10-Q – 2026-07-30 – exc-20260630.htm

(Stipulation), which contained the terms of the proposed settlement. The proposed settlement terms include but 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. The court granted the renewed motion for preliminary approval on November 17, 2025, and the final settlement hearing was held on May 5, 2026.
Maryland Sales and Use Tax Refund Claim (Exelon, BGE, PHI, Pepco, and DPL). Maryland imposes a 6% sales tax on the purchase of most goods and services. BGE, Pepco, and DPL have filed or plan to file refund claims that treat electric transmission and distribution machinery and equipment as nontaxable pursuant to the manufacturing exemption available under Maryland law. These claims were initially denied by the Maryland Comptroller.
On November 22, 2024, the Appellate Court of Maryland, in a case involving a regulated electric utility operating in Maryland, ruled that the purchase of certain transmission and distribution equipment qualifies 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. 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 decision, which was granted. 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.
On July 17, 2026, the Supreme Court of Maryland issued a decision affirming that purchases of certain transmission and distribution equipment qualify for the sales tax manufacturing exemption. The Supreme Court of Maryland also concluded that sales tax refund claims are eligible for interest.
As of June 30, 2026, Exelon, BGE, PHI, Pepco, and DPL have filed or plan to file refund claims including interest of $ 160 million, $ 110 million, $ 50 million, $ 30 million, and $ 20 million, respectively. The receivable will be recorded in the period that resolution is reached with taxing authorities. The sales tax payments were primarily capitalized; therefore, that portion of 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 Program
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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 May 2, 2025, Exelon executed an equity distribution agreement ("2025 Equity Distribution Agreement"), 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. 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. Exelon issued the following shares of Common stock in the second quarter of 2026:

Effective Period
Shares Issued
(in millions)
Weighted-Average Net Price
Net Proceeds (a)
(in millions)

Q2 2026 (b)
8.7 $ 44.03   $ 382  

_________
(a) Proceeds were used for general corporate purposes.
(b) In Q2 2026, Exelon settled all forward sale agreements with a November 16, 2026 maturity date and a portion of the forward sale agreements with December 15, 2026 and July 30, 2027 maturity dates that were entered into by various forward sellers under the ATM program as outlined below.
In the first quarter of 2026, Exelon entered into various forward sale agreements under the 2025 ATM program. The forward sale agreements require Exelon to, at its election prior to the maturity date, either (i) physically settle the transactions by issuing shares of its Common stock to the forward counterparties in exchange for net proceeds at the then-applicable forward sale price specified by the agreements or (ii) net settle the transactions in whole or in part through the delivery to the forward counterparties or receipt from the forward counterparties of cash or shares in accordance with the provisions of the agreements. The following forward sale agreements were entered into under Exelon’s ATM program in the first quarter of 2026:

Effective Period Shares Available
(in millions) Weighted-Average Net Price Maturity Date
Q1 2026 5.4 $ 47.67   July 30, 2027
Q1 2026 6.4 $ 48.68   September 2, 2027

Additionally, the following forward sale agreements were entered into during the twelve months ended 2025 under Exelon’s ATM program and were not settled as of December 31, 2025:

Effective Period Shares Available
(in millions) Weighted-Average Net Price Maturity Date
Q2 2025 3.6 $ 43.17   November 16, 2026
Q3 2025 11.5 $ 43.73   December 15, 2026
Q4 2025 0.8 $ 45.42   December 15, 2026

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 three and six months ended June 30, 2026, approximately 18.4 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, $ 1.0 billion of Common stock remained available for sale pursuant to the ATM program as of June 30, 2026.
On July 6, 2026, Exelon settled an additional forward agreement that was entered into under the 2025 ATM program. Exelon issued approximately 2.3 million shares of Common stock at a weighted-average net price of $ 43.29 per share. The net proceeds from the issuance were $ 101 million, which will be used for general corporate purposes.

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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 June 30, 2026  Cash Flow Hedges Pension and Non-Pension Postretirement Benefit Plan Items (a)
Total
Balance at March 31, 2026 $ 28   $ ( 784 ) $ ( 756 )
OCI before reclassifications 2   ( 1 ) 1  
Amounts reclassified from AOCI ( 2 ) 7   5  
Net current-period OCI —   6   6  
Balance at June 30, 2026 $ 28   $ ( 778 ) $ ( 750 )

Three Months Ended June 30, 2025  Cash Flow Hedges Pension and Non-Pension Postretirement Benefit Plan Items (a)
Total
Balance at March 31, 2025 $ 37   $ ( 755 ) $ ( 718 )
OCI before reclassifications ( 4 ) 1   ( 3 )
Amounts reclassified from AOCI ( 2 ) 5   3  
Net current-period OCI ( 6 ) 6   —  
Balance at June 30, 2025 $ 31   $ ( 749 ) $ ( 718 )

Six Months Ended June 30, 2026  Cash Flow Hedges Pension and Non-Pension Postretirement Benefit Plan Items (a)
Total
Balance at December 31, 2025 $ 33   $ ( 795 ) $ ( 762 )
OCI before reclassifications ( 2 ) 3   1  
Amounts reclassified from AOCI ( 3 ) 14   11  
Net current-period OCI ( 5 ) 17   12  
Balance at June 30, 2026 $ 28   $ ( 778 ) $ ( 750 )

Six Months Ended June 30, 2025  Cash Flow Hedges Pension and Non-Pension Postretirement Benefit Plan Items (a)
Total
Balance at December 31, 2024 $ 45   $ ( 765 ) $ ( 720 )
OCI before reclassifications ( 11 ) 5   ( 6 )
Amounts reclassified from AOCI ( 3 ) 11   8  
Net current-period OCI ( 14 ) 16   2  
Balance at June 30, 2025 $ 31   $ ( 749 ) $ ( 718 )

______
(a) This AOCI component is included in the computation of net periodic pension and OPEB cost. See Note 12 — Retirement Benefits of the 2025 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 June 30, Six Months Ended June 30,
2026 2025 2026 2025
Pension and non-pension postretirement benefit plans:

Actuarial losses reclassified to periodic benefit cost $ ( 2 ) $ ( 2 ) $ ( 4 ) $ ( 4 )
Pension and non-pension postretirement benefit plans valuation adjustments 1   —   —   ( 2 )
Unrealized gains on cash flow hedges —   —   —   2  

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 June 30, 2026
Utility taxes (a)
$ 253   $ 86   $ 51   $ 27   $ 89   $ 81   $ 7   $ 1  
Property 124   10   5   63   46   30   15   1  
Payroll 36   9   5   4   9   2   1   1  

Three Months Ended June 30, 2025
Utility taxes (a)
$ 247   $ 79   $ 47   $ 33   $ 88   $ 80   $ 7   $ 1  
Property 111   8   4   57   40   27   12   1  
Payroll 34   9   5   5   8   2   1   1  

Six Months Ended June 30, 2026
Utility taxes (a)
$ 528   $ 171   $ 109   $ 63   $ 185   $ 167   $ 16   $ 2  
Property 250   20   10   126   93   60   31   1  
Payroll 70   18   10   8   17   4   2   2  

Six Months Ended June 30, 2025
Utility taxes (a)
$ 496   $ 159   $ 98   $ 58   $ 181   $ 164   $ 15   $ 2  
Property 222   18   9   114   80   55   24   1  
Payroll 67   16   9   10   15   3   2   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 June 30, 2026
AFUDC — Equity $ 63   $ 24   $ 11   $ 16   $ 12   $ 9   $ 2   $ 1  
Non-service net periodic benefit cost ( 11 ) —   —   —   —   —   —   —  

Three Months Ended June 30, 2025
AFUDC — Equity $ 43   $ 14   $ 10   $ 9   $ 10   $ 8   $ 1   $ 1  
Non-service net periodic benefit cost ( 13 ) —   —   —   —   —   —   —  

Six Months Ended June 30, 2026
AFUDC — Equity $ 120   $ 45   $ 21   $ 30   $ 24   $ 19   $ 3   $ 2  
Non-service net periodic benefit cost ( 21 ) —   —   —   —   —   —   —  

Six Months Ended June 30, 2025
AFUDC — Equity $ 81   $ 26   $ 17   $ 18   $ 20   $ 15   $ 3   $ 2  
Non-service net periodic benefit cost ( 26 ) —   —   —   —   —   —   —  

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
Six Months Ended June 30, 2026
Property, plant, and equipment (a)
$ 1,605   $ 639   $ 246   $ 267   $ 427   $ 189   $ 120   ` $ 116  
Amortization of regulatory assets and liabilities, net (a)
315   181   1   67   64   39   13   12  
Amortization of intangible assets, net (a)
—   —   —   —   —   —   —   —  

ARO accretion (b)
1   —   —   —   —   —   —   —  
Total depreciation, amortization, and accretion $ 1,921   $ 820   $ 247   $ 334   $ 491   $ 228   $ 133   $ 128  

Six Months Ended June 30, 2025
Property, plant, and equipment (a)
$ 1,506   $ 608   $ 219   $ 249   $ 402   $ 177   $ 113   $ 111  
Amortization of regulatory assets and liabilities, net (a)
296   159   2   69   65   35   13   16  
Amortization of intangible assets, net (a)
3   —   —   —   —   —   —   —  

ARO accretion (b)
1   —   —   —   —   —   —   —  
Total depreciation, amortization, and accretion $ 1,806   $ 767   $ 221   $ 318   $ 467   $ 212   $ 126   $ 127  

__________
(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
Six Months Ended June 30, 2026
Pension and OPEB costs $ 129   $ 54   $ 8   $ 14   $ 41   $ 14   $ 7   $ 5  
Allowance for credit losses 171   35   48   53   35   17   7   11  

True-up adjustments to decoupling mechanisms and formula rates (a)
98   46   ( 10 ) 18   44   14   5   25  

Amortization of operating ROU asset 11   —   —   3   5   1   2   1  

AFUDC — Equity ( 120 ) ( 45 ) ( 21 ) ( 30 ) ( 24 ) ( 19 ) ( 3 ) ( 2 )

Six Months Ended June 30, 2025
Pension and OPEB costs $ 136   $ 42   $ 3   $ 30   $ 49   $ 18   $ 8   $ 6  
Allowance for credit losses 137   23   50   17   47   19   11   17  

True-up adjustments to decoupling mechanisms and formula rates (a)
397   319   8   43   27   14   5   8  

Amortization of operating ROU asset 16   —   —   4   9   2   3   1  

AFUDC — Equity ( 81 ) ( 26 ) ( 17 ) ( 18 ) ( 20 ) ( 15 ) ( 3 ) ( 2 )

__________
(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 2 — Regulatory Matters of the 2025 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 June 30, 2026
Cash and cash equivalents $ 1,813   $ 704   $ 39   $ 1,010   $ 47   $ 21   $ 8   $ 13  
Restricted cash and cash equivalents 608   533   —   4   36   31   2   2  
Restricted cash included in Other deferred debits and other assets 9   9   —   —   —   —   —   —  
Total cash, restricted cash, and cash equivalents $ 2,430   $ 1,246   $ 39   $ 1,014   $ 83   $ 52   $ 10   $ 15  

Balance at December 31, 2025
Cash and cash equivalents $ 626   $ 159   $ 116   $ 217   $ 103   $ 22   $ 9   $ 22  
Restricted cash and cash equivalents 525   454   —   3   38   33   3   2  
Restricted cash included in Other deferred debits and other assets 50   50   —   —   —   —   —   —  
Total cash, restricted cash, and cash equivalents $ 1,201   $ 663   $ 116   $ 220   $ 141   $ 55   $ 12   $ 24  

Balance at June 30, 2025
Cash and cash equivalents $ 724   $ 387   $ 25   $ 236   $ 67   $ 22   $ 9   $ 15  
Restricted cash and cash equivalents 478   411   —   5   30   22   5   2  
Restricted cash included in Other deferred debits and other assets 49   49   —   —   —   —   —   —  
Total cash, restricted cash, and cash equivalents $ 1,251   $ 847   $ 25   $ 241   $ 97   $ 44   $ 14   $ 17  

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  

For additional information on restricted cash see Note 1 — Significant Accounting Policies of the 2025 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 June 30, 2026
Compensation-related accruals (a)
$ 503   $ 140   $ 77   $ 69   $ 102   $ 29   $ 21   $ 15  
Taxes accrued 224   91   6   32   88   64   10   10  
Interest accrued 583   165   75   58   99   52   20   22  

Balance at December 31, 2025
Compensation-related accruals (a)
$ 705   $ 209   $ 96   $ 99   $ 125   $ 35   $ 24   $ 17  
Taxes accrued 242   94   306   191   107   69   25   18  
Interest accrued 538   155   75   55   92   49   18   20  

__________
(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 June 30, Six Months Ended June 30, Three Months Ended June 30, Six Months Ended June 30,
2026 2025 2026 2025 2026 2025 2026 2025
Exelon
   BSC $ 117   $ 162   $ 251   $ 323  
   PHISCO 28   29   51   53  
ComEd
   BSC $ 109   $ 100   $ 212   $ 200   51   61   111   124  
PECO
   BSC 68   61   133   120   19   28   40   54  
BGE
   BSC 71   63   137   125   20   32   41   65  
PHI
   BSC 58   49   116   100   28   41   58   80  
   PHISCO —   —   —   —   28   29   51   53  
Pepco
   BSC 37   32   72   63   12   17   25   34  
   PHISCO 35   32   67   62   12   12   22   23  

DPL
   BSC 23   20   45   40   9   12   18   24  
   PHISCO 27   26   51   50   8   9   15   16  

ACE
   BSC 19   16   36   32   6   9   13   18  
   PHISCO 25   24   51   47   7   8   14   14  

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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

Receivables from/Payables to Affiliates
The following tables present Receivables from affiliates and Payables to affiliates:
June 30, 2026

Receivables from affiliates:
Payables to affiliates: ComEd PECO BGE Pepco DPL ACE BSC PHISCO Other Total
ComEd $ —   $ —   $ —   $ —   $ —   $ 69   $ —   $ 6   $ 75  
PECO $ —   —   —   —   —   33   —   3   36  
BGE —   —   —   —   —   38   —   1   39  
PHI (a)
—   —   —   —   —   —   6   —   5   11  
Pepco —   —   —   —   —   22   18   1   41  
DPL —   —   —   —   —   14   13   1   28  
ACE —   —   —   —   —   11   11   1   23  

Other 5   —   —   —   4   1   —   —   10  
Total $ 5   $ —   $ —   $ —   $ 4   $ 1   $ 193   $ 42   $ 18   $ 263  

December 31, 2025

Receivables from affiliates:
Payables to affiliates: ComEd PECO BGE Pepco DPL ACE BSC PHISCO Other Total
ComEd $ —   $ —   $ —   $ —   $ —   $ 76   $ —   $ 5   $ 81  
PECO $ —   —   —   —   —   33   —   2   35  
BGE —   —   —   —   —   39   —   —   39  
PHI (a)
—   —   —   —   —   —   5   2   11   18  
Pepco —   —   —   —   —   25   11   1   37  
DPL —   —   —   —   —   15   10   —   25  
ACE —   —   —   —   —   14   10   —   24  
Other 5   —   1   —   2   12   —   —   20  
Total $ 5   $ —   $ 1   $ —   $ 2   $ 12   $ 207   $ 33   $ 19   $ 279  

__________
(a) PHI is presented exclusive of Pepco, DPL, and ACE, which are included in the table herein.
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:

June 30, 2026 December 31, 2025
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 six months ended June 30, 2026 compared to the same period in 2025. For additional information regarding the financial results for the three and six months ended June 30, 2026 and 2025, see the discussions of Results of Operations by Registrant.

Three Months Ended June 30, Favorable (Unfavorable) Variance Six Months Ended June 30, Favorable (Unfavorable) Variance
2026 2025 2026 2025
Exelon $ 396  $ 391  $ 5  $ 1,315  $ 1,300  $ 15 
ComEd 249  228  21  559  530  29 
PECO 119  136  (17) 397  402  (5)
BGE 55  55  —  353  315  38 
PHI 109  143  (34) 278  337  (59)
Pepco 65  84  (19) 133  181  (48)
DPL 26  39  (13) 103  108  (5)
ACE 22  24  (2) 49  56  (7)
Other (a)
(136) (171) 35  (272) (284) 12 

__________
(a) Other primarily includes eliminating and consolidating adjustments, Exelon’s corporate operations, shared service entities, and other financing and investment activities.
Three Months Ended June 30, 2026 Compared to Three Months Ended June 30, 2025. Net income attributable to common shareholders increased by $5 million and diluted earnings per average common share remained relatively consistent to the prior year at $0.39 primarily due to:
• Favorable impacts of approved rate increases at ComEd, BGE and PHI;
• Absence of Customer Relief Fund contribution at Exelon Corporate;
• Absence of Customer Surcharge Credits at PECO;
• Higher AFUDC at ComEd; and
• Favorable weather at PECO.
Note that rate increases are associated with updated recovery rates for costs and investments to serve customers. The increases were partially offset by:
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• Higher depreciation expense at PECO and PHI;
• Higher interest expense at PECO and Exelon Corporate; and
• Higher credit loss expense at BGE.
Six Months Ended June 30, 2026 Compared to Six Months Ended June 30, 2025. Net income attributable to common shareholders increased by $15 million and diluted earnings per average common share decreased to $1.28 in 2026 from $1.29 in 2025 primarily due to:
• Favorable impacts of approved rate increases at ComEd, BGE and PHI;
• Absence of Customer Relief Fund contribution at Exelon Corporate;
• Absence of Customer Surcharge Credits at PECO;
• Higher AFUDC at ComEd; and
• Favorable weather at PECO;
Note that rate increases are associated with updated recovery rates for costs and investments to serve customers, driving top quartile reliability and avoiding outage costs. The increases were partially offset by:
• Timing of distribution earnings at ComEd;
• Higher interest expense at PECO, PHI, and Exelon Corporate;
• Higher depreciation expense at PECO and PHI;
• Higher credit loss expense at BGE; and
• Unfavorable impacts of the Pepco Maryland multi-year plan reconciliation at PHI.
Adjusted (non-GAAP) operating earnings. In addition to Net income, Exelon evaluates its operating performance using the measure of Adjusted (non-GAAP) operating earnings because management believes it represents earnings directly related to the ongoing operations of the business. Adjusted (non-GAAP) operating earnings exclude certain costs, expenses, gains and losses, and other specified items. This information is intended to enhance an investor’s overall understanding of year-over-year operating results and provide an indication of Exelon’s baseline operating performance excluding items not considered by management to be directly related to the ongoing operations of the business. In addition, this information is among the primary indicators management uses as a basis for evaluating performance, allocating resources, setting incentive compensation targets, and planning and forecasting of future periods. Adjusted (non-GAAP) operating earnings is not a presentation defined under GAAP and may not be comparable to other companies’ presentations or deemed more useful than the GAAP information provided elsewhere in this report.
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The following table provides a reconciliation between GAAP Net income attributable to common shareholders and Adjusted (non-GAAP) operating earnings for the three and six months ended June 30, 2026 compared to the same period in 2025:

Three Months Ended June 30,
2026 2025
(In millions, except per share data) Earnings per
Diluted Share Earnings per
Diluted Share
Net income attributable to common shareholders $ 396   $ 0.39   $ 391   $ 0.39  

Cost management program (net of taxes of $16) (a)
42  0.04  —  — 
Income tax-related adjustments (entire amount represents tax expense) (b)
—  —  1  — 
Adjusted (non-GAAP) operating earnings $ 438   $ 0.43   $ 392   $ 0.39  

Six Months Ended June 30,
2026 2025
(In millions, except per share data) Earnings per
Diluted Share Earnings per
Diluted Share
Net income attributable to common shareholders $ 1,315   $ 1.28   $ 1,300   $ 1.29  

Change in FERC audit liability (net of taxes of $1)
—  —  2  — 

Cost management program (net of taxes of $16 and $0, respectively) (a)
42  0.04  (1) — 
Income tax-related adjustments (entire amount represents tax expense) (b)
—  —  1  — 
Regulatory matters (net of taxes of $4 and $7, respectively) (c)
11  0.01  22  0.02 

Adjusted (non-GAAP) operating earnings $ 1,368   $ 1.33   $ 1,324   $ 1.31  

__________
Note:
Amounts may not sum due to rounding.
Unless otherwise noted, the income tax impact of each reconciling item between GAAP Net income attributable to common shareholders and Adjusted (non-GAAP) operating earnings is based on the marginal statutory federal and state income tax rates for each Registrant, taking into account whether the income or expense item is taxable or deductible, respectively, in whole or in part. The marginal statutory income tax rates for 2026 and 2025 ranged from 24.0% to 29.0%.

(a) Primarily represents severance costs related to cost management program.
(b) Reflects the adjustment to state deferred income taxes due to changes in forecasted apportionment.
(c) Represents the disallowance of certain capitalized costs.

Significant 2026 Transactions and Developments
At-the-Market Program
In the second quarter of 2026, Exelon issued approximately 8.7 million shares of Common stock at a weighted-average net price of $44.03 per share. The net proceeds from the issuance were $382 million, which were used for general corporate purposes. See Note 12 — Shareholders' Equity of the Combined Notes to Consolidated Financial Statements for additional information.
Distribution Base Rate Case Proceedings
The Utility Registrants file base rate cases with their regulatory commissions seeking increases or decreases to their electric transmission and distribution, and gas distribution rates to recover their costs and earn a fair return on their investments. The outcomes of these regulatory proceedings impact the Utility Registrants’ current and future financial statements.
The following tables show the Utility Registrants’ completed and pending distribution base rate case proceedings in 2026. See Note 2 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.
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Completed Distribution Base Rate Case Proceedings

Registrant/Jurisdiction Filing Date Service Requested Revenue Requirement Increase Approved Revenue Requirement Increase Approved ROE Approval Date Rate Effective Date
ComEd - Illinois 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
September 20, 2024 (amended September 5, 2025) Natural Gas $ 37  $ 22  9.60% December 17, 2025 January 1, 2026
ACE - New Jersey November 21, 2024 Electric $ 109  $ 54  9.60% November 21, 2025 December 1, 2025

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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 (amended April 16, 2026) Electric $ 120  10.50% Third quarter of 2026
DPL - Delaware December 9, 2025 (amended June 1, 2026) Electric $ 45  10.50% Third quarter of 2027
BGE - Maryland July 2, 2026 Electric $ 156  10.40% First quarter of 2027

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

Registrant Initial Revenue Requirement Increase (Decrease) Annual Reconciliation (Decrease) Increase Total Revenue Requirement (Decrease) Increase Allowed Return on Rate Base Allowed ROE
ComEd $ 31  $ (52) $ (21) 8.15  % 11.50  %
PECO $ 20  $ 20  $ 40  7.62  % 10.35  %
BGE $ 16  $ (40) $ (30) 7.51  % 10.50  %
Pepco $ 12  $ (21) $ (9) 7.72  % 10.50  %
DPL $ 3  $ 1  $ 4  7.53  % 10.50  %
ACE $ 1  $ 16  $ 17  7.26  % 10.50  %

2026 PECO Distribution Base Rate Filing

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

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

Corporate Alternative Minimum Tax (All Registrants)
On August 16, 2022, the IRA was signed into law and implements a new corporate alternative minimum tax (CAMT) that imposes a 15.0% tax on modified GAAP net income. Corporations will now pay the greater of 15.0% of financial statement pre-tax income (with certain adjustments) or their regular federal tax liability, which is federal taxable income multiplied by the 21.0% federal corporate tax rate. Corporations are entitled to a tax credit (minimum tax credit) to the extent the CAMT liability exceeds the regular tax liability. This amount can be carried forward indefinitely and used in future years when regular tax exceeds the CAMT.
For the years ended December 31, 2025, December 31, 2024, and December 31, 2023, based on the existing guidance in effect at that time, Exelon and each of the Utility Registrants were subject to and reported the CAMT on a separate Registrant basis in the Consolidated Statements of Operations and Comprehensive Income and the Consolidated Balance Sheets.
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On February 18, 2026, the U.S. Treasury issued guidance addressing the implementation of CAMT in the form of a notice. The new guidance permits corporate taxpayers to deduct repair and maintenance costs in the calculation of their CAMT liabilities. The notice applies retroactively, permitting Exelon to file amended returns for both 2024 and 2023 to reduce its CAMT liability by $80 million. Pursuant to the TMA, Exelon received reimbursement from Constellation for $235 million due to the reduction in the amount of Constellation's tax credits needed to offset Exelon's CAMT liability on its amended returns. See Note 6 – Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information.
The impact of the notice was recorded as of March 31, 2026.

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

In May 2026, Exelon announced plans to identify approximately $350 million of operating and maintenance costs savings at Exelon and the Utility Registrants in 2027. This announcement is a result of Exelon’s continuous focus on the needs of our customers through enhanced efficiency and productivity.
Allocation of Income Taxes to Regulated Utilities (All Registrants)
In Q2 2024, the IRS issued a series of PLRs, to another taxpayer, providing guidance with respect to the application of the tax normalization rules to the allocation of consolidated tax benefits among the members of a consolidated group associated with NOLC for ratemaking purposes. The rulings provide that for ratemaking purposes the tax benefit of NOLC should be reflected on a separate company basis not taking into consideration the utilization of losses by other affiliates. A PLR issued to another taxpayer may not be relied on as precedent.
For the Utility Registrants, except for PECO, the methodology prescribed by the IRS in these PLRs could result in a material reduction of the regulatory liability established for EDITs arising from the TCJA corporate tax rate change that are being amortized and flowed through to customers as well as a reduction in the accumulated deferred income taxes included in rate base for ratemaking purposes of approximately $0.8 billion - $1.2 billion.
The Utility Registrants, except for PECO, filed PLR requests with the IRS confirming the treatment of the NOLC for ratemaking purposes. The Utility Registrants will record the impact, if any, upon receiving the PLR from the IRS.
Legislative and Regulatory Developments

Maryland Utility Relief Act (Exelon, BGE, PHI, Pepco, and DPL)
On May 12, 2026, the Governor of Maryland signed into law legislation that addresses several matters pertaining to electric and gas utilities, including a moratorium on rate cases with forecasted test years until April 1, 2027. Additionally, BGE, Pepco and DPL are required to participate as a member in an RTO effective July 1, 2026, which resulted in a complaint filed on July 2, 2026 against Maryland Transmission Operators, including BGE, Pepco, and DPL, at FERC for the removal of the 50-basis-point incentive adder in the transmission formula rates. The final outcome and resolution of the complaint filing cannot be predicted and the results are not expected to be material to Exelon, BGE, PHI, Pepco, and DPL financial statements.
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PJM Cost Allocation Methodology (All Registrants)
On March 6, 2026, FERC issued an order requiring the removal of the de minimis threshold exemption in the calculation of the cost responsibility of certain transmission reliability upgrade costs allocated to the rate zones of PJM Transmission Owners, including the Utility Registrants. FERC further ordered PJM to recalculate historical cost allocations for the period beginning June 18, 2015, and to pass through additional charges or payments to PJM customers, including Utility Registrants, as applicable, with interest within 90 days. On April 29, 2026, the time for those calculations was extended until further order from FERC. The Utility Registrants expect to recover any incremental charges incurred or reimburse any payments received through prospective electric customer rates. On April 6, 2026, a number of parties filed requests for rehearing or clarification, which were denied by operation of law on May 7, 2026. On May 12, 2026, PJM Transmission Owners, including Exelon, on behalf of the Utility Registrants, filed a petition for review at the United States Court of Appeals for the D.C. Circuit.
The final impacts of the decision cannot be predicted and the results, while not reasonably estimable at this time, could be material to the financial statements.
New Jersey Repeal RTO Adder Bill (Exelon, PHI, and ACE)
On July 7, 2026, the Governor of New Jersey signed into law legislation that addresses several matters pertaining to electric utility companies. As part of the legislation ACE is required to participate as a member in an RTO effective January 1, 2027, which could result in a complaint filed for the removal of the 50-basis-point incentive adder in the transmission formula rates.
Delaware Senate Bill 326 (Exelon, PHI, and DPL)
On July 13, 2026, the Governor of Delaware signed into law legislation that addresses several matters pertaining to public utility companies. As part of the law, DPL’s non-mandatory capital spend eligible to be recovered in rates will be limited to $70 million in each of the years ended 2026 and 2027 unless the spend falls within an exception or the commission orders otherwise. Further, beginning in 2028, DPL’s non-mandatory capital spend eligible to be recovered in rates shall not exceed 5% of DPL’s rate base approved in its most recent base rate case. The legislation also modifies the timing of interim rate recovery in base rate case proceedings. If the DEPSC has not issued a decision within 7 months of a filing, DPL may implement 50% of the proposed rate increase, subject to refund. If no decision has been issued after 12 months, DPL may implement 75% of the proposed increase, also subject to refund. DPL is continuing to evaluate the overall potential impacts of the legislation and will continue to monitor related regulatory developments.

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

Results of Operations — ComEd

Three Months Ended
June 30, Favorable (Unfavorable) Variance Six Months Ended
June 30, (Unfavorable) Favorable Variance
2026 2025 2026 2025
Operating revenues $ 1,985  $ 1,836  $ 149  $ 3,898  $ 3,901  $ (3)
Operating expenses
Purchased power 579  550  (29) 1,031  1,239  208 
Operating and maintenance 449  422  (27) 886  845  (41)
Depreciation and amortization 416  387  (29) 820  767  (53)
Taxes other than income taxes 107  97  (10) 212  196  (16)
Total operating expenses 1,551  1,456  (95) 2,949  3,047  98 

Operating income 434  380  54  949  854  95 
Other income and (deductions)
Interest expense, net (143) (131) (12) (279) (260) (19)
Other, net 41  31  10  73  53  20 
Total other income and (deductions) (102) (100) (2) (206) (207) 1 
Income before income taxes 332  280  52  743  647  96 
Income taxes 83  52  (31) 184  117  (67)
Net income $ 249  $ 228  $ 21  $ 559  $ 530  $ 29 

Three Months Ended June 30, 2026 Compared to Three Months Ended June 30, 2025. Net Income increased by $21 million as compared to the same period in 2025, primarily due to higher distribution and transmission rate base driven by incremental investments to serve customers and higher AFUDC.
Six Months Ended June 30, 2026 Compared to Six Months Ended June 30, 2025. Net income increased by $29 million as compared to the same period in 2025, primarily due to higher distribution and transmission rate base driven by incremental investments to serve customers and higher AFUDC, offset by the timing of distribution earnings.
The changes in Operating revenues consisted of the following:

Three Months Ended
June 30, 2026 Six Months Ended
June 30, 2026
Increase (Decrease) Increase (Decrease)
Distribution $ 24  $ 16 
Transmission 13  33 
Energy efficiency 14  22 
Other (8) (5)
43  66 
Regulatory required programs 106  (69)
Total increase (decrease) $ 149  $ (3)

Revenue Decoupling. The demand for electricity is affected by weather and customer usage. Operating revenues are not intended to be impacted by abnormal weather, usage per customer, or number of customers as a result of revenue decoupling mechanisms.
Distribution Revenue. Starting in 2024, distribution revenues are under a MRP. The MRP requires an annual reconciliation of the revenue requirement in effect to the actual costs the ICC determines are prudently and reasonably incurred. Electric distribution revenue varies from year to year based upon fluctuations in the underlying costs (e.g., severe weather and storm restoration), investments being recovered, and allowed ROE. Electric distribution revenues increased for the three and six months ended June 30, 2026 as compared to the same periods in 2025, primarily due to higher rate base and higher fully recoverable costs.
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Transmission Revenue. Under a FERC-approved formula, transmission revenue varies from year to year based upon fluctuations in the underlying costs and capital investments being recovered. Transmission revenues increased for the three and six months ended June 30, 2026 compared to the same periods in 2025, primarily due to higher rate base and higher fully recoverable costs.
Energy Efficiency Revenue. Energy efficiency revenues are under a performance-based formula rate, which requires an annual reconciliation of the revenue requirement in effect to the actual costs the ICC determines are prudently and reasonably incurred in a given year. Energy efficiency revenue varies from year to year based upon fluctuations in the underlying costs, investments being recovered, and allowed ROE. Energy efficiency revenues increased for the three and six months ended June 30, 2026 as compared to the same periods in 2025, primarily due to higher fully recoverable costs.
Other Revenue primarily includes assistance provided to other utilities through mutual assistance programs. Other revenues decreased for the three and six months ended June 30, 2026 as compared to the same periods in 2025, which primarily reflects decreased mutual assistance revenues associated with storm restoration efforts.
Regulatory Required Programs represents revenues collected under approved riders to recover costs incurred for regulatory programs. The riders are designed to provide full and current cost recovery. The costs of these programs are included in Purchased power expense, Operating and maintenance expense, Depreciation and amortization expense, and Taxes other than income taxes. Customers have the choice to purchase electricity from competitive electric generation suppliers. Customer choice programs do not impact the volume of deliveries as ComEd remains the distribution service provider for all customers and charges a regulated rate for distribution service, which is recorded in Operating revenues. For customers that choose to purchase electric generation from competitive suppliers, this is treated as a pass through for ComEd and therefore, financial results are not impacted if customers purchase electricity supply from these alternative suppliers. For customers that choose to purchase electric generation from ComEd, ComEd is permitted to recover costs from customers.
See Note 4 — Segment Information of the Combined Notes to Consolidated Financial Statements for the presentation of ComEd's revenue disaggregation.
The increase of $29 million for the three months ended June 30, 2026 and the decrease of $208 million for the six months ended June 30, 2026, compared to the same periods in 2025, in Purchased power expense is offset in Operating revenues as part of regulatory required programs.

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

Three Months Ended
June 30, 2026 Six Months Ended
June 30, 2026
Increase (Decrease) Increase (Decrease)
Labor, other benefits, contracting, and materials $ 19  $ 40 
Storm-related costs (3) 9 
BSC costs 9  12 
Pension and non-pension postretirement benefits expense 3  5 

Other (a)
(7) (39)
21  27 
Regulatory required programs 6  14 
Total increase $ 27  $ 41 
__________
(a) Primarily reflects the disallowance of certain capitalized costs in regulatory matters during the three months ended March 31, 2025.

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

Three Months Ended
June 30, 2026 Six Months Ended
June 30, 2026
Increase Increase
Depreciation and amortization (a)
$ 16  $ 31 
Regulatory asset amortization 13  22 

Total increase $ 29  $ 53 

__________
(a) Reflects ongoing capital expenditures.
Other , net increased $10 million and $20 million for the three and six months ended June 30, 2026, respectively, compared to the same periods in 2025, primarily due to higher AFUDC equity.
Effective income tax rat es were 25.0% and 18.6% for the three months ended June 30, 2026 and 2025, respectively, and 24.8% and 18.1% for the six months ended June 30, 2026 and 2025, respectively. See Note 6 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the effective income tax rates.
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Results of Operations — PECO

Three Months Ended
June 30, Favorable (Unfavorable) Variance Six Months Ended
June 30, Favorable (Unfavorable) Variance
2026 2025 2026 2025
Operating revenues $ 1,062  $ 1,000  $ 62  $ 2,554  $ 2,333  $ 221 
Operating expenses
Purchased power and fuel 389  339  (50) 1,001  841  (160)
Operating and maintenance 300  305  5  636  631  (5)
Depreciation and amortization 125  112  (13) 247  221  (26)
Taxes other than income taxes 62  54  (8) 131  115  (16)
Total operating expenses 876  810  (66) 2,015  1,808  (207)

Operating income 186  190  (4) 539  525  14 
Other income and (deductions)
Interest expense, net (72) (60) (12) (144) (124) (20)
Other, net 13  10  3  25  18  7 
Total other income and (deductions) (59) (50) (9) (119) (106) (13)
Income before income taxes 127  140  (13) 420  419  1 
Income taxes 8  4  (4) 23  17  (6)

Net income $ 119  $ 136  $ (17) $ 397  $ 402  $ (5)

Three Months Ended June 30, 2026 Compared to Three Months Ended June 30, 2025. Net Income decreased by $17 million due to an increase in depreciation, interest expense, tax repairs, a portion of which is timing, and severance costs related to the cost management program, partially offset by higher revenues resulting from the absence of surcharge credits to customers, and favorable weather.
Six Months Ended June 30, 2026 Compared to Six Months Ended June 30, 2025. Net income decreased by $5 million due to an increase in depreciation, interest expense, and severance costs related to the cost management program, partially offset by higher revenues resulting from the absence of surcharge credits to customers, and favorable weather.
The changes in Operating revenues consisted of the following:

Three Months Ended
June 30, 2026 Six Months Ended
June 30, 2026
Increase (Decrease) Increase (Decrease)
Electric Gas Total Electric Gas Total
Weather $ 6  $ (1) $ 5  $ 14  $ 7  $ 21 
Volume (7) 1  (6) (10) 2  (8)
Pricing (1) (1) (2) 4  —  4 
Transmission 4  —  4  16  —  16 
Other (a)
16  (1) 15  40  4  44 
18  (2) 16  64  13  77 
Regulatory required programs 43  3  46  122  22  144 
Total increase $ 61  $ 1  $ 62  $ 186  $ 35  $ 221 
__________
(a) Other revenues increased primarily due to the absence of electric surcharge credits to customers recognized in 2025.

Weather. The demand for electricity and natural gas is affected by weather conditions. With respect to the electric business, very warm weather in summer months and, with respect to the electric and natural gas businesses, very cold weather in winter months are referred to as “favorable weather conditions” because these weather conditions result in increased deliveries of electricity and natural gas. Conversely, mild weather reduces demand. During the three and six months ended June 30, 2026 , compared to the same period in 2025, Operating revenues related to weather increased due to favorable weather conditions in PECO's service territory.
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Heating and cooling degree-days are quantitative indices that reflect the demand for energy needed to heat or cool a home or business. Normal weather is determined based on historical average heating and cooling degree-days for a 30-year period in PECO's service territory. The changes in heating and cooling degree-days in PECO’s service territory for the three and six months ended June 30, 2026, compared to the same period in 2025, and normal weather consisted of the following:

Three Months Ended June 30, % Change
PECO Service Territory 2026 2025 Normal 2026 vs. 2025 2026 vs. Normal
Heating Degree-Days 321 333 415 (3.6) % (22.7) %
Cooling Degree-Days 526 425 387 23.8  % 35.9  %
Six Months Ended June 30, % Change
2026 2025 Normal 2026 vs. 2025 2026 vs. Normal
Heating Degree-Days 2,720  2,684 2,774 1.3  % (1.9) %
Cooling Degree-Days 536  426 388 25.8  % 38.1  %

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

Electric Retail Deliveries to Customers (in GWhs) Three Months Ended
June 30, % Change Weather -
Normal
% Change (b)
Six Months Ended June 30, % Change Weather -
Normal
% Change (b)

2026 2025 2026 2025
Residential 3,042 3,030 0.4  % (1.8) % 6,994 6,889 1.5  % (0.7) %
Small commercial & industrial 1,742 1,832 (4.9) % (3.6) % 3,752 3,778 (0.7) % (1.2) %
Large commercial & industrial 3,426 3,314 3.4  % 2.4  % 6,558 6,739 (2.7) % (3.9) %
Public authorities & electric railroads 157 163 (3.7) % (3.6) % 333 352 (5.4) % (5.4) %
Total electric retail deliveries (a)
8,367 8,339 0.3  % (0.5) % 17,637 17,758 (0.7) % (2.1) %

At June 30,
Number of Electric Customers 2026 2025
Residential 1,540,384 1,538,280
Small commercial & industrial 154,463 154,977
Large commercial & industrial 3,141 3,155
Public authorities & electric railroads 10,133 10,343
Total 1,708,121 1,706,755

__________
(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
June 30, % Change Weather -
Normal
% Change (b)
Six Months Ended
June 30, % Change Weather -
Normal
% Change (b)

2026 2025 2026 2025
Residential 4,525 4,571 (1.0) % 1.9  % 26,961 26,405 2.1  % (-0.4)%
Small commercial & industrial 3,072 3,398 (9.6) % (9.0) % 14,423 13,803 4.5  % 2.3  %
Large commercial & industrial 1 2 (50.0) % 2.3  % (9) 14 (164.3) % (10.5) %
Transportation 6,578 5,436 21.0  % 25.6  % 13,720 12,678 8.2  % 9.2  %
Total natural gas deliveries (a)
14,176 13,407 5.7  % 8.1  % 55,095 52,900 4.1  % 2.5  %

  At June 30,
Number of Natural Gas Customers 2026 2025
Residential 511,121 509,671
Small commercial & industrial 44,494 44,646
Large commercial & industrial 7 7
Transportation 605 623
Total 556,227 554,947

__________
(a) Reflects delivery volumes from customers purchasing natural gas directly from PECO and customers purchasing natural gas from a competitive natural gas supplier as all customers are assessed distribution charges.
(b) Reflects the change in delivery volumes assuming normalized weather based on the historical 30-year average.
Pricing for the three and six months ended June 30, 2026, compared to the same period in 2025, remained relatively consistent.
Transmission Revenue. Under a FERC-approved formula, transmission revenue varies from year to year based upon fluctuations in the underlying costs and capital investments being recovered. Transmission revenue for the three and six months ended June 30, 2026, compared to the same period in 2025, increased primarily due to increases in the underlying costs and capital investments.
Other Revenue primarily includes revenue related to late payment charges. Other revenue for the three and six months ended June 30, 2026, compared to the same period in 2025, increased primarily due to the absence of electric surcharge credits to customers recognized in 2025.
Regulatory Required Programs represent revenues collected under approved riders to recover costs incurred for regulatory programs. The riders are designed to provide full and current cost recovery as well as a return in certain instances. The costs of these programs are included in Purchased power and fuel expense, Operating and maintenance expense, Depreciation and amortization expense, and Income taxes. Customers have the choice to purchase electricity and natural gas from competitive electric generation and natural gas suppliers. Customer choice programs do not impact the volume of deliveries as PECO remains the distribution service provider for all customers and charges a regulated rate for distribution service. For customers that choose to purchase electric generation or natural gas from competitive suppliers, this is treated as a pass through for PECO and therefore, financial results are not impacted if customers purchase electricity or natural gas supply from these alternative suppliers. For customers that choose to purchase electric generation or natural gas from PECO, PECO is permitted to recover costs from customers.
See Note 4 — Segment Information of the Combined Notes to Consolidated Financial Statements for the presentation of PECO's revenue disaggregation.
The increase of $50 million and $160 million for the three and six months ended June 30, 2026, compared to the same period in 2025, in Purchased power and fuel expense is fully offset in Operating revenues as part of regulatory required programs.

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PECO

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

Three Months Ended
June 30, 2026 Six Months Ended
June 30, 2026
Increase (Decrease) Increase (Decrease)
Labor, other benefits, contracting and materials (a)
$ 29  $ 45 
BSC costs 8  13 
Pension and non-pension postretirement benefit expense 1  3 
Credit loss expense (2) (4)
Storm-related costs (32) (39)
Other —  15 
4  33 
Regulatory required programs (9) (28)
Total (decrease) increase $ (5) $ 5 

__________
(a) Reflects severance related to cost management program
The changes in Depreciation and amortization expense consisted of the following:

Three Months Ended June 30, 2026 Six Months Ended
June 30, 2026
Increase Increase (Decrease)
Depreciation and amortization (a)
$ 13  $ 27 
Regulatory asset amortization —  (1)

Total increase $ 13  $ 26 

__________
(a) Depreciation and amortization expense increased primarily due to ongoing capital expenditures.
Taxes other than income taxes increased by $8 million and $16 million for the three and six months ended June 30, 2026, respectively, compared to the same period in 2025, primarily due to higher Pennsylvania gross receipts tax.
Interest expense, net increased by $12 million and $20 million for the three and six months ended June 30, 2026, respectively, compared to the same period in 2025, primarily due to an increase in interest rates and higher outstanding debt.
Effective income tax rates were 6.3% and 2.9% for the three months ended June 30, 2026 and 2025, respectively, and 5.5% and 4.1% for the six months ended June 30, 2026 and 2025, respectively. See Note 6 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the effective income tax rates.
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BGE

Results of Operations — BGE

Three Months Ended
June 30, Favorable (Unfavorable) Variance Six Months Ended
June 30, Favorable (Unfavorable) Variance
2026 2025 2026 2025
Operating revenues $ 1,218  $ 1,029  $ 189  $ 3,046  $ 2,583  $ 463 
Operating expenses
Purchased power and fuel 545  406  (139) 1,353  1,016  (337)
Operating and maintenance 293  264  (29) 619  568  (51)
Depreciation and amortization 166  154  (12) 334  318  (16)
Taxes other than income taxes 96  85  (11) 200  181  (19)
Total operating expenses 1,100  909  (191) 2,506  2,083  (423)

Operating income 118  120  (2) 540  500  40 
Other income and (deductions)
Interest expense, net (68) (61) (7) (129) (120) (9)
Other, net 22  11  11  38  20  18 
Total other income and (deductions) (46) (50) 4  (91) (100) 9 
Income before income taxes 72  70  2  449  400  49 
Income taxes 17  15  (2) 96  85  (11)
Net income $ 55  $ 55  $ —  $ 353  $ 315  $ 38 

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

Three Months Ended
June 30, Six Months Ended
June 30,
Increase (Decrease) Increase (Decrease)
Electric Gas Total Electric Gas Total
Distribution $ 11  $ 7  $ 18  $ 15  $ 29  $ 44 
Transmission 3  —  3  1  —  1 
Other 4  —  4  13  2  15 
18  7  25  29  31  60 
Regulatory required programs 183  (19) 164  406  (3) 403 
Total increase $ 201  $ (12) $ 189  $ 435  $ 28  $ 463 

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 June 30,
Number of Electric Customers 2026 2025
Residential 1,230,523  1,219,904 
Small commercial & industrial 114,986  115,316 
Large commercial & industrial 13,430  13,345 
Public authorities & electric railroads 250  257 
Total 1,359,189  1,348,822 

At June 30,
Number of Natural Gas Customers 2026 2025
Residential 664,257  660,049 
Small commercial & industrial 37,638  37,806 
Large commercial & industrial 6,406  6,387 

Total 708,301  704,242 

Distribution Revenue increased for the three and six months ended June 30, 2026, compared to the same period in 2025, due to favorable impacts of the multi-year plans.
Transmission Revenue. Under a FERC-approved formula, transmission revenue varies from year to year based upon fluctuations in the underlying costs and capital investments being recovered. Transmission revenue for the three and six months ended June 30, 2026, compared to the same period in 2025 remained relatively consistent.
Other Revenue includes revenue related to late payment charges, mutual assistance, off-system sales, and service application fees. Other Revenue increased for the three and six months ended June 30, 2026 as compared to the same period in 2025, primarily driven by increases in late payment charges.
Regulatory Required Programs represent revenues collected under approved riders to recover costs incurred for regulatory programs. The riders are designed to provide full and current cost recovery as well as a return in certain instances. The costs of these programs are included in Purchased power and fuel expense, Operating and maintenance expense, Depreciation and amortization expense, and Taxes other than income taxes. Customers have the choice to purchase electricity and natural gas from competitive electric generation and natural gas suppliers. Customer choice programs do not impact the volume of deliveries as BGE remains the distribution service provider for all customers and charges a regulated rate for distribution service. For customers that choose to purchase electric generation or natural gas from competitive suppliers, this is treated as a pass through for BGE and therefore, financial results are not impacted if customers purchase electricity or natural gas supply from these alternative suppliers. For customers that choose to purchase electric generation or natural gas from BGE, BGE is permitted to recover costs from customers.
See Note 4 — Segment Information of the Combined Notes to Consolidated Financial Statements for the presentation of BGE's revenue disaggregation.
The increase of $139 million and $337 million for the three and six months ended June 30, 2026, compared to the same period in 2025, in Purchased power and fuel expense is fully offset in Operating revenues as part of regulatory required programs.

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BGE

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

Three Months Ended
June 30, 2026 Six Months Ended
June 30, 2026
  Increase (Decrease) Increase (Decrease)
Credit loss expense $ 25  $ 36 
BSC costs 8  11 
Storm-related costs (4) (4)
Pension and non-pension postretirement benefits expense (5) (10)
Labor, other benefits, contracting and materials (a)
(1) (17)
Other (b)
(19) (18)
4  (2)
Regulatory required programs (c)
25  53 

Total increase $ 29  $ 51 

__________
(a) Reflects severance related to cost management program.
(b) Reflects the absence of the derecognition of regulatory assets for multi-year plan reconciliations that occurred during the second quarter of 2025. Please refer to 2025 10-K Note 2 — Regulatory Matters for additional information.
(c) Reflects the cost recovery associated with EmPOWER Maryland. Please refer to 2025 10-K Note 2 — Regulatory Matters for additional information.
The changes in Depreciation and amortization expense consisted of the following:

Three Months Ended
June 30, 2026 Six Months Ended
June 30, 2026
Increase Increase (Decrease)
Depreciation and amortization $ 8  $ 18 
Regulatory required programs (a)
3  6 
Regulatory asset amortization 1  (8)

Total increase $ 12  $ 16 

__________
(a) Reflects the cost recovery associated with EmPOWER Maryland. Please refer to 2025 10-K Note 2 — Regulatory Matters for additional information.
Taxes other than income taxes increased by $11 million and $19 million for the three and six months ended June 30, 2026, compared to the same period in 2025, primarily due to increased property taxes.
Other, net increased by $11 million and $18 million for the three and six months ended June 30, 2026 compared to the same period in 2025, primarily due to higher AFUDC equity.
Effective income tax rates were 23.6% and 21.4% for the three months ended June 30, 2026 and 2025, and 21.4% and 21.3% for the six months ended June 30, 2026 and 2025. See Note 6 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the effective income tax rates.
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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 six months ended June 30, 2026 compared to the same periods in 2025. See the Results of Operations for Pepco, DPL, and ACE for additional information.

Three Months Ended
June 30, Unfavorable Variance Six Months Ended June 30, (Unfavorable) Favorable Variance
2026 2025 2026 2025
PHI $ 109  $ 143  $ (34) $ 278  $ 337  $ (59)
Pepco 65  84  (19) 133  181  (48)
DPL
26  39  (13) 103  108  (5)
ACE 22  24  (2) 49  56  (7)
Other (a)
(4) (4) —  (7) (8) 1 

__________
(a) Primarily includes eliminating and consolidating adjustments, PHI's corporate operations, shared service entities, and other financing and investing activities.
Three Months Ended June 30, 2026 Compared to Three Months Ended June 30, 2025. Net Income decreased by $34 million primarily due to an increase in severance costs related to the cost management program, depreciation expense, property taxes at DPL, and various operating expenses, partially offset by approved Delaware electric DSIC and natural gas rates.
Six Months Ended June 30, 2026 Compared to Six Months Ended June 30, 2025. Net Income decreased by $59 million primarily due to an increase in depreciation and interest expenses, property taxes at DPL, unfavorable impacts of the Pepco Maryland multi-year plan reconciliation and related disallowance of capitalized costs, severance costs related to the cost management program, storm costs, and various operating expenses, partially offset by approved Delaware electric DSIC and natural gas rates, approved distribution and transmission rates, and favorable weather conditions at DPL.
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Pepco

Results of Operations — Pepco

Three Months Ended June 30, Favorable (Unfavorable) Variance Six Months Ended June 30, Favorable (Unfavorable) Variance
2026 2025 2026 2025
Operating revenues $ 859  $ 776  $ 83  $ 1,849  $ 1,635  $ 214 

Operating expenses
Purchased power 316  256  (60) 727  574  (153)
Operating and maintenance 190  155  (35) 409  313  (96)
Depreciation and amortization 114  107  (7) 228  212  (16)
Taxes other than income taxes 113  109  (4) 231  222  (9)
Total operating expenses 733  627  (106) 1,595  1,321  (274)
(Loss) gain on sale of assets —  2  (2) —  1  (1)
Operating income 126  151  (25) 254  315  (61)
Other income and (deductions)
Interest expense, net (56) (54) (2) (111) (106) (5)
Other, net 12  9  3  23  20  3 
Total other income and (deductions) (44) (45) 1  (88) (86) (2)
Income before income taxes 82  106  (24) 166  229  (63)
Income taxes 17  22  5  33  48  15 
Net income $ 65  $ 84  $ (19) $ 133  $ 181  $ (48)

Three Months Ended June 30, 2026 Compared to Three Months Ended June 30, 2025. Net Income decreased by $19 million primarily due to increases in severance costs related to the cost management program, depreciation, and various operating expenses.
Six Months Ended June 30, 2026 Compared to Six Months Ended June 30, 2025. Net Income decreased by $48 million primarily due to unfavorable impacts of the Pepco Maryland multi-year plan reconciliation and related disallowance of capitalized costs, increases in depreciation expense, severance costs related to the cost management program, interest, and various operating expenses.
The changes in Operating revenues consisted of the following:

Three Months Ended
June 30, 2026 Six Months Ended
June 30, 2026
Increase (Decrease) Increase
Distribution $ 7  $ 9 
Transmission 2  5 
Other (3) 3 
6  17 
Regulatory required programs 77  197 
Total increase $ 83  $ 214 

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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Pepco

At June 30,
Number of Electric Customers in Maryland 2026 2025
Residential 561,146  558,254 
Small commercial & industrial 30,546  30,512 
Large commercial & industrial 19,083  19,064 
Public authorities & electric railroads 181  177 
Total 610,956  608,007 

Distribution Revenue increased for the three and six months ended June 30, 2026 compared to the same periods in 2025 primarily due to favorable impacts of the District of Columbia multi-year plans and customer growth in Maryland.
Transmission Revenue. Under a FERC-approved formula, transmission revenue varies from year to year based upon fluctuations in the underlying costs and capital investments being recovered. Transmission revenue increased for the three and six months ended June 30, 2026, compared to the same periods in 2025, primarily due to increases in underlying costs and capital investments.
Other Revenue includes rental revenue, revenue related to late payment charges, mutual assistance revenues, and recoveries of other taxes.
Regulatory Required Programs represent revenues collected under approved riders to recover costs incurred for regulatory programs. The riders are designed to provide full and current cost recovery as well as a return in certain instances. The costs of these programs are included in Purchased power expense, Operating and maintenance expense, Depreciation and amortization expense, and Taxes other than income taxes. Customers have the choice to purchase electricity from competitive electric generation suppliers. Customer choice programs do not impact the volume of deliveries as Pepco remains the distribution service provider for all customers and charges a regulated rate for distribution service. For customers that choose to purchase electric generation from competitive suppliers, this is treated as a pass through for Pepco and therefore, financial results are not impacted if customers purchase electricity supply from these alternative suppliers. For customers that choose to purchase electric generation from Pepco, Pepco is permitted to recover the costs from customers.
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 $60 million and $153 million for the three and six months ended June 30, 2026, respectively, compared to the same periods in 2025, in Purchased power expense is fully offset in Operating revenues as part of regulatory required programs.
The changes in Operating and maintenance expense consisted of the following:

Three Months Ended
June 30, 2026 Six Months Ended
June 30, 2026
(Decrease) Increase Increase (Decrease)
Maryland multi-year plan reconciliation (a)
$ —  $ 26 
Labor, other benefits, contracting, and materials (b)
14 25
BSC and PHISCO costs 9 13
Credit loss expense (3) (3)
Pension and non-pension postretirement benefits expense —  (1)
Storm-related costs (3) (1)
Other 4  2 
21  61 

Regulatory required programs (c)
14  35 
Total increase $ 35  $ 96 
________ _
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Pepco

(a) Reflects unfavorable impacts of the Pepco Maryland multi-year plan reconciliation. See Note 2 — Regulatory Matters for additional information.
(b) Reflects severance related to cost management program.
(c) Reflects the cost recovery associated with EmPOWER Maryland. Please refer to 2025 10-K Note 2 — Regulatory Matters for additional information.

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

Three Months Ended
June 30, 2026 Six Months Ended
June 30, 2026
Increase (Decrease) Increase
Depreciation and amortization (a)
$ 6  $ 12 
Regulatory asset amortization (1) — 
Regulatory required programs (b)
2  4 
Total increase $ 7  $ 16 

__________
(a) Depreciation and amortization increased primarily due to ongoing capital expenditures.
(b) Reflects the cost recovery associated with EmPOWER Maryland. Please refer to 2025 10-K Note 2 — Regulatory Matters additional information.
Taxes other than income taxes increased $4 million and $9 million for the three and six months ended June 30, 2026, respectively, compared to the same period 2025, primarily due to increases in utility taxes and property taxes.
Effective income tax rates were 20.7% and 20.8% for the three months ended June 30, 2026 and 2025, respectively, and 19.9% and 21.0% for the six months ended June 30, 2026 and 2025, respectively. See Note 6 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the effective income tax rates.
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DPL

Results of Operations — DPL

Three Months Ended June 30, Favorable (Unfavorable) Variance Six Months Ended June 30, Favorable (Unfavorable) Variance
2026 2025 2026 2025
Operating revenues $ 454  $ 421  $ 33  $ 1,076  $ 969  $ 107 
Operating expenses
Purchased power and fuel 195  172  (23) 483  419  (64)
Operating and maintenance 112  95  (17) 231  201  (30)
Depreciation and amortization 67  63  (4) 133  126  (7)
Taxes other than income taxes 24  20  (4) 50  41  (9)
Total operating expenses 398  350  (48) 897  787  (110)

Operating income 56  71  (15) 179  182  (3)
Other income and (deductions)
Interest expense, net (26) (25) (1) (53) (50) (3)
Other, net 4  4  —  8  8  — 
Total other income and (deductions) (22) (21) (1) (45) (42) (3)
Income before income taxes 34  50  (16) 134  140  (6)
Income taxes 8  11  3  31  32  1 
Net income $ 26  $ 39  $ (13) $ 103  $ 108  $ (5)

Three Months Ended June 30, 2026 Compared to Three Months Ended June 30, 2025. Net income decreased by $13 million primarily due to an increase in depreciation expense, severance costs related to the cost management program, and property taxes, partially offset by approved Delaware electric DSIC and natural gas rates.
Six Months Ended June 30, 2026 Compared to Six Months Ended June 30, 2025 . Net income decreased by $5 million primarily due to an increase in property taxes, depreciation expense, severance costs related to the cost management program, storm costs and interest expense, partially offset by approved Delaware electric DSIC and natural gas rates, and favorable weather conditions at Delaware electric and natural gas service territories.
The changes in Operating revenues consisted of the following:

Three Months Ended
June 30, 2026 Six Months Ended
June 30, 2026
(Decrease) Increase Increase (Decrease)
Electric Gas Total Electric Gas Total
Weather $ —  $ —  $ —  $ 2  $ 2  $ 4 
Volume —  (1) (1) 1  (1) — 
Distribution 2  —  2  8  10  18 
Transmission 3  —  3  5  —  5 
Other —  —  —  —  1  1 
5  (1) 4  16  12  28 
Regulatory required programs 21  8  29  54  25  79 
Total increase $ 26  $ 7  $ 33  $ 70  $ 37  $ 107 

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.
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DPL

Weather. The demand for electricity and natural gas in Delaware is affected by weather conditions. With respect to the electric business, very warm weather in summer months and, with respect to the electric and natural gas businesses, very cold weather in winter months are referred to as "favorable weather conditions” because these weather conditions result in increased deliveries of electricity and natural gas. Conversely, mild weather reduces demand. During the three months ended June 30, 2026 compared to the same period in 2025, Operating revenues related to weather remained relatively consistent. During the six months ended June 30, 2026 compared to the same period in 2025, Operating revenues related to weather increased due to favorable weather conditions in 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 six months ended June 30, 2026, compared to same periods in 2025 and normal weather consisted of the following:

Three Months Ended June 30, % Change
Delaware Electric Service Territory 2026 2025 Normal 2026 vs. 2025 2026 vs. Normal
Heating Degree-Days 376  373  439  0.8  % (14.4) %
Cooling Degree-Days 404  390  349  3.6  % 15.8  %

Six Months Ended June 30, % Change
Delaware Electric Service Territory 2026 2025 Normal 2026 vs. 2025 2026 vs. Normal
Heating Degree-Days 2,906  2,771  2,844  4.9  % 2.2  %
Cooling Degree-Days 412  399  350  3.3  % 17.7  %

Three Months Ended June 30, % Change
Delaware Natural Gas Service Territory 2026 2025 Normal 2026 vs. 2025 2026 vs. Normal
Heating Degree-Days 376  373  476  0.8  % (21.0) %

Six Months Ended June 30, % Change
Delaware Natural Gas Service Territory 2026 2025 Normal 2026 vs. 2025 2026 vs. Normal
Heating Degree-Days 2,906  2,771  2,925  4.9  % (0.6) %

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

Electric Retail Deliveries to Delaware Customers (in GWhs) Three Months Ended
June 30, % Change Weather - Normal
% Change (b)
Six Months Ended
June 30, % Change Weather - Normal
% Change (b)

2026 2025 2026 2025
Residential 692  675  2.5  % 3.0  % 1,666  1,605  3.8  % 1.9  %
Small commercial & industrial 354  369  (4.1) % (3.8) % 721  723  (0.3) % (1.0) %
Large commercial & industrial 754  766  (1.6) % (1.3) % 1,441  1,456  (1.0) % (1.1) %
Public authorities & electric railroads (16) 9  (277.8) % (287.3) % (10) 15  (166.7) % (163.3) %
Total electric retail deliveries (a)
1,784  1,819  (1.9) % (1.6) % 3,818  3,799  0.5  % (0.5) %

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DPL

At June 30,
Number of Total Electric Customers (Maryland and Delaware) 2026 2025
Residential 496,515  492,999 
Small commercial & industrial 65,710  65,177 
Large commercial & industrial 1,295  1,253 
Public authorities & electric railroads 626  628 
Total 564,146  560,057 

__________
(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
June 30, % Change Weather - Normal
% Change (b)
Six Months Ended
June 30, % Change Weather - Normal
% Change (b)

2026 2025 2026 2025
Residential 729  803  (9.2) % (8.8) % 5,407  5,393  0.3  % (3.4) %
Small commercial & industrial 482  535  (9.9) % (10.0) % 2,606  2,502  4.2  % —  %
Large commercial & industrial 400  405  (1.2) % (1.3) % 833  837  (0.5) % (0.5) %
Transportation 1,270  1,282  (0.9) % (1.3) % 3,297  3,387  (2.7) % (4.3) %
Total natural gas deliveries (a)
2,881  3,025  (4.8) % (5.1) % 12,143  12,119  0.2  % (2.7) %

At June 30,
Number of Delaware Natural Gas Customers 2026 2025
Residential 131,951  131,332 
Small commercial & industrial 10,207  10,146 
Large commercial & industrial 14  14 
Transportation 160  161 
Total 142,332  141,653 

__________
(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 remained relatively consistent for the three months ended June 30, 2026 compared to the same period in 2025. During the six months ended June 30, 2026, compared to the same period in 2025, distribution revenue increased primarily due to Delaware natural gas rates that became effective in 2025 & electric DSIC rates that became effective in 2026.
Transmission Revenue. Under a FERC-approved formula, transmission revenue varies from year to year based upon fluctuations in the underlying costs and capital investments being recovered. During the three and six months ended June 30, 2026 compared to the same period in 2025, transmission revenue increased due to increases in underlying costs and capital investments.
Other Revenue includes rental revenue, service connection fees, and mutual assistance revenues.
Regulatory Required Programs represent revenues collected under approved riders to recover costs incurred for regulatory programs. The riders are designed to provide full and current cost recovery as well as a return in certain instances. All customers have the choice to purchase electricity from competitive electric generation suppliers; however, only certain commercial and industrial customers have the choice to purchase natural gas from competitive natural gas suppliers. Customer choice programs do not impact the volume of deliveries as DPL remains the distribution service provider for all customers and charges a regulated rate for distribution service. For customers that choose to purchase electric generation or natural gas from competitive suppliers, this is treated as a pass through for DPL and therefore, financial results are not impacted if customers purchase electricity or natural gas supply from these alternative suppliers. For customers that choose to purchase electric generation or natural gas from DPL, DPL is permitted to recover costs from customers.
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DPL

See Note 4 — Segment Information of the Combined Notes to Consolidated Financial Statements for the presentation of DPL's revenue disaggregation.
The decrease of $23 million and $64 million for the three and six months ended June 30, 2026, respectively, compared to the same periods in 2025 in Purchased power and fuel expense is fully offset in Operating revenues as part of regulatory required programs.
The changes in Operating and maintenance expense consisted of the following:

Three Months Ended
June 30, 2026 Six Months Ended
June 30, 2026
Increase (Decrease) Increase (Decrease)
Labor, other benefits, contracting, and materials (a)
$ 9  $ 12 
BSC and PHISCO costs
5  5 
Storm-related costs
(2) 3 
Credit loss expense (1) (3)

Other
1  2 
12  19 
Regulatory required programs (b)
5  11 
Total increase $ 17  $ 30 

__________
(a) Reflects severance related to the cost management program.
(b) Reflects the cost recovery associated with EmPOWER Maryland. Please refer to 2025 10-K Note 2 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.
The changes in Depreciation and amortization expense consisted of the following:

Three Months Ended
June 30, 2026 Six Months Ended
June 30, 2026
Increase Increase (Decrease)
Depreciation and amortization (a)
$ 4  $ 7 
Regulatory asset amortization —  (1)
Regulatory required programs (b)
—  1 
Total increase $ 4  $ 7 

__________
(a) Depreciation and amortization increased primarily due to ongoing capital expenditures.
(b) Reflects the cost recovery associated with EmPOWER Maryland. Please refer to 2025 10-K Note 2 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information

Taxes other than income taxes increased by $4 million and $9 million for the three and six months ended June 30, 2026, respectively, compared to the same periods in 2025 primarily due to an increase in property taxes.
Effective income tax rates were 23.5% and 22.0% for the three months ended June 30, 2026 and 2025, respectively, and 23.1% and 22.9% for the six months ended June 30, 2026 and 2025, respectively. See Note 6 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the effective income tax rates.
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ACE

Results of Operations — ACE

Three Months Ended June 30, Favorable (Unfavorable) Variance Six Months Ended June 30, Favorable (Unfavorable) Variance
2026 2025 2026 2025
Operating revenues $ 401  $ 384  $ 17  $ 822  $ 757  $ 65 

Operating expenses
Purchased power 187  173  (14) 392  329  (63)
Operating and maintenance 99  95  (4) 192  185  (7)
Depreciation and amortization 63  62  (1) 128  127  (1)
Taxes other than income taxes 3  3  —  5  5  — 
Total operating expenses 352  333  (19) 717  646  (71)

Operating income 49  51  (2) 105  111  (6)
Other income and (deductions)
Interest expense, net (22) (20) (2) (44) (41) (3)
Other, net 3  2  1  5  6  (1)
Total other income and (deductions) (19) (18) (1) (39) (35) (4)
Income before income taxes 30  33  (3) 66  76  (10)
Income taxes 8  9  1  17  20  3 
Net income $ 22  $ 24  $ (2) $ 49  $ 56  $ (7)

Three Months Ended June 30, 2026 Compared to Three Months Ended June 30, 2025 . Net income decreased by $2 million primarily due to an increase in severance costs related to the cost management program, partially offset by an increase in approved distribution and transmission rates.

Six Months Ended June 30, 2026 Compared to Six Months Ended June 30, 2025 . Net income decreased by $7 million primarily due to an increase in depreciation and interest expense, storm costs, and severance costs related to the cost management program, partially offset by an increase in approved distribution and transmission rates.
The changes in Operating revenues consisted of the following:

Three Months Ended
June 30, 2026 Six Months Ended
June 30, 2026
Increase Increase
Distribution $ 8  $ 7 
Transmission 6  9 
Other —  — 
14  16 
Regulatory required programs 3  49 
Total increase $ 17  $ 65 

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 June 30,
Number of Electric Customers 2026 2025
Residential 511,568  508,775 
Small commercial & industrial 63,070  62,817 
Large commercial & industrial 2,665  2,803 
Public authorities & electric railroads 767  729 
Total 578,070  575,124 

Distribution Revenue increased for the three and six months ended June 30, 2026 compared to the same periods in 2025 due to approved distribution rates that became effective in December 2025 as well as an increase in customer growth.
Transmission Revenues Under a FERC-approved formula, transmission revenue varies from year to year based upon fluctuations in the underlying costs and capital investments being recovered. Transmission revenue increased for the three and six months ended June 30, 2026 compared to the same periods in 2025 primarily due to increases in underlying costs and capital investment.
Other Revenue includes rental revenue, revenue related to late payment charges, mutual assistance revenues, and recoveries of other taxes.
Regulatory Required Programs represent revenues collected under approved riders to recover costs incurred for regulatory programs. The riders are designed to provide full and current cost recovery as well as a return in certain instances. Customers have the choice to purchase electricity from competitive electric generation suppliers. Customer choice programs do not impact the volume of deliveries as ACE remains the distribution service provider for all customers and charges a regulated rate for distribution service. For customers that choose to purchase electric generation from competitive suppliers, this is treated as a pass through for ACE and therefore, financial results are not impacted if customers purchase electricity supply from these alternative suppliers. For customers that choose to purchase electric generation from ACE, ACE is permitted to recover costs from customers.
See Note 4 — Segment Information of the Combined Notes to Consolidated Financial Statements for the presentation of ACE's revenue disaggregation.
The increase of $14 million and $63 million for the three and six months ended June 30, 2026, respectively, compared to the same periods in 2025 in Purchased power expense is fully offset in Operating revenues as part of regulatory required programs.
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ACE

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

Three Months Ended
June 30, 2026 Six Months Ended
June 30, 2026
Increase (Decrease) Increase (Decrease)
Labor, other benefits, contracting, and materials (a)
$ 8  $ 6 
BSC and PHISCO costs 3  4 
Storm-related costs (1) 3 
Pension and non-pension postretirement benefits expense —  (1)
Credit Loss Expense —  (2)
Other —  2 
10  12 

Regulatory required programs (6) (4)
Total increase $ 4  $ 8 
________ _
(a) Reflects severance related to cost management program.
The changes in Depreciation and amortization expense consisted of the following:

Three Months Ended
June 30, 2026 Six Months Ended
June 30, 2026
Increase (Decrease) Increase (Decrease)
Depreciation and amortization (a)
$ 4  $ 5 
Regulatory asset amortization 4  8 
Regulatory required programs (7) (12)
Total increase $ 1  $ 1 

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

Effective income tax rates were 26.7% and 27.3% for the three months ended June 30, 2026 and 2025, respectively, and 25.8% and 26.3% for the six months ended June 30, 2026 and 2025, respectively. See Note 6 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the effective income tax rates.
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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 2 — Regulatory Matters of the 2025 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 six months ended June 30, 2026 and 2025 by Registrant:

Increase in cash flows from operating activities Exelon ComEd PECO BGE   PHI Pepco DPL ACE
Net income (loss) $ 15  $ 29  $ (5) $ 38  $ (59) $ (48) $ (5) $ (7)
Adjustments to reconcile net income to cash:
Non-cash operating activities 109  (113) 334  161  99  56  19  38 

Collateral received, net 58  84  (6) (7) (14) (2) (4) (9)
Income taxes (137) (11) (280) (175) (3) 19  (12) (9)
Pension and non-pension postretirement benefit contributions (54) (32) (4) (7) (11) 2  —  (12)
Regulatory assets and liabilities, net (580) (704) (72) 106  85  39  18  25 
Changes in working capital and other assets and liabilities 1,547  1,227  48  (53) 152  87  53  (2)
Increase in cash flows from operating activities $ 958  $ 480  $ 15  $ 63  $ 249  $ 153  $ 69  $ 24 

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 changes in cash flows from operating activities were primarily due to the following:
• 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 six months ended June 30, 2026 to the six months ended June 30, 2025. 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 six months ended June 30, 2026. See Note 12 — Retirement Benefits of the 2025 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. ComEd recognized a reduction in regulatory liabilities of $670 million and an increase in regulatory assets of $150 million related to CMCs for the six months ended June 30, 2026 and a decrease in regulatory assets of $20 million related to CMCs for the six months ended June 30, 2025. Included within the change in 2026 are payments for CMC nuclear production tax credits, which relate to a decrease in Accounts Receivable. ComEd's energy efficiency program recognized changes of $206 million and $191 million for the six months ended June 30, 2026 and 2025, respectively. Additionally, ComEd recognized changes in the distributed generation rebates programs of $70 million and $35 million for the six months ended June 30, 2026 and 2025, respectively. Also included within the changes is energy efficiency and demand response
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programs spend for DPL and ACE of $2 million and $35 million for the six months ended June 30, 2026 and $7 million, and $16 million for the six months ended June 30, 2025, respectively. BGE and Pepco had no energy efficiency and demand response programs spend recorded to the regulatory asset for the six months ended June 30, 2026 and $41 million and $16 million for six months ended June 30, 2025. PECO had no energy efficiency and demand response programs spend recorded to the regulatory asset for the six months ended June 30, 2026 and 2025.
• Changes in working capital and other assets and liabilities for the Utility Registrants and Exelon Corporate totaled $1,360 million and $1,547 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 six months ended June 30, 2026, the established pricing has resulted in ComEd receiving payments from nuclear-powered generating facilities, which is reported within the cash flows from operations as a change in Accounts receivable. This change corresponds to a change in the Carbon mitigation credit regulatory mechanism. See Note 2 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.
Cash Flows from Investing Activities
The following table provides a summary of the change in cash flows from investing activities for the six months ended June 30, 2026 and 2025 by Registrant:

(Decrease) increase in cash flows from investing activities Exelon ComEd PECO BGE   PHI Pepco DPL ACE
Capital expenditures $ (599) $ (482) $ (132) $ (18) $ 46  $ (48) $ (23) $ (44)

Proceeds from sales of assets (2) —  —  —  (2) (2) —  — 
Changes in intercompany money pool —  —  —  —  —  (95) —  — 

Other investing activities 3  2  (11) —  1  —  1  1 
(Decrease) increase in cash flows from investing activities $ (598) $ (480) $ (143) $ (18) $ 45  $ (145) $ (22) $ (43)

Significant changes in cash flows from investing activities were primarily due to the following:
• 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 six months ended June 30, 2026 and 2025 by Registrant:
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Increase (decrease) in cash flows from financing activities Exelon ComEd PECO BGE   PHI Pepco DPL ACE
Changes in short-term borrowings, net $ 1,381  $ 36  $ 70  $ 175  $ (280) $ (252) $ 13  $ (41)
Long-term debt, net (993) 200  —  (75) 50  100  (50) — 
Changes in intercompany money pool —  —  —  —  15  —  47  48 
Issuance of common stock 209  —  —  —  —  —  —  — 
Dividends paid on common stock (52) (30) —  (31) —  37  4  4 

Distributions to member —  —  —  —  45  —  —  — 
Contributions from parent/member —  169  4  474  (116) 113  (54) (3)

Other financing activities 12  (7) —  (1) —  (2) —  (1)
Increase (decrease) in cash flows from financing activities $ 557  $ 368  $ 74  $ 542  $ (286) $ (4) $ (40) $ 7 

Significant changes in cash flows from financing activities were primarily due to the following:
• 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 second quarter of 2026. 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 16 — Commitments and Contingencies of the 2025 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 six months ended June 30, 2026, the following long-term debt was retired and/or redeemed:

Company Type Interest Rate Maturity Amount
Exelon Senior Notes 3.40  % April 15, 2026 $ 750 
ComEd First Mortgage Bonds 2.55  % June 15, 2026 $ 500 
BGE Senior Notes 2.40  % August 15, 2026 $ 350 

Dividends
Quarterly dividends declared by the Exelon Board of Directors during the six months ended June 30, 2026 and for the third quarter of 2026 were as follows:
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Period Declaration Date Shareholder of Record Date Dividend Payable Date Cash per Share (a)

First Quarter 2026 February 12, 2026 March 2, 2026 March 13, 2026 $ 0.4200 
Second Quarter 2026 April 28, 2026 June 4, 2026 June 15, 2026 $ 0.4200 
Third Quarter 2026 July 28, 2026 September 4, 2026 September 15, 2026 $ 0.4200 

__________
(a) Exelon's Board of Directors approved an updated dividend policy for 2026. The 2026 quarterly dividend will be $0.42 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 $3.2 billion was available to support additional commercial paper as of June 30, 2026, and of which 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 six months ended June 30, 2026 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 2025 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 Program
On May 2, 2025, Exelon executed an equity distribution agreement ("2025 Equity Distribution Agreement"), 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. 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. Exelon issued the following shares of Common stock in the second quarter of 2026:

Effective Period
Shares Issued
(in millions)
Weighted-Average Net Price
Net Proceeds (a)
(in millions)

Q2 2026 (b)
8.7 $ 44.03  $ 382 

_________
(a) Proceeds were used for general corporate purposes.
(b) In Q2 2026, Exelon settled all forward sale agreements with a November 16, 2026 maturity date and a portion of the forward sale agreements with December 15, 2026 and July 30, 2027 maturity dates that were entered into by various forward sellers under the ATM program as outlined below.
In the first quarter of 2026, Exelon entered into various forward sale agreements under the 2025 ATM program. The forward sale agreements require Exelon to, at its election prior to the maturity date, either (i) physically settle the transactions by issuing shares of its Common stock to the forward counterparties in exchange for net proceeds at the then-applicable forward sale price specified by the agreements or (ii) net settle the transactions in whole or in part through the delivery to the forward counterparties or receipt from the forward counterparties of cash or shares in accordance with the provisions of the agreements. The following forward sale agreements were entered into under Exelon’s ATM program in the first quarter of 2026:
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Effective Period Shares Available
(in millions) Weighted-Average Net Price Maturity Date
Q1 2026 5.4 $ 47.67  July 30, 2027
Q1 2026 6.4 $ 48.68  September 2, 2027

Additionally, the following forward sale agreements were entered into during the twelve months ended 2025 under Exelon’s ATM program and were not settled as of December 31, 2025:

Effective Period Shares Available
(in millions) Weighted-Average Net Price Maturity Date
Q2 2025 3.6 $ 43.17  November 16, 2026
Q3 2025 11.5 $ 43.73  December 15, 2026
Q4 2025 0.8 $ 45.42  December 15, 2026

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 three and six months ended June 30, 2026 June 30, 2026, approximately 18.4 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, $1.0 billion of Common stock remained available for sale pursuant to the ATM program as of June 30, 2026.
On July 6, 2026, Exelon settled an additional forward agreement that was entered into under the 2025 ATM program. Exelon issued approximately 2.3 million shares of Common stock at a weighted-average net price of $43.29 per share. The net proceeds from the issuance were $101 million, which will be used for general corporate purposes.
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 June 30, 2026 and available credit facility capacity prior to any incremental collateral at June 30, 2026:

PJM Credit Policy Collateral Other Incremental Collateral Required (a)
Available Credit Facility Capacity Prior to Any Incremental Collateral
ComEd $ 25  $ —  $ 982 
PECO 7  26  514 
BGE 3  16  573 

Pepco —  —  297 
DPL —  13  267 
ACE —  —  297 

__________
(a) Represents incremental collateral related to natural gas procurement contracts.
Capital Expenditure Spending
As of June 30, 2026, the most recent estimates of capital expenditures for plant additions and improvements for 2026 are as follows:        
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(In millions) Transmission Distribution Gas Total (a)

Exelon N/A N/A N/A $ 9,900 
ComEd 1,100  2,400  N/A 3,500 
PECO 450  1,325  400  2,175 
BGE 1,075  575  525  2,175 
PHI 725  1,250  50  2,050 
Pepco 325  650  N/A 975 
DPL 225  325  50  625 
ACE 175  275  N/A 450 

__________
(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. Exelon’s estimated annual qualified pension contributions will be $325 million in 2026. 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 12 — Retirement Benefits of the Combined Notes to Consolidated Financial Statements of the 2025 Form 10-K for additional information on pension and OPEB contributions.
Credit Facilities
Exelon Corporate, ComEd, and BGE meet their short-term liquidity needs primarily through commercial paper issuances. PECO also utilizes commercial paper, supplemented by borrowings from the Exelon intercompany money pool. Pepco, DPL, and ACE similarly rely on commercial paper, along with borrowings from the PHI intercompany money pool. PHI Corporate meets its short-term liquidity needs through borrowings from 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.
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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 Exelon, ComEd, PECO, PHI, Pepco, DPL, and ACE did not change for the six months ended June 30, 2026. On April 30, 2026, S&P lowered its long-term issuer credit rating and senior unsecured debt rating for BGE from 'A' to 'A-', and its short-term commercial paper rating for BGE from 'A-1' to 'A-2'. On July 15, 2026, Moody's lowered PECO's long-term issuer rating from 'A2' to 'A3', its senior secured debt rating from 'Aa3' to 'A1', and short-term commercial paper rating from 'P-1' to 'P-2'.
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 June 30, 2026, are presented in the following table:

During the Six Months Ended June 30, 2026 At June 30, 2026
Exelon Intercompany Money Pool Maximum
Contributed Maximum
Borrowed Contributed
(Borrowed)
Exelon Corporate $ 502  $ —  $ 399 
PECO 343  (63) — 
BSC —  (461) (360)
PHI Corporate —  (134) (92)
PCI 65  —  53 

During the Six Months Ended June 30, 2026 At June 30, 2026
PHI Intercompany Money Pool Maximum
Contributed Maximum
Borrowed
Contributed
(Borrowed)
Pepco $ 116  $ —  $ 95 
DPL —  (85) (47)
ACE —  (66) (48)

Shelf Registration Statements
On February 13, 2025, Exelon and ComEd filed a combined shelf registration statement on Form S-3 registering $12.6 billion in aggregate amount of securities, which was declared effective by the SEC on April 8, 2025. The shelf registration statement may be used to issue Exelon debt and equity securities as well as ComEd debt securities through the expiration date of April 8, 2028. On February 21, 2024, PECO and BGE 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. The ability of Exelon, ComEd, PECO and BGE to sell securities off their corresponding registration statements will depend on a number of
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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.
Regulatory Authorizations
The Utility Registrants are required to obtain short-term and long-term financing authority from Federal and State Commissions as follows:

At June 30, 2026
Short-term Financing Authority Remaining Long-term Financing Authority
Commission Expiration Date Amount Commission Expiration Date Amount
ComEd FERC December 31, 2027 $ 2,500  ICC January 1, 2027, May 1, 2027, & January 1, 2029 $ 2,968 
PECO FERC December 31, 2027 1,500  PAPUC December 31, 2027 1,850 
BGE FERC December 31, 2027 900  MDPSC N/A 925 
Pepco (a)
FERC December 31, 2027 700  MDPSC / DCPSC December 31, 2028 800 
DPL (a)
FERC December 31, 2027 700  MDPSC / DEPSC December 31, 2028 625 
ACE (b)
NJBPU January 1, 2028 350  NJBPU December 31, 2026 525 

__________

(a) 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, 2028.
(b) On June 4, 2026, ACE filed an application with the NJBPU to extend their long-term financing authority through December 31, 2028. ACE expects approval of their application by November 20, 2026.

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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 12 — Retirement Benefits of the 2025 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 hybrid, convertible, 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 Corporate 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 Utility 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 Board of Directors, Exelon's Audit and Risk Committee, and/or the applicable Utility Board Registrant. The Registrants do not execute derivatives for speculative or proprietary trading purposes.
Commodity Price Risk (All Registrants)
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.
For additional information on these contracts, see Note 2 — Regulatory Matters and Note 8 — Derivative Financial Instruments 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 liabilities. Second, the table shows the maturity, by year, of Exelon's and ComEd's commodity contract liabilities giving an indication of when these mark-to-market amounts will settle and 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) :
2026 2027 2028 2029 2030 2031 and Beyond
Prices based on model or other valuation methods (Level 3) $ (9) $ (23) $ (23) $ (23) $ (22) $ (28) $ (128)
_________
(a) Represents ComEd's net liabilities associated with the floating-to-fixed energy swap contracts with unaffiliated suppliers.
Credit Risk (All Registrants)
Credit risk for the Utility Registrants is governed by credit and collection policies, which are aligned with state regulatory requirements. The Utility Registrants are currently obligated to provide service to all electric customers within their franchised territories. The Utility Registrants record an allowance for credit losses, based upon historical experience, current information, and forward-looking risk factors, to provide for the potential loss from nonpayment by these customers. The Utility Registrants will monitor nonpayment from customers and will make any necessary adjustments to the allowance for credit losses. See Note 1 — Significant Accounting Policies of the Combined Notes to Consolidated Financial Statements of the 2025 Form 10-K for the allowance for credit losses policy. The Utility Registrants did not have any customers representing over 10% of their revenues as of June 30, 2026. See Note 2 — Regulatory Matters of the Combined Notes to the Consolidated Financial Statements for additional information.

ITEM 4.    CONTROLS AND PROCEDURES
During the second quarter of 2026, each of the Registrants' management, including its principal executive officer and principal financial officer, evaluated its disclosure controls and procedures (as defined in Exchange Act Rules 13a‑15(e) and 15d‑15(e)) as of the end of the period covered by this report, pursuant to Exchange Act Rules 13a‑15(b) and 15d‑15(b). 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 June 30, 2026, the principal executive officer and principal financial officer of each of the Registrants concluded that such Registrant’s disclosure controls and procedures were effective (Item 307 of Regulation S‑K).
Changes in Internal Control Over Financial Reporting
The Registrants continually strive to improve disclosure controls and procedures to enhance the quality of financial reporting and to maintain dynamic systems that change as conditions warrant. During the first quarter of 2026, a new ERP system was implemented for a majority of the financial accounting systems, which is expected to improve the efficiency of certain financial and related transaction processes. As part of the implementation of the ERP, the Registrants modified certain existing internal controls and implemented certain new controls in order to align the financial accounting processes with the new ERP system. The Registrants do not believe that any of these modifications or new controls have materially affected, or are reasonably likely to affect, internal control
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over financial reporting. There have been no other changes in internal control over financial reporting that occurred during the three and six months ended June 30, 2026, that have 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 2025 Form 10-K, (b) Notes 2 — Regulatory Matters and 16 — Commitments and Contingencies of the 2025 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 June 30, 2026, the Registrants' risk factors were consistent with the risk factors described in the Registrants' combined 2025 Form 10-K in ITEM 1A. RISK FACTORS.

ITEM 5.    OTHER INFORMATION
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 June 30, 2026, except as follows:
On June 9, 2026 , Calvin G. Butler, Jr. , President and Chief Executive Officer, Exelon Corporation, terminated a Rule 10b5-1 trading arrangement he had previously adopted on March 13, 2026 , which was intended to satisfy the affirmative defense of Rule 10b5-1(c). As of the date of termination of the trading arrangement, Mr. Butler had not sold any shares of common stock under its terms.

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
Commonwealth Edison Company
Exhibit No. Description Location
4-1
Supplemental Indenture dated as of May 1, 2026, from ComEd to The Bank of New York Mellon Trust Company, N.A., as trustee File No. 001-01839, Form 8-K dated May 14, 2026, Exhibit 4.1

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Baltimore Gas and Electric Company
Exhibit No. Description Location
4-2
Form of 5.150% Notes due 2033 issued May 22, 2026 by Baltimore Gas and Electric Company File No. 001-01910, Form 8-K dated May 22 , 2026, Exhibit 4.1

4-3
Form of 6.050% Notes due 2056 issued May 22, 2026 by Baltimore Gas and Electric Company File No. 001-01910, Form 8-K dated May 22, 2026, Exhibit 4.2

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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 June 30, 2026 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 Michael A. Innocenzo 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 June 30, 2026 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 Michael A. Innocenzo 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, Chief Finance Officer, Audit and Risk (Principal Financial Officer)

/s/ ROBERT A. KLECZYNSKI
Robert A. Kleczynski
Senior Vice President, Controller and Tax (Principal Accounting Officer)

July 30, 2026
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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)

July 30, 2026
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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/   MICHAEL A. INNOCENZO /s/    MARISSA E. HUMPHREY
Michael A. Innocenzo Marissa E. Humphrey
Interim 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)

July 30, 2026

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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/ CAROLINE FULGINITI
Caroline Fulginiti
Vice President and Assistant Controller, Exelon (Principal Accounting Officer, BGE)

July 30, 2026

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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)

July 30, 2026

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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)

July 30, 2026

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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)

July 30, 2026

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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)

July 30, 2026
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