EXELON CORP

ComEd

Results of Operations by Registrant

Results of Operations—ComEd

Year Ended December 31, 2024 Compared to Year Ended December 31, 2023. Net income decreased by $24 million primarily due to a lower allowed distribution ROE, the absence of a return on the pension asset within distribution earnings, and lower carrying cost recovery related to the CMC regulatory asset. These were partially offset by higher distribution rate base, higher return on regulatory assets primarily due to an increase in asset balances, and higher transmission peak load.

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. Distribution revenues were under a performance-based formula rate through 2023. Starting in 2024, distribution revenues are under a MRP. Both the performance-based formula rate and the MRP require annual reconciliations of the revenue requirement in effect to the actual costs the ICC determines are prudently and reasonably incurred with certain limitations for the MRP reconciliations. 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, 2024, compared to the same period in 2023, primarily due to higher fully

ComEd

recoverable costs and higher rate base, partially offset by lower allowed ROE and the absence of a return on the pension asset.

Transmission Revenue. Under a FERC-approved formula, transmission revenue varies from year to year based upon fluctuations in the underlying costs, capital investments being recov ered, and the highest daily peak load, which is updated annually in January based on the prior calendar year. Transmission revenues increased during the year ended December 31, 2024, compared to the same period in 2023, primarily due to increased underlying costs, higher peak load, and increased capital investments.

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, 2024, compared to the same period in 2023, primarily due to increased regulatory asset amortization, which is fully recoverable, and the impacts of a higher rate base.

Other Revenue primarily includes assistance provided to other utili ties through mutual assistance programs. Other revenue increased for the year ended December 31, 2024, compared to the same period in 2023, which primarily reflects 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 5 — Segment Information of the Combined Notes to Consolidated Financial Statements for the presentation of ComEd's revenue disaggregation.

The $226 million increase in Purchased power expense for the year ended December 31, 2024 compared to the same period in 2023 is offset in Operating revenues as part of regulatory required programs.

ComEd

(a)Primarily reflects an updated rate of capitalization of certain overhead costs.

(b)Primarily reflects the reclassification and increase of the FERC audit liability during the current year and an increase in credit loss expense. See Note 3— Regulatory Matters for additional information regarding the FERC audit liability.

(a)Reflects ongoing capital expenditures.

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

Interest expense, net increased $24 million for the year ended December 31, 2024, compared to the same period in 2023, primarily due to an increase in the principal balance and interest rates of debt issued in 2024.

Effective income tax rates were 9.8% and 22.4% for the years ended December 31, 2024 and 2023, respectively. See Note 13 — 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

Year Ended December 31, 2024 Compared to Year Ended December 31, 2023. Net income decreased by $12 million, primarily due to an increase in credit loss expense, interest expense, and depreciation expense, partially offset by a decrease in income tax expense due to a higher tax repairs deduction and an increase in revenue as a result of less unfavorable weather impact relative to the same period last year.

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, 2024 compared to the same period in 2023, Operating revenues related to weather increased due to less unfavorable 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 years ended December 31, 2024 compared to the same period in 2023 and normal weather consisted of the following:

PECO

Volume. Electric volume, exclusive of the effects of weather, for the year ended December 31, 2024 compared to the same period in 2023, increased due to customer load growth. Natural gas volume for the year ended December 31, 2024 compared to the same period in 2023, 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.

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

Pricingfor the year ended December 31, 2024 compared to the same period in 2023 increased primarily due to higher electric DSIC rates in PECO's service territories.

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 increased for the year ended December 31, 2024 compared to the same period in 2023 primarily due to increases in underlying costs and capital investments.

Other Revenue primarily includes revenue related to late payment charges. Other revenues for the year ended December 31, 2024 compared to the same period in 2023, remained relatively consistent.

Regulatory Required Programs represents revenues collected under approved riders to recover costs incurred for regulatory programs such as energy efficiency, PGC, and the GSA. The riders are designed to provide full and current cost recovery as well as 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 5 — Segment Information of the Combined Notes to Consolidated Financial Statements for the presentation of PECO's revenue disaggregation.

The decrease of $67 million for the year ended December 31, 2024, compared to the same period in 2023, in Purchased power and fuel expense is fully offset in Operating revenues as part of regulatory required programs.

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

Taxes other than income taxes increased by $16 million for the year ended December 31, 2024, compared to the same period in 2023, primarily due to higher Pennsylvania gross receipts tax.

PECO

Interest expense, net increased $31 million for the year ended December 31, 2024, compared to the same period in 2023, primarily due to an increase in interest rates and the issuance of debt in 2024.

Effective income tax rates were (2.2)% and 3.4% for the years ended December 31, 2024 and 2023, respectively. See Note 13 — 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

Year Ended December 31, 2024 Compared to Year Ended December 31, 2023. Net income increased $42 million primarily due to favorable distribution rates, partially offset by lower impacts of multi-year plans reconciliations, an increase in interest expense, storm costs, credit loss expense and various operating expenses. See Note 3 —Regulatory Matters for additional information on multi-year plan order.

BGE

Revenue Decoupling. The demand for electricity and natural gas is affected by weather and customer usage. However, Operating revenues are not intended to be 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 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information on revenue decoupling for BGE.

Distribution Revenue increased for the year ended December 31, 2024 compared to the same period in 2023, 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, 2024 compared to the same period in 2023 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 remained relatively consistent for the year ended December 31, 2024 compared to the same period in 2023.

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

The increase of $120 million for the year ended December 31, 2024 compared to the same period in 2023 in Purchased power and fuel expense is fully offset in Operating revenues as part of regulatory required programs.

BGE

(a)See Note 3 — Regulatory Matters for additional information on multi-year plans reconciliations.

(b)Primarily related to capital write-offs.

(c)Increase due to the cost recovery associated with EmPOWER Maryland. See Note 3 — Regulatory Matters for additional information

(a)Decrease due to the cost recovery associated with EmPOWER Maryland. See Note 3 — Regulatory Matters for additional information.

Taxes other than income taxes increased by $26 million for the year ended December 31, 2024 compared to the same period in 2023, primarily due to increased property taxes.

Interest expense, netincreased $34 million for the year ended December 31, 2024 compared to the same period in 2023, primarily due to an increase in interest rates and the issuance of debt in the second quarter of 2024 and 2023 .

Other, netincreased by $18 million for the year ended December 31, 2024 compared to the same period in 2023, primarily due to increased interest income and higher AFUDC equity.

Effective income tax rates were 8.5% and 21.5% for the years ended December 31, 2024 and 2023, respectively. See Note 13 — 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 year ended December 31, 2024 compared to the same period in 2023. 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.

Year Ended December 31, 2024 Compared to Year Ended December 31, 2023. Net income increased by $151 million primarily due to higher electric distribution rates, lower contracting costs due to the absence of the ACE employee strike, higher transmission rates, decrease in environmental costs at Pepco, favorable impacts of the Pepco Maryland multi-year plans including the recognition of the reconciliations, and a decrease in storm costs, partially offset by increases in depreciation expense and interest expense.

Pepco

Results of Operations—Pepco

Year Ended December 31, 2024 Compared to Year Ended December 31, 2023. Net income increased by $84 million primarily due to decreases in environmental costs, higher transmission rates, favorable impacts of the Maryland multi-year plans including the recognition of the reconciliations, customer growth, and a decrease in storm costs partially offset by an increase in depreciation expense and interest expense.

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 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 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information on revenue decoupling for Pepco Maryland and District of Columbia.

Pepco

Distribution Revenue increased for the year ended December 31, 2024 compared to the same period in 2023, primarily due to higher rates due to the favorable impacts of the Maryland multi-year plans and 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 increased for the year ended December 31, 2024 compared to the same period in 2023 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 5 — Segment Information of the Combined Notes to Consolidated Financial Statements for the presentation of Pepco's revenue disaggregation.

The increase of $81 million for the year ended December 31, 2024 compared to the same period in 2023, in Purchased power expense is fully offset in Operating revenues as part of regulatory required programs.

Pepco

(a)Primarily reflects the decreases in environmental costs for the year ended December 31, 2024.

(b)See Note 3 — Regulatory Matters for additional information on multi-year plan reconciliations.

(c)Increase primarily due to the cost recovery associated with EmPOWER Maryland. Please refer to Note 3 — Regulatory Matters additional information.

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

(b)Decrease includes the cost recovery associated with EmPOWER Maryland. Please refer to Note 3 — Regulatory Matters additional information.

Taxes other than income taxes increased $34 million for the year ended December 31, 2024 compared to the same period in 2023, primarily due to increases in utility taxes, which are offset in revenues, and property taxes.

Interest expense, netincreased $27 million for the year ended December 31, 2024 compared to the same period in 2023 primarily due to an increase in interest rates and the issuance of debt in 2023 and 2024.

(Loss) gain on sales of assets for the year ended December 31, 2024 compared to the same period in 2023 decreased $10 million due to the absence of the gain on sale of land in the fourth quarter of 2023.

Other, net decreased $12 million for the year ended December 31, 2024 compared to the same period in 2023, primarily due to lower AFUDC equity.

Effective income tax rates were 18.8% and 14.3% for the years ended December 31, 2024 and 2023, respectively. See Note 13 — 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

Year Ended December 31, 2024 Compared to Year Ended December 31, 2023. Net income increased by $32 million primarily due to higher Delaware electric distribution rates, favorable weather conditions at Delaware electric and natural gas service territories, and higher transmission rates, partially offset by an increase in interest expense.

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 3 — 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, 2024 compared to the same period in 2023, Operating revenues related to weather increased due to favorable weather conditions in DPL's Delaware electric and natural gas service territories.

DPL

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, 2024 compared to same period in 2023 and normal weather consisted of the following:

Volume, exclusive of the effects of weather, increased for the year ended December 31, 2024 compared to the same period in 2023 primarily due to an increase in customer usage and customer growth.

(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.

DPL

(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 increased for the year ended December 31, 2024 compared to the same period in 2023 primarily due to favorable impacts of the higher electric distribution rates in Delaware that became effective July 2023, and higher natural gas DSIC rates in Delaware that became effective in January 2024, partially offset by lower electric DSIC rates in Delaware that became effective in January 2024.

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, 2024 compared to the same period in 2023 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 5 — Segment Information of the Combined Notes to Consolidated Financial Statements for the presentation of DPL's revenue disaggregation.

The increase of $23 million for the year ended December 31, 2024 compared to the same period in 2023, in Purchased power and fuel expenseis fully offset in Operating revenues as part of regulatory required programs.

DPL

(a)Increase is primarily due to the cost recovery associated with EmPOWER Maryland. Please refer to Note 3 — Regulatory Matters additional information.

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

(b)Decrease is primarily due to the cost recovery associated with EmPOWER Maryland. Please refer to Note 3 — Regulatory Matters additional information.

Taxes other than income taxes increased by $4 million for the year ended December 31, 2024 compared to the same period in 2023, primarily due to an increase in property taxes.

Interest expense, netincreased $19 million for the year ended December 31, 2024 compared to the same period in 2023 primarily due to an increase in interest rates and the issuance of debt in 2023 and 2024.

Other, netincreased $7 million for the year ended December 31, 2024 compared to the same period in 2023, primarily due to higher interest income.

Effective income tax rates were 19.0% and 16.5% for the years ended December 31, 2024 and 2023, respectively. See Note 13 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the change in effective income tax rates.

ACE

Results of Operations—ACE

Year Ended December 31, 2024 Compared to Year Ended December 31, 2023. Net income increased by $35 million primarily due to higher distribution rates and lower contracting costs due to the absence of the ACE employee strike, partially offset by increases in depreciation expense and interest expense.

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 became effective, prospectively, in the third quarter of 2021. The CIP compares current distribution revenues by customer class to approved target revenues established in ACE’s most recent distribution base rate case. The CIP is calculated annually, and recovery is subject to certain conditions, including an earnings test and ceilings on customer rate increases. 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 3 — Regulatory Matters of the Combined Notes to the Consolidated Financial Statements for additional information on the ACE CIP.

ACE

Distribution Revenue increased for the year ended December 31, 2024 compared to the same period in 2023 primarily due to higher distribution rates that became effective December 2023 and the expiration of customer credits related to the TCJA tax benefits.

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, 2024 compared to the same period in 2023.

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

The increase of $61 million for the year ended December 31, 2024 compared to same period in 2023, in Purchased power expense is fully offset in Operating revenues as part of regulatory required programs.

(a)Reflects a decrease in contracting costs for the year ended December 31, 2024, primarily due to the absence of the ACE employee strike that occurred in 2023.

ACE

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

(b)Regulatory required programs decreased primarily due to the regulatory asset amortization of the PPA termination obligation which is fully offset in Operating revenues.

Interest expense, netincreased $7 million for the year ended December 31, 2024 compared to the same period in 2023 primarily due to an increase in interest rates and the issuance of debt in 2023 and 2024.

Other, netdecreased $6 million for the year ended December 31, 2024 compared to the same period in 2023, primarily due to lower AFUDC equity.

Effective income tax rates were 26.2% and 23.1% for the years ended December 31, 2024 and 2023, respectively. See Note 13 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the effective income tax rates.