ATLANTIC CITY ELECTRIC CO
For the period ended Mar 31, 2026. Filed May 6, 2026.
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A company's report for each of its first three quarters. The financial statements are not audited. It shows how the business has moved since the last annual report, and what management says changed.
Mar 31, 2026 · Filed May 6, 2026
EXC$45.62-2.0%Stored close · as of Nov 6, 2026
What changed in Management’s Discussion and Analysis?
Read the current filingPrevious report: 10-Q
Period ended 2025-09-30; filed 2025-11-04.
0001109357-25-000182
ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONSExecutive OverviewFinancial Results of OperationsSignificant 2025 Transactions and DevelopmentsOther Key Business Drivers and Management StrategiesCritical Accounting Policies and EstimatesResults of Operations By RegistrantLiquidity and Capital ResourcesCurrent report: 10-Q
Period ended 2026-03-31; filed 2026-05-06.
0001109357-26-000063
ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONSExecutive OverviewFinancial Results of OperationsSignificant 202 Transactions and DevelopmentsOther Key Business Drivers and Management StrategiesCritical Accounting Policies and EstimatesResults of Operations By RegistrantLiquidity and Capital ResourcesThe baseline is this issuer’s latest earlier reporting period of the same form that was filed before the current report. A previous 10-Q is a different quarter, not a year-over-year comparison. Amendments are excluded.
Compared 291 previous paragraphs and 238 current paragraphs.
132 unchanged; 62 reworded; 40 added; 90 removed; 7 previous and 4 current paragraphs rearranged.
Tables are not compared: 56 previous and 55 current tables excluded. Dates, whitespace, punctuation and numbering changes are ignored; changes to financial figures remain significant.
A changed paragraph is not evidence that risk increased or decreased. An unchanged paragraph does not establish that risk stayed the same.
Added paragraphs (40)
Current report
•Favorable impacts of approved rate increases at ComEd, BGE and PHI;
Current report
•Absence of Customer Surcharge Credits at PECO;
Current report
•Unfavorable impacts of the Pepco Maryland multi-year plan reconciliation at PHI.
Current report
2026 PECO Distribution Base Rate Filing
Current report
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.
Current report
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.
Current report
Corporate Alternative Minimum Tax (All Registrants)
Current report
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.
Current report
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.
Current report
On 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.
Current report
The impact of the notice was recorded as of March 31, 2026.
Current report
Maryland Utility Relief Act
Current report
On April 13, 2026, the Maryland Utility RELIEF Act (Utility RELIEF Act) was passed through the Maryland General Assembly and awaits the Governor’s signature to become law. If and when the Utility RELIEF Act becomes law, it will modify the regulatory framework and rules governing recovery of certain costs in utility ratemaking in Maryland. Exelon, BGE, Pepco, and DPL are in the process of assessing the potential impacts of the pending legislation.
Current report
PJM Cost Allocation Methodology (All Registrants).
Current report
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 petitions for rehearing or clarification.
Current report
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.
Current report
The decrease of $238 million for the three months ended March 31, 2026 compared to the same period in 2025 in Purchased power expenseis offset in Operating revenues as part of regulatory required programs.
Current report
(a)Primarily reflects the probable disallowance of certain capitalized costs in regulatory matters during the three months ended March 31, 2025.
Current report
Effective income tax rates were 24.6% and 17.7% for the three months ended March 31, 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.
Current report
(a)Other revenues increased primarily due to the absence of electric surcharge credits to customers recognized in 2025.
Current report
The increase of $110 million for the three months ended March 31, 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.
Current report
Effective income tax rates were 5.1% and 5.0% for the three months ended March 31, 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.
Current report
The increase of $199 million for the three months ended March 31, 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.
Current report
Effective income tax rates were 21.0% and 21.5% for the three months ended March 31, 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.
Current report
Three Months Ended March 31, 2026 Compared to Three Months Ended March 31, 2025. Net Income decreased by $25 million primarily due to unfavorable impacts of the Pepco Maryland multi-year plan reconciliation and related disallowance of capitalized costs, an increase in depreciation expense, storm costs, and interest expense, partially offset by approved transmission rates, favorable weather conditions at DPL and approved Delaware electric DSIC and natural gas rates.
Current report
The increase of $93 million for the three months ended March 31, 2026, respectively, compared to the same period in 2025, in Purchased power expense is fully offset in Operating revenues as part of regulatory required programs.
Current report
(a)Reflects unfavorable impacts of the Pepco Maryland multi-year plan reconciliation. See Note 2 — Regulatory Matters for additional information.
Current report
Effective income tax rates were 19.0% and 20.5% for the three months ended March 31, 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.
Current report
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. 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. 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.
Current report
The increase of $42 million for the three months ended March 31, 2026, respectively, 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.
Current report
Effective income tax rates were 23.0% and 23.3% for the three months ended March 31, 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.
Current report
Three Months Ended March 31, 2026 Compared to Three Months Ended March 31, 2025. Net income decreased by $4 million primarily due to an increase in storms costs and depreciation expense, partially offset by an increase in approved transmission rates.
Current report
The increase of $48 million for the three months ended March 31, 2026, respectively, compared to the same period in 2025 in Purchased power expense is fully offset in Operating revenues as part of regulatory required programs.
Current report
Significant changes in cash flows from operating activities were primarily due to the following:
Current report
Significant changes in cash flows from investing activities were primarily due to the following:
Current report
Significant changes in cash flows from financing activities were primarily due to the following:
Current report
In the first quarter of 2026, Exelon entered into various forward sale agreements under the 2025 ATM programs. The forward sale agreements require Exelon to, at its election prior to the maturity date, either (i) physically settle the transactions by issuing shares of its Common stock to the forward counterparties in exchange for net proceeds at the then-applicable forward sale price specified by the agreements or (ii) net settle the transactions in whole or in part through the delivery to the forward counterparties or receipt from the forward counterparties of cash or shares in accordance with the provisions of the agreements. The following forward sale agreements were entered into under Exelon’s ATM program in the first quarter of 2026:
Current report
Additionally, the following forward sale agreements were entered into during the twelve months ended 2025 under Exelon’s ATM program and were not settled as of December 31, 2025:
Removed paragraphs (90)
Previous report
•Favorable impacts of rates at ComEd, PECO, BGE, and PHI;
Previous report
•Lower storm costs at PECO, due to deferral of extraordinary February and June storm costs;
Previous report
•Timing of income tax expenses at PECO;
Previous report
•Higher return on regulatory assets at ComEd;
Previous report
Nine Months Ended September 30, 2025 Compared to Nine Months Ended September 30, 2024. Net income attributable to common shareholders increased by $361 million and diluted earnings per average common share increased to $2.15 in 2025 from $1.81 in 2024 primarily due to:
Previous report
•Favorable impacts of rates at ComEd, PECO, BGE and PHI;
Previous report
•Timing of income tax expenses at PECO;
Previous report
•Higher return on regulatory assets at ComEd;
Previous report
•Customer Relief Fund contribution at Exelon Corporate;
Previous report
•Lower transmission peak load due to lower energy demand at ComEd;
Previous report
•Lower impacts of the Maryland multi-year plan reconciliations at PHI; and
Previous report
(b)Reflects the adjustment to state deferred income taxes due to changes in forecasted apportionment.
Previous report
Transmission Formula Rates
Previous report
For 2025, the following total increases/(decreases) were included in the Utility Registrant's electric transmission formula rate updates. See Note 2 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.
Previous report
The Utility Registrants are subject to periodic audits and investigations by FERC. FERC’s Division of Audits and Accounting initiated a nonpublic audit of ComEd in April 2021 evaluating ComEd’s compliance with (1) approved terms, rates and conditions of its federally regulated service; (2) accounting requirements of the Uniform System of Accounts; (3) reporting requirements of the FERC Form 1; and (4) the requirements for record retention. The audit period extended back to January 1, 2017.
Previous report
On July 27, 2023, FERC published a final audit report which included, among other things, findings and recommendations related to ComEd's methodology regarding the allocation of certain overhead costs to capitalized construction costs under FERC regulations, including a suggestion that refunds may be due to customers for amounts collected in previous years. ComEd responded to that report and on August 28, 2023, ComEd filed a formal notice of the issues it contested within the audit report. On December 14, 2023, FERC appointed a settlement judge for the contested overhead allocation findings and set the matter for a trial-type hearing. That hearing process was held in abeyance while a formal settlement process, which began in February 2024, took place.
Previous report
On July 30, 2024, ComEd reached an agreement in principle on the contested overhead allocation finding. As a result of the settlement process, ComEd recorded a charge for the probable disallowance of $70 million of certain currently capitalized construction costs to operating expenses, which are not expected to be recovered in future rates. The existing loss estimate was reflected in Exelon and ComEd's financial statements as of December 31, 2024. ComEd and FERC staff jointly filed the settlement agreement with FERC for approval on February 11, 2025. The settlement was approved by FERC on April 4, 2025.
Previous report
Infrastructure Investment and Jobs Act
Previous report
On November 15, 2021, the $1.2 trillion IIJA was signed into law. IIJA provides for approximately $550 billion in new federal spending. Categories of funding include funding for a variety of infrastructure needs, including but not limited to: (1) power and grid reliability and resilience, (2) resilience for cybersecurity to address critical infrastructure needs, and (3) electric vehicle charging infrastructure for alternative fuel corridors. The Registrants continue to evaluate programs under the legislation and consider possible opportunities to apply for funding, either directly or in potential collaborations with state and/or local agencies and key stakeholders. The Registrants cannot predict the ultimate timing and success of securing funding from programs under IIJA.
Previous report
On January 20, 2025, the Unleashing American Energy Order was issued as a Presidential Executive Order, which required an immediate pause in the disbursement of funds appropriated through the IRA and IIJA pending DOE review. In October 2025, Exelon, ComEd, and BGE received termination notifications from the DOE for their Renewable-Aware Distribution Operations, Deployment of a Community-Oriented Interoperable Control Framework for Aggregating and Integrating Distributed Energy Resources and Other Grid-Edge Devices, and Baltimore Interconnection Readiness & Deployment of Storage (BIRDS) awards, respectively. There are no material financial statement impacts as a result of the DOE terminations. Exelon, ComEd, and BGE will continue to evaluate whether to move forward with these projects.
Previous report
Next Generation Energy Act (Exelon, BGE, PHI, Pepco, and DPL)
Previous report
On May 20, 2025, the Governor of Maryland signed into law legislation that addresses several matters pertaining to electric and gas utilities, including affirming that the MDPSC may approve the use of multi-year rate plans that demonstrate customer benefits, among other things. It also prohibits utilities from filing after January 1, 2025, for the reconciliation of actuals costs and revenues to amounts approved within the multi-year plans. In the second quarter of 2025, BGE derecognized Regulatory assets of $10 million and Regulatory liabilities of $3 million for multi-year plan reconciliations that will no longer be filed. DPL also derecognized Regulatory liabilities of $0.4 million during the second quarter of 2025 for multi-year reconciliations yet to be filed. Multi-year plan reconciliations filed prior to January 1, 2025, remain lawful and will be resolved in their respective proceedings.
Previous report
Summer Rate Mitigation (Exelon, BGE, PHI, Pepco, DPL, and ACE).
Previous report
As part of the passing of the Next Generation Energy Act by the Maryland General Assembly, the MDPSC issued an order on June 26, 2025, to implement the Legislative Energy Relief Refund program under which bill credits will be distributed to residential customers based on their consumption of electricity supply that is subject to the renewable energy portfolio standard. On July 24, 2025, the MDPSC issued an order accepting BGE, Pepco, and DPL's proposal for the implementation of the program. As a result, BGE, Pepco, and DPL received approximately $49 million, $21 million, and $8 million, respectively, from the MDPSC on August 6, 2025. These amounts were used to reduce residential customer accounts receivable balances within the third quarter. An additional disbursement from the state of Maryland is expected in the first quarter of 2026, which will also be used to reduce residential customer receivables upon receipt.
Previous report
In response to significant increases in electric supply costs, on April 23, 2025, the NJBPU issued an order directing the State's electric public utilities to file petitions proposing distribution side measures to mitigate residential customer bill impacts during summer months. As a result, on June 18, 2025, the NJBPU approved a stipulation of settlement for ACE to issue a bill credit of $30 per residential customer for the months of July and August 2025, which was deferred to a Regulatory asset. The amounts will subsequently be collected from September 2025 through February 2026 at a flat rate of $10 per residential customer. The bill credit and subsequent collections will not be subject to carrying costs.
Previous report
In an effort to further reduce the burden of increased electric supply costs, on August 13, 2025, the NJBPU issued an order to establish the RUBC, which will be funded by the NJBPU. The program will provide a $50 bill credit per eligible residential customer for the months of September and October 2025. ACE received $51 million from the NJBPU on September 25, 2025, which was recognized as a Regulatory liability. ACE subsequently issued $25 million in bill credits to residential customers in September 2025 reducing the Regulatory liability to $26 million as of September 30, 2025. The remaining funds were disbursed in October 2025.
Previous report
One Big Beautiful Bill Act (All Registrants)
Previous report
On July 4, 2025, the OBBBA was signed into law. The bill permanently extends expiring tax benefits of the TCJA and provides additional tax relief for individuals and businesses while accelerating the phase-out and curtailment for renewable energy tax credits enacted by the IRA. The tax law changes enacted as part of OBBBA will not have a direct material impact on the Registrants’ financial statements.
Previous report
Nine Months Ended September 30, 2025 Compared to Nine Months Ended September 30, 2024. Net income increased by $80 million as compared to the same period in 2024, primarily due to higher distribution and transmission rate base driven by incremental investments to serve customers, higher return on regulatory assets due to an increase in asset balances, higher AFUDC, and timing of distribution earnings, partially offset by lower transmission peak load.
Previous report
The decrease in Purchased power expense of $29 million and $460 million for the three and nine months ended September 30, 2025, respectively, compared to the same periods in 2024 is offset in Operating revenues as part of regulatory required programs.
Previous report
(a)Primarily reflects the reclassification and increase of the FERC audit liability and a decrease in credit loss expense during the nine months ended September 30, 2024. See Note 2 - Regulatory Matters for additional information regarding the FERC audit liability.
Previous report
(b)ComEd is allowed to recover from or refund to customers the difference between its annual credit loss expense and the amounts collected in rates annually through a rider mechanism.
Previous report
Interest expense, net increased $7 million and $21 million for the three and nine months ended September 30, 2025, respectively, compared to the same periods in 2024, primarily due to an increase in outstanding debt.
Previous report
Effective income tax rates were 18.2% and 9.1% for the three months ended September 30, 2025 and 2024, respectively, and 18.2% and 9.4% for the nine months ended September 30, 2025 and 2024, 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.
Previous report
Nine Months Ended September 30, 2025 Compared to Nine Months Ended September 30, 2024. Net income increased by $296 million due to an increase in revenue as a result of electric and gas distribution rates, coupled with less unfavorable weather relative to the same period last year, decrease in storm costs due to deferral of extraordinary February and June storm costs in the third quarter of 2025 and lower storm costs relative to the same period last year, and tax repairs deduction related to storms, some of which is timing, partially offset by an increase in depreciation expense and interest expense.
Showing the first 40 of 90 passages. Open the source sections for the rest.
Reworded paragraphs (62)
Previous wording
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 nine months ended September 30, 2025 compared to the same period in 2024. For additional information regarding the financial results for the three and nine months ended September 30, 2025 and 2024, see the discussions of Results of Operations by Registrant.
Current wording
GAAP Results of Operations. The following table sets forth Exelon's GAAP consolidated Net income attributable to common shareholders by Registrant for the three months ended March 31, 2026 compared to the same period in 2025. For additional information regarding the financial results for the three months ended March 31, 2026 and 2025, see the discussions of Results of Operations by Registrant.
Previous wording
Three Months Ended September 30, 2025 Compared to Three Months Ended September 30, 2024. Net income attributable to common shareholders increased by $168 million and diluted earnings per average common share increased to $0.86 in 2025 from $0.70 in 2024 primarily due to:
Current wording
Three Months Ended March 31, 2026 Compared to Three Months Ended March 31, 2025. Net income attributable to common shareholders increased by $11 million and diluted earnings per average common share remained relatively consistent to the prior year at $0.90 primarily due to:
Previous wording
The increases were partially offset by:
Current wording
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:
Previous wording
•Higher interest expense at PECO, BGE, PHI, and Exelon Corporate;
Current wording
•Higher interest expense at PECO and Exelon Corporate;
Previous wording
•Lower storm costs and credit loss expense at BGE.
Current wording
•Higher credit loss expense at BGE; and
Previous wording
The following table provides a reconciliation between GAAP Net income attributable to common shareholders and Adjusted (non-GAAP) operating earnings for the three and nine months ended September 30, 2025 compared to the same period in 2024:
Current wording
The following table provides a reconciliation between GAAP Net income attributable to common shareholders and Adjusted (non-GAAP) operating earnings for the three months ended March 31, 2026 compared to the same period in 2025:
Previous wording
(c)Represents the probable disallowance of certain capitalized costs.
Current wording
(b)Represents the disallowance of certain capitalized costs.
Previous wording
Three Months Ended September 30, 2025 Compared to Three Months Ended September 30, 2024. Net Income increased by $13 million as compared to the same period in 2024 primarily due to higher distribution and transmission rate base driven by incremental investments to serve customers, higher return on regulatory assets due to an increase in asset balances, and higher AFUDC, partially offset by the timing of distribution earnings.
Current wording
Three Months Ended March 31, 2026 Compared to Three Months Ended March 31, 2025. Net Income increased by $8 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.
Previous wording
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 months ended September 30, 2025 as compared to the same period in 2024, primarily due to higher fully recoverable costs, higher rate base, and higher return on regulatory assets. Electric distribution revenues increased for the nine months ended September 30, 2025 as compared to the same period in 2024, primarily due to higher fully recoverable costs, higher rate base, higher return on regulatory assets, and differences in the timing of distribution earnings.
Current wording
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 decreased for the three months ended March 31, 2026 as compared to the same period in 2025, primarily due to lower fully recoverable costs.
Previous wording
Transmission Revenue. Under a FERC-approved formula, transmission revenue varies from year to year based upon fluctuations in the underlying costs, capital investments being recovered, and the highest daily peak load, which is updated annually in January based on the prior calendar year. Transmission revenues increased for the three months ended September 30, 2025 compared to the same period in 2024, primarily due to higher fully recoverable costs and higher rate base. Transmission revenues decreased for the nine months ended September 30, 2025 as compared to the same period in 2024, primarily due to lower transmission peak load, partially offset by higher fully recoverable costs and the impacts of higher rate base.
Current wording
Transmission Revenue. Under a FERC-approved formula, transmission revenue varies from year to year based upon fluctuations in the underlying costs, capital investments being recovered, and the highest daily peak load, which is updated annually in January based on the prior calendar year. Transmission revenues increased
Previous wording
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, 2025 as compared to the same periods in 2024, primarily due to increased regulatory asset amortization, which is fully recoverable.
Current wording
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 months ended March 31, 2026 as compared to the same periods in 2025, primarily due to higher fully recoverable costs.
Previous wording
Other Revenue primarily includes assistance provided to other utilities through mutual assistance programs. Other revenues decreased for the three and nine months ended September 30, 2025 as compared to the same periods in 2024, which primarily reflects decreased mutual assistance revenues associated with storm restoration efforts.
Current wording
Other Revenue primarily includes assistance provided to other utilities through mutual assistance programs. Other revenues increased for the three months ended March 31, 2026 as compared to the same periods in 2025, which primarily reflects increased mutual assistance revenues associated with storm restoration efforts.
Previous wording
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.
Current wording
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.
Previous wording
Other, net increased $7 million and $20 million for the three and nine months ended September 30, 2025, respectively, compared to the same periods in 2024, primarily due to higher AFUDC equity.
Current wording
Other, net increased $10 million for the three months ended March 31, 2026 compared to the same period in 2025, primarily due to higher AFUDC equity.
Previous wording
Three Months Ended September 30, 2025 Compared to Three Months Ended September 30, 2024. Net income increased by $133 million due to an increase in revenue as a result of electric and gas distribution rates, decrease in storm costs due to deferral of extraordinary February and June storm costs in the third quarter of 2025, and tax repairs deduction related to storms, some of which is timing, partially offset by an increase in depreciation expense.
Current wording
Three Months Ended March 31, 2026 Compared to Three Months Ended March 31, 2025. Net income increased by $12 million due to an increase in revenue as a result of the absence of surcharge credits to customers, favorable weather relative to the same period last year, and tax repairs, some of which is timing, partially offset by an increase in depreciation and interest expense.
Previous wording
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
Current wording
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 months ended March 31, 2026, compared to the same period in 2025, Operating revenues related to weather increased due to favorable weather conditions in PECO's service territory.
Previous wording
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, 2025 compared to the same period in 2024 and normal weather consisted of the following:
Current wording
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
Previous wording
Volume. Electric volume, exclusive of the effects of weather, for the three and nine months ended September 30, 2025 compared to the same period in 2024, decreased due to customer load. Natural gas volume for the three and nine months ended September 30, 2025 compared to the same period in 2024, remained relatively consistent.
Current wording
Volume. Electric volume, exclusive of the effects of weather, for the three months ended March 31, 2026 compared to the same period in 2025, remained relatively consistent. Natural gas volume for the three months ended March 31, 2026, compared to the same period in 2025, remained relatively consistent.
Previous wording
Pricingfor the three and nine months ended September 30, 2025 compared to the same period in 2024 increased primarily due to electric and gas distribution rates charged to customers.
Current wording
Pricingfor the three months ended March 31, 2026, compared to the same period in 2025, remained relatively consistent.
Previous wording
Other Revenue primarily includes revenue related to late payment charges. Other revenue for the three months ended September 30, 2025 compared to the same period in 2024 remained relatively consistent. Other revenue for the nine months ended September 30, 2025 compared to the same period in 2024 increased primarily due to revenue related to late payment charges.
Current wording
Other Revenue primarily includes revenue related to late payment charges. Other revenue for the three months ended March 31, 2026, compared to the same period in 2025, increased primarily due to the absence of electric surcharge credits to customers recognized in 2025.
Previous wording
Regulatory Required Programs represent revenues collected under approved riders to recover costs incurred for regulatory programs such as energy efficiency, PGC, TSC, and the GSA. The riders are designed to provide full and current cost recovery, and in some cases, a return. The costs of these programs are included in Purchased power and fuel expense, Operating and maintenance expense, Depreciation and amortization expense, and Income taxes. Customers have the choice to purchase electricity and natural gas from competitive electric generation and natural gas suppliers. Customer choice programs do not impact the volume of deliveries as PECO remains the distribution service provider for all customers and charges a regulated rate for distribution service, which is recorded in Operating revenues. For customers that choose to purchase electric generation or natural gas from competitive suppliers, PECO either acts as the billing agent or the competitive supplier separately bills its own customers and therefore PECO does not record Operating revenues or Purchased power and fuel expense related to the electricity and/or natural gas. For customers that choose to purchase electric generation or natural gas from PECO, PECO is permitted to recover the electricity, natural gas, and REC procurement costs without mark-up and therefore records equal and offsetting amounts in Operating revenues and Purchased power and fuel expense related to the electricity, natural gas, and RECs.
Current wording
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.
Previous wording
Nine Months Ended September 30, 2025 Compared to Nine Months Ended September 30, 2024. Net Income increased by $5 million primarily due to an increase in customer growth and a decrease in various operating expenses, offset by an increase in interest and depreciation expense.
Current wording
Three Months Ended March 31, 2026 Compared to Three Months Ended March 31, 2025. Net income increased $38 million primarily due to approved distribution rates and a decrease in various operating expenses, partially offset by an increase in credit loss expense.
Previous wording
Distribution Revenue increased for the three and nine months ended September 30, 2025, compared to the same period in 2024, due to favorable impacts of the multi-year plans.
Current wording
Distribution Revenue increased for the three months ended March 31, 2026, compared to the same period in 2025, due to favorable impacts of the multi-year plans.
Previous wording
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, 2025 compared to the same period in 2024 remained relatively consistent.
Current wording
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 months ended March 31, 2026, compared to the same period in 2025 remained relatively consistent.
Previous wording
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, 2025 as compared to the same period in 2024, primarily driven by increases in service application fees.
Current wording
Other Revenue includes revenue related to late payment charges, mutual assistance, off-system sales, and service application fees. Other Revenue increased for the three months ended March 31, 2026 as compared to the same period in 2025, primarily driven by increases in late payment charges.
Previous wording
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.
Current wording
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.
Previous wording
Taxes other than income taxes increased $7 million and $19 million for the three and nine months ended September 30, 2025, respectively, compared to the same period in 2024, primarily due to increased property taxes.
Current wording
Taxes other than income taxes increased $8 million for the three months ended March 31, 2026, compared to the same period in 2025, primarily due to increased property taxes.
Previous wording
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, 2025 compared to the same periods in 2024. See the Results of Operations for Pepco, DPL, and ACE for additional information.
Current wording
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 months ended March 31, 2026 compared to the same period in 2025. See the Results of Operations for Pepco, DPL, and ACE for additional information.
Previous wording
Nine Months Ended September 30, 2025 Compared to Nine Months Ended September 30, 2024. Net Income increased by $14 million primarily due to distribution and transmission rates, partially offset by lower impacts of the Maryland multi-year plans reconciliations and increases in depreciation and interest expense.
Current wording
Three Months Ended March 31, 2026 Compared to Three Months Ended March 31, 2025. Net Income decreased by $29 million primarily due to unfavorable impacts of the Pepco Maryland multi-year plan reconciliation and related disallowance of capitalized costs, and increases in depreciation and interest expense.
Previous wording
Distribution Revenue increased for the three and nine months ended September 30, 2025 compared to the same periods in 2024 primarily due to favorable impacts of the Maryland and District of Columbia multi-year plans and customer growth in Maryland.
Current wording
Distribution Revenue increased for the three months ended March 31, 2026 compared to the same period in 2025 primarily due to favorable impacts of the District of Columbia multi-year plans and customer growth in Maryland.
Previous wording
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, 2025, compared to the same periods in 2024, primarily due to increases in underlying costs and capital investments.
Current wording
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 months ended March 31, 2026, compared to the same period in 2025, primarily due to increases in underlying costs and capital investments.
Previous wording
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.
Current wording
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.
Previous wording
Nine Months Ended September 30, 2025 Compared to Nine Months Ended September 30, 2024. Net income increased $7 million primarily due to Delaware electric DSIC rates and natural gas rates, favorable weather conditions at Delaware electric and natural gas service territories, and transmission rates, partially offset by increases in interest and depreciation expense.
Current wording
Three Months Ended March 31, 2026 Compared to Three Months Ended March 31, 2025. Net income increased by $8 million primarily due to approved Delaware electric DSIC and natural gas rates, favorable weather conditions at Delaware electric and natural gas service territories, partially offset by an increase in storm costs.
Previous wording
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
Current wording
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 three months ended March 31, 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.
Previous wording
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, 2025, compared to same periods in 2024 and normal weather consisted of the following:
Current wording
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 months ended March 31, 2026, compared to same period in 2025 and normal weather consisted of the following:
Previous wording
Volume, exclusive of the effects of weather, decreased for the three months ended September 30, 2025 compared to the same period in 2024, primarily due to a decrease in customer usage. During the nine months ended September 30, 2025, Volume remained relatively consistent compared to the same period in 2024.
Current wording
Volume, exclusive of the effects of weather, remained relatively consistent for the three months ended March 31, 2026 compared to the same period in 2025.
Previous wording
Distribution Revenue increased for the three and nine months ended September 30, 2025 compared to the same periods in 2024 primarily due to Delaware electric DSIC rates and natural gas rates that became effective in 2025.
Current wording
Distribution Revenue increased for the three months ended March 31, 2026 compared to the same period in 2025 primarily due to Delaware natural gas rates that became effective in 2025 & electric DSIC rates that became effective in 2026.
Previous wording
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, 2025 compared to the same periods in 2024, transmission revenue increased due to increases in underlying costs and capital investments.
Current wording
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 months ended March 31, 2026 compared to the same period in 2025, transmission revenue remained relatively consistent.
Previous wording
Taxes other than income taxes increased by $1 million and $4 million for the three and nine months ended September 30, 2025, respectively, compared to the same period in 2024 primarily due to an increase in property taxes.
Current wording
Taxes other than income taxes increased by $5 million for the three months ended March 31, 2026, respectively, compared to the same period in 2025 primarily due to an increase in property taxes.
Previous wording
Distribution Revenue remained relatively consistent for the three months ended September 30, 2025 compared to the same period in 2024, and increased for the nine months ended September 30, 2025 compared to the same period in 2024, due to an increase in customer growth.
Current wording
Distribution Revenue remained relatively consistent for the three months ended March 31, 2026 compared to the same period in 2025.
Showing the first 40 of 62 pairs. Open the source sections for the rest.
Rearranged current paragraphs (4)
Current report — wording carried from elsewhere
for the three months ended March 31, 2026 compared to the same period in 2025, primarily due to higher fully recoverable costs and higher rate base.
Current report — wording carried from elsewhere
PECO’s service territory for the three months ended March 31, 2026, compared to the same period in 2025, and normal weather consisted of the following:
Current report — wording carried from elsewhere
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 months ended March 31, 2026, compared to the same period in 2025, increased primarily due to increases in the underlying costs and capital investments.
Current report — wording carried from elsewhere
(a)Reflects the cost recovery associated with EmPOWER Maryland. Please refer to 2025 10-K Note 2 — Regulatory Matters for additional information.
Rearranged previous paragraphs (7)
Previous report — wording carried elsewhere
•Higher depreciation expense at PECO; and
Previous report — wording carried elsewhere
•Higher interest expense at PHI and Exelon Corporate.
Previous report — wording carried elsewhere
•Timing of distribution earnings at ComEd; and
Previous report — wording carried elsewhere
The increases were partially offset by:
Previous report — wording carried elsewhere
demand. During the three months ended September 30, 2025 compared to the same period in 2024, Operating revenues related to weather remained relatively consistent. During the nine months ended September 30, 2025 compared to the same period in 2024, Operating revenues related to weather increased due to less unfavorable weather conditions in PECO's service territory.
Previous report — wording carried elsewhere
demand. During the three months ended September 30, 2025 compared to the same period in 2024, Operating revenues related to weather remained relatively consistent. During the nine months ended September 30, 2025 compared to the same period in 2024, Operating revenues related to weather increased due to favorable weather conditions in DPL's Delaware electric and natural gas service territories.
Previous report — wording carried elsewhere
Exelon’s estimated annual qualified pension contributions will be $275 million in 2025. Unlike the qualified pension plans, Exelon’s non-qualified pension plans are not funded, given that they are not subject to statutory minimum contribution requirements.