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 months ended March 31, 2024 compared to the same period in 2023. For additional information regarding the financial results for the three months ended March 31, 2024 and 2023, see the discussions of Results of Operations by Registrant.

Three Months Ended March 31,(Unfavorable) Favorable Variance
20242023
Exelon$658$669$(11)
ComEd193241(48)
PECO149166(17)
BGE26420064
PHI16815513
Pepco756510
DPL66606
ACE2933(4)
Other(a)(116)(93)(23)

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

Three Months Ended March 31, 2024 Compared to Three Months Ended March 31, 2023. Net income attributable to common shareholders decreased by $11 million and diluted earnings per average common share decreased to $0.66 in 2024 from $0.67 in 2023 primarily due to:

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

  • Higher storm costs at PECO and BGE;

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

  • Lower carrying costs related to the CMC regulatory assets at ComEd.

The decreases were partially offset by:

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  • The favorable impacts of rate increases at BGE and PHI; and

  • Less unfavorable weather impacts at PECO.

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

The following table provides a reconciliation between GAAP Net income attributable to common shareholders and Adjusted (non-GAAP) operating earnings for the three months ended March 31, 2024 compared to the same period in 2023:

Three Months Ended March 31,
20242023
(In millions, except per share data)Earnings per Diluted ShareEarnings per Diluted Share
Net income attributable to common shareholders$658$0.66$669$0.67
Mark-to-market impact of economic hedging activities (net of taxes of $0)——(1)—
Change in environmental liabilities (net of taxes of $7)——180.02
Separation costs (net of taxes of $0)(a)——(1)—
Change in FERC audit liability (net of taxes of $9 and $4, respectively )270.03110.01
Adjusted (non-GAAP) operating earnings$685$0.68$696$0.70

Note:

Amounts may not sum due to rounding.

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

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

Significant 2024 Transactions and Developments

Distribution Base Rate Case Proceedings

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

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

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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 - MarylandOctober 26, 2020 (amended March 31, 2021)Electric$104$529.55%June 28, 2021June 28, 2021
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

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Pending Distribution Base Rate Case Proceedings

Registrant/JurisdictionFiling DateServiceRequested Revenue Requirement IncreaseRequested ROEExpected Approval Timing
ComEd - IllinoisMarch 15, 2024Electric$6708.905%December 2024
April 26, 2024Electric$6279.89%December 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%Third quarter of 2024
Pepco - MarylandMay 16, 2023 (amended February 23, 2024)Electric$18610.50%Second quarter of 2024

Transmission Formula Rates

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

RegistrantInitial Revenue Requirement IncreaseAnnual Reconciliation (Decrease) IncreaseTotal Revenue Requirement IncreaseAllowed Return on Rate BaseAllowed ROE
ComEd$32$(12)$208.14%11.50%
BGE$42$13$537.47%10.50%

ComEd's FERC Audit

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

On July 27, 2023, FERC issued a final audit report which included, among other things, findings and recommendations related to ComEd's methodology regarding the allocation of certain overhead costs to capitalized construction costs under FERC regulations, including a suggestion that refunds may be due to customers for amounts collected in previous years. On August 28, 2023, ComEd filed a formal notice of the issues it will contest. On December 14, 2023, FERC appointed a settlement judge for the contested overhead allocation findings and set the matter for a trial-type hearing. That hearing process has been held in abeyance while a formal settlement process, which began in February 2024, takes place. Based on the preliminary findings and the ongoing settlement process, ComEd determined that a loss was probable and recorded its regulatory liability to reflect its best estimate of that loss. The final outcome and resolution of any contested audit issues as well as a reasonable estimate of potential future losses cannot be accurately estimated at this stage; however, the final resolution of these matters could result in recognition of future losses, above the amounts currently accrued, that could be material to the Exelon and ComEd financial statements.

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Other Key Business Drivers and Management Strategies

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

Legislative and Regulatory Developments

Infrastructure Investment and Jobs Act

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

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

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

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

In November 2023, the GDO announced up to $3.9 billion available through the second-round funding opportunity of the Grid Resilience and Innovation Partnerships (GRIP) Program for Fiscal Years 2024 and 2025. This funding opportunity focuses on projects that will improve electric transmission by increasing funding and advancing interconnection processes for faster build out of energy projects, create comprehensive solutions that

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link grid communications systems and operations to increase resilience and reduce power outages and threats, and deploy advanced technologies such as distributed energy resources and battery systems to provide essential grid services to ensure American communities across the country have access to affordable, reliable, clean electricity. In January 2024, Exelon, ComEd, BGE, PHI, Pepco, DPL, and ACE submitted seven concept papers in response to the second round of the GRIP program. The concept papers were focused on improving the resilience of the electric grid and deployment of technologies to enhance grid flexibility and deliver benefits to customers and communities across the Exelon footprint. Six of the seven concept papers submitted received notifications of encouragement to submit a full application. Exelon, BGE, PHI, Pepco, DPL, and ACE are in the process of evaluating the development and submission of final applications. Formal applications for Topic Area 1 (Grid Resilience) and Topic Area 3 (Grid Innovation) were due on April 17, 2024. ACE in coordination with the NJBPU Division of Clean Energy submitted an application for Topic Area 3 to expand DER hosting capacity through integrated grid enhancing technologies. Formal applications for Topic Area 2 (Smart Grid Grants) are due on May 22, 2024. The GDO is expected to announce award notification in the second half of 2024. Exelon, BGE, PHI, Pepco, DPL and ACE cannot predict if their applications will be selected for negotiation of a final award.

Critical Accounting Policies and Estimates

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

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Results of Operations by Registrant

Results of Operations — ComEd

Three Months Ended March 31,Favorable (Unfavorable) Variance
20242023
Operating revenues$2,095$1,667$428
Operating expenses
Purchased power907488(419)
Operating and maintenance418337(81)
Depreciation and amortization362338(24)
Taxes other than income taxes9493(1)
Total operating expenses1,7811,256(525)
Operating income314411(97)
Other income and (deductions)
Interest expense, net(122)(117)(5)
Other, net20182
Total other income and (deductions)(102)(99)(3)
Income before income taxes212312(100)
Income taxes197152
Net income$193$241$(48)

Three Months Ended March 31, 2024 Compared to Three Months Ended March 31, 2023. Net income decreased by $48 million as compared to the same period in 2023, primarily due to decreases in electric distribution earnings reflecting lower allowed ROE.

The changes in Operating revenues consisted of the following:

Three Months Ended March 31, 2024
Increase (Decrease)
Distribution$34
Transmission2
Energy efficiency20
Other(5)
51
Regulatory required programs377
Total increase$428

Revenue Decoupling. The demand for electricity is affected by weather and customer usage. Operating revenues are not impacted by abnormal weather, usage per customer, or number of customers as a result of revenue decoupling mechanisms.

Distribution Revenue. Distribution revenues were under a performance-based formula rate through 2023. Starting in 2024, distribution revenues are under a MRP. Both the performance-based formula rate and the MRP require annual reconciliations of the revenue requirement in effect to the actual costs that the ICC determines are prudently and reasonably incurred with certain limitations for the MRP reconciliations. Electric distribution revenue varies from year to year based upon fluctuations in the underlying costs, (e.g., severe weather and storm restoration), investments being recovered, and allowed ROE. Electric distribution revenue increased for the three months ended March 31, 2024 as compared to the same period in 2023, due to higher fully recoverable costs offset by lower allowed ROE.

Transmission Revenue. Under a FERC-approved formula, transmission revenue varies from year to year based upon fluctuations in the underlying costs, capital investments being recovered, and the highest daily peak

ComEd

load, which is updated annually in January based on the prior calendar year. Transmission revenue increased for the three months ended March 31, 2024 as compared to the same period in 2023, primarily due to higher peak load.

Energy Efficiency Revenue. Energy efficiency revenues are under a performance-based formula rate, which requires an annual reconciliation of the revenue requirement in effect to the actual costs that the ICC determines are prudently and reasonably incurred in a given year. Energy efficiency revenue varies from year to year based upon fluctuations in the underlying costs, investments being recovered, and allowed ROE. Energy efficiency revenue increased for the three months ended March 31, 2024 as compared to the same period in 2023, primarily due to increased regulatory asset amortization, which is fully recoverable.

Other Revenue primarily includes assistance provided to other utilities through mutual assistance programs. Other revenue decreased for the three months ended March 31, 2024 as compared to the same period in 2023, which primarily reflects less mutual assistance revenues associated with storm restoration efforts.

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

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

The increase of $419 million for the three months ended March 31, 2024 compared to the same period in 2023, in Purchased power expense is offset in Operating revenues as part of regulatory required programs.

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

Three Months Ended March 31, 2024
Increase
Labor, other benefits, contracting and materials$45
BSC costs17
Storm-related costs6
Pension and non-pension postretirement benefits expense6
Other3
77
Regulatory required programs(a)4
Total increase$81

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

ComEd

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

Three Months Ended March 31, 2024
Increase
Depreciation and amortization(a)$16
Regulatory asset amortization(b)8
Total increase$24

(a)Reflects ongoing capital expenditures.

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

Effective income tax rat****es were 9.0% and 22.8% for the three months ended March 31, 2024 and 2023, respectively. See Note 6 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the effective income tax rates.

PECO

Results of Operations — PECO

Three Months Ended March 31,(Unfavorable) Favorable Variance
20242023
Operating revenues$1,054$1,112$(58)
Operating expenses
Purchased power and fuel40348481
Operating and maintenance293270(23)
Depreciation and amortization10498(6)
Taxes other than income taxes5150(1)
Total operating expenses85190251
Gain on sales of assets2—2
Operating income205210(5)
Other income and (deductions)
Interest expense, net(55)(48)(7)
Other, net981
Total other income and (deductions)(46)(40)(6)
Income before income taxes159170(11)
Income taxes104(6)
Net income$149$166$(17)

Three Months Ended March 31, 2024 Compared to Three Months Ended March 31, 2023**.** Net inco****me decreased by $17 million, due to an increase in operating expenses as a result of higher storm costs and an increase in interest expense, partially offset by an increase in revenue as a result of less unfavorable weather impact relative to the same period last year.

The changes in Operating revenues consisted of the following:

Three Months Ended March 31, 2024
Increase (Decrease)
ElectricGasTotal
Weather$12$12$24
Volume(2)(2)(4)
Pricing134
Transmission8—8
Other(4)(3)(7)
151025
Regulatory required programs(30)(53)(83)
Total decrease$(15)$(43)$(58)

Weather. The demand for electricity and natural gas is affected by weather conditions. With respect to the electric business, very warm weather in summer months and, with respect to the electric and natural gas businesses, very cold weather in winter months are referred to as “favorable weather conditions” because these weather conditions result in increased deliveries of electricity and natural gas. Conversely, mild weather reduces demand. During the three months ended March 31, 2024 compared to the same period in 2023, Operating revenues related to weather increased due to less unfavorable weather conditions in PECO's service territory.

Heating and cooling degree-days are quantitative indices that reflect the demand for energy needed to heat or cool a home or business. Normal weather is determined based on historical average heating and cooling degree-days for a 30-year period in PECO's service territory. The changes in heating and cooling degree-days in

PECO

PECO’s service territory for the three months ended March 31, 2024 compared to the same period in 2023 and normal weather consisted of the following:

Three Months Ended March 31,% Change
PECO Service Territory20242023Normal2024 vs. 20232024 vs. Normal
Heating Degree-Days2,0891,8882,41010.6%(13.3)%
Cooling Degree-Days——1N/A(100.0)%

Volume. Electric volume, exclusive of the effects of weather, for the three months ended March 31, 2024 compared to the same period in 2023, remained relatively consistent. Natural gas volume for the three months ended March 31, 2024 compared to the same period in 2023, remained relatively consistent.

Electric Retail Deliveries to Customers (in GWhs)Three Months Ended March 31,% ChangeWeather - Normal % Change**(b)**
20242023
Residential3,4553,3582.9%(1.2)%
Small commercial & industrial1,8911,8432.6%(1.7)%
Large commercial & industrial3,3553,2373.6%2.5%
Public authorities & electric railroads1791686.5%7.1%
Total electric retail deliveries(a)8,8808,6063.2%0.2%
At March 31,
Number of Electric Customers20242023
Residential1,540,4911,529,779
Small commercial & industrial156,475155,846
Large commercial & industrial3,1603,118
Public authorities & electric railroads10,71310,401
Total1,710,8391,699,144

(a)Reflects delivery volumes from customers purchasing electricity directly from PECO and customers purchasing electricity from a competitive electric generation supplier as all customers are assessed distribution charges.

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

Natural Gas Deliveries to Customers (in mmcf)Three Months Ended March 31,% ChangeWeather - Normal % Change**(b)**
20242023
Residential18,89517,1909.9%0.6%
Small commercial & industrial9,4888,6999.1%(0.8)%
Large commercial & industrial1629(44.8)%(12.2)%
Transportation6,8997,014(1.6)%(3.0)%
Total natural gas retail deliveries(a)35,29832,9327.2%(0.5)%
At March 31,
Number of Natural Gas Customers20242023
Residential508,429504,181
Small commercial & industrial45,03845,003
Large commercial & industrial79
Transportation646650
Total554,120549,843

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

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

Pricing for the three months ended March 31, 2024 compared to the same period in 2023 remained relatively consistent.

PECO

Transmission Revenue. Under a FERC-approved formula, transmission revenue varies from year to year based upon fluctuations in the underlying costs and capital investments being recovered.

Other revenue primarily includes revenue related to late payment charges. Other revenue for the three months ended March 31, 2024 compared to the same period in 2023 remained relatively consistent.

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

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

The decrease of $81 million for the three months ended March 31, 2024 compared to the same period in 2023, in Purchased power and fuel expense is offset in Operating revenues as part of regulatory required programs.

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

Three Months Ended March 31, 2024
Increase (Decrease)
Storm-related costs$25
BSC costs7
Pension and non-pension postretirement benefit expense2
Labor, other benefits, contracting and materials(6)
Credit loss expense(10)
Other7
25
Regulatory required programs(2)
Total increase$23

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

Three Months Ended March 31, 2024
Increase
Depreciation and amortization(a)$6
Regulatory asset amortization—
Total increase$6

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

PECO

Interest expense, net increased $7 million for the three months ended March 31, 2024, compared to the same period in 2023, primarily due to an increase in interest rates and the issuance of debt in the second quarter of 2023.

Effective income tax rates were 6.3% and 2.4% for the three months ended March 31, 2024 and 2023, respectively, See Note 6 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the effective income tax rates.

BGE

Results of Operations — BGE

Three Months Ended March 31,Favorable (Unfavorable) Variance
20242023
Operating revenues$1,297$1,257$40
Operating expenses
Purchased power and fuel46449228
Operating and maintenance264222(42)
Depreciation and amortization15016717
Taxes other than income taxes8983(6)
Total operating expenses967964(3)
Operating income33029337
Other income and (deductions)
Interest expense, net(50)(44)(6)
Other, net835
Total other income and (deductions)(42)(41)(1)
Income before income taxes28825236
Income taxes245228
Net income$264$200$64

Three Months Ended March 31, 2024 Compared to Three Months Ended March 31, 2023. Net Income increased $64 million primarily due to favorable impacts of the multi-year plans, partially offset by an increase in storm costs, an increase in property tax expense, and an increase in interest expense. See Note 2 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information on the three-year electric and natural gas distribution multi-year plans.

The changes in Operating revenues consisted of the following:

Three Months Ended March 31, 2024
Increase (Decrease)
ElectricGasTotal
Distribution$23$44$67
Transmission(1)—(1)
Other(1)(2)(3)
214263
Regulatory required programs47(70)(23)
Total increase (decrease)$68$(28)$40

Revenue Decoupling. The demand for electricity and natural gas is affected by weather and customer usage. However, Operating revenues are not impacted by abnormal weather or usage per customer as a result of a monthly rate adjustment that provides for fixed distribution revenue per customer by customer class. While Operating revenues are not impacted by abnormal weather or usage per customer, they are impacted by changes in the number of customers.

At March 31,
Number of Electric Customers20242023
Residential1,213,0631,207,486
Small commercial & industrial115,406115,658
Large commercial & industrial13,11012,911
Public authorities & electric railroads261266
Total1,341,8401,336,321

BGE

At March 31,
Number of Natural Gas Customers20242023
Residential658,818656,583
Small commercial & industrial37,98238,260
Large commercial & industrial6,3366,261
Total703,136701,104

Distribution Revenue increased for the three months ended March 31, 2024, compared to the same period in 2023, due to favorable impacts of the multi-year plans.

Transmission Revenue. Under a FERC-approved formula, transmission revenue varies from year to year based upon fluctuations in the underlying costs and capital investments being recovered.Transmission revenue remained relatively the same for the three months ended March 31, 2024, compared to the same period in 2023.

Other Revenue includes revenue related to late payment, charges, mutual assistance, off-system sales, and service application fees. Other Revenue decreased for the three months ended March 31, 2024 compared to the same period in 2023.

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

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

The decrease of $28 million for the three months ended March 31, 2024 compared to the same period in 2023, in Purchased power and fuel expense is fully offset in Operating revenues as part of regulatory required programs.

BGE

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

Three Months Ended March 31, 2024
Increase (Decrease)
Storm-related costs10
BSC costs5
Credit loss expense(6)
Labor, other benefits, contracting, and materials(3)
6
Regulatory required programs(a)36
Total increase$42

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

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

Three Months Ended March 31, 2024
Increase (Decrease)
Depreciation and amortization$1
Regulatory required programs(a)(25)
Regulatory asset amortization7
Total decrease$(17)

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

Interest expense, net increased by $6 million for the three months ended March 31, 2024, respectively compared to the same period in 2023, primarily due to the issuance of debt during the second quarter of 2023.

Taxes other than income taxes increased by $6 million for the three months ended March 31, 2024, respectively, compared to the same period in 2023, primarily due to increased property taxes.

Effective income tax rates were 8.3% and 20.6% for the three months ended March 31, 2024 and 2023, respectively. See Note 6 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the effective income tax rates.

PHI

Results of Operations — PHI

PHI’s Results of Operations include the results of its three reportable segments, Pepco, DPL, and ACE. PHI also has a business services subsidiary, PHISCO, which provides a variety of support services, and the costs are directly charged or allocated to the applicable subsidiaries. Additionally, the results of PHI’s corporate operations include interest costs from various financing activities. All material intercompany accounts and transactions have been eliminated in consolidation. The following table sets forth PHI's GAAP consolidated Net income, by Registrant, for the three months ended March 31, 2024 compared to the same period in 2023. See the Results of Operations for Pepco, DPL, and ACE for additional information.

Three Months Ended March 31,Favorable (Unfavorable) Variance
20242023
PHI$168$155$13
Pepco756510
DPL66606
ACE2933(4)
Other(a)(2)(3)1

(a)Primarily includes eliminating and consolidating adjustments, PHI's corporate operations, shared service entities, and other financing and investment activities.

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

Pepco

Results of Operations — Pepco

Three Months Ended March 31,Favorable (Unfavorable) Variance
20242023
Operating revenues$759$710$49
Operating expenses
Purchased power281258(23)
Operating and maintenance150150—
Depreciation and amortization1071081
Taxes other than income taxes10294(8)
Total operating expenses640610(30)
Operating income11910019
Other income and (deductions)
Interest expense, net(45)(39)(6)
Other, net1516(1)
Total other income and (deductions)(30)(23)(7)
Income before income taxes897712
Income taxes1412(2)
Net income$75$65$10

Three Months Ended March 31, 2024 Compared to Three Months Ended March 31, 2023. Net Income increased by $10 million primarily due to the absence of an increase in environmental liabilities, favorable impacts of the Maryland multi-year plan, customer growth, and higher transmission rates, partially offset by an increase in interest expense, credit loss expense, and depreciation expense.

The changes in Operating revenues consisted of the following:

Three Months Ended March 31, 2024
Increase
Distribution$9
Transmission9
Other—
18
Regulatory required programs31
Total increase$49

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

At March 31,
Number of Electric Customers20242023
Residential869,606859,207
Small commercial & industrial54,17754,089
Large commercial & industrial22,99222,858
Public authorities & electric railroads207201
Total946,982936,355

Pepco

Distribution Revenue increased for the three months ended March 31, 2024 compared to the same period in 2023 primarily due to favorable impacts of the Maryland multi-year plan, and customer growth.

Transmission Revenue. Under a FERC-approved formula, transmission revenue varies from year to year based upon fluctuations in the underlying costs and capital investments being recovered. Transmission revenue increased for the three months ended March 31, 2024, compared to the same period in 2023, primarily due to increases in underlying costs and capital investment.

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

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

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

The increase of $23 million for the three months ended March 31, 2024 compared to the same period in 2023, in Purchased power expense is fully offset in Operating revenues as part of regulatory required programs.

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

Three Months Ended March 31, 2024
Increase (Decrease)
BSC and PHISCO costs$7
Credit loss expense7
Pension and non-pension postretirement benefits expense(1)
Labor, other benefits, contracting and materials(a)(22)
Other1
(8)
Regulatory required programs(b)8
Total increase$—

(a)Primarily reflects the absence of an increase in environmental liabilities for the three months ended March 31, 2024 compared to the same period in 2023.

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

Pepco

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

Three Months Ended March 31, 2024
Increase (Decrease)
Depreciation and amortization(a)$5
Regulatory asset amortization—
Regulatory required programs(6)
Total decrease$(1)

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

Taxes other than income taxes increased $8 million for the or the three months ended March 31, 2024 compared to the same period in 2023, primarily due to an increase in property taxes.

Interest expense, net increased by $6 million for the three months ended March 31, 2024 compared to the same period in 2023, primarily due to an increase in interest rates and the issuance of debt in 2023 and 2024.

Effective income tax rates were 15.7% and 15.6% for the three months ended March 31, 2024 and 2023, respectively. See Note 6 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the effective income tax rates.

DPL

Results of Operations — DPL

Three Months Ended March 31,Favorable (Unfavorable) Variance
20242023
Operating revenues$491$474$17
Operating expenses
Purchased power and fuel2152216
Operating and maintenance9587(8)
Depreciation and amortization6160(1)
Taxes other than income taxes2020—
Total operating expenses391388(3)
Operating income1008614
Other income and (deductions)
Interest expense, net(22)(17)(5)
Other, net532
Total other income and (deductions)(17)(14)(3)
Income before income taxes837211
Income taxes1712(5)
Net income$66$60$6

Three Months Ended March 31, 2024 Compared to Three Months Ended March 31, 2023. Net income increased $6 million primarily due to an increase in Delaware electric distribution rates, higher transmission rates, and favorable impacts of the Maryland multi-year plan, partially offset by an increase in interest expense.

The changes in Operating revenues consisted of the following:

Three Months Ended March 31, 2024
Increase (Decrease)
ElectricGasTotal
Weather$3$3$6
Volume(1)(1)(2)
Distribution10111
Transmission7—7
Other2—2
21324
Regulatory required programs21(28)(7)
Total increase (decrease)$42$(25)$17

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

Weather. The demand for electricity and natural gas in Delaware is affected by weather conditions. With respect to the electric business, very warm weather in summer months and, with respect to the electric and natural gas businesses, very cold weather in winter months are referred to as "favorable weather conditions” because these weather conditions result in increased deliveries of electricity and natural gas. Conversely, mild weather reduces demand. During the three months ended March 31, 2024, compared to the same period in 2023, Operating revenues related to weather increased due to favorable weather conditions in Delaware electric and natural gas service territories.

DPL

Heating and cooling degree days are quantitative indices that reflect the demand for energy needed to heat or cool a home or business. Normal weather is determined based on historical average heating and cooling degree days for a 20-year period in the Delaware electric service territory and a 30-year period in the Delaware natural gas service territory. The changes in heating and cooling degree days in the Delaware service territory for the three months ended March 31, 2024 compared to same period in 2023 and normal weather consisted of the following:

Three Months Ended March 31,% Change
Delaware Electric Service Territory20242023Normal2024 vs. 20232024 vs. Normal
Heating Degree-Days2,2041,9522,44712.9%(9.9)%
Cooling Degree-Days——1—%(100.0)%
Three Months Ended March 31,% Change
Delaware Natural Gas Service Territory20242023Normal2024 vs. 20232024 vs. Normal
Heating Degree-Days2,2041,9522,47612.9%(11.0)%

Volume, exclusive of the effects of weather, remained relatively consistent for the three months ended March 31, 2024 compared to the same period in 2023.

Electric Retail Deliveries to Delaware Customers (in GWhs)Three Months Ended March 31,% ChangeWeather - Normal % Change**(b)**
20242023
Residential8577977.5%(0.4)%
Small commercial & industrial3393273.7%(0.3)%
Large commercial & industrial718719(0.1)%(1.0)%
Public authorities & electric railroads79(22.2)%(24.7)%
Total electric retail deliveries(a)1,9211,8523.7%(0.7)%
At March 31,
Number of Total Electric Customers (Maryland and Delaware)20242023
Residential486,950482,979
Small commercial & industrial64,33863,794
Large commercial & industrial1,2601,236
Public authorities & electric railroads593595
Total553,141548,604

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

(b)Reflects the change in delivery volumes assuming normalized weather based on the historical 20-year average.

Natural Gas Retail Deliveries to Delaware Customers (in mmcf)Three Months Ended March 31,% ChangeWeather - Normal % Change**(b)**
20242023
Residential3,9133,5819.3%(1.2)%
Small commercial & industrial1,7171,6523.9%(6.8)%
Large commercial & industrial4284143.4%3.5%
Transportation1,9601,9003.2%(1.9)%
Total natural gas deliveries(a)8,0187,5476.2%(2.4)%

DPL

At March 31,
Number of Delaware Natural Gas Customers20242023
Residential130,427129,791
Small commercial & industrial10,18210,158
Large commercial & industrial1616
Transportation163158
Total140,788140,123

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

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

Distribution Revenue increased for the three months ended March 31, 2024 compared to the same period in 2023 primarily due to favorable impacts of the higher electric distribution rates in Delaware that became effective July 2023, favorable impacts of the Maryland multi-year plan that became effective in January 2024, and higher natural gas DSIC rates in Delaware that became effective in January 2024, partially offset by lower electric DSIC rates in Delaware that became effective in January 2024.

Transmission Revenue. Under a FERC-approved formula, transmission revenue varies from year to year based upon fluctuations in the underlying costs and capital investments being recovered. During the three months ended March 31, 2024 compared to the same period in 2023, transmission revenue increased primarily due to increases in underlying costs and capital investment.

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

Regulatory Required Programs represent revenues collected under approved riders to recover costs incurred for regulatory programs such as energy efficiency programs, DE Renewable Portfolio Standards, SOS procurement and administrative costs, and GCR costs. The riders are designed to provide full and current cost recovery as well as a return in certain instances. The costs of these programs are included in Purchased power and fuel expense, Operating and maintenance expense, Depreciation and amortization expense, and Taxes other than income taxes. All customers have the choice to purchase electricity from competitive electric generation suppliers; however, only certain commercial and industrial customers have the choice to purchase natural gas from competitive natural gas suppliers. Customer choice programs do not impact the volume of deliveries as DPL remains the distribution service provider for all customers and charges a regulated rate for distribution service, which is recorded in Operating revenues. For customers that choose to purchase electric generation or natural gas from competitive suppliers, DPL either acts as the billing agent or the competitive supplier separately bills its own customers, and therefore does not record Operating revenues or Purchased power and fuel expense related to the electricity and/or natural gas. For customers that choose to purchase electric generation or natural gas from DPL, DPL is permitted to recover the electricity, natural gas, and REC procurement costs from customers and therefore records the amounts related to the electricity, natural gas, and RECs in Operating revenues and Purchased power and fuel expense. DPL recovers electricity and REC procurement costs from customers with a slight mark-up, and natural gas costs without mark-up.

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

The decrease of $6 million for the three months ended March 31, 2024, compared to the same period in 2023, respectively, in Purchased power and fuel expense is fully offset in Operating revenues as part of regulatory required programs.

DPL

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

Three Months Ended March 31, 2024
Increase (Decrease)
Storm-related Costs$6
BSC and PHISCO costs3
Labor and contracting2
Credit loss expense(2)
Other(1)
8
Regulatory required programs—
Total increase$8

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

Three Months Ended March 31, 2024
Increase
Depreciation and amortization(a)$1
Regulatory required programs—
Regulatory asset amortization—
Total increase$1

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

Interest expense, net increased by $5 million for the three months ended March 31, 2024 compared to the same period in 2023, primarily due to an increase in interest rates and the issuance of debt in 2023 and 2024.

Effective income tax rates were 20.5% and 16.7% for the three months ended March 31, 2024 and 2023, respectively. See Note 6 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the effective income tax rates.

ACE

Results of Operations — ACE

Three Months Ended March 31,Favorable (Unfavorable) Variance
20242023
Operating revenues$358$353$5
Operating expenses
Purchased power1401488
Operating and maintenance8781(6)
Depreciation and amortization7467(7)
Taxes other than income taxes22—
Total operating expenses303298(5)
Operating income5555—
Other income and (deductions)
Interest expense, net(20)(16)(4)
Other, net55—
Total other income and (deductions)(15)(11)(4)
Income before income taxes4044(4)
Income taxes1111—
Net income$29$33$(4)

Three Months Ended March 31, 2024 Compared to Three Months Ended March 31, 2023. Net income decreased by $4 million primarily due to an increase in various operating expenses, depreciation expense, and interest expense, partially offset by an increase in distribution rates.

The changes in Operating revenues consisted of the following:

Three Months Ended March 31, 2024
Increase (Decrease)
Distribution$11
Transmission2
Other1
14
Regulatory required programs(9)
Total increase$5

Revenue Decoupling. The demand for electricity is affected by weather and customer usage. However, Operating revenues from electric distribution in New Jersey are not impacted by abnormal weather or usage per customer as a result of the CIP which became effective, prospectively, in the third quarter of 2021. The CIP compares current distribution revenues by customer class to approved target revenues established in ACE’s most recent distribution base rate case. The CIP is calculated annually, and recovery is subject to certain conditions, including an earnings test and ceilings on customer rate increases. While Operating revenues are not impacted by abnormal weather or usage per customer, they are impacted by changes in the number of customers.

ACE

At March 31,
Number of Electric Customers20242023
Residential505,793503,260
Small commercial & industrial62,70462,230
Large commercial & industrial2,8933,030
Public authorities & electric railroads728726
Total572,118569,246

Distribution Revenue increased for the three months ended March 31, 2024 compared to the same period in 2023 due to higher distribution rates that became effective December 2023 and the expiration of customer credits related to the TCJA tax benefits.

Transmission Revenues. Under a FERC-approved formula, transmission revenue varies from year to year based upon fluctuations in the underlying costs and capital investments being recovered. Transmission revenue increased for the three months ended March 31, 2024 compared to the same period in 2023, primarily due to increases in underlying costs and capital investment.

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

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

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

The decrease of $8 million for the three months ended March 31, 2024 compared to the same period in 2023, in Purchased power expense is fully offset in Operating revenues as part of regulatory required programs.

ACE

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

Three Months Ended March 31, 2024
Increase
BSC and PHISCO costs$3
Storm-related costs2
Other1
6
Regulatory required programs(a)—
Total increase$6

(a)ACE is allowed to recover from or refund to customers the difference between its annual credit loss expense and the amounts collected in rates annually through the Societal Benefits Charge.

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

Three Months Ended March 31, 2024
Increase
Depreciation and amortization(a)$5
Regulatory asset amortization2
Regulatory required programs—
Total increase$7

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

Interest expense, net increased $4 million for the year ended March 31, 2024 compared to the same period in 2023 primarily due to an increase in interest rates and the issuance of debt in 2023 and 2024.

Effective income tax rates were 27.5% and 25.0% for the three months ended March 31, 2024 and 2023, respectively. See Note 6 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the effective income tax rates.

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 three months ended March 31, 2024 and 2023 by Registrant:

Increase (decrease) in cash flows from operating activitiesExelonComEdPECOBGEPHIPepcoDPLACE
Net income (loss)$(11)$(48)$(17)$64$13$10$6$(4)
Adjustments to reconcile net income to cash:
Non-cash operating activities129115—(34)24(4)1719
Collateral received (paid), net22112—221892412045
Income taxes(2)6(1)—441(2)
Pension and non-pension postretirement benefit contributions(67)18(2)(17)(65)——(6)
Regulatory assets and liabilities, net576653(35)31(69)9(28)(50)
Changes in working capital and other assets and liabilities(338)(84)(72)(58)(63)(38)(6)(18)
Increase (decrease) in cash flows from operating activities$508$672$(127)$8$33$5$110$(16)

Changes in the Registrants' cash flows from operations were generally consistent with changes in each Registrant’s respective results of operations, as adjusted by changes in working capital in the normal course of business, except as discussed below. See above for additional information related to cash flows from Generation. Significant operating cash flow impacts for the Registrants and Generation for the three months ended March 31, 2024 and 2023 were as follows:

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

  • Changes in collateral depended upon whether the Registrant was in a net mark-to-market liability or asset position, and collateral may have been required to be posted with or collected from its counterparties. In addition, the collateral posting and collection requirements differed depending on whether the transactions were on an exchange or in the over-the-counter markets. Changes in collateral for the Registrants are dependent upon the credit exposure of procurement contracts that may require suppliers to post collateral. The change in Collateral received (paid), net, when comparing the three month ended March 31, 2024 to the three month ended March 31, 2023, is due to stable energy prices for the current year. See Note 8 — Derivative Financial Instruments for additional information.

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

  • Changes in Pension and non-pension postretirement benefit contributions relates to Exelon's increased contributions to the Qualified Plans during the three months ended March 31, 2024. See Note 14 — Retirement Benefits of the 2023 Form 10-K for additional information.

  • Changes in regulatory assets and liabilities, net, are due to the timing of cash payments for costs recoverable, or cash receipts for costs recovered, under our regulatory mechanisms differs from the recovery period of those costs. Included within the changes is energy efficiency spend for ComEd of $80 million and $72 million for the three months ended March 31, 2024 and 2023, respectively. Also included within the changes is energy efficiency and demand response programs spend for BGE, Pepco, DPL and ACE of $28 million, $10 million, $4 million, and $8 million for the three months ended March 31, 2024 and $33 million, $14 million, $5 million, and $4 million for the three months ended March 31, 2023, respectively. PECO had no energy efficiency and demand response programs spend recorded to the regulatory asset for the three months ended March 31,

2024 and 2023. See Note 2 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.

  • Changes in working capital and other assets and liabilities for the Utility Registrants and Exelon Corporate totaled $(276) million and $(338) million, respectively. The change in working capital and other noncurrent assets and liabilities for Exelon Corporate and the Utility Registrants is dependent upon the normal course of operations for all Registrants. For ComEd, it is also dependent upon whether the participating nuclear-powered generating facilities are owed money from ComEd as a result of the established pricing for CMCs. For the three months ended March 31, 2024, the established pricing resulted in ComEd owing payments to nuclear-powered generating facilities, which is reported within the cash flows from operations as a change in accounts payable and accrued expense.

Cash Flows from Investing Activities

The following table provides a summary of the change in cash flows from investing activities for the three months ended March 31, 2024 and 2023 by Registrant:

Increase (decrease) in cash flows from investing activitiesExelonComEdPECOBGEPHIPepcoDPLACE
Capital expenditures$114$23$(26)$26$108$35$—$72
Proceeds from sales of assets and businesses2———————
Changes in intercompany money pool—————(134)——
Other investing activities(12)—25(8)(8)——
Increase (decrease) in cash flows from investing activities$104$23$(24)$31$100$(107)$—$72

Significant investing cash flow impacts for the Registrants for three months ended March 31, 2024 and 2023 were as follows:

  • Changes in capital expenditures are primarily due to the timing of cash expenditures for capital projects. See the "Credit Matters and Cash Requirements" section below for additional information on projected capital expenditure spending for the Utility Registrants. See Note — Discontinued Operations of the Combined Notes to Consolidated Financial Statements for capital expenditures related to Generation prior to the separation.

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

Cash Flows from Financing Activities

The following table provides a summary of the change in cash flows from financing activities for the three months ended March 31, 2024 and 2023 by Registrant:

(Decrease) increase in cash flows from financing activitiesExelonComEdPECOBGEPHIPepcoDPLACE
Changes in short-term borrowings, net$963$296$(71)$235$20$167$52$(199)
Long-term debt, net(1,344)(975)——752550—
Changes in intercompany money pool———————134
Dividends paid on common stock(23)(7)1(12)—(3)(3)(1)
Distributions to member————(6)———
Contributions from parent/member—(147)250(237)8285518
Other financing activities612——(4)(1)(1)(1)
(Decrease) increase in cash flows from financing activities$(398)$(821)$180$(14)$167$196$153$(49)

Significant financing cash flow impacts for the Registrants for the three months ended March 31, 2024 and 2023 were as follows:

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

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

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

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

Debt

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

During the three months ended March 31, 2024, the following long-term debt was retired and/or redeemed:

CompanyTypeInterest RateMaturityAmount
ExelonSMBC Term Loan AgreementSOFR plus 0.85%April 8, 2024$500
ExelonSoftware Licensing Agreement3.62%December 1, 2025$1
PepcoFirst Mortgage Bonds3.60%March 15, 2024$400

Dividends

Quarterly dividends declared by the Exelon Board of Directors during the three months ended March 31, 2024 and for the second quarter of 2024 were as follows:

PeriodDeclaration DateShareholder of Record DateDividend Payable 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

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

Credit Matters and Cash Requirements

The Registrants fund liquidity needs for capital investment, working capital, energy hedging, and other financial commitments through cash flows from continuing operations, public debt offerings, commercial paper markets, and large, diversified credit facilities. The credit facilities include $4.0 billion in aggregate total commitments of which $2.7 billion was available to support additional commercial paper as of March 31, 2024, and of which no financial institution has more than 6% of the aggregate commitments for the Registrants. The Registrants had access to the commercial paper markets and had availability under their revolving credit facilities during the three months ended March 31, 2024 to fund their short-term liquidity needs, when necessary. Exelon Corporate and the Utility Registrants each have a 5-year revolving credit facility. See Note 9 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information. The Registrants routinely review the sufficiency of their liquidity position, including appropriate sizing of credit facility commitments, by performing various stress test scenarios, such as commodity price movements, increases in margin-related transactions, changes in hedging levels, and the impacts of hypothetical credit downgrades. The Registrants have continued to closely monitor events in the financial markets and the financial institutions associated with the credit facilities, including monitoring credit ratings and outlooks, credit default swap levels, capital raising, and merger activity. See PART I. ITEM 1A. RISK FACTORS of the 2023 Form 10-K for additional information regarding the effects of uncertainty in the capital and credit markets.

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

On August 4, 2022, Exelon executed an equity distribution agreement (“Equity Distribution Agreement”) with certain sales agents and forward sellers and certain forward purchasers establishing an ATM equity distribution program under which it may offer and sell shares of its common stock, having an aggregate gross sales price of up to $1.0 billion. Exelon has no obligation to offer or sell any shares of common stock under the Equity Distribution Agreement and may at any time suspend or terminate offers and sales under the Equity Distribution Agreement. As of December 31, 2023, $858 million of Common stock remained available for sale pursuant to the ATM program. For the period ended March 31, 2024, Exelon did not issue any shares of common stock under the ATM program and did not enter into any forward sale agreements.

The following table presents the incremental collateral that each Utility Registrant would have been required to provide in the event each Utility Registrant lost its investment grade credit rating at March 31, 2024 and available credit facility capacity prior to any incremental collateral at March 31, 2024:

PJM Credit Policy CollateralOther Incremental Collateral Required**(a)**Available Credit Facility Capacity Prior to Any Incremental Collateral
ComEd$—$—$660
PECO—27598
BGE—47188
Pepco——300
DPL—12300
ACE——300

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

Capital Expenditure Spending

As of March 31, 2024, the most recent estimates of capital expenditures for plant additions and improvements for 2024 are as follows:

(In millions)TransmissionDistributionGasTotal**(a)**
ExelonN/AN/AN/A$7,425
ComEd4751,675N/A2,150
PECO751,2254001,700
BGE4756255001,600
PHI5751,3251001,975
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 three months ended March 31, 2024.

Intercompany Money Pool

To provide an additional short-term borrowing option that will generally be more favorable to the borrowing participants than the cost of external financing, both Exelon and PHI operate an intercompany money pool. Maximum amounts contributed to and borrowed from the money pool by participant and the net contribution or borrowing as of March 31, 2024, are presented in the following table:

During the Three Months Ended March 31, 2024At March 31, 2024
Exelon Intercompany Money PoolMaximum ContributedMaximum BorrowedContributed (Borrowed)
Exelon Corporate$626$—$330
PECO55(255)—
BSC—(420)(302)
PHI Corporate—(86)(73)
PCI45—45
During the Three Months Ended March 31, 2024At March 31, 2024
PHI Intercompany Money PoolMaximum ContributedMaximum Borrowed(Borrowed) Contributed
Pepco$171$—$134
DPL—(33)—
ACE—(171)(134)

Shelf Registration Statements

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

On February 21, 2024, Exelon Corporation, together with Pepco and ComEd as co-registrants, filed with the SEC Post-Effective Amendment 2 to its Legacy Registration Statement. Post-Effective Amendment 2 amends the Legacy Registration Statement to include an authorized limit of $7,200 million, which can be used to issue Exelon Corporation debt securities and equity securities, as well as Pepco and ComEd debt securities, through the expiration date of August 3, 2025. On February 21, 2024, PECO and BGE filed with the SEC a standalone effective shelf registration statement, unlimited in amount, which can be used to issue PECO and BGE debt securities through the expiration date of February 20, 2027. The ability of Exelon Corporation, ComEd, Pepco,

PECO and BGE to sell securities off their corresponding registration Statements, or to access the private placement markets, will depend on a number of factors at the time of the proposed sale, including other required regulatory approvals, as applicable, the current financial condition of the Registrant, its securities ratings and market conditions.

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

Regulatory Authorizations

The Utility Registrants are required to obtain short-term and long-term financing authority from Federal and State Commissions as follows:

At March 31, 2024
Short-term Financing Authority (e)Remaining Long-term Financing Authority
CommissionExpiration DateAmountCommissionExpiration DateAmount
ComEd(a) (b)FERCDecember 31, 2025$2,500ICCJanuary 1, 2027$2,368
PECOFERCDecember 31, 20251,500PAPUCDecember 31, 2024550
BGE(c)FERCDecember 31, 2025700MDPSCN/A1,100
PepcoFERCDecember 31, 2025500MDPSC / DCPSCDecember 31, 2025375
DPLFERCDecember 31, 2025500MDPSC / DEPSCDecember 31, 2025375
ACENJBPUDecember 31, 2025350NJBPUDecember 31, 2024550

(a)On June 29, 2023, ComEd filed an application for $2 billion in new money long-term debt financing authority from the ICC and received approval on January 1, 2024.

(b)On February 20, 2024, ComEd filed an application for $750 million in refinancing authority from the ICC, which was approved on April 18, 2024. The refinancing authority under the approved application has an effective date of May 1, 2024, and extends the expiration date to May 1, 2027.

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

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