ATLANTIC CITY ELECTRIC CO

Results of Operations — ComEd

Three Months Ended September 30, 2026 Compared to Three Months Ended September 30, 2025. Net Income increased by $33 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.

Nine Months Ended September 30, 2026 Compared to Nine Months Ended September 30, 2025. Net income increased by $62 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.

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 nine months ended September 30, 2026 as compared to the same periods in 2025, primarily due to higher rate base and higher fully recoverable costs.

ComEd

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 revenues increased for the three and nine months ended September 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 nine months ended September 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 increased for the three and nine months ended September 30, 2026 as compared to the same periods in 2025, which primarily reflects increased mutual assistance revenues associated with storm restoration efforts.

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. One of our larger regulatory required programs is our customer choice program where 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. 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 decrease of $23 million and $230 million for the three and nine months ended September 30, 2026, compared to the same periods in 2025, in Purchased Power Expenseis offset in Operating revenues as part of regulatory required programs.

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

ComEd

(a)Reflects ongoing capital expenditures.

Taxes other than income taxes increased by $26 million and $42 million for the three and nine months ended September 30, 2026, respectively, compared to the same period in 2025, primarily due to increased Assistance Charges for Electricity Distributors and increased utility property taxes.

Interest expense, netincreased by $14 million and $33 million for the three and nine months ended September 30, 2026, respectively, compared to the same period in 2025, primarily due to an increase in outstanding debt.

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

Effective income tax rates were 25.6% and 18.2% for the three months ended September 30, 2026 and 2025, respectively, and 25.1% and 18.2% for the nine months ended September 30, 2026 and 2025, respectively. See Note 7 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the effective income tax rates.

PECO

Results of Operations — PECO

Three Months Ended September 30, 2026 Compared to Three Months Ended September 30, 2025. Net Income decreased by $85 million due to higher storm costs, tax repairs, some of which is timing, contracting, depreciation, and interest expense. The higher storm costs reflect the absence of extraordinary February and June storm cost deferrals recognized in the third quarter of 2025 and increased storm costs in the third quarter of 2026. These unfavorable impacts were partially offset by higher revenues, primarily due to the absence of surcharge credits to customers and favorable weather.

Nine Months Ended September 30, 2026 Compared to Nine Months Ended September 30, 2025. Net income decreased by $90 million due to higher storm costs, tax repairs, some of which is timing, contracting, depreciation, interest, and severance costs related to the cost management program. The higher storm costs reflect the absence of extraordinary storm cost deferrals recognized in the third quarter of 2025, partially offset by lower storm costs in 2026. These unfavorable impacts were partially offset by higher revenues, primarily due to the absence of surcharge credits to customers and favorable weather.

(a)Other revenues for the three and nine months ended September 30, 2026 increased primarily due to the absence of electric surcharge credits to customers recognized in 2025.

PECO

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 nine months ended September 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.

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 nine months ended September 30, 2026, compared to the same period in 2025, and normal weather consisted of the following:

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

(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.

PECO

(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.

Pricingfor the three and nine months ended September 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 nine months ended September 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 nine months ended September 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. One of our larger regulatory required programs is our customer choice program where 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 $48 million and $207 million for the three and nine months ended September 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.

PECO

(a)Reflects severance related to cost management program.

(b)Increase primarily due to the absence of $53 million deferral for extraordinary February and June storm costs recognized in the third quarter of 2025.

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

Taxes other than income taxes increased by $4 million and $21 million for the three and nine months ended September 30, 2026, respectively, compared to the same period in 2025, primarily due to higher Pennsylvania gross receipts tax.

Interest expense, netincreased by $11 million and $31 million for the three and nine months ended September 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 4.6% and 2.0% for the three months ended September 30, 2026 and 2025, respectively, and 5.2% and 3.4% for the nine months ended September 30, 2026 and 2025, respectively. See Note 7 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the effective income tax rates.

BGE

Results of Operations — BGE

Three Months Ended September 30, 2026 Compared to Three Months Ended September 30, 2025. Net income increased $8 million primarily due to approved distribution and transmission rates and a decrease in contracting and various operating expenses, partially offset by project impairments.

Nine Months Ended September 30, 2026 Compared to Nine Months Ended September 30, 2025. Net income increased $45 million primarily due to approved distribution and transmission 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 contracting and various operating expenses, partially offset by project impairments, an increase in credit loss expense, and severance costs related to the cost management program.

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.

BGE

Distribution Revenue increased for the three and nine months ended September 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 increased for the three and nine months ended September 30, 2026, compared to the same period in 2025, 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 three and nine months ended September 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. One of our larger regulatory required programs is our customer choice program where 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 $82 million and $418 million for the three and nine months ended September 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.

BGE

(a)See Note 6 — Property, Plant, and Equipment for additional information.

(b)Reflects severance related to cost management program.

(c)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.

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

(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 $7 million and $28 million for the three and nine months ended September 30, 2026, compared to the same period in 2025, primarily due to increased property taxes.

Interest expense, net increased $9 million and $19 million for the three and nine months ended September 30, 2026, respectively, compared to the same period in 2025, primarily due to the issuance of debt in the second quarter of 2026.

Other, netincreased by $11 million and $29 million for the three and nine months ended September 30, 2026 compared to the same period in 2025, primarily due to increased interest income and higher AFUDC equity.

Effective income tax rates were 20.4% and 21.9% for the three months ended September 30, 2026 and 2025, and 21.2% and 21.3% for the nine months ended September 30, 2026 and 2025. See Note 7 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the effective income tax rates.

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 nine months ended September 30, 2026 compared to the same periods in 2025. See the Results of Operations for Pepco, DPL, and ACE for additional information.

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

Three Months Ended September 30, 2026 Compared to Three Months Ended September 30, 2025. Net Income decreased by $104 million primarily due to write-offs associated with Pepco's Maryland Base Rate Case and increases in storm costs, depreciation and interest expense, partially offset by an increase in approved distribution rates and favorable weather conditions at DPL.

Nine Months Ended September 30, 2026 Compared to Nine Months Ended September 30, 2025. Net Income decreased by $163 million primarily due to write-offs associated with Pepco's Maryland Base Rate Case and multi-year rate plan reconciliation, increases in storm costs, depreciation and interest expense, severance costs related to the cost management program, and various operating expenses, partially offset by an increase in approved distribution rates.

Pepco

Results of Operations — Pepco

Three Months Ended September 30, 2026 Compared to Three Months Ended September 30, 2025. Net Income decreased by $116 million primarily due to write-offs associated with Pepco's Maryland Base Rate Case, and increases in depreciation and interest expense, partially offset by an increase in approved distribution rates.

Nine Months Ended September 30, 2026 Compared to Nine Months Ended September 30, 2025. Net Income decreased by $164 million primarily due to write-offs associated with Pepco's Maryland Base Rate Case and multi-year rate plan reconciliation, increases in depreciation and interest expense, severance costs related to the cost management program, and various operating expenses, partially offset by an increase in approved distribution rates.

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.

Pepco

Distribution Revenue increased for the three and nine months ended September 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 nine months ended September 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. One of our larger regulatory required programs is our customer choice program where 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 $83 million and $236 million for the three and nine months ended September 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.

Pepco

(a)Reflects the write-offs associated with Pepco's Maryland Base Rate Case and multi-year rate 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.

(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 $6 million and $15 million for the three and nine months ended September 30, 2026, respectively, compared to the same period 2025, primarily due to increases in utility taxes and property taxes.

Interest expense, net increased $4 million and $9 million for the three and nine months ended September 30, 2026, respectively, compared to the same period 2025, primarily due to the issuance of debt in 2026.

Effective income tax rates were (11.1)% and 20.8% for the three months ended September 30, 2026 and 2025, respectively, and 14.4% and 20.9% for the nine months ended September 30, 2026 and 2025, respectively. See Note 7 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the effective income tax rates.

DPL

Results of Operations — DPL

Three Months Ended September 30, 2026 Compared to Three Months Ended September 30, 2025. Net income increased by $6 million primarily due to favorable weather conditions at Delaware electric and natural gas service territories, an increase in approved Delaware electric distribution and natural gas rates, and a decrease in property taxes partially offset by an increase in storm costs.

Nine Months Ended September 30, 2026 Compared to Nine Months Ended September 30, 2025. Net income remained relatively consistent.

Revenue Decoupling. The demand for electricity is affected by weather and customer usage. However, Operating revenues from electric distribution in Maryland are not impacted by abnormal weather or usage per customer as a result of a BSA that provides for a fixed distribution charge per customer by customer class. While Operating revenues from electric distribution customers in Maryland are not intended to be impacted by abnormal weather or usage per customer, they are impacted by changes in the number of customers.

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

DPL

weather conditions result in increased deliveries of electricity and natural gas. Conversely, mild weather reduces demand. During the three and nine months ended September 30, 2026 compared to the same period in 2025, Operating revenues 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 three and nine months ended September 30, 2026, compared to same periods in 2025 and normal weather consisted of the following:

Volume, exclusive of the effects of weather, remained relatively consistent for the three and nine months ended September 30, 2026 compared to the same periods in 2025.

DPL

(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.

(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.

Distribution Revenue remained relatively consistent for the three months ended September 30, 2026 compared to the same period in 2025. During the nine months ended September 30, 2026, compared to the same period in 2025, distribution revenue increased primarily due to Delaware natural gas rates that became effective in 2025 & electric distribution rates that became effective in 2026.

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. During the three and nine months ended September 30, 2026 compared to the same period in 2025, transmission revenue increased due to increases in underlying costs and capital investments.

Other Revenue includes rental revenue, service connection fees, and mutual assistance revenues.

Regulatory Required Programs represent revenues collected under approved riders to recover costs incurred for regulatory programs. The riders are designed to provide full and current cost recovery as well as a return in certain instances. One of our larger regulatory required programs is our customer choice program where 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. For customers that choose to purchase electric generation or natural gas from competitive suppliers, this is treated as a pass through for DPL 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 DPL, DPL is permitted to recover costs from customers.

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

The increase of $45 million and $110 million for the three and nine months ended September 30, 2026, respectively, compared to the same periods in 2025 in Purchased power and fuel expense is fully offset in Operating revenues as part of regulatory required programs.

DPL

(a)Reflects severance related to the cost management program.

(b)Reflects the cost recovery associated with EmPOWER Maryland. Please refer to 2025 10-K Note 2 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.

(b)Reflects the cost recovery associated with EmPOWER Maryland. Please refer to 2025 10-K Note 2 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information

Taxes other than income taxes decreased by $5 million for the three months ended September 30, 2026, compared to the same period in 2025 primarily due to a decrease in property taxes. For the nine months ended September 30, 2026 compared to the same period in 2025 taxes other than income taxes remained relatively consistent.

Interest Expense, net increased by $2 million and $6 million for the three and nine months ended September 30, 2026, respectively, compared to the same period in 2025 primarily due to the issuance of debt in 2026.

Effective income tax rates were 23.8% and 23.6% for the three months ended September 30, 2026 and 2025, respectively, and 23.0% and 23.1% for the nine months ended September 30, 2026 and 2025, respectively. See Note 7 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the effective income tax rates.

ACE

Results of Operations — ACE

Three Months Ended September 30, 2026 Compared to Three Months Ended September 30, 2025. Net income increased by $8 million primarily due to an increase in approved distribution rates, partially offset by an increase in storm costs, interest and depreciation expense.

Nine Months Ended September 30, 2026 Compared to Nine Months Ended September 30, 2025. Net income remained relatively consistent.

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.

ACE

Distribution Revenue increased for the three and nine months ended September 30, 2026 compared to the same periods in 2025 due to approved distribution rates that became effective in December 2025 as well as an increase in customer growth.

Transmission Revenues 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 nine months ended September 30, 2026 compared to the same periods in 2025 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. The riders are designed to provide full and current cost recovery as well as a return in certain instances. One of our larger regulatory required programs is our customer choice program where 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. For customers that choose to purchase electric generation from competitive suppliers, this is treated as a pass through for ACE 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 ACE, ACE is permitted to recover costs from customers.

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

The decrease of $10 million and increase $52 million for the three and nine months ended September 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.

ACE

(a)Reflects severance related to cost management program.

Interest expense, net increased $3 million and $5 million for the three and nine months ended September 30, 2026, respectively, compared to the same period 2025, primarily due to the issuance of debt in 2026.

Effective income tax rates were 26.2% and 26.1% for the three months ended September 30, 2026 and 2025, respectively, and 25.7% and 25.8% for the nine months ended September 30, 2026 and 2025, respectively. See Note 7 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the effective income tax rates.