10-K – 2026-02-12 – exc-20251231.htm

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 20 — 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 when the term is 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 Property, plant, 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 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 9 — 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.
158

Table of Contents
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)

Note 1 — Significant Accounting Policies

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, 2025 and 2024, the Registrants' restricted cash and cash equivalents primarily represented the following items:

Registrant 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.
PECO Proceeds from the sales of assets that were subject to PECO’s mortgage indenture.
BGE Collateral held from energy suppliers.
PHI Payment of merger commitments, collateral held from energy suppliers associated with procurement contracts, and payments of REC procurement costs to NJBPU program participants through an administrator.
Pepco Payment of merger commitments and collateral held from energy suppliers.
DPL Collateral held from energy suppliers.
ACE Payment of REC procurement costs to NJBPU program participants through an administrator.

__________
Restricted cash and cash equivalents not available to satisfy current liabilities are classified as noncurrent assets. As of December 31, 2025 and 2024, the Registrants' noncurrent restricted cash and cash equivalents primarily represented ComEd’s alternative compliance payments received from RES pursuant to FEJA and are included in other deferred debits and other assets.
See Note 14 — Debt and Credit Agreements and Note 20 — Supplemental Financial Information for additional information.
Allowance for Credit Losses on Customer 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 estimated based on historical experience, current conditions, and forward-looking risk factors. 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 2 — 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 5 — 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
159

Table of Contents
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)

Note 1 — Significant Accounting Policies

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 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 6 — Property, Plant, and Equipment, Note 7 — Jointly Owned Electric Utility Plant and Note 20 — 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 6 — 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 rate reconciliations and energy efficiency formula rate regulatory assets and the Utility Registrants' transmission formula rate regulatory assets is recorded to Operating revenues.
160

Table of Contents
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)

Note 1 — Significant Accounting Policies

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 2 — Regulatory Matters and Note 20 — 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 8 — 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. 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 systematic and rational amortization method over the term of the guarantee. See Note 16 — 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 10 — 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. 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
161

Table of Contents
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)

Note 1 — Significant Accounting Policies

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 2 — Regulatory Matters and Note 13 — 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 experiences different from those 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 12 — Retirement Benefits for additional information.
New Accounting Standards (All Registrants)
New Accounting Standards Adopted in 2025: In 2025, the Registrants adopted the following new FASB authoritative accounting guidance.
Improvements to Income Tax Disclosures (Issued December 2023). Provides additional disclosure requirements related to the effective tax rate reconciliation and income taxes paid. Under the revised guidance for the effective tax reconciliations, entities would be required to disclose: (1) eight specific categories in the effective tax rate reconciliation in both percentages and reporting currency amount, (2) additional information for reconciling items over a certain threshold, (3) explanation of individual reconciling items disclosed, and (4) provide a qualitative description of the state and local jurisdictions that contribute to the majority of the state income tax expense. For each annual period presented, the new standard requires disclosure of the year-to-date amount of income taxes paid (net of refunds received) disaggregated by federal, state, and foreign. It also requires additional disaggregated information on income taxes paid (net of refunds received) to an individual jurisdiction equal to or greater than 5% of total income taxes paid (net of refunds received). The standard is effective for annual periods beginning January 1, 2025. The Registrants' adoption of this guidance in the fourth quarter of 2025 resulted in an expanded effective tax rate reconciliation. The standard has been applied retrospectively. See Note 11 — Income Taxes for additional information.
New Accounting Standards Issued and Not Yet Adopted as of December 31, 2025: 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, 2025. 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 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.
Disaggregation of Income Statement Expenses (Issued November 2024) . Provides additional disclosure requirements related to relevant expense captions of income statement expense line items. The revised guidance requires a new tabular disclosure of disaggregated income statement expenses including a break out of (1) purchases of inventory, (2) employee compensation, (3) depreciation, (4) intangible asset amortization, (5) depreciation, depletion, and amortization recognized as part of oil and gas producing activities included in each relevant expense line item on the income statement. The tabular disaggregation should include certain amounts already required to be disclosed under GAAP elsewhere. Any remaining amounts not separately disaggregated quantitatively should include a qualitative description. Additionally, on an annual basis, the standard requires disclosure of management’s definition of selling expenses and the amount of expense. The standard is effective January 1, 2027, with early adoption permitted.
Targeted Improvements to the Accounting for Internal Use Software (Issued September 2025) . Modernizes the accounting for costs related to internal use software to align with the agile basis utilized to develop software. The revised guidance removes references to project stages, clarifies the capitalization threshold for software costs, and expands disclosure requirements for capitalized software. Cost capitalization will begin with (1) management
162

Table of Contents
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)

Note 1 — Significant Accounting Policies

authorized and committed project funding and (2) it is 'probable' to complete the project and the software will be used in its intended function. The standard is effective for annual and interim periods beginning January 1, 2028. The standard can be implemented using a prospective, retrospective, or modified retrospective transition approach with early adoption permitted.
Accounting for Government Grants (Issued December 2025) . Establishes accounting guidance for government grants received by defining (1) a grant related to an asset and (2) a grant related to income. Updates provide that a grant should not be recognized until it is probable the entity will comply with grant conditions and the grant will be received. A grant related to an asset is required to be recognized on the balance sheet either as (1) deferred income (deferred income approach) or (2) an adjustment to carrying value (cost accumulation approach). Grants related to income and grants related to assets for which the deferred income approach is elected should be recognized in earnings on a systematic basis over the periods in which an entity recognizes expenses for the costs the grant was intended to compensate. The standard is effective for annual and interim periods beginning January 1, 2029, with early adoption permitted.
163

Table of Contents
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)

Note 2 — Regulatory Matters

2.   Regulatory Matters (All Registrants)
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 2025.
Completed Distribution Base Rate Case Proceedings

Registrant/Jurisdiction Filing Date Service Requested Revenue Requirement Increase Approved Revenue Requirement Increase Approved ROE Approval Date Rate Effective Date
ComEd - Illinois January 17, 2023 Electric $ 1,487   $ 1,045   8.905 % December 19, 2024 January 1, 2024
April 26, 2024 (amended on September 11, 2024) Electric $ 624   $ 623   9.89 % October 31, 2024 January 1, 2025
PECO - Pennsylvania March 28, 2024 Electric $ 464 $ 354   N/A December 12, 2024 January 1, 2025
Natural Gas $ 111 $ 78  
BGE - Maryland February 17, 2023 Electric $ 313   $ 179   9.50 % December 14, 2023 January 1, 2024
Natural Gas $ 289   $ 229   9.45 %
Pepco - District of Columbia April 13, 2023 (amended February 27, 2024) Electric $ 186   $ 123   9.50 % November 26, 2024 January 1, 2025
Pepco - Maryland May 16, 2023 (amended February 23, 2024) Electric $ 111   $ 45   9.50 % June 10, 2024 April 1, 2024
DPL - Maryland May 19, 2022 Electric $ 38   $ 29   9.60 % December 14, 2022 January 1, 2023
DPL - Delaware December 15, 2022 (amended September 29, 2023) Electric $ 39   $ 28   9.60 % April 18, 2024 July 15, 2023
September 20, 2024 (amended September 5, 2025) Natural Gas $ 37   $ 22   9.60 % December 17, 2025 January 1, 2026
ACE - New Jersey February 15, 2023 (amended August 21, 2023) Electric $ 92   $ 45   9.60 % November 17, 2023 December 1, 2023
November 21, 2024 Electric $ 109   $ 54   9.60 % November 21, 2025 December 1, 2025

164

Table of Contents
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)

Note 2 — Regulatory Matters

Pending Distribution Base Rate Case Proceedings

Registrant/Jurisdiction Filing Date Service Requested Revenue Requirement Increase Requested ROE Expected Approval Timing
Pepco - Maryland October 14, 2025 Electric $ 133   10.50 % Third quarter of 2026
DPL - Delaware (a)
December 9, 2025 Electric $ 45   10.50 % Third quarter of 2027
__________
(a) DPL can implement interim rates on July 9, 2026, subject to refund.

ComEd Distribution Base Rate Case Proceedings
The ICC approved ComEd's four-year MRP for the period January 1, 2024 through December 31, 2027. The MRP was originally approved by the ICC on December 14, 2023 and was subsequently amended on January 10, 2024, April 18, 2024 and December 19, 2024. The December 19, 2024 order provided a total revenue requirement increase of $ 1.045 billion inclusive of rate increases of approximately $ 752  million in 2024, $ 80 million in 2025, $ 102 million in 2026, and $ 111  million in 2027.
On March 20, 2025, ComEd filed its annual revenue balancing reconciliation for 2024. This reconciliation, which is a component of revenue decoupling, reflected a revenue reduction of $ 55 million, effective January 1, 2026.
On December 18, 2025, the ICC approved ComEd's 2024 MRP Reconciliation reflecting a revenue increase of $ 243 million, including the tax benefit of NOLCs. While NOLCs are included in the MRP Reconciliation per the final order, the impacts of the NOLCs will not be reflected in the financial statements until the PLR is received from the IRS. See Note 11 — Income Taxes for additional information on NOLCs. On January 20, 2026, the Illinois Attorney General filed an Application for Rehearing of the December 18 order, which focuses solely on NOLCs. On February 5, 2026, the ICC denied the Illinois Attorney General's Application for Rehearing.
On October 31, 2024, the Delivery Reconciliation Amount for 2023 defined in Rider Delivery Service Pricing Reconciliation (Rider DSPR) was approved. Rider DSPR allows for the reconciliation of the revenue requirement in effect in the final years in which formula rates were determined and until such time as new rates were established under ComEd's approved MRP. The 2024 order reconciled the delivery service rates in effect in 2023 with the actual delivery service costs incurred in 2023. The reconciliation revenue requirement provides for a weighted average debt and equity return on distribution rate base of 7.02 %, inclusive of an allowed ROE of 9.89 %, reflecting the monthly yields on 30-year treasury bonds plus 580 basis points.
PECO Distribution Base Rate Case Proceedings
On December 12, 2024, the PAPUC issued their Opinions and Orders which approved the non-unanimous partial settlements with limited modifications for both the electric and natural gas base rate cases, and denied the Weather Normalization Adjustment requested in the natural gas base rate case.
PECO’s approved annual electric revenue requirement increase of $ 354 million is partially offset by a one-time credit of $ 64 million in 2025. In addition, the PAPUC approved the recovery of storm damage costs incurred by PECO in January 2024, up to $ 23 million, subject to review for reasonableness and prudency in PECO’s next distribution rate case.
BGE Distribution Base Rate Case Proceedings
In February 2023, BGE filed its three-year cumulative multi-year plan for January 1, 2024 through December 31, 2026 to the MDPSC, which was approved in December 2023 and went into effect on January 1, 2024. The MDSPC awarded BGE electric revenue requirement increases of $ 41 million, $ 113 million, and $ 25 million with an approved ROE of 9.50 % in 2024, 2025, and 2026, respectively, and natural gas revenue requirement increases of $ 126 million, $ 62 million, and $ 41 million with an approved ROE of 9.45 % in 2024, 2025, and 2026, respectively. The 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.
165

Table of Contents
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)

Note 2 — Regulatory Matters

The MDPSC also approved a portion of the requested 2021 and 2022 reconciliation amounts, which were recovered through separate electric and gas riders between March 2024 and February 2025. As such, the reconciliation amounts are not included in the approved revenue 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. In April 2024, BGE filed with the MDPSC its request for recovery of the 2023 reconciliation amounts of $ 79  million and $ 73  million for electric and gas, respectively, with supporting testimony and schedules. In December 2025, the MDPSC authorized BGE to recover $ 31 million and $ 46 million for electric and gas, respectively, beginning in February 2026 and extending through December 2027, in the reconciliation rider. In addition to the amounts approved in the reconciliation rider, the MDPSC provided for additional regulatory assets related to minor storms of $ 24 million (to be recovered over 5 years) and the Baltimore City conduit of $ 4 million (to be reviewed along with a cost-benefit analysis in BGE’s next rate case).
Pepco District of Columbia Distribution Base Rate Case Proceedings
On April 13, 2023, Pepco filed an electric base rate case with the DCPSC (amended February 27, 2024) requesting a total revenue requirement increase of $ 186  million and an ROE of 10.50 %. The DCPSC issued an order approving the two-year cumulative multi-year plan on November 26, 2024, which included a total revenue requirement increase of $ 123  million with an ROE of 9.50 % effective January 1, 2025 through December 31, 2026. The DCPSC awarded Pepco electric incremental revenue requirement increases of $ 99  million and $ 24  million for 2025 and 2026, respectively.
Pepco Maryland Distribution Base Rate Case Proceedings
On May 16, 2023, Pepco filed an electric base rate case with the MDPSC (amended February 23, 2024) requesting a total revenue requirement increase of $ 111  million (before offsets) and an ROE of 10.50 %. The MDPSC issued an order on June 10, 2024 awarding Pepco a one-year multi-year plan for April 1, 2024 through March 31, 2025 which included an incremental revenue requirement increase of $ 45  million and an ROE of 9.50 %. The MDPSC did not adopt the requested revenue requirement increases of $ 80  million (before offsets), $ 51  million, and $ 14  million as filed for 2025, 2026, and the 2027 nine-month extension period, respectively. The MDPSC also approved the requested reconciliation amounts for the 12-month periods ending March 31, 2022, and March 31, 2023, which will be recovered through a rider between August 2024 through March 2026. As such, the reconciliation amounts are not included in the approved revenue requirement increases. The reconciliation amounts are $ 1  million and $ 7  million, for the 12-month periods ending March 31, 2022, and March 31, 2023, respectively. In July 2024, Pepco filed its request with the MDPSC, for which it is awaiting approval, for recovery of the reconciliation amounts of $ 31  million for the 12-month period ended March 31, 2024, with supporting testimony and schedules.
DPL Maryland Distribution Base Rate Case Proceedings
On May 19, 2022, DPL filed an electric base rate case with the MDPSC requesting a total revenue requirement increase of $ 38  million based on an ROE of 10.25 %. On December 14, 2022, the MDPSC issued an order awarding DPL a total revenue requirement increase of $ 29  million with an ROE of 9.60 %. The order reflects a three-year cumulative multi-year plan for January 1, 2023 through December 31, 2025, with rates remaining in effect subsequent to the multi-year plan period. The MDPSC awarded DPL electric incremental revenue requirement increases of $ 17  million, $ 6  million, and $ 6  million for 2023, 2024, and 2025, respectively.
DPL Delaware Distribution Base Rate Case Proceedings
On December 15, 2022, DPL filed an electric base rate case with the DEPSC (amended September 29, 2023) requesting a total revenue requirement increase of $ 39  million and an ROE of 10.50 %. On April 18, 2024, the DEPSC issued an order awarding DPL a total revenue requirement increase of $ 28  million with an ROE of 9.60 %, effective July 15, 2023. As part of the approved order, the DEPSC approved the Significant Storm Expense Rate Rider (Rider SSER) which will allow DPL to recover expenses associated with qualified storms. A qualified storm will be an individual storm for which DPL incurs expenses between $ 5  million and $ 15  million. The Rider SSER allows DPL to recover significant storm damage expenses for the previous 12-month period over a future 24-month period. For individual storm events for which DPL incurs expenses of more than $ 15  million, the future recovery period will be evaluated on a case-by-case basis and the unamortized balance will earn a return at DPL's authorized long-term cost of debt. The Rider SSER will have an annual true-up filing, subject to DEPSC review and approval.
166

Table of Contents
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)

Note 2 — Regulatory Matters

ACE New Jersey Distribution Base Rate Case Proceedings
On February 15, 2023, ACE filed an electric base rate case with the NJBPU (amended August 21, 2023) requesting a total revenue requirement increase of $ 92  million, before NJ sales and use tax, and an ROE of 10.50 %. On November 17, 2023, the NJBPU issued an order awarding ACE electric revenue requirement increases, before NJ sales and use tax, of $ 36  million and $ 9  million effective December 1, 2023 and February 1, 2024, respectively, with an ROE of 9.60 %.
On November 21, 2024, ACE filed an electric base rate case with the NJBPU requesting a total revenue requirement increase of $ 109  million, before NJ sales and use tax, and an ROE of 10.70 %. On November 21, 2025, the NJBPU issued an order awarding ACE an electric revenue requirement increase, before NJ sales and use tax, of $ 54  million effective December 1, 2025, with an ROE of 9.60 %. In addition, the NJBPU approved the recovery through a regulatory asset of work stoppage costs that were incurred by ACE in 2023 of $ 38  million.
Transmission Formula Rates
The Utility Registrants' transmission rates are each established based on a FERC-approved formula. ComEd, BGE, Pepco, DPL, and ACE are required to file an annual update to the FERC-approved formula on or before May 15, and PECO is required to file on or before May 31, with the resulting rates effective on June 1 of the same year. The annual update for ComEd is based on prior year actual costs and current year projected capital additions (initial year revenue requirement). The update for ComEd also reconciles any differences between the revenue requirement in effect beginning June 1 of the prior year and actual costs incurred for that year (annual reconciliation). The annual update for PECO is based on prior year actual costs and current year projected capital additions, accumulated depreciation, and accumulated deferred income taxes. The annual update for BGE, Pepco, DPL, and ACE is based on prior year actual costs and current year projected capital additions, accumulated depreciation, depreciation and amortization expense, and accumulated deferred income taxes. The update for PECO, BGE, Pepco, DPL, and ACE also reconciles any differences between the actual costs and actual revenues for the calendar year (annual reconciliation).
For 2025, the following increases/(decreases) were included in the Utility Registrants' electric transmission formula rate updates:

Registrant (a)
Initial Revenue Requirement Increase (Decrease) Annual Reconciliation Increase (Decrease) Total Revenue Requirement Increase (Decrease) (b)
Allowed Return on Rate Base (c)
Allowed ROE (d)

ComEd $ 78   $ 49   $ 127   8.13   % 11.50   %
PECO $ 9   $ 13   $ 22   7.54   % 10.35   %
BGE $ 21   $ 21   $ 35   (e) 7.53   % 10.50   %
Pepco $ 35   $ 16   $ 51   7.71   % 10.50   %
DPL $ 32   $ ( 9 ) $ 23   7.48   % 10.50   %
ACE $ ( 11 ) $ ( 46 ) $ ( 57 ) 7.16   % 10.50   %

__________
(a) All rates are effective June 1, 2025 - May 31, 2026, subject to review by interested parties pursuant to review protocols of each Utility Registrants' tariffs.
(b) For the Utility Registrants, except for PECO, while the transmission filings reflect the tax benefit of NOLCs, the impacts of the NOLCs will not be reflected in the financial statements until the PLR is received from the IRS. See Note 11 — Income Taxes for additional information on NOLCs.
(c) Represents the weighted average debt and equity return on transmission rate base.
(d) The rate of return on common equity for each Utility Registrant includes a 50 -basis-point incentive adder for being a member of an RTO.
(e) The increase in BGE's transmission revenue requirement includes a $ 7 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,
167

Table of Contents
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)

Note 2 — Regulatory Matters

(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
Beginning in 2024, ComEd recovers 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 (2024-2027 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 December 14, 2023, the ICC issued a final order. The ICC rejected ComEd’s 2024-2027 Grid Plan as non-compliant with certain requirements of CEJA and required ComEd to file a revised 2024-2027 Grid Plan. In the absence of an approved 2024-2027 Grid Plan, the ICC set ComEd’s forecast revenue requirements for 2024-2027 based on ComEd's approved year-end 2022 rate base. This resulted in a total cumulative revenue requirement increase of $ 501 million, a $ 986 million total revenue reduction from the requested cumulative revenue requirement increase but remained subject to annual reconciliation in accordance with CEJA. The final order approved the process and formulas associated with the MRP reconciliation mechanisms. The ICC's December 2023 order 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 application for rehearing was denied on all issues except for the order’s use of the 2022 year-end rate base. On April 18, 2024, the ICC issued its final order on rehearing, which approved the use of the forecasted year-end 2023 rate base that resulted in increased revenue requirements for 2024-2027. These revenue requirements determined during the rehearing process established base revenue requirements until the ICC approved the Refiled 2024-2027 Grid Plan on December 19, 2024.
On January 10, 2024, ComEd filed an appeal in the Illinois Appellate Court of the issues on which rehearing was denied, including but not limited to the allowed ROE, 50 % equity ratio, and denial of a return on ComEd’s pension asset. There is no deadline by when the appellate court must rule. On March 13, 2024, ComEd filed its Refiled 2024-2027 Grid Plan with supporting testimony and schedules with the ICC and subsequently on March 15, 2024, ComEd also filed a petition to adjust its MRP to authorize increased rates consistent with the Refiled 2024-2027 Grid Plan. On December 19, 2024, the ICC approved the Refiled 2024-2027 Grid Plan and adjusted the approved MRP with rates effective on January 1, 2025. The final approved MRP, as adjusted, which reflects the Refiled Grid Plan, resulted in a total cumulative revenue requirement increase of $ 1.045 billion over the 2024-2027 plan years and remains subject to annual reconciliations in accordance with CEJA. ComEd filed timely requests for rehearing and an appeal of the MRP order, again limited to the issues on which rehearing of the December 2023 order was denied, including the allowed ROE, 50 % equity ratio, and denial of a return on ComEd's pension asset.
On January 16, 2026, ComEd filed a multi-year integrated grid plan (2028-2031 Grid Plan), seeking approval for planned investments on the electric distribution system within ComEd's service area in 2028-2031. The ICC must issue an order by December 15, 2026.
Carbon Mitigation Credit
CEJA establishes decarbonization requirements for Illinois as well as programs to support the retention and development of emissions-free sources of electricity. ComEd is required to purchase CMCs from participating nuclear power generating facilities between June 1, 2022 and May 31, 2027. The price to be paid for each CMC
168

Table of Contents
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)

Note 2 — Regulatory Matters

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. On October 31, 2025, the seller provided notification to ComEd and the IPA that it has reflected on its 2024 federal tax return $ 804 million of nuclear production tax credits associated with its participating nuclear power generating facilities. These amounts will be collected from the seller through an adjustment to the CMC price to be paid by ComEd and returned to customers in 2026. As of December 31, 2025, Exelon and ComEd's Consolidated Balance Sheets reflect these amounts as a receivable from the seller with an offsetting balance within the Carbon mitigation credit regulatory liability. These adjustments had no net impact on Exelon and ComEd’s Consolidated Statements of Operations and Comprehensive Income. 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. Beginning with the June 2022 monthly billing period, ComEd began issuing credits and/or charges to its retail customers under its CMC rider, the Rider Carbon-Free Resource Adjustment (Rider CFRA). A regulatory asset or liability is recorded for the difference between ComEd's costs associated with the procurement of CMCs from participating nuclear power generating facilities and revenues received from customers. The balance of the liability as of December 31, 2025 is $ 670 million.
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 CMC’s during the delivery year beginning June 1, 2022 and extending through May 31, 2023. While both Staff and the Administrative Law Judge's proposed order supported ComEd’s proposed reconciliation adjustment, on September 4, 2025, the ICC issued its final order rejecting the proposed reconciliation adjustment. Specifically, the order disallowed portions of the administrative costs as well as a portion of ComEd's interest costs on the balance of credit extended to customers under the applicable tariff that were not yet funded by payments from the generator. The CMC costs themselves were not disallowed. The order resulted in an immaterial impact to the financial statements and on October 3, 2025 ComEd filed its Application for Rehearing. On October 16, 2025, the ICC denied ComEd's Application. On October 17, 2025, ComEd filed its appeal with the Illinois Appellate Court for review of the ICC's order and its denial of rehearing.
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 through 2040 to achieve these energy efficiency MWh savings goals, which is deferred 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.
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 electric distribution rates) 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 a weighted average cost of capital, which is based on a year-end capital structure and a statutorily-based formula based on long-term treasury debt. 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 rate 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.
169

Table of Contents
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)

Note 2 — Regulatory Matters

During 2025, 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 23, 2025 $ 19   $ 19   10.21   % November 19, 2025 January 1, 2026

_________
(a) ComEd's 2026 approved revenue requirement reflects an increase of $ 24 million for the initial year revenue requirement for 2026 and a decrease of $ 5 million related to the annual reconciliation for 2024. The revenue requirement for 2025 provides for a weighted average debt and equity return on the energy efficiency regulatory asset and rate base of 7.23 % inclusive of an allowed ROE of 10.21 %, reflecting the monthly average yields for 30-year treasury bonds plus 580 basis points. The revenue requirement for the 2024 reconciliation year provides for a weighted average debt and equity return on the energy efficiency regulatory asset and rate base of 7.50 % inclusive of an allowed ROE of 10.75 %, 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 intended to be 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.
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 began deferring less energy efficiency and demand response program costs and beginning January 1, 2026, program costs are no longer being deferred. 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.
Next Generation Energy Act (Exelon, BGE, PHI, Pepco, and DPL). On May 20, 2025, the Governor of Maryland signed into law legislation that addresses several matters pertaining to electric and gas utilities, including affirming that the MDPSC may approve the use of multi-year rate plans that demonstrate customer benefits, among other things. It also prohibits utilities from filing after January 1, 2025, for the reconciliation of actuals costs and revenues to amounts approved within the multi-year plans. In the second quarter of 2025, BGE derecognized Regulatory assets of $ 10  million and Regulatory liabilities of $ 3  million for multi-year plan reconciliations that are no longer eligible to be filed. DPL also derecognized Regulatory liabilities of $ 0.4  million during the second quarter of 2025 for multi-year reconciliations ineligible to be filed. Multi-year plan reconciliations filed prior to January 1, 2025, remain lawful and will be resolved in their respective proceedings.
Summer and Winter Rate Mitigation (Exelon, BGE, PHI, Pepco, and DPL). As part of the passing of the Next Generation Energy Act by the Maryland General Assembly, the MDPSC issued an order on June 26, 2025, to implement the Legislative Energy Relief Refund program under which bill credits were distributed to residential customers based on their consumption of electricity supply that was subject to the renewable energy portfolio standard. On July 24, 2025, the MDPSC issued an order accepting BGE, Pepco, and DPL's proposal for the implementation of the program. As a result, BGE, Pepco, and DPL received $ 49  million, $ 21  million, and $ 8  million, respectively, from the MDPSC on August 6, 2025. These amounts were used to reduce residential customer account receivable balances within the third quarter of 2025. Additional disbursements from the state of
170

Table of Contents
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)

Note 2 — Regulatory Matters

Maryland were received by BGE, Pepco, and DPL on February 3, 2026 for approximately $ 49  million, $ 21  million, and $ 8  million, respectively. These amounts will also be used to reduce residential customer receivables in the first quarter of 2026.
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 intended to be impacted by abnormal weather or usage per customer. The decoupling mechanism initially approved eliminated the impacts of abnormal weather or customer usage by recognizing revenues based on an authorized distribution amount per customer by customer class. Prior to 2025, operating revenues from electric distribution at Pepco District of Columbia were, impacted by changes in the number of customers. Beginning in 2025, based on modifications approved by the DCPSC, Pepco District of Columbia began recognizing revenues on an authorized distribution amount per customer class basis, and operating revenues from electric distribution have no longer been impacted by changes in the number of customers.
New Jersey Regulatory Matters
Conservation Incentive Program (CIP) (Exelon, PHI, and ACE). On September 25, 2020, ACE filed an application with the NJBPU as required to seek 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 are no longer intended to be impacted by abnormal weather or usage for most customers. Starting in the third quarter of 2021, ACE began recording 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 a petition with the NJBPU 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 and recognized a corresponding regulatory asset of $ 203 million. The liability has been paid in full as of December 31, 2024.
For the year ended December 31, 2024, ACE paid $ 49  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 October 31, 2022, ACE filed with the NJBPU an 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 required to seek 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
171

Table of Contents
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)

Note 2 — Regulatory Matters

involved 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 addressed all material aspects of ACE's smart energy network deployment plan, including cost recovery of the investment costs, incremental Operating and maintenance 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.
Summer Rate Mitigation (Exelon and ACE). In response to significant increases in electric supply costs, on April 23, 2025, the NJBPU issued an order directing the State's electric public utilities to file petitions proposing distribution side measures to mitigate residential customer bill impacts during summer months. As a result, on June 18, 2025, the NJBPU approved a stipulation of settlement for ACE to issue a bill credit of $ 30 per residential customer for the months of July and August 2025, which was deferred to Regulatory assets. The amounts will subsequently be collected from September 2025 through February 2026 at a flat rate of $ 10 per residential customer. The bill credit and subsequent collections will not be subject to carrying costs. As of December 31, 2025, the Regulatory asset has a remaining balance of $ 10 million.
Residential Universal Bill Credit (Exelon and ACE). In an effort to further reduce the burden of increased electric supply costs, on August 13, 2025, the NJBPU issued an order to establish the RUBC, which was funded by the NJBPU. The program provided a $ 50 bill credit per eligible residential customer for the months of September and October 2025. ACE received $ 51 million from the NJBPU on September 25, 2025, which was recognized as a Regulatory liability. ACE subsequently issued all bill credits to residential customers in September and October. As of December 31, 2025, there is no Regulatory liability remaining.
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 extended back to January 1, 2017.
On July 27, 2023, FERC published 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 July 30, 2024, ComEd reached an agreement in principle on the contested overhead allocation finding. As a result of the settlement process, ComEd recorded a charge for the probable disallowance of $ 70 million of certain currently capitalized construction costs to operating expenses, which are not expected to be recovered in future rates. The existing loss estimate was reflected in Exelon and ComEd's financial statements as of December 31, 2024. ComEd and FERC staff jointly filed the settlement agreement with FERC for approval on February 11, 2025. The settlement was approved by FERC on April 4, 2025.
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.
172

Table of Contents
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)

Note 2 — Regulatory Matters

The following tables provide information about the regulatory assets and liabilities of the Registrants at December 31, 2025 and 2024:

December 31, 2025 Exelon ComEd PECO BGE PHI Pepco DPL ACE
Regulatory assets
AMI programs - deployment costs $ 49   $ —   $ —   $ 8   $ 41   $ 6   $ 8   $ 27  
AMI programs - legacy meters 64   4   —   1   59   19   7   33  
Asset retirement obligations 193   129   22   28   14   9   4   1  

COVID-19 45   —   —   2   43   42   1   —  
Deferred income taxes 1,167   —   1,154   —   13   13   —   —  
Deferred storm costs 182   —   75   81   26   8   1   17  
Distributed generation rebates 246   246   —   —   —   —   —   —  
Electric distribution formula rate annual reconciliations 20   20   —   —   —   —   —   —  
Electric distribution formula rate significant one-time events 73   73   —   —   —   —   —   —  
Electric energy and natural gas costs 205   43   —   52   110   67   37   6  
Energy efficiency and demand response programs 686   —   —   327   359   178   68   113  
Energy efficiency costs 2,018   2,018   —   —   —   —   —   —  
Fair value of long-term debt 426   —   —   —   338   —   —   —  
Fair value of PHI's unamortized energy contracts 21   —   —   —   21   —   —   —  
MGP remediation costs 310   283   14   13   —   —   —   —  
Multi-year plan reconciliations 116   71   —   26   19   19   —   —  
Pension and OPEB 2,603   —   —   —   —   —   —   —  
Pension and OPEB - merger related 371   —   —   —   —   —   —   —  
Removal costs 967   —   —   340   627   139   140   348  
Renewable energy 131   131   —   —   —   —   —   —  
Transmission formula rate annual reconciliations 61   17   14   4   26   18   8   —  
Under-recovered credit loss expense 152   152   —   —   —   —   —   —  
Under-recovered revenue decoupling 107   —   —   39   68   30   —   38  
Universal service fund charge under-recovery - Electric 32   —   32   —   —   —   —   —  
Work stoppage costs 37   —   —   —   37   —   —   37  
Zero emission credit 41   41   —   —   —   —   —   —  
Other 250   54   36   58   107   39   12   32  
Total regulatory assets 10,573   3,282   1,347   979   1,908   587   286   652  
        Less: current portion 1,359   595   72   175   352   182   72   93  
Total noncurrent regulatory assets $ 9,214   $ 2,687   $ 1,275   $ 804   $ 1,556   $ 405   $ 214   $ 559  

173

Table of Contents
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)

Note 2 — Regulatory Matters

December 31, 2025 Exelon ComEd PECO BGE PHI Pepco DPL ACE
Regulatory liabilities
Carbon mitigation credit $ 670   $ 670   $ —   $ —   $ —   $ —   $ —   $ —  
Decommissioning the Regulatory Agreement Units 4,755   4,313   442   —   —   —   —   —  
Dedicated facilities charge 155   —   —   155   —   —   —   —  
Deferred income taxes 2,447   1,419   —   427   601   241   232   128  
Electric energy and natural gas costs 155   —   113   25   17   —   —   17  
Energy efficiency and demand response programs 16   —   16   —   —   —   —   —  
Fiber Refund —   —   —   —   —   —   —   —  
Multi-year plan reconciliations 13   —   —   —   13   6   7   —  
Over-recovered credit loss expense 5   —   —   —   5   —   —   5  
Over-recovered revenue decoupling 8   —   —   1   7   —   7   —  
Removal costs 2,070   1,960   —   —   110   20   88   2  
Renewable portfolio standards costs 1,611   1,611   —   —   —   —   —   —  

Transmission formula rate annual reconciliations 31   —   —   4   27   —   7   20  
Other 208   36   18   14   45   14   17   13  
Total regulatory liabilities 12,144   10,009   589   626   825   281   358   185  
        Less: current portion 1,128   846   140   31   103   13   42   48  
Total noncurrent regulatory liabilities $ 11,016   $ 9,163   $ 449   $ 595   $ 722   $ 268   $ 316   $ 137  

174

Table of Contents
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)

Note 2 — Regulatory Matters

December 31, 2024 Exelon ComEd PECO BGE PHI Pepco DPL ACE
Regulatory assets
AMI programs - deployment costs $ 82   $ —   $ —   $ 29   $ 53   $ 11   $ 13   $ 29  
AMI programs - legacy meters 90   13   —   4   73   30   10   33  
Asset retirement obligations 173   112   23   26   12   8   3   1  
Carbon mitigation credit 179   179   —   —   —   —   —   —  
COVID-19 59   3   —   4   52   49   3   —  
Deferred income taxes 937   —   925   —   12   12   —   —  
Deferred storm costs 125   —   23   73   29   8   1   20  
Distributed generation rebate 171   171   —   —   —   —   —   —  
Electric distribution formula rate annual reconciliations 554   554   —   —   —   —   —   —  
Electric distribution formula rate significant one-time events 98   98   —   —   —   —   —   —  
Electric energy and natural gas costs 108   —   —   38   70   18   20   32  
Energy efficiency and demand response programs 652   —   10   329   313   174   72   67  
Energy efficiency costs 1,890   1,890   —   —   —   —   —   —  
Fair value of long-term debt 457   —   —   —   362   —   —   —  
Fair value of PHI's unamortized energy contracts 26   —   —   —   26   —   —   —  
MGP remediation costs 307   275   18   14   —   —   —   —  
Multi-year plan reconciliations 170   81   —   66   23   23   —   —  
Pension and OPEB 2,382   —   —   —   —   —   —   —  
Pension and OPEB - merger related 503   —   —   —   —   —   —   —  
Removal costs 869   —   —   261   608   127   127   356  
Renewable energy 131   131   —   —   —   —   —   —  
Transmission formula rate annual reconciliations 114   20   15   30   49   37   12   —  
Under-recovered credit loss expense 147   126   —   —   21   —   —   21  
Under-recovered revenue decoupling 188   —   —   98   90   60   —   30  
Universal service fund charge under-recovery - Electric 19   —   19   —   —   —   —   —  
Zero emission credit 4   4   —   —   —   —   —   —  
Other 215   64   35   23   100   46   14   14  
Total regulatory assets 10,650   3,721   1,068   995   1,893   603   275   603  
        Less: current portion 1,940   1,159   65   207   323   157   60   101  
Total noncurrent regulatory assets $ 8,710   $ 2,562   $ 1,003   $ 788   $ 1,570   $ 446   $ 215   $ 502  

175

Table of Contents
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)

Note 2 — Regulatory Matters

December 31, 2024 Exelon ComEd PECO BGE PHI Pepco DPL ACE
Regulatory liabilities
Decommissioning the Regulatory Agreement Units $ 4,027   $ 3,780   $ 247   $ —   $ —   $ —   $ —   $ —  
Dedicated facilities charge 143   —   —   143   —   —   —   —  
Deferred income taxes 2,756   1,607   —   484   665   285   247   133  
Electric energy and natural gas costs 108   12   81   —   15   8   7   —  
Energy efficiency and demand response programs 1   —   1   —   —   —   —   —  
Fiber Refund 16   —   16   —   —   —   —   —  
Multi-year plan reconciliations 9   —   —   —   9   —   9   —  
Over-recovered revenue decoupling 2   —   —   —   2   —   2   —  
Removal costs 1,958   1,841   —   11   106   20   86   —  
Renewable portfolio standards costs 1,369   1,369   —   —   —   —   —   —  

Transmission formula rate annual reconciliations 14   —   —   —   14   —   —   14  
Other 206   9   30   10   52   14   16   9  
Total regulatory liabilities 10,609   8,618   375   648   863   327   367   156  
        Less: current portion 411   197   122   12   69   17   42   10  
Total noncurrent regulatory liabilities $ 10,198   $ 8,421   $ 253   $ 636   $ 794   $ 310   $ 325   $ 146  

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 - 2045
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 - 2045
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
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. 2026 No

176

Table of Contents
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)

Note 2 — Regulatory Matters

Line Item Description End Date of Remaining Recovery/Refund Period Return
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. This also includes under-recovered amounts due to COVID-19 that were previously deferred under Pepco’s revenue decoupling program. ComEd - 2025

BGE - 2028

PECO - 2025

Pepco (District of Columbia) - $ 37  million - 2034

Pepco (Maryland) - $ 5  million - 2029

DPL (Delaware) - $ 1  million - 2028
ComEd, BGE, and Pepco - Yes

PECO and DPL (Delaware) - No
Decommissioning the Regulatory Agreement 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
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

177

Table of Contents
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)

Note 2 — Regulatory Matters

Line Item Description End Date of Remaining Recovery/Refund Period Return
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, PECO and BGE, amounts represent total incremental storm restoration costs incurred due to major storm events recoverable from customers in the Maryland, New Jersey jurisdictions and Pennsylvania. Pepco (Maryland) - $ 8  million to be determined in pending multi-year plan filed with MDPSC.

DPL - 2027

ACE - $ 2  million - 2026; $ 15  million - 2028

PECO - $ 75  million to be determined in the next distribution rate case filed with the PAPUC.

BGE - $ 34  million - 2028; $ 47 million to be determined in the next multi-year plan filed with MDPSC.
Pepco, DPL, BGE - Yes

ACE, PECO - No
Distributed generation rebates Represents ComEd's costs recovered through the distributed generation rebate adjustment 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 distributed generation rebate costs are recovered over a 15-year period. 2039 Yes

178

Table of Contents
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)

Note 2 — Regulatory Matters

Line Item Description End Date of Remaining Recovery/Refund Period Return
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 was updated annually with rates effective on January 1 st .
2026 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. 2029 Yes
Electric energy and natural gas costs Represents under (over)-recoveries related to energy and gas supply related costs recoverable (refundable) under approved rate riders. 2026
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
Pepco (District of Columbia) - No
DPL (Delaware), 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. 2038 Yes

179

Table of Contents
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)

Note 2 — Regulatory Matters

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 $ 88  million and $ 338  million, respectively, as of December 31, 2025, and $ 95 million and $ 362 million, respectively, as of December 31, 2024, 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
Fiber Refund Represents revenues collected from Constellation and BSC for their use of PECO's fiber assets before the end of 2021. 2025 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 16 — 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. ComEd - 2028

BGE - 2027

Pepco (Maryland) - $ 1  million related to 2023 reconciliation - 2026. $ 18  million related to 2024 reconciliation - to be determined in a future MDPSC order.

Pepco (District of Columbia) - $ 6  million related to 2025 reconciliation - to be determined in a future DCPSC order.

DPL (Maryland) - $ 7  million related to 2024 reconciliation.
ComEd - Yes

BGE - No

Pepco (Maryland) - No

Pepco (District of Columbia) - Yes

DPL (Maryland) - Yes

180

Table of Contents
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)

Note 2 — Regulatory Matters

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 12 — Retirement Benefits for additional information. The capitalized non–service cost components are amortized over the lives of the underlying assets.
No
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 12 — 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, DPL, and ACE - 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

181

Table of Contents
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)

Note 2 — Regulatory Matters

Line Item Description End Date of Remaining Recovery/Refund Period Return
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. $ 1,535 million to be determined in pending ICC annual reconciliation for the Renewable Energy Adjustment rider.

$ 76 million to be determined based on the LTRRPP developed by the IPA.
No
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 .
2027 Yes
Under (over) -recovered revenue decoupling
Represents electric and / or gas distribution costs recoverable from or refundable to customers under decoupling mechanisms. BGE - 2026
Pepco (Maryland) - $ 4  million - 2026
Pepco (District of Columbia) - $ 26  million - 2028
DPL - 2025
ACE - 2026
BGE, Pepco, DPL, ACE - No

182

Table of Contents
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)

Note 2 — Regulatory Matters

Line Item Description End Date of Remaining Recovery/Refund Period Return
Under (over) -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 or refund to customers June through May of each respective year, subject to approval of the NJBPU. ComEd - 2026

ACE - To be determined in the annual 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
Work stoppage costs Represents work stoppage costs incurred by ACE. 2030 No
Zero emission credit Represents ZEC procurement costs and any reasonable costs ComEd has incurred to implement and comply with the ZEC procurement process. Over 9 months starting with the September billing period and ending with the following May billing period. 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 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 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.
183

Table of Contents
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)

Note 2 — Regulatory Matters

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, 2025 and December 31, 2024

Exelon ComEd (a)
BGE (b)
PHI Pepco (c)
DPL (d)
ACE (e)

December 31, 2025 $ 98   $ 12   $ 47   $ 39   $ 22   $ 1   $ 16  
December 31, 2024 $ 117   $ 46   $ 16   $ 55   $ 40   $ 1   $ 14  

__________
(a) For the year ended December 31, 2025, reflects ComEd's unrecognized equity returns earned for ratemaking purposes on its electric distribution rates and distributed generation regulatory assets. For the year ended December 31, 2024, reflects ComEd's unrecognized equity returns earned for ratemaking purposes on its electric distribution rates and formula rates regulatory assets.
(b) BGE's amount capitalized for ratemaking purposes primarily relates to earnings on shareholders' investment on AMI programs and investments in rate base included in the multi-year plan reconciliations.
(c) Pepco's authorized amounts capitalized for ratemaking purposes relate to earnings on shareholders' investment on AMI programs, Energy efficiency and demand response programs, COVID-19 costs, investments in rate base and revenues included in the multi-year plan reconciliations, and a portion of Pepco District of Columbia's revenue decoupling.
(d) DPL's authorized amounts capitalized for ratemaking purposes relate to earnings on shareholders' investment on AMI programs and Energy efficiency and demand response programs.
(e) ACE's authorized amounts capitalized for ratemaking purposes primarily relate to earnings on shareholders' investment on AMI programs.

3. Revenue from Contracts with Customers (All Registrants)
The Registrants recognize revenue from contracts with customers to depict the transfer of goods or services to customers at an amount that the entities expect to be entitled to in exchange for those goods or services. The primary sources of revenue include regulated electric and gas tariff sales, distribution, and transmission services. 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.
184

Table of Contents
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)

Note 3 — Revenue from Contracts with Customers

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.
In July 2020, Pepco, DPL, and ACE entered into a collaborative arrangement with an unrelated communications‑infrastructure owner involving the sale of an undivided interest in certain transmission tower attachment agreements and the transfer of management rights, as further described in Note 4 — Revenue from Contracts with Customers of the 2024 Form 10‑K. The Companies received additional consideration in 2023 related to an amendment of the payment options under the arrangement. Contract liabilities associated with the original arrangement and the 2023 amendment are being recognized as Electric operating revenues over 35‑year and 31‑year periods, respectively.
185

Table of Contents
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)

Note 3 — Revenue from Contracts with Customers

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, 2025, 2024, and 2023, 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, 2023 $ 133   $ 133   $ 107   $ 13   $ 13  

Revenues recognized ( 6 ) ( 6 ) ( 6 ) —   —  

Balance at December 31, 2024 $ 127   $ 127   $ 101   $ 13   $ 13  

Revenues recognized ( 8 ) ( 8 ) ( 6 ) ( 1 ) ( 1 )

Balance at December 31, 2025 $ 119   $ 119   $ 95   $ 12   $ 12  
__________
(a) Revenues recognized in the years ended December 31, 2025 and 2024, were included in the contract liabilities at December 31, 2024 and 2023, 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, 2025. 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
2026 $ 5   $ 5   $ 5   $ —   $ —  
2027 6   6   5   1   —  
2028 6   6   5   —   1  
2029 7   7   6   1   —  
2030 and thereafter 95   95   74   10   11  
Total $ 119   $ 119   $ 95   $ 12   $ 12  

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 4 — Segment Information for the presentation of the Registrant's revenue disaggregation.

4. Segment Information (All Registrants)
Operating segments for each of the Registrants are determined based on information used by the CODMs in deciding how to evaluate performance and allocate resources at each of the Registrants. The Chief Executive Officer is the CODM for Exelon. For PHI and each of the Utility Registrants, CODM responsibilities are shared by Exelon's Chief Operating Officer and the Utility Registrant's Chief Executive Officer.
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 rely on a variety of business considerations, including net income, in evaluating segment performance, determining reinvestment of profits, and establishing the amounts of dividend distributions.
186

Table of Contents
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)

Note 4 — Segment 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, 2025, 2024, and 2023 is as follows:

ComEd PECO BGE PHI Other (a)
Intersegment
Eliminations Exelon
Operating revenues (b) :

2025
Electric revenues $ 7,267   $ 3,827   $ 4,007   $ 6,894   $ —   $ ( 36 ) $ 21,959  
Natural gas revenues —   857   1,215   231   —   ( 4 ) 2,299  
Shared service and other revenues —   —   —   10   1,900   ( 1,910 ) —  
Total operating revenues $ 7,267   $ 4,684   $ 5,222   $ 7,135   $ 1,900   $ ( 1,950 ) $ 24,258  
2024
Electric revenues $ 8,219   $ 3,325   $ 3,436   $ 6,258   $ —   $ ( 22 ) $ 21,216  
Natural gas revenues —   648   990   180   —   ( 6 ) 1,812  
Shared service and other revenues —   —   —   10   1,865   ( 1,875 ) —  
Total operating revenues $ 8,219   $ 3,973   $ 4,426   $ 6,448   $ 1,865   $ ( 1,903 ) $ 23,028  
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  

Less:
Purchased power
2025 $ 1,782   $ 1,436   $ 1,890   $ 2,836   $ —   $ —   $ 7,944  
2024 3,042   1,265   1,460   2,447   —   —   8,214  
2023 2,816   1,270   1,311   2,250   —   1   7,648  
Purchased fuel
2025 $ —   $ 297   $ 331   $ 95   $ —   $ —   $ 723  
2024 —   212   191   66   —   —   469  
2023 —   274   220   98   —   1   593  

Operating and maintenance
2025 $ 1,306   $ 946   $ 815   $ 1,123   $ 1,840   $ ( 853 ) $ 5,177  
2024 1,284   875   790   1,046   1,733   ( 788 ) 4,940  
2023 1,096   786   520   1,110   1,861   ( 814 ) 4,559  
Operating and maintenance from affiliates
2025 $ 404   $ 249   $ 251   $ 204   $ 43   $ ( 1,151 ) $ —  
2024 419   245   246   204   41   ( 1,155 ) —  
2023 354   217   221   179   37   ( 1,008 ) —  
Depreciation and amortization
2025 $ 1,560   $ 454   $ 632   $ 935   $ 59   $ —   $ 3,640  
2024 1,514   428   638   947   67   —   3,594  
2023 1,403   397   654   990   62   —   3,506  
Taxes other than income taxes
2025 $ 409   $ 240   $ 370   $ 568   $ 42   $ —   $ 1,629  
2024 376   218   345   528   37   —   1,504  
2023 369   202   319   487   31   —   1,408  

187

Table of Contents
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)

Note 4 — Segment Information

ComEd PECO BGE PHI Other (a)
Intersegment
Eliminations Exelon
(Gain) loss on sale of assets and businesses
2025 $ —   $ —   $ —   $ ( 3 ) $ —   $ —   $ ( 3 )
2024 ( 5 ) ( 4 ) —   1   ( 4 ) —   ( 12 )
2023 —   —   —   ( 9 ) ( 1 ) —   ( 10 )
Interest expense, net (c)

2025 $ 517   $ 249   $ 247   $ 408   $ 681   $ —   $ 2,102  
2024 487   221   216   373   592   —   1,889  
2023 464   192   182   323   545   ( 2 ) 1,704  
Interest expense to affiliates, net (c)

2025 $ 13   $ 11   $ —   $ 3   $ ( 2 ) $ —   $ 25  
2024 14   11   —   3   ( 3 ) —   25  
2023 13   9   —   —   1   2   25  
Other, net
2025 $ ( 132 ) $ ( 41 ) $ ( 51 ) $ ( 72 ) $ ( 28 ) $ 54   $ ( 270 )
2024 ( 94 ) ( 37 ) ( 36 ) ( 97 ) ( 38 ) 40   ( 262 )
2023 ( 75 ) ( 36 ) ( 18 ) ( 108 ) ( 190 ) 19   ( 408 )
Income taxes
2025 $ 261   $ 29   $ 159   $ 239   $ ( 165 ) $ —   $ 523  
2024 116   ( 12 ) 49   189   ( 135 ) —   207  
2023 314   20   133   116   ( 207 ) ( 2 ) 374  
Net income (loss)
2025 $ 1,147   $ 814   $ 578   $ 799   $ ( 570 ) $ —   $ 2,768  
2024 1,066   551   527   741   ( 425 ) —   2,460  
2023 1,090   563   485   590   ( 380 ) ( 20 ) 2,328  
Supplemental segment information
Intersegment revenues (d)

2025 $ 21   $ 12   $ 8   $ 10   $ 1,890   $ ( 1,941 ) $ —  
2024 8   10   10   10   1,855   ( 1,893 ) —  
2023 16   9   9   9   1,750   ( 1,793 ) —  
Capital expenditures
2025 $ 2,899   $ 1,867   $ 1,657   $ 2,056   $ 50   $ —   $ 8,529  
2024 2,195   1,553   1,420   1,863   66   —   7,097  
2023 2,576   1,426   1,367   1,988   54   —   7,411  
Total assets
2025 $ 48,285   $ 19,362   $ 17,184   $ 29,715   $ 6,170   $ ( 4,146 ) $ 116,570  
2024 44,750   17,123   15,542   28,297   6,012   ( 3,940 ) 107,784  

__________
(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 20 — Supplemental Financial Information for additional information on total utility taxes.
(c) Interest expense, net and Interest expense to affiliates, net are primarily inclusive of Interest expense, which is partially offset by an immaterial amount of interest income.
(d) See Note 21 — Related Party Transactions for additional information on intersegment revenues.
188

Table of Contents
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)

Note 4 — Segment Information

PHI:

Pepco DPL ACE Other (a)
Intersegment
Eliminations PHI
Operating revenues (b) :

2025
Electric revenues $ 3,454   $ 1,740   $ 1,718   $ —   $ ( 18 ) $ 6,894  
Natural gas revenues —   231   —   —   —   231  
Shared service and other revenues —   —   —   424   ( 414 ) 10  
Total operating revenues $ 3,454   $ 1,971   $ 1,718   $ 424   $ ( 432 ) $ 7,135  
2024
Electric revenues $ 3,039   $ 1,607   $ 1,628   $ —   $ ( 16 ) $ 6,258  
Natural gas revenues —   180   —   —   —   180  
Shared service and other revenues —   —   —   438   ( 428 ) 10  
Total operating revenues $ 3,039   $ 1,787   $ 1,628   $ 438   $ ( 444 ) $ 6,448  
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  
Less:
Purchased power
2025 $ 1,262   $ 766   $ 808   $ —   $ —   $ 2,836  
2024 1,055   694   698   —   —   2,447  
2023 974   639   637   —   —   2,250  
Purchased fuel
2025 $ —   $ 95   $ —   $ —   $ —   $ 95  
2024 —   66   —   —   —   66  
2023 —   98   —   —   —   98  

Operating and maintenance
2025 $ 379   $ 213   $ 173   $ 358   $ —   $ 1,123  
2024 283   196   206   361   —   1,046  
2023 336   193   233   348   —   1,110  
Operating and maintenance from affiliates
2025 $ 246   $ 178   $ 155   $ 57   $ ( 432 ) $ 204  
2024 251   181   162   54   ( 444 ) 204  
2023 236   171   153   50   ( 431 ) 179  
Depreciation and amortization
2025 $ 433   $ 252   $ 248   $ 2   $ —   $ 935  
2024 407   245   278   17   —   947  

189

Table of Contents
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)

Note 4 — Segment Information

Pepco DPL ACE Other (a)
Intersegment
Eliminations PHI
2023 441   244   283   22   —   990  
Taxes other than income taxes
2025 $ 455   $ 88   $ 9   $ 16   $ —   $ 568  
2024 424   79   9   16   —   528  
2023 390   75   8   14   —   487  
(Gain) loss on sale of assets and businesses
2025 $ ( 1 ) $ —   $ ( 2 ) $ —   $ —   $ ( 3 )
2024 1   —   —   —   —   1  
2023 ( 9 ) —   —   —   —   ( 9 )
Interest expense, net (c)

2025 $ 214   $ 102   $ 82   $ 10   $ —   $ 408  
2024 195   94   74   10   —   373  
2023 165   74   72   12   —   323  
Interest expense to affiliates, net (c)

2025 $ —   $ —   $ —   $ 3   $ —   $ 3  
2024 ( 3 ) ( 1 ) 5   2   —   3  
2023 —   —   —   —   —   —  
Other, net
2025 $ ( 41 ) $ ( 16 ) $ ( 10 ) $ ( 5 ) $ —   $ ( 72 )
2024 ( 54 ) ( 25 ) ( 14 ) ( 4 ) —   ( 97 )
2023 ( 66 ) ( 18 ) ( 20 ) ( 4 ) —   ( 108 )
Income taxes
2025 $ 106   $ 69   $ 67   $ ( 3 ) $ —   $ 239  
2024 90   49   55   ( 5 ) —   189  
2023 51   35   36   ( 6 ) —   116  
Net income (loss) from continuing operations
2025 $ 401   $ 224   $ 188   $ ( 14 ) $ —   $ 799  
2024 390   209   155   ( 13 ) —   741  
2023 306   177   120   ( 13 ) —   590  
Supplemental segment information
Intersegment revenues (d)

2025 $ 6   $ 9   $ 4   $ 423   $ ( 432 ) $ 10  
2024 7   7   2   438   ( 444 ) 10  
2023 9   8   2   422   ( 432 ) 9  
Capital expenditures
2025 $ 957   $ 534   $ 390   $ 175   $ —   $ 2,056  
2024 929   556   373   5   —   1,863  
2023 957   562   460   9   —   1,988  
Total assets
2025 $ 12,728   $ 6,789   $ 5,632   $ 4,602   $ ( 36 ) $ 29,715  
2024 12,000   6,421   5,349   4,567   ( 40 ) 28,297  

__________
(a) Other primarily includes PHI’s corporate operations, shared service entities, and other financing and investment activities.
(b) Includes gross utility tax receipts from customers. The offsetting remittance of utility taxes to the governing bodies is recorded in Taxes other than income taxes in the Registrants’ Consolidated Statements of Operations and Comprehensive Income. See Note 20 — Supplemental Financial Information for additional information on total utility taxes.
(c) Interest expense, net is primarily inclusive of Interest expense, which is partially offset by an immaterial amount of Interest income.
(d) Includes intersegment revenues with ComEd, PECO, and BGE, which are eliminated at Exelon.
190

Table of Contents
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)

Note 4 — Segment Information

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

2025
Revenues from contracts with customers ComEd PECO BGE PHI Pepco DPL ACE
Electric revenues
Residential $ 4,203   $ 2,494   $ 2,503   $ 3,733   $ 1,669   $ 1,049   $ 1,015  
Small commercial & industrial 2,072   627   414   722   205   264   253  
Large commercial & industrial 593   339   603   1,514   1,212   122   180  
Public authorities & electric railroads 47   34   33   73   39   16   18  
Other (a)
907   312   476   917   372   303   250  
Total electric revenues (b)
$ 7,822   $ 3,806   $ 4,029   $ 6,959   $ 3,497   $ 1,754   $ 1,716  
Natural gas revenues
Residential $ —   $ 593   $ 823   $ 139   $ —   $ 139   $ —  
Small commercial & industrial —   206   140   55   —   55   —  
Large commercial & industrial —   —   248   7   —   7   —  
Transportation —   37   —   19   —   19   —  
Other (c)
—   19   51   11   —   11   —  
Total natural gas revenues (d)
$ —   $ 855   $ 1,262   $ 231   $ —   $ 231   $ —  
Total revenues from contracts with customers $ 7,822   $ 4,661   $ 5,291   $ 7,190   $ 3,497   $ 1,985   $ 1,716  
Other revenues
Revenues from alternative revenue programs $ ( 596 ) $ —   $ ( 87 ) $ ( 63 ) $ ( 49 ) $ ( 16 ) $ 2  
Other electric revenues (e)
41   21   14   8   6   2   —  
Other natural gas revenues (e)
—   2   4   —   —   —   —  

Total other revenues $ ( 555 ) $ 23   $ ( 69 ) $ ( 55 ) $ ( 43 ) $ ( 14 ) $ 2  
Total revenues for reportable segments $ 7,267   $ 4,684   $ 5,222   $ 7,135   $ 3,454   $ 1,971   $ 1,718  

191

Table of Contents
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)

Note 4 — Segment Information

2024

Revenues from contracts with customers ComEd PECO BGE PHI Pepco DPL ACE
Electric revenues
Residential $ 3,809   $ 2,169   $ 2,038   $ 3,256   $ 1,413   $ 943   $ 900  
Small commercial & industrial 2,259   547   360   681   184   253   244  
Large commercial & industrial 1,145   261   557   1,372   1,053   123   196  
Public authorities & electric railroads 60   29   31   74   37   17   20  
Other (a)
1,080   296   414   871   327   270   280  
Total electric revenues (b)
$ 8,353   $ 3,302   $ 3,400   $ 6,254   $ 3,014   $ 1,606   $ 1,640  
Natural gas revenues
Residential $ —   $ 445   $ 625   $ 108   $ —   $ 108   $ —  
Small commercial & industrial —   157   110   43   —   43   —  
Large commercial & industrial —   —   204   5   —   5   —  
Transportation —   28   —   17   —   17   —  
Other (c)
—   16   18   7   —   7   —  
Total natural gas revenues (d)
$ —   $ 646   $ 957   $ 180   $ —   $ 180   $ —  
Total revenues from contracts with customers $ 8,353   $ 3,948   $ 4,357   $ 6,434   $ 3,014   $ 1,786   $ 1,640  
Other revenues
Revenues from alternative revenue programs $ ( 151 ) $ 6   $ 52   $ 1   $ 15   $ ( 2 ) $ ( 12 )
Other electric revenues (e)
17   17   14   13   10   3   —  
Other natural gas revenues (e)
—   2   3   —   —   —   —  

Total other revenues $ ( 134 ) $ 25   $ 69   $ 14   $ 25   $ 1   $ ( 12 )
Total revenues for reportable segments $ 8,219   $ 3,973   $ 4,426   $ 6,448   $ 3,039   $ 1,787   $ 1,628  

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  

192

Table of Contents
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)

Note 4 — Segment Information

__________
(a) Includes transmission revenue from PJM, wholesale electric revenue and mutual assistance revenue.
(b) Includes operating revenues from affiliates in 2025, 2024, and 2023 respectively of:
• $ 21 million, $ 8 million, and $ 16 million at ComEd
• $ 9 million, $ 7  million, and $ 7 million at PECO
• $ 6 million, $ 7  million, and $ 6  million at BGE
• $ 10 million, $ 10  million, and $ 9  million at PHI
• $ 6 million, $ 7  million, and $ 9  million at Pepco
• $ 9 million, $ 7  million, and $ 8  million at DPL
• $ 4 million, $ 2  million, and $ 2  million at ACE
(c) Includes revenues from off-system natural gas sales.
(d) Includes operating revenues from affiliates in 2025, 2024, and 2023 respectively of:
• $ 3  million, $ 3  million, and $ 2  million at PECO
• $ 2 million, $ 3 million, and $ 3 million at BGE
(e) Includes late payment charge revenues.

5. Accounts Receivable (All Registrants)
Allowance for Credit Losses on Accounts Receivable
The following tables present the rollforward of Allowance for Credit Losses on Customer Accounts Receivable.

Year Ended December 31, 2025

Exelon ComEd PECO BGE PHI Pepco DPL ACE
Balance at December 31, 2024 $ 406   $ 109   $ 133   $ 56   $ 108   $ 59   $ 17   $ 32  
Plus: Current period provision for expected credit losses (a)(b)(c)
289   90   91   43   65   41   16   8  
Less: Write-offs (d)(e) , net of recoveries (f)(g)
260   84   87   31   58   31   14   13  

Balance at December 31, 2025 $ 435   $ 115   $ 137   $ 68   $ 115   $ 69   $ 19   $ 27  

Year Ended December 31, 2024

Exelon ComEd PECO BGE PHI Pepco DPL ACE
Balance at December 31, 2023 $ 317   $ 69   $ 95   $ 46   $ 107   $ 52   $ 19   $ 36  
Plus: Current period provision for expected credit losses
248   78   72   37   61   39   10   12  
Less: Write-offs, net of recoveries 159   38   34   27   60   32   12   16  
Balance at December 31, 2024 $ 406   $ 109   $ 133   $ 56   $ 108   $ 59   $ 17   $ 32  

__________
(a) For ComEd, the increase is primarily a result of increased aging of receivables.
(b) For PECO, BGE, and DPL, the increase is primarily a result of increased receivable balances.
(c) For ACE, the decrease is primarily a result of decreased aging of receivables.
(d) For ComEd, PECO, and DPL, the increase is primarily a result of increased disconnection activities.
(e) For ACE, the decrease is primarily a result of decreased disconnection activities.
(f) Recoveries were not material to ComEd, BGE, Pepco, DPL, and ACE.
(g) For PECO, the increase in recoveries collected is primarily a result of increased customer repayments.
193

Table of Contents
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)

Note 5 — Accounts Receivable

The following tables present the rollforward of Allowance for Credit Losses on Other Accounts Receivable.

Year Ended December 31, 2025

Exelon ComEd PECO BGE PHI Pepco DPL ACE
Balance at December 31, 2024 $ 107   $ 34   $ 18   $ 6   $ 49   $ 27   $ 9   $ 13  
Plus: Current period provision (benefit) for expected credit losses (a)(b)
24   10   14   ( 2 ) 2   ( 1 ) 1   2  
Less: Write-offs (c)(d) , net of recoveries (e)
37   21   14   —   2   —   —   2  
Balance at December 31, 2025 $ 94   $ 23   $ 18   $ 4   $ 49   $ 26   $ 10   $ 13  

Year Ended December 31, 2024

Exelon ComEd PECO BGE PHI Pepco DPL ACE
Balance at December 31, 2023 $ 82   $ 17   $ 8   $ 7   $ 50   $ 28   $ 8   $ 14  
Plus: Current period provision (benefit) for expected credit losses
45   21   15   6   3   ( 1 ) 1   3  
Less: Write-offs, net of recoveries 20   4   5   7   4   —   —   4  
Balance at December 31, 2024 $ 107   $ 34   $ 18   $ 6   $ 49   $ 27   $ 9   $ 13  

__________
(a) For ComEd, the decrease is primarily a result of decreased aging of receivables.
(b) For BGE, the decrease is primarily a result of decreased receivable balances.
(c) For ComEd and PECO, the increase is primarily a result of increased disconnection activities.
(d) For BGE and ACE, the decrease is primarily a result of decreased disconnection activities.
(e) 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, 2025 and 2024.

Unbilled customer revenues (a)

Exelon ComEd PECO BGE PHI Pepco DPL ACE
December 31, 2025 $ 1,231   $ 301   $ 278   $ 325   $ 327   $ 155   $ 100   $ 72  
December 31, 2024 1,114   335   254   257   268   121   76   71  

__________
(a) Unbilled customer revenues are classified in Customer accounts receivable, net in the Registrants' Consolidated Balance Sheets.
Other Purchases of Customer and Other Accounts Receivables
For the twelve months ended December 31, 2025 and 2024, the Utility Registrants were required, under separate legislation and regulations in Illinois, Pennsylvania, Maryland, District of Columbia, Delaware, and New Jersey, to purchase certain receivables from alternative retail electric and, as applicable, natural gas suppliers that participated in the utilities' consolidated billing. The following table presents the total receivables purchased.

Total receivables purchased
Exelon ComEd PECO BGE PHI Pepco DPL ACE
Year ended December 31, 2025
$ 4,341   $ 1,066   $ 1,257   $ 700   $ 1,318   $ 823   $ 263   $ 232  
Year ended December 31, 2024
4,128   964   1,111   778   1,275   799   252   224  

194

Table of Contents
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)

Note 6 — Property, Plant, and Equipment

6. Property, Plant, and Equipment (All Registrants)
The following tables present a summary of property, plant, and equipment by asset category at December 31, 2025 and 2024:

Asset Category Exelon ComEd PECO BGE PHI Pepco DPL ACE
December 31, 2025
Electric—transmission and distribution $ 84,282   $ 38,370   $ 13,314   $ 11,687   $ 22,614   $ 14,420   $ 6,423   $ 6,247  
Gas—transportation and distribution 10,499   —   4,649   5,190   940   —   1,094   —  
Common—electric and gas (a)
2,954   —   1,135   1,430   460   —   251   —  
Construction work in progress 5,755   1,997   836   1,236   1,629   1,087   290   238  
Other property, plant, and equipment (b)
908   179   119   76   84   24   38   27  
Total property, plant, and equipment 104,398   40,546   20,053   19,619   25,727   15,531   8,096   6,512  
Less: accumulated depreciation 20,080   8,291   4,131   5,234   4,350   4,784   2,241   1,956  
Property, plant, and equipment, net $ 84,318   $ 32,255   $ 15,922   $ 14,385   $ 21,377   $ 10,747   $ 5,855   $ 4,556  

December 31, 2024
Electric—transmission and distribution $ 79,283   $ 36,493   $ 12,234   $ 11,131   $ 21,130   $ 13,593   $ 6,086   $ 5,947  
Gas—transportation and distribution 9,599   —   4,247   4,796   821   —   976   —  
Common—electric and gas 2,630   —   1,064   1,385   272   —   241   —  
Construction work in progress 4,306   1,219   813   779   1,472   1,002   275   187  
Other property, plant and equipment (a)
809   118   76   48   86   24   37   30  
Total property, plant and equipment 96,627   37,830   18,434   18,139   23,781   14,619   7,615   6,164  
Less: accumulated depreciation 18,445   7,619   4,042   5,005   3,728   4,522   2,075   1,798  
Property, plant, and equipment, net $ 78,182   $ 30,211   $ 14,392   $ 13,134   $ 20,053   $ 10,097   $ 5,540   $ 4,366  

__________
(a) On April 15, 2025, PHI purchased an office building and land in the District of Columbia for $ 177 million which it had been leasing. The lease was terminated on April 15, 2025, in conjunction with the purchase (See Note 9 — Leases for additional information).
(b) Primarily composed of land and non-utility property.

195

Table of Contents
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)

Note 6 — Property, Plant, and Equipment

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 5-80 5-80 5-75 N/A 5-75 N/A
Common - electric and gas 4-75 N/A 5-53 4-45 5-75 N/A 5-75 N/A
Other property, plant, and equipment 4-61 28-50 50 20-50 10-43 10-33 10-43 10-43

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, 2025
Electric—transmission and distribution 2.85 % 3.07 % 2.33 % 2.56 % 2.89 % 2.51 % 3.09 % 3.62 %
Gas—transportation and distribution 2.08 % N/A 1.94 % 2.37 % 1.29 % N/A 1.29 % N/A
Common—electric and gas 6.14 % N/A 6.37 % 7.08 % 2.88 % N/A 5.53 % N/A

December 31, 2024
Electric—transmission and distribution 2.83 % 3.06 % 2.30 % 2.55 % 2.87 % 2.49 % 2.99 % 3.41 %
Gas—transportation and distribution 2.12 % N/A 1.96 % 2.42 % 1.38 % N/A 1.38 % N/A
Common—electric and gas 7.00 % N/A 6.73 % 7.81 % 4.82 % N/A 6.14 % N/A

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

AFUDC
The following table summarizes credits to AFUDC by year:

For the Years Ended December 31,
2025 2024 2023
Exelon $ 275   $ 251   $ 256  
ComEd 94   75   72  
PECO 54   48   46  
BGE 58   39   25  
PHI 69   89   113  
Pepco 49   62   85  
DPL 11   19   16  
ACE 8   8   12  

See Note 1 — Significant Accounting Policies for additional information regarding property, plant and equipment policies. See Note 14 — 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.
196

Table of Contents
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)

Note 7 — Jointly Owned Electric Utility Plant

7. Jointly Owned Electric Utility Plant (Exelon, PECO, PHI, DPL, and ACE)
PECO's, DPL's, and ACE's material undivided ownership interests in transmission facilities jointly owned with non-affiliated utilities as of December 31, 2025 and 2024 were as follows:

Transmission
NJ/DE (a)

Operator PSEG/DPL
Ownership interest various
Exelon’s share at December 31, 2025:
Plant in service $ 119  
Accumulated depreciation 55  
Construction work in progress 16  
Exelon’s share at December 31, 2024:
Plant in service $ 105  
Accumulated depreciation 57  
Construction work in progress 4  

__________
(a) PECO, DPL, and ACE own a 42.55 %, 1 %, and 13.9 % share, respectively, in 151.3 miles of 500 kV 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 500 kV line located over the Delaware River. ACE also has a 21.78 % share in a 500 kV 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, 2025 and 2024 were as follows:

PECO PHI DPL ACE
Ownership interest 56   % 44   % 27   % 17   %
Registrant's share at December 31, 2025:
Plant in service $ 82   $ 73   $ 45   $ 28  
Accumulated depreciation 4   6   4   2  
Construction work in progress —   —   —   —  
Registrant's share at December 31, 2024:
Plant in service $ 84   $ 72   $ 44   $ 28  
Accumulated depreciation 2   3   3   —  
Construction work in progress —   —   —   —  

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.

197

Table of Contents
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)

Note 8 — Asset Retirement Obligations

8. Asset Retirement Obligations (All Registrants)
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, 2023 to December 31, 2025:

Exelon ComEd PECO BGE PHI Pepco DPL ACE
AROs at December 31, 2023 $ 269   $ 150   $ 27   $ 32   $ 56   $ 37   $ 13   $ 6  
Revisions in estimates of cash flows 26   12   1   3   10   10   —   —  

Accretion expense (a)
11   7   1   1   2   2   —   —  

Payments ( 2 ) ( 1 ) ( 1 ) —   —   —   —   —  
AROs at December 31, 2024 $ 304   $ 168   $ 28   $ 36   $ 68   $ 49   $ 13   $ 6  
Revisions in estimates of cash flows 15   19   —   ( 1 ) ( 3 ) ( 1 ) ( 1 ) ( 1 )

Accretion expense (a)
13   8   1   1   3   3   —   —  

Payments ( 8 ) ( 1 ) ( 2 ) —   ( 5 ) ( 5 ) —   —  
AROs at December 31, 2025 $ 324   $ 194   $ 27   $ 36   $ 63   $ 46   $ 12   $ 5  

__________
(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.

9. Leases (All Registrants)
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, 2025. Exelon, ComEd, PECO, and BGE did not have material finance leases in 2025, 2024, or 2023.

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 1-80 1-27 1-9 1-80 1-7 1-7 1-7 1-7
Options to extend the term 3-30 N/A N/A 3-5 3-30 5 3-30 N/A
Options to terminate within 2-7 N/A N/A 2 N/A N/A N/A N/A

198

Table of Contents
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)

Note 9 — Leases

The components of operating lease costs were as follows:

Exelon   ComEd PECO BGE PHI Pepco DPL ACE
For the year ended December 31, 2025
Operating lease costs $ 47   $ —   $ —   $ 7   $ 31   $ 12   $ 9   $ 6  
Variable lease costs 7   —   —   —   1   —   1   —  

Total lease costs (a)
$ 54   $ —   $ —   $ 7   $ 32   $ 12   $ 10   $ 6  

For the year ended December 31, 2024
Operating lease costs $ 57   $ —   $ —   $ 8   $ 41   $ 10   $ 10   $ 5  
Variable lease costs 9   —   —   —   3   1   1   1  
Total lease costs (a)
$ 66   $ —   $ —   $ 8   $ 44   $ 11   $ 11   $ 6  

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  

__________
(a) Excludes sublease income recorded at Exelon, PHI, and DPL of $ 4 million for the years ended December 31, 2025, 2024, and 2023.
The components of financing lease costs were as follows:

PHI Pepco DPL ACE
For the year ended December 31, 2025
Amortization of ROU asset $ 21   $ 7   $ 8   $ 6  
Interest on lease liabilities 6   2   2   2  
Total finance lease cost $ 27   $ 9   $ 10   $ 8  

For the year ended December 31, 2024
Amortization of ROU asset $ 18   $ 7   $ 7   $ 4  
Interest on lease liabilities 6   2   2   2  
Total finance lease cost $ 24   $ 9   $ 9   $ 6  

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  

199

Table of Contents
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)

Note 9 — Leases

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:

Operating Leases
Exelon   ComEd PECO BGE PHI (a)
Pepco DPL ACE
At December 31, 2025
Operating lease ROU assets
Other deferred debits and other assets $ 139   $ —  $ 1   $ 17   $ 54   $ 22   $ 23   $ 5  

Operating lease liabilities
Other current liabilities $ 19   $ —   $ —   $ 3   $ 10   $ 4   $ 5   $ 1  
Other deferred credits and other liabilities 146   —   1   13   55   22   28   5  
Total operating lease liabilities $ 165   $ —  $ 1   $ 16   $ 65   $ 26   $ 33   $ 6  

At December 31, 2024
Operating lease ROU assets
Other deferred debits and other assets $ 224   $ —  $ —  $ 24   $ 127   $ 26   $ 27   $ 7  

Operating lease liabilities
Other current liabilities $ 38   $ —   $ —   $ 3   $ 30   $ 5   $ 6   $ 3  
Other deferred credits and other liabilities 217   —   —   16   116   25   32   5  
Total operating lease liabilities $ 255   $ —   $ —   $ 19   $ 146   $ 30   $ 38   $ 8  
__________
(a) On April 15, 2025, PHI purchased an office building and land in the District of Columbia for $ 177 million which it had been leasing. PHI's operating lease liability and operating lease ROU asset amounts for the office building and land were $ 64 million and $ 47 million, respectively, at the time of the purchase. In conjunction with the purchase, the lease has been terminated and the difference of $ 17 million between the operating lease liability and operating lease ROU asset were recorded as an adjustment to the carrying value of the purchased assets.

Finance Leases
PHI Pepco DPL ACE
At December 31, 2025
Finance lease ROU assets
Plant, property and equipment, net $ 68   $ 23   $ 25   $ 20  

Finance lease liabilities
Long-term debt due within one year $ 19   $ 7   $ 7   $ 5  
Long-term debt 53   18   20   15  
Total finance lease liabilities $ 72   $ 25   $ 27   $ 20  

At December 31, 2024
Finance lease ROU assets
Plant, property and equipment, net $ 72   $ 26   $ 26   $ 20  

Finance lease liabilities
Long-term debt due within one year $ 17   $ 6   $ 7   $ 4  
Long-term debt 58   21   21   16  
Total finance lease liabilities $ 75   $ 27   $ 28   $ 20  

200

Table of Contents
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)

Note 9 — Leases

Future minimum lease payments for operating and finance leases as of December 31, 2025 were as follows:

Operating Leases
Year Exelon   ComEd PECO BGE PHI Pepco DPL ACE
2026 $ 26   $ —   $ 1   $ 4   $ 13   $ 5   $ 6   $ 2  
2027 24   —   —   2   12   4   7   2  
2028 24   —   —   3   11   4   6   1  
2029 24   —   —   3   11   4   6   1  
2030 24   —   —   3   11   4   6   1  
Remaining years 91   —   —   18   21   9   12   —  
Total 213   —   1   33   79   30   43   7  
Interest 48   —   —   17   14   4   10   1  
Total operating lease liabilities $ 165   $ —   $ 1   $ 16   $ 65   $ 26   $ 33   $ 6  

Finance Leases
Year PHI Pepco DPL ACE
2026 $ 21   $ 8   $ 8   $ 6  
2027 19   7   7   5  
2028 15   5   6   4  
2029 12   4   5   2  
2030 7   2   2   2  
Remaining years 6   1   2   3  
Total 80   27   30   22  
Interest 8   2   3   2  
Total finance lease liabilities $ 72   $ 25   $ 27   $ 20  

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, 2025 9.3 — 6.4 19.2 6.2 6.6 6.3 3.2
At December 31, 2024 8.2 1.7 5.3 17.4 5.3 7.1 6.9 3.1

Finance Leases
PHI Pepco DPL ACE
At December 31, 2025 4.1 4.0 3.9 4.4
At December 31, 2024 4.4 4.4 4.2 4.5

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, 2025 3.9   % —   % 4.4   % 5.0   % 4.2   % 4.2   % 4.2   % 4.2   %
At December 31, 2024 4.0   % 0.8   % 2.8   % 5.0   % 4.2   % 4.1   % 4.1   % 3.9   %

Finance Leases
PHI Pepco DPL ACE
At December 31, 2025 3.8   % 3.8   % 3.6   % 3.9   %
At December 31, 2024 3.4   % 3.5   % 3.1   % 3.5   %

201

Table of Contents
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)

Note 9 — Leases

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, 2025 $ 35   $ —   $ —   $ 4   $ 22   $ 6   $ 7   $ 3  
For the year ended December 31, 2024 48   —   —   4   35   7   7   3  
For the year ended December 31, 2023 65   2   —   15   37   7   9   3  

Financing Cash Flows from Finance Leases
PHI Pepco DPL ACE
For the year ended December 31, 2025 $ 20   $ 7   $ 8   $ 5  
For the year ended December 31, 2024 17   6   7   4  
For the year ended December 31, 2023 15   5   6   4  

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, 2025 $ 3   $ —   $ —   $ —   $ 3   $ 1   $ 2   $ —  
For the year ended December 31, 2024 8   —   —   1   5   1   2   2  
For the year ended December 31, 2023 35   —   —   32   3   —   1   2  

Finance Leases
PHI Pepco DPL ACE
For the year ended December 31, 2025 $ 15   $ 4   $ 6   $ 5  
For the year ended December 31, 2024 15   7   4   4  
For the year ended December 31, 2023 11   5   3   3  

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, 2025. ACE did not have any operating leases for which they are the lessors for the years ended December 31, 2025, 2024, and 2023.

Exelon   ComEd PECO BGE PHI Pepco DPL
Real estate ● ● ● ● ● ● ●

(in years) Exelon   ComEd PECO BGE PHI Pepco DPL
Remaining lease terms 1-77 1-11 1-77 17 1-7 1 6-7
Options to extend the term 1-79 5-79 1-50 N/A N/A N/A N/A

202

Table of Contents
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)

Note 9 — Leases

The components of lease income were as follows:

Exelon   ComEd PECO BGE PHI Pepco DPL
For the year ended December 31, 2025
Operating lease income $ 5   $ —   $ —   $ —   $ 4   $ —   $ 4  
Variable lease income 1   —   —   —   1   —   1  

For the year ended December 31, 2024
Operating lease income $ 4   $ —   $ —   $ —   $ 4   $ —   $ 3  
Variable lease income 1   —   —   —   1   —   1  

For the year ended December 31, 2023
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, 2025 were as follows:

Year Exelon   ComEd PECO BGE PHI Pepco DPL
2026 $ 7   $ 1   $ 1   $ —   $ 5   $ —   $ 4  
2027 7   —   2   —   5   —   4  
2028 6   —   1   —   5   —   5  
2029 6   —   1   —   4   —   5  
2030 5   —   1   —   4   —   4  
Remaining years 17   —   7   1   9   —   9  
Total $ 48   $ 1   $ 13   $ 1   $ 32   $ —   $ 31  

10. Intangible Assets
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, 2025 and 2024. There were no additions or impairments during the years ended December 31, 2025, 2024, and 2023.

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 4 — 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
203

Table of Contents
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)

Note 10 — Intangible Assets

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 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.
2025 and 2024 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, 2025 and 2024. 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 2 — 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, 2025 and 2024. 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, 2025 and 2024. 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, 2025 December 31, 2024
Gross Accumulated Amortization Net Gross Accumulated Amortization Net
Exelon
Unamortized Energy Contracts $ ( 1,515 ) $ 1,494   $ ( 21 ) $ ( 1,515 ) $ 1,489   $ ( 26 )
Software License 81   ( 81 ) —   81   ( 78 ) 3  
Exelon Total $ ( 1,434 ) $ 1,413   $ ( 21 ) $ ( 1,434 ) $ 1,411   $ ( 23 )
PHI
Unamortized Energy Contracts $ ( 1,515 ) $ 1,494   $ ( 21 ) $ ( 1,515 ) $ 1,489   $ ( 26 )

204

Table of Contents
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)

Note 10 — Intangible Assets

The following table summarizes the amortization expense related to intangible assets and liabilities for each of the years ended December 31, 2025, 2024, and 2023:

For the Years Ended December 31, Exelon (a)
PHI (a)

2025 $ ( 2 ) $ ( 5 )
2024 ( 1 ) ( 9 )
2023 ( 1 ) ( 10 )

__________
(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.

11. Income Taxes (All Registrants)
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, 2025
 Exelon ComEd PECO BGE PHI Pepco DPL ACE
Included in operations:
Federal
Current $ 119   $ 143   $ 97   $ 74   $ 91   $ 47   $ 28   $ 20  
Deferred 169   ( 16 ) ( 45 ) 28   60   18   16   24  
Investment tax credit amortization ( 1 ) ( 1 ) —   —   —   —   —   —  
State
Current 13   80   —   —   16   7   8   —  
Deferred 223   55   ( 23 ) 57   72   34   17   23  
Total $ 523   $ 261   $ 29   $ 159   $ 239   $ 106   $ 69   $ 67  

For the Year Ended December 31, 2024
 Exelon ComEd PECO BGE PHI Pepco DPL ACE
Included in operations:
Federal
Current $ 42   $ 76   $ 51   $ 45   $ 97   $ 50   $ 29   $ 16  
Deferred ( 27 ) ( 76 ) ( 46 ) ( 42 ) 21   3   3   20  
Investment tax credit amortization ( 2 ) ( 1 ) —   —   ( 1 ) —   —   —  
State
Current 37   60   —   —   19   17   4   —  
Deferred 157   57   ( 17 ) 46   53   20   13   19  
Total $ 207   $ 116   $ ( 12 ) $ 49   $ 189   $ 90   $ 49   $ 55  

205

Table of Contents
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)

Note 11 — Income Taxes

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  

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

For the Year Ended December 31, 2025 (a)(b)

Exelon ComEd (c)
PECO (d)
BGE
U.S. Federal Statutory Tax Rate $ 691   21.0   % $ 296   21.0   % $ 177   21.0   % $ 155   21.0   %
Increase (decrease) due to:
State income taxes, net of Federal income tax benefit 187   5.7   107   7.6   ( 18 ) ( 2.1 ) 45   6.1  
Tax credits ( 13 ) ( 0.4 ) ( 6 ) ( 0.4 ) —   —   ( 3 ) ( 0.4 )
Nontaxable or nondeductible items 13   0.4   1   0.1   1   0.1   1   0.2  
Other Adjustments
Plant basis differences ( 145 ) ( 4.4 ) ( 13 ) ( 1.0 ) ( 117 ) ( 13.9 ) ( 11 ) ( 1.5 )
Excess deferred tax ( 208 ) ( 6.3 ) ( 123 ) ( 8.7 ) ( 14 ) ( 1.7 ) ( 28 ) ( 3.8 )
Amortization of ITC, net deferred taxes ( 2 ) ( 0.1 ) ( 1 ) ( 0.1 ) —   —   —   —  
Effective Tax Rate $ 523   15.9   % $ 261   18.5   % $ 29   3.4   % $ 159   21.6   %

For the Year Ended December 31, 2025 (a)(b)

PHI PEPCO DPL ACE
U.S. Federal Statutory Tax Rate $ 218   21.0   % $ 106   21.0   % $ 62   21.0   % $ 53   21.0   %
Increase (decrease) due to:
State income taxes, net of Federal income tax benefit 70   6.7   32   6.3   20   6.8   18   7.1  
Tax credits ( 4 ) ( 0.4 ) ( 2 ) ( 0.4 ) ( 1 ) ( 0.3 ) ( 1 ) ( 0.4 )
Nontaxable or nondeductible items 3   0.3   2   0.3   ( 1 ) ( 0.3 ) 1   0.2  
Other Adjustments
Plant basis differences ( 5 ) ( 0.5 ) ( 3 ) ( 0.6 ) ( 1 ) ( 0.3 ) ( 1 ) ( 0.4 )
Excess deferred tax ( 42 ) ( 4.0 ) ( 29 ) ( 5.7 ) ( 10 ) ( 3.4 ) ( 3 ) ( 1.2 )
Amortization of ITC, net deferred taxes ( 1 ) ( 0.1 ) —   —   —   —   —   —  
Effective Tax Rate $ 239   23.0   % $ 106   20.9   % $ 69   23.5   % $ 67   26.3   %

206

Table of Contents
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)

Note 11 — Income Taxes

For the Year Ended December 31, 2024 (a)(b)

Exelon ComEd (c)
PECO (d)
BGE (e)

U.S. Federal Statutory Tax Rate $ 560   21.0   % $ 248   21.0   % $ 113   21.0   % $ 121   21.0   %
Increase (decrease) due to:
State income taxes, net of Federal income tax benefit 153   5.7   92   7.8   ( 13 ) ( 2.4 ) 36   6.3  
Tax credits ( 19 ) ( 0.6 ) ( 13 ) ( 1.1 ) —   —   ( 2 ) ( 0.3 )
Nontaxable or nondeductible items 6   0.2   2   0.2   —   —   1   0.1  
Other Adjustments
Plant basis differences ( 120 ) ( 4.5 ) ( 8 ) ( 0.7 ) ( 96 ) ( 17.8 ) ( 8 ) ( 1.4 )
Excess deferred tax ( 371 ) ( 13.9 ) ( 204 ) ( 17.3 ) ( 16 ) ( 3.0 ) ( 99 ) ( 17.2 )
Amortization of ITC, net deferred taxes ( 2 ) ( 0.1 ) ( 1 ) ( 0.1 ) —   —   —   —  
Effective Tax Rate $ 207   7.8   % $ 116   9.8   % $ ( 12 ) ( 2.2 ) % $ 49   8.5   %

For the Year Ended December 31, 2024 (a)(b)

PHI PEPCO DPL ACE
U.S. Federal Statutory Tax Rate $ 195   21.0   % $ 101   21.0   % $ 54   21.0   % $ 44   21.0   %
Increase (decrease) due to:
State income taxes, net of Federal income tax benefit 57   6.1   29   6.0   13   5.0   15   7.1  
Tax credits ( 4 ) ( 0.4 ) ( 2 ) ( 0.4 ) ( 1 ) ( 0.4 ) ( 1 ) ( 0.5 )
Nontaxable or nondeductible items 1   0.1   —   —   1   0.4   —   —  
Other Adjustments
Plant basis differences ( 7 ) ( 0.8 ) ( 5 ) ( 1.0 ) ( 3 ) ( 1.2 ) 1   0.5  
Excess deferred tax ( 52 ) ( 5.6 ) ( 33 ) ( 6.8 ) ( 15 ) ( 5.8 ) ( 4 ) ( 1.9 )
Amortization of ITC, net deferred taxes ( 1 ) ( 0.1 ) —   —   —   —   —   —  
Effective Tax Rate $ 189   20.3   % $ 90   18.8   % $ 49   19.0   % $ 55   26.2   %

For the Year Ended December 31, 2023 (a)(b)

Exelon ComEd PECO (d)
BGE
U.S. Federal Statutory Tax Rate $ 567   21.0   % $ 295   21.0   % $ 122   21.0   % $ 130   21.0   %
Increase (decrease) due to:
State income taxes, net of Federal income tax benefit 104   3.8   111   7.9   ( 6 ) ( 1.0 ) 40   6.5  
Tax credits ( 16 ) ( 0.6 ) ( 8 ) ( 0.6 ) —   —   ( 3 ) ( 0.5 )
Nontaxable or nondeductible items 7   0.3   1   0.2   2   0.2   —   —  
Other Adjustments
Plant basis differences ( 106 ) ( 3.9 ) ( 7 ) ( 0.5 ) ( 84 ) ( 14.4 ) ( 6 ) ( 1.0 )
Excess deferred tax ( 180 ) ( 6.7 ) ( 77 ) ( 5.5 ) ( 14 ) ( 2.4 ) ( 28 ) ( 4.5 )
Amortization of ITC, net deferred taxes ( 2 ) ( 0.1 ) ( 1 ) ( 0.1 ) —   —   —   —  
Effective Tax Rate $ 374   13.8   % $ 314   22.4   % $ 20   3.4   % $ 133   21.5   %

207

Table of Contents
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)

Note 11 — Income Taxes

For the Year Ended December 31, 2023 (a)(b)

PHI PEPCO DPL ACE
U.S. Federal Statutory Tax Rate $ 148   21.0   % $ 75   21.0   % $ 45   21.0   % $ 33   21.0   %
Increase (decrease) due to:
State income taxes, net of Federal income tax benefit 43   6.1   20   5.5   13   6.1   11   7.1  
Tax credits ( 3 ) ( 0.6 ) ( 3 ) ( 0.7 ) ( 1 ) ( 0.4 ) ( 1 ) ( 0.6 )
Nontaxable or nondeductible items —   0.1   1   0.3   —   —   1   0.7  
Other Adjustments
Plant basis differences ( 10 ) ( 1.5 ) ( 8 ) ( 2.2 ) ( 2 ) ( 0.8 ) ( 1 ) ( 0.6 )
Excess deferred tax ( 61 ) ( 8.6 ) ( 34 ) ( 9.6 ) ( 20 ) ( 9.4 ) ( 7 ) ( 4.5 )
Amortization of ITC, net deferred taxes ( 1 ) ( 0.1 ) —   —   —   —   —   —  
Effective Tax Rate $ 116   16.4   % $ 51   14.3   % $ 35   16.5   % $ 36   23.1   %

__________
(a) Positive percentages represent income tax expense. Negative percentages represent income tax benefit.
(b) Exelon and Registrants had no adjustments related to the following disclosure categories: Foreign Tax Effects, Effects of Changes in Tax law or Rates Enacted in the Current Period, Effects of Cross-Border Tax Laws, Changes in Valuation Allowances, and Changes in Unrecognized Tax Benefits.
(c) For ComEd, the lower effective tax rate is primarily due to CEJA which resulted in the acceleration of certain income tax benefits being provided to customers.
(d) For PECO, the lower effective tax rate is primarily related to state income taxes, net of federal income tax benefit and plant basis differences attributable to tax repair deductions.
(e) For BGE, the lower effective tax rate is primarily due to the Maryland Multi-year plan which resulted in the acceleration of certain tax benefits being provided to customers.

State and local Income Tax (Major Jurisdictions)
The state and local jurisdictions that comprise the majority of the effect of the state and local income tax, net of federal income taxes category by Registrant are presented below:

2025 2024 2023
Exelon IL, MD IL, MD MD, IL
ComEd IL IL IL
PECO PA PA PA
BGE MD MD MD
PHI MD, NJ MD, NJ MD, NJ
Pepco MD MD MD
DPL DE DE DE
ACE NJ NJ NJ

208

Table of Contents
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)

Note 11 — Income Taxes

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, 2025 and 2024 are presented below:

At December 31, 2025
Exelon ComEd PECO BGE PHI Pepco DPL ACE
Plant basis differences $ ( 13,989 ) $ ( 5,231 ) $ ( 2,676 ) $ ( 2,411 ) $ ( 3,596 ) $ ( 1,628 ) $ ( 1,033 ) $ ( 936 )
Accrual based contracts 18   —   —   —   5   —   —   —  
Derivatives and other financial instruments 26   36   —   —   1   —   —   —  
Deferred pension and postretirement obligation 506   ( 382 ) ( 41 ) ( 20 ) ( 60 ) ( 57 ) ( 28 ) —  
Deferred debt refinancing costs 101   ( 4 ) —   ( 2 ) 91   ( 2 ) ( 1 ) ( 1 )
Regulatory assets and liabilities ( 1,756 ) ( 490 ) ( 324 ) ( 39 ) ( 122 ) ( 36 ) 29   ( 25 )
Tax loss carryforward, net of valuation allowances 275   —   72   63   67   —   14   53  
Tax credit carryforward —   —   —   —   —   —   —   —  
Corporate Alternative Minimum Tax 553   —   289   142   71   44   17   20  
Investment in partnerships ( 28 ) —   —   —   —   —   —   —  
Other, net 601   250   86   26   166   76   9   23  
Deferred income tax liabilities (net) ( 13,693 ) ( 5,821 ) ( 2,594 ) ( 2,241 ) ( 3,377 ) ( 1,603 ) ( 993 ) ( 866 )
Unamortized investment tax credits ( 15 ) ( 7 ) —   ( 1 ) ( 7 ) ( 1 ) ( 3 ) ( 3 )
Total deferred income tax liabilities (net) and unamortized investment tax credits $ ( 13,708 ) $ ( 5,828 ) $ ( 2,594 ) $ ( 2,242 ) $ ( 3,384 ) $ ( 1,604 ) $ ( 996 ) $ ( 869 )

209

Table of Contents
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)

Note 11 — Income Taxes

At December 31, 2024
Exelon ComEd PECO BGE PHI Pepco DPL ACE
Plant basis differences $ ( 13,150 ) $ ( 5,069 ) $ ( 2,446 ) $ ( 2,232 ) $ ( 3,371 ) $ ( 1,512 ) $ ( 975 ) $ ( 881 )
Accrual based contracts 19   —   —   —   6   —   —   —  
Derivatives and other financial instruments 21   36   —   —   1   —   —   —  
Deferred pension and postretirement obligation 512   ( 339 ) ( 39 ) ( 24 ) ( 68 ) ( 64 ) ( 32 ) —  
Deferred debt refinancing costs 108   ( 4 ) —   ( 2 ) 98   ( 3 ) ( 1 ) ( 1 )
Regulatory assets and liabilities ( 1,665 ) ( 515 ) ( 254 ) ( 37 ) ( 96 ) ( 16 ) 33   ( 18 )
Tax loss carryforward, net of valuation allowances 283   —   63   78   68   —   16   51  
Tax credit carryforward 142   —   —   —   —   —   —   —  
Corporate Alternative Minimum Tax 369   47   166   95   2   2   4   8  
Investment in partnerships ( 27 ) —   —   —   —   —   —   —  
Other, net 612   249   77   24   180   85   10   27  
Deferred income tax liabilities (net) ( 12,776 ) ( 5,595 ) ( 2,433 ) ( 2,098 ) ( 3,180 ) ( 1,508 ) ( 945 ) ( 814 )
Unamortized investment tax credits ( 10 ) ( 6 ) —   ( 1 ) ( 3 ) ( 1 ) ( 1 ) ( 2 )
Total deferred income tax liabilities (net) and
unamortized investment tax credits $ ( 12,786 ) $ ( 5,601 ) $ ( 2,433 ) $ ( 2,099 ) $ ( 3,183 ) $ ( 1,509 ) $ ( 946 ) $ ( 816 )

The following table provides federal and state tax attribute carryforwards at December 31, 2025 for Exelon, ComEd, PECO, BGE, PHI, Pepco, DPL, and ACE. The state net operating loss carryforwards and any corresponding valuation allowance are presented on a post-apportioned basis.

Exelon ComEd PECO BGE PHI Pepco DPL ACE
Federal

Federal general business credits carryforwards $ —   $ —   $ —   $ —   $ —   $ —   $ —   $ —  
Corporate Alternative Minimum Tax credit carryforward (a)
$ 553   $ —   $ 289   $ 142   $ 71   $ 44   $ 17   $ 20  
State
State net operating loss carryforwards $ 6,684   $ —   $ 1,944   $ 972   $ 1,387   $ —   $ 635   $ 752  
Deferred taxes on state tax attributes (net of federal taxes) $ 381   $ —   $ 76   $ 63   $ 96   $ —   $ 43   $ 53  
Valuation allowance on state tax attributes (net of federal taxes) (b)
$ 106   $ —   $ 4   $ —   $ 29   $ —   $ 29   $ —  
Year in which net operating loss or credit carryforwards will begin to expire (c)
2031 N/A 2031 2033 2031 N/A 2033 2031

__________
(a) For Exelon, PECO, BGE, PHI, Pepco, DPL, and ACE, the Corporate Alternative Minimum Tax credit carryforward has an indefinite carryforward period.
(b) 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 Pennsylvania net operating losses that are expected to expire before realization. For DPL, a full valuation allowance has
210

Table of Contents
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)

Note 11 — Income Taxes

been recorded against Delaware net operating losses carryforwards due to a change in Delaware tax law that limits the ability of corporate taxpayers to monetize net operating losses.
(c) 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, DPL, and ACE. Amounts for ComEd, PECO, BGE, and Pepco are not material.

Exelon (a)
PHI DPL ACE
Balance at January 1, 2023 $ 148   $ 59   $ 4   $ 17  
Change to positions that only affect timing ( 57 ) ( 9 ) ( 2 ) ( 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   $ 2   $ 15  
Change to positions that only affect timing 10   10   —   —  
Increases based on tax positions related to 2024 4   1   10   —  
Increases based on tax positions prior to 2024 2   —   —   —  
Decreases based on tax positions prior to 2024 ( 14 ) ( 14 ) —   ( 14 )
Balance at December 31, 2024 $ 96   $ 48   $ 12   $ 1  
Change to positions that only affect timing —   ( 1 ) —   —  
Increases based on tax positions related to 2025 3   1   —   —  
Increases based on tax positions prior to 2025 1   —   —   —  
Decreases based on tax positions prior to 2025 —   —   —   —  

Balance at December 31, 2025 $ 100   $ 48   $ 12   $ 1  

______
(a) At December 31, 2025 and 2024, Exelon recorded a receivable of $ 31  million and $ 31  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 of Exelon and Constellation in February 2022.
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, 2025 $ 83  
December 31, 2024 69  
December 31, 2023 71  

At December 31, 2025 Exelon, PHI, and DPL have approximately $ 65  million, $ 6  million, and $ 1  million, respectively, of unrecognized federal tax benefits that could significantly change within the 12 months after the reporting date based on the outcome of pending refund claims that impacts the effective tax rate.
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, 2025 (a)
$ 61  
December 31, 2024 (b)
76  

211

Table of Contents
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)

Note 11 — Income Taxes

__________
(a) At December 31, 2025, Exelon classified $ 7  million and $ 54  million of the interest receivable as current and noncurrent, respectively, based on the expected timing for settlement in cash. At December 31, 2025, Exelon recorded a receivable of $ 12  million in noncurrent Other assets in the Consolidated Balance Sheet for Constellation's share of net interest for periods prior to the separation of Exelon and Constellation in February 2022.
(b) At December 31, 2024, Exelon classified $ 27  million and $ 49  million of the interest receivable as current and noncurrent, respectively, based on the expected timing for settlement in cash. At December 31, 2024, Exelon recorded a receivable of $ 9 million in noncurrent Other assets in the Consolidated Balance Sheet for Constellation's share of net interest for periods prior to the separation of Exelon and Constellation in February 2022.
The Registrants did not record material interest or penalties related to tax positions reflected in their Consolidated Balance Sheets. Interest and penalties 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)
2010-2024
All Registrants
Delaware separate corporate income tax returns 2010-2024
DPL
District of Columbia combined corporate income tax returns 2022-2024
Exelon, PHI, Pepco
Illinois unitary corporate income tax returns 2012-2024
Exelon, ComEd
Maryland separate company corporate net income tax returns 2010-2024
BGE, Pepco, DPL
New Jersey combined corporate income tax returns 2021-2024
Exelon
New Jersey separate corporate income tax returns 2021-2024
ACE
Pennsylvania separate corporate income tax returns 2021-2024
Exelon
Pennsylvania separate corporate income tax returns 2021-2024
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.

212

Table of Contents
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)

Note 11 — Income Taxes

Tax Payments (Refunds) by Major Jurisdiction

For the Year Ended December 31, 2025
 Exelon ComEd PECO BGE PHI Pepco DPL ACE
Federal (a)
$ —   $ 128   $ ( 186 ) $ ( 95 ) $ 88   $ 69   $ 13   $ 11  
Delaware 8   —   —   —   8   —   7   —  
District of Columbia —   —   —   —   4   6   —   —  
Illinois ( 1 ) 96   —   —   —   —   —   —  
Maryland 14   —   —   —   14   13   —   —  

Pennsylvania ( 10 ) —   —   —   —   —   —   —  
Other States 1   —   —   —   —   —   —   —  
Total Payments (Refunds) $ 12   $ 224   $ ( 186 ) $ ( 95 ) $ 114   $ 88   $ 20   $ 11  

For the Year Ended December 31, 2024
 Exelon ComEd PECO BGE PHI Pepco DPL ACE
Federal $ 54   $ 188   $ 128   $ 100   $ 119   $ 62   $ 43   $ 20  
Delaware 13   —   —   —   13   —   13   —  
District of Columbia —   —   —   —   5   21   —   —  
Illinois —   62   —   —   —   —   —   —  
Maryland 13   —   —   —   13   13   —   —  

Pennsylvania —   —   —   —   —   —   —   —  
Other States 1   —   —   —   —   —   1   —  
Total Payments $ 81   $ 250   $ 128   $ 100   $ 150   $ 96   $ 57   $ 20  

For the Year Ended December 31, 2023
 Exelon ComEd PECO BGE PHI Pepco DPL ACE
Federal $ 18   $ 40   $ ( 24 ) $ 29   $ 25   $ 14   $ 6   $ 9  
Delaware 2   —   —   —   2   —   —   —  
District of Columbia —   —   —   —   ( 6 ) ( 8 ) —   —  
Illinois —   ( 28 ) —   —   —   —   —   —  
Maryland 1   —   —   —   —   —   —   —  

Pennsylvania ( 1 ) —   —   —   —   —   —   —  
Other States ( 10 ) ( 1 ) —   —   —   —   —   —  
Total Payments (Refunds) $ 10   $ 11   $ ( 24 ) $ 29   $ 21   $ 6   $ 6   $ 9  
__________
(a) In 2025, Exelon received a one-time federal refund claim that reduced current year federal tax payments to a net zero.

Other Tax Matters
Tax Matters Agreement (Exelon)
In February 2022, in connection with the separation between Exelon and Constellation, the parties entered into a TMA. The TMA governs the respective rights, responsibilities, and obligations between Exelon and Constellation after the separation with respect to tax liabilities, refunds and attributes for open tax years that Constellation was part of Exelon’s consolidated group for U.S. federal, state, and local tax purposes.
Indemnification for Taxes. As a former subsidiary of Exelon, Constellation has joint and several liability with Exelon to the IRS and certain state jurisdictions relating to the taxable periods prior to the separation. The TMA specifies that Constellation is liable for their share of taxes required to be paid by Exelon with respect to taxable periods prior to the separation to the extent Constellation would have been responsible for such taxes under the existing Exelon tax sharing agreement when Constellation was included in Exelon's consolidated group. At December 31, 2025, there is no balance due to or from Constellation.
213

Table of Contents
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)

Note 11 — Income Taxes

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 when Constellation was included in Exelon's consolidated group. At December 31, 2025, there is no balance due to or from Constellation.
Tax Attributes . At the date of separation certain tax attributes, primarily tax credit carryforwards, that were generated by Constellation prior to the separation, 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 2025, Exelon remitted $ 143  million of payments to Constellation for the utilization of pre-separation tax credit carryforwards. At December 31, 2025, Exelon recorded a payable of $ 175  million and $ 21  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 will now pay the greater of 15.0% of financial statement pre-tax income (with certain adjustments) or their regular federal tax liability, which is federal taxable income x 21.0% federal corporate tax rate. 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.
Beginning in 2023, based on the existing statue, Exelon and each of the Utility Registrants will be subject to and will report the CAMT on a separate Registrant basis in the Consolidated Statements of Operations and Comprehensive Income and the Consolidated Balance Sheets. The deferred tax asset related to the minimum tax credit carryforward will be realized to the extent Exelon’s consolidated deferred tax liabilities exceed the minimum tax credit carryforward. Exelon’s deferred tax liabilities are expected to exceed the minimum tax credit carryforward for the foreseeable future and thus no valuation allowance is required.
On September 12, 2024, the U.S. Treasury issued proposed regulations providing further guidance addressing the implementation of CAMT. The proposed regulations are consistent with Exelon’s prior interpretation and therefore there are no financial statement impacts. Exelon will continue to monitor and assess the potential financial statement impacts of final regulations or other guidance when issued.
On September 30, 2025, the U.S. Treasury issued interim guidance addressing the implementation of CAMT in the form of a notice. The guidance allows entities with regulated operations a repairs adjustment for CAMT purposes, however the provision was drafted in a manner that does not achieve that intended result. Thus, the guidance does not benefit Exelon and has no financial statement impact. Exelon will continue to monitor and assess the potential financial statement impacts of future regulations or other guidance when issued.
Allocation of Income Taxes to Regulated Utilities (All Registrants)
In Q2 2024, the IRS issued a series of PLRs, to another taxpayer, providing guidance with respect to the application of the tax normalization rules to the allocation of consolidated tax benefits among the members of a consolidated group associated with NOLC for ratemaking purposes. The rulings provide that for ratemaking purposes the tax benefit of NOLC should be reflected on a separate company basis not taking into consideration the utilization of losses by other affiliates. A PLR issued to another taxpayer may not be relied on as precedent.
For the Registrants, except for PECO, the methodology prescribed by the IRS in these PLRs could result in a material reduction of the regulatory liability established for EDITs arising from the TCJA corporate tax rate change that are being amortized and flowed through to customers as well as a reduction in the accumulated deferred income taxes included in rate base for ratemaking purposes. The Utility Registrants, except for PECO, filed PLR requests with the IRS confirming the treatment of the NOLC for ratemaking purposes. The Utility Registrants will record the impact, if any, upon receiving the PLR from the IRS.
One Big Beautiful Bill Act (All Registrants)
On July 4, 2025, the OBBBA was signed into law. The bill permanently extends expiring tax benefits of the TCJA and provides additional tax relief for individuals and businesses while accelerating the phase-out and curtailment
214

Table of Contents
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)

Note 11 — Income Taxes

of certain renewable energy tax credits enacted by the IRA. The tax law changes enacted as part of OBBBA will not have a direct material impact on the Registrants’ financial statements.
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 year ended December 31, 2023. There were no impacts to Exelon, ComEd, BGE, PHI, Pepco, DPL, and ACE for the years ended December 31, 2025 and 2024.

December 31, 2025 Exelon
Decrease to Deferred Income Tax Liability and Income Tax Expense, Net of Federal Taxes $ —  

December 31, 2024
Decrease to Deferred Income Tax Liability and Income Tax Expense, Net of Federal Taxes —  

December 31, 2023
Decrease to Deferred Income Tax Liability and Income Tax Expense, Net of Federal Taxes ( 54 )

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, 2025, 2024, and 2023.

ComEd PECO BGE PHI Pepco DPL ACE
December 31, 2025 $ 20   $ 14   $ 12   $ 23   $ 12   $ 7   $ 4  
December 31, 2024 30   15   14   16   9   5   2  
December 31, 2023 (a)
13   19   —   10   4   —   2  
__________
(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.

12. Retirement Benefits (All Registrants)
Exelon sponsors defined benefit pension and OPEB plans. Substantially all non-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, most newly-hired BSC non-represented, non-craft employees are not eligible to participate in defined benefit pension plans; January 1, 2021, most newly hired utility management employees are not eligible; and certain newly-hired union employees, pursuant to their collective bargaining agreements, are not eligible. In lieu of pension participation, affected employees are eligible to receive an automatic company 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. 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. Certain union represented employees are not eligible for retiree healthcare benefits pursuant to their collective bargaining
215

Table of Contents
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)

Note 12 — Retirement Benefits

agreements. Effective January 1, 2022, management employees retiring on or after that date are no longer eligible for retiree life insurance benefits.
The tables below show the pension and OPEB plans in which current and former employees of each operating company participated as of December 31, 2025:

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 X X X
Exelon Corporation Supplemental Management Retirement Plan 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 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
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 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.

216

Table of Contents
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)

Note 12 — Retirement Benefits