# EXELON CORP (EXC) FY 2023 MD&A Verbatim Item 7 Management's Discussion and Analysis from EXELON CORP's 10-K for fiscal year 2023. SEC filing source: https://www.sec.gov/Archives/edgar/data/1109357/000110935724000053/exc-20231231.htm Accession: 0001109357-24-000053 Filing date: 2024-02-21 Report date: 2023-12-31 Extracted structurally from real Item 7 body heading to real Item 7A/8 boundary. Confidence: high Company profile: /company/EXC/ All MD&A years: /company/EXC/mda/ Previous year: /company/EXC/mda/fy2022/ (FY 2022) Next year: /company/EXC/mda/fy2024/ (FY 2024) Item 7. 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 its six reportable segments: ComEd, PECO, BGE, Pepco, DPL, and ACE. See Note 1 — Significant Accounting Policies and Note 5 — Segment Information of the Combined Notes to Consolidated Financial Statements for additional information regarding Exelon's principal subsidiaries and reportable segments. Exelon’s consolidated financial information includes the results of its seven separate operating subsidiary registrants, ComEd, PECO, BGE, PHI, Pepco, DPL, and ACE, which, along with Exelon, are collectively referred to as the Registrants. The following combined Management’s Discussion and Analysis of Financial Condition and Results of Operations is separately filed by Exelon, ComEd, PECO, BGE, PHI, Pepco, DPL, and ACE. However, none of the Registrants makes any representation as to information related solely to any of the other Registrants. For discussion of the Utility Registrants' year ended December 31, 2022 compared to the year ended December 31, 2021, refer to ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS in the 2022 Form 10-K, which was filed with the SEC on February 14, 2023. COVID-19. There were no material impacts to the Registrants from unfavorable economic conditions due to COVID-19 for the years ended December 31, 2023 and 2022, other than the 2022 impairment discussed below. The Registrants assessed long-lived assets, goodwill, and investments for recoverability. Exelon and BGE recorded a pre-tax impairment charge of $48 million in 2022 as a result of COVID-19 impacts on office use. See Note 11 — Asset Impairments for additional information related to this impairment assessment. Financial Results of Operations GAAP Results of Operations. The following table sets forth Exelon's GAAP consolidated Net income attributable to common shareholders from continuing operations by Registrant for the year ended December 31, 2023 compared to the same period in 2022. For additional information regarding the financial results for the years ended December 31, 2023 and 2022, see the discussions of Results of Operations by Registrant. [[GREPCENT_TABLE]] [["","2023","","2022","","Favorable (Unfavorable) Variance"],["Exelon","$","2,328","","","$","2,054","","","$","274"],["ComEd","1,090","","","917","","","173"],["PECO","563","","","576","","","(13)"],["BGE","485","","","380","","","105"],["PHI","590","","","608","","","(18)"],["Pepco","306","","","305","","","1"],["DPL","177","","","169","","","8"],["ACE","120","","","148","","","(28)"],["Other(a)","(400)","","","(427)","","","27"]] [[/GREPCENT_TABLE]] __________ (a)Other primarily includes eliminating and consolidating adjustments, Exelon’s corporate operations, shared service entities, and other financing and investing activities. The separation of Constellation, including Generation and its subsidiaries, met the criteria for discontinued operations and as such, Generation's results of operations are presented as discontinued operations and have been excluded from Exelon's continuing operations for the year ended December 31, 2022 presented in the table 40 Table of Contents above. See Note 1 — Significant Accounting Policies and Note 2 — Discontinued Operations for additional information. Accounting rules require certain BSC costs previously allocated to Generation to be presented as part of Exelon’s continuing operations as these costs do not qualify as expenses of the discontinued operations. Such costs are included in Other in the table above and were $28 million on a pre-tax basis, for the year ended December 31, 2022. There were no such costs included in Exelon's continuing operations for the year ended December 31, 2023 Year Ended December 31, 2023 Compared to Year Ended December 31, 2022. Net income attributable to common shareholders from continuing operations increased by $274 million and Diluted earnings per average common share from continuing operations increased to $2.34 in 2023 from $2.08 in 2022 primarily due to: •Higher electric distribution and transmission earnings from higher allowed ROE due to an increase in treasury rates and higher rate base at ComEd; •Favorable impacts of rate increases at PECO, BGE, and PHI; •Favorable impacts of the multi-year plans including the recognition of the reconciliation in 2023 at BGE; •Higher carrying costs related to the CMC regulatory assets at ComEd; and •Lower BSC costs presented in Exelon’s continuing operations, which were previously allocated to Generation but do not qualify as expenses of the discontinued operation per the accounting rules. The increases were partially offset by: •Higher interest expense at PECO, BGE, PHI, and Exelon Corporate; •Unfavorable weather at PECO and PHI; •Higher depreciation expense at PECO, BGE, and PHI; •Higher contracting costs at PHI; •Higher storm costs at PECO and BGE; and •Higher realized losses from hedging activity at Exelon Corporate. 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 not considered by management to be 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. 41 Table of Contents The following table provides a reconciliation between Net income attributable to common shareholders from continuing operations as determined in accordance with GAAP and Adjusted (non-GAAP) operating earnings for the year ended December 31, 2023 compared to 2022:  [[GREPCENT_TABLE]] [["","2023","","2022"],["(In millions, except per share data)","","","Earnings per Diluted Share","","","","Earnings per Diluted Share"],["Net income attributable to common shareholders from continuing operations","$","2,328","","","$","2.34","","","$","2,054","","","$","2.08"],["Mark-to-market impact of economic hedging activities (net of taxes of $1 and $1, respectively)","(4)","","","\u2014","","","4","","","\u2014"],["Change in environmental liabilities (net of taxes of $8)","29","","","0.03","","","\u2014","","","\u2014"],["ERP system implementation costs (net of taxes of $0)(a)","\u2014","","","\u2014","","","1","","","\u2014"],["Asset retirement obligations (net of taxes of $1 and $2, respectively)","(1)","","","\u2014","","","(4)","","","\u2014"],["SEC matter loss contingency (net of taxes of $0)","46","","","0.05","","","\u2014","","","\u2014"],["Asset impairments (net of taxes of $10)(b)","\u2014","","","\u2014","","","38","","","0.04"],["Separation costs (net of taxes of $7 and $10, respectively)(c)","22","","","0.02","","","24","","","0.02"],["Change in FERC audit liability (net of taxes of $4)","11","","","0.01","","","\u2014","","","\u2014"],["Income tax-related adjustments (entire amount represents tax expense)(d)","(54)","","","(0.05)","","","122","","","0.12"],["Adjusted (non-GAAP) operating earnings","$","2,377","","","$","2.38","","","$","2,239","","","$","2.27"]] [[/GREPCENT_TABLE]] __________ Note: Amounts may not sum due to rounding. Unless otherwise noted, the income tax impact of each reconciling item between GAAP Net income and Adjusted (non-GAAP) operating earnings is based on the marginal statutory federal and state income tax rates for each Registrant, taking into account whether the income or expense item is taxable or deductible, respectively, in whole or in part. The marginal statutory income tax rates for 2023 and 2022 ranged from 24.0% to 29.0%. (a)Reflects costs related to a multi-year ERP system implementation, which are recorded in Operating and maintenance expense. (b)Reflects costs related to the impairment of an office building at BGE, which are recorded in Operating and maintenance expense. (c)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. (d)In 2022, for PECO, primarily reflects an adjustment to exclude one-time non-cash impacts associated with the remeasurement of deferred income taxes as a result of the reduction in Pennsylvania corporate income tax rate. For Corporate, in connection with the separation, Exelon recorded an income tax expense primarily due to the long-term marginal state income tax rate change, the recognition of valuation allowances against the net deferred tax assets positions for certain standalone state filing jurisdictions, and nondeductible transaction costs partially offset by a one-time impact associated with a state tax benefit. In 2023, reflects the adjustment to state deferred income taxes due to changes in forecasted apportionment. Significant 2023 Transactions and Developments Separation On February 21, 2021, Exelon’s Board of Directors approved a plan to separate the Utility Registrants and Generation, creating two publicly traded companies (“the separation”). Exelon completed the separation on February 1, 2022. Constellation was newly formed and incorporated in Pennsylvania on June 15, 2021 for the purpose of separation and holds Generation. The separation represented a strategic shift that would have a major effect on Exelon’s operations and financial results. Accordingly, the separation meets the criteria for discontinued operations. See Note 2 — Discontinued Operations of the Combined Notes to Consolidated Financial Statements for additional information on the separation and discontinued operations. 42 Table of Contents In connection with the separation, Exelon incurred separation costs impacting continuing operations of $29 million and $34 million on a pre-tax basis for the year ended December 31, 2023 and 2022, respectively, which are recorded in Operating and maintenance expense. These costs are excluded from Adjusted (non-GAAP) Operating Earnings. The separation costs are primarily comprised of system-related costs, third-party costs paid to advisors, consultants, lawyers, and other experts assisting in the separation, and employee-related severance costs. At-the-Market Program In November and December 2023, Exelon issued approximately 3.6 million shares of Common stock at an average gross price of $39.58 per share. The net proceeds from these issuances were $140 million, which were used for general corporate purposes. See Note 19 — Shareholders' Equity of the Combined Notes to Consolidated Financial Statements for additional information. Distribution Base Rate Case Proceedings The Utility Registrants file base rate cases with their regulatory commissions seeking increases or decreases to their electric transmission and distribution, and gas distribution rates to recover their costs and earn a fair return on their investments. The outcomes of these regulatory proceedings impact the Utility Registrants’ current and future financial statements. The following tables show the Utility Registrants’ completed and pending distribution base rate case proceedings in 2023. See Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information on these and other regulatory proceedings. 43 Table of Contents Completed Distribution Base Rate Case Proceedings [[GREPCENT_TABLE]] [["Registrant/Jurisdiction","","Filing Date","","Service","","Requested Revenue Requirement Increase","","Approved Revenue Requirement Increase","","Approved ROE","","Approval Date","","Rate Effective Date"],["ComEd - Illinois","","April 15, 2022","","Electric","","$","199","","","$","199","","","7.85%","","November 17, 2022","","January 1, 2023"],["","January 17, 2023","","Electric","","$","1,487","","","$","501","","","8.905%","","December 14, 2023","","January 1, 2024"],["","April 21, 2023","","Electric","","$","247","","","$","259","","","8.91%","","November 30, 2023","","January 1, 2024"],["PECO - Pennsylvania","","March 31, 2022","","Natural Gas","","$","82","","","$","55","","","N/A","","October 27, 2022","","January 1, 2023"],["BGE - Maryland","","May 15, 2020 (amended September 11, 2020)","","Electric","","$","203","","","$","140","","","9.50","%","","December 16, 2020","","January 1, 2021"],["","","Natural Gas","","$","108","","","$","74","","","9.65","%"],["","February 17, 2023","","Electric","","$","313","","","$","179","","","9.50%","","December 14, 2023","","January 1, 2024"],["","","Natural Gas","","$","289","","","$","229","","","9.45%"],["Pepco - Maryland","","October 26, 2020 (amended March 31, 2021)","","Electric","","$","104","","","$","52","","","9.55","%","","June 28, 2021","","June 28, 2021"],["DPL - Maryland","","May 19, 2022","","Electric","","$","38","","","$","29","","","9.60","%","","December 14, 2022","","January 1, 2023"],["ACE - New Jersey","","February 15, 2023 (amended August 21, 2023)","","Electric","","$","92","","","$","45","","","9.60","%","","November 17, 2023","","December 1, 2023"]] [[/GREPCENT_TABLE]] Pending Distribution Base Rate Case Proceedings [[GREPCENT_TABLE]] [["Registrant/Jurisdiction","","Filing Date","","Service","","Requested Revenue Requirement Increase","","Requested ROE","","Expected Approval Timing"],["Pepco - District of Columbia","","April 13, 2023","","Electric","","$","191","","","10.50%","","Third quarter of 2024"],["Pepco - Maryland","","May 16, 2023 (amended January 26, 2024)","","Electric","","$","188","","","10.50%","","Second quarter of 2024"],["DPL - Delaware","","December 15, 2022 (amended September 29, 2023)","","Electric","","$","39","","","10.50%","","Second quarter of 2024"]] [[/GREPCENT_TABLE]] 44 Table of Contents Transmission Formula Rates The following total increases/(decreases) were included in the Utility Registrants' 2023 annual electric transmission formula rate updates. All rates are effective June 1, 2023 to May 31, 2024, subject to review by interested parties pursuant to review protocols of each Utility Registrants' tariff. See Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information. [[GREPCENT_TABLE]] [["Registrant","","Initial Revenue Requirement Increase","","Annual Reconciliation Increase (Decrease)","","Total Revenue Requirement Increase","","Allowed Return on Rate Base","","Allowed ROE"],["ComEd","","$","20","","","$","63","","","$","83","","","8.09","%","","11.50","%"],["PECO","","$","24","","","$","23","","","$","47","","","7.41","%","","10.35","%"],["BGE","","$","19","","","$","(12)","","","$","4","","","7.34","%","","10.50","%"],["Pepco","","$","37","","","$","(5)","","","$","32","","","7.57","%","","10.50","%"],["DPL","","$","32","","","$","(3)","","","$","29","","","7.08","%","","10.50","%"],["ACE","","$","41","","","$","(12)","","","$","29","","","7.08","%","","10.50","%"]] [[/GREPCENT_TABLE]] 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. During the first quarter of 2023, ComEd was provided with information from FERC about several potential findings, including ComEd's methodology regarding the allocation of certain overhead costs to capital under FERC regulations. Based on the preliminary findings and discussions with FERC staff, ComEd determined that a loss was probable and recorded a regulatory liability to reflect its best estimate of that loss in the first quarter of 2023. On July 27, 2023, FERC issued a final audit report which included, among other things, findings and recommendations related to ComEd's methodology regarding the allocation of certain overhead costs to capitalized construction costs under FERC regulations, 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. 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. ACE Employee Strike ACE’s collective bargaining agreement with the International Brotherhood of Electrical Workers (IBEW) Local 210, expired on November 2, 2023. On November 5, 2023, IBEW Local 210 initiated a strike in ACE’s service territory. While the work stoppage did not result in a disruption in service to customers, Exelon, PHI, and ACE incurred unfavorable impacts to Net income of approximately $31 million, $31 million, and $32 million for the year ended December 31, 2023. On December 5, 2023, IBEW Local 210 ratified a new collective bargaining agreement with ACE and ceased the work stoppage. Other Key Business Drivers and Management Strategies Utility Rates and Rate Proceedings The Utility Registrants file 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 45 Table of Contents results of operations, cash flows, and financial positions. See Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information on these regulatory proceedings. 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 September 2022, ComEd and BGE applied for the MMG, which establishes and funds construction, improvement, or acquisition of middle mile broadband infrastructure which creates high-speed internet services. The MMG addresses inequitable broadband access by expansion and extension of the middle mile infrastructure in underserved communities. In June 2023, the National Telecommunications and Information Administration (NTIA) announced it selected two of the applications submitted by BGE and ComEd; awarding ComEd and BGE $14.5 million and $15.4 million respectively. The applications selected by NTIA for BGE and ComEd proposed projects designed to enhance electric grid reliability and resiliency while leading and advancing shared local, state, and national goals to increase broadband connectivity, redundancy, affordability, and equity. In March 2023, Exelon, ComEd, and PHI submitted three applications related to the Smart Grid Grants program under section 40107 of IIJA. These applications are focused on replacing existing Advanced Distribution Management Systems (ADMS) in support of distributed energy resources (DERs) and grid-edged technologies, strengthening interoperability and data architecture of systems in support of two-way power flows and accelerating advanced metering deployment in disadvantaged communities. In October 2023, ComEd’s project, Deployment of a Community-Oriented Interoperable Control Framework for Aggregating and Integrating Distributed Energy Resources and Other Grid-Edge Devices, was recommended by the Grid Deployment Office (GDO) for negotiation of a final award up to $50 million. This project will enable ComEd and its local partners to deploy the next generation of grid technologies that support the growth of solar and electric vehicles (EVs), while piloting new local workforce training initiatives to support job creation connected to the clean energy transition. The GDO has indicated the award negotiation process can take approximately 120 days. In April 2023, ComEd, PECO, BGE, and PHI submitted seven applications related to the Grid Resilience Grants program under section 40101(c) of IIJA. These applications are broadly focused on improving grid resilience with an emphasis on disadvantaged communities, relief of capacity constraints and modernizing infrastructure, deployment of DER and microgrid technologies and providing improved resilience through storm hardening projects. In October 2023, PECO’s project, Creating a Resilient, Equitable, and Accessible Transformation in Energy for Greater Philadelphia (CREATE), was recommended by the GDO for negotiation of a final award up to $100 million. This project will support critical electric infrastructure investments to help reduce the impact of extreme weather and historic flooding on the Registrants' electric distribution system. The GDO has indicated the award negotiation process can take approximately 120 days. The Registrants are supporting three different Regional Clean Hydrogen Hub opportunities, covering all five states that Exelon operates in plus Washington D.C. under a program that will create networks of hydrogen producers, consumers, and local connective infrastructure to accelerate the use of hydrogen as a clean energy carrier that can deliver or store energy. Applications for the three opportunities under this program were submitted in April 2023. In October 2023 the DOE announced it selected two of the projects for further negotiation: (1) the Mid-Atlantic Clean Hydrogen Hub (MACH2), which is being supported by PECO and PHI, and (2) the Midwest Alliance for Clean Hydrogen (MachH2), which is being supported by ComEd. 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 46 Table of Contents 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. 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 are 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. The GDO is expected to issue notifications of encouragement/discouragement for full applications in the first quarter of 2024. Exelon cannot predict if their concept papers will receive a notification of encouragement to submit a full application. PJM Regional Transmission Expansion On April 6, 2023, PJM received a deactivation notice for Brandon Shores, a 1,282 MW coal generation plant located in BGE service territory. The deactivation was requested for June 1, 2025 and will result in numerous reliability issues across the region. In June 2023, PJM assigned a portion of transmission system upgrades to mitigate these reliability impacts to PECO, BGE, and Pepco. In July 2023, PJM Board of Managers approved assigning Exelon transmission system upgrades to mitigate these reliability impacts to PECO, BGE, and Pepco. The initial projected capital expenditures associated with these upgrades are approximately $80 million, $650 million, and $80 million for PECO, BGE, and Pepco, respectively. These amounts include a scope reduction estimated by PJM for PECO of $60 million associated with a transmission proposal window, as disclosed at a Transmission Expansion Advisory Committee meeting on October 31, 2023. The upgrades are expected to be completed by the end of 2028. Separately, PJM held a competitive transmission proposal window from February 24, 2023 through May 31, 2023 to address reliability issues driven by significant load increases in northern Virginia. PECO, BGE, and Pepco submitted four solution proposals. At a meeting of the Transmission Expansion Advisory Committee on October 31, 2023, PJM recommended that PECO, BGE, Pepco, and DPL be awarded a portion of the work for the proposed solution. Initial estimated costs for these upgrades are approximately $70 million, $700 million, $80 million, and $5 million for PECO, BGE, Pepco, and DPL, respectively. The PJM Board of Managers approved the solution in December 2023 and the upgrades are expected to be completed by the end of 2030. Critical Accounting Policies and Estimates The preparation of financial statements in conformity with GAAP requires that management apply accounting policies and make estimates and assumptions that affect results of operations and the amounts of assets and liabilities reported in the financial statements. Management believes that the accounting policies described below require significant judgment in their application or incorporate estimates and assumptions that are inherently uncertain and that may change in subsequent periods. Additional information on the application of these accounting policies can be found in the Combined Notes to Consolidated Financial Statements. Goodwill (Exelon, ComEd, and PHI) As of December 31, 2023, Exelon’s $6.6 billion carrying amount of goodwill consists of $2.6 billion at ComEd and $4 billion at PHI. These entities are required to perform an assessment for possible impairment of their goodwill at least annually or more frequently if an event occurs or circumstances change that would more likely than not reduce the fair value of the reporting units below their carrying amount. A reporting unit is an operating segment or one level below an operating segment (known as a component) and is the level at which goodwill is assessed for impairment. ComEd has a single operating segment and reporting unit. PHI’s operating segments and reporting units are Pepco, DPL, and ACE. See Note 5 — Segment Information of the Combined Notes to Consolidated Financial Statements for additional information. Exelon's and ComEd’s goodwill has been assigned entirely to the ComEd reporting unit. Exelon's and PHI’s goodwill has been assigned to the Pepco, DPL, and ACE reporting units in the amounts of $2.1 billion, $1.4 billion, and $0.5 billion, respectively. See Note 12 — Intangible Assets of the Combined Notes to Consolidated Financial Statements for additional information. Entities assessing goodwill for impairment have the option of first performing a qualitative assessment to determine whether a quantitative assessment is necessary. As part of the qualitative assessments, Exelon, ComEd, and PHI evaluate, among other things, management's best estimate of projected operating and capital cash flows for their businesses, outcomes of recent regulatory proceedings, changes in certain market 47 Table of Contents conditions, including the discount rate and regulated utility peer EBITDA multiples, and the passing margin from their last quantitative assessments performed. Application of the goodwill impairment assessment requires management judgment, including the identification of reporting units and determining the fair value of the reporting unit, which management estimates using a weighted combination of a discounted cash flow analysis and a market multiples analysis. Significant assumptions used in these fair value analyses include discount and growth rates, utility sector market performance and transactions, and projected operating and capital cash flows for ComEd’s, Pepco's, DPL's, and ACE's businesses and the fair value of debt. While the 2023 annual assessments indicated no impairments, certain assumptions used in the assessment are highly sensitive to changes. Adverse regulatory actions or changes in significant assumptions could potentially result in future impairments of Exelon’s, ComEd's, or PHI’s goodwill, which could be material. See Note 1 — Significant Accounting Policies and Note 12 — Intangible Assets of the Combined Notes to Consolidated Financial Statements for additional information. Unamortized Energy Contract Liabilities (Exelon and PHI) Unamortized energy contract liabilities represent the remaining unamortized balances of non-derivative electricity contracts that Exelon acquired as part of the PHI merger. The initial amount recorded represents the difference between the fair value of the contracts at the time of acquisition and the contract value based on the terms of each contract. Offsetting regulatory assets were also recorded for those energy contract costs that are probable of recovery through customer rates. The unamortized energy contract liabilities and the corresponding regulatory assets, respectively, are amortized over the life of the contract in relation to the expected realization of the underlying cash flows. Amortization of the unamortized energy contract liabilities are recorded through Purchased power and fuel expense. See Note 3 — Regulatory Matters and Note 12 — Intangible Assets of the Combined Notes to Consolidated Financial Statements for additional information. Depreciable Lives of Property, Plant, and Equipment (All Registrants) The Registrants have significant investments in electric and natural gas transmission and distribution assets. These assets are generally depreciated on a straight-line basis, using the group, or composite methods of depreciation. The group approach is typically for groups of similar assets that have approximately the same useful lives and the composite approach is used for heterogeneous assets that have different lives. Under both methods, a reporting entity depreciates the assets over the average life of the assets in the group. The estimation of asset useful lives requires management judgment, supported by formal depreciation studies of historical asset retirement experience. Depreciation studies are conducted periodically and as required by a rate regulator or regulatory action, or changes in retirement patterns indicate an update is necessary. Depreciation studies generally serve as the basis for amounts allowed in customer rates for recovery of depreciation costs. Generally, the Registrants adjust their depreciation rates for financial reporting purposes concurrent with adjustments to depreciation rates reflected in customer rates, unless the depreciation rates reflected in customer rates do not align with management’s judgment as to an appropriate estimated useful life or have not been updated on a timely basis. Depreciation expense and customer rates for ComEd, BGE, Pepco, DPL, and ACE include an estimate of the future costs of dismantling and removing plant from service upon retirement. See Note 3 — Regulatory Matters of the Combined Notes to the Consolidated Financial Statements for information regarding regulatory liabilities and assets recorded by ComEd, BGE, Pepco, DPL, and ACE related to removal costs. PECO’s removal costs are capitalized to accumulated depreciation when incurred and recorded to depreciation expense over the life of the new asset constructed consistent with PECO’s regulatory recovery method. Estimates for such removal costs are also evaluated in the periodic depreciation studies. Changes in estimated useful lives of electric and natural gas transmission and distribution assets could have a significant impact on the Registrants’ future results of operations. See Note 1 — Significant Accounting Policies of the Combined Notes to Consolidated Financial Statements for information regarding depreciation and estimated service lives of the property, plant, and equipment of the Registrants. 48 Table of Contents Retirement Benefits (All Registrants) Exelon sponsors defined benefit pension plans and OPEB plans. The measurement of the plan obligations and costs of providing benefits involves various factors, including the development of valuation assumptions and inputs and accounting policy elections. When developing the required assumptions, Exelon considers historical information as well as future expectations. The measurement of benefit obligations and costs is affected by several assumptions including the discount rate, the long-term expected rate of return on plan assets, the anticipated rate of increase of health care costs, Exelon's contributions, the rate of compensation increases, and the long-term expected investment rate credited to employees of certain plans, among others. The assumptions are updated annually and upon any interim remeasurement of the plan obligations. Pension and OPEB plan assets include cash and cash equivalents, equity securities, including U.S. and international securities, and fixed income securities, as well as certain alternative investment classes such as real estate, private equity, private credit, and hedge funds. Expected Rate of Return on Plan Assets. In determining the EROA, Exelon considers historical economic indicators (including inflation and GDP growth) that impact asset returns, as well as expectation regarding future long-term capital market performance, weighted by Exelon’s target asset class allocations. Exelon calculates the amount of expected return on pension and OPEB plan assets by multiplying the EROA by the MRV of plan assets at the beginning of the year, taking into consideration anticipated contributions and benefit payments to be made during the year. In determining MRV, the authoritative guidance for pensions and postretirement benefits allows the use of either fair value or a calculated value that recognizes changes in fair value in a systematic and rational manner over not more than five years. For the majority of pension plan assets, Exelon uses a calculated value that adjusts for 20% of the difference between fair value and expected MRV of plan assets. Use of this calculated value approach enables less volatile expected asset returns to be recognized as a component of pension cost from year to year. For OPEB plan assets and certain pension plan assets, Exelon uses fair value to calculate the MRV. Discount Rate. The discount rates are determined by developing a spot rate curve based on the yield to maturity of a universe of high-quality non-callable (or callable with make whole provisions) bonds with similar maturities to the related pension and OPEB obligations. The spot rates are used to discount the estimated future benefit distribution amounts under the pension and OPEB plans. The discount rate is the single level rate that produces the same result as the spot rate curve. Exelon utilizes an analytical tool developed by its actuaries to determine the discount rates. Mortality. The mortality assumption is composed of a base table that represents the current expectation of life expectancy of the population adjusted by an improvement scale that attempts to anticipate future improvements in life expectancy. Exelon’s mortality assumption utilizes the SOA 2019 base table (Pri-2012) and MP-2021 improvement scale adjusted to use Proxy SSA ultimate improvement rates. 49 Table of Contents Sensitivity to Changes in Key Assumptions. The following tables illustrate the effects of changing certain of the actuarial assumptions discussed above, while holding all other assumptions constant: [[GREPCENT_TABLE]] [["","Actual Assumption","","","","(Decrease) Increase"],["Actuarial Assumption","Pension","","OPEB","","Change in Assumption","","Pension","","OPEB","","Total"],["Change in 2023 cost:"],["Discount rate(a)","5.53%","","5.51%","","0.5%","","$","(17)","","","$","(2)","","","$","(19)"],["","5.53%","","5.51%","","(0.5)%","","$","21","","","$","2","","","$","23"],["EROA","7.00%","","6.50%","","0.5%","","$","(54)","","","$","(6)","","","$","(60)"],["","7.00%","","6.50%","","(0.5)%","","$","54","","","$","6","","","$","60"],["Change in benefit obligation at December 31, 2023:"],["Discount rate(a)","5.19%","","5.17%","","0.5%","","$","(449)","","","$","(82)","","","$","(531)"],["","5.19%","","5.17%","","(0.5)%","","$","513","","","$","92","","","$","605"]] [[/GREPCENT_TABLE]] __________ (a)In general, the discount rate will have a larger impact on the pension and OPEB cost and obligation as the rate moves closer to 0%. Therefore, the discount rate sensitivities above cannot necessarily be extrapolated for larger increases or decreases in the discount rate. Additionally, Exelon utilizes a liability-driven investment strategy for its pension asset portfolio. The sensitivities shown above do not reflect the offsetting impact that changes in discount rates may have on pension asset returns. See Note 1 — Significant Accounting Policies and Note 14 — Retirement Benefits of the Combined Notes to Consolidated Financial Statements for additional information regarding the accounting for the defined benefit pension plans and OPEB plans. Regulatory Accounting (All Registrants) For their regulated electric and gas operations, the Registrants reflect the effects of cost-based rate regulation in their financial statements, which is required for entities with regulated operations that meet the following criteria: (1) rates are established or approved by a third-party regulator; (2) rates are designed to recover the entities’ cost of providing services or products; and (3) a reasonable expectation that rates designed to recover costs can be charged to and collected from customers. Regulatory assets represent incurred costs that have been deferred because of their probable future recovery from customers through regulated rates. Regulatory liabilities represent (1) revenue or gains that have been deferred because it is probable such amounts will be returned to customers through future regulated rates; or (2) billings in advance of expenditures for approved regulatory programs. If it is concluded in a future period that a separable portion of operations no longer meets the criteria discussed above, the Registrants would be required to eliminate any associated regulatory assets and liabilities and the impact, which could be material, would be recognized in the Consolidated Statements of Operations and Comprehensive Income. The following table illustrates gains (losses) to be included in net income that could result from the elimination of regulatory assets and liabilities and charges against OCI related to deferred costs associated with Exelon's pension and OPEB plans that are recorded as Regulatory assets in Exelon's Consolidated Balance Sheets (before taxes) at December 31, 2023: [[GREPCENT_TABLE]] [["(In millions)","Exelon","","ComEd","","PECO","","BGE","","PHI","","Pepco","","DPL","","ACE"],["Gain (loss)","$","1,920","","","$","3,555","","","$","(514)","","","$","(156)","","","$","(949)","","","$","(203)","","","$","143","","","$","(462)"],["Charge against OCI(a)","(2,868)","","","\u2014","","","\u2014","","","\u2014","","","\u2014","","","\u2014","","","\u2014","","","\u2014"]] [[/GREPCENT_TABLE]] ___________ (a)Exelon's charge against OCI (before taxes) consists of up to $2.1 billion, $355 million, $485 million, $298 million, $122 million, and $22 million related to ComEd's, BGE's, PHI's, Pepco's, DPL's, and ACE's respective portions of the deferred costs associated with Exelon's pension and OPEB plans. Exelon also has a net regulatory liability of $102 million (before taxes) related to PECO’s portion of the deferred costs associated with Exelon’s OPEB plans that would result in an increase in OCI if reversed. 50 Table of Contents See Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information regarding regulatory matters, including the regulatory assets and liabilities of the Registrants. For each regulatory jurisdiction in which they conduct business, the Registrants assess whether the regulatory assets and liabilities continue to meet the criteria for probable future recovery or refund at each balance sheet date and when regulatory events occur. This assessment includes consideration of recent rate orders, historical regulatory treatment for similar costs in each Registrant's jurisdictions, and factors such as changes in applicable regulatory and political environments. If the assessments and estimates made by the Registrants for regulatory assets and regulatory liabilities are ultimately different than actual regulatory outcomes, the impact in their consolidated financial statements could be material. Refer to the revenue recognition discussion below for additional information on the annual revenue reconciliations associated with ICC-approved electric distribution and energy efficiency formula rates for ComEd, and FERC transmission formula rate tariffs for the Utility Registrants. Derivative Financial Instruments (All Registrants) The Registrants use derivative instruments to manage commodity price risk and interest rate risk related to ongoing business operations. See Note 15 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information. Determining whether a contract qualifies as a derivative requires that management exercise significant judgment, including assessing market liquidity as well as determining whether a contract has one or more underlying and one or more notional quantities. All derivatives are recognized on the balance sheet at their fair value, except for certain derivatives that qualify for, and are elected under, NPNS. For derivatives that qualify and are designated as cash flow hedges, changes in fair value each period are initially recorded in AOCI and recognized in earnings when the hedged transaction affects earnings. For derivatives intended to serve as economic hedges, which are not designated for hedge accounting, changes in fair value each period are recognized in earnings on the Consolidated Statement of Operations and Comprehensive Income or are recorded as a regulatory asset or liability when there is an ability to recover or return the associated costs or benefits in accordance with regulatory requirements. NPNS. Contracts that are designated as NPNS are not required to be recorded at fair value, but rather on an accrual basis of accounting. Determining whether a contract qualifies for NPNS requires judgment on whether the contract will physically deliver and requires that management ensure compliance with all the associated qualification and documentation requirements. For all NPNS derivative instruments, accounts payable is recorded when derivatives settle and expense is recognized in earnings as the underlying physical commodity is consumed. Contracts that qualify for NPNS are those for which physical delivery is probable, quantities are expected to be used or sold in the normal course of business over a reasonable period, and the contract is not financially settled on a net basis. See Note 15 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for all contracts that are accounted for under NPNS. Commodity Contracts. The Registrants make estimates and assumptions concerning future commodity prices, interest rates, and the timing of future transactions and their probable cash flows in deciding whether to enter derivative transactions, and in determining the initial accounting treatment for derivative transactions. The Registrants categorize these derivatives under a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value. Derivative contracts can be traded in both exchange-based and non-exchange-based markets. Exchange-based derivatives that are valued using unadjusted quoted prices in active markets are generally categorized in Level 1 in the fair value hierarchy. Certain derivative pricing is verified using indicative price quotations available through brokers or over-the-counter, online exchanges. For derivatives that trade in liquid markets, the model inputs are generally observable. Such instruments are categorized in Level 2. For derivatives that trade in less liquid markets with limited pricing information, the model inputs generally would include both observable and unobservable inputs and are categorized in Level 3. The Registrants consider nonperformance risk, including credit risk in the valuation of derivative contracts, and both historical and current market data in the assessment of nonperformance risk. The impacts of nonperformance and credit risk to date have generally not been material to the Registrants’ financial statements. 51 Table of Contents Interest Rate Derivative Instruments. Exelon Corporate utilizes interest rate swaps to manage interest rate risk on existing and planned future debt issuances as well as potential fluctuations in Electric operating revenues at the corporate level in consolidation, which are directly correlated to yields on U.S. Treasury bonds under ComEd's distribution formula rate. The fair value of the swaps is calculated by discounting the future net cash flows to the present value based on the terms and conditions of the agreements and the forward interest rate curves. As these inputs are based on observable data and valuations of similar instruments, the interest rate derivatives are primarily categorized in Level 2 in the fair value hierarchy. See ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK and Note 17 — Fair Value of Financial Assets and Liabilities and Note 15 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information regarding the Registrants’ derivative instruments. Income Taxes (All Registrants) Significant management judgment is required in determining the Registrants’ provisions for income taxes, primarily due to the uncertainty related to tax positions taken, as well as deferred tax assets and liabilities and valuation allowances. The Registrants account for uncertain income tax positions using a benefit recognition model with a two-step approach including a more-likely-than-not recognition threshold and a measurement approach based on the largest amount of tax benefit that is greater than 50% likely of being realized upon ultimate settlement. Management evaluates each position based solely on the technical merits and facts and circumstances of the position, assuming the position will be examined by a taxing authority having full knowledge of all relevant information. Significant judgment is required to determine whether the recognition threshold has been met and, if so, the appropriate amount of tax benefits to be recorded in the Registrants’ consolidated financial statements. The Registrants evaluate quarterly the probability of realizing deferred tax assets by reviewing a forecast of future taxable income and their intent and ability to implement tax planning strategies, if necessary, to realize deferred tax assets. The Registrants also assess negative evidence, such as the expiration of historical operating loss or tax credit carryforwards, that could indicate the Registrant's inability to realize its deferred tax assets. Based on the combined assessment, the Registrants record valuation allowances for deferred tax assets when it is more-likely-than-not such benefit will not be realized in future periods. Actual income taxes could vary from estimated amounts due to the future impacts of various items, including future changes in income tax laws, the Registrants’ forecasted financial condition and results of operations, failure to successfully implement tax planning strategies, as well as results of audits and examinations of filed tax returns by taxing authorities. See Note 13 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information. Accounting for Loss Contingencies (All Registrants) In the preparation of their financial statements, the Registrants make judgments regarding the future outcome of contingent events and record liabilities for loss contingencies that are probable and can be reasonably estimated based upon available information. The amount recorded may differ from the actual expense incurred when the uncertainty is resolved. Such difference could have a significant impact in the Registrants' consolidated financial statements. Environmental Costs. Environmental investigation and remediation liabilities are based upon estimates with respect to the number of sites for which the Registrants will be responsible, the scope and cost of work to be performed at each site, the portion of costs that will be shared with other parties, the timing of the remediation work, regulations, and the requirements of local governmental authorities. Annual studies and/or reviews are conducted at ComEd, PECO, BGE, and DPL to determine future remediation requirements for MGP sites and estimates are adjusted accordingly. In addition, periodic reviews are performed at each of the Registrants to assess the adequacy of other environmental reserves. These matters, if resolved in a manner different from the estimate, could have a significant impact in the Registrants’ consolidated financial statements. See Note 18 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for additional information. Other, Including Personal Injury Claims. The Registrants are self-insured for general liability, automotive liability, workers’ compensation, and personal injury claims to the extent that losses are within policy deductibles 52 Table of Contents or exceed the amount of insurance maintained. The Registrants have reserves for both open claims asserted, and an estimate of claims incurred but not reported (IBNR). The IBNR reserve is estimated based on actuarial assumptions and analysis and is updated annually. Future events, such as the number of new claims to be filed each year, the average cost of disposing of claims, as well as the numerous uncertainties surrounding litigation and possible state and national legislative measures could cause the actual costs to be higher or lower than estimated. Accordingly, these claims, if resolved in a manner different from the estimate, could have a material impact to the Registrants’ consolidated financial statements. Revenues (All Registrants) Sources of Revenue and Determination of Accounting Treatment. The Registrants earn revenues from the sale and delivery of power and natural gas in regulated markets. The accounting treatment for revenue recognition is based on the nature of the underlying transaction and applicable authoritative guidance. The Registrants primarily apply the Revenue from Contracts with Customers, and Alternative Revenue Program accounting guidance to recognize revenues as discussed in more detail below. Revenue from Contracts with Customers. The Registrants recognize revenues in the period in which the performance obligations within contracts with customers are satisfied, which generally occurs when power and natural gas are physically delivered to the customer. Transactions of the Registrants within the scope of Revenue from Contracts with Customers generally include sales to utility customers under regulated service tariffs. The determination of the Registrants' power and natural gas sales to individual customers is based on systematic readings of customer meters, generally monthly. At the end of each month, amounts of energy delivered to customers since the date of the last meter reading are estimated, and corresponding unbilled revenue is recorded. The measurement of unbilled revenue is affected by the following factors: daily customer usage measured by generation or gas throughput volume, customer usage by class, losses of energy during delivery to customers and applicable customer rates. Increases or decreases in volumes delivered to the Registrant’s customers and favorable or unfavorable rate mix due to changes in usage patterns in customer classes in the period could be significant to the calculation of unbilled revenue. In addition, revenues may fluctuate monthly as a result of customers electing to use an alternative supplier, since unbilled commodity revenues are not recorded for these customers. Changes in the timing of meter reading schedules and the number and type of customers scheduled for each meter reading date also impact the measurement of unbilled revenue; however, total operating revenues would remain materially unchanged. See Note 1 — Significant Accounting Policies of the Combined Notes to Consolidated Financial Statements for additional information. Alternative Revenue Program Accounting. Certain of the Registrants’ ratemaking mechanisms qualify as ARPs if they (i) are established by a regulatory order and allow for automatic adjustment to future rates, (ii) provide for additional revenues (above those amounts currently reflected in the price of utility service) that are objectively determinable and probable of recovery, and (iii) allow for the collection of those additional revenues within 24 months following the end of the period in which they were recognized. For mechanisms that meet these criteria, which include the Registrants’ formula rate mechanisms and revenue decoupling mechanisms, the Registrants adjust revenue and record an offsetting regulatory asset or liability once the condition or event allowing additional billing or refund has occurred. The ARP revenues presented in the Registrants’ Consolidated Statements of Operations and Comprehensive Income include both: (i) the recognition of “originating” ARP revenues (when the regulator-specified condition or event allowing for additional billing or refund has occurred) and (ii) an equal and offsetting reversal of the “originating” ARP revenues as those amounts are reflected in the price of utility service and recognized as Revenue from Contracts with Customers. ComEd records ARP revenue for its best estimate of the electric distribution, energy efficiency, distributed generation rebates, and transmission revenue impacts resulting from future changes in rates that ComEd believes are probable of approval by the ICC and FERC in accordance with its formula rate mechanisms. BGE, Pepco, DPL, and ACE record ARP revenue for their best estimate of the electric and natural gas distribution revenue impacts resulting from future changes in rates that they believe are probable of approval by the MDPSC, DCPSC, and/or NJBPU in accordance with their revenue decoupling mechanisms. PECO, BGE, Pepco, DPL, and ACE record ARP revenue for their best estimate of the transmission revenue impacts resulting from future changes in rates that they believe are probable of approval by FERC in accordance with their formula rate mechanisms. Estimates of the current year revenue requirement are based on actual and/or forecasted costs and investments in rate base for the period and the rates of return on common equity and associated regulatory 53 Table of Contents capital structure allowed under the applicable tariff. The estimated reconciliation can be affected by, among other things, variances in costs incurred, investments made, allowed ROE, and actions by regulators or courts. See Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information. Allowance for Credit Losses on Customer Accounts Receivable (All Registrants) The Registrants estimate the allowance for credit losses on customer receivables by applying loss rates developed specifically for each company based on historical loss experience, current conditions, and forward-looking risk factors to the outstanding receivable balance by customer risk segment. Risk segments represent a group of customers with similar forward-looking credit quality indicators and risk factors that are comprised based on various attributes, including delinquency of their balances and payment history and represent expected, future customer behavior. Loss rates applied to the accounts receivable balances are based on a historical average of charge-offs as a percentage of accounts receivable in each risk segment. The Registrants' customer accounts are generally considered delinquent if the amount billed is not received by the time the next bill is issued, which normally occurs on a monthly basis. The Registrants' customer accounts are written off consistent with approved regulatory requirements. The Registrants' allowances for credit losses will continue to be affected by changes in volume, prices, and economic conditions as well as changes in ICC, PAPUC, MDPSC, DCPSC, DEPSC, and NJBPU regulations. 54 Table of Contents ComEd Results of Operations by Registrant Results of Operations—ComEd [[GREPCENT_TABLE]] [["","2023","","2022","","Favorable (Unfavorable) Variance"],["Operating revenues","$","7,844","","","$","5,761","","","$","2,083"],["Operating expenses"],["Purchased power","2,816","","","1,109","","","(1,707)"],["Operating and maintenance","1,450","","","1,412","","","(38)"],["Depreciation and amortization","1,403","","","1,323","","","(80)"],["Taxes other than income taxes","369","","","374","","","5"],["Total operating expenses","6,038","","","4,218","","","(1,820)"],["Gain on sales of assets","\u2014","","","(2)","","","2"],["Operating income","1,806","","","1,541","","","265"],["Other income and (deductions)"],["Interest expense, net","(477)","","","(414)","","","(63)"],["Other, net","75","","","54","","","21"],["Total other income and (deductions)","(402)","","","(360)","","","(42)"],["Income before income taxes","1,404","","","1,181","","","223"],["Income taxes","314","","","264","","","(50)"],["Net income","$","1,090","","","$","917","","","$","173"]] [[/GREPCENT_TABLE]] Year Ended December 31, 2023 Compared to Year Ended December 31, 2022. Net income increased by $173 million primarily due to increases in electric distribution formula rate earnings (reflecting higher allowed ROE due to an increase in U.S. Treasury rates and the impacts of higher rate base) and carrying costs related to CMC regulatory assets. The changes in Operating revenues consisted of the following: [[GREPCENT_TABLE]] [["","2023 vs. 2022"],["","Increase"],["Distribution","$","384"],["Transmission","11"],["Energy efficiency","64"],["Other","7"],["","466"],["Regulatory required programs","1,617"],["Total increase","$","2,083"]] [[/GREPCENT_TABLE]] Revenue Decoupling. The demand for electricity is affected by weather and customer usage. Operating revenues are not impacted by abnormal weather, usage per customer, or number of customers as a result of revenue decoupling mechanisms implemented pursuant to FEJA. Distribution Revenue. EIMA and FEJA provide for a performance-based formula rate, which requires an annual reconciliation of the revenue requirement in effect to the actual costs that the ICC determines are prudently and reasonably incurred in a given year. Electric distribution revenue varies from year to year based upon fluctuations in the underlying costs (e.g., severe weather and storm restoration), investments being recovered, and allowed ROE. Electric distribution revenue increased during the year ended December 31, 2023, compared to the same period in 2022, due to higher allowed ROE due to an increase in U.S. Treasury rates, the impact of a higher rate base, and higher fully recoverable costs. 55 Table of Contents ComEd Transmission Revenue. Under a FERC-approved formula, transmission revenue varies from year to year based upon fluctuations in the underlying costs, capital investments being recovered, and the highest daily peak load, which is updated annually in January based on the prior calendar year. Generally, increases/decreases in the highest daily peak load will result in higher/lower transmission revenue. Transmission revenues increased during the year ended December 31, 2023, compared to the same period in 2022, primarily due to the impact of a higher rate base and higher fully recoverable costs. Energy Efficiency Revenue. FEJA provides for a performance-based formula rate, which requires an annual reconciliation of the revenue requirement in effect to the actual costs that the ICC determines are prudently and reasonably incurred in a given year. Under FEJA, energy efficiency revenue varies from year to year based upon fluctuations in the underlying costs, investments being recovered, and allowed ROE. Energy efficiency revenue increased during the year ended December 31, 2023, compared to the same period in 2022, primarily due to the impact of a higher rate base, and increased regulatory asset amortization, which is fully recoverable. Other Revenue primarily includes assistance provided to other utilities through mutual assistance programs. Other revenue increased for the year ended December 31, 2023, compared to the same period in 2022, which primarily reflects mutual assistance revenues associated with storm restoration efforts. Regulatory Required Programs represents revenues collected under approved riders to recover costs incurred for regulatory programs such as recoveries under the credit loss expense tariff, environmental costs associated with MGP sites, ETAC, and costs related to electricity, ZEC, CMC, and REC procurement. See Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information regarding CMCs. ETAC is a retail customer surcharge collected by electric utilities operating in Illinois established by CEJA and remitted to an Illinois state agency for programs to support clean energy jobs and training. The riders are designed to provide full and current cost recovery. The costs of these programs are included in Purchased power expense, Operating and maintenance expense, Depreciation and amortization expense, and Taxes other than income. Customers have the choice to purchase electricity from competitive electric generation suppliers. Customer choice programs do not impact the volume of deliveries as ComEd remains the distribution service provider for all customers and charges a regulated rate for distribution service, which is recorded in Operating revenues. For customers that choose to purchase electric generation from competitive suppliers, ComEd either acts as the billing agent or the competitive supplier separately bills its own customers, and therefore does not record Operating revenues or Purchased power expense related to the electricity. For customers that choose to purchase electric generation from ComEd, ComEd is permitted to recover the electricity, ZEC, CMC, and REC procurement costs without mark-up and therefore records equal and offsetting amounts in Operating revenues and Purchased power expense related to the electricity, ZECs, CMCs, and RECs. See Note 5 — Segment Information of the Combined Notes to Consolidated Financial Statements for the presentation of ComEd's revenue disaggregation. The increase of $1,707 million for the year ended December 31, 2023, compared to the same period in 2022, in Purchased power expense is primarily due to the CMCs from the participating nuclear-powered generating facilities, which is offset by an increase in Operating revenues as part of regulatory required programs. See Note 3 - Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information regarding CMCs. 56 Table of Contents ComEd The changes in Operating and maintenance expense consisted of the following: [[GREPCENT_TABLE]] [["","2023 vs. 2022"],["","Increase (Decrease)"],["BSC costs","$","36"],["Labor, other benefits, contracting, and materials","35"],["Storm-related costs","(10)"],["Pension and non-pension postretirement benefits expense","(13)"],["Other","53"],["","101"],["Regulatory required programs(a)","(63)"],["Total increase","$","38"]] [[/GREPCENT_TABLE]] __________ (a)ComEd is allowed to recover from or refund to customers the difference between its annual credit loss expense and the amounts collected in rates annually through a rider mechanism. The changes in Depreciation and amortization expense consisted of the following: [[GREPCENT_TABLE]] [["","2023 vs. 2022"],["","Increase"],["Depreciation and amortization(a)","$","64"],["Regulatory asset amortization(b)","16"],["Total increase","$","80"]] [[/GREPCENT_TABLE]] __________ (a)Reflects ongoing capital expenditures and higher depreciation rates effective January 2023. (b)Includes amortization of ComEd's energy efficiency formula rate regulatory asset. Interest expense, net increased $63 million for the year ended December 31, 2023, compared to the same period in 2022, primarily due to an increase in interest rates and the issuance of debt in 2022 and 2023. Effective income tax rates were 22.4% and 22.4% for the years ended December 31, 2023 and 2022, respectively. See Note 13 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the effective income tax rates. 57 Table of Contents PECO Results of Operations—PECO [[GREPCENT_TABLE]] [["","2023","","2022","","(Unfavorable) Favorable Variance"],["Operating revenues","$","3,894","","","$","3,903","","","$","(9)"],["Operating expenses"],["Purchased power and fuel","1,544","","","1,535","","","(9)"],["Operating and maintenance","1,003","","","992","","","(11)"],["Depreciation and amortization","397","","","373","","","(24)"],["Taxes other than income taxes","202","","","202","","","\u2014"],["Total operating expenses","3,146","","","3,102","","","(44)"],["Operating income","748","","","801","","","(53)"],["Other income and (deductions)"],["Interest expense, net","(201)","","","(177)","","","(24)"],["Other, net","36","","","31","","","5"],["Total other income and (deductions)","(165)","","","(146)","","","(19)"],["Income before income taxes","583","","","655","","","(72)"],["Income taxes","20","","","79","","","59"],["Net income","$","563","","","$","576","","","$","(13)"]] [[/GREPCENT_TABLE]] Year Ended December 31, 2023 Compared to Year Ended December 31, 2022. Net income decreased by $13 million, primarily due to unfavorable weather and increases in depreciation and amortization expense and interest expense, partially offset by an increase in gas distribution rates and Pennsylvania corporate income tax legislation passed in July 2022 driving a one-time non-cash decrease to net income for 2022. The changes in Operating revenues consisted of the following: [[GREPCENT_TABLE]] [["","2023 vs. 2022"],["","(Decrease) Increase"],["","Electric","","Gas","","Total"],["Weather","$","(103)","","","$","(37)","","","$","(140)"],["Volume","1","","","1","","","2"],["Pricing","31","","","52","","","83"],["Transmission","23","","","\u2014","","","23"],["Other","(3)","","","6","","","3"],["","(51)","","","22","","","(29)"],["Regulatory required programs","88","","","(68)","","","20"],["Total decrease","$","37","","","$","(46)","","","$","(9)"]] [[/GREPCENT_TABLE]] 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. For the year ended December 31, 2023 compared to the same period in 2022, Operating revenues related to weather decreased due to the impact of 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’s service territory for the years ended December 31, 2023 compared to the same period in 2022 and normal weather consisted of the following: 58 Table of Contents PECO [[GREPCENT_TABLE]] [["","For the Years Ended December 31,","","","","% Change"],["PECO Service Territory","2023","","2022","","Normal","","2023 vs. 2022","","2023 vs. Normal"],["Heating Degree-Days","3,587","","","4,135","","","4,399","","","(13.3)","%","","(18.5)","%"],["Cooling Degree-Days","1,345","","","1,743","","","1,440","","","(22.8)","%","","(6.6)","%"]] [[/GREPCENT_TABLE]] Volume. Electric volume, exclusive of the effects of weather, for the year ended December 31, 2023 compared to the same period in 2022, remained relatively consistent. Natural gas volume for the year ended December 31, 2023 compared to the same period in 2022, remained relatively consistent. [[GREPCENT_TABLE]] [["Electric Retail Deliveries to Customers (in GWhs)","2023","","2022","","% Change","","Weather - Normal % Change(b)"],["Residential","13,262","","","14,379","","","(7.8)","%","","0.5","%"],["Small commercial & industrial","7,367","","","7,701","","","(4.3)","%","","(0.3)","%"],["Large commercial & industrial","13,638","","","14,046","","","(2.9)","%","","(0.8)","%"],["Public authorities & electric railroads","606","","","638","","","(5.0)","%","","(5.0)","%"],["Total electric retail deliveries(a)","34,873","","","36,764","","","(5.1)","%","","(0.3)","%"]] [[/GREPCENT_TABLE]] __________ (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. [[GREPCENT_TABLE]] [["","At December 31,"],["Number of Electric Customers","2023","","2022"],["Residential","1,535,927","","","1,525,635"],["Small commercial & industrial","156,248","","","155,576"],["Large commercial & industrial","3,127","","","3,121"],["Public authorities & electric railroads","10,417","","","10,393"],["Total","1,705,719","","","1,694,725"]] [[/GREPCENT_TABLE]] [[GREPCENT_TABLE]] [["Natural Gas Deliveries to customers (in mmcf)","2023","","2022","","% Change","","Weather - Normal % Change(b)"],["Residential","35,842","","","42,135","","","(14.9)","%","","(3.2)","%"],["Small commercial & industrial","21,182","","","23,449","","","(9.7)","%","","(1.7)","%"],["Large commercial & industrial","51","","","31","","","64.5","%","","2.7","%"],["Transportation","23,741","","","25,011","","","(5.1)","%","","(2.4)","%"],["Total natural gas deliveries(a)","80,816","","","90,626","","","(10.8)","%","","(2.6)","%"]] [[/GREPCENT_TABLE]] __________ (a)Reflects delivery volumes from customers purchasing natural gas directly from PECO and customers purchasing electricity 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. [[GREPCENT_TABLE]] [["","At December 31,"],["Number of Gas Customers","2023","","2022"],["Residential","507,197","","","502,944"],["Small commercial & industrial","45,001","","","44,957"],["Large commercial & industrial","9","","","9"],["Transportation","627","","","655"],["Total","552,834","","","548,565"]] [[/GREPCENT_TABLE]] Pricing for the year ended December 31, 2023 compared to the same period in 2022 increased primarily due to an increase in gas distribution rates charged to customers, coupled with higher overall effective rates for both electric and gas attributable to decreased usage. 59 Table of Contents 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 revenues for the year ended December 31, 2023 compared to the same period in 2022, remained relatively consistent. Regulatory Required Programs represents revenues collected under approved riders to recover costs incurred for regulatory programs such as energy efficiency, PGC, and the GSA. The riders are designed to provide full and current cost recovery as well as a return. The costs of these programs are included in Purchased power and fuel expense, Operating and maintenance expense, Depreciation and amortization expense, and Income taxes. Customers have the choice to purchase electricity and natural gas from competitive electric generation and natural gas suppliers. Customer choice programs do not impact the volume of deliveries as PECO remains the distribution service provider for all customers and charges a regulated rate for distribution service, which is recorded in Operating revenues. For customers that choose to purchase electric generation or natural gas from competitive suppliers, PECO either acts as the billing agent or the competitive supplier separately bills its own customers and therefore PECO does not record Operating revenues or Purchased power and fuel expense related to the electricity and/or natural gas. For customers that choose to purchase electric generation or natural gas from PECO, PECO is permitted to recover the electricity, natural gas, and REC procurement costs without mark-up and therefore records equal and offsetting amounts in Operating revenues and Purchased power and fuel expense related to the electricity, natural gas, and RECs. See Note 5 — Segment Information of the Combined Notes to Consolidated Financial Statements for the presentation of PECO's revenue disaggregation. The increase of $9 million for the year ended December 31, 2023, compared to the same period in 2022, in Purchased power and fuel expense is fully offset in Operating revenues as part of regulatory required programs. The changes in Operating and maintenance expense consisted of the following: [[GREPCENT_TABLE]] [["","2023 vs. 2022"],["","Increase (Decrease)"],["Storm-related costs","$","22"],["BSC costs","15"],["Pension and non-pension postretirement benefits expense","(3)"],["Labor, other benefits, contracting, and materials","(2)"],["Other(a)","(31)"],["","1"],["Regulatory Required Programs","10"],["Total increase","$","11"]] [[/GREPCENT_TABLE]] __________ (a) Due to one-time charitable contributions for the year ended December 31, 2022 The changes in Depreciation and amortization expense consisted of the following: [[GREPCENT_TABLE]] [["","2023 vs. 2022"],["","Increase"],["Depreciation and amortization(a)","$","24"],["Regulatory asset amortization","\u2014"],["Total increase","$","24"]] [[/GREPCENT_TABLE]] __________ (a)Depreciation and amortization expense increased primarily due to ongoing capital expenditures. Interest expense, net increased $24 million for the year ended December 31, 2023, compared to the same period in 2022, primarily due to the issuance of debt in 2022 and 2023 and increases in interest rates. 60 Table of Contents PECO Effective income tax rates were 3.4% and 12.1% for the years ended December 31, 2023 and 2022, respectively. See Note 13 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the effective income tax rates. 61 Table of Contents BGE Results of Operations—BGE [[GREPCENT_TABLE]] [["","2023","","2022","","Favorable (Unfavorable) Variance"],["Operating revenues","$","4,027","","","$","3,895","","","$","132"],["Operating expenses"],["Purchased power and fuel","1,531","","","1,567","","","36"],["Operating and maintenance","741","","","877","","","136"],["Depreciation and amortization","654","","","630","","","(24)"],["Taxes other than income taxes","319","","","302","","","(17)"],["Total operating expenses","3,245","","","3,376","","","131"],["Operating income","782","","","519","","","263"],["Other income and (deductions)"],["Interest expense, net","(182)","","","(152)","","","(30)"],["Other, net","18","","","21","","","(3)"],["Total other income and (deductions)","(164)","","","(131)","","","(33)"],["Income before income taxes","618","","","388","","","230"],["Income taxes","133","","","8","","","(125)"],["Net income","$","485","","","$","380","","","$","105"]] [[/GREPCENT_TABLE]] Year Ended December 31, 2023 Compared to Year Ended December 31, 2022. Net income increased $105 million primarily due to favorable impacts of the multi-year plans including the recognition of the reconciliation in 2023 and an asset impairment in 2022, partially offset by an increase in depreciation expense, interest expense, and increase in income taxes in 2023 as compared to 2022. See Note 11 — Asset Impairments for additional information on the asset impairment and Note 3 — Regulatory Matters for additional information on multi-year plan order. The changes in Operating revenues consisted of the following: [[GREPCENT_TABLE]] [["","2023 vs. 2022"],["","Increase (Decrease)"],["","Electric","","Gas","","Total"],["Distribution","$","78","","","$","45","","","$","123"],["Transmission","56","","","\u2014","","","56"],["Other","(1)","","","2","","","1"],["","133","","","47","","","180"],["Regulatory required programs","104","","","(152)","","","(48)"],["Total increase (decrease)","$","237","","","$","(105)","","","$","132"]] [[/GREPCENT_TABLE]] 62 Table of Contents BGE 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. See Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information on revenue decoupling for BGE. [[GREPCENT_TABLE]] [["","At December 31,"],["Number of Electric Customers","2023","","2022"],["Residential","1,211,889","","","1,204,429"],["Small commercial & industrial","115,787","","","115,524"],["Large commercial & industrial","13,072","","","12,839"],["Public authorities & electric railroads","261","","","266"],["Total","1,341,009","","","1,333,058"]] [[/GREPCENT_TABLE]] [[GREPCENT_TABLE]] [["","At December 31,"],["Number of Gas Customers","2023","","2022"],["Residential","657,823","","","655,373"],["Small commercial & industrial","37,993","","","38,207"],["Large commercial & industrial","6,309","","","6,233"],["Total","702,125","","","699,813"]] [[/GREPCENT_TABLE]] Distribution Revenue increased for the year ended December 31, 2023 compared to the same period in 2022, due to favorable impacts of the multi-year plans. Transmission Revenue. Under a FERC-approved formula, transmission revenue varies from year to year based upon fluctuations in the underlying costs and capital investments being recovered. Transmission revenue increased for the year ended December 31, 2023 compared to the same period in 2022 primarily due to increases in underlying costs and capital investments. Other Revenue includes revenue related to late payment charges, mutual assistance, off-system sales, and service application fees. Other Revenue remained relatively consistent for the year ended December 31, 2023 compared to the same period in 2022. Regulatory Required Programs represent revenues collected under approved riders to recover costs incurred for regulatory programs such as conservation, demand response, STRIDE, and the POLR mechanism. The riders are designed to provide full and current cost recovery, as well as a return in certain instances. The costs of these programs are included in Purchased power and fuel expense, Operating and maintenance expense, Depreciation and amortization expense, and Taxes other than income taxes. Customers have the choice to purchase electricity and natural gas from competitive electric generation and natural gas suppliers. Customer choice programs do not impact the volume of deliveries as BGE remains the distribution service provider for all customers and charges a regulated rate for distribution service, which is recorded in Operating revenues. For customers that choose to purchase electric generation or natural gas from competitive suppliers, BGE acts as the billing agent and therefore does not record Operating revenues or Purchased power and fuel expense related to the electricity and/or natural gas. For customers that choose to purchase electric generation or natural gas from BGE, BGE is permitted to recover the electricity and natural gas procurement costs from customers and therefore records the amounts related to the electricity and/or natural gas in Operating revenues and Purchased power and fuel expense. BGE recovers electricity and natural gas procurement costs from customers with a slight mark-up. See Note 5 — Segment Information of the Combined Notes to Consolidated Financial Statements for the presentation of BGE's revenue disaggregation. The decrease of $36 million for the year ended December 31, 2023 compared to the same period in 2022 in Purchased power and fuel expense is fully offset in Operating revenues as part of regulatory required programs. 63 Table of Contents BGE The changes in Operating and maintenance expense consisted of the following: [[GREPCENT_TABLE]] [["","2023 vs. 2022"],["","Increase (Decrease)"],["BSC costs","$","18"],["Storm-related costs","12"],["Labor, other benefits, contracting, and materials","12"],["Pension and non-pension postretirement benefits expense","5"],["Credit loss expense","(8)"],["Impairment on long-lived assets(a)","(48)"],["Multi-year plan reconciliations(b)","(112)"],["Other","(17)"],["","(138)"],["Regulatory required programs","2"],["Total decrease","$","(136)"]] [[/GREPCENT_TABLE]] __________ (a)See Note 11 — Asset Impairments for additional information on the asset impairment taken in 2022. (b)See Note 3 — Regulatory Matters for additional information on multi-year plan reconciliations. The changes in Depreciation and amortization expense consisted of the following: [[GREPCENT_TABLE]] [["","2023 vs. 2022"],["","Increase (Decrease)"],["Depreciation and amortization(a)","$","30"],["Regulatory required programs","(5)"],["Regulatory asset amortization","(1)"],["Total increase","$","24"]] [[/GREPCENT_TABLE]] __________ (a)Depreciation and amortization increased primarily due to ongoing capital expenditures. Taxes other than income taxes increased by $17 million for the year ended December 31, 2023 compared to the same period in 2022, primarily due to increased property taxes. Interest expense, net increased $30 million for the year ended December 31, 2023 compared to the same period in 2022, due to the issuance of debt in 2022 and 2023 and increases in interest rates. Effective income tax rates were 21.5% and 2.1% for the years ended December 31, 2023 and 2022, respectively. The change is primarily due to decreases in the multi-year plans' accelerated income tax benefits in 2023 compared to 2022. See Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information on both the three-year electric and natural gas distribution multi-year plans and Note 13 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the effective income tax rates. 64 Table of Contents PHI Results of Operations—PHI PHI’s Results of Operations include the results of its three reportable segments, Pepco, DPL, and ACE. PHI also has a business services subsidiary, PHISCO, which provides a variety of support services and the costs are directly charged or allocated to the applicable subsidiaries. Additionally, the results of PHI's corporate operations include interest costs from various financing activities. All material intercompany accounts and transactions have been eliminated in consolidation. The following table sets forth PHI's GAAP consolidated Net income, by Registrant, for the year ended December 31, 2023 compared to the same period in 2022. See the Results of Operations for Pepco, DPL, and ACE for additional information. [[GREPCENT_TABLE]] [["","2023","","2022","","(Unfavorable) Favorable Variance"],["PHI","$","590","","","$","608","","","$","(18)"],["Pepco","306","","","305","","","1"],["DPL","177","","","169","","","8"],["ACE","120","","","148","","","(28)"],["Other(a)","(13)","","","(14)","","","1"]] [[/GREPCENT_TABLE]] __________ (a)Primarily includes eliminating and consolidating adjustments, PHI's corporate operations, shared service entities, and other financing and investing activities. Year Ended December 31, 2023 Compared to Year Ended December 31, 2022. Net income decreased by $18 million primarily due to higher contracting costs as a result of the ACE employee strike, an increase in environmental liabilities at Pepco, an increase in interest expense, depreciation expense, and unfavorable weather at DPL Delaware electric and natural gas service territories, partially offset by higher distribution rates at DPL Delaware, favorable impacts of the Pepco Maryland and DPL Maryland multi-year plans, and higher transmission rates. 65 Table of Contents Pepco Results of Operations—Pepco [[GREPCENT_TABLE]] [["","2023","","2022","","Favorable (Unfavorable) Variance"],["Operating revenues","$","2,824","","","$","2,531","","","$","293"],["Operating expenses"],["Purchased power","974","","","834","","","(140)"],["Operating and maintenance","572","","","507","","","(65)"],["Depreciation and amortization","441","","","417","","","(24)"],["Taxes other than income taxes","390","","","382","","","(8)"],["Total operating expenses","2,377","","","2,140","","","(237)"],["Gain on sales of assets","9","","","\u2014","","","9"],["Operating income","456","","","391","","","65"],["Other income and (deductions)"],["Interest expense, net","(165)","","","(150)","","","(15)"],["Other, net","66","","","55","","","11"],["Total other income and (deductions)","(99)","","","(95)","","","(4)"],["Income before income taxes","357","","","296","","","61"],["Income taxes","51","","","(9)","","","(60)"],["Net income","$","306","","","$","305","","","$","1"]] [[/GREPCENT_TABLE]] Year Ended December 31, 2023 Compared to Year Ended December 31, 2022. Net income increased by $1 million primarily due to favorable impacts of the Maryland multi-year plan, higher transmission rates, customer growth, and a gain on sale of land in the fourth quarter of 2023, partially offset by an increase in environmental liabilities, depreciation expense, and interest expense. [[GREPCENT_TABLE]] [["","2023 vs. 2022"],["","Increase"],["Distribution","$","94"],["Transmission","55"],["Other","3"],["","152"],["Regulatory required programs","141"],["Total increase","$","293"]] [[/GREPCENT_TABLE]] 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. See Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information on revenue decoupling for Pepco Maryland and District of Columbia. [[GREPCENT_TABLE]] [["","At December 31,"],["Number of Electric Customers","2023","","2022"],["Residential","866,018","","","856,037"],["Small commercial & industrial","54,142","","","54,339"],["Large commercial & industrial","22,941","","","22,841"],["Public authorities & electric railroads","208","","","197"],["Total","943,309","","","933,414"]] [[/GREPCENT_TABLE]] 66 Table of Contents Pepco Distribution Revenue increased for the year ended December 31, 2023 compared to the same period in 2022, primarily due to higher rates due to the expiration of customer offsets, favorable impacts of the Maryland multi-year plan, and customer growth. Transmission Revenue. Under a FERC-approved formula, transmission revenue varies from year to year based upon fluctuations in the underlying costs and capital investments being recovered. Transmission revenue increased for the year ended December 31, 2023 compared to the same period in 2022 primarily due to increases in underlying costs and capital investment. Other Revenue includes rental revenue, revenue related to late payment charges, mutual assistance revenues, and recoveries of other taxes. Regulatory Required Programs represent revenues collected under approved riders to recover costs incurred for regulatory programs such as energy efficiency programs, DC PLUG, and SOS procurement and administrative costs. The riders are designed to provide full and current cost recovery as well as a return in certain instances. The costs of these programs are included in Purchased power expense, Operating and maintenance expense, Depreciation and amortization expense, and Taxes other than income taxes. Customers have the choice to purchase electricity from competitive electric generation suppliers. Customer choice programs do not impact the volume of deliveries, as Pepco remains the distribution service provider for all customers and charges a regulated rate for distribution service, which is recorded in Operating revenues. For customers that choose to purchase electric generation from competitive suppliers, Pepco acts as the billing agent and therefore, Pepco does not record Operating revenues or Purchased power expense related to the electricity. For customers that choose to purchase electric generation from Pepco, Pepco is permitted to recover the electricity and REC procurement costs from customers and therefore records the amounts related to the electricity and RECs in Operating revenues and Purchased power expense. Pepco recovers electricity and REC procurement costs from customers with a slight mark-up. See Note 5 — Segment Information of the Combined Notes to Consolidated Financial Statements for the presentation of Pepco's revenue disaggregation. The increase of $140 million for the year ended December 31, 2023 compared to the same period in 2022, in Purchased power expense is fully offset in Operating revenues as part of regulatory required programs. 67 Table of Contents Pepco The changes in Operating and maintenance expense consisted of the following: [[GREPCENT_TABLE]] [["","2023 vs. 2022"],["","Increase (Decrease)"],["Labor, other benefits, contracting, and materials(a)","$","26"],["BSC and PHISCO costs","14"],["Pension and non-pension postretirement benefits expense","11"],["Credit loss expense","(3)"],["Storm-related costs","(9)"],["Other","16"],["","55"],["Regulatory required programs","10"],["Total increase","$","65"]] [[/GREPCENT_TABLE]] __________ (a)Primarily reflects an increase in environmental liabilities for the year ended December 31, 2023. The changes in Depreciation and amortization expense consisted of the following: [[GREPCENT_TABLE]] [["","2023 vs. 2022"],["","Increase (Decrease)"],["Depreciation and amortization(a)","$","22"],["Regulatory asset amortization","13"],["Regulatory required programs","(11)"],["Total increase","$","24"]] [[/GREPCENT_TABLE]] __________ (a)Depreciation and amortization increased primarily due to ongoing capital expenditures. Taxes other than income taxes increased $8 million for the year ended December 31, 2023 compared to the same period in 2022, primarily due to an increase in property taxes. Interest expense, net increased $15 million for the year ended December 31, 2023 compared to the same period in 2022 primarily due to an increase in interest rates and the issuance of debt in 2022 and 2023. Gain on sales of assets for the year ended December 31, 2023 compared to the same period in 2022 increased $9 million due to the sale of land in the fourth quarter of 2023. Other, net increased $11 million for the year ended December 31, 2023 compared to the same period in 2022, primarily due to higher AFUDC equity. Effective income tax rates were 14.3% and (3.0)% for the years ended December 31, 2023 and 2022, respectively. See Note 13 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the effective income tax rates. 68 Table of Contents DPL Results of Operations—DPL [[GREPCENT_TABLE]] [["","2023","","2022","","Favorable (Unfavorable) Variance"],["Operating revenues","$","1,688","","","$","1,595","","","$","93"],["Operating expenses"],["Purchased power and fuel","737","","","706","","","(31)"],["Operating and maintenance","364","","","349","","","(15)"],["Depreciation and amortization","244","","","232","","","(12)"],["Taxes other than income taxes","75","","","72","","","(3)"],["Total operating expenses","1,420","","","1,359","","","(61)"],["Operating income","268","","","236","","","32"],["Other income and (deductions)"],["Interest expense, net","(74)","","","(66)","","","(8)"],["Other, net","18","","","13","","","5"],["Total other income and (deductions)","(56)","","","(53)","","","(3)"],["Income before income taxes","212","","","183","","","29"],["Income taxes","35","","","14","","","(21)"],["Net income","$","177","","","$","169","","","$","8"]] [[/GREPCENT_TABLE]] Year Ended December 31, 2023 Compared to Year Ended December 31, 2022. Net income increased by $8 million primarily due to favorable impacts of the Maryland multi-year plan, higher Delaware electric and natural gas distribution rates, and higher transmission rates, partially offset by unfavorable weather conditions in Delaware electric and natural gas service territories, and an increase in depreciation expense and interest expense. The changes in Operating revenues consisted of the following: [[GREPCENT_TABLE]] [["","2023 vs. 2022"],["","(Decrease) Increase"],["","Electric","","Gas","","Total"],["Weather","$","(10)","","","$","(6)","","","$","(16)"],["Volume","(6)","","","(5)","","","(11)"],["Distribution","34","","","7","","","41"],["Transmission","42","","","\u2014","","","42"],["Other","5","","","\u2014","","","5"],["","65","","","(4)","","","61"],["Regulatory required programs","61","","","(29)","","","32"],["Total increase","$","126","","","$","(33)","","","$","93"]] [[/GREPCENT_TABLE]] 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. See Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information on revenue decoupling for DPL Maryland. 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 year ended December 31, 2023 compared to the same period in 2022, Operating revenues 69 Table of Contents DPL related to weather decreased due to unfavorable weather conditions in DPL's 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 DPL's Delaware electric service territory and a 30-year period in DPL's Delaware natural gas service territory. The changes in heating and cooling degree days in DPL’s Delaware service territory for the year ended December 31, 2023 compared to same period in 2022 and normal weather consisted of the following: [[GREPCENT_TABLE]] [["","For the Years Ended December 31,","","","","% Change"],["Delaware Electric Service Territory","2023","","2022","","Normal","","2023 vs. 2022","","2023 vs. Normal"],["Heating Degree-Days","3,845","","","4,428","","","4,585","","","(13.2)","%","","(16.1)","%"],["Cooling Degree-Days","1,275","","","1,382","","","1,276","","","(7.7)","%","","(0.1)","%"]] [[/GREPCENT_TABLE]] [[GREPCENT_TABLE]] [["","For the Years Ended December 31,","","","","% Change"],["Delaware Natural Gas Service Territory","2023","","2022","","Normal","","2023 vs. 2022","","2023 vs. Normal"],["Heating Degree-Days","3,845","","","4,428","","","4,662","","","(13.2)","%","","(17.5)","%"]] [[/GREPCENT_TABLE]] Volume, exclusive of the effects of weather, decreased for the year ended December 31, 2023 compared to the same period in 2022 primarily due to customer usage, partially offset by customer growth. [[GREPCENT_TABLE]] [["Electric Retail Deliveries to Delaware Customers (in GWhs)","2023","","2022","","% Change","","Weather - Normal % Change (b)"],["Residential","3,065","","","3,242","","","(5.5)","%","","(1.4)","%"],["Small commercial & industrial","1,399","","","1,443","","","(3.0)","%","","(1.4)","%"],["Large commercial & industrial","3,071","","","3,162","","","(2.9)","%","","(2.0)","%"],["Public authorities & electric railroads","33","","","33","","","\u2014","%","","1.2","%"],["Total electric retail deliveries(a)","7,568","","","7,880","","","(4.0)","%","","(1.6)","%"]] [[/GREPCENT_TABLE]] [[GREPCENT_TABLE]] [["","At December 31,"],["Number of Total Electric Customers (Maryland and Delaware)","2023","","2022"],["Residential","485,713","","","481,688"],["Small commercial & industrial","64,220","","","63,738"],["Large commercial & industrial","1,260","","","1,235"],["Public authorities & electric railroads","593","","","597"],["Total","551,786","","","547,258"]] [[/GREPCENT_TABLE]] __________ (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. [[GREPCENT_TABLE]] [["Natural Gas Retail Deliveries to Delaware Customers (in mmcf)","2023","","2022","","% Change","","Weather - Normal % Change(b)"],["Residential","7,326","","","8,709","","","(15.9)","%","","(6.4)","%"],["Small commercial & industrial","3,660","","","4,176","","","(12.4)","%","","(2.1)","%"],["Large commercial & industrial","1,588","","","1,697","","","(6.4)","%","","(6.4)","%"],["Transportation","6,004","","","6,696","","","(10.3)","%","","(7.1)","%"],["Total natural gas deliveries(a)","18,578","","","21,278","","","(12.7)","%","","(5.7)","%"]] [[/GREPCENT_TABLE]] 70 Table of Contents DPL [[GREPCENT_TABLE]] [["","At December 31,"],["Number of Delaware Natural Gas Customers","2023","","2022"],["Residential","129,903","","","129,502"],["Small commercial & industrial","10,133","","","10,144"],["Large commercial & industrial","14","","","17"],["Transportation","163","","","156"],["Total","140,213","","","139,819"]] [[/GREPCENT_TABLE]] __________ (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 year ended December 31, 2023 compared to the same period in 2022 primarily due favorable impacts of the Maryland multi-year plan that became effective January 2023, favorable impacts of the higher electric distribution rates in Delaware that became effective July 2023, and higher natural gas distribution rates effective in August 2022. Transmission Revenue. Under a FERC-approved formula, transmission revenue varies from year to year based upon fluctuations in the underlying costs and capital investments being recovered. Transmission revenue increased for the year ended December 31, 2023 compared to the same period in 2022 primarily due to increases in underlying costs and capital investment. Other Revenue includes rental revenue, revenue related to late payment charges, mutual assistance revenues, and recoveries of other taxes. Regulatory Required Programs represent revenues collected under approved riders to recover costs incurred for regulatory programs such as energy efficiency programs, 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 5 — Segment Information of the Combined Notes to Consolidated Financial Statements for the presentation of DPL's revenue disaggregation. The increase of $31 million for the year ended December 31, 2023 compared to the same period in 2022, in Purchased power and fuel expense is fully offset in Operating revenues as part of regulatory required programs. 71 Table of Contents DPL The changes in Operating and maintenance expense consisted of the following: [[GREPCENT_TABLE]] [["","2023 vs. 2022"],["","Increase (Decrease)"],["Pension and non-pension postretirement benefits expense","$","6"],["Storm-related costs","5"],["BSC and PHISCO costs","4"],["Labor, other benefits, contracting, and materials","1"],["Credit loss expense","(3)"],["Other","2"],["Total increase","$","15"]] [[/GREPCENT_TABLE]] The changes in Depreciation and amortization expense consisted of the following: [[GREPCENT_TABLE]] [["","2023 vs. 2022"],["","Increase (Decrease)"],["Depreciation and amortization(a)","$","17"],["Regulatory asset amortization","(1)"],["Regulatory required programs","(4)"],["Total increase","$","12"]] [[/GREPCENT_TABLE]] __________ (a)For the year ended December 31, 2023, reflects ongoing capital expenditures, higher distribution depreciation rates in Maryland effective March 2022, and higher transmission depreciation rates effective September 2022. Interest expense, net increased $8 million for the year ended December 31, 2023 compared to the same period in 2022 primarily due to the issuance of debt in 2022 and 2023. Other, net increased $5 million for the year ended December 31, 2023 compared to the same period in 2022, primarily due to higher AFUDC equity. Effective income tax rates were 16.5% and 7.7% for the years ended December 31, 2023 and 2022, respectively. See Note 13 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the change in effective income tax rates. 72 Table of Contents ACE Results of Operations—ACE [[GREPCENT_TABLE]] [["","2023","","2022","","Favorable (Unfavorable) Variance"],["Operating revenues","$","1,522","","","$","1,431","","","$","91"],["Operating expenses"],["Purchased power","637","","","624","","","(13)"],["Operating and maintenance","386","","","331","","","(55)"],["Depreciation and amortization","283","","","261","","","(22)"],["Taxes other than income taxes","8","","","9","","","1"],["Total operating expenses","1,314","","","1,225","","","(89)"],["Operating income","208","","","206","","","2"],["Other income and (deductions)"],["Interest expense, net","(72)","","","(66)","","","(6)"],["Other, net","20","","","11","","","9"],["Total other income and (deductions)","(52)","","","(55)","","","3"],["Income before income taxes","156","","","151","","","5"],["Income taxes","36","","","3","","","(33)"],["Net income","$","120","","","$","148","","","$","(28)"]] [[/GREPCENT_TABLE]] Year Ended December 31, 2023 Compared to Year Ended December 31, 2022. Net income decreased $28 million primarily due to higher contracting costs primarily due to the ACE employee strike, and an increase in depreciation expense, and interest expense, partially offset by higher transmission rates. The changes in Operating revenues consisted of the following: [[GREPCENT_TABLE]] [["","2023 vs. 2022"],["","Increase"],["Distribution","$","33"],["Transmission","46"],["Other","1"],["","80"],["Regulatory required programs","11"],["Total increase","$","91"]] [[/GREPCENT_TABLE]] 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. See Note 3 — Regulatory Matters of the Combined Notes to the Consolidated Financial Statements for additional information on the ACE CIP. 73 Table of Contents ACE [[GREPCENT_TABLE]] [["","At December 31,"],["Number of Electric Customers","2023","","2022"],["Residential","504,919","","","502,247"],["Small commercial & industrial","62,646","","","62,246"],["Large commercial & industrial","2,909","","","3,051"],["Public authorities & electric railroads","727","","","734"],["Total","571,201","","","568,278"]] [[/GREPCENT_TABLE]] Distribution Revenue increased for the year ended December 31, 2023 compared to the same period in 2022 due to higher distribution rates primarily due to the expiration of customer credits related to the TCJA tax benefits. Transmission 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 year ended December 31, 2023 compared to the same period in 2022 primarily due to increases in capital investment and underlying costs. 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, Societal Benefits Charge, Transition Bonds, and BGS procurement and administrative costs. The riders are designed to provide full and current cost recovery as well as a return in certain instances. The costs of these programs are included in Purchased power expense, Operating and maintenance expense, Depreciation and amortization expense, and Taxes other than income taxes. Customers have the choice to purchase electricity from competitive electric generation suppliers. Customer choice programs do not impact the volume of deliveries, as ACE remains the distribution service provider for all customers and charges a regulated rate for distribution service, which is recorded in Operating revenues. For customers that choose to purchase electric generation from competitive suppliers, ACE acts as the billing agent and therefore, ACE does not record Operating revenues or Purchased power expense related to the electricity. For customers that choose to purchase electric generation from ACE, ACE is permitted to recover the electricity, ZEC, and REC procurement costs without mark-up and therefore records equal and offsetting amounts in Operating revenues and Purchased power expense related to the electricity, ZECs, and RECs. See Note 5 - Segment Information of the Combined Notes to Consolidated Financial Statements for the presentation of ACE's revenue disaggregation. The increase of $13 million for the year ended December 31, 2023 compared to same period in 2022, in Purchased power expense is fully offset in Operating revenues as part of regulatory required programs. The changes in Operating and maintenance expense consisted of the following: [[GREPCENT_TABLE]] [["","2023 vs. 2022"],["","Increase (Decrease)"],["Labor, other benefits, contracting and materials(a)","$","41"],["BSC and PHISCO costs","9"],["Pension and non-pension postretirement benefits expense","1"],["Storm-related costs","1"],["Credit loss expense","1"],["Other","3"],["","56"],["Regulatory required programs(b)","(1)"],["Total increase","$","55"]] [[/GREPCENT_TABLE]] __________ (a)Reflects an increase in contracting costs for the year ended December 31, 2023, primarily due to the ACE employee strike. 74 Table of Contents ACE (b)ACE is allowed to recover from or refund to customers the difference between its annual credit loss expense and the amounts collected in rates annually through the Societal Benefits Charge. The changes in Depreciation and amortization expense consisted of the following: [[GREPCENT_TABLE]] [["","2023 vs. 2022"],["","Increase (Decrease)"],["Depreciation and amortization(a)","$","23"],["Regulatory required programs(b)","(1)"],["Total increase","$","22"]] [[/GREPCENT_TABLE]] __________ (a)Depreciation and amortization increased primarily due to ongoing capital expenditures and higher transmission depreciation rates effective September 2022. (b)Regulatory required programs decreased primarily due to the regulatory asset amortization of the PPA termination obligation which is fully offset in Operating revenues. Interest expense, net increased $6 million for the year ended December 31, 2023 compared to the same period in 2022 primarily due to an increase in interest rates and the issuance of debt in 2022 and 2023. Effective income tax rates were 23.1% and 2.0% for the years ended December 31, 2023 and 2022, respectively. See Note 13 — 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 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, as of December 31, 2023. 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 16 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information on the Registrants’ debt and credit agreements. Cash flows related to Generation have not been presented as discontinued operations and are included in the Consolidated Statements of Cash Flows for all periods presented. The Exelon Consolidated Statement of Cash Flows for the year ended December 31, 2023 includes no cash flows from Generation. The Exelon Consolidated Statement of Cash Flows for the year ended December 31, 2022 includes one months of cash flows from Generation. See below for additional reasons for the changes in cash flows. 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 75 Table of Contents 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, and all of its costs of doing so will be recovered through a new 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 and Note 18 — 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 years ended December 31, 2023 and 2022 by Registrant: [[GREPCENT_TABLE]] [["Increase (decrease) in cash flows from operating activities","Exelon","","ComEd","","PECO","","BGE","","PHI","","Pepco","","DPL","","ACE"],["Net income","$","157","","","$","173","","","$","(13)","","","$","105","","","$","(18)","","","$","1","","","$","8","","","$","(28)"],["Adjustments to reconcile net income to cash:"],["Non-cash operating activities","(864)","","","(336)","","","(116)","","","(103)","","","28","","","34","","","(16)","","","5"],["Option premiums (paid), net","39","","","\u2014","","","\u2014","","","\u2014","","","\u2014","","","\u2014","","","\u2014","","","\u2014"],["Collateral (paid) received, net","(1,394)","","","18","","","\u2014","","","(41)","","","(344)","","","(49)","","","(199)","","","(96)"],["Income taxes","52","","","106","","","106","","","54","","","66","","","79","","","26","","","(11)"],["Pension and non-pension postretirement benefit contributions","487","","","143","","","17","","","49","","","54","","","(1)","","","(3)","","","4"],["Regulatory assets and liabilities, net","887","","","973","","","14","","","(132)","","","75","","","24","","","59","","","(28)"],["Changes in working capital and other noncurrent assets and liabilities","469","","","(426)","","","170","","","259","","","193","","","140","","","80","","","(29)"],["(Decrease) increase in cash flows from operating activities","$","(167)","","","$","651","","","$","178","","","$","191","","","$","54","","","$","228","","","$","(45)","","","$","(183)"]] [[/GREPCENT_TABLE]] 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 years ended December 31, 2023 and 2022 were as follows: •See Note 22 —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 Utility Registrants are dependent upon the credit exposure of procurement contracts that may require suppliers to post collateral. The amount of cash collateral received from external counterparties increased due to rising energy prices. See Note 15 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information. •See Note 13 — Income Taxes of the Combined Notes to Consolidated Financial Statements and the Registrants' Consolidated Statements of Cash Flows for additional information on income taxes. •Changes in Pension and non-pension postretirement benefit contributions relate to Exelon's funding strategy and incremental contributions made in 2022 in connection with the separation. See Note 14 — Retirement Benefits 76 Table of Contents •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 $416 million and $394 million for the years ended December 31, 2023 and 2022, respectively. Also included within the changes is energy efficiency and demand response programs spend for BGE, Pepco, DPL, and ACE of $132 million, $70 million, $25 million, and $20 million for the year ended December 31, 2023, respectively, and $113 million, $71 million, $28 million, and $11 million for the year ended December 31, 2022, respectively. PECO had no energy efficiency and demand response programs spend recorded to a regulatory asset for the years ended December 31, 2023 and 2022. See Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information. •Changes in working capital and other noncurrent assets and liabilities for the Utility Registrants and Exelon Corporate total $146 million and for Generation total $323 million. The change for Generation primarily relates to the revolving accounts receivable financing arrangement. The change in working capital and other noncurrent assets and liabilities for Exelon Corporate and the Utility Registrants is dependent upon the normal course of operations for all Registrants. For ComEd, it is also dependent upon whether the participating nuclear-powered generating facilities owe money to ComEd as a result of the established pricing for CMCs. For the year ended December 31, 2023, the established pricing resulted in ComEd owing payments to nuclear-powered generating facilities, which is reported within the cash flows from operations as a change in Accounts payable and accrued expense. Cash Flows from Investing Activities The following table provides a summary of the change in cash flows from investing activities for the years ended December 31, 2023 and 2022 by Registrant: [[GREPCENT_TABLE]] [["(Decrease) increase in cash flows from investing activities","Exelon","","ComEd","","PECO","","BGE","","PHI","","Pepco","","DPL","","ACE"],["Capital expenditures","$","(261)","","","$","(70)","","","$","(77)","","","$","(105)","","","$","(279)","","","$","(83)","","","$","(132)","","","$","(62)"],["Investment in NDT fund sales, net","28","","","\u2014","","","\u2014","","","\u2014","","","\u2014","","","\u2014","","","\u2014","","","\u2014"],["Collection of DPP","(169)","","","\u2014","","","\u2014","","","\u2014","","","\u2014","","","\u2014","","","\u2014","","","\u2014"],["Proceeds from sales of assets and businesses","9","","","\u2014","","","\u2014","","","\u2014","","","10","","","10","","","\u2014","","","\u2014"],["Other investing activities","8","","","(20)","","","(6)","","","(4)","","","2","","","5","","","(3)","","","(1)"],["(Decrease) increase in cash flows from investing activities","$","(385)","","","$","(90)","","","$","(83)","","","$","(109)","","","$","(267)","","","$","(68)","","","$","(135)","","","$","(63)"]] [[/GREPCENT_TABLE]] Significant investing cash flow impacts for the Registrants for 2023 and 2022 were as follows: •Variances in Capital expenditures are primarily due to the timing of cash expenditures for capital projects. See the "Credit Matters and Cash Requirements" section below for additional information on projected capital expenditure spending for the Utility Registrants. See Note 2 — Discontinued Operations of the Combined Notes to Consolidated Financial Statements for Capital expenditures related to Generation prior to the separation. •Collection of DPP relates to Generation's revolving accounts receivable financing agreement which Generation entered into in April 2020. 77 Table of Contents Cash Flows from Financing Activities The following table provides a summary of the change in cash flows from financing activities for the years ended December 31, 2023 and 2022 by Registrant: [[GREPCENT_TABLE]] [["(Decrease) increase in cash flows from financing activities","Exelon","","ComEd","","PECO","","BGE","","PHI","","Pepco","","DPL","","ACE"],["Changes in short-term borrowings, net","$","(2,199)","","","$","(402)","","","$","(313)","","","$","(350)","","","$","34","","","$","(291)","","","$","(18)","","","$","343"],["Long-term debt, net","(124)","","","225","","","100","","","150","","","(40)","","","35","","","25","","","(100)"],["Changes in intercompany money pool","\u2014","","","\u2014","","","\u2014","","","\u2014","","","(16)","","","\u2014","","","\u2014","","","\u2014"],["Issuance of common stock","(423)","","","\u2014","","","\u2014","","","\u2014","","","\u2014","","","\u2014","","","\u2014","","","\u2014"],["Dividends paid on common stock","(99)","","","(168)","","","(6)","","","(16)","","","\u2014","","","211","","","10","","","19"],["Repayments on short-term borrowings with maturities greater than 90 days","1,350","","","(150)","","","\u2014","","","\u2014","","","\u2014","","","\u2014","","","\u2014","","","\u2014"],["Distributions to member","\u2014","","","\u2014","","","\u2014","","","\u2014","","","237","","","\u2014","","","\u2014","","","\u2014"],["Contributions from parent/member","\u2014","","","(15)","","","74","","","99","","","(312)","","","(157)","","","(48)","","","(110)"],["Transfer of cash, restricted cash, and cash equivalents to Constellation","2,594","","","\u2014","","","\u2014","","","\u2014","","","\u2014","","","\u2014","","","\u2014","","","\u2014"],["Other financing activities","(7)","","","(3)","","","9","","","4","","","(19)","","","(16)","","","(6)","","","\u2014"],["Increase (decrease) in cash flows from financing activities","$","1,092","","","$","(513)","","","$","(136)","","","$","(113)","","","$","(116)","","","$","(218)","","","$","(37)","","","$","152"]] [[/GREPCENT_TABLE]] Significant financing cash flow impacts for the Registrants for 2023 and 2022 were as follows: •Changes in short-term borrowings, net, is driven by repayments on and issuances of notes due in less than 365 days. Refer to Note 16 — 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. Refer to the debt issuances and redemptions tables below for additional information for the Registrants. •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 2022 underwritten public offering of Exelon common stock as well as 2023 issuances under the ATM program. See Note 19 — 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 Combined Notes to Consolidated Financial Statements for additional information on dividend restrictions. See below for quarterly dividends declared. •Repayments on short-term borrowings, varies due to debt issuances and redemptions each year. Refer to Note 16 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information on repayments on short-term borrowings for the Registrants. •Refer to Note 2 — Discontinued Operations for the Transfer of cash, restricted cash, and cash equivalents to Constellation related to the separation. •Other financing activities primarily consists of debt issuance costs. See debt issuances table below for additional information on the Registrants’ debt issuances. 78 Table of Contents Debt Issuances and Redemptions See Note 16 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information of the Registrants’ long-term debt. Debt activity for 2023 and 2022 by Registrant was as follows: During 2023, the following long-term debt was issued: [[GREPCENT_TABLE]] [["Company","","Type","","Interest Rate","","Maturity","","Amount","","Use of Proceeds"],["Exelon","","Notes","","5.15%","","March 15, 2028","","$1,000","","Repay existing indebtedness and for general corporate purposes."],["Exelon","","Notes","","5.30%","","March 15, 2033","","850","","Repay existing indebtedness and for general corporate purposes."],["Exelon","","Notes","","5.60%","","March 15, 2053","","650","","Repay existing indebtedness and for general corporate purposes."],["ComEd","","First Mortgage Bonds, Series 134","","4.90%","","February 1, 2033","","400","","Repay outstanding commercial paper obligations and to fund other general corporate purposes."],["ComEd","","First Mortgage Bonds Series 135","","5.30%","","February 1, 2053","","575","","Repay outstanding commercial paper obligations and to fund other general corporate purposes."],["PECO","","First and Refunding Mortgage Bonds","","4.90%","","June 15, 2033","","575","","Refinance existing indebtedness, refinance outstanding commercial paper obligations, and for general corporate purposes."],["BGE","","Notes","","5.40%","","June 1, 2053","","700","","Repay outstanding commercial paper obligations, repay existing indebtedness, and for general corporate purposes."],["Pepco","","First Mortgage Bonds","","5.35%","","September 13, 2033","","100","","Repay existing indebtedness and for general corporate purposes."],["Pepco","","First Mortgage Bonds","","5.30%","","March 15, 2033","","85","","Repay existing indebtedness and for general corporate purposes."],["Pepco","","First Mortgage Bonds","","5.40%","","March 15, 2038","","40","","Repay existing indebtedness and for general corporate purposes."],["Pepco","","First Mortgage Bonds","","5.57%","","March 15, 2053","","125","","Repay existing indebtedness and for general corporate purposes."],["DPL","","First Mortgage Bonds","","5.30%","","March 15, 2033","","60","","Repay existing indebtedness and for general corporate purposes."],["DPL","","First Mortgage Bonds","","5.57%","","March 15, 2053","","65","","Repay existing indebtedness and for general corporate purposes."],["DPL","","First Mortgage Bonds","","5.45%","","November 8, 2033","","340","","Repay existing indebtedness and for general corporate purposes."],["DPL","","First Mortgage Bonds","","5.55%","","November 8, 2038","","75","","Repay existing indebtedness and for general corporate purposes."],["DPL","","First Mortgage Bonds","","5.72%","","November 8, 2053","","110","","Repay existing indebtedness and for general corporate purposes."],["ACE","","First Mortgage Bonds","","5.57%","","March 15, 2053","","75","","Repay existing indebtedness and for general corporate purposes."]] [[/GREPCENT_TABLE]] 79 Table of Contents During 2022, the following long-term debt was issued: [[GREPCENT_TABLE]] [["Company","","Type","","Interest Rate","","Maturity","","Amount","","Use of Proceeds"],["Exelon","","SMBC Term Loan Agreement","","SOFR plus 0.65%","","July 21, 2023(b)","","$300","","Fund a cash payment to Constellation and for general corporate purposes."],["Exelon","","U.S. Bank Term Loan Agreement","","SOFR plus 0.65%","","July 21, 2023(b)","","300","","Fund a cash payment to Constellation and for general corporate purposes."],["Exelon","","PNC Term Loan Agreement","","SOFR plus 0.65%","","July 24, 2023(b)","","250","","Fund a cash payment to Constellation and for general corporate purposes."],["Exelon","","Notes(a)","","2.75%","","March 15, 2027","","650","","Repay existing indebtedness and for general corporate purposes."],["Exelon","","Notes(a)","","3.35%","","March 15, 2032","","650","","Repay existing indebtedness and for general corporate purposes."],["Exelon","","Notes(a)","","4.10%","","March 15, 2052","","700","","Repay existing indebtedness and for general corporate purposes."],["Exelon","","Long-Term Software License Agreements","","2.30%","","December 1, 2025","","17","","Procurement of software licenses"],["Exelon","","Long-Term Software License Agreements","","3.70%","","August 9, 2025","","8","","Procurement of software licenses"],["Exelon","","SMBC Term Loan Agreement","","SOFR plus 0.85%","","April 7, 2024","","500","","Repay existing indebtedness and for general corporate purposes."],["ComEd","","First Mortgage Bonds, Series 132","","3.15%","","March 15, 2032","","300","","Repay outstanding commercial paper obligations and to fund other general corporate purposes."],["ComEd","","First Mortgage Bonds, Series 133","","3.85%","","March 15, 2052","","450","","Repay outstanding commercial paper obligations and to fund other general corporate purposes."],["PECO","","First and Refunding Mortgage Bonds","","4.60%","","May 15, 2052","","350","","Refinance existing indebtedness and for general corporate purposes."],["PECO","","First and Refunding Mortgage Bonds","","4.375%","","August 15, 2052","","425","","Refinance outstanding commercial paper and for general corporate purposes."],["BGE","","Notes","","4.55%","","June 1, 2052","","500","","Repay outstanding commercial paper obligations, repay existing indebtedness, and for general corporate purposes."],["Pepco","","First Mortgage Bonds","","3.97%","","March 24, 2052","","400","","Repay existing indebtedness and for general corporate purposes."],["Pepco","","First Mortgage Bonds","","3.35%","","September 15, 2032","","225","","Repay existing indebtedness and for general corporate purposes."],["DPL","","First Mortgage Bonds","","3.06%","","February 15, 2052","","125","","Repay existing indebtedness and for general corporate purposes."],["ACE","","First Mortgage Bonds","","2.27%","","February 15, 2032","","25","","Repay existing indebtedness and for general corporate purposes."],["ACE","","First Mortgage Bonds","","3.06%","","February 15, 2052","","150","","Repay existing indebtedness and for general corporate purposes."]] [[/GREPCENT_TABLE]] __________ (a)In connection with the issuance and sale of the Notes, Exelon entered into a Registration Rights Agreement with the representatives of the initial purchasers of the Notes and other parties. Pursuant to the Registration Rights Agreement, Exelon filed a registration statement on August 3, 2022, with respect to an offer to exchange the Notes for substantially similar notes of Exelon that are registered under the Securities Act. An exchange offer of registered notes for the Notes was completed on January 12, 2023. The registered notes issued in exchange for Notes in the exchange offer have terms identical in all respects to the Notes, except that their issuance was registered under the Securities Act. (b)During the third quarter of 2022, the SMBC Term Loan, U.S. Bank Term Loan, and PNC Term Loan were all reclassified to Long-term debt due within one year on the Exelon Consolidated Balance Sheet, given that the Term Loans have maturity dates of July 21, 2023, and July 24, 2023, respectively. 80 Table of Contents During 2023, the following long-term debt was retired and/or redeemed: [[GREPCENT_TABLE]] [["Company","","Type","","Interest Rate","","Maturity","","Amount"],["Exelon","","SMBC Term Loan Agreement","","SOFR plus 0.65%","","July 21, 2023","","$","300"],["Exelon","","US Bank Term Loan Agreement","","SOFR plus 0.65%","","July 21, 2023","","300"],["Exelon","","PNC Term Loan Agreement","","SOFR plus 0.65%","","July 24, 2023","","250"],["Exelon","","Long-Term Software License Agreement","","3.70%","","August 9, 2025","","6"],["Exelon","","Long-Term Software License Agreement","","3.95%","","May 1, 2024","","2"],["Exelon","","Long-Term Software License Agreement","","3.70%","","August 9, 2025","","1"],["Exelon","","Long-Term Software License Agreement","","2.30%","","December 1, 2025","","4"],["PECO","","Loan Agreement","","2.00%","","June 20, 2023","","50"],["BGE","","Notes","","3.35%","","July 1, 2023","","300"],["DPL","","First Mortgage Bonds","","3.50%","","November 15, 2023","","500"]] [[/GREPCENT_TABLE]] During 2022, the following long-term debt was retired and/or redeemed: [[GREPCENT_TABLE]] [["Company","","Type","","Interest Rate","","Maturity","","Amount"],["Exelon","","Junior Subordinated Notes","","3.50%","","May 2, 2022","","$","1,150"],["Exelon","","Long-Term Software License Agreement","","3.96%","","May 1, 2024","","2"],["Exelon","","Long-Term Software License Agreement","","2.30%","","December 1, 2025","","4"],["ComEd","","Long-Term Software License Agreement","","3.70%","","August 9, 2025","","1"],["PECO","","First Mortgage Bonds","","2.375%","","September 15, 2022","","350"],["BGE","","Notes","","2.80%","","August 15, 2022","","250"],["ACE","","First Mortgage Bonds","","3.05%","","April 1, 2022","","200"],["ACE","","Tax-Exempt Bonds","","1.70%","","September 1, 2022","","110"]] [[/GREPCENT_TABLE]] Additionally, in connection with the separation, on January 31, 2022, Exelon Corporate received cash from Generation of $258 million to settle an intercompany loan that mirrored the terms and amounts of the third-party debt obligations. The loan agreements were entered into as part of the 2012 Constellation merger. See Note 16 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information on the mirror debt. From time to time and as market conditions warrant, the Registrants may engage in long-term debt retirements via tender offers, open market repurchases or other viable options to reduce debt on their respective balance sheets. Dividends Quarterly dividends declared by the Exelon Board of Directors during the year ended December 31, 2023 and for the first quarter of 2024 were as follows: [[GREPCENT_TABLE]] [["Period","","Declaration Date","","Shareholder of Record Date","","Dividend Payable Date","","Cash per Share(a)"],["First Quarter 2023","","February 14, 2023","","February 27, 2023","","March 10, 2023","","$","0.3600"],["Second Quarter 2023","","April 25, 2023","","May 15, 2023","","June 9, 2023","","$","0.3600"],["Third Quarter 2023","","July 25, 2023","","August 15, 2023","","September 8, 2023","","$","0.3600"],["Fourth Quarter 2023","","November 1, 2023","","November 15, 2023","","December 8, 2023","","$","0.3600"],["First Quarter 2024","","February 21, 2024","","March 4, 2024","","March 15, 2024","","$","0.3800"]] [[/GREPCENT_TABLE]] ___________ (a)Exelon's Board of Directors approved an updated dividend policy for 2024. The 2024 quarterly dividend will be $0.38 per share. 81 Table of Contents Credit Matters and Cash Requirements The Registrants fund liquidity needs for capital expenditures, 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 $2.4 billion was available to support additional commercial paper as of December 31, 2023, and of which no financial institution has more than 6% of the aggregate commitments for the Registrants. The Registrants had access to the commercial paper markets and had availability under their revolving credit facilities during 2023 to fund their short-term liquidity needs, when necessary. Exelon Corporate and the Utility Registrants each have a 5-year revolving credit facility. See Note 16 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information. The Registrants had access to the commercial paper markets and had availability under their revolving credit facilities during 2023 to fund their short-term liquidity needs, when necessary. 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 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 for additional information regarding the effects of uncertainty in the capital and credit markets. The Registrants believe their cash flow from operating activities, access to credit markets, and their credit facilities provide sufficient liquidity to support the estimated future cash requirements discussed below. On August 4, 2022, Exelon entered into an agreement with certain underwriters in connection with an underwritten public offering of 12.995 million shares of its Common stock, no par value. The net proceeds were $563 million before expenses paid. Exelon used the proceeds, together with available cash balances, to repay $575 million in borrowings under a $1.15 billion term loan credit facility. See Note 19 — Shareholders' Equity and Note 16 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information. On August 4, 2022, Exelon executed an equity distribution agreement (“Equity Distribution Agreement”) with certain sales agents and forward sellers and certain forward purchasers establishing an ATM equity distribution program under which it may offer and sell shares of its Common stock, having an aggregate gross sales price of up to $1.0 billion. Exelon has no obligation to offer or sell any shares of Common stock under the Equity Distribution Agreement and may at any time suspend or terminate offers and sales under the Equity Distribution Agreement. In November and December 2023, Exelon issued approximately 3.6 million shares of Common stock at an average gross price of $39.58 per share. The net proceeds from these issuances were $140 million, which were used for general corporate purposes. As of December 31, 2023, $858 million of Common stock remained available for sale pursuant to the ATM program. Pursuant to the Separation Agreement between Exelon and Constellation Energy Corporation, Exelon made a cash payment of $1.75 billion to Generation on January 31, 2022. See Note 2 — Discontinued Operations of the Combined Notes to Consolidated Financial Statements for additional information on the separation. The following table presents the incremental collateral that each Utility Registrant would have been required to provide in the event each Utility Registrant lost its investment grade credit rating at December 31, 2023 and available credit facility capacity prior to any incremental collateral at December 31, 2023: [[GREPCENT_TABLE]] [["","PJM Credit Policy Collateral","","Other Incremental Collateral Required(a)","","Available Credit Facility Capacity Prior to Any Incremental Collateral"],["ComEd","$","\u2014","","","$","\u2014","","","$","788"],["PECO","\u2014","","","25","","","435"],["BGE","\u2014","","","61","","","258"],["Pepco","\u2014","","","\u2014","","","168"],["DPL","\u2014","","","10","","","237"],["ACE","\u2014","","","\u2014","","","101"]] [[/GREPCENT_TABLE]] __________ (a)Represents incremental collateral related to natural gas procurement contracts. 82 Table of Contents Capital Expenditures As of December 31, 2023, estimates of capital expenditures for plant additions and improvements are as follows: [[GREPCENT_TABLE]] [["(in millions)(a)","2024 Transmission","","2024 Distribution","","2024 Gas","","Total 2024","","Beyond 2024(b)"],["Exelon","N/A","","N/A","","N/A","","$","7,425","","","$","27,100"],["ComEd (c)","550","","","1,600","","","N/A","","2,150","","","9,150"],["PECO","75","","","1,225","","","400","","","1,700","","","5,650"],["BGE","475","","","625","","","500","","","1,600","","","6,075"],["PHI","550","","","1,325","","","100","","","1,975","","","6,275"],["Pepco","200","","","750","","","N/A","","950","","","2,925"],["DPL","200","","","325","","","100","","","600","","","1,825"],["ACE","150","","","275","","","N/A","","425","","","1,500"]] [[/GREPCENT_TABLE]] ___________ (a)Numbers rounded to the nearest $25M and may not sum due to rounding. (b)Includes estimated capital expenditures for the Utility Registrants from 2025 to 2027. (c)Effective in 2024, ComEd has chosen to update its rate of capitalization of certain overhead costs on a prospective basis. Projected capital expenditures and other investments are subject to periodic review and revision to reflect changes in economic conditions and other factors. Projected capital expenditures at the Utility Registrants are for continuing projects to maintain and improve operations, including enhancing reliability and adding capacity to the transmission and distribution systems. The Utility Registrants anticipate that they will fund their capital expenditures with a combination of internally generated funds and borrowings and additional capital contributions from parent. 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 below 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 $93 million in 2024. Unlike the qualified pension plans, Exelon’s non-qualified pension plans are not funded, given they are not subject to statutory minimum contribution requirements. While OPEB plans are also not subject to statutory minimum contribution requirements, Exelon does fund certain of its plans. For Exelon's funded OPEB plans, contributions generally equal accounting costs, however, Exelon’s management has historically considered several factors in determining the level of contributions to its OPEB plans, including liabilities management, levels of benefit claims paid, and regulatory implications (amounts deemed prudent to meet regulatory expectations and best assure continued rate recovery). The amounts below include benefit payments related to unfunded plans. 83 Table of Contents The following table provides all Registrants' planned contributions to the qualified pension plans, planned benefit payments to non-qualified pension plans, and planned contributions to OPEB plans in 2024: [[GREPCENT_TABLE]] [["","Qualified Pension Plans","","Non-Qualified Pension Plans","","OPEB"],["Exelon","$","93","","","$","15","","","$","47"],["ComEd","3","","","1","","","18"],["PECO","2","","","1","","","1"],["BGE","17","","","1","","","14"],["PHI","66","","","8","","","11"],["Pepco","\u2014","","","1","","","10"],["DPL","\u2014","","","\u2014","","","\u2014"],["ACE","7","","","\u2014","","","\u2014"]] [[/GREPCENT_TABLE]] 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 for additional information on pension and OPEB contributions. Cash Requirements for Other Financial Commitments The following tables summarize the Registrants' future estimated cash payments as of December 31, 2023 under existing financial commitments: Exelon [[GREPCENT_TABLE]] [["","2024","","Beyond 2024","","Total","","Time Period"],["Long-term debt and finance leases(a)","$","1,403","","","$","39,876","","","$","41,279","","","2024 - 2053"],["Interest payments on long-term debt(b)","1,659","","","26,936","","","28,595","","","2024 - 2053"],["Operating leases","49","","","302","","","351","","","2024 - 2099"],["Fuel purchase agreements(c)","281","","","1,557","","","1,838","","","2024 - 2039"],["Electric supply procurement","3,808","","","2,222","","","6,030","","","2024 - 2027"],["Long-term renewable energy and REC commitments","366","","","1,672","","","2,038","","","2024 - 2038"],["Other purchase obligations(d)","4,839","","","3,236","","","8,075","","","2024 - 2031"],["DC PLUG obligation","3","","","\u2014","","","3","","","2024"],["ZEC commitments","218","","","421","","","639","","","2024 - 2027"],["Pension contributions(e)","93","","","1,000","","","1,093","","","2024 - 2029"],["Total cash requirements","$","12,719","","","$","77,222","","","$","89,941"]] [[/GREPCENT_TABLE]] __________ (a)Includes amounts from ComEd and PECO financing trusts. (b)Interest payments are estimated based on final maturity dates of debt securities outstanding as of December 31, 2023 and do not reflect anticipated future refinancing, early redemptions, or debt issuances. Variable rate interest obligations are estimated based on rates as of December 31, 2023. Includes estimated interest payments due to ComEd and PECO financing trusts. (c)Represents commitments to purchase natural gas and related transportation, storage capacity, and services. (d)Represents the future estimated value at December 31, 2023 of the cash flows associated with all contracts, both cancellable and non-cancellable, entered into between the Registrants or subsidiary and third-parties for the provision of services and materials, entered into in the normal course of business not specifically reflected elsewhere in this table. These estimates are subject to significant variability from period to period. (e)These amounts represent Exelon’s expected contributions to its qualified pension plans. Qualified pension contributions for years after 2029 are not included. 84 Table of Contents ComEd [[GREPCENT_TABLE]] [["","2024","","Beyond 2024","","Total","","Time Period"],["Long-term debt(a)","$","250","","","$","11,567","","","$","11,817","","","2024 - 2053"],["Interest payments on long-term debt(b)","470","","","8,240","","","8,710","","","2024 - 2053"],["Operating leases","\u2014","","","\u2014","","","\u2014","","","2024 - 2026"],["Electric supply procurement","417","","","196","","","613","","","2024 - 2026"],["Long-term renewable energy and REC commitments","336","","","1,523","","","1,859","","","2024 - 2038"],["Other purchase obligations(c)","1,244","","","835","","","2,079","","","2024 - 2031"],["ZEC commitments","218","","","421","","","639","","","2024 - 2027"],["Total cash requirements","$","2,935","","","$","22,782","","","$","25,717"]] [[/GREPCENT_TABLE]] __________ (a)Includes amounts from ComEd financing trust. (b)Interest payments are estimated based on final maturity dates of debt securities outstanding as of December 31, 2023 and do not reflect anticipated future refinancing, early redemptions, or debt issuances. Includes estimated interest payments due to the ComEd financing trust. (c)Represents the future estimated value, as of December 31, 2023, of the cash flows associated with all contracts, both cancellable and non-cancellable, entered into between ComEd and third-parties for the provision of services and materials, entered into in the normal course of business not specifically reflected elsewhere in this table. These estimates are subject to significant variability from period to period. PECO [[GREPCENT_TABLE]] [["","2024","","Beyond 2024","","Total","","Time Period"],["Long-term debt(a)","$","\u2014","","","$","5,384","","","$","5,384","","","2024 - 2052"],["Interest payments on long-term debt(b)","222","","","4,097","","","4,319","","","2024 - 2052"],["Operating leases","\u2014","","","\u2014","","","\u2014","","","2024 - 2034"],["Fuel purchase agreements(c)","140","","","571","","","711","","","2024 - 2039"],["Electric supply procurement","729","","","183","","","912","","","2024 - 2025"],["Other purchase obligations(d)","785","","","759","","","1,544","","","2024 - 2031"],["Total cash requirements","$","1,876","","","$","10,994","","","$","12,870"]] [[/GREPCENT_TABLE]] __________ (a)Includes amounts from PECO financing trusts. (b)Interest payments are estimated based on final maturity dates of debt securities outstanding as of December 31, 2023 and do not reflect anticipated future refinancing, early redemptions, or debt issuances. Includes estimated interest payments due to the PECO financing trusts. (c)Represents commitments to purchase natural gas and related transportation, storage capacity, and services. (d)Represents the future estimated value, as of December 31, 2023, of the cash flows associated with all contracts, both cancellable and non-cancellable, entered into between PECO and third-parties for the provision of services and materials, entered into in the normal course of business not specifically reflected elsewhere in this table. These estimates are subject to significant variability from period to period. 85 Table of Contents BGE [[GREPCENT_TABLE]] [["","2024","","Beyond 2024","","Total","","Time Period"],["Long-term debt","$","\u2014","","","$","4,650","","","$","4,650","","","2024 - 2053"],["Interest payments on long-term debt(a)","184","","","3,775","","","3,959","","","2024 - 2053"],["Operating leases","4","","","34","","","38","","","2024 - 2099"],["Fuel purchase agreements(b)","108","","","792","","","900","","","2024 - 2038"],["Electric supply procurement","1,097","","","746","","","1,843","","","2024 - 2026"],["Other purchase obligations(c)","928","","","433","","","1,361","","","2024 - 2029"],["Total cash requirements","$","2,321","","","$","10,430","","","$","12,751"]] [[/GREPCENT_TABLE]] __________ (a)Interest payments are estimated based on final maturity dates of debt securities outstanding as of December 31, 2023 and do not reflect anticipated future refinancing, early redemptions, or debt issuances. (b)Represents commitments to purchase natural gas and related transportation, storage capacity, and services. (c)Represents the future estimated value, as of December 31, 2023, of the cash flows associated with all contracts, both cancellable and non-cancellable, entered into between BGE and third-parties for the provision of services and materials, entered into in the normal course of business not specifically reflected elsewhere in this table. These estimates are subject to significant variability from period to period. PHI [[GREPCENT_TABLE]] [["","2024","","Beyond 2024","","Total","","Time Period"],["Long-term debt and finance leases","$","644","","","$","7,631","","","$","8,275","","","2024 - 2053"],["Interest payments on long-term debt(a)","296","","","4,500","","","4,796","","","2024 - 2053"],["Operating leases","36","","","164","","","200","","","2024 - 2032"],["Fuel purchase agreements(b)","33","","","194","","","227","","","2024 - 2029"],["Electric supply procurement","1,565","","","1,097","","","2,662","","","2024 - 2027"],["Long-term renewable energy and REC commitments","30","","","149","","","179","","","2024 - 2033"],["Other purchase obligations(c)","1,379","","","394","","","1,773","","","2024 - 2031"],["DC PLUG obligation","3","","","\u2014","","","3","","","2024"],["Total cash requirements","$","3,986","","","$","14,129","","","$","18,115"]] [[/GREPCENT_TABLE]] __________ (a)Interest payments are estimated based on final maturity dates of debt securities outstanding as of December 31, 2023 and do not reflect anticipated future refinancing, early redemptions, or debt issuances. Variable rate interest obligations are estimated based on rates as of December 31, 2023. (b)Represents commitments to purchase natural gas and related transportation, storage capacity, and services. (c)Represents the future estimated value, as of December 31, 2023, of the cash flows associated with all contracts, both cancellable and non-cancellable, entered into between Pepco, DPL, ACE, and PHISCO and third-parties for the provision of services and materials, entered into in the normal course of business not specifically reflected elsewhere in this table. These estimates are subject to significant variability from period to period. 86 Table of Contents Pepco [[GREPCENT_TABLE]] [["","2024","","Beyond 2024","","Total","","Time Period"],["Long-term debt and finance leases","$","405","","","$","3,746","","","$","4,151","","","2024 - 2053"],["Interest payments on long-term debt(a)","152","","","2,809","","","2,961","","","2024 - 2053"],["Operating leases","7","","","34","","","41","","","2024 - 2032"],["Electric supply procurement","776","","","574","","","1,350","","","2024 - 2027"],["Other purchase obligations(b)","661","","","231","","","892","","","2024 - 2031"],["DC PLUG obligation","3","","","\u2014","","","3","","","2024"],["Total cash requirements","$","2,004","","","$","7,394","","","$","9,398"]] [[/GREPCENT_TABLE]] __________  (a)Interest payments are estimated based on final maturity dates of debt securities outstanding as of December 31, 2023 and do not reflect anticipated future refinancing, early redemptions, or debt issuances. (b)Represents the future estimated value, as of December 31, 2023, of the cash flows associated with all contracts, both cancellable and non-cancellable, entered into between Pepco and third-parties for the provision of services and materials, entered into in the normal course of business not specifically reflected elsewhere in this table. These estimates are subject to significant variability from period to period. DPL [[GREPCENT_TABLE]] [["","2024","","Beyond 2024","","Total","","Time Period"],["Long-term debt and finance leases","$","84","","","$","2,012","","","$","2,096","","","2024 - 2053"],["Interest payments on long-term debt(a)","70","","","1,048","","","1,118","","","2024 - 2053"],["Operating leases","9","","","46","","","55","","","2024 - 2031"],["Fuel purchase agreements(b)","33","","","194","","","227","","","2024 - 2029"],["Electric supply procurement","445","","","245","","","690","","","2024 - 2026"],["Long-term renewable energy and REC commitments","30","","","149","","","179","","","2024 - 2033"],["Other purchase obligations(c)","291","","","81","","","372","","","2024 - 2031"],["Total cash requirements","$","962","","","$","3,775","","","$","4,737"]] [[/GREPCENT_TABLE]] __________ (a)Interest payments are estimated based on final maturity dates of debt securities outstanding as of December 31, 2023 and do not reflect anticipated future refinancing, early redemptions, or debt issuances. Variable rate interest obligations are estimated based on rates as of December 31, 2023. (b)Represents commitments to purchase natural gas and related transportation, storage capacity, and services. (c)Represents the future estimated value, as of December 31, 2023, of the cash flows associated with all contracts, both cancellable and non-cancellable, entered into between DPL and third-parties for the provision of services and materials, entered into in the normal course of business not specifically reflected elsewhere in this table. These estimates are subject to significant variability from period to period. 87 Table of Contents ACE [[GREPCENT_TABLE]] [["","2024","","Beyond 2024","","Total","","Time Period"],["Long-term debt and finance leases","$","154","","","$","1,688","","","$","1,842","","","2024 - 2053"],["Interest payments on long-term debt(a)","60","","","537","","","597","","","2024 - 2053"],["Operating leases","3","","","7","","","10","","","2024 - 2029"],["Electric supply procurement","344","","","278","","","622","","","2024 - 2026"],["Other purchase obligations(b)","386","","","53","","","439","","","2024 - 2028"],["Total cash requirements","$","947","","","$","2,563","","","$","3,510"]] [[/GREPCENT_TABLE]] __________ (a)Interest payments are estimated based on final maturity dates of debt securities outstanding as of December 31, 2023 and do not reflect anticipated future refinancing, early redemptions, or debt issuances. (b)Represents the future estimated value, as of December 31, 2023, of the cash flows associated with all contracts, both cancellable and non-cancellable, entered into between ACE and third-parties for the provision of services and materials, entered into in the normal course of business not specifically reflected elsewhere in this table. These estimates are subject to significant variability from period to period. See Note 18 — Commitments and Contingencies and Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information of the Registrants’ other commitments potentially triggered by future events. Additionally, see below for where to find additional information regarding the financial commitments in the tables above in the Combined Notes to the Consolidated Financial Statements: [[GREPCENT_TABLE]] [["Item","Location within Notes to the Consolidated Financial Statements"],["Long-term debt","Note 16 \u2014 Debt and Credit Agreements"],["Interest payments on long-term debt","Note 16 \u2014 Debt and Credit Agreements"],["Finance leases","Note 10 \u2014 Leases"],["Operating leases","Note 10 \u2014 Leases"],["Long-term renewable energy and REC commitments","Note 3 \u2014 Regulatory Matters"],["ZEC commitments","Note 3 \u2014 Regulatory Matters"],["DC PLUG obligation","Note 3 \u2014 Regulatory Matters"],["Pension contributions","Note 14 \u2014 Retirement Benefits"]] [[/GREPCENT_TABLE]] 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 16 — 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. 88 Table of Contents Capital Structure As of December 31, 2023, the capital structures of the Registrants consisted of the following: [[GREPCENT_TABLE]] [["","Exelon(a)","","ComEd","","PECO","","BGE","","PHI","","Pepco","","DPL","","ACE"],["Long-term debt","59","%","","43","%","","44","%","","44","%","","42","%","","49","%","","49","%","","48","%"],["Long-term debt to affiliates(b)","1","%","","1","%","","2","%","","\u2014","%","","\u2014","%","","\u2014","%","","\u2014","%","","\u2014","%"],["Common equity","37","%","","54","%","","53","%","","53","%","","\u2014","%","","49","%","","49","%","","47","%"],["Member\u2019s equity","\u2014","%","","\u2014","%","","\u2014","%","","\u2014","%","","56","%","","\u2014","%","","\u2014","%","","\u2014","%"],["Commercial paper and notes payable","3","%","","2","%","","1","%","","3","%","","2","%","","2","%","","2","%","","5","%"]] [[/GREPCENT_TABLE]] __________  (a)As of December 31, 2022, Exelon's Long-term debt and Common equity capital structure percentages were 57% and 38%, respectively. The change in capital structure percentages above is a result of a decrease in common equity due to the separation of Constellation in addition to an increase in long-term debt issuances. See Note 2 — Discontinued Operations for additional information regarding the separation. (b)Includes approximately $390 million, $205 million, and $184 million owed to unconsolidated affiliates of Exelon, ComEd, and PECO respectively. These special purpose entities were created for the sole purposes of issuing mandatory redeemable trust preferred securities of ComEd and PECO. 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 additional collateral. See Note 15 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information on collateral provisions. The credit ratings for Exelon Corporate, PECO, BGE, PHI, Pepco, DPL, and ACE did not change for the year ended December 31, 2023. On July 26, 2023, S&P raised ComEd's long-term issuer credit rating from 'BBB+' to a 'A-'. S&P also affirmed the current 'A' rating on ComEd's senior secured debt and 'A-2' short-term rating, which influences long and short-term borrowing cost. On December 20, 2023, Moody's revised its outlook on ComEd to negative from stable due to the final order issued by the ICC on December 14, 2023 rejecting ComEd's proposed Grid Plan and establishing retail rates for 2024-2027 as further discussed in Note 3 — Regulatory Matters. At the same time, Moody's affirmed ComEd's current 'A1' senior secured debt rating and its 'P-2' short-term rating. 89 Table of Contents 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 December 31, 2023, are presented in the following tables. [[GREPCENT_TABLE]] [["","For the Year Ended December 31, 2023","","As of December 31, 2023"],["Exelon Intercompany Money Pool","Maximum Contributed","","Maximum Borrowed","","Contributed (Borrowed)"],["Exelon Corporate","$","510","","","$","\u2014","","","$","225"],["PECO","305","","","(238)","","","\u2014"],["BSC","\u2014","","","(350)","","","(205)"],["PHI Corporate","\u2014","","","(65)","","","(65)"],["PCI","45","","","\u2014","","","45"]] [[/GREPCENT_TABLE]] [[GREPCENT_TABLE]] [["","For the Year Ended December 31, 2023","","As of December 31, 2023"],["PHI Intercompany Money Pool","Maximum Contributed","","Maximum Borrowed","","Contributed (Borrowed)"],["Pepco","$","106","","","$","(55)","","","$","\u2014"],["DPL","147","","","(2)","","","\u2014"],["ACE","\u2014","","","(147)","","","\u2014"]] [[/GREPCENT_TABLE]] Shelf Registration Statements Exelon, ComEd and Pepco have a currently effective combined shelf registration statement that expires in 2025. PECO and BGE plan to file a new combined shelf registration in the first quarter of 2024. DPL and ACE periodically issue securities through the private placement markets. The ability of each Registrant to sell securities off the shelf registration statement or to access the private placement markets will depend on a number of factors at the time of the proposed sale, including other required regulatory approvals, as applicable, the current financial condition of the Registrant, its securities ratings and market conditions. Regulatory Authorizations The Utility Registrants are required to obtain short-term and long-term financing authority from Federal and State Commissions as follows: [[GREPCENT_TABLE]] [["","","At December 31, 2023"],["","","Short-term Financing Authority (f)","","Remaining Long-term Financing Authority"],["Commission","","Expiration Date","","Amount","Commission","","Expiration Date","","Amount"],["ComEd(a)","","FERC","","December 31, 2025","","$","2,500","","","ICC","","January 1, 2025","","$","368"],["PECO","","FERC","","December 31, 2025","","1,500","","","PAPUC","","December 31, 2024","","550"],["BGE(b)","","FERC","","December 31, 2025","","700","","","MDPSC","","N/A","","1,100"],["Pepco(c)","","FERC","","December 31, 2025","","500","","","MDPSC / DCPSC","","December 31, 2025","","1,050"],["DPL(d)","","FERC","","December 31, 2025","","500","","","MDPSC / DEPSC","","December 31, 2025","","550"],["ACE(e)","","NJBPU","","December 31, 2025","","350","","","NJBPU","","December 31, 2024","","625"]] [[/GREPCENT_TABLE]] __________ (a)On June 29, 2023, ComEd filed an application for $2 billion in new money long-term debt financing authority from the ICC, which was approved on December 14, 2023. The finance authority under the approved application has an effective date of January 1, 2024, and extends the expiration date to January 1, 2027. (b)On December 21, 2022, BGE received approval from the MDPSC for $1.8 billion in new long-term financing authority with an effective date of January 4, 2023. (c)On June 9, 2022 and June 30, 2022, Pepco received approval from the MDPSC and DCPSC, respectively, for $1.4 billion in new long-term financing authority. The long-term financing authority became effective on the date of respective approvals and has an expiration date of December 31, 2025. 90 Table of Contents (d)On November 2, 2022, DPL filed with the MDPSC and DEPSC for approval of $1.2 billion in new long-term financing authority with an effective date of December 14, 2022. The financing authority filed with MDPSC does not have an expiration date, while the financing authority filed with DEPSC has an expiration date of December 31, 2025. (e)On July 14, 2023, ACE filed an application with the NJBPU for renewal of its short-term financing authority through December 31, 2025. ACE received approval on December 20, 2023. (f)On October 2, 2023, ComEd, PECO, BGE, Pepco, and DPL filed applications with FERC for renewal of their short-term financing authority through December 31, 2025. ComEd, PECO, Pepco, and DPL received approval on December 7, 2023. BGE received approval on December 8, 2023.