Exelon · 10-Q · Item 2 MD&A

ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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

Exelon

Executive Overview

Exelon is a utility services holding company engaged in the energy transmission and distribution businesses through 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.

Financial Results of Operations

GAAP Results of Operations. The following table sets forth Exelon's GAAP consolidated Net income attributable to common shareholders by Registrant for the three and six months ended June 30, 2026 compared to the same period in 2025. For additional information regarding the financial results for the three and six months ended June 30, 2026 and 2025, see the discussions of Results of Operations by Registrant.

Three Months Ended June 30,

Favorable (Unfavorable) Variance

Six Months Ended June 30,

Favorable (Unfavorable) Variance

Exelon

$

$

$

5

$

$

$

ComEd

PECO

(5)

BGE

—

PHI

Pepco

DPL

(5)

ACE

(2)

(7)

Other(a)

__________

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

Three Months Ended June 30, 2026 Compared to Three Months Ended June 30, 2025. Net income attributable to common shareholders increased by $5 million and diluted earnings per average common share remained relatively consistent to the prior year at $0.39 primarily due to:

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

•Absence of Customer Relief Fund contribution at Exelon Corporate;

•Absence of Customer Surcharge Credits at PECO;

•Higher AFUDC at ComEd; and

•Favorable weather at PECO.

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

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•Higher depreciation expense at PECO and PHI;

•Higher interest expense at PECO and Exelon Corporate; and

•Higher credit loss expense at BGE.

Six Months Ended June 30, 2026 Compared to Six Months Ended June 30, 2025. Net income attributable to common shareholders increased by $15 million and diluted earnings per average common share decreased to $1.28 in 2026 from $1.29 in 2025 primarily due to:

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

•Absence of Customer Relief Fund contribution at Exelon Corporate;

•Absence of Customer Surcharge Credits at PECO;

•Higher AFUDC at ComEd; and

•Favorable weather at PECO;

Note that rate increases are associated with updated recovery rates for costs and investments to serve customers, driving top quartile reliability and avoiding outage costs. The increases were partially offset by:

•Timing of distribution earnings at ComEd;

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

•Higher depreciation expense at PECO and PHI;

•Higher credit loss expense at BGE; and

•Unfavorable impacts of the Pepco Maryland multi-year plan reconciliation at PHI.

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 GAAP Net income attributable to common shareholders and Adjusted (non-GAAP) operating earnings for the three and six months ended June 30, 2026 compared to the same period in 2025:

Three Months Ended June 30,

(In millions, except per share data)

Earnings per

Diluted Share

Earnings per

Diluted Share

Net income attributable to common shareholders

$

$

$

$

Cost management program (net of taxes of $16)(a)

—

—

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

—

—

1

—

Adjusted (non-GAAP) operating earnings

$

$

$

$

Six Months Ended June 30,

(In millions, except per share data)

Earnings per

Diluted Share

Earnings per

Diluted Share

Net income attributable to common shareholders

$

$

$

$

Change in FERC audit liability (net of taxes of $1)

—

—

2

—

Cost management program (net of taxes of $16 and $0, respectively)(a)

(1)

—

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

—

—

1

—

Regulatory matters (net of taxes of $4 and $7, respectively)(c)

Adjusted (non-GAAP) operating earnings

$

$

$

$

__________

Note:

Amounts may not sum due to rounding.

Unless otherwise noted, the income tax impact of each reconciling item between GAAP Net income attributable to common shareholders and Adjusted (non-GAAP) operating earnings is based on the marginal statutory federal and state income tax rates for each Registrant, taking into account whether the income or expense item is taxable or deductible, respectively, in whole or in part. The marginal statutory income tax rates for 2026 and 2025 ranged from 24.0% to 29.0%.

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

(b)Reflects the adjustment to state deferred income taxes due to changes in forecasted apportionment.

(c)Represents the disallowance of certain capitalized costs.

Significant 2026 Transactions and Developments

At-the-Market Program

In the second quarter of 2026, Exelon issued approximately 8.7 million shares of Common stock at a weighted-average net price of $44.03 per share. The net proceeds from the issuance were $382 million, which were used for general corporate purposes. See Note 12 — 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 2026. See Note 2 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.

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Completed Distribution Base Rate Case Proceedings

Registrant/Jurisdiction

Filing Date

Service

Requested Revenue Requirement Increase

Approved Revenue Requirement Increase

Approved ROE

Approval Date

Rate Effective Date

ComEd - Illinois

Electric

$

$

Electric

$

$

PECO - Pennsylvania

Electric

$

$

N/A

Natural Gas

$

$

BGE - Maryland

Electric

$

$

Natural Gas

$

$

Pepco - District of Columbia

Electric

$

$

Pepco - Maryland

Electric

$

$

DPL - Maryland

Electric

$

$

DPL - Delaware

Electric

$

$

Natural Gas

$

$

ACE - New Jersey

Electric

$

$

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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

Electric

$

DPL - Delaware

Electric

$

BGE - Maryland

Electric

$

Transmission Formula Rates

For 2026, the following increases/(decreases) were included in the Utility Registrants' electric transmission formula rate updates. See Note 2 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.

Registrant

Initial Revenue Requirement Increase (Decrease)

Annual Reconciliation (Decrease) Increase

Total Revenue Requirement (Decrease) Increase

Allowed Return on Rate Base

Allowed ROE

ComEd

$

$

$

%

%

PECO

$

$

$

%

%

BGE

$

$

$

%

%

Pepco

$

$

$

(9)

%

%

DPL

$

3

$

1

$

4

%

%

ACE

$

1

$

$

%

%

2026 PECO Distribution Base Rate Filing

On April 16, 2026, PECO filed a petition with the PAPUC to withdraw its previously filed electric and gas distribution rate proceedings submitted on March 30, 2026. The PAPUC approved the petition to withdraw the rate cases on April 30, 2026.

PECO will continue to evaluate the timing and approach for future capital investments and potential regulatory filings. Any decisions related to capital investments to support longer-term grid modernization will be informed by customer affordability considerations, system reliability needs, and ongoing engagement with regulators and other stakeholders. As PECO assesses longer-term grid needs, it remains committed to providing safe and reliable service.

Corporate Alternative Minimum Tax (All Registrants)

On August 16, 2022, the IRA was signed into law and implements a new corporate alternative minimum tax (CAMT) that imposes a 15.0% tax on modified GAAP net income. Corporations will now pay the greater of 15.0% of financial statement pre-tax income (with certain adjustments) or their regular federal tax liability, which is federal taxable income multiplied by the 21.0% federal corporate tax rate. Corporations are entitled to a tax credit (minimum tax credit) to the extent the CAMT liability exceeds the regular tax liability. This amount can be carried forward indefinitely and used in future years when regular tax exceeds the CAMT.

For the years ended December 31, 2025, December 31, 2024, and December 31, 2023, based on the existing guidance in effect at that time, Exelon and each of the Utility Registrants were subject to and reported the CAMT on a separate Registrant basis in the Consolidated Statements of Operations and Comprehensive Income and the Consolidated Balance Sheets.

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T1On February 18, 2026, the U.S. Treasury issued guidance addressing the implementation of CAMT in the form of a notice. The new guidance permits corporate taxpayers to deduct repair and maintenance costs in the calculation of their CAMT liabilities. The notice applies retroactively, permitting Exelon to file amended returns for both 2024 and 2023 to reduce its CAMT liability by $80 million. Pursuant to the TMA, Exelon received reimbursement from Constellation for $235 million due to the reduction in the amount of Constellation's tax credits needed to offset Exelon's CAMT liability on its amended returns. See Note 6 – Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information.

The impact of the notice was recorded as of March 31, 2026.

Other Key Business Drivers and Management Strategies

The following discussion of other key business drivers and management strategies includes current developments of previously disclosed matters and new issues arising during the period that may impact future financial statements. This section should be read in conjunction with ITEM 1. Business in the 2025 Form 10-K, ITEM 7. Management's Discussion and Analysis of Financial Condition and Results of Operations — Other Key Business Drivers and Management Strategies in the 2025 Form 10-K, and Note 11 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements in this report for additional information on various environmental matters.

Exelon’s Cost Saving Strategy (All Registrants)

T2In May 2026, Exelon announced plans to identify approximately $350 million of operating and maintenance costs savings at Exelon and the Utility Registrants in 2027. This announcement is a result of Exelon’s continuous focus on the needs of our customers through enhanced efficiency and productivity.

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 $0.8 billion - $1.2 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

Maryland Utility Relief Act (Exelon, BGE, PHI, Pepco, and DPL)

T3On May 12, 2026, the Governor of Maryland signed into law legislation that addresses several matters pertaining to electric and gas utilities, including a moratorium on rate cases with forecasted test years until April 1, 2027. Additionally, BGE, Pepco and DPL are required to participate as a member in an RTO effective July 1, 2026, which resulted in a complaint filed on July 2, 2026 against Maryland Transmission Operators, including BGE, Pepco, and DPL, at FERC for the removal of the 50-basis-point incentive adder in the transmission formula rates. The final outcome and resolution of the complaint filing cannot be predicted and the results are not expected to be material to Exelon, BGE, PHI, Pepco, and DPL financial statements.

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PJM Cost Allocation Methodology (All Registrants)

On March 6, 2026, FERC issued an order requiring the removal of the de minimis threshold exemption in the calculation of the cost responsibility of certain transmission reliability upgrade costs allocated to the rate zones of PJM Transmission Owners, including the Utility Registrants. FERC further ordered PJM to recalculate historical cost allocations for the period beginning June 18, 2015, and to pass through additional charges or payments to PJM customers, including Utility Registrants, as applicable, with interest within 90 days. On April 29, 2026, the time for those calculations was extended until further order from FERC. The Utility Registrants expect to recover any incremental charges incurred or reimburse any payments received through prospective electric customer rates.

On April 6, 2026, a number of parties filed requests for rehearing or clarification, which were denied by operation of law on May 7, 2026. On May 12, 2026, PJM Transmission Owners, including Exelon, on behalf of the Utility Registrants, filed a petition for review at the United States Court of Appeals for the D.C. Circuit.

The final impacts of the decision cannot be predicted and the results, while not reasonably estimable at this time, could be material to the financial statements.

New Jersey Repeal RTO Adder Bill (Exelon, PHI, and ACE)

On July 7, 2026, the Governor of New Jersey signed into law legislation that addresses several matters pertaining to electric utility companies. As part of the legislation ACE is required to participate as a member in an RTO effective January 1, 2027, which could result in a complaint filed for the removal of the 50-basis-point incentive adder in the transmission formula rates.

Delaware Senate Bill 326 (Exelon, PHI, and DPL)

On July 13, 2026, the Governor of Delaware signed into law legislation that addresses several matters pertaining to public utility companies. As part of the law, DPL’s non-mandatory capital spend eligible to be recovered in rates will be limited to $70 million in each of the years ended 2026 and 2027 unless the spend falls within an exception or the commission orders otherwise. Further, beginning in 2028, DPL’s non-mandatory capital spend eligible to be recovered in rates shall not exceed 5% of DPL’s rate base approved in its most recent base rate case. The legislation also modifies the timing of interim rate recovery in base rate case proceedings. If the DEPSC has not issued a decision within 7 months of a filing, DPL may implement 50% of the proposed rate increase, subject to refund.

If no decision has been issued after 12 months, DPL may implement 75% of the proposed increase, also subject to refund. DPL is continuing to evaluate the overall potential impacts of the legislation and will continue to monitor related regulatory developments.

Critical Accounting Policies and Estimates

Management of each of the Registrants makes a number of significant estimates, assumptions, and judgments in the preparation of its financial statements. As of June 30, 2026, the Registrants’ critical accounting policies and estimates had not changed significantly from December 31, 2025. See ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS — Critical Accounting Policies and Estimates in the 2025 Form 10-K for further information.

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Results of Operations by Registrant

Results of Operations — ComEd

Three Months Ended

Favorable (Unfavorable) Variance

Six Months Ended

(Unfavorable) Favorable Variance

Operating revenues

$

$

$

$

$

$

(3)

Operating expenses

Purchased power

Operating and maintenance

Depreciation and amortization

Taxes other than income taxes

Total operating expenses

Operating income

Other income and (deductions)

Interest expense, net

Other, net

Total other income and (deductions)

(2)

1

Income before income taxes

Income taxes

Net income

$

$

$

$

$

$

Three Months Ended June 30, 2026 Compared to Three Months Ended June 30, 2025. Net Income increased by $21 million as compared to the same period in 2025, primarily due to higher distribution and transmission rate base driven by incremental investments to serve customers and higher AFUDC.

Six Months Ended June 30, 2026 Compared to Six Months Ended June 30, 2025. Net income increased by $29 million as compared to the same period in 2025, primarily due to higher distribution and transmission rate base driven by incremental investments to serve customers and higher AFUDC, offset by the timing of distribution earnings.

The changes in Operating revenues consisted of the following:

Three Months Ended

Six Months Ended

Increase (Decrease)

Increase (Decrease)

Distribution

$

$

Transmission

Energy efficiency

Other

(8)

(5)

Regulatory required programs

Total increase (decrease)

$

$

(3)

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 revenues increased for the three and six months ended June 30, 2026 as compared to the same periods in 2025, primarily due to higher rate base and higher fully recoverable costs.

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ComEd

Transmission Revenue. T4Under a FERC-approved formula, transmission revenue varies from year to year based upon fluctuations in the underlying costs and capital investments being recovered. Transmission revenues increased for the three and six months ended June 30, 2026 compared to the same periods in 2025, primarily due to higher rate base and higher fully recoverable costs.

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 revenues increased for the three and six months ended June 30, 2026 as compared to the same periods in 2025, primarily due to higher fully recoverable costs.

Other Revenue primarily includes assistance provided to other utilities through mutual assistance programs. Other revenues decreased for the three and six months ended June 30, 2026 as compared to the same periods in 2025, 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. 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, this is treated as a pass through for ComEd and therefore, financial results are not impacted if customers purchase electricity supply from these alternative suppliers. For customers that choose to purchase electric generation from ComEd, ComEd is permitted to recover costs from customers.

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

The increase of $29 million for the three months ended June 30, 2026 and the decrease of $208 million for the six months ended June 30, 2026, compared to the same periods in 2025, in Purchased power expense is offset in Operating revenues as part of regulatory required programs.

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

Three Months Ended

Six Months Ended

Increase (Decrease)

Increase (Decrease)

Labor, other benefits, contracting, and materials

$

$

Storm-related costs

(3)

9

BSC costs

9

Pension and non-pension postretirement benefits expense

3

5

Other(a)

(7)

Regulatory required programs

6

Total increase

$

$

__________

(a)Primarily reflects the disallowance of certain capitalized costs in regulatory matters during the three months ended March 31, 2025.

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ComEd

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

Three Months Ended

Six Months Ended

Increase

Increase

Depreciation and amortization(a)

$

$

Regulatory asset amortization

Total increase

$

$

__________

(a)Reflects ongoing capital expenditures.

Other, net increased $10 million and $20 million for the three and six months ended June 30, 2026, respectively, compared to the same periods in 2025, primarily due to higher AFUDC equity.

Effective income tax rates were 25.0% and 18.6% for the three months ended June 30, 2026 and 2025, respectively, and 24.8% and 18.1% for the six months ended June 30, 2026 and 2025, respectively. See Note 6 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the effective income tax rates.

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PECO

Results of Operations — PECO

Three Months Ended

Favorable (Unfavorable) Variance

Six Months Ended

Favorable (Unfavorable) Variance

Operating revenues

$

$

$

$

$

$

Operating expenses

Purchased power and fuel

Operating and maintenance

5

(5)

Depreciation and amortization

Taxes other than income taxes

(8)

Total operating expenses

Operating income

(4)

Other income and (deductions)

Interest expense, net

Other, net

3

7

Total other income and (deductions)

(9)

Income before income taxes

1

Income taxes

8

4

(4)

(6)

Net income

$

$

$

$

$

$

(5)

Three Months Ended June 30, 2026 Compared to Three Months Ended June 30, 2025. Net Income decreased by $17 million due to an increase in depreciation, interest expense, tax repairs, a portion of which is timing, and severance costs related to the cost management program, partially offset by higher revenues resulting from the absence of surcharge credits to customers, and favorable weather.

Six Months Ended June 30, 2026 Compared to Six Months Ended June 30, 2025. Net income decreased by $5 million due to an increase in depreciation, interest expense, and severance costs related to the cost management program, partially offset by higher revenues resulting from the absence of surcharge credits to customers, and favorable weather.

The changes in Operating revenues consisted of the following:

Three Months Ended

Six Months Ended

Increase (Decrease)

Increase (Decrease)

Electric

Gas

Total

Electric

Gas

Total

Weather

$

6

$

(1)

$

5

$

$

7

$

Volume

(7)

1

(6)

2

(8)

Pricing

(1)

(1)

(2)

4

—

4

Transmission

4

—

4

—

Other(a)

(1)

4

(2)

Regulatory required programs

3

Total increase

$

$

1

$

$

$

$

__________

(a)Other revenues increased primarily due to the absence of electric surcharge credits to customers recognized in 2025.

Weather. The demand for electricity and natural gas is affected by weather conditions. With respect to the electric business, very warm weather in summer months and, with respect to the electric and natural gas businesses, very cold weather in winter months are referred to as “favorable weather conditions” because these weather conditions result in increased deliveries of electricity and natural gas. Conversely, mild weather reduces demand. During the three and six months ended June 30, 2026, compared to the same period in 2025, Operating revenues related to weather increased due to favorable weather conditions in PECO's service territory.

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PECO

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 three and six months ended June 30, 2026, compared to the same period in 2025, and normal weather consisted of the following:

Three Months Ended June 30,

% Change

PECO Service Territory

Normal

Heating Degree-Days

%

%

Cooling Degree-Days

%

%

Six Months Ended June 30,

% Change

Normal

Heating Degree-Days

%

%

Cooling Degree-Days

%

%

Volume. Electric volume, exclusive of the effects of weather, for the three and six months ended June 30, 2026 compared to the same period in 2025, decreased due to customer load. Natural gas volume for the three and six months ended June 30, 2026, compared to the same period in 2025, remained relatively consistent.

Electric Retail Deliveries to Customers (in GWhs)

Three Months Ended

% Change

Weather -

Normal

% Change(b)

Six Months Ended June 30,

% Change

Weather -

Normal

% Change(b)

Residential

%

%

%

%

Small commercial & industrial

%

%

%

%

Large commercial & industrial

%

%

%

%

Public authorities & electric railroads

%

%

%

%

Total electric retail deliveries(a)

%

%

%

%

Number of Electric Customers

Residential

Small commercial & industrial

Large commercial & industrial

Public authorities & electric railroads

Total

__________

(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.

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PECO

Natural Gas Deliveries to Customers (in mmcf)

Three Months Ended

% Change

Weather -

Normal

% Change(b)

Six Months Ended

% Change

Weather -

Normal

% Change(b)

Residential

%

%

%

Small commercial & industrial

%

%

%

%

Large commercial & industrial

1

2

%

%

(9)

%

%

Transportation

%

%

%

%

Total natural gas deliveries(a)

%

%

%

%

Number of Natural Gas Customers

Residential

Small commercial & industrial

Large commercial & industrial

7

7

Transportation

Total

__________

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

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

Pricing for the three and six months ended June 30, 2026, compared to the same period in 2025, remained relatively consistent.

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 three and six months ended June 30, 2026, compared to the same period in 2025, increased primarily due to increases in the underlying costs and capital investments.

Other Revenue primarily includes revenue related to late payment charges. Other revenue for the three and six months ended June 30, 2026, compared to the same period in 2025, increased primarily due to the absence of electric surcharge credits to customers recognized in 2025.

Regulatory Required Programs represent revenues collected under approved riders to recover costs incurred for regulatory programs. 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 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. For customers that choose to purchase electric generation or natural gas from competitive suppliers, this is treated as a pass through for PECO and therefore, financial results are not impacted if customers purchase electricity or natural gas supply from these alternative suppliers. For customers that choose to purchase electric generation or natural gas from PECO, PECO is permitted to recover costs from customers.

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

The increase of $50 million and $160 million for the three and six months ended June 30, 2026, compared to the same period in 2025, in Purchased power and fuel expense is fully offset in Operating revenues as part of regulatory required programs.

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PECO

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

Three Months Ended

Six Months Ended

Increase (Decrease)

Increase (Decrease)

Labor, other benefits, contracting and materials(a)

$

$

BSC costs

8

Pension and non-pension postretirement benefit expense

1

3

Credit loss expense

(2)

(4)

Storm-related costs

Other

—

4

Regulatory required programs

(9)

Total (decrease) increase

$

(5)

$

5

__________

(a)Reflects severance related to cost management program

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

Six Months Ended

Increase

Increase (Decrease)

Depreciation and amortization(a)

$

$

Regulatory asset amortization

—

(1)

Total increase

$

$

__________

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

Taxes other than income taxes increased by $8 million and $16 million for the three and six months ended June 30, 2026, respectively, compared to the same period in 2025, primarily due to higher Pennsylvania gross receipts tax.

Interest expense, net increased by $12 million and $20 million for the three and six months ended June 30, 2026, respectively, compared to the same period in 2025, primarily due to an increase in interest rates and higher outstanding debt.

Effective income tax rates were 6.3% and 2.9% for the three months ended June 30, 2026 and 2025, respectively, and 5.5% and 4.1% for the six months ended June 30, 2026 and 2025, respectively. See Note 6 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the effective income tax rates.

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BGE

Results of Operations — BGE

Three Months Ended

Favorable (Unfavorable) Variance

Six Months Ended

Favorable (Unfavorable) Variance

Operating revenues

$

$

$

$

$

$

Operating expenses

Purchased power and fuel

Operating and maintenance

Depreciation and amortization

Taxes other than income taxes

Total operating expenses

Operating income

(2)

Other income and (deductions)

Interest expense, net

(7)

(9)

Other, net

Total other income and (deductions)

4

9

Income before income taxes

2

Income taxes

(2)

Net income

$

$

$

—

$

$

$

Three Months Ended June 30, 2026 Compared to Three Months Ended June 30, 2025. Net income remained consistent primarily due to approved distribution rates, the absence of the derecognition of regulatory assets for multi-year plan reconciliations that occurred during the second quarter of 2025, and a decrease in various operating expenses, offset by an increase in credit loss expense and severance costs related to the cost management program.

Six Months Ended June 30, 2026 Compared to Six Months Ended June 30, 2025. Net income increased $38 million primarily due to approved distribution rates, the absence of the derecognition of regulatory assets for multi-year plan reconciliations that occurred during the second quarter of 2025, and a decrease in various operating expenses, partially offset by an increase in credit loss expense and severance costs related to the cost management program.

The changes in Operating revenues consisted of the following:

Three Months Ended

Six Months Ended

Increase (Decrease)

Increase (Decrease)

Electric

Gas

Total

Electric

Gas

Total

Distribution

$

$

7

$

$

$

$

Transmission

3

—

3

1

—

1

Other

4

—

4

2

7

Regulatory required programs

(3)

Total increase

$

$

$

$

$

$

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.

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BGE

Number of Electric Customers

Residential

Small commercial & industrial

Large commercial & industrial

Public authorities & electric railroads

Total

Number of Natural Gas Customers

Residential

Small commercial & industrial

Large commercial & industrial

Total

Distribution Revenue increased for the three and six months ended June 30, 2026, compared to the same period in 2025, 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 for the three and six months ended June 30, 2026, compared to the same period in 2025 remained relatively consistent.

Other Revenue includes revenue related to late payment charges, mutual assistance, off-system sales, and service application fees. Other Revenue increased for the three and six months ended June 30, 2026 as compared to the same period in 2025, primarily driven by increases in late payment charges.

Regulatory Required Programs represent revenues collected under approved riders to recover costs incurred for regulatory programs. 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. For customers that choose to purchase electric generation or natural gas from competitive suppliers, this is treated as a pass through for BGE and therefore, financial results are not impacted if customers purchase electricity or natural gas supply from these alternative suppliers. For customers that choose to purchase electric generation or natural gas from BGE, BGE is permitted to recover costs from customers.

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

The increase of $139 million and $337 million for the three and six months ended June 30, 2026, compared to the same period in 2025, in Purchased power and fuel expense is fully offset in Operating revenues as part of regulatory required programs.

Table of Contents

BGE

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

Three Months Ended

Six Months Ended

Increase (Decrease)

Increase (Decrease)

Credit loss expense

$

$

BSC costs

8

Storm-related costs

(4)

(4)

Pension and non-pension postretirement benefits expense

(5)

Labor, other benefits, contracting and materials(a)

(1)

Other(b)

4

(2)

Regulatory required programs(c)

Total increase

$

$

__________

(a)Reflects severance related to cost management program.

(b)Reflects the absence of the derecognition of regulatory assets for multi-year plan reconciliations that occurred during the second quarter of 2025. Please refer to 2025 10-K Note 2 — Regulatory Matters for additional information.

(c)Reflects the cost recovery associated with EmPOWER Maryland. Please refer to 2025 10-K Note 2 — Regulatory Matters for additional information.

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

Three Months Ended

Six Months Ended

Increase

Increase (Decrease)

Depreciation and amortization

$

8

$

Regulatory required programs(a)

3

6

Regulatory asset amortization

1

(8)

Total increase

$

$

__________

(a)Reflects the cost recovery associated with EmPOWER Maryland. Please refer to 2025 10-K Note 2 — Regulatory Matters for additional information.

Taxes other than income taxes increased by $11 million and $19 million for the three and six months ended June 30, 2026, compared to the same period in 2025, primarily due to increased property taxes.

Other, net increased by $11 million and $18 million for the three and six months ended June 30, 2026 compared to the same period in 2025, primarily due to higher AFUDC equity.

Effective income tax rates were 23.6% and 21.4% for the three months ended June 30, 2026 and 2025, and 21.4% and 21.3% for the six months ended June 30, 2026 and 2025. See Note 6 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the effective income tax rates.

Table of Contents

PHI

Results of Operations — PHI

PHI’s Results of Operations include the results of its three reportable segments, Pepco, DPL, and ACE. PHI also has a business services subsidiary, PHISCO, which provides a variety of support services, and the costs are directly charged or allocated to the applicable subsidiaries. Additionally, the results of PHI’s corporate operations include interest costs from various financing activities. All material intercompany accounts and transactions have been eliminated in consolidation. The following table sets forth PHI's GAAP consolidated Net income, by Registrant, for the three and six months ended June 30, 2026 compared to the same periods in 2025. See the Results of Operations for Pepco, DPL, and ACE for additional information.

Three Months Ended

Unfavorable Variance

Six Months Ended June 30,

(Unfavorable) Favorable Variance

PHI

$

$

$

$

$

$

Pepco

DPL

(5)

ACE

(2)

(7)

Other(a)

(4)

(4)

—

(7)

(8)

1

__________

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

Three Months Ended June 30, 2026 Compared to Three Months Ended June 30, 2025. Net Income decreased by $34 million primarily due to an increase in severance costs related to the cost management program, depreciation expense, property taxes at DPL, and various operating expenses, partially offset by approved Delaware electric DSIC and natural gas rates.

Six Months Ended June 30, 2026 Compared to Six Months Ended June 30, 2025. Net Income decreased by $59 million primarily due to an increase in depreciation and interest expenses, property taxes at DPL, unfavorable impacts of the Pepco Maryland multi-year plan reconciliation and related disallowance of capitalized costs, severance costs related to the cost management program, storm costs, and various operating expenses, partially offset by approved Delaware electric DSIC and natural gas rates, approved distribution and transmission rates, and favorable weather conditions at DPL.

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Pepco

Results of Operations — Pepco

Three Months Ended June 30,

Favorable (Unfavorable) Variance

Six Months Ended June 30,

Favorable (Unfavorable) Variance

Operating revenues

$

$

$

$

$

$

Operating expenses

Purchased power

Operating and maintenance

Depreciation and amortization

(7)

Taxes other than income taxes

(4)

(9)

Total operating expenses

(Loss) gain on sale of assets

—

2

(2)

—

1

(1)

Operating income

Other income and (deductions)

Interest expense, net

(2)

(5)

Other, net

9

3

3

Total other income and (deductions)

1

(2)

Income before income taxes

Income taxes

5

Net income

$

$

$

$

$

$

Three Months Ended June 30, 2026 Compared to Three Months Ended June 30, 2025. Net Income decreased by $19 million primarily due to increases in severance costs related to the cost management program, depreciation, and various operating expenses.

Six Months Ended June 30, 2026 Compared to Six Months Ended June 30, 2025. Net Income decreased by $48 million primarily due to unfavorable impacts of the Pepco Maryland multi-year plan reconciliation and related disallowance of capitalized costs, increases in depreciation expense, severance costs related to the cost management program, interest, and various operating expenses.

The changes in Operating revenues consisted of the following:

Three Months Ended

Six Months Ended

Increase (Decrease)

Increase

Distribution

$

7

$

9

Transmission

2

5

Other

(3)

3

6

Regulatory required programs

Total increase

$

$

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.

Table of Contents

Pepco

Number of Electric Customers in Maryland

Residential

Small commercial & industrial

Large commercial & industrial

Public authorities & electric railroads

Total

Distribution Revenue increased for the three and six months ended June 30, 2026 compared to the same periods in 2025 primarily due to favorable impacts of the 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 three and six months ended June 30, 2026, compared to the same periods in 2025, primarily due to increases in underlying costs and capital investments.

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. 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. For customers that choose to purchase electric generation from competitive suppliers, this is treated as a pass through for Pepco and therefore, financial results are not impacted if customers purchase electricity supply from these alternative suppliers. For customers that choose to purchase electric generation from Pepco, Pepco is permitted to recover the costs from customers.

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

The increase of $60 million and $153 million for the three and six months ended June 30, 2026, respectively, compared to the same periods in 2025, in Purchased power expense is fully offset in Operating revenues as part of regulatory required programs.

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

Three Months Ended

Six Months Ended

(Decrease) Increase

Increase (Decrease)

Maryland multi-year plan reconciliation(a)

$

—

$

Labor, other benefits, contracting, and materials(b)

BSC and PHISCO costs

9

Credit loss expense

(3)

(3)

Pension and non-pension postretirement benefits expense

—

(1)

Storm-related costs

(3)

(1)

Other

4

2

Regulatory required programs(c)

Total increase

$

$

_________

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Pepco

(a)Reflects unfavorable impacts of the Pepco Maryland multi-year plan reconciliation. See Note 2 — Regulatory Matters for additional information.

(b)Reflects severance related to cost management program.

(c)Reflects the cost recovery associated with EmPOWER Maryland. Please refer to 2025 10-K Note 2 — Regulatory Matters for additional information.

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

Three Months Ended

Six Months Ended

Increase (Decrease)

Increase

Depreciation and amortization(a)

$

6

$

Regulatory asset amortization

(1)

—

Regulatory required programs(b)

2

4

Total increase

$

7

$

__________

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

(b)Reflects the cost recovery associated with EmPOWER Maryland. Please refer to 2025 10-K Note 2 — Regulatory Matters additional information.

Taxes other than income taxes increased $4 million and $9 million for the three and six months ended June 30, 2026, respectively, compared to the same period 2025, primarily due to increases in utility taxes and property taxes.

Effective income tax rates were 20.7% and 20.8% for the three months ended June 30, 2026 and 2025, respectively, and 19.9% and 21.0% for the six months ended June 30, 2026 and 2025, respectively. See Note 6 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the effective income tax rates.

Table of Contents

DPL

Results of Operations — DPL

Three Months Ended June 30,

Favorable (Unfavorable) Variance

Six Months Ended June 30,

Favorable (Unfavorable) Variance

Operating revenues

$

$

$

$

$

$

Operating expenses

Purchased power and fuel

Operating and maintenance

Depreciation and amortization

(4)

(7)

Taxes other than income taxes

(4)

(9)

Total operating expenses

Operating income

(3)

Other income and (deductions)

Interest expense, net

(1)

(3)

Other, net

4

4

—

8

8

—

Total other income and (deductions)

(1)

(3)

Income before income taxes

(6)

Income taxes

8

3

1

Net income

$

$

$

$

$

$

(5)

Three Months Ended June 30, 2026 Compared to Three Months Ended June 30, 2025. Net income decreased by $13 million primarily due to an increase in depreciation expense, severance costs related to the cost management program, and property taxes, partially offset by approved Delaware electric DSIC and natural gas rates.

Six Months Ended June 30, 2026 Compared to Six Months Ended June 30, 2025. Net income decreased by $5 million primarily due to an increase in property taxes, depreciation expense, severance costs related to the cost management program, storm costs and interest expense, partially offset by approved Delaware electric DSIC and natural gas rates, and favorable weather conditions at Delaware electric and natural gas service territories.

The changes in Operating revenues consisted of the following:

Three Months Ended

Six Months Ended

(Decrease) Increase

Increase (Decrease)

Electric

Gas

Total

Electric

Gas

Total

Weather

$

—

$

—