, there is considerable uncertainty regarding the timing or ultimate resolution of such matters, including a possible eventual loss.
13. 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. As of September 30, 2023, Exelon has not issued any shares of Common stock under the ATM program and has not entered into any forward sale agreements.
101


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

Note 14 — Changes in Accumulated Other Comprehensive Income
14. Changes in Accumulated Other Comprehensive Income (Loss) (Exelon)
The following tables present changes in Exelon's AOCI, net of tax, by component:
Nine Months Ended September 30, 2023 Cash Flow Hedges
Pension and
Non-Pension
Postretirement
Benefit Plan
Items(a)
Foreign
Currency
Items		Total
Balance at December 31, 2022$2 $(640)$— $(638)
OCI before reclassifications6 (10)— (4)
Amounts reclassified from AOCI— 3 — 3 
Net current-period OCI6 (7)— (1)
Balance at March 31, 20238 (647)— (639)
OCI before reclassifications9 (3)— 6 
Amounts reclassified from AOCI— 3 — 3 
Net current-period OCI9 — — 9 
Balance at June 30, 202317 (647)— (630)
OCI before reclassifications22 (3)— 19 
Amounts reclassified from AOCI(1)16 — 15 
Net current-period OCI21 13 — 34 
Balance at September 30, 2023$38 $(634)$— $(596)

Nine Months Ended September 30, 2022Cash Flow Hedges
Pension and
Non-Pension
Postretirement
Benefit Plan
Items(a)
Foreign
Currency
Items		Total
Balance at December 31, 2021$(6)$(2,721)$(23)$(2,750)
Separation of Constellation6 1,994 23 2,023 
Amounts reclassified from AOCI— 14 — 14 
Net current-period OCI— 14 — 14 
Balance at March 31, 2022— (713)— (713)
OCI before reclassifications— 2 — 2 
Amounts reclassified from AOCI— 10 — 10 
Net current-period OCI— 12 — 12 
Balance at June 30, 2022— (701)— (701)
Amounts reclassified from AOCI— 9 — 9 
Net current-period OCI— 9 — 9 
Balance at September 30, 2022$— $(692)$— $(692)
__________
(a)This AOCI component is included in the computation of net periodic pension and OPEB cost. Additionally, as of February 1, 2022, in connection with the separation, Exelon's pension and OPEB plans were remeasured. See Note 14 — Retirement Benefits of the 2022 Form 10-K and Note 8 — Retirement Benefits for additional information. See Exelon's Statements of Operations and Comprehensive Income for individual components of AOCI.
102


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

Note 14 — 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 September 30,Nine Months Ended September 30,
2023202220232022
Pension and non-pension postretirement benefit plans:
Actuarial losses reclassified to periodic benefit cost$(5)$(3)$(7)$(11)
Pension and non-pension postretirement benefit plans valuation adjustments1 — 5 — 
Unrealized gains on cash flow hedges(7)— (11)— 
15. 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 September 30, 2023
Utility taxes(a)
$244 $82 $50 $23 $89 $82 $6 $1 
Property104 9 4 53 38 25 12 1 
Payroll31 8 4 5 7 2 1 1 
Three Months Ended September 30, 2022
Utility taxes(a)
$244 $84 $51 $22 $87 $79 $7 $1 
Property99 10 4 50 35 23 11 1 
Payroll28 7 5 4 7 2 1 — 
Nine Months Ended September 30, 2023
Utility taxes(a)
$665 $228 $128 $73 $236 $213 $20 $3 
Property300 27 12 153 108 73 34 1 
Payroll93 22 13 14 22 5 3 3 
Nine Months Ended September 30, 2022
Utility taxes(a)
$667 $233 $126 $70 $238 $216 $19 $3 
Property287 30 12 142 103 70 31 2 
Payroll92 21 14 13 21 5 4 2 
_________
(a)The Registrants' utility taxes represent municipal and state utility taxes and gross receipts taxes related to their operating revenues. The offsetting collection of utility taxes from customers is recorded in revenues in the Registrants’ Consolidated Statements of Operations and Comprehensive Income.
103


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

Note 15 — Supplemental Financial Information
Other, Net
ExelonComEdPECOBGE PHIPepcoDPLACE
Three Months Ended September 30, 2023
AFUDC — Equity$40 $7 $10 $4 $19 $15 $3 $1 
Non-service net periodic benefit cost(18)— — — — — — — 
Three Months Ended September 30, 2022
AFUDC — Equity$38 $10 $7 $5 $16 $12 $2 $2 
Non-service net periodic benefit cost16 — — — — — — — 
Nine Months Ended September 30, 2023
AFUDC — Equity$113 $25 $22 $11 $55 $42 $7 $6 
Non-service net periodic benefit cost(18)— — — — — — — 
Nine Months Ended September 30, 2022
AFUDC — Equity$112 $28 $22 $17 $45 $35 $5 $5 
Non-service net periodic benefit cost48 — — — — — — — 
Supplemental Cash Flow Information
The following tables provide additional information about material items recorded in the Registrants' Consolidated Statements of Cash Flows.
Depreciation, amortization, and accretion
Exelon(a)
ComEdPECOBGEPHIPepcoDPLACE
Nine Months Ended September 30, 2023
Property, plant, and equipment(b)
$2,073 $815 $287 $381 $550 $232 $155 $145 
Amortization of regulatory assets(b)
537 230 10 106 191 97 27 67 
Amortization of intangible assets, net(b)
6 — — — — — — — 
Total depreciation and amortization$2,616 $1,045 $297 $487 $741 $329 $182 $212 
Nine Months Ended September 30, 2022
Property, plant, and equipment(b)
$2,024 $770 $267 $355 $502 $214 $141 $126 
Amortization of regulatory assets(b)
532 212 10 115 195 98 31 66 
Amortization of intangible assets, net(b)
10 — — — — — — — 
Amortization of energy contract assets and liabilities(c)
3 — — — — — — — 
Nuclear fuel(d)
66 — — — — — — — 
ARO accretion(e)
44 — — — — — — — 
Total depreciation, amortization, and accretion$2,679 $982 $277 $470 $697 $312 $172 $192 
__________
(a)Exelon's 2022 amounts include amounts related to Generation prior to the separation. See Note 2 — Discontinued Operations for additional information.
(b)Included in Depreciation and amortization in the Registrants' Consolidated Statements of Operations and Comprehensive Income.
(c)Included in Electric operating revenues or Purchased power expense in Exelon’s Consolidated Statements of Operations and Comprehensive Income.
104


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

Note 15 — Supplemental Financial Information
(d)Included in Purchased fuel expense in Exelon's Consolidated Statement of Operations and Comprehensive Income.
(e)Included in Operating and maintenance expense in Exelon's Consolidated Statement of Operations and Comprehensive Income.
Other non-cash operating activities
Exelon(a)
ComEdPECOBGEPHIPepcoDPLACE
Nine Months Ended September 30, 2023
Pension and OPEB costs (benefit)$152 $19 $(10)$41 $74 $26 $13 $10 
Allowance for credit losses86 4 31 4 47 27 9 11 
True-up adjustments to decoupling mechanisms and formula rates(b)
(522)(405)(1)(47)(69)(28)(15)(26)
Amortization of operating ROU asset29 2 — 4 21 5 6 2 
Change in environmental liabilities37 — — — 37 37 — — 
AFUDC — Equity(113)(25)(22)(11)(55)(42)(7)(6)
Nine Months Ended September 30, 2022
Pension and OPEB costs (benefit)$124 $45 $(6)$34 $39 $6 $3 $9 
Allowance for credit losses130 40 32 18 42 21 9 12 
Other decommissioning-related activity36 — — — — — — — 
Energy-related options60 — — — — — — — 
True-up adjustments to decoupling mechanisms and formula rates(b)
(92)(163)(1)40 33 15 3 14 
Long-term incentive plan35 — — — — — — — 
Amortization of operating ROU asset47 1 — 14 21 5 6 3 
AFUDC — Equity(112)(28)(22)(17)(45)(35)(5)(5)
__________
(a)Exelon's 2022 amounts include amounts related to Generation prior to the separation. See Note 2 — Discontinued Operations for additional information.
(b)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 2022 Form 10-K for additional information.

105


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

Note 15 — Supplemental Financial Information
The following tables provide a reconciliation of cash, cash equivalents, and restricted cash reported within the Registrants’ Consolidated Balance Sheets that sum to the total of the same amounts in their Consolidated Statements of Cash Flows.
Cash, cash equivalents, and restricted cash
ExelonComEdPECOBGEPHIPepcoDPLACE
Balance at September 30, 2023
Cash and cash equivalents$300 $79 $43 $15 $121 $31 $5 $14 
Restricted cash and cash equivalents435 360 9 1 25 25 1 — 
Restricted cash included in Other deferred debits and other assets212 212 — — — — — — 
Total cash, restricted cash, and cash equivalents$947 $651 $52 $16 $146 $56 $6 $14 
Balance at December 31, 2022
Cash and cash equivalents$407 $67 $59 $43 $198 $45 $31 $72 
Restricted cash and cash equivalents566 327 9 24 175 54 121 — 
Restricted cash included in Other deferred debits and other assets117 117 — — — — — — 
Total cash, restricted cash, and cash equivalents$1,090 $511 $68 $67 $373 $99 $152 $72 
Balance at September 30, 2022
Cash and cash equivalents$446 $63 $94 $20 $219 $21 $49 $112 
Restricted cash and cash equivalents744 342 9 130 234 77 157 — 
Restricted cash included in Other deferred debits and other assets83 83 — — — — — — 
Total cash, restricted cash, and cash equivalents$1,273 $488 $103 $150 $453 $98 $206 $112 
Balance at December 31, 2021
Cash and cash equivalents$672 $131 $36 $51 $136 $34 $28 $29 
Restricted cash and cash equivalents321 210 8 4 77 34 43 — 
Restricted cash included in Other deferred debits and other assets44 43 — — — — — — 
Cash, restricted cash, and cash equivalents from discontinued operations582 — — — — — — — 
Total cash, restricted cash, and cash equivalents$1,619 $384 $44 $55 $213 $68 $71 $29 
For additional information on restricted cash see Note 1 — Significant Accounting Policies of the 2022 Form 10-K.
Supplemental Balance Sheet Information
The following table provides additional information about material items recorded in the Registrants' Consolidated Balance Sheets.
106


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

Note 15 — Supplemental Financial Information
Accrued expenses
ExelonComEdPECOBGEPHIPepcoDPLACE
Balance at September 30, 2023
Compensation-related accruals(a)
$548 $162 $67 $63 $99 $27 $17 $14 
Taxes accrued255 148 61 100 120 88 19 13 
Interest accrued391 78 52 59 81 38 24 17 
Balance at December 31, 2022
Compensation-related accruals(a)
$613 $179 $81 $79 $104 $29 $20 $16 
Taxes accrued211 92 10 34 70 52 8 12 
Interest accrued338 124 47 42 61 32 9 14 
__________
(a)Primarily includes accrued payroll, bonuses and other incentives, vacation, and benefits.

16. Related Party Transactions (All Registrants)
Utility Registrants' expense with Generation
The Utility Registrants incurred expenses from transactions with the Generation affiliate as described in the footnotes to the table below prior to separation on February 1, 2022. Such expenses were primarily recorded as Purchased power from affiliate and an immaterial amount recorded as Operating and maintenance expense from affiliates at the Utility Registrants. Effective February 1, 2022, Generation is no longer considered a related party.
 Nine Months Ended September 30,
 2022
ComEd(a)
$59 
PECO(b)
33 
BGE(c)
18 
PHI51 
Pepco(d)
39 
DPL(e)
10 
ACE(f)
2 
__________
(a)ComEd had an ICC-approved RFP contract with Generation to provide a portion of ComEd’s electric supply requirements. ComEd also purchased RECs and ZECs from Generation.
(b)PECO received electric supply from Generation under contracts executed through PECO’s competitive procurement process. In addition, PECO had a ten-year agreement with Generation to sell solar AECs.
(c)BGE received a portion of its energy requirements from Generation under its MDPSC-approved market-based SOS and gas commodity programs.
(d)Pepco received electric supply from Generation under contracts executed through Pepco's competitive procurement process approved by the MDPSC and DCPSC.
(e)DPL received a portion of its energy requirements from Generation under its MDPSC and DEPSC approved market-based SOS commodity programs.
(f)ACE received electric supply from Generation under contracts executed through ACE's competitive procurement process approved by the NJBPU.
107


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

Note 16 — Related Party Transactions

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 September 30,Nine Months Ended September 30,Three Months Ended September 30,Nine Months Ended September 30,
20232022202320222023202220232022
Exelon
   BSC$162 $156 $502 $500 
   PHISCO25 20 74 60 
ComEd
   BSC$92 $69 $263 $234 71 70 230 222 
PECO
   BSC55 44 160 140 29 24 89 80 
BGE
   BSC58 46 166 148 23 26 69 86 
PHI
   BSC50 39 135 135 39 36 114 112 
   PHISCO— — — — 24 20 73 60 
Pepco
   BSC30 24 85 80 13 13 41 41 
   PHISCO31 28 91 86 9 8 30 24 
DPL
   BSC19 16 54 51 12 11 32 34 
   PHISCO24 24 73 73 7 7 22 20 
ACE
   BSC16 13 45 42 13 12 39 37 
   PHISCO23 20 67 63 7 5 20 16 
108


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

Note 16 — Related Party Transactions

Current Receivables from/Payables to affiliates
The following tables present current Receivables from affiliates and current Payables to affiliates:
September 30, 2023
Receivables from affiliates:
Payables to affiliates:ComEdPECOBGEPepcoDPLACEBSCPHISCOOtherTotal
ComEd$— $— $— $— $— $57 $— $5 $62 
PECO$— — — — — 31 — 6 37 
BGE— — — — — 31 — 2 33 
PHI— — — — — — 6 — 11 17 
Pepco— — — — — 16 15 1 32 
DPL— 1 — — — 13 11 — 25 
ACE— — — — — 11 10 1 22 
Other3 — — — — 3 (1)1 6 
Total$3 $1 $— $— $— $3 $164 $37 $26 $234 
December 31, 2022
Receivables from affiliates:
Payables to affiliates:ComEdPECOBGEPepcoDPLACEBSCPHISCOOtherTotal
ComEd$— $— $— $— $— $66 $— $8 $74 
PECO$— — — — — 39 — 3 42 
BGE— — — — — 38 — 1 39 
PHI— — — — — — 4 — 10 14 
Pepco— — — — — 20 13 1 34 
DPL— 2 — — — 12 8 — 22 
ACE— 2 — — — 14 9 1 26 
Other3 — — — — 1 — — 4 
Total$3 $4 $— $— $— $1 $193 $30 $24 $255 
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:
September 30, 2023December 31, 2022
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 
109



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 5 — 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 from continuing operations by Registrant for the three and nine months ended September 30, 2023 compared to the same period in 2022. For additional information regarding the financial results for the three and nine months ended September 30, 2023 and 2022, see the discussions of Results of Operations by Registrant.
Three Months Ended September 30,Favorable (Unfavorable) VarianceNine Months Ended September 30,Favorable (Unfavorable) Variance
2023202220232022
Exelon$700 $676 $24 $1,711 $1,622 $89 
ComEd333 291 42 822 706 116 
PECO146 135 11 410 474 (64)
BGE45 33 12 286 267 19 
PHI232 289 (57)490 518 (28)
Pepco120 145 (25)249 261 (12)
DPL43 52 (9)128 130 (2)
ACE71 94 (23)122 131 (9)
Other(a)
(56)(72)16 (297)(343)46 
__________
(a)Other primarily includes eliminating and consolidating adjustments, Exelon’s corporate operations, shared service entities, and other financing and investment activities.
The separation of Constellation, including Generation and its subsidiaries, meets the criteria for discontinued operations and as such, Generation's results of operations are presented as discontinued operations and have been excluded from Exelon's continuing operations for the three and nine months ended September 30, 2022 presented in the table above. See Note 1 — Significant Accounting Policies and Note 2 — Discontinued Operations for additional information.
Accounting rules require that certain BSC costs previously allocated to Generation be presented as part of Exelon’s continuing operations as these costs do not qualify as expenses of the discontinued operations. Such costs are included in Other in the table above and were $28 million on a pre-tax basis, for the nine months ended September 30, 2022. There were no such costs included in Exelon's continuing operations for the three months ended September 30, 2022.
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Three Months Ended September 30, 2023 Compared to Three Months Ended September 30, 2022. Net income attributable to common shareholders from continuing operations increased by $24 million and diluted earnings per average common share from continuing operations increased to $0.70 in 2023 from $0.68 in 2022 primarily due to:
•Higher electric distribution formula rate earnings from higher allowed ROE due to an increase in U.S. treasury rates and impacts of higher rate base at ComEd;
•Favorable impacts of rate increases at PECO, BGE, and PHI; and
•Carrying costs related to the CMC regulatory assets at ComEd.
The increases were partially offset by:
•Higher operating expense as a result of higher storm costs at PECO, BGE and PHI;
•Higher interest expense at BGE and Exelon Corporate;
•Unfavorable weather at PECO; and
•Higher depreciation expense at BGE and PHI.
Nine Months Ended September 30, 2023 Compared to Nine Months Ended September 30, 2022. Net income attributable to common shareholders from continuing operations increased by $89 million and diluted earnings per average common share from continuing operations increased to $1.72 in 2023 from $1.65 in 2022 primarily due to:
•Higher electric distribution formula rate earnings from higher allowed ROE due to an increase in U.S. treasury rates and impacts of higher rate base at ComEd;
•The favorable impacts of rate increases at PECO, BGE, and PHI;
•Carrying costs related to the CMC regulatory assets at ComEd; and
•Lower BSC costs presented in Exelon’s continuing operations, which were previously allocated to Generation but did not qualify as discontinued operation expenses per the accounting rules.
The increases were partially offset by:
•Higher interest expense at PECO, BGE, PHI and Exelon Corporate;
•Unfavorable weather at PECO and PHI;
•Higher depreciation expense at PECO, BGE and PHI; and
•Higher operating expense as a result of higher storm costs at PECO and BGE.
Adjusted (non-GAAP) operating earnings. In addition to Net income, Exelon evaluates its operating performance using the measure of Adjusted (non-GAAP) operating earnings because management believes it represents earnings directly related to the ongoing operations of the business. Adjusted (non-GAAP) operating earnings exclude certain costs, expenses, gains and losses, and other specified items. This information is intended to enhance an investor’s overall understanding of year-over-year operating results and provide an indication of Exelon’s baseline operating performance excluding items that are considered by management to be not directly related to the ongoing operations of the business. In addition, this information is among the primary indicators management uses as a basis for evaluating performance, allocating resources, setting incentive compensation targets, and planning and forecasting of future periods. Adjusted (non-GAAP) operating earnings is not a presentation defined under GAAP and may not be comparable to other companies’ presentations or deemed more useful than the GAAP information provided elsewhere in this report.
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The following tables provide a reconciliation between Net income attributable to common shareholders from continuing operations as determined in accordance with GAAP and Adjusted (non-GAAP) operating earnings for the three and nine months ended September 30, 2023 compared to the same periods in 2022:
Three Months Ended September 30,
20232022
(In millions, except per share data)Earnings per
Diluted Share		Earnings per
Diluted Share
Net income attributable to common shareholders from continuing operations$700 $0.70 $676 $0.68 
Mark-to-market impact of economic hedging activities (net of taxes of $4)
12 0.01 — — 
Asset retirement obligation (net of taxes of $1 and $2, respectively)
(1)— (4)— 
Asset impairments (net of taxes of $10)(a)
— — 37 0.04 
Separation costs (net of taxes of $5 and $1, respectively)(b)
14 0.01 (3)— 
Income tax-related adjustments (entire amount represents tax expense)(c)
(54)(0.05)38 0.04 
Adjusted (non-GAAP) operating earnings$671 $0.67 $745 $0.75 
Nine Months Ended September 30,
20232022
(In millions, except per share data)Earnings per
Diluted Share		Earnings per
Diluted Share
Net income attributable to common shareholders from continuing operations$1,711 $1.72 $1,622 $1.65 
Mark-to-market impact of economic hedging activities (net of taxes of $4)
14 0.01 — — 
Change in environmental liabilities (net of taxes of $8)
29 0.03 — — 
ERP system implementation costs (net of taxes of $0)(d)
— — 1 — 
Asset retirement obligation (net of taxes of $1 and $2, respectively)
(1)— (4)— 
SEC matter loss contingency (net of taxes of $0)
46 0.05 — — 
Asset impairments (net of taxes of $10)(a)
— — 37 0.04 
Separation costs (net of taxes of $7 and $10, respectively)(b)
19 0.02 25 0.03 
Change in FERC audit liability (net of taxes of $4)
11 0.01 — — 
Income tax-related adjustments (entire amount represents tax expense)(e)
(54)(0.05)130 0.13 
Adjusted (non-GAAP) operating earnings$1,774 $1.78 $1,811 $1.84 
__________
Note:
Amounts may not sum due to rounding.
Unless otherwise noted, the income tax impact of each reconciling item between GAAP Net income 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 2023 and 2022 ranged from 24.0% to 29.0%.

(a)Reflects costs related to the impairment of an office building at BGE, which are recorded in Operating and maintenance expense.
(b)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.
(c)In 2022, reflects an adjustment to exclude one-time non-cash impacts associated with the remeasurement of deferred income taxes as a result of the reduction in Pennsylvania corporate income tax rate. In 2023, reflects the adjustment to state deferred income taxes due to changes in forecasted apportionment.
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(d)Reflects costs related to a multi-year ERP system implementation, which are recorded in Operating and maintenance expense.
(e)In 2022, for PECO, reflects an adjustment to exclude one-time non-cash impacts associated with the remeasurement of deferred income taxes as a result of the reduction in Pennsylvania corporate income tax rate. For Corporate, in connection with the separation, Exelon recorded an income tax expense primarily due to the long-term marginal state income tax rate change, the recognition of valuation allowances against the net deferred tax assets positions for certain standalone state filing jurisdictions, and nondeductible transaction costs partially offset by a one-time impact associated with a state tax benefit. In 2023, reflects the adjustment to state deferred income taxes dues to changes in forecasted apportionment.
Significant 2023 Transactions and Developments
Separation
On February 21, 2021, Exelon’s Board of Directors approved a plan to separate the Utility Registrants and Generation, creating two publicly traded companies (“the separation”). Exelon completed the separation on February 1, 2022. Constellation was newly formed and incorporated in Pennsylvania on June 15, 2021 for the purpose of separation and holds Generation. The separation represented a strategic shift that would have a major effect on Exelon’s operations and financial results. Accordingly, the separation met the criteria for discontinued operations. See Note 2 — Discontinued Operations of the Combined Notes to Consolidated Financial Statements for additional information on the separation and discontinued operations.
In connection with the separation, Exelon incurred separation costs/(benefit) impacting continuing operations of $19 million and $(2) million on a pre-tax basis for the three months ended September 30, 2023 and 2022, respectively, and $26 million and $35 million on a pre-tax basis for the nine months ended September 30, 2023 and 2022, respectively, which are recorded in Operating and maintenance expense. Total separation costs impacting continuing operations for the remainder of 2023 are not expected to be material. These costs are excluded from Adjusted (non-GAAP) Operating Earnings. The separation costs are 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.
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 2023. See Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.
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Completed Distribution Base Rate Case Proceedings
Registrant/JurisdictionFiling DateServiceRequested Revenue Requirement IncreaseApproved Revenue Requirement IncreaseApproved ROEApproval DateRate Effective Date
ComEd - IllinoisApril 15, 2022Electric$199 $199 7.85 %November 17, 2022January 1, 2023
PECO - PennsylvaniaMarch 31, 2022Natural Gas82 55 N/AOctober 27, 2022January 1, 2023
BGE - MarylandMay 15, 2020 (amended September 11, 2020)Electric203 140 9.50 %December 16, 2020January 1, 2021
Natural Gas108 74 9.65 %
Pepco - MarylandOctober 26, 2020 (amended March 31, 2021)Electric104 52 9.55 %June 28, 2021June 28, 2021
DPL - MarylandMay 19, 2022Electric38 29 9.60 %December 14, 2022January 1, 2023
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Pending Distribution Base Rate Case Proceedings
Registrant/JurisdictionFiling DateServiceRequested Revenue Requirement IncreaseRequested ROEExpected Approval Timing
ComEd - IllinoisJanuary 17, 2023Electric$1,487 10.50% to 10.65%Fourth quarter of 2023
ComEd - IllinoisApril 21, 2023Electric247 8.91 %Fourth quarter of 2023
BGE - MarylandFebruary 17, 2023Electric313 10.40 %Fourth quarter of 2023
Natural Gas289 10.40 %
Pepco - District of ColumbiaApril 13, 2023Electric191 10.50 %Second quarter of 2024
Pepco - MarylandMay 16, 2023Electric214 10.50 %Second quarter of 2024
DPL - DelawareDecember 15, 2022 (amended September 29, 2023)Electric39 10.50 %Second quarter of 2024
ACE - New JerseyFebruary 15, 2023 (amended August 21, 2023)Electric92 10.50 %Fourth quarter of 2023
Transmission Formula Rates
For 2023, the following total increases/(decreases) were included in the Utility Registrants' electric transmission formula rate updates. See Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.
RegistrantInitial Revenue Requirement IncreaseAnnual Reconciliation Increase (Decrease)Total Revenue Requirement IncreaseAllowed Return on Rate BaseAllowed ROE
ComEd$20 $63 $83 8.09 %11.50 %
PECO24 23 47 7.41 %10.35 %
BGE19 (12)4 7.34 %10.50 %
Pepco37 (5)32 7.57 %10.50 %
DPL32 (3)29 7.08 %10.50 %
ACE41 (12)29 7.08 %10.50 %
ComEd's FERC Audit
The Utility Registrants are subject to periodic audits 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. During the first quarter of 2023, ComEd was provided with information from FERC about several potential findings, including ComEd's methodology regarding the allocation of certain overhead costs to capital under FERC regulations. Based on the preliminary findings and discussions with FERC staff, ComEd determined that a loss was probable and recorded a regulatory liability to reflect its best estimate of that loss as of March 31, 2023.
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
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capitalized construction costs under FERC regulations. On August 28, 2023, ComEd filed a formal notice of the issues it will contest. 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.
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 2022 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 2022 Form 10-K, and Note 12 — 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
City of Chicago Franchise Agreement
The current ComEd Franchise Agreement with the City of Chicago (the City) has been in force since 1992. The Franchise Agreement grants rights to use the public right of way to install, maintain, and operate the wires, poles, and other infrastructure required to deliver electricity to residents and businesses across the City. The Franchise Agreement became terminable on one year notice as of December 31, 2020. It now continues in effect indefinitely unless and until either party issues a notice of termination, effective one year later, or it is replaced by mutual agreement with a new franchise agreement between ComEd and the City. If either party terminates and no new agreement is reached between the parties, the parties could continue with ComEd providing electric services within the City with no franchise agreement in place. The City also has an option to terminate and purchase the ComEd system (“municipalize”), which also requires one year notice. Neither party has issued a notice of termination at this time, the City has not exercised its municipalization option, and no new agreement has become effective. Accordingly, the 1992 Franchise Agreement remains in effect at this time. In April 2021, the City invited interested parties to respond to a Request for Information (RFI) regarding the franchise for electricity delivery. Final responses to the RFI were due on July 30, 2021, however, on July 29, 2021, the City chose to extend the final submission deadline to September 30, 2021. ComEd submitted its response to the RFI by the due date. However, the City did not proceed to issue an RFP. Since that time, ComEd and the City continued to negotiate and have arrived at a proposed Chicago Franchise Agreement (CFA) and an Energy and Equity Agreement (EEA). These agreements together are intended t o grant ComEd the right to continue providing electric utility services using public ways within the City of Chicago, and to create a new non-profit entity to advance energy and energy-related equity projects. On February 1, 2023, the proposed CFA and EEA were introduced to the City Council. The proposed CFA and EEA remain subject to approval by the City Council and the Exelon Board.
While Exelon and ComEd cannot predict the ultimate outcome of these processes, fundamental changes in the agreements or other adverse actions affecting ComEd’s business in the City would require changes in their business planning models and operations and could have a material adverse impact on Exelon’s and ComEd’s consolidated financial statements. If the City were to disconnect from the ComEd system, ComEd would seek full compensation for the business and its associated property taken by the City, as well as for all damages resulting to ComEd and its system. ComEd would also seek appropriate compensation for stranded costs with FERC.
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
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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 September 2022, ComEd and BGE applied for the MMG, which establishes and funds construction, improvement, or acquisition of middle mile broadband infrastructure which creates high-speed internet services. The MMG addresses inequitable broadband access by expansion and extension of the middle mile infrastructure in underserved communities. In June 2023, the National Telecommunications and Information Administration (NTIA) announced it selected two of the applications submitted by BGE and ComEd; awarding ComEd and BGE $14.5 million and $15.4 million respectively. The applications selected by NTIA for BGE and ComEd proposed projects designed to enhance electric grid reliability and resiliency while leading and advancing shared local, state, and national goals to increase broadband connectivity, redundancy, affordability, and equity.

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 GDO has indicated the award negotiation process can take approximately 120 days.

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 company's electric distribution system. The GDO has indicated the award negotiation process can take approximately 120 days.

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.
PJM Regional Transmission Expansion
On April 6, 2023, PJM received a deactivation notice for Brandon Shores, a 1,282 MW coal generation plant located in BGE service territory. The deactivation was requested for June 1, 2025 and will result in numerous reliability issues across the region. In June 2023, PJM assigned a portion of transmission system upgrades to mitigate these reliability impacts to PECO, BGE, and Pepco. In July 2023, PJM Board of Managers approved assigning Exelon transmission system upgrades to mitigate these reliability impacts to PECO, BGE, and Pepco. The most recent projected capital expenditures associated with these upgrades are approximately $80 million, $650 million, and $80 million for PECO, BGE, and Pepco, respectively. These amounts include a scope reduction estimated by PJM for PECO of $60 million associated with a transmission proposal window, as disclosed at a Transmission Expansion Advisory Committee meeting on October 31, 2023. The upgrades are expected to be completed by the end of 2028.
Separately, PJM held a competitive transmission proposal window from February 24, 2023 through May 31, 2023 to address reliability issues driven by significant load increases in northern Virginia. PECO, BGE, and Pepco submitted four solution proposals. At a meeting of the Transmission Expansion Advisory Committee on October 31, 2023, PJM recommended that PECO, BGE, Pepco, and DPL be awarded a portion of the work for the
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proposed solution. Initial estimated costs for these upgrades, as posted by PJM on its website on October 27, 2023, are approximately $55 million, $700 million, $80 million, and $5 million for PECO, BGE, Pepco, and DPL, respectively. The PJM Board of Managers is scheduled to approve the solution in December 2023 and the upgrades are expected to be completed by the end of 2030.
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 September 30, 2023, the Registrants’ critical accounting policies and estimates had not changed significantly from December 31, 2022. See ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS — Critical Accounting Policies and Estimates in the 2022 Form 10-K for further information.
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Results of Operations by Registrant
Results of Operations — ComEd
Three Months Ended
September 30,		Favorable (Unfavorable) VarianceNine Months Ended
September 30,		Favorable (Unfavorable) Variance
2023202220232022
Operating revenues$2,268 $1,378 $890 $5,836 $4,536 $1,300 
Operating expenses
Purchased power896 121 (775)2,068 1,041 (1,027)
Operating and maintenance385 355 (30)1,077 1,045 (32)
Depreciation and amortization357 333 (24)1,045 982 (63)
Taxes other than income taxes100 104 4 282 289 7 
Total operating expenses1,738 913 (825)4,472 3,357 (1,115)
Loss on sales of assets— — — — (2)2 
Operating income530 465 65 1,364 1,177 187 
Other income and (deductions)
Interest expense, net(119)(104)(15)(357)(308)(49)
Other, net16 14 2 50 40 10 
Total other income and (deductions)(103)(90)(13)(307)(268)(39)
Income before income taxes427 375 52 1,057 909 148 
Income taxes 94 84 (10)235 203 (32)
Net income $333 $291 $42 $822 $706 $116 
Three Months Ended September 30, 2023 Compared to Three Months Ended September 30, 2022. Net income increased by $42 million as compared to the same period in 2022, primarily due to increases in electric distribution formula rate earnings (reflecting higher allowed ROE due to an increase in U.S. Treasury rates and the impacts of higher rate base) and carrying costs related to the CMC regulatory assets.
Nine Months Ended September 30, 2023 Compared to Nine Months Ended September 30, 2022. Net income increased by $116 million as compared to the same period in 2022, primarily due to increases in electric distribution formula rate earnings (reflecting higher allowed ROE due to an increase in U.S. Treasury rates and the impacts of higher rate base) and carrying costs related to the CMC regulatory assets.
The changes in Operating revenues consisted of the following:
Three Months Ended
September 30, 2023		Nine Months Ended
September 30, 2023
IncreaseIncrease (Decrease)
Distribution$103 $277 
Transmission3 (4)
Energy efficiency17 55 
Other8 11 
131 339 
Regulatory required programs 759 961 
Total increase$890 $1,300 
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 implemented pursuant to FEJA.
Distribution Revenue. EIMA and FEJA provide for 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. Electric distribution revenue varies from year to year based upon fluctuations
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ComEd
in the underlying costs, (e.g., severe weather and storm restoration), investments being recovered, and allowed ROE. Electric distribution revenue increased for the three and nine months ended September 30, 2023 as compared to the same period in 2022, due to higher allowed ROE due to an increase in U.S. Treasury rates, the impact of a higher rate base, and higher fully recoverable costs.
Transmission Revenue. Under a FERC-approved formula, transmission revenue varies from year to year based upon fluctuations in the underlying costs, capital investments being recovered, and the highest daily peak load, which is updated annually in January based on the prior calendar year. Generally, increases/decreases in the highest daily peak load will result in higher/lower transmission revenue.
Energy Efficiency Revenue. FEJA provides for 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. Under FEJA, 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 and nine months ended September 30, 2023 as compared to the same period in 2022, 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 increased for the three and nine months ended September 30, 2023 as compared to the same period in 2022, which primarily reflects 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. See Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information regarding CMCs. ETAC is a retail customer surcharge collected by electric utilities operating in Illinois established by CEJA 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 5 — Segment Information of the Combined Notes to Consolidated Financial Statements for the presentation of ComEd's revenue disaggregation.
The increase of $775 million and $1,027 million for the three and nine months ended September 30, 2023 compared to the same period in 2022, in Purchased power expense is primarily due to the CMCs from the participating nuclear-powered generating facilities including the deferral of any associated carrying costs. This increase is primarily offset by an increase in Operating revenues as part of regulatory required programs. See Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information regarding CMCs.

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ComEd
The changes in Operating and maintenance expense consisted of the following:
Three Months Ended
September 30, 2023		Nine Months Ended
September 30, 2023
Increase (Decrease)Increase (Decrease)
Labor, other benefits, contracting and materials$10 $36 
Storm-related costs(4)4 
BSC costs23 28 
Pension and non-pension postretirement benefits expense(3)(11)
Other27 25 
53 82 
Regulatory required programs(a)
(23)(50)
Total increase$30 $32 
__________
(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.
The changes in Depreciation and amortization expense consisted of the following:
Three Months Ended
September 30, 2023		Nine Months Ended
September 30, 2023
IncreaseIncrease
Depreciation and amortization(a)
$16 $45 
Regulatory asset amortization(b)
8 18 
Total increase$24 $63 
__________
(a)Reflects ongoing capital expenditures and higher depreciation rates effective January 2023.
(b)Includes amortization of ComEd's energy efficiency formula rate regulatory asset.
Interest expense, net increased by $15 million and $49 million for the three and nine months ended September 30, 2023, compared to the same period in 2022, primarily due to an increase in interest rates and the issuance of debt during the year.
Effective income tax rates were 22.0% and 22.4% for the three months ended September 30, 2023 and 2022, respectively, and 22.2% and 22.3% for the nine months ended September 30, 2023 and 2022, respectively. See Note 7 — 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
September 30,		Favorable (Unfavorable) VarianceNine Months Ended
September 30,		Favorable (Unfavorable) Variance
2023202220232022
Operating revenues$1,037 $1,014 $23 $2,977 $2,877 $100 
Operating expenses
Purchased power and fuel411 403 (8)1,197 1,093 (104)
Operating and maintenance277 243 (34)786 705 (81)
Depreciation and amortization100 92 (8)297 277 (20)
Taxes other than income taxes59 60 1 156 155 (1)
Total operating expenses847 798 (49)2,436 2,230 (206)
Operating income190 216 (26)541 647 (106)
Other income and (deductions)
Interest expense, net(52)(45)(7)(149)(129)(20)
Other, net11 8 3 26 23 3 
Total other income and (deductions)(41)(37)(4)(123)(106)(17)
Income before income taxes149 179 (30)418 541 (123)
Income taxes3 44 41 8 67 59 
Net income$146 $135 $11 $410 $474 $(64)
Three Months Ended September 30, 2023 Compared to Three Months Ended September 30, 2022. Net income increased by $11 million as compared to the same period in 2022, primarily due to Pennsylvania corporate income tax legislation passed in July 2022 driving a one-time non-cash decrease to net income for 2022, partially offset by an increase in operating expense as a result of higher storm costs.
Nine Months Ended September 30, 2023 Compared to Nine Months Ended September 30, 2022. Net income decreased by $64 million as compared to the same period in 2022, primarily due to increases in operating expenses as a result of higher storm costs, depreciation and amortization expense, and interest expense.
The changes in Operating revenues consisted of the following:
Three Months Ended
September 30, 2023		Nine Months Ended
September 30, 2023
(Decrease) Increase(Decrease) Increase
ElectricGasTotalElectricGasTotal
Weather$(38)$— $(38)$(96)$(27)$(123)
Volume15 — 15 5 — 5 
Pricing2 6 8 20 35 55 
Transmission23 — 23 24 — 24 
Other(3)— (3)(4)6 2 
(1)6 5 (51)14 (37)
Regulatory required programs28 (10)18 145 (8)137 
Total increase$27 $(4)$23 $94 $6 $100 
Weather. The demand for electricity and natural gas is affected by weather conditions. With respect to the electric business, very warm weather in summer months and, with respect to the electric and natural gas businesses, very cold weather in winter months are referred to as “favorable weather conditions” because these weather conditions result in increased deliveries of electricity and natural gas. Conversely, mild weather reduces demand. During the three and nine months ended September 30, 2023 compared to the same period in 2022, Operating revenues related to weather decreased by the impact of unfavorable weather conditions in PECO's service territory.
122



PECO
Heating and cooling degree-days are quantitative indices that reflect the demand for energy needed to heat or cool a home or business. Normal weather is determined based on historical average heating and cooling degree-days for a 30-year period in PECO's service territory. The changes in heating and cooling degree-days in PECO’s service territory for the three and nine months ended September 30, 2023 compared to the same period in 2022 and normal weather consisted of the following:
Three Months Ended September 30,% Change
PECO Service Territory20232022Normal2023 vs. 20222023 vs. Normal
Heating Degree-Days181922(5.3)%(18.2)%
Cooling Degree-Days1,0641,2901,022(17.5)%4.1 %
Nine Months Ended September 30,% Change
20232022Normal2023 vs. 20222023 vs. Normal
Heating Degree-Days2,236 2,6322,866(15.0)%(22.0)%
Cooling Degree-Days1,297 1,7251,408(24.8)%(7.9)%
Volume. Electric volume, exclusive of the effects of weather, for the three and nine months ended September 30, 2023 compared to the same period in 2022, increased due to customer mix and load growth. Natural gas volume for the three and nine months ended September 30, 2023 compared to the same period in 2022, remained relatively consistent.
Electric Retail Deliveries to Customers (in GWhs)Three Months Ended
September 30,		% Change
Weather -
Normal
% Change(b)
Nine Months Ended September 30,% Change
Weather -
Normal
% Change(b)
2023202220232022
Residential4,1344,386(5.7)%4.9 %10,18611,204(9.1)%0.7 %
Small commercial & industrial2,0702,139(3.2)%0.8 %5,6165,889(4.6)%— %
Large commercial & industrial3,8303,943(2.9)%(0.4)%10,39810,691(2.7)%(0.3)%
Public authorities & electric railroads152172(11.6)%(10.8)%464489(5.1)%(5.0)%
Total electric retail deliveries(a)
10,18610,640(4.3)%1.7 %26,66428,273(5.7)%0.1 %
At September 30,
Number of Electric Customers20232022
Residential1,531,1681,523,269
Small commercial & industrial155,932155,516
Large commercial & industrial3,1113,120
Public authorities & electric railroads10,41610,393
Total1,700,6271,692,298
__________
(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
September 30,		% Change
Weather -
Normal
% Change(b)
Nine Months Ended
September 30,		% Change
Weather -
Normal
% Change(b)
2023202220232022
Residential2,1342,197(2.9)%(5.4)%23,69728,240(16.1)%(3.9)%
Small commercial & industrial1,9392,054(5.6)%(8.1)%14,38116,238(11.4)%(1.8)%
Large commercial & industrial46(33.3)%(7.1)%392095.0 %3.6 %
Transportation5,2785,1622.2 %8.3 %17,48218,508(5.5)%(2.3)%
Total natural gas retail deliveries(a)
9,3559,419(0.7)%1.1 %55,59963,006(11.8)%(2.9)%
123



PECO
 At September 30,
Number of Natural Gas Customers20232022
Residential505,370500,934
Small commercial & industrial44,74346,074
Large commercial & industrial99
Transportation629656
Total550,751547,673
__________
(a)Reflects delivery volumes from customers purchasing natural gas directly from PECO and customers purchasing natural gas from a competitive natural gas supplier as all customers are assessed distribution charges.
(b)Reflects the change in delivery volumes assuming normalized weather based on the historical 30-year average.
Pricing for the three and nine months ended September 30, 2023 compared to the same period in 2022 increased primarily due to an increase in gas distribution rates charged to customers.
Transmission Revenue. Under a FERC-approved formula, transmission revenue varies from year to year based upon fluctuations in the underlying costs and capital investments being recovered.
Other revenue primarily includes revenue related to late payment charges. Other revenue for the three and nine months ended September 30, 2023 compared to the same period in 2022 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 5 — Segment Information of the Combined Notes to Consolidated Financial Statements for the presentation of PECO's revenue disaggregation.
The increase of $104 million and $8 million for the three and nine months ended September 30, 2023 compared to the same period in 2022, in Purchased power and fuel expense is offset in Operating revenues as part of regulatory required programs.
124



PECO
The changes in Operating and maintenance expense consisted of the following:
Three Months Ended
September 30, 2023		Nine Months Ended
September 30, 2023
Increase (Decrease)Increase (Decrease)
Storm-related costs$26 $28 
BSC costs11 19 
Labor, other benefits, contracting and materials(7)15 
Pension and non-pension postretirement benefit expense— (3)
Credit loss expense1 (1)
Other(6)(5)
25 53 
Regulatory required programs9 28 
Total increase$34 $81 
The changes in Depreciation and amortization expense consisted of the following:
Three Months Ended September 30, 2023Nine Months Ended
September 30, 2023
IncreaseIncrease
Depreciation and amortization(a)
$7 $20 
Regulatory asset amortization1 — 
Total increase$8 $20 
__________
(a)Depreciation and amortization increased primarily due to ongoing capital expenditures.


Interest expense, net increased $7 million and $20 million for the three and nine months ended September 30, 2023, compared to the same period in 2022, primarily due to an increase in interest rates and the issuance of debt in 2022 and 2023.
Effective income tax rates were 2.0% and 24.6% for the three months ended September 30, 2023 and 2022, respectively, and 1.9% and 12.4% for the nine months ended September 30, 2023 and 2022, respectively. See Note 7 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the effective income tax rates.
125



BGE

Results of Operations — BGE
Three Months Ended
September 30,		Favorable (Unfavorable) VarianceNine Months Ended
September 30,		Favorable (Unfavorable) Variance
2023202220232022
Operating revenues$932 $870 $62 $2,986 $2,810 $176 
Operating expenses
Purchased power and fuel 380 350 (30)1,145 1,093 (52)
Operating and maintenance214 235 21 632 658 26 
Depreciation and amortization161 148 (13)487 470 (17)
Taxes other than income taxes80 77 (3)239 225 (14)
Total operating expenses835 810 (25)2,503 2,446 (57)
Operating income97 60 37 483 364 119 
Other income and (deductions)
Interest expense, net(47)(39)(8)(135)(110)(25)
Other, net6 5 1 14 16 (2)
Total other income and (deductions)(41)(34)(7)(121)(94)(27)
Income before income taxes56 26 30 362 270 92 
Income taxes11 (7)(18)76 3 (73)
Net income$45 $33 $12 $286 $267 $19 
Three Months Ended September 30, 2023 Compared to Three Months Ended September 30, 2022. Net income increased $12 million primarily due to favorable impacts of the multi-year plans, partially offset by an increase in storm costs, an increase in depreciation and amortization, and an increase in interest expense. See Note 3 — 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.
Nine Months Ended September 30, 2023 Compared to Nine Months Ended September 30, 2022. Net Income increased $19 million primarily due to favorable impacts of the multi-year plans, partially offset by an increase in storm costs, an increase in depreciation and amortization, and an increase in interest expense. See Note 3 — 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
September 30, 2023		Nine Months Ended
September 30, 2023
Increase (Decrease)Increase (Decrease)
ElectricGasTotalElectricGasTotal
Distribution$19 $4 $23 $61 $33 $94 
Transmission4 — 4 34 — 34 
Other— 1 1 (1)3 2 
23 5 28 94 36 130 
Regulatory required programs56 (22)34 106 (60)46 
Total increase (decrease)$79 $(17)$62 $200 $(24)$176 
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.
126



BGE

 At September 30,
Number of Electric Customers20232022
Residential1,208,230 1,200,786 
Small commercial & industrial115,557 115,778 
Large commercial & industrial13,007 12,774 
Public authorities & electric railroads264 266 
Total1,337,058 1,329,604 
At September 30,
Number of Natural Gas Customers20232022
Residential655,753 653,413 
Small commercial & industrial37,950 38,128 
Large commercial & industrial6,289 6,222 
Total699,992 697,763 
Distribution Revenue increased for the three and nine months ended September 30, 2023, compared to the same period in 2022, due to favorable impacts of the multi-year plans.
Transmission Revenue. Under a FERC-approved formula, transmission revenue varies from year to year based upon fluctuations in the underlying costs and capital investments being recovered. Transmission revenue increased for the three and nine months ended September 30, 2023, compared to the same period in 2022, primarily due to increases in underlying costs and capital investments.
Other Revenue includes revenue related to late payment, charges, mutual assistance, off-system sales, and service application fees. Other Revenue remained relatively the same for the three and nine months ended September 30, 2023 compared to the same period in 2022.
Regulatory Required Programs represent revenues collected under approved riders to recover costs incurred for regulatory programs such as conservation, demand response, STRIDE, 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 5 — Segment Information of the Combined Notes to Consolidated Financial Statements for the presentation of BGE's revenue disaggregation.
The increase of $30 million and $52 million for the three and nine months ended September 30, 2023 compared to the same period in 2022, in Purchased power and fuel expense is fully offset in Operating revenues as part of regulatory required programs.

127



BGE

The changes in Operating and maintenance expense consisted of the following:
Three Months Ended
September 30, 2023		Nine Months Ended
September 30, 2023
 Increase (Decrease)Increase (Decrease)
Labor, other benefits, contracting, and materials$3 $15 
Storm-related costs12 12 
Pension and non-pension postretirement benefits expense2 4 
BSC costs12 18 
Credit loss expense1 (14)
Other(a)
(51)(62)
(21)(27)
Regulatory required programs— 1 
Total decrease$(21)$(26)
__________
(a)Primarily relates to the prior year asset impairment of $46 million. See Note 11 - Asset Impairments of the 2022 Form 10-K for additional information.
The changes in Depreciation and amortization expense consisted of the following:
Three Months Ended
September 30, 2023		Nine Months Ended
September 30, 2023
IncreaseIncrease (Decrease)
Depreciation and amortization(a)
$9 $22 
Regulatory required programs4 (4)
Regulatory asset amortization— (1)
Total increase$13 $17 
__________
(a)Depreciation and amortization increased primarily due to ongoing capital expenditures.

Interest expense, net increased by $25 million for the nine months ended September 30, 2023, respectively compared to the same period in 2022, primarily due to an increase in interest rates and the issuance of debt in 2023 and 2022.
Taxes other than income taxes increased by $14 million for the nine months ended September 30, 2023, respectively, compared to the same period in 2022, primarily due to increased property taxes.
Effective income tax rates were 19.6% and (26.9)% for the three months ended September 30, 2023 and 2022 respectively, and 21.0% and 1.1% for the nine months ended September 30, 2023 and 2022, respectively. See Note 7 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the effective income tax rates.
128



PHI
Results of Operations — PHI
PHI’s Results of Operations include the results of its three reportable segments, Pepco, DPL, and ACE. PHI also has a business services subsidiary, PHISCO, which provides a variety of support services, and the costs are directly charged or allocated to the applicable subsidiaries. Additionally, the results of PHI’s corporate operations include interest costs from various financing activities. All material intercompany accounts and transactions have been eliminated in consolidation. The following table sets forth PHI's GAAP consolidated Net income, by Registrant, for the three and nine months ended September 30, 2023 compared to the same period in 2022. See the Results of Operations for Pepco, DPL, and ACE for additional information.
Three Months Ended
September 30,		Unfavorable VarianceNine Months Ended September 30,Unfavorable Variance
2023202220232022
PHI$232 $289 $(57)$490 $518 $(28)
Pepco120 145 (25)249 261 (12)
DPL
43 52 (9)128 130 (2)
ACE71 94 (23)122 131 (9)
Other(a)
(2)(2)— (9)(4)(5)
__________
(a)Primarily includes eliminating and consolidating adjustments, PHI's corporate operations, shared service entities, and other financing and investment activities.

Three Months Ended September 30, 2023 Compared to Three Months Ended September 30, 2022. Net Income decreased by $57 million primarily due to an increase in depreciation expense, higher contracting costs partially due to timing of maintenance projects, an increase in credit loss expense at Pepco, higher storm costs at DPL, timing of decoupling revenues in the District of Columbia, timing of excess deferred tax amortization at DPL and ACE, and an increase in various operating expenses, partially offset by higher transmission rates, higher distribution rates at DPL Delaware, and favorable impacts of the Pepco Maryland and DPL Maryland multi-year plans.
Nine Months Ended September 30, 2023 Compared to Nine Months Ended September 30, 2022. Net Income decreased by $28 million primarily due to an increase in environmental liabilities at Pepco, an increase in depreciation expense, an increase in interest expense, unfavorable weather at DPL Delaware electric and natural gas service territories, and an increase in various operating expenses, partially offset by higher transmission rates, higher distribution rates at DPL Delaware, and favorable impacts of the Pepco Maryland and DPL Maryland multi-year plans.

129



Pepco

Results of Operations — Pepco
Three Months Ended September 30,Favorable (Unfavorable) VarianceNine Months Ended September 30,Favorable (Unfavorable) Variance
2023202220232022
Operating revenues$822 $724 $98 $2,174 $1,919 $255 
Operating expenses
Purchased power 288 230 (58)750 605 (145)
Operating and maintenance149 121 (28)440 380 (60)
Depreciation and amortization112 99 (13)329 312 (17)
Taxes other than income taxes109 105 (4)291 291 — 
Total operating expenses658 555 (103)1,810 1,588 (222)
Operating income 164 169 (5)364 331 33 
Other income and (deductions)
Interest expense, net(41)(37)(4)(122)(111)(11)
Other, net18 14 4 50 39 11 
Total other income and (deductions)(23)(23)— (72)(72)— 
Income before income taxes141 146 (5)292 259 33 
Income taxes21 1 (20)43 (2)(45)
Net income$120 $145 $(25)$249 $261 $(12)
Three Months Ended September 30, 2023 Compared to Three Months Ended September 30, 2022. Net Income decreased by $25 million primarily due to the timing of decoupling revenues in the District of Columbia, higher contracting costs partially due to timing of maintenance projects, an increase in depreciation expense, credit loss expense, interest expense, and various operating expenses, partially offset by favorable impacts of the Maryland multi-year plan and higher transmission rates.
Nine Months Ended September 30, 2023 Compared to Nine Months Ended September 30, 2022. Net Income decreased by $12 million primarily due to an increase in environmental liabilities, depreciation expense, interest expense, and various operating expenses, partially offset by favorable impacts of the Maryland multi-year plan, higher transmission rates, and customer growth.
The changes in Operating revenues consisted of the following:
Three Months Ended
September 30, 2023		Nine Months Ended
September 30, 2023
Increase (Decrease)Increase
Distribution$17 $69 
Transmission16 44 
Other(1)2 
32 115 
Regulatory required programs66 140 
Total increase$98 $255 
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.
130



Pepco

At September 30,
Number of Electric Customers20232022
Residential862,321 853,873 
Small commercial & industrial54,082 54,423 
Large commercial & industrial22,952 22,789 
Public authorities & electric railroads205 196 
Total939,560 931,281 
Distribution Revenue increased for the three months ended September 30, 2023 compared to the same period in 2022 primarily due to higher rates due to the expiration of customer offsets and favorable impacts of the Maryland multi-year plan, partially offset by the timing of decoupling revenues in the District of Columbia. Distribution revenue increased for the nine months ended September 30, 2023 compared to the same period in 2022 primarily due to higher rates due to the expiration of customer offsets, 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 both the three and nine months ended September 30, 2023, compared to the same period in 2022, 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 5 — Segment Information of the Combined Notes to Consolidated Financial Statements for the presentation of Pepco's revenue disaggregation.
The increase of $58 million and $145 million for the three and nine months ended September 30, 2023 compared to the same period in 2022, respectively, in Purchased power expense is fully offset in Operating revenues as part of regulatory required programs.
131



Pepco

The changes in Operating and maintenance expense consisted of the following:
Three Months Ended
September 30, 2023		Nine Months Ended
September 30, 2023
Increase (Decrease)Increase (Decrease)
BSC and PHISCO costs$9 $10 
Labor, other benefits, contracting and materials(a)
6 29 
Credit Loss expense6 — 
Pension and non-pension postretirement benefits expense3 8 
Storm-related costs(2)(7)
Other3 12 
25 52 
Regulatory required programs3 8 
Total increase$28 $60 
__________
(a)Primarily reflects an increase in environmental liabilities for the nine months ended September 30, 2023.

The changes in Depreciation and amortization expense consisted of the following:
Three Months Ended
September 30, 2023		Nine Months Ended
September 30, 2023
IncreaseIncrease (Decrease)
Depreciation and amortization(a)
$10 $17 
Regulatory asset amortization3 10 
Regulatory required programs— (10)
Total increase$13 $17 
__________
(a)Depreciation and amortization increased primarily due to ongoing capital expenditures.
Interest expense, net increased by $4 million and $11 million for the three and nine months ended September 30, 2023 compared to the same period in 2022, respectively, primarily due to an increase in interest rates and the issuance of debt in 2022 and 2023.
Other, net increased by $4 million and $11 million for the three and nine months ended September 30, 2023 compared to the same period in 2022, respectively, primarily due to higher AFUDC equity.
Effective income tax rates were 14.9% and 0.7% for the three months ended September 30, 2023 and 2022, respectively, and 14.7% and (0.8)% for the nine months ended September 30, 2023 and 2022, respectively. See Note 7 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the effective income tax rates.
132



Table of Contents
DPL

Results of Operations — DPL
Three Months Ended September 30,Favorable (Unfavorable) VarianceNine Months Ended September 30,Favorable (Unfavorable) Variance
2023202220232022
Operating revenues$450 $412 $38 $1,273 $1,176 $97 
Operating expenses
Purchased power and fuel 201 183 (18)562 507 (55)
Operating and maintenance104 84 (20)278 266 (12)
Depreciation and amortization62 59 (3)182 172 (10)
Taxes other than income taxes19 19 — 57 54 (3)
Total operating expenses386 345 (41)1,079 999 (80)
Operating income64 67 (3)194 177 17 
Other income and (deductions)
Interest expense, net(18)(16)(2)(53)(48)(5)
Other, net5 3 2 12 9 3 
Total other income and (deductions)(13)(13)— (41)(39)(2)
Income before income taxes51 54 (3)153 138 15 
Income taxes8 2 (6)25 8 (17)
Net income $43 $52 $(9)$128 $130 $(2)

Three Months Ended September 30, 2023 Compared to Three Months Ended September 30, 2022. Net income decreased $9 million primarily due to an increase in storm costs, depreciation expense, various operating expenses, and the timing of excess deferred tax amortization, partially offset by favorable impacts of the Maryland multi-year plan, higher Delaware electric and natural gas distribution rates, and higher transmission rates.
Nine Months Ended September 30, 2023 Compared to Nine Months Ended September 30, 2022. Net income decreased $2 million primarily due to unfavorable weather conditions at Delaware electric and natural gas service territories, an increase in depreciation expense, and interest expense, partially offset by favorable impacts of the Maryland multi-year plan, higher Delaware electric and natural gas distribution rates, and higher transmission rates.
The changes in Operating revenues consisted of the following:
Three Months Ended
September 30, 2023		Nine Months Ended
September 30, 2023
(Decrease) Increase(Decrease) Increase
ElectricGasTotalElectricGasTotal
Weather$(1)$— $(1)$(11)$(5)$(16)
Volume(1)— (1)(3)(3)(6)
Distribution7 1 8 26 6 32 
Transmission12 — 12 25 — 25 
Other2 — 2 4 1 5 
19 1 20 41 (1)40 
Regulatory required programs33 (15)18 64 (7)57 
Total increase (decrease)$52 $(14)$38 $105 $(8)$97 
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.
133



Table of Contents
DPL

Weather. The demand for electricity and natural gas in Delaware is affected by weather conditions. With respect to the electric business, very warm weather in summer months and, with respect to the electric and natural gas businesses, very cold weather in winter months are referred to as "favorable weather conditions” because these weather conditions result in increased deliveries of electricity and natural gas. Conversely, mild weather reduces demand. During the three months ended September 30, 2023, compared to the same period in 2022, Operating revenues related to weather remained relatively consistent. During the nine months ended September 30, 2023, compared to the same period in 2022, Operating revenues related to weather decreased due to unfavorable weather conditions in Delaware electric and natural gas service territories.
Heating and cooling degree days are quantitative indices that reflect the demand for energy needed to heat or cool a home or business. Normal weather is determined based on historical average heating and cooling degree days for a 20-year period in the Delaware electric service territory and a 30-year period in the Delaware natural gas service territory. The changes in heating and cooling degree days in the Delaware service territory for the three and nine months ended September 30, 2023 compared to same period in 2022 and normal weather consisted of the following:
Three Months Ended September 30,% Change
Delaware Electric Service Territory20232022Normal2023 vs. 20222023 vs. Normal
Heating Degree-Days37 32 27 15.6 %37.0 %
Cooling Degree-Days996 1,043 911 (4.5)%9.3 %
Nine Months Ended September 30,% Change
Delaware Electric Service Territory20232022Normal2023 vs. 20222023 vs. Normal
Heating Degree-Days2,306 2,828 2,984 (18.5)%(22.7)%
Cooling Degree-Days1,249 1,374 1,248 (9.1)%0.1 %
Three Months Ended September 30,% Change
Delaware Natural Gas Service Territory20232022Normal2023 vs. 20222023 vs. Normal
Heating Degree-Days37 32 35 15.6 %5.7 %
Nine Months Ended September 30,% Change
Delaware Natural Gas Service Territory20232022Normal2023 vs. 20222023 vs. Normal
Heating Degree-Days2,306 2,828 3,020 (18.5)%(23.6)%
Volume, exclusive of the effects of weather, remained relatively consistent for the three months ended September 30, 2023 compared to the same period in 2022 and decreased for the nine months ended September 30, 2023 compared to the same period in 2022 primarily due to customer usage, partially offset by customer growth.
Electric Retail Deliveries to Delaware Customers (in GWhs)Three Months Ended
September 30,		% Change
Weather - Normal
% Change(b)
Nine Months Ended
September 30,		% Change
Weather - Normal
% Change(b)
2023202220232022
Residential995 978 1.7 %0.6 %2,403 2,548 (5.7)%(0.2)%
Small commercial & industrial405 400 1.3 %0.6 %1,081 1,107 (2.3)%(0.1)%
Large commercial & industrial849 856 (0.8)%(0.2)%2,349 2,394 (1.9)%(0.7)%
Public authorities & electric railroads7 7 — %(5.8)%23 24 (4.2)%(4.3)%
Total electric retail deliveries(a)
2,256 2,241 0.7 %0.3 %5,856 6,073 (3.6)%(0.4)%
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At September 30,
Number of Total Electric Customers (Maryland and Delaware)20232022
Residential484,425 480,779 
Small commercial & industrial64,101 63,685 
Large commercial & industrial1,245 1,230 
Public authorities & electric railroads593 597 
Total550,364 546,291 
__________
(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
September 30,		% Change
Weather - Normal
% Change(b)
Nine Months Ended
September 30,		% Change
Weather - Normal
% Change(b)
2023202220232022
Residential414 374 10.7 %8.3 %4,781 5,810 (17.7)%(4.9)%
Small commercial & industrial350 331 5.7 %4.4 %2,494 2,882 (13.5)%(0.3)%
Large commercial & industrial381 397 (4.0)%(4.0)%1,166 1,259 (7.4)%(7.2)%
Transportation1,119 1,284 (12.9)%(13.0)%4,350 4,934 (11.8)%(7.9)%
Total natural gas deliveries(a)
2,264 2,386 (5.1)%(5.7)%12,791 14,885 (14.1)%(5.2)%
At September 30,
Number of Delaware Natural Gas Customers20232022
Residential129,436 129,005 
Small commercial & industrial10,039 10,044 
Large commercial & industrial14 16 
Transportation165 156 
Total139,654 139,221 
__________
(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 both the three and nine months ended September 30, 2023 compared to the same period in 2022 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 2023, and higher natural gas distribution rates effective in August 2022.
Transmission Revenue. Under a FERC-approved formula, transmission revenue varies from year to year based upon fluctuations in the underlying costs and capital investments being recovered. During the three and nine months ended September 30, 2023 compared to the same period in 2022, 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
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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 5 — Segment Information of the Combined Notes to Consolidated Financial Statements for the presentation of DPL's revenue disaggregation.
The increase of $18 million and $55 million for the three and nine months ended September 30, 2023, compared to the same period in 2022, respectively, in Purchased power and fuel expense is fully offset in Operating revenues as part of regulatory required programs.
The changes in Operating and maintenance expense consisted of the following:
Three Months Ended
September 30, 2023		Nine Months Ended
September 30, 2023
IncreaseIncrease (Decrease)
Storm-related Costs$7 $5 
BSC and PHISCO costs4 3 
Labor and contracting3 (3)
Credit Loss Expense2 — 
Pension and non-pension postretirement benefits expense1 4 
Other
3 2 
20 11 
Regulatory required programs— 1 
Total increase$20 $12 
The changes in Depreciation and amortization expense consisted of the following:
Three Months Ended
September 30, 2023		Nine Months Ended
September 30, 2023
IncreaseIncrease (Decrease)
Depreciation and amortization(a)
$3 $15 
Regulatory required programs— (4)
Regulatory asset amortization— (1)
Total increase$3 $10 
__________
(a)For the three months ended September 30, 2023, reflects ongoing capital expenditures and higher transmission depreciation rates effective September 2022. For the nine months ended September 30, 2023, reflects ongoing capital expenditures, higher distribution depreciation rates in Maryland effective March 2022, and higher transmission depreciation rates effective September 2022.
Interest expense, net increased by $2 million and $5 million for the three and nine months ended September 30, 2023 compared to the same period in 2022, respectively, primarily due to an increase in interest rates and the issuance of debt in 2022 and 2023.
Effective income tax rates were 15.7% and 3.7% for the three months ended September 30, 2023 and 2022, respectively, and 16.3% and 5.8% for the nine months ended September 30, 2023 and 2022, respectively. See Note 7 — 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 September 30,Favorable (Unfavorable) VarianceNine Months Ended September 30,Favorable (Unfavorable) Variance
2023202220232022
Operating revenues$502 $462 $40 $1,172 $1,120 $52 
Operating expenses
Purchased power 221 197 (24)493 497 4 
Operating and maintenance94 80 (14)259 251 (8)
Depreciation and amortization77 74 (3)212 192 (20)
Taxes other than income taxes2 2 — 7 7 — 
Total operating expenses394 353 (41)971 947 (24)
Operating income 108 109 (1)201 173 28 
Other income and (deductions)
Interest expense, net(19)(17)(2)(52)(49)(3)
Other, net5 3 2 13 9 4 
Total other income and (deductions)(14)(14)— (39)(40)1 
Income before income taxes94 95 (1)162 133 29 
Income taxes23 1 (22)40 2 (38)
Net income $71 $94 $(23)$122 $131 $(9)
Three Months Ended September 30, 2023 Compared to Three Months Ended September 30, 2022. Net income decreased by $23 million primarily due to timing of excess deferred tax amortization and an increase in depreciation expense and various operating expenses.
Nine Months Ended September 30, 2023 Compared to Nine Months Ended September 30, 2022. Net income decreased by $9 million primarily due to an increase in depreciation expense and various operating expenses, partially offset by higher transmission rates.
The changes in Operating revenues consisted of the following:
Three Months Ended
September 30, 2023		Nine Months Ended
September 30, 2023
Increase (Decrease)Increase (Decrease)
Distribution$15 $27 
Transmission5 30 
Other(1)(1)
19 56 
Regulatory required programs21 (4)
Total increase$40 $52 
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 September 30,
Number of Electric Customers20232022
Residential504,330 501,869 
Small commercial & industrial62,410 62,204 
Large commercial & industrial2,980 3,075 
Public authorities & electric railroads729 731 
Total570,449 567,879 
Distribution Revenue increased for both the three and nine months ended September 30, 2023 compared to the same period in 2022 due to higher distribution rates primarily due to 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 both the three and nine months ended September 30, 2023 compared to the same period in 2022, 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 5 — Segment Information of the Combined Notes to Consolidated Financial Statements for the presentation of ACE's revenue disaggregation.
The increase of $24 million and decrease of $4 million for the three and nine months ended September 30, 2023 compared to the same period in 2022, respectively, 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
September 30, 2023		Nine Months Ended
September 30, 2023
IncreaseIncrease (Decrease)
BSC and PHISCO costs$5 $6 
Labor and contracting5 2 
Storm-related costs3 — 
Pension and non-pension postretirement benefits expense— 1 
Other1 1 
14 10 
Regulatory required programs(a)
— (2)
Total increase$14 $8 
__________
(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
September 30, 2023		Nine Months Ended
September 30, 2023
Increase (Decrease)Increase
Depreciation and amortization(a)
$6 $19 
Regulatory required programs(b)
(3)1 
Total increase$3 $20 
__________
(a)Reflects ongoing capital expenditures and higher transmission depreciation rates effective September 2022.
(b)For the nine months ended September 30, 2023, regulatory required programs increased primarily due to the regulatory asset amortization of the PPA termination obligation which is fully offset in Operating revenues.
Interest expense, net increased by $2 million and $3 million for the three and nine months ended September 30, 2023 compared to the same period in 2022, respectively, primarily due to an increase in interest rates and the issuance of debt in 2022 and 2023.
Effective income tax rates were 24.5% and 1.1% for the three months ended September 30, 2023 and 2022, respectively, and 24.7% and 1.5% for the nine months ended September 30, 2023 and 2022, respectively. See Note 7 — 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 10 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information on the Registrants’ debt and credit agreements.
Cash flows related to Generation have not been presented as discontinued operations and are included in the Consolidated Statements of Cash Flows for only 2022. The Exelon Consolidated Statement of Cash Flows for the nine months ended September 30, 2022 includes one month of cash flows from Generation.
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 2022 Form 10-K and Notes 3 — Regulatory Matters and 12 — 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 nine months ended September 30, 2023 and 2022 by Registrant:
(Decrease) increase in cash flows from operating activitiesExelonComEdPECOBGE PHIPepcoDPLACE
Net income (loss)$(28)$116 $(64)$19 $(28)$(12)$(2)$(9)
Adjustments to reconcile net income to cash:
Non-cash operating activities(790)(268)(85)(90)58 62 (6)4 
Option premiums (paid), net39 — — — — — — — 
Collateral (paid) received, net(1,639)(41)— (147)(421)(72)(234)(115)
Income taxes47 50 46 39 40 40 11 (1)
Pension and non-pension postretirement benefit contributions499 153 12 49 60 — 1 6 
Regulatory assets and liabilities, net294 251 28 (38)80 37 56 (22)
Changes in working capital and other assets and liabilities729 (118)184 276 48 77 20 (53)
(Decrease) increase in cash flows from operating activities$(849)$143 $121 $108 $(163)$132 $(154)$(190)
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 nine months ended September 30, 2023 and 2022 were as follows:
•See Note 15 — Supplemental Financial Information of the Combined Notes to Consolidated Financial Statements and the Registrants’ Consolidated Statements of Cash Flows for additional information on non-cash operating activities.
•Changes in collateral depended upon whether the Registrant was in a net mark-to-market liability or asset position, and collateral may have been required to be posted with or collected from its counterparties. In addition, the collateral posting and collection requirements differed depending on whether the transactions were on an exchange or in the over-the-counter markets. Changes in collateral for the Registrants are dependent upon the credit exposure of procurement contracts that may require suppliers to post collateral. The amount of cash collateral received from external counterparties decreased due to decreasing energy prices. See Note 9 — Derivative Financial Instruments for additional information.
•See Note 7 — 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 relate to Exelon's funding strategy and incremental contributions made in 2022 in connection with the separation. See Note 14 — Retirement Benefits of the 2022 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 $428 million and $394 million for the nine months ended September 30, 2023 and 2022, respectively. Also included within the changes is energy efficiency and demand response programs spend for BGE, Pepco, DPL and ACE of $102 million, $49 million, $19 million, and $14 million for the nine months ended September 30, 2023 and $83 million, $50 million, $21 million, and $7 million for the nine months ended September 30, 2022, respectively. PECO had no energy efficiency and demand response programs spend recorded to the regulatory asset for the nine
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months ended September 30, 2023 and 2022. See Note 3 — 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 $406 million and for Generation total $323 million. The change for Generation primarily relates to the revolving accounts receivable financing arrangement which was entered into in April 2020. The change in working capital and other noncurrent assets and liabilities for Exelon Corporate and the Utility Registrants is dependent upon the normal course of operations for all Registrants. For ComEd, it is also dependent upon whether the participating nuclear-powered generating facilities are owed money from ComEd as a result of the established pricing for CMCs. For the nine months ended September 30, 2023, the established pricing resulted in ComEd owing payments to nuclear-powered generating facilities, which is reported within the cash flows from operations as a change in accounts payable and accrued expense.
Cash Flows from Investing Activities
The following table provides a summary of the change in cash flows from investing activities for the nine months ended September 30, 2023 and 2022 by Registrant:
Decrease in cash flows from investing activitiesExelonComEdPECOBGE PHIPepcoDPLACE
Capital expenditures$(361)$(125)$(77)$(68)$(336)$(115)$(122)$(92)
Investment in NDT fund sales, net28 — — — — — — — 
Collection of DPP(169)— — — — — — — 
Proceeds from sales of assets and businesses(16)— — — — — — — 
Changes in intercompany money pool— — (51)— — (7)15 — 
Other investing activities(11)(13)(7)(1)3 6 (2)(1)
Decrease in cash flows from investing activities$(529)$(138)$(135)$(69)$(333)$(116)$(109)$(93)
Significant investing cash flow impacts for the Registrants for nine months ended September 30, 2023 and 2022 were as follows:
•Changes in capital expenditures are primarily due to the timing of cash expenditures for capital projects. See the "Credit Matters and Cash Requirements" section below for additional information on projected capital expenditure spending for the Utility Registrants. See Note 2 — Discontinued Operations of the Combined Notes to Consolidated Financial Statements for capital expenditures related to Generation prior to the separation.
•Collection of DPP relates to Generation's revolving accounts receivable financing agreement which Generation entered into in April 2020.
•Changes in intercompany money pool are driven by short-term borrowing needs. Refer to more information regarding the intercompany money pool below.
Cash Flows from Financing Activities
The following table provides a summary of the change in cash flows from financing activities for the nine months ended September 30, 2023 and 2022 by Registrant:
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Increase (decrease) in cash flows from financing activitiesExelonComEdPECOBGE PHIPepcoDPLACE
Changes in short-term borrowings, net$(756)$(133)$(239)$(375)$227 $(124)$34 $317 
Long-term debt, net357 225 100 150 (65)35 — (100)
Changes in intercompany money pool— — — — (18)(25)— 17 
Issuance of common stock(563)— — — — — — — 
Dividends paid on common stock(75)(126)(4)(12)— 200 (2)17 
Distributions to member— — — — 215 — — — 
Contributions from parent/member— 67 74 51 (312)(157)(48)(110)
Transfer of cash, restricted cash, and cash equivalents to Constellation2,594 — — — — — — — 
Other financing activities24 (2)8 1 (18)(18)(2)1 
Increase (decrease) in cash flows from financing activities$1,581 $31 $(61)$(185)$29 $(89)$(18)$142 
Significant financing cash flow impacts for the Registrants for the nine months ended September 30, 2023 and 2022 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 10 — 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 10 — 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 2022 Form 10-K for additional information on dividend restrictions. See below for quarterly dividends declared.
•Refer to Note 2 — Discontinued Operations for the transfer of cash, restricted cash, and cash equivalents to Constellation related to the separation.
Debt
See Note 10 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information on the Registrants’ debt issuances.
During the nine months ended September 30, 2023, the following long-term debt was retired and/or redeemed:
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CompanyTypeInterest RateMaturityAmount
ExelonSMBC Term Loan AgreementSOFR plus 0.65%July 21, 2023$300 
ExelonUS Bank Term Loan AgreementSOFR plus 0.65%July 21, 2023300 
ExelonPNC Term Loan AgreementSOFR plus 0.65%July 24, 2023250 
ExelonLong-Term Software License Agreement3.70 %August 9, 20256 
ExelonLong-Term Software License Agreement3.95 %May 1, 20242 
ExelonLong-Term Software License Agreement3.70 %August 9, 20251 
PECOLoan Agreement2.00 %June 20, 202350 
BGENotes3.35 %July 1, 2023300 
Dividends
Quarterly dividends declared by the Exelon Board of Directors during the nine months ended September 30, 2023 and for the fourth quarter of 2023 were as follows:
PeriodDeclaration DateShareholder of Record DateDividend Payable Date
Cash per Share(a)
First Quarter 2023February 14, 2023February 27, 2023March 10, 2023$0.3600 
Second Quarter 2023April 25, 2023May 15, 2023June 9, 2023$0.3600 
Third Quarter 2023July 25, 2023August 15, 2023September 8, 2023$0.3600 
Fourth Quarter 2023November 1, 2023November 15, 2023December 8, 2023$0.3600 
__________
(a)Exelon's Board of Directors approved an updated dividend policy for 2023. The 2023 quarterly dividend will be $0.36 per share.
Credit Matters and Cash Requirements
The Registrants fund liquidity needs for capital investment, working capital, energy hedging, and other financial commitments through cash flows from continuing operations, public debt offerings, commercial paper markets, and large, diversified credit facilities. The credit facilities include $4.0 billion in aggregate total commitments of which $3.2 billion was available to support additional commercial paper as of September 30, 2023, 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 nine months ended September 30, 2023 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 10 — 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 2022 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 September 30, 2023, Exelon has not issued any shares of common stock under the ATM program and has not entered into any forward sale agreements.
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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 September 30, 2023 and available credit facility capacity prior to any incremental collateral at September 30, 2023:
PJM Credit Policy Collateral
Other Incremental Collateral Required(a)
Available Credit Facility Capacity Prior to Any Incremental Collateral
ComEd$1 $— $718 
PECO1 20 600 
BGE3 30 539 
Pepco4 — 300 
DPL4 9 300 
ACE2 — 127 
__________
(a)Represents incremental collateral related to natural gas procurement contracts.
Capital Expenditure Spending
As of September 30, 2023, the most recent estimates of capital expenditures for plant additions and improvements for 2023 are as follows:        
(In millions)TransmissionDistributionGas
Total(a)
ExelonN/AN/AN/A$7,300 
ComEd400 2,175 N/A2,575 
PECO175 925 325 1,425 
BGE225 625 500 1,350 
PHI550 1,275 100 1,925 
Pepco250 675 N/A925 
DPL175 300 100 575 
ACE125 300 N/A425 
__________
(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 $20 million in 2023. 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).
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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 2022 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 10 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information on the Registrants’ credit facilities and short term borrowing activity.
Security Ratings
The Registrants’ access to the capital markets, including the commercial paper market, and their respective financing costs in those markets, may depend on the securities ratings of the entity that is accessing the capital markets.
The Registrants’ borrowings are not subject to default or prepayment as a result of a downgrading of securities, although such a downgrading of a Registrant’s securities could increase fees and interest charges under that Registrant’s credit agreements.
As part of the normal course of business, the Registrants enter into contracts that contain express provisions or otherwise permit the Registrants and their counterparties to demand adequate assurance of future performance when there are reasonable grounds for doing so. In accordance with the contracts and applicable contracts law, if the Registrants are downgraded by a credit rating agency, it is possible that a counterparty would attempt to rely on such a downgrade as a basis for making a demand for adequate assurance of future performance, which could include the posting of collateral. See Note 9 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information on collateral provisions.
The credit ratings for Exelon Corporate, PECO, BGE, PHI, Pepco, DPL, and ACE did not change for the nine months ended September 30, 2023. On July 26, 2023, S&P raised ComEd's long-term issuer credit rating from 'BBB+' to a 'A-'. S&P also affirmed the current 'A' rating on ComEd's senior secured debt and 'A-2' short-term rating, which influences long and short-term borrowing cost.
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 September 30, 2023, are presented in the following table:
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During the Nine Months Ended September 30, 2023At September 30, 2023
Exelon Intercompany Money PoolMaximum
Contributed		Maximum
Borrowed		Contributed
(Borrowed)
Exelon Corporate$510 $— $178 
PECO305 (238)51 
BSC— (350)(212)
PHI Corporate— (62)(62)
PCI45 — 45 
During the Nine Months Ended September 30, 2023At September 30, 2023
PHI Intercompany Money PoolMaximum
Contributed		Maximum
Borrowed
(Borrowed)
Contributed
Pepco$39 $(55)$7 
DPL111 — 10 
ACE— (95)(17)
Shelf Registration Statements
Exelon and the Utility Registrants have a currently effective combined shelf registration statement, unlimited in amount, that will expire in August 2025. The ability of each Registrant to sell securities off the shelf registration statement 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.
Regulatory Authorizations
The Utility Registrants are required to obtain short-term and long-term financing authority from Federal and State Commissions as follows:
At September 30, 2023
Short-term Financing Authority (e)
Remaining Long-term Financing Authority
CommissionExpiration DateAmountCommissionExpiration DateAmount
ComEd(a)
FERCDecember 31, 2023$2,500 ICCJanuary 1, 2025$368 
PECOFERCDecember 31, 20231,500 PAPUCDecember 31, 2024550 
BGE(b)
FERCDecember 31, 2023700 MDPSCN/A1,100 
Pepco(c)
FERCDecember 31, 2023500 MDPSC / DCPSCDecember 31, 20251,050 
DPL(c)
FERCDecember 31, 2023500 MDPSC / DEPSCDecember 31, 20251,075 
ACE(d)
NJBPUDecember 31, 2023350 NJBPUDecember 31, 2024625 
__________
(a)On June 29, 2023, ComEd filed an application for $2 billion in new money long-term debt financing authority from the ICC and expects approval by December 31, 2023.
(b)On December 21, 2022, BGE received approval from the MDPSC for $1.8 billion in new long-term financing authority with an effective date of January 4, 2023.
(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.
(d)On July 14, 2023, ACE filed an application with the NJBPU for renewal of their short-term financing authority through January 1, 2026. ACE expects approval of their application by December 31, 2023.
(e)On October 2, 2023, ComEd, PECO, BGE, Pepco, and DPL filed applications with FERC for renewal of their short-term financing authority through December 31, 2025. ComEd, PECO, BGE, Pepco, and DPL expect approval of their applications by December 31, 2023.
147


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 9 — 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 8 — Retirement Benefits of the 2022 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 10 — 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 9 – Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information.

•Electric operating revenues risk associated with ComEd's distribution formula rate. ComEd's ROE for its electric distribution service through 2023 is directly correlated to yields on U.S. Treasury bonds. Exelon Corporate may utilize interest rate derivatives to mitigate volatility and manage risk to Exelon, which are typically accounted for as economic hedges. See Note 9 – 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.
148


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 9 — Derivative Financial Instruments and Note 11 — Fair Value of Financial Assets and Liabilities of the Combined Notes to Consolidated Financial Statements.
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 11 — 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):
202320242025202620272028 and Beyond
Prices based on model or other valuation methods (Level 3)$(10)$(18)$(17)$(17)$(17)$(55)$(134)
_________
(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 third quarter of 2023, 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 September 30, 2023, the principal executive officer and principal financial officer of each of the Registrants concluded that such Registrant’s disclosure controls and procedures were effective to accomplish its objectives. The Registrants continually strive to improve their disclosure controls and procedures to enhance the quality of its financial reporting and to maintain dynamic systems that change as conditions warrant. There were no changes in internal control over financial reporting during the third quarter of 2023 that materially affected, or are reasonably likely to materially affect, any of the Registrants' internal control over financial reporting.
PART II — OTHER INFORMATION
ITEM 1.    LEGAL PROCEEDINGS
The Registrants are parties to various lawsuits and regulatory proceedings in the ordinary course of their respective businesses. For information regarding material lawsuits and proceedings, see (a) ITEM 3. LEGAL PROCEEDINGS of the 2022 Form 10-K, (b) Notes 3 — Regulatory Matters and 18 — Commitments and Contingencies of the 2022 Form 10-K, and (c) Notes 3 — Regulatory Matters and 12 — 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.
149


ITEM 1A.    RISK FACTORS
Risks Related to All Registrants
At September 30, 2023, the Registrants' risk factors were consistent with the risk factors described in the Registrants' combined 2022 Form 10-K in ITEM 1A. RISK FACTORS, except for the following risk factor, which was amended.
The activities associated with the past Deferred Prosecution Agreement and the now resolved associated SEC investigation could have a material adverse effect on Exelon’s and ComEd’s reputation and relationship with legislators, regulators and customers that could affect their ability to achieve actions and approvals (Exelon and ComEd).
On July 17, 2020, ComEd entered into a Deferred Prosecution Agreement with the U.S. Attorney’s Office for the Northern District of Illinois (USAO) to resolve the USAO’s investigation into Exelon’s and ComEd’s lobbying activities in the State of Illinois. Exelon was not made a party to the DPA and no charges were brought against Exelon. Under the DPA, the USAO filed a single charge alleging that ComEd improperly gave and offered to give jobs, vendor subcontracts, and payments associated with those jobs and subcontracts for the benefit of the Speaker of the Illinois House of Representatives and the Speaker’s associates, with the intent to influence the Speaker’s action regarding legislation affecting ComEd’s interests. The DPA provided that the USAO would defer any prosecution of such charge and any other criminal or civil case against ComEd in connection with the matters identified therein for a three-year period, which expired, and the pending charge was dismissed in July 2023. In October 2019, the SEC notified Exelon and ComEd that it had opened an investigation into their lobbying activities in the state of Illinois. On September 28, 2023, Exelon and ComEd reached a settlement with the SEC to fully resolve the matter.
The DPA and the settlement with the SEC could have a material adverse impact on Exelon’s and ComEd’s reputation or relationships with regulatory and legislative authorities, customers, and other stakeholders. Those impacts could affect, or make more difficult, their efforts to achieve actions or approvals associated with operations. See Note 18 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for more information regarding the DPA and SEC settlement.

ITEM 5.    OTHER INFORMATION
All Registrants
None.
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Table of Contents
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.
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 September 30, 2023 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
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Table of Contents
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 September 30, 2023 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)
153


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)
November 2, 2023
154


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)
November 2, 2023
155


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 Director		Senior Vice President, Chief Financial Officer and Treasurer
(Principal Financial Officer)
/s/    CAROLINE FULGINITI
Caroline Fulginiti
Director, Accounting
(Principal Accounting Officer)
November 2, 2023

156


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)
November 2, 2023

157


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)
November 2, 2023

158


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)
November 2, 2023

159


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)
November 2, 2023

160


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)
November 2, 2023
161


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