EXC 10-K Fiscal year ended Dec. 31, 2023

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Description of Business (All Registrants)

Exelon is a utility services holding company engaged in the energy transmission and distribution businesses through ComEd, PECO, BGE, Pepco, DPL, and ACE.

On February 21, 2021, Exelon’s Board of Directors approved a plan to separate the Utility Registrants and Generation. The separation was completed on February 1, 2022, creating two publicly traded companies, Exelon and Constellation. See Note 2 — Discontinued Operations for additional information.

Name of Registrant

Business

Service Territories

Commonwealth Edison Company

Purchase and regulated retail sale of electricity

Northern Illinois, including the City of Chicago

Transmission and distribution of electricity to retail customers

PECO Energy Company

Purchase and regulated retail sale of electricity and natural gas

Southeastern Pennsylvania, including the City of Philadelphia (electricity)

Transmission and distribution of electricity and distribution of natural gas to retail customers

Pennsylvania counties surrounding the City of Philadelphia (natural gas)

Baltimore Gas and Electric Company

Purchase and regulated retail sale of electricity and natural gas

Central Maryland, including the City of Baltimore (electricity and natural gas)

Transmission and distribution of electricity and distribution of natural gas to retail customers

Pepco Holdings LLC

Utility services holding company engaged, through its reportable segments Pepco, DPL, and ACE

Service Territories of Pepco, DPL, and ACE

Potomac Electric Power Company

Purchase and regulated retail sale of electricity

District of Columbia, and major portions of Montgomery and Prince George’s Counties, Maryland.

Transmission and distribution of electricity to retail customers

Delmarva Power &  Light Company

Purchase and regulated retail sale of electricity and natural gas

Portions of Delaware and Maryland (electricity)

Transmission and distribution of electricity and distribution of natural gas to retail customers

Portions of New Castle County, Delaware (natural gas)

Atlantic City Electric Company

Purchase and regulated retail sale of electricity

Portions of Southern New Jersey

Transmission and distribution of electricity to retail customers

Basis of Presentation (All Registrants)

This is a combined annual report of all Registrants. The Notes to the Consolidated Financial Statements apply to the Registrants as indicated parenthetically next to each corresponding disclosure. When appropriate, the Registrants are named specifically for their related activities and disclosures. Each of the Registrant’s Consolidated Financial Statements includes the accounts of its subsidiaries. All intercompany transactions have been eliminated, except for the historical transactions between the Utility Registrants and Generation for the purposes of presenting discontinued operations in all periods presented in the Consolidated Statements of Operations and Comprehensive Income.

Through its business services subsidiary, BSC, Exelon provides its subsidiaries with a variety of support services at cost, including legal, human resources, financial, information technology, and supply management services. PHI also has a business services subsidiary, PHISCO, which provides a variety of support services at cost, including legal, finance, engineering, customer operations, transmission and distribution planning, asset management, system operations, and power procurement, to PHI operating Registrants. The costs of BSC and PHISCO are directly charged or allocated to the applicable subsidiaries. The results of Exelon’s corporate operations are presented as “Other” within the consolidated financial statements and include intercompany eliminations unless otherwise disclosed.

As of December 31, 2023 and 2022, Exelon owned 100 % of PECO, BGE, and PHI and more than 99 % of ComEd. PHI owns 100 % of Pepco, DPL, and ACE. As of December 31, 2021, Exelon owned 100 % of Generation. As of February 1, 2022, as a result of the completion of the separation, Exelon no longer owns any interest in Generation. The separation of Constellation, including Generation and its subsidiaries, meets the

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criteria for discontinued operations and as such, its results of operations are presented as discontinued operations and have been excluded from continuing operations for all periods presented. Accounting rules require that certain BSC costs previously allocated to Generation be presented as part of Exelon’s continuing operations as these costs do not qualify as expenses of the discontinued operations. Comprehensive income, shareholders' equity, and cash flows related to Generation have not been segregated and are included in the Consolidated Statements of Operations and Comprehensive Income, Consolidated Statements of Changes in Shareholders’ Equity, and Consolidated Statements of Cash Flows, respectively, for the periods ended December 31, 2022 and December 31, 2021. See Note 2 — Discontinued Operations for additional information.

The accompanying consolidated financial statements have been prepared in accordance with GAAP for annual financial statements and in accordance with the instructions to Form 10-K and Regulation S-X promulgated by the SEC.

COVID-19 (All Registrants)

The Registrants have taken steps to mitigate the potential risks posed by the global outbreak (pandemic) of the 2019 novel coronavirus (COVID-19). The Registrants provide a critical service to their customers and have taken measures to keep employees who operate the business safe and minimize unnecessary risk of exposure to the virus, including extra precautions for employees who work in the field. The Registrants have implemented work from home policies where appropriate.

Management makes estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities as of the date of the financial statements and accompanying notes, and the amounts of revenues and expenses reported during the periods covered by those financial statements and accompanying notes. As of December 31, 2023 and 2022, and through the date of this report, management assessed certain accounting matters that require consideration of forecasted financial information, including, but not limited to, allowance for credit losses and the carrying value of goodwill and other long-lived assets, in context with the information reasonably available and the unknown future impacts of COVID-19. The Registrants' future assessment of the magnitude and duration of COVID-19, as well as other factors, could result in material impacts to their consolidated financial statements in future reporting periods.

Use of Estimates (All Registrants)

The preparation of financial statements of each of the Registrants in conformity with GAAP requires management to make estimates and assumptions that affect the amounts reported in the financial statements and accompanying notes. Areas in which significant estimates have been made include, but are not limited to, the accounting for pension and OPEB, unbilled energy revenues, allowance for credit losses, inventory reserves, goodwill and long-lived asset impairment assessments, derivative instruments, unamortized energy contracts, fixed asset depreciation, environmental costs and other loss contingencies, AROs, and taxes. Actual results could differ from those estimates.

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) there is a reasonable expectation that rates designed to recover costs can be charged to and collected from customers. The Registrants account for their regulated operations in accordance with regulatory and legislative guidance from the regulatory authorities having jurisdiction, principally the ICC, PAPUC, MDPSC, DCPSC, DEPSC, and NJBPU, under state public utility laws and the FERC under various Federal laws. Regulatory assets and liabilities are amortized and the related expense or revenue is recognized in the Consolidated Statements of Operations consistent with the recovery or refund included in customer rates. The Registrants' regulatory assets and liabilities as of the balance sheet date are probable of being recovered or settled in future rates. If a separable portion of the Registrants' business was no longer able to meet the criteria discussed above, the affected entities would be required to eliminate from their consolidated financial statements the effects of regulation for that portion, which could have a material impact on their financial statements. See Note 3 — Regulatory Matters for additional information.

With the exception of income tax-related regulatory assets and liabilities, the Registrants classify regulatory assets and liabilities with a recovery or settlement period greater than one year as both current and noncurrent in

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their Consolidated Balance Sheets, with the current portion representing the amount expected to be recovered from or refunded to customers over the next twelve-month period as of the balance sheet date. Income tax-related regulatory assets and liabilities are classified entirely as noncurrent in the Registrants’ Consolidated Balance Sheets to align with the classification of the related deferred income tax balances.

The Registrants treat the impacts of a final rate order received after the balance sheet date but prior to the issuance of the financial statements as a non-recognized subsequent event, as the receipt of a final rate order is a separate and distinct event that has future impacts on the parties affected by the order.

Revenues (All Registrants)

Operating Revenues. The Registrants’ operating revenues generally consist of revenues from contracts with customers involving the sale and delivery of power and natural gas and utility revenues from ARP. The Registrants recognize revenue from contracts with customers to depict the transfer of goods or services to customers in an amount that the entities expect to be entitled to in exchange for those goods or services. The primary sources of revenue include regulated electric and natural gas tariff sales, distribution, and transmission services. At the end of each month, the Registrants accrue an estimate for the unbilled amount of energy delivered or services provided to customers.

ComEd records ARP revenue for its best estimate of the electric distribution, energy efficiency, 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. The Registrants recognize all ARP revenues that will be collected within 24 months of the end of the annual period in which they are recorded. See Note 3 — Regulatory Matters for additional information.

Taxes Directly Imposed on Revenue-Producing Transactions. The Registrants collect certain taxes from customers such as sales and gross receipts taxes, along with other taxes, surcharges, and fees, that are levied by state or local governments on the sale or distribution of electricity and gas. Some of these taxes are imposed on the customer, but paid by the Registrants, while others are imposed on the Registrants. Where these taxes are imposed on the customer, such as sales taxes, they are reported on a net basis with no impact to the Consolidated Statements of Operations and Comprehensive Income. However, where these taxes are imposed on the Registrants, such as gross receipts taxes or other surcharges or fees, they are reported on a gross basis. Accordingly, revenues are recognized for the taxes collected from customers along with an offsetting expense. Se e Note 22 — Supplemental Financial Information for taxes that are presented on a gross basis.

Leases (All Registrants)

The Registrants recognize a ROU asset and lease liability for operating and finance leases with a term of greater than one year. Operating lease ROU assets are included in Other deferred debits and other assets and operating lease liabilities are included in Other current liabilities and Other deferred credits and other liabilities on the Consolidated Balance Sheets. Finance lease ROU assets are included in Plant, property, and equipment, net and finance lease liabilities are included in Long-term debt due within one year and Long-term debt on the Consolidated Balance Sheets. The ROU asset is measured as the sum of (1) the present value of all remaining fixed and in-substance fixed payments using the rate implicit in the lease whenever that is readily determinable or each Registrant’s incremental borrowing rate, (2) any lease payments made at or before the commencement date (less any lease incentives received), and (3) any initial direct costs incurred. The lease liability is measured the same as the ROU asset, but excludes any payments made before the commencement date and initial direct costs incurred. Lease terms include options to extend or terminate the lease if it is reasonably certain they will be exercised. The Registrants include non-lease components, which are service-related costs that are not integral to the use of the asset, in the measurement of the ROU asset and lease liability.

Expense for operating leases and leases with a term of one year or less is recognized on a straight-line basis over the term of the lease, unless another systematic and rational basis is more representative of the derivation of benefit from use of the leased property. Variable lease payments are recognized in the period in which the

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related obligation is incurred. Operating lease expense, finance lease expense, and variable lease payments are primarily recorded to Operating and maintenance expense on the Registrants’ Statements of Operations and Comprehensive Income.

Income from operating leases, including subleases, is recognized on a straight-line basis over the term of the lease, unless another systematic and rational basis is more representative of the pattern in which income is earned over the term of the lease. Variable lease income is recognized in the period in which the related obligation is performed. Operating lease income and variable lease income are recorded to Operating revenues on the Registrants’ Statements of Operations and Comprehensive Income.

The Registrants’ operating and finance leases consist primarily of real estate including office buildings and vehicles and equipment. The Registrants account for land right arrangements that provide for exclusive use as leases while shared use land arrangements are generally not leases. The Registrants do not account for secondary use pole attachments as leases.

See Note 10 — Leases for additional information.

Income Taxes (All Registrants)

Deferred federal and state income taxes are recorded on significant temporary differences between the book and tax basis of assets and liabilities and for tax benefits carried forward. Investment tax credits have been deferred in the Registrants’ Consolidated Balance Sheets and are recognized in book income over the life of the related property. The Registrants account for uncertain income tax positions using a benefit recognition model with a two-step approach; a more-likely-than-not recognition criterion; and a measurement approach that measures the position as the largest amount of tax benefit that is greater than 50 % likely of being realized upon ultimate settlement. If it is not more-likely-than-not that the benefit of the tax position will be sustained on its technical merits, no benefit is recorded. Uncertain tax positions that relate only to timing of when an item is included on a tax return are considered to have met the recognition threshold. The Registrants recognize accrued interest related to unrecognized tax benefits in Interest expense, net or Other, net (interest income) and recognize penalties related to unrecognized tax benefits in Other, net in their Consolidated Statements of Operations and Comprehensive Income.

Cash and Cash Equivalents (All Registrants)

The Registrants consider investments purchased with an original maturity of three months or less to be cash equivalents.

Restricted Cash and Cash Equivalents (All Registrants)

Restricted cash and cash equivalents represent funds that are restricted to satisfy designated current liabilities. As of December 31, 2023 and 2022, the Registrants' restricted cash and cash equivalents primarily represented the following items:

Registrant (a)			Description
Exelon			Payment of medical, dental, vision, and long-term disability benefits, in addition to the items listed below for the Utility Registrants.
ComEd			Collateral held from suppliers associated with energy and REC procurement contracts, any over-recovered RPS costs and alternative compliance payments received from RES pursuant to FEJA, and costs for the remediation of an MGP site.
PECO			Proceeds from the sales of assets that were subject to PECO’s mortgage indenture.
BGE			Proceeds from the loan program for the completion of certain energy efficiency measures and collateral held from energy suppliers.
PHI (a)			Payment of merger commitments and collateral held from its energy suppliers associated with procurement contracts.
Pepco			Payment of merger commitments and collateral held from energy suppliers.
DPL			Collateral held from energy suppliers.

__________

(a) As of December 31, 2023 and 2022, ACE had no restricted cash and cash equivalents.

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Restricted cash and cash equivalents not available to satisfy current liabilities are classified as noncurrent assets. As of December 31, 2023 and 2022, the Registrants' noncurrent restricted cash and cash equivalents primarily represented ComEd’s over-recovered RPS costs and alternative compliance payments received from RES pursuant to FEJA and costs for the remediation of an MGP site.

See Note 16 — Debt and Credit Agreements and Note 22 — Supplemental Financial Information for additional information.

Allowance for Credit Losses on Accounts Receivables (All Registrants)

The allowance for credit losses reflects the Registrants’ best estimates of losses on the customers' accounts receivable balances based on historical experience, current information, and reasonable and supportable forecasts.

The allowance for credit losses is developed by applying loss rates for each Utility Registrant, based on historical loss experience, current conditions, and forward-looking risk factors, to the outstanding receivable balance by customer risk segment. Utility Registrants' customer accounts are written off consistent with approved regulatory requirements. Adjustments to the allowance for credit losses are primarily recorded to Operating and maintenance expense on the Registrants' Consolidated Statements of Operations and Comprehensive Income or Regulatory assets and liabilities on the Registrants' Consolidated Balance Sheets. See Note 3 - Regulatory Matters for additional information regarding the regulatory recovery of credit losses on customer accounts receivable.

The Registrants have certain non-customer receivables in Other deferred debits and other assets which primarily are with governmental agencies and other high-quality counterparties with no history of default. As such, the allowance for credit losses related to these receivables is not material.  The Registrants monitor these balances and will record an allowance if there are indicators of a decline in credit quality. See Note 6 — Accounts Receivable for additional information.

Inventories (All Registrants)

Inventory is recorded at the lower of weighted average cost or net realizable value. Provisions are recorded for excess and obsolete inventory. Fossil fuel and Materials and supplies are generally included in inventory when purchased. Fossil fuel is expensed to Purchased power and fuel expense when used or sold. Materials and supplies generally includes transmission and distribution materials and are expensed to Operating and maintenance or capitalized to Property, plant, and equipment, as appropriate, when installed or used.

Property, Plant, and Equipment (All Registrants)

Property, plant, and equipment is recorded at original cost. Original cost includes construction-related direct labor and material costs and indirect construction costs including labor and related costs of departments associated with supporting construction activities. When appropriate, original cost also includes AFUDC for regulated property at the Utility Registrants. The cost of repairs and maintenance and minor replacements of property is charged to Operating and maintenance expense as incurred.

Third parties reimburse the Utility Registrants for all or a portion of expenditures for certain capital projects. Such contributions in aid of construction costs (CIAC) are recorded as a reduction to Property, plant, and equipment, net.

Upon retirement, the cost of property, net of salvage, is charged to accumulated depreciation consistent with the composite and group methods of depreciation. Depreciation expense at ComEd, BGE, Pepco, DPL, and ACE includes the estimated cost of dismantling and removing plant from service upon retirement. Actual incurred removal costs are applied against a related regulatory liability or recorded to a regulatory asset if in excess of previously collected 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.

Capitalized Software. Certain costs, such as design, coding, and testing incurred during the application development stage of software projects that are internally developed or purchased for operational use are capitalized within Property, plant, and equipment. Similar costs incurred for cloud-based solutions treated as

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service arrangements are capitalized within Other Current Assets and Deferred Debits and Other Assets. Such capitalized amounts are amortized ratably over the expected lives of the projects when they become operational, generally not to exceed five years. Certain other capitalized software costs are being amortized over longer lives based on the expected life or pursuant to prescribed regulatory requirements.

AFUDC. AFUDC is the cost, during the period of construction, of debt and equity funds used to finance construction projects for regulated operations. AFUDC is recorded to construction work in progress and as a non-cash credit to an allowance that is included in interest expense for debt-related funds and other income and deductions for equity-related funds. The rates used for capitalizing AFUDC are computed under a method prescribed by regulatory authorities.

See Note 7 — Property, Plant, and Equipment, Note 8 — Jointly Owned Electric Utility Plant and Note 22 — Supplemental Financial Information for additional information.

Depreciation and Amortization (All Registrants)

Depreciation is generally recorded over the estimated service lives of property, plant, and equipment 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 dissimilar assets that have different lives. Under both methods, a reporting entity depreciates the assets over the average life of the assets in the group. ComEd, BGE, Pepco, DPL, and ACE's depreciation expense includes the estimated cost of dismantling and removing plant from service upon retirement, which is consistent with each utility's regulatory recovery method. 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. The estimated service lives for the Registrants are based on a combination of depreciation studies and historical retirements. See Note 7 — Property, Plant, and Equipment for additional information regarding depreciation.

Amortization of regulatory assets and liabilities are recorded over the recovery or refund period specified in the related legislation or regulatory order or agreement. When the recovery or refund period is less than one year, amortization is recorded to the line item in which the deferred cost or income would have originally been recorded in the Registrants’ Consolidated Statements of Operations and Comprehensive Income. Amortization of ComEd’s electric distribution and energy efficiency formula rate regulatory assets and the Utility Registrants' transmission formula rate regulatory assets is recorded to Operating revenues.

Amortization of income tax related regulatory assets and liabilities is generally recorded to Income tax expense. Except for the regulatory assets and liabilities discussed above, amortization is generally recorded to Depreciation and amortization in the Registrants’ Consolidated Statements of Operations and Comprehensive Income when the recovery period is more than one year.

See Note 3 — Regulatory Matters and Note 22 — Supplemental Financial Information for additional information regarding the amortization of the Registrants' regulatory assets.

Asset Retirement Obligations (All Registrants)

The Registrants estimate and recognize a liability for their legal obligation to perform asset retirement activities even though the timing and/or methods of settlement may be conditional on future events. The Registrants update their AROs either annually or on a rotational basis at least once every three years, based on a risk profile, unless circumstances warrant more frequent updates. The updates factor in new cost estimates, credit-adjusted, risk-free rates (CARFR) and escalation rates, and the timing of cash flows. AROs are accreted throughout each year to reflect the time value of money for these present value obligations through an increase to Regulatory assets. See Note 9 — Asset Retirement Obligations for additional information.

Guarantees (All Registrants)

If necessary, the Registrants recognize a liability at the time of issuance of a guarantee for the fair value of the obligations they have undertaken by issuing the guarantee. The liability is reduced or eliminated as the Registrants are released from risk under the guarantee. Depending on the nature of the guarantee, the release from risk of the Registrant may be recognized only upon the expiration or settlement of the guarantee or by a

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systematic and rational amortization method over the term of the guarantee. See Note 18 — Commitments and Contingencies for additional information.

Asset Impairments

Long-Lived Assets (All Registrants). The Registrants evaluate the carrying value of long-lived assets for recoverability whenever events or changes in circumstances indicate that the carrying value of those assets may not be recoverable. Indicators of impairment may include specific regulatory disallowance, abandonment, or plans to dispose of a long-lived asset significantly before the end of its useful life. When the estimated undiscounted future cash flows attributable to the long-lived asset may not be recoverable, the amount of the impairment loss is determined by measuring the excess of the carrying amount of the long-lived asset over its fair value.

Goodwill (Exelon, ComEd, and PHI). Goodwill represents the excess of the purchase price paid over the estimated fair value of the net assets acquired and liabilities assumed in the acquisition of a business. Goodwill is not amortized but is assessed for impairment at least annually or on an interim basis if an event occurs or circumstances change that would more likely than not reduce the fair value of a reporting unit below its carrying value. See Note 12 — Intangible Assets for additional information.

Derivative Financial Instruments (All Registrants)

Derivatives are recognized on the balance sheet at their fair value unless they qualify for certain exceptions, including 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 underlying hedged transaction affects earnings. Amounts recognized in earnings are recorded in Interest expense, net on the Consolidated Statement of Operations and Comprehensive Income based on the activity the transaction is economically hedging. Cash inflows and outflows related to derivative instruments designated as cash flow hedges are included as a component of operating, investing, or financing cash flows in the Consolidated Statements of Cash Flows, depending on the nature of each transaction.

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 or as a regulatory asset or liability each period. Amounts recognized in earnings are recorded in Electric operating revenues, Purchased power and fuel, or Interest expense in the Consolidated Statements of Operations and Comprehensive Income based on the activity the transaction is economically hedging. Changes in fair value are also 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. Cash inflows and outflows related to derivative instruments are included as a component of operating, investing, or financing cash flows in the Consolidated Statements of Cash Flows, depending on the nature of the hedged item. See Note 3 — Regulatory Matters and Note 15 — Derivative Financial Instruments for additional information.

Retirement Benefits (All Registrants)

Exelon sponsors defined benefit pension plans and OPEB plans.

The plan obligations and costs of providing benefits under these plans are measured as of December 31. The measurement involves various factors, assumptions, and accounting elections. The impact of assumption changes or experience different from that assumed on pension and OPEB obligations is recognized over time rather than immediately recognized in the Consolidated Statements of Operations and Comprehensive Income. Gains or losses in excess of the greater of ten percent of the projected benefit obligation or the MRV of plan assets are amortized over the expected average remaining service period of plan participants. See Note 14 — Retirement Benefits for additional information.

New Accounting Standards (All Registrants)

New Accounting Standards Issued and Not Yet Adopted as of December 31, 2023: The following new authoritative accounting guidance issued by the FASB has not yet been adopted and reflected by the Registrants in their consolidated financial statements as of December 31, 2023. Unless otherwise indicated, the Registrants are currently assessing the impacts such guidance may have (which could be material) in their Consolidated Balance Sheets, Consolidated Statements of Operations and Comprehensive Income, Consolidated Statements

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of Cash Flows and disclosures, as well as the potential to early adopt where applicable. The Registrants have assessed other FASB issuances of new standards which are not listed below given the current expectation that such standards will not significantly impact the Registrants' financial reporting.

Segment Reporting (Issued November 2023). Improves reportable segment disclosure requirements, primarily through enhanced disclosures about significant segment expenses. The objective of the revised guidance is to introduce a new requirement to disclose significant segment expenses regularly provided to the CODM, extend  certain annual disclosures to interim periods, clarify single reportable segment entities must apply ASC 280 in its entirety, permit more than one measure of segment profit or loss to be reported under certain conditions, and require disclosure of the title and position of the CODM. The standard is effective for annual periods beginning January 1, 2024 and interim periods beginning January 1, 2025, with early adoption permitted. The standard will be applied retrospectively.

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, through the distribution of 326,663,937 common stock shares of Constellation, the new publicly traded company, to Exelon shareholders. Under the separation plan, Exelon shareholders retained their current shares of Exelon stock and received one share of Constellation common stock for every three shares of Exelon common stock held on January 20, 2022, the record date for the distribution, in a transaction that was tax-free to Exelon and its shareholders for U.S. federal income tax purposes.

Constellation was newly formed and incorporated in Pennsylvania on June 15, 2021 for the purposes of separation and holds Generation (including Generation's subsidiaries).

Pursuant to the separation:

• Exelon entered into four term loans consisting of a 364-day term loan for $ 1.15 billion and three 18-month term loans for $ 300 million, $ 300 million, and $ 250 million, respectively. Exelon issued these term loans primarily to fund the cash payment to Constellation and for general corporate purposes. See Note 16 — Debt and Credit Agreements for additional information.

• Exelon made a cash payment of $ 1.75 billion to Constellation on January 31, 2022.

• Exelon contributed its equity ownership interest in Generation to Constellation. Exelon no longer retains any equity ownership interest in Generation or Constellation.

• Exelon transferred certain corporate assets and employee-related obligations to Constellation.

• Exelon received cash from Generation of $ 258 million to settle the intercompany loan on January 31, 2022. See Note 16 — Debt and Credit Agreements for additional information.

Continuing Involvement

In order to govern the ongoing relationships between Exelon and Constellation after the separation, and to facilitate an orderly transition, Exelon and Constellation have entered into several agreements, including the following:

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• Separation Agreement – governs the rights and obligations between Exelon and Constellation regarding certain actions to be taken in connection with the separation, among others, including the allocation of assets and liabilities between Exelon and Constellation.

• Transition Services Agreement (TSA) – governs the terms and conditions of the services that Exelon provides to Constellation and Constellation provides to Exelon for an expected period of two years, provided that certain services may be longer than the term and services may be extended with approval from both parties. The services include specified accounting, finance, information technology, human resources, employee benefits, and other services that have historically been provided on a centralized basis by BSC. For the year ended December 31, 2023, the amounts Exelon billed Constellation and Constellation billed Exelon for these services were $ 151 million recorded in Other income, net and $ 14 million recorded in Operating and maintenance expense, respectively. For the period from February 1, 2022 to December 31, 2022, the amounts Exelon billed Constellation and Constellation billed Exelon for these services were $ 266 million recorded in Other income, net and $ 43 million recorded in Operating and maintenance expense, respectively.

• Tax Matters Agreement (TMA) – governs the respective rights, responsibilities and obligations of Exelon and Constellation with respect to all tax matters, including tax liabilities and benefits, tax attributes, tax returns, tax contests and other tax sharing regarding U.S. federal, state, local and foreign income taxes, other tax matters and related tax returns. See Note 13 — Income Taxes for additional information.

In addition, the Utility Registrants will continue to incur expenses from transactions with Constellation after the separation. Prior to the separation, such expenses were primarily recorded as Purchased power from affiliates and an immaterial amount recorded as Operating and maintenance expense from affiliates at the Utility Registrants. After the separation, such expenses are primarily recorded as Purchased power and an immaterial amount recorded as Operating and maintenance expense at the Utility Registrants.

• ComEd had an ICC-approved RFP contract with Constellation to provide a portion of ComEd’s electric supply requirements. ComEd also purchased RECs and ZECs from Constellation.

• PECO received electric supply from Constellation under contracts executed through PECO’s competitive procurement process. In addition, PECO had a ten-year agreement with Constellation to sell solar AECs.

• BGE received a portion of its energy requirements from Constellation under its MDPSC-approved market-based SOS and gas commodity programs.

• Pepco received electric supply from Constellation under contracts executed through Pepco’s competitive procurement process approved by the MDPSC and DCPSC.

• DPL received a portion of its energy requirements from Constellation under its MDPSC and DEPSC approved market-based SOS commodity programs.

• ACE received electric supply from Constellation under contracts executed through ACE’s competitive procurement process approved by the NJBPU.

ComEd and PECO also have receivables with Constellation for estimated excess funds at the end of decommissioning the Regulatory Agreement Units, such amounts are due back to ComEd and PECO, as applicable, for payment to their respective customers. See Note 3 — Regulatory Matters and Note 23 — Related Party Transactions for additional information.

Discontinued Operations

The separation represented a strategic shift that had a major effect on Exelon’s operations and financial results. Accordingly, the separation met the criteria for discontinued operations.

There were no results from discontinued operations for the year ended December 31, 2023. The following table presents the results of Constellation that have been reclassified from continuing operations and included in discontinued operations within Exelon’s Consolidated Statements of Operations and Comprehensive Income for the years ended December 31, 2022 and 2021.

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These results are primarily Generation, which is comprised of Exelon’s Mid-Atlantic, Midwest, New York, ERCOT, and Other Power Regions reportable segments, and include the impact of transaction costs, certain BSC costs, including any transition costs, that were historically allocated and directly attributable to Generation, transactions between Generation and the Utility Registrants, and tax-related adjustments. Transaction costs include costs for external bankers, accountants, appraisers, lawyers, external counsels and other advisors, among others, who are involved in the negotiation, appraisal, due diligence and regulatory approval of the separation. Transition costs are primarily employee-related costs such as recruitment expenses, costs to establish certain stand-alone functions and information technology systems, professional services fees, and other separation-related costs during the transition to separate Generation. For the purposes of reporting discontinued operations, these results also include transactions between Generation and the Utility Registrants that were historically eliminated within Exelon’s Consolidated Statements of Operations, as these transactions will be ongoing after the separation. Certain BSC costs that were historically allocated to Generation are presented as part of continuing operations in Exelon’s Consolidated Statements of Operations as these costs do not qualify as expenses of the discontinued operations per the accounting rules.

									For the Years Ended December 31,
									2022						2021
Operating revenues
Competitive business revenues									$	1,855					$	18,466
Competitive business revenues from affiliates									161						1,189
Total operating revenues									2,016						19,655
Operating expenses
Competitive businesses purchased power and fuel									1,138						12,163
Operating and maintenance (a)									371						4,174
Depreciation and amortization									94						3,003
Taxes other than income taxes									44						475
Total operating expenses									1,647						19,815
Gain on sales of assets and businesses									10						201
Operating income									379						41
Other income and (deductions)
Interest expense, net									( 20 )						( 282 )
Other, net									( 281 )						795
Total other income and (deductions)									( 301 )						513
Income before income taxes									78						554
Income taxes									( 40 )						332
Equity in losses of unconsolidated affiliates									( 1 )						( 9 )
Net income									117						213
Net income attributable to noncontrolling interests									1						123
Net income from discontinued operations									$	116					$	90

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(a) Includes transaction and transition costs related to the separation of $ 52 million and $ 43 million for the years ended December 31, 2022 and 2021, respectively.

There were no assets or liabilities of discontinued operations included in Exelon's Consolidated Balance Sheet as of December 31, 2023 and 2022. Constellation had net assets of $ 11,573 million that separated on February 1, 2022 that resulted in a reduction to Exelon's equity during the year ended December 31, 2022. Refer to the Distribution of Constellation line in Exelon's Consolidated Statement of Changes in Shareholders' Equity for further information.

There w ere no d iscontinued operations included within Exelon's Consolidated Statements of Cash Flows for the year ended December 31, 2023. The following table presents selected financial information regarding cash flows of the discontinued operations that are included within Exelon’s Consolidated Statements of Cash Flows for the years ended December 31, 2022 and 2021.

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									For the Years Ended December 31,
									2022						2021
Non-cash items included in net income from discontinued operations:
Depreciation, amortization, and accretion, including nuclear fuel and energy contract amortization									$	207					$	4,540
Asset impairments									—						545
Loss (gain) on sales of assets and businesses									9						( 201 )
Deferred income taxes and amortization of investment tax credits									( 143 )						( 224 )
Net fair value changes related to derivatives									( 59 )						( 568 )
Net realized and unrealized losses (gains) on NDT fund investments									205						( 586 )
Net unrealized losses on equity investments									16						160
Other decommissioning-related activity									36						( 946 )
Cash flows from investing activities:
Capital expenditures									( 227 )						( 1,341 )
Collection of DPP									169						3,902
Supplemental cash flow information:
(Decrease) increase in capital expenditures not paid									$	( 128 )					$	96
Increase in DPP									348						3,652
Increase in PP&E related to ARO update									335						618

The following matters below discuss the status of material regulatory and legislative proceedings of the Registrants.

Distribution Base Rate Case Proceedings

The following tables show the completed and pending distribution base rate case proceedings in 2023.

Completed Distribution Base Rate Case Proceedings

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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 (a)						Electric						$	199					$	199					7.85 %						November 17, 2022						January 1, 2023
						January 17, 2023 (b)						Electric						$	1,487					$	501					8.905 %						December 14, 2023						January 1, 2024
						April 21, 2023 (c)						Electric						$	247					$	259					8.91 %						November 30, 2023						January 1, 2024
PECO - Pennsylvania						March 31, 2022						Natural Gas						$	82					$	55					N/A (d)						October 27, 2022						January 1, 2023
BGE - Maryland						May 15, 2020 (amended September 11, 2020) (e)						Electric						$	203					$	140					9.50 %						December 16, 2020						January 1, 2021
												Natural Gas						$	108					$	74					9.65 %
						February 17, 2023 (f)						Electric						$	313					$	179					9.50 %						December 14, 2023						January 1, 2024
												Natural Gas						$	289					$	229					9.45 %
Pepco - Maryland (g)						October 26, 2020 (amended March 31, 2021)						Electric						$	104					$	52					9.55 %						June 28, 2021						June 28, 2021
DPL - Maryland (h)						May 19, 2022						Electric						$	38					$	29					9.60 %						December 14, 2022						January 1, 2023
ACE - New Jersey (i)						February 15, 2023 (amended August 21, 2023)						Electric						$	92					$	45					9.60 %						November 17, 2023						December 1, 2023

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(a) ComEd’s 2023 approved revenue requirement above reflects an increase of $ 144 million for the initial year revenue requirement for 2023 and an increase of $ 55 million related to the annual reconciliation for 2021. The revenue requirement for 2023 provides for a weighted average debt and equity return on distribution rate base of 5.94 % inclusive of an allowed ROE of 7.85 %, reflecting the monthly average yields for 30-year treasury bonds plus 580 basis points. The reconciliation revenue requirement for 2021 provides for a weighted average debt and equity return on distribution rate base of 5.91 %, inclusive of an allowed ROE of 7.78 %, reflecting the monthly yields on 30-year treasury bonds plus 580 basis points less a performance metrics penalty of 7 basis points. ComEd's last performance-based electric distribution formula rate update filing under EIMA was completed in 2022. See discussion of CEJA below for details on the transition away from the electric distribution formula rate.

(b) Reflects a four-year cumulative multi-year rate plan for January 1, 2024 to December 31, 2027. On December 14, 2023, the ICC approved year-over-year distribution revenue requirement increases in 2024-2027, with an amendatory order on January 10, 2024, of approximately $ 451 million effective January 1, 2024, $ 14 million effective January 1, 2025, $ 6 million effective January 1, 2026, and $ 30 million effective January 1, 2027, based on an ROE of 8.905 %, an equity ratio of 50 %, and year end 2022 rate base. The ICC rejected ComEd’s Grid Plan, requiring ComEd to file a revised Grid Plan by March 13, 2024, 90 days after the issuance of the December final order. The ICC also directed that the revised Grid Plan would be reviewed through further formal proceedings in that docket. On January 10, 2024, the ICC granted one portion of ComEd’s application for rehearing of the December 14, 2023 final order, and directing that a 150-day rehearing process reconsider the revenue requirements for the test years (2024-2027), absent an approved Grid Plan. On January 31,2024, the ICC further clarified the scope of the rehearing process. ComEd anticipates that the revenue requirements determined during the rehearing process will be further updated upon approval of a revised Grid Plan. On January 10, 2024, ComEd also filed with the Illinois appellate court an appeal of various aspects of the ICC’s final order on which rehearing was denied, including the 8.905 % ROE, 50 % equity ratio, and denial of any return on ComEd’s pension asset.

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(c) On November 30, 2023, the Delivery Reconciliation Amount for 2022 defined in Rider Delivery Service Pricing Reconciliation (Rider DSPR) was approved. The delivery reconciliation amount allows for the reconciliation of the revenue requirement in effect in the final years in which formula rates are determined and until such time as new rates are established under ComEd’s approved MRP. The 2023 filing reconciled the delivery service rates in effect in 2022 with the actual delivery service costs incurred in 2022. The reconciliation revenue requirement provides for a weighted average debt and equity return on distribution rate base of 6.48 %, inclusive of an allowed ROE of 8.91 %, reflecting the monthly yields on 30-year treasury bonds plus 580 basis points.

(d) The PECO electric and natural gas base rate case proceedings were resolved through settlement agreements, which did not specify an approved ROE.

(e) Reflects a three-year cumulative multi-year plan for 2021 through 2023. BGE proposed to use certain tax benefits to fully offset the increases in 2021 and 2022 and partially offset the increase in 2023. The MDPSC awarded BGE electric revenue requirement increases of $ 59 million, $ 39 million, and $ 42 million, before offsets, in 2021, 2022, and 2023, respectively, and natural gas revenue requirement increases of $ 53 million, $ 11 million, and $ 10 million, before offsets, in 2021, 2022, and 2023, respectively. However, the MDPSC utilized the tax benefits to fully offset the increases in 2021 and January 2022 such that customer rates remained unchanged. For the remainder of 2022, the MDPSC chose to offset only 25 % of the cumulative 2021 and 2022 electric revenue requirement increases and 50 % of the cumulative gas revenue requirement i ncreases. In 2021, the MDPSC deferred a decision on whether to use certain tax benefits to offset the revenue requirement increases in 2023 and directed BGE to make another proposal at the end of 2022. In September 2022, BGE proposed that tax benefits not be used to offset the 2023 revenue requirement increases. On October 26, 2022, the MDPSC accepted BGE's recommendation to not use tax benefits to offset the 2023 revenue requirement increases .

(f) Reflects a three-year cumulative multi-year plan for January 1, 2024 through December 31, 2026. The MDPSC awarded BGE electric revenue requirement increases of $ 41 million, $ 113 million, and $ 25 million in 2024, 2025, and 2026, respectively, and natural gas revenue requirement increases of $ 126 million, $ 62 million, and $ 41 million in 2024, 2025, and 2026, respectively. Requested revenue requirement increases will be used to recover capital investments designed to increase the resilience of the electric and gas distribution systems and support Maryland's climate and regulatory initiatives. The MDPSC also approved a portion of the requested 2021 and 2022 reconciliation amounts, which will be recovered through separate electric and gas riders starting in 2024. As such, the reconciliation amounts are not included in the approved revenue requirement increases. The 2021 reconciliation amounts are $ 13 million and $ 7 million for electric and gas, respectively, and the 2022 reconciliation amounts are $ 39 million and $ 15 million for electric and gas, respectively.

(g) Reflects a three-year cumulative multi-year plan for April 1, 2021 through March 31, 2024. The MDPSC awarded Pepco electric incremental revenue requirement increases of $ 21 million, $ 16 million, and $ 15 million, before offsets, for the 12-month periods ending March 31, 2022, 2023, and 2024, respectively. Pepco proposed to utilize certain tax benefits to fully offset the increase through 2023 and partially offset customer rate increases in 2024. However, the MDPSC only utilized the acceleration of refunds for certain tax benefits to fully offset the increases such that customer rates remain unchanged through March 31, 2022. On February 23, 2022, the MDPSC chose to offset 25 % of the cumulative revenue requirement increase through March 31, 2023. In 2021, the MDPSC deferred a decision on whether to use certain tax benefits to offset the revenue requirement increases for the 12-month period ending March 31, 2024. In December 2022 Pepco proposed that tax benefits not be used to offset the revenue requirement increases for this period. On January 25, 2023, the MDPSC accepted Pepco’s recommendations not to use tax benefits to offset revenue requirement increases for the 12-month period ending March 31, 2024.

(h) Reflects a three-year cumulative multi-year plan for January 1, 2023 through December 31, 2025. The MDPSC awarded DPL electric incremental revenue requirement increases of $ 17 million, $ 6 million, and $ 6 million for 2023, 2024, and 2025, respectively.

(i) Requested and approved increases are before New Jersey sales and use tax. The NJBPU awarded ACE electric revenue requirement increases of $ 36 million and $ 9 million effective December 1, 2023 and February 1, 2024, respectively.

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Pending Distribution Base Rate Case Proceedings

Registrant/Jurisdiction

Filing Date

Service

Requested Revenue Requirement Increase

Requested ROE

Expected Approval Timing

Pepco - District of Columbia (a)

April 13, 2023

Electric

$

191

10.50 %

Third quarter of 2024

Pepco - Maryland (b)

May 16, 2023 (amended January 26, 2024)

Electric

$

188

10.50 %

Second quarter of 2024

DPL - Delaware (c)

December 15, 2022 (amended September 29, 2023)

Electric

$

39

10.50 %

Second quarter of 2024

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(a) Reflects a three-year cumulative multi-year plan for January 1, 2024 through December 31, 2026 submitted to the DCPSC. Pepco requested total electric revenue requirement increases of $ 117 million, $ 37 million, and $ 37 million in 2024, 2025 and 2026, respectively. Requested revenue requirement increases will be used to recover capital investments designed to advance system-readiness and support the District of Columbia’s climate and clean energy goals.

(b) Reflects a three-year cumulative multi-year plan for April 1, 2024 through March 31, 2027 submitted to the MDPSC. Pepco requested total electric revenue requirement increases of $ 69 million, $ 54 million and $ 51 million effective April 1, 2024, April 1, 2025, and April 1, 2026, respectively through its rebuttal filing made on January 26, 2024. The plan contains a proposed nine-month extension period with a requested revenue requirement increase of $ 14 million effective April 1, 2027 through December 31, 2027. Requested revenue requirement increases will be used to recover capital investments designed to advance system-readiness and support Maryland's climate and clean energy goals. On August 7, 2023, the MDPSC issued an order approving a settlement agreement which allows Pepco to establish a revenue deferral mechanism to recover its full Commission-authorized year 1 increase between July 1, 2024 through March 31, 2025 and extend the procedural schedule to address intervenor resource constraints.

(c) The rates went into effect on July 15, 2023, subject to refund.

Transmission Formula Rates

The Utility Registrants' transmission rates are each established based on a FERC-approved formula. ComEd, BGE, Pepco, DPL, and ACE are required to file an annual update to the FERC-approved formula on or before May 15, and PECO is required to file on or before May 31, with the resulting rates effective on June 1 of the same year. The annual update for ComEd is based on prior year actual costs and current year projected capital additions (initial year revenue requirement). The update for ComEd also reconciles any differences between the revenue requirement in effect beginning June 1 of the prior year and actual costs incurred for that year (annual reconciliation). The annual update for PECO is based on prior year actual costs and current year projected capital additions, accumulated depreciation, and accumulated deferred income taxes. The annual update for BGE, Pepco, DPL, and ACE is based on prior year actual costs and current year projected capital additions, accumulated depreciation, Depreciation and amortization expense, and accumulated deferred income taxes. The update for PECO, BGE, Pepco, DPL, and ACE also reconciles any differences between the actual costs and actual revenues for the calendar year (annual reconciliation).

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For 2023, the following total increases/(decreases) were included in the Utility Registrants' electric transmission formula rate updates:

Registrant (a)						Initial Revenue Requirement Increase						Annual Reconciliation Increase (Decrease)						Total Revenue Requirement Increase						Allowed Return on Rate Base (b)						Allowed ROE (c)
ComEd						$	20					$	63					$	83					8.09		%				11.50		%
PECO						$	24					$	23					$	47					7.41		%				10.35		%
BGE						$	19					$	( 12 )					$	4		(d)			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		%

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(a) All rates are effective June 1, 2023 - May 31, 2024, subject to review by interested parties pursuant to review protocols of each Utility Registrants' tariff.

(b) Represents the weighted average debt and equity return on transmission rate bases. For ComEd and PECO, the common equity component of the ratio used to calculate the weighted average debt and equity return on the transmission formula rate base is currently capped at 55 % and 55.75 %, respectively.

(c) The rate of return on common equity for each Utility Registrant includes a 50 -basis-point incentive adder for being a member of a RTO.

(d) The increase in BGE's transmission revenue requirement includes a $ 3 million reduction related to a FERC-approved dedicated facilities charge to recover the costs of providing transmission service to specifically designated load by BGE.

Other State Regulatory Matters

Illinois Regulatory Matters

CEJA (Exelon and ComEd). On September 15, 2021, the Governor of Illinois signed into law CEJA. CEJA includes, among other features, (1) procurement of CMCs from qualifying nuclear-powered generating facilities, (2) a requirement to file a general rate case or a new four-year MRP no later than January 20, 2023 to establish rates effective after ComEd’s existing performance-based distribution formula rate sunsets, (3) requirements that ComEd and the ICC initiate and conduct various regulatory proceedings on subjects including ethics, spending, grid investments, and performance metrics.

ComEd Electric Distribution Rates

ComEd filed, and received approval for, its last performance-based electric distribution formula rate update under EIMA in 2022; those rates were in effect throughout 2023.

On February 3, 2022, the ICC approved a tariff that establishes the process under which ComEd reconciled its 2022 and will reconcile its 2023 rate year revenue requirements with actual costs. Those reconciliation amounts are determined using the same process used for prior reconciliations under the performance-based electric distribution formula rate. Using that process, for the rate years 2022 and 2023 ComEd will ultimately collect revenues from customers reflecting each year’s actual recoverable costs, year-end rate base, and a weighted average debt and equity return on distribution rate base, with the ROE component based on the annual average of the monthly yields of the 30-year U.S. Treasury bonds plus 580 basis points. In April 2023, ComEd filed its first petition with the ICC to reconcile its 2022 actual costs with the approved revenue requirement that was in effect in 2022; the final order was issued on November 30, 2023, for rates beginning January 2024. In 2024, ComEd will file with the ICC its 2023 actual costs with the approved revenue requirement that was in effect in 2023.

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Beginning in 2024, ComEd will recover from retail customers, subject to certain exceptions, the costs it incurs to provide electric delivery services either through its electric distribution rate or other recovery mechanisms authorized by CEJA. On January 17, 2023, ComEd filed a petition with the ICC seeking approval of a MRP for 2024-2027. The MRP supports a multi-year grid plan (Grid Plan), also filed on January 17, covering planned investments on the electric distribution system within ComEd’s service area through 2027. Costs incurred during each year of the MRP are subject to ICC review and the plan’s revenue requirement for each year will be reconciled with the actual costs that the ICC determines are prudently and reasonably incurred for that year. The reconciliation is subject to adjustment for certain costs, including a limitation on recovery of costs that are more than 105 % of certain costs in the previously approved MRP revenue requirement, absent a modification of the rate plan itself. Thus, for example, the rate adjustments necessary to reconcile 2024 revenues to ComEd’s actual 2024 costs incurred would take effect in January 2026 after the ICC’s review during 2025. On May 22, 2023, direct testimony was filed by ICC staff and more than a dozen intervenors and intervenor groups. The testimonies addressed a wide variety of topics, including rate of return on equity, capital structure, grid planning, various distribution grid and information technology investments, and affordability and customer service. ComEd also made voluntary adjustments and, per the ICC’s final beneficial electrification order requiring ComEd to recover beneficial electrification costs through the MRP, increased its total revenue requirement request from $ 1.472 billion to $ 1.545 billion. ComEd filed its reply brief on September 27, 2023, to adjust its total requested revenue requirement increase to $ 1.487 billion.

On December 14, 2023, the ICC issued a final order. The ICC rejected ComEd’s Grid Plan as non-compliant with certain requirements of CEJA, and required ComEd to file a revised Grid Plan by March 13, 2024, 90 days after the issuance of the final order. In the absence of an approved Grid Plan, the ICC set ComEd’s forecast revenue requirements for 2024-2027 based on ComEd's approved year-end 2022 rate base. This results in a total cumulative revenue requirement increase of $ 501 million, a $ 986 million total revenue reduction from the requested cumulative revenue requirement increase but remains subject to annual reconciliation in accordance with CEJA. The final order approved the process and formulas associated with the MRP reconciliation mechanisms. The ICC did not approve a previously proposed phase-in of the ICC's approved year-over-year revenue increases, and it also denied ComEd's ability to earn a return on its pension asset.

On December 22, 2023, ComEd filed an application for rehearing on several findings in the final order including the use of the 2022 year-end rate base to establish forecast revenue requirements for 2024-2027, ROE, pension asset return, and capital structure. On January 10, 2024, ComEd’s app lication for rehearing was denied on all issues except for the order’s use of the 2022 year-end rate base. On January 31, 2024, the ICC granted ComEd's motion seeking additional clarification on the scope on rehearing, generally accepting ComEd's proposal and confirming that the rehearing will determine if the forecasted year-end 2023 rate base should be used to set rates for 2024 through 2027 until a refiled Grid Plan is approved. A final rehearing order on that topic is statutorily required by early June 2024. On January 10, 2024, ComEd also filed an appeal in the Illinois Appellate Court of the issues on which rehearing was denied, including but not limited to the allowed ROE and denial of a return on ComEd’s pension asset. There is no deadline by when the appellate court must rule. On February 8, 2024, the ICC denied ComEd's request to provide clarification on other issues including the schedule for review of the refiled Grid Plan. ComEd has completed and placed in service additional utility plant assets in 2023 and will continue to complete and place in service additional utility plant assets prior to the approval of the new Grid Plan. There are still significant unknowns, but ComEd does not currently believe that it is probable that the initially uncollected depreciation or return on the recently completed plant will ultimately be disallowed.

In January 2022, ComEd filed a request with the ICC proposing performance metrics that would be used in determining ROE incentives and penalties in the event ComEd filed a MRP in January 2023. On September 27, 2022, the ICC issued a final order approving seven performance metrics that provide symmetrical performance adjustments of 32 total basis points to ComEd’s rate of return on common equity based on the extent to which ComEd achieves the annual performance goals. On November 10, 2022, the ICC granted ComEd's application for rehearing, in part. On April 5, 2023, the ICC issued its final order on rehearing for the performance and tracking metrics proceeding, in which the ICC declined to adopt ComEd's proposed modifications to the reliability and peak load reduction performance metrics. Efforts are underway to implement the performance metrics, which took effect on January 1, 2024. ComEd will make its initial filing in 2025 to assess performance achieved under the metrics in 2024, and to determine any ROE adjustment, which would take effect in 2026.

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Carbon Mitigation Credit

CEJA establishes decarbonization requirements for Illinois as well as programs to support the retention and development of emissions-free sources of electricity. ComEd is required to purchase CMCs from participating nuclear-powered generating facilities between June 1, 2022 and May 31, 2027. The price to be paid for each CMC was established through a competitive bidding process that included consumer-protection measures that capped the maximum acceptable bid amount and a formula that reduces CMC prices by an energy price index, the base residual auction capacity price in the ComEd zone of PJM, and the monetized value of any federal tax credit or other subsidy if applicable. The consumer protection measures contained in CEJA will result in net payments to ComEd ratepayers if the energy index, the capacity price and applicable federal tax credits or subsidy exceed the CMC contract price. In the June 2022 billing period. ComEd began issuing credits to its retail customers under its new CMC rider. A regulatory asset is recorded for the difference between customer credits issued and the credit to be received from the participating nuclear-powered generating facilities. The balance as of December 31, 2023 is $ 673 million.

Under CEJA, the costs of procuring CMCs, including carrying costs, are recovered through a rider, the Rider Carbon-Free Resource Adjustment (Rider CFRA). As originally approved by the ICC, Rider CFRA provides for an annual reconciliation and true-up to actual costs incurred or credits received by ComEd to purchase CMCs, with any difference to be credited to or collected from ComEd’s retail customers in subsequent periods. The difference between the net payments to (or receivables from) ComEd ratepayers and the credits received by ComEd to purchase CMCs is recorded to Purchased power expense with an offset to the regulatory asset (or regulatory liability). On December 21, 2022, ComEd filed an amendment to Rider CFRA proposing that it recover costs or provide credits faster than the tariff allows, implement monthly reconciliations, and allow ComEd to adjust Rider CFRA rates based not only on anticipated differences but also past payments or credits, and implement monthly reconciliations beginning with the June 2023 delivery period. The ICC approved the proposal on January 19, 2023. In addition, on March 24, 2023, ComEd submitted revisions to Rider CFRA which clarified the methodology for calculating interest to be included in the annual reconciliation associated with the June 2022 through May 2023 delivery year. The ICC approved the proposal on April 20, 2023. On February 2, 2024, ComEd filed a petition with the ICC to initiate the reconciliation proceeding for the costs incurred in connection with the procurement of CMCs during the delivery year beginning June 1, 2022 and extending through May 31, 2023.

Excess Deferred Income Taxes

The ICC initiated a docket to accelerate and fully credit to customers TCJA unprotected property-related EDIT no later than December 31, 2025. On July 7, 2022, the ICC issued a final order on the schedule for the acceleration of EDIT amortization, adopting the proposal as submitted by several parties, including ComEd, ICC Staff, the Illinois Attorney General's Office, and the Citizens Utility Board. EDIT amortization will be credited to customers through a new rider from January 1, 2023 through December 31, 2025.

Beneficial Electrification Plan

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On March 23, 2023, the ICC issued its final order approving the beneficial electrification plan for ComEd. The ICC rejected ComEd's request to treat a large portion of beneficial electrification costs as a regulatory asset and ordered ComEd to seek cost recovery through the multi-year rate plan filing for 2024 and 2025, and the final formula rate reconciliation docket for 2023, rather than through a separate charge. The order also authorized an overall annual budget of $ 77 million per year for the three year plan period (2023 through 2025), with flexibility to roll forward unused funds to future years within the same plan period. On April 18, 2023, ComEd filed an application for rehearing in the beneficial electrification plan docket. The Chicago Transit Authority and City of Chicago, jointly, and the Office of the Illinois Attorney General (ILAG) also filed applications for rehearing. On April 27, 2023, ICC staff filed a motion for clarification, seeking clarification from the ICC on the precise budget described in the final order. On May 8, 2023, the ICC denied all applications for rehearing, and entered an amendatory order regarding the annual beneficial electrification plan budgets. ComEd has been directed to use good faith efforts to spend $ 77 million annually. ComEd subsequently filed its compliance filing in May 2023, detailing project related spending, clarifying the procedure that will be used to seek stakeholder feedback related to beneficial electrification pilot programs, and including the timeline for tariff changes required to implement the programs. ComEd and the ILAG both filed appeals of the ICC’s interim order that addressed the permissible scope of utility beneficial electrification programs outside of transportation and the rate impact cap. The ILAG also filed an appeal seeking reversal of portions of the ICC’s final decision. The final order partly mooted ComEd’s appeal of the interim order and ComEd has decided not to pursue the other issues. As such, ComEd moved to voluntarily dismiss its appeal and the appellate court granted that request. The ILAG consolidated their appeals. Any ruling on the appeals, even a negative ruling removing programs from the BE Plan or lowering the overall budget of the BE Plan, will only impact forward-looking costs.

Energy Efficiency

CEJA extends ComEd’s current cumulative annual energy efficiency MWh savings goals through 2040, adds expanded electrification measures to those goals, increases low-income commitments and adds a new performance adjustment to the energy efficiency formula rate. ComEd expects its annual spend to increase in 2023 through 2040 to achieve these energy efficiency MWh savings goals, which will be deferred as a separate regulatory asset that will be recovered through the energy efficiency formula rate over the weighted average useful life, as approved by the ICC, of the related energy efficiency measures.

Energy Efficiency Formula Rate (Exelon and ComEd). FEJA allows ComEd to defer energy efficiency costs (except for any voltage optimization costs which are recovered through the electric distribution formula rate) as a separate regulatory asset that is recovered through the energy efficiency formula rate over the weighted average useful life, as approved by the ICC, of the related energy efficiency measures. ComEd earns a return on the energy efficiency regulatory asset at a rate equal to its weighted average cost of capital, which is based on a year-end capital structure and calculated using the same methodology applicable to ComEd’s electric distribution formula rate. Beginning January 1, 2018, the ROE that ComEd earns on its energy efficiency regulatory asset is subject to a maximum downward or upward adjustment of 200 basis points if ComEd’s cumulative persisting annual MWh savings falls short of or exceeds specified percentage benchmarks of its annual incremental savings goal. ComEd is required to file an update to its energy efficiency formula rate on or before June 1 st each year, with resulting rates effective in January of the following year. The annual update is based on projected current year energy efficiency costs, PJM capacity revenues, and the projected year-end regulatory asset balance less any related deferred income taxes (initial year revenue requirement). The update also reconciles any differences between the revenue requirement in effect for the prior year and actual costs incurred from the year (annual reconciliation). The approved energy efficiency formula rate also provides for revenue decoupling provisions similar to those in ComEd’s electric distribution formula rate.

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During 2023, the ICC approved the following total increases in ComEd's requested energy efficiency revenue requirement:

Filing Date						Requested Revenue Requirement Increase						Approved Revenue Requirement Increase (a)						Approved ROE						Approval Date						Rate Effective Date
May 26, 2023						$	118					$	118					8.91		%				November 30, 2023						January 1, 2024

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(a) ComEd's 2024 approved revenue requirement above reflects an increase of $ 71 million for the initial year revenue requirement for 2024 and a increase of $ 47 million related to the annual reconciliation for 2022. The revenue requirement for 2024 provides for a weighted average debt and equity return on the energy efficiency regulatory asset and rate base of 6.48 % inclusive of an allowed ROE of 8.91 %, reflecting the monthly average yields for 30-year treasury bonds plus 580 basis points. The revenue requirement for the 2022 reconciliation year provides for a weighted average debt and equity return on the energy efficiency regulatory asset and rate base of 7.47 % inclusive of an allowed ROE of 10.89 %, which includes an upward performance adjustment that increased the ROE. The performance adjustment can either increase or decrease the ROE based upon the achievement of energy efficiency savings goals. See table below for ComEd's regulatory assets associated with its energy efficiency formula rate.

Maryland Regulatory Matters

Maryland Revenue Decoupling (Exelon, BGE, PHI, Pepco, and DPL). In 1998, the MDPSC approved natural gas monthly rate adjustments for BGE and in 2007, the MDPSC approved electric monthly rate adjustments for BGE and BSAs for Pepco and DPL, all of which are decoupling mechanisms. As a result of the decoupling mechanisms, certain Operating revenues from electric and natural gas distribution at BGE and Operating revenues from electric distribution at Pepco Maryland (see also District of Columbia Revenue Decoupling below for Pepco District of Columbia) and DPL are not impacted by abnormal weather or usage per customer. For BGE, Pepco, and DPL, the decoupling mechanism eliminates the impacts of abnormal weather or customer usage by recognizing revenues based on an authorized distribution amount per customer by customer class. Operating revenues from electric and natural gas distribution at BGE and Operating revenues from electric distribution at Pepco Maryland and DPL are, however, impacted by changes in the number of customers.

Maryland Order Directing the Distribution of Energy Assistance Funds (Exelon, BGE, PHI, Pepco, and DPL). On June 15, 2021, the MDPSC issued an order authorizing the disbursal of funds to utilities in accordance with Maryland COVID-19 relief legislation. Under this order, BGE, Pepco, and DPL received funds of $ 50 million, $ 12 million, and $ 8 million, respectively, in July 2021. The funds have been used to reduce or eliminate certain qualifying past-due residential customer receivables.

EmPOWER Maryland Cost Recovery (Exelon, BGE, PHI, Pepco and DPL). On December 29, 2023, the MDPSC issued an order authorizing the next three-year program cycle for EmPOWER Maryland and approved various proposals by the program administrators to implement new energy efficiency programs for the 2024-2026 program cycle, as well as continue operating core programs. Historically, BGE, Pepco, and DPL deferred most of their energy efficiency program costs to a regulatory asset and either deferred most of their demand response program costs to a regulatory asset or capitalized them. Beginning in 2024, BGE, Pepco, and DPL will begin deferring less energy efficiency and demand response program costs to a regulatory asset. Additionally, as part of the order, the MDPSC directed BGE, Pepco, and DPL to extend the amortization of unamortized costs as of December 31, 2023 from 5 to 7 years to mitigate customer bill impacts.

District of Columbia Regulatory Matters

District of Columbia Revenue Decoupling (Exelon, PHI, and Pepco). In 2009, the DCPSC approved a BSA, which is a decoupling mechanism. As a result of the decoupling mechanism, Operating revenues from electric distribution at Pepco District of Columbia (see also Maryland Revenue Decoupling above for Pepco Maryland) are not impacted by abnormal weather or usage per customer. The decoupling mechanism eliminates the impacts of abnormal weather or customer usage by recognizing revenues based on an authorized distribution amount per customer by customer class. Operating revenues from electric distribution at Pepco District of Columbia are, however, impacted by changes in the number of customers.

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New Jersey Regulatory Matters

Conservation Incentive Program (CIP) (Exelon, PHI, and ACE). On September 25, 2020, ACE filed an application with the NJBPU as was required seeking approval to implement a portfolio of energy efficiency programs pursuant to New Jersey’s clean energy legislation. The filing included a request to implement a CIP that would eliminate the favorable and unfavorable impacts of weather and customer usage patterns on distribution revenues for most customers. 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.

On April 27, 2021, the NJBPU approved the settlement filed by ACE and the third parties to the proceeding. The approved settlement addresses all material aspects of ACE’s filing, including ACE’s ability to implement the CIP prospectively effective July 1, 2021. As a result of this decoupling mechanism, operating revenues will no longer be impacted by abnormal weather or usage for most customers. Starting in third quarter of 2021, ACE has recorded alternative revenue program revenues for its best estimate of the distribution revenue impacts resulting from future changes in CIP rates that it believes are probable of approval by the NJBPU in accordance with this mechanism.

Termination of Energy Procurement Provisions of PPAs (Exelon, PHI, and ACE). On December 22, 2021, ACE filed with the NJBPU a petition to terminate the provisions in the PPAs to purchase electricity from two coal-powered generation facilities located in the state of New Jersey. The petition was approved by the NJBPU on March 23, 2022. Upon closing of the transaction on March 31, 2022, ACE recognized a liability of $ 203 million for the contract termination fee, which is to be paid by the end of 2024, and recognized a corresponding regulatory asset of $ 203 million.

As of December 31, 2023, the $ 49 million liability for the contract termination fee is included in Other current liabilities in Exelon's Consolidated Balance Sheet and PPA termination obligation in PHI's and ACE's Consolidated Balance Sheets. For the year ended December 31, 2023 and 2022, ACE has paid $ 88 million and $ 66 million of the liability, which is recorded in Changes in Other assets and liabilities in Exelon's, PHI's, and ACE's Consolidated Statements of Cash Flows.

ACE Infrastructure Investment Program Filings (Exelon, PHI, and ACE). On February 28, 2018, ACE filed with the NJBPU the Registrants' IIP proposing to seek recovery of a series of investments through a new rider mechanism, totaling $ 338 million, between 2019-2022 to provide safe and reliable service for its customers. The IIP will allow for more timely recovery of investments made to modernize and enhance ACE’s electric system. On April 15, 2019, ACE entered into a settlement agreement with other parties, which allows for a recovery totaling $ 96 million of reliability related capital investments from July 1, 2019 through June 30, 2023. On April 18, 2019, the NJBPU approved the settlement agreement.

On October 31, 2022, ACE filed with the NJBPU a second IIP, called “Powering the Future”, proposing to seek recovery through a new component of ACE’s rider mechanism, totaling $ 379 million, over the four-year period of July 1, 2023, to June 30, 2027. The new IIP will allow ACE to invest in projects that are designed to enhance the reliability, resiliency, and safety of the service ACE provides to its customers. On June 15, 2023, ACE entered into a settlement agreement with other parties, which allows for a recovery totaling $ 93 million of reliability related capital investments from July 1, 2023, through June 30, 2027. ACE will have the option of seeking approval from the NJBPU to extend the end date of the IIP beyond June 30, 2027, if ACE determines an extension is necessary. On June 29, 2023, the NJBPU adopted the settlement agreement and issued an order approving the program.

Advanced Metering Infrastructure Filing (Exelon, PHI, and ACE). On August 26, 2020, ACE filed an application with the NJBPU as was required seeking approval to deploy a smart energy network in alignment with New Jersey’s Energy Master Plan and Clean Energy Act. The proposal consisted of estimated costs totaling $ 220 million with deployment taking place over a 3-year implementation period from approximately 2021 to 2024 that involves the installation of an integrated system of smart meters for all customers accompanied by the requisite communications facilities and data management systems.

On July 14, 2021, the NJBPU approved the settlement filed by ACE and the third parties to the proceeding. The approved settlement addresses all material aspects of ACE's smart energy network deployment plan, including

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cost recovery of the investment costs, incremental O&M expenses, and the unrecovered balance of existing infrastructure through future distribution rates.

New Jersey Clean Energy Legislation (Exelon, PHI, and ACE). On May 23, 2018, New Jersey enacted legislation that established and modified New Jersey’s clean energy and energy efficiency programs and solar and RPS. On the same day, New Jersey enacted legislation that established a ZEC program that provides compensation for nuclear plants that demonstrate to the NJBPU that they meet certain requirements. Under the legislation, the NJBPU will issue ZECs to the qualifying nuclear power plants and the electric distribution utilities in New Jersey, including ACE, will be required to purchase those ZECs. ACE began collecting from retail distribution customers, through a non-bypassable charge, all costs associated with the procurement of the ZECs effective April 18, 2019.

Other Federal Regulatory Matters

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

Regulatory Assets and Liabilities

Regulatory assets represent incurred costs that have been deferred because of their probable future recovery from customers through regulated rates. Regulatory liabilities represent the excess recovery of costs or accrued credits that have been deferred because it is probable such amounts will be returned to customers through future regulated rates or represent billings in advance of expenditures for approved regulatory programs.

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The following tables provide information about the regulatory assets and liabilities of the Registrants at December 31, 2023 and 2022:

December 31, 2023			Exelon						ComEd						PECO						BGE						PHI						Pepco						DPL						ACE
Regulatory assets
AMI programs - deployment costs			$	109					$	—					$	—					$	49					$	60					$	18					$	17					$	25
AMI programs - legacy meters			127						28						—						12						87						41						14						32
Asset retirement obligations			159						104						22						23						10						6						2						2
Carbon mitigation credit			673						673						—						—						—						—						—						—
COVID-19			41						11						11						6						13						10						3						—
DC PLUG charge			3						—						—						—						3						3						—						—
Deferred income taxes			759						—						748						—						11						11						—						—
Deferred storm costs			114						—						—						84						30						9						2						19
Electric distribution formula rate annual reconciliations			787						787						—						—						—						—						—						—
Electric distribution formula rate significant one-time events			89						89						—						—						—						—						—						—
Electric energy and natural gas costs			98						—						1						25						72						11						2						59
Energy efficiency and demand response programs			631						—						23						316						292						187						73						32
Energy efficiency costs			1,691						1,691						—						—						—						—						—						—
Fair value of long-term debt			486						—						—						—						385						—						—						—
Fair value of PHI's unamortized energy contracts			35						—						—						—						35						—						—						—
MGP remediation costs			315						286						15						14						—						—						—						—
Multi-year plan reconciliations			112						—						—						112						—						—						—						—
Pension and OPEB			2,254						—						—						—						—						—						—						—
Pension and OPEB - merger related			637						—						—						—						—						—						—						—
Removal costs			827						—						—						219						608						137						118						354
Renewable energy			134						134						—						—						—						—						—						—
Transmission formula rate annual reconciliations			75						—						9						5						61						15						22						24
Under-recovered credit loss expense			112						78						—						—						34						—						—						34
Under-recovered revenue decoupling			176						—						—						64						112						100						—						12
Universal service fund charge under-recovery - Electric			59						—						59						—						—						—						—						—
Zero emission credit			58						58						—						—						—						—						—						—
Other			352						190						32						27						111						52						19						15
Total regulatory assets			10,913						4,129						920						956						1,924						600						272						608
Less: current portion			2,215						1,335						127						229						337						150						54						125
Total noncurrent regulatory assets			$	8,698					$	2,794					$	793					$	727					$	1,587					$	450					$	218					$	483

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December 31, 2023			Exelon						ComEd						PECO						BGE						PHI						Pepco						DPL						ACE
Regulatory liabilities
Decommissioning the Regulatory Agreement Units			$	3,232					$	2,954					$	278					$	—					$	—					$	—					$	—					$	—
Dedicated facilities charge			129						—						—						129						—						—						—						—
Deferred income taxes			3,284						1,900						—						634						750						338						274						138
Electric energy and natural gas costs			121						4						93						—						24						9						15						—
Energy efficiency and demand response programs			1						—						1						—						—						—						—						—
Multi-year plan reconciliations			23						—						—						—						23						16						7						—
Over-recovered revenue decoupling			2						—						—						—						2						—						2						—
Removal costs			1,845						1,701						—						28						116						20						96						—
Renewable portfolio standards costs			1,102						1,102						—						—						—						—						—						—
Other			226						23						34						9						60						14						21						8
Total regulatory liabilities			9,965						7,684						406						800						975						397						415						146
Less: current portion			389						191						92						27						71						15						50						6
Total noncurrent regulatory liabilities			$	9,576					$	7,493					$	314					$	773					$	904					$	382					$	365					$	140

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December 31, 2022			Exelon						ComEd						PECO						BGE						PHI						Pepco						DPL						ACE
Regulatory assets
AMI programs - deployment costs			$	122					$	—					$	—					$	69					$	53					$	25					$	22					$	6
AMI programs - legacy meters			160						48						—						20						92						53						17						22
Asset retirement obligations			151						99						22						21						9						6						2						1
Carbon mitigation credit			843						843						—						—						—						—						—						—
COVID-19			58						20						17						8						13						10						3						—
DC PLUG charge			37						—						—						—						37						37						—						—
Deferred income taxes			606						—						595						—						11						11						—						—
Deferred storm costs			90						—						—						55						35						2						2						31
Electric distribution formula rate annual reconciliations			271						271						—						—						—						—						—						—
Electric distribution formula rate significant one-time events			115						115						—						—						—						—						—						—
Electric energy and natural gas costs			241						—						15						25						201						41						26						134
Energy efficiency and demand response programs			560						—						—						286						274						187						74						13
Energy efficiency costs			1,434						1,434						—						—						—						—						—						—
Fair value of long-term debt			521						—						—						—						414						—						—						—
Fair value of PHI's unamortized energy contracts			44						—						—						—						44						—						—						—
MGP remediation costs			318						293						13						12						—						—						—						—
Pension and OPEB			1,867						—						—						—						—						—						—						—
Pension and OPEB - merger related			769						—						—						—						—						—						—						—
Removal costs			782						—						—						171						611						144						109						359
Renewable energy			85						85						—						—						—						—						—						—
Transmission formula rate annual reconciliations			37						—						16						—						21						3						5						13
Under-recovered credit loss expense			71						38						—						—						33						—						—						33
Under-recovered revenue decoupling			106						—						—						8						98						98						—						—
Universal service fund charge under-recovery - Electric			19						—						19						—						—						—						—						—
Other			371						196						35						29						119						55						22						12
Total regulatory assets			9,678						3,442						732						704						2,065						672						282						624
Less: current portion			1,641						775						80						177						455						235						80						130
Total noncurrent regulatory assets			$	8,037					$	2,667					$	652					$	527					$	1,610					$	437					$	202					$	494

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December 31, 2022			Exelon						ComEd						PECO						BGE						PHI						Pepco						DPL						ACE
Regulatory liabilities
Decommissioning the Regulatory Agreement Units			$	2,897					$	2,660					$	237					$	—					$	—					$	—					$	—					$	—
Dedicated facilities charge			110						—						—						110						—						—						—						—
Deferred income taxes			3,546						2,010						—						682						854						402						304						148
Electric energy and natural gas costs			87						11						65						4						7						—						7						—
Energy efficiency and demand response programs			15						—						15						—						—						—						—						—
Multi-year plan reconciliations			14						—						—						—						14						14						—						—
Over-recovered revenue decoupling			19						—						—						4						15						—						6						9
Removal costs			1,750						1,604						—						35						111						20						91						—
Renewable portfolio standards costs			810						810						—						—						—						—						—						—
Stranded costs			9						—						—						—						9						—						—						9
Transmission formula rate annual reconciliations			31						3						—						18						10						9						1						—
Other			261						41						28						10						67						16						15						16
Total regulatory liabilities			9,549						7,139						345						863						1,087						461						424						182
Less: current portion			437						226						75						47						76						6						44						26
Total noncurrent regulatory liabilities			$	9,112					$	6,913					$	270					$	816					$	1,011					$	455					$	380					$	156

Descriptions of the regulatory assets and liabilities included in the tables above are summarized below, including their recovery and amortization periods.

Line Item			Description			End Date of Remaining Recovery/Refund Period			Return
AMI programs - deployment costs			Represents installation and ongoing incremental costs of new smart meters, including implementation costs at Pepco and DPL of dynamic pricing for energy usage resulting from smart meters.			BGE - 2026 Pepco - 2029 DPL - 2030 ACE - 2029			BGE, Pepco, DPL - Yes ACE - Yes, on incremental costs of new smart meters
AMI programs - legacy meters			Represents early retirement costs of legacy meters.			ComEd - 2028 BGE - 2026 Pepco - 2029 DPL - 2030 ACE - To be determined in next distribution rate case filed with NJBPU.			ComEd, Pepco (District of Columbia), DPL (Delaware), ACE - Yes BGE, Pepco (Maryland), DPL (Maryland) - No
Asset retirement obligations			Represents future legally required removal costs associated with existing AROs.			Over the life of the related assets.			Yes, once the removal activities have been performed

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Line Item			Description			End Date of Remaining Recovery/Refund Period			Return
Carbon mitigation credit			Represents CMC procurement costs and credits as well as reasonable costs ComEd has incurred to implement and comply with the CMC procurement process.			2024			No
COVID-19			Represents incremental credit losses and direct costs related to COVID-19 incurred primarily in 2020 at the Utility Registrants, partially offset by a decrease in travel costs at BGE, Pepco and DPL. Direct costs consisted primarily of costs to acquire personal protective equipment, costs for cleaning supplies and services, and costs to hire healthcare professionals to monitor the health of employees.			ComEd - 2025 BGE - 2028 PECO - 2024 Pepco (District of Columbia) - $ 8 million to be determined in pending multi-year plan filed with DCPSC. Pepco (Maryland) - $ 2 million to be determined in pending multi-year plan filed with MDPSC. DPL (Maryland) - $ 1 million - 2027 DPL (Delaware) - $ 2 million to be determined in pending distribution rate case filed with DEPSC.			ComEd, BGE, and DPL (Maryland) - Yes PECO, Pepco, and DPL (Delaware) - No
DC PLUG charge			Represents costs associated with DC PLUG, which is a projected six-year, $ 500 million project to place underground some of the District of Columbia’s most outage-prone power lines with $ 250 million of the project costs funded by Pepco and $ 250 million funded by the District of Columbia. Rates for the DC PLUG initiative went into effect on February 7, 2018.			2024			Portion of asset funded by Pepco-Yes
Decommissioning the Regulatory Units			Represents estimated excess funds at the end of decommissioning the Regulatory Agreement Units. See below regarding Decommissioning the Regulatory Agreement Units for additional information.			Not currently being refunded.			No

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Line Item			Description			End Date of Remaining Recovery/Refund Period			Return
Dedicated facilities charge			Represents the timing difference between the recovery of certain transmission-related assets and their depreciable life.			Depreciable life of the related assets.			Yes
Deferred income taxes			Represents deferred income taxes that are recoverable or refundable through customer rates, primarily associated with accelerated depreciation, the equity component of AFUDC, and the effects of income tax rate changes, including those resulting from the TCJA.			Amounts are recoverable over the period in which the related deferred income taxes reverse, which is generally based on the expected life of the underlying assets. For TCJA, generally refunded over the remaining depreciable life of the underlying assets, except in certain jurisdictions where the commissions have approved a shorter refund period for certain assets not subject to IRS normalization rules.			No
Deferred storm costs			For Pepco, DPL, ACE, and BGE, amounts represent total incremental storm restoration costs incurred due to major storm events recoverable from customers in the Maryland and New Jersey jurisdictions.			Pepco - $ 1 million - 2024; $ 8 million to be determined in a future multi-year plan filed with MDPSC. DPL - 2027 ACE - 2026 BGE - $ 57 million - 2028; $ 27 million to be determined in the next multi-year plan filed with MDPSC.			Pepco, DPL, BGE - Yes ACE - No
Electric distribution formula rate annual reconciliations			Represents under/(over)-recoveries related to electric distribution service costs recoverable through ComEd's performance-based formula rate, which is updated annually with rates effective on January 1 st .			2025			Yes
Electric distribution formula rate significant one-time events			Represents deferred distribution service costs related to ComEd's significant one-time events (e.g., storm costs), which are recovered over 5 years from date of the event.			2027			Yes

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Line Item			Description			End Date of Remaining Recovery/Refund Period			Return
Electric energy and natural gas costs			Represents under (over)-recoveries related to energy and gas supply related costs recoverable (refundable) under approved rate riders.			2025			DPL (Delaware), ACE - Yes ComEd, PECO, BGE, Pepco, DPL (Maryland) - No
Energy efficiency and demand response programs			Includes under (over)-recoveries of costs incurred related to energy efficiency programs and demand response programs and recoverable costs associated with customer direct load control and energy efficiency and conservation programs that are being recovered from customers.			PECO - 2025 BGE - 2030 Pepco, DPL - 2030 ACE - 2032			BGE, Pepco (Maryland), DPL (Maryland) - See above regarding EmPOWER Maryland Cost Recovery for additional information DPL (Delaware), Pepco (District of Columbia) - No ACE - Yes PECO - Yes on capital investment recovered through this mechanism
Energy efficiency costs			Represents ComEd's costs recovered through the energy efficiency formula rate tariff and the reconciliation of the difference of the revenue requirement in effect for the prior year and the revenue requirement based on actual prior year costs. Deferred energy efficiency costs are recovered over the weighted average useful life of the related energy measure.			2035			Yes

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Line Item			Description			End Date of Remaining Recovery/Refund Period			Return
Fair value of long-term debt			Represents the difference between the carrying value and fair value of long-term debt of BGE, recorded at Exelon, and PHI of $ 101 million and $ 385 million, respectively, as of December 31, 2023, and $ 107 million and $ 414 million, respectively, as of December 31, 2022, as of the 2016 PHI and 2012 Constellation merger dates.			Exelon - 2036 PHI - 2045			No
Fair value of PHI’s unamortized energy contracts			Represents the regulatory assets recorded at Exelon and PHI offsetting the fair value adjustment related to Pepco's, DPL's, and ACE's electricity and natural gas energy supply contracts recorded at PHI as of the PHI merger date.			2036			No
MGP remediation costs			Represents environmental remediation costs for MGP sites recorded at ComEd, PECO, and BGE.			ComEd and PECO - Over the expected remediation period. See Note 18 — Commitments and Contingencies for additional information. BGE - 10 years from when the remediation spend occurs.			ComEd and PECO - No BGE - Yes
Multi-year plan reconciliations			Represents under (over)-recoveries related to electric and gas distribution multi-year plans.			BGE - $ 60 million related to 2021 and 2022 reconciliations - 2025. $ 52 million related to 2023 reconciliations - to be determined in a future MDPSC order. Pepco (District of Columbia) - $ 16 million which has been reviewed by the DCPSC and will be finalized upon receipt of the DCPSC order in the pending multi-year plan filing. DPL (Maryland) - $ 7 million to be determined in next multi-year plan filed with MDPSC.			BGE - No Pepco (District of Columbia) - Yes DPL (Maryland) - Yes

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Line Item			Description			End Date of Remaining Recovery/Refund Period			Return
Pension and OPEB			Primarily reflects the Utility Registrants' and PHI's portion of deferred costs, including unamortized actuarial losses (gains) and prior service costs (credits), associated with Exelon's pension and OPEB plans, which are recovered through customer rates once amortized through net periodic benefit cost. Also, includes the Utility Registrants' and PHI's non–service cost components capitalized in Property, plant and equipment, net on their Consolidated Balance Sheets.			The deferred costs are amortized over the plan participants' average remaining service periods subject to applicable pension and OPEB cost recognition policies. See Note 14 — Retirement Benefits for additional information. The capitalized non–service cost components are amortized over the lives of the underlying assets.			No

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Line Item			Description			End Date of Remaining Recovery/Refund Period			Return
Pension and OPEB - merger related			The deferred costs established at the date of the 2012 Constellation and 2016 PHI mergers are amortized over the plan participants' average remaining service periods subject to applicable pension and OPEB cost recognition policies. The costs are recovered through customer rates once amortized through net periodic benefit cost. See Note 14 — Retirement Benefits for additional information. The capitalized non–service cost components are amortized over the lives of the underlying assets.			Legacy BGE - 2038 Legacy PHI - 2032			No
Removal costs			For BGE, Pepco, DPL, and ACE, the regulatory asset represents costs incurred to remove property, plant and equipment in excess of amounts received from customers through depreciation rates. For ComEd, BGE, Pepco, and DPL, the regulatory liability represents amounts received from customers through depreciation rates to cover the future non–legally required cost to remove property, plant and equipment, which reduces rate base for ratemaking purposes.			BGE, Pepco, DPL, and ACE - Asset is generally recovered over the life of the underlying assets. ComEd, BGE, Pepco, and DPL - Liability is reduced as costs are incurred.			Yes
Renewable energy			Represents the change in fair value of ComEd‘s 20-year floating-to-fixed long-term renewable energy swap contracts.			2032			No
Renewable portfolio standards costs			Represents an overcollection of funds from both ComEd customers and alternative retail electricity suppliers to be spent on future renewable energy procurements.			$ 1,033 million to be determined in pending ICC annual reconciliation for the Renewable Energy Adjustment rider. $ 69 million to be determined based on the LTRRPP developed by the IPA.			No
Stranded costs			Represents overcollection of a customer surcharge collected by ACE to fund principal and interest payments on Transition Bonds of ACE Transition Funding that securitized such costs.			2023			No

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Line Item			Description			End Date of Remaining Recovery/Refund Period			Return
Transmission formula rate annual reconciliations			Represents under (over)-recoveries related to transmission service costs recoverable through the Utility Registrants’ FERC formula rates, which are updated annually with rates effective each June 1 st .			2025			Yes
Under (over) -recovered revenue decoupling			Represents electric and / or gas distribution costs recoverable from or refundable to customers under decoupling mechanisms.			BGE - 2025 Pepco (Maryland) - $ 10 million - 2024 Pepco (District of Columbia) - $ 90 million to be determined in the next multi-year plan filed with DCPSC. DPL - 2024 ACE - 2024			BGE, Pepco, DPL, ACE - No
Under-recovered credit loss expense			For ComEd and ACE, amounts represent the difference between annual credit loss expense and revenues collected in rates through ICC and NJBPU-approved riders. The difference between net credit loss expense and revenues collected through the rider each calendar year for ComEd is recovered over a twelve-month period beginning in June of the following calendar year. ACE intends to recover from June through May of each respective year, subject to approval of the NJBPU.			ComEd - 2024 ACE - To be determined in pending Societal Benefits Rider filing with NJBPU.			No
Universal service fund charge under-recovery - Electric			Represents under-recovery of electric supply and distribution revenue shortfalls net of base rate recovery related to PECO’s Universal Service programs, which are designed to provide affordable bills for electric service to low-income, residential customers based on individual household needs.			PECO - To be determined in the annual adjustment and reconciliation as approved by the PAPUC.			No
Zero emission credit			Represents ZEC procurement costs and any reasonable costs ComEd has incurred to implement and comply with the ZEC procurement process.			ComEd - Over 9 months starting with the September billing period and ending with the following May billing period.			ComEd - No

Decommissioning the Regulatory Agreement Units

The regulatory agreements with the ICC and PAPUC dictate obligations related to the shortfall or excess of NDT funds necessary for decommissioning the former ComEd units on a unit-by-unit basis and the former PECO units in total.

For the former PECO units, given the symmetric settlement provisions that allow for continued recovery of decommissioning costs from PECO customers in the event of a shortfall and the obligation for Constellation to ultimately return excess funds to PECO customers (on an aggregate basis for all seven units), decommissioning-related activities prior to separation on February 1, 2022 were generally offset in Exelon’s Consolidated

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Statements of Operations and Comprehensive Income with an offsetting adjustment to the regulatory liabilities or regulatory assets and an equal noncurrent affiliate receivable from or payable to Generation at PECO. Following the separation, decommissioning-related activities result in an adjustment to the Receivable related to Regulatory Agreement Units and an equal adjustment to the regulatory liabilities or regulatory assets at PECO.

For the former ComEd units, given no further recovery from ComEd customers is permitted and Constellation retains an obligation to ultimately return excess funds to ComEd customers (on a unit-by-unit basis), to the extent excess funds are expected for each unit, decommissioning-related activities prior to separation on February 1, 2022 were offset in the Consolidated Statements of Operations and Comprehensive Income with an offsetting adjustment to regulatory liabilities and noncurrent affiliate receivable from Generation at ComEd. Following the separation, decommissioning-related activities result in an adjustment to the Receivable related to Regulatory Agreement Units and an equal adjustment to the regulatory liabilities at ComEd. However, given the asymmetric settlement provision that does not allow for continued recovery from ComEd customers in the event of a shortfall, recognition of a regulatory asset at ComEd is not permissible.

Capitalized Ratemaking Amounts Not Recognized

The following table presents authorized amounts capitalized for ratemaking purposes related to earnings on shareholders’ investment that are not recognized for financial reporting purposes in the Registrants' Consolidated Balance Sheets. These amounts will be recognized as revenues in the related Consolidated Statements of Operations and Comprehensive Income in the periods they are billable to the Utility Registrants' customers. PECO had no related amounts at December 31, 2023 and December 31, 2022

			Exelon						ComEd (a)									BGE (b)						PHI						Pepco (c)						DPL (c)						ACE (d)
December 31, 2023			$	110					$	32								$	33					$	45					$	34					$	1					$	10
December 31, 2022			57						8									28						21						18						2						1

__________

(a) Reflects ComEd's unrecognized equity returns earned for ratemaking purposes on its energy efficiency and electric distribution formula rate regulatory assets.

(b) BGE's amount capitalized for ratemaking purposes primarily relates to earnings on shareholders' investment on their AMI programs and on investments in rate base included in the multi-year plan reconciliations.

(c) Pepco's and DPL's authorized amounts capitalized for ratemaking purposes relate to earnings on shareholders' investment on their respective AMI programs and Energy efficiency and demand response programs, and for Pepco District of Columbia revenue decoupling program. The earnings on energy efficiency are on Pepco District of Columbia and DPL Delaware programs only.

The Registrants recognize revenue from contracts with customers to depict the transfer of goods or services to customers at an amount that the entities expect to be entitled to in exchange for those goods or services. The primary sources of revenue include regulated electric and gas tariff sales, distribution, and transmission services. The performance obligations, revenue recognition, and payment terms associated with these sources of revenue are further discussed in the table below. There are no significant financing components for these sources of revenue and no variable consideration.

Unless otherwise noted, for each of the significant revenue categories and related performance obligations described below, the Registrants have the right to consideration from the customer in an amount that corresponds directly with the value transferred to the customer for the performance completed to date. Therefore, the Registrants generally recognize revenue in the amount for which they have the right to invoice the customer. As a result, there are generally no significant judgments used in determining or allocating the transaction price.

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Revenue Source

Description

Performance Obligation

Timing of Revenue Recognition

Payment Terms

Regulated Electric and Gas Tariff Sales

Sales of electricity and electricity distribution services (the Utility Registrants) and natural gas and gas distribution services (PECO, BGE, and DPL) to residential, commercial, industrial, and governmental customers through regulated tariff rates approved by state regulatory commissions.

Delivery of electricity and/or natural gas.

Over time (each day) as the electricity and/or natural gas is delivered to customers. Tariff sales are generally considered daily contracts as customers can discontinue service at any time. (a)

Within the month following delivery of the electricity or natural gas to the customer.

Regulated Transmission Services

The Utility Registrants provide open access to their transmission facilities to PJM, which directs and controls the operation of these transmission facilities and accordingly compensates the Utility Registrants pursuant to filed tariffs at cost-based rates approved by FERC.

Various including (i) Network Integration Transmission Services (NITS), (ii) scheduling, system control and dispatch services, and (iii) access to the wholesale grid.

Over time utilizing output methods to measure progress towards completion. (b)

Paid weekly by PJM.

__________

(a) Electric and natural gas utility customers have the choice to purchase electricity or natural gas from competitive electric generation and natural gas suppliers. While the Utility Registrants are required under state legislation to bill their customers for the supply and distribution of electricity and/or natural gas, they recognize revenue related only to the distribution services when customers purchase their electricity or natural gas from competitive suppliers.

(b) Passage of time is used for NITS and access to the wholesale grid and MWhs of energy transported over the wholesale grid is used for scheduling, system control and dispatch services.

The Utility Registrants do not incur any material costs to obtain or fulfill contracts with customers.

Contract Liabilities

The Registrants record contract liabilities when consideration is received or due prior to the satisfaction of the performance obligations. The Registrants record contract liabilities in Other current liabilities and Other noncurrent liabilities in the Registrants' Consolidated Balance Sheets.

On July 1, 2020, Pepco, DPL, and ACE each entered into a collaborative arrangement ("Agreement") with an unrelated owner and manager of communication infrastructure (the "Buyer"). Under this arrangement, Pepco, DPL, and ACE sold a 60 % undivided interest in their respective portfolios of transmission tower attachment agreements with telecommunications companies to the Buyer, in addition to transitioning management of the day-to-day operations of the jointly-owned agreements to the Buyer for 35 years, while retaining the safe and reliable operation of its utility assets. In return, Pepco, DPL, and ACE will provide the Buyer limited access on the portion of the towers where the equipment resides for the purposes of managing the agreements for the benefit of Pepco, DPL, ACE, and the Buyer. Pursuant to the Agreement, Pepco, DPL, and ACE have the option ("Payment Option"), but not obligation, to sell two additional 10 % undivided interests in the tower attachment agreements to the Buyer for specified consideration. In addition, for an initial period of three years and two , two-year extensions that are subject to certain conditions, the Buyer has the exclusive right to enter into new agreements with telecommunications companies and to receive a specified undivided percentage interest in those new agreements as set forth in the Agreement. Pepco, DPL, and ACE received cash and recorded contract liabilities as of July 1, 2020. The revenue attributable to this arrangement will be recognized as Electric operating revenues over the 35 years under the Agreement.

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During the fourth quarter of 2023, Pepco, DPL, and ACE entered into an amendment to the Agreement (“Amendment”) to modify the terms of the Payment Option and the conditions to exercise the exclusive right extensions. Concurrently, Pepco, DPL and ACE exercised both Payment Options which also triggered the extension of the exclusive right period until 2027. The Amendment and executed Payment Options represent a contract modification that is accounted for prospectively in accordance with authoritative guidance. Pepco, DPL and ACE received cash and recorded an increase to the contract liabilities as of December 31, 2023 as shown in the table below. The revenue will be recognized as Electric operating revenues over the remaining term of the Agreement (approximately 31 years).

The following table provides a rollforward of the contract liabilities reflected in Exelon's, PHI's, Pepco's, DPL's, and ACE'S Consolidated Balance Sheets. As of December 31, 2023, 2022, and 2021, ComEd's, PECO's, and BGE's contract liabilities were not material.

			Exelon (a)						PHI (a)						Pepco (a)						DPL (a)						ACE (a)
Balance at December 31, 2021			$	109					$	109					$	87					$	11					$	11
Revenues recognized			( 8 )						( 8 )						( 6 )						( 1 )						( 1 )
Balance at December 31, 2022			$	101					$	101					$	81					$	10					$	10
Consideration received			39						39						31						4						4
Revenues recognized			( 7 )						( 7 )						( 5 )						( 1 )						( 1 )
Balance at December 31, 2023			$	133					$	133					$	107					$	13					$	13

__________

(a) Revenues recognized in the years ended December 31, 2023 and 2022, were included in the contract liabilities at December 31, 2022 and 2021, respectively.

Transaction Price Allocated to Remaining Performance Obligations

The following table shows the amounts of future revenues expected to be recorded in each year for performance obligations that are unsatisfied or partially unsatisfied as of December 31, 2023. This disclosure only includes contracts for which the total consideration is fixed and determinable at contract inception. The average contract term varies by customer type and commodity but ranges from one month to several years.

This disclosure excludes the Utility Registrants' gas and electric tariff sales contracts and transmission revenue contracts as they generally have an original expected duration of one year or less and, therefore, do not contain any future, unsatisfied performance obligations to be included in this disclosure.

Year			Exelon						PHI						Pepco						DPL						ACE
2024			$	8					$	8					$	6					$	1					$	1
2025			6						6						5						—						1
2026			6						6						5						—						1
2027			5						5						5						—						—
2028 and thereafter			108						108						86						12						10
Total			$	133					$	133					$	107					$	13					$	13

Revenue Disaggregation

The Registrants disaggregate revenue recognized from contracts with customers into categories that depict how the nature, amount, timing, and uncertainty of revenue and cash flows are affected by economic factors. See Note 5 — Segment Information for the presentation of the Registrant's revenue disaggregation.

Operating segments for each of the Registrants are determined based on information used by the CODMs in deciding how to evaluate performance and allocate resources at each of the Registrants.

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Exelon has six reportable segments, which include ComEd, PECO, BGE, and PHI's three reportable segments consisting of Pepco, DPL, and ACE. ComEd, PECO, BGE, Pepco, DPL, and ACE each represent a single reportable segment, and as such, no separate segment information is provided for these Registrants. Exelon, ComEd, PECO, BGE, Pepco, DPL, and ACE's CODMs evaluate the performance of and allocate resources to the segments based on net income.

The separation of Constellation Energy Corporation, including Generation and its subsidiaries, meets the criteria for discontinued operations and as such, results of operations are presented as discontinued operations and have been excluded from continuing operations for all periods presented. Furthermore, the reportable segment information related to the discontinued operations has been excluded from the tables presented below. See Note 2 — Discontinued Operations for additional information.

An analysis and reconciliation of the Registrants' reportable segment information to the respective information in the consolidated financial statements for the years ended December 31, 2023, 2022, and 2021 is as follows:

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			ComEd						PECO						BGE						PHI						Other (a)						Intersegment Eliminations						Exelon
Operating revenues (b) :
2023
Electric revenues			$	7,844					$	3,202					$	3,109					$	5,812					$	—					$	( 51 )					$	19,916
Natural gas revenues			—						692						918						205						—						( 4 )						1,811
Shared service and other revenues			—						—						—						9						1,759						( 1,768 )						—
Total operating revenues			$	7,844					$	3,894					$	4,027					$	6,026					$	1,759					$	( 1,823 )					$	21,727
2022
Electric revenues			$	5,761					$	3,165					$	2,871					$	5,317					$	—					$	( 31 )					$	17,083
Natural gas revenues			—						738						1,024						238						—						( 5 )						1,995
Shared service and other revenues			—						—						—						10						1,823						( 1,833 )						—
Total operating revenues			$	5,761					$	3,903					$	3,895					$	5,565					$	1,823					$	( 1,869 )					$	19,078
2021
Electric revenues			$	6,406					$	2,659					$	2,505					$	4,860					$	—					$	( 35 )					$	16,395
Natural gas revenues			—						539						836						168						—						—						1,543
Shared service and other revenues			—						—						—						13						2,213						( 2,226 )						—
Total operating revenues			$	6,406					$	3,198					$	3,341					$	5,041					$	2,213					$	( 2,261 )					$	17,938
Intersegment revenues (c) :
2023			$	16					$	9					$	9					$	9					$	1,750					$	( 1,793 )					$	—
2022			16						7						15						10						1,823						( 1,865 )						6
2021			41						21						31						13						2,203						( 2,252 )						57
Depreciation and amortization:
2023			$	1,403					$	397					$	654					$	990					$	62					$	—					$	3,506
2022			1,323						373						630						938						61						—						3,325
2021			1,205						348						591						821						67						1						3,033
Operating expenses:
2023			$	6,038					$	3,146					$	3,245					$	5,114					$	1,991					$	( 1,820 )					$	17,714
2022			4,218						3,102						3,376						4,734						2,093						( 1,762 )						15,761
2021			5,151						2,547						2,860						4,240						2,045						( 1,587 )						15,256
Interest expense, net:
2023			$	477					$	201					$	182					$	323					$	546					$	—					$	1,729
2022			414						177						152						292						415						( 3 )						1,447
2021			389						161						138						267						335						( 1 )						1,289
Income taxes:
2023			$	314					$	20					$	133					$	116					$	( 207 )					$	( 2 )					$	374
2022			264						79						8						9						—						( 11 )						349
2021			172						12						( 35 )						42						8						( 161 )						38
Net income (loss) from continuing operations:
2023			$	1,090					$	563					$	485					$	590					$	( 380 )					$	( 20 )					$	2,328
2022			917						576						380						608						( 393 )						( 34 )						2,054
2021			742						504						408						561						( 156 )						( 443 )						1,616
Capital expenditures:
2023			$	2,576					$	1,426					$	1,367					$	1,988					$	54					$	—					$	7,411
2022			2,506						1,349						1,262						1,709						95						—						6,921
2021			2,387						1,240						1,226						1,720						67						—						6,640
Total assets:
2023			$	42,827					$	15,595					$	14,184					$	26,903					$	6,374					$	( 4,337 )					$	101,546
2022			39,661						14,502						13,350						26,082						6,014						( 4,260 )						95,349

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__________

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

(b) Includes gross utility tax receipts from customers. The offsetting remittance of utility taxes to the governing bodies is recorded in Taxes other than income taxes in the Registrants’ Consolidated Statements of Operations and Comprehensive Income. See Note 22 — Supplemental Financial Information for additional information on total utility taxes.

(c) See Note 23 — Related Party Transactions for additional information on intersegment revenues.

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PHI:

			Pepco						DPL						ACE						Other (a)						Intersegment Eliminations						PHI
Operating revenues (b) :
2023
Electric revenues			$	2,824					$	1,483					$	1,522					$	1					$	( 18 )					$	5,812
Natural gas revenues			—						205						—						—						—						205
Shared service and other revenues			—						—						—						422						( 413 )						9
Total operating revenues			$	2,824					$	1,688					$	1,522					$	423					$	( 431 )					$	6,026
2022
Electric revenues			$	2,531					$	1,357					$	1,431					$	—					$	( 2 )					$	5,317
Natural gas revenues			—						238						—						—						—						238
Shared service and other revenues			—						—						—						391						( 381 )						10
Total operating revenues			$	2,531					$	1,595					$	1,431					$	391					$	( 383 )					$	5,565
2021
Electric revenues			$	2,274					$	1,212					$	1,388					$	—					$	( 14 )					$	4,860
Natural gas revenues			—						168						—						—						—						168
Shared service and other revenues			—						—						—						379						( 366 )						13
Total operating revenues			$	2,274					$	1,380					$	1,388					$	379					$	( 380 )					$	5,041
Intersegment revenues (c) :
2023			$	9					$	8					$	2					$	422					$	( 432 )					$	9
2022			5						6						2						380						( 383 )						10
2021			5						7						2						380						( 381 )						13
Depreciation and amortization:
2023			$	441					$	244					$	283					$	22					$	—					$	990
2022			417						232						261						28						—						938
2021			403						210						179						29						—						821
Operating expenses:
2023			$	2,377					$	1,420					$	1,314					$	434					$	( 431 )					$	5,114
2022			2,140						1,359						1,225						393						( 383 )						4,734
2021			1,871						1,161						1,201						388						( 381 )						4,240
Interest expense, net:
2023			$	165					$	74					$	72					$	12					$	—					$	323
2022			150						66						66						9						1						292
2021			140						61						58						8						—						267
Income taxes:
2023			$	51					$	35					$	36					$	( 6 )					$	—					$	116
2022			( 9 )						14						3						1						—						9
2021			15						42						( 13 )						( 2 )						—						42
Net income (loss):
2023			$	306					$	177					$	120					$	( 13 )					$	—					$	590
2022			305						169						148						( 14 )						—						608
2021			296						128						146						( 9 )						—						561
Capital expenditures:
2023			$	957					$	562					$	460					$	9					$	—					$	1,988
2022			874						430						398						7						—						1,709
2021			843						429						445						3						—						1,720
Total assets:
2023			$	11,194					$	5,966					$	5,157					$	4,627					$	( 41 )					$	26,903
2022			10,657						5,802						4,979						4,677						( 33 )						26,082

__________

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

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(b) Includes gross utility tax receipts from customers. The offsetting remittance of utility taxes to the governing bodies is recorded in Taxes other than income taxes in the Registrants’ Consolidated Statements of Operations and Comprehensive Income. See Note 22 — Supplemental Financial Information for additional information on total utility taxes.

(c) Includes intersegment revenues with ComEd, PECO, and BGE, which are eliminated at Exelon.

Electric and Gas Revenue by Customer Class (Utility Registrants):

The following tables disaggregate the Registrants' revenues recognized from contracts with customers into categories that depict how the nature, amount, timing, and uncertainty of revenue and cash flows are affected by economic factors. For the Utility Registrants, the disaggregation of revenues reflects the two primary utility services of electric sales and natural gas sales (where applicable), with further disaggregation of these tariff sales provided by major customer groups. Exelon's disaggregated revenues are consistent with the Utility Registrants, but exclude any intercompany revenues.

			2023
Revenues from contracts with customers			ComEd						PECO						BGE						PHI						Pepco						DPL						ACE
Electric revenues
Residential			$	3,565					$	2,090					$	1,765					$	2,845					$	1,236					$	827					$	782
Small commercial & industrial			1,857						526						331						651						176						246						229
Large commercial & industrial			824						249						528						1,420						1,087						126						207
Public authorities & electric railroads			51						30						29						67						34						16						17
Other (a)			965						298						402						760						258						250						260
Total electric revenues (b)			$	7,262					$	3,193					$	3,055					$	5,743					$	2,791					$	1,465					$	1,495
Natural gas revenues
Residential			$	—					$	473					$	568					$	122					$	—					$	122					$	—
Small commercial & industrial			—						172						100						53						—						53						—
Large commercial & industrial			—						1						161						4						—						4						—
Transportation			—						27						—						16						—						16						—
Other (c)			—						17						37						10						—						10						—
Total natural gas revenues (d)			$	—					$	690					$	866					$	205					$	—					$	205					$	—
Total revenues from contracts with customers			$	7,262					$	3,883					$	3,921					$	5,948					$	2,791					$	1,670					$	1,495
Other revenues
Revenues from alternative revenue programs			$	556					$	( 7 )					$	84					$	64					$	22					$	15					$	27
Other electric revenues (e)			26						16						16						14						11						3						—
Other natural gas revenues (e)			—						2						6						—						—						—						—
Total other revenues			$	582					$	11					$	106					$	78					$	33					$	18					$	27
Total revenues for reportable segments			$	7,844					$	3,894					$	4,027					$	6,026					$	2,824					$	1,688					$	1,522

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			2022
Revenues from contracts with customers			ComEd						PECO						BGE						PHI						Pepco						DPL						ACE
Electric revenues
Residential			$	3,304					$	2,026					$	1,564					$	2,590					$	1,076					$	750					$	764
Small commercial & industrial			1,173						521						327						607						155						235						217
Large commercial & industrial			5						299						567						1,422						1,083						137						202
Public authorities & electric railroads			29						30						27						64						34						15						15
Other (a)			955						271						398						695						208						227						252
Total electric revenues (b)			$	5,466					$	3,147					$	2,883					$	5,378					$	2,556					$	1,364					$	1,450
Natural gas revenues
Residential			$	—					$	512					$	678					$	127					$	—					$	127					$	—
Small commercial & industrial			—						186						111						55						—						55						—
Large commercial & industrial			—						—						183						12						—						12						—
Transportation			—						26						—						15						—						15						—
Other (c)			—						12						68						29						—						29						—
Total natural gas revenues (d)			$	—					$	736					$	1,040					$	238					$	—					$	238					$	—
Total revenues from contracts with customers			$	5,466					$	3,883					$	3,923					$	5,616					$	2,556					$	1,602					$	1,450
Other revenues
Revenues from alternative revenue programs			$	267					$	2					$	( 47 )					$	( 59 )					$	( 31 )					$	( 9 )					$	( 19 )
Other electric revenues (e)			28						16						14						8						6						2						—
Other natural gas revenues (e)			—						2						5						—						—						—						—
Total other revenues			$	295					$	20					$	( 28 )					$	( 51 )					$	( 25 )					$	( 7 )					$	( 19 )
Total revenues for reportable segments			$	5,761					$	3,903					$	3,895					$	5,565					$	2,531					$	1,595					$	1,431

			2021
Revenues from contracts with customers			ComEd						PECO						BGE						PHI						Pepco						DPL						ACE
Electric revenues
Residential			$	3,233					$	1,704					$	1,375					$	2,441					$	1,003					$	694					$	744
Small commercial & industrial			1,571						422						267						521						135						193						193
Large commercial & industrial			559						243						459						1,123						844						94						185
Public authorities & electric railroads			45						31						27						58						31						14						13
Other (a)			926						229						371						634						205						201						229
Total electric revenues (b)			$	6,334					$	2,629					$	2,499					$	4,777					$	2,218					$	1,196					$	1,364
Natural gas revenues
Residential			$	—					$	372					$	518					$	97					$	—					$	97					$	—
Small commercial & industrial			—						136						83						42						—						42						—
Large commercial & industrial			—						—						147						7						—						7						—
Transportation			—						24						—						14						—						14						—
Other (c)			—						7						68						8						—						8						—
Total natural gas revenues (d)			$	—					$	539					$	816					$	168					$	—					$	168					$	—
Total revenues from contracts with customers			$	6,334					$	3,168					$	3,315					$	4,945					$	2,218					$	1,364					$	1,364
Other revenues
Revenues from alternative revenue programs			$	42					$	26					$	12					$	91					$	53					$	14					$	24
Other electric revenues (e)			30						4						11						5						3						2						—
Other natural gas revenues (e)			—						—						3						—						—						—						—
Total other revenues			$	72					$	30					$	26					$	96					$	56					$	16					$	24
Total revenues for reportable segments			$	6,406					$	3,198					$	3,341					$	5,041					$	2,274					$	1,380					$	1,388

---

__________

(a) Includes revenues from transmission revenue from PJM, wholesale electric revenue and mutual assistance revenue.

(b) Includes operating revenues from affiliates in 2023, 2022, and 2021 respectively of:

• $ 16 million, $ 16 million, and $ 41 million at ComEd

• $ 7 million, $ 7 million, and $ 20 million at PECO

• $ 6 million, $ 7 million, and $ 13 million at BGE

• $ 9 million, $ 10 million, and $ 13 million at PHI

• $ 9 million, $ 5 million, and $ 5 million at Pepco

• $ 8 million, $ 6 million, and $ 7 million at DPL

• $ 2 million, $ 2 million, and $ 2 million at ACE

(c) Includes revenues from off-system natural gas sales.

(d) Includes operating revenues from affiliates in 2023, 2022, and 2021 respectively of:

• $ 2 million, less than $1 million, and $ 1 million at PECO

• $ 3 million, $ 8 million, and $ 18 million at BGE

(e) Includes late payment charge revenues.

Allowance for Credit Losses on Accounts Receivable

The following tables present the rollforward of Allowance for credit losses on Customer accounts receivable.

			Year Ended December 31, 2023
			Exelon						ComEd						PECO						BGE						PHI						Pepco						DPL						ACE
Balance at December 31, 2022			$	327					$	59					$	105					$	54					$	109					$	47					$	21					$	41
Plus: Current period provision for expected credit losses (a)(b)(c)			170						53						48						26						43						23						9						11
Less: Write-offs (d)(e)(f) , net of recoveries (g)			180						43						58						34						45						18						11						16
Balance at December 31, 2023			$	317					$	69					$	95					$	46					$	107					$	52					$	19					$	36
			Year Ended December 31, 2022
			Exelon						ComEd						PECO						BGE						PHI						Pepco						DPL						ACE
Balance at December 31, 2021			$	320					$	73					$	105					$	38					$	104					$	37					$	18					$	49
Plus: Current period provision for expected credit losses			176						29						52						37						58						31						12						15
Less: Write-offs, net of recoveries			169						43						52						21						53						21						9						23
Balance at December 31, 2022			$	327					$	59					$	105					$	54					$	109					$	47					$	21					$	41

_________

(a) For ComEd, the change in current period provision for expected credit losses is primarily a result of increased receivable balances.

(b) For BGE, DPL and ACE, the change in current period provision for expected credit losses is primarily a result of decreased receivable balances.

(c) For Pepco the change in current period provision for expected credit losses is primarily a result of receivables increasing at a slower pace versus the prior period.

(d) For PECO and BGE the change in write-offs is primarily a result of increased disconnection activities.

(e) For PHI, ACE, and Pepco, write-offs are primarily attributable to the termination of the moratorium in the service territory for each operating company, which beginning in 2020, prevented customer disconnections for non-payment. Disconnection activities across the service territories resumed from September 2020 through January 2022, resulting in write-offs of aged accounts receivable.

(f) For DPL, the change in write-offs is primarily attributable to unfavorable customer payment behavior.

(g) Recoveries were not material to the Registrants.

The following tables present the rollforward of Allowance for credit losses on Other accounts receivable.

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			Year Ended December 31, 2023
			Exelon						ComEd						PECO						BGE						PHI						Pepco						DPL						ACE
Balance at December 31, 2022			$	82					$	17					$	9					$	10					$	46					$	25					$	7					$	14
Plus: Current period provision for expected credit losses			21						5						4						5						7						3						1						3
Less: Write-offs, net of recoveries (a)			21						5						5						8						3						—						—						3
Balance at December 31, 2023			$	82					$	17					$	8					$	7					$	50					$	28					$	8					$	14
			Year Ended December 31, 2022
			Exelon						ComEd						PECO						BGE						PHI						Pepco						DPL						ACE
Balance at December 31, 2021			$	72					$	17					$	7					$	9					$	39					$	16					$	8					$	15
Plus: Current period provision (benefit) for expected credit losses			26						3						6						6						11						9						( 1 )						3
Less: Write-offs, net of recoveries			16						3						4						5						4						—						—						4
Balance at December 31, 2022			$	82					$	17					$	9					$	10					$	46					$	25					$	7					$	14

_________

(a) Recoveries were not material to the Registrants.

Unbilled Customer Revenue

The following table provides additional information about unbilled customer revenues recorded in the Registrants' Consolidated Balance Sheets as of December 31, 2023 and 2022.

			Unbilled customer revenues (a)
			Exelon						ComEd						PECO						BGE						PHI						Pepco						DPL						ACE
December 31, 2023			$	991					$	351					$	185					$	208					$	247					$	109					$	64					$	74
December 31, 2022			912						223						219						247						223						103						74						46

_________

(a) Unbilled customer revenues are classified in Customer accounts receivables, net in the Registrants' Consolidated Balance Sheets.

Other Purchases of Customer and Other Accounts Receivables

The Utility Registrants are required, under separate legislation and regulations in Illinois, Pennsylvania, Maryland, District of Columbia, and New Jersey, to purchase certain receivables from alternative retail electric and, as applicable, natural gas suppliers that participate in the utilities' consolidated billing. The following tables present the total receivables purchased.

			Total receivables purchased
			Exelon						ComEd						PECO						BGE						PHI						Pepco						DPL						ACE
Year ended December 31, 2023			$	4,056					$	942					$	1,099					$	804					$	1,211					$	782					$	228					$	201
Year ended December 31, 2022			3,981			(a)			965						1,081						792			(a)			1,143						723						205						215

_________

(a) Includes $ 4 million of receivables purchased from Generation prior to the separation on February 1, 2022 for the year ended December 31, 2022.

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The following tables present a summary of property, plant, and equipment by asset category at December 31, 2023 and 2022:

Asset Category			Exelon						ComEd						PECO						BGE						PHI						Pepco						DPL						ACE
December 31, 2023
Electric—transmission and distribution			$	74,102					$	34,834					$	11,295					$	10,537					$	19,153					$	12,429					$	5,590					$	5,659
Gas—transportation and distribution			8,818						—						3,905						4,428						748						—						905						—
Common—electric and gas			2,510						—						1,083						1,275						243						—						211						—
Construction work in progress			4,589						1,369						879						561						1,762						1,226						345						189
Other property, plant, and equipment (a)			825						107						63						45						120						59						39						28
Total property, plant, and equipment			90,844						36,310						17,225						16,846						22,026						13,714						7,090						5,876
Less: accumulated depreciation			17,251						7,222						4,097						4,744						3,175						4,284						1,925						1,684
Property, plant, and equipment, net			$	73,593					$	29,088					$	13,128					$	12,102					$	18,851					$	9,430					$	5,165					$	4,192
December 31, 2022
Electric—transmission and distribution			$	69,034					$	32,906					$	10,719					$	9,993					$	17,165					$	11,270					$	5,231					$	5,219
Gas—transportation and distribution			8,126						—						3,619						4,074						696						—						855						—
Common—electric and gas			2,521						—						1,071						1,317						228						—						206						—
Construction work in progress			4,534						1,174						744						487						2,101						1,526						271						296
Other property, plant and equipment (a)			791						106						50						50						114						65						29						26
Total property, plant and equipment			85,006						34,186						16,203						15,921						20,304						12,861						6,592						5,541
Less: accumulated depreciation			15,930						6,673						4,078						4,583						2,618						4,067						1,772						1,551
Property, plant, and equipment, net			$	69,076					$	27,513					$	12,125					$	11,338					$	17,686					$	8,794					$	4,820					$	3,990

__________

(a) Primarily composed of land and non-utility property.

---

The following table presents the average service life for each asset category in number of years:

			Average Service Life (years)
Asset Category			Exelon						ComEd						PECO						BGE						PHI						Pepco						DPL						ACE
Electric - transmission and distribution			5-80						5-80						5-70						5-80						5-75						5-75						5-75						5-75
Gas - transportation and distribution			5-80						N/A						5-70						5-80						5-75						N/A						5-75						N/A
Common - electric and gas			4-75						N/A						5-55						4-50						5-75						N/A						5-75						N/A
Other property, plant, and equipment			4-61						30-50						50						20-50						10-43						10-33						10-43						13-15

The following table presents the annual depreciation rates for each asset category.

			Annual Depreciation Rates
			Exelon						ComEd						PECO						BGE						PHI						Pepco						DPL						ACE
December 31, 2023
Electric—transmission and distribution			2.90 %						3.02 %						2.30 %						2.89 %						3.03 %						2.51 %						3.29 %						3.66 %
Gas—transportation and distribution			2.15 %						N/A						1.85 %						2.56 %						1.44 %						N/A						1.44 %						N/A
Common—electric and gas			7.77 %						N/A						6.87 %						8.68 %						7.18 %						N/A						8.79 %						N/A
December 31, 2022
Electric—transmission and distribution			2.87 %						3.00 %						2.29 %						2.82 %						2.96 %						2.58 %						3.08 %						3.38 %
Gas—transportation and distribution			2.14 %						N/A						1.87 %						2.53 %						1.45 %						N/A						1.45 %						N/A
Common—electric and gas			7.54 %						N/A						6.31 %						8.20 %						8.96 %						N/A						10.03 %						N/A
December 31, 2021
Electric—transmission and distribution			2.81 %						2.94 %						2.28 %						2.80 %						2.87 %						2.56 %						2.86 %						3.21 %
Gas—transportation and distribution			2.13 %						N/A						1.84 %						2.54 %						1.47 %						N/A						1.47 %						N/A
Common—electric and gas			7.31 %						N/A						6.34 %						7.88 %						8.33 %						N/A						8.69 %						N/A

AFUDC

The following table summarizes credits to AFUDC by year:

			For the Years Ended December 31,
			2023						2022						2021
Exelon			$	256					$	215					$	189
ComEd			72						54						47
PECO			46						42						34
BGE			25						29						36
PHI			113						90						72
Pepco			85						69						59
DPL			16						10						8
ACE			12						11						5

See Note 1 — Significant Accounting Policies for additional information regarding property, plant and equipment policies. See Note 16 — Debt and Credit Agreements for additional information regarding Exelon’s, ComEd’s, PECO's, Pepco's, DPL's, and ACE’s property, plant and equipment subject to mortgage liens.

---

PECO's, DPL's, and ACE's material undivided ownership interests in transmission facilities jointly owned with non-affiliated utilities as of December 31, 2023 and 2022 were as follows:

			Transmission
			NJ/DE (a)
Operator			PSEG/DPL
Ownership interest			various
Exelon’s share at December 31, 2023:
Plant in service			$	103
Accumulated depreciation			56
Construction work in progress			2
Exelon’s share at December 31, 2022:
Plant in service			$	103
Accumulated depreciation			56
Construction work in progress			—

__________

(a) PECO, DPL, and ACE own a 42.55 %, 1 %, and 13.9 % share, respectively, in 151.3 miles of 500kV lines located in New Jersey and in the Salem substation. PECO, DPL, and ACE also own a 42.55 %, 7.45 %, and 7.45 % share, respectively, in 2.5 miles of 500kV line located over the Delaware River. ACE also has a 21.78 % share in a 500kV New Freedom Switching substation.

Certain facilities are fully owned by Exelon through its 100 % ownership in PECO, DPL, and ACE. These facilities are operated by Exelon Registrants. PECO's, DPL's, and ACE's material undivided ownership interests in Exelon owned facilities as of December 31, 2023 and 2022 were as follows:

			PECO						PHI						DPL						ACE
Ownership interest			56		%				44		%				27		%				17		%
Registrant's share at December 31, 2023:
Plant in service			$	7					$	6					$	4					$	2
Accumulated depreciation			—						—						—						—
Construction work in progress			70						58						36						22
Registrant's share at December 31, 2022:
Plant in service			$	7					$	6					$	4					$	2
Accumulated depreciation			—						—						—						—
Construction work in progress			41						36						22						14

PECO's, DPL's, and ACE's undivided ownership interests presented in the tables above are financed with their funds and all operations are accounted for as if such participating interests were wholly owned facilities. PECO's, DPL's, and ACE's share of direct expenses of the jointly owned plants are included in Operating and maintenance expenses in Exelon's, PECO's, PHI's, DPL's, and ACE's Consolidated Statements of Operations and Comprehensive Income.

---

The Registrants have AROs primarily associated with the abatement and disposal of equipment and buildings contaminated with asbestos and PCBs. See Note 1 — Significant Accounting Policies for additional information on the Registrants’ accounting policy for AROs.

The following table provides a rollforward of the AROs reflected in the Registrants’ Consolidated Balance Sheets from December 31, 2021 to December 31, 2023:

			Exelon						ComEd						PECO						BGE						PHI						Pepco						DPL						ACE
AROs at December 31, 2021			$	274					$	146					$	29					$	26					$	70					$	45					$	16					$	9
Revisions in estimates of cash flows			( 8 )						2						( 1 )						3						( 13 )						( 8 )						( 3 )						( 2 )
Accretion expense (a)			8						4						1						1						2						2						—						—
Payments			( 3 )						( 2 )						( 1 )						—						—						—						—						—
AROs at December 31, 2022			$	271					$	150					$	28					$	30					$	59					$	39					$	13					$	7
Revisions in estimates of cash flows			( 9 )						( 3 )						( 1 )						1						( 6 )						( 4 )						( 1 )						( 1 )
Accretion expense (a)			11						6						1						1						3						2						1						—
Payments			( 4 )						( 3 )						( 1 )						—						—						—						—						—
AROs at December 31, 2023			$	269					$	150					$	27					$	32					$	56					$	37					$	13					$	6

__________

(a) For ComEd, PECO, BGE, DPL and ACE, the majority of the accretion is recorded as an increase to a regulatory asset due to the associated regulatory treatment.

Lessee

The Registrants have operating and finance leases for which they are the lessees. The following tables outline the significant types of leases at each of the Registrants and other terms and conditions of the lease agreements as of December 31, 2023. Exelon, ComEd, PECO, and BGE did not have material finance leases in 2023, 2022, or 2021.

Exelon

ComEd

PECO

BGE

PHI

Pepco

DPL

ACE

Real estate

●

●

●

●

●

●

●

●

Vehicles and equipment

●

●

●

●

●

●

(in years)			Exelon						ComEd						PECO						BGE						PHI						Pepco						DPL						ACE
Remaining lease terms			1-82						1-29						1-10						1-82						1-8						1-8						1-8						1-7
Options to extend the term			3-30						N/A						N/A						3-5						3-30						5						3-30						5
Options to terminate within			9						N/A						N/A						N/A						N/A						N/A						N/A						N/A

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The components of operating lease costs were as follows:

			Exelon						ComEd						PECO						BGE						PHI						Pepco						DPL						ACE
For the year ended December 31, 2023
Operating lease costs			$	58					$	1					$	—					$	5					$	43					$	11					$	11					$	6
Variable lease costs			9						1						—						—						3						1						1						1
Total lease costs (a)			$	67					$	2					$	—					$	5					$	46					$	12					$	12					$	7
For the year ended December 31, 2022
Operating lease costs			$	66					$	2					$	—					$	15					$	42					$	10					$	12					$	6
Variable lease costs			8						1						—						—						2						1						1						1
Total lease costs (a)			$	74					$	3					$	—					$	15					$	44					$	11					$	13					$	7
For the year ended December 31, 2021
Operating lease costs			$	84					$	3					$	—					$	30					$	43					$	10					$	12					$	6
Variable lease costs			7						1						—						1						1						—						—						—
Total lease costs (a)			$	91					$	4					$	—					$	31					$	44					$	10					$	12					$	6

__________

(a) Excludes sublease income recorded at Exelon, PHI, and DPL of $ 4 million for the years ended December 31, 2023, 2022, and 2021.

The components of financing lease costs were as follows:

																											PHI						Pepco						DPL						ACE
For the year ended December 31, 2023
Amortization of ROU asset																											$	16					$	6					$	6					$	4
Interest on lease liabilities																											6						2						2						1
Total finance lease cost																											$	22					$	8					$	8					$	5
For the year ended December 31, 2022
Amortization of ROU asset																											$	14					$	5					$	6					$	3
Interest on lease liabilities																											4						1						2						1
Total finance lease cost																											$	18					$	6					$	8					$	4
For the year ended December 31, 2021
Amortization of ROU asset																											$	11					$	4					$	4					$	3
Interest on lease liabilities																											2						1						1						—
Total finance lease cost																											$	13					$	5					$	5					$	3

The following tables provide additional information regarding the presentation of operating and finance lease ROU assets and lease liabilities within the Registrants’ Consolidated Balance Sheets:

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			Operating Leases
			Exelon						ComEd						PECO						BGE						PHI						Pepco						DPL						ACE
At December 31, 2023
Operating lease ROU assets
Other deferred debits and other assets			$	257					$	—					$	1					$	29					$	152					$	31					$	32					$	8
Operating lease liabilities
Other current liabilities			$	38					$	—					$	—					$	4					$	30					$	5					$	7					$	3
Other deferred credits and other liabilities			248						—						—						17						141						30						36						6
Total operating lease liabilities			$	286					$	—					$	—					$	21					$	171					$	35					$	43					$	9
At December 31, 2022
Operating lease ROU assets
Other deferred debits and other assets			$	265					$	2					$	1					$	2					$	180					$	36					$	39					$	9
Operating lease liabilities
Other current liabilities			$	40					$	2					$	—					$	—					$	31					$	6					$	8					$	3
Other deferred credits and other liabilities			266						—						1						4						167						34						42						7
Total operating lease liabilities			$	306					$	2					$	1					$	4					$	198					$	40					$	50					$	10

																											Finance Leases
																											PHI						Pepco						DPL						ACE
At December 31, 2023
Finance lease ROU assets
Plant, property and equipment, net																											$	72					$	25					$	28					$	18
Finance lease liabilities
Long-term debt due within one year																											$	15					$	5					$	6					$	4
Long-term debt																											59						21						23						15
Total finance lease liabilities																											$	74					$	26					$	29					$	19
At December 31, 2022
Finance lease ROU assets
Plant, property and equipment, net																											$	74					$	25					$	31					$	18
Finance lease liabilities
Long-term debt due within one year																											$	12					$	4					$	5					$	3
Long-term debt																											64						21						27						16
Total finance lease liabilities																											$	76					$	25					$	32					$	19

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Future minimum lease payments for operating and finance leases as of December 31, 2023 were as follows:

			Operating Leases
Year			Exelon						ComEd						PECO						BGE						PHI						Pepco						DPL						ACE
2024			$	49					$	—					$	—					$	4					$	36					$	7					$	9					$	3
2025			47						—						—						4						34						5						8						3
2026			43						—						—						4						30						5						5						1
2027			41						—						—						2						30						4						6						1
2028			41						—						—						2						30						4						6						1
Remaining years			130						—						—						22						40						16						21						1
Total			351						—						—						38						200						41						55						10
Interest			65						—						—						17						29						6						12						1
Total operating lease liabilities			$	286					$	—					$	—					$	21					$	171					$	35					$	43					$	9

																											Finance Leases
Year																											PHI						Pepco						DPL						ACE
2024																											$	16					$	6					$	6					$	4
2025																											16						6						6						4
2026																											16						6						6						4
2027																											14						5						6						3
2028																											10						3						4						3
Remaining years																											8						2						3						3
Total																											80						28						31						21
Interest																											6						2						2						2
Total finance lease liabilities																											$	74					$	26					$	29					$	19

The weighted average remaining lease terms, in years, for operating and finance leases were as follows:

			Operating Leases
			Exelon						ComEd						PECO						BGE						PHI						Pepco						DPL						ACE
At December 31, 2023			8.8						1.8						5.0						17.1						6.1						7.6						7.4						3.2
At December 31, 2022			9.5						1.0						5.5						70.9						6.8						8.1						7.9						3.3

																											Finance Leases
																											PHI						Pepco						DPL						ACE
At December 31, 2023																											4.9						4.9						4.8						5.1
At December 31, 2022																											5.5						5.4						5.5						5.6

The weighted average discount rates for operating and finance leases were as follows:

			Operating Leases
			Exelon						ComEd						PECO						BGE						PHI						Pepco						DPL						ACE
At December 31, 2023			4.0		%				0.7		%				2.5		%				5.0		%				4.2		%				4.1		%				4.0		%				3.6		%
At December 31, 2022			3.9		%				2.6		%				2.3		%				4.5		%				4.2		%				4.0		%				4.0		%				3.3		%

																											Finance Leases
																											PHI						Pepco						DPL						ACE
At December 31, 2023																											2.7		%				2.7		%				2.6		%				2.8		%
At December 31, 2022																											2.3		%				2.3		%				2.3		%				2.4		%

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Cash paid for amounts included in the measurement of operating and finance lease liabilities were as follows:

			Operating Cash Flows from Operating Leases
			Exelon						ComEd						PECO						BGE						PHI						Pepco						DPL						ACE
For the year ended December 31, 2023			$	65					$	2					$	—					$	15					$	37					$	7					$	9					$	3
For the year ended December 31, 2022			66						3						—						16						37						8						9						4
For the year ended December 31, 2021			93						3						—						46						39						8						9						4

																											Financing Cash Flows from Finance Leases
																											PHI						Pepco						DPL						ACE
For the year ended December 31, 2023																											$	15					$	5					$	6					$	4
For the year ended December 31, 2022																											13						5						5						3
For the year ended December 31, 2021																											10						3						4						3

ROU assets obtained in exchange for operating and finance lease obligations were as follows:

			Operating Leases
			Exelon						ComEd						PECO						BGE						PHI						Pepco						DPL						ACE
For the year ended December 31, 2023			$	35					$	—					$	—					$	32					$	3					$	—					$	1					$	2
For the year ended December 31, 2022			46						—						—						—						2						—						1						1
For the year ended December 31, 2021			1						—						—						( 1 )						1						—						1						—

																											Finance Leases
																											PHI						Pepco						DPL						ACE
For the year ended December 31, 2023																											$	11					$	5					$	3					$	3
For the year ended December 31, 2022																											14						4						7						3
For the year ended December 31, 2021																											32						12						12						8

Lessor

The Registrants have operating leases for which they are the lessors. The following tables outline the significant types of leases at each of the Registrants and other terms and conditions of their lease agreements as of December 31, 2023. ACE did not have any operating leases for which they are the lessors for the years ended December 31, 2023, 2022, and 2021.

Exelon

ComEd

PECO

BGE

PHI

Pepco

DPL

Real estate

●

●

●

●

●

●

●

(in years)			Exelon						ComEd						PECO						BGE						PHI						Pepco						DPL
Remaining lease terms			1-79						1-13						1-79						19						1-9						1-2						8-9
Options to extend the term			1-79						5-79						1-50						N/A						N/A						N/A						N/A

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The components of lease income were as follows:

			Exelon						ComEd						PECO						BGE						PHI						Pepco						DPL
For the year ended December 31, 2023
Operating lease income			$	5					$	—					$	—					$	—					$	4					$	—					$	3
Variable lease income			1						—						—						—						1						—						1
For the year ended December 31, 2022
Operating lease income			$	4					$	—					$	—					$	—					$	4					$	—					$	3
Variable lease income			1						—						—						—						1						—						1
For the year ended December 31, 2021
Operating lease income			$	5					$	—					$	—					$	—					$	4					$	—					$	3
Variable lease income			1						—						—						—						1						—						1

Future minimum lease payments to be recovered under operating leases as of December 31, 2023 were as follows:

Year			Exelon						ComEd						PECO						BGE						PHI						Pepco						DPL
2024			$	6					$	1					$	1					$	—					$	4					$	—					$	4
2025			6						1						1						—						4						—						4
2026			6						—						1						—						5						—						4
2027			6						—						—						—						5						—						4
2028			5						—						—						—						5						—						4
Remaining years			22						—						3						1						18						—						18
Total			$	51					$	2					$	6					$	1					$	41					$	—					$	38

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In the third quarter of 2022, a review of the impacts of COVID-19 on office use resulted in plans to cease the renovation and dispose of an office building at BGE before the asset was placed into service. BGE determined that the carrying value was not recoverable and that its fair value was less than carrying value. As a result, in 2022, a pre-tax impairment charge of $ 48 million was recorded in Operating and maintenance expense in Exelon’s and BGE’s Consolidated Statements of Operations and Comprehensive Income. The fair value used in the analysis was based on an estimate of an expected sales price. The office building met all of the criteria for classification as held for sale as of December 31, 2023, and therefore is reported within Other current assets in Exelon’s and BGE’s Balance Sheets as of December 31, 2023.

Goodwill (Exelon, ComEd, PHI, Pepco, DPL, and ACE)

The following table presents the gross amount, accumulated impairment loss, and carrying amount of Goodwill at Exelon, ComEd, and PHI at December 31, 2023 and 2022. There were no additions or impairments during the years ended December 31, 2023 and 2022.

			Gross Amount						Accumulated Impairment Loss						Carrying Amount
Exelon			$	8,613					$	1,983					$	6,630
ComEd (a)			4,608						1,983						2,625
PHI (b)			4,005						—						4,005

__________

(a) Reflects goodwill recorded in 2000 from the PECO/Unicom merger (predecessor parent company of ComEd).

(b) Reflects goodwill recorded in 2016 from the PHI merger.

Goodwill is not amortized, but is subject to an assessment for impairment at least annually, or more frequently if events occur or circumstances change that would more likely than not reduce the fair value of ComEd's and PHI's reporting units below their carrying amounts. 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. A component of an operating segment is a reporting unit if the component constitutes a business for which discrete financial information is available and its operating results are regularly reviewed by segment management. ComEd has a single operating segment. PHI's operating segments are Pepco, DPL, and ACE. See Note 5 — Segment Information for additional information. There is no level below these operating segments for which operating results are regularly reviewed by segment management. Therefore, the ComEd, Pepco, DPL, and ACE operating segments are also considered reporting units for goodwill impairment assessment purposes. Exelon's and ComEd's $ 2.6 billion of goodwill has been assigned entirely to the ComEd reporting unit, while Exelon's and PHI's $ 4.0 billion of 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.

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 conditions, including the discount rate and regulated utility peer EBITDA multiples, and the passing margin from their last quantitative assessments performed. If an entity bypasses the qualitative assessment, a quantitative, fair value-based assessment is performed, which compares the fair value of the reporting unit to its carrying amount, including goodwill. If the carrying amount of the reporting unit exceeds its fair value, the entity recognizes an impairment charge, which is limited to the amount of goodwill allocated to the reporting unit.

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

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performance and transactions, projected operating and capital cash flows for ComEd's, Pepco's, DPL's, and ACE's businesses, and the fair value of debt.

2023 and 2022 Goodwill Impairment Assessment. ComEd and PHI qualitatively determined that it was more likely than not that the fair values of their reporting units exceeded their carrying values and, therefore, did not perform quantitative assessments as of November 1, 2023 and 2022. The last quantitative assessments performed for PHI was as of November 1, 2018. On December 14, 2023, due to the issuance of the ICC's final order rejecting ComEd’s proposed Grid Plan and establishing retail rates for 2024-2027 as further discussed in Note 3 — Regulatory Matters, Exelon’s stock price decreased approximately 10 % triggering an interim quantitative assessment for potential goodwill impairment at ComEd. ComEd performed a quantitative assessment as of December 31, 2023, comparing the estimated fair value of ComEd to its carrying value, and determined there was no indication of goodwill impairment.

While the annual and interim assessments indicated no impairments, certain assumptions used to estimate reporting unit fair values are highly sensitive to changes. Adverse regulatory actions or changes in significant assumptions could potentially result in future impairments of Exelon's, ComEd's, and PHI’s goodwill, which could be material.

Other Intangible Assets and Liabilities (Exelon and PHI)

Exelon’s other intangible assets, included in Other current assets and Other deferred debits and other assets in the Consolidated Balance Sheets, consisted of the following at December 31, 2023 and 2022. Exelon's and PHI's other intangible liabilities, included in current and noncurrent Unamortized energy contract liabilities in their Consolidated Balance Sheets, consisted of the following at December 31, 2023 and 2022. The intangible assets and liabilities shown below are amortized on a straight-line basis, except for unamortized energy contracts which are amortized in relation to the expected realization of the underlying cash flows:

						December 31, 2023																		December 31, 2022
						Gross						Accumulated Amortization						Net						Gross						Accumulated Amortization						Net
Exelon
Unamortized Energy Contracts						$	( 1,515 )					$	1,480					$	( 35 )					$	( 1,515 )					$	1,470					$	( 45 )
Software License						81						( 70 )						11						81						( 61 )						20
Exelon Total						$	( 1,434 )					$	1,410					$	( 24 )					$	( 1,434 )					$	1,409					$	( 25 )
PHI
Unamortized Energy Contracts						$	( 1,515 )					$	1,480					$	( 35 )					$	( 1,515 )					$	1,470					$	( 45 )

The following table summarizes the amortization expense related to intangible assets and liabilities for each of the years ended December 31, 2023, 2022, and 2021:

For the Years Ended December 31,						Exelon (a)						PHI (a)
2023						$	( 1 )					$	( 10 )
2022 (b)						( 182 )						( 190 )
2021						( 83 )						( 92 )

__________

(a) For PHI unamortized energy contracts, the amortization of the fair value adjustment amounts and the corresponding offsetting regulatory asset amounts are amortized through Purchased power and fuel expense in their Consolidated Statements of Operations and Comprehensive Income resulting in no effect to net income.

(b) On March 23, 2022, the NJBPU approved a petition by ACE to terminate the provisions in its PPAs. As such, the contract was fully amortized during the year ended December 31, 2022. See Note 3 - Regulatory Matters for additional information.

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Components of Income Tax Expense or Benefit

Income tax expense (benefit) from continuing operations is comprised of the following components:

			For the Year Ended December 31, 2023
			Exelon						ComEd						PECO						BGE						PHI						Pepco						DPL						ACE
Included in operations:
Federal
Current			$	51					$	130					$	63					$	67					$	71					$	54					$	25					$	9
Deferred			193						45						( 36 )						16						( 8 )						( 28 )						( 6 )						13
Investment tax credit amortization			( 2 )						( 1 )						—						—						( 1 )						—						—						—
State
Current			4						( 13 )						—						—						15						12						6						—
Deferred			128						153						( 7 )						50						39						13						10						14
Total			$	374					$	314					$	20					$	133					$	116					$	51					$	35					$	36

			For the Year Ended December 31, 2022
			Exelon						ComEd						PECO						BGE						PHI						Pepco						DPL						ACE
Included in operations:
Federal
Current			$	( 24 )					$	29					$	13					$	( 1 )					$	16					$	9					$	( 2 )					$	6
Deferred			106						117						18						( 3 )						( 23 )						( 2 )						2						( 15 )
Investment tax credit amortization			( 3 )						( 1 )						—						—						( 1 )						—						—						—
State
Current			( 13 )						( 6 )						( 4 )						—						2						—						—						—
Deferred			283						125						52						12						15						( 16 )						14						12
Total			$	349					$	264					$	79					$	8					$	9					$	( 9 )					$	14					$	3

			For the Year Ended December 31, 2021
			Exelon						ComEd						PECO						BGE						PHI						Pepco						DPL						ACE
Included in operations:
Federal
Current			$	( 152 )					$	( 30 )					$	1					$	( 18 )					$	18					$	22					$	2					$	1
Deferred			89						113						20						34						( 52 )						( 17 )						( 14 )						( 26 )
Investment tax credit amortization			( 2 )						( 1 )						—						—						( 1 )						—						—						—
State
Current			( 46 )						( 41 )						—						—						—						1						1						—
Deferred			149						131						( 9 )						( 51 )						77						9						53						12
Total			$	38					$	172					$	12					$	( 35 )					$	42					$	15					$	42					$	( 13 )

Rate Reconciliation

The effective income tax rate from continuing operations varies from the U.S. federal statutory rate principally due to the following:

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			For the Year Ended December 31, 2023 (a)
			Exelon						ComEd						PECO (b)						BGE						PHI						Pepco						DPL						ACE
U.S. federal statutory rate			21.0		%				21.0		%				21.0		%				21.0		%				21.0		%				21.0		%				21.0		%				21.0		%
Increase (decrease) due to:
State income taxes, net of Federal income tax benefit (c)			3.9						7.9						( 1.0 )						6.4						5.9						5.5						6.1						7.1
Plant basis differences			( 3.9 )						( 0.5 )						( 14.4 )						( 0.9 )						( 1.4 )						( 2.2 )						( 0.7 )						( 0.4 )
Excess deferred tax amortization			( 6.6 )						( 5.5 )						( 2.4 )						( 4.6 )						( 8.6 )						( 9.6 )						( 9.4 )						( 4.2 )
Amortization of investment tax credit, including deferred taxes on basis differences			( 0.1 )						( 0.1 )						—						—						( 0.1 )						—						( 0.1 )						( 0.2 )
Tax credits			( 0.6 )						( 0.6 )						—						( 0.6 )						( 0.6 )						( 0.7 )						( 0.4 )						( 0.5 )
Other			0.1						0.2						0.2						0.2						0.2						0.3						—						0.3
Effective income tax rate			13.8		%				22.4		%				3.4		%				21.5		%				16.4		%				14.3		%				16.5		%				23.1		%

			For the Year Ended December 31, 2022 (a)
			Exelon						ComEd						PECO (d)						BGE (d)						PHI (d)						Pepco (d)						DPL (d)						ACE (d)
U.S. federal statutory rate			21.0		%				21.0		%				21.0		%				21.0		%				21.0		%				21.0		%				21.0		%				21.0		%
Increase (decrease) due to:
State income taxes, net of Federal income tax benefit (e)			8.8						8.0						5.8						2.6						2.1						( 4.1 )						6.5						6.9
Plant basis differences			( 4.1 )						( 0.6 )						( 11.9 )						( 1.0 )						( 1.7 )						( 2.7 )						( 0.7 )						( 0.7 )
Excess deferred tax amortization			( 11.8 )						( 5.6 )						( 3.0 )						( 19.8 )						( 19.5 )						( 16.8 )						( 18.4 )						( 24.5 )
Amortization of investment tax credit, including deferred taxes on basis differences			( 0.1 )						( 0.1 )						—						( 0.1 )						( 0.1 )						—						( 0.2 )						( 0.2 )
Tax credits (f)			0.1						( 0.3 )						—						( 0.7 )						( 0.7 )						( 0.7 )						( 0.6 )						( 0.5 )
Other (g)			0.6						—						0.2						0.1						0.4						0.3						0.1						—
Effective income tax rate			14.5		%				22.4		%				12.1		%				2.1		%				1.5		%				( 3.0 )		%				7.7		%				2.0		%

			For the Year Ended December 31, 2021 (a)
			Exelon						ComEd						PECO (h)						BGE (h)						PHI						Pepco (h)						DPL (h)						ACE (h)
U.S. federal statutory rate			21.0		%				21.0		%				21.0		%				21.0		%				21.0		%				21.0		%				21.0		%				21.0		%
Increase (decrease) due to:
State income taxes, net of federal income tax benefit			5.0						7.8						( 1.4 )						( 10.8 )						10.1						2.7						25.0						7.4
Plant basis differences			( 5.4 )						( 0.8 )						( 13.6 )						( 1.7 )						( 1.1 )						( 1.6 )						( 0.8 )						( 0.2 )
Excess deferred tax amortization			( 17.2 )						( 7.6 )						( 3.8 )						( 16.3 )						( 22.4 )						( 16.4 )						( 20.0 )						( 37.1 )
Amortization of investment tax credit, including deferred taxes on basis differences			( 0.1 )						( 0.1 )						—						( 0.1 )						( 0.1 )						—						( 0.2 )						( 0.2 )
Tax credits			( 0.7 )						( 0.5 )						—						( 0.9 )						( 0.5 )						( 0.5 )						( 0.4 )						( 0.5 )
Other			( 0.3 )						( 1.0 )						0.1						( 0.6 )						—						( 0.4 )						0.1						( 0.2 )
Effective income tax rate			2.3		%				18.8		%				2.3		%				( 9.4 )		%				7.0		%				4.8		%				24.7		%				( 9.8 )		%

__________

(a) Positive percentages represent income tax expense. Negative percentages represent income tax benefit.

(b) For PECO, the lower effective tax rate is primarily related to plant basis differences attributable to tax repair deductions.

(c) For Exelon, the lower state income taxes, net of federal income tax benefit, is primarily due to the long-term marginal state income tax rate change of $ 54 million.

(d) For PECO, the lower effective tax rate is primarily related to plant basis differences attributable to tax repair deductions partially offset by higher state income taxes, net of federal income tax benefit, related to a one-time expense of $ 38 million attributable to the change in the Pennsylvania corporate income tax rate. For BGE, PHI, Pepco, DPL, and ACE, the lower effective tax rate is primarily related to the acceleration of certain income tax benefits due to transmission and distribution rate case settlements.

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(e) For Exelon, the higher state income taxes, net of federal income tax benefit, is primarily due to the long-term marginal state income tax rate change of $ 67 million and the recognition of a valuation allowance of $ 40 million against the net deferred tax asset position for certain standalone state filing jurisdictions, partially offset by a one-time impact associated with a state tax benefit of $ 43 million and indemnification adjustments pursuant to the Tax Matters Agreement of $ 11 million as a result of the separation. For PECO, the higher state income taxes, net of federal income tax benefit, related to a one-time expense of $ 38 million attributable to the change in the Pennsylvania corporate income tax rate.

(f) For Exelon, reflects the income tax expense related to the write-off of federal tax credits subject to recapture of $ 15 million as a result of the separation.

(g) For Exelon, reflects the nondeductible transaction costs of approximately $ 12 million arising as part of the separation and indemnification adjustments pursuant to the Tax Matters Agreement of $ 9 million.

(h) For PECO, the lower effective tax rate is primarily related to plant basis differences attributable to tax repair deductions. For BGE, the income tax benefit is primarily due to the Maryland multi-year plan which resulted in the acceleration of certain income tax benefits. For Pepco, the lower effective tax rate is primarily related to the acceleration of certain income tax benefits due to transmission and distribution rate case settlements. For DPL, the higher effective tax rate is primarily related to a state income tax expense, net of federal income tax benefit, due to the recognition of a valuation allowance of approximately $ 31 million against a deferred tax asset associated with Delaware net operating loss carryforwards as a result of a change in Delaware tax law. For ACE, the income tax benefit is primarily due to a distribution rate case settlement which allows ACE to retain certain tax benefits.

Tax Differences and Carryforwards

The tax effects of temporary differences and carryforwards, which give rise to significant portions of the deferred tax assets (liabilities), at December 31, 2023 and 2022 are presented below:

			At December 31, 2023
			Exelon						ComEd						PECO						BGE						PHI						Pepco						DPL						ACE
Plant basis differences			$	( 12,631 )					$	( 4,993 )					$	( 2,264 )					$	( 2,064 )					$	( 3,262 )					$	( 1,454 )					$	( 947 )					$	( 850 )
Accrual based contracts			8						—						—						—						8						—						—						—
Derivatives and other financial instruments			46						37						—						—						2						—						—						—
Deferred pension and postretirement obligation			524						( 299 )						( 36 )						( 26 )						( 78 )						( 70 )						( 35 )						( 2 )
Deferred debt refinancing costs			115						( 5 )						—						( 2 )						104						( 3 )						( 2 )						( 1 )
Regulatory assets and liabilities			( 1,429 )						( 405 )						( 208 )						( 4 )						( 52 )						9						45						( 4 )
Tax loss carryforward, net of valuation allowances			295						—						47						77						72						—						18						52
Tax credit carryforward			281						—						—						—						—						—						—						—
Corporate Alternative Minimum Tax			264						118						82						55						—						—						2						11
Investment in partnerships			( 28 )						—						—						—						—						—						—						—
Other, net			619						227						58						21						186						88						16						25
Deferred income tax liabilities (net)			( 11,936 )						( 5,320 )						( 2,321 )						( 1,943 )						( 3,020 )						( 1,430 )						( 903 )						( 769 )
Unamortized investment tax credits			( 13 )						( 7 )						—						( 2 )						( 4 )						( 1 )						( 1 )						( 2 )
Total deferred income tax liabilities (net) and unamortized investment tax credits			$	( 11,949 )					$	( 5,327 )					$	( 2,321 )					$	( 1,945 )					$	( 3,024 )					$	( 1,431 )					$	( 904 )					$	( 771 )

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			At December 31, 2022
			Exelon						ComEd						PECO						BGE						PHI						Pepco						DPL						ACE
Plant basis differences			$	( 12,130 )					$	( 4,823 )					$	( 2,119 )					$	( 1,949 )					$	( 3,131 )					$	( 1,394 )					$	( 906 )					$	( 813 )
Accrual based contracts			10						—						—						—						10						—						—						—
Derivatives and other financial instruments			26						23						—						—						2						—						—						—
Deferred pension and postretirement obligation			551						( 300 )						( 31 )						( 31 )						( 80 )						( 76 )						( 39 )						( 3 )
Deferred debt refinancing costs			132						( 5 )						—						( 2 )						111						( 4 )						( 2 )						( 1 )
Regulatory assets and liabilities			( 1,107 )						( 131 )						( 169 )						57						( 50 )						7						43						11
Tax loss carryforward, net of valuation allowances			250						—						33						72						71						3						20						46
Tax credit carryforward			468						—						—						—						—						—						—						—
Investment in partnerships			( 21 )						—						—						—						—						—						—						—
Other, net			591						223						73						23						182						83						16						28
Deferred income tax liabilities (net)			( 11,230 )						( 5,013 )						( 2,213 )						( 1,830 )						( 2,885 )						( 1,381 )						( 868 )						( 732 )
Unamortized investment tax credits			( 14 )						( 8 )						—						( 2 )						( 4 )						( 1 )						( 1 )						( 2 )
Total deferred income tax liabilities (net) and unamortized investment tax credits			$	( 11,244 )					$	( 5,021 )					$	( 2,213 )					$	( 1,832 )					$	( 2,889 )					$	( 1,382 )					$	( 869 )					$	( 734 )

The following table provides Exelon’s, ComEd's, PECO’s, BGE’s, PHI’s, Pepco’s, DPL’s, and ACE’s carryforwards, of which the state related items are presented on a post-apportioned basis, as well as, any corresponding valuation allowances at December 31, 2023.

			Exelon						ComEd						PECO						BGE						PHI						Pepco						DPL						ACE
Federal
Federal net operating loss carryforward (a)			$	130					$	—					$	—					$	—					$	—					$	—					$	—					$	—
Deferred taxes on Federal net operating loss			27						—						—						—						—						—						—						—
Federal general business credits carryforwards (b)			281						—						—						—						—						—						—						—
Corporate Alternative Minimum Tax credit carryforward (c)			264						118						82						55						—						—						2						11
State
State net operating loss carryforwards			5,629						—						1,286						1,187						1,509						—						743						736
Deferred taxes on state tax attributes (net of federal taxes)			341						—						51						77						104						—						50						52
Valuation allowance on state tax attributes (net of federal taxes) (d)			73						—						4						—						32						—						32						—
Year in which net operating loss or credit carryforwards will begin to expire (e)			2035						N/A						2032						2033						2029						N/A						2035						2031

__________

(a) For Exelon, the federal net operating loss carryforward has an indefinite carryforward period.

(b) For Exelon, the federal general business credit carryforward will begin expiring in 2035.

(c) For Exelon, ComEd, PECO, BGE, DPL and ACE, the Corporate Alternative Minimum Tax credit carryforward has an indefinite carryforward period.

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(d) For Exelon, a full valuation allowance has been recorded against certain separate company state net operating loss carryforwards that are expected to expire before realization. For PECO, a valuation allowance has been recorded against certain Pennsylvania net operating losses that are expected to expire before realization. For DPL, a full valuation allowance has been recorded against Delaware net operating losses carryforwards due to a change in Delaware tax law that restricts the ability for corporate taxpayers to monetize net operating losses.

(e) A portion of Exelon's, BGE's, and DPL's Maryland state net operating loss carryforward have an indefinite carryforward period.

Tabular Reconciliation of Unrecognized Tax Benefits

The following table presents changes in unrecognized tax benefits, for Exelon, PHI, and ACE. ComEd's, PECO's, BGE's, Pepco's, and DPL's amounts are not material.

			Exelon (a)																								PHI																		ACE
Balance at January 1, 2021			$	125																							$	52																	$	15
Change to positions that only affect timing			13																								3																		1
Increases based on tax positions related to 2021			4																								1																		—
Increases based on tax positions prior to 2021			4																								—																		—
Decreases based on tax positions prior to 2021			( 3 )																								—																		—
Balance at December 31, 2021			$	143																							$	56																	$	16
Change to positions that only affect timing			( 1 )																								1																		1
Increases based on tax positions related to 2022			3																								2																		—
Increases based on tax positions prior to 2022			3																								—																		—
Decreases based on tax positions prior to 2022			—																								—																		—
Balance at December 31, 2022			$	148																							$	59																	$	17
Change to positions that only affect timing			( 57 )																								( 9 )																		( 2 )
Increases based on tax positions related to 2023			3																								1																		—
Increases based on tax positions prior to 2023			1																								—																		—
Decreases based on tax positions prior to 2023			( 1 )																								—																		—
Balance at December 31, 2023			$	94																							$	51																	$	15

______

(a) At December 31, 2023 and 2022, Exelon recorded a receivable of $ 31 million and $ 50 million, respectively, in noncurrent Other assets in the Consolidated Balance Sheet for Constellation’s share of unrecognized tax benefits for periods prior to the separation.

Recognition of Unrecognized Tax Benefits

The following table presents Exelon's unrecognized tax benefits that, if recognized, would decrease the effe ctive tax rate. The Utility Registrants' amounts are not material.

			Exelon
December 31, 2023			$	71
December 31, 2022			90
December 31, 2021			77

Unrecognized tax benefits for which significant increases or decreases are possible within 12 months after the reporting date

At December 31, 2023, ACE has approximately $ 14 million of unrecognized state tax benefits that could significantly decrease within the 12 months after the reporting date based on the outcome of pending court cases involving other taxpayers. The unrecognized tax benefit, if recognized, may be included in future base rates and that portion would have no impact to the effective tax rate.

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Total Amounts of Interest and Penalties Recognized

The following table represents the net interest and penalties receivable (payable) related to tax positions reflected in Exelon's Consolidated Balance Sheets. The Utility Registrants' amounts are not material.

Net interest and penalties receivable at			Exelon
December 31, 2023 (a)			$	62
December 31, 2022 (b)			45

__________

(a) At December 31, 2023, Exelon classified $ 21 million and $ 41 million of the interest receivable as current and noncurrent, respectively, based on the expected timing for settlement in cash. At December 31, 2023, Exelon recorded a receivable of $ 5 million in noncurrent Other assets in the Consolidated Balance Sheet for Constellation's share of net interest for periods prior to the separation.

(b) At December 31, 2022, the interest receivable balance is not expected to be settled in cash within the next twelve months and is therefore classified as a noncurrent receivable. At December 31, 2022, Exelon recorded a receivable of $ 1 million in noncurrent Other assets in the Consolidated Balance Sheet for Constellation's share of net interest for periods prior to the separation.

The Registrants did not record material interest and penalty expense related to tax positions reflected in their Consolidated Balance Sheets. Interest expense and penalty expense are recorded in Interest expense, net and Other, net, respect ively, in Other income and deductions in the Registrants Consolidated Statements of Operations and Comprehensive Income.

Description of Tax Years Open to Assessment by Major Jurisdiction

Major Jurisdiction			Open Years						Registrants Impacted
Federal consolidated income tax returns (a)			2010-2022						All Registrants
Delaware separate corporate income tax returns			Same as federal						DPL
District of Columbia combined corporate income tax returns			2020-2022						Exelon, PHI, Pepco
Illinois unitary corporate income tax returns			2012-2022						Exelon, ComEd
Maryland separate company corporate net income tax returns			Same as federal						BGE, Pepco, DPL
New Jersey separate corporate income tax returns			2017-2018						Exelon
New Jersey combined corporate income tax returns			2019-2022						Exelon
New Jersey separate corporate income tax returns			2019-2022						ACE
New York combined corporate income tax returns			2015-2022						Exelon
Pennsylvania separate corporate income tax returns			2020-2022						Exelon
Pennsylvania separate corporate income tax returns			2020-2022						PECO

__________

(a) Certain registrants are only open to assessment for tax years since joining the Exelon federal consolidated group; BGE beginning in 2012 and PHI, Pepco, DPL, and ACE beginning in 2016.

Other Tax Matters

Separation (Exelon)

In the first quarter of 2022, in connection with the separation, Exelon recorded an income tax expense related to continuing operations of $ 148 million primarily due to the long-term marginal state income tax rate change of $ 54 million discussed further below, the recognition of valuation allowances of approximately $ 40 million against the net deferred tax assets positions for certain standalone state filing jurisdictions, the write-off of federal and state tax credits subject to recapture of $ 17 million, and nondeductible transaction costs for federal and state taxes of $ 24 million.

Tax Matters Agreement (Exelon)

In connection with the separation, Exelon entered into a TMA with Constellation. The TMA governs the respective rights, responsibilities, and obligations between Exelon and Constellation after the separation with respect to tax liabilities, refunds and attributes for open tax years that Constellation was part of Exelon’s consolidated group for U.S. federal, state, and local tax purposes.

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Indemnification for Taxes. As a former subsidiary of Exelon, Constellation has joint and several liability with Exelon to the IRS and certain state jurisdictions relating to the taxable periods prior to the separation. The TMA specifies that Constellation is liable for their share of taxes required to be paid by Exelon with respect to taxable periods prior to the separation to the extent Constellation would have been responsible for such taxes under the existing Exelon tax sharing agreement. In 2023, Exelon remitted $ 9 million of payments to Constellation. At December 31, 2023, Exelon recorded a payable of $ 11 million in Other current liabilities that is due to Constellation.

Tax Refunds. The TMA specifies that Constellation is entitled to their share of any future tax refunds claimed by Exelon with respect to taxable periods prior to the separation to the extent that Constellation would have received such tax refunds under the existing Exelon tax sharing agreement.

Tax Attributes . At the date of separation certain tax attributes, primarily pre-closing tax credit carryforwards, that were generated by Constellation were required by law to be allocated to Exelon. The TMA also provides that Exelon will reimburse Constellation when those allocated tax attribute carryforwards are utilized. In 2023, Exelon remitted $ 21 million of payments to Constellation for the utilization of pre-closing tax credit carryforwards. At December 31, 2023, Exelon recorded a payable of $ 182 million and $ 331 million in Other current liabilities and Other deferred credits and other liabilities, respectively, in the Consolidated Balance Sheet for tax attribute carryforwards that are expected to be utilized and reimbursed to Constellation.

Corporate Alternative Minimum Tax (All Registrants)

On August 16, 2022, the IRA was signed into law and implemented a new corporate alternative minimum tax (CAMT) that imposes a 15.0 % tax on modified GAAP net income. Corporations are entitled to a tax credit (minimum tax credit) to the extent the CAMT liability exceeds the regular tax liability. This amount can be carried forward indefinitely and used in future years when regular tax exceeds the CAMT.

Based on the existing statue, Exelon and each of the Utility Registrants will be subject to and will report the CAMT on a separate Registrant basis in the Consolidated Statements of Operations and Comprehensive Income and the Consolidated Balance Sheets. The deferred tax asset related to the minimum tax credit carryforward will be realized to the extent Exelon’s consolidated deferred tax liabilities exceed the minimum tax credit carryforward. Exelon’s deferred tax liabilities are expected to exceed the minimum tax credit carryforward for the foreseeable future and thus no valuation allowance is required. Exelon is continuing to assess the financial statement impacts of the IRA and will update estimates based on future guidance issued by the U.S. Treasury.

Long-Term Marginal State Income Tax Rate (All Registrants)

Quarterly, Exelon reviews and updates its marginal state income tax rates for material changes in state tax laws and state apportionment. The Registrants remeasure their existing deferred income tax balances to reflect the changes in marginal rates, which results in either an increase or a decrease to their net deferred income tax liability balances. Utility Registrants record corresponding regulatory liabilities or assets to the extent such amounts are probable of settlement or recovery through customer rates and an adjustment to income tax expense for all other amounts. In the third quarter of 2023, Exelon updated its marginal state income tax rates for changes in state apportionment. The changes in marginal rates in the third quarter resulted in a decrease of $ 54 million to the deferred tax liability at Exelon, and a corresponding adjustment to income tax expense, net of federal taxes. There were no impacts to ComEd, BGE, PHI, Pepco, DPL, and ACE for the years ended December 31, 2023, 2022, and 2021.

December 31, 2023

Exelon

Decrease to Deferred Income Tax Liability and Income Tax Expense, Net of Federal Taxes

$

( 54 )

December 31, 2022

Increase to Deferred Income Tax Liability and Income Tax Expense, Net of Federal Taxes

67

December 31, 2021

Increase to Deferred Income Tax Liability and Income Tax Expense, Net of Federal Taxes

27

Pennsylvania Corporate Income Tax Rate Change (Exelon and PECO)

On July 8, 2022, Pennsylvania enacted House Bill 1342, which will permanently reduce the corporate income tax rate from 9.99 % to 4.99 %. The tax rate will be reduced to 8.99 % for the 2023 tax year. Starting with the 2024 tax year, the rate is reduced by 0.50 % annually until it reaches 4.99 % in 2031. As a result of the rate change, in the

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third quarter of 2022, Exelon and PECO recorded a one-time decrease to deferred income taxes of $ 390 million with a corresponding decrease to the deferred income taxes regulatory asset of $ 428 million for the amounts that are expected to be settled through future customer rates and an increase to income tax expense of $ 38 million (net of federal taxes). The tax rate decrease is not expected to have a material ongoing impact to Exelon’s and PECO’s financial statements. There were no changes to PECO's marginal state income tax rates for the years ended December 31, 2022, and 2021.

Allocation of Tax Benefits (All Registrants)

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

The following table presents the allocation of tax benefits from Exelon under the Tax Sharing Agreement, for the year ended December 31, 2023, 2022, and 2021.

			ComEd						PECO						BGE									PHI						Pepco						DPL						ACE
December 31, 2023 (a)			$	13					$	19					$	—								$	10					$	4					$	—					$	2
December 31, 2022 (b)			1						47						—									28						23						3						2
December 31, 2021 (c)			1						19						—									17						16						—						—

__________

(a) BGE and DPL did not record an allocation of federal tax benefits from Exelon under the Tax Sharing Agreement as a result of a tax net operating loss.

(b) BGE did not record an allocation of federal tax benefits from Exelon under the Tax Sharing Agreement as a result of a tax net operating loss.

(c) BGE, DPL, and ACE did not record an allocation of federal tax benefits from Exelon under the Tax Sharing Agreement as a result of a tax net operating loss.

Exelon sponsors defined benefit pension and OPEB plans. Substantially all non-union employees and electing union employees hired on or after January 1, 2001 participate in cash balance pension plans. Effective January 1, 2009, substantially all newly-hired union-represented employees participate in cash balance pension plans. Effective February 1, 2018 for most newly-hired BSC non-represented, non-craft, employees, January 1, 2021 for most newly-hired utility management employees, and for certain newly-hired union employees pursuant to their collective bargaining agreements, these newly-hired employees are not eligible for pension benefits, and will instead be eligible to receive an enhanced non-discretionary employer contribution in an Exelon defined contribution savings plan. Effective January 1, 2018, most newly-hired non-represented, non-craft, employees are not eligible for OPEB benefits and employees represented by Local 614 are not eligible for retiree health care benefits. Effective January 1, 2021, most non-represented, non-craft, employees who are under the age of 40 are not eligible for retiree health care benefits. Effective January 1, 2022, management employees retiring on or after that date are no longer eligible for retiree life insurance benefits.

Effective February 1, 2022, in connection with the separation, pension and OPEB obligations and assets for current and former employees of the Constellation business and certain other former employees of Exelon and its subsidiaries transferred to pension and OPEB plans and trusts maintained by Constellation or its subsidiaries. The Exelon New England Union Employees Pension Plan and Constellation Mystic Power, LLC Union Employees Pension Plan Including Plan A and Plan B were transferred. The following OPEB plans were also transferred: Constellation Mystic Power, LLC Post-Employment Medical Savings Account Plan; Exelon New England Union Post-Employment Medical Savings Account Plan; and the Nine Mile Point Nuclear Station, LLC Medical Care and Prescription Drug Plan for Retired Employees.

As a result of the separation, Exelon restructured certain of its qualified pension plans. Pension obligations and assets for current and former employees continuing with Exelon and who were participants in the Exelon Employee Pension Plan for Clinton, TMI, and Oyster Creek, Pension Plan of Constellation Energy Nuclear Group, LLC, and Nine Mile Point Pension Plan were merged into the Pension Plan of Constellation Energy

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Group, Inc, which was subsequently renamed, Exelon Pension Plan (EPP). Exelon employees who participated in these plans prior to the separation now participate in the EPP. The merging of the plans did not change the benefits offered to the plan participants and, thus, had no impact on Exelon's pension obligations.

The tables below show the pension and OPEB plans in which current and former employees of each operating company participated as of December 31, 2023:

Operating Company (a)

Name of Plan:

ComEd

PECO

BGE

PHI

Pepco

DPL

ACE

Qualified Pension Plans:

Exelon Corporation Retirement Program (ECRP)

X

X

X

X

X

X

X

Exelon Corporation Pension Plan for Bargaining Unit Employees (PPBU)

X

Exelon Pension Plan (EPP)

X

X

X

X

X

X

X

Pepco Holdings LLC Retirement Plan (PHI Qualified)

X

X

X

X

X

X

X

Non-Qualified Pension Plans:

Exelon Corporation Supplemental Pension Benefit Plan and 2000 Excess Benefit Plan (SPBP)

X

X

X

Exelon Corporation Supplemental Management Retirement Plan (SMRP)

X

X

X

X

Constellation Energy Group, Inc. Senior Executive Supplemental Plan

X

X

Constellation Energy Group, Inc. Supplemental Pension Plan

X

X

Constellation Energy Group, Inc. Benefits Restoration Plan

X

X

X

Baltimore Gas & Electric Company Executive Benefit Plan

X

Baltimore Gas & Electric Company Manager Benefit Plan

X

X

Pepco Holdings LLC 2011 Supplemental Executive Retirement Plan

X

X

X

X

Conectiv Supplemental Executive Retirement Plan

X

X

X

Pepco Holdings LLC Combined Executive Retirement Plan

X

X

Operating Company (a)

Name of Plan:

ComEd

PECO

BGE

PHI

Pepco

DPL

ACE

OPEB Plans:

PECO Energy Company Retiree Medical Plan (East)

X

X

X

X

X

X

X

Exelon Corporation Health Care Program (West)

X

X

X

X

X

X

X

Pepco Holdings LLC Welfare Plan for Retirees (PHI PRW)

X

X

X

X

X

X

X

Exelon Corporation Employees’ Life Insurance Plan

X

X

X

Exelon Corporation Health Reimbursement Arrangement Plan

X

X

X

BGE Retiree Medical Plan

X

X

X

X

X

X

BGE Retiree Dental Plan

X

Exelon Retiree Medical Plan of Constellation Energy Nuclear Group, LLC

X

X

X

Exelon Retiree Dental Plan of Constellation Energy Nuclear Group, LLC

X

X

X

__________

(a) Employees generally remain in their legacy benefit plans when transferring between operating companies.

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Exelon’s traditional and cash balance pension plans are intended to be tax-qualified defined benefit plans. Exelon has elected that the trusts underlying these plans be treated as qualified trusts under the IRC. If certain conditions are met, Exelon can deduct payments made to the qualified trusts, subject to certain IRC limitations.

Benefit Obligations, Plan Assets, and Funded Status

As of February 1, 2022, in connection with the separation, Exelon's pension and OPEB plans were remeasured. The remeasurement and separation resulted in a decrease to the Pension obligation, net of plan assets, of $ 921 million and a decrease to the OPEB obligation of $ 893 million. Additionally, AOCI decreased by $ 1,994 million (after-tax) and Regulatory assets and liabilities increased by $ 14 million and $ 5 million, respectively. Key assumptions were held consistent with the year end December 31, 2021 assumptions with the exception of the discount rate.

During the first quarter of 2023, Exelon received an updated valuation of its pension and OPEB to reflect actual census data as of January 1, 2023. This valuation resulted in an increase to the pension obligation of $ 27 million and an increase to the OPEB obligations of $ 2 million. Additionally, AOCI increased by $ 10 million (after-tax) and Regulatory assets and liabilities increased by $ 18 million and $ 1 million, respectively.

The following tables provide a rollforward of the changes in the benefit obligations and plan assets of Exelon for the most recent two years for all plans combined:

			Pension Benefits												OPEB
			2023						2022						2023						2022
Change in benefit obligation:
Net benefit obligation as of the beginning of year			$	10,677					$	14,236					$	1,884					$	2,502
Service cost			155						236						26						41
Interest cost			578						439						101						76
Plan participants’ contributions			—						—						27						26
Actuarial loss (gain) (a)			406						( 3,379 )						55						( 604 )
Plan amendments			4						—						—						—
Settlements			( 42 )						—						—						—
Gross benefits paid			( 790 )						( 855 )						( 185 )						( 157 )
Net benefit obligation as of the end of year			$	10,988					$	10,677					$	1,908					$	1,884

			Pension Benefits												OPEB
			2023						2022						2023						2022
Change in plan assets:
Fair value of net plan assets as of the beginning of year			$	9,521					$	12,165					$	1,351					$	1,665
Actual return on plan assets			638						( 2,359 )						108						( 225 )
Employer contributions			75						570						54						42
Plan participants’ contributions			—						—						27						26
Gross benefits paid			( 790 )						( 855 )						( 185 )						( 157 )
Settlements			( 42 )						—						—						—
Fair value of net plan assets as of the end of year			$	9,402					$	9,521					$	1,355					$	1,351

__________

(a) The pension and OPEB losses in 2023 primarily reflect a decrease in the discount rate. The pension and OPEB gains in 2022 primarily reflect an increase in the discount rate.

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Exelon presents its benefit obligations and plan assets net on its Consolidated Balance Sheets within the following line items:

			Pension Benefits												OPEB
			2023						2022						2023						2022
Other current liabilities			$	15					$	47					$	26					$	26
Pension obligations			1,571						1,109						—						—
Non-pension postretirement benefit obligations			—						—						527						507
Unfunded status (net benefit obligation less plan assets)			$	1,586					$	1,156					$	553					$	533

The following table provides the ABO and fair value of plan assets for all pension plans with an ABO in excess of plan assets. Information for pension and OPEB plans with projected benefit obligations (PBO) and accumulated postretirement benefit obligation (APBO), respectively, in excess of plan assets has been disclosed in the Obligations and Plan Assets table above as all pension and OPEB plans are underfunded.

			Exelon
			2023						2022
ABO			$	10,376					$	10,108
Fair value of net plan assets			9,279						9,427

Components of Net Periodic Benefit Costs

The majority of the 2023 pension benefit cost for the Exelon-sponsored plans is calculated using an expected long-term rate of return on plan assets of 7.00 % and a discount rate of 5.53 %. The majority of the 2023 OPEB cost is calculated using an expected long-term rate of return on plan assets of 6.50 % for funded plans and a discount rate of 5.51 %.

A portion of the net periodic benefit cost for all plans is capitalized in the Consolidated Balance Sheets. The following table presents the components of Exelon’s net periodic benefit costs, prior to capitalization, for the years ended December 31, 2023, 2022, and 2021.

			Pension Benefits																		OPEB
			2023						2022						2021						2023						2022						2021
Components of net periodic benefit cost:
Service cost			$	155					$	236					$	294					$	26					$	41					$	51
Interest cost			578						439						406						101						76						69
Expected return on assets			( 755 )						( 822 )						( 843 )						( 83 )						( 99 )						( 99 )
Amortization of:
Prior service cost (credit)			2						2						2						( 10 )						( 19 )						( 25 )
Actuarial loss (gain)			166						295						399						( 2 )						12						27
Settlement and other charges			20						—						7						—						—						1
Net periodic benefit cost			$	166					$	150					$	265					$	32					$	11					$	24

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Cost Allocation to Exelon Subsidiaries

All Registrants account for their participation in Exelon’s pension and OPEB plans by applying multi-employer accounting. Exelon allocates costs related to its pension and OPEB plans to its subsidiaries based on both active and retired employee participation in each plan.

The amounts below represent the Registrants' allocated pension and OPEB costs (benefit). For Exelon, the service cost component is included in Operating and maintenance expense and Property, plant, and equipment, net while the non-service cost components are included in Other, net and Regulatory assets. For the Utility Registrants, the service cost and non-service cost components are included in Operating and maintenance expense and Property, plant, and equipment, net in their consolidated financial statements.

For the Years Ended December 31,			Exelon						ComEd						PECO						BGE						PHI						Pepco						DPL						ACE
2023			$	198					$	26					$	( 14 )					$	56					$	99					$	34					$	18					$	13
2022			161						60						( 9 )						44						53						9						3						12
2021			288						129						8						64						49						6						2						11

Components of AOCI and Regulatory Assets

Exelon recognizes the overfunded or underfunded status of defined benefit pension and OPEB plans as an asset or liability on its Consolidated Balance Sheets, with offsetting entries to AOCI and Regulatory assets (liabilities). A portion of current year actuarial (gains) losses and prior service costs (credits) is capitalized in Exelon’s Consolidated Balance Sheets to reflect the expected regulatory recovery of these amounts, which would otherwise be recorded to AOCI. The following tables provide the components of AOCI and Regulatory assets (liabilities) for Exelon for the years ended December 31, 2023, 2022, and 2021 for all plans combined. The tables include amounts related to Generation prior to the separation.

			Pension Benefits																		OPEB
			2023						2022						2021						2023						2022						2021
Changes in plan assets and benefit obligations recognized in AOCI and Regulatory assets (liabilities):
Current year actuarial loss (gain)			$	523					$	( 226 )					$	( 700 )					$	30					$	( 271 )					$	( 270 )
Amortization of actuarial (loss) gain			( 166 )						( 295 )						( 598 )						2						( 12 )						( 37 )
Separation of Constellation			—						( 2,631 )						—						—						( 43 )						—
Current year prior service cost			4						—						—						—						—						—
Amortization of prior service (cost) credit			( 2 )						( 2 )						( 3 )						10						19						34
Settlements			( 20 )						—						( 27 )						—						—						( 1 )
Total recognized in AOCI and Regulatory assets (liabilities)			$	339					$	( 3,154 )					$	( 1,328 )					$	42					$	( 307 )					$	( 274 )
Total recognized in AOCI			$	99					$	( 2,719 )					$	( 747 )					$	4					$	( 74 )					$	( 130 )
Total recognized in Regulatory assets (liabilities)			$	240					$	( 435 )					$	( 581 )					$	38					$	( 233 )					$	( 144 )

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The following table provides the components of gross AOCI and Regulatory assets (liabilities) for Exelon that have not been recognized as components of periodic benefit cost as of December 31, 2023 and 2022, respectively, for all plans combined:

			Pension Benefits												OPEB
			2023						2022						2023						2022
Prior service cost (credit)			$	21					$	19					$	( 45 )					$	( 55 )
Actuarial loss (gain)			3,948						3,611						( 101 )						( 133 )
Total			$	3,969					$	3,630					$	( 146 )					$	( 188 )
Total included in AOCI			$	972					$	873					$	( 17 )					$	( 21 )
Total included in Regulatory assets (liabilities)			$	2,997					$	2,757					$	( 129 )					$	( 167 )

Average Remaining Service Period

For pension benefits, Exelon amortizes its unrecognized prior service costs (credits) and certain actuarial (gains) losses, as applicable, based on participants’ average remaining service periods.

For OPEB, Exelon amortizes its unrecognized prior service costs (credits) over participants’ average remaining service period to benefit eligibility age and amortizes certain actuarial (gains) losses over participants’ average remaining service period to expected retirement. The resulting average remaining service periods for pension and OPEB were as follows:

						2023						2022						2021
Pension plans						12.6						12.5						12.4
OPEB plans:
Benefit Eligibility Age						8.1						7.9						7.6
Expected Retirement						9.3						9.1						8.8

Assumptions

The measurement of the plan obligations and costs of providing benefits under Exelon’s defined benefit and OPEB plans involves various factors, including the development of valuation assumptions and inputs and accounting policy elections. The measurement of benefit obligations and costs is impacted by several assumptions and inputs, as shown below, among other factors. When developing the required assumptions, Exelon considers historical information as well as future expectations.

Expected Rate of Return. In determining the EROA, Exelon considers historical economic indicators (including inflation and GDP growth) that impact asset returns, as well as expectations regarding future long-term capital market performance, weighted by Exelon’s target asset class allocations.

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. For the years ended December 31, 2023 and 2022, 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.

For Exelon, the following assumptions were used to determine the benefit obligations for the plans as of December 31, 2023 and 2022. Assumptions used to determine year-end benefit obligations are the assumptions used to estimate the subsequent year’s net periodic benefit costs.

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			Pension Benefits												OPEB
			2023						2022						2023						2022
Discount rate (a)			5.19		%				5.53		%				5.17		%				5.51		%
Investment crediting rate (b)			5.03		%				5.07		%				N/A						N/A
Rate of compensation increase			3.75		%				3.75		%				3.75		%				3.75		%
Mortality table			Pri-2012 table with MP- 2021 improvement scale (adjusted)						Pri-2012 table with MP- 2021 improvement scale (adjusted)						Pri-2012 table with MP- 2021 improvement scale (adjusted)						Pri-2012 table with MP- 2021 improvement scale (adjusted)
Health care cost trend on covered charges			N/A						N/A						Initial and ultimate trend rate of 5.00 %						Initial and ultimate trend rate of 5.00 %

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(a) The discount rates above represent the blended rates used to determine the majority of Exelon’s pension and OPEB obligations. Certain benefit plans used individual rates, which range from 5.11 % - 5.27 % and 5.15 % - 5.17 % for pension and OPEB plans, respectively, as of December 31, 2023 and 5.46 % - 5.60 % and 5.49 % - 5.51 % for pension and OPEB plans, respectively, as of December 31, 2022.

(b) The investment crediting rate above represents a weighted average rate.

The following assumptions were used to determine the net periodic benefit cost for Exelon for the years ended December 31, 2023, 2022 and 2021:

			Pension Benefits																		OPEB
			2023						2022						2021						2023						2022						2021
Discount rate (a)			5.53		%				3.24		%				2.58		%				5.51		%				3.20		%				2.51		%
Investment crediting rate (b)			5.07		%				3.75		%				3.72		%				N/A						N/A						N/A
Expected return on plan assets (c)			7.00		%				7.00		%				7.00		%				6.50		%				6.44		%				6.46		%
Rate of compensation increase			3.75		%				3.75		%				3.75		%				3.75		%				3.75		%				3.75		%
Mortality table			Pri-2012 table with MP- 2021 improvement scale (adjusted)						Pri-2012 table with MP- 2021 improvement scale (adjusted)						Pri-2012 table with MP - 2020 improvement scale (adjusted)						Pri-2012 table with MP- 2021 improvement scale (adjusted)						Pri-2012 table with MP- 2021 improvement scale (adjusted)						Pri-2012 table with MP - 2020 improvement scale (adjusted)
Health care cost trend on covered charges			N/A						N/A						N/A						Initial and ultimate rate of 5.00 %						Initial and ultimate rate of 5.00 %						Initial and ultimate rate of 5.00 %

__________

(a) The discount rates above represent the blended rates used to establish the majority of Exelon’s pension and OPEB costs. Certain benefit plans used individual rates, which range from 5.46 %- 5.60 % and 5.49 %- 5.51 % for pension and OPEB plans, respectively, for the year ended December 31, 2023; 2.55 %- 3.24 % and 2.84 %- 3.20 % for pension and OPEB plans; respectively, for the year ended December 31, 2022; and 2.11 %- 2.73 % and 2.45 %- 2.63 % for pension and OPEB plans, respectively, for the year ended December 31, 2021.

(b) The investment crediting rate above represents a weighted average rate.

(c) Not applicable to pension and OPEB plans that do not have plan assets.

Contributions

Exelon allocates contributions related to its ECRP and PPBU pension plans and East and West OPEB plans to its subsidiaries based on accounting cost. For the EPP pension plan, PHI Qualified, and PHI PRW plans, pension and OPEB contributions are allocated to the subsidiaries based on employee participation (both active and retired). For Exelon, in connection with the separation, additional qualified pension contributions of $ 207 million and $ 33 million were completed on February 1, 2022 and March 2, 2022, respectively. The following table provides contributions to the pension and OPEB plans:

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			Pension Benefits																		OPEB
			2023						2022						2021						2023						2022						2021
Exelon			$	75					$	570					$	343					$	54					$	42					$	63
ComEd			24						176						174						17						8						22
PECO			1						15						17						—						3						1
BGE			—						48						57						19						20						24
PHI			8						69						39						16						9						9
Pepco			1						3						2						11						8						9
DPL			2						1						1						2						—						—
ACE			—						7						3						3						—						—

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. Based on this funding strategy and current market conditions, which are subject to change, Exelon’s estimated annual qualified pension contributions will be approximately $ 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.

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:

			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			—						1						10
DPL			—						—						—
ACE			7						—						—

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Estimated Future Benefit Payments

Estimated future benefit payments to participants in all of the pension plans and postretirement benefit plans as of December 31, 2023 were:

			Pension Benefits						OPEB
2024			$	782					$	152
2025			783						151
2026			795						152
2027			800						151
2028			792						151
2029 through 2033			3,977						730
Total estimated future benefits payments through 2033			$	7,929					$	1,487

Plan Assets

Investment Strategy. On a regular basis, Exelon evaluates its investment strategy to ensure plan assets will be sufficient to pay plan benefits when due. As part of this ongoing evaluation, Exelon may make changes to its targeted asset allocation and investment strategy.

Exelon has developed and implemented a liability hedging investment strategy for its qualified pension plans that has reduced the volatility of its pension assets relative to its pension liabilities. Exelon is likely to continue to gradually increase the liability hedging portfolio as the funded status of its plans improves. The overall objective is to achieve attractive risk-adjusted returns that will balance the liquidity requirements of the plans’ liabilities while striving to minimize the risk of significant losses. Trust assets for Exelon’s OPEB plans are managed in a diversified investment strategy that prioritizes maximizing liquidity and returns while minimizing asset volatility.

Actual asset returns have an impact on the costs reported for the Exelon-sponsored pension and OPEB plans. The actual asset returns across Exelon’s pension and OPEB plans for the year ended December 31, 2023 were 7.73 % and 9.20 %, respectively, compared to an expected long-term return assumption of 7.00 % and 6.50 %, respectively. Exelon used an EROA of 7.00 % and 6.50 % to estimate its 2024 pension and OPEB costs, respectively.

Exelon’s pension and OPEB plan target asset allocations as of December 31, 2023 and 2022 were as follows:

			December 31, 2023												December 31, 2022
Asset Category			Pension Benefits						OPEB						Pension Benefits						OPEB
Equity securities			28		%				44		%				28		%				44		%
Fixed income securities			44		%				41		%				44		%				41		%
Alternative investments (a)			28		%				15		%				28		%				15		%
Total			100		%				100		%				100		%				100		%

__________

(a) Alternative investments include private equity, hedge funds, real estate, and private credit.

Concentrations of Credit Risk. Exelon evaluated its pension and OPEB plans’ asset portfolios for the existence of significant concentrations of credit risk as of December 31, 2023. Types of concentrations that were evaluated include, but are not limited to, investment concentrations in a single entity, type of industry, foreign country, and individual fund. As of December 31, 2023, there were no significant concentrations (defined as greater than 10% of plan assets) of risk in Exelon’s pension and OPEB plan assets.

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Fair Value Measurements

The following tables present pension and OPEB plan assets measured and recorded at fair value in Exelon's Consolidated Balance Sheets on a recurring basis and their level within the fair value hierarchy as of December 31, 2023 and 2022:

			December 31, 2023																														December 31, 2022
			Level 1						Level 2						Level 3						Not Subject to Leveling						Total						Level 1						Level 2						Level 3						Not Subject to Leveling						Total
Pension plan assets (a)
Cash and cash equivalents			$	267					$	—					$	—					$	—					$	267					$	200					$	—					$	—					$	—					$	200
Equities (b)			1,513						—						1						694						2,208						1,448						—						—						782						2,230
Fixed income:
U.S. Treasury and agencies			1,291						184						—						—						1,475						986						178						—						—						1,164
State and municipal debt			—						42						—						—						42						—						44						—						—						44
Corporate debt			—						1,792						9						—						1,801						—						1,975						12						—						1,987
Other (b)			—						79						—						788						867						—						63						—						744						807
Fixed income subtotal			1,291						2,097						9						788						4,185						986						2,260						12						744						4,002
Private equity			—						—						—						1,166						1,166						—						—						—						1,169						1,169
Hedge funds			—						—						—						578						578						—						—						—						760						760
Real estate			—						—						—						760						760						—						—						—						821						821
Private credit			—						—						—						626						626						—						—						—						658						658
Pension plan assets subtotal			$	3,071					$	2,097					$	10					$	4,612					$	9,790					$	2,634					$	2,260					$	12					$	4,934					$	9,840
OPEB plan assets (a)
Cash and cash equivalents			$	45					$	—					$	—					$	—					$	45					$	39					$	—					$	—					$	—					$	39
Equities			315						1						—						270						586						305						1						—						273						579
Fixed income:
U.S. Treasury and agencies			15						54						—						—						69						17						45						—						—						62
State and municipal debt			—						7						—						—						7						—						8						—						—						8
Corporate debt			—						44						—						—						44						—						44						—						—						44
Other			175						4						—						206						385						161						5						—						187						353
Fixed income subtotal			190						109						—						206						505						178						102						—						187						467
Hedge funds			—						—						—						109						109						—						—						—						120						120
Real estate			—						—						—						88						88						—						—						—						106						106
Private credit			—						—						—						22						22						—						—						—						39						39
OPEB plan assets subtotal			$	550					$	110					$	—					$	695					$	1,355					$	522					$	103					$	—					$	725					$	1,350
Total pension and OPEB plan assets (c)			$	3,621					$	2,207					$	10					$	5,307					$	11,145					$	3,156					$	2,363					$	12					$	5,659					$	11,190

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(a) See Note 17—Fair Value of Financial Assets and Liabilities for a description of levels within the fair value hierarchy.

(b) Includes derivative instruments of $ 51 million and $ 11 million for the years ended December 31, 2023 and 2022, respectively, which have total notional amounts of $ 3,351 million and $ 3,434 million as of December 31, 2023 and 2022, respectively. The notional principal amounts for these instruments provide one measure of the transaction volume outstanding as of the fiscal years ended and do not represent the amount of Exelon's exposure to credit or market loss.

(c) Excludes net liabilities of $ 388 million and $ 318 million as of December 31, 2023 and 2022, respectively, which include certain derivative assets that have notional amounts of $ 59 million and $ 69 million as of December 31, 2023 and 2022, respectively. These items are required to reconcile to the fair value of net plan assets and consist primarily of receivables or payables related to pending securities sales and purchases, interest and dividends receivable, and repurchase agreement obligations. The repurchase agreements generally have maturities ranging from 3 - 6 months.

The following table presents the reconciliation of Level 3 assets and liabilities for Exelon measured at fair value for pension and OPEB plans for the years ended December 31, 2023 and 2022:

																					Fixed Income						Equities						Private Credit						Total
Pension Assets
Balance as of January 1, 2023																					$	12					$	—					$	—					$	12
Actual return on plan assets:
Relating to assets still held as of the reporting date																					—						—						—						—
Relating to assets sold during the period																					—						—						—						—
Purchases, sales and settlements:
Purchases																					—						—						—						—
Settlements (a)																					—						—						—						—
Level 3 transfers (out) in																					( 3 )						1						—						( 2 )
Balance as of December 31, 2023																					$	9					$	1					$	—					$	10

																					Fixed Income						Equities						Private Credit						Total
Pension Assets
Balance as of January 1, 2022																					$	337					$	2					$	130					$	469
Actual return on plan assets:
Relating to assets still held as of the reporting date																					( 9 )						—						( 15 )						( 24 )
Relating to assets sold during the period																					( 19 )						—						13						( 6 )
Purchases, sales and settlements:
Purchases																					—						—						7						7
Settlements (a)																					( 1 )						—						( 52 )						( 53 )
Level 3 transfers out (b)																					( 296 )						( 2 )						( 83 )						( 381 )
Balance as of December 31, 2022																					$	12					$	—					$	—					$	12

__________

(a) Represents cash settlements only.

(b) In 2022, transfers relate to changes in investment structure for certain investments due to the separation.

Valuation Techniques Used to Determine Fair Value

The techniques used to fair value the pension and OPEB assets invested in cash equivalents are the same as the valuation techniques used to determine the fair value of financial assets. See Cash Equivalents in Note 17 - Fair Value of Financial Assets and Liabilities for further information. Below outlines the techniques used to fair value the pension and OPEB assets invested in equities, fixed income, derivatives, private credit, private equity, and real estate investments.

Equities. These investments consist of individually held equity securities, equity mutual funds, and equity commingled funds in domestic and foreign markets. With respect to individually held equity securities, the trustees obtain prices from pricing services, whose prices are generally obtained from direct feeds from market

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exchanges, which Exelon is able to independently corroborate. Equity securities held individually, including real estate investment trusts, rights, and warrants, are primarily traded on exchanges that contain only actively traded securities due to the volume trading requirements imposed by these exchanges. The equity securities that are held directly by the trust funds are valued based on quoted prices in active markets and categorized as Level 1. Certain equity securities have been categorized as Level 2 because they are based on evaluated prices that reflect observable market information, such as actual trade information or similar securities. Certain private placement equity securities are categorized as Level 3 because they are not publicly traded and are priced using significant unobservable inputs.

Equity commingled funds and mutual funds are maintained by investment companies, and fund investments are held in accordance with a stated set of fund objectives. The values of some of these funds are publicly quoted. For mutual funds which are publicly quoted, the funds are valued based on quoted prices in active markets and have been categorized as Level 1. For equity commingled funds and mutual funds that are not publicly quoted, the fund administrators value the funds using the NAV per fund share, derived from the quoted prices in active markets on the underlying securities and are not classified within the fair value hierarchy. These investments can typically be redeemed monthly or more frequently, with 30 or less days of notice and without further restrictions.

Fixed income. For fixed income securities, which consist primarily of corporate debt securities, U.S. government securities, foreign government securities, municipal bonds, asset and mortgage-backed securities, commingled funds, mutual funds, and derivative instruments, the trustees obtain multiple prices from pricing vendors whenever possible, which enables cross-provider validations in addition to checks for unusual daily movements. A primary price source is identified based on asset type, class, or issue for each security. With respect to individually held fixed income securities, the trustees monitor prices supplied by pricing services and may use a supplemental price source or change the primary price source of a given security if the portfolio managers challenge an assigned price and the trustees determine another price source is considered to be preferable. Exelon has obtained an understanding of how these prices are derived, including the nature and observability of the inputs used in deriving such prices. Additionally, Exelon selectively corroborates the fair values of securities by comparison to other market-based price sources. Investments in U.S. Treasury securities have been categorized as Level 1 because they trade in highly-liquid and transparent markets. Certain private placement fixed income securities have been categorized as Level 3 because they are priced using certain significant unobservable inputs and are typically illiquid. The remaining fixed income securities, including certain other fixed income investments, are based on evaluated prices that reflect observable market information, such as actual trade information of similar securities, adjusted for observable differences and are categorized as Level 2.

Other fixed income investments primarily consist of fixed income commingled funds and mutual funds, which are maintained by investment companies and hold fund investments in accordance with a stated set of fund objectives. The values of some of these funds are publicly quoted. For mutual funds which are publicly quoted, the funds are valued based on quoted prices in active markets and have been categorized as Level 1. For fixed income commingled funds and mutual funds that are not publicly quoted, the fund administrators value the funds using the NAV per fund share, derived from the quoted prices in active markets of the underlying securities and are not classified within the fair value hierarchy. These investments typically can be redeemed monthly or more frequently, with 30 or less days of notice and without further restrictions.

Derivative instruments. These instruments, consisting primarily of futures and swaps to manage risk, are recorded at fair value. Over-the-counter derivatives are valued daily, based on quoted prices in active markets and trade in open markets, and have been categorized as Level 1. Derivative instruments other than over-the-counter derivatives are valued based on external price data of comparable securities and have been categorized as Level 2.

Private credit. Private credit investments primarily consist of investments in private debt strategies. These investments are generally less liquid assets with an underlying term of 3 to 5 years and are intended to be held to maturity. The fair value of these investments is determined by the fund manager or administrator using a combination of valuation models including cost models, market models, and income models and typically cannot be redeemed until maturity of the term loan. For managed private credit funds, the fair value is determined using a combination of valuation models including cost models, market models, and income models and typically cannot be redeemed until maturity of the term loan. Managed private credit fund investments are not classified within the fair value hierarchy because their fair value is determined using NAV or its equivalent as a practical expedient.

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Private equity. These investments include those in limited partnerships that invest in operating companies that are not publicly traded on a stock exchange such as leveraged buyouts, growth capital, venture capital, distressed investments, and investments in natural resources. These investments typically cannot be redeemed and are generally liquidated over a period of 8 to 10 years from the initial investment date, which is based on Exelon's understanding of the investment funds. Private equity valuations are reported by the fund manager and are based on the valuation of the underlying investments, which include unobservable inputs such as cost, operating results, discounted future cash flows, and market based comparable data. These valuation inputs are unobservable. The fair value of private equity investments is determined using NAV or its equivalent as a practical expedient, and therefore, these investments are not classified within the fair value hierarchy.

Real estate. These investments are funds with a direct investment in pools of real estate properties. These funds are reported by the fund manager and are generally based on independent appraisals of the underlying investments from sources with professional qualifications, typically using a combination of market based comparable data and discounted cash flows. These valuation inputs are unobservable. Certain real estate investments cannot be redeemed and are generally liquidated over a period of 8 to 10 years from the initial investment date, which is based on Exelon's understanding of the investment funds. The remaining liquid real estate investments are generally redeemable from the investment vehicle quarterly, with 30 to 90 days of notice. The fair value of real estate investments is determined using NAV or its equivalent as a practical expedient, and therefore, these investments are not classified within the fair value hierarchy.

Pension and OPEB assets also include investments in hedge funds. Hedge fund investments include those that employ a broad range of strategies to enhance returns and provide additional diversification. The fair value of hedge funds is determined using NAV or its equivalent as a practical expedient, and therefore, hedge funds are not classified within the fair value hierarchy. Exelon has the ability to redeem these investments at NAV or its equivalent subject to certain restrictions that may include a lock-up period or a gate.

Defined Contribution Savings Plan

The Registrants participate in a 401(k) defined contribution savings plan that is sponsored by Exelon. The plan is qualified under applicable sections of the IRC and allows employees to contribute a portion of their pre-tax and/or after-tax income in accordance with specified guidelines. All Registrants match a percentage of the employee contributions up to certain limits. The following table presents the employer contributions and employer matching contributions to the savings plan for the years ended December 31, 2023, 2022, and 2021:

For the Years Ended December 31,			Exelon						ComEd						PECO						BGE						PHI						Pepco						DPL						ACE
2023			$	109					$	47					$	15					$	12					16						$	4					$	3					$	2
2022			91						39						13						11						14						4						3						2
2021			90						35						12						12						14						4						3						2

The Registrants use derivative instruments to manage commodity price risk and interest rate risk related to ongoing business operations. The Registrants do not execute derivatives for speculative or proprietary trading purposes.

Authoritative guidance requires that derivative instruments be recognized as either assets or liabilities at fair value, with changes in fair value of the derivative recognized in earnings immediately. Other accounting treatments are available through special election and designation, provided they meet specific, restrictive criteria both at the time of designation and on an ongoing basis. These alternative permissible accounting treatments include NPNS, cash flow hedges, and fair value hedges. At ComEd, derivative economic hedges related to commodities are recorded at fair value and offset by a corresponding regulatory asset or liability. At Exelon, derivative economic hedges related to interest rates are recorded at fair value and offsets are recorded to Electric operating revenues or Interest expense based on the activity the transaction is economically hedging. For all NPNS derivative instruments, accounts receivable or accounts payable are recorded when derivatives settle and revenue or expense is recognized in earnings as the underlying physical commodity is sold or consumed. At Exelon, derivative hedges that qualify and are designated as cash flow hedges are recorded at fair value and offsets are recorded to AOCI.

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ComEd’s use of cash collateral is generally unrestricted unless ComEd is downgraded below investment grade. Cash collateral held by PECO, BGE, Pepco, DPL, and ACE must be deposited in an unaffiliated major U.S. commercial bank or foreign bank with a U.S. branch office that meets certain qualifications.

Commodity Price Risk

The Utility Registrants employ established policies and procedures to manage their risks associated with market fluctuations in commodity prices by entering into physical and financial derivative contracts, which are either determined to be non-derivative or classified as economic hedges. The Utility Registrants procure electric and natural gas supply through a competitive procurement process approved by each of the respective state utility commissions. The Utility Registrants’ hedging programs are intended to reduce exposure to energy and natural gas price volatility and have no direct earnings impact as the costs are fully recovered from customers through regulatory-approved recovery mechanisms. The following table provides a summary of the Utility Registrants’ primary derivative hedging instruments, listed by commodity and accounting treatment.

Registrant			Commodity			Accounting Treatment			Hedging Instrument
ComEd			Electricity			NPNS			Fixed price contracts based on all requirements in the IPA procurement plans.
			Electricity			Changes in fair value of economic hedge recorded to an offsetting regulatory asset or liability (a)			20-year floating-to-fixed energy swap contracts beginning June 2012 based on the renewable energy resource procurement requirements in the Illinois Settlement Legislation of approximately 1.3 million MWhs per year.
PECO			Electricity			NPNS			Fixed price contracts for default supply requirements through full requirements contracts.
			Gas			NPNS			Fixed price contracts to cover about 10 % of planned natural gas purchases in support of projected firm sales.
BGE			Electricity			NPNS			Fixed price contracts for all SOS requirements through full requirements contracts.
			Gas			NPNS			Fixed price contracts for between 10 - 20 % of forecasted system supply requirements for flowing (i.e., non-storage) gas for the November through March period.
Pepco			Electricity			NPNS			Fixed price contracts for all SOS requirements through full requirements contracts.
DPL			Electricity			NPNS			Fixed price contracts for all SOS requirements through full requirements contracts.
			Gas			NPNS			Fixed and index priced contracts through full requirements contracts.
			Gas			Changes in fair value of economic hedge recorded to an offsetting regulatory asset or liability (b)			Exchange traded future contracts for up to 50 % of estimated monthly purchase requirements each month, including purchases for storage injections.
ACE			Electricity			NPNS			Fixed price contracts for all BGS requirements through full requirements contracts.

_________

(a) See Note 3—Regulatory Matters for additional information.

(b) The fair value of the DPL economic hedge is not material as of December 31, 2023 and 2022.

The fair value of derivative economic hedges is presented in Other current assets and current and noncurrent Mark-to-market derivative liabilities in Exelon's and ComEd's Consolidated Balance Sheets.

Interest Rate and Other Risk (Exelon)

Exelon Corporate uses a combination of fixed-rate and variable-rate debt to manage interest rate exposure. Exelon Corporate may utilize interest rate derivatives to lock in rate levels in anticipation of future financings, which are typically designated as cash flow hedges. In addition, Exelon Corporate utilized interest rate swaps to manage interest rate exposure and manage potential fluctuations in Electric operating revenues at the corporate level in consolidation, which were directly correlated to yields on U.S. Treasury bonds under ComEd's distribution formula rate through December 31, 2023. These interest rate swaps were accounted for as economic hedges. A hypothetical 50 basis point change in the interest rates associated with Exelon's interest rate swaps as of December 31, 2023 would result in an immaterial impact to Exelon's Consolidated Net Income.

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Below is a summary of the interest rate hedge balances at December 31, 2023 and 2022.

			December 31, 2023
			Derivatives Designated as Hedging Instruments						Economic Hedges						Total
Other current assets			$	11					$	1					$	12
Other deferred debits (noncurrent assets)			—						—						—
Total derivative assets			11						1						12
Mark-to-market derivative liabilities (current liabilities)			( 24 )						( 22 )						( 46 )
Total mark-to-market derivative liabilities			( 24 )						( 22 )						( 46 )
Total mark-to-market derivative net liabilities			$	( 13 )					$	( 21 )					$	( 34 )

			December 31, 2022
			Derivatives Designated as Hedging Instruments						Economic Hedges						Total
Other deferred debits (noncurrent assets)			$	6					$	5					$	11
Total derivative assets			6						5						11
Mark-to-market derivative liabilities (current liabilities)			—						( 3 )						( 3 )
Mark-to-market derivative liabilities (noncurrent liabilities)			( 4 )						—						( 4 )
Total mark-to-market derivative liabilities			( 4 )						( 3 )						( 7 )
Total mark-to-market derivative net assets			$	2					$	2					$	4

Cash Flow Hedges (Interest Rate Risk)

For derivative instruments that qualify and are designated as cash flow hedges, the changes in fair value each period are initially recorded in AOCI and reclassified into earnings when the underlying transaction affects earnings. In January 2023, Exelon Corporate entered into $ 115 million notional of 5-year maturity floating-to-fixed swaps and $ 115 million notional of 10-year maturity floating-to-fixed swaps, for a total of $ 230 million designated as cash flow hedges. In February 2023, Exelon terminated the previously issued floating-to-fixed swaps with a total notional of $ 1.5 billion upon issuance of $ 2.5 billion of debt. See Note 16 – Debt and Credit Agreements for additional information on the debt issuance. Prior to the termination, the AOCI derivative gain was $ 7 million (net of tax). The settlements resulted in a cash receipt of $ 10 million, which is being amortized into Interest expense in Exelon's Consolidated Statement of Operations and Comprehensive Income over the 5-year and 10-year terms of the swaps.

Since the termination in February 2023, Exelon has entered into additional floating-to-fixed swaps.

The following table provides the notional amounts outstanding held by Exelon at December 31, 2023 and 2022.

						December 31, 2023						December 31, 2022
5-year maturity floating-to-fixed swaps						$	655					$	635
10-year maturity floating-to-fixed swaps						655						635
Total						$	1,310					$	1,270

The AOCI derivative loss (net of tax) was $ 10 million as of December 31, 2023 and gain was $ 2 million as of December 31, 2022. See Note 21 – Changes in Accumulated Other Comprehensive Income (Loss) for additional information.

Economic Hedges (Interest Rate and Other Risk)

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Exelon Corporate executes derivative instruments to mitigate exposure to fluctuations in interest rates but for which the fair value or cash flow hedge elections were not made. For derivatives intended to serve as economic hedges, fair value is recorded on the balance sheet and changes in fair value each period are recognized in earnings or as a regulatory asset or liability, if regulatory requirements are met, each period.

Exelon Corporate enters into floating-to-fixed interest rate cap swaps to manage a portion of interest rate exposure in connection with existing borrowings. In 2022, Exelon Corporate entered into $ 1 billion notional of 18-month maturity floating-to-fixed interest rate cap swaps and $ 850 million notional of 6-month maturity floating-to-fixed interest rate cap swaps, for a total of $ 1,850 million notional of floating-to-fixed interest rate cap swaps as of December 31, 2022. The 6-month maturity floating-to-fixed interest rate cap swaps of $ 850 million notional matured in March 2023. Exelon receives payments on the interest rate cap when the floating rate exceeds the fixed rate. Settlements received are immaterial as of December 31, 2023.

Additionally, to manage potential fluctuations in Electric operating revenues related to ComEd's distribution formula rate, Exelon Corporate entered into a total of $ 4,875 million notional of 30-year constant maturity treasury interest rate (Corporate 30-year treasury) swaps from 2022 through 2023. The Corporate 30-year treasury swaps matured on December 31, 2023 and Exelon recorded a Mark-to-market liability of $ 22 million for the final settlement amount, which was paid in January 2024.

The following table provides the notional amounts outstanding held by Exelon at December 31, 2023 and 2022.

Hedging Instrument						December 31, 2023						December 31, 2022
Interest rate cap swaps						$	1,000					$	1,850
Constant maturity treasury interest rate swaps						—						500
Total						$	1,000					$	2,350

For the year ended December 31, 2023, Exelon Corporate recognized the following net pre-tax mark-to-market losses which are also recognized in Net fair value changes related to derivatives in Exelon's Consolidated Statements of Cash Flows.

						December 31, 2023						December 31, 2022
Income Statement Location						(Loss)						(Loss)
Electric operating revenues						$	( 20 )					$	( 2 )
Interest expense						—						( 3 )
Total						$	( 20 )					$	( 5 )

Credit Risk

The Registrants would be exposed to credit-related losses in the event of non-performance by counterparties on executed derivative instruments. The credit exposure of derivative contracts, before collateral, is represented by the fair value of contracts at the reporting date. The Utility Registrants have contracts to procure electric and natural gas supply that provide suppliers with a certain amount of unsecured credit. If the exposure on the supply contract exceeds the amount of unsecured credit, the suppliers may be required to post collateral. The net credit exposure is mitigated primarily by the ability to recover procurement costs through customer rates. The amount of cash collateral received from external counterparties decreased as of December 31, 2023 due to decreasing energy prices. The following table reflects the Registrants' cash collateral held from external counterparties, which is recorded in Other current liabilities on their respective Consolidated Balance Sheets, at December 31, 2023 and 2022

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						December 31, 2023						December 31, 2022
Exelon						$	148					$	297
ComEd						146						77
PECO (a)						—						—
BGE						1						23
PHI						1						197
Pepco						1						26
DPL						—						121
ACE						—						50

__________

(a) PECO had less than one million in cash collateral held with external parties as of December 31, 2023 and 2022.

The Utility Registrants’ electric supply procurement contracts do not contain provisions that would require them to post collateral. PECO’s, BGE’s, and DPL’s natural gas procurement contracts contain provisions that could require PECO, BGE, and DPL to post collateral in the form of cash or credit support, which vary by contract and counterparty, with thresholds contingent upon PECO’s, BGE's, and DPL’s credit rating. As of December 31, 2023, PECO, BGE, and DPL were not required to post collateral for any of these agreements. If PECO, BGE, or DPL lost their investment grade credit rating as of December 31, 2023, they could have been required to post collateral to their counterparties of $ 25 million, $ 61 million, and $ 10 million, respectively.

Short-Term Borrowings

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

Commercial Paper

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The following table reflects the Registrants' commercial paper programs supported by the revolving credit agreements and bilateral credit agreements at December 31, 2023 and 2022:

			Credit Facility Size at December 31,												Outstanding Commercial Paper at December 31,												Average Interest Rate on Commercial Paper Borrowings at December 31,
Commercial Paper Issuer			2023 (a)						2022 (a)						2023						2022						2023						2022
Exelon (b)			$	4,000					$	4,000					$	1,624					$	1,938					5.58		%				4.77		%
ComEd			$	1,000					$	1,000					$	202					$	427					5.53		%				4.71		%
PECO			$	600					$	600					$	165					$	239					5.57		%				4.71		%
BGE			$	600					$	600					$	336					$	409					5.59		%				4.81		%
PHI (c)			$	900					$	900					$	394					$	414					5.60		%				4.78		%
Pepco			$	300		(d)			$	300					$	132					$	299					5.59		%				4.79		%
DPL			$	300		(d)			$	300					$	63					$	115					5.60		%				4.76		%
ACE			$	300		(d)			$	300					$	199					$	—					5.60		%				—		%

__________

(a) Excludes credit facility agreements arranged at minority and community banks. See below for additional information.

(b) Includes revolving credit agreements at Exelon Corporate with a maximum program size of $ 900 million as of December 31, 2023 and December 31, 2022. Exelon Corporate had $ 527 million in outstanding commercial paper as of December 31, 2023 and $ 449 million outstanding commercial paper as of December 31, 2022.

(c) Represents the consolidated amounts of Pepco, DPL, and ACE.

(d) The standard maximum program size for revolving credit facilities is $ 300 million each for Pepco, DPL and ACE based on the credit agreements in place. However, the facilities at Pepco, DPL, and ACE have the ability to flex to $ 500 million, $ 500 million, and $ 350 million, respectively. The borrowing capacity may be increased or decreased during the term of the facility, except that (i) the sum of the borrowing capacity must equal the total amount of the facility, and (ii) the aggregate amount of credit used at any given time by each of Pepco, DPL, or ACE may not exceed $ 900 million or the maximum amount of short-term debt the company is permitted to have outstanding by its regulatory authorities. The total number of the borrowing reallocations may not exceed eight per year during the term of the facility. In January 2024, this ability was utilized to increase ACE's program size to $ 350 million. As a result, the program size for Pepco did not change and DPL was decreased to $ 250 million, which prevents the aggregate amount of outstanding short-term debt from exceeding the $ 900 million limit.

In order to maintain their respective commercial paper programs in the amounts indicated above, each Registrant must have credit facilities in place, at least equal to the amount of its commercial paper program. A registrant does not issue commercial paper in an aggregate amount exceeding the then available capacity under its credit facility.

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At December 31, 2023, the Registrants had the following aggregate bank commitments, credit facility borrowings, and available capacity under their respective credit facilities:

																											Available Capacity at December 31, 2023
Borrower (a)			Facility Type						Aggregate Bank Commitment (b)						Facility Draws						Outstanding Letters of Credit						Actual						To Support Additional Commercial Paper (c)
Exelon (c)			Syndicated Revolver						$	4,000					$	—					$	19					$	3,981					$	2,357
ComEd			Syndicated Revolver						1,000						—						10						990						788
PECO			Syndicated Revolver						600						—						—						600						435
BGE			Syndicated Revolver						600						—						6						594						258
PHI (d)			Syndicated Revolver						900						—						—						900						506
Pepco			Syndicated Revolver						300						—						—						300						168
DPL			Syndicated Revolver						300						—						—						300						237
ACE			Syndicated Revolver						300						—						—						300						101

__________

(a) On February 1, 2022, Exelon Corporate and the Utility Registrants' respective syndicated revolving credit facilities were replaced with a new 5-year revolving credit facility.

(b) Excludes credit facility agreements arranged at minority and community banks. See below for additional information.

(c) Includes $ 900 million aggregate bank commitment related to Exelon Corporate. Exelon Corporate had $ 3 million outstanding letters of credit as of December 31, 2023. Exelon Corporate had $ 370 million in available capacity to support additional commercial paper as of December 31, 2023.

(d) Represents the consolidated amounts of Pepco, DPL, and ACE.

The following table reflects the Registrants' credit facility agreements arranged at minority and community banks at December 31, 2023 and 2022. These are excluded from the Maximum Program Size and Aggregate Bank Commitment amounts within the two tables above and the facilities are solely used to issue letters of credit.

						Aggregate Bank Commitments												Outstanding Letters of Credit
Borrower						2023 (a)						2022						2023						2022
Exelon (b)						$	140					$	140					$	10					$	10
ComEd						40						40						7						7
PECO						40						40						1						1
BGE						15						15						2						2
PHI (c)						45						45						—						—
Pepco						15						15						—						—
DPL						15						15						—						—
ACE						15						15						—						—

__________

(a) These facilities were entered into on October 6, 2023 and expire on October 4, 2024.

(b) Represents the consolidated amounts of ComEd, PECO, BGE, Pepco, DPL, and ACE.

(c) Represents the consolidated amounts of Pepco, DPL, and ACE.

Revolving Credit Agreements

On February 1, 2022, Exelon Corporate and the Utility Registrants each entered into a new 5-year revolving credit facility that replaced its existing syndicated revolving credit facility. The following table reflects the credit agreements:

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Borrower						Aggregate Bank Commitment						Interest Rate
Exelon Corporate						$	900					SOFR plus 1.275		%
ComEd						$	1,000					SOFR plus 1.000		%
PECO						$	600					SOFR plus 0.900		%
BGE						$	600					SOFR plus 0.900		%
Pepco						$	300					SOFR plus 1.075		%
DPL						$	300					SOFR plus 1.000		%
ACE						$	300					SOFR plus 1.000		%

Borrowings under Exelon’s, ComEd’s, PECO’s, BGE's, Pepco's, DPL's, and ACE's revolving credit agreements bear interest at a rate based upon either the prime rate or a SOFR-based rate, plus an adder based upon the particular Registrant’s credit rating. The adders for the prime based borrowings and SOFR-based borrowings are presented in the following table:

			Exelon (a)						ComEd						PECO						BGE												Pepco						DPL						ACE
Prime based borrowings			0 - 27.5						—						—						—												7.5						—						—
SOFR-based borrowings			90.0 - 127.5						100.0						90.0						90.0												107.5						100.0						100.0

__________

(a) Includes interest rate adders at Exelon Corporate of 27.5 basis points and 127.5 basis points for prime and SOFR-based borrowings, respectively.

If any registrant loses its investment grade rating, the maximum adders for prime rate borrowings and SOFR-based rate borrowings would be 65 basis points and 165 basis points, respectively. The credit agreements also require the borrower to pay a facility fee based upon the aggregate commitments. The fee varies depending upon the respective credit ratings of the borrower. Exelon Corporate and the Utility Registrants had no outstanding amounts on the revolving credit facilities as of December 31, 2023.

Short-Term Loan Agreements

On March 23, 2017, Exelon Corporate entered into a term loan agreement for $ 500 million. The loan agreement was renewed in the first quarter of 2023 and was bifurcated into two tranches of $ 300 million on March 14, 2023 and $ 200 million on March 24, 2023. The agreements will expire on March 14, 2024 and March 22, 2024, respectively. Pursuant to the loan agreements, loans made thereunder bear interest at a variable rate equal to SOFR plus 0.90 % and all indebtedness thereunder is unsecured. The loan agreement is reflected in Exelon's Consolidated Balance Sheets within Short-term borrowings.

On October 4, 2022, ComEd entered into a 364-day term loan agreement for $ 150 million with a variable rate equal to SOFR plus 0.75 % and an expiration date of October 3, 2023. The proceeds from this loan were used to repay outstanding commercial paper obligations. The loan agreement is reflected in Exelon's and ComEd's Consolidated Balance Sheets within Short-term borrowings. The balance of the loan was repaid on January 13, 2023 in conjunction with the $ 400 million and $ 575 million First Mortgage Bond agreements that were entered into on January 3, 2023.

On May 9, 2023, ComEd entered into a 364-day term loan agreement for $ 400 million with a variable rate equal to SOFR plus 1.00 % and an expiration date of May 7, 2024. The proceeds from this loan were used to repay outstanding commercial paper obligations and for general corporate purposes. The loan agreement is reflected in Exelon's and ComEd's Consolidated Balance Sheets within Short-term borrowings.

Variable Rate Demand Bonds

DPL has outstanding obligations in respect of Variable Rate Demand Bonds (VRDB). VRDBs are subject to repayment on the demand of the holders and, for this reason, are accounted for as short-term debt in accordance with GAAP. However, these bonds may be converted to a fixed-rate, fixed-term option to establish a maturity which corresponds to the date of final maturity of the bonds. On this basis, PHI views VRDBs as a source of long-term financing. At both December 31, 2023 and December 31, 2022, $ 79 million in variable rate demand bonds issued by DPL were outstanding and are included in the Long-term debt due within one year in Exelon's, PHI's, and DPL's Consolidated Balance Sheets.

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Long-Term Debt

The following tables present the outstanding long-term debt at the Registrants at December 31, 2023 and 2022:

Exelon

															Maturity Date						December 31,
			Rates																		2023						2022
Long-term debt
First mortgage bonds (a)			1.05		%	-			7.90		%				2024 - 2053						$	24,776					$	22,651
Senior unsecured notes			2.75		%	-			7.60		%				2025 - 2053						10,824						8,324
Unsecured notes			2.25		%	-			6.35		%				2026 - 2053						4,650						4,250
Notes payable and other			1.64		%	-			7.49		%				2025 - 2053						84						86
Long-term software licensing agreement			2.30		%	-			3.95		%				2024 - 2025						12						25
Unsecured tax-exempt bonds			4.15		%	-			4.20		%				2024						33						33
Medium-terms notes (unsecured)									7.72		%				2027						10						10
Loan agreement (b)									6.23		%				2024						500						1,400
Total long-term debt																					40,889						36,779
Unamortized debt discount and premium, net																					( 80 )						( 74 )
Unamortized debt issuance costs																					( 296 )						( 257 )
Fair value adjustment																					582						626
Long-term debt due within one year																					( 1,403 )						( 1,802 )
Long-term debt																					$	39,692					$	35,272
Long-term debt to financing trusts (c)
Subordinated debentures to ComEd Financing III									6.35		%				2033						$	206					$	206
Subordinated debentures to PECO Trust III			7.38		%	-			10.50		%				2028						81						81
Subordinated debentures to PECO Trust IV									5.75		%				2033						103						103
Total long-term debt to financing trusts																					$	390					$	390

__________

(a) Substantially all of ComEd’s assets other than expressly excluded property and substantially all of PECO’s, Pepco's, DPL's, and ACE's assets are subject to the liens of their respective mortgage indentures.

(b) Pursuant to the loan agreement, loans made thereunder bear interest at a variable rate equal to SOFR plus 0.85 %.

(c) Amounts owed to these financing trusts are recorded as Long-term debt to financing trusts within Exelon’s Consolidated Balance Sheets.

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ComEd

															Maturity Date						December 31,
			Rates																		2023						2022
Long-term debt
First mortgage bonds (a)			2.20		%	-			6.45		%				2024 - 2053						$	11,603					$	10,629
Other									7.49		%				2053						8						8
Total long-term debt																					11,611						10,637
Unamortized debt discount and premium, net																					( 28 )						( 27 )
Unamortized debt issuance costs																					( 97 )						( 92 )
Long-term debt due within one year																					( 250 )						—
Long-term debt																					$	11,236					$	10,518
Long-term debt to financing trust (b)
Subordinated debentures to ComEd Financing III									6.35		%				2033						$	206					$	206
Total long-term debt to financing trusts																					206						206
Unamortized debt issuance costs																					( 1 )						( 1 )
Long-term debt to financing trusts																					$	205					$	205

__________

(a) Substantially all of ComEd’s assets, other than expressly excluded property, are subject to the lien of its mortgage indenture.

(b) Amount owed to this financing trust is recorded as Long-term debt to financing trust within ComEd’s Consolidated Balance Sheets.

PECO

															Maturity Date						December 31,
			Rates																		2023						2022
Long-term debt
First mortgage bonds (a)			2.80		%	-			5.95		%				2025 - 2052						$	5,200					$	4,625
Loan agreement									2.00		%				2023						—						50
Total long-term debt																					5,200						4,675
Unamortized debt discount and premium, net																					( 24 )						( 24 )
Unamortized debt issuance costs																					( 42 )						( 39 )
Long-term debt due within one year																					—						( 50 )
Long-term debt																					$	5,134					$	4,562
Long-term debt to financing trusts (b)
Subordinated debentures to PECO Trust III			7.38		%	-			10.50		%				2028						$	81					$	81
Subordinated debentures to PECO Trust IV									5.75		%				2033						103						103
Long-term debt to financing trusts																					$	184					$	184

__________

(a) Substantially all of PECO’s assets are subject to the lien of its mortgage indenture.

(b) Amounts owed to this financing trust are recorded as Long-term debt to financing trusts within PECO’s Consolidated Balance Sheets.

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BGE

															Maturity Date						December 31,
			Rates																		2023						2022
Long-term debt
Unsecured notes			2.25		%	-			6.35		%				2026 - 2053						$	4,650					$	4,250
Total long-term debt																					4,650						4,250
Unamortized debt discount and premium, net																					( 12 )						( 13 )
Unamortized debt issuance costs																					( 36 )						( 30 )
Long-term debt due within one year																					—						( 300 )
Long-term debt																					$	4,602					$	3,907

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PHI

															Maturity Date						December 31,
			Rates																		2023						2022
Long-term debt
First mortgage bonds (a)			1.05		%	-			7.90		%				2024 - 2053						$	7,972					$	7,397
Senior unsecured notes									7.45		%				2032						185						185
Unsecured tax-exempt bonds			4.15		%	-			4.20		%				2024						33						33
Medium-terms notes (unsecured)									7.72		%				2027						10						10
Finance leases									5.62		%				2025 - 2031						74						76
Total long-term debt																					8,274						7,701
Unamortized debt discount and premium, net																					—						4
Unamortized debt issuance costs																					( 55 )						( 47 )
Fair value adjustment																					429						462
Long-term debt due within one year																					( 644 )						( 591 )
Long-term debt																					$	8,004					$	7,529

_________

(a) Substantially all of Pepco's, DPL's, and ACE's assets are subject to the liens of their respective mortgage indentures.

Pepco

															Maturity Date						December 31,
			Rates																		2023						2022
Long-term debt
First mortgage bonds (a)			2.32		%	-			7.90		%				2024 - 2053						$	4,125					$	3,775
Finance leases									5.62		%				2025 - 2031						26						25
Total long-term debt																					4,151						3,800
Unamortized debt discount and premium, net																					2						2
Unamortized debt issuance costs																					( 57 )						( 51 )
Long-term debt due within one year																					( 405 )						( 4 )
Long-term debt																					$	3,691					$	3,747

________

(a) Substantially all of Pepco's assets are subject to the lien of its mortgage indenture.

DPL

															Maturity Date						December 31,
			Rates																		2023						2022
Long-term debt
First mortgage bonds (a)			1.05		%	-			5.72		%				2028 - 2053						$	2,024					$	1,874
Unsecured tax-exempt bonds			4.15		%	-			4.20		%				2024						33						33
Medium-terms notes (unsecured)									7.72		%				2027						10						10
Finance leases									5.62		%				2025 - 2031						29						32
Total long-term debt																					2,096						1,949
Unamortized debt discount and premium, net (b)																					—						—
Unamortized debt issuance costs																					( 16 )						( 11 )
Long-term debt due within one year																					( 84 )						( 584 )
Long-term debt																					$	1,996					$	1,354

__________

(a) Substantially all of DPL's assets are subject to the lien of its mortgage indenture.

(b) The amount in the Unamortized debt discount and premium, net category was less than $1 million as of December 31, 2023 and 2022.

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ACE

															Maturity Date						December 31,
			Rates																		2023						2022
Long-term debt
First mortgage bonds (a)			2.25		%	-			5.80		%				2024 - 2053						$	1,823					$	1,748
Finance leases									5.62		%				2025 - 2031						19						19
Total long-term debt																					1,842						1,767
Unamortized debt discount and premium, net																					—						( 1 )
Unamortized debt issuance costs																					( 9 )						( 9 )
Long-term debt due within one year																					( 154 )						( 3 )
Long-term debt																					$	1,679					$	1,754

__________

(a) Substantially all of ACE's assets are subject to the lien of its mortgage indenture.

Long-term debt maturities at the Registrants in the periods 2024 through 2028 and thereafter are as follows:

Year			Exelon						ComEd						PECO						BGE						PHI						Pepco						DPL						ACE
2024			$	1,403					$	250					$	—					$	—					$	644					$	405					$	84					$	154
2025			1,327						—						350						—						166						6						6						154
2026			1,615						500						—						350						15						5						6						4
2027			1,023						350						—						—						22						4						15						3
2028			1,990						550						81						—						358						3						3						352
Thereafter			33,921			(a)			10,167			(b)			4,953			(c)			4,300						7,070						3,728						1,982						1,175
Total			$	41,279					$	11,817					$	5,384					$	4,650					$	8,275					$	4,151					$	2,096					$	1,842

__________

(a) Includes $ 390 million due to ComEd and PECO financing trusts.

(b) Includes $ 206 million due to ComEd financing trust.

(c) Includes $ 184 million due to PECO financing trusts.

Long-Term Debt to Affiliates

In connection with the debt obligations assumed by Exelon as part of the Constellation merger, Exelon and subsidiaries of Generation (former Constellation subsidiaries) entered into intercompany loan agreements that mirror the terms and amounts of the third-party debt obligations of Exelon, resulting in intercompany notes receivable at Exelon Corporate from Generation. In connection with the separation, on January 31, 2022, Exelon Corporate received cash from Generation of $ 258 million to settle the intercompany loan.

Debt Covenants

As of December 31, 2023, the Registrants are in compliance with debt covenants.

Exelon measures and classifies fair value measurements in accordance with the hierarchy as defined by GAAP. The hierarchy prioritizes the inputs to valuation techniques used to measure fair value into three levels as follows:

• Level 1 — quoted prices (unadjusted) in active markets for identical assets or liabilities that the Registrants have the ability to liquidate as of the reporting date.

• Level 2 — inputs other than quoted prices included within Level 1 that are directly observable for the asset or liability or indirectly observable through corroboration with observable market data.

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• Level 3 — unobservable inputs, such as internally developed pricing models or third-party valuations for the asset or liability due to little or no market activity for the asset or liability.

Fair Value of Financial Liabilities Recorded at Amortized Cost

The following tables present the carrying amounts and fair values of the Registrants’ short-term liabilities, long-term debt, and trust preferred securities (long-term debt to financing trusts or junior subordinated debentures) at December 31, 2023 and 2022. The Registrants have no financial liabilities classified as Level 1 or measured using the NAV practical expedient.

The carrying amounts of the Registrants’ short-term liabilities as presented in their Consolidated Balance Sheets are representative of their fair value (Level 2) because of the short-term nature of these instruments.

						December 31, 2023																														December 31, 2022
						Carrying Amount						Fair Value																								Carrying Amount						Fair Value
												Level 1						Level 2						Level 3						Total												Level 1						Level 2						Level 3						Total
Long-Term Debt, including amounts due within one year (a)
Exelon						$	41,095					$	—					$	33,804					$	3,442					$	37,246					$	37,074					$	—					$	29,902					$	2,327					$	32,229
ComEd						11,486						—						10,210						—						10,210						10,518						—						9,006						—						9,006
PECO						5,134						—						4,562						—						4,562						4,612						—						3,864						50						3,914
BGE						4,602						—						4,145						—						4,145						4,207						—						3,613						—						3,613
PHI						8,648						—						4,160						3,442						7,602						8,120						—						4,507						2,277						6,784
Pepco						4,096						—						2,311						1,600						3,911						3,751						—						2,229						1,205						3,434
DPL						2,080						—						694						1,134						1,828						1,938						—						1,164						458						1,622
ACE						1,833						—						939						708						1,647						1,757						—						909						614						1,523
Long-Term Debt to Financing Trusts
Exelon						$	390					$	—					$	—					$	390					$	390					$	390					$	—					$	—					$	384					$	384
ComEd						205						—						—						208						208						205						—						—						204						204
PECO						184						—						—						182						182						184						—						—						180						180

__________

(a) Includes unamortized debt issuance costs, unamortized debt discount and premium, net, purchase accounting fair value adjustments, and finance lease liabilities which are not fair valued. Refer to Note 16 — Debt and Credit Agreements for unamortized debt issuance costs, unamortized debt discount and premium, net, and purchase accounting fair value adjustments and Note 10 — Leases for finance lease liabilities.

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Exelon uses the following methods and assumptions to estimate fair value of financial liabilities recorded at carrying cost:

Type			Level			Registrants			Valuation
Long-Term Debt, including amounts due within one year
Taxable Debt Securities			2			All			The fair value is determined by a valuation model that is based on a conventional discounted cash flow methodology and utilizes assumptions of current market pricing curves. Exelon obtains credit spreads based on trades of existing Exelon debt securities as well as other issuers in the utility sector with similar credit ratings. The yields are then converted into discount rates of various tenors that are used for discounting the respective cash flows of the same tenor for each bond or note.
Variable Rate Financing Debt			2			Exelon, DPL			Debt rates are reset on a regular basis and the carrying value approximates fair value.
Non-Government Backed Fixed Rate Nonrecourse Debt			2			Exelon			Fair value is based on market and quoted prices for its own and other nonrecourse debt with similar risk profiles. Given the low trading volume in the nonrecourse debt market, the price quotes used to determine fair value will reflect certain qualitative factors, such as market conditions, investor demand, new developments that might significantly impact the project cash flows or off-taker credit, and other circumstances related to the project.
Taxable Private Placement Debt Securities			3			Exelon, Pepco, DPL, ACE			Rates are obtained similar to the process for taxable debt securities. Due to low trading volume and qualitative factors such as market conditions, low volume of investors, and investor demand, these debt securities are Level 3.
Long-Term Debt to Financing Trusts
Long Term Debt to Financing Trusts			3			Exelon, ComEd, PECO			Fair value is based on publicly traded securities issued by the financing trusts. Due to low trading volume of these securities and qualitative factors, such as market conditions, investor demand, and circumstances related to each issue, this debt is classified as Level 3.

Recurring Fair Value Measurements

The following tables present assets and liabilities measured and recorded at fair value in the Registrants' Consolidated Balance Sheets on a recurring basis and their level within the fair value hierarchy at December 31, 2023 and 2022. Exelon and the Utility Registrants have immaterial and no financial assets or liabilities measured using the NAV practical expedient, respectively:

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Exelon

			At December 31, 2023																								At December 31, 2022
			Level 1						Level 2						Level 3						Total						Level 1						Level 2						Level 3						Total
Assets
Cash equivalents (a)			$	618					$	—					$	—					$	618					$	664					$	—					$	—					$	664
Rabbi trust investments
Cash equivalents			67						—						—						67						62						—						—						62
Mutual funds			53						—						—						53						49						—						—						49
Fixed income			—						7						—						7						—						7						—						7
Life insurance contracts			—						61						43						104						—						58						40						98
Rabbi trust investments subtotal			120						68						43						231						111						65						40						216
Interest rate derivative assets
Derivatives designated as hedging instruments			—						11						—						11						—						6						—						6
Economic hedges			—						1						—						1						—						5						—						5
Interest rate derivative assets subtotal			—						12						—						12						—						11						—						11
Total assets			738						80						43						861						775						76						40						891
Liabilities
Commodity derivative liabilities			—						—						( 133 )						( 133 )						—						—						( 84 )						( 84 )
Interest rate derivative liabilities
Derivatives designated as hedging instruments			—						( 24 )						—						( 24 )						—						( 4 )						—						( 4 )
Economic hedges			—						( 22 )						—						( 22 )						—						( 3 )						—						( 3 )
Interest rate derivative liabilities subtotal			—						( 46 )						—						( 46 )						—						( 7 )						—						( 7 )
Deferred compensation obligation			—						( 75 )						—						( 75 )						—						( 75 )						—						( 75 )
Total liabilities			—						( 121 )						( 133 )						( 254 )						—						( 82 )						( 84 )						( 166 )
Total net assets (liabilities)			$	738					$	( 41 )					$	( 90 )					$	607					$	775					$	( 6 )					$	( 44 )					$	725

__________

(a) Excludes cash of $ 334 million and $ 345 million at December 31, 2023 and 2022, respectively, and restricted cash of $ 149 million and $ 81 million at December 31, 2023 and 2022, respectively, and includes long-term restricted cash of $ 174 million and $ 117 million at December 31, 2023 and 2022, respectively, which is reported in Other deferred debits in the Consolidated Balance Sheets.

ComEd, PECO, and BGE

			ComEd																								PECO																								BGE
At December 31, 2023			Level 1						Level 2						Level 3						Total						Level 1						Level 2						Level 3						Total						Level 1						Level 2						Level 3						Total
Assets
Cash equivalents (a)			$	453					$	—					$	—					$	453					$	9					$	—					$	—					$	9					$	—					$	—					$	—					$	—
Rabbi trust investments
Mutual funds			—						—						—						—						9						—						—						9						9						—						—						9
Life insurance contracts			—						—						—						—						—						18						—						18						—						—						—						—
Rabbi trust investments subtotal			—						—						—						—						9						18						—						27						9						—						—						9
Total assets			453						—						—						453						18						18						—						36						9						—						—						9
Liabilities
Commodity derivative liabilities (b)			—						—						( 133 )						( 133 )						—						—						—						—						—						—						—						—
Deferred compensation obligation			—						( 8 )						—						( 8 )						—						( 8 )						—						( 8 )						—						( 4 )						—						( 4 )
Total liabilities			—						( 8 )						( 133 )						( 141 )						—						( 8 )						—						( 8 )						—						( 4 )						—						( 4 )
Total net assets (liabilities)			$	453					$	( 8 )					$	( 133 )					$	312					$	18					$	10					$	—					$	28					$	9					$	( 4 )					$	—					$	5

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			ComEd																								PECO																								BGE
At December 31, 2022			Level 1						Level 2						Level 3						Total						Level 1						Level 2						Level 3						Total						Level 1						Level 2						Level 3						Total
Assets
Cash equivalents (a)			$	392					$	—					$	—					$	392					$	10					$	—					$	—					$	10					$	23					$	—					$	—					$	23
Rabbi trust investments
Mutual funds			—						—						—						—						7						—						—						7						7						—						—						7
Life insurance contracts			—						—						—						—						—						15						—						15						—						—						—						—
Rabbi trust investments subtotal			—						—						—						—						7						15						—						22						7						—						—						7
Total assets			392						—						—						392						17						15						—						32						30						—						—						30
Liabilities
Commodity derivative liabilities (b)			—						—						( 84 )						( 84 )						—						—						—						—						—						—						—						—
Deferred compensation obligation			—						( 8 )						—						( 8 )						—						( 7 )						—						( 7 )						—						( 4 )						—						( 4 )
Total liabilities			—						( 8 )						( 84 )						( 92 )						—						( 7 )						—						( 7 )						—						( 4 )						—						( 4 )
Total net assets (liabilities)			$	392					$	( 8 )					$	( 84 )					$	300					$	17					$	8					$	—					$	25					$	30					$	( 4 )					$	—					$	26

__________

(a) ComEd excludes cash of $ 86 million and $ 42 million at December 31, 2023 and 2022, respectively, and restricted cash of $ 147 million and $ 77 million at December 31, 2023 and 2022, respectively, and includes long-term restricted cash of $ 174 million and $ 117 million at December 31, 2023 and 2022, respectively, which is reported in Other deferred debits in the Consolidated Balance Sheets. PECO excludes cash of $ 42 million and $ 58 million at December 31, 2023 and 2022, respectively. BGE excludes cash of $ 47 million and $ 43 million at December 31, 2023 and 2022, respectively, and restricted cash of $ 1 million and $ 1 million at December 31, 2023 and 2022, respectively.

(b) The Level 3 balance consists of the current and noncurrent liability of $ 27 million and $ 106 million, respectively, at December 31, 2023, and $ 5 million and $ 79 million, respectively, at December 31, 2022 related to floating-to-fixed energy swap contracts with unaffiliated suppliers.

PHI, Pepco, DPL, and ACE

			At December 31, 2023																								At December 31, 2022
PHI			Level 1						Level 2						Level 3						Total						Level 1						Level 2						Level 3						Total
Assets
Cash equivalents (a)			$	107					$	—					$	—					$	107					$	205					$	—					$	—					$	205
Rabbi trust investments
Cash equivalents			64						—						—						64						59						—						—						59
Mutual funds			9						—						—						9						11						—						—						11
Fixed income			—						7						—						7						—						7						—						7
Life insurance contracts			—						21						41						62						—						22						39						61
Rabbi trust investments subtotal			73						28						41						142						70						29						39						138
Total assets			180						28						41						249						275						29						39						343
Liabilities
Deferred compensation obligation			—						( 13 )						—						( 13 )						—						( 14 )						—						( 14 )
Total liabilities			—						( 13 )						—						( 13 )						—						( 14 )						—						( 14 )
Total net assets			$	180					$	15					$	41					$	236					$	275					$	15					$	39					$	329

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			Pepco																								DPL																								ACE
At December 31, 2023			Level 1						Level 2						Level 3						Total						Level 1						Level 2						Level 3						Total						Level 1						Level 2						Level 3						Total
Assets
Cash equivalents (a)			$	23					$	—					$	—					$	23					$	1					$	—					$	—					$	1					$	—					$	—					$	—					$	—
Rabbi trust investments
Cash equivalents			63						—						—						63						—						—						—						—						—						—						—						—
Life insurance contracts			—						21						41						62						—						—						—						—						—						—						—						—
Rabbi trust investments subtotal			63						21						41						125						—						—						—						—						—						—						—						—
Total assets			86						21						41						148						1						—						—						1						—						—						—						—
Liabilities
Deferred compensation obligation			—						( 1 )						—						( 1 )						—						—						—						—						—						—						—						—
Total liabilities			—						( 1 )						—						( 1 )						—						—						—						—						—						—						—						—
Total net assets			$	86					$	20					$	41					$	147					$	1					$	—					$	—					$	1					$	—					$	—					$	—					$	—

			Pepco																								DPL																								ACE
At December 31, 2022			Level 1						Level 2						Level 3						Total						Level 1						Level 2						Level 3						Total						Level 1						Level 2						Level 3						Total
Assets
Cash equivalents (a)			$	51					$	—					$	—					$	51					$	121					$	—					$	—					$	121					$	1					$	—					$	—					$	1
Rabbi trust investments
Cash equivalents			59						—						—						59						—						—						—						—						—						—						—						—
Life insurance contracts			—						22						38						60						—						—						—						—						—						—						—						—
Rabbi trust investments subtotal			59						22						38						119						—						—						—						—						—						—						—						—
Total assets			110						22						38						170						121						—						—						121						1						—						—						1
Liabilities
Deferred compensation obligation			—						( 1 )						—						( 1 )						—						—						—						—						—						—						—						—
Total liabilities			—						( 1 )						—						( 1 )						—						—						—						—						—						—						—						—
Total net assets			$	110					$	21					$	38					$	169					$	121					$	—					$	—					$	121					$	1					$	—					$	—					$	1

__________

(a) PHI excludes cash of $ 96 million and $ 165 million at December 31, 2023 and 2022, respectively, and restricted cash of $ 1 million and $ 3 million at December 31, 2023 and 2022, respectively. Pepco excludes cash of $ 48 million and $ 45 million at December 31, 2023 and 2022, respectively, and restricted cash of $ 1 million and $ 3 million at December 31, 2023 and 2022, respectively. DPL excludes cash of $ 15 million and $ 31 million at December 31, 2023 and 2022, respectively. ACE excludes cash of $ 21 million and $ 71 million at December 31, 2023 and 2022, respectively.

Reconciliation of Level 3 Assets and Liabilities

The following tables present the fair value reconciliation of Level 3 assets and liabilities measured at fair value on a recurring basis during the years ended December 31, 2023 and 2022:

			Exelon									ComEd						PHI and Pepco
For the year ended December 31, 2023			Total									Commodity Derivatives						Life Insurance Contracts
Balance at December 31, 2022			$	( 44 )								$	( 84 )					$	40
Total realized / unrealized gains (losses)
Included in net income (a)			3									—						1
Included in regulatory assets/liabilities			( 49 )									( 49 )			(b)			—
Balance at December 31, 2023			$	( 90 )								$	( 133 )		(c)			$	41
The amount of total gains included in income attributed to the change in unrealized gains (losses) related to assets and liabilities as of December 31, 2023			$	3								$	—					$	1

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			Exelon						ComEd						PHI and Pepco
For the year ended December 31, 2022			Total						Commodity Derivatives						Life Insurance Contracts
Balance at December 31, 2021			$	( 182 )					$	( 219 )					$	35
Total realized / unrealized gains (losses)
Included in net income (a)			5						—						5
Included in regulatory assets/liabilities			135						135			(b)			—
Transfers into Level 3			( 2 )						—						—
Balance at December 31, 2022			$	( 44 )					$	( 84 )					$	40
The amount of total gains included in income attributed to the change in unrealized gains (losses) related to assets and liabilities as of December 31, 2022			$	5					$	—					$	5

__________

(a) Classified in Operating and maintenance expense in the Consolidated Statements of Operations and Comprehensive Income.

(b) Includes $ 83 million of decreases in fair value and an increase for realized gains due to settlements of $ 34 million recorded in Purchased power expense associated with floating-to-fixed energy swap contracts with unaffiliated suppliers for the year ended December 31, 2023. Includes $ 136 million of increases in fair value and a decrease for realized losses due to settlements of $ 1 million recorded in Purchased power expense associated with floating-to-fixed energy swap contracts with unaffiliated suppliers for the year ended December 31, 2022.

(c) The balance of the current and noncurrent asset was effectively zero as of December 31, 2023. The balance consists of a current and noncurrent liability of $ 27 million and $ 106 million, respectively, as of December 31, 2023.

Valuation Techniques Used to Determine Fair Value

Cash Equivalents (All Registrants). Investments with original maturities of three months or less when purchased, including mutual and money market funds, are considered cash equivalents. The fair values are based on observable market prices and, therefore, are included in the recurring fair value measurements hierarchy as Level 1.

Rabbi Trust Investments (Exelon, PECO, BGE, PHI, Pepco, DPL, and ACE). The Rabbi trusts were established to hold assets related to deferred compensation plans existing for certain active and retired members of Exelon’s executive management and directors. The Rabbi trusts' assets are included in Investments in the Registrants’ Consolidated Balance Sheets and consist primarily of money market funds, mutual funds, fixed income securities, and life insurance policies. Money market funds and mutual funds are publicly quoted and have been categorized as Level 1 given the clear observability of the prices. The fair values of fixed income securities are based on evaluated prices that reflect observable market information, such as actual trade information or similar securities, adjusted for observable differences and are categorized in Level 2. The life insurance policies are valued using the cash surrender value of the policies, net of loans against those policies, which is provided by a third-party. Certain life insurance policies, which consist primarily of mutual funds that are priced based on observable market data, have been categorized as Level 2 because the life insurance policies can be liquidated at the reporting date for the value of the underlying assets. Life insurance policies that are valued using unobservable inputs have been categorized as Level 3, where the fair value is determined based on the cash surrender value of the policy, which contains unobservable inputs and assumptions. Because Exelon relies on its third-party insurance provider to develop the inputs without adjustment for the valuations of its Level 3 investments, quantitative information about significant unobservable inputs used in valuing these investments is not reasonably available to Exelon. Therefore, Exelon has not disclosed such inputs.

Interest Rate Derivatives (Exelon) Exelon may utilize fixed-to-floating or floating-to-fixed interest rate swaps as a means to manage interest rate risk. These interest rate swaps are typically accounted for as economic hedges. In addition, Exelon may utilize interest rate derivatives to lock in interest rate levels in anticipation of future financings. These interest rate derivatives are typically designated as cash flow hedges. Exelon determines the current fair value by calculating the net present value of expected payments and receipts under the swap agreement, based on and discounted by the market's expectation of future interest rates. Additional inputs to the net present value calculation may include the contract terms, counterparty credit risk and other market parameters. As these inputs are based on observable data and valuations of similar instruments, the interest rate swaps are categorized as Level 2 in the fair value hierarchy. See Note 15 — Derivative Financial Instruments for additional information on mark-to-market derivatives.

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Deferred Compensation Obligations (All Registrants). The Registrants’ deferred compensation plans allow participants to defer certain cash compensation into a notional investment account. The Registrants include such plans in other current and noncurrent liabilities in their Consolidated Balance Sheets. The value of the Registrants’ deferred compensation obligations is based on the market value of the participants’ notional investment accounts. The underlying notional investments are comprised primarily of equities, mutual funds, commingled funds, and fixed income securities which are based on directly and indirectly observable market prices. Since the deferred compensation obligations themselves are not exchanged in an active market, they are categorized as Level 2 in the fair value hierarchy.

The value of certain employment agreement obligations (which are included with the Deferred Compensation Obligation in the tables above) are based on a known and certain stream of payments to be made over time and are categorized as Level 2 within the fair value hierarchy.

Commodity Derivatives (Exelon and ComEd). On December 17, 2010, ComEd entered into several 20-year floating to fixed energy swap contracts with unaffiliated suppliers for the procurement of long-term renewable energy and associated RECs. Delivery under the contracts began in June 2012. The fair value of these swaps has been designated as a Level 3 valuation due to the long tenure of the positions and the internal modeling assumptions. The modeling assumptions include using forward power prices. See Note 15 — Derivative Financial Instruments for additional information on mark-to-market derivatives.

The following table discloses the significant unobservable inputs to the forward curve used to value mark-to-market derivatives:

Type of trade						Fair Value as of December 31, 2023						Fair Value as of December 31, 2022						Valuation Technique						Unobservable Input						2023 Range & Arithmetic Average															2022 Range & Arithmetic Average
Commodity derivatives						$	( 133 )					$	( 84 )					Discounted Cash Flow						Forward power price (a)						$	30.27		-			$	73.71		$	43.35					$	34.78		-			$	75.71		$	48.44

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(a) An increase to the forward power price would increase the fair value.

Commitments

PHI Merger Commitments (Exelon, PHI, Pepco, DPL, and ACE). Approval of the PHI Merger in Delaware, New Jersey, Maryland, and the District of Columbia was conditioned upon Exelon and PHI agreeing to certain commitments. The following amounts represent total commitment costs that have been recorded since the acquisition date and the total remaining obligations for Exelon, PHI, Pepco, DPL, and ACE at December 31, 2023:

Description			Exelon						PHI						Pepco						DPL						ACE
Total commitments			$	513					$	320					$	120					$	89					$	111
Remaining commitments (a)			38						35						31						3						1

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(a) Remaining commitments extend through 2026 and include escrow funds, charitable contributions, and rate credits.

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Commercial Commitments (All Registrants). The Registrants' commercial commitments at December 31, 2023, representing commitments potentially triggered by future events were as follows:

									Expiration within
Exelon			Total						2024						2025						2026						2027						2028						2029 and beyond
Letters of credit (a)			$	29					$	27					$	2					$	—					$	—					$	—					$	—
Surety bonds (b)			204						204						—						—						—						—						—
Financing trust guarantees (c)			378						—						—						—						—						78						300
Guaranteed lease residual values (d)			27						—						5						6						4						6						6
Total commercial commitments			$	638					$	231					$	7					$	6					$	4					$	84					$	306
ComEd
Letters of credit (a)			$	17					$	15					$	2					$	—					$	—					$	—					$	—
Surety bonds (b)			46						46						—						—						—						—						—
Financing trust guarantees (c)			200						—						—						—						—						—						200
Total commercial commitments			$	263					$	61					$	2					$	—					$	—					$	—					$	200
PECO
Letters of credit (a)			$	1					$	1					$	—					$	—					$	—					$	—					$	—
Surety bonds (b)			2						2						—						—						—						—						—
Financing trust guarantees (c)			178						—						—						—						—						78						100
Total commercial commitments			$	181					$	3					$	—					$	—					$	—					$	78					$	100
BGE
Letters of credit (a)			$	8					$	8					$	—					$	—					$	—					$	—					$	—
Surety bonds (b)			3						3						—						—						—						—						—
Total commercial commitments			$	11					$	11					$	—					$	—					$	—					$	—					$	—
PHI
Surety bonds (b)			$	96					$	96					$	—					$	—					$	—					$	—					$	—
Guaranteed lease residual values (d)			27						—						5						6						4						6						6
Total commercial commitments			$	123					$	96					$	5					$	6					$	4					$	6					$	6
Pepco
Surety bonds (b)			$	84					$	84					$	—					$	—					$	—					$	—					$	—
Guaranteed lease residual values (d)			9						—						2						2						1						2						2
Total commercial commitments			$	93					$	84					$	2					$	2					$	1					$	2					$	2
DPL
Surety bonds (b)			$	7					$	7					$	—					$	—					$	—					$	—					$	—
Guaranteed lease residual values (d)			11						—						2						3						2						2						2
Total commercial commitments			$	18					$	7					$	2					$	3					$	2					$	2					$	2
ACE
Surety bonds (b)			$	5					$	5					$	—					$	—					$	—					$	—					$	—
Guaranteed lease residual values (d)			7						—						1						1						1						2						2
Total commercial commitments			$	12					$	5					$	1					$	1					$	1					$	2					$	2

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(a) Exelon and certain of its subsidiaries maintain non-debt letters of credit to provide credit support for certain transactions as requested by third parties.

(b) Surety bonds—Guarantees issued related to contract and commercial agreements, excluding bid bonds. Historically, payments under the guarantees have not been made and the likelihood of payments being required is remote.

(c) Reflects guarantee of ComEd and PECO securities held by ComEd Financing III, PECO Trust III, and PECO Trust IV.

(d) Represents the maximum potential obligation in the event that the fair value of certain leased equipment and fleet vehicles is zero at the end of the maximum lease term. The lease term associated with these assets ranges from 1 to 8 years. The maximum potential obligation at the end of the minimum lease term would be $ 61 million guaranteed by Exelon and PHI, of which $ 20 million , $ 24 million, and $ 17 million is guaranteed by Pepco, DPL, and ACE, respectively. Historically, payments under the guarantees have not been made and PHI believes the likelihood of payments being required under the guarantees is remote.

Environmental Remediation Matters

General (All Registrants). The Registrants’ operations have in the past, and may in the future, require substantial expenditures to comply with environmental laws. Additionally, under federal and state environmental laws, the Registrants are generally liable for the costs of remediating environmental contamination of property now or formerly owned by them and of property contaminated by hazardous substances generated by them. The Registrants own or lease a number of real estate parcels, including parcels on which their operations or the operations of others may have resulted in contamination by substances that are considered hazardous under environmental laws. In addition, the Registrants are currently involved in a number of proceedings relating to sites where hazardous substances have been deposited and may be subject to additional proceedings in the future. Unless otherwise disclosed, the Registrants cannot reasonably estimate whether they will incur significant liabilities for additional investigation and remediation costs at these or additional sites identified by the Registrants, environmental agencies or others, or whether such costs will be recoverable from third parties, including customers. Additional costs could have a material, unfavorable impact on the Registrants' financial statements.

MGP Sites (All Registrants). ComEd, PECO, BGE, and DPL have identified sites where former MGP or gas purification activities have or may have resulted in actual site contamination. For some sites, there are additional PRPs that may share responsibility for the ultimate remediation of each location.

• ComEd has 17 sites that are currently under some degree of active study and/or remediation. ComEd expects the majority of the remediation at these sites to continue through at least 2031.

• PECO has 6 sites that are currently under some degree of active study and/or remediation. PECO expects the majority of the remediation at these sites to continue through at least 2025.

• BGE has 4 sites that currently require some level of remediation and/or ongoing activity. BGE expects the majority of the remediation at these sites to continue through at least 2025.

• DPL has 1 site that is currently under study and the required cost at the site is not expected to be material.

The historical nature of the MGP and gas purification sites and the fact that many of the sites have been buried and built over, impacts the ability to determine a precise estimate of the ultimate costs prior to initial sampling and determination of the exact scope and method of remedial activity. Management determines its best estimate of remediation costs using all available information at the time of each study, including probabilistic and deterministic modeling for ComEd and PECO, and the remediation standards currently required by the applicable state environmental agency. Prior to completion of any significant clean up, each site remediation plan is approved by the appropriate state environmental agency.

ComEd, pursuant to an ICC order, and PECO, pursuant to a PAPUC order, are currently recovering environmental remediation costs of former MGP facility sites through customer rates. While BGE and DPL do not have riders for MGP clean-up costs, they have historically received recovery of actual clean-up costs in distribution rates.

In 2023, ComEd and PECO completed an annual study of their future estimated MGP remediation requirements. The study resulted in a $ 25 million increase to the environmental liability and related regulatory asset for ComEd.

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The increase was primarily due to increased costs resulting from inflation and changes in remediation plans. The study did not result in a material change to the environmental liability for PECO.

At December 31, 2023 and 2022, the Registrants had accrued the following undiscounted amounts for environmental liabilities in Accrued expenses, Other current liabilities, and Other deferred credits and other liabilities in their respective Consolidated Balance Sheets:

			December 31, 2023												December 31, 2022
			Total Environmental Investigation and Remediation Liabilities						Portion of Total Related to MGP Investigation and Remediation						Total Environmental Investigation and Remediation Liabilities						Portion of Total Related to MGP Investigation and Remediation
Exelon			$	428					$	338					$	409					$	355
ComEd			303						302						325						324
PECO			27						25						25						23
BGE			14						11						9						8
PHI			81						—						46						—
Pepco			79						—						44						—
DPL			1						—						1						—
ACE			1						—						1						—

Benning Road Site (Exelon, PHI, and Pepco). In September 2010, PHI received a letter from EPA identifying the Benning Road site as one of six land-based sites potentially contributing to contamination of the lower Anacostia River. A portion of the site, which is owned by Pepco, was formerly the location of an electric generating facility owned by Pepco subsidiary, Pepco Energy Services (PES), which became a part of Generation, following the 2016 merger between PHI and Exelon. This generating facility was deactivated in June 2012. The remaining portion of the site consists of a Pepco transmission and distribution service center that remains in operation. In December 2011, the U.S. District Court for the District of Columbia approved a Consent Decree entered into by Pepco and Pepco Energy Services (hereinafter "Pepco Entities") with the DOEE, which requires the Pepco Entities to conduct a Remedial Investigation and Feasibility Study (RI/FS) for the Benning Road site and an approximately 10 to 15-acre portion of the adjacent Anacostia River. The purpose of this RI/FS is to define the nature and extent of contamination from the Benning Road site and to evaluate remedial alternatives.

Pursuant to an internal agreement between the Pepco Entities, since 2013, Pepco has performed the work required by the Consent Decree and has been reimbursed for that work by an agreed upon allocation of costs between the Pepco Entities. In September 2019, the Pepco Entities issued a draft “final” RI report which DOEE approved on February 3, 2020. The Pepco Entities are completing a FS to evaluate possible remedial alternatives for submission to DOEE. In October, 2022, DOEE approved dividing the work to complete the landside portion of the FS from the waterside portion to expedite the overall schedule for completion of the project. It is currently anticipated that the landside FS will be complete and approved by DOEE by the end of the first quarter of 2024 and the waterside FS will be complete and approved by DOEE by the end of the fourth quarter of 2024. Following the completion of each FS, DOEE will issue a Proposed Plan for public comment and then issue a Record of Decision (ROD) identifying the remedial actions determined to be necessary for the area in question. On October 3, 2023, DOEE and Pepco entered into an addendum to the Benning Consent Decree pursuant to which Pepco has agreed to fund or perform the remedial actions to be selected by DOEE for the landslide and water areas. This addendum to the Benning Consent Decree has been lodged with the court in January 2024. Once the addendum is signed and entered by the court it will become effective.

As part of the separation between Exelon and Constellation in February 2022, the internal agreement between the Pepco Entities for completion and payment for the remaining Consent Decree work was memorialized in a formal agreement for post-separation activities. A second post-separation assumption agreement between Exelon and Constellation transferred any of the potential remaining remediation liability, if any, of PES/Generation to a non-utility subsidiary of Exelon which going forward will be responsible for those liabilities. Exelon, PHI, and Pepco have determined that a loss associated with this matter is probable and have accrued an estimated liability, which is included in the table above.

Anacostia River Tidal Reach (Exelon, PHI, and Pepco). Contemporaneous with the Benning Road site RI/FS being performed by the Pepco Entities, DOEE and NPS have been conducting a separate RI/FS focused on the

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entire tidal reach of the Anacostia River extending from just north of the Maryland-District of Columbia boundary line to the confluence of the Anacostia and Potomac Rivers. The river-wide RI incorporated the results of the river sampling performed by the Pepco Entities as part of the Benning RI/FS, as well as similar sampling efforts conducted by owners of other sites adjacent to this segment of the river and supplemental river sampling conducted by DOEE’s contractor.

On September 30, 2020, DOEE released its Interim ROD for the Anacostia River sediments. The Interim ROD reflects an adaptive management approach which will require several identified “hot spots” in the river to be addressed first while continuing to conduct studies and to monitor the river to evaluate improvements and determine potential future remediation plans. The adaptive management process chosen by DOEE is less intrusive, provides more long-term environmental certainty, is less costly, and allows for site specific remediation plans already underway, including the plan for the Benning Road site to proceed to conclusion.

On July 15, 2022, Pepco received a letter from the District of Columbia's Office of the Attorney General (D.C. OAG) on behalf of DOEE conveying a settlement offer to resolve all PRPs' liability to the District of Columbia (District) for their past costs and their anticipated future costs to complete the work for the Interim ROD. Pepco responded on July 27, 2022 to enter into settlement discussions. On October 3, 2023, Pepco and the District entered into another consent decree (the “Anacostia River Consent Decree”) pursuant to which Pepco agreed to pay $ 47 million to resolve its liability to the District for all past costs to perform the river-wide RI/FS and all future costs to complete the work required by the Interim ROD. This amount will be paid in four equal annual installments beginning a year after the effective date of the Anacostia River Consent Decree. The funds will be deposited into the DOEE’s Clean Land Fund for the District’s costs of the Interim ROD work. The Anacostia River Consent Decree caps Pepco’s liability for these costs and provides Pepco with the right to seek contribution from other potentially responsible parties. The Anacostia River Consent Decree was lodged with the U.S. District Court for the District of Columbia in January 2024. Once the court signs and approves the Anacostia River Consent Decree it will become effective. Exelon, PHI, and Pepco have accrued a liability for Pepco’s payment obligations under the Anacostia Consent Decree and management's best estimate of its share of any other future Anacostia River response costs. Pepco has concluded that incremental exposure remains reasonably possible, but management cannot reasonably estimate a range of loss beyond the amounts recorded, which are included in the table above.

In addition to the activities associated with the remedial process outlined above, CERCLA separately requires federal and state (here including Washington, D.C.) Natural Resource Trustees (federal or state agencies designated by the President or the relevant state, respectively, or Indian tribes) to conduct an assessment of any damages to natural resources within their jurisdiction as a result of the contamination that is being remediated. The Trustees can seek compensation from responsible parties for such damages, including restoration costs. During the second quarter of 2018, Pepco became aware that the Trustees are in the beginning stages of a NRD assessment, a process that often takes many years beyond the remedial decision to complete. Pepco has concluded that a loss associated with the eventual NRD assessment is reasonably possible. Due to the very early stage of the NRD process, Pepco cannot reasonably estimate the final range of loss potentially resulting from this process.

As noted in the Benning Road Site disclosure above, as part of the separation of Exelon and Constellation in February 2022, an assumption agreement was executed transferring any potential future remediation liabilities associated with the Benning Site remediation to a non-utility subsidiary of Exelon. Similarly, any potential future liability associated with the Anacostia River Sediment Project (ARSP) was also assumed by this entity.

Buzzard Point Site (Exelon, PHI, and Pepco). On December 8, 2022, Pepco received a letter from the D.C. OAG, alleging wholly past violations of the District's stormwater discharge and waste disposal requirements related to operations at the Buzzard Point facility, a 9-acre parcel of waterfront property in Washington, D.C. occupied by an active substation and former steam plant building. The letter also alleged wholly past violations by Pepco of stormwater discharge requirements related to its district-wide system of underground vaults. On October 3, 2023, Pepco entered into a Consent Order with the District of Columbia to resolve the alleged violations without any admission of liability. The Consent Order requires Pepco to pay a civil penalty of $ 10 million. In addition, Pepco has agreed to assess the environmental conditions at its Buzzard Point facility and conduct any remedial actions deemed necessary as a result of the assessment, and also to assess potential environmental impacts associated with the operation of its underground vaults. The Consent Order was lodged with the District of Columbia Superior Court in January 2024. The court signed and entered the Consent Order, and it became effective on February 2, 2024. Exelon, PHI, and Pepco have accrued a liability for the penalty

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payments and for the projected costs for the required environmental assessments and remediation. Pepco has concluded that incremental exposure is reasonably possible, but the range of loss cannot be reasonably estimated beyond the amounts included in the table above.

Litigation and Regulatory Matters

Fund Transfer Restrictions (All Registrants). Under applicable law, Exelon may borrow or receive an extension of credit from its subsidiaries. Under the terms of Exelon’s intercompany money pool agreement, Exelon can lend to, but not borrow from the money pool.

Under applicable law, ComEd, PECO, BGE, PHI, Pepco, DPL, and ACE can pay dividends only from retained, undistributed or current earnings. A significant loss recorded at ComEd, PECO, BGE, PHI, Pepco, DPL, or ACE may limit the dividends that these Registrants can distribute to Exelon.

ComEd has agreed in connection with financings arranged through ComEd Financing III that it will not declare dividends on any shares of its capital stock in the event that: (1) it exercises its right to extend the interest payment periods on the subordinated debt securities issued to ComEd Financing III; (2) it defaults on its guarantee of the payment of distributions on the preferred trust securities of ComEd Financing III; or (3) an event of default occurs under the Indenture under which the subordinated debt securities are issued. No such event has occurred.

PECO has agreed in connection with financings arranged through PEC L.P. and PECO Trust IV that PECO will not declare dividends on any shares of its capital stock in the event that: (1) it exercises its right to extend the interest payment periods on the subordinated debentures, which were issued to PEC L.P. or PECO Trust IV; (2) it defaults on its guarantee of the payment of distributions on the Series D Preferred Securities of PEC L.P. or the preferred trust securities of PECO Trust IV; or (3) an event of default occurs under the Indenture under which the subordinated debentures are issued. No such event has occurred.

BGE is subject to restrictions established by the MDPSC that prohibit BGE from paying a dividend on its common shares if (a) after the dividend payment, BGE’s equity ratio would be below 48 % as calculated pursuant to the MDPSC’s ratemaking precedents or (b) BGE’s senior unsecured credit rating is rated by two of the three major credit rating agencies below investment grade. No such event has occurred.

Pepco is subject to certain dividend restrictions established by settlements approved by the MDPSC and DCPSC that prohibit Pepco from paying a dividend on its common shares if (a) after the dividend payment, Pepco's equity ratio would be 48 % as calculated pursuant to the MDPSC's and DCPSC's ratemaking precedents, of or (b) Pepco’s senior unsecured credit rating is rated by one of the three major credit rating agencies below investment grade. No such event has occurred.

DPL is subject to certain dividend restrictions established by settlements approved by the DEPSC and MDPSC that prohibit DPL from paying a dividend on its common shares if (a) after the dividend payment, DPL's equity ratio would be 48 % as calculated pursuant to the DEPSC's and MDPSC's ratemaking precedents, or (b) DPL’s corporate issuer or senior unsecured credit rating, or its equivalent, is rated by any of the three major credit rating agencies below the generally accepted definition of investment grade. No such event has occurred.

ACE is subject to certain dividend restrictions established by settlements approved by the NJBPU that prohibit ACE from paying a dividend on its common shares if (a) after the dividend payment, ACE's common equity ratio would be 48 % as calculated pursuant to the NJBPU's ratemaking precedents, or (b) ACE's senior corporate issuer or senior unsecured credit rating is rated by one of the three major credit rating agencies below investment grade. ACE is also subject to a dividend restriction which requires ACE to notify and obtain the prior approval of the NJBPU before dividends can be paid if its equity as a percent of its total capitalization, excluding securitization debt, falls below 30 %. No such events have occurred.

DPA and Related Matters (Exelon and ComEd). Exelon and ComEd received a grand jury subpoena in the second quarter of 2019 from the USAO requiring production of information concerning their lobbying activities in the State of Illinois. On October 4, 2019, Exelon and ComEd received a second grand jury subpoena from the USAO requiring production of records of any communications with certain individuals and entities. On October 22, 2019, the SEC notified Exelon and ComEd that it had also opened an investigation into their lobbying activities. On July 17, 2020, ComEd entered into a DPA with the USAO to resolve the USAO investigation. Under the DPA, the USAO filed a single charge alleging that ComEd improperly gave and offered to give jobs, vendor

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subcontracts, and payments associated with those jobs and subcontracts for the benefit of the former Speaker of the Illinois House of Representatives and the Speaker’s associates, with the intent to influence the Speaker’s action regarding legislation affecting ComEd’s interests. The DPA provided that the USAO would defer any prosecution of such charge and any other criminal or civil case against ComEd in connection with the matters identified therein for a three-year period subject to certain obligations of ComEd, including payment to the U.S. Treasury of $ 200 million, which was paid in November 2020. Exelon was not made a party to the DPA, and therefore the investigation by the USAO into Exelon’s activities ended with no charges being brought against Exelon. The three-year term of the DPA ended on July 17, 2023, and on that same date the court granted the USAO’s motion to dismiss the pending charge against ComEd that had been deferred by the DPA.

On September 28, 2023, Exelon and ComEd reached a settlement with the SEC, concluding and resolving in its entirety the SEC investigation, which related to the conduct identified in the DPA that was entered into by ComEd in July 2020 and successfully exited in July 2023. Under the terms of the settlement, Exelon agreed to pay a civil penalty of $ 46.2 million and Exelon and ComEd agreed to cease and desist from committing or causing any violations and any future violations of specified provisions of the federal securities laws and rules promulgated thereunder. Exelon recorded an accrual for the full amount of the penalty in the second quarter of 2023, which was reflected in Operating and maintenance expense within Exelon's Consolidated Statements of Operations and Comprehensive Income and in Accrued expenses on the Consolidated Balance Sheets. Exelon paid the civil penalty in full on October 4, 2023.

Subsequent to Exelon announcing the receipt of the subpoenas, various lawsuits were filed, and various demand letters were received related to the subject of the subpoenas and, the conduct described in the DPA and the SEC's investigation, including:

• Four putative class action lawsuits against ComEd and Exelon were filed in federal court on behalf of ComEd customers in the third quarter of 2020 alleging, among other things, civil violations of federal racketeering laws. In addition, the Citizens Utility Board (CUB) filed a motion to intervene in these cases on October 22, 2020 which was granted on December 23, 2020. On September 9, 2021, the federal court granted Exelon’s and ComEd’s motion to dismiss and dismissed the plaintiffs’ and CUB’s federal law claim with prejudice. The federal court also dismissed the related state law claims made by the federal plaintiffs and CUB on jurisdictional grounds. Plaintiffs appealed dismissal of the federal law claim to the Seventh Circuit Court of Appeals. Plaintiffs and CUB also refiled their state law claims in state court and moved to consolidate them with the already pending consumer state court class action, discussed below. On August 22, 2022, the Seventh Circuit affirmed the dismissal of the consolidated federal cases in their entirety. The time to further appeal has passed and the Seventh Circuit’s decision is final.

• Three putative class action lawsuits against ComEd and Exelon were filed in Illinois state court in the third quarter of 2020 seeking restitution and compensatory damages on behalf of ComEd customers. The cases were consolidated into a single action in October of 2020. In November 2020, CUB filed a motion to intervene in the cases pursuant to an Illinois statute allowing CUB to intervene as a party or otherwise participate on behalf of utility consumers in any proceeding which affects the interest of utility consumers. On November 23, 2020, the court allowed CUB’s intervention, but denied CUB's request to stay these cases. Plaintiffs subsequently filed a consolidated complaint, and ComEd and Exelon filed a motion to dismiss on jurisdictional and substantive grounds on January 11, 2021. Briefing on that motion was completed on March 2, 2021. The parties agreed, on March 25, 2021, along with the federal court plaintiffs discussed above, to jointly engage in mediation. The parties participated in a one-day mediation on June 7, 2021 but no settlement was reached. On December 23, 2021, the state court granted ComEd and Exelon’s motion to dismiss with prejudice. On December 30, 2021, plaintiffs filed a motion to reconsider that dismissal and for permission to amend their complaint. The court denied the plaintiffs' motion on January 21, 2022. Plaintiffs have appealed the court's ruling dismissing their complaint to the First District Court of Appeals. On February 15, 2022, Exelon and ComEd moved to dismiss the federal plaintiffs' refiled state law claims, seeking dismissal on the same legal grounds asserted in their motion to dismiss the original state court plaintiffs' complaint. The court granted dismissal of the refiled state claims on February 16, 2022. The original federal plaintiffs appealed that dismissal on February 18, 2022. The two state appeals were consolidated on March 21, 2022. On September 8, 2023, the Illinois appellate court affirmed the dismissal. Plaintiffs have asked the Illinois Supreme Court to grant them leave to further appeal, but such appeal is not allowed as a matter of right.

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Exelon and ComEd filed a response in opposition to the request for leave to further appeal on January 12, 2024.

• On November 3, 2022, a plaintiff filed a putative class action complaint in Lake County, Illinois Circuit Court against ComEd and Exelon for unjust enrichment and deceptive business practices in connection with the conduct giving rise to the DPA. Plaintiff seeks an accounting and disgorgement of any benefits ComEd allegedly obtained from said conduct. Plaintiff served initial discovery requests on ComEd in December 2022, to which ComEd has responded. ComEd and Exelon filed a motion to dismiss the Complaint on February 3, 2023. On June 16, 2023, the court granted Exelon and ComEd's motion to dismiss the action with prejudice. Plaintiff filed its notice of appeal of that dismissal on July 17, 2023. Plaintiff's opening appellate brief was filed on October 19, 2023. ComEd and Exelon filed a response on January 2, 2024. Plaintiff filed its reply brief on February 2, 2024. With leave of court, Exelon and ComEd filed a sur-reply on February 14, 2024. The appellate court has set oral argument for April 3, 2024.

• A putative class action lawsuit against Exelon and certain officers of Exelon and ComEd was filed in federal court in December 2019 alleging misrepresentations and omissions in Exelon’s SEC filings related to ComEd’s lobbying activities and the related investigations. The complaint was amended on September 16, 2020, to dismiss two of the original defendants and add other defendants, including ComEd. Defendants filed a motion to dismiss in November 2020. The court denied the motion in April 2021. On May 26, 2021, defendants moved the court to certify its order denying the motion to dismiss for interlocutory appeal. Briefing on the motion was completed in June 2021, and that motion was denied on January 28, 2022. In May 2021, the parties each filed respective initial discovery disclosures. On June 9, 2021, defendants filed their answer and affirmative defenses to the complaint and the parties engaged thereafter in discovery. On September 9, 2021, the U.S. government moved to intervene in the lawsuit and stay discovery until the parties entered into an amendment to their protective order that would prohibit the parties from requesting discovery into certain matters, including communications with the U.S. government. The court ordered said amendment to the protective order on November 15, 2021 and discovery resumed. The court further amended the protective order on October 17, 2022 and extended it until May 15, 2023. Following mediation, the parties reached a settlement of the lawsuit, under which defendants agreed to pay plaintiffs $ 173 million. On May 26, 2023, plaintiffs filed a motion for preliminary approval of the settlement, which the court granted on June 9, 2023. The court granted final settlement approval on September 7, 2023. The settlement was fully covered by insurance and has been paid in full.

• Several shareholders have sent letters to the Exelon Board of Directors since 2020 demanding, among other things, that the Exelon Board of Directors investigate and address alleged breaches of fiduciary duties and other alleged violations by Exelon and ComEd officers and directors related to the conduct described in the DPA. In the first quarter of 2021, the Exelon Board of Directors appointed a Special Litigation Committee (SLC) consisting of disinterested and independent parties to investigate and address these shareholders' allegations and make recommendations to the Exelon Board of Directors based on the outcome of the SLC's investigation. In July 2021, one of the demand letter shareholders filed a derivative action against current and former Exelon and ComEd officers and directors, and against Exelon, as nominal defendant, asserting the same claims made in its demand letter. On October 12, 2021, the parties to the derivative action filed an agreed motion to stay that litigation for 120 days in order to allow the SLC to continue its investigation, which the court granted. The stay has been extended several times. The parties participated in a mediation in February 2023, but the matter did not resolve at that time. On April 26 and May 1, 2023, two additional demand letter shareholders each filed a separate derivative lawsuit against current and former Exelon and ComEd officers and directors, and certain third parties, and against Exelon as nominal defendant, asserting claims similar to those made in their respective demand letters. On May 25, 2023, certain demand letter shareholders (Settling Shareholders) filed a separate derivative lawsuit against current and former Exelon and ComEd officers and directors, and against Exelon as nominal defendant, asserting claims similar to those made in their respective demand letters. The then pending derivative lawsuits were subsequently consolidated. On May 26, 2023, prior to lawsuit consolidation, the SLC filed a Notice of Determination and Intent to Seek Court Approval of Settlement (Notice of Determination). The Notice of Determination stated that, through mediation efforts, a settlement of the derivative claims had been approved by the SLC, the Independent Review Committee of the Board (which had been formed in the third quarter of 2022, to ensure the Board’s consideration of any SLC recommendations would be independent and objective),

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the Board, and the Settling Shareholders (the Settling Parties). The Notice of Determination further specified the process by which the Settling Parties would seek court approval of the proposed settlement and resolution and dismissal of all derivative claims and lawsuits, including any lawsuits or actions brought by demand letter shareholders who are not participating in the proposed settlement. In furtherance of the proposed settlement, on June 16, 2023, the SLC filed a motion for preliminary approval of the settlement, attaching the Stipulation and Agreement of Settlement (Stipulation), which contains the terms of the proposed settlement. The proposed settlement terms include but are not limited to: a payment of $ 40 million to Exelon by Exelon’s insurers of which $ 10 million constitutes the attorneys’ fee award to be paid to the Settling Shareholders’ counsel; various compliance and disclosure-related reforms; and certain changes in Board and Committee composition. On June 13, 2023, the non-settling derivative shareholders filed a motion asking the court to set a status conference to discuss lifting the discovery stay. On June 29, 2023, an additional shareholder filed a separate derivative lawsuit against current and former Exelon and ComEd officers and directors, and against Exelon as nominal defendant, asserting claims similar to those made in its demand letter. That lawsuit has been consolidated into the other pending derivative lawsuits. On June 30, 2023, the non-settling shareholders’ motion for status and the SLC’s motion for preliminary approval was heard by the court, during which the court set a briefing schedule on the appropriate standard for evaluating the settlement and the proper scope of requested discovery. Following briefing and a hearing, the court allowed the non-settling shareholders to seek certain, limited discovery, which the SLC, Independent Review Committee, and Exelon responded to on October 5, 2023. On October 11, 2023, an additional non-settling shareholder filed a separate derivative lawsuit against current and former Exelon and ComEd officers and directors, and against Exelon as a nominal defendant, asserting claims similar to those made in its demand letter. That lawsuit has been consolidated into the other pending derivative lawsuits. The SLC filed its renewed motion for preliminary approval on October 26, 2023, with supporting submissions filed by the Independent Review Committee, Exelon, and the settling shareholders on that same day. The non-settling plaintiffs filed a response to the renewed motion for preliminary approval and supporting submissions on November 29, 2023, and the SLC Independent Review Committee, Exelon and the Settling Shareholders filed their respective reply briefs on December 21, 2023. On January 16, 2024, the non-settling plaintiffs sought leave of court to file a sur-reply, which the court granted on January 18, 2024.

In August 2022, the ICC concluded its investigation initiated on August 12, 2021 into rate impacts of conduct admitted in the DPA, including the costs recovered from customers related to the DPA and Exelon's funding of the fine paid by ComEd. On August 17, 2022, the ICC issued its final order accepting ComEd's voluntary customer refund offer of approximately $ 38 million (of which about $ 31 million is ICC jurisdictional; the remaining balance is FERC jurisdictional) that resolves the question of whether customer funds were used for DPA related activities. The customer refund includes the cost of every individual or entity that was either (i) identified in the DPA or (ii) identified by ComEd as an associate of the former Speaker of the Illinois House of Representatives in the ICC proceeding. The ICC’s DPA investigation is now closed. The ICC jurisdictional refund was made to customers during the April 2023 billing cycle, as required by the ICC. The FERC jurisdictional refund was included in ComEd's transmission formula rate update proceeding, filed on May 12, 2023. The filed transmission rate, inclusive of the FERC jurisdictional DPA refund, will appear on ComEd retail customers' bills for the June 2023 through May 2024 monthly billing periods, in the line designated as "Transmission Services Charge." The customer refund will not be recovered in rates or charged to customers and ComEd will not seek or accept reimbursement or indemnification from any source other than Exelon. An accrual for the amount of the customer refund has been recorded in Regulatory assets in Exelon’s and ComEd’s Consolidated Balance Sheets as of December 31, 2023.

Savings Plan Claim (Exelon). On December 6, 2021, seven current and former employees filed a putative ERISA class action suit in U.S. District Court for the Northern District of Illinois against Exelon, its Board of Directors, the former Board Investment Oversight Committee, the Corporate Investment Committee, individual defendants, and other unnamed fiduciaries of the Exelon Corporation Employee Savings Plan (Plan). The complaint alleges that the defendants violated their fiduciary duties under the Plan by including certain investment options that allegedly were more expensive than and underperformed similar passively-managed or other funds available in the marketplace and permitting a third-party administrative service provider/recordkeeper and an investment adviser to charge excessive fees for the services provided. The plaintiffs seek declaratory, equitable and monetary relief on behalf of the Plan and participants. On February 16, 2022, the court granted the parties' stipulated dismissal of the individual named defendants without prejudice. The remaining defendants filed

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a motion to dismiss the complaint on February 25, 2022. On March 4, 2022, the Chamber of Commerce filed a brief of amicus curiae in support of the defendants' motion to dismiss. On September 22, 2022, the court granted Exelon’s motion to dismiss without prejudice. The court granted plaintiffs leave until October 31, 2022 to file an amended complaint, which was later extended to November 30, 2022. Plaintiffs filed their amended complaint on November 30, 2022. Defendants filed their motion to dismiss the amended complaint on January 20, 2023. On September 29, 2023, the court again granted Exelon's motion to dismiss but granted plaintiffs leave until October 20, 2023 to file a second amended complaint. Plaintiffs did not file an amended complaint by the deadline. On October 25, 2023, the parties filed a joint Stipulation of Dismissal, which provides that plaintiffs agreed that they will not initiate an appeal from the dismissal of this matter, and the parties agree that each side shall bear their own costs and attorneys’ fees. Plaintiffs also acknowledge in the Stipulation that defendants have neither paid nor agreed to pay or provide any monetary or equitable remedy in connection with the dismissal of this action. On October 27, 2023, the court entered final judgment dismissing the matter with prejudice. No loss contingencies have been reflected in Exelon’s consolidated financial statements with respect to this matter.

General (All Registrants). The Registrants are involved in various other litigation matters that are being defended and handled in the ordinary course of business. The Registrants are also from time to time subject to audits and investigations by the FERC and other regulators. The assessment of whether a loss is probable or reasonably possible, and whether the loss or a range of loss is estimable, often involves a series of complex judgments about future events. The Registrants maintain accruals for such losses that are probable of being incurred and subject to reasonable estimation. Management is sometimes unable to estimate an amount or range of reasonably possible loss, particularly where (1) the damages sought are indeterminate, (2) the proceedings are in the early stages, or (3) the matters involve novel or unsettled legal theories. In such cases, there is considerable uncertainty regarding the timing or ultimate resolution of such matters, including a possible eventual loss.

Equity Securities Offering (Exelon)

On August 4, 2022, Exelon entered into an agreement with certain underwriters in connection with an underwritten public offering (the “Offering”) of 11.3 million shares (the “Shares”) of its Common stock, no par value (“Common Stock”). The Shares were sold to the underwriters at a price per share of $ 43.32 . Exelon also granted the underwriters an option to purchase an additional 1.695 million shares of Common stock also at the price per share of $ 43.32 . On August 5, 2022, the underwriters exercised the option in full. The net proceeds from the Offering and the exercise of the underwriters’ option were $ 563 million before expenses paid by Exelon. 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 16 — Debt and Credit Agreements for additional information on Exelon’s term loan.

At-the-Market Program (Exelon)

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.

ComEd Common Stock Warrants

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The following table presents warrants outstanding to purchase ComEd common stock and shares of common stock reserved for the conversion of warrants. The warrants entitle the holders to convert such warrants into common stock of ComEd at a conversion rate of one share of common stock for three warrants.

			December 31,
			2023						2022
Warrants outstanding			60,032						60,052
Common Stock reserved for conversion			20,011						20,017

Share Repurchases

There currently is no Exelon Board of Director authority to repurchase shares. Any previous shares repurchased are held as treasury shares, at cost, unless cancelled or reissued at the discretion of Exelon’s management.

Preferred and Preference Securities

The following table presents Exelon, ComEd, PECO, BGE, Pepco, and ACE's shares of preferred securities authorized, none of which were outstanding, as of December 31, 2023 and 2022. There are no shares of preferred securities authorized for DPL.

			Preferred Securities Authorized
Exelon			100,000,000
ComEd			850,000
PECO			15,000,000
BGE			1,000,000
Pepco			6,000,000
ACE (a)			2,799,979

_________

(a) Includes 799,979 shares of cumulative preferred stock and 2,000,000 of no par value preferred stock as of December 31, 2023 and 2022.

The following table presents ComEd, BGE, and ACE's preference securities authorized, none of which were outstanding as of December 31, 2023 and 2022. There are no shares of preference securities authorized for Exelon, PECO, Pepco, and DPL.

			Preference Securities Authorized
ComEd			6,810,451
BGE (a)			6,500,000
ACE			3,000,000

__________

(a) Includes 4,600,000 shares of unclassified preference securities and 1,900,000 shares of previously redeemed preference securities as of December 31, 2023 and 2022.

Stock-Based Compensation Plans

Exelon grants stock-based awards through its LTIP, which primarily includes performance share awards, restricted stock units, and stock options. At December 31, 2023, there were approximately 33 million shares authorized for issuance under the LTIP. For the years ended December 31, 2023, 2022, and 2021, exercised and distributed stock-based awards were primarily issued from authorized but unissued Common stock shares.

Separation-related Adjustments. In connection with the separation, Exelon and Constellation entered into an Employee Matters Agreement, effective February 1, 2022. Under the terms of the Employee Matters Agreement, and pursuant to the terms of the LTIP, the Compensation Committee of the Board of Exelon approved an

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adjustment to outstanding awards granted under the LTIP in order to preserve the intrinsic aggregate value of such awards before the separation. The separation-related adjustments did not have a material impact on either compensation expense or the potentially dilutive securities to be considered in the calculation of diluted earnings per share of Common stock. Former Exelon employees transferred to Constellation as a result of the separation surrendered their outstanding unvested Exelon awards effective February 1, 2022.

The Registrants grant cash awards. The following table does not include expense related to these plans as they are not considered stock-based compensation plans under the applicable authoritative guidance.

The following table presents the stock-based compensation expense included in Exelon's Consolidated Statements of Operations and Comprehensive Income. The Utility Registrants' stock-based compensation expense for the years ended December 31, 2023, 2022, and 2021 was not material.

			Year Ended December 31,
Exelon			2023						2022						2021
Total stock-based compensation expense included in Operating and maintenance expense			$	21					$	41					$	95
Income tax benefit			( 5 )						( 10 )						( 25 )
Total after-tax stock-based compensation expense			$	16					$	31					$	70

Exelon receives a tax deduction based on the intrinsic value of the award on the exercise date for stock options and the distribution date for performance share awards and restricted stock units. For each award, throughout the requisite service period, Exelon recognizes the tax benefit related to compensation costs. The following table presents information regarding Exelon’s realized tax benefit when distributed:

			Year Ended December 31,
			2023						2022						2021
Performance share awards			$	8					$	6					$	6
Restricted stock units			6						6						6

Performance Share Awards

Performance share awards are granted under the LTIP. The performance share awards are settled 50 % in common stock and 50 % in cash at the end of the three-year performance period, except for awards that are settled 100 % in cash if certain ownership requirements are satisfied.

The common stock portion of the performance share awards is considered an equity award and is valued based on Exelon's stock price on the grant date. The cash portion of the performance share awards is considered a liability award which is remeasured each reporting period based on Exelon’s current stock price. As the value of the common stock and cash portions of the awards are based on Exelon’s stock price during the performance period, coupled with changes in the total shareholder return modifier and expected payout of the award, the compensation costs are subject to volatility until payout is established.

For nonretirement-eligible employees, stock-based compensation costs are recognized over the vesting period of three years using the straight-line method. For performance share awards granted to retirement-eligible employees, the value of the performance shares is recognized ratably over the vesting period, which is the year of grant. Exelon processes forfeitures as they occur for employees who do not complete the requisite service period.

The following table summarizes Exelon’s nonvested performance share awards activity:

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			Shares						Weighted Average Grant Date Fair Value (per share)
Nonvested at December 31, 2022 (a)			866,805						$	41.86
Granted			679,196						41.82
Change in performance			( 1,233 )						41.75
Vested			( 261,577 )						41.25
Forfeited			( 112,727 )						41.96
Undistributed vested awards (b)			( 212,222 )						41.61
Nonvested at December 31, 2023 (a)			958,242						$	42.01

__________

(a) Excludes 1,198,093 and 1,539,819 of performance share awards issued to retirement-eligible employees as of December 31, 2023 and 2022, respectively, as they are fully vested.

(b) Represents performance share awards that vested but were not distributed to retirement-eligible employees during 2023

The following table summarizes the weighted average grant date fair value and the total fair value of performance share awards vested.

			Year Ended December 31,
			2023 (a)						2022						2021
Weighted average grant date fair value (per share)			$	41.82					$	43.05					$	43.37
Total fair value of performance shares vested			17						29						44
Total fair value of performance shares settled in cash			26						25						28

__________

(a) As of December 31, 2023, $ 11 million of total unrecognized compensation costs related to nonvested performance shares are expected to be recognized over the remaining weighted-average period of 1.8 years.

Restricted Stock Units

Restricted stock units are granted under the LTIP with the majority being settled in a specific number of shares of common stock after the service condition has been met. The corresponding cost of services is measured based on the grant date fair value of the restricted stock unit issued.

The value of the restricted stock units is expensed over the requisite service period using the straight-line method. The requisite service period for restricted stock units is generally three to five years . However, certain restricted stock unit awards become fully vested upon the employee reaching retirement-eligibility. The value of the restricted stock units granted to retirement-eligible employees is either recognized ratably over the first six months in the year of grant if the employee reaches retirement eligibility prior to July 1st of the grant year or through the date of which the employee reaches retirement eligibility. Exelon processes forfeitures as they occur for employees who do not complete the requisite service period.

The following table summarizes Exelon’s nonvested restricted stock unit activity:

			Shares						Weighted Average Grant Date Fair Value (per share)
Nonvested at December 31, 2022 (a)			561,161						$	41.98
Granted			385,065						41.84
Vested			( 246,618 )						42.36
Forfeited			( 55,371 )						40.56
Undistributed vested awards (b)			( 112,292 )						41.87
Nonvested at December 31, 2023 (a)			531,945						$	42.87

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__________

(a) Excludes 205,855 and 476,592 of restricted stock units issued to retirement-eligible employees as of December 31, 2023 and 2022, respectively, as they are fully vested.

(b) Represents restricted stock units that vested but were not distributed to retirement-eligible employees during 2023.

The following table summarizes the weighted average grant date fair value and the total fair value of restricted stock units vested.

			Year Ended December 31,
			2023 (a)						2022						2021
Weighted average grant date fair value (per share)			$	41.84					$	42.97					$	44.21
Total fair value of restricted stock units vested			15						23						34

__________

(a) As of December 31, 2023, $ 9 million of total unrecognized compensation costs related to nonvested restricted stock units are expected to be recognized over the remaining weighted-average period of 1.6 years.

Stock Options

Non-qualified stock options to purchase shares of Exelon’s common stock were granted through 2012 under the LTIP. The exercise price of the stock options is equal to the fair market value of the underlying stock on the date of option grant. Stock options will expire no later than ten years from the date of grant.

There were no stock options granted during the year ended December 31, 2023. All stock options were vested and exercised as of December 31, 2022.

The following table summarizes additional information regarding stock options exercised:

			Year Ended December 31,
			2023						2022						2021
Intrinsic value (a)			$	—					$	—					$	11
Cash received for exercise price			—						1						37

__________

(a) The difference between the market value on the date of exercise and the option exercise price.

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The following table presents changes in Exelon's AOCI, net of tax, by component:

			Cash Flow Hedges												Pension and Non-Pension Postretirement Benefit Plan Items (a)						Foreign Currency Items												Total
Balance at December 31, 2020			$	( 5 )											$	( 3,372 )					$	( 23 )											$	( 3,400 )
OCI before reclassifications			( 1 )												432						—												431
Amounts reclassified from AOCI			—												219						—												219
Net current-period OCI			$	( 1 )											$	651					$	—											$	650
Balance at December 31, 2021			$	( 6 )											$	( 2,721 )					$	( 23 )											$	( 2,750 )
Separation of Constellation			6												1,994						23												2,023
OCI before reclassifications			2												46						—												48
Amounts reclassified from AOCI			—												41						—												41
Net current-period OCI			$	2											$	87					$	—											$	89
Balance at December 31, 2022			$	2											$	( 640 )					$	—											$	( 638 )
OCI before reclassifications			( 4 )												( 109 )						—												( 113 )
Amounts reclassified from AOCI			( 1 )												26						—												25
Net current-period OCI			$	( 5 )											$	( 83 )					$	—											$	( 88 )
Balance at December 31, 2023			$	( 3 )											$	( 723 )					$	—											$	( 726 )

__________

(a) This AOCI component is included in the computation of net periodic pension and OPEB cost. Additionally, as of February 1, 2022, in connection with the separation, Exelon's pension and OPEB plans were remeasured. See Note 14 — Retirement Benefits for additional information. See Exelon's Statements of Operations and Comprehensive Income for individual components of AOCI.

The following table presents income tax benefit (expense) allocated to each component of Exelon's Other comprehensive income (loss):

			For the Years Ended December 31,
			2023						2022						2021
Pension and non-pension postretirement benefit plans:
Prior service benefits reclassified to periodic benefit cost			$	—					$	—					$	4
Actuarial losses reclassified to periodic benefit cost			( 8 )						( 14 )						( 76 )
Pension and non-pension postretirement benefit plans valuation adjustments			33						( 14 )						( 153 )
Unrealized gains on cash flow hedges			2						—						—

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Supplemental Statement of Operations Information

The following tables provide additional information about material items recorded in the Registrants' Consolidated Statements of Operations and Comprehensive Income.

			Taxes other than income taxes
			Exelon						ComEd						PECO						BGE						PHI						Pepco						DPL						ACE
For the Year Ended December 31, 2023
Utility (a)			$	875					$	299					$	166					$	97					$	313					$	283					$	26					$	4
Property			401						33						16						205						147						101						44						2
Payroll			124						31						17						18						27						6						5						3
For the Year Ended December 31, 2022
Utility (a)			$	878					$	306					$	166					$	94					$	312					$	283					$	25					$	4
Property			377						31						17						191						138						94						42						2
Payroll			117						28						16						17						25						6						4						3
For the Year Ended December 31, 2021
Utility (a)			$	774					$	246					$	139					$	88					$	301					$	278					$	22					$	3
Property			364						39						18						176						131						88						40						3
Payroll			124						27						16						18						27						7						5						3

__________

(a) The Registrants’ utility taxes represents municipal and state utility taxes and gross receipts taxes related to their operating revenues. The offsetting collection of utility taxes from customers is recorded in revenues in the Registrants’ Consolidated Statements of Operations and Comprehensive Income.

			Other, net
			Exelon						ComEd						PECO						BGE						PHI						Pepco						DPL						ACE
For the Year Ended December 31, 2023
AFUDC—Equity			$	151					$	33					$	31					$	16					$	71					$	54					$	10					$	7
Non-service net periodic benefit cost			( 18 )						—						—						—						—						—						—						—
For the Year Ended December 31, 2022
AFUDC—Equity			$	150					$	35					$	31					$	21					$	63					$	48					$	7					$	8
Non-service net periodic benefit cost			63						—						—						—						—						—						—						—
For the Year Ended December 31, 2021
AFUDC—Equity			$	136					$	34					$	26					$	27					$	49					$	40					$	6					$	3
Non-service net periodic benefit cost			91						—						—						—						—						—						—						—

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Supplemental Cash Flow Information

The following tables provide additional information about material items recorded in the Registrants' Consolidated Statements of Cash Flows.

			Depreciation, amortization, and accretion
			Exelon (a)						ComEd						PECO						BGE						PHI						Pepco						DPL						ACE
For the Year Ended December 31, 2023
Property, plant, and equipment (b)			$	2,778					$	1,095					$	383					$	509					$	737					$	311					$	208					$	195
Amortization of regulatory assets (b)			720						308						14						145						253						130						36						88
Amortization of intangible assets, net (b)			8						—						—						—						—						—						—						—
Total depreciation and amortization			$	3,506					$	1,403					$	397					$	654					$	990					$	441					$	244					$	283
For the Year Ended December 31, 2022
Property, plant, and equipment (b)			$	2,690					$	1,031					$	359					$	476					$	680					$	288					$	191					$	173
Amortization of regulatory assets (b)			718						292						14						154						258						129						41						88
Amortization of intangible assets, net (b)			12						—						—						—						—						—						—						—
Amortization of energy contract assets and liabilities (c)			3						—						—						—						—						—						—						—
Nuclear fuel (d)			66						—						—						—						—						—						—						—
ARO accretion (e)			44						—						—						—						—						—						—						—
Total depreciation, amortization, and accretion			$	3,533					$	1,323					$	373					$	630					$	938					$	417					$	232					$	261
For the Year Ended December 31, 2021
Property, plant, and equipment (b)			$	5,384					$	970					$	336					$	439					$	627					$	274					$	169					$	155
Amortization of regulatory assets (b)			594						235						12						152						194						129						41						24
Amortization of intangible assets, net (b)			58						—						—						—						—						—						—						—
Amortization of energy contract assets and liabilities (c)			31						—						—						—						—						—						—						—
Nuclear fuel (d)			992						—						—						—						—						—						—						—
ARO accretion (e)			514						—						—						—						—						—						—						—
Total depreciation, amortization, and accretion			$	7,573					$	1,205					$	348					$	591					$	821					$	403					$	210					$	179

__________

(a) Exelon's 2022 and 2021 amounts include amounts related to Generation prior to the separation. See Note 2 — Discontinued Operations for additional information.

(b) Included in Depreciation and amortization in the Registrants' Consolidated Statements of Operations and Comprehensive Income.

(c) Included in Electric operating revenues or Purchased power expense in Exelon’s Consolidated Statements of Operations and Comprehensive Income.

(d) Included in Purchased fuel expense in Exelon’s Consolidated Statements of Operations and Comprehensive Income.

(e) Included in Operating and maintenance expense in Exelon's Consolidated Statements of Operations and Comprehensive Income.

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			Cash paid (refunded) during the year
			Exelon (a)						ComEd						PECO						BGE						PHI						Pepco						DPL						ACE
For the Year Ended December 31, 2023
Interest (net of amount capitalized)			$	1,616					$	441					$	200					$	171					$	301					$	153					$	69					$	68
Income taxes (net of refunds)			10						11						( 24 )						29						21						6						6						9
For the Year Ended December 31, 2022
Interest (net of amount capitalized)			$	1,434					$	396					$	166					$	147					$	274					$	141					$	63					$	60
Income taxes (net of refunds)			73						23						31						16						19						28						( 2 )						( 6 )
For the Year Ended December 31, 2021
Interest (net of amount capitalized)			$	1,505					$	372					$	152					$	134					$	255					$	132					$	59					$	56
Income taxes (net of refunds)			281						( 72 )						( 4 )						( 38 )						—						12						( 9 )						2

__________

(a) Exelon's 2022 and 2021 amounts include amounts related to Generation prior to the separation. See Note 2 — Discontinued Operations for additional information.

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			Other non-cash operating activities
			Exelon (a)						ComEd						PECO						BGE						PHI						Pepco						DPL						ACE
For the Year Ended December 31, 2023
Pension and OPEB costs (benefit)			$	198					$	26					$	( 14 )					$	56					$	99					$	34					$	18					$	13
Allowance for credit losses			125						4						45						16						60						33						10						17
True-up adjustments to decoupling mechanisms and formula rates (b)			( 708 )						( 556 )						7						( 84 )						( 77 )						( 22 )						( 21 )						( 34 )
Amortization of operating ROU asset			39						2						—						5						28						6						8						3
Change in environmental liabilities			37						—						—						—						37						37						—						—
AFUDC - Equity			( 151 )						( 33 )						( 31 )						( 16 )						( 71 )						( 54 )						( 10 )						( 7 )
For the Year Ended December 31, 2022
Pension and OPEB costs (benefit)			$	164					$	60					$	( 9 )					$	44					$	53					$	9					$	3					$	12
Allowance for credit losses			173						46						45						25						58						29						12						16
Other decommissioning-related activity			36						—						—						—						—						—						—						—
Energy-related options			60						—						—						—						—						—						—						—
True-up adjustments to decoupling mechanisms and formula rates (b)			( 168 )						( 267 )						( 2 )						47						54						31						7						16
Long-term incentive plan			42						—						—						—						—						—						—						—
Amortization of operating ROU asset			56						2						—						14						27						7						8						3
AFUDC - Equity			( 150 )						( 35 )						( 31 )						( 21 )						( 63 )						( 48 )						( 7 )						( 8 )
For the Year Ended December 31, 2021
Pension and OPEB costs			$	411					$	129					$	8					$	61					$	49					$	6					$	2					$	11
Allowance for credit losses			160						47						39						17						24						9						5						10
Other decommissioning-related activity			( 946 )						—						—						—						—						—						—						—
Energy-related options			125						—						—						—						—						—						—						—
True-up adjustments to decoupling mechanisms and formula rates (b)			( 171 )						( 42 )						( 26 )						( 12 )						( 91 )						( 53 )						( 14 )						( 24 )
Severance costs			( 57 )						2						—						—						1						—						—						—
Long-term incentive plan			137						—						—						—						—						—						—						—
Amortization of operating ROU Asset			183						1						—						29						28						6						8						4
AFUDC - Equity			( 136 )						( 34 )						( 26 )						( 27 )						( 49 )						( 40 )						( 6 )						( 3 )

__________

(a) Exelon's 2022 and 2021 amounts include amounts related to Generation prior to the separation. See Note 2 — Discontinued Operations for additional information.

(b) For ComEd, reflects the true-up adjustments in Regulatory assets and liabilities associated with its distribution, energy efficiency, distributed generation, and transmission formula rates. For PECO, reflects the change in Regulatory assets and liabilities associated with its transmission formula rate. For BGE, Pepco, DPL, and ACE, reflects the change in Regulatory assets and liabilities associated with their decoupling mechanisms and transmission formula rates. See Note 3 — Regulatory Matters for additional information.

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The following tables provide a reconciliation of cash, restricted cash, and cash equivalents reported within the Registrants' Consolidated Balance Sheets that sum to the total of the same amounts in their Consolidated Statements of Cash Flows.

			Cash, restricted cash, and cash equivalents
			Exelon						ComEd						PECO						BGE						PHI						Pepco						DPL						ACE
Balance at December 31, 2023
Cash and cash equivalents			$	445					$	110					$	42					$	47					$	180					$	48					$	16					$	21
Restricted cash and cash equivalents			482						402						9						1						24						24						—						—
Restricted cash included in Other deferred debits and other assets			174						174						—						—						—						—						—						—
Total cash, restricted cash, and cash equivalents			$	1,101					$	686					$	51					$	48					$	204					$	72					$	16					$	21
Balance at December 31, 2022
Cash and cash equivalents			$	407					$	67					$	59					$	43					$	198					$	45					$	31					$	72
Restricted cash and cash equivalents			566						327						9						24						175						54						121						—
Restricted cash included in Other deferred debits and other assets			117						117						—						—						—						—						—						—
Total cash, restricted cash, and cash equivalents			$	1,090					$	511					$	68					$	67					$	373					$	99					$	152					$	72
Balance at December 31, 2021
Cash and cash equivalents			$	672					$	131					$	36					$	51					$	136					$	34					$	28					$	29
Restricted cash and cash equivalents			321						210						8						4						77						34						43						—
Restricted cash included in Other deferred debits and other assets			44						43						—						—						—						—						—						—
Cash, restricted cash, and cash equivalents included in current assets of discontinued operations			582						—						—						—						—						—						—						—
Total cash, restricted cash, and cash equivalents			$	1,619					$	384					$	44					$	55					$	213					$	68					$	71					$	29
Balance at December 31, 2020
Cash and cash equivalents			$	432					$	83					$	19					$	144					$	111					$	30					$	15					$	17
Restricted cash and cash equivalents			349						279						7						1						39						35						—						3
Restricted cash included in Other deferred debits and other assets			53						43						—						—						10						—						—						10
Cash, restricted cash, and cash equivalents included in current assets of discontinued operations			332						—						—						—						—						—						—						—
Total cash, restricted cash, and cash equivalents			$	1,166					$	405					$	26					$	145					$	160					$	65					$	15					$	30

For additional information on restricted cash, see Note 1 — Significant Accounting Policies.

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Supplemental Balance Sheet Information

The following tables provide additional information about material items recorded in the Registrants' Consolidated Balance Sheets.

			Investments
			Exelon						ComEd						PECO						BGE						PHI						Pepco
Balance at December 31, 2023
Rabbi trust investments (a)			$	231					$	—					$	28					$	9					$	142					$	124
Equity method investments			15						6						7						—						1						—
Other investments			5						—						—						—						—						—
Total investments			$	251					$	6					$	35					$	9					$	143					$	124
Balance at December 31, 2022
Rabbi trust investments (a)			$	216					$	—					$	22					$	7					$	138					$	119
Equity method investments			$	16					$	6					$	8					$	—					$	—					$	—
Total investments			$	232					$	6					$	30					$	7					$	138					$	119

__________

(a) The Registrants’ debt and equity security investments and life insurance contracts are recorded at fair market value.

			Accrued expenses
			Exelon						ComEd						PECO						BGE						PHI						Pepco						DPL						ACE
Balance at December 31, 2023
Compensation-related accruals (a)			$	661					$	206					$	87					$	81					$	107					$	27					$	17					$	12
Taxes accrued			221						204						96						75						137						116						30						10
Interest accrued			414						148						49						44						72						38						13						15
Balance at December 31, 2022
Compensation-related accruals (a)			$	613					$	179					$	81					$	79					$	104					$	29					$	20					$	16
Taxes accrued			211						92						10						34						70						52						8						12
Interest accrued			338						124						47						42						61						32						9						14

__________

(a) Primarily includes accrued payroll, bonuses and other incentives, vacation, and benefits.

Utility Registrants' expense with Generation

The Utility Registrants incurred expenses from transactions with the Generation affiliate as described in the footnotes to the table below prior to separation on February 1, 2022. Such expenses were primarily recorded as Purchased power from affiliates and an immaterial amount recorded as Operating and maintenance expense from affiliates at the Utility Registrants:

			At December 31,
						2022						2021
ComEd (a)						$	59					$	376
PECO (b)						33						196
BGE (c)						18						236
PHI						51						366
Pepco (d)						39						270
DPL (e)						10						79
ACE (f)						2						17

__________

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(a) ComEd had an ICC-approved RFP contract with Generation to provide a portion of ComEd’s electric supply requirements. ComEd also purchased RECs and ZECs from Generation.

(b) PECO received electric supply from Generation under contracts executed through PECO’s competitive procurement process. In addition, PECO had a ten-year agreement with Generation to sell solar AECs.

(c) BGE received a portion of its energy requirements from Generation under its MDPSC-approved market-based SOS and gas commodity programs.

(d) Pepco received electric supply from Generation under contracts executed through Pepco's competitive procurement process approved by the MDPSC and DCPSC.

(e) DPL received a portion of its energy requirements from Generation under its MDPSC and DEPSC approved market-based SOS commodity programs.

(f) ACE received electric supply from Generation under contracts executed through ACE's competitive procurement process approved by the NJBPU.

Service Company Costs for Corporate Support

The Registrants receive a variety of corporate support services from BSC. Pepco, DPL, and ACE also receive corporate support services from PHISCO. See Note 1 — Significant Accounting Policies for additional information regarding BSC and PHISCO.

The following table presents the service company costs allocated to the Registrants:

						Operating and maintenance from affiliates																		Capitalized costs
						For the years ended December 31,																		For the years ended December 31,
						2023						2022						2021						2023						2022						2021
Exelon
BSC																								$	670					$	707					$	508
PHISCO																								96						80						72
ComEd
BSC						$	353					$	316					$	304					307						311						207
PECO
BSC						213						197						169						120						115						81
BGE
BSC						221						204						189						90						122						92
PHI
BSC						177						188						168						153						159						128
PHISCO						—						—						—						95						80						72
Pepco
BSC						114						110						96						59						60						50
PHISCO						122						112						114						39						33						31
DPL
BSC						73						71						61						43						45						43
PHISCO						98						96						99						29						26						22
ACE
BSC						59						57						53						47						54						33
PHISCO						92						84						86						26						21						19

Current Receivables from/Payables to affiliates

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The following tables present current Receivables from affiliates and current Payables to affiliates:

December 31, 2023

						Receivables from affiliates:
Payables to affiliates:						ComEd						PECO						BGE												Pepco						DPL						ACE						BSC						PHISCO						Other						Total
ComEd												$	—					$	—											$	—					$	—					$	—					$	64					$	—					$	8					$	72
PECO						$	—											—												—						—						—						36						—						3						39
BGE						—						—																		—						—						—						33						—						2						35
PHI						—						—						—												—						—						—						5						—						10						15
Pepco						—						—						—																		—						—						17						14						1						32
DPL						—						1						—												—												—						12						11						1						25
ACE						—						1						—												1						1												11						11						—						25
Other						3						—						—												1						—						3						1						—												8
Total						$	3					$	2					$	—											$	2					$	1					$	3					$	179					$	36					$	25					$	251

December 31, 2022

						Receivables from affiliates:
Payables to affiliates:						ComEd						PECO						BGE												Pepco						DPL						ACE						BSC						PHISCO						Other						Total
ComEd												$	—					$	—											$	—					$	—					$	—					$	66					$	—					$	8					$	74
PECO						$	—											—												—						—						—						39						—						3						42
BGE						—						—																		—						—						—						38						—						1						39
PHI						—						—						—												—						—						—						4						—						10						14
Pepco						—						—						—																		—						—						20						13						1						34
DPL						—						2						—												—												—						12						8						—						22
ACE						—						2						—												—						—												14						9						1						26
Other						3						—						—												—						—						1						—						—												4
Total						$	3					$	4					$	—											$	—					$	—					$	1					$	193					$	30					$	24					$	255

Borrowings from Exelon/PHI intercompany money pool

To provide an additional short-term borrowing option that will generally be more favorable to the borrowing participants than the cost of external financing both Exelon and PHI operate an intercompany money pool. PECO and PHI Corporate participate in the Exelon money pool. Pepco, DPL, and ACE participate in the PHI intercompany money pool.

Long-term Debt to Financing Trusts

The following table presents Long-term debt to financing trusts:

			At December 31,
			2023																		2022
			Exelon						ComEd						PECO						Exelon						ComEd						PECO
ComEd Financing III			$	206					$	205					$	—					$	206					$	205					$	—
PECO Trust III			81						—						81						81						—						81
PECO Trust IV			103						—						103						103						—						103
Total			$	390					$	205					$	184					$	390					$	205					$	184

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Exelon Corporation and Subsidiary Companies

Schedule I – Condensed Financial Information of Parent (Exelon Corporate)

Condensed Statements of Operations and Other Comprehensive Income

			For the Years Ended December 31,
(In millions)			2023						2022						2021
Operating expenses
Operating and maintenance			$	88					$	25					$	( 9 )
Operating and maintenance from affiliates			7						4						14
Other			1						2						2
Total operating expenses			96						31						7
Operating loss			( 96 )						( 31 )						( 7 )
Other income and (deductions)
Interest expense, net			( 544 )						( 413 )						( 333 )
Equity in earnings of investments			2,728						2,450						1,908
Interest income from affiliates, net			9						5						—
Other, net			19						22						—
Total other income and (deductions)			2,212						2,064						1,575
Income from continuing operations before income taxes			2,116						2,033						1,568
Income taxes			( 212 )						( 21 )						( 48 )
Net income from continuing operations after income taxes			2,328						2,054						1,616
Net income from discontinued operations after income taxes			—						116						90
Net income			$	2,328					$	2,170					$	1,706
Other comprehensive income (loss), net of income taxes
Pension and non-pension postretirement benefit plans:
Prior service benefits reclassified to periodic benefit cost			—						( 1 )						( 4 )
Actuarial losses reclassified to periodic benefit cost			26						42						223
Pension and non-pension postretirement benefit plans valuation adjustments			( 109 )						46						431
Unrealized (loss) gain on cash flow hedges			( 5 )						2						—
Other comprehensive (loss) income			( 88 )						89						650
Comprehensive income			$	2,240					$	2,259					$	2,356

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Exelon Corporation and Subsidiary Companies

Schedule I – Condensed Financial Information of Parent (Exelon Corporate)

Condensed Statements of Cash Flows

			For the Years Ended December 31,
(In millions)			2023						2022						2021
Net cash flows provided by operating activities			$	1,486					$	1,690					$	3,629
Cash flows from investing activities
Changes in Exelon intercompany money pool			( 43 )						35						381
Notes receivable from affiliates			—						274						—
Investment in affiliates			( 1,864 )						( 4,011 )						( 2,231 )
Other investing activities			( 1 )						—						1
Net cash flows used in investing activities			( 1,908 )						( 3,702 )						( 1,849 )
Cash flows from financing activities
Changes in short-term borrowings			78						448						—
Proceeds from short-term borrowings with maturities greater than 90 days			—						1,150						500
Repayments on short-term borrowings with maturities greater than 90 days			—						( 1,300 )						( 350 )
Issuance of long-term debt			2,500						3,350						—
Retirement of long-term debt			( 850 )						( 1,150 )						( 300 )
Issuance of common stock			140						563						—
Dividends paid on common stock			( 1,433 )						( 1,334 )						( 1,497 )
Proceeds from employee stock plans			41						36						80
Other financing activities			( 39 )						( 35 )						19
Net cash flows provided by (used in) financing activities			437						1,728						( 1,548 )
Increase (decrease) in cash, restricted cash, and cash equivalents			15						( 284 )						232
Cash, restricted cash, and cash equivalents at beginning of period			11						295						63
Cash, restricted cash, and cash equivalents at end of period			$	26					$	11					$	295

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Exelon Corporation and Subsidiary Companies

Schedule I – Condensed Financial Information of Parent (Exelon Corporate)

Condensed Balance Sheets

			December 31,
(In millions)			2023						2022
ASSETS
Current assets
Cash and cash equivalents			$	26					$	11
Accounts receivable, net
Other accounts receivable			561						358
Accounts receivable from affiliates			14						17
Notes receivable from affiliates			225						182
Regulatory assets			188						154
Other			17						6
Total current assets			1,031						728
Property, plant, and equipment, net			44						44
Deferred debits and other assets
Regulatory assets			2,877						2,650
Investments in affiliates from continuing operations			38,545						35,925
Deferred income taxes			884						929
Non-pension postretirement benefit asset			144						187
Other			107						115
Total deferred debits and other assets			42,557						39,806
Total assets			$	43,632					$	40,578

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Exelon Corporation and Subsidiary Companies

Schedule I – Condensed Financial Information of Parent (Exelon Corporate)

Condensed Balance Sheets

			December 31,
(In millions)			2023						2022
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities
Short-term borrowings			$	1,026					$	948
Long-term debt due within one year			500						850
Accounts payable			194						188
Accrued expenses			144						101
Payables to affiliates			361						360
Regulatory liabilities			10						12
Pension obligations			45						77
Other			49						7
Total current liabilities			2,329						2,543
Long-term debt			10,713						8,742
Deferred credits and other liabilities
Regulatory liabilities			92						103
Pension obligations			4,268						3,896
Deferred income taxes			56						53
Other			419						497
Total deferred credits and other liabilities			4,835						4,549
Total liabilities			17,877						15,834
Commitments and contingencies
Shareholders’ equity
Common stock ( No par value, 2,000 shares authorized, 999 shares and 994 shares outstanding as of December 31, 2023 and 2022, respectively)			21,114						20,908
Treasury stock, at cost ( 2 shares as of December 31, 2023 and 2022)			( 123 )						( 123 )
Retained earnings			5,490						4,597
Accumulated other comprehensive loss, net			( 726 )						( 638 )
Total shareholders’ equity			25,755						24,744
Total liabilities and shareholders’ equity			$	43,632					$	40,578

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Exelon Corporation and Subsidiary Companies

Schedule I – Condensed Financial Information of Parent (Exelon Corporate)

Notes to Financial Statements

Exelon Corporate is a holding company that conducts substantially all of its business operations through its subsidiaries. These condensed financial statements and related footnotes have been prepared in accordance with Rule 12-04, Schedule I of Regulation S-X. These statements should be read in conjunction with the consolidated financial statements, and notes thereto, of Exelon Corporation.

As of December 31, 2023 and 2022, Exelon Corporate owned 100 % of all of its significant subsidiaries, either directly or indirectly, except for Commonwealth Edison Company (ComEd), of which Exelon Corporate owns more than 99 %. As of February 1, 2022, as a result of the completion of the separation, Exelon Corporate no longer retains any equity ownership interest in Generation or Constellation. The separation of Constellation, including Generation and its subsidiaries, met the criteria for discontinued operations and as such, results of operations are presented as discontinued operations and have been excluded from continuing operations for all periods presented. Accounting rules require 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. Comprehensive income and cash flows related to Generation have not been segregated and are included in the Condensed Statements of Operations and Comprehensive Income and Condensed Statements of Cash Flows, respectively, for all periods presented. See Note 2 — Discontinued Operations of the Combined Notes to Consolidated Financial Statements for additional information.

See Note 14—Retirement Benefits of the Combined Notes to Consolidated Financial Statements for Exelon Corporate’s retirement benefits.

See Note 15—Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for Exelon Corporate’s derivatives.

Short-Term Borrowings

Exelon Corporate meets its short-term liquidity requirements primarily through the issuance of commercial paper. Exelon Corporate had $ 527 million in outstanding commercial paper borrowings as of December 31, 2023 and $ 449 million outstanding commercial paper as of December 31, 2022.

Revolving Credit Agreements

As of December 31, 2023, Exelon Corporation had a $ 900 million aggregate bank commitment under its existing syndicated revolving facility in which $ 370 million was available to support additional commercial paper as of December 31, 2023. See Note 16 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information regarding Exelon Corporate’s credit agreement.

On February 1, 2022, Exelon Corporate entered into a new 5-year revolving credit facility with an aggregate bank commitment of $ 900 million at a variable interest rate of SOFR plus 1.275 % which replaced its existing $ 600 million syndicated revolving credit facility.

Exelon Corporate had no outstanding amounts on the revolving credit facilities as of December 31, 2023.

Short-Term Loan Agreements

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On March 23, 2017, Exelon Corporate entered into a term loan agreement for $ 500 million. The loan agreement was renewed in the first quarter of 2023 and was bifurcated into two tranches of $ 300 million on March 14, 2023 and $ 200 million on March 24, 2023. The agreements will expire on March 14, 2024 and March 22, 2024, respectively. Pursuant to the loan agreements, loans made thereunder bear interest at a variable rate equal to SOFR plus 0.90 % and all indebtedness thereunder is unsecured. The loan agreement is reflected in Exelon's Consolidated Balance Sheets within Short-term borrowings.

Long-Term Debt

The following tables present the outstanding long-term debt for Exelon Corporate at December 31, 2023 and December 31, 2022:

															Maturity Date						December 31,
			Rates																		2023						2022
Long-term debt
Senior unsecured notes (a)			2.75		%	-			7.60		%				2025 - 2053						$	10,639					$	8,139
Loan agreement (c)									6.23		%				2024						500						1,350
Total long-term debt																					11,139						9,489
Unamortized debt discount and premium, net																					( 13 )						( 10 )
Unamortized debt issuance costs																					( 65 )						( 51 )
Fair value adjustment																					152						164
Long-term debt due within one year (b)																					( 500 )						( 850 )
Long-term debt																					$	10,713					$	8,742

__________

(a) Senior unsecured notes included mirror debt that was held on Exelon Corporation's Balance Sheet in 2021. In connection with the separation, on January 31, 2022, Exelon Corporate received cash from Generation of $ 258 million to settle the intercompany loan. See Note 16 — Debt and Credit Agreements for additional information on the merger debt.

(b) In connection with the separation, Exelon Corporate entered into three 18-month term loan agreements. On January 21, 2022, two of the loan agreements were issued for $ 300 million each with an expiration date of July 21, 2023. On January 24, 2022, the third loan agreement was issued for $ 250 million with an expiration date of July 24, 2023. Pursuant to the loan agreement, loans made thereunder bear interest at a variable rate equal to SOFR plus 0.65 %.

(c) Pursuant to the loan agreement, loans made thereunder bear interest at a variable rate equal to SOFR plus 0.85 %.

The long-term debt maturities for Exelon Corporate for the periods 2024 through 2028 and thereafter are as follows:

2024			$	500
2025			807
2026			750
2027			650
2028			1,000
Thereafter			7,432
Total long-term debt			$	11,139

See Note 18—Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for Exelon Corporate’s commitments and contingencies.

The financial statements of Exelon Corporate include related party transactions as presented in the tables below:

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			For the Years Ended December 31,
(In millions)			2023						2022						2021
Operating and maintenance from affiliates:
BSC (a)			$	7					$	4					$	14
Total operating and maintenance from affiliates:			$	7					$	4					$	14
Interest income (expense) from affiliates, net:
BSC			$	6					$	4					$	—
EEDC (b)			3						1						—
Total interest income from affiliates, net:			$	9					$	5					$	—
Equity in earnings (losses) of investments:
BSC			$	—					$	( 18 )					$	( 301 )
EEDC (b)			2,727						2,482						2,215
PCI			2						( 9 )						( 1 )
Exelon Enterprises			1						—						—
Exelon InQB8R			( 2 )						( 4 )						( 7 )
Other			—						( 1 )						2
Total equity in earnings of investments:			$	2,728					$	2,450					$	1,908
Cash contributions received from affiliates			$	1,978					$	2,027					$	1,842

			At December 31,
(in millions)			2023						2022
Accounts receivable from affiliates (current):
BSC			$	—					$	3
ComEd			4						4
PECO			2						2
BGE			1						1
PHISCO			7						7
Total accounts receivable from affiliates (current):			$	14					$	17
Notes receivable from affiliates (current):
BSC (a)			$	160					$	138
PHI			65						44
Total notes receivable from affiliates (current):			$	225					$	182
Investments in affiliates from continuing operations:
BSC (a)			$	384					$	384
EEDC (b)			37,705						35,092
PCI			54						52
UII			365						365
Voluntary Employee Beneficiary Association trust			9						4
Exelon Enterprises			4						3
Conectiv			12						12
Exelon InQB8R			13						15
Other (c)			( 1 )						( 2 )
Total investments in affiliates from continuing operations:			$	38,545					$	35,925
Accounts payable to affiliates (current):
UII			$	360					$	360
BSC (a)			1						—
Total accounts payable to affiliates (current):			$	361					$	360

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__________

(a) Exelon Corporate receives a variety of corporate support services from BSC, including legal, human resources, financial, information technology, and supply management services. All services are provided at cost, including applicable overhead.

(b) EEDC consists of ComEd, PECO, BGE, PHI, Pepco, DPL, and ACE.

(c) Primarily relates to elimination of affiliate transactions with Generation, primarily related to the Regulatory Agreement Units. See Note 3 — Regulatory Matters and Note 23 — Related Party Transactions of the Combined Notes to Consolidated Financial Statements for additional information.

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Exelon Corporation and Subsidiary Companies

Schedule II – Valuation and Qualifying Accounts

Column A						Column B						Column C												Column D						Column E
												Additions and adjustments
Description						Balance at Beginning of Period						Charged to Costs and Expenses						Charged to Other Accounts						Deductions						Balance at End of Period
(In millions)
For the year ended December 31, 2023
Allowance for credit losses (a)						$	409					$	171		(b)			$	20					$	201		(c)			$	399
Deferred tax valuation allowance						94						—						20						—						114
For the year ended December 31, 2022
Allowance for credit losses (a)						$	392					$	174		(b)			$	28					$	185		(c)			$	409
Deferred tax valuation allowance						37						—						57						—						94
For the year ended December 31, 2021
Allowance for credit losses (a)						$	405					$	107		(b)			$	—					$	120		(c)			$	392
Deferred tax valuation allowance						4						—						33			(d)			—						37

__________

(a) Excludes the noncurrent Allowance for credit losses related to PECO’s installment plan receivables of $ 6 million, $ 7 million, and $ 14 million for the years ended December 31, 2023, 2022, and 2021, respectively.

(b) The amount charged to costs and expenses includes the amount reclassified to Regulatory assets/liabilities under different mechanisms applicable to the different jurisdictions in which the Utility Registrants operate.

(c) Primarily reflects write-offs, net of recoveries, of individual accounts receivable.

(d) DPL recorded a full valuation allowance against Delaware net operating losses carryforwards due to a change in Delaware tax law. See Note 13 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information on the valuation allowance.

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Commonwealth Edison Company and Subsidiary Companies

(2) ComEd

(i)						Financial Statements (Item 8):
						Report of Independent Registered Public Accounting Firm dated February 21, 2024 of PricewaterhouseCoopers LLP (PCAOB ID 238)
						Consolidated Statements of Operations and Comprehensive Income for the Years Ended December 31, 2023, 2022, and 2021
						Consolidated Statements of Cash Flows for the Years Ended December 31, 2023, 2022, and 2021
						Consolidated Balance Sheets at December 31, 2023 and 2022
						Consolidated Statements of Changes in Shareholders’ Equity for the Years Ended December 31, 2023, 2022, and 2021
						Notes to Consolidated Financial Statements
(ii)						Financial Statement Schedule:
						Schedule II—Valuation and Qualifying Accounts for the Years Ended December 31, 2023, 2022, and 2021
						Schedules not included are omitted because of the absence of conditions under which they are required or because the required information is provided in the consolidated financial statements, including the notes thereto

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Commonwealth Edison Company and Subsidiary Companies

Schedule II – Valuation and Qualifying Accounts

Column A						Column B						Column C												Column D						Column E
												Additions and adjustments
Description						Balance at Beginning of Period						Charged to Costs and Expenses						Charged to Other Accounts						Deductions						Balance at End of Period
(In millions)
For the year ended December 31, 2023
Allowance for credit losses						$	76					$	45		(a)			$	13					$	48		(b)			$	86
For the year ended December 31, 2022
Allowance for credit losses						$	90					$	24		(a)			$	8					$	46		(b)			$	76
For the year ended December 31, 2021
Allowance for credit losses						$	118					$	18		(a)			$	1					$	47		(b)			$	90

__________

(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 amount charged to costs and expenses includes the amount that was reclassified to Regulatory assets/liabilities under such mechanism. See Note 3 – Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.

(b) Write-offs, net of recoveries of individual accounts receivable.

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PECO Energy Company and Subsidiary Companies

(3) PECO

(i)						Financial Statements (Item 8):
						Report of Independent Registered Public Accounting Firm dated February 21, 2024 of PricewaterhouseCoopers LLP (PCAOB ID 238)
						Consolidated Statements of Operations and Comprehensive Income for the Years Ended December 31, 2023, 2022, and 2021
						Consolidated Statements of Cash Flows for the Years Ended December 31, 2023, 2022, and 2021
						Consolidated Balance Sheets at December 31, 2023 and 2022
						Consolidated Statements of Changes in Shareholder's Equity for the Years Ended December 31, 2023, 2022, and 2021
						Notes to Consolidated Financial Statements
(ii)						Financial Statement Schedule:
						Schedule II—Valuation and Qualifying Accounts for the Years Ended December 31, 2023, 2022, and 2021
						Schedules not included are omitted because of the absence of conditions under which they are required or because the required information is provided in the consolidated financial statements, including the notes thereto

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PECO Energy Company and Subsidiary Companies

Schedule II – Valuation and Qualifying Accounts

Column A						Column B						Column C												Column D						Column E
												Additions and adjustments
Description						Balance at Beginning of Period						Charged to Costs and Expenses						Charged to Other Accounts						Deductions						Balance at End of Period
(In millions)
For the year ended December 31, 2023
Allowance for credit losses (a)						$	114					$	43		(b)			$	9					$	63		(c)			$	103
Deferred tax valuation allowance						7						—						—						—						7
For the year ended December 31, 2022
Allowance for credit losses (a)						$	112					$	44		(b)			$	14					$	56		(c)			$	114
Deferred tax valuation allowance						3						—						4						—						7
For the year ended December 31, 2021
Allowance for credit losses (a)						$	124					$	32		(b)			$	( 6 )					$	38		(c)			$	112
Deferred tax valuation allowance						1						—						2						—						3

__________

(a) Excludes the noncurrent Allowance for credit losses related to PECO’s installment plan receivables of $ 6 million, $ 7 million, and $ 14 million for the years ended December 31, 2023, 2022, and 2021, respectively.

(b) The amount charged to costs and expenses includes the amount that was reclassified to the COVID-19 regulatory asset. See Note 3 – Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.

(c) Write-offs, net of recoveries of individual accounts receivable.

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Baltimore Gas and Electric Company

(4) BGE

(i)						Financial Statements (Item 8):
						Report of Independent Registered Public Accounting Firm dated February 21, 2024 of PricewaterhouseCoopers LLP (PCAOB ID 238)
						Statements of Operations and Comprehensive Income for the Years Ended December 31, 2023, 2022 and 2021
						Statements of Cash Flows for the Years Ended December 31, 2023, 2022 and 2021
						Balance Sheets at December 31, 2023 and 2022
						Statements of Changes in Shareholder's Equity for the Years Ended December 31, 2023, 2022 and 2021
						Notes to Financial Statements
(ii)						Financial Statement Schedule:
						Schedule II—Valuation and Qualifying Accounts for the Years Ended December 31, 2023, 2022, and 2021
						Schedules not included are omitted because of the absence of conditions under which they are required or because the required information is provided in the consolidated financial statements, including the notes thereto

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Baltimore Gas and Electric Company

Schedule II – Valuation and Qualifying Accounts

Column A						Column B						Column C												Column D						Column E
												Additions and adjustments
Description						Balance at Beginning of Period						Charged to Costs and Expenses						Charged to Other Accounts						Deductions						Balance at End of Period
(In millions)
For the year ended December 31, 2023
Allowance for credit losses						$	64					$	26		(a)			$	5					$	42		(b)			$	53
Deferred tax valuation allowance						3						—						—						—						3
For the year ended December 31, 2022
Allowance for credit losses						$	47					$	37		(a)			$	6					$	26		(b)			$	64
Deferred tax valuation allowance						—						—						3						—						3
For the year ended December 31, 2021
Allowance for credit losses						$	44					$	16		(a)			$	3					$	16		(b)			$	47
Deferred tax valuation allowance						—						—						—						—						—

__________

(a) The amount charged to costs and expenses includes the amount that was reclassified to Regulatory assets/liabilities under different mechanisms as approved by the MDPSC.

(b) Write-offs, net of recoveries of individual accounts receivable.

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Pepco Holdings LLC and Subsidiary Companies

(5) PHI

(i)						Financial Statements (Item 8):
						Report of Independent Registered Public Accounting Firm dated February 21, 2024 of PricewaterhouseCoopers LLP (PCAOB ID 238)
						Consolidated Statements of Operations and Comprehensive Income for the Years Ended December 31, 2023, 2022, and 2021
						Consolidated Statements of Cash Flows for the Years Ended December 31, 2023, 2022, and 2021
						Consolidated Balance Sheets at December 31, 2023 and 2022
						Consolidated Statements of Changes in Equity for the Years Ended December 31, 2023, 2022, and 2021
						Notes to Consolidated Financial Statements
(ii)						Financial Statement Schedule:
						Schedule II—Valuation and Qualifying Accounts for the Years Ended December 31, 2023, 2022, and 2021
						Schedules not included are omitted because of the absence of conditions under which they are required or because the required information is provided in the consolidated financial statements, including the notes thereto

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Pepco Holdings LLC and Subsidiary Companies

Schedule II – Valuation and Qualifying Accounts

Column A						Column B						Column C												Column D						Column E
												Additions and adjustments
Description						Balance at Beginning of Period						Charged to Costs and Expenses						Charged to Other Accounts						Deductions						Balance at End of Period
(In millions)
For the year ended December 31, 2023
Allowance for credit losses						$	155					$	57		(a)			$	( 7 )					$	48		(b)			$	157
Deferred tax valuation allowance						35						—						—						—						35
For the year ended December 31, 2022
Allowance for credit losses						$	143					$	69		(a)			$	—					$	57		(b)			$	155
Deferred tax valuation allowance						31						—						4						—						35
For the year ended December 31, 2021
Allowance for credit losses						$	119					$	41		(a)			$	2					$	19		(b)			$	143
Deferred tax valuation allowance						—						—						31			(c)			—						31

__________

(a) The amount charged to costs and expenses includes the amount that was reclassified to Regulatory assets/liabilities under different mechanisms applicable to the different jurisdictions Pepco, DPL, and ACE operate in.

(b) Write-offs, net of recoveries of individual accounts receivable.

(c) DPL recorded a full valuation allowance against Delaware net operating losses carryforwards due to a change in Delaware tax law. See Note 13 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information on the valuation allowance.

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Potomac Electric Power Company

(6) Pepco

(i)						Financial Statements (Item 8):
						Report of Independent Registered Public Accounting Firm dated February 21, 2024 of PricewaterhouseCoopers LLP (PCAOB ID 238)
						Statements of Operations and Comprehensive Income for the Years Ended December 31, 2023, 2022 and 2021
						Statements of Cash Flows for the Years Ended December 31, 2023, 2022 and 2021
						Balance Sheets at December 31, 2023 and 2022
						Statements of Changes in Shareholder's Equity for the Years Ended December 31, 2023, 2022 and 2021
						Notes to Financial Statements
(ii)						Financial Statement Schedule:
						Schedule II—Valuation and Qualifying Accounts for the Years Ended December 31, 2023, 2022, and 2021
						Schedules not included are omitted because of the absence of conditions under which they are required or because the required information is provided in the consolidated financial statements, including the notes thereto

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Potomac Electric Power Company

Schedule II – Valuation and Qualifying Accounts

Column A						Column B						Column C												Column D						Column E
												Additions and adjustments
Description						Balance at Beginning of Period						Charged to Costs and Expenses						Charged to Other Accounts						Deductions						Balance at End of Period
(In millions)
For the year ended December 31, 2023
Allowance for credit losses						$	72					$	31		(a)			$	( 5 )					$	18		(b)			$	80
For the year ended December 31, 2022
Allowance for credit losses						$	53					$	36		(a)			$	4					$	21		(b)			$	72
For the year ended December 31, 2021
Allowance for credit losses						$	45					$	14		(a)			$	2					$	8		(b)			$	53

__________

(a) The amount charged to costs and expenses includes the amount that was reclassified to Regulatory assets/liabilities under different mechanisms as approved by the DCPSC and MDPSC.

(b) Write-offs, net of recoveries of individual accounts receivable.

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Delmarva Power & Light Company

(7) DPL

(i)						Financial Statements (Item 8):
						Report of Independent Registered Public Accounting Firm dated February 21, 2024 of PricewaterhouseCoopers LLP (PCAOB ID 238)
						Statements of Operations and Comprehensive Income for the Years Ended December 31, 2023, 2022 and 2021
						Statements of Cash Flows for the Years Ended December 31, 2023, 2022 and 2021
						Balance Sheets at December 31, 2023 and 2022
						Statements of Changes in Shareholder's Equity for the Years Ended December 31, 2023, 2022 and 2021
						Notes to Financial Statements
(ii)						Financial Statement Schedule:
						Schedule II—Valuation and Qualifying Accounts for the Years Ended December 31, 2023, 2022, and 2021
						Schedules not included are omitted because of the absence of conditions under which they are required or because the required information is provided in the consolidated financial statements, including the notes thereto

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Delmarva Power & Light Company

Schedule II – Valuation and Qualifying Accounts

Column A						Column B						Column C												Column D						Column E
												Additions and adjustments
Description						Balance at Beginning of Period						Charged to Costs and Expenses						Charged to Other Accounts						Deductions						Balance at End of Period
(In millions)
For the year ended December 31, 2023
Allowance for credit losses						$	28					$	10		(a)			$	—					$	11		(b)			$	27
Deferred tax valuation allowance						32						—						—						—						32
For the year ended December 31, 2022
Allowance for credit losses						$	26					$	13		(a)			$	( 2 )					$	9		(b)			$	28
Deferred tax valuation allowance						31						—						1						—						32
For the year ended December 31, 2021
Allowance for credit losses						$	31					$	6		(a)			$	( 1 )					$	10		(b)			$	26
Deferred tax valuation allowance						—						—						31			(c)			—						31

__________

(a) The amount charged to costs and expenses includes the amount that was reclassified to Regulatory assets/liabilities under different mechanisms as approved by the DEPSC and MDPSC.

(b) Write-offs, net of recoveries of individual accounts receivable.

(c) DPL recorded a full valuation allowance against Delaware net operating losses carryforwards due to a change in Delaware tax law. See Note 13 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information on the valuation allowance.

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Atlantic City Electric Company and Subsidiary Company

(8) ACE

(i)						Financial Statements (Item 8):
						Report of Independent Registered Public Accounting Firm dated February 21, 2024 of PricewaterhouseCoopers LLP (PCAOB ID 238)
						Consolidated Statements of Operations and Comprehensive Income for the Years Ended December 31, 2023, 2022, and 2021
						Consolidated Statements of Cash Flows for the Years Ended December 31, 2023, 2022, and 2021
						Consolidated Balance Sheets at December 31, 2023 and 2022
						Consolidated Statements of Changes in Shareholder's Equity for the Years Ended December 31, 2023, 2022, and 2021
						Notes to Consolidated Financial Statements
(ii)						Financial Statement Schedule:
						Schedule II—Valuation and Qualifying Accounts for the Years Ended December 31, 2023, 2022, and 2021
						Schedules not included are omitted because of the absence of conditions under which they are required or because the required information is provided in the consolidated financial statements, including the notes thereto

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Atlantic City Electric Company and Subsidiary Company

Schedule II – Valuation and Qualifying Accounts

Column A						Column B						Column C												Column D						Column E
												Additions and adjustments
Description						Balance at Beginning of Period						Charged to Costs and Expenses						Charged to Other Accounts						Deductions						Balance at End of Period
(In millions)
For the year ended December 31, 2023
Allowance for credit losses						$	55					$	16		(a)			$	( 2 )					$	19		(b)			$	50
For the year ended December 31, 2022
Allowance for credit losses						$	64					$	20		(a)			$	( 2 )					$	27		(b)			$	55
For the year ended December 31, 2021
Allowance for credit losses						$	43					$	21		(a)			$	1					$	1		(b)			$	64

__________

(a) ACE is allowed to recover from or refund to customers the difference between its annual credit loss expense and the amounts collected in rates annually through the Societal Benefits Charge. The amount charged to costs and expenses includes the amount that was reclassified to Regulatory assets/liabilities under such mechanism. See Note 3 – Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.

(b) Write-offs, net of recoveries of individual accounts receivable.

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