EXELON CORP (EXC)

CIK: 0001109357. SIC: 4931 Electric & Other Services Combined. Latest 10-K as of: 2026-02-12.

SIC breadcrumb: Transportation, Communications, Electric, Gas, And Sanitary Services > Electric, Gas, And Sanitary Services > SIC 4931 Electric & Other Services Combined

SEC company page: https://www.sec.gov/edgar/browse/?CIK=1109357. Latest filing source: 0001109357-26-000018.

Selected Fundamentals

Financials

Annual standardized facts from SEC companyfacts as of latest extracted filing date 2026-02-12. Source: https://data.sec.gov/api/xbrl/companyfacts/CIK0001109357.json. Derived margins are computed from the extracted annual SEC facts.

Flow metrics use full-year FY periods from 10-K/10-K/A filings; balance-sheet metrics use FY-end instants. Missing metrics are omitted rather than fabricated.

Financial Charts

Macro Cross-References

• CPIAUCSL - Consumer Price Index for All Urban Consumers: All Items in U.S. City Average
• UNRATE - Unemployment Rate
• FEDFUNDS - Federal Funds Effective Rate
• CES0500000003 - Average Hourly Earnings of All Employees, Total Private
• DFEDTARU - Federal Funds Target Range - Upper Limit
• DFEDTARL - Federal Funds Target Range - Lower Limit
• DGS3MO - Market Yield on U.S. Treasury Securities at 3-Month Constant Maturity
• DGS2 - Market Yield on U.S. Treasury Securities at 2-Year Constant Maturity
• DGS10 - Market Yield on U.S. Treasury Securities at 10-Year Constant Maturity
• DGS30 - Market Yield on U.S. Treasury Securities at 30-Year Constant Maturity
• T10Y2Y - 10-Year Treasury Constant Maturity Minus 2-Year Treasury Constant Maturity
• CPILFESL - Consumer Price Index for All Urban Consumers: All Items Less Food and Energy
• CPIUFDSL - Consumer Price Index for All Urban Consumers: Food
• CPIENGSL - Consumer Price Index for All Urban Consumers: Energy
• CUSR0000SAH1 - Consumer Price Index for All Urban Consumers: Shelter
• PCEPI - Personal Consumption Expenditures: Chain-type Price Index
• PCEPILFE - Personal Consumption Expenditures Excluding Food and Energy: Chain-type Price Index
• PPIACO - Producer Price Index by Commodity: All Commodities
• T10YIE - 10-Year Breakeven Inflation Rate
• U6RATE - Total Unemployed, Plus All Marginally Attached Workers Plus Total Employed Part Time for Economic Reasons
• PAYEMS - All Employees, Total Nonfarm
• CIVPART - Labor Force Participation Rate
• EMRATIO - Employment-Population Ratio
• UNEMPLOY - Unemployed
• CE16OV - Employment Level
• ICSA - Initial Claims
• JTSJOL - Job Openings: Total Nonfarm
• JTSQUR - Quits: Total Nonfarm
• GDPC1 - Real Gross Domestic Product
• A191RL1Q225SBEA - Real Gross Domestic Product: Percent Change from Preceding Period
• INDPRO - Industrial Production: Total Index
• TCU - Capacity Utilization: Total Index
• HOUST - New Privately-Owned Housing Units Started: Total Units
• PERMIT - New Privately-Owned Housing Units Authorized in Permit-Issuing Places: Total Units
• RSAFS - Advance Retail Sales: Retail Trade
• PCE - Personal Consumption Expenditures
• DSPIC96 - Real Disposable Personal Income
• PSAVERT - Personal Saving Rate
• M2SL - M2
• BOPGSTB - U.S. International Trade in Goods and Services: Balance

Latest 10-K MD&A

Extracted between Item 7 and the next Item 7A/8 heading after HTML sanitization. Confidence: high. Filing date: 2026-02-12. Report date: 2025-12-31.

Item 7.

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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

Exelon

Executive Overview

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

Exelon’s consolidated financial information includes the results of its seven separate operating subsidiary registrants, ComEd, PECO, BGE, PHI, Pepco, DPL, and ACE, which, along with Exelon, are collectively referred to as the Registrants. The following combined Management’s Discussion and Analysis of Financial Condition and Results of Operations is separately filed by Exelon, ComEd, PECO, BGE, PHI, Pepco, DPL, and ACE. However, none of the Registrants makes any representation as to information related solely to any of the other Registrants. For discussion of the Utility Registrants' year ended December 31, 2024 compared to the year ended December 31, 2023, refer to ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS in the 2024 Form 10-K, which was filed with the SEC on February 12, 2025.

Financial Results of Operations

GAAP Results of Operations. The following table sets forth Exelon's GAAP consolidated Net income attributable to common shareholders by Registrant for the year ended December 31, 2025 compared to the same period in 2024. For additional information regarding the financial results for the years ended December 31, 2025 and 2024, see the discussions of Results of Operations by Registrant.

2025

2024

Favorable (Unfavorable) Variance

Exelon

$

2,768 

$

2,460 

$

308 

ComEd

1,147 

1,066 

81 

PECO

814 

551 

263 

BGE

578 

527 

51 

PHI

799 

741 

58 

Pepco

401 

390 

11 

DPL

224 

209 

15 

ACE

188 

155 

33 

Other(a)

(570)

(425)

(145)

__________

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

Year Ended December 31, 2025 Compared to Year Ended December 31, 2024. Net income attributable to common shareholders increased by $308 million and Diluted earnings per average common share increased to $2.73 in 2025 from $2.45 in 2024 primarily due to:

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•Favorable impacts of rate increases at ComEd, PECO, BGE, and PHI;

•Favorable weather at PECO;

•Higher return on regulatory assets at ComEd;

•Higher AFUDC at ComEd;

•Lower income tax expense at PECO;

•Lower storm costs at BGE; and

•Impacts of the multi-year plan reconciliation at BGE.

Note that rate increases are associated with updated recovery rates for costs and investments to serve customers. The increases were partially offset by:

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

•Higher depreciation expense at PECO and PHI;

•Higher contracting costs at PECO and PHI;

•Lower transmission peak load due to lower energy demand at ComEd;

•Absence of the Maryland multi-year plan reconciliations at PHI;

•Charitable contributions at Exelon Corporate;

•Lower AFUDC at PHI; and

•Higher income tax expense at Exelon Corporate.

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

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The following table provides a reconciliation between Net income attributable to common shareholders as determined in accordance with GAAP and Adjusted (non-GAAP) operating earnings for the year ended December 31, 2025 compared to 2024: 

2025

2024

(In millions, except per share data)

Earnings per

Diluted Share

Earnings per

Diluted Share

Net income attributable to common shareholders

$

2,768 

$

2.73 

$

2,460 

$

2.45 

Asset retirement obligations (net of taxes of $0 and $3, respectively)

(1)

— 

8 

0.01 

Change in FERC audit liability (net of taxes of $1 and $13, respectively)

2 

— 

42 

0.04 

Cost management charge (net of taxes of $0 and $4, respectively)(a)

(1)

— 

13 

0.01 

Environmental costs (net of taxes of $5)

— 

— 

(13)

(0.01)

Regulatory matters (net of taxes of $10)(b)

30 

0.03 

— 

— 

Income tax-related adjustments (entire amount represents tax expense)(c)

1 

— 

(3)

— 

Adjusted (non-GAAP) operating earnings

$

2,801 

$

2.77 

$

2,507 

$

2.50 

__________

Note:

Amounts may not sum due to rounding.

Unless otherwise noted, the income tax impact of each reconciling item between GAAP Net income and Adjusted (non-GAAP) operating earnings is based on the marginal statutory federal and state income tax rates for each Registrant, taking into account whether the income or expense item is taxable or deductible, respectively, in whole or in part. The marginal statutory income tax rates for 2025 and 2024 ranged from 24.0% to 29.0%.

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

(b)Represents the disallowance of certain capitalized costs.

(c)In 2024, reflects the adjustment to state deferred income taxes due to change in DPL's Delaware net operating loss valuation allowance. In 2025, reflects the adjustment to state deferred income taxes due to changes in forecasted apportionment.

Significant 2025 Transactions and Developments

At-the-Market Program

During 2025, Exelon issued approximately 16 million shares of Common Stock at a net weighted-average price of $43.24 per share. The net proceeds from the 2025 issuances were $691 million, which were used for general corporate purposes. See Note 17 — Shareholders' Equity of the Combined Notes to Consolidated Financial Statements for additional information.

Distribution Base Rate Case Proceedings

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

The following tables show the Utility Registrants’ completed and pending distribution base rate case proceedings in 2025. See Note 2 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information on these and other regulatory proceedings.

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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

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Pending Distribution Base Rate Case Proceedings

Registrant/Jurisdiction

Filing Date

Service

Requested Revenue Requirement Increase

Requested ROE

Expected Approval Timing

Pepco - Maryland

October 14, 2025

Electric

$

133 

10.50%

Third quarter of 2026

DPL - Delaware

December 9, 2025

Electric

$

45 

10.50%

Third quarter of 2027

Transmission Formula Rates

The following total increases/(decreases) were included in the Utility Registrants' 2025 annual electric transmission formula rate updates. All rates are effective June 1, 2025 to May 31, 2026, subject to review by interested parties pursuant to review protocols of each Utility Registrants' tariff. See Note 2 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.

Registrant

Initial Revenue Requirement Increase (Decrease)

Annual Reconciliation Increase (Decrease)

Total Revenue Requirement Increase (Decrease)

Allowed Return on Rate Base

Allowed ROE

ComEd

$

78 

$

49 

$

127 

8.13 

%

11.50 

%

PECO

$

9 

$

13 

$

22 

7.54 

%

10.35 

%

BGE

$

21 

$

21 

$

35 

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 

%

ComEd's FERC Audit

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

Other Key Business Drivers and Management Strategies

Utility Rates and Rate Proceedings

The Utility Registrants file rate cases with their regulatory commissions seeking increases or decreases to their electric transmission and distribution and gas distribution rates to recover their costs and earn a fair return on their investments. The outcomes of these regulatory proceedings impact the Utility Registrants’ current and future results of operations, cash flows, and financial positions. See Note 2 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information on these regulatory proceedings.

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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 Utility 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 of approximately $1.2 billion - $1.7 billion.

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.

Legislative and Regulatory Developments

Infrastructure Investment and Jobs Act

On November 15, 2021, the $1.2 trillion IIJA was signed into law. IIJA provides for approximately $550 billion in new federal spending. Categories of funding include funding for a variety of infrastructure needs, including but not limited to: (1) power and grid reliability and resilience, (2) resilience for cybersecurity to address critical infrastructure needs, and (3) electric vehicle charging infrastructure for alternative fuel corridors. The Registrants continue to evaluate programs under the legislation and consider possible opportunities to apply for funding, either directly or in potential collaborations with state and/or local agencies and key stakeholders. The Registrants cannot predict the ultimate timing and success of securing funding from programs under IIJA.

On January 20, 2025, the Unleashing American Energy Order was issued as a Presidential Executive Order, which required an immediate pause in the disbursement of funds appropriated through the IRA and IIJA pending DOE review. In October 2025, Exelon, ComEd, and BGE received termination notifications from the DOE for their Renewable-Aware Distribution Operations, Deployment of a Community-Oriented Interoperable Control Framework for Aggregating and Integrating Distributed Energy Resources and Other Grid-Edge Devices, and Baltimore Interconnection Readiness & Deployment of Storage (BIRDS) awards, respectively. In the fourth quarter of 2025, Exelon, ComEd, and BGE elected to decline the previously awarded Middle Mile Grant (MMG) and Exelon and PECO elected to decline the previously awarded Creating a Resilient, Equitable, and Accessible Transformation in Energy for Greater Philadelphia (CREATE) grant. There are no material financial statement impacts as a result of the DOE terminations. Exelon, ComEd, PECO, and BGE will continue to evaluate whether to move forward with these projects.

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, DPL, and ACE).

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 approximately

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$49 million, $21 million, and $8 million, respectively, from the MDPSC on August 6, 2025. These amounts were used to reduce residential customer accounts receivable balances within the third quarter of 2025. Additional disbursements from the state of 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.

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 Residential Universal Bill Credit (RUBC), which will be 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.

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 for 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.

Critical Accounting Policies and Estimates

The preparation of financial statements in conformity with GAAP requires that management apply accounting policies and make estimates and assumptions that affect results of operations and the amounts of assets and liabilities reported in the financial statements. Management believes that the accounting policies described below require significant judgment in their application or incorporate estimates and assumptions that are inherently uncertain and that may change in subsequent periods. Additional information on the application of these accounting policies can be found in the Combined Notes to Consolidated Financial Statements.

Regulatory Accounting (All Registrants)

For their regulated electric and gas operations, the Registrants reflect the effects of cost-based rate regulation in their financial statements, which is required for entities with regulated operations that meet the following criteria: (1) rates are established or approved by a third-party regulator; (2) rates are designed to recover the entities’ cost of providing services or products; and (3) a reasonable expectation that rates designed to recover costs can be charged to and collected from customers. Regulatory assets represent incurred costs that have been deferred because of their probable future recovery from customers through regulated rates. Regulatory liabilities represent (1) revenue or gains that have been deferred because it is probable such amounts will be returned to customers through future regulated rates; or (2) billings in advance of expenditures for approved regulatory programs. If it is concluded in a future period that a separable portion of operations no longer meets the criteria discussed above, the Registrants would be required to eliminate any associated regulatory assets and liabilities and the impact, which could be material, would be recognized in the Consolidated Statements of Operations and Comprehensive Income.

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The following table illustrates gains (losses) to be included in net income that could result from the elimination of regulatory assets and liabilities and charges against OCI related to deferred costs associated with Exelon's pension and OPEB plans that are recorded as Regulatory assets in Exelon's Consolidated Balance Sheets (before taxes) at December 31, 2025:

(In millions)

Exelon

ComEd

PECO

BGE

PHI

Pepco

DPL

ACE

Gain (loss)

$

4,482 

$

6,727 

$

(758)

$

(353)

$

(1,083)

$

(306)

$

72 

$

(467)

Charge against OCI(a)

(2,911)

— 

— 

— 

— 

— 

— 

— 

___________

(a)Exelon's charge against OCI (before taxes) consists of up to $2.4 billion, $346 million, $298 million, $214 million, and $75 million, related to ComEd's, BGE's, PHI's, Pepco's, and DPL's respective portions of the deferred costs associated with Exelon's pension and OPEB plans. Exelon also has a net regulatory liability (before taxes) of $86 million and $6 million related to PECO's and ACE's portions of the deferred costs associated with Exelon’s OPEB plans that would result in an increase in OCI if reversed.

See Note 2 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information regarding regulatory matters, including the regulatory assets and liabilities of the Registrants.

For each regulatory jurisdiction in which they conduct business, the Registrants assess whether the regulatory assets and liabilities continue to meet the criteria for probable future recovery or refund at each balance sheet date and when regulatory events occur. This assessment includes consideration of recent rate orders, historical regulatory treatment for similar costs in each Registrant's jurisdictions, and factors such as changes in applicable regulatory and political environments. If the assessments and estimates made by the Registrants for regulatory assets and regulatory liabilities are ultimately different than actual regulatory outcomes, the impact in their consolidated financial statements could be material.

Refer to the revenue recognition discussion below for additional information on the annual revenue reconciliations associated with ICC-approved electric distribution MRP and formula rate mechanisms for ComEd, and FERC transmission formula rate tariffs for the Utility Registrants.

Revenues (All Registrants)

Sources of Revenue and Determination of Accounting Treatment. The Registrants earn revenues from the sale and delivery of power and natural gas in regulated markets. The accounting treatment for revenue recognition is based on the nature of the underlying transaction and applicable authoritative guidance. The Registrants primarily apply the Revenue from Contracts with Customers, and Alternative Revenue Program accounting guidance to recognize revenues as discussed in more detail below.

Revenue from Contracts with Customers. The Registrants recognize revenues in the period in which the performance obligations within contracts with customers are satisfied, which generally occurs when power and natural gas are physically delivered to the customer. Transactions of the Registrants within the scope of Revenue from Contracts with Customers generally include sales to utility customers under regulated service tariffs.

The determination of the Registrants' power and natural gas sales to individual customers is based on systematic readings of customer meters, generally monthly. At the end of each month, amounts of energy delivered to customers since the date of the last meter reading are estimated, and corresponding unbilled revenue is recorded. The measurement of unbilled revenue is affected by the following factors: daily customer usage measured by generation or gas throughput volume, customer usage by class, losses of energy during delivery to customers and applicable customer rates. Increases or decreases in volumes delivered to the Registrant’s customers and favorable or unfavorable rate mix due to changes in usage patterns in customer classes in the period could be significant to the calculation of unbilled revenue. In addition, revenues may fluctuate monthly as a result of customers electing to use an alternative supplier, since unbilled commodity revenues are not recorded for these customers. Changes in the timing of meter reading schedules and the number and type of customers scheduled for each meter reading date also impact the measurement of unbilled revenue; however, total operating revenues would remain materially unchanged. See Note 1 — Significant Accounting Policies of the Combined Notes to Consolidated Financial Statements for additional information.

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Alternative Revenue Program Accounting. Certain of the Registrants’ ratemaking mechanisms qualify as ARPs if they (i) are established by a regulatory order and allow for automatic adjustment to future rates, (ii) provide for additional revenues (above those amounts currently reflected in the price of utility service) that are objectively determinable and probable of recovery, and (iii) allow for the collection of those additional revenues within 24 months following the end of the period in which they were recognized. For mechanisms that meet these criteria, the Registrants adjust revenue and record an offsetting regulatory asset or liability once the condition or event allowing additional billing or refund has occurred. The ARP revenues presented in the Registrants’ Consolidated Statements of Operations and Comprehensive Income include both: (i) the recognition of “originating” ARP revenues (when the regulator-specified condition or event allowing for additional billing or refund has occurred) and (ii) an equal and offsetting reversal of the “originating” ARP revenues as those amounts are reflected in the price of utility service and recognized as Revenue from Contracts with Customers.

ComEd records ARP revenue for its best estimate of the electric distribution, energy efficiency, distributed generation rebates, and transmission revenue impacts resulting from future changes in rates that ComEd believes are probable of approval by the ICC and FERC in accordance with its distribution multi-year rate plan, distribution revenue decoupling mechanisms, and formula rate mechanisms. BGE, Pepco, DPL, and ACE record ARP revenue for their best estimate of the electric and natural gas distribution revenue impacts resulting from future changes in rates that they believe are probable of approval by the MDPSC, DCPSC, and/or NJBPU in accordance with their revenue decoupling mechanisms. PECO, BGE, Pepco, DPL, and ACE record ARP revenue for their best estimate of the transmission revenue impacts resulting from future changes in rates that they believe are probable of approval by FERC in accordance with their formula rate mechanisms. Estimates of the current year revenue requirement are based on actual and/or forecasted costs and investments in rate base for the period and the rates of return on common equity and associated regulatory capital structure allowed under the applicable tariff. The estimated reconciliation can be affected by, among other things, variances in costs incurred, investments made, allowed ROE, and actions by regulators or courts.

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

Income Taxes (All Registrants)

Significant management judgment is required in determining the Registrants’ provisions for income taxes, primarily due to the uncertainty related to tax positions taken, as well as deferred tax assets and liabilities and valuation allowances. The Registrants account for uncertain income tax positions using a benefit recognition model with a two-step approach including a more-likely-than-not recognition threshold and a measurement approach based on the largest amount of tax benefit that is greater than 50% likely of being realized upon ultimate settlement. Management evaluates each position based solely on the technical merits and facts and circumstances of the position, assuming the position will be examined by a taxing authority having full knowledge of all relevant information. Significant judgment is required to determine whether the recognition threshold has been met and, if so, the appropriate amount of tax benefits to be recorded in the Registrants’ consolidated financial statements.

The Registrants evaluate quarterly the probability of realizing deferred tax assets by reviewing a forecast of future taxable income and their intent and ability to implement tax planning strategies, if necessary, to realize deferred tax assets. The Registrants also assess negative evidence, such as the expiration of historical operating loss or tax credit carryforwards, that could indicate the Registrant's inability to realize its deferred tax assets. Based on the combined assessment, the Registrants record valuation allowances for deferred tax assets when it is more-likely-than-not such benefit will not be realized in future periods.

Actual income taxes could vary from estimated amounts due to the future impacts of various items, including future changes in income tax laws, the Registrants’ forecasted financial condition and results of operations, failure to successfully implement tax planning strategies, as well as results of audits and examinations of filed tax returns by taxing authorities. See Note 11 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information.

Allowance for Credit Losses on Customer Receivables (All Registrants)

The Registrants allowance for credit losses on customer receivables is estimated based on historical experience, current conditions, and forward-looking risk factors. Historical experience considered include

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collection activities and payment history utilized for risk segmentation; current conditions include changes in economic conditions, aging of receivable balances, payment options and programs available to customers, and industry trends for each company; and forward-looking risk factors include assumptions related to the level of write-offs and recoveries. Risk segments represent a group of customers with similar forward-looking credit quality indicators and risk factors that are comprised based on various attributes, including delinquency of their balances and payment history and represent expected, future customer behavior. The Registrants' customer accounts are generally considered delinquent if the amount billed is not received by the time the next bill is issued, which normally occurs on a monthly basis. The Registrants' customer accounts are written off consistent with approved regulatory requirements. The Registrants' allowances for credit losses will continue to be affected by changes in volume, prices, and economic conditions as well as changes in ICC, PAPUC, MDPSC, DCPSC, DEPSC, and NJBPU regulations.

Depreciable Lives of Property, Plant, and Equipment (All Registrants)

The Registrants have significant investments in electric and natural gas transmission and distribution assets. These assets are generally depreciated on a straight-line basis, using the group, or composite methods of depreciation. The group approach is typically for groups of similar assets that have approximately the same useful lives and the composite approach is used for heterogeneous assets that have different lives. Under both methods, a reporting entity depreciates the assets over the average life of the assets in the group. The estimation of asset useful lives requires management judgment, supported by formal depreciation studies of historical asset retirement experience. Depreciation studies are conducted periodically and as required by a rate regulator or regulatory action, or changes in retirement patterns indicate an update is necessary.

Depreciation studies generally serve as the basis for amounts allowed in customer rates for recovery of depreciation costs. Generally, the Registrants adjust their depreciation rates for financial reporting purposes concurrent with adjustments to depreciation rates reflected in customer rates, unless the depreciation rates reflected in customer rates do not align with management’s judgment as to an appropriate estimated useful life or have not been updated on a timely basis. Depreciation expense and customer rates for ComEd, BGE, Pepco, DPL, and ACE include an estimate of the future costs of dismantling and removing plant from service upon retirement. See Note 2 — Regulatory Matters of the Combined Notes to the Consolidated Financial Statements for information regarding regulatory liabilities and assets recorded by ComEd, BGE, Pepco, DPL, and ACE related to removal costs.

PECO’s removal costs are capitalized to accumulated depreciation when incurred and recorded to depreciation expense over the life of the new asset constructed consistent with PECO’s regulatory recovery method. Estimates for such removal costs are also evaluated in the periodic depreciation studies.

Changes in estimated useful lives of electric and natural gas transmission and distribution assets could have a significant impact on the Registrants’ future results of operations. See Note 1 — Significant Accounting Policies of the Combined Notes to Consolidated Financial Statements for information regarding depreciation and estimated service lives of the property, plant, and equipment of the Registrants.

Goodwill (Exelon, ComEd, and PHI)

As of December 31, 2025, Exelon’s $6.6 billion carrying amount of goodwill consists of $2.6 billion at ComEd and $4 billion at PHI. These entities are required to perform an assessment for possible impairment of their goodwill at least annually or more frequently if an event occurs or circumstances change that would more likely than not reduce the fair value of the reporting units below their carrying amount. A reporting unit is an operating segment or one level below an operating segment (known as a component) and is the level at which goodwill is assessed for impairment. ComEd has a single operating segment and reporting unit. PHI’s operating segments and reporting units are Pepco, DPL, and ACE. See Note 4 — Segment Information of the Combined Notes to Consolidated Financial Statements for additional information. Exelon's and ComEd’s goodwill has been assigned entirely to the ComEd reporting unit. Exelon's and PHI’s goodwill has been assigned to the Pepco, DPL, and ACE reporting units in the amounts of $2.1 billion, $1.4 billion, and $0.5 billion, respectively. See Note 10 — Intangible Assets of the Combined Notes to Consolidated Financial Statements for additional information.

Entities assessing goodwill for impairment have the option of first performing a qualitative assessment to determine whether a quantitative assessment is necessary. As part of the qualitative assessments, Exelon, ComEd, and PHI evaluate, among other things, management's best estimate of projected operating and capital

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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.

Application of the goodwill impairment assessment requires management judgment, including the identification of reporting units and determining the fair value of the reporting unit, which management estimates using a weighted combination of a discounted cash flow analysis and a market multiples analysis. Significant assumptions used in these fair value analyses include discount and growth rates, utility sector market performance and transactions, and projected operating and capital cash flows for ComEd’s, Pepco's, DPL's, and ACE's businesses and the fair value of debt.

While the 2025 annual assessments indicated no impairments, certain assumptions used in the assessment are highly sensitive to changes. Adverse regulatory actions or changes in significant assumptions could potentially result in future impairments of Exelon’s, ComEd's, or PHI’s goodwill, which could be material.

See Note 1 — Significant Accounting Policies and Note 10 — Intangible Assets of the Combined Notes to Consolidated Financial Statements for additional information.

Unamortized Energy Contract Liabilities (Exelon and PHI)

Unamortized energy contract liabilities represent the remaining unamortized balances of non-derivative electricity contracts that Exelon acquired as part of the PHI merger. The initial amount recorded represents the difference between the fair value of the contracts at the time of acquisition and the contract value based on the terms of each contract. Offsetting regulatory assets were also recorded for those energy contract costs that are probable of recovery through customer rates. The unamortized energy contract liabilities and the corresponding regulatory assets, respectively, are amortized over the life of the contract in relation to the expected realization of the underlying cash flows. Amortization of the unamortized energy contract liabilities are recorded through Purchased power and fuel expense. See Note 2 — Regulatory Matters and Note 10 — Intangible Assets of the Combined Notes to Consolidated Financial Statements for additional information.

Accounting for Loss Contingencies (All Registrants)

In the preparation of the financial statements, the Registrants make judgments regarding the future outcome of contingent events and record liabilities for loss contingencies that are probable and can be reasonably estimated based upon available information. The amount recorded may differ from the actual expense incurred when the uncertainty is resolved. Such difference could have a significant impact in the Registrants' consolidated financial statements.

Environmental Costs. Environmental investigation and remediation liabilities are based upon estimates with respect to the number of sites for which the Registrants will be responsible, the scope and cost of work to be performed at each site, the portion of costs that will be shared with other parties, the timing of the remediation work, regulations, and the requirements of local governmental authorities. Annual studies and/or reviews are conducted at ComEd, PECO, BGE, and DPL to determine future remediation requirements for MGP sites and estimates are adjusted accordingly. In addition, periodic reviews are performed at each of the Registrants to assess the adequacy of other environmental reserves. These matters, if resolved in a manner different from the estimate, could have a significant impact in the Registrants’ consolidated financial statements. See Note 16 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for additional information.

Other, Including Personal Injury Claims. The Registrants are self-insured for general liability, automotive liability, workers’ compensation, and personal injury claims to the extent that losses are within policy deductibles or exceed the amount of insurance maintained. The Registrants have reserves for both open claims asserted, and an estimate of claims incurred but not reported (IBNR). The IBNR reserve is estimated based on actuarial assumptions and analysis and is updated annually. Future events, such as the number of new claims to be filed each year, the average cost of disposing of claims, as well as the numerous uncertainties surrounding litigation and possible state and national legislative measures could cause the actual costs to be higher or lower than estimated. Accordingly, these claims, if resolved in a manner different from the estimate, could have a material impact to the Registrants’ consolidated financial statements.

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Retirement Benefits (All Registrants)

Exelon sponsors defined benefit pension plans and OPEB plans. The measurement of the plan obligations and costs of providing benefits involves various factors, including the development of valuation assumptions and inputs and accounting policy elections. When developing the required assumptions, Exelon considers historical information as well as future expectations. The measurement of benefit obligations and costs is affected by several assumptions including the discount rate, the long-term expected rate of return on plan assets, the anticipated rate of increase of health care costs, Exelon's contributions, the rate of compensation increases, and the long-term expected investment rate credited to employees of certain plans, among others. The assumptions are updated annually and upon any interim remeasurement of the plan obligations.

Pension and OPEB plan assets include cash and cash equivalents, equity securities, including U.S. and international securities, and fixed income securities, as well as certain alternative investment classes such as private equity, real estate, private credit, and hedge funds.

Expected Rate of Return on Plan Assets. In determining the EROA, Exelon considers historical economic indicators (including inflation and GDP growth) that impact asset returns, as well as expectations regarding future long-term capital market performance, weighted by Exelon’s target asset class allocations. Exelon calculates the amount of expected return on pension and OPEB plan assets by multiplying the EROA by the MRV of plan assets at the beginning of the year, taking into consideration anticipated contributions and benefit payments to be made during the year. In determining MRV, the authoritative guidance for pensions and postretirement benefits allows the use of either fair value or a calculated value that recognizes changes in fair value in a systematic and rational manner over not more than five years. For the majority of pension plan assets, Exelon uses a calculated value that adjusts for 20% of the difference between fair value and expected MRV of plan assets. Use of this calculated value approach enables less volatile expected asset returns to be recognized as a component of pension cost from year to year. For OPEB plan assets and certain pension plan assets, Exelon uses fair value to calculate the MRV.

Discount Rate. The discount rates are determined by developing a spot rate curve based on the yield to maturity of a universe of high-quality bonds with similar maturities to the related pension and OPEB obligations. The spot rates are used to discount the estimated future benefit distribution amounts under the pension and OPEB plans. The discount rate is the single level rate that produces the same result as the spot rate curve. Exelon utilizes an analytical tool developed by its actuaries to determine the discount rates.

Mortality. The mortality assumption is composed of a base table that represents the current expectation of life expectancy of the population adjusted by an improvement scale that attempts to anticipate future improvements in life expectancy. Exelon’s mortality assumption utilizes the SOA 2019 base table (Pri-2012) and MP-2021 improvement scale adjusted to use Proxy SSA ultimate improvement rates.

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Sensitivity to Changes in Key Assumptions. The following tables illustrate the effects of changing certain of the actuarial assumptions discussed above, while holding all other assumptions constant:

Actual Assumption

(Decrease) Increase

Actuarial Assumption

Pension

OPEB

Change in

Assumption

Pension

OPEB

Total

Change in 2025 cost:

Discount rate(a)

5.68%

5.64%

0.5%

$

(16)

$

(2)

$

(18)

5.68%

5.64%

(0.5)%

$

18 

$

2 

$

20 

EROA

7.00%

6.50%

0.5%

$

(51)

$

(6)

$

(57)

7.00%

6.50%

(0.5)%

$

51 

$

6 

$

57 

Change in benefit obligation at December 31, 2025:

Discount rate(a)

5.42%

5.34%

0.5%

$

(485)

$

(79)

$

(564)

5.42%

5.34%

(0.5)%

$

552 

$

89 

$

641 

__________

(a)In general, the discount rate will have a larger impact on the pension and OPEB cost and obligation as the rate moves closer to 0%. Therefore, the discount rate sensitivities above cannot necessarily be extrapolated for larger increases or decreases in the discount rate. Additionally, Exelon utilizes a liability-driven investment strategy for its pension asset portfolio. The sensitivities shown above do not reflect the offsetting impact that changes in discount rates may have on pension asset returns.

See Note 1 — Significant Accounting Policies and Note 12 — Retirement Benefits of the Combined Notes to Consolidated Financial Statements for additional information regarding the accounting for the defined benefit pension plans and OPEB plans.

Derivative Financial Instruments (All Registrants)

The Registrants use derivative instruments to manage commodity price risk and interest rate risk related to ongoing business operations. See Note 13 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information.

Determining whether a contract qualifies as a derivative requires that management exercise significant judgment, including assessing market liquidity as well as determining whether a contract has one or more underlying and one or more notional quantities.

All derivatives are recognized on the balance sheet at their fair value, except for certain derivatives that qualify for, and are elected under, NPNS. For derivatives that qualify and are designated as cash flow hedges, changes in fair value each period are initially recorded in AOCI and recognized in earnings when the hedged transaction affects earnings. For derivatives intended to serve as economic hedges, which are not designated for hedge accounting, changes in fair value each period are recognized in earnings on the Consolidated Statement of Operations and Comprehensive Income or are recorded as a regulatory asset or liability when there is an ability to recover or return the associated costs or benefits in accordance with regulatory requirements.

NPNS. Contracts that are designated as NPNS are not required to be recorded at fair value, but rather on an accrual basis of accounting. Determining whether a contract qualifies for NPNS requires judgment on whether the contract will physically deliver and requires that management ensure compliance with all the associated qualification and documentation requirements. For all NPNS derivative instruments, accounts payable is recorded when derivatives settle and expense is recognized in earnings as the underlying physical commodity is consumed. Contracts that qualify for NPNS are those for which physical delivery is probable, quantities are expected to be used or sold in the normal course of business over a reasonable period, and the contract is not financially settled on a net basis. See Note 13 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for all contracts that are accounted for under NPNS.

Commodity Contracts. The Registrants make estimates and assumptions concerning future commodity prices, interest rates, and the timing of future transactions and their probable cash flows in deciding whether to enter derivative transactions, and in determining the initial accounting treatment for derivative transactions. The

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Registrants categorize these derivatives under a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value.

Derivative contracts can be traded in both exchange-based and non-exchange-based markets. Exchange-based derivatives that are valued using unadjusted quoted prices in active markets are generally categorized in Level 1 in the fair value hierarchy. Certain derivative pricing is verified using indicative price quotations available through brokers or over-the-counter, online exchanges. For derivatives that trade in liquid markets, the model inputs are generally observable. Such instruments are categorized in Level 2. For derivatives that trade in less liquid markets with limited pricing information, the model inputs generally would include both observable and unobservable inputs and are categorized in Level 3.

The Registrants consider nonperformance risk, including credit risk in the valuation of derivative contracts, and both historical and current market data in the assessment of nonperformance risk. The impacts of nonperformance and credit risk to date have generally not been material to the Registrants’ financial statements.

Interest Rate Derivative Instruments. Exelon Corporate utilizes interest rate swaps to manage interest rate risk on existing and planned future debt issuances. The fair value of the swaps is calculated by discounting the future net cash flows to the present value based on the terms and conditions of the agreements and the forward interest rate curves. As these inputs are based on observable data and valuations of similar instruments, the interest rate derivatives are primarily categorized in Level 2 in the fair value hierarchy.

See ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK and Note 15 — Fair Value of Financial Assets and Liabilities and Note 13 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information regarding the Registrants’ derivative instruments.

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ComEd

Results of Operations by Registrant

Results of Operations—ComEd

2025

2024

(Unfavorable) Favorable Variance

Operating revenues

$

7,267 

$

8,219 

$

(952)

Operating expenses

Purchased power

1,782 

3,042 

1,260 

Operating and maintenance

1,710 

1,703 

(7)

Depreciation and amortization

1,560 

1,514 

(46)

Taxes other than income taxes

409 

376 

(33)

Total operating expenses

5,461 

6,635 

1,174 

Gain on sales of assets

— 

5 

(5)

Operating income

1,806 

1,589 

217 

Other income and (deductions)

Interest expense, net

(530)

(501)

(29)

Other, net

132 

94 

38 

Total other income and (deductions)

(398)

(407)

9 

Income before income taxes

1,408 

1,182 

226 

Income taxes

261 

116 

(145)

Net income

$

1,147 

$

1,066 

$

81 

Year Ended December 31, 2025 Compared to Year Ended December 31, 2024. Net income increased by $81 million primarily due to higher distribution and transmission rate base driven by incremental investments to serve customers, higher return on regulatory assets due to an increase in asset balances, and higher AFUDC, partially offset by lower transmission peak load.

The changes in Operating revenues consisted of the following:

2025 vs. 2024

Increase (Decrease)

Distribution

$

297 

Transmission

— 

Energy efficiency

32 

Other

(47)

282 

Regulatory required programs

(1,234)

Total decrease

$

(952)

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

Distribution Revenue. Starting in 2024, distribution revenues are under a MRP. The MRP requires an annual reconciliation of the revenue requirement in effect to the actual costs the ICC determines are prudently and reasonably incurred. Electric distribution revenue varies from year to year based upon fluctuations in the underlying costs, (e.g., severe weather and storm restoration), investments being recovered, and allowed ROE. Electric distribution revenue increased during the year ended December 31, 2025, compared to the same period in 2024, primarily due to higher fully recoverable costs, higher rate base, and higher return on regulatory assets.

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ComEd

Transmission Revenue. Under a FERC-approved formula, transmission revenue varies from year to year based upon fluctuations in the underlying costs, capital investments being recovered, and the highest daily peak load, which is updated annually in January based on the prior calendar year. Transmission revenue for the year ended December 31, 2025, compared to the same period in 2024, remained relatively consistent.

Energy Efficiency Revenue. Energy efficiency revenues are under a performance-based formula rate, which requires an annual reconciliation of the revenue requirement in effect to the actual costs the ICC determines are prudently and reasonably incurred in a given year. Energy efficiency revenue varies from year to year based upon fluctuations in the underlying costs, investments being recovered, and allowed ROE. Energy efficiency revenue increased during the year ended December 31, 2025, compared to the same period in 2024, primarily due to increased regulatory asset amortization, which is fully recoverable.

Other Revenue primarily includes assistance provided to other utilities through mutual assistance programs. Other revenue decreased for the year ended December 31, 2025, compared to the same period in 2024, which primarily reflects decreased mutual assistance revenues associated with storm restoration efforts.

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

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

The $1,260 million decrease in Purchased power expense for the year ended December 31, 2025 compared to the same period in 2024, which includes the impacts of CMC nuclear production tax credits, is offset in Operating revenues as part of regulatory required programs. See Note 2 — Regulatory Matters for additional information.

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ComEd

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

2025 vs. 2024

(Decrease) Increase

Labor, other benefits, contracting, and materials

$

(9)

BSC costs

(14)

Pension and non-pension postretirement benefits expense

5 

Storm-related costs

2 

(15)

Regulatory required programs(a)

22 

Total increase

$

7 

__________

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

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

2025 vs. 2024

Increase (Decrease)

Depreciation and amortization(a)

$

56 

Regulatory asset amortization(b)

(10)

Total increase

$

46 

__________

(a)Reflects ongoing capital expenditures.

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

Interest expense, net increased $29 million for the year ended December 31, 2025, compared to the same period in 2024, primarily due to an increase in interest rates and the issuance of debt in 2025.

Other, net increased $38 million for the year ended December 31, 2025, compared to the same period in 2024, primarily due to higher AFUDC equity.

Effective income tax rates were 18.5% and 9.8% for the years ended December 31, 2025 and 2024, respectively. See Note 11 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the effective income tax rates.

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PECO

Results of Operations—PECO

2025

2024

Favorable (Unfavorable) Variance

Operating revenues

$

4,684 

$

3,973 

$

711 

Operating expenses

Purchased power and fuel

1,733 

1,477 

(256)

Operating and maintenance

1,195 

1,120 

(75)

Depreciation and amortization

454 

428 

(26)

Taxes other than income taxes

240 

218 

(22)

Total operating expenses

3,622 

3,243 

(379)

Gain on sales of assets

— 

4 

(4)

Operating income

1,062 

734 

328 

Other income and (deductions)

Interest expense, net

(260)

(232)

(28)

Other, net

41 

37 

4 

Total other income and (deductions)

(219)

(195)

(24)

Income before income taxes

843 

539 

304 

Income taxes

29 

(12)

(41)

Net income

$

814 

$

551 

$

263 

Year Ended December 31, 2025 Compared to Year Ended December 31, 2024. Net income increased by $263 million due to an increase in revenue as a result of electric and gas distribution rates, favorable weather relative to the same period last year, and tax repairs related to storms, partially offset by an increase in contracting, depreciation and interest expense.

The changes in Operating revenues consisted of the following:

2025 vs. 2024

Increase (Decrease)

Electric

Gas

Total

Weather

$

27 

$

32 

$

59 

Volume

(27)

2 

(25)

Pricing

321 

91 

412 

Transmission

4 

— 

4 

Other

10 

2 

12 

335 

127 

462 

Regulatory required programs

168 

81 

249 

Total increase

$

503 

$

208 

$

711 

Weather. The demand for electricity and natural gas is affected by weather conditions. With respect to the electric business, very warm weather in summer months and, with respect to the electric and natural gas businesses, very cold weather in winter months are referred to as “favorable weather conditions” because these weather conditions result in increased deliveries of electricity and natural gas. Conversely, mild weather reduces demand. For the year ended December 31, 2025, compared to the same period in 2024, Operating revenues related to weather increased due to favorable weather conditions in PECO's service territory.

Heating and cooling degree days are quantitative indices that reflect the demand for energy needed to heat or cool a home or business. Normal weather is determined based on historical average heating and cooling degree days for a 30-year period in PECO’s service territory. The changes in heating and cooling degree days in PECO’s service territory for the year ended December 31, 2025, compared to the same period in 2024, and normal weather consisted of the following:

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PECO

For the Years Ended December 31,

% Change

PECO Service Territory

2025

2024

Normal

2025 vs. 2024

2025 vs. Normal

Heating Degree-Days

4,274 

3,786 

4,348 

12.9 

%

(1.7)

%

Cooling Degree-Days

1,547 

1,652 

1,455 

(6.4)

%

6.3 

%

Volume. Electric volume, exclusive of the effects of weather, for the year ended December 31, 2025, compared to the same period in 2024, decreased due to customer load. Natural gas volume for the year ended December 31, 2025, compared to the same period in 2024, remained relatively consistent.

Electric Retail Deliveries to Customers (in GWhs)

2025

2024

% Change

Weather - Normal % Change(b)

Residential

14,078 

13,963 

0.8 

%

(1.5)

%

Small commercial & industrial

7,537 

7,683 

(1.9)

%

(3.0)

%

Large commercial & industrial

13,683 

13,889 

(1.5)

%

(2.2)

%

Public authorities & electric railroads

678 

613 

10.6 

%

11.0 

%

Total electric retail deliveries(a)

35,976 

36,148 

(0.5)

%

(1.9)

%

At December 31,

Number of Electric Customers

2025

2024

Residential

1,541,970 

1,533,443 

Small commercial & industrial

154,841 

155,164 

Large commercial & industrial

3,158 

3,150 

Public authorities & electric railroads

10,248 

10,708 

Total

1,710,217 

1,702,465 

__________

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

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

Natural Gas Deliveries to Customers (in mmcf)

2025

2024

% Change

Weather - Normal % Change(b)

Residential

43,189 

38,328 

12.7 

%

1.6 

%

Small commercial & industrial

23,709 

21,906 

8.2 

%

0.6 

%

Large commercial & industrial

15 

17 

(11.8)

%

(2.2)

%

Transportation

24,204 

23,357 

3.6 

%

0.7 

%

Total natural gas deliveries(a)

91,117 

83,608 

9.0 

%

1.1 

%

At December 31,

Number of Natural Gas Customers

2025

2024

Residential

510,959 

508,224 

Small commercial & industrial

44,698 

44,846 

Large commercial & industrial

7 

7 

Transportation

617 

644 

Total

556,281 

553,721 

__________

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

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

Pricing for the year ended December 31, 2025, compared to the same period in 2024, increased primarily due to electric and gas distribution rates charged to customers.

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PECO

Transmission Revenue. Under a FERC-approved formula, transmission revenue varies from year to year based upon fluctuations in the underlying costs and capital investments being recovered. Transmission revenue for the year ended December 31, 2025, compared to the same period in 2024, remained relatively consistent.

Other Revenue primarily includes revenue related to late payment charges. Other revenues for the year ended December 31, 2025, compared to the same period in 2024, increased primarily due to revenue related to late payment charges.

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

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

The increase of $256 million for the year ended December 31, 2025, compared to the same period in 2024, in Purchased power and fuel expense is fully offset in Operating revenues as part of regulatory required programs.

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

2025 vs. 2024

Increase (Decrease)

Labor, other benefits, contracting, and materials

$

51 

Credit loss expense

8 

Pension and non-pension postretirement benefits expense

4 

Storm-related costs

3 

BSC costs

2 

Other

22 

90 

Regulatory required programs

(15)

Total increase

$

75 

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

2025 vs. 2024

Increase (Decrease)

Depreciation and amortization(a)

$

37 

Regulatory asset amortization

(11)

Total increase

$

26 

__________

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

Taxes other than income taxes increased by $22 million for the year ended December 31, 2025, compared to the same period in 2024, primarily due to higher Pennsylvania gross receipts tax.

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PECO

Interest expense, net increased $28 million for the year ended December 31, 2025, compared to the same period in 2024, primarily due to an increase in interest rates and the issuance of debt in 2025.

Effective income tax rates were 3.4% and (2.2)% for the years ended December 31, 2025 and 2024, respectively. See Note 11 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the effective income tax rates.

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BGE

Results of Operations—BGE

2025

2024

Favorable (Unfavorable) Variance

Operating revenues

$

5,222 

$

4,426 

$

796 

Operating expenses

Purchased power and fuel

2,221 

1,651 

(570)

Operating and maintenance

1,066 

1036 

(30)

Depreciation and amortization

632 

638 

6 

Taxes other than income taxes

370 

345 

(25)

Total operating expenses

4,289 

3,670 

(619)

Operating income

933 

756 

177 

Other income and (deductions)

Interest expense, net

(247)

(216)

(31)

Other, net

51 

36 

15 

Total other income and (deductions)

(196)

(180)

(16)

Income before income taxes

737 

576 

161 

Income taxes

159 

49 

(110)

Net income

$

578 

$

527 

$

51 

Year Ended December 31, 2025 Compared to Year Ended December 31, 2024. Net income increased $51 million primarily due to distribution rates, favorable impacts of the multi-year plan reconciliation and a decrease in storm costs, partially offset by an increase in interest expense and the derecognition of regulatory assets and liabilities for multi-year plan reconciliations that will no longer be filed as a result of the Next Generation Energy Act. See Note 2 — Regulatory Matters for additional information on the multi-year plan reconciliation and the Next Generation Energy Act.

The changes in Operating revenues consisted of the following:

2025 vs. 2024

Increase

Electric

Gas

Total

Distribution

$

82 

$

62 

$

144 

Transmission

6 

— 

6 

Other

11 

— 

11 

99 

62 

161 

Regulatory required programs

471 

164 

635 

Total increase

$

570 

$

226 

$

796 

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BGE

Revenue Decoupling. The demand for electricity and natural gas is affected by weather and customer usage. However, Operating revenues are not impacted by abnormal weather or usage per customer as a result of a monthly rate adjustment that provides for fixed distribution revenue per customer by customer class. While Operating revenues are not impacted by abnormal weather or usage per customer, they are impacted by changes in the number of customers. See Note 2 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information on revenue decoupling.

At December 31,

Number of Electric Customers

2025

2024

Residential

1,222,397 

1,216,614 

Small commercial & industrial

115,197 

115,010 

Large commercial & industrial

13,445 

13,266 

Public authorities & electric railroads

252 

260 

Total

1,351,291 

1,345,150 

At December 31,

Number of Natural Gas Customers

2025

2024

Residential

660,986 

658,776 

Small commercial & industrial

37,759 

37,874 

Large commercial & industrial

6,417 

6,369 

Total

705,162 

703,019 

Distribution Revenue increased for the year ended December 31, 2025 compared to the same period in 2024, due to favorable impacts of the multi-year plans.

Transmission Revenue. Under a FERC-approved formula, transmission revenue varies from year to year based upon fluctuations in the underlying costs and capital investments being recovered. Transmission revenue increased for the year ended December 31, 2025 compared to the same period in 2024 primarily due to increases in underlying costs and capital investments.

Other Revenue includes revenue related to late payment charges, mutual assistance, off-system sales, and service application fees. Other Revenue increased for the year ended December 31, 2025 compared to the same period in 2024, primarily driven by an increase in service application fees.

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

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

The increase of $570 million for the year ended December 31, 2025 compared to the same period in 2024 in Purchased power and fuel expense is fully offset in Operating revenues as part of regulatory required programs.

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BGE

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

2025 vs. 2024

Increase (Decrease)

BSC costs

$

5 

Credit loss expense

1 

Labor, other benefits, contracting, and materials

1 

Multi-year plan reconciliation(a)

(9)

Storm-related costs

(13)

Other(b)

5 

(10)

Regulatory required programs(c)

40 

Total increase

$

30 

__________

(a)See Note 2 — Regulatory Matters for additional information on the multi-year plan reconciliation.

(b)Reflects the derecognition of regulatory assets for multi-year plan reconciliations that will no longer be filed as a result of the Next Generation Energy Act, partially offset by the absence of capital write-offs included in 2024. See Note 2 — Regulatory Matters for additional information regarding the Next Generation Energy Act.

(c)Reflects the cost recovery associated with EmPOWER Maryland. See Note 2 — Regulatory Matters for additional information.

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

2025 vs. 2024

Increase (Decrease)

Depreciation and amortization

$

13 

Regulatory required programs(a)

21 

Regulatory asset amortization

(40)

Total decrease

$

(6)

__________

(a)Reflects the cost recovery associated with EmPOWER Maryland. See Note 2 — Regulatory Matters for additional information.

Taxes other than income taxes increased by $25 million for the year ended December 31, 2025 compared to the same period in 2024, primarily due to increased property taxes.

Interest expense, net increased $31 million for the year ended December 31, 2025 compared to the same period in 2024, primarily due to the issuance of debt in the second quarter of 2025.

Other, net increased by $15 million for the year ended December 31, 2025 compared to the same period in 2024, primarily due to increased interest income and higher AFUDC equity.

Effective income tax rates were 21.6% and 8.5% for the years ended December 31, 2025 and 2024, respectively. See Note 11 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the effective income tax rates.

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PHI

Results of Operations—PHI

PHI’s Results of Operations include the results of its three reportable segments, Pepco, DPL, and ACE. PHI also has a business services subsidiary, PHISCO, which provides a variety of support services and the costs are directly charged or allocated to the applicable subsidiaries. Additionally, the results of PHI's corporate operations include interest costs from various financing activities. All material intercompany accounts and transactions have been eliminated in consolidation. The following table sets forth PHI's GAAP consolidated Net income, by Registrant, for the year ended December 31, 2025 compared to the same period in 2024. See the Results of Operations for Pepco, DPL, and ACE for additional information.

2025

2024

Favorable Variance

PHI

$

799 

$

741 

$

58 

Pepco

401 

390 

11 

DPL

224 

209 

15 

ACE

188 

155 

33 

Other(a)

(14)

(14)

— 

__________

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

Year Ended December 31, 2025 Compared to Year Ended December 31, 2024. Net income increased by $58 million primarily due to electric distribution rates, favorable impacts of the ACE Electric Distribution Base Rate Case, including the recognition of the regulatory asset and corresponding decrease in O&M associated with work stoppage costs that were incurred by ACE in 2023, DPL Delaware electric DSIC rates and natural gas rates, and transmission rates, partially offset by the absence of the Pepco Maryland multi-year plans reconciliations, lower AFUDC income, and increases in interest expense, depreciation expense and contracting costs.

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Pepco

Results of Operations—Pepco

2025

2024

Favorable (Unfavorable) Variance

Operating revenues

$

3,454 

$

3,039 

$

415 

Operating expenses

    Purchased power

1,262 

1,055 

(207)

Operating and maintenance

625 

534 

(91)

Depreciation and amortization

433 

407 

(26)

Taxes other than income taxes

455 

424 

(31)

Total operating expenses

2,775 

2,420 

(355)

(Loss) gain on sales of assets

1 

(1)

2 

Operating income

680 

618 

62 

Other income and (deductions)

Interest expense, net

(214)

(192)

(22)

Other, net

41 

54 

(13)

Total other income and (deductions)

(173)

(138)

(35)

Income before income taxes

507 

480 

27 

Income taxes

106 

90 

(16)

Net income

$

401 

$

390 

$

11 

Year Ended December 31, 2025 Compared to Year Ended December 31, 2024. Net income increased by $11 million primarily due to distribution and transmission rates, partially offset by the absence of the Maryland multi-year plans reconciliations, lower AFUDC income, and increases in interest expense and depreciation expense.

The changes in Operating revenues consisted of the following:

2025 vs. 2024

Increase (Decrease)

Distribution

$

135 

Transmission

27 

Other

(9)

153 

Regulatory required programs

262 

Total increase

$

415 

Revenue Decoupling. The demand for electricity is affected by weather and customer usage. However, Operating revenues from electric distribution in both Maryland and the District of Columbia are not intended to be impacted by abnormal weather or usage per customer as a result of a BSA that provides for a fixed distribution charge per customer class in the District of Columbia and per customer by customer class in Maryland. Therefore, changes in the number of customers only impacts Operating revenues in Maryland. See Note 2 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information on revenue decoupling Pepco Maryland.

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Pepco

At December 31,

Number of Electric Customers in Maryland

2025

2024

Residential

560,304 

556,239 

Small commercial & industrial

30,548 

30,571 

Large commercial & industrial

19,078 

18,989 

Public authorities & electric railroads

179 

179 

Total

610,109 

605,978 

Distribution Revenue increased for the year ended December 31, 2025 compared to the same period in 2024, primarily due to the favorable impacts of the Maryland and District of Columbia multi-year plans and customer growth in Maryland.

Transmission Revenue. Under a FERC-approved formula, transmission revenue varies from year to year based upon fluctuations in the underlying costs and capital investments being recovered. Transmission revenue increased for the year ended December 31, 2025 compared to the same period in 2024 primarily due to increases in underlying costs and capital investment.

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

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

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

The increase of $207 million for the year ended December 31, 2025 compared to the same period in 2024, in Purchased power expense is fully offset in Operating revenues as part of regulatory required programs.

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Pepco

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

2025 vs. 2024

Increase (Decrease)

Labor, other benefits, contracting, and materials

$

26 

Maryland multi-year plan reconciliations (a)

23 

Credit loss expense

2 

Pension and non-pension postretirement benefits expense

1 

Storm-related costs

1 

BSC and PHISCO costs

(5)

Other

7 

55 

Regulatory required programs (b)

36 

Total increase

$

91 

__________

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

(b)Reflects the cost recovery associated with EmPOWER Maryland. Please refer to Note 2 — Regulatory Matters for additional information.

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

2025 vs. 2024

Increase (Decrease)

Depreciation and amortization(a)

$

24 

Regulatory asset amortization

6 

Regulatory required programs(b)

(4)

Total increase

$

26 

__________

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

(b)Reflects the cost recovery associated with EmPOWER Maryland. Please refer to Note 2 — Regulatory Matters for additional information.

Taxes other than income taxes increased $31 million for the year ended December 31, 2025 compared to the same period in 2024, primarily due to increases in utility taxes, which are offset in revenues, and property taxes.

Interest expense, net increased $22 million for the year ended December 31, 2025 compared to the same period in 2024 primarily due to an increase in interest rates and the issuance of debt in 2025.

Other, net decreased $13 million for the year ended December 31, 2025 compared to the same period in 2024, primarily due to lower AFUDC equity.

Effective income tax rates were 20.9% and 18.8% for the years ended December 31, 2025 and 2024, respectively. See Note 11 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the effective income tax rates.

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DPL

Results of Operations—DPL

2025

2024

Favorable (Unfavorable) Variance

Operating revenues

$

1,971 

$

1,787 

$

184 

Operating expenses

Purchased power and fuel

861 

760 

(101)

Operating and maintenance

391 

377 

(14)

Depreciation and amortization

252 

245 

(7)

Taxes other than income taxes

88 

79 

(9)

Total operating expenses

1,592 

1,461 

(131)

Operating income

379 

326 

53 

Other income and (deductions)

Interest expense, net

(102)

(93)

(9)

Other, net

16 

25 

(9)

Total other income and (deductions)

(86)

(68)

(18)

Income before income taxes

293 

258 

35 

Income taxes

69 

49 

(20)

Net income

$

224 

$

209 

$

15 

Year Ended December 31, 2025 Compared to Year Ended December 31, 2024. Net income increased by $15 million primarily due to Delaware electric DSIC and natural gas rates, favorable weather conditions at Delaware electric and natural gas service territories, and transmission rates, partially offset by increases in interest and depreciation expense.

The changes in Operating revenues consisted of the following:

2025 vs. 2024

Increase (Decrease)

Electric

Gas

Total

Weather

$

8 

$

3 

$

11 

Volume

(4)

7 

3 

Distribution

20 

14 

34 

Transmission

19 

— 

19 

Other

(1)

— 

(1)

42 

24 

66 

Regulatory required programs

90 

28 

118 

Total increase

$

132 

$

52 

$

184 

Revenue Decoupling. The demand for electricity is affected by weather and customer usage. However, Operating revenues from electric distribution in Maryland are not intended to be impacted by abnormal weather or usage per customer as a result of a BSA that provides for a fixed distribution charge per customer by customer class. While Operating revenues from electric distribution customers in Maryland are not impacted by abnormal weather or usage per customer, they are impacted by changes in the number of customers. See Note 2 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information on revenue decoupling for DPL Maryland.

Weather. The demand for electricity and natural gas in Delaware is affected by weather conditions. With respect to the electric business, very warm weather in summer months and, with respect to the electric and natural gas businesses, very cold weather in winter months are referred to as "favorable weather conditions” because these weather conditions result in increased deliveries of electricity and natural gas. Conversely, mild weather reduces demand. During the year ended December 31, 2025 compared to the same period in 2024, Operating revenues

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DPL

related to weather increased due to favorable weather conditions in DPL's Delaware electric and natural gas service territories.

Heating and cooling degree days are quantitative indices that reflect the demand for energy needed to heat or cool a home or business. Normal weather is determined based on historical average heating and cooling degree days for a 20-year period in DPL's Delaware electric service territory and a 30-year period in DPL's Delaware natural gas service territory. The changes in heating and cooling degree days in DPL’s Delaware service territory for the year ended December 31, 2025 compared to same period in 2024 and normal weather consisted of the following:

For the Years Ended December 31,

% Change

Delaware Electric Service Territory

2025

2024

Normal

2025 vs. 2024

2025 vs. Normal

Heating Degree-Days

4,500 

4,100 

4,477 

9.8 

%

0.5 

%

Cooling Degree-Days

1,309 

1,277 

1,302 

2.5 

%

0.5 

%

For the Years Ended December 31,

% Change

Delaware Natural Gas Service Territory

2025

2024

Normal

2025 vs. 2024

2025 vs. Normal

Heating Degree-Days

4,500 

4,100 

4,605 

9.8 

%

(2.3)

%

Volume, exclusive of the effects of weather, increased for the year ended December 31, 2025 compared to the same period in 2024 primarily due to an increase in customer growth.

Electric Retail Deliveries to Delaware Customers (in GWhs)

2025

2024

% Change

Weather - Normal % Change (b)

Residential

3,288 

3,227 

1.9 

%

(1.4)

%

Small commercial & industrial

1,459 

1,445 

1.0 

%

0.2 

%

Large commercial & industrial

3,049 

3,019 

1.0 

%

0.6 

%

Public authorities & electric railroads

31 

32 

(3.1)

%

(3.5)

%

Total electric retail deliveries(a)

7,827 

7,723 

1.3 

%

(0.3)

%

At December 31,

Number of Total Electric Customers (Maryland and Delaware)

2025

2024

Residential

495,254 

490,626 

Small commercial & industrial

65,500 

64,813 

Large commercial & industrial

1,273 

1,255 

Public authorities & electric railroads

634 

606 

Total

562,661 

557,300 

__________

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

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

Natural Gas Retail Deliveries to Delaware Customers (in mmcf)

2025

2024

% Change

Weather - Normal % Change(b)

Residential

9,052 

7,810 

15.9 

%

7.5 

%

Small commercial & industrial

4,339 

3,801 

14.2 

%

5.5 

%

Large commercial & industrial

1,680 

1,674 

0.4 

%

0.4 

%

Transportation

6,355 

6,206 

2.4 

%

(0.3)

%

Total natural gas deliveries(a)

21,426 

19,491 

9.9 

%

4.1 

%

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DPL

At December 31,

Number of Delaware Natural Gas Customers

2025

2024

Residential

132,148 

131,392 

Small commercial & industrial

10,255 

10,218 

Large commercial & industrial

14 

14 

Transportation

160 

162 

Total

142,577 

141,786 

__________

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

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

Distribution Revenue increased for the year ended December 31, 2025 compared to the same period in 2024 primarily due to Delaware electric DSIC rates and natural gas rates that became effective in 2025.

Transmission Revenue. Under a FERC-approved formula, transmission revenue varies from year to year based upon fluctuations in the underlying costs and capital investments being recovered. Transmission revenue increased for the year ended December 31, 2025 compared to the same period in 2024 primarily due to increases in underlying costs and capital investment.

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

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

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

The increase of $101 million for the year ended December 31, 2025 compared to the same period in 2024, in Purchased power and fuel expense is fully offset in Operating revenues as part of regulatory required programs.

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DPL

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

2025 vs. 2024

Increase (Decrease)

Credit loss expense

$

3 

Pension and non-pension postretirement benefits expense

1 

Labor, other benefits, contracting, and materials

(2)

BSC and PHISCO costs

(5)

Storm-related costs

(5)

Other

3 

$

(5)

Regulatory required programs(a)

19 

Total increase

$

14 

__________

(a)Reflects the cost recovery associated with EmPOWER Maryland. Please refer to Note 2 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.

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

2025 vs. 2024

Increase (Decrease)

Depreciation and amortization(a)

$

8 

Regulatory asset amortization

(1)

Total increase

$

7 

__________

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

Taxes other than income taxes increased by $9 million for the year ended December 31, 2025 compared to the same period in 2024, primarily due to an increase in property taxes.

Interest expense, net increased $9 million for the year ended December 31, 2025 compared to the same period in 2024 primarily due to an increase in interest rates and the issuance of debt in 2025.

Other, net decreased by $9 million for the year ended December 31, 2025 compared to the same period in 2024, primarily due to lower AFUDC equity and a decrease in interest income.

Effective income tax rates were 23.5% and 19.0% for the years ended December 31, 2025 and 2024, respectively. See Note 11 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the change in effective income tax rates.

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ACE

Results of Operations—ACE

2025

2024

Favorable (Unfavorable) Variance

Operating revenues

$

1,718 

$

1,628 

$

90 

Operating expenses

Purchased power

808 

698 

(110)

Operating and maintenance

328 

368 

40 

Depreciation and amortization

248 

278 

30 

Taxes other than income taxes

9 

9 

— 

Total operating expenses

1,393 

1,353 

(40)

Gain on sale of assets

2 

— 

2 

Operating income

327 

275 

52 

Other income and (deductions)

Interest expense, net

(82)

(79)

(3)

Other, net

10 

14 

(4)

Total other income and (deductions)

(72)

(65)

(7)

Income before income taxes

255 

210 

45 

Income taxes

67 

55 

(12)

Net income

$

188 

$

155 

$

33 

Year Ended December 31, 2025 Compared to Year Ended December 31, 2024. Net income increased by $33 million primarily due to favorable impacts of the ACE Electric Distribution Base Rate Case, including the recognition of the regulatory asset and corresponding decrease in O&M associated with work stoppage costs that were incurred by ACE in 2023, a decrease in various operating expenses, distribution rates and an increase in customer growth, offset by an increase in interest and depreciation expense.

The changes in Operating revenues consisted of the following:

2025 vs. 2024

Increase

Distribution

$

6 

Other

3 

9 

Regulatory required programs

81 

Total increase

$

90 

Revenue Decoupling. The demand for electricity is affected by weather and customer usage. However, Operating revenues from electric distribution in New Jersey are not intended to be impacted by abnormal weather or usage per customer as a result of the CIP which compares current distribution revenues by customer class to approved target revenues established in ACE’s most recent distribution base rate case. The CIP is calculated annually, and recovery is subject to certain conditions, including an earnings test and ceilings on customer rate increases. While Operating revenues are not impacted by abnormal weather or usage per customer, they are impacted by changes in the number of customers. See Note 2 — Regulatory Matters of the Combined Notes to the Consolidated Financial Statements for additional information on the ACE CIP.

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ACE

At December 31,

Number of Electric Customers

2025

2024

Residential

510,005 

507,483 

Small commercial & industrial

63,154 

62,739 

Large commercial & industrial

2,682 

2,843 

Public authorities & electric railroads

754 

714 

Total

576,595 

573,779 

Distribution Revenue increased for the year ended December 31, 2025 compared to the same period in 2024 primarily due to distribution rates and an increase in customer growth.

Transmission Revenue. Under a FERC-approved formula, transmission revenue varies from year to year based upon fluctuations in the underlying costs and capital investments being recovered. Transmission revenue remained relatively consistent for the year ended December 31, 2025 compared to the same period in 2024.

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

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

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

The increase of $110 million for the year ended December 31, 2025 compared to same period in 2024, in Purchased power expense is fully offset in Operating revenues as part of regulatory required programs.

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

2025 vs. 2024

Increase (Decrease)

Storm-related costs

$

3 

BSC and PHISCO costs

(10)

Labor, other benefits, contracting and materials(a)

(33)

Other

(1)

(41)

Regulatory required programs

1 

Total decrease

$

(40)

__________

(a)Reflects a decrease in contracting costs for the year ended December 31, 2025, resulting from the favorable impacts of the ACE Electric Distribution Base Rate Case, including the recognition of the regulatory asset and corresponding decrease in O&M associated with work stoppage costs that were incurred by ACE in 2023. See Note 2 — Regulatory Matters for additional information.

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ACE

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

2025 vs. 2024

Increase (Decrease)

Depreciation and amortization(a)

$

12 

Regulatory asset amortization

(11)

Regulatory required programs(b)

(31)

Total decrease

$

(30)

__________

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

(b)Regulatory required programs decreased primarily due to the absence of the regulatory asset amortization of the PPA termination obligation, which was fully amortized in 2024.

Interest expense, net increased $3 million for the year ended December 31, 2025 compared to the same period in 2024 primarily due to an increase in interest rates and the issuance of debt in 2025.

Effective income tax rates were 26.3% and 26.2% for the years ended December 31, 2025 and 2024, respectively. See Note 11 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the effective income tax rates.

Liquidity and Capital Resources

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

The Registrants’ operating and capital expenditure requirements are provided by internally generated cash flows from operations, as well as funds from external sources in the capital markets and through bank borrowings. The Registrants’ businesses are capital intensive and require considerable capital resources. Each of the Registrants annually evaluates its financing plan, dividend practices, and credit line sizing, focusing on maintaining its investment grade ratings while meeting its cash needs to fund capital requirements, including construction expenditures, retire debt, pay dividends, and fund pension and OPEB obligations. The Registrants spend a significant amount of cash on capital improvements and construction projects that have a long-term return on investment. Additionally, the Utility Registrants operate in rate-regulated environments in which the amount of new investment recovery may be delayed or limited and where such recovery takes place over an extended period of time. Each Registrant’s access to external financing on reasonable terms depends on its credit ratings and current overall capital market business conditions, including that of the utility industry in general. If these conditions deteriorate to the extent that the Registrants no longer have access to the capital markets at reasonable terms, the Registrants have access to credit facilities with aggregate bank commitments of $4 billion, as of December 31, 2025. The Registrants utilize their credit facilities to support their commercial paper programs, provide for other short-term borrowings, and to issue letters of credit. See the “Credit Matters and Cash Requirements” section below for additional information. The Registrants expect cash flows to be sufficient to meet operating expenses, financing costs, and capital expenditure requirements. See Note 14 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information on the Registrants’ debt and credit agreements.

Cash Flows from Operating Activities

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

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See Note 2 — Regulatory Matters and Note 16 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for additional information on regulatory and legal proceedings and proposed legislation.

The following table provides a summary of the change in cash flows from operating activities for the years ended December 31, 2025 and 2024 by Registrant:

Increase (decrease) in cash flows from operating activities

Exelon

ComEd

PECO

BGE

PHI

Pepco

DPL

ACE

Net income (loss)

$

308 

$

81 

$

263 

$

51 

$

58 

$

11 

$

15 

$

33 

Adjustments to reconcile net income to cash:

Non-cash operating activities

1,058 

617 

43 

207 

98 

131 

40 

(56)

Collateral (paid) received, net

(43)

(66)

6 

5 

17 

12 

— 

5 

Income taxes

125 

113 

359 

223 

26 

(3)

40 

14 

Pension and non-pension postretirement benefit contributions

(162)

(184)

(9)

(7)

36 

— 

2 

5 

Regulatory assets and liabilities, net

206 

260 

(60)

(13)

31 

(8)

16 

26 

Changes in working capital and other noncurrent assets and liabilities

(807)

(869)

47 

(132)

(78)

(102)

(35)

74 

Increase (decrease) in cash flows from operating activities

$

685 

$

(48)

$

649 

$

334 

$

188 

$

41 

$

78 

$

101 

Changes in the Registrants' cash flows from operations were generally consistent with changes in each Registrant’s respective results of operations, as adjusted by changes in working capital in the normal course of business, except as discussed below. Significant operating cash flow impacts for the Registrants for the years ended December 31, 2025 and 2024 were as follows:

•See Note 20 —Supplemental Financial Information of the Combined Notes to Consolidated Financial Statements and the Registrants’ Consolidated Statements of Cash Flows for additional information on non-cash operating activities.

•Changes in collateral depended upon whether the Registrant was in a net mark-to-market liability or asset position and whether collateral may have been required to be posted with or collected from its counterparties. In addition, the collateral posting and collection requirements differed depending on whether the transactions were on an exchange or in the over-the-counter markets. Changes in collateral for the Utility Registrants are dependent upon the credit exposure of procurement contracts that may require suppliers to post collateral. The amount of cash collateral received from external counterparties remained relatively consistent due to stable energy prices. See Note 13 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information.

•See Note 11 — Income Taxes of the Combined Notes to Consolidated Financial Statements and the Registrants' Consolidated Statements of Cash Flows for additional information on income taxes.

•Changes in Pension and non-pension postretirement benefit contributions relate to Exelon's increased contributions to the Qualified Plans during the year ended December 31, 2025. See Note 14 — Retirement Benefits

•Changes in Regulatory assets and liabilities, net, are due to the timing of cash payments for costs recoverable, or cash receipts for costs recovered, under our regulatory mechanisms differing from the recovery period of those costs. ComEd recognized changes of $849 million and $493 million related to carbon mitigation credits for the years ended December 31, 2025 and 2024, respectively. Included within the change in 2025 is an $804 million adjustment for CMC nuclear production tax credits, which is offset by an increase in Accounts receivable. See Note 2 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information. ComEd's energy efficiency program recognized changes of $447 million and $435 million for the years ended December 31, 2025 and 2024, respectively. Additionally, ComEd recognized changes in the distributed generation rebates program of $83 million and $74 million for the years ended December 31, 2025 and 2024, respectively. Also included within the changes is

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energy efficiency and demand response programs spend for BGE, Pepco, DPL, and ACE of $85 million, $41 million, $16 million, and $55 million for the year ended December 31, 2025, respectively, and $127 million, $52 million, $21 million, and $37 million for the year ended December 31, 2024, respectively. PECO had no energy efficiency and demand response programs spend recorded to a regulatory asset for the years ended December 31, 2025 and 2024.

•Changes in working capital and other noncurrent assets and liabilities for the Utility Registrants and Exelon Corporate total $(1,017) million and $(807) million. The change in working capital and other noncurrent assets and liabilities for Exelon Corporate and the Utility Registrants is dependent upon the normal course of operations for all Registrants. For ComEd, it is also dependent upon whether the participating nuclear-powered generating facilities owe money to ComEd as a result of the established pricing for CMCs. For the year ended December 31, 2025, the established pricing resulted in nuclear-powered generating facilities owing payments to ComEd primarily due to $804 million of nuclear production tax credits, which is reported within the cash flows from operations as a change in Accounts receivable. This change is offset by an increase in the Carbon mitigation credit regulatory liability. See Note 2 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.

Cash Flows from Investing Activities

The following table provides a summary of the change in cash flows from investing activities for the years ended December 31, 2025 and 2024 by Registrant:

(Decrease) increase in cash flows from investing activities

Exelon

ComEd

PECO

BGE

PHI

Pepco

DPL

ACE

Capital expenditures

$

(1,432)

$

(704)

$

(314)

$

(237)

$

(193)

$

(28)

$

22 

$

(17)

Proceeds from sales of assets

(34)

— 

— 

— 

4 

2 

— 

2 

Other investing activities

(17)

(1)

(3)

(3)

— 

— 

— 

— 

(Decrease) increase in cash flows from investing activities

$

(1,483)

$

(705)

$

(317)

$

(240)

$

(189)

$

(26)

$

22 

$

(15)

Significant investing cash flow impacts for the Registrants for 2025 and 2024 were as follows:

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

Cash Flows from Financing Activities

The following table provides a summary of the change in cash flows from financing activities for the years ended December 31, 2025 and 2024 by Registrant:

Increase (decrease) in cash flows from financing activities

Exelon

ComEd

PECO

BGE

PHI

Pepco

DPL

ACE

Changes in short-term borrowings, net

$

(583)

$

530 

$

(219)

$

(14)

$

(54)

$

35 

$

(64)

$

(25)

Long-term debt, net

1,347 

175 

125 

(150)

(17)

— 

(17)

— 

Changes in intercompany money pool

— 

— 

— 

— 

19 

— 

— 

— 

Issuance of common stock

543 

— 

— 

— 

— 

— 

— 

— 

Dividends paid on common stock

(93)

(37)

(146)

(25)

— 

32 

18 

(56)

Distributions to member

— 

— 

— 

— 

(4)

— 

— 

— 

Contributions from parent/member

— 

164 

(18)

294 

63 

(67)

(53)

13 

Other financing activities

8 

6 

(3)

1 

13 

10 

(2)

(1)

Increase (decrease) in cash flows from financing activities

$

1,222 

$

838 

$

(261)

$

106 

$

20 

$

10 

$

(118)

$

(69)

Significant financing cash flow impacts for the Registrants for 2025 and 2024 were as follows:

•Changes in short-term borrowings, net, is driven by repayments on and issuances of notes due in less than 365 days. Refer to Note 14 — Debt and Credit Agreements of the Combined Notes to

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Consolidated Financial Statements for additional information on Short-term borrowings for the Registrants.

•Long-term debt, net, varies due to debt issuances and redemptions each year. Refer to the debt issuances and redemptions tables below for additional information for the Registrants.

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

•Issuance of common stock is driven by the issuance of Exelon common stock under the ATM program in 2025 compared to 2024. See Note 17 — Shareholders' Equity of the Combined Notes to Consolidated Financial Statements for additional information.

•Exelon’s ability to pay dividends on its Common stock depends on the receipt of dividends paid by its operating subsidiaries. The payments of dividends to Exelon by its subsidiaries in turn depend on their results of operations and cash flows and other items affecting Retained earnings. See Note 16 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for additional information on dividend restrictions. See below for quarterly dividends declared.

•Other financing activities primarily consists of debt issuance costs. See the debt issuances table below for additional information on the Registrants’ debt issuances.

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Debt Issuances and Redemptions

See Note 14 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information of the Registrants’ long-term debt. The Registrants' debt activities for 2025 and 2024 was as follows:

During 2025, the following long-term debt was issued:

Company

Type

Interest Rate

Maturity

Amount

Use of Proceeds

Exelon

Junior Subordinated Notes(a)

6.50%

March 15, 2055

$1,000

Repay outstanding commercial paper obligations and for general corporate purposes.

Exelon

Notes

5.125%

March 15, 2031

500

Repay outstanding commercial paper obligations and for general corporate purposes.

Exelon

Notes

5.875%

March 15, 2055

500

Repay outstanding commercial paper obligations and for general corporate purposes.

Exelon

Convertible Senior Notes

3.25%

March 15, 2029

1,000

Repay or refinance debt and for general corporate purposes.

ComEd

First Mortgage Bonds

5.95%

June 1, 2055

725

Repay outstanding commercial paper obligations and for general corporate purposes.

PECO

First Mortgage Bonds

4.875%

September 15, 2035

525

Repay existing indebtedness, repay outstanding commercial paper obligations, and for general corporate purposes.

PECO

First Mortgage Bonds

5.65%

September 15, 2055

525

Repay existing indebtedness, repay outstanding commercial paper obligations, and for general corporate purposes.

BGE

Notes

5.45%

June 1, 2035

650

Repay outstanding commercial paper obligations and for general corporate purposes.

Pepco

First Mortgage Bonds

5.78%

September 17, 2055

75

Repay existing indebtedness and for general corporate purposes.

Pepco

First Mortgage Bonds

5.48%

March 26, 2040

200

Repay existing indebtedness and for general corporate purposes.

DPL

First Mortgage Bonds

5.28%

March 26, 2035

125

Repay existing indebtedness and for general corporate purposes.

ACE

First Mortgage Bonds

5.28%

March 26, 2035

100

Repay existing indebtedness and for general corporate purposes.

ACE

First Mortgage Bonds

5.54%

November 19, 2040

75

Repay existing indebtedness and for general corporate purposes.

ACE

First Mortgage Bonds

5.81%

November 19, 2055

75

Repay existing indebtedness and for general corporate purposes.

__________

(a)The Junior Subordinated Notes bear interest at 6.50% per annum, commencing February 19, 2025 to, but excluding March 15, 2035. Thereafter, the interest rate resets every five years on March 15 and will be set at a rate per annum equal to the Five-year U.S. Treasury Rate plus a spread of 1.975%.

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During 2024, the following long-term debt was issued:

Company

Type

Interest Rate

Maturity

Amount

Use of Proceeds

Exelon

Notes

5.15%

March 15, 2029

$650

Repay existing indebtedness and for general corporate purposes.

Exelon

Notes

5.45%

March 15, 2034

650

Repay existing indebtedness and for general corporate purposes.

Exelon

Notes

5.60%

March 15, 2053

400

Repay existing indebtedness and for general corporate purposes.

ComEd

First Mortgage Bonds

5.30%

June 1, 2034

400

Repay outstanding commercial paper obligations and to fund other general corporate purposes.

ComEd

First Mortgage Bonds

5.65%

June 1, 2054

400

Repay outstanding commercial paper obligations and to fund other general corporate purposes.

PECO

First Mortgage Bonds

5.25%

September 15, 2054

575

Refinance existing indebtedness, refinance outstanding commercial paper obligations, and for general corporate purposes.

BGE

Notes

5.30%

June 1, 2034

400

Repay outstanding commercial paper obligations, repay existing indebtedness, and for general corporate purposes.

BGE

Notes

5.65%

June 1, 2054

400

Repay existing indebtedness and for general corporate purposes.

Pepco

First Mortgage Bonds

5.20%

March 15, 2034

375

Repay existing indebtedness and for general corporate purposes.

Pepco

First Mortgage Bonds

5.50%

March 15, 2054

300

Repay existing indebtedness and for general corporate purposes.

Pepco

First Mortgage Bonds

5.24%

March 20, 2034

100

Repay existing indebtedness and for general corporate purposes.

DPL

First Mortgage Bonds

5.55%

March 20, 2054

75

Repay existing indebtedness and for general corporate purposes.

DPL

First Mortgage Bonds

5.55%

March 20, 2054

75

Repay existing indebtedness and for general corporate purposes.

DPL

First Mortgage Bonds

5.29%

August 28, 2034

75

Repay existing indebtedness and for general corporate purposes.

DPL

First Mortgage Bonds

5.49%

August 28, 2039

100

Repay existing indebtedness and for general corporate purposes.

During 2025, the following long-term debt was retired and/or redeemed:

Company

Type

Interest Rate

Maturity

Amount

Exelon

Senior Notes

3.95%

June 15, 2025

$

807 

Exelon

Software Licensing Agreement

2.30%

December 1, 2025

4 

PECO

First Mortgage Bonds

3.15%

October 15, 2025

350 

ACE

Senior Notes

3.50%

December 1, 2025

150 

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During 2024, the following long-term debt was retired and/or redeemed:

Company (a)

Type

Interest Rate

Maturity

Amount

Exelon

SMBC Term Loan Agreement

SOFR plus 0.85%

April 8, 2024

$

500 

Exelon

Software Licensing Agreement

3.62%

December 1, 2025

1 

Exelon

Software Licensing Agreement

3.95%

May 1, 2024

2 

Exelon

Software Licensing Agreement

2.30%

December 1, 2025

4 

ComEd

First Mortgage Bonds

3.10%

November 1, 2024

250 

Pepco

First Mortgage Bonds

3.60%

March 15, 2024

400 

DPL(b)

Unsecured tax-exempt bonds

4.32%

July 1, 2024

33 

ACE

First Mortgage Bonds

3.38%

September 1, 2024

150 

(a)Exelon repurchased a portion of its Senior unsecured notes during 2024. Refer to Note 14 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information.

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

From time to time and as market conditions warrant, the Registrants may engage in long-term debt retirements via tender offers, open market repurchases or other viable options to reduce debt on their respective Balance sheets.

Dividends

Quarterly dividends declared by the Exelon Board of Directors during the year ended December 31, 2025 and for the first quarter of 2026 were as follows:

Period

Declaration Date

Shareholder of

Record Date

Dividend Payable Date

Cash per Share(a)

First Quarter 2025

February 12, 2025

February 24. 2025

March 14, 2025

$

0.4000 

Second Quarter 2025

April 29, 2025

May 12, 2025

June 13, 2025

$

0.4000 

Third Quarter 2025

July 29, 2025

August 11, 2025

September 15, 2025

$

0.4000 

Fourth Quarter 2025

October 29, 2025

November 10, 2025

December 15, 2025

$

0.4000 

First Quarter 2026

February 12, 2026

March 2, 2026

March 13, 2026

$

0.4200 

___________

(a)Exelon's Board of Directors approved an updated dividend policy for 2026. The 2026 quarterly dividend will be $0.42 per share.

Credit Matters and Cash Requirements

The Registrants fund liquidity needs for capital expenditures, working capital, energy hedging, and other financial commitments through cash flows from operations, public debt offerings, commercial paper markets, and large diversified credit facilities. The credit facilities include $4 billion in aggregate total commitments of which $3.3 billion was available to support additional commercial paper as of December 31, 2025, and of which no financial institution has more than 6.2% of the aggregate commitments for the Registrants. During 2025, the Registrants had access to the commercial paper markets and availability under their revolving credit facilities to fund their short-term liquidity needs, when necessary. Exelon Corporate and the Utility Registrants each have a 5-year revolving credit facility. See Note 14 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information. The Registrants routinely review the sufficiency of their liquidity position, including appropriate sizing of credit facility commitments, by performing various stress test scenarios, such as commodity price movements, increases in margin-related transactions, changes in hedging levels, and the impacts of hypothetical credit downgrades. The Registrants closely monitor events in the financial markets and the financial institutions associated with the credit facilities, including monitoring credit ratings and outlooks, credit default swap levels, capital raising, and merger activity. See PART I, ITEM 1A. RISK FACTORS for additional information regarding the effects of uncertainty in the capital and credit markets.

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

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On August 4, 2022, Exelon executed an equity distribution agreement (“2022 Equity Distribution Agreement”), with certain sales agents and forward sellers and certain forward purchasers, establishing an ATM equity distribution program under which it may offer and sell shares of its Common stock, having an aggregate gross sales price of up to $1 billion through August 3, 2025. On May 2, 2025, Exelon executed an additional equity distribution agreement ("2025 Equity Distribution Agreement" and, together with the August 4, 2022 Equity Distribution Agreement, "Equity Distribution Agreements"), with certain sales agents and forward sellers and certain forward purchasers, establishing an ATM equity distribution program which it may offer and sell shares of its Common stock, having an aggregate gross sales price of up to $2.5 billion through May 2, 2028. The 2025 Equity Distribution Agreement replaced the 2022 Equity Distribution Agreement. Exelon has no obligation to offer or sell any shares of Common stock under the 2025 Equity Distribution Agreement and may, at any time, suspend or terminate offers and sales under the 2025 Equity Distribution Agreement. Exelon issued a total of 23.6 million shares of common stock with net proceeds of $979 million under these agreements in the years ended December 31, 2023 through December 31, 2025.

In addition, during the twelve months ended December 31, 2025, Exelon entered into various forward sale agreements under the 2025 ATM programs. The forward sale agreements require Exelon to, at its election prior to the maturity date, either (i) physically settle the transactions by issuing shares of its Common stock to the forward counterparties in exchange for net proceeds at the then-applicable forward sale price specified by the agreements or (ii) net settle the transactions in whole or in part through the delivery to the forward counterparties or receipt from the forward counterparties of cash or shares in accordance with the provisions of the agreements.

No amounts have been or will be recorded on Exelon's Balance sheets with respect to the equity offerings until the equity forward sale agreements have been settled. Each initial forward sale price is subject to adjustment on a daily basis based on a floating interest rate factor and will decrease by other fixed amounts specified in the agreements. Until settlement of the equity forward, earnings per share dilution resulting from the agreement, if any, will be determined under the treasury stock method. For the twelve months ended December 31, 2025, approximately 15.4 million shares under the forward sale agreements were not included in the calculation of diluted earnings per share because their effect would have been antidilutive.

Inclusive of the impact of the forward sale agreements, $1.5 billion of Common stock remained available for sale pursuant to the ATM program as of December 31, 2025.

See Note 17 — Shareholders' Equity of the Combined Notes to the Consolidated Financial Statements for additional information regarding ATM program terms, forward sale agreements, and share-level activity.

The following table presents the incremental collateral that each Utility Registrant would have been required to provide in the event each Utility Registrant lost its investment grade credit rating at December 31, 2025 and available credit facility capacity prior to any incremental collateral at December 31, 2025:

PJM Credit Policy Collateral

Other Incremental Collateral Required(a)

Available Credit Facility Capacity Prior to Any Incremental Collateral

ComEd

$

27 

$

— 

$

985 

PECO

— 

58 

595 

BGE

— 

43 

575 

Pepco

4 

— 

55 

DPL

1 

14 

139 

ACE

— 

— 

92 

__________

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

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Capital Expenditures

As of December 31, 2025, estimates of future capital expenditures for plant additions and improvements were as follows:

(in millions)(a)

2026 Transmission

  2026 Distribution

      2026 Gas

      Total 2026

     Beyond 2026(b)

Exelon

N/A

N/A

N/A

$

9,950 

$

31,300 

ComEd

1,100 

2,425 

N/A

3,500 

11,450 

PECO

450 

1,375 

400 

2,225 

7,075 

BGE

1,075 

575 

525 

2,175 

6,100 

PHI

725 

1,250 

50 

2,050 

6,650 

Pepco

325 

650 

N/A

975 

2,925 

DPL

225 

325 

50 

625 

2,175 

ACE

175 

275 

N/A

450 

1,550 

___________

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

(b)Includes estimated capital expenditures for the Utility Registrants from 2027 to 2029.

Projected capital expenditures and other investments are subject to periodic review and revision to reflect changes in economic conditions and other factors. Projected capital expenditures at the Utility Registrants are for continuing projects to maintain and improve operations, including enhancing reliability and adding capacity to the transmission and distribution systems. The Utility Registrants anticipate that they will fund their capital expenditures with a combination of internally generated funds and borrowings and additional capital contributions from parent.

Retirement Benefits

Management considers various factors when making pension funding decisions, including actuarially determined minimum contribution requirements under ERISA, contributions required to avoid benefit restrictions and at-risk status as defined by the Pension Protection Act of 2006 (the Act), management of the pension obligation, and regulatory implications. The Act requires the attainment of certain funding levels to avoid benefit restrictions (such as an inability to pay lump sums or to accrue benefits prospectively), and at-risk status (which triggers higher minimum contribution requirements and participant notification). The projected contributions below reflect a funding strategy to make annual contributions with the objective of achieving 100% funded status on an ABO basis over time. This funding strategy helps minimize volatility of future period required pension contributions. Exelon’s estimated annual qualified pension contributions will be $325 million in 2026. Unlike the qualified pension plans, Exelon’s non-qualified pension plans are not funded, given that they are not subject to statutory minimum contribution requirements.

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

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The following table provides all Registrants' planned contributions to the qualified pension plans, planned benefit payments to non-qualified pension plans, and planned contributions to OPEB plans in 2026:

Qualified Pension Plans

Non-Qualified Pension Plans

OPEB

Exelon

$

325 

$

19 

$

48 

ComEd

217 

3 

22 

PECO

9 

1 

4 

BGE

32 

2 

14 

PHI

48 

7 

6 

Pepco

1 

— 

6 

DPL

1 

— 

— 

ACE

14 

— 

— 

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

See Note 12 — Retirement Benefits of the Combined Notes to Consolidated Financial Statements for additional information on pension and OPEB contributions.

Cash Requirements for Other Financial Commitments

The following tables summarize the Registrants' future estimated cash payments as of December 31, 2025 under existing financial commitments:

Exelon

2026

Beyond 2026

Total

Time Period

Long-term debt and finance leases(a)

$

1,665 

$

47,763 

$

49,428 

2026 - 2055

Interest payments on long-term debt(b)

1,932 

31,796 

33,728 

2026 - 2055

Operating leases

26 

187 

213 

2026 - 2099

Fuel purchase agreements(c)

321 

1,293 

1,614 

2026 - 2039

Electric supply procurement

4,259 

2,733 

6,992 

2026 - 2029

Long-term renewable energy and REC commitments

290 

7,716 

8,006 

2026 - 2044

ZEC commitments

156 

62 

218 

2026 - 2027

Pension contributions(d)

325 

1,625 

1,950 

2026 - 2031

Other purchase obligations(e)

9,526 

5,303 

14,829 

2026 - 2035

Total cash requirements

$

18,500 

$

98,478 

$

116,978 

__________

(a)Includes amounts from ComEd and PECO financing trusts.

(b)Interest payments are estimated based on final maturity dates of debt securities outstanding as of December 31, 2025 and do not reflect anticipated future refinancing, early redemptions, or debt issuances. Variable rate interest obligations are estimated based on rates as of December 31, 2025. Includes estimated interest payments due to ComEd and PECO financing trusts.

(c)Represents commitments to purchase natural gas and related transportation, storage capacity, and services.

(d)These amounts represent Exelon’s expected contributions to its qualified pension plans. Qualified pension contributions for years after 2031 are not included.

(e)Represents the future estimated value at December 31, 2025 of the cash flows associated with all contracts, both cancellable and non-cancellable, entered into between the Registrants and third-parties for the provision of services and materials, entered into in the normal course of business, and not specifically reflected elsewhere in this table. These estimates are subject to significant variability from period to period.

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ComEd

2026

Beyond 2026

Total

Time Period

Long-term debt(a)

$

500 

$

12,592 

$

13,092 

2026 - 2055

Interest payments on long-term debt(b)

507 

9,880 

10,387 

2026 - 2055

Electric supply procurement

286 

273 

559 

2026 - 2028

Long-term renewable energy and REC commitments

268 

7,606 

7,874 

2026 - 2044

ZEC commitments

156 

62 

218 

2026 - 2027

Other purchase obligations(c)

2,093 

1,076 

3,169 

2026 - 2034

Total cash requirements

$

3,810 

$

31,489 

$

35,299 

__________

(a)Includes amounts from ComEd financing trust.

(b)Interest payments are estimated based on final maturity dates of debt securities outstanding as of December 31, 2025 and do not reflect anticipated future refinancing, early redemptions, or debt issuances. Includes estimated interest payments due to the ComEd financing trust.

(c)Represents the future estimated value, as of December 31, 2025, of the cash flows associated with all contracts, both cancellable and non-cancellable, entered into between ComEd and third-parties for the provision of services and materials, entered into in the normal course of business, and not specifically reflected elsewhere in this table. These estimates are subject to significant variability from period to period.

PECO

2026

Beyond 2026

Total

Time Period

Long-term debt(a)

$

— 

$

6,659 

$

6,659 

2026 - 2055

Interest payments on long-term debt(b)

266 

5,895 

6,161 

2026 - 2055

Operating leases

1 

— 

1 

2026 - 2035

Fuel purchase agreements(c)

156 

578 

734 

2026 - 2039

Electric supply procurement

767 

177 

944 

2026 - 2027

Other purchase obligations(d)

1,774 

632 

2,406 

2026 - 2035

Total cash requirements

$

2,964 

$

13,941 

$

16,905 

__________

(a)Includes amounts from PECO financing trusts.

(b)Interest payments are estimated based on final maturity dates of debt securities outstanding as of December 31, 2025 and do not reflect anticipated future refinancing, early redemptions, or debt issuances. Includes estimated interest payments due to the PECO financing trusts.

(c)Represents commitments to purchase natural gas and related transportation, storage capacity, and services.

(d)Represents the future estimated value, as of December 31, 2025, of the cash flows associated with all contracts, both cancellable and non-cancellable, entered into between PECO and third-parties for the provision of services and materials, entered into in the normal course of business, and not specifically reflected elsewhere in this table. These estimates are subject to significant variability from period to period.

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BGE

2026

Beyond 2026

Total

Time Period

Long-term debt

$

350 

$

5,750 

$

6,100 

2026 - 2054

Interest payments on long-term debt(a)

241 

4,749 

4,990 

2026 - 2054

Operating leases

4 

29 

33 

2026 - 2099

Fuel purchase agreements(b)

130 

506 

636 

2026 - 2039

Electric supply procurement

1,396 

961 

2,357 

2026 - 2028

Other purchase obligations(c)

2,363 

945 

3,308 

2026 - 2033

Total cash requirements

$

4,484 

$

12,940 

$

17,424 

__________

(a)Interest payments are estimated based on final maturity dates of debt securities outstanding as of December 31, 2025 and do not reflect anticipated future refinancing, early redemptions, or debt issuances.

(b)Represents commitments to purchase natural gas and related transportation, storage capacity, and services.

(c)Represents the future estimated value, as of December 31, 2025, of the cash flows associated with all contracts, both cancellable and non-cancellable, entered into between BGE and third-parties for the provision of services and materials, entered into in the normal course of business, and not specifically reflected elsewhere in this table. These estimates are subject to significant variability from period to period.

PHI

2026

Beyond 2026

Total

Time Period

Long-term debt and finance leases

$

64 

$

9,225 

$

9,289 

2026 - 2055

Interest payments on long-term debt(a)

389 

6,408 

6,797 

2026 - 2055

Operating leases

13 

66 

79 

2026 - 2032

Fuel purchase agreements(b)

35 

209 

244 

2026 - 2031

Electric supply procurement

1,810 

1,322 

3,132 

2026 - 2029

Long-term renewable energy commitments

22 

110 

132 

2026 - 2033

Other purchase obligations(c)

1,749 

1,534 

3,283 

2026 - 2033

Total cash requirements

$

4,082 

$

18,874 

$

22,956 

__________

(a)Interest payments are estimated based on final maturity dates of debt securities outstanding as of December 31, 2025 and do not reflect anticipated future refinancing, early redemptions, or debt issuances. Variable rate interest obligations are estimated based on rates as of December 31, 2025.

(b)Represents commitments to purchase natural gas and related transportation, storage capacity, and services.

(c)Represents the future estimated value, as of December 31, 2025, of the cash flows associated with all contracts, both cancellable and non-cancellable, entered into between Pepco, DPL, ACE, and PHISCO and third-parties for the provision of services and materials, entered into in the normal course of business, and not specifically reflected elsewhere in this table. These estimates are subject to significant variability from period to period.

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Pepco

2026

Beyond 2026

Total

Time Period

Long-term debt and finance leases

$

6 

$

4,694 

$

4,700 

2026 - 2055

Interest payments on long-term debt(a)

205 

3,553 

3,758 

2026 - 2055

Operating leases

5 

25 

30 

2026 - 2032

Electric supply procurement

936 

711 

1,647 

2026 - 2029

Other purchase obligations(b)

1,032 

836 

1,868 

2026 - 2033

Total cash requirements

$

2,184 

$

9,819 

$

12,003 

__________ 

(a)Interest payments are estimated based on final maturity dates of debt securities outstanding as of December 31, 2025 and do not reflect anticipated future refinancing, early redemptions, or debt issuances.

(b)Represents the future estimated value, as of December 31, 2025, of the cash flows associated with all contracts, both cancellable and non-cancellable, entered into between Pepco and third-parties for the provision of services and materials, entered into in the normal course of business, and not specifically reflected elsewhere in this table. These estimates are subject to significant variability from period to period.

DPL

2026

Beyond 2026

Total

Time Period

Long-term debt and finance leases

$

53 

$

2,308 

$

2,361 

2026 - 2054

Interest payments on long-term debt(a)

100 

1,695 

1,795 

2026 - 2054

Operating leases

6 

37 

43 

2025 - 2031

Fuel purchase agreements(b)

35 

209 

244 

2026 - 2031

Electric supply procurement

474 

307 

781 

2026 - 2028

Long-term renewable energy commitments

22 

110 

132 

2026 - 2033

Other purchase obligations(c)

401 

231 

632 

2026 - 2031

Total cash requirements

$

1,091 

$

4,897 

$

5,988 

__________

(a)Interest payments are estimated based on final maturity dates of debt securities outstanding as of December 31, 2025 and do not reflect anticipated future refinancing, early redemptions, or debt issuances. Variable rate interest obligations are estimated based on rates as of December 31, 2025.

(b)Represents commitments to purchase natural gas and related transportation, storage capacity, and services.

(c)Represents the future estimated value, as of December 31, 2025, of the cash flows associated with all contracts, both cancellable and non-cancellable, entered into between DPL and third-parties for the provision of services and materials, entered into in the normal course of business, and not specifically reflected elsewhere in this table. These estimates are subject to significant variability from period to period.

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ACE

2026

Beyond 2026

Total

Time Period

Long-term debt and finance leases

$

5 

$

2,038 

$

2,043 

2026 - 2055

Interest payments on long-term debt(a)

70 

1,068 

1,138 

2026 - 2055

Operating leases

2 

5 

7 

2026 - 2030

Electric supply procurement

400 

304 

704 

2026 - 2028

Other purchase obligations(b)

255 

428 

683 

2026 - 2030

Total cash requirements

$

732 

$

3,843 

$

4,575 

__________

(a)Interest payments are estimated based on final maturity dates of debt securities outstanding as of December 31, 2025 and do not reflect anticipated future refinancing, early redemptions, or debt issuances.

(b)Represents the future estimated value, as of December 31, 2025, of the cash flows associated with all contracts, both cancellable and non-cancellable, entered into between ACE and third-parties for the provision of services and materials, entered into in the normal course of business, and not specifically reflected elsewhere in this table. These estimates are subject to significant variability from period to period.

See Note 16 — Commitments and Contingencies and Note 2 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information of the Registrants’ other commitments potentially triggered by future events. Additionally, see below for where to find additional information regarding the financial commitments in the tables above in the Combined Notes to the Consolidated Financial Statements:

Item

Location within Notes to the Consolidated Financial Statements

Long-term debt

Note 14 — Debt and Credit Agreements

Interest payments on long-term debt

Note 14 — Debt and Credit Agreements

Finance leases

Note 9 — Leases

Operating leases

Note 9 — Leases

Long-term renewable energy and REC commitments

Note 2 — Regulatory Matters

ZEC commitments

Note 2 — Regulatory Matters

Pension contributions

Note 12 — Retirement Benefits

Credit Facilities

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

See Note 14 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information on the Registrants’ credit facilities and short term borrowing activity.

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Capital Structure

As of December 31, 2025, the capital structures of the Registrants consisted of the following:

Exelon

ComEd

PECO

BGE

PHI

Pepco

DPL

ACE

Long-term debt

62 

%

45 

%

45 

%

48 

%

41 

%

48 

%

48 

%

48 

%

Long-term debt to affiliates(a)

— 

%

1 

%

1 

%

— 

%

— 

%

— 

%

— 

%

— 

%

Common equity

37 

%

54 

%

54 

%

52 

%

— 

%

49 

%

49 

%

48 

%

Member’s equity

— 

%

— 

%

— 

%

— 

%

56 

%

— 

%

— 

%

— 

%

Commercial paper and notes payable

1 

%

— 

%

— 

%

— 

%

3 

%

3 

%

3 

%

4 

%

__________ 

(a)Includes approximately $390 million, $206 million, and $184 million owed to unconsolidated affiliates of Exelon, ComEd, and PECO respectively. These special purpose entities were created for the sole purposes of issuing mandatory redeemable trust preferred securities of ComEd and PECO.

Security Ratings

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

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

As part of the normal course of business, the Registrants enter into contracts that contain express provisions or otherwise permit the Registrants and their counterparties to demand adequate assurance of future performance when there are reasonable grounds for doing so. In accordance with the contracts and applicable contracts law, if the Registrants are downgraded by a credit rating agency, it is possible that a counterparty would attempt to rely on such a downgrade as a basis for making a demand for adequate assurance of future performance, which could include the posting of additional collateral. See Note 13 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information on collateral provisions.

The credit ratings for ComEd, BGE, PHI, Pepco, DPL, and ACE did not change for the year ended December 31, 2025. On January 17, 2025, Fitch Ratings affirmed and withdrew the long-term and short-term issuer default ratings along with individual securities ratings of the Registrants for commercial reasons. On February 7, 2025, S&P raised its long-term issuer credit rating for Exelon and PECO from 'BBB+' to 'A-', and raised its rating on Exelon’s senior unsecured debt from ‘BBB’ to 'BBB+'. S&P also affirmed its short-term issuer and commercial paper rating for Exelon and PECO of 'A-2'.

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Intercompany Money Pool

To provide an additional short-term borrowing option that will generally be more favorable to the borrowing participants than the cost of external financing, both Exelon and PHI operate an intercompany money pool. Maximum amounts contributed to and borrowed from the money pool by participant and the net contribution or borrowing as of December 31, 2025, are presented in the following tables.

For the Year Ended December 31, 2025

As of December 31, 2025

Exelon Intercompany Money Pool

Maximum Contributed

Maximum Borrowed

Contributed (Borrowed)

Exelon Corporate

$

578 

$

— 

$

250 

PECO

336 

(253)

— 

BSC

— 

(413)

(233)

PHI Corporate

— 

(85)

(80)

PCI

63 

— 

63 

For the Year Ended December 31, 2025

As of December 31, 2025

PHI Intercompany Money Pool

Maximum Contributed

Maximum Borrowed

Contributed (Borrowed)

Pepco

$

20 

$

(35)

$

— 

DPL

48 

(1)

— 

ACE

— 

(46)

— 

Shelf Registration Statements

On February 13, 2025, Exelon and ComEd filed a combined shelf registration statement on Form S-3 registering $12.6 billion in aggregate amount of securities, which was declared effective by the SEC on April 8, 2025. The shelf registration statement may be used to issue Exelon debt and equity securities as well as ComEd debt securities through the expiration date of April 8, 2028. On February 21, 2024, PECO and BGE filed with the SEC a standalone automatically effective shelf registration statement, unlimited in amount, which can be used to issue PECO and BGE debt securities through the expiration date of February 20, 2027. The ability of Exelon, ComEd, PECO and BGE to sell securities off their corresponding registration statements will depend on a number of factors at the time of the proposed sale, including other required regulatory approvals, as applicable, the current financial condition of the Registrant, its securities ratings, and market conditions.

Pepco, DPL, and ACE periodically issue securities through the private placement markets. Pepco, DPL, and ACE's ability to access the private placement markets will depend on a number of factors at the time of the proposed sale, including other required regulatory approvals, as applicable, current financial condition, securities ratings, and market conditions.

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Regulatory Authorizations

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

At December 31, 2025

Short-term Financing Authority

Remaining Long-term Financing Authority

Commission

Expiration Date

Amount

Commission

Expiration Date

Amount

ComEd(a)(b)

FERC

December 31, 2025

$

2,500 

ICC

January 1, 2027, May 1, 2027

$

1,593 

PECO(a)

FERC

December 31, 2025

1,500 

PAPUC

December 31, 2027

1,850 

BGE(a)

FERC

December 31, 2025

700 

MDPSC

N/A

1,850 

Pepco(a)(c)(d)

FERC

December 31, 2025

500 

MDPSC / DCPSC

December 31, 2025

100 

DPL(a)(c)(e)

FERC

December 31, 2025

500 

MDPSC / DEPSC

December 31, 2025

172 

ACE(f)

NJBPU

January 1, 2028

350 

NJBPU

December 31, 2026

625 

__________

(a)On September 8, 2025, ComEd, PECO, BGE, Pepco, and DPL filed applications with the FERC for renewal of their short-term financing authority through December 31, 2027. On November 7, 2025, ComEd, PECO, BGE, Pepco, and DPL received approval for $2.5 billion, $1.5 billion, $900 million, $700 million, and $700 million, respectively, with an effective date of January 1, 2026.

(b)On December 18, 2025, ComEd received approval from the ICC for $2.8 billion in new long-term debt financing authority, with an effective date of January 1, 2026.

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

(d)On September 3, 2025 and December 17, 2025, Pepco received approval from the MDPSC and DCPSC, respectively, for $1.1 billion in new long-term financing authority, with an effective date of January 1, 2026.

(e)On September 3, 2025, DPL received approval from the MDSPC and DEPSC, respectively, for $700 million in new long-term financing authority, with an effective date of January 1, 2026.

(f)On November 21, 2025, ACE received approval from the NJBPU to extend their $350 million short-term financing authority through January 1, 2028, with an effective date of November 28, 2025.