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10-Q – 2025-11-04 – exc-20250930.htm
Buzzard Point Site (Exelon, PHI, and Pepco). On December 8, 2022, Pepco received a letter from the D.C. OAG, alleging wholly past violations of the District's stormwater discharge and waste disposal requirements related to operations at the Buzzard Point facility, a 9-acre parcel of waterfront property in Washington, D.C. occupied by an active substation and former steam plant building. The letter also alleged wholly past violations by Pepco of stormwater discharge requirements related to its district-wide system of underground vaults. Pepco entered into a Consent Order with the District of Columbia to resolve the alleged violations without any admission of liability. The Consent Order requires Pepco to pay a civil penalty of $ 10 million. In addition, Pepco has agreed to assess the environmental conditions at its Buzzard Point facility and conduct any remedial actions deemed necessary as a result of the assessment, and also to assess potential environmental impacts associated with the operation of its underground vaults. The Superior Court for the District of Columbia signed and entered the Consent Order, and it became effective on February 2, 2024. Pepco is proceeding through the multi-step environmental investigation and response as outlined in the consent order. Specifically, the DOEE approved Pepco's Preliminary Site Assessment in July 2025. In September 2025, Pepco timely submitted its work plan for the second stage, the Supplemental Investigation Plan. Pepco also submitted an environmental assessment to the DOEE of the vault system pursuant to the Consent Order in July 2024, and revisions in response to the DOEE's comments in May 2025 and September 2025. Exelon, PHI, and Pepco have accrued a liability for the projected costs for the required environmental assessments and remediation. In January 2025, Pepco paid the last installment of the civil penalty. Pepco has concluded that incremental exposure remains reasonably possible, but management cannot reasonably estimate a range of loss beyond the amounts recorded, which are included in the table above.
Litigation and Regulatory Matters
DPA and Related Matters (Exelon and ComEd). Exelon and ComEd received a grand jury subpoena in the second quarter of 2019 from the U.S. Attorney’s Office for the Northern District of Illinois (USAO) requiring production of information concerning their lobbying activities in the State of Illinois. On October 4, 2019, Exelon and ComEd received a second grand jury subpoena from the USAO requiring production of records of any communications with certain individuals and entities. The Companies cooperated fully with the USAO and any government requests or inquiries. On July 17, 2020, ComEd entered into a DPA with the USAO to resolve the USAO investigation into its historical state legislative lobbying and related practices in Illinois. The agreement resolved the Department of Justice investigation into both ComEd and Exelon, which included a payment to the U.S. Treasury of $ 200 million, which was paid in November 2020. The three-year term of the DPA ended on July 17, 2023, and on that same date the court granted the USAO’s motion to dismiss the pending charge against ComEd that had been deferred by the DPA.
Subsequent to Exelon announcing the receipt of the USAO subpoenas, various lawsuits were filed related to the subject of the subpoenas and the conduct described in the DPA. Several putative class actions were brought in federal and state court by ComEd customers. These actions were dismissed prior to discovery or trial and those dismissals were affirmed on appeal. A putative class action alleging misrepresentations and omissions in Exelon's SEC filings related to ComEd's lobbying activities and the related investigations was also brought in federal court against Exelon and ComEd, which was subsequently settled.
In addition, subsequent to Exelon announcing the receipt of the USAO subpoenas, several shareholders sent letters to the Exelon Board of Directors demanding, among other things, that the Exelon Board of Directors investigate and address alleged breaches of fiduciary duties and other alleged violations by Exelon and ComEd officers and directors related to the conduct described in the DPA. In the first quarter of 2021, the Exelon Board of Directors appointed a Special Litigation Committee (SLC) consisting of disinterested and independent parties to investigate and address these shareholders’ allegations and make recommendations to the Exelon Board of Directors based on the outcome of the SLC’s investigation. In July 2021, one of the demand letter shareholders filed a derivative action against current and former Exelon and ComEd officers and directors, and against Exelon, as nominal defendant, asserting the same claims made in its demand letter. Since that date, multiple parties have filed separate derivative lawsuits that were subsequently consolidated. On October 12, 2021, the parties filed an agreed motion to stay the litigation for 120 days in order to allow the SLC to continue its investigation, which the court granted. The stay was extended several times. Through mediation efforts, a settlement of the derivative claims was reached by the SLC, the Independent Review Committee of the Board (which had been formed in the third quarter of 2022, to ensure the Board’s consideration of any SLC recommendations would be independent and objective), the Board, and certain of the derivative shareholders. On June 16, 2023, the SLC filed a motion for preliminary approval of the settlement, attaching the Stipulation and Agreement of Settlement (Stipulation), which contained the terms of the proposed settlement. The proposed settlement terms include but
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Combined Notes to Consolidated Financial Statements — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Note 11 — Commitments and Contingencies
are not limited to: a payment of $ 40 million to Exelon by Exelon’s insurers of which $ 10 million constitutes the attorneys’ fee award to be paid to the Settling Shareholders’ counsel; various compliance and disclosure-related reforms; and certain changes in Board and Committee composition. The non-settling shareholders objected to the settlement and opposed preliminary approval. On September 20, 2024, the court denied without prejudice the SLC’s motion for preliminary approval. The court’s order provided that if the SLC can substantiate or otherwise revise the attorneys’ fees aspect of the settlement, then the SLC could renew its motion for preliminary approval by October 21, 2024. On October 21, 2024, the SLC filed its second renewed motion for preliminary approval, and the Settling Shareholders filed a brief in support of the SLC's second renewed motion for preliminary approval. On November 20, 2024, the non-settling plaintiffs filed an opposition to the renewed motion for preliminary approval. On December 18, 2024, the SLC and Settling Shareholders filed replies in support of the renewed motion for preliminary approval.
Maryland Sales and Use Tax Refund Claim (Exelon, BGE, PHI, Pepco, and DPL). Maryland imposes a 6% sales and use tax on the purchase of most goods and services. BGE, Pepco, and DPL have filed or plan to file protective refund claims, totaling an estimated $ 100 million, treating electric transmission and distribution machinery and equipment as nontaxable pursuant to the manufacturing exemption available under the Maryland sales and use tax law. The Maryland Comptroller has initially denied the refund claim and litigation is pending.
On November 22, 2024, the Appellate Court of Maryland, in a case involving a regulated electric utility operating in Maryland, ruled the purchase of certain transmission and distribution equipment qualify for the sales tax manufacturing exemption. On December 20, 2024, the Maryland Attorney General, on behalf of the Maryland Comptroller, filed a motion for reconsideration with the Appellate Court of Maryland of its ruling. The motion for reconsideration was denied on February 3, 2025.
On February 18, 2025, the Maryland Attorney General, on behalf of the Maryland Comptroller, filed a petition with the Maryland Supreme Court requesting review of the Appellate Court of Maryland’s ruling. On April 24, 2025, the Maryland Supreme Court granted the petition to review the ruling. On October 1, 2025, the Maryland Supreme Court heard oral arguments in the case.
In the event transmission and distribution equipment is determined to be exempt, Exelon, BGE, PHI, Pepco, and DPL will record estimated receivables of $ 100 million, $ 65 million, $ 35 million, $ 25 million, and $ 10 million, respectively. The sales tax payments were primarily capitalized; therefore, the refund would be recorded as a reduction to PP&E included in rate base.
General (All Registrants). The Registrants are involved in various other litigation matters that are being defended and handled in the ordinary course of business. The Registrants are also from time to time subject to audits and investigations by the FERC and other regulators. The assessment of whether a loss is probable or reasonably possible, and whether the loss or a range of loss is estimable, often involves a series of complex judgments about future events. The Registrants maintain accruals for such losses that are probable of being incurred and subject to reasonable estimation. Management is sometimes unable to estimate an amount or range of reasonably possible loss, particularly where (1) the damages sought are indeterminate, (2) the proceedings are in the early stages, or (3) the matters involve novel or unsettled legal theories. In such cases, there is considerable uncertainty regarding the timing or ultimate resolution of such matters, including a possible eventual loss.
12. Shareholders' Equity (Exelon)
At-the-Market Programs
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Combined Notes to Consolidated Financial Statements — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Note 12 — Shareholders' Equity
On August 4, 2022, Exelon executed an equity distribution agreement (“2022 Equity Distribution Agreement”), with certain sales agents and forward sellers and certain forward purchasers, establishing an ATM equity distribution program under which it may offer and sell shares of its Common stock, having an aggregate gross sales price of up to $ 1 billion through August 3, 2025. On May 2, 2025, Exelon executed an additional equity distribution agreement ("2025 Equity Distribution Agreement" and, together with the August 4, 2022 Equity Distribution Agreement, "Equity Distribution Agreements"), with certain sales agents and forward sellers and certain forward purchasers, establishing an ATM equity distribution program which it may offer and sell shares of its Common stock, having an aggregate gross sales price of up to $ 2.5 billion through May 2, 2028. The 2025 Equity Distribution Agreement replaced the 2022 Equity Distribution Agreement. Exelon has no obligation to offer or sell any shares of Common stock under the 2025 Equity Distribution Agreement and may, at any time, suspend or terminate offers and sales under the 2025 Equity Distribution Agreement.
During the first quarter of 2025, Exelon issued approximately 4.0 million shares of Common stock at an average net price of $ 42.98 per share. The net proceeds from the issuance were $ 173 million, which were used for general corporate purposes.
In addition, in the first quarter of 2025, Exelon entered into forward sale agreements for 5.7 million shares of Common stock, at a weighted-average net forward price of $ 43.24 per share. The forward sale agreements require Exelon to, at its election prior to December 15, 2025, 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.
In the second quarter of 2025, Exelon entered into forward sale agreements for 6.2 million shares and 3.6 million shares of Common stock at weighted-average net forward prices of $ 43.51 and $ 43.17 per share, respectively. The forward sale agreements require Exelon to, at its election prior to December 15, 2025 and November 16, 2026, respectively, 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.
In the third quarter of 2025, Exelon entered into forward sale agreements for 11.5 million shares at a weighted-average net forward price of $ 43.73 per share. The forward sale agreements require Exelon to, at its election prior to December 15, 2026 either (i) physically settle the transactions by issuing shares of its Common stock to the forward counterparties in exchange for net proceeds at the then-applicable forward sale price specified by the agreements or (ii) net settle the transactions in whole or in part through the delivery to the forward counterparties or receipt from the forward counterparties of cash or shares in accordance with the provisions of the agreements.
No amounts have been or will be recorded on Exelon's balance sheet with respect to the equity offerings until the equity forward sale agreements have been settled. Each initial forward sale price is subject to adjustment on a daily basis based on a floating interest rate factor and will decrease by other fixed amounts specified in the agreements. Until settlement of the equity forward, earnings per share dilution resulting from the agreement, if any, will be determined under the treasury stock method. For the nine months ended September 30, 2025, approximately 26.7 million shares under the forward sale agreements were not included in the calculation of diluted earnings per share because their effect would have been antidilutive.
Inclusive of the impact of the forward sale agreements, $ 1.6 billion of Common stock remained available for sale pursuant to the ATM program as of September 30, 2025.
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Combined Notes to Consolidated Financial Statements — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Note 13 — Changes in Accumulated Other Comprehensive Income
13. Changes in Accumulated Other Comprehensive Income (Loss) (Exelon)
The following table presents changes in Exelon's AOCI, net of tax, by component:
Three Months Ended September 30, 2025 Cash Flow Hedges Pension and Non-Pension Postretirement Benefit Plan Items (a)
Total
Balance at June 30, 2025 $ 31 $ ( 749 ) $ ( 718 )
OCI before reclassifications ( 1 ) — ( 1 )
Amounts reclassified from AOCI ( 1 ) 5 4
Net current-period OCI ( 2 ) 5 3
Balance at September 30, 2025 $ 29 $ ( 744 ) $ ( 715 )
Three Months Ended September 30, 2024 Cash Flow Hedges Pension and Non-Pension Postretirement Benefit Plan Items (a)
Total
Balance at June 30, 2024 $ 27 $ ( 739 ) $ ( 712 )
OCI before reclassifications ( 28 ) — ( 28 )
Amounts reclassified from AOCI ( 1 ) 5 4
Net current-period OCI ( 29 ) 5 ( 24 )
Balance at September 30, 2024 $ ( 2 ) $ ( 734 ) $ ( 736 )
Nine Months Ended September 30, 2025 Cash Flow Hedges Pension and Non-Pension Postretirement Benefit Plan Items (a)
Total
December 31, 2024 $ 45 $ ( 765 ) $ ( 720 )
OCI before reclassifications ( 11 ) 5 ( 6 )
Amounts reclassified from AOCI ( 5 ) 16 11
Net current-period OCI $ ( 16 ) $ 21 $ 5
Balance at September 30, 2025 $ 29 $ ( 744 ) $ ( 715 )
Nine Months Ended September 30, 2024 Cash Flow Hedges Pension and Non-Pension Postretirement Benefit Plan Items (a)
Total
Balance at December 31, 2023 $ ( 3 ) $ ( 723 ) $ ( 726 )
OCI before reclassifications 4 ( 26 ) ( 22 )
Amounts reclassified from AOCI ( 3 ) 15 12
Net current-period OCI $ 1 $ ( 11 ) $ ( 10 )
Balance at September 30, 2024 $ ( 2 ) $ ( 734 ) $ ( 736 )
__________
(a) This AOCI component is included in the computation of net periodic pension and OPEB cost. See Note 14 — Retirement Benefits of the 2024 Form 10-K and Note 7 — Retirement Benefits for additional information. See Exelon's Statements of Operations and Comprehensive Income for individual components of AOCI.
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Combined Notes to Consolidated Financial Statements — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Note 13 — Changes in Accumulated Other Comprehensive Income
The following table presents Income tax benefit (expense) allocated to each component of Exelon's Other comprehensive income (loss):
Three Months Ended September 30, Nine Months Ended September 30,
2025 2024 2025 2024
Pension and non-pension postretirement benefit plans:
Actuarial losses reclassified to periodic benefit cost $ ( 2 ) $ ( 2 ) $ ( 6 ) $ ( 6 )
Pension and non-pension postretirement benefit plans valuation adjustments — — ( 2 ) 8
Unrealized gains on cash flow hedges 2 10 4 —
14. Supplemental Financial Information (All Registrants)
Supplemental Statement of Operations Information
The following tables provide additional information about material items recorded in the Registrants' Consolidated Statements of Operations and Comprehensive Income:
Taxes other than income taxes
Exelon ComEd PECO BGE PHI Pepco DPL ACE
Three Months Ended September 30, 2025
Utility taxes (a)
$ 269 $ 85 $ 58 $ 27 $ 99 $ 91 $ 7 $ 1
Property 119 9 6 61 43 29 13 1
Payroll 34 9 4 5 8 2 1 1
Three Months Ended September 30, 2024
Utility taxes (a)
$ 248 $ 80 $ 51 $ 25 $ 92 $ 84 $ 7 $ 1
Property 111 7 5 57 41 28 12 1
Payroll 33 9 4 5 7 2 1 —
Nine Months Ended September 30, 2025
Utility taxes (a)
$ 765 $ 244 $ 156 $ 85 $ 280 $ 255 $ 22 $ 3
Property 341 27 15 175 123 84 37 2
Payroll 101 26 14 14 22 5 3 2
Nine Months Ended September 30, 2024
Utility taxes (a)
$ 695 $ 229 $ 134 $ 78 $ 254 $ 230 $ 21 $ 3
Property 323 25 14 164 119 81 35 2
Payroll 100 27 13 14 22 6 3 2
_________
(a) The Registrants' utility taxes represent municipal and state utility taxes and gross receipts taxes related to their operating revenues. The offsetting collection of utility taxes from customers is recorded in revenues in the Registrants’ Consolidated Statements of Operations and Comprehensive Income.
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Combined Notes to Consolidated Financial Statements — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Note 14 — Supplemental Financial Information
Other, net
Exelon ComEd PECO BGE PHI Pepco DPL ACE
Three Months Ended September 30, 2025
AFUDC — Equity $ 49 $ 19 $ 9 $ 11 $ 10 $ 8 $ 1 $ 1
Non-service net periodic benefit cost ( 13 ) — — — — — — —
Three Months Ended September 30, 2024
AFUDC — Equity $ 38 $ 13 $ 7 $ 5 $ 12 $ 8 $ 3 $ 1
Non-service net periodic benefit cost ( 13 ) — — — — — — —
Nine Months Ended September 30, 2025
AFUDC — Equity $ 130 $ 45 $ 26 $ 29 $ 30 $ 23 $ 4 $ 3
Non-service net periodic benefit cost ( 39 ) — — — — — — —
Nine Months Ended September 30, 2024
AFUDC — Equity $ 116 $ 32 $ 24 $ 18 $ 42 $ 32 $ 9 $ 1
Non-service net periodic benefit cost ( 29 ) — — — — — — —
Supplemental Cash Flow Information
The following tables provide additional information about material items recorded in the Registrants' Consolidated Statements of Cash Flows.
Depreciation, amortization, and accretion
Exelon ComEd PECO BGE PHI Pepco DPL ACE
Nine Months Ended September 30, 2025
Property, plant, and equipment (a)
$ 2,270 $ 915 $ 333 $ 375 $ 606 $ 268 $ 169 ` $ 166
Amortization of regulatory assets and liabilities, net (a)
444 247 3 98 95 53 20 22
Amortization of intangible assets, net (a)
3 — — — — — — —
ARO accretion (b)
2 — — — 2 1 — —
Total depreciation, amortization and accretion $ 2,719 $ 1,162 $ 336 $ 473 $ 703 $ 322 $ 189 $ 188
Nine Months Ended September 30, 2024
Property, plant, and equipment (a)
$ 2,168 $ 869 $ 308 $ 369 $ 581 $ 249 $ 162 $ 158
Amortization of regulatory assets and liabilities, net (a)
507 255 10 105 135 58 21 56
Amortization of intangible assets, net (a)
6 — — — — — — —
ARO accretion (b)
2 — — — — — — —
Total depreciation and amortization $ 2,683 $ 1,124 $ 318 $ 474 $ 716 $ 307 $ 183 $ 214
__________
(a) Included in Depreciation and amortization expense in the Registrants' Consolidated Statements of Operations and Comprehensive Income.
(b) Included in Operating and maintenance expense in Exelon's Consolidated Statements of Operations and Comprehensive Income.
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Combined Notes to Consolidated Financial Statements — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Note 14 — Supplemental Financial Information
Other non-cash operating activities
Exelon ComEd PECO BGE PHI Pepco DPL ACE
Nine Months Ended September 30, 2025
Pension and OPEB costs $ 204 $ 64 $ 5 $ 46 $ 72 $ 26 $ 12 $ 10
Allowance for credit losses 202 41 75 20 66 29 13 24
True-up adjustments to decoupling mechanisms and formula rates (a)
627 525 6 63 33 19 10 4
Amortization of operating ROU asset 22 — — 5 13 4 4 2
AFUDC — Equity ( 130 ) ( 45 ) ( 26 ) ( 29 ) ( 30 ) ( 23 ) ( 4 ) ( 3 )
Nine Months Ended September 30, 2024
Pension and OPEB costs (benefit) $ 181 $ 53 $ ( 1 ) $ 45 $ 71 $ 24 $ 11 $ 10
Allowance for credit losses 170 17 79 23 51 25 7 19
True-up adjustments to decoupling mechanisms and formula rates (a)
49 100 ( 3 ) ( 28 ) ( 20 ) ( 42 ) 7 15
Amortization of operating ROU asset 28 — — 5 19 4 6 2
AFUDC — Equity ( 116 ) ( 32 ) ( 24 ) ( 18 ) ( 42 ) ( 32 ) ( 9 ) ( 1 )
__________
(a) For ComEd, reflects the true-up adjustments in Regulatory assets and liabilities associated with its distribution MRP and distribution, energy efficiency, distributed generation, and transmission formula rates. For PECO, reflects the change in Regulatory assets and liabilities associated with its transmission formula rates. For BGE, Pepco, DPL, and ACE, reflects the change in Regulatory assets and liabilities associated with their decoupling mechanisms and transmission formula rates. See Note 3 — Regulatory Matters of the 2024 Form 10-K for additional information.
The following tables provide a reconciliation of cash, cash equivalents, and restricted cash reported within the Registrants’ Consolidated Balance Sheets that sum to the total of the same amounts in their Consolidated Statements of Cash Flows.
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Combined Notes to Consolidated Financial Statements — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Note 14 — Supplemental Financial Information
Cash, cash equivalents, and restricted cash
Exelon ComEd PECO BGE PHI Pepco DPL ACE
Balance at September 30, 2025
Cash and cash equivalents $ 1,533 $ 405 $ 364 $ 663 $ 93 $ 25 $ 6 $ 25
Restricted cash and cash equivalents 516 453 — 2 27 22 2 3
Restricted cash included in Other deferred debits and other assets 49 49 — — — — — —
Total cash, restricted cash, and cash equivalents $ 2,098 $ 907 $ 364 $ 665 $ 120 $ 47 $ 8 $ 28
Balance at December 31, 2024
Cash and cash equivalents $ 357 $ 105 $ 48 $ 33 $ 139 $ 30 $ 21 $ 14
Restricted cash and cash equivalents 541 486 — 1 24 21 2 —
Restricted cash included in Other deferred debits and other assets 41 41 — — — — — —
Total cash, restricted cash, and cash equivalents $ 939 $ 632 $ 48 $ 34 $ 163 $ 51 $ 23 $ 14
Balance at September 30, 2024
Cash and cash equivalents $ 616 $ 109 $ 28 $ 330 $ 100 $ 20 $ 8 $ 17
Restricted cash and cash equivalents 552 481 9 — 22 20 2 —
Restricted cash included in Other deferred debits and other assets 65 65 — — — — — —
Total cash, restricted cash, and cash equivalents $ 1,233 $ 655 $ 37 $ 330 $ 122 $ 40 $ 10 $ 17
Balance at December 31, 2023
Cash and cash equivalents $ 445 $ 110 $ 42 $ 47 $ 180 $ 48 $ 16 $ 21
Restricted cash and cash equivalents 482 402 9 1 24 24 — —
Restricted cash included in Other deferred debits and other assets 174 174 — — — — — —
Total cash, restricted cash, and cash equivalents $ 1,101 $ 686 $ 51 $ 48 $ 204 $ 72 $ 16 $ 21
For additional information on restricted cash see Note 1 — Significant Accounting Policies of the 2024 Form 10-K.
Supplemental Balance Sheet Information
The following table provides additional information about material items recorded in the Registrants' Consolidated Balance Sheets.
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Combined Notes to Consolidated Financial Statements — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Note 14 — Supplemental Financial Information
Accrued expenses
Exelon ComEd PECO BGE PHI Pepco DPL ACE
Balance at September 30, 2025
Compensation-related accruals (a)
$ 584 $ 179 $ 74 $ 73 $ 105 $ 29 $ 20 $ 13
Taxes accrued 283 160 13 96 116 82 21 7
Interest accrued 458 106 59 91 86 38 28 18
Balance at December 31, 2024
Compensation-related accruals (a)
$ 679 $ 197 $ 87 $ 88 $ 132 $ 38 $ 26 $ 18
Taxes accrued 217 96 13 34 110 92 11 11
Interest accrued 468 150 60 50 83 44 16 18
__________
(a) Primarily includes accrued payroll, bonuses and other incentives, vacation, and benefits.
15. Related Party Transactions (All Registrants)
Service Company Costs for Corporate Support
The Registrants receive a variety of corporate support services from BSC. Pepco, DPL, and ACE also receive corporate support services from PHISCO. See Note 1 — Significant Accounting Policies for additional information regarding BSC and PHISCO.
The following table presents the service company costs allocated to the Registrants:
Operating and maintenance from affiliates Capitalized costs
Three Months Ended September 30, Nine Months Ended September 30, Three Months Ended September 30, Nine Months Ended September 30,
2025 2024 2025 2024 2025 2024 2025 2024
Exelon
BSC $ 156 $ 141 $ 478 $ 458
PHISCO 29 27 83 85
ComEd
BSC $ 95 $ 102 $ 296 $ 306 63 55 186 189
PECO
BSC 58 61 178 180 24 23 79 81
BGE
BSC 60 61 185 182 28 25 92 74
PHI
BSC 44 46 144 145 41 38 121 114
PHISCO — — — — 29 27 83 85
Pepco
BSC 30 29 93 92 18 16 52 51
PHISCO 29 28 91 94 14 12 36 36
DPL
BSC 19 19 58 58 12 11 36 36
PHISCO 24 24 75 75 8 8 25 25
ACE
BSC 15 16 47 48 10 9 28 24
PHISCO 22 23 69 71 7 7 22 24
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Combined Notes to Consolidated Financial Statements — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Note 15 — Related Party Transactions
Current Receivables from/Payables to Affiliates
The following tables present current Receivables from affiliates and current Payables to affiliates:
September 30, 2025
Receivables from affiliates:
Payables to affiliates: ComEd PECO BGE Pepco DPL ACE BSC PHISCO Other Total
ComEd $ — $ — $ — $ — $ — $ 60 $ — $ 1 $ 61
PECO $ — — — — — 30 — 5 35
BGE — — — — — 33 — — 33
PHI — — 1 — — — 5 — 10 16
Pepco — — — — — 17 15 1 33
DPL — — — — — 11 11 1 23
ACE — — — — — 9 9 — 18
Other 4 2 — 1 1 11 — — 19
Total $ 4 $ 2 $ 1 $ 1 $ 1 $ 11 $ 165 $ 35 $ 18 $ 238
December 31, 2024
Receivables from affiliates:
Payables to affiliates: ComEd PECO BGE Pepco DPL ACE BSC PHISCO Other Total
ComEd $ — $ — $ — $ — $ — $ 67 $ — $ 10 $ 77
PECO $ — — — — — 37 — 4 41
BGE — — — — — 47 — 1 48
PHI — — — — — — 7 1 10 18
Pepco — — — — — 21 15 1 37
DPL — — — — — 14 11 1 26
ACE — — — — — 11 10 1 22
Other 4 — — 1 — 7 — — 12
Total $ 4 $ — $ — $ 1 $ — $ 7 $ 204 $ 37 $ 28 $ 281
Borrowings from Exelon/PHI intercompany money pool
To provide an additional short-term borrowing option that will generally be more favorable to the borrowing participants than the cost of external financing both Exelon and PHI operate an intercompany money pool. PECO and PHI Corporate participate in the Exelon intercompany money pool. Pepco, DPL, and ACE participate in the PHI intercompany money pool.
Long-term debt to financing trusts
The following table presents Long-term debt to financing trusts:
September 30, 2025 December 31, 2024
Exelon ComEd PECO Exelon ComEd PECO
ComEd Financing III $ 206 $ 206 $ — $ 206 $ 206 $ —
PECO Trust III 81 — 81 81 — 81
PECO Trust IV 103 — 103 103 — 103
Total $ 390 $ 206 $ 184 $ 390 $ 206 $ 184
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ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
(Dollars in millions except per share data, unless otherwise noted)
Exelon
Executive Overview
Exelon is a utility services holding company engaged in the energy transmission and distribution businesses through its six reportable segments: ComEd, PECO, BGE, Pepco, DPL, and ACE. See Note 1 — Significant Accounting Policies and Note 4 — Segment Information of the Combined Notes to Consolidated Financial Statements for additional information regarding Exelon's principal subsidiaries and reportable segments.
Exelon’s consolidated financial information includes the results of its seven separate operating subsidiary registrants, ComEd, PECO, BGE, PHI, Pepco, DPL, and ACE, which, along with Exelon, are collectively referred to as the Registrants. The following combined Management’s Discussion and Analysis of Financial Condition and Results of Operations is separately filed by Exelon, ComEd, PECO, BGE, PHI, Pepco, DPL, and ACE. However, none of the Registrants makes any representation as to information related solely to any of the other Registrants.
Financial Results of Operations
GAAP Results of Operations. The following table sets forth Exelon's GAAP consolidated Net income attributable to common shareholders by Registrant for the three and 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.
Three Months Ended September 30, Favorable (Unfavorable) Variance Nine Months Ended September 30, Favorable (Unfavorable) Variance
2025 2024 2025 2024
Exelon $ 875 $ 707 $ 168 $ 2,174 $ 1,813 $ 361
ComEd 373 360 13 903 823 80
PECO 250 117 133 652 356 296
BGE 82 45 37 398 353 45
PHI 291 278 13 628 603 25
Pepco 156 140 16 337 323 14
DPL 55 55 — 163 156 7
ACE 82 83 (1) 138 133 5
Other (a)
(121) (93) (28) (407) (322) (85)
__________
(a) Other primarily includes eliminating and consolidating adjustments, Exelon’s corporate operations, shared service entities, and other financing and investment activities.
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:
• Favorable impacts of rates at ComEd, PECO, BGE, and PHI;
• Lower storm costs at PECO, due to deferral of extraordinary February and June storm costs;
• Timing of income tax expenses at PECO;
• Higher return on regulatory assets at ComEd;
• Higher AFUDC at ComEd; and
• Lower storm costs and credit loss expense at BGE.
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The increases were partially offset by:
• Timing of distribution earnings at ComEd;
• Higher depreciation expense at PECO; and
• Higher interest expense at PHI and Exelon Corporate.
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:
• Favorable impacts of rates at ComEd, PECO, BGE and PHI;
• Timing of income tax expenses at PECO;
• Less unfavorable weather at PECO;
• Lower storm costs at PECO and BGE;
• Higher return on regulatory assets at ComEd;
• Timing of distribution earnings at ComEd; and
• Higher AFUDC at ComEd.
The increases were partially offset by:
• Higher interest expense at PECO, BGE, PHI, and Exelon Corporate;
• Customer Relief Fund contribution at Exelon Corporate;
• Higher depreciation expense at PECO and PHI;
• Lower transmission peak load due to lower energy demand at ComEd;
• Lower impacts of the Maryland multi-year plan reconciliations at PHI; and
• Lower AFUDC at PHI.
Adjusted (non-GAAP) operating earnings. In addition to Net income, Exelon evaluates its operating performance using the measure of Adjusted (non-GAAP) operating earnings because management believes it represents earnings directly related to the ongoing operations of the business. Adjusted (non-GAAP) operating earnings exclude certain costs, expenses, gains and losses, and other specified items. This information is intended to enhance an investor’s overall understanding of year-over-year operating results and provide an indication of Exelon’s baseline operating performance excluding items not considered by management to be directly related to the ongoing operations of the business. In addition, this information is among the primary indicators management uses as a basis for evaluating performance, allocating resources, setting incentive compensation targets, and planning and forecasting of future periods. Adjusted (non-GAAP) operating earnings is not a presentation defined under GAAP and may not be comparable to other companies’ presentations or deemed more useful than the GAAP information provided elsewhere in this report.
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The following table provides a reconciliation between GAAP Net income attributable to common shareholders and Adjusted (non-GAAP) operating earnings for the three and nine months ended September 30, 2025 compared to the same period in 2024:
Three Months Ended September 30,
2025 2024
(In millions, except per share data) Earnings per
Diluted Share Earnings per
Diluted Share
Net income attributable to common shareholders $ 875 $ 0.86 $ 707 $ 0.70
Asset retirement obligation (net of taxes of $0 and $0, respectively)
(1) — — —
Cost management charge (net of taxes of $0) (a)
— — 1 —
Adjusted (non-GAAP) operating earnings $ 874 $ 0.86 $ 708 $ 0.71
Nine Months Ended September 30,
2025 2024
(In millions, except per share data) Earnings per
Diluted Share Earnings per
Diluted Share
Net income attributable to common shareholders $ 2,174 $ 2.15 $ 1,813 $ 1.81
Asset retirement obligation (net of taxes of $0 and $0, respectively)
(1) — — —
Change in FERC audit liability (net of taxes of $1 and $13, respectively)
2 — 42 0.04
Cost management charge (net of taxes of $0 and $3, respectively) (a)
(1) — 10 0.01
Income tax-related adjustments (entire amount represents tax expense) (b)
1 — — —
Regulatory matters (net of taxes of $7) (c)
22 0.02 — —
Change in environmental liabilities (net of taxes of $0)
— — (1) —
Adjusted (non-GAAP) operating earnings $ 2,198 $ 2.17 $ 1,865 $ 1.86
__________
Note:
Amounts may not sum due to rounding.
Unless otherwise noted, the income tax impact of each reconciling item between GAAP Net income attributable to common shareholders and Adjusted (non-GAAP) operating earnings is based on the marginal statutory federal and state income tax rates for each Registrant, taking into account whether the income or expense item is taxable or deductible, respectively, in whole or in part. The marginal statutory income tax rates for 2025 and 2024 ranged from 24.0% to 29.0%.
(a) Primarily represents severance and reorganization costs related to cost management.
(b) Reflects the adjustment to state deferred income taxes due to changes in forecasted apportionment.
(c) Represents the probable disallowance of certain capitalized costs.
Significant 2025 Transactions and Developments
Distribution Base Rate Case Proceedings
The Utility Registrants file base rate cases with their regulatory commissions seeking increases or decreases to their electric transmission and distribution, and gas distribution rates to recover their costs and earn a fair return on their investments. The outcomes of these regulatory proceedings impact the Utility Registrants’ current and future financial statements.
The following tables show the Utility Registrants’ completed and pending distribution base rate case proceedings in 2025. See Note 2 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.
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Completed Distribution Base Rate Case Proceedings
Registrant/Jurisdiction Filing Date Service Requested Revenue Requirement Increase Approved Revenue Requirement Increase Approved ROE Approval Date Rate Effective Date
ComEd - Illinois January 17, 2023 Electric $ 1,487 $ 1,045 8.905% December 19, 2024 January 1, 2024
April 26, 2024 (amended on September 11, 2024) Electric $ 624 $ 623 9.89% October 31, 2024 January 1, 2025
PECO - Pennsylvania March 28, 2024 Electric $ 464 $ 354 N/A December 12, 2024 January 1, 2025
Natural Gas $ 111 $ 78
BGE - Maryland February 17, 2023 Electric $ 313 $ 179 9.50% December 14, 2023 January 1, 2024
Natural Gas $ 289 $ 229 9.45%
Pepco - District of Columbia April 13, 2023 (amended February 27, 2024) Electric $ 186 $ 123 9.50% November 26, 2024 January 1, 2025
Pepco - Maryland May 16, 2023 (amended February 23, 2024) Electric $ 111 $ 45 9.50% June 10, 2024 April 1, 2024
DPL - Maryland May 19, 2022 Electric $ 38 $ 29 9.60% December 14, 2022 January 1, 2023
DPL - Delaware December 15, 2022 (amended September 29, 2023) Electric $ 39 $ 28 9.60% April 18, 2024 July 15, 2023
ACE - New Jersey February 15, 2023 (amended August 21, 2023) Electric $ 92 $ 45 9.60% November 17, 2023 December 1, 2023
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Pending Distribution Base Rate Case Proceedings
Registrant/Jurisdiction Filing Date Service Requested Revenue Requirement Increase Requested ROE Expected Approval Timing
Pepco - Maryland October 14, 2025 Electric $ 133 10.50% Third quarter of 2026
DPL - Delaware September 20, 2024 (amended September 5, 2025) Natural Gas $ 37 10.65% First quarter of 2026
ACE - New Jersey November 21, 2024 Electric $ 109 10.70% Fourth quarter of 2025
Transmission Formula Rates
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.
Registrant Initial Revenue Requirement Increase (Decrease) Annual Reconciliation
Increase (Decrease) Total Revenue Requirement Increase (Decrease) Allowed Return on Rate Base Allowed ROE
ComEd $ 78 $ 49 $ 127 8.13 % 11.50 %
PECO $ 9 $ 13 $ 22 7.54 % 10.35 %
BGE $ 21 $ 21 $ 35 7.53 % 10.50 %
Pepco $ 35 $ 16 $ 51 7.71 % 10.50 %
DPL $ 32 $ (9) $ 23 7.48 % 10.50 %
ACE $ (11) $ (46) $ (57) 7.16 % 10.50 %
ComEd's FERC Audit
The Utility Registrants are subject to periodic audits and investigations by FERC. FERC’s Division of Audits and Accounting initiated a nonpublic audit of ComEd in April 2021 evaluating ComEd’s compliance with (1) approved terms, rates and conditions of its federally regulated service; (2) accounting requirements of the Uniform System of Accounts; (3) reporting requirements of the FERC Form 1; and (4) the requirements for record retention. The audit period extended back to January 1, 2017.
On July 27, 2023, FERC published a final audit report which included, among other things, findings and recommendations related to ComEd's methodology regarding the allocation of certain overhead costs to capitalized construction costs under FERC regulations, including a suggestion that refunds may be due to customers for amounts collected in previous years. 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.
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.
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Other Key Business Drivers and Management Strategies
The following discussion of other key business drivers and management strategies includes current developments of previously disclosed matters and new issues arising during the period that may impact future financial statements. This section should be read in conjunction with ITEM 1. Business in the 2024 Form 10-K, ITEM 7. Management's Discussion and Analysis of Financial Condition and Results of Operations — Other Key Business Drivers and Management Strategies in the 2024 Form 10-K, and Note 11 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements in this report for additional information on various environmental matters.
Allocation of Income Taxes to Regulated Utilities (All Registrants)
In Q2 2024, the IRS issued a series of PLRs, to another taxpayer, providing guidance with respect to the application of the tax normalization rules to the allocation of consolidated tax benefits among the members of a consolidated group associated with NOLC for ratemaking purposes. The rulings provide that for ratemaking purposes the tax benefit of NOLC should be reflected on a separate company basis not taking into consideration the utilization of losses by other affiliates. A PLR issued to another taxpayer may not be relied on as precedent.
For the Utility Registrants, except for PECO, the methodology prescribed by the IRS in these PLRs could result in a material reduction of the regulatory liability established for EDITs arising from the TCJA corporate tax rate change that are being amortized and flowed through to customers as well as a reduction in the accumulated deferred income taxes included in rate base for ratemaking purposes of approximately $1.2 billion - $1.7 billion.
The Utility Registrants, except for PECO, filed PLR requests with the IRS confirming the treatment of the NOLC for ratemaking purposes. The Utility Registrants will record the impact, if any, upon receiving the PLR from the IRS.
Legislative and Regulatory Developments
Infrastructure Investment and Jobs Act
On November 15, 2021, the $1.2 trillion IIJA was signed into law. IIJA provides for approximately $550 billion in new federal spending. Categories of funding include funding for a variety of infrastructure needs, including but not limited to: (1) power and grid reliability and resilience, (2) resilience for cybersecurity to address critical infrastructure needs, and (3) electric vehicle charging infrastructure for alternative fuel corridors. The Registrants continue to evaluate programs under the legislation and consider possible opportunities to apply for funding, either directly or in potential collaborations with state and/or local agencies and key stakeholders. The Registrants cannot predict the ultimate timing and success of securing funding from programs under IIJA.
On January 20, 2025, the Unleashing American Energy Order was issued as a Presidential Executive Order, which required an immediate pause in the disbursement of funds appropriated through the IRA and IIJA pending DOE review. In October 2025, Exelon, ComEd, and BGE received termination notifications from the DOE for their Renewable-Aware Distribution Operations, Deployment of a Community-Oriented Interoperable Control Framework for Aggregating and Integrating Distributed Energy Resources and Other Grid-Edge Devices, and Baltimore Interconnection Readiness & Deployment of Storage (BIRDS) awards, respectively. 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.
Next Generation Energy Act (Exelon, BGE, PHI, Pepco, and DPL)
On May 20, 2025, the Governor of Maryland signed into law legislation that addresses several matters pertaining to electric and gas utilities, including affirming that the MDPSC may approve the use of multi-year rate plans that demonstrate customer benefits, among other things. It also prohibits utilities from filing after January 1, 2025, for the reconciliation of actuals costs and revenues to amounts approved within the multi-year plans. In the second quarter of 2025, BGE derecognized Regulatory assets of $10 million and Regulatory liabilities of $3 million for multi-year plan reconciliations that 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.
Summer Rate Mitigation (Exelon, BGE, PHI, Pepco, DPL, and ACE).
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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.
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.
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.
One Big Beautiful Bill Act (All Registrants)
On July 4, 2025, the OBBBA was signed into law. The bill permanently extends expiring tax benefits of the TCJA and provides additional tax relief for individuals and businesses while accelerating the phase-out and curtailment for renewable energy tax credits enacted by the IRA. The tax law changes enacted as part of OBBBA will not have a direct material impact on the Registrants’ financial statements.
Critical Accounting Policies and Estimates
Management of each of the Registrants makes a number of significant estimates, assumptions, and judgments in the preparation of its financial statements. As of September 30, 2025, the Registrants’ critical accounting policies and estimates had not changed significantly from December 31, 2024. See ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS — Critical Accounting Policies and Estimates in the 2024 Form 10-K for further information.
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Results of Operations by Registrant
Results of Operations — ComEd
Three Months Ended
September 30, Favorable (Unfavorable) Variance Nine Months Ended
September 30, (Unfavorable) Favorable Variance
2025 2024 2025 2024
Operating revenues $ 2,275 $ 2,229 $ 46 $ 6,176 $ 6,403 $ (227)
Operating expenses
Purchased power 806 835 29 2,044 2,504 460
Operating and maintenance 409 410 1 1,254 1,277 23
Depreciation and amortization 395 387 (8) 1,162 1,124 (38)
Taxes other than income taxes 107 99 (8) 303 287 (16)
Total operating expenses 1,717 1,731 14 4,763 5,192 429
Gain on sales of assets — — — — 5 (5)
Operating income 558 498 60 1,413 1,216 197
Other income and (deductions)
Interest expense, net (135) (128) (7) (395) (374) (21)
Other, net 33 26 7 86 66 20
Total other income and (deductions) (102) (102) — (309) (308) (1)
Income before income taxes 456 396 60 1,104 908 196
Income taxes 83 36 (47) 201 85 (116)
Net income $ 373 $ 360 $ 13 $ 903 $ 823 $ 80
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.
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.
The changes in Operating revenues consisted of the following:
Three Months Ended
September 30, 2025 Nine Months Ended
September 30, 2025
Increase (Decrease) Increase (Decrease)
Distribution $ 85 $ 200
Transmission 3 (15)
Energy efficiency 9 25
Other (30) (17)
67 193
Regulatory required programs (21) (420)
Total increase (decrease) $ 46 $ (227)
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.
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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.
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.
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.
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.
Regulatory Required Programs represents revenues collected under approved riders to recover costs incurred for regulatory programs such as recoveries under the credit loss expense tariff, environmental costs associated with MGP sites, ETAC, and costs related to electricity, ZEC, CMC, and REC procurement. ETAC is a retail customer surcharge collected and remitted to an Illinois state agency for programs to support clean energy jobs and training. The riders are designed to provide full and current cost recovery. The costs of these programs are included in Purchased power expense, Operating and maintenance expense, Depreciation and amortization expense, and Taxes other than income taxes. Customers have the choice to purchase electricity from competitive electric generation suppliers. Customer choice programs do not impact the volume of deliveries as ComEd remains the distribution service provider for all customers and charges a regulated rate for distribution service, which is recorded in Operating revenues. For customers that choose to purchase electric generation from competitive suppliers, ComEd either acts as the billing agent or the competitive supplier separately bills its own customers, and therefore does not record Operating revenues or Purchased power expense related to the electricity. For customers that choose to purchase electric generation from ComEd, ComEd is permitted to recover the electricity, ZEC, CMC, and REC procurement costs without mark-up and therefore records equal and offsetting amounts in Operating revenues and Purchased power expense related to the electricity, ZECs, CMCs, and RECs.
See Note 4 — Segment Information of the Combined Notes to Consolidated Financial Statements for the presentation of ComEd's revenue disaggregation.
The 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.
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The changes in Operating and maintenance expense consisted of the following:
Three Months Ended
September 30, 2025 Nine Months Ended
September 30, 2025
Increase (Decrease) (Decrease) Increase
Labor, other benefits, contracting, and materials $ 3 $ (14)
Storm-related costs (2) (5)
BSC costs (7) (10)
Pension and non-pension postretirement benefits expense 1 4
Other (a)
9 (33)
4 (58)
Regulatory required programs (b)
(5) 35
Total decrease $ (1) $ (23)
__________
(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.
(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.
The changes in Depreciation and amortization expense consisted of the following:
Three Months Ended
September 30, 2025 Nine Months Ended
September 30, 2025
Increase (Decrease) Increase (Decrease)
Depreciation and amortization (a)
$ 12 $ 46
Regulatory asset amortization (4) (8)
Total increase $ 8 $ 38
__________
(a) Reflects ongoing capital expenditures.
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.
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.
Effective income tax rat es 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.
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PECO
Results of Operations — PECO
Three Months Ended
September 30, Favorable (Unfavorable) Variance Nine Months Ended
September 30, Favorable (Unfavorable) Variance
2025 2024 2025 2024
Operating revenues $ 1,180 $ 1,030 $ 150 $ 3,513 $ 2,975 $ 538
Operating expenses
Purchased power and fuel 446 386 (60) 1,288 1,113 (175)
Operating and maintenance 241 313 72 872 876 4
Depreciation and amortization 115 108 (7) 336 318 (18)
Taxes other than income taxes 69 61 (8) 183 164 (19)
Total operating expenses 871 868 (3) 2,679 2,471 (208)
Gain on sales of assets — — — — 4 (4)
Operating income 309 162 147 834 508 326
Other income and (deductions)
Interest expense, net (65) (58) (7) (188) (170) (18)
Other, net 11 9 2 29 27 2
Total other income and (deductions) (54) (49) (5) (159) (143) (16)
Income before income taxes 255 113 142 675 365 310
Income taxes 5 (4) (9) 23 9 (14)
Net income $ 250 $ 117 $ 133 $ 652 $ 356 $ 296
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.
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.
The changes in Operating revenues consisted of the following:
Three Months Ended
September 30, 2025 Nine Months Ended
September 30, 2025
Increase (Decrease) Increase (Decrease)
Electric Gas Total Electric Gas Total
Weather $ 1 $ — $ 1 $ 18 $ 18 $ 36
Volume (11) — (11) (17) 2 (15)
Pricing 99 8 107 263 65 328
Transmission — — — (3) — (3)
Other — — — 10 5 15
89 8 97 271 90 361
Regulatory required programs 48 5 53 124 53 177
Total increase $ 137 $ 13 $ 150 $ 395 $ 143 $ 538
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
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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.
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:
Three Months Ended September 30, % Change
PECO Service Territory 2025 2024 Normal 2025 vs. 2024 2025 vs. Normal
Heating Degree-Days — 1 20 (100.0) % (100.0) %
Cooling Degree-Days 1,095 1,062 1,035 3.1 % 5.8 %
Nine Months Ended September 30, % Change
2025 2024 Normal 2025 vs. 2024 2025 vs. Normal
Heating Degree-Days 2,684 2,441 2,827 10.0 % (5.1) %
Cooling Degree-Days 1,521 1,599 1,422 (4.9) % 7.0 %
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.
Electric Retail Deliveries to Customers (in GWhs) Three Months Ended
September 30, % Change Weather -
Normal
% Change (b)
Nine Months Ended September 30, % Change Weather -
Normal
% Change (b)
2025 2024 2025 2024
Residential 4,063 4,146 (2.0) % (2.1) % 10,952 10,897 0.5 % (1.5) %
Small commercial & industrial 2,057 2,129 (3.4) % (2.0) % 5,835 5,876 (0.7) % (2.0) %
Large commercial & industrial 3,731 3,768 (1.0) % (2.3) % 10,470 10,531 (0.6) % (1.4) %
Public authorities & electric railroads 159 156 1.9 % 1.7 % 511 470 8.7 % 8.6 %
Total electric retail deliveries (a)
10,010 10,199 (1.9) % (2.1) % 27,768 27,774 — % (1.4) %
At September 30,
Number of Electric Customers 2025 2024
Residential 1,539,345 1,529,205
Small commercial & industrial 154,955 155,126
Large commercial & industrial 3,159 3,156
Public authorities & electric railroads 10,343 10,716
Total 1,707,802 1,698,203
__________
(a) Reflects delivery volumes from customers purchasing electricity directly from PECO and customers purchasing electricity from a competitive electric generation supplier as all customers are assessed distribution charges.
(b) Reflects the change in delivery volumes assuming normalized weather based on the historical 30-year average.
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Natural Gas Deliveries to Customers (in mmcf) Three Months Ended
September 30, % Change Weather -
Normal
% Change (b)
Nine Months Ended
September 30, % Change Weather -
Normal
% Change (b)
2025 2024 2025 2024
Residential 2,064 2,359 (12.5) % (12.1) % 28,469 25,779 10.4 % (0.5) %
Small commercial & industrial 2,243 1,933 16.0 % 17.5 % 16,046 14,742 8.8 % 1.8 %
Large commercial & industrial — 1 (100.0) % (9.8) % 14 17 (17.6) % (3.8) %
Transportation 5,081 5,232 (2.9) % (2.6) % 17,759 17,248 3.0 % 0.4 %
Total natural gas retail deliveries (a)
9,388 9,525 (1.4) % (1.2) % 62,288 57,786 7.8 % 0.3 %
At September 30,
Number of Natural Gas Customers 2025 2024
Residential 510,166 506,476
Small commercial & industrial 44,603 44,682
Large commercial & industrial 7 7
Transportation 619 643
Total 555,395 551,808
__________
(a) Reflects delivery volumes from customers purchasing natural gas directly from PECO and customers purchasing natural gas from a competitive natural gas supplier as all customers are assessed distribution charges.
(b) Reflects the change in delivery volumes assuming normalized weather based on the historical 30-year average.
Pricing for the three and 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.
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.
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.
Regulatory Required Programs represent revenues collected under approved riders to recover costs incurred for regulatory programs such as energy efficiency, PGC, TSC, and the GSA. The riders are designed to provide full and current cost recovery, and in some cases, a return. The costs of these programs are included in Purchased power and fuel expense, Operating and maintenance expense, Depreciation and amortization expense, and Income taxes. Customers have the choice to purchase electricity and natural gas from competitive electric generation and natural gas suppliers. Customer choice programs do not impact the volume of deliveries as PECO remains the distribution service provider for all customers and charges a regulated rate for distribution service, which is recorded in Operating revenues. For customers that choose to purchase electric generation or natural gas from competitive suppliers, PECO either acts as the billing agent or the competitive supplier separately bills its own customers and therefore PECO does not record Operating revenues or Purchased power and fuel expense related to the electricity and/or natural gas. For customers that choose to purchase electric generation or natural gas from PECO, PECO is permitted to recover the electricity, natural gas, and REC procurement costs without mark-up and therefore records equal and offsetting amounts in Operating revenues and Purchased power and fuel expense related to the electricity, natural gas, and RECs.
See Note 4 — Segment Information of the Combined Notes to Consolidated Financial Statements for the presentation of PECO's revenue disaggregation.
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The increase of $60 million and increase of $175 million for the three and nine months ended September 30, 2025, respectively, compared to the same period in 2024, in Purchased power and fuel expense is fully offset in Operating revenues as part of regulatory required programs.
The changes in Operating and maintenance expense consisted of the following:
Three Months Ended
September 30, 2025 Nine Months Ended
September 30, 2025
Increase (Decrease) Increase (Decrease)
Labor, other benefits, contracting and materials $ 18 $ 32
Pension and non-pension postretirement benefit expense 1 3
BSC costs (3) (1)
Credit loss expense (7) (3)
Storm-related costs (a)
(63) (29)
Other (7) (7)
(61) (5)
Regulatory required programs (11) 1
Total decrease $ (72) $ (4)
__________
(a) Decrease primarily due to deferral of extraordinary February and June storm costs of $53 million in the third quarter of 2025.
The changes in Depreciation and amortization expense consisted of the following:
Three Months Ended September 30, 2025 Nine Months Ended
September 30, 2025
Increase (Decrease) Increase (Decrease)
Depreciation and amortization (a)
$ 10 $ 26
Regulatory asset amortization (3) (8)
Total increase $ 7 $ 18
__________
(a) Depreciation and amortization expense increased primarily due to ongoing capital expenditures.
Taxes other than income taxes increased by $8 million and increased by $19 million for the three and nine months ended September 30, 2025, respectively, compared to the same period in 2024, primarily due to higher Pennsylvania gross receipts tax.
Interest expense, net increased $7 million and increased $18 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 interest rates and the issuance of debt in the third quarter of 2025.
Effective income tax rates were 2.0% and (3.5)% for the three months ended September 30, 2025 and 2024, respectively, 3.4% and 2.5% 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.
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BGE
Results of Operations — BGE
Three Months Ended
September 30, Favorable (Unfavorable) Variance Nine Months Ended
September 30, Favorable (Unfavorable) Variance
2025 2024 2025 2024
Operating revenues $ 1,209 $ 1,044 $ 165 $ 3,791 $ 3,268 $ 523
Operating expenses
Purchased power and fuel 568 420 (148) 1,584 1,228 (356)
Operating and maintenance 239 281 42 807 795 (12)
Depreciation and amortization 155 162 7 473 474 1
Taxes other than income taxes 93 86 (7) 273 254 (19)
Total operating expenses 1,055 949 (106) 3,137 2,751 (386)
Operating income 154 95 59 654 517 137
Other income and (deductions)
Interest expense, net (64) (57) (7) (183) (159) (24)
Other, net 15 11 4 35 27 8
Total other income and (deductions) (49) (46) (3) (148) (132) (16)
Income before income taxes 105 49 56 506 385 121
Income taxes 23 4 (19) 108 32 (76)
Net income $ 82 $ 45 $ 37 $ 398 $ 353 $ 45
Three Months Ended September 30, 2025 Compared to Three Months Ended September 30, 2024 . Net income increased $37 million primarily due to electric distribution rates and decreases in storm costs, credit loss expense, and various operating expenses.
Nine Months Ended September 30, 2025 Compared to Nine Months Ended September 30, 2024. Net Income increased $45 million primarily due to distribution and transmission rates and a decrease in storm costs, partially offset by an increase in interest expense and the derecognition of regulatory assets and liabilities for multi-year plan reconciliations that will no longer be filed as a result of the Next Generation Energy Act. See Note 2 — Regulatory Matters for additional information regarding the Next Generation Energy Act.
The changes in Operating revenues consisted of the following:
Three Months Ended
September 30, 2025 Nine Months Ended
September 30, 2025
Increase (Decrease) Increase
Electric Gas Total Electric Gas Total
Distribution $ 17 $ (9) $ 8 $ 66 $ 46 $ 112
Transmission (1) — (1) 10 — 10
Other 3 — 3 11 — 11
19 (9) 10 87 46 133
Regulatory required programs 146 9 155 276 114 390
Total increase $ 165 $ — $ 165 $ 363 $ 160 $ 523
Revenue Decoupling. The demand for electricity and natural gas is affected by weather and customer usage. However, Operating revenues are not impacted by abnormal weather or usage per customer as a result of a monthly rate adjustment that provides for fixed distribution revenue per customer by customer class. While Operating revenues are not impacted by abnormal weather or usage per customer, they are impacted by changes in the number of customers.
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BGE
At September 30,
Number of Electric Customers 2025 2024
Residential 1,220,937 1,215,873
Small commercial & industrial 115,246 115,032
Large commercial & industrial 13,432 13,206
Public authorities & electric railroads 254 260
Total 1,349,869 1,344,371
At September 30,
Number of Natural Gas Customers 2025 2024
Residential 660,241 658,485
Small commercial & industrial 37,731 37,752
Large commercial & industrial 6,404 6,353
Total 704,376 702,590
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.
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 three months ended September 30, 2025 and increased for the nine months ended September 30, 2025, compared to the same period in 2024, primarily due to increases in underlying costs and capital investments.
Other Revenue includes revenue related to late payment charges, mutual assistance, off-system sales, and service application fees. Other Revenue increased for the three and nine months ended September 30, 2025 as compared to the same period in 2024, primarily driven by increases in service application fees.
Regulatory Required Programs represent revenues collected under approved riders to recover costs incurred for regulatory programs such as conservation, demand response, and the POLR mechanism. The riders are designed to provide full and current cost recovery, as well as a return in certain instances. The costs of these programs are included in Purchased power and fuel expense, Operating and maintenance expense, Depreciation and amortization expense, and Taxes other than income taxes. Customers have the choice to purchase electricity and natural gas from competitive electric generation and natural gas suppliers. Customer choice programs do not impact the volume of deliveries as BGE remains the distribution service provider for all customers and charges a regulated rate for distribution service, which is recorded in Operating revenues. For customers that choose to purchase electric generation or natural gas from competitive suppliers, BGE acts as the billing agent and therefore does not record Operating revenues or Purchased power and fuel expense related to the electricity and/or natural gas. For customers that choose to purchase electric generation or natural gas from BGE, BGE is permitted to recover the electricity and natural gas procurement costs from customers and therefore records the amounts related to the electricity and/or natural gas in Operating revenues and Purchased power and fuel expense. BGE recovers electricity and natural gas procurement costs from customers with a slight mark-up.
See Note 4 — Segment Information of the Combined Notes to Consolidated Financial Statements for the presentation of BGE's revenue disaggregation.
The increase of $148 million and $356 million for the three and nine months ended September 30, 2025, respectively, compared to the same period in 2024, in Purchased power and fuel expense is fully offset in Operating revenues as part of regulatory required programs.
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The changes in Operating and maintenance expense consisted of the following:
Three Months Ended
September 30, 2025 Nine Months Ended
September 30, 2025
(Decrease) Increase Increase (Decrease)
Labor, other benefits, contracting, and materials (8) 8
Credit loss expense (7) (2)
BSC costs — 4
Pension and non-pension postretirement benefits expense — 1
Storm-related costs (9) (16)
Other (a)
(19) (6)
(43) (11)
Regulatory required programs (b)
1 23
Total (decrease) increase $ (42) $ 12
__________
(a) For the three and nine months ended, reflects the absence of capital write-offs included in 2024. For the nine months ended, reflects the derecognition of regulatory assets for multi-year plan reconciliations that will no longer be filed as a result of the Next Generation Energy Act. See Note 2 — Regulatory Matters for additional information regarding the Next Generation Energy Act.
(b) Reflects the cost recovery associated with EmPOWER Maryland. Please refer to 2024 10-K Note 3 — Regulatory Matters for additional information.
The changes in Depreciation and amortization expense consisted of the following:
Three Months Ended
September 30, 2025 Nine Months Ended
September 30, 2025
Increase (Decrease) Increase (Decrease)
Depreciation and amortization $ 4 $ 7
Regulatory required programs (a)
5 16
Regulatory asset amortization (16) (24)
Total decrease $ (7) $ (1)
__________
(a) Reflects the cost recovery associated with EmPOWER Maryland. Please refer to 2024 10-K Note 3 — Regulatory Matters for additional information.
Interest expense, net increased $7 million and $24 million for the three and nine months ended September 30, 2025, respectively, compared to the same period in 2024, primarily due to the issuance of debt in the second quarter of 2025.
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.
Effective income tax rates were 21.9% and 8.2% for the three months ended September 30, 2025 and 2024, respectively, and 21.3% and 8.3% for the nine months ended September 30, 2025 and 2024. See Note 6 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the effective income tax rates.
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PHI
Results of Operations — PHI
PHI’s Results of Operations include the results of its three reportable segments, Pepco, DPL, and ACE. PHI also has a business services subsidiary, PHISCO, which provides a variety of support services, and the costs are directly charged or allocated to the applicable subsidiaries. Additionally, the results of PHI’s corporate operations include interest costs from various financing activities. All material intercompany accounts and transactions have been eliminated in consolidation. The following table sets forth PHI's GAAP consolidated Net income, by Registrant, for the three and nine months ended September 30, 2025 compared to the same periods in 2024. See the Results of Operations for Pepco, DPL, and ACE for additional information.
Three Months Ended
September 30, Favorable (Unfavorable) Variance Nine Months Ended September 30, Favorable (Unfavorable) Variance
2025 2024 2025 2024
PHI $ 291 $ 278 $ 13 $ 628 $ 603 $ 25
Pepco 156 140 16 337 323 14
DPL
55 55 — 163 156 7
ACE 82 83 (1) 138 133 5
Other (a)
(2) — (2) (10) (9) (1)
__________
(a) Primarily includes eliminating and consolidating adjustments, PHI's corporate operations, shared service entities, and other financing and investing activities.
Three Months Ended September 30, 2025 Compared to Three Months Ended September 30, 2024. Net Income increased by $13 million primarily due to distribution rates and transmission rates at Pepco, partially offset by increases in interest and depreciation expense at Pepco.
Nine Months Ended September 30, 2025 Compared to Nine Months Ended September 30, 2024. Net Income increased by $25 million primarily due to distribution rates at Pepco, DPL Delaware electric DSIC rates and natural gas rates, transmission rates at Pepco and DPL, and favorable weather conditions at DPL, partially offset by an increase in interest and depreciation expense and the lower impacts of the Maryland multi-year plans reconciliations at Pepco.
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Pepco
Results of Operations — Pepco
Three Months Ended September 30, Favorable (Unfavorable) Variance Nine Months Ended September 30, Favorable (Unfavorable) Variance
2025 2024 2025 2024
Operating revenues $ 992 $ 861 $ 131 $ 2,626 $ 2,320 $ 306
Operating expenses
Purchased power 367 294 (73) 942 808 (134)
Operating and maintenance 154 140 (14) 466 392 (74)
Depreciation and amortization 110 102 (8) 321 307 (14)
Taxes other than income taxes 122 114 (8) 344 317 (27)
Total operating expenses 753 650 (103) 2,073 1,824 (249)
Loss on sale of assets — — — 1 — 1
Operating income 239 211 28 554 496 58
Other income and (deductions)
Interest expense, net (53) (50) (3) (159) (142) (17)
Other, net 11 11 — 31 43 (12)
Total other income and (deductions) (42) (39) (3) (128) (99) (29)
Income before income taxes 197 172 25 426 397 29
Income taxes 41 32 (9) 89 74 (15)
Net income $ 156 $ 140 $ 16 $ 337 $ 323 $ 14
Three Months Ended September 30, 2025 Compared to Three Months Ended September 30, 2024. Net Income increased by $16 million primarily due to distribution and transmission rates, partially offset by increases in depreciation and interest expense.
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.
The changes in Operating revenues consisted of the following:
Three Months Ended
September 30, 2025 Nine Months Ended
September 30, 2025
Increase (Decrease) Increase (Decrease)
Distribution $ 42 $ 124
Transmission 1 12
Other (2) (7)
41 129
Regulatory required programs 90 177
Total increase $ 131 $ 306
Revenue Decoupling. The demand for electricity is affected by weather and customer usage. However, Operating revenues from electric distribution in both Maryland and the District of Columbia are not intended to be impacted by abnormal weather or usage per customer as a result of a BSA that provides for a fixed distribution charge per customer class in the District of Columbia and per customer by customer class in Maryland. Therefore, changes in the number of customers only impacts Operating revenues in Maryland.
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At September 30,
Number of Electric Customers in Maryland 2025 2024
Residential 559,986 555,029
Small commercial & industrial 30,485 30,606
Large commercial & industrial 19,086 18,987
Public authorities & electric railroads 177 179
Total 609,734 604,801
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.
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.
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.
S ee Note 4 — Segment Information of the Combined Notes to Consolidated Financial Statements for the presentation of Pepco's revenue disaggregation.
The increase of $73 million and $134 million for the three and nine months ended September 30, 2025, respectively, compared to the same period in 2024, in Purchased power expense is fully offset in Operating revenues as part of regulatory required programs.
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The changes in Operating and maintenance expense consisted of the following:
Three Months Ended
September 30, 2025 Nine Months Ended
September 30, 2025
Increase (Decrease) Increase (Decrease)
Maryland multi-year plan reconciliations (a)
$ 3 $ 27
Labor, other benefits, contracting, and materials 7 3
Storm-related costs (1) 2
Pension and non-pension postretirement benefits expense — 1
Credit loss expense (2) 1
BSC and PHISCO costs 1 (2)
Other (b)
(4) 12
4 44
Regulatory required programs (c)
10 30
Total increase $ 14 $ 74
________ _
(a) See Note 2 - Regulatory Matters for additional information on multi-year plan reconciliations.
(b) Primarily relates to a revenue deferral mechanism approved by the MDPSC in 2024.
(c) Reflects the cost recovery associated with EmPOWER Maryland. Please refer to 2024 10-K Note 3 — Regulatory Matters for additional information.
The changes in Depreciation and amortization expense consisted of the following:
Three Months Ended
September 30, 2025 Nine Months Ended
September 30, 2025
Increase Increase (Decrease)
Depreciation and amortization (a)
$ 6 $ 18
Regulatory asset amortization 2 4
Regulatory required programs (b)
— (8)
Total increase $ 8 $ 14
__________
(a) Depreciation and amortization increased primarily due to ongoing capital expenditures.
(b) Reflects the cost recovery associated with EmPOWER Maryland. Please refer to 2024 10-K Note 3 — Regulatory Matters additional information.
Taxes other than income taxes increased $8 million and $27 million for the three and nine months ended September 30, 2025, respectively, compared to the same periods in 2024, primarily due to increases in utility taxes, which are offset in revenues, and property taxes.
Interest expense, net increased $3 million and $17 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 interest rates and the issuance of debt in 2024 and 2025.
Other , net decreased $12 million for the nine months ended September 30, 2025, respectively, and stayed relatively consistent for the three months ended September 30, 2025, respectively, compared to the same periods in 2024, primarily due to lower AFUDC equity.
Effective income tax rates were 20.8% and 18.6% for the three months ended September 30, 2025 and 2024, respectively, and 20.9% and 18.6% 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.
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DPL
Results of Operations — DPL
Three Months Ended September 30, Favorable (Unfavorable) Variance Nine Months Ended September 30, Favorable (Unfavorable) Variance
2025 2024 2025 2024
Operating revenues $ 491 $ 462 $ 29 $ 1,460 $ 1,343 $ 117
Operating expenses
Purchased power and fuel 219 203 (16) 637 573 (64)
Operating and maintenance 94 92 (2) 296 284 (12)
Depreciation and amortization 63 62 (1) 189 183 (6)
Taxes other than income taxes 21 20 (1) 63 59 (4)
Total operating expenses 397 377 (20) 1,185 1,099 (86)
Operating income 94 85 9 275 244 31
Other income and (deductions)
Interest expense, net (26) (22) (4) (75) (69) (6)
Other, net 4 6 (2) 12 20 (8)
Total other income and (deductions) (22) (16) (6) (63) (49) (14)
Income before income taxes 72 69 3 212 195 17
Income taxes 17 14 (3) 49 39 (10)
Net income $ 55 $ 55 $ — $ 163 $ 156 $ 7
Three Months Ended September 30, 2025 Compared to Three Months Ended September 30, 2024. Net income remained relatively consistent.
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.
The changes in Operating revenues consisted of the following:
Three Months Ended
September 30, 2025 Nine Months Ended
September 30, 2025
Increase (Decrease) Increase (Decrease)
Electric Gas Total Electric Gas Total
Weather $ 1 $ — $ 1 $ 4 $ 2 $ 6
Volume (5) 1 (4) (3) 3 —
Distribution 6 3 9 14 7 21
Transmission 2 — 2 10 — 10
Other 1 — 1 2 — 2
5 4 9 27 12 39
Regulatory required programs 19 1 20 65 13 78
Total increase $ 24 $ 5 $ 29 $ 92 $ 25 $ 117
Revenue Decoupling. The demand for electricity is affected by weather and customer usage. However, Operating revenues from electric distribution in Maryland are not impacted by abnormal weather or usage per customer as a result of a BSA that provides for a fixed distribution charge per customer by customer class. While Operating revenues from electric distribution customers in Maryland are not intended to be impacted by abnormal weather or usage per customer, they are impacted by changes in the number of customers.
Weather. The demand for electricity and natural gas in Delaware is affected by weather conditions. With respect to the electric business, very warm weather in summer months and, with respect to the electric and natural gas businesses, very cold weather in winter months are referred to as "favorable weather conditions” because these weather conditions result in increased deliveries of electricity and natural gas. Conversely, mild weather reduces
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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.
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:
Three Months Ended September 30, % Change
Delaware Electric Service Territory 2025 2024 Normal 2025 vs. 2024 2025 vs. Normal
Heating Degree-Days 3 13 28 (76.9) % (89.3) %
Cooling Degree-Days 897 856 928 4.8 % (3.3) %
Nine Months Ended September 30, % Change
Delaware Electric Service Territory 2025 2024 Normal 2025 vs. 2024 2025 vs. Normal
Heating Degree-Days 2,774 2,620 2,896 5.9 % (4.2) %
Cooling Degree-Days 1,296 1,256 1,272 3.2 % 1.9 %
Three Months Ended September 30, % Change
Delaware Natural Gas Service Territory 2025 2024 Normal 2025 vs. 2024 2025 vs. Normal
Heating Degree-Days 3 13 34 (76.9) % (91.2) %
Nine Months Ended September 30, % Change
Delaware Natural Gas Service Territory 2025 2024 Normal 2025 vs. 2024 2025 vs. Normal
Heating Degree-Days 2,774 2,620 2,970 5.9 % (6.6) %
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.
Electric Retail Deliveries to Delaware Customers (in GWhs) Three Months Ended
September 30, % Change Weather - Normal
% Change (b)
Nine Months Ended
September 30, % Change Weather - Normal
% Change (b)
2025 2024 2025 2024
Residential 928 974 (4.7) % (6.1) % 2,533 2,529 0.2 % (2.1) %
Small commercial & industrial 389 402 (3.2) % (3.5) % 1,112 1,094 1.6 % 1.3 %
Large commercial & industrial 873 811 7.6 % 7.3 % 2,329 2,285 1.9 % 1.6 %
Public authorities & electric railroads 8 8 — % (0.1) % 23 22 4.5 % 4.4 %
Total electric retail deliveries (a)
2,198 2,195 0.1 % (0.7) % 5,997 5,930 1.1 % — %
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At September 30,
Number of Total Electric Customers (Maryland and Delaware) 2025 2024
Residential 494,232 489,634
Small commercial & industrial 65,322 64,626
Large commercial & industrial 1,257 1,267
Public authorities & electric railroads 632 598
Total 561,443 556,125
__________
(a) Reflects delivery volumes from customers purchasing electricity directly from DPL and customers purchasing electricity from a competitive electric generation supplier as all customers are assessed distribution charges.
(b) Reflects the change in delivery volumes assuming normalized weather based on the historical 20-year average.
Natural Gas Retail Deliveries to Delaware Customers (in mmcf) Three Months Ended
September 30, % Change Weather - Normal
% Change (b)
Nine Months Ended
September 30, % Change Weather - Normal
% Change (b)
2025 2024 2025 2024
Residential 409 397 3.0 % 5.7 % 5,802 5,162 12.4 % 6.9 %
Small commercial & industrial 375 343 9.3 % 10.9 % 2,881 2,590 11.2 % 5.7 %
Large commercial & industrial 404 408 (1.0) % (1.1) % 1,237 1,239 (0.2) % (0.1) %
Transportation 1,239 1,190 4.1 % 4.3 % 4,626 4,491 3.0 % 1.4 %
Total natural gas deliveries (a)
2,427 2,338 3.8 % 4.7 % 14,546 13,482 7.9 % 4.3 %
At September 30,
Number of Delaware Natural Gas Customers 2025 2024
Residential 131,494 130,885
Small commercial & industrial 10,134 10,110
Large commercial & industrial 14 14
Transportation 160 161
Total 141,802 141,170
__________
(a) Reflects delivery volumes from customers purchasing natural gas directly from DPL and customers purchasing natural gas from a competitive natural gas supplier as all customers are assessed distribution charges.
(b) Reflects the change in delivery volumes assuming normalized weather based on the historical 30-year average.
Distribution Revenue increased for the 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.
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.
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, 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
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deliveries as DPL remains the distribution service provider for all customers and charges a regulated rate for distribution service, which is recorded in Operating revenues. For customers that choose to purchase electric generation or natural gas from competitive suppliers, DPL either acts as the billing agent or the competitive supplier separately bills its own customers, and therefore does not record Operating revenues or Purchased power and fuel expense related to the electricity and/or natural gas. For customers that choose to purchase electric generation or natural gas from DPL, DPL is permitted to recover the electricity, natural gas, and REC procurement costs from customers and therefore records the amounts related to the electricity, natural gas, and RECs in Operating revenues and Purchased power and fuel expense. DPL recovers electricity and REC procurement costs from customers with a slight mark-up, and natural gas costs without mark-up.
See Note 4 — Segment Information of the Combined Notes to Consolidated Financial Statements for the presentation of DPL's revenue disaggregation.
The increase of $16 million and $64 million for the three and nine months ended September 30, 2025, respectively, compared to the same period in 2024 in Purchased power and fuel expense is fully offset in Operating revenues as part of regulatory required programs.
The changes in Operating and maintenance expense consisted of the following:
Three Months Ended
September 30, 2025 Nine Months Ended
September 30, 2025
(Decrease) Increase Increase (Decrease)
Credit loss expense $ (2) $ 3
Storm-related costs (3) (5)
Labor, other benefits, contracting, and materials 3 (4)
Other
1 2
(1) (4)
Regulatory required programs (a)
3 16
Total increase $ 2 $ 12
__________
(a) Reflects the cost recovery associated with EmPOWER Maryland. Please refer to 2024 10-K Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.
The changes in Depreciation and amortization expense consisted of the following:
Three Months Ended
September 30, 2025 Nine Months Ended
September 30, 2025
Increase Increase (Decrease)
Depreciation and amortization (a)
$ 1 $ 7
Regulatory asset amortization — —
Regulatory required programs (b)
— (1)
Total increase $ 1 $ 6
__________
(a) Depreciation and amortization increased primarily due to ongoing capital expenditures.
(b) Reflects the cost recovery associated with EmPOWER Maryland. Please refer to 2024 10-K Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information
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.
Interest Expense, net increased by $4 million and $6 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 interest rates and the issuance of debt in 2024 and 2025 .
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DPL
Other, net decreased by $2 million and $8 million for the three and nine months ended September 30, 2025, respectively, compared to the same period in 2024 primarily due to a decrease in interest income and lower AFUDC equity.
Effective income tax rates were 23.6% and 20.3% for the three months ended September 30, 2025 and 2024, respectively, and 23.1% and 20.0% 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.
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ACE
Results of Operations — ACE
Three Months Ended September 30, Favorable (Unfavorable) Variance Nine Months Ended September 30, Favorable (Unfavorable) Variance
2025 2024 2025 2024
Operating revenues $ 570 $ 540 $ 30 $ 1,328 $ 1,280 $ 48
Operating expenses
Purchased power 286 245 (41) 616 557 (59)
Operating and maintenance 92 96 4 277 274 (3)
Depreciation and amortization 61 67 6 188 214 26
Taxes other than income taxes 2 2 — 7 7 —
Total operating expenses 441 410 (31) 1,088 1,052 (36)
Operating income 129 130 (1) 240 228 12
Other income and (deductions)
Interest expense, net (20) (21) 1 (62) (59) (3)
Other, net 2 4 (2) 8 12 (4)
Total other income and (deductions) (18) (17) (1) (54) (47) (7)
Income before income taxes 111 113 (2) 186 181 5
Income taxes 29 30 1 48 48 —
Net income $ 82 $ 83 $ (1) $ 138 $ 133 $ 5
Three Months Ended September 30, 2025 Compared to Three Months Ended September 30, 2024 . Net income remained relatively consistent.
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.
The changes in Operating revenues consisted of the following:
Three Months Ended
September 30, 2025 Nine Months Ended
September 30, 2025
(Decrease) Increase Increase (Decrease)
Distribution $ — $ 4
Transmission (2) (2)
Other — 2
(2) 4
Regulatory required programs 32 44
Total increase $ 30 $ 48
Revenue Decoupling. The demand for electricity is affected by weather and customer usage. However, Operating revenues from electric distribution in New Jersey are not intended to be impacted by abnormal weather or usage per customer as a result of the CIP which compares current distribution revenues by customer class to approved target revenues established in ACE’s most recent distribution base rate case. The CIP is calculated annually, and recovery is subject to certain conditions, including an earnings test and ceilings on customer rate increases. While Operating revenues are not impacted by abnormal weather or usage per customer, they are impacted by changes in the number of customers.
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ACE
At September 30,
Number of Electric Customers 2025 2024
Residential 509,739 507,060
Small commercial & industrial 62,923 62,761
Large commercial & industrial 2,730 2,848
Public authorities & electric railroads 745 707
Total 576,137 573,376
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.
Transmission Revenues Under a FERC-approved formula, transmission revenue varies from year to year based upon fluctuations in the underlying costs and capital investments being recovered. Transmission revenue remained relatively consistent for the three and nine months ended September 30, 2025 compared to the same periods in 2024.
Other Revenue includes rental revenue, revenue related to late payment charges, mutual assistance revenues, and recoveries of other taxes.
Regulatory Required Programs represent revenues collected under approved riders to recover costs incurred for regulatory programs such as energy efficiency programs, Societal Benefits Charge, Transition Bonds, and BGS procurement and administrative costs. The riders are designed to provide full and current cost recovery as well as a return in certain instances. The costs of these programs are included in Purchased power expense, Operating and maintenance expense, Depreciation and amortization expense, and Taxes other than income taxes. Customers have the choice to purchase electricity from competitive electric generation suppliers. Customer choice programs do not impact the volume of deliveries, as ACE remains the distribution service provider for all customers and charges a regulated rate for distribution service, which is recorded in Operating revenues. For customers that choose to purchase electric generation from competitive suppliers, ACE acts as the billing agent and therefore, ACE does not record Operating revenues or Purchased power expense related to the electricity. For customers that choose to purchase electric generation from ACE, ACE is permitted to recover the electricity, ZEC, and REC procurement costs without mark-up and therefore records equal and offsetting amounts in Operating revenues and Purchased power expense related to the electricity, ZECs, and RECs.
See Note 4 — Segment Information of the Combined Notes to Consolidated Financial Statements for the presentation of ACE's revenue disaggregation.
The increase of $41 million and $59 million for the three and nine months ended September 30, 2025, respectively, compared to the same periods in 2024 in Purchased power expense is fully offset in Operating revenues as part of regulatory required programs.
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ACE
The changes in Operating and maintenance expense consisted of the following:
Three Months Ended
September 30, 2025 Nine Months Ended
September 30, 2025
Increase (Decrease) Increase (Decrease)
Labor, other benefits, contracting, and materials $ 6 $ 3
Storm-related costs (1) —
Credit Loss Expense (1) —
BSC and PHISCO costs (2) (5)
Other (2) (4)
— (6)
Regulatory required programs (4) 9
Total (decrease) increase $ (4) $ 3
The changes in Depreciation and amortization expense consisted of the following:
Three Months Ended
September 30, 2025 Nine Months Ended
September 30, 2025
Increase (Decrease) Increase (Decrease)
Depreciation and amortization (a)
$ 3 $ 9
Regulatory asset amortization (3) (10)
Regulatory required programs (6) (25)
Total decrease $ (6) $ (26)
__________
(a) Depreciation and amortization increased primarily due to ongoing capital expenditures.
Effective income tax rates were 26.1% and 26.5% for the three months ended September 30, 2025 and 2024, respectively and 25.8% and 26.5% 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.
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Liquidity and Capital Resources (All Registrants)
All results included throughout the liquidity and capital resources section are presented on a GAAP basis.
The Registrants’ operating and capital expenditures requirements are provided by internally generated cash flows from operations, as well as funds from external sources in the capital markets and through bank borrowings. The Registrants’ businesses are capital intensive and require considerable capital resources. Each of the Registrants annually evaluates its financing plan, dividend practices, and credit line sizing, focusing on maintaining its investment grade ratings while meeting its cash needs to fund capital requirements, including construction expenditures, retire debt, pay dividends, and fund pension and OPEB obligations. The Registrants spend a significant amount of cash on capital improvements and construction projects that have a long-term return on investment. Additionally, the Utility Registrants operate in rate-regulated environments in which the amount of new investment recovery may be delayed or limited and where such recovery takes place over an extended period of time. Each Registrant’s access to external financing on reasonable terms depends on its credit ratings and current overall capital market business conditions, including that of the utility industry in general. If these conditions deteriorate to the extent that the Registrants no longer have access to the capital markets at reasonable terms, the Registrants have access to credit facilities with aggregate bank commitments of $4.0 billion. The Registrants utilize their credit facilities to support their commercial paper programs, provide for other short-term borrowings, and to issue letters of credit. See the “Credit Matters and Cash Requirements” section below for additional information. The Registrants expect cash flows to be sufficient to meet operating expenses, financing costs, and capital expenditure requirements. See Note 9 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information on the Registrants’ debt and credit agreements.
Cash Flows from Operating Activities
The Utility Registrants' cash flows from operating activities primarily result from the transmission and distribution of electricity and, in the case of PECO, BGE, and DPL, gas distribution services. The Utility Registrants' distribution services are provided to an established and diverse base of retail customers. The Utility Registrants' future cash flows may be affected by the economy, weather conditions, future legislative initiatives, future regulatory proceedings with respect to their rates or operations, and their ability to achieve operating cost reductions. Additionally, ComEd is required to purchase CMCs from participating nuclear-powered generating facilities for a five-year period that began in June 2022, and all of its costs of doing so will be recovered through a rider. The price to be paid for each CMC is established through a competitive bidding process. ComEd will provide net payments to, or collect net payments from, customers for the difference between customer credits issued and the credit to be received from the participating nuclear-powered generating facilities. ComEd’s cash flows are affected by the establishment of CMC prices and the timing of recovering costs through the CMC regulatory asset.
See Note 3 — Regulatory Matters of the 2024 Form 10-K and Notes 2 — Regulatory Matters and 11 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for additional information on regulatory and legal proceedings and proposed legislation.
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The following table provides a summary of the change in cash flows from operating activities for the nine months ended September 30, 2025 and 2024 by Registrant:
Increase in cash flows from operating activities Exelon ComEd PECO BGE PHI Pepco DPL ACE
Net income (loss) $ 361 $ 80 $ 296 $ 45 $ 25 $ 14 $ 7 $ 5
Adjustments to reconcile net income to cash:
Non-cash operating activities 887 553 — 135 99 99 31 (34)
Collateral (paid) received, net (46) (52) 6 2 — 3 (2) —
Income taxes 37 175 68 70 42 18 24 5
Pension and non-pension postretirement benefit contributions (173) (181) (8) (6) 32 — — 4
Regulatory assets and liabilities, net (584) (550) (43) (45) 70 15 9 48
Changes in working capital and other assets and liabilities 385 (1) 39 41 113 (13) 27 122
Increase in cash flows from operating activities $ 867 $ 24 $ 358 $ 242 $ 381 $ 136 $ 96 $ 150
Changes in the Registrants' cash flows from operations were generally consistent with changes in each Registrant’s respective results of operations, as adjusted by changes in working capital in the normal course of business, except as discussed below. Significant operating cash flow impacts for the Registrants for the nine months ended September 30, 2025 and 2024 were as follows:
• See Note 14 — Supplemental Financial Information of the Combined Notes to Consolidated Financial Statements and the Registrants’ Consolidated Statements of Cash Flows for additional information on non-cash operating activities .
• Changes in collateral depended upon whether the Registrant was in a net mark-to-market liability or asset position, and collateral may have been required to be posted with or collected from its counterparties. In addition, the collateral posting and collection requirements differed depending on whether the transactions were on an exchange or in the over-the-counter markets. Changes in collateral for the Registrants are dependent upon the credit exposure of procurement contracts that may require suppliers to post collateral. The amount of cash collateral received from external counterparties remained relatively consistent comparing the nine months ended September 30, 2025 to the nine months ended September 30, 2024. See Note 8 — Derivative Financial Instruments for additional information.
• See Note 6 — Income Taxes of the Combined Notes to Consolidated Financial Statements and the Registrants' Consolidated Statements of Cash Flows for additional information on income taxes .
• Changes in Pension and non-pension postretirement benefit contributions relates to Exelon's increased contributions to the Qualified Plans during the nine months ended September 30, 2025. See Note 14 — Retirement Benefits of the 2024 Form 10-K for additional information.
• Changes in regulatory assets and liabilities, net, are due to the timing of cash payments for costs recoverable, or cash receipts for costs recovered, under our regulatory mechanisms differing from the recovery period of those costs. Included within the changes is energy efficiency spend for ComEd of $311 million and $266 million for the nine months ended September 30, 2025 and 2024, respectively. Also included within the changes is energy efficiency and demand response programs spend for BGE, Pepco, DPL and ACE of $64 million, $27 million, $11 million, and $37 million for the nine months ended September 30, 2025 and $94 million, $34 million, $14 million, and $24 million for the nine months ended September 30, 2024, respectively. PECO had no energy efficiency and demand response programs spend recorded to the regulatory asset for the nine months ended September 30, 2025 and 2024. See Note 2 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.
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• Changes in working capital and other assets and liabilities for the Utility Registrants and Exelon Corporate totaled $215 million and $385 million, respectively. The change in working capital and other noncurrent assets and liabilities for Exelon Corporate and the Utility Registrants is dependent upon the normal course of operations for all Registrants. For ComEd, it is also dependent upon whether the participating nuclear-powered generating facilities are owed money from ComEd as a result of the established pricing for CMCs. For the nine months ended September 30, 2025, the established pricing has resulted in both a receivable from, and payable to, nuclear-powered generating facilities. The change in receivable from nuclear-powered generating facilities, and the change in payable to nuclear-powered generating facilities, are reflected as a change in accounts receivable and a change in accounts payable and accrued expenses, respectively, within the cash flows from operations.
Cash Flows from Investing Activities
The following table provides a summary of the change in cash flows from investing activities for the nine months ended September 30, 2025 and 2024 by Registrant:
(Decrease) increase in cash flows from investing activities Exelon ComEd PECO BGE PHI Pepco DPL ACE
Capital expenditures $ (934) $ (351) $ (209) $ (178) $ (209) $ (18) $ 2 $ (27)
Proceeds from sales of assets (36) — — — 2 2 — —
Changes in intercompany money pool — — (133) — — — — —
Other investing activities (16) (3) (4) (3) — — — —
(Decrease) increase in cash flows from investing activities $ (986) $ (354) $ (346) $ (181) $ (207) $ (16) $ 2 $ (27)
Significant investing cash flow impacts for the Registrants for nine months ended September 30, 2025 and 2024 were as follows:
• Changes in capital expenditures are primarily due to the timing of cash expenditures for capital projects. See the "Credit Matters and Cash Requirements" section below for additional information on projected capital expenditure spending for the Utility Registrants.
• Changes in intercompany money pool are driven by short-term borrowing needs. Refer to more information regarding the intercompany money pool below.
Cash Flows from Financing Activities
The following table provides a summary of the change in cash flows from financing activities for the nine months ended September 30, 2025 and 2024 by Registrant:
Increase (decrease) in cash flows from financing activities Exelon ComEd PECO BGE PHI Pepco DPL ACE
Changes in short-term borrowings, net $ 713 $ 493 $ (27) $ 161 $ (188) $ (54) $ (48) $ (86)
Long-term debt, net 479 175 475 (150) (17) — (17) —
Changes in intercompany money pool — — — — (9) — — —
Issuance of common stock 25 — — — — — — —
Dividends paid on common stock (70) (28) (110) (18) — 19 13 (32)
Distributions to member — — — — 1 — — —
Contributions from parent/member — (9) (17) 294 64 (68) (53) 13
Other financing activities (1) 5 (3) 1 14 11 (2) —
Increase (decrease) in cash flows from financing activities $ 1,146 $ 636 $ 318 $ 288 $ (135) $ (92) $ (107) $ (105)
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Significant financing cash flow impacts for the Registrants for the nine months ended September 30, 2025 and 2024 were as follows:
• Changes in short-term borrowings, net , is driven by repayments on and issuances of notes due in less than 365 days. See Note 9 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information on short-term borrowings for the Registrants.
• Long-term debt, net , varies due to debt issuances and redemptions each year. See Note 9 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information on debt issuances. Refer to the "Debt" section below for additional information.
• Changes in intercompany money pool are driven by short-term borrowing needs. Refer below for more information regarding the intercompany money pool.
• Issuance of common stock relates to issuances of Exelon common stock during the first quarter of 2025. See Note 12 — Shareholders' Equity of the Combined Notes to Consolidated Financial Statements for additional information.
• Exelon’s ability to pay dividends on its common stock depends on the receipt of dividends paid by its operating subsidiaries. The payments of dividends to Exelon by its subsidiaries in turn depend on their results of operations and cash flows and other items affecting retained earnings. See Note 18 — Commitments and Contingencies of the 2024 Form 10-K for additional information on dividend restrictions. See below for quarterly dividends declared.
Debt
See Note 9 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information on the Registrants’ debt issuances.
During the nine months ended September 30, 2025, the following long-term debt was retired and/or redeemed.
Company (a)
Type Interest Rate Maturity Amount
Exelon Senior Notes 3.95 % June 15, 2025 $ 807
(a) On October 15, 2025, PECO redeemed $350 million of its 3.15% First Mortgage Bonds at maturity.
Dividends
Quarterly dividends declared by the Exelon Board of Directors during the nine months ended September 30, 2025 and for the fourth quarter of 2025 were as follows:
Period Declaration Date Shareholder of Record Date Dividend Payable Date Cash per Share (a)
First Quarter 2025 February 12, 2025 February 24, 2025 March 14, 2025 $ 0.4000
Second Quarter 2025 April 29, 2025 May 12, 2025 June 13, 2025 $ 0.4000
Third Quarter 2025 July 29, 2025 August 11, 2025 September 15, 2025 $ 0.4000
Fourth Quarter 2025 October 29, 2025 November 10, 2025 December 15, 2025 $ 0.4000
__________
(a) Exelon's Board of Directors approved an updated dividend policy for 2025. The 2025 quarterly dividend will be $0.40 per share.
Credit Matters and Cash Requirements
The Registrants fund liquidity needs for capital investment, working capital, energy hedging, and other financial commitments through cash flows from continuing operations, public debt offerings, commercial paper markets, and large, diversified credit facilities. The credit facilities include $4.0 billion in aggregate total commitments of which $3.4 billion was available to support additional commercial paper as of September 30, 2025, and of which
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no financial institution has more than 6.2% of the aggregate commitments for the Registrants. The Registrants had access to the commercial paper markets and had availability under their revolving credit facilities during the nine months ended September 30, 2025 to fund their short-term liquidity needs, when necessary. Exelon Corporate and the Utility Registrants each have a 5-year revolving credit facility. See Note 9 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information. The Registrants routinely review the sufficiency of their liquidity position, including appropriate sizing of credit facility commitments, by performing various stress test scenarios, such as commodity price movements, increases in margin-related transactions, changes in hedging levels, and the impacts of hypothetical credit downgrades. The Registrants have continued to closely monitor events in the financial markets and the financial institutions associated with the credit facilities, including monitoring credit ratings and outlooks, credit default swap levels, capital raising, and merger activity. See PART I. ITEM 1A. RISK FACTORS of the 2024 Form 10-K for additional information regarding the effects of uncertainty in the capital and credit markets.
The Registrants believe their cash flows from operating activities, access to credit markets, and their credit facilities provide sufficient liquidity to support the estimated future cash requirements.
At-the-Market Programs
On August 4, 2022, Exelon executed an equity distribution agreement (“2022 Equity Distribution Agreement”), with certain sales agents and forward sellers and certain forward purchasers, establishing an ATM equity distribution program under which it may offer and sell shares of its Common stock, having an aggregate gross sales price of up to $1 billion through August 3, 2025. On May 2, 2025, Exelon executed an additional equity distribution agreement ("2025 Equity Distribution Agreement" and, together with the August 4, 2022 Equity Distribution Agreement, "Equity Distribution Agreements"), with certain sales agents and forward sellers and certain forward purchasers, establishing an ATM equity distribution program which it may offer and sell shares of its Common stock, having an aggregate gross sales price of up to $2.5 billion through May 2, 2028. The 2025 Equity Distribution Agreement replaced the 2022 Equity Distribution Agreement. Exelon has no obligation to offer or sell any shares of Common stock under the 2025 Equity Distribution Agreement and may, at any time, suspend or terminate offers and sales under the 2025 Equity Distribution Agreement.
During the first quarter of 2025, Exelon issued approximately 4.0 million shares of Common stock at an average net price of $42.98 per share. The net proceeds from the issuance were $173 million, which were used for general corporate purposes.
In addition, in the first quarter of 2025, Exelon entered into forward sale agreements for 5.7 million shares of Common stock, at a weighted-average net forward price of $43.24 per share. The forward sale agreements require Exelon to, at its election prior to December 15, 2025, 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.
In the second quarter of 2025, Exelon entered into forward sale agreements for 6.2 million shares, and 3.6 million shares of Common stock, at a weighted-average net forward price of $43.51, and $43.17 per share, respectively. The forward sale agreements require Exelon to, at its election prior to December 15, 2025 and November 16, 2026, respectively, 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.
In the third quarter of 2025, Exelon entered into forward sale agreements for 11.5 million shares at a weighted-average net forward price of $43.73 per share. The forward sale agreements require Exelon to, at its election prior to December 15, 2026 either (i) physically settle the transactions by issuing shares of its Common stock to the forward counterparties in exchange for net proceeds at the then-applicable forward sale price specified by the agreements or (ii) net settle the transactions in whole or in part through the delivery to the forward counterparties or receipt from the forward counterparties of cash or shares in accordance with the provisions of the agreements.
No amounts have been or will be recorded on Exelon's balance sheet with respect to the equity offerings until the equity forward sale agreements have been settled. Each initial forward sale price is subject to adjustment on a
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daily basis based on a floating interest rate factor and will decrease by other fixed amounts specified in the agreements. Until settlement of the equity forward, earnings per share dilution resulting from the agreement, if any, will be determined under the treasury stock method. For the nine months ended September 30, 2025, approximately 26.7 million shares under the forward sale agreements were not included in the calculation of diluted earnings per share because their effect would have been antidilutive.
Inclusive of the impact of the forward sale agreements, $1.6 billion of Common stock remained available for sale pursuant to the ATM program as of September 30, 2025.
Incremental Collateral Requirements
The following table presents the incremental collateral that each Utility Registrant would have been required to provide in the event each Utility Registrant lost its investment grade credit rating at September 30, 2025 and available credit facility capacity prior to any incremental collateral at September 30, 2025:
PJM Credit Policy Collateral Other Incremental Collateral Required (a)
Available Credit Facility Capacity Prior to Any Incremental Collateral
ComEd $ 26 $ — $ 985
PECO — 40 595
BGE — 23 575
Pepco 1 — 235
DPL — 13 267
ACE — — 230
__________
(a) Represents incremental collateral related to natural gas procurement contracts.
Capital Expenditure Spending
As of September 30, 2025, the most recent estimates of capital expenditures for plant additions and improvements for 2025 are as follows:
(In millions) Transmission Distribution Gas Total (a)
Exelon N/A N/A N/A $ 8,975
ComEd 950 2,250 N/A 3,200
PECO 200 1,375 350 1,950
BGE 650 650 525 1,850
PHI 575 1,475 100 2,150
Pepco 250 750 N/A 1,000
DPL 150 325 75 525
ACE 150 275 N/A 425
__________
(a) Numbers rounded to the nearest $25M and may not sum due to rounding.
Projected capital expenditures and other investments are subject to periodic review and revision to reflect changes in economic conditions and other factors.
Retirement Benefits
Management considers various factors when making pension funding decisions, including actuarially determined minimum contribution requirements under ERISA, contributions required to avoid benefit restrictions and at-risk status as defined by the Pension Protection Act of 2006 (the Act), management of the pension obligation, and regulatory implications. The Act requires the attainment of certain funding levels to avoid benefit restrictions (such as an inability to pay lump sums or to accrue benefits prospectively), and at-risk status (which triggers higher minimum contribution requirements and participant notification). The projected contributions reflect a funding strategy to make annual contributions with the objective of achieving 100% funded status on an ABO basis over time. This funding strategy helps minimize volatility of future period required pension contributions.
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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.
While OPEB plans are also not subject to statutory minimum contribution requirements, Exelon does fund certain of its plans. For Exelon's funded OPEB plans, contributions generally equal accounting costs, however, Exelon’s management has historically considered several factors in determining the level of contributions to its OPEB plans, including liabilities management, levels of benefit claims paid, and regulatory implications (amounts deemed prudent to meet regulatory expectations and best assure continued rate recovery).
To the extent interest rates decline significantly or the pension and OPEB plans earn less than the expected asset returns, annual pension contribution requirements in future years could increase. Conversely, to the extent interest rates increase significantly or the pension and OPEB plans earn greater than the expected asset returns, annual pension and OPEB contribution requirements in future years could decrease. Additionally, expected contributions could change if Exelon changes its pension or OPEB funding strategy.
See Note 14 — Retirement Benefits of the Combined Notes to Consolidated Financial Statements of the 2024 Form 10-K for additional information on pension and OPEB contributions.
Credit Facilities
Exelon Corporate, ComEd, and BGE meet their short-term liquidity requirements primarily through the issuance of commercial paper. PECO meets its short-term liquidity requirements primarily through the issuance of commercial paper and borrowings from the Exelon intercompany money pool. Pepco, DPL, and ACE meet their short-term liquidity requirements primarily through the issuance of commercial paper and borrowings from the PHI intercompany money pool. PHI Corporate meets its short-term liquidity requirements primarily through the issuance of short-term notes and the Exelon intercompany money pool. The Registrants may use their respective credit facilities for general corporate purposes, including meeting short-term funding requirements and the issuance of letters of credit.
See Note 9 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information on the Registrants’ credit facilities and short term borrowing activity.
Security Ratings
The Registrants’ access to the capital markets, including the commercial paper market, and their respective financing costs in those markets, may depend on the securities ratings of the entity that is accessing the capital markets.
The Registrants’ borrowings are not subject to default or prepayment as a result of a downgrading of securities, although such a downgrading of a Registrant’s securities could increase fees and interest charges under that Registrant’s credit agreements.
As part of the normal course of business, the Registrants enter into contracts that contain express provisions or otherwise permit the Registrants and their counterparties to demand adequate assurance of future performance when there are reasonable grounds for doing so. In accordance with the contracts and applicable contracts law, if the Registrants are downgraded by a credit rating agency, it is possible that a counterparty would attempt to rely on such a downgrade as a basis for making a demand for adequate assurance of future performance, which could include the posting of collateral. See Note 8 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information on collateral provisions.
The credit ratings for ComEd, BGE, PHI, Pepco, DPL, and ACE did not change for the nine months ended September 30, 2025. On January 17, 2025, Fitch Ratings affirmed and withdrew the long-term and short-term issuer default ratings along with individual securities ratings of the Registrants for commercial reasons. On February 7, 2025, S&P raised its long-term issuer credit rating for Exelon and PECO from 'BBB+' to 'A-', and raised its rating on Exelon’s senior unsecured debt from ‘BBB’ to 'BBB+'. S&P also affirmed its short-term issuer and commercial paper rating for Exelon and PECO of 'A-2'.
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Intercompany Money Pool
To provide an additional short-term borrowing option that will generally be more favorable to the borrowing participants than the cost of external financing, both Exelon and PHI operate an intercompany money pool. Maximum amounts contributed to and borrowed from the money pool by participant and the net contribution or borrowing as of September 30, 2025, are presented in the following table:
During the Nine Months Ended September 30, 2025 At September 30, 2025
Exelon Intercompany Money Pool Maximum
Contributed Maximum
Borrowed Contributed
(Borrowed)
Exelon Corporate $ 578 $ — $ 64
PECO 336 (253) 222
BSC — (413) (284)
PHI Corporate — (85) (64)
PCI 62 — 62
During the Nine Months Ended September 30, 2025 At September 30, 2025
PHI Intercompany Money Pool Maximum
Contributed Maximum
Borrowed
Contributed
(Borrowed)
Pepco $ 20 $ (35) $ —
DPL 48 (1) —
ACE — (46) —
Shelf Registration Statements
On February 21, 2024, PECO and BGE, as co-registrants, filed with the SEC a standalone automatically effective shelf registration statement, unlimited in amount, which can be used to issue PECO and BGE debt securities through the expiration date of February 20, 2027. On February 13, 2025, as most recently amended on March 27, 2025, Exelon Corporation and ComEd, as co-registrants filed a shelf registration statement with the SEC ("Exelon and ComEd Shelf Registration") for authorization of up to $12,575 million in additional security registration, to be used to issue Exelon Corporate debt securities and equity securities, as well as ComEd debt securities. The Exelon and ComEd Shelf Registration was declared effective by the SEC on April 8, 2025, and is effective through April 8, 2028. The ability of Exelon Corporation, ComEd, PECO and BGE to sell securities off their corresponding registration Statements, or to access the private placement markets, will depend on a number of factors at the time of the proposed sale, including other required regulatory approvals, as applicable, the current financial condition of the Registrant, its securities ratings and market conditions.
Pepco, DPL and ACE periodically issue securities through the private placement markets. Pepco, DPL and ACE's ability to access the private placement markets will depend on a number of factors at the time of the proposed sale, including other required regulatory approvals, as applicable, current financial condition, securities ratings and market conditions.
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Regulatory Authorizations
The Utility Registrants are required to obtain short-term and long-term financing authority from Federal and State Commissions as follows:
At September 30, 2025
Short-term Financing Authority Remaining Long-term Financing Authority
Commission Expiration Date Amount Commission Expiration Date Amount
ComEd (a)(b)
FERC December 31, 2025 $ 2,500 ICC January 1, 2027 & May 1, 2027 $ 1,593
PECO (c)
FERC December 31, 2025 1,500 PAPUC December 31, 2027 1,850
BGE (d)
FERC December 31, 2025 700 MDPSC N/A 1,850
Pepco (e)(f)(g)
FERC December 31, 2025 500 MDPSC / DCPSC December 31, 2025 100
DPL (e)(h)(i)
FERC December 31, 2025 500 MDPSC / DEPSC December 31, 2025 172
ACE (j)
NJBPU December 31, 2025 350 NJBPU December 31, 2026 775
__________
(a) On September 8, 2025, ComEd filed an application with the FERC to request a new short-term financing authority for $2.5 billion through December 31, 2027. ComEd expects approval of their application by December 31, 2025.
(b) On September 19, 2025, ComEd filed an application for $2.8 billion in new money long-term debt financing authority from the ICC and expects approval of their application by December 31, 2025.
(c) On September 8, 2025, PECO filed an application with the FERC to request a new short-term financing authority for $1.5 billion through December 31, 2027. PECO expects approval of their application by December 31, 2025.
(d) On September 8, 2025, BGE filed an application with the FERC to request a new short term financing authority for $900 million through December 31, 2027. BGE expects approval of their application by December 31, 2025.
(e) The financing authority filed with MDPSC does not have an expiration date, while the financing authority filed with DCPSC and DEPSC have an expiration date of December 31, 2025.
(f) On July 17, 2025, Pepco filed an application with the MDPSC and DCPSC to request a new long-term financing authority for $1.1 billion through December 31, 2028. On September 3, 2025, Pepco received approval of their application from the MDSPC. Pepco expects approval of their application from the DCPSC by December 31, 2025.
(g) On September 8, 2025, Pepco filed an application with the FERC to request a new short-term financing authority for $700 million through December 31, 2027. Pepco expects approval of their application by December 31, 2025.
(h) On September 3, 2025, DPL received approval from the MDSPC and DEPSC, respectively, for $700 million in new long-term financing authority, with an effective date of January 1, 2026.
(i) On September 8, 2025, DPL filed an application with the FERC to request a new short-term financing authority for $700 million through December 31, 2027. DPL expects approval of their application by December 31, 2025.
(j) On June 6, 2025, ACE filed an application with the NJBPU to extend their short-term financing authority through January 1, 2028. ACE expects approval of their application by December 31, 2025.
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ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK
The Registrants hold commodity and financial instruments that are exposed to the following market risks:
• Commodity price risk, which is discussed further below.
• Counterparty credit risk associated with non-performance by counterparties on executed derivative instruments and participation in all, or some of the established, wholesale spot energy markets that are administered by PJM. The credit policies of PJM may, under certain circumstances, require that losses arising from the default of one member on spot energy market transactions be shared by the remaining participants. See Note 8 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for a detailed discussion of counterparty credit risk related to derivative instruments.
• Equity price and interest rate risk associated with Exelon’s pension and OPEB plan trusts. See Note 7 — Retirement Benefits of the 2024 Form 10-K for additional information.
• Interest rate risk associated with changes in interest rates for the Registrants’ outstanding long-term debt. This risk is significantly reduced as substantially all of the Registrants’ outstanding debt has fixed interest rates. There is inherent interest rate risk related to refinancing maturing debt by issuing new long-term debt. The Registrants use a combination of fixed-rate and variable-rate debt to manage interest rate exposure. See Note 9 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information. In addition, Exelon may utilize interest rate derivatives to lock in rate levels in anticipation of future financings, which are typically designated as cash flow hedges. See Note 8 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information.
The Registrants operate primarily under cost-based rate regulation limiting exposure to the effects of market risk. Hedging programs are utilized to reduce exposure to energy and natural gas price volatility and have no direct earnings impacts as the costs are fully recovered through regulatory-approved recovery mechanisms.
Exelon manages these risks through risk management policies and objectives for risk assessment, control and valuation, counterparty credit approval, and the monitoring and reporting of risk exposures. Risk management issues are reported to Exelon’s Executive Committee, the Risk Management Committees of each Utility Registrant, and the Audit and Risk Committee of Exelon’s Board of Directors.
Commodity Price Risk
Commodity price risk is associated with price movements resulting from changes in supply and demand, fuel costs, market liquidity, weather conditions, governmental regulatory and environmental policies, and other factors. To the extent the total amount of energy Exelon purchases differs from the amount of energy it has contracted to sell, Exelon is exposed to market fluctuations in commodity prices. Exelon seeks to mitigate its commodity price risk through the sale and purchase of electricity and natural gas.
ComEd entered into 20-year floating-to-fixed renewable energy swap contracts beginning in June 2012, which are considered an economic hedge and have changes in fair value recorded to an offsetting regulatory asset or liability. ComEd has block energy contracts to procure electric supply that are executed through a competitive procurement process, which are considered derivatives and qualify for NPNS, and as a result are accounted for on an accrual basis of accounting. PECO, BGE, Pepco, DPL, and ACE have contracts to procure electric supply that are executed through a competitive procurement process. PECO, BGE, Pepco, DPL, and ACE have certain full requirements contracts, which are considered derivatives and qualify for NPNS, and as a result are accounted for on an accrual basis of accounting. Other full requirements contracts are not derivatives.
PECO, BGE, and DPL also have executed derivative natural gas contracts, which qualify for NPNS, to hedge their long-term price risk in the natural gas market. The hedging programs for natural gas procurement have no direct impact on their financial statements.
For additional information on these contracts, see Note 8 — Derivative Financial Instruments and Note 10 — Fair Value of Financial Assets and Liabilities of the Combined Notes to Consolidated Financial Statements.
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The following table presents the maturity and source of fair value for Exelon’s and ComEd’s mark-to-market commodity contract net liabilities. These net liabilities are associated with ComEd’s floating-to-fixed energy swap contracts with unaffiliated suppliers. The table provides two fundamental pieces of information. First, the table provides the source of fair value used in determining the carrying amount of Exelon's and ComEd's total mark-to-market net liabilities. Second, the table shows the maturity, by year, of Exelon's and ComEd's commodity contract net liabilities giving an indication of when these mark-to-market amounts will settle and either generate or require cash. See Note 10 — Fair Value of Financial Assets and Liabilities of the Combined Notes to Consolidated Financial Statements for additional information regarding fair value measurements and the fair value hierarchy.
Maturities Within Total Fair
Value
Commodity derivative contracts (a) :
2025 2026 2027 2028 2029 2030 and Beyond
Prices based on model or other valuation methods (Level 3) $ (10) $ (20) $ (20) $ (20) $ (19) $ (39) $ (128)
_________
(a) Represents ComEd's net liabilities associated with the floating-to-fixed energy swap contracts with unaffiliated suppliers.
ITEM 4. CONTROLS AND PROCEDURES
During the third quarter of 2025, each of the Registrants' management, including its principal executive officer and principal financial officer, evaluated its disclosure controls and procedures related to the recording, processing, summarizing, and reporting of information in its periodic reports that it files with the SEC. These disclosure controls and procedures have been designed by the Registrants to ensure that (a) material information relating to that Registrant, including its consolidated subsidiaries, is accumulated and made known to that Registrant's management, including its principal executive officer and principal financial officer, by other employees of that Registrant and its subsidiaries as appropriate to allow timely decisions regarding required disclosure, and (b) this information is recorded, processed, summarized, evaluated, and reported, as applicable, within the time periods specified in the SEC’s rules and forms. Due to the inherent limitations of control systems, not all misstatements may be detected. These inherent limitations include the realities that judgments in decision-making can be faulty and that breakdowns can occur because of simple error or mistake. Additionally, controls could be circumvented by the individual acts of some persons or by collusion of two or more people.
Accordingly, as of September 30, 2025, the principal executive officer and principal financial officer of each of the Registrants concluded that such Registrant’s disclosure controls and procedures were effective to accomplish its objectives. The Registrants continually strive to improve their disclosure controls and procedures to enhance the quality of its financial reporting and to maintain dynamic systems that change as conditions warrant. There were no changes in internal control over financial reporting during the third quarter of 2025 that materially affected, or are reasonably likely to materially affect, any of the Registrants' internal control over financial reporting.
PART II — OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS
The Registrants are parties to various lawsuits and regulatory proceedings in the ordinary course of their respective businesses. For information regarding material lawsuits and proceedings, see (a) ITEM 3. LEGAL PROCEEDINGS of the 2024 Form 10-K, (b) Notes 3 — Regulatory Matters and 18 — Commitments and Contingencies of the 2024 Form 10-K, and (c) Notes 2 — Regulatory Matters and 11 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements in PART I, ITEM 1. FINANCIAL STATEMENTS of this Report. Such descriptions are incorporated herein by these references.
ITEM 1A. RISK FACTORS
Risks Related to All Registrants
At September 30, 2025, the Registrants' risk factors were consistent with the risk factors described in the Registrants' combined 2024 Form 10-K in ITEM 1A. RISK FACTORS.
ITEM 5. OTHER INFORMATION
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All Registrants
None of our officers or directors, as defined in Rule 16a-1(f) of the Securities Exchange Act of 1934, adopted , modified, or terminated a “Rule 10b5-1 trading arrangement” or a “non-Rule 10b5-1 trading arrangement,” as defined in Item 408 of Regulation S-K, during the three months ended September 30, 2025.
ITEM 6. EXHIBITS
Certain of the following exhibits are incorporated herein by reference under Rule 12b-32 of the Securities and Exchange Act of 1934, as amended. Certain other instruments which would otherwise be required to be listed below have not been so listed because such instruments do not authorize securities in an amount which exceeds 10% of the total assets of the applicable Registrant and its subsidiaries on a consolidated basis, and the applicable Registrant agrees to furnish a copy of any such instrument to the Commission upon request.
(4) Instruments Defining the Rights of Securities Holders, Including Indentures
PECO Energy Company
Exhibit No. Description Location
4-1
One Hundred and Twenty-Fifth Supplemental Indenture dated as of August 15, 2025 from PECO to U.S. Bank National Association, as trustee File No. 000-16844, Form 8-K dated September 10, 2025, Exhibit 4.1
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Certifications Pursuant to Rule 13a-14(a) and 15d-14(a) of the Securities and Exchange Act of 1934 as to the Quarterly Report on Form 10-Q for the quarterly period ended September 30, 2025 filed by the following officers for the following companies:
Exelon Corporation
Exhibit No. Description
31-1
Filed by Calvin G. Butler, Jr. for Exelon Corporation
31-2
Filed by Jeanne M. Jones for Exelon Corporation
Commonwealth Edison Company
Exhibit No. Description
31-3
Filed by Gil C. Quiniones for Commonwealth Edison Company
31-4
Filed by Joshua S. Levin for Commonwealth Edison Company
PECO Energy Company
Exhibit No. Description
31-5
Filed by David M. Vahos for PECO Energy Company
31-6
Filed by Marissa E. Humphrey for PECO Energy Company
Baltimore Gas and Electric Company
Exhibit No. Description
31-7
Filed by Tamla A. Olivier for Baltimore Gas and Electric Company
31-8
Filed by Michael J. Cloyd for Baltimore Gas and Electric Company
Pepco Holdings LLC
Exhibit No. Description
31-9
Filed by J. Tyler Anthony for Pepco Holdings LLC
31-10
Filed by Elizabeth Morgan Downs O'Donnell for Pepco Holdings LLC
Potomac Electric Power Company
Exhibit No. Description
31-11
Filed by J. Tyler Anthony for Potomac Electric Power Company
31-12
Filed by Elizabeth Morgan Downs O'Donnell for Potomac Electric Power Company
Delmarva Power & Light Company
Exhibit No. Description
31-13
Filed by J. Tyler Anthony for Delmarva Power & Light Company
31-14
Filed by Elizabeth Morgan Downs O'Donnell for Delmarva Power & Light Company
Atlantic City Electric Company
Exhibit No. Description
31-15
Filed by J. Tyler Anthony for Atlantic City Electric Company
31-16
Filed by Elizabeth Morgan Downs O'Donnell for Atlantic City Electric Company
Certifications Pursuant to Section 1350 of Chapter 63 of Title 18 United States Code (Sarbanes-Oxley Act of 2002) as to the Quarterly Report on Form 10-Q for the quarterly period ended September 30, 2025 filed by the following officers for the following companies:
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Exelon Corporation
Exhibit No. Description
32-1
Filed by Calvin G. Butler, Jr. for Exelon Corporation
32-2
Filed by Jeanne M. Jones for Exelon Corporation
Commonwealth Edison Company
Exhibit No. Description
32-3
Filed by Gil C. Quiniones for Commonwealth Edison Company
32-4
Filed by Joshua S. Levin for Commonwealth Edison Company
PECO Energy Company
Exhibit No. Description
32-5
Filed by David M. Vahos for PECO Energy Company
32-6
Filed by Marissa E. Humphrey for PECO Energy Company
Baltimore Gas and Electric Company
Exhibit No. Description
32-7
Filed by Tamla A. Olivier for Baltimore Gas and Electric Company
32-8
Filed by Michael J. Cloyd for Baltimore Gas and Electric Company
Pepco Holdings LLC
Exhibit No. Description
32-9
Filed by J. Tyler Anthony for Pepco Holdings LLC
32-10
Filed by Elizabeth Morgan Downs O'Donnell for Pepco Holdings LLC
Potomac Electric Power Company
Exhibit No. Description
32-11
Filed by J. Tyler Anthony for Potomac Electric Power Company
32-12
Filed by Elizabeth Morgan Downs O'Donnell for Potomac Electric Power Company
Delmarva Power & Light Company
Exhibit No. Description
32-13
Filed by J. Tyler Anthony for Delmarva Power & Light Company
32-14
Filed by Elizabeth Morgan Downs O'Donnell for Delmarva Power & Light Company
Atlantic City Electric Company
Exhibit No. Description
32-15
Filed by J. Tyler Anthony for Atlantic City Electric Company
32-16
Filed by Elizabeth Morgan Downs O'Donnell for Atlantic City Electric Company
101.INS Inline XBRL Instance Document - the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document.
101.SCH Inline XBRL Taxonomy Extension Schema Document
101.CAL Inline XBRL Taxonomy Extension Calculation Linkbase Document
101.DEF Inline XBRL Taxonomy Extension Definition Linkbase Document
101.LAB Inline XBRL Taxonomy Extension Labels Linkbase Document
101.PRE Inline XBRL Taxonomy Extension Presentation Linkbase Document
104 Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101)
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SIGNATURES
Pursuant to requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
EXELON CORPORATION
/s/ CALVIN G. BUTLER, JR. /s/ JEANNE M. JONES
Calvin G. Butler, Jr. Jeanne M. Jones
President, Chief Executive Officer
(Principal Executive Officer), and Director Executive Vice President and Chief Financial Officer
(Principal Financial Officer)
/s/ ROBERT A. KLECZYNSKI
Robert A. Kleczynski
Senior Vice President, Corporate Controller and Tax
(Principal Accounting Officer)
November 4, 2025
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Pursuant to requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
COMMONWEALTH EDISON COMPANY
/s/ GIL C. QUINIONES /s/ JOSHUA S. LEVIN
Gil C. Quiniones Joshua S. Levin
President, Chief Executive Officer
(Principal Executive Officer), and Director Senior Vice President, Chief Financial Officer, and Treasurer
(Principal Financial Officer)
/s/ ERIN V. WHITE
Erin V. White
Director, Accounting
(Principal Accounting Officer)
November 4, 2025
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Pursuant to requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
PECO ENERGY COMPANY
/s/ DAVID M. VAHOS /s/ MARISSA E. HUMPHREY
David M. Vahos Marissa E. Humphrey
President, Chief Executive Officer (Principal Executive Officer), and Director Senior Vice President, Chief Financial Officer, and Treasurer
(Principal Financial Officer)
/s/ MARIANA HUFFORD
Mariana Hufford
Director, Accounting
(Principal Accounting Officer)
November 4, 2025
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Pursuant to requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
BALTIMORE GAS AND ELECTRIC COMPANY
/s/ TAMLA A. OLIVIER /s/ MICHAEL J. CLOYD
Tamla A. Olivier Michael J. Cloyd
President, Chief Executive Officer
(Principal Executive Officer), and Director Senior Vice President, Chief Financial Officer, and Treasurer
(Principal Financial Officer)
/s/ DAMON M. SCOLERI
Damon M. Scoleri
Director, Accounting
(Principal Accounting Officer)
November 4, 2025
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Pursuant to requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
PEPCO HOLDINGS LLC
/s/ J. TYLER ANTHONY /s/ ELIZABETH MORGAN DOWNS O'DONNELL
J. Tyler Anthony Elizabeth Morgan Downs O'Donnell
President, Chief Executive Officer
(Principal Executive Officer), and Director Senior Vice President, Chief Financial Officer, and Treasurer
(Principal Financial Officer)
/s/ JASON T. JONES
Jason T. Jones
Director, Accounting
(Principal Accounting Officer)
November 4, 2025
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Pursuant to requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
POTOMAC ELECTRIC POWER COMPANY
/s/ J. TYLER ANTHONY /s/ ELIZABETH MORGAN DOWNS O'DONNELL
J. Tyler Anthony Elizabeth Morgan Downs O'Donnell
President, Chief Executive Officer
(Principal Executive Officer), and Director Senior Vice President, Chief Financial Officer, and Treasurer
(Principal Financial Officer)
/s/ JASON T. JONES
Jason T. Jones
Director, Accounting
(Principal Accounting Officer)
November 4, 2025
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Pursuant to requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
DELMARVA POWER & LIGHT COMPANY
/s/ J. TYLER ANTHONY /s/ ELIZABETH MORGAN DOWNS O'DONNELL
J. Tyler Anthony Elizabeth Morgan Downs O'Donnell
President, Chief Executive Officer
(Principal Executive Officer), and Director Senior Vice President, Chief Financial Officer, and Treasurer
(Principal Financial Officer)
/s/ JASON T. JONES
Jason T. Jones
Director, Accounting
(Principal Accounting Officer)
November 4, 2025
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Pursuant to requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
ATLANTIC CITY ELECTRIC COMPANY
/s/ J. TYLER ANTHONY /s/ ELIZABETH MORGAN DOWNS O'DONNELL
J. Tyler Anthony Elizabeth Morgan Downs O'Donnell
President, Chief Executive Officer
(Principal Executive Officer), and Director Senior Vice President, Chief Financial Officer, and Treasurer
(Principal Financial Officer)
/s/ JASON T. JONES
Jason T. Jones
Director, Accounting
(Principal Accounting Officer)
November 4, 2025
159