Item 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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Item 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

(Dollars in millions except per share data, unless otherwise noted)

Exelon

Executive Overview

Exelon is a utility services holding company engaged in the energy transmission and distribution businesses through it's six reportable segments: ComEd, PECO, BGE, Pepco, DPL, and ACE. See Note 1 — Significant Accounting Policies and Note 4 — Segment Information of the Combined Notes to Consolidated Financial Statements for additional information regarding Exelon's principal subsidiaries and reportable segments.

Exelon’s consolidated financial information includes the results of its seven separate operating subsidiary registrants, ComEd, PECO, BGE, PHI, Pepco, DPL, and ACE, which, along with Exelon, are collectively referred to as the Registrants. The following combined Management’s Discussion and Analysis of Financial Condition and Results of Operations is separately filed by Exelon, ComEd, PECO, BGE, PHI, Pepco, DPL, and ACE. However, none of the Registrants makes any representation as to information related solely to any of the other Registrants.

Financial Results of Operations

GAAP Results of Operations. The following table sets forth Exelon's GAAP consolidated Net income attributable to common shareholders by Registrant for the three and nine months ended September 30, 2024 compared to the same period in 2023. For additional information regarding the financial results for the three and nine months ended September 30, 2024 and 2023, see the discussions of Results of Operations by Registrant.

Three Months Ended September 30,Favorable (Unfavorable) VarianceNine Months Ended September 30,Favorable (Unfavorable) Variance
2024202320242023
Exelon$707$700$7$1,813$1,711$102
ComEd360333278238221
PECO117146(29)356410(54)
BGE4545—35328667
PHI27823246603490113
Pepco1401202032324974
DPL55431215612828
ACE83711213312211
Other(a)(93)(56)(37)(322)(297)(25)

(a)Other primarily includes eliminating and consolidating adjustments, Exelon’s corporate operations, shared service entities, and other financing and investment activities.

Three Months Ended September 30, 2024 Compared to Three Months Ended September 30, 2023. Net income attributable to common shareholders increased by $7 million and diluted earnings per average common share remained relatively consistent to the prior year at $0.70 primarily due to:

  • Timing of distribution earnings at ComEd;

  • Favorable impacts of rate increases at BGE and PHI;

  • Higher return on regulatory assets at ComEd; and

  • Lower storm costs at PHI.

The increases were partially offset by:

  • Higher interest expense at PECO, BGE, and PHI;

  • Higher credit loss expense at PECO and BGE;

  • Higher depreciation and amortization expense at PECO and BGE;

  • Lower electric distribution earnings from lower allowed ROE and the absence of a return on the pension asset at ComEd; and

  • Lower carrying cost recovery related to the CMC regulatory asset at ComEd.

Nine Months Ended September 30, 2024 Compared to Nine Months Ended September 30, 2023. Net income attributable to common shareholders increased by $102 million and diluted earnings per average common share increased to $1.81 in 2024 from $1.72 in 2023 primarily due to:

  • Favorable impacts of rate increases at BGE and PHI;

  • Less unfavorable weather at PECO;

  • Timing of distribution earnings at ComEd;

  • Higher return on regulatory assets at ComEd;

  • Favorable impacts of the multi-year plans including the recognition of the reconciliations at Pepco;

  • Higher transmission peak load due to higher energy demand at ComEd; and

  • Lower storm costs at PHI.

The increases were partially offset by:

  • Higher interest expense at PECO, BGE, PHI, and Exelon Corporate;

  • Higher credit loss expense at PECO, BGE, and PHI;

  • Higher depreciation expense at PECO and PHI;

  • Lower electric distribution earnings from lower allowed ROE and the absence of a return on the pension asset at ComEd;

  • Higher storm costs at PECO and BGE; and

  • Lower carrying cost recovery related to the CMC regulatory asset at ComEd.

Adjusted (non-GAAP) operating earnings. In addition to Net income, Exelon evaluates its operating performance using the measure of Adjusted (non-GAAP) operating earnings because management believes it represents earnings directly related to the ongoing operations of the business. Adjusted (non-GAAP) operating earnings exclude certain costs, expenses, gains and losses, and other specified items. This information is intended to enhance an investor’s overall understanding of year-over-year operating results and provide an indication of Exelon’s baseline operating performance excluding items that are considered by management to be not directly related to the ongoing operations of the business. In addition, this information is among the primary indicators management uses as a basis for evaluating performance, allocating resources, setting incentive compensation targets, and planning and forecasting of future periods. Adjusted (non-GAAP) operating earnings is not a presentation defined under GAAP and may not be comparable to other companies’ presentations or deemed more useful than the GAAP information provided elsewhere in this report.

The following table provides a reconciliation between GAAP Net income attributable to common shareholders and Adjusted (non-GAAP) operating earnings for the three and nine months ended September 30, 2024 compared to the same period in 2023:

Three Months Ended September 30,
20242023
(In millions, except per share data)Earnings per Diluted ShareEarnings per Diluted Share
Net income attributable to common shareholders$707$0.70$700$0.70
Mark-to-market impact of economic hedging activities (net of taxes of $4)——12—
Asset retirement obligation (net of taxes of $0 and $1, respectively)——(1)—
Separation costs (net of taxes of $5)(a)——140.01
Cost management charge (net of taxes of $0)(b)1———
Income tax-related adjustments (entire amount represents tax expense)(c)——(54)(0.05)
Adjusted (non-GAAP) operating earnings$708$0.71$671$0.67
Nine Months Ended September 30,
20242023
(In millions, except per share data)Earnings per Diluted ShareEarnings per Diluted Share
Net income attributable to common shareholders$1,813$1.81$1,711$1.72
Mark-to-market impact of economic hedging activities (net of taxes of $0 and $4)——140.01
Change in environmental liabilities (net of taxes of $0 and $8, respectively)(1)—290.03
Asset retirement obligation (net of taxes of $0 and $1, respectively)——(1)—
SEC matter loss contingency (net of taxes of $0)——460.05
Change in FERC audit liability (net of taxes of $13 and $4, respectively)420.04110.01
Separation costs (net of taxes of $7)(a)——190.02
Cost management charge (net of taxes of $3)(b)100.01——
Income tax-related adjustments (entire amount represents tax expense)(c)——(54)(0.05)
Adjusted (non-GAAP) operating earnings$1,865$1.86$1,774$1.78

Note:

Amounts may not sum due to rounding.

Unless otherwise noted, the income tax impact of each reconciling item between GAAP Net income attributable to common shareholders and Adjusted (non-GAAP) operating earnings is based on the marginal statutory federal and state income tax rates for each Registrant, taking into account whether the income or expense item is taxable or deductible, respectively, in whole or in part. The marginal statutory income tax rates for 2024 and 2023 ranged from 24.0% to 29.0%.

(a)Represents costs related to the separation primarily comprised of system-related costs, third-party costs paid to advisors, consultants, lawyers, and other experts assisting in the separation, and employee-related severance costs, which are recorded in Operating and maintenance expense and Other, net.

(b)Primarily represents severance and reorganization costs related to cost management.

(c)In 2023, reflects the adjustment to state deferred income taxes dues to changes in forecasted apportionment.

Significant 2024 Transactions and Developments

Distribution Base Rate Case Proceedings

The Utility Registrants file base rate cases with their regulatory commissions seeking increases or decreases to their electric transmission and distribution, and gas distribution rates to recover their costs and earn a fair return on their investments. The outcomes of these regulatory proceedings impact the Utility Registrants’ current and future financial statements.

The following tables show the Utility Registrants’ completed and pending distribution base rate case proceedings in 2024. See Note 2 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.

Completed Distribution Base Rate Case Proceedings

Registrant/JurisdictionFiling DateServiceRequested Revenue Requirement IncreaseApproved Revenue Requirement IncreaseApproved ROEApproval DateRate Effective Date
ComEd - IllinoisJanuary 17, 2023Electric$1,487$5018.905%December 14, 2023January 1, 2024
$838$8108.905%April 18, 2024May 1, 2024
April 21, 2023Electric$247$2598.91%November 30, 2023January 1, 2024
BGE - MarylandFebruary 17, 2023Electric$313$1799.50%December 14, 2023January 1, 2024
Natural Gas$289$2299.45%
Pepco - MarylandMay 16, 2023 (amended February 23, 2024)Electric$111$459.50%June 10, 2024April 1, 2024
DPL - MarylandMay 19, 2022Electric$38$299.60%December 14, 2022January 1, 2023
DPL - DelawareDecember 15, 2022 (amended September 29, 2023)Electric$39$289.60%April 18, 2024July 15, 2023
ACE - New JerseyFebruary 15, 2023 (amended August 21, 2023)Electric$92$459.60%November 17, 2023December 1, 2023

Pending Distribution Base Rate Case Proceedings

Registrant/JurisdictionFiling DateServiceRequested Revenue Requirement IncreaseRequested ROEExpected Approval Timing
ComEd - IllinoisMarch 15, 2024 (amended August 13, 2024)Electric$6678.905%December 2024
April 26, 2024 (amended September 11, 2024)Electric$6249.89%Fourth quarter of 2024
PECO - PennsylvaniaMarch 28, 2024Electric$46410.95%Fourth quarter of 2024
Natural Gas$11111.15%
Pepco - District of ColumbiaApril 13, 2023 (amended February 27, 2024)Electric$18610.50%Fourth quarter of 2024
DPL - DelawareSeptember 20, 2024Natural Gas$3610.65%First quarter of 2026

Transmission Formula Rates

For 2024, the following total increases/(decreases) were included in the Utility Registrant's electric transmission formula rate updates. See Note 2 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.

RegistrantInitial Revenue Requirement IncreaseAnnual Reconciliation (Decrease) IncreaseTotal Revenue Requirement IncreaseAllowed Return on Rate BaseAllowed ROE
ComEd$32$(12)$208.14%11.50%
PECO$2$3$57.45%10.35%
BGE$42$13$537.47%10.50%
Pepco$58$15$737.62%10.50%
DPL$7$17$247.23%10.50%
ACE$14$18$327.11%10.50%

ComEd's FERC Audit

The Utility Registrants are subject to periodic audits and investigations by FERC. FERC’s Division of Audits and Accounting initiated a nonpublic audit of ComEd in April 2021 evaluating ComEd’s compliance with (1) approved terms, rates and conditions of its federally regulated service; (2) accounting requirements of the Uniform System of Accounts; (3) reporting requirements of the FERC Form 1; and (4) the requirements for record retention. The audit period extends back to January 1, 2017.

On July 27, 2023, FERC issued a final audit report which included, among other things, findings and recommendations related to ComEd's methodology regarding the allocation of certain overhead costs to capitalized construction costs under FERC regulations, including a suggestion that refunds may be due to customers for amounts collected in previous years. On August 28, 2023, ComEd filed a formal notice of the issues it contested within the audit report. On December 14, 2023, FERC appointed a settlement judge for the contested overhead allocation findings and set the matter for a trial-type hearing. That hearing process was held in abeyance while a formal settlement process, which began in February 2024, took place.

On July 30, 2024, ComEd reached an agreement in principle on the contested overhead allocation finding. As a result of the settlement process, ComEd recorded a charge for the probable disallowance of $70 million of certain currently capitalized construction costs to operating expenses, which are not expected to be recovered in future rates. The final settlement is subject to FERC approval. The existing loss estimate is reflected in Exelon and ComEd's financial statements as of September 30, 2024.

Other Key Business Drivers and Management Strategies

The following discussion of other key business drivers and management strategies includes current developments of previously disclosed matters and new issues arising during the period that may impact future financial statements. This section should be read in conjunction with ITEM 1. Business in the 2023 Form 10-K, ITEM 7. Management's Discussion and Analysis of Financial Condition and Results of Operations — Other Key Business Drivers and Management Strategies in the 2023 Form 10-K, and Note 11 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements in this report for additional information on various environmental matters.

Legislative and Regulatory Developments

Infrastructure Investment and Jobs Act

On November 15, 2021, President Biden signed the $1.2 trillion IIJA into law. IIJA provides for approximately $550 billion in new federal spending. Categories of funding include funding for a variety of infrastructure needs, including but not limited to: (1) power and grid reliability and resilience, (2) resilience for cybersecurity to address critical infrastructure needs, and (3) electric vehicle charging infrastructure for alternative fuel corridors. Federal agencies are developing guidelines to implement spending programs under IIJA. The time needed to develop these guidelines will vary with some limited program applications opened as early as the first quarter of 2022. The Registrants continue to evaluate programs under the legislation and consider possible opportunities to apply for funding, either directly or in potential collaborations with state and/or local agencies and key stakeholders. The Registrants cannot predict the ultimate timing and success of securing funding from programs under IIJA.

In March 2023, Exelon, ComEd, and PHI submitted three applications related to the Smart Grid Grants program under section 40107 of IIJA. These applications are focused on replacing existing Advanced Distribution Management Systems (ADMS) in support of distributed energy resources (DERs) and grid-edged technologies, strengthening interoperability and data architecture of systems in support of two-way power flows and accelerating advanced metering deployment in disadvantaged communities. In October 2023, ComEd’s project, Deployment of a Community-Oriented Interoperable Control Framework for Aggregating and Integrating Distributed Energy Resources and Other Grid-Edge Devices, was recommended by the Grid Deployment Office (GDO) for negotiation of a final award up to $50 million. This project will enable ComEd and its local partners to deploy the next generation of grid technologies that support the growth of solar and electric vehicles (EVs), while piloting new local workforce training initiatives to support job creation connected to the clean energy transition. The award negotiation process is complete and funding has been obligated.

In April 2023, ComEd, PECO, BGE, and PHI submitted seven applications related to the Grid Resilience Grants program under section 40101(c) of IIJA. These applications are broadly focused on improving grid resilience with an emphasis on disadvantaged communities, relief of capacity constraints and modernizing infrastructure, deployment of DER and microgrid technologies and providing improved resilience through storm hardening projects. In October 2023, PECO’s project, Creating a Resilient, Equitable, and Accessible Transformation in Energy for Greater Philadelphia (CREATE), was recommended by the GDO for negotiation of a final award up to $100 million. This project will support critical electric infrastructure investments to help reduce the impact of extreme weather and historic flooding on the Registrants' electric distribution system. The award negotiation process is complete and funding has been obligated.

The Registrants are supporting three different Regional Clean Hydrogen Hub opportunities, covering all five states that Exelon operates in plus Washington D.C. under a program that will create networks of hydrogen producers, consumers, and local connective infrastructure to accelerate the use of hydrogen as a clean energy carrier that can deliver or store energy. Applications for the three opportunities under this program were submitted in April 2023. In October 2023 the DOE announced it selected two of the projects for further negotiation: (1) the Mid-Atlantic Clean Hydrogen Hub (MACH2), which is being supported by PECO and PHI, and (2) the Midwest Alliance for Clean Hydrogen (MachH2), which is being supported by ComEd.

In November 2023, the GDO announced up to $3.9 billion available through the second-round funding opportunity of the Grid Resilience and Innovation Partnerships (GRIP) Program for fiscal years 2024 and 2025. This funding opportunity focuses on projects that will improve electric transmission by increasing funding and advancing interconnection processes for faster build out of energy projects, create comprehensive solutions that link grid communications systems and operations to increase resilience and reduce power outages and threats, and deploy advanced technologies such as distributed energy resources and battery systems to provide essential grid services to ensure American communities across the country have access to affordable, reliable, clean electricity. In March 2024, Exelon, BGE, PHI, Pepco, DPL, and ACE submitted five applications for Topic Area 2 (Smart Grid Grants). These applications focus on improving resilience of the electric grid and deployment of technologies to enhance grid flexibility and deliver benefits to customers across the Exelon footprint.

In October 2024, Exelon’s project, Renewable-Aware Distribution Operations: Pioneering a cleaner future for all our communities, and BGE’s project, Baltimore Interconnection Readiness & Deployment of Storage (BIRDS), were recommended by the GDO for negotiation of a final award up to $100 million and $50 million, respectively. The Exelon project will deploy advanced Distribution Energy Resource Management System (DERMS) capabilities and pilot technology to increase the flexibility, efficiency, reliability, and resilience of its distribution network. BGE’s project will facilitate a programmatic approach to a flexible and decentralized energy distribution grid while setting an automated and digitized framework for unlocking future clean energy investments. The GDO has indicated the negotiation process is expected to take a minimum of 120 days.

PJM Regional Transmission Expansion

On July 11, 2024, BGE submitted an application to the MDPSC for a Certificate of Public Convenience and Necessity for certain overhead transmission system upgrades necessitated due to the planned retirement of the Brandon Shores Generating Station. The total estimated costs of all work by BGE directed by PJM in connection with the retirement of the Brandon Shores Generating Station is approximately $1.1 billion.

Critical Accounting Policies and Estimates

Management of each of the Registrants makes a number of significant estimates, assumptions, and judgments in the preparation of its financial statements. As of September 30, 2024, the Registrants’ critical accounting policies and estimates had not changed significantly from December 31, 2023. See ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS — Critical Accounting Policies and Estimates in the 2023 Form 10-K for further information.

Results of Operations by Registrant

Results of Operations — ComEd

Three Months Ended September 30,(Unfavorable) Favorable VarianceNine Months Ended September 30,Favorable (Unfavorable) Variance
2024202320242023
Operating revenues$2,229$2,268$(39)$6,403$5,836$567
Operating expenses
Purchased power835896612,5042,068(436)
Operating and maintenance410385(25)1,2771,077(200)
Depreciation and amortization387357(30)1,1241,045(79)
Taxes other than income taxes991001287282(5)
Total operating expenses1,7311,73875,1924,472(720)
Gain on sales of assets———5—5
Operating income498530(32)1,2161,364(148)
Other income and (deductions)
Interest expense, net(128)(119)(9)(374)(357)(17)
Other, net261610665016
Total other income and (deductions)(102)(103)1(308)(307)(1)
Income before income taxes396427(31)9081,057(149)
Income taxes36945885235150
Net income$360$333$27$823$822$1

Three Months Ended September 30, 2024 Compared to Three Months Ended September 30, 2023. Net income increased by $27 million as compared to the same period in 2023, primarily due to timing of distribution earnings, higher distribution rate base, and higher return on regulatory assets. These were partially offset by a lower allowed distributions ROE, the absence of a return on the pension asset within distribution earnings, and lower carrying cost recovery related to the CMC regulatory asset.

Nine Months Ended September 30, 2024 Compared to Nine Months Ended September 30, 2023. Net income increased by $1 million as compared to the same period in 2023, primarily due to timing of distribution earnings, higher distribution rate base, higher return on regulatory assets, and higher transmission peak load. These were partially offset by a lower allowed distribution ROE, the absence of a return on the pension asset within distribution earnings, and lower carrying cost recovery related to the CMC regulatory asset.

The changes in Operating revenues consisted of the following:

Three Months Ended September 30, 2024Nine Months Ended September 30, 2024
Increase (Decrease)Increase
Distribution$46$189
Transmission1976
Energy efficiency1343
Other1614
94322
Regulatory required programs(133)245
Total (decrease) increase$(39)$567

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.

ComEd

Distribution Revenue. Distribution revenues were under a performance-based formula rate through 2023. Starting in 2024, distribution revenues are under a MRP. Both the performance-based formula rate and the MRP require annual reconciliations of the revenue requirement in effect to the actual costs the ICC determines are prudently and reasonably incurred with certain limitations for the MRP reconciliations. Electric distribution revenue varies from year to year based upon fluctuations in the underlying costs, (e.g., severe weather and storm restoration), investments being recovered, and allowed ROE. Electric distribution revenues increased for the three and nine months ended September 30, 2024 as compared to the same period in 2023, primarily due to differences in the timing of distribution earnings and higher rate base, partially offset by lower allowed ROE and the absence of a return on the pension asset.

Transmission Revenue. Under a FERC-approved formula, transmission revenue varies from year to year based upon fluctuations in the underlying costs, capital investments being recovered, and the highest daily peak load, which is updated annually in January based on the prior calendar year. Transmission revenues increased for the three and nine months ended September 30, 2024 as compared to the same period in 2023, primarily due to higher fully recoverable costs, higher peak load, and the impacts of higher rate base.

Energy Efficiency Revenue. Energy efficiency revenues are under a performance-based formula rate, which requires an annual reconciliation of the revenue requirement in effect to the actual costs the ICC determines are prudently and reasonably incurred in a given year. Energy efficiency revenue varies from year to year based upon fluctuations in the underlying costs, investments being recovered, and allowed ROE. Energy efficiency revenues increased for the three and nine months ended September 30, 2024 as compared to the same periods in 2023, primarily due to increased regulatory asset amortization, which is fully recoverable.

Other Revenue primarily includes assistance provided to other utilities through mutual assistance programs. Other revenues increased for the three and nine months ended September 30, 2023 as compared to the same periods in 2023, which primarily reflects increased mutual assistance revenues associated with storm restoration efforts.

Regulatory Required Programs represents revenues collected under approved riders to recover costs incurred for regulatory programs such as recoveries under the credit loss expense tariff, environmental costs associated with MGP sites, ETAC, and costs related to electricity, ZEC, CMC, and REC procurement. ETAC is a retail customer surcharge collected and remitted to an Illinois state agency for programs to support clean energy jobs and training. The riders are designed to provide full and current cost recovery. The costs of these programs are included in Purchased power expense, Operating and maintenance expense, Depreciation and amortization expense, and Taxes other than income taxes. Customers have the choice to purchase electricity from competitive electric generation suppliers. Customer choice programs do not impact the volume of deliveries as ComEd remains the distribution service provider for all customers and charges a regulated rate for distribution service, which is recorded in Operating revenues. For customers that choose to purchase electric generation from competitive suppliers, ComEd either acts as the billing agent or the competitive supplier separately bills its own customers, and therefore does not record Operating revenues or Purchased power expense related to the electricity. For customers that choose to purchase electric generation from ComEd, ComEd is permitted to recover the electricity, ZEC, CMC, and REC procurement costs without mark-up and therefore records equal and offsetting amounts in Operating revenues and Purchased power expense related to the electricity, ZECs, CMCs, and RECs.

See Note 4 — Segment Information of the Combined Notes to Consolidated Financial Statements for the presentation of ComEd's revenue disaggregation.

The $61 million decrease and $436 million increase in Purchased power expense for the three and nine months ended September 30, 2024 compared to the same periods in 2023, respectively, is offset in Operating revenues as part of regulatory required programs.

ComEd

The changes in Operating and maintenance expense consisted of the following:

Three Months Ended September 30, 2024Nine Months Ended September 30, 2024
Increase (Decrease)Increase (Decrease)
Labor, other benefits, contracting and materials(a)$9$81
BSC costs1043
Pension and non-pension postretirement benefits expense618
Storm-related costs(7)(4)
Other(b)(5)77
13215
Regulatory required programs(c)12(15)
Total increase$25$200

(a)Primarily reflects an updated rate of capitalization of certain overhead costs.

(b)Primarily reflects the reclassification and increase of the FERC audit liability during the current year and an increase in credit loss expense. See Note 2 — Regulatory Matters for additional information regarding the FERC audit liability.

(c)ComEd is allowed to recover from or refund to customers the difference between its annual credit loss expense and the amounts collected in rates annually through a rider mechanism.

The changes in Depreciation and amortization expense consisted of the following:

Three Months Ended September 30, 2024Nine Months Ended September 30, 2024
IncreaseIncrease
Depreciation and amortization(a)$20$53
Regulatory asset amortization(b)1026
Total increase$30$79

(a)Reflects ongoing capital expenditures.

(b)Includes amortization of ComEd's energy efficiency formula rate regulatory asset.

Effective income tax rat****es were 9.1% and 22.0% for the three months ended September 30, 2024 and 2023, respectively, and 9.4% and 22.2% for the nine months ended September 30, 2024 and 2023, respectively. See Note 6 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the effective income tax rates.

PECO

Results of Operations — PECO

Three Months Ended September 30,(Unfavorable) Favorable VarianceNine Months Ended September 30,(Unfavorable) Favorable Variance
2024202320242023
Operating revenues$1,030$1,037$(7)$2,975$2,977$(2)
Operating expenses
Purchased power and fuel386411251,1131,19784
Operating and maintenance313277(36)876786(90)
Depreciation and amortization108100(8)318297(21)
Taxes other than income taxes6159(2)164156(8)
Total operating expenses868847(21)2,4712,436(35)
Gain on sales of assets———4—4
Operating income162190(28)508541(33)
Other income and (deductions)
Interest expense, net(58)(52)(6)(170)(149)(21)
Other, net911(2)27261
Total other income and (deductions)(49)(41)(8)(143)(123)(20)
Income before income taxes113149(36)365418(53)
Income taxes(4)3798(1)
Net income$117$146$(29)$356$410$(54)

Three Months Ended September 30, 2024 Compared to Three Months Ended September 30, 2023. Net income decreased by $29 million, due to an increase in credit loss expense, interest expense, and depreciation expense.

Nine Months Ended September 30, 2024 Compared to Nine Months Ended September 30, 2023. Net income decreased by $54 million, due to an increase in credit loss expense, interest expense, depreciation expense, and storm costs, partially offset by an increase in revenue as a result of less unfavorable weather impact relative to the same period last year.

The changes in Operating revenues consisted of the following:

Three Months Ended September 30, 2024Nine Months Ended September 30, 2024
(Decrease) IncreaseIncrease (Decrease)
ElectricGasTotalElectricGasTotal
Weather$—$—$—$57$13$70
Volume31411—11
Pricing1421612—12
Transmission(11)—(11)4—4
Other415(3)(3)(6)
10414811091
Regulatory required programs(20)(1)(21)(28)(65)(93)
Total decrease$(10)$3$(7)$53$(55)$(2)

Weather. The demand for electricity and natural gas is affected by weather conditions. With respect to the electric business, very warm weather in summer months and, with respect to the electric and natural gas businesses, very cold weather in winter months are referred to as “favorable weather conditions” because these weather conditions result in increased deliveries of electricity and natural gas. Conversely, mild weather reduces demand. During the three months ended September 30, 2024 compared to the same period in 2023, Operating revenues related to weather remained consistent in PECO's service territory. During the nine months ended September 30, 2024 compared to the same period in 2023, Operating revenues related to weather increased due to less unfavorable weather conditions in PECO's service territory.

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, 2024 compared to the same period in 2023 and normal weather consisted of the following:

Three Months Ended September 30,% Change
PECO Service Territory20242023Normal2024 vs. 20232024 vs. Normal
Heating Degree-Days11821(94.4)%(95.2)%
Cooling Degree-Days1,0621,0641,038(0.2)%2.3%
Nine Months Ended September 30,% Change
20242023Normal2024 vs. 20232024 vs. Normal
Heating Degree-Days2,4412,2362,8539.2%(14.4)%
Cooling Degree-Days1,5991,2971,43023.3%11.8%

Volume. Electric volume, exclusive of the effects of weather, for the three months ended September 30, 2024 compared to the same period in 2023, remained relatively consistent. Electric volume, exclusive of the effects of weather, for the nine months ended September 30, 2024 compared to the same period in 2023, increased due to customer load growth. Natural gas volume for the three and nine months ended September 30, 2024 compared to the same period in 2023, remained relatively consistent.

Electric Retail Deliveries to Customers (in GWhs)Three Months Ended September 30,% ChangeWeather - Normal % Change**(b)**Nine Months Ended September 30,% ChangeWeather - Normal % Change**(b)**
2024202320242023
Residential4,1464,1340.3%0.2%10,89710,1867.0%0.7%
Small commercial & industrial2,1292,0702.9%2.8%5,8765,6164.6%1.5%
Large commercial & industrial3,7683,830(1.6)%(1.5)%10,53110,3981.3%—%
Public authorities & electric railroads1561522.6%2.0%4704641.3%1.3%
Total electric retail deliveries(a)10,19910,1860.1%0.1%27,77426,6644.2%0.6%
At September 30,
Number of Electric Customers20242023
Residential1,529,2051,531,168
Small commercial & industrial155,126155,932
Large commercial & industrial3,1563,111
Public authorities & electric railroads10,71610,416
Total1,698,2031,700,627

(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.

PECO

Natural Gas Deliveries to Customers (in mmcf)Three Months Ended September 30,% ChangeWeather - Normal % Change**(b)**Nine Months Ended September 30,% ChangeWeather - Normal % Change**(b)**
2024202320242023
Residential2,3592,13410.5%13.4%25,77923,6978.8%1.5%
Small commercial & industrial1,9331,939(0.3)%1.4%14,74214,3812.5%(3.3)%
Large commercial & industrial14(75.0)%(4.6)%1739(56.4)%(9.4)%
Transportation5,2325,278(0.9)%(2.5)%17,24817,482(1.3)%(3.0)%
Total natural gas retail deliveries(a)9,5259,3551.8%1.9%57,78655,5993.9%(1.1)%
At September 30,
Number of Natural Gas Customers20242023
Residential506,476505,370
Small commercial & industrial44,68244,743
Large commercial & industrial79
Transportation643629
Total551,808550,751

(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, 2024 compared to the same period in 2023 increased primarily due to higher electric DSIC rates in PECO's service territories.

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, 2024 compared to the same period in 2023 remained relatively consistent.

Regulatory Required Programs represents revenues collected under approved riders to recover costs incurred for regulatory programs such as energy efficiency, PGC, and the GSA. The riders are designed to provide full and current cost recovery as well as a return. The costs of these programs are included in Purchased power and fuel expense, Operating and maintenance expense, Depreciation and amortization expense, and Income taxes. Customers have the choice to purchase electricity and natural gas from competitive electric generation and natural gas suppliers. Customer choice programs do not impact the volume of deliveries as PECO remains the distribution service provider for all customers and charges a regulated rate for distribution service, which is recorded in Operating revenues. For customers that choose to purchase electric generation or natural gas from competitive suppliers, PECO either acts as the billing agent or the competitive supplier separately bills its own customers and therefore PECO does not record Operating revenues or Purchased power and fuel expense related to the electricity and/or natural gas. For customers that choose to purchase electric generation or natural gas from PECO, PECO is permitted to recover the electricity, natural gas, and REC procurement costs without mark-up and therefore records equal and offsetting amounts in Operating revenues and Purchased power and fuel expense related to the electricity, natural gas, and RECs.

See Note 4 — Segment Information of the Combined Notes to Consolidated Financial Statements for the presentation of PECO's revenue disaggregation.

The decrease of $25 million and decrease of $84 million for the three and nine months ended September 30, 2024 compared to the same period in 2023, in Purchased power and fuel expense is offset in Operating revenues as part of regulatory required programs.

PECO

The changes in Operating and maintenance expense consisted of the following:

Three Months Ended September 30, 2024Nine Months Ended September 30, 2024
Increase (Decrease)Increase (Decrease)
Credit loss expense$19$47
BSC costs619
Storm-related costs(10)13
Pension and non-pension postretirement benefit expense25
Labor, other benefits, contracting and materials5—
Other811
3095
Regulatory required programs6(5)
Total increase$36$90

The changes in Depreciation and amortization expense consisted of the following:

Three Months Ended September 30, 2024Nine Months Ended September 30, 2024
IncreaseIncrease
Depreciation and amortization(a)$8$21
Regulatory asset amortization——
Total increase$8$21

(a)Depreciation and amortization increased primarily due to ongoing capital expenditures.

Interest expense, net increased $6 million and $21 million for the three and nine months ended September 30, 2024, compared to the same period in 2023, primarily due to an increase in interest rates and the issuance of debt in the third quarter of 2024.

Effective income tax rates were (3.5)% and 2.0% for the three months ended September 30, 2024 and 2023, respectively, and 2.5% and 1.9% for the nine months ended September 30, 2024 and 2023, respectively. See Note 6 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the effective income tax rates.

BGE

Results of Operations — BGE

Three Months Ended September 30,Favorable (Unfavorable) VarianceNine Months Ended September 30,Favorable (Unfavorable) Variance
2024202320242023
Operating revenues$1,044$932$112$3,268$2,986$282
Operating expenses
Purchased power and fuel420380(40)1,2281,145(83)
Operating and maintenance281214(67)795632(163)
Depreciation and amortization162161(1)47448713
Taxes other than income taxes8680(6)254239(15)
Total operating expenses949835(114)2,7512,503(248)
Operating income9597(2)51748334
Other income and (deductions)
Interest expense, net(57)(47)(10)(159)(135)(24)
Other, net1165271413
Total other income and (deductions)(46)(41)(5)(132)(121)(11)
Income before income taxes4956(7)38536223
Income taxes4117327644
Net income$45$45$—$353$286$67

Three Months Ended September 30, 2024 Compared to Three Months Ended September 30, 2023. Net Income remained consistent with favorable distribution rates, offset by an increase in credit loss expense, various operating expenses and interest expense.

Nine Months Ended September 30, 2024 Compared to Nine Months Ended September 30, 2023. Net Income increased $67 million primarily due to favorable distribution rates, partially offset by an increase in storm costs, credit loss expense, various operating expenses and interest expense.

The changes in Operating revenues consisted of the following:

Three Months Ended September 30, 2024Nine Months Ended September 30, 2024
Increase (Decrease)Increase (Decrease)
ElectricGasTotalElectricGasTotal
Distribution$25$23$48$68$82$150
Transmission17—1720—20
Other2133(1)2
4424689181172
Regulatory required programs45(1)44176(66)110
Total increase$89$23$112$267$15$282

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.

BGE

At September 30,
Number of Electric Customers20242023
Residential1,215,8731,208,230
Small commercial & industrial115,032115,557
Large commercial & industrial13,20613,007
Public authorities & electric railroads260264
Total1,344,3711,337,058
At September 30,
Number of Natural Gas Customers20242023
Residential658,485655,753
Small commercial & industrial37,75237,950
Large commercial & industrial6,3536,289
Total702,590699,992

Distribution Revenue increased for the three and nine months ended September 30, 2024, compared to the same period in 2023, due to favorable impacts of the multi-year plans.

Transmission Revenue. Under a FERC-approved formula, transmission revenue varies from year to year based upon fluctuations in the underlying costs and capital investments being recovered. Transmission revenue increased for the three and nine months ended September 30, 2024, compared to the same period in 2023, primarily due to increases in underlying costs and capital investments.

Other Revenue includes revenue related to late payment charges, mutual assistance, off-system sales, and service application fees. Other Revenue remained relatively consistent for the three and nine months ended September 30, 2024 compared to the same period in 2023.

Regulatory Required Programs represent revenues collected under approved riders to recover costs incurred for regulatory programs such as conservation, demand response, and the POLR mechanism. The riders are designed to provide full and current cost recovery, as well as a return in certain instances. The costs of these programs are included in Purchased power and fuel expense, Operating and maintenance expense, Depreciation and amortization expense, and Taxes other than income taxes. Customers have the choice to purchase electricity and natural gas from competitive electric generation and natural gas suppliers. Customer choice programs do not impact the volume of deliveries as BGE remains the distribution service provider for all customers and charges a regulated rate for distribution service, which is recorded in Operating revenues. For customers that choose to purchase electric generation or natural gas from competitive suppliers, BGE acts as the billing agent and therefore does not record Operating revenues or Purchased power and fuel expense related to the electricity and/or natural gas. For customers that choose to purchase electric generation or natural gas from BGE, BGE is permitted to recover the electricity and natural gas procurement costs from customers and therefore records the amounts related to the electricity and/or natural gas in Operating revenues and Purchased power and fuel expense. BGE recovers electricity and natural gas procurement costs from customers with a slight mark-up.

See Note 4 — Segment Information of the Combined Notes to Consolidated Financial Statements for the presentation of BGE's revenue disaggregation.

The increase of $40 million and $83 million for the three and nine months ended September 30, 2024 compared to the same period in 2023, in Purchased power and fuel expense is fully offset in Operating revenues as part of regulatory required programs.

BGE

The changes in Operating and maintenance expense consisted of the following:

Three Months Ended September 30, 2024Nine Months Ended September 30, 2024
(Decrease) IncreaseIncrease
Storm-related costs(4)6
BSC costs316
Credit loss expense1119
Labor, other benefits, contracting, and materials1414
Other(a)2122
4577
Regulatory required programs(b)2286
Total increase$67$163

(a)Primarily related to capital write-offs.

(b)Increase due to the cost recovery associated with EmPOWER Maryland. Please refer to 2023 10-K Note 3 — Regulatory Matters for additional information.

The changes in Depreciation and amortization expense consisted of the following:

Three Months Ended September 30, 2024Nine Months Ended September 30, 2024
(Decrease) Increase(Decrease) Increase
Depreciation and amortization$(7)$(3)
Regulatory required programs(a)(9)(49)
Regulatory asset amortization1739
Total increase (decrease)$1$(13)

(a)Decrease due to the cost recovery associated with EmPOWER Maryland. Please refer to 2023 10-K Note 3 — Regulatory Matters for additional information.

Interest expense, net increased by $10 million and $24 million for the three and nine months ended September 30, 2024 , respectively compared to the same period in 2023, primarily due to an increase in interest rates and the issuance of debt in the second quarter of 2024 and 2023.

Taxes other than income taxes increased by $6 million and $15 million for the three and nine months ended September 30, 2024, respectively, compared to the same period in 2023, primarily due to increased property taxes.

Other, net increased by $5 million and $13 million for the three and nine months ended September 30, 2024, respectively, compared to the same period in 2023, primarily due to increased interest income and higher AFUDC equity.

Effective income tax rates were 8.2% and 19.6% for the three months ended September 30, 2024 and 2023, respectively, and 8.3% and 21.0% for the nine months ended September 30, 2024 and 2023, respectively. See Note 6 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the effective income tax rates.

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, 2024 compared to the same period in 2023. See the Results of Operations for Pepco, DPL, and ACE for additional information.

Three Months Ended September 30,Favorable VarianceNine Months Ended September 30,Favorable Variance
2024202320242023
PHI$278$232$46$603$490$113
Pepco1401202032324974
DPL55431215612828
ACE83711213312211
Other(a)—(2)2(9)(9)—

(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, 2024 Compared to Three Months Ended September 30, 2023. Net Income increased by $46 million primarily due to higher ACE and DPL Delaware electric distribution rates, favorable impacts of the Pepco Maryland multi-year plans, higher transmission rates at Pepco, and a decrease in storm costs and various operating expenses, partially offset by an increase in interest expense.

Nine Months Ended September 30, 2024 Compared to Nine Months Ended September 30, 2023. Net Income increased by $113 million primarily due to the favorable impacts of the Pepco Maryland multi-year plans including the recognition of the reconciliations, the absence of an increase in environmental liabilities at Pepco, higher ACE and DPL Delaware electric distribution rates, higher transmission rates at Pepco and DPL, and a decrease in storm costs and various operating expenses, partially offset by increases in interest expense and depreciation expense.

Pepco

Results of Operations — Pepco

Three Months Ended September 30,Favorable (Unfavorable) VarianceNine Months Ended September 30,Favorable (Unfavorable) Variance
2024202320242023
Operating revenues$861$822$39$2,320$2,174$146
Operating expenses
Purchased power294288(6)808750(58)
Operating and maintenance140149939244048
Depreciation and amortization1021121030732922
Taxes other than income taxes114109(5)317291(26)
Total operating expenses65065881,8241,810(14)
Operating income21116447496364132
Other income and (deductions)
Interest expense, net(50)(41)(9)(142)(122)(20)
Other, net1118(7)4350(7)
Total other income and (deductions)(39)(23)(16)(99)(72)(27)
Income before income taxes17214131397292105
Income taxes3221(11)7443(31)
Net income$140$120$20$323$249$74

Three Months Ended September 30, 2024 Compared to Three Months Ended September 30, 2023. Net Income increased by $20 million primarily due to higher transmission rates, favorable impacts of the Maryland multi-year plans, customer growth, and decrease in storm costs, partially offset by increases in depreciation expense and interest expense.

Nine Months Ended September 30, 2024 Compared to Nine Months Ended September 30, 2023. Net Income increased by $74 million primarily due to the favorable impacts of the Maryland multi-year plans including the recognition of the reconciliations, the absence of an increase in environmental liabilities, higher transmission rates, customer growth, and decrease in storm costs partially offset by increases in depreciation expense and interest expense.

The changes in Operating revenues consisted of the following:

Three Months Ended September 30, 2024Nine Months Ended September 30, 2024
IncreaseIncrease (Decrease)
Distribution$14$30
Transmission2448
Other1(1)
3977
Regulatory required programs—69
Total increase$39$146

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.

Pepco

At September 30,
Number of Electric Customers20242023
Residential875,456862,321
Small commercial & industrial54,05854,082
Large commercial & industrial23,05422,952
Public authorities & electric railroads207205
Total952,775939,560

Distribution Revenue increased for the three and nine months ended September 30, 2024 compared to the same period in 2023 primarily due to favorable impacts of the Maryland multi-year plans and customer growth.

Transmission Revenue. Under a FERC-approved formula, transmission revenue varies from year to year based upon fluctuations in the underlying costs and capital investments being recovered. Transmission revenue increased for the three and nine months ended September 30, 2024, compared to the same period in 2023, primarily due to increases in underlying costs and capital investments.

Other Revenue includes rental revenue, revenue related to late payment charges, mutual assistance revenues, and recoveries of other taxes.

Regulatory Required Programs represent revenues collected under approved riders to recover costs incurred for regulatory programs such as energy efficiency programs, DC PLUG, and SOS procurement and administrative costs. The riders are designed to provide full and current cost recovery as well as a return in certain instances. The costs of these programs are included in Purchased power expense, Operating and maintenance expense, Depreciation and amortization expense, and Taxes other than income taxes. Customers have the choice to purchase electricity from competitive electric generation suppliers. Customer choice programs do not impact the volume of deliveries, as Pepco remains the distribution service provider for all customers and charges a regulated rate for distribution service, which is recorded in Operating revenues. For customers that choose to purchase electric generation from competitive suppliers, Pepco acts as the billing agent and therefore, Pepco does not record Operating revenues or Purchased power expense related to the electricity. For customers that choose to purchase electric generation from Pepco, Pepco is permitted to recover the electricity and REC procurement costs from customers and therefore records the amounts related to the electricity and RECs in Operating revenues and Purchased power expense. Pepco recovers electricity and REC procurement costs from customers with a slight mark-up.

See Note 4 — Segment Information of the Combined Notes to Consolidated Financial Statements for the presentation of Pepco's revenue disaggregation.

The increase of $6 million and $58 million for the three and nine months ended September 30, 2024, respectively, compared to the same period in 2023, in Purchased power expense is fully offset in Operating revenues as part of regulatory required programs.

Pepco

The changes in Operating and maintenance expense consisted of the following:

Three Months Ended September 30, 2024Nine Months Ended September 30, 2024
(Decrease) IncreaseIncrease (Decrease)
BSC and PHISCO costs$(3)$11
Credit loss expense(3)(3)
Storm-related costs(4)(4)
Pension and non-pension postretirement benefits expense—(2)
Labor, other benefits, contracting and materials(a)(7)(36)
Pepco Maryland multi-year plan reconciliations(b)(3)(27)
Other (c)—(21)
(20)(82)
Regulatory required programs(d)1134
Total decrease$(9)$(48)

(a)Primarily reflects the absence of an increase in environmental liabilities for the nine months ended September 30, 2024 compared to the same period in 2023.

(b)See Note 2 — Regulatory Matters for additional information on multi-year plan reconciliations.

(c)Primarily relates to a revenue deferral mechanism approved by the MDPSC to capture rate increases attributable to April 1, 2024 through June 30, 2024.

(d)Increase primarily due to the cost recovery associated with EmPOWER Maryland. Please refer to 2024 10-K Note 2 — Regulatory Matters for additional information.

The changes in Depreciation and amortization expense consisted of the following:

Three Months Ended September 30, 2024Nine Months Ended September 30, 2024
Increase (Decrease)Increase (Decrease)
Depreciation and amortization(a)$7$18
Regulatory asset amortization——
Regulatory required programs(17)(40)
Total decrease$(10)$(22)

(a)Depreciation and amortization increased primarily due to ongoing capital expenditures.

Taxes other than income taxes increased $5 million and $26 million for the three and nine months ended September 30, 2024, respectively, compared to the same period in 2023, primarily due to increases in utility taxes, which are offset in revenues, and property taxes.

Interest expense, net increased by $9 million and $20 million for the three and nine months ended September 30, 2024, respectively, compared to the same period in 2023, primarily due to increases in interest rates and the issuance of debt in 2023 and 2024.

Effective income tax rates were 18.6% and 14.9% for the three months ended September 30, 2024 and 2023, respectively, and 18.6% and 14.7% for the nine months ended September 30, 2024 and 2023, respectively. See Note 6 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the effective income tax rates.

DPL

Results of Operations — DPL

Three Months Ended September 30,Favorable (Unfavorable) VarianceNine Months Ended September 30,Favorable (Unfavorable) Variance
2024202320242023
Operating revenues$462$450$12$1,343$1,273$70
Operating expenses
Purchased power and fuel203201(2)573562(11)
Operating and maintenance9210412284278(6)
Depreciation and amortization6262—183182(1)
Taxes other than income taxes2019(1)5957(2)
Total operating expenses37738691,0991,079(20)
Operating income85642124419450
Other income and (deductions)
Interest expense, net(22)(18)(4)(69)(53)(16)
Other, net65120128
Total other income and (deductions)(16)(13)(3)(49)(41)(8)
Income before income taxes69511819515342
Income taxes148(6)3925(14)
Net income$55$43$12$156$128$28

Three Months Ended September 30, 2024 Compared to Three Months Ended September 30, 2023. Net income increased $12 million primarily due to higher Delaware electric distribution rates, and a decrease in storm costs, partially offset by unfavorable weather conditions at Delaware electric service territories.

Nine Months Ended September 30, 2024 Compared to Nine Months Ended September 30, 2024. Net income increased $28 million primarily due to higher Delaware electric distribution rates, favorable weather conditions at Delaware electric and natural gas service territories, and higher transmission rates, partially offset by an increase in interest expense.

The changes in Operating revenues consisted of the following:

Three Months Ended September 30, 2024Nine Months Ended September 30, 2024
(Decrease) IncreaseIncrease (Decrease)
ElectricGasTotalElectricGasTotal
Weather$(4)$—$(4)$5$4$9
Volume4—43—3
Distribution1211334337
Transmission(2)—(2)11—11
Other1—13—3
1111256763
Regulatory required programs2(2)—41(34)7
Total increase (decrease)$13$(1)$12$97$(27)$70

Revenue Decoupling. The demand for electricity is affected by weather and customer usage. However, Operating revenues from electric distribution in Maryland are not impacted by abnormal weather or usage per customer as a result of a BSA that provides for a fixed distribution charge per customer by customer class. While Operating revenues from electric distribution customers in Maryland are not impacted by abnormal weather or usage per customer, they are impacted by changes in the number of customers.

Weather. The demand for electricity and natural gas in Delaware is affected by weather conditions. With respect to the electric business, very warm weather in summer months and, with respect to the electric and natural gas businesses, very cold weather in winter months are referred to as "favorable weather conditions” because these

DPL

weather conditions result in increased deliveries of electricity and natural gas. Conversely, mild weather reduces demand. During the three months ended September 30, 2024 compared to the same period in 2023, Operating revenues related to weather decreased due to unfavorable weather conditions in Delaware electric service territories. During the nine months ended September 30, 2024 compared to the same period in 2023, Operating revenues related to weather increased due to favorable weather conditions in Delaware electric and natural gas service territories.

Heating and cooling degree days are quantitative indices that reflect the demand for energy needed to heat or cool a home or business. Normal weather is determined based on historical average heating and cooling degree days for a 20-year period in the Delaware electric service territory and a 30-year period in the Delaware natural gas service territory. The changes in heating and cooling degree days in the Delaware service territory for the three and nine months ended September 30, 2024, compared to same period in 2023 and normal weather consisted of the following:

Three Months Ended September 30,% Change
Delaware Electric Service Territory20242023Normal2024 vs. 20232024 vs. Normal
Heating Degree-Days133728(64.9)%(53.6)%
Cooling Degree-Days856996920(14.1)%(7.0)%
Nine Months Ended September 30,% Change
Delaware Electric Service Territory20242023Normal2024 vs. 20232024 vs. Normal
Heating Degree-Days2,6202,3062,92413.6%(10.4)%
Cooling Degree-Days1,2561,2491,2610.6%(0.4)%
Three Months Ended September 30,% Change
Delaware Natural Gas Service Territory20242023Normal2024 vs. 20232024 vs. Normal
Heating Degree-Days133735(64.9)%(62.9)%
Nine Months Ended September 30,% Change
Delaware Natural Gas Service Territory20242023Normal2024 vs. 20232024 vs. Normal
Heating Degree-Days2,6202,3062,99313.6%(12.5)%

Volume, exclusive of the effects of weather, increased for both the three and nine months ended September 30, 2024 compared to the same period in 2023, primarily due to an increase in customer usage and customer growth.

Electric Retail Deliveries to Delaware Customers (in GWhs)Three Months Ended September 30,% ChangeWeather - Normal % Change**(b)**Nine Months Ended September 30,% ChangeWeather - Normal % Change**(b)**
2024202320242023
Residential974995(2.1)%6.3%2,5292,4035.2%1.9%
Small commercial & industrial402405(0.7)%3.2%1,0941,0811.2%(0.3)%
Large commercial & industrial811849(4.5)%(2.7)%2,2852,349(2.7)%(3.1)%
Public authorities & electric railroads8714.3%12.4%2223(4.3)%(5.1)%
Total electric retail deliveries(a)2,1952,256(2.7)%2.3%5,9305,8561.3%(0.5)%

DPL

At September 30,
Number of Total Electric Customers (Maryland and Delaware)20242023
Residential489,634484,425
Small commercial & industrial64,62664,101
Large commercial & industrial1,2671,245
Public authorities & electric railroads598593
Total556,125550,364

(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,% ChangeWeather - Normal % Change**(b)**Nine Months Ended September 30,% ChangeWeather - Normal % Change**(b)**
2024202320242023
Residential397414(4.1)%4.1%5,1624,7818.0%(1.8)%
Small commercial & industrial343350(2.0)%2.9%2,5902,4943.8%(5.4)%
Large commercial & industrial4083817.1%7.1%1,2391,1666.3%6.3%
Transportation1,1901,1196.3%7.2%4,4914,3503.2%0.4%
Total natural gas deliveries(a)2,3382,2643.3%6.0%13,48212,7915.4%(1.2)%
At September 30,
Number of Delaware Natural Gas Customers20242023
Residential130,885129,436
Small commercial & industrial10,11010,039
Large commercial & industrial1414
Transportation161165
Total141,170139,654

(a)Reflects delivery volumes from customers purchasing natural gas directly from DPL and customers purchasing natural gas from a competitive natural gas supplier as all customers are assessed distribution charges.

(b)Reflects the change in delivery volumes assuming normalized weather based on the historical 30-year average.

Distribution Revenue increased for the three and nine months ended September 30, 2024 compared to the same period in 2023 primarily due to favorable impacts of the higher electric distribution rates in Delaware that became effective July 2023, and higher natural gas DSIC rates in Delaware that became effective in January 2024, partially offset by lower electric DSIC rates in Delaware that became effective in January 2024.

Transmission Revenue. Under a FERC-approved formula, transmission revenue varies from year to year based upon fluctuations in the underlying costs and capital investments being recovered. During the three months ended September 30, 2024 compared to the same period in 2023, transmission revenue remained relatively consistent. During the nine months ended September 30, 2024 compared to the same period in 2023, transmission revenue increased due to increases in underlying costs and capital investments.

Other Revenue includes rental revenue, service connection fees, and mutual assistance revenues.

Regulatory Required Programs represent revenues collected under approved riders to recover costs incurred for regulatory programs such as energy efficiency programs, DE Renewable Portfolio Standards, SOS procurement and administrative costs, and GCR costs. The riders are designed to provide full and current cost recovery as well as a return in certain instances. The costs of these programs are included in Purchased power and fuel expense, Operating and maintenance expense, Depreciation and amortization expense, and Taxes

DPL

other than income taxes. All customers have the choice to purchase electricity from competitive electric generation suppliers; however, only certain commercial and industrial customers have the choice to purchase natural gas from competitive natural gas suppliers. Customer choice programs do not impact the volume of deliveries as DPL remains the distribution service provider for all customers and charges a regulated rate for distribution service, which is recorded in Operating revenues. For customers that choose to purchase electric generation or natural gas from competitive suppliers, DPL either acts as the billing agent or the competitive supplier separately bills its own customers, and therefore does not record Operating revenues or Purchased power and fuel expense related to the electricity and/or natural gas. For customers that choose to purchase electric generation or natural gas from DPL, DPL is permitted to recover the electricity, natural gas, and REC procurement costs from customers and therefore records the amounts related to the electricity, natural gas, and RECs in Operating revenues and Purchased power and fuel expense. DPL recovers electricity and REC procurement costs from customers with a slight mark-up, and natural gas costs without mark-up.

See Note 4 — Segment Information of the Combined Notes to Consolidated Financial Statements for the presentation of DPL's revenue disaggregation.

The increase of $2 million and $11 million for the three and nine months ended September 30, 2024, compared to the same period in 2023, respectively, in Purchased power and fuel expense is fully offset in Operating revenues as part of regulatory required programs.

The changes in Operating and maintenance expense consisted of the following:

Three Months Ended September 30, 2024Nine Months Ended September 30, 2024
(Decrease) IncreaseIncrease (Decrease)
BSC and PHISCO costs$—$6
Labor and contracting(3)—
Pension and non-pension postretirement benefits expense(1)(1)
Credit loss expense(1)(2)
Storm-related Costs(8)(3)
Other(2)(1)
(15)(1)
Regulatory required programs (a)37
Total (decrease) increase$(12)$6

(a)Increase primarily due to the cost recovery associated with EmPOWER Maryland. Please refer to 2024 10-K Note 2 — Regulatory Matters for additional information

The changes in Depreciation and amortization expense consisted of the following:

Three Months Ended September 30, 2024Nine Months Ended September 30, 2024
Increase (Decrease)Increase (Decrease)
Depreciation and amortization(a)$3$6
Regulatory asset amortization—1
Regulatory required programs(3)(6)
Total increase$—$1

(a)Depreciation and amortization increased primarily due to ongoing capital expenditures.

Interest expense, net increased by $4 million and $16 million for the three and nine months ended September 30, 2024 compared to the same period in 2023, respectively, primarily due to an increase in interest rates and the issuance of debt in 2023 and 2024.

Other, net increased by $1 million and $8 million for the three and nine months ended September 30, 2024 compared to the same period in 2023, respectively, primarily due to higher AFUDC equity.

DPL

Effective income tax rates were 20.3% and 15.7% for the three months ended September 30, 2024 and 2023, respectively, and 20.0% and 16.3% for the nine months ended September 30, 2024 and 2023, respectively. See Note 6 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the effective income tax rates.

ACE

Results of Operations — ACE

Three Months Ended September 30,Favorable (Unfavorable) VarianceNine Months Ended September 30,Favorable (Unfavorable) Variance
2024202320242023
Operating revenues$540$502$38$1,280$1,172$108
Operating expenses
Purchased power245221(24)557493(64)
Operating and maintenance9694(2)274259(15)
Depreciation and amortization677710214212(2)
Taxes other than income taxes22—77—
Total operating expenses410394(16)1,052971(81)
Operating income1301082222820127
Other income and (deductions)
Interest expense, net(21)(19)(2)(59)(52)(7)
Other, net45(1)1213(1)
Total other income and (deductions)(17)(14)(3)(47)(39)(8)
Income before income taxes113941918116219
Income taxes3023(7)4840(8)
Net income$83$71$12$133$122$11

Three Months Ended September 30, 2024 Compared to Three Months Ended September 30, 2023. Net income increased by $12 million primarily due to higher distribution rates.

Nine Months Ended September 30, 2024 Compared to Nine Months Ended September 30, 2023. Net income increased by $11 million primarily due to higher distribution rates partially offset by increases in depreciation expense and interest expense.

The changes in Operating revenues consisted of the following:

Three Months Ended September 30, 2024Nine Months Ended September 30, 2024
IncreaseIncrease
Distribution$16$45
Transmission44
2049
Regulatory required programs1859
Total increase$38$108

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.

ACE

At September 30,
Number of Electric Customers20242023
Residential507,060504,330
Small commercial & industrial62,76162,410
Large commercial & industrial2,8482,980
Public authorities & electric railroads707729
Total573,376570,449

Distribution Revenue increased for the three and nine months ended September 30, 2024 compared to the same period in 2023 due to higher distribution rates that became effective December 2023 and the expiration of customer credits related to the TCJA tax benefits.

Transmission Revenues. Under a FERC-approved formula, transmission revenue varies from year to year based upon fluctuations in the underlying costs and capital investments being recovered. Transmission revenue increased for the three and nine months ended September 30, 2024 compared to the same period in 2023 due to increases in underlying costs and capital investments.

Other Revenue includes rental revenue, revenue related to late payment charges, mutual assistance revenues, and recoveries of other taxes.

Regulatory Required Programs represent revenues collected under approved riders to recover costs incurred for regulatory programs such as energy efficiency programs, Societal Benefits Charge, Transition Bond Charge, and BGS procurement and administrative costs. The riders are designed to provide full and current cost recovery as well as a return in certain instances. The costs of these programs are included in Purchased power expense, Operating and maintenance expense, Depreciation and amortization expense, and Taxes other than income taxes. Customers have the choice to purchase electricity from competitive electric generation suppliers. Customer choice programs do not impact the volume of deliveries, as ACE remains the distribution service provider for all customers and charges a regulated rate for distribution service, which is recorded in Operating revenues. For customers that choose to purchase electric generation from competitive suppliers, ACE acts as the billing agent and therefore, ACE does not record Operating revenues or Purchased power expense related to the electricity. For customers that choose to purchase electric generation from ACE, ACE is permitted to recover the electricity, ZEC, and REC procurement costs without mark-up and therefore records equal and offsetting amounts in Operating revenues and Purchased power expense related to the electricity, ZECs, and RECs.

See Note 4 — Segment Information of the Combined Notes to Consolidated Financial Statements for the presentation of ACE's revenue disaggregation.

The increase of $24 million and $64 million for the three and nine months ended September 30, 2024, respectively, compared to the same period in 2023 in Purchased power expense is fully offset in Operating revenues as part of regulatory required programs.

ACE

The changes in Operating and maintenance expense consisted of the following:

Three Months Ended September 30, 2024Nine Months Ended September 30, 2024
(Decrease) IncreaseIncrease (Decrease)
BSC and PHISCO costs$—$7
Labor and contracting(4)(6)
Storm-related costs(3)1
Other—2
(7)4
Regulatory required programs(a)911
Total increase$2$15

(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, 2024Nine Months Ended September 30, 2024
Increase (Decrease)Increase (Decrease)
Depreciation and amortization(a)$5$13
Regulatory asset amortization14
Regulatory required programs(16)(15)
Total (decrease) increase$(10)$2

(a)Depreciation and amortization increased primarily due to ongoing capital expenditures.

Interest expense, net increased $2 million and $7 million for the three and nine months ended September 30, 2024, respectively, compared to the same period in 2023 primarily due to increases in interest rates and the issuance of debt in 2023 and 2024.

Effective income tax rates were 26.5% and 24.5% for the three months ended September 30, 2024 and 2023, respectively, and 26.5% and 24.7% for the nine months ended September 30, 2024 and 2023, respectively. See Note 6 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the effective income tax rates.

Liquidity and Capital Resources (All Registrants)

All results included throughout the liquidity and capital resources section are presented on a GAAP basis.

The Registrants’ operating and capital expenditures requirements are provided by internally generated cash flows from operations, as well as funds from external sources in the capital markets and through bank borrowings. The Registrants’ businesses are capital intensive and require considerable capital resources. Each of the Registrants annually evaluates its financing plan, dividend practices, and credit line sizing, focusing on maintaining its investment grade ratings while meeting its cash needs to fund capital requirements, including construction expenditures, retire debt, pay dividends, and fund pension and OPEB obligations. The Registrants spend a significant amount of cash on capital improvements and construction projects that have a long-term return on investment. Additionally, the Utility Registrants operate in rate-regulated environments in which the amount of new investment recovery may be delayed or limited and where such recovery takes place over an extended period of time. Each Registrant’s access to external financing on reasonable terms depends on its credit ratings and current overall capital market business conditions, including that of the utility industry in general. If these conditions deteriorate to the extent that the Registrants no longer have access to the capital markets at reasonable terms, the Registrants have access to credit facilities with aggregate bank commitments of $4.0 billion. The Registrants utilize their credit facilities to support their commercial paper programs, provide for other short-term borrowings, and to issue letters of credit. See the “Credit Matters and Cash Requirements” section below for additional information. The Registrants expect cash flows to be sufficient to meet operating expenses, financing costs, and capital expenditure requirements. See Note 9 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information on the Registrants’ debt and credit agreements.

Cash Flows from Operating Activities

The Utility Registrants' cash flows from operating activities primarily result from the transmission and distribution of electricity and, in the case of PECO, BGE, and DPL, gas distribution services. The Utility Registrants' distribution services are provided to an established and diverse base of retail customers. The Utility Registrants' future cash flows may be affected by the economy, weather conditions, future legislative initiatives, future regulatory proceedings with respect to their rates or operations, and their ability to achieve operating cost reductions. Additionally, ComEd is required to purchase CMCs from participating nuclear-powered generating facilities for a five-year period that began in June 2022, and all of its costs of doing so will be recovered through a rider. The price to be paid for each CMC is established through a competitive bidding process. ComEd will provide net payments to, or collect net payments from, customers for the difference between customer credits issued and the credit to be received from the participating nuclear-powered generating facilities. ComEd’s cash flows are affected by the establishment of CMC prices and the timing of recovering costs through the CMC regulatory asset.

See Note 3 — Regulatory Matters of the 2023 Form 10-K and Notes 2 — Regulatory Matters and 11 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for additional information on regulatory and legal proceedings and proposed legislation.

The following table provides a summary of the change in cash flows from operating activities for the nine months ended September 30, 2024 and 2023 by Registrant:

Increase (decrease) in cash flows from operating activitiesExelonComEdPECOBGEPHIPepcoDPLACE
Net income (loss)$102$1$(54)$67$113$74$28$11
Adjustments to reconcile net income to cash:
Non-cash operating activities60544790(10)3(71)2762
Collateral received (paid), net204(7)—221922512245
Income taxes(68)(159)(131)(70)(92)(60)(40)(8)
Pension and non-pension postretirement benefit contributions(43)15(2)(19)(64)2(1)(6)
Regulatory assets and liabilities, net5896701682(156)(47)(74)(34)
Changes in working capital and other assets and liabilities(538)84(199)(68)7237(9)39
Increase (decrease) in cash flows from operating activities$851$1,051$(280)$4$68$(40)$53$109

Changes in the Registrants' cash flows from operations were generally consistent with changes in each Registrant’s respective results of operations, as adjusted by changes in working capital in the normal course of business, except as discussed below. Significant operating cash flow impacts for the Registrants for the nine months ended September 30, 2024 and 2023 were as follows:

  • See Note 14 — Supplemental Financial Information of the Combined Notes to Consolidated Financial Statements and the Registrants’ Consolidated Statements of Cash Flows for additional information on non-cash operating activities.

  • Changes in collateral depended upon whether the Registrant was in a net mark-to-market liability or asset position, and collateral may have been required to be posted with or collected from its counterparties. In addition, the collateral posting and collection requirements differed depending on whether the transactions were on an exchange or in the over-the-counter markets. Changes in collateral for the Registrants are dependent upon the credit exposure of procurement contracts that may require suppliers to post collateral. The change in Collateral received (paid), net, when comparing the nine months ended September 30, 2024 to the nine months ended September 30, 2023, is due to stable energy prices for the current year. See Note 8 — Derivative Financial Instruments for additional information.

  • See Note 6 — Income Taxes of the Combined Notes to Consolidated Financial Statements and the Registrants' Consolidated Statements of Cash Flows for additional information on income taxes.

  • Changes in Pension and non-pension postretirement benefit contributions relates to Exelon's increased contributions to the Qualified Plans during the nine months ended September 30, 2024. See Note 14 — Retirement Benefits of the 2023 Form 10-K for additional information.

  • Changes in regulatory assets and liabilities, net, are due to the timing of cash payments for costs recoverable, or cash receipts for costs recovered, under our regulatory mechanisms differing from the recovery period of those costs. Included within the changes is energy efficiency spend for ComEd of $266 million and $299 million for the nine months ended September 30, 2024 and 2023, respectively. Also included within the changes is energy efficiency and demand response programs spend for BGE, Pepco, DPL and ACE of $94 million, $34 million, $14 million, and $24 million for the nine months ended September 30, 2024 and $102 million, $49 million, $19 million, and $14 million for the nine months ended September 30, 2023, respectively. PECO had no energy efficiency and demand response programs spend recorded to the regulatory asset for the nine months ended September 30, 2024 and 2023. See Note 2 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.

  • Changes in working capital and other assets and liabilities for the Utility Registrants and Exelon Corporate totaled $(116) million and $(538) million, respectively. The change in working capital and other noncurrent assets and liabilities for Exelon Corporate and the Utility Registrants is dependent upon the normal course of operations for all Registrants. For ComEd, it is also dependent upon whether the participating nuclear-powered generating facilities are owed money from ComEd as a result of the established pricing for CMCs. For the nine months ended September 30, 2024, the established pricing resulted in ComEd owing payments to nuclear-powered generating facilities, which is reported within the cash flows from operations as a change in accounts payable and accrued expense.

Cash Flows from Investing Activities

The following table provides a summary of the change in cash flows from investing activities for the nine months ended September 30, 2024 and 2023 by Registrant:

Increase (decrease) in cash flows from investing activitiesExelonComEdPECOBGEPHIPepcoDPLACE
Capital expenditures$379$307$(57)$(47)$167$38$12$111
Proceeds from sales of assets and businesses38———————
Changes in intercompany money pool——(38)——710—
Other investing activities(16)—44(8)(8)——
Increase (decrease) in cash flows from investing activities$401$307$(91)$(43)$159$37$22$111

Significant investing cash flow impacts for the Registrants for nine months ended September 30, 2024 and 2023 were as follows:

  • Changes in capital expenditures are primarily due to the timing of cash expenditures for capital projects. See the "Credit Matters and Cash Requirements" section below for additional information on projected capital expenditure spending for the Utility Registrants.

  • Changes in intercompany money pool are driven by short-term borrowing needs. Refer to more information regarding the intercompany money pool below.

Cash Flows from Financing Activities

The following table provides a summary of the change in cash flows from financing activities for the nine months ended September 30, 2024 and 2023 by Registrant:

(Decrease) increase in cash flows from financing activitiesExelonComEdPECOBGEPHIPepcoDPLACE
Changes in short-term borrowings, net$(626)$(629)$74$13$65$216$52$(203)
Long-term debt, net(452)(425)50400(33)(75)1725
Changes in intercompany money pool————(8)——(17)
Issuance of common stock148———————
Dividends paid on common stock(68)(22)3(39)—(86)(65)11
Distributions to member————(139)———
Contributions from parent/member—(453)247—30(48)6120
Other financing activities21—(1)(2)37—(2)
(Decrease) increase in cash flows from financing activities$(977)$(1,529)$373$372$(82)$14$65$(166)

Significant financing cash flow impacts for the Registrants for the nine months ended September 30, 2024 and 2023 were as follows:

  • Changes in short-term borrowings, net**, is driven by repayments on and issuances of notes due in less than 365 days. See Note 9 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information on short-term borrowings for the Registrants.

  • Long-term debt, net**, varies due to debt issuances and redemptions each year. See Note 9 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information on debt issuances. Refer to the debt redemptions table below for additional information.

  • Changes in intercompany money pool** are driven by short-term borrowing needs. Refer below for more information regarding the intercompany money pool.

  • Issuance of common stock** relates to the August 2024 issuance of Exelon common stock. See Note 12 — Shareholders' Equity of the Combined Notes to Consolidated Financial Statements for additional information.

  • Exelon’s ability to pay dividends on its common stock depends on the receipt of dividends paid by its operating subsidiaries. The payments of dividends to Exelon by its subsidiaries in turn depend on their results of operations and cash flows and other items affecting retained earnings. See Note 18 — Commitments and Contingencies of the 2023 Form 10-K for additional information on dividend restrictions. See below for quarterly dividends declared.

Debt

See Note 9 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information on the Registrants’ debt issuances.

During the nine months ended September 30, 2024, the following long-term debt was retired and/or redeemed:

CompanyTypeInterest RateMaturityAmount
ExelonSMBC Term Loan AgreementSOFR plus 0.85%April 8, 2024$500
ExelonSoftware Licensing Agreement3.62%December 1, 2025$1
ExelonSoftware Licensing Agreement3.95%May 1, 2024$2
ComEdFirst Mortgage Bonds3.10%November 1, 2024$250
PepcoFirst Mortgage Bonds3.60%March 15, 2024$400
DPL(a)Unsecured tax-exempt bonds4.32%July 1, 2024$33
ACEFirst Mortgage Bonds3.38%September 1, 2024150

(a)Variable interest on the DPL unsecured tax-exempt bonds reset on a weekly basis.

Dividends

Quarterly dividends declared by the Exelon Board of Directors during the nine months ended September 30, 2024 and for the fourth quarter of 2024 were as follows:

PeriodDeclaration DateShareholder of Record DateDividend Payable DateCash per Share**(a)**
First Quarter 2024February 21, 2024March 4, 2024March 15, 2024$0.3800
Second Quarter 2024April 30, 2024May 13, 2024June 14, 2024$0.3800
Third Quarter 2024July 30, 2024August 12, 2024September 13, 2024$0.3800
Fourth Quarter 2024October 29, 2024November 11, 2024December 13, 2024$0.3800

(a)Exelon's Board of Directors approved an updated dividend policy for 2024. The 2024 quarterly dividend will be $0.38 per share.

Credit Matters and Cash Requirements

The Registrants fund liquidity needs for capital investment, working capital, energy hedging, and other financial commitments through cash flows from continuing operations, public debt offerings, commercial paper markets, and large, diversified credit facilities. The credit facilities include $4.0 billion in aggregate total commitments of which $3.4 billion was available to support additional commercial paper as of September 30, 2024, and of which no financial institution has more than 6.2% of the aggregate commitments for the Registrants. The Registrants had access to the commercial paper markets and had availability under their revolving credit facilities during the nine months ended September 30, 2024 to fund their short-term liquidity needs, when necessary. Exelon Corporate and the Utility Registrants each have a 5-year revolving credit facility. See Note 9 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information. The Registrants routinely review the sufficiency of their liquidity position, including appropriate sizing of credit facility commitments, by performing various stress test scenarios, such as commodity price movements, increases in margin-related transactions, changes in hedging levels, and the impacts of hypothetical credit downgrades. The Registrants have continued to closely monitor events in the financial markets and the financial institutions associated with the credit facilities, including monitoring credit ratings and outlooks, credit default swap levels, capital raising, and merger activity. See PART I. ITEM 1A. RISK FACTORS of the 2023 Form 10-K for additional information regarding the effects of uncertainty in the capital and credit markets.

The Registrants believe their cash flows from operating activities, access to credit markets, and their credit facilities provide sufficient liquidity to support the estimated future cash requirements.

On August 4, 2022, Exelon executed an equity distribution agreement (“Equity Distribution Agreement”), with certain sales agents and forward sellers and certain forward purchasers, establishing an ATM equity distribution program under which it may offer and sell shares of its common stock, having an aggregate gross sales price of up to $1.0 billion. Exelon has no obligation to offer or sell any shares of common stock under the Equity Distribution Agreement and may, at any time, suspend or terminate offers and sales under the Equity Distribution Agreement. In November and December 2023, Exelon issued approximately 3.6 million shares of common stock at an average gross price of $39.58 per share. In the third quarter 2024, Exelon issued approximately 4.0 million shares of Common Stock at an average gross price of $37.60 per share. The net proceeds from the fourth quarter 2023 issuances and third quarter 2024 issuances were $140 million and $147 million, respectively, which were used for general corporate purposes. As of September 30, 2024, $708 million of Common stock remained available for sale pursuant to the ATM program.

The following table presents the incremental collateral that each Utility Registrant would have been required to provide in the event each Utility Registrant lost its investment grade credit rating at September 30, 2024 and available credit facility capacity prior to any incremental collateral at September 30, 2024:

PJM Credit Policy CollateralOther Incremental Collateral Required**(a)**Available Credit Facility Capacity Prior to Any Incremental Collateral
ComEd$19$—$913
PECO—18596
BGE—37575
Pepco——249
DPL—9300
ACE——131

(a)Represents incremental collateral related to natural gas procurement contracts.

Capital Expenditure Spending

As of September 30, 2024, the most recent estimates of capital expenditures for plant additions and improvements for 2024 are as follows:

(In millions)TransmissionDistributionGasTotal**(a)**
ExelonN/AN/AN/A$7,450
ComEd4501,775N/A2,225
PECO1001,2003751,700
BGE3506755001,550
PHI5501,3251001,975
Pepco225750N/A975
DPL200300100625
ACE125275N/A400

(a)Numbers rounded to the nearest $25M and may not sum due to rounding.

Projected capital expenditures and other investments are subject to periodic review and revision to reflect changes in economic conditions and other factors.

Retirement Benefits

Management considers various factors when making pension funding decisions, including actuarially determined minimum contribution requirements under ERISA, contributions required to avoid benefit restrictions and at-risk status as defined by the Pension Protection Act of 2006 (the Act), management of the pension obligation, and regulatory implications. The Act requires the attainment of certain funding levels to avoid benefit restrictions (such as an inability to pay lump sums or to accrue benefits prospectively), and at-risk status (which triggers higher minimum contribution requirements and participant notification). The projected contributions reflect a funding strategy to make annual contributions with the objective of achieving 100% funded status on an ABO basis over time. This funding strategy helps minimize volatility of future period required pension contributions. Exelon’s estimated annual qualified pension contributions will be $93 million in 2024. Unlike the qualified pension plans, Exelon’s non-qualified pension plans are not funded, given that they are not subject to statutory minimum contribution requirements.

While OPEB plans are also not subject to statutory minimum contribution requirements, Exelon does fund certain of its plans. For Exelon's funded OPEB plans, contributions generally equal accounting costs, however, Exelon’s management has historically considered several factors in determining the level of contributions to its OPEB plans, including liabilities management, levels of benefit claims paid, and regulatory implications (amounts deemed prudent to meet regulatory expectations and best assure continued rate recovery).

To the extent interest rates decline significantly or the pension and OPEB plans earn less than the expected asset returns, annual pension contribution requirements in future years could increase. Conversely, to the extent interest rates increase significantly or the pension and OPEB plans earn greater than the expected asset returns, annual pension and OPEB contribution requirements in future years could decrease. Additionally, expected contributions could change if Exelon changes its pension or OPEB funding strategy.

See Note 14 — Retirement Benefits of the Combined Notes to Consolidated Financial Statements of the 2023 Form 10-K for additional information on pension and OPEB contributions.

Credit Facilities

Exelon Corporate, ComEd, and BGE meet their short-term liquidity requirements primarily through the issuance of commercial paper. PECO meets its short-term liquidity requirements primarily through the issuance of commercial paper and borrowings from the Exelon intercompany money pool. Pepco, DPL, and ACE meet their short-term liquidity requirements primarily through the issuance of commercial paper and borrowings from the PHI intercompany money pool. PHI Corporate meets its short-term liquidity requirements primarily through the issuance of short-term notes and the Exelon intercompany money pool. The Registrants may use their respective credit facilities for general corporate purposes, including meeting short-term funding requirements and the issuance of letters of credit.

See Note 9 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information on the Registrants’ credit facilities and short term borrowing activity.

Security Ratings

The Registrants’ access to the capital markets, including the commercial paper market, and their respective financing costs in those markets, may depend on the securities ratings of the entity that is accessing the capital markets.

The Registrants’ borrowings are not subject to default or prepayment as a result of a downgrading of securities, although such a downgrading of a Registrant’s securities could increase fees and interest charges under that Registrant’s credit agreements.

As part of the normal course of business, the Registrants enter into contracts that contain express provisions or otherwise permit the Registrants and their counterparties to demand adequate assurance of future performance when there are reasonable grounds for doing so. In accordance with the contracts and applicable contracts law, if the Registrants are downgraded by a credit rating agency, it is possible that a counterparty would attempt to rely on such a downgrade as a basis for making a demand for adequate assurance of future performance, which could include the posting of collateral. See Note 8 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information on collateral provisions.

The credit ratings for the Registrants did not change for the nine months ended September 30, 2024.

Intercompany Money Pool

To provide an additional short-term borrowing option that will generally be more favorable to the borrowing participants than the cost of external financing, both Exelon and PHI operate an intercompany money pool. Maximum amounts contributed to and borrowed from the money pool by participant and the net contribution or borrowing as of September 30, 2024, are presented in the following table:

During the Nine Months Ended September 30, 2024At September 30, 2024
Exelon Intercompany Money PoolMaximum ContributedMaximum BorrowedContributed (Borrowed)
Exelon Corporate$626$—$177
PECO241(255)89
BSC—(420)(236)
PHI Corporate—(86)(75)
PCI45—45
During the Nine Months Ended September 30, 2024At September 30, 2024
PHI Intercompany Money PoolMaximum ContributedMaximum BorrowedContributed (Borrowed)
Pepco$171$(35)$—
DPL130(33)—
ACE—(197)—

Shelf Registration Statements

As of January 1st, 2024 Exelon and the Utility Registrants had an effective combined shelf registration statement, unlimited in amount (“Legacy Registration Statement”). On February 20, 2024, Exelon Corporation filed with the SEC Post-Effective Amendment 1 to its Legacy Registration Statement to remove and withdraw registration of all registered securities of ACE, DPL, PECO and BGE.

On February 21, 2024, Exelon Corporation, together with Pepco and ComEd as co-registrants, filed with the SEC Post-Effective Amendment 2 to its Legacy Registration Statement. Post-Effective Amendment 2 amends the Legacy Registration Statement to include an authorized limit of $7,200 million, which can be used to issue Exelon Corporation debt securities and equity securities, as well as Pepco and ComEd debt securities, through the expiration date of August 3, 2025. The amended Legacy Registration Statement was declared effective by the SEC on April 30, 2024. On February 21, 2024, PECO and BGE filed with the SEC a standalone automatically effective shelf registration statement, unlimited in amount, which can be used to issue PECO and BGE debt

securities through the expiration date of February 20, 2027. The ability of Exelon Corporation, ComEd, Pepco, PECO and BGE to sell securities off their corresponding registration Statements, or to access the private placement markets, will depend on a number of factors at the time of the proposed sale, including other required regulatory approvals, as applicable, the current financial condition of the Registrant, its securities ratings and market conditions.

As a result of Post-Effect Amendment 1, DPL and ACE filed to deregister all securities that remain unsold. DPL and ACE periodically issue securities through the private placement markets. DPL and ACE's ability to access the private placement markets will depend on a number of factors at the time of the proposed sale, including other required regulatory approvals, as applicable, current financial condition, securities ratings and market conditions.

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, 2024
Short-term Financing AuthorityRemaining Long-term Financing Authority
CommissionExpiration DateAmountCommissionExpiration DateAmount
ComEdFERCDecember 31, 2025$2,500ICCJanuary 1, 2027 & May 1, 2027$2,318
PECO(c)FERCDecember 31, 20251,500PAPUCDecember 31, 2024—
BGEFERCDecember 31, 2025700MDPSCN/A300
Pepco(a)FERCDecember 31, 2025500MDPSC / DCPSCDecember 31, 2025375
DPL(a)FERCDecember 31, 2025500MDPSC / DEPSCDecember 31, 2025375
ACE(b)NJBPUDecember 31, 2025350NJBPUDecember 31, 2024375

(a)The financing authority filed with MDPSC does not have an expiration date, while the financing authority filed with DCPSC and DEPSC have an expiration date of December 31, 2025.

(b)On June 24, 2024, ACE filed an application with the NJBPU for renewal of their long-term financing authority through December 31, 2026. ACE expects approval of their application by December 31, 2024.

(c)On October 16, 2024, PECO filed an application for $3.5 billion with the PAPUC for a new long-term financing authority order through December 31, 2027. PECO expects approval of their application by December 31, 2024.

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