FULLTEXT DEL 3 AV 4
10-Q – 2026-05-06 – exc-20260331.htm
(b) The fair value of the DPL economic hedge is not material at March 31, 2026 and December 31, 2025.
The fair value of derivative economic hedges is presented in Other current assets and current and noncurrent Mark-to-market derivative liabilities in Exelon's and ComEd's Consolidated Balance Sheets.
Interest Rate Risk (Exelon)
Exelon Corporate uses a combination of fixed-rate and variable-rate debt to manage interest rate exposure. 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. A hypothetical 50 basis point change in the interest rates associated with Exelon's interest rate swaps as of March 31, 2026 would result in an immaterial impact to Exelon's Consolidated Net income.
Below is a summary of the interest rate hedge balances at March 31, 2026 and December 31, 2025 .
Derivatives Designated
as Hedging Instruments
March 31, 2026 December 31, 2025
Other current assets $ — $ 3
Other deferred debits (noncurrent assets) 2 —
Total derivative assets 2 3
Mark-to-market derivative liabilities (current liabilities) — ( 4 )
Mark-to-market derivative liabilities (noncurrent liabilities) ( 1 ) —
Total mark-to-market derivative liabilities ( 1 ) ( 4 )
Total mark-to-market derivative net assets (liabilities) $ 1 $ ( 1 )
Cash Flow Hedges (Interest Rate Risk)
For derivative instruments that qualify and are designated as cash flow hedges, the changes in fair value each period are initially recorded in AOCI and reclassified into earnings when the underlying transaction affects earnings. The gains and losses reclassified out of AOCI for the three months ended March 31, 2026 and 2025 are immaterial.
In February 2026, Exelon terminated the previously issued floating-to-fixed swaps with a total notional of $ 550 million upon issuance of $ 775 million of debt. See Note 9 – Debt and Credit Agreements for additional information on the debt issuance. The settlements resulted in a net cash payment of $ 6 million. The accumulated AOCI loss of $ 4 million (net of tax) is being amortized into Interest expense in Exelon's Consolidated Statement of Operations and Comprehensive Income over the 5-year and 10-year terms of the swaps. During the first quarter of 2026, Exelon Corporate entered into $ 30 million notional of 10-year maturity floating-to-fixed swaps designated as cash flow hedges. The following table provides the notional amounts outstanding held by Exelon at March 31, 2026 and December 31, 2025.
March 31, 2026 December 31, 2025
5-year maturity floating-to-fixed swaps $ 60 $ 335
10-year maturity floating-to-fixed swaps 120 365
Total $ 180 $ 700
The related AOCI derivative gain for the three months ended March 31, 2026 was $ 1 million (net of tax). The related AOCI derivative loss for the three months ended March 31, 2025 was $ 9 million (net of tax). See Note 13 – Changes in Accumulated Other Comprehensive Income (Loss) for additional information.
Credit Risk (All Registrants)
The Registrants would be exposed to credit-related losses in the event of non-performance by counterparties on executed derivative instruments. The credit exposure of derivative contracts, before collateral, is represented by the fair value of contracts at the reporting date. The Utility Registrants have contracts to procure electric and natural gas supply that provide suppliers with a certain amount of unsecured credit. If the exposure on the supply contract exceeds the amount of unsecured credit, the suppliers may be required to post collateral. The net credit
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Combined Notes to Consolidated Financial Statements — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Note 8 — Derivative Financial Instruments
exposure is mitigated primarily by the ability to recover procurement costs through customer rates. The amount of cash collateral received from external counterparties remained relatively consistent as of March 31, 2026. Cash collateral held by ComEd, PECO, BGE, Pepco, DPL, and ACE must be deposited in an unaffiliated major U.S. commercial bank or foreign bank with a U.S. branch office that meets certain qualifications. The following table reflects the Registrants' cash collateral held from external counterparties, which is recorded in Other current liabilities on their respective Consolidated Balance Sheets, at March 31, 2026 and December 31, 2025:
March 31, 2026 December 31, 2025
Exelon $ 217 $ 223
ComEd 192 192
PECO 6 6
BGE 8 4
PHI 11 21
Pepco 1 13
DPL 10 3
ACE (a)
— 5
__________
(a) ACE had less than one million in cash collateral with external parties at March 31, 2026.
The Utility Registrants’ electric supply procurement contracts do not contain provisions that would require them to post collateral. PECO’s, BGE’s, and DPL’s natural gas procurement contracts contain provisions that could require PECO, BGE, and DPL to post collateral in the form of cash or credit support, which vary by contract and counterparty, with thresholds contingent upon PECO's, BGE's, and DPL's credit rating. As of March 31, 2026, PECO, BGE, and DPL were not required to post collateral for any of these agreements. If PECO, BGE, or DPL lost their investment grade credit rating as of March 31, 2026, they could have been required to post collateral to their counterparties of $ 38 million, $ 20 million, and $ 23 million, respectively.
9. Debt and Credit Agreements (All Registrants)
Short-Term Borrowings
Exelon Corporate, ComEd, and BGE meet their short-term liquidity requirements primarily through the issuance of commercial paper. PECO meets its short-term liquidity requirements primarily through the issuance of commercial paper and borrowings from the Exelon intercompany money pool. Pepco, DPL, and ACE meet their short-term liquidity requirements primarily through the issuance of commercial paper and borrowings from the PHI intercompany money pool. PHI Corporate meets its short-term liquidity requirements primarily through the issuance of short-term notes and 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.
Commercial Paper
The following table reflects the Registrants' commercial paper programs supported by the revolving credit agreements at March 31, 2026 and December 31, 2025.
Outstanding Commercial
Paper at Average Interest Rate on
Commercial Paper Borrowings at
Commercial Paper Issuer March 31, 2026 December 31, 2025 March 31, 2026 December 31, 2025
Exelon (a)
$ 165 $ 612 3.94 % 3.94 %
ComEd $ 46 $ — 3.93 % — %
PECO $ — $ — — % — %
BGE $ — $ — — % — %
PHI (b)
$ 119 $ 612 3.95 % 3.94 %
Pepco $ 73 $ 303 3.94 % 3.93 %
DPL $ 46 $ 161 3.96 % 3.94 %
ACE $ — $ 148 — % 3.94 %
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Combined Notes to Consolidated Financial Statements — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Note 9 — Debt and Credit Agreements
__________
(a) Exelon Corporate had no outstanding commercial paper borrowings at March 31, 2026 and no outstanding commercial paper borrowings at December 31, 2025.
(b) Represents the consolidated amounts of Pepco, DPL, and ACE.
Revolving Credit Agreements
On August 29, 2024, Exelon Corporate and each of the Utility Registrants amended and restated their respective syndicated revolving credit facility, extending the maturity date to August 29, 2029. The following table reflects the credit agreements:
Borrower Aggregate Bank Commitment Interest Rate
Exelon Corporate $ 900 SOFR plus 1.075 %
ComEd $ 1,000 SOFR plus 1.000 %
PECO $ 600 SOFR plus 0.900 %
BGE $ 600 SOFR plus 0.900 %
Pepco $ 300 SOFR plus 1.000 %
DPL $ 300 SOFR plus 1.000 %
ACE $ 300 SOFR plus 1.000 %
Exelon Corporate and the Utility Registrants had no outstanding amounts on the revolving credit facilities as of March 31, 2026.
The Utility Registrants have credit facility agreements, arranged at community banks, which may be utilized to issue letters of credit. The facility agreements have aggregate commitments of $ 40 million, $ 40 million, $ 15 million, $ 15 million, $ 15 million, and $ 15 million, at ComEd, PECO, BGE, Pepco, DPL, and ACE, respectively. On October 3, 2025, the Utility Registrants amended and extended their credit facilities at community banks. Previously structured as one-year arrangements, the facilities are now two-year terms. These facilities expire on October 1, 2027.
See Note 14 — Debt and Credit Agreements of the 2025 Form 10-K for additional information on the Registrants' credit facilities.
Short-Term Loan Agreements
On March 14, 2024, Exelon Corporate amended and bifurcated the $ 500 million term loan agreement into two tranches of $ 350 million and $ 150 million. The loan agreements were renewed in the first quarter of 2025, extending the expiration date to March 13, 2026. Exelon Corporate repaid the term loans on December 5, 2025.
On March 25, 2026, Exelon Corporate entered into two term loan agreements for $ 350 million and $ 150 million. Both agreements mature on March 24, 2027. Pursuant to the loan agreements, loans made thereunder bear interest at a variable rate equal to SOFR plus 0.85 % and all indebtedness thereunder is unsecured. The loans are reflected in Exelon's Consolidated Balance Sheet within Short-term borrowings.
Long-Term Debt
Issuance of Long-Term Debt
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Combined Notes to Consolidated Financial Statements — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Note 9 — Debt and Credit Agreements
During the three months ended March 31, 2026, the following long-term debt was issued:
Company Type Interest Rate Maturity Amount Use of Proceeds
Exelon Senior Notes 4.95 % March 15, 2036 $ 775 Repay existing indebtedness and for general corporate purposes.
Pepco First Mortgage Bonds 5.00 % March 19, 2036 110 Repay existing indebtedness and for general corporate purposes.
Pepco First Mortgage Bonds 5.30 % March 19, 2041 60 Repay existing indebtedness and for general corporate purposes.
DPL First Mortgage Bonds 5.74 % March 19, 2056 75 Repay existing indebtedness and for general corporate purposes.
ACE First Mortgage Bonds 4.95 % March 19, 2036 100 Repay existing indebtedness and for general corporate purposes.
Convertible Senior Notes
On December 4, 2025, Exelon Corporation issued $ 1 billion aggregate principal amount of 3.25 % Convertible Senior Notes due 2029 (Convertible Senior Notes). The Convertible Senior Notes are reflected as Long-term debt on Exelon’s Consolidated Balance Sheet.
The Convertible Senior Notes are senior, unsecured notes that bear interest at a fixed rate of 3.25 % per year, payable semiannually in arrears on March 15 and September 15 of each year, beginning on September 15, 2026. The Convertible Senior Notes will mature on March 15, 2029, unless earlier converted or repurchased in accordance with their terms.
Under the following circumstances, holders may convert the Convertible Senior Notes at their option prior to the close of business on the business day preceding December 15, 2028:
• during any calendar quarter beginning after the quarter ending on March 31, 2026, if the last reported sale price of Exelon’s common stock for at least 20 trading days (whether consecutive or not) during the period of 30 consecutive trading days ending on, and including, the last trading day of the immediately preceding calendar quarter is greater than or equal the stock was trading at greater than or equal to 130 % of the conversion price on each applicable trading day as determined by Exelon;
• during the five business day period after any ten consecutive trading day period (measurement period) in which the applicable trading price per $ 1,000 principal amount of notes for each trading day of the measurement period was less than 98 % of the product of the last reported sale price of the common stock and the conversion rate on each such trading day;
• upon the occurrence of certain corporate events specified in the respective supplemental indentures governing the Convertible Senior Notes.
On or after December 15, 2028, a holder may convert for all, or any portion of its Convertible Senior Notes at any time prior to the close of business on the business day immediately preceding the applicable maturity date regardless of the foregoing conditions.
Exelon will settle conversions of the Convertible Senior Notes by paying cash up to the aggregate principal amount to be converted and paying or delivering, as the case may be, cash, shares of common stock, or a combination of cash and shares of common stock, at Exelon’s discretion, in respect of the remainder, if any, of Exelon's conversion obligation in excess of the aggregate principal amount of the Convertible Senior Notes being converted. The Convertible Senior Notes are initially convertible at 17.5093 shares per $ 1,000 principal amount, which is equivalent to an initial conversion price of approximately 57.11 per share of common stock. The initial conversion price of the Convertible Senior Notes represents a premium of approximately 25 % over the last reported sale price of Exelon’s common stock on the Nasdaq Global Select Market on December 1, 2025. These conversions will be subject to adjustment upon the occurrence of certain specified events but will not be adjusted for accrued and unpaid interest. In addition, upon the occurrence of a make-whole fundamental change (as defined in the indenture) Exelon will, in certain circumstances, increase the applicable conversion rate by a number of additional shares of common stock for conversions in connection with the make-whole fundamental change.
As of March 31, 2026, no shares of the Convertible Senior Notes have been converted.
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Combined Notes to Consolidated Financial Statements — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Note 9 — Debt and Credit Agreements
EPS Impact
Diluted earnings per common shares will also reflect the dilutive effect of potential common shares from share-based awards and convertible notes. The dilutive effect of the Convertible Senior Notes is computed using the if-converted method. For the period ended March 31, 2026, no incremental shares were assumed converted or included in the diluted earnings per common share resulting from the Convertible Senior Notes.
Tax-Exempt Bonds
As of March 31, 2026, DPL had $ 78.4 million outstanding of its 3.60 % Delaware Economic Development Authority's Gas Facilities Refunding Revenue Bonds, maturing on January 1, 2031. The bonds were previously reoffered in July 2025. There have been no material changes to the terms since December 31, 2025. See Note 14 — Debt and Credit Agreements of the 2025 Form 10-K for additional information on the DPL reoffering of tax-exempt bonds.
Debt Covenants
As of March 31, 2026, the Registrants are in compliance with debt covenants.
10. Fair Value of Financial Assets and Liabilities (All Registrants)
Exelon measures and classifies fair value measurements in accordance with the hierarchy as defined by GAAP. The hierarchy prioritizes the inputs to valuation techniques used to measure fair value into three levels as follows:
• Level 1 — quoted prices (unadjusted) in active markets for identical assets or liabilities that the Registrants have the ability to liquidate as of the reporting date.
• Level 2 — inputs other than quoted prices included within Level 1 that are directly observable for the asset or liability or indirectly observable through corroboration with observable market data.
• Level 3 — unobservable inputs, such as internally developed pricing models or third-party valuations for the asset or liability due to little or no market activity for the asset or liability.
Exelon’s valuation techniques used to measure the fair value of the assets and liabilities shown in the tables below are in accordance with the policies discussed in Note 15 — Fair Value of Financial Assets and Liabilities of the 2025 Form 10-K.
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Combined Notes to Consolidated Financial Statements — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Note 10 — Fair Value of Financial Assets and Liabilities
Fair Value of Financial Liabilities Recorded at Amortized Cost
The following tables present the carrying amounts and fair values of the Registrants’ short-term liabilities, long-term debt, and trust preferred securities (long-term debt to financing trusts or junior subordinated debentures) as of March 31, 2026 and December 31, 2025. The Registrants have no financial liabilities measured using the NAV practical expedient.
The carrying amounts of the Registrants’ short-term liabilities as presented in their Consolidated Balance Sheets are representative of their fair value (Level 2) because of the short-term nature of these instruments.
March 31, 2026 December 31, 2025
Carrying Amount Fair Value Carrying Amount Fair Value
Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total
Long-Term Debt, including amounts due within one year (a)
Exelon (b)
$ 50,185 $ — $ 40,580 $ 4,558 $ 45,138 $ 49,078 $ — $ 40,637 $ 4,318 $ 44,955
ComEd 12,755 — 11,019 — 11,019 12,753 — 11,291 — 11,291
PECO 6,397 — 5,471 — 5,471 6,396 — 5,593 — 5,593
BGE 6,042 — 5,390 — 5,390 6,041 — 5,510 — 5,510
PHI 9,928 — 4,151 4,558 8,709 9,590 — 4,236 4,318 8,554
Pepco 4,802 — 2,484 1,990 4,474 4,632 — 2,546 1,861 4,407
DPL 2,421 — 644 1,446 2,090 2,344 — 657 1,410 2,067
ACE 2,133 — 812 1,123 1,935 2,033 — 819 1,047 1,866
Long-Term Debt to Financing Trusts
Exelon $ 390 $ — $ — $ 398 $ 398 $ 390 $ — $ — $ 403 $ 403
ComEd 206 — — 212 212 206 — — 216 216
PECO 184 — — 186 186 184 — — 187 187
__________
(a) Includes unamortized debt issuance costs, unamortized debt discount and premium, net, purchase accounting fair value adjustments, and finance lease liabilities which are not fair valued. Refer to Note 14 — Debt and Credit Agreements of the 2025 Form 10-K for unamortized debt issuance costs, unamortized debt discount and premium, net, and purchase accounting fair value adjustments and Note 9 — Leases of the 2025 Form 10-K for finance lease liabilities.
(b) Includes the net carrying amount and the estimated fair value (Level 2) of the Convertible Senior Notes $ 1 billion and $ 1 billion for the year ended March 31, 2026, respectively.
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Combined Notes to Consolidated Financial Statements — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Note 10 — Fair Value of Financial Assets and Liabilities
Recurring Fair Value Measurements
The following tables present assets and liabilities measured and recorded at fair value in the Registrants' Consolidated Balance Sheets on a recurring basis and their level within the fair value hierarchy at March 31, 2026 and December 31, 2025. Exelon and the Utility Registrants have immaterial and no financial assets or liabilities measured using the NAV practical expedient, respectively:
Exelon
At March 31, 2026 At December 31, 2025
Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total
Assets
Cash equivalents (a)
$ 945 $ — $ — $ 945 $ 825 $ — $ — $ 825
Rabbi trust investments
Cash equivalents 103 — — 103 101 — — 101
Mutual funds 72 — — 72 71 — — 71
Fixed income — 6 — 6 — 6 — 6
Life insurance contracts — 80 21 101 — 79 21 100
Rabbi trust investments subtotal 175 86 21 282 172 85 21 278
Interest rate derivative assets
Derivatives designated as hedging instruments — 2 — 2 — 3 — 3
Interest rate derivative assets subtotal — 2 — 2 — 3 — 3
Total assets 1,120 88 21 1,229 997 88 21 1,106
Liabilities
Commodity derivative liabilities — — ( 133 ) ( 133 ) — — ( 131 ) ( 131 )
Interest rate derivative liabilities
Derivatives designated as hedging instruments — ( 1 ) — ( 1 ) — ( 4 ) — ( 4 )
Interest rate derivative liabilities subtotal — ( 1 ) — ( 1 ) — ( 4 ) — ( 4 )
Deferred compensation obligation — ( 68 ) — ( 68 ) — ( 71 ) — ( 71 )
Total liabilities — ( 69 ) ( 133 ) ( 202 ) — ( 75 ) ( 131 ) ( 206 )
Total net assets (liabilities) $ 1,120 $ 19 $ ( 112 ) $ 1,027 $ 997 $ 13 $ ( 110 ) $ 900
__________
(a) Exelon excludes cash of $ 157 million and $ 180 million at March 31, 2026 and December 31, 2025, respectively, and restricted cash of $ 195 million and $ 196 million at March 31, 2026 and December 31, 2025, respectively, and includes long-term restricted cash of $ 24 million and $ 50 million at March 31, 2026 and December 31, 2025, respectively, which is reported in Other deferred debits and other assets in the 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 10 — Fair Value of Financial Assets and Liabilities
ComEd, PECO, and BGE
ComEd PECO BGE
At March 31, 2026 Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total
Assets
Cash equivalents (a)
$ 343 $ — $ — $ 343 $ 125 $ — $ — $ 125 $ 172 $ — $ — $ 172
Rabbi trust investments
Mutual funds — — — — 13 — — 13 11 — — 11
Life insurance contracts — — — — — 25 — 25 — — — —
Rabbi trust investments subtotal — — — — 13 25 — 38 11 — — 11
Total assets 343 — — 343 138 25 — 163 183 — — 183
Liabilities
Commodity derivative liabilities (b)
— — ( 133 ) ( 133 ) — — — — — — — —
Deferred compensation obligation — ( 9 ) — ( 9 ) — ( 8 ) — ( 8 ) — ( 4 ) — ( 4 )
Total liabilities — ( 9 ) ( 133 ) ( 142 ) — ( 8 ) — ( 8 ) — ( 4 ) — ( 4 )
Total net assets (liabilities) $ 343 $ ( 9 ) $ ( 133 ) $ 201 $ 138 $ 17 $ — $ 155 $ 183 $ ( 4 ) $ — $ 179
ComEd PECO BGE
At December 31, 2025 Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total
Assets
Cash equivalents (a)
$ 393 $ — $ — $ 393 $ 93 $ — $ — $ 93 $ 205 $ — $ — $ 205
Rabbi trust investments
Mutual funds — — — — 13 — — 13 10 — — 10
Life insurance contracts — — — — — 25 — 25 — — — —
Rabbi trust investments subtotal — — — — 13 25 — 38 10 — — 10
Total assets 393 — — 393 106 25 — 131 215 — — 215
Liabilities
Commodity derivative liabilities (b)
— — ( 131 ) ( 131 ) — — — — — — — —
Deferred compensation obligation — ( 9 ) — ( 9 ) — ( 8 ) — ( 8 ) — ( 4 ) — ( 4 )
Total liabilities — ( 9 ) ( 131 ) ( 140 ) — ( 8 ) — ( 8 ) — ( 4 ) — ( 4 )
Total net assets (liabilities) $ 393 $ ( 9 ) $ ( 131 ) $ 253 $ 106 $ 17 $ — $ 123 $ 215 $ ( 4 ) $ — $ 211
__________
(a) ComEd excludes cash of $ 69 million and $ 77 million at March 31, 2026 and December 31, 2025, respectively, and restricted cash of $ 194 million and $ 193 million at March 31, 2026 and December 31, 2025, respectively. Additionally, ComEd includes long-term restricted cash of $ 24 million and $ 50 million at March 31, 2026 and December 31, 2025, respectively, which is reported in Other deferred debits and other assets in the Consolidated Balance Sheets. PECO
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Combined Notes to Consolidated Financial Statements — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Note 10 — Fair Value of Financial Assets and Liabilities
excludes cash of $ 26 million and $ 23 million at March 31, 2026 and December 31, 2025, respectively. BGE excludes cash of $ 8 million and $ 15 million at March 31, 2026 and December 31, 2025, respectively.
(b) The Level 3 balance consists of the current and noncurrent liability of $ 22 million and $ 111 million, respectively, at March 31, 2026 and $ 25 million and $ 106 million, respectively, at December 31, 2025 related to floating-to-fixed energy swap contracts with unaffiliated suppliers.
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Combined Notes to Consolidated Financial Statements — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Note 10 — Fair Value of Financial Assets and Liabilities
PHI, Pepco, DPL, and ACE
At March 31, 2026 At December 31, 2025
PHI Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total
Assets
Cash equivalents (a)
$ 35 $ — $ — $ 35 $ 83 $ — $ — $ 83
Rabbi trust investments
Cash equivalents 101 — — 101 99 — — 99
Mutual funds 9 — — 9 9 — — 9
Fixed income — 6 — 6 — 6 — 6
Life insurance contracts — 23 20 43 — 23 20 43
Rabbi trust investments subtotal 110 29 20 159 108 29 20 157
Total assets 145 29 20 194 191 29 20 240
Liabilities
Deferred compensation obligation — ( 9 ) — ( 9 ) — ( 9 ) — ( 9 )
Total liabilities — ( 9 ) — ( 9 ) — ( 9 ) — ( 9 )
Total net assets $ 145 $ 20 $ 20 $ 185 $ 191 $ 20 $ 20 $ 231
Pepco DPL ACE
At March 31, 2026 Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total
Assets
Cash equivalents (a)
$ 20 $ — $ — $ 20 $ 10 $ — $ — $ 10 $ 5 $ — $ — $ 5
Rabbi trust investments
Cash equivalents 100 — — 100 — — — — — — — —
Life insurance contracts — 23 20 43 — — — — — — — —
Rabbi trust investments subtotal 100 23 20 143 — — — — — — — —
Total assets 120 23 20 163 10 — — 10 5 — — 5
Liabilities
Deferred compensation obligation — ( 1 ) — ( 1 ) — — — — — — — —
Total liabilities — ( 1 ) — ( 1 ) — — — — — — — —
Total net assets $ 120 $ 22 $ 20 $ 162 $ 10 $ — $ — $ 10 $ 5 $ — $ — $ 5
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Combined Notes to Consolidated Financial Statements — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Note 10 — Fair Value of Financial Assets and Liabilities
Pepco DPL ACE
At December 31, 2025 Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total
Assets
Cash equivalents (a)
$ 33 $ — $ — $ 33 $ 3 $ — $ — $ 3 $ — $ — $ — $ —
Rabbi trust investments
Cash equivalents 98 — — 98 — — — — — — — —
Life insurance contracts — 23 20 43 — — — — — — — —
Rabbi trust investments subtotal 98 23 20 141 — — — — — — — —
Total assets 131 23 20 174 3 — — 3 — — — —
Liabilities
Deferred compensation obligation — ( 1 ) — ( 1 ) — — — — — — — —
Total liabilities — ( 1 ) — ( 1 ) — — — — — — — —
Total net assets $ 131 $ 22 $ 20 $ 173 $ 3 $ — $ — $ 3 $ — $ — $ — $ —
__________
(a) PHI excludes cash of $ 44 million and $ 56 million at March 31, 2026 and December 31, 2025, respectively, and restricted cash of $ 1 million and $ 2 million at March 31, 2026 and December 31, 2025. Pepco excludes cash of $ 20 million and $ 22 million at March 31, 2026 and December 31, 2025, respectively. DPL excludes cash of $ 12 million and $ 9 million at March 31, 2026 and December 31, 2025, respectively. ACE excludes cash of $ 7 million and $ 22 million at March 31, 2026 and December 31, 2025, respectively and restricted cash of $ 1 million and $ 2 million at March 31, 2026 and December 31, 2025, respectively.
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Combined Notes to Consolidated Financial Statements — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Note 10 — Fair Value of Financial Assets and Liabilities
Reconciliation of Level 3 Assets and Liabilities
The following tables present the fair value reconciliation of Level 3 assets and liabilities measured at fair value on a recurring basis during the three months ended March 31, 2026 and 2025:
Exelon ComEd PHI and Pepco
Three Months Ended March 31, 2026 Total Commodity
Derivatives Life Insurance Contracts
Balance at December 31, 2025 $ ( 110 ) $ ( 131 ) $ 20
Total realized / unrealized gains (losses)
Included in net income (a)
— — —
Included in regulatory assets/liabilities (b)
( 2 ) ( 2 ) —
Balance at March 31, 2026 (c)
$ ( 112 ) $ ( 133 ) $ 20
The amount of total gains included in income attributed to the change in unrealized gains related to assets and liabilities at March 31, 2026 $ — $ — $ —
Exelon ComEd PHI and Pepco
Three Months Ended March 31, 2025 Total Commodity
Derivatives Life Insurance Contracts
Balance at December 31, 2024 $ ( 110 ) $ ( 132 ) $ 21
Total realized / unrealized gains (losses)
Included in net income (a)
— — —
Included in regulatory assets/liabilities (b)
( 19 ) ( 19 ) —
Balance at March 31, 2025 (c)
$ ( 129 ) $ ( 151 ) $ 21
The amount of total gains included in income attributed to the change in unrealized gains related to assets and liabilities at March 31, 2025 $ — $ — $ —
__________
(a) Classified in Operating and maintenance expense in the Consolidated Statements of Operations and Comprehensive Income.
(b) For ComEd, this includes $ 10 million of decreases in fair value and an increase for realized gains due to settlements of $ 8 million recorded in Purchased power expense associated with floating-to-fixed energy swap contracts with unaffiliated suppliers for the three months ended March 31, 2026. Includes $ 30 million of decreases in fair value and an increase for realized gains due to settlements of $ 11 million recorded in Purchased power expense associated with floating-to-fixed energy swap contracts with unaffiliated suppliers for the three months ended March 31, 2025.
(c) For ComEd, the balance of the current and noncurrent asset was zero as of March 31, 2026. The balance consists of a current and noncurrent liability of $ 22 million and $ 111 million, respectively, as of March 31, 2026.
Commodity Derivatives (Exelon and ComEd)
The table below discloses the significant unobservable inputs to the forward curve used to value mark-to-market derivatives.
Type of trade Fair Value at March 31, 2026 Fair Value at December 31, 2025 Valuation
Technique Unobservable
Input 2026 Range & Arithmetic Average 2025 Range & Arithmetic Average
Commodity derivatives $ ( 133 ) $ ( 131 ) Discounted
Cash Flow Forward power price (a)
$ 26.72 - $ 57.33 $ 40.28 $ 28.45 - $ 62.87 $ 38.62
________
(a) An increase to the forward power price would increase the fair value.
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Combined Notes to Consolidated Financial Statements — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Note 11 — Commitments and Contingencies
11. Commitments and Contingencies (All Registrants)
The following is an update to the current status of commitments and contingencies set forth in Note 16 — Commitments and Contingencies of the 2025 Form 10-K.
Commitments
PHI Merger Commitments (Exelon, PHI, Pepco, DPL, and ACE). Approval of the PHI Merger in Delaware, New Jersey, Maryland, and the District of Columbia was conditioned upon Exelon and PHI agreeing to certain commitments. The following amounts represent total commitment costs that have been recorded since the acquisition date and the total remaining obligations for Exelon, PHI, Pepco, DPL, and ACE at March 31, 2026:
Description Exelon PHI Pepco DPL ACE
Total commitments $ 513 $ 320 $ 120 $ 89 $ 111
Remaining commitments (a)
21 19 19 — —
__________
(a) Remaining commitments extend through 2026 and include escrow funds and rate credits.
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Combined Notes to Consolidated Financial Statements — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Note 11 — Commitments and Contingencies
Commercial Commitments (All Registrants). The Registrants’ commercial commitments at March 31, 2026, representing commitments potentially triggered by future events were as follows:
Expiration within
Total 2026 2027 2028 2029 2030 2031 and beyond
Exelon
Letters of credit (a)
$ 57 $ 38 $ 19 $ — $ — $ — $ —
Surety bonds (b)
465 185 115 165 — — —
Financing trust guarantees (c)
378 — — 78 — — 300
Guaranteed lease residual values (d)
23 — 2 6 4 4 7
Total commercial commitments $ 923 $ 223 $ 136 $ 249 $ 4 $ 4 $ 307
ComEd
Letters of credit (a)
$ 18 $ 15 $ 3 $ — $ — $ — $ —
Surety bonds (b)
131 37 94 — — — —
Financing trust guarantees (c)
200 — — — — — 200
Total commercial commitments $ 349 $ 52 $ 97 $ — $ — $ — $ 200
PECO
Letters of credit (a)
$ 5 $ 3 $ 2 $ — $ — $ — $ —
Surety bonds (b)
10 1 9 — — — —
Financing trust guarantees (c)
178 — — 78 — — 100
Total commercial commitments $ 193 $ 4 $ 11 $ 78 $ — $ — $ 100
BGE
Letters of credit (a)
$ 27 $ 16 $ 11 $ — $ — $ — $ —
Surety bonds (b)
92 2 3 87 — — —
Total commercial commitments $ 119 $ 18 $ 14 $ 87 $ — $ — $ —
PHI
Letters of credit (a)
$ 4 $ 2 $ 2 $ — $ — $ — $ —
Surety bonds (b)
173 90 5 78 — — —
Guaranteed lease residual values (d)
23 — 2 6 4 4 7
Total commercial commitments $ 200 $ 92 $ 9 $ 84 $ 4 $ 4 $ 7
Pepco
Letters of credit (a)
$ 2 $ 2 $ — $ — $ — $ — $ —
Surety bonds (b)
161 82 1 78 — — —
Guaranteed lease residual values (d)
8 — 1 2 1 2 2
Total commercial commitments $ 171 $ 84 $ 2 $ 80 $ 1 $ 2 $ 2
DPL
Letters of credit (a)
$ 1 $ — $ 1 $ — $ — $ — $ —
Surety bonds (b)
6 3 3 — — — —
Guaranteed lease residual values (d)
9 — 1 2 2 1 3
Total commercial commitments $ 16 $ 3 $ 5 $ 2 $ 2 $ 1 $ 3
ACE
Letters of credit (a)
$ 1 $ — $ 1 $ — $ — $ — $ —
Surety bonds (b)
6 5 1 — — — —
Guaranteed lease residual values (d)
6 — — 2 1 1 2
Total commercial commitments $ 13 $ 5 $ 2 $ 2 $ 1 $ 1 $ 2
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Combined Notes to Consolidated Financial Statements — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Note 11 — Commitments and Contingencies
__________
(a) Exelon and certain of its subsidiaries maintain non-debt letters of credit to provide credit support for certain transactions as requested by third parties.
(b) Surety bonds—Guarantees issued related to contract and commercial agreements, excluding bid bonds. Historically, payments under the guarantees have not been made and the likelihood of payments being required is remote.
(c) Reflects guarantee of ComEd and PECO securities held by ComEd Financing III, PECO Trust III, and PECO Trust IV.
(d) Represents the maximum potential obligation in the event the fair value of certain leased equipment and fleet vehicles is zero at the end of the maximum lease term. The lease term associated with these assets ranges from 1 to 9 years. The maximum potential obligation at the end of the minimum lease term would be $ 53 million guaranteed by Exelon and PHI, of which $ 17 million, $ 20 million, and $ 16 million is guaranteed by Pepco, DPL, and ACE, respectively. Historically, payments under the guarantees have not been made and PHI believes the likelihood of payments being required under the guarantees is remote.
Environmental Remediation Matters
General (All Registrants). The Registrants’ operations have in the past, and may in the future, require substantial expenditures to comply with environmental laws. Additionally, under federal and state environmental laws, the Registrants are generally liable for the costs of remediating environmental contamination of property now or formerly owned by them and of property contaminated by hazardous substances generated by them. The Registrants own or lease a number of real estate parcels, including parcels on which their operations or the operations of others may have resulted in contamination by substances that are considered hazardous under environmental laws. In addition, the Registrants are currently involved in a number of proceedings relating to sites where hazardous substances have been deposited and may be subject to additional proceedings in the future. Unless otherwise disclosed, the Registrants cannot reasonably estimate whether they will incur significant liabilities for additional investigation and remediation costs at these or additional sites identified by the Registrants, environmental agencies, or others, or whether such costs will be recoverable from third parties, including customers. Additional costs could have a material, unfavorable impact on the Registrants' financial statements.
MGP Sites (All Registrants). ComEd, PECO, BGE, and DPL have identified sites where former MGP or gas purification activities have or may have resulted in actual site contamination. For some sites, there are additional PRPs that may share responsibility for the ultimate remediation of each location.
• ComEd has 16 sites currently under some degree of active study and/or remediation. ComEd expects the majority of the remediation at these sites to continue through at least 2033.
• PECO has 5 sites currently under some degree of active study and/or remediation. PECO expects the majority of the remediation at these sites to continue through at least 2030.
• BGE has 4 sites currently requiring some level of remediation and/or ongoing activity. BGE expects the majority of the remediation at these sites to continue through at least 2026.
• DPL has 1 site currently under study and the required cost at the site is not expected to be material.
The historical nature of the MGP and gas purification sites, and the fact that many of the sites have been buried and built over, impacts the ability to determine a precise estimate of the ultimate costs prior to initial sampling and determination of the exact scope and method of remedial activity. Management determines its best estimate of remediation costs using all available information at the time of each study, including probabilistic and deterministic modeling for ComEd and PECO, and the remediation standards currently required by the applicable state environmental agency. Prior to performing any significant clean up, each site remediation plan is approved by the appropriate state environmental agency.
ComEd, pursuant to an ICC order, and PECO, pursuant to a PAPUC order, are currently recovering environmental remediation costs of former MGP facility sites through customer rates. While BGE and DPL do not have riders for MGP clean-up costs, they have historically received recovery of actual clean-up costs in distribution rates.
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Combined Notes to Consolidated Financial Statements — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Note 11 — Commitments and Contingencies
At March 31, 2026 and December 31, 2025, the Registrants had accrued the following undiscounted amounts for environmental liabilities in Accrued expenses, Other current liabilities, and Other deferred credits and other liabilities in their respective Consolidated Balance Sheets:
March 31, 2026 December 31, 2025
Total Environmental
Investigation and
Remediation Liabilities Portion of Total Related to
MGP Investigation and
Remediation Total Environmental
Investigation and
Remediation Liabilities Portion of Total Related to
MGP Investigation and
Remediation
Exelon $ 381 $ 318 $ 386 $ 321
ComEd 289 288 289 289
PECO 22 20 23 22
BGE 13 10 13 10
PHI 57 — 57 —
Pepco 55 — 55 —
DPL 1 — 1 —
ACE 1 — 1 —
Benning Road Site (Exelon, PHI, and Pepco) . In September 2010, PHI received a letter from the EPA identifying the Benning Road site as one of six land-based sites potentially contributing to contamination of the lower Anacostia River. A portion of the site, which is owned by Pepco, was formerly the location of an electric generating facility owned by Pepco subsidiary, Pepco Energy Services (PES), which became a part of Constellation following the 2016 merger between PHI and Exelon. This generating facility was deactivated in June 2012. The remaining portion of the site consists of a Pepco transmission and distribution service center that remains in operation. In December 2011, the U.S. District Court for the District of Columbia approved a Consent Decree entered into by Pepco and Pepco Energy Services (hereinafter "Pepco Entities") with the DOEE, which requires the Pepco Entities to conduct a Remedial Investigation and Feasibility Study (RI/FS) for the Benning Road site and an approximately 10 to 15-acre portion of the adjacent Anacostia River. The purpose of this RI/FS is to define the nature and extent of contamination from the Benning Road site and to evaluate remedial alternatives.
Pursuant to an internal agreement between the Pepco Entities, since 2013, Pepco has performed the work required by the Consent Decree and has been reimbursed for that work by an agreed upon allocation of costs between the Pepco Entities. In September 2019, the Pepco Entities issued a draft “final” RI report which the DOEE approved on February 3, 2020. In October 2022, the DOEE approved dividing the work to complete the landside portion of the FS from the waterside portion to expedite the overall schedule for completion of the project. The landside FS was approved by the DOEE on March 15th, 2024, and the waterside FS was approved by the DOEE on December 16, 2024. The DOEE and Pepco entered into an addendum to the Benning Consent Decree pursuant to which Pepco has agreed to fund or perform the remedial actions to be selected by the DOEE for the landside and waterside areas. This addendum to the Benning Consent Decree was entered by the Court on February 27, 2024 and became effective on that date. Pepco drafted separate proposed plans for the landside and waterside areas, which were approved and issued by the DOEE for public comment on December 16, 2024 and September 4, 2025, respectively. The public comment period for the landside and waterside areas closed on April 18, 2025 and October 31, 2025, respectively. Pepco submitted a matrix of proposed responses to the public comments and a proposed Record of Decision (ROD) to the DOEE for the landside area on August 15, 2025. Following the close of the waterside area comment period, Pepco will submit a matrix of proposed responses to the public comments and a proposed ROD to the DOEE for the waterside area. The DOEE will issue RODs identifying the remedial actions determined to be necessary for the landside and waterside areas, which will be implemented by Pepco in accordance with the Benning Consent Decree.
As part of the separation between Exelon and Constellation in February 2022, the internal agreement between the Pepco Entities for completion and payment for the remaining Consent Decree work was memorialized in a formal agreement for post-separation activities. A second post-separation assumption agreement between Exelon and Constellation transferred any of the potential remaining remediation liability, if any, of PES/Constellation to a non-utility subsidiary of Exelon which going forward will be responsible for those liabilities. Exelon, PHI, and Pepco have determined that a loss associated with this matter is probable and have accrued an estimated liability, which is included in the table above.
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Combined Notes to Consolidated Financial Statements — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Note 11 — Commitments and Contingencies
Anacostia River Tidal Reach (Exelon, PHI, and Pepco) . Contemporaneous with the Benning Road site RI/FS being performed by the Pepco Entities, the DOEE and NPS have been conducting a separate RI/FS focused on the entire tidal reach of the Anacostia River extending from just north of the Maryland-District of Columbia boundary line to the confluence of the Anacostia and Potomac Rivers. The riverwide RI incorporated the results of the river sampling performed by the Pepco Entities as part of the Benning RI/FS, as well as similar sampling efforts conducted by owners of other sites adjacent to this segment of the river and supplemental river sampling conducted by the DOEE’s contractor.
On September 30, 2020, the DOEE released its Interim ROD for the Anacostia River sediments. The Interim ROD reflects an adaptive management approach which will require several identified “hot spots” in the river to be addressed first while continuing to conduct studies and to monitor the river to evaluate improvements and determine potential future remediation plans. The adaptive management process chosen by the DOEE is less intrusive, provides more long-term environmental certainty, is less costly, and allows for site specific remediation plans already underway, including the plan for the Benning Road site to proceed to conclusion.
On July 15, 2022, Pepco received a letter from the District of Columbia's Office of the Attorney General (D.C. OAG) on behalf of the DOEE conveying a settlement offer to resolve all PRPs' liability to the District of Columbia (District) for their past costs and their anticipated future costs to complete the work for the Interim ROD. Pepco responded on July 27, 2022 agreeing to enter into settlement discussions. Pepco and the District entered into another consent decree (the “Anacostia River Consent Decree”) pursuant to which Pepco agreed to pay $ 47 million to resolve its liability to the District for all past costs to perform the riverwide RI/FS and all future costs to complete the work required by the Interim ROD. This amount was agreed to be paid in four equal annual installments beginning a year after the effective date of the Anacostia River Consent Decree. Pepco paid the first installment of $ 12 million on April 9, 2025, and the second installment of $ 12 million on April 7, 2026. The funds were deposited into the DOEE’s Clean Land Fund for the District’s costs of the Interim ROD work. The Anacostia River Consent Decree caps Pepco’s liability for these costs and provides Pepco with the right to seek contributions from other PRPs. The Anacostia River Consent Decree was signed by the judge for the U.S. District Court for the District of Columbia and became effective on April 11, 2024. Exelon, PHI, and Pepco have accrued a liability for Pepco’s payment obligations under the Anacostia Consent Decree and management's best estimate of its share of any other future Anacostia River response costs. Pepco has concluded that incremental exposure remains reasonably possible, but management cannot reasonably estimate a range of loss beyond the amounts recorded, which are included in the table above.
In addition to the activities associated with the remedial process outlined above, CERCLA separately requires federal and state (here including Washington, D.C.) Natural Resource Trustees (federal or state agencies designated by the President or the relevant state, respectively, or Indian tribes) to conduct an assessment of any damages to natural resources within their jurisdiction as a result of the contamination that is being remediated. The Trustees can seek compensation from responsible parties for such damages, including restoration costs. During the second quarter of 2018, Pepco became aware that the Trustees are in the beginning stages of a NRD assessment, a process that often takes many years beyond the remedial decision to complete. Pepco has concluded that a loss associated with the eventual NRD assessment is reasonably possible. Due to the early stage of the NRD process, Pepco cannot reasonably estimate the final range of loss potentially resulting from this process. Pepco has become aware, however, that the District is pursuing claims against other parties. Specifically, in January 2025, D.C. OAG filed a lawsuit against the United States seeking to declare the United States liable under CERCLA and the District of Columbia’s Brownfield Revitalization Act of 2000 and to recover the District’s response costs associated with its investigation and remediation of Anacostia River sediment contamination and for future NRDs. Pepco is not a party to this suit, but Pepco, the United States, and the District of Columbia have entered mediation discussions to resolve their respective claims against one another under CERCLA and the Brownfield Revitalization Act with respect to the river. The court has put the case on hold pending the outcome of the mediation.
As noted in the Benning Road Site disclosure above, as part of the separation of Exelon and Constellation in February 2022, an assumption agreement was executed transferring any potential future remediation liabilities associated with the Benning Site remediation to a non-utility subsidiary of Exelon. Similarly, any potential future liability associated with the Anacostia River Sediment Project was also assumed by this entity.
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Combined Notes to Consolidated Financial Statements — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Note 11 — Commitments and Contingencies
Buzzard Point Site (Exelon, PHI, and Pepco). On December 8, 2022, Pepco received a letter from the D.C. OAG, alleging wholly past violations of the District's stormwater discharge and waste disposal requirements related to operations at the Buzzard Point facility, a 9-acre parcel of waterfront property in Washington, D.C. occupied by an active substation and former steam plant building. The letter also alleged wholly past violations by Pepco of stormwater discharge requirements related to its district-wide system of underground vaults. Pepco entered into a Consent Order with the District of Columbia to resolve the alleged violations without any admission of liability. The Consent Order requires Pepco to pay a civil penalty of $ 10 million. In addition, Pepco has agreed to assess the environmental conditions at its Buzzard Point facility and conduct any remedial actions deemed necessary as a result of the assessment, and also to assess potential environmental impacts associated with the operation of its underground vaults. The Superior Court for the District of Columbia signed and entered the Consent Order, and it became effective on February 2, 2024. Pepco is proceeding through the multi-step environmental investigation and response as outlined in the consent order. Specifically, the DOEE approved Pepco's Preliminary Site Assessment in July 2025. In September 2025, Pepco timely submitted its work plan for the second stage, the Supplemental Investigation Plan, which the DOEE approved in November 2025. Pepco also submitted an environmental assessment to the DOEE of the vault system pursuant to the Consent Order in July 2024. In response to the DOEE's comments, Pepco made revised submissions in May 2025, September 2025, and January 2026. The DOEE approved Pepco's vault system report on February 2, 2026. Exelon, PHI, and Pepco have accrued a liability for the projected costs for the required environmental assessments and remediation. In January 2025, Pepco paid the last installment of the civil penalty. Pepco has concluded that incremental exposure remains reasonably possible, but management cannot reasonably estimate a range of loss beyond the amounts recorded, which are included in the table above.
Litigation and Regulatory Matters
DPA and Related Matters (Exelon and ComEd). Exelon and ComEd received a grand jury subpoena in the second quarter of 2019 from the U.S. Attorney’s Office for the Northern District of Illinois (USAO) requiring production of information concerning their lobbying activities in the State of Illinois. On October 4, 2019, Exelon and ComEd received a second grand jury subpoena from the USAO requiring production of records of any communications with certain individuals and entities. The Companies cooperated fully with the USAO and any government requests or inquiries. On July 17, 2020, ComEd entered into a DPA with the USAO to resolve the USAO investigation into its historical state legislative lobbying and related practices in Illinois. The agreement resolved the Department of Justice investigation into both ComEd and Exelon, which included a payment to the U.S. Treasury of $ 200 million, which was paid in November 2020. The three-year term of the DPA ended on July 17, 2023, and on that same date the court granted the USAO’s motion to dismiss the pending charge against ComEd that had been deferred by the DPA.
Subsequent to Exelon announcing the receipt of the USAO subpoenas, various lawsuits were filed related to the subject of the subpoenas and the conduct described in the DPA. Several putative class actions were brought in federal and state court by ComEd customers. These actions were dismissed prior to discovery or trial and those dismissals were affirmed on appeal. A putative class action alleging misrepresentations and omissions in Exelon's SEC filings related to ComEd's lobbying activities and the related investigations was also brought in federal court against Exelon and ComEd, which was subsequently settled.
In addition, subsequent to Exelon announcing the receipt of the USAO subpoenas, several shareholders sent letters to the Exelon Board of Directors demanding, among other things, that the Exelon Board of Directors investigate and address alleged breaches of fiduciary duties and other alleged violations by Exelon and ComEd officers and directors related to the conduct described in the DPA. In the first quarter of 2021, the Exelon Board of Directors appointed a Special Litigation Committee (SLC) consisting of disinterested and independent parties to investigate and address these shareholders’ allegations and make recommendations to the Exelon Board of Directors based on the outcome of the SLC’s investigation. In July 2021, one of the demand letter shareholders filed a derivative action against current and former Exelon and ComEd officers and directors, and against Exelon, as nominal defendant, asserting the same claims made in its demand letter. Since that date, multiple parties have filed separate derivative lawsuits that were subsequently consolidated. On October 12, 2021, the parties filed an agreed motion to stay the litigation for 120 days in order to allow the SLC to continue its investigation, which the court granted. The stay was extended several times. Through mediation efforts, a settlement of the derivative claims was reached by the SLC, the Independent Review Committee of the Board (which had been formed in the third quarter of 2022, to ensure the Board’s consideration of any SLC recommendations would be independent and objective), the Board, and certain of the derivative shareholders. On June 16, 2023, the SLC filed a motion for preliminary approval of the settlement, attaching the Stipulation and Agreement of Settlement
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(Dollars in millions, except per share data, unless otherwise noted)
Note 11 — Commitments and Contingencies
(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 and use tax on the purchase of most goods and services. BGE, Pepco, and DPL have filed or plan to file protective refund claims, totaling an estimated $ 100 million, treating electric transmission and distribution machinery and equipment as nontaxable pursuant to the manufacturing exemption available under the Maryland sales and use tax law. The Maryland Comptroller has initially denied the refund claim and litigation is pending.
On November 22, 2024, the Appellate Court of Maryland, in a case involving a regulated electric utility operating in Maryland, ruled the purchase of certain transmission and distribution equipment qualify for the sales tax manufacturing exemption. On December 20, 2024, the Maryland Attorney General, on behalf of the Maryland Comptroller, filed a motion for reconsideration with the Appellate Court of Maryland of its ruling. The motion for reconsideration was denied on February 3, 2025.
On February 18, 2025, the Maryland Attorney General, on behalf of the Maryland Comptroller, filed a petition with the Maryland Supreme Court requesting review of the Appellate Court of Maryland’s ruling. On April 24, 2025, the Maryland Supreme Court granted the petition to review the ruling. On October 1, 2025, the Maryland Supreme Court heard oral arguments in the case.
In the event transmission and distribution equipment is determined to be exempt, Exelon, BGE, PHI, Pepco, and DPL will record estimated receivables of $ 100 million, $ 65 million, $ 35 million, $ 25 million, and $ 10 million, respectively. The sales tax payments were primarily capitalized; therefore, the refund would be recorded as a reduction to PP&E included in rate base.
General (All Registrants). The Registrants are involved in various other litigation matters that are being defended and handled in the ordinary course of business. The Registrants are also from time to time subject to audits and investigations by the FERC and other regulators. The assessment of whether a loss is probable or reasonably possible, and whether the loss or a range of loss is estimable, often involves a series of complex judgments about future events. The Registrants maintain accruals for such losses that are probable of being incurred and subject to reasonable estimation. Management is sometimes unable to estimate an amount or range of reasonably possible loss, particularly where (1) the damages sought are indeterminate, (2) the proceedings are in the early stages, or (3) the matters involve novel or unsettled legal theories. In such cases, there is considerable uncertainty regarding the timing or ultimate resolution of such matters, including a possible eventual loss.
12. Shareholders' Equity (Exelon)
At-the-Market 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.
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
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(Dollars in millions, except per share data, unless otherwise noted)
Note 12 — Shareholders' Equity
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 months ended March 31, 2026, approximately 26.5 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 March 31, 2026.
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 March 31, 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 ( 3 ) 4 1
Amounts reclassified from AOCI ( 2 ) 7 5
Net current-period OCI ( 5 ) 11 6
Balance at March 31, 2026 $ 28 $ ( 784 ) $ ( 756 )
Three Months Ended March 31, 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 ( 6 ) 5 ( 1 )
Amounts reclassified from AOCI ( 2 ) 5 3
Net current-period OCI ( 8 ) 10 2
Balance at March 31, 2025 $ 37 $ ( 755 ) $ ( 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 March 31,
2026 2025
Pension and non-pension postretirement benefit plans:
Actuarial losses reclassified to periodic benefit cost $ ( 2 ) $ ( 2 )
Pension and non-pension postretirement benefit plans valuation adjustments ( 1 ) ( 2 )
Unrealized gains on cash flow hedges 1 3
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 March 31, 2026
Utility taxes (a)
$ 275 $ 86 $ 57 $ 36 $ 96 $ 86 $ 9 $ 1
Property 125 10 5 63 47 31 15 1
Payroll 34 8 5 4 8 2 1 1
Three Months Ended March 31, 2025
Utility taxes (a)
$ 258 $ 81 $ 50 $ 34 $ 93 $ 84 $ 8 $ 1
Property 111 9 5 57 40 28 12 —
Payroll 33 8 5 5 7 1 1 1
_________
(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.
Other, net
Exelon ComEd PECO BGE PHI Pepco DPL ACE
Three Months Ended March 31, 2026
AFUDC — Equity $ 57 $ 21 $ 10 $ 15 $ 11 $ 9 $ 1 $ 1
Non-service net periodic benefit cost ( 10 ) — — — — — — —
Three Months Ended March 31, 2025
AFUDC — Equity $ 39 $ 12 $ 7 $ 9 $ 11 $ 8 $ 2 $ 1
Non-service net periodic benefit cost ( 13 ) — — — — — — —
Supplemental Cash Flow Information
The following tables provide additional information about material items recorded in the Registrants' Consolidated Statements of Cash Flows.
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(Dollars in millions, except per share data, unless otherwise noted)
Note 14 — Supplemental Financial Information
Depreciation, amortization, and accretion
Exelon ComEd PECO BGE PHI Pepco DPL ACE
Three Months Ended March 31, 2026
Property, plant, and equipment (a)
$ 794 $ 317 $ 120 $ 132 $ 211 $ 94 $ 59 ` $ 57
Amortization of regulatory assets and liabilities, net (a)
158 87 1 35 35 20 7 8
Amortization of intangible assets, net (a)
— — — — — — — —
ARO accretion (b)
1 — — — — — — —
Total depreciation, amortization, and accretion $ 953 $ 404 $ 121 $ 167 $ 246 $ 114 $ 66 $ 65
Three Months Ended March 31, 2025
Property, plant, and equipment (a)
$ 750 $ 302 $ 108 $ 124 $ 201 $ 88 $ 57 $ 55
Amortization of regulatory assets and liabilities, net (a)
152 78 1 40 33 17 6 9
Amortization of intangible assets, net (a)
2 — — — — — — —
ARO accretion (b)
1 — — — — — — —
Total depreciation, amortization, and accretion $ 905 $ 380 $ 109 $ 164 $ 234 $ 105 $ 63 $ 64
__________
(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.
Other non-cash operating activities
Exelon ComEd PECO BGE PHI Pepco DPL ACE
Three Months Ended March 31, 2026
Pension and OPEB costs $ 65 $ 27 $ 4 $ 7 $ 20 $ 7 $ 4 $ 2
Allowance for credit losses 109 17 43 26 23 11 7 5
True-up adjustments to decoupling mechanisms and formula rates (a)
40 ( 8 ) ( 5 ) 22 31 ( 1 ) 6 26
Amortization of operating ROU asset 6 — — 2 3 1 1 1
AFUDC — Equity ( 57 ) ( 21 ) ( 10 ) ( 15 ) ( 11 ) ( 9 ) ( 1 ) ( 1 )
Three Months Ended March 31, 2025
Pension and OPEB costs $ 68 $ 21 $ 2 $ 16 $ 25 $ 8 $ 4 $ 3
Allowance for credit losses 97 11 43 14 29 10 9 10
True-up adjustments to decoupling mechanisms and formula rates (a)
136 85 9 29 13 ( 2 ) 5 10
Amortization of operating ROU asset 9 — — 2 6 1 2 2
AFUDC — Equity ( 39 ) ( 12 ) ( 7 ) ( 9 ) ( 11 ) ( 8 ) ( 2 ) ( 1 )
__________
(a) For ComEd, reflects the true-up adjustments in Regulatory assets and liabilities associated with its distribution MRP and distribution, energy efficiency, distributed generation, and transmission formula rates. For PECO, reflects the change in Regulatory assets and liabilities associated with its transmission formula rates. For BGE, Pepco, DPL, and ACE, reflects the change in Regulatory assets and liabilities associated with their decoupling mechanisms and transmission formula rates. See Note 2 — Regulatory Matters of the 2025 Form 10-K for additional information.
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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
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.
Cash, cash equivalents, and restricted cash
Exelon ComEd PECO BGE PHI Pepco DPL ACE
Balance at March 31, 2026
Cash and cash equivalents $ 713 $ 95 $ 151 $ 173 $ 49 $ 20 $ 12 $ 12
Restricted cash and cash equivalents 560 487 — 7 31 20 10 1
Restricted cash included in Other deferred debits and other assets 24 24 — — — — — —
Total cash, restricted cash, and cash equivalents $ 1,297 $ 606 $ 151 $ 180 $ 80 $ 40 $ 22 $ 13
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
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.
Accrued expenses
Exelon ComEd PECO BGE PHI Pepco DPL ACE
Balance at March 31, 2026
Compensation-related accruals (a)
$ 395 $ 130 $ 55 $ 52 $ 66 $ 20 $ 14 $ 10
Taxes accrued 249 118 20 105 96 71 21 10
Interest accrued 466 105 55 91 85 37 28 19
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.
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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
The following table presents the service company costs allocated to the Registrants:
Operating and maintenance from affiliates Capitalized costs
Three Months Ended March 31, Three Months Ended March 31,
2026 2025 2026 2025
Exelon
BSC $ 134 $ 160
PHISCO 25 25
ComEd
BSC $ 103 $ 100 61 62
PECO
BSC 65 59 21 27
BGE
BSC 66 63 21 33
PHI
BSC 58 52 30 39
PHISCO — — 25 25
Pepco
BSC 35 32 13 17
PHISCO 32 31 10 10
DPL
BSC 22 20 9 12
PHISCO 24 25 7 8
ACE
BSC 17 16 7 8
PHISCO 26 23 7 7
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Combined Notes to Consolidated Financial Statements — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Note 15 — Related Party Transactions
Current Receivables from/Payables to Affiliates
The following tables present current Receivables from affiliates and current Payables to affiliates:
March 31, 2026
Receivables from affiliates:
Payables to affiliates: ComEd PECO BGE Pepco DPL ACE BSC PHISCO Other Total
ComEd $ — $ — $ — $ — $ — $ 70 $ — $ 2 $ 72
PECO $ — — — — — 36 — 5 41
BGE — — — — — 31 — 1 32
PHI (a)
— — — — — — 2 — 5 7
Pepco — — — — — 15 16 1 32
DPL — — — — — 10 14 1 25
ACE 3 — — — — 6 10 1 20
Other 4 2 1 1 2 12 ( 1 ) — 21
Total $ 7 $ 2 $ 1 $ 1 $ 2 $ 12 $ 169 $ 40 $ 16 $ 250
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:
March 31, 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 months ended March 31, 2026 compared to the same period in 2025. For additional information regarding the financial results for the three months ended March 31, 2026 and 2025, see the discussions of Results of Operations by Registrant.
Three Months Ended March 31, Favorable (Unfavorable) Variance
2026 2025
Exelon $ 919 $ 908 $ 11
ComEd 310 302 8
PECO 278 266 12
BGE 298 260 38
PHI 169 194 (25)
Pepco 68 97 (29)
DPL 77 69 8
ACE 27 31 (4)
Other (a)
(136) (114) (22)
__________
(a) Other primarily includes eliminating and consolidating adjustments, Exelon’s corporate operations, shared service entities, and other financing and investment activities.
Three Months Ended March 31, 2026 Compared to Three Months Ended March 31, 2025. Net income attributable to common shareholders increased by $11 million and diluted earnings per average common share remained relatively consistent to the prior year at $0.90 primarily due to:
• Favorable impacts of approved rate increases at ComEd, BGE and PHI;
• 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;
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• Higher depreciation expense at PECO and PHI;
• Higher interest expense at PECO and Exelon Corporate;
• 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.
The following table provides a reconciliation between GAAP Net income attributable to common shareholders and Adjusted (non-GAAP) operating earnings for the three months ended March 31, 2026 compared to the same period in 2025:
Three Months Ended March 31,
2026 2025
(In millions, except per share data) Earnings per
Diluted Share Earnings per
Diluted Share
Net income attributable to common shareholders $ 919 $ 0.90 $ 908 $ 0.90
Change in FERC audit liability (net of taxes of $1)
— — 2 —
Cost management charge (net of taxes of $0) (a)
— — (1) —
Regulatory matters (net of taxes of $4 and $7, respectively) (b)
11 0.01 22 0.02
Adjusted (non-GAAP) operating earnings $ 930 $ 0.91 $ 932 $ 0.92
__________
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 and reorganization costs related to cost management.
(b) Represents the disallowance of certain capitalized costs.
Significant 2026 Transactions and Developments
Distribution Base Rate Case Proceedings
The Utility Registrants file base rate cases with their regulatory commissions seeking increases or decreases to their electric transmission and distribution, and gas distribution rates to recover their costs and earn a fair return on their investments. The outcomes of these regulatory proceedings impact the Utility Registrants’ current and future financial statements.
The following tables show the Utility Registrants’ completed and pending distribution base rate case proceedings in 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
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 Electric $ 45 10.50% Third quarter of 2027
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.
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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.
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.
Allocation of Income Taxes to Regulated Utilities (All Registrants)
In Q2 2024, the IRS issued a series of PLRs, to another taxpayer, providing guidance with respect to the application of the tax normalization rules to the allocation of consolidated tax benefits among the members of a consolidated group associated with NOLC for ratemaking purposes. The rulings provide that for ratemaking purposes the tax benefit of NOLC should be reflected on a separate company basis not taking into consideration the utilization of losses by other affiliates. A PLR issued to another taxpayer may not be relied on as precedent.
For the Utility Registrants, except for PECO, the methodology prescribed by the IRS in these PLRs could result in a material reduction of the regulatory liability established for EDITs arising from the TCJA corporate tax rate change that are being amortized and flowed through to customers as well as a reduction in the accumulated deferred income taxes included in rate base for ratemaking purposes of approximately $1.2 billion - $1.7 billion.
The Utility Registrants, except for PECO, filed PLR requests with the IRS confirming the treatment of the NOLC for ratemaking purposes. The Utility Registrants will record the impact, if any, upon receiving the PLR from the IRS.
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Legislative and Regulatory Developments
Maryland Utility Relief Act
On April 13, 2026, the Maryland Utility RELIEF Act (Utility RELIEF Act) was passed through the Maryland General Assembly and awaits the Governor’s signature to become law. If and when the Utility RELIEF Act becomes law, it will modify the regulatory framework and rules governing recovery of certain costs in utility ratemaking in Maryland. Exelon, BGE, Pepco, and DPL are in the process of assessing the potential impacts of the pending legislation.
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 petitions for rehearing or clarification.
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.
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 March 31, 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
March 31, (Unfavorable) Favorable Variance
2026 2025
Operating revenues $ 1,913 $ 2,065 $ (152)
Operating expenses
Purchased power 451 689 238
Operating and maintenance 438 423 (15)
Depreciation and amortization 404 380 (24)
Taxes other than income taxes 105 99 (6)
Total operating expenses 1,398 1,591 193
Operating income 515 474 41
Other income and (deductions)
Interest expense, net (135) (128) (7)
Other, net 31 21 10
Total other income and (deductions) (104) (107) 3
Income before income taxes 411 367 44
Income taxes 101 65 (36)
Net income $ 310 $ 302 $ 8
Three Months Ended March 31, 2026 Compared to Three Months Ended March 31, 2025. Net Income increased by $8 million as compared to the same period in 2025 primarily due to higher distribution and transmission rate base driven by incremental investments to serve customers and higher AFUDC, offset by the timing of distribution earnings.
The changes in Operating revenues consisted of the following:
Three Months Ended
March 31, 2026
(Decrease) Increase
Distribution $ (8)
Transmission 20
Energy efficiency 8
Other 3
23
Regulatory required programs (175)
Total decrease $ (152)
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 decreased for the three months ended March 31, 2026 as compared to the same period in 2025, primarily due to lower fully recoverable costs.
Transmission Revenue. Under a FERC-approved formula, transmission revenue varies from year to year based upon fluctuations in the underlying costs, capital investments being recovered, and the highest daily peak load, which is updated annually in January based on the prior calendar year. Transmission revenues increased
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ComEd
for the three months ended March 31, 2026 compared to the same period in 2025, primarily due to higher fully recoverable costs and higher rate base.
Energy Efficiency Revenue. Energy efficiency revenues are under a performance-based formula rate, which requires an annual reconciliation of the revenue requirement in effect to the actual costs the ICC determines are prudently and reasonably incurred in a given year. Energy efficiency revenue varies from year to year based upon fluctuations in the underlying costs, investments being recovered, and allowed ROE. Energy efficiency revenues increased for the three months ended March 31, 2026 as compared to the same periods in 2025, primarily due to higher fully recoverable costs.
Other Revenue primarily includes assistance provided to other utilities through mutual assistance programs. Other revenues increased for the three months ended March 31, 2026 as compared to the same periods in 2025, which primarily reflects increased mutual assistance revenues associated with storm restoration efforts.
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 decrease of $238 million for the three months ended March 31, 2026 compared to the same period 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
March 31, 2026
Increase (Decrease)
Labor, other benefits, contracting, and materials $ 21
Storm-related costs 12
BSC costs 3
Pension and non-pension postretirement benefits expense 2
Other (a)
(20)
18
Regulatory required programs (3)
Total increase $ 15
__________
(a) Primarily reflects the probable disallowance of certain capitalized costs in regulatory matters during the three months ended March 31, 2025.
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ComEd
The changes in Depreciation and amortization expense consisted of the following:
Three Months Ended
March 31, 2026
Increase
Depreciation and amortization (a)
$ 15
Regulatory asset amortization 9
Total increase $ 24
__________
(a) Reflects ongoing capital expenditures.
Other , net increased $10 million for the three months ended March 31, 2026 compared to the same period in 2025, primarily due to higher AFUDC equity.
Effective income tax rat es were 24.6% and 17.7% for the three months ended March 31, 2026 and 2025, respectively. See Note 6 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the effective income tax rates.
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PECO
Results of Operations — PECO
Three Months Ended
March 31, Favorable (Unfavorable) Variance
2026 2025
Operating revenues $ 1,492 $ 1,333 $ 159
Operating expenses
Purchased power and fuel 612 502 (110)
Operating and maintenance 337 327 (10)
Depreciation and amortization 121 109 (12)
Taxes other than income taxes 69 60 (9)
Total operating expenses 1,139 998 (141)
Operating income 353 335 18
Other income and (deductions)
Interest expense, net (71) (63) (8)
Other, net 11 8 3
Total other income and (deductions) (60) (55) (5)
Income before income taxes 293 280 13
Income taxes 15 14 (1)
Net income $ 278 $ 266 $ 12
Three Months Ended March 31, 2026 Compared to Three Months Ended March 31, 2025. Net income increased by $12 million due to an increase in revenue as a result of the absence of surcharge credits to customers, favorable weather relative to the same period last year, and tax repairs, some of which is timing, partially offset by an increase in depreciation and interest expense.
The changes in Operating revenues consisted of the following:
Three Months Ended
March 31, 2026
Increase (Decrease)
Electric Gas Total
Weather $ 8 $ 8 $ 16
Volume (4) 1 (3)
Pricing 5 2 7
Transmission 12 — 12
Other (a)
25 4 29
46 15 61
Regulatory required programs 79 19 98
Total increase $ 125 $ 34 $ 159
__________
(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 months ended March 31, 2026 , compared to the same period in 2025, Operating revenues related to weather increased due to favorable weather conditions in PECO's service territory.
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
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PECO
PECO’s service territory for the three months ended March 31, 2026, compared to the same period in 2025, and normal weather consisted of the following:
Three Months Ended March 31, % Change
PECO Service Territory 2026 2025 Normal 2026 vs. 2025 2026 vs. Normal
Heating Degree-Days 2,399 2,351 2,359 2.0 % 1.7 %
Cooling Degree-Days 10 1 1 900.0 % 900.0 %
Volume. Electric volume, exclusive of the effects of weather, for the three months ended March 31, 2026 compared to the same period in 2025, remained relatively consistent. Natural gas volume for the three months ended March 31, 2026, compared to the same period in 2025, remained relatively consistent.
Electric Retail Deliveries to Customers (in GWhs) Three Months Ended March 31, % Change Weather -
Normal
% Change (b)
2026 2025
Residential 3,952 3,859 2.4 % 0.1 %
Small commercial & industrial 2,010 1,946 3.3 % 1.0 %
Large commercial & industrial 3,132 3,425 (8.6) % (10.0) %
Public authorities & electric railroads 176 189 (6.9) % (7.0) %
Total electric retail deliveries (a)
9,270 9,419 (1.6) % (3.5) %
At March 31,
Number of Electric Customers 2026 2025
Residential 1,544,881 1,540,453
Small commercial & industrial 154,634 155,131
Large commercial & industrial 3,149 3,151
Public authorities & electric railroads 10,108 10,703
Total 1,712,772 1,709,438
__________
(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.
Natural Gas Deliveries to Customers (in mmcf) Three Months Ended
March 31, % Change Weather -
Normal
% Change (b)
2026 2025
Residential 22,436 21,834 2.8 % (0.9) %
Small commercial & industrial 11,351 10,405 9.1 % 6.2 %
Large commercial & industrial (10) 12 (183.3) % (20.0) %
Transportation 7,142 7,242 (1.4) % (2.2) %
Total natural gas deliveries (a)
40,919 39,493 3.6 % 0.7 %
At March 31,
Number of Natural Gas Customers 2026 2025
Residential 511,085 509,773
Small commercial & industrial 44,642 44,869
Large commercial & industrial 7 7
Transportation 606 623
Total 556,340 555,272
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PECO
__________
(a) Reflects delivery volumes from customers purchasing natural gas directly from PECO and customers purchasing natural gas from a competitive natural gas supplier as all customers are assessed distribution charges.
(b) Reflects the change in delivery volumes assuming normalized weather based on the historical 30-year average.
Pricing for the three months ended March 31, 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 months ended March 31, 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 months ended March 31, 2026, compared to the same period in 2025, increased primarily due to the absence of electric surcharge credits to customers recognized in 2025.
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 $110 million for the three months ended March 31, 2026, compared to the same period in 2025, in Purchased power and fuel expense is fully offset in Operating revenues as part of regulatory required programs.
The changes in Operating and maintenance expense consisted of the following:
Three Months Ended
March 31, 2026
Increase (Decrease)
Labor, other benefits, contracting and materials $ 17
BSC costs 6
Pension and non-pension postretirement benefit expense 1
Credit loss expense (2)
Storm-related costs (6)
Other 13
29
Regulatory required programs (19)
Total increase $ 10
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PECO
The changes in Depreciation and amortization expense consisted of the following:
Three Months Ended
March 31, 2026
Increase
Depreciation and amortization (a)
$ 12
Total increase $ 12
__________
(a) Depreciation and amortization expense increased primarily due to ongoing capital expenditures.
Effective income tax rates were 5.1% and 5.0% for the three months ended March 31, 2026 and 2025, respectively. See Note 6 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the effective income tax rates.
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BGE
Results of Operations — BGE
Three Months Ended
March 31, Favorable (Unfavorable) Variance
2026 2025
Operating revenues $ 1,828 $ 1,554 $ 274
Operating expenses
Purchased power and fuel 808 609 (199)
Operating and maintenance 327 305 (22)
Depreciation and amortization 167 164 (3)
Taxes other than income taxes 104 96 (8)
Total operating expenses 1,406 1,174 (232)
Operating income 422 380 42
Other income and (deductions)
Interest expense, net (62) (58) (4)
Other, net 17 9 8
Total other income and (deductions) (45) (49) 4
Income before income taxes 377 331 46
Income taxes 79 71 (8)
Net income $ 298 $ 260 $ 38
Three Months Ended March 31, 2026 Compared to Three Months Ended March 31, 2025 . Net income increased $38 million primarily due to approved distribution rates and a decrease in various operating expenses, partially offset by an increase in credit loss expense.
The changes in Operating revenues consisted of the following:
Three Months Ended
March 31, 2026
Increase (Decrease)
Electric Gas Total
Distribution $ 4 $ 22 $ 26
Transmission (2) — (2)
Other 9 2 11
11 24 35
Regulatory required programs 223 16 239
Total increase $ 234 $ 40 $ 274
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.
At March 31,
Number of Electric Customers 2026 2025
Residential 1,226,941 1,220,769
Small commercial & industrial 115,253 115,359
Large commercial & industrial 13,372 13,302
Public authorities & electric railroads 251 258
Total 1,355,817 1,349,688
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BGE
At March 31,
Number of Natural Gas Customers 2026 2025
Residential 663,324 661,195
Small commercial & industrial 37,735 37,945
Large commercial & industrial 6,421 6,380
Total 707,480 705,520
Distribution Revenue increased for the three months ended March 31, 2026, compared to the same period in 2025, due to favorable impacts of the multi-year plans.
Transmission Revenue. Under a FERC-approved formula, transmission revenue varies from year to year based upon fluctuations in the underlying costs and capital investments being recovered. Transmission revenue for the three months ended March 31, 2026, compared to the same period in 2025 remained relatively consistent.
Other Revenue includes revenue related to late payment charges, mutual assistance, off-system sales, and service application fees. Other Revenue increased for the three months ended March 31, 2026 as compared to the same period in 2025, primarily driven by increases in late payment charges.
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 $199 million for the three months ended March 31, 2026, compared to the same period in 2025, in Purchased power and fuel expense is fully offset in Operating revenues as part of regulatory required programs.
The changes in Operating and maintenance expense consisted of the following:
Three Months Ended
March 31, 2026
Increase (Decrease)
Credit loss expense $ 11
BSC costs 3
Pension and non-pension postretirement benefits expense (5)
Labor, other benefits, contracting and materials (16)
Other 1
(6)
Regulatory required programs (a)
28
Total increase $ 22
__________
(a) Reflects the cost recovery associated with EmPOWER Maryland. Please refer to 2025 10-K Note 2 — Regulatory Matters for additional information.
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BGE
The changes in Depreciation and amortization expense consisted of the following:
Three Months Ended
March 31, 2026
Increase (Decrease)
Depreciation and amortization $ 9
Regulatory required programs (a)
3
Regulatory asset amortization (9)
Total increase $ 3
__________
(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 $8 million for the three months ended March 31, 2026, compared to the same period in 2025, primarily due to increased property taxes.
Effective income tax rates were 21.0% and 21.5% for the three months ended March 31, 2026 and 2025. See Note 6 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the effective income tax rates.
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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 months ended March 31, 2026 compared to the same period in 2025. See the Results of Operations for Pepco, DPL, and ACE for additional information.
Three Months Ended March 31, (Unfavorable) Favorable Variance
2026 2025
PHI $ 169 $ 194 $ (25)
Pepco 68 97 (29)
DPL
77 69 8
ACE 27 31 (4)
Other (a)
(3) (3) —
__________
(a) Primarily includes eliminating and consolidating adjustments, PHI's corporate operations, shared service entities, and other financing and investing activities.
Three Months Ended March 31, 2026 Compared to Three Months Ended March 31, 2025. Net Income decreased by $25 million primarily due to unfavorable impacts of the Pepco Maryland multi-year plan reconciliation and related disallowance of capitalized costs, an increase in depreciation expense, storm costs, and interest expense, partially offset by approved transmission rates, favorable weather conditions at DPL and approved Delaware electric DSIC and natural gas rates.
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Pepco
Results of Operations — Pepco
Three Months Ended March 31, Favorable (Unfavorable) Variance
2026 2025
Operating revenues $ 989 $ 859 $ 130
Operating expenses
Purchased power 411 318 (93)
Operating and maintenance 218 159 (59)
Depreciation and amortization 114 105 (9)
Taxes other than income taxes 118 113 (5)
Total operating expenses 861 695 (166)
Loss on sale of assets — (1) 1
Operating income 128 163 (35)
Other income and (deductions)
Interest expense, net (55) (52) (3)
Other, net 11 11 —
Total other income and (deductions) (44) (41) (3)
Income before income taxes 84 122 (38)
Income taxes 16 25 9
Net income $ 68 $ 97 $ (29)
Three Months Ended March 31, 2026 Compared to Three Months Ended March 31, 2025. Net Income decreased by $29 million primarily due to unfavorable impacts of the Pepco Maryland multi-year plan reconciliation and related disallowance of capitalized costs, and increases in depreciation and interest expense.
The changes in Operating revenues consisted of the following:
Three Months Ended
March 31, 2026
Increase
Distribution $ 2
Transmission 3
Other 6
11
Regulatory required programs 119
Total increase $ 130
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.
At March 31,
Number of Electric Customers in Maryland 2026 2025
Residential 560,946 557,672
Small commercial & industrial 30,637 30,555
Large commercial & industrial 19,058 18,986
Public authorities & electric railroads 181 177
Total 610,822 607,390
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Pepco
Distribution Revenue increased for the three months ended March 31, 2026 compared to the same period in 2025 primarily due to favorable impacts of the District of Columbia multi-year plans and customer growth in Maryland.
Transmission Revenue. Under a FERC-approved formula, transmission revenue varies from year to year based upon fluctuations in the underlying costs and capital investments being recovered. Transmission revenue increased for the three months ended March 31, 2026, compared to the same period in 2025, primarily due to increases in underlying costs and capital investments.
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 $93 million for the three months ended March 31, 2026, respectively, compared to the same period in 2025, in Purchased power expense is fully offset in Operating revenues as part of regulatory required programs.
The changes in Operating and maintenance expense consisted of the following:
Three Months Ended
March 31, 2026
Increase (Decrease)
Maryland multi-year plan reconciliation (a)
$ 26
Labor, other benefits, contracting, and materials 9
BSC and PHISCO costs 5
Storm-related costs 1
Other (3)
38
Regulatory required programs (b)
21
Total increase $ 59
________ _
(a) Reflects unfavorable impacts of the Pepco Maryland multi-year plan reconciliation. See Note 2 — Regulatory Matters for additional information.
(b) Reflects the cost recovery associated with EmPOWER Maryland. Please refer to 2025 10-K Note 2 — Regulatory Matters for additional information.
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Pepco
The changes in Depreciation and amortization expense consisted of the following:
Three Months Ended
March 31, 2026
Increase
Depreciation and amortization (a)
$ 6
Regulatory asset amortization 1
Regulatory required programs (b)
2
Total increase $ 9
__________
(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.
Effective income tax rates were 19.0% and 20.5% for the three months ended March 31, 2026 and 2025, respectively. See Note 6 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the effective income tax rates.
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DPL
Results of Operations — DPL
Three Months Ended March 31, Favorable (Unfavorable) Variance
2026 2025
Operating revenues $ 622 $ 548 $ 74
Operating expenses
Purchased power and fuel 289 247 (42)
Operating and maintenance 118 106 (12)
Depreciation and amortization 66 63 (3)
Taxes other than income taxes 26 21 (5)
Total operating expenses 499 437 (62)
Operating income 123 111 12
Other income and (deductions)
Interest expense, net (27) (25) (2)
Other, net 4 4 —
Total other income and (deductions) (23) (21) (2)
Income before income taxes 100 90 10
Income taxes 23 21 (2)
Net income $ 77 $ 69 $ 8
Three Months Ended March 31, 2026 Compared to Three Months Ended March 31, 2025. Net income increased by $8 million primarily due to approved Delaware electric DSIC and natural gas rates, favorable weather conditions at Delaware electric and natural gas service territories, partially offset by an increase in storm costs.
The changes in Operating revenues consisted of the following:
Three Months Ended
March 31, 2026
Increase (Decrease)
Electric Gas Total
Weather $ 3 $ 2 $ 5
Volume 1 (1) —
Distribution 6 10 16
Transmission 2 — 2
Other — — —
12 11 23
Regulatory required programs 33 18 51
Total increase $ 45 $ 29 $ 74
Revenue Decoupling. The demand for electricity is affected by weather and customer usage. However, Operating revenues from electric distribution in Maryland are not impacted by abnormal weather or usage per customer as a result of a BSA that provides for a fixed distribution charge per customer by customer class. While Operating revenues from electric distribution customers in Maryland are not intended to be impacted by abnormal weather or usage per customer, they are impacted by changes in the number of customers.
Weather. The demand for electricity and natural gas in Delaware is affected by weather conditions. With respect to the electric business, very warm weather in summer months and, with respect to the electric and natural gas businesses, very cold weather in winter months are referred to as "favorable weather conditions” because these weather conditions result in increased deliveries of electricity and natural gas. Conversely, mild weather reduces demand. During the three months ended March 31, 2026 compared to the same period in 2025, Operating revenues related to weather increased due to favorable weather conditions in DPL's Delaware electric and natural gas service territories.
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DPL
Heating and cooling degree days are quantitative indices that reflect the demand for energy needed to heat or cool a home or business. Normal weather is determined based on historical average heating and cooling degree days for a 20-year period in DPL's Delaware electric service territory and a 30-year period in DPL's Delaware natural gas service territory. The changes in heating and cooling degree days in DPL's Delaware service territory for the three months ended March 31, 2026, compared to same period in 2025 and normal weather consisted of the following:
Three Months Ended March 31, % Change
Delaware Electric Service Territory 2026 2025 Normal 2026 vs. 2025 2026 vs. Normal
Heating Degree-Days 2,531 2,399 2,406 5.5 % 5.2 %
Cooling Degree-Days 9 9 1 — % 800.0 %
Three Months Ended March 31, % Change
Delaware Natural Gas Service Territory 2026 2025 Normal 2026 vs. 2025 2026 vs. Normal
Heating Degree-Days 2,531 2,399 2,449 5.5 % 3.3 %
Volume, exclusive of the effects of weather, remained relatively consistent for the three months ended March 31, 2026 compared to the same period in 2025.
Electric Retail Deliveries to Delaware Customers (in GWhs) Three Months Ended
March 31, % Change Weather - Normal
% Change (b)
2026 2025
Residential 974 930 4.7 % 1.1 %
Small commercial & industrial 367 354 3.7 % 1.8 %
Large commercial & industrial 687 690 (0.4) % (1.0) %
Public authorities & electric railroads 7 7 — % (2.8) %
Total electric retail deliveries (a)
2,035 1,981 2.7 % 0.5 %
At March 31,
Number of Total Electric Customers (Maryland and Delaware) 2026 2025
Residential 496,074 491,907
Small commercial & industrial 65,604 64,999
Large commercial & industrial 1,288 1,251
Public authorities & electric railroads 628 617
Total 563,594 558,774
__________
(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
March 31, % Change Weather - Normal
% Change (b)
2026 2025
Residential 4,678 4,590 1.9 % (2.3) %
Small commercial & industrial 2,128 1,970 8.0 % 3.0 %
Large commercial & industrial 429 428 0.2 % 0.2 %
Transportation 2,027 2,106 (3.8) % (6.1) %
Total natural gas deliveries (a)
9,262 9,094 1.8 % (1.9) %
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DPL
At March 31,
Number of Delaware Natural Gas Customers 2026 2025
Residential 132,419 131,716
Small commercial & industrial 10,285 10,254
Large commercial & industrial 14 15
Transportation 159 161
Total 142,877 142,146
__________
(a) Reflects delivery volumes from customers purchasing natural gas directly from DPL and customers purchasing natural gas from a competitive natural gas supplier as all customers are assessed distribution charges.
(b) Reflects the change in delivery volumes assuming normalized weather based on the historical 30-year average.
Distribution Revenue increased for the three months ended March 31, 2026 compared to the same period in 2025 primarily due to Delaware natural gas rates that became effective in 2025 & electric DSIC rates that became effective in 2026.
Transmission Revenue. Under a FERC-approved formula, transmission revenue varies from year to year based upon fluctuations in the underlying costs and capital investments being recovered. During the three months ended March 31, 2026 compared to the same period in 2025, transmission revenue remained relatively consistent.
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.
See Note 4 — Segment Information of the Combined Notes to Consolidated Financial Statements for the presentation of DPL's revenue disaggregation.
The increase of $42 million for the three months ended March 31, 2026, respectively, compared to the same period in 2025 in Purchased power and fuel expense is fully offset in Operating revenues as part of regulatory required programs.
The changes in Operating and maintenance expense consisted of the following:
Three Months Ended
March 31, 2026
Increase (Decrease)
Storm-related costs $ 5
Labor, other benefits, contracting, and materials 2
Credit loss expense (2)
5
Regulatory required programs (a)
7
Total increase $ 12
__________
(a) 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.
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DPL
The changes in Depreciation and amortization expense consisted of the following:
Three Months Ended
March 31, 2026
Increase
Depreciation and amortization (a)
$ 2
Regulatory asset amortization —
Regulatory required programs (b)
1
Total increase $ 3
__________
(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 $5 million for the three months ended March 31, 2026, respectively, compared to the same period in 2025 primarily due to an increase in property taxes.
Effective income tax rates were 23.0% and 23.3% for the three months ended March 31, 2026 and 2025, respectively. See Note 6 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the effective income tax rates.
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ACE
Results of Operations — ACE
Three Months Ended March 31, Favorable (Unfavorable) Variance
2026 2025
Operating revenues $ 421 $ 373 $ 48
Operating expenses
Purchased power 205 157 (48)
Operating and maintenance 93 90 (3)
Depreciation and amortization 65 64 (1)
Taxes other than income taxes 2 2 —
Total operating expenses 365 313 (52)
Operating income 56 60 (4)
Other income and (deductions)
Interest expense, net (22) (21) (1)
Other, net 2 3 (1)
Total other income and (deductions) (20) (18) (2)
Income before income taxes 36 42 (6)
Income taxes 9 11 2
Net income $ 27 $ 31 $ (4)
Three Months Ended March 31, 2026 Compared to Three Months Ended March 31, 2025 . Net income decreased by $4 million primarily due to an increase in storms costs and depreciation expense, partially offset by an increase in approved transmission rates.
The changes in Operating revenues consisted of the following:
Three Months Ended
March 31, 2026
(Decrease) Increase
Distribution $ (1)
Transmission 3
2
Regulatory required programs 46
Total increase $ 48
Revenue Decoupling. The demand for electricity is affected by weather and customer usage. However, Operating revenues from electric distribution in New Jersey are not intended to be impacted by abnormal weather or usage per customer as a result of the CIP which compares current distribution revenues by customer class to approved target revenues established in ACE’s most recent distribution base rate case. The CIP is calculated annually, and recovery is subject to certain conditions, including an earnings test and ceilings on customer rate increases. While Operating revenues are not impacted by abnormal weather or usage per customer, they are impacted by changes in the number of customers.
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ACE
At March 31,
Number of Electric Customers 2026 2025
Residential 510,569 508,354
Small commercial & industrial 63,174 62,861
Large commercial & industrial 2,660 2,824
Public authorities & electric railroads 756 723
Total 577,159 574,762
Distribution Revenue remained relatively consistent for the three months ended March 31, 2026 compared to the same period in 2025.
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 months ended March 31, 2026 compared to the same period 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 $48 million for the three months ended March 31, 2026, respectively, compared to the same period in 2025 in Purchased power expense is fully offset in Operating revenues as part of regulatory required programs.
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ACE
The changes in Operating and maintenance expense consisted of the following:
Three Months Ended
March 31, 2026
(Decrease) Increase
Storm-related costs $ 4
Credit Loss Expense (2)
Other (1)
1
Regulatory required programs 2
Total increase $ 3
The changes in Depreciation and amortization expense consisted of the following:
Three Months Ended
March 31, 2026
Increase (Decrease)
Depreciation and amortization (a)
$ 2
Regulatory asset amortization 4
Regulatory required programs (5)
Total increase $ 1
__________
(a) Depreciation and amortization increased primarily due to ongoing capital expenditures.
Effective income tax rates were 25.0% and 26.2% for the three months ended March 31, 2026 and 2025, respectively. See Note 6 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the effective income tax rates.
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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 three months ended March 31, 2026 and 2025 by Registrant:
Increase (decrease) in cash flows from operating activities Exelon ComEd PECO BGE PHI Pepco DPL ACE
Net income (loss) $ 11 $ 8 $ 12 $ 38 $ (25) $ (29) $ 8 $ (4)
Adjustments to reconcile net income to cash:
Non-cash operating activities 148 (17) 288 148 88 57 18 32
Collateral received, net 1 47 (12) 3 (37) (22) (2) (11)
Income taxes (203) (43) (294) (147) (70) (43) (16) (24)
Pension and non-pension postretirement benefit contributions (54) (31) (3) (6) (10) — (1) (10)
Regulatory assets and liabilities, net (415) (426) (82) 57 23 22 1 (4)
Changes in working capital and other assets and liabilities 1,036 847 (23) (8) 105 81 22 3
Increase (decrease) in cash flows from operating activities $ 524 $ 385 $ (114) $ 85 $ 74 $ 66 $ 30 $ (18)
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 three months ended March 31, 2026 to the three months ended March 31, 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 three months ended March 31, 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 $236 million and a reduction in regulatory assets of $162 million related to carbon mitigation credits for the three months ended March 31, 2026 and 2025, respectively. 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 $84 million for the three months ended March 31, 2026 and 2025, respectively. Additionally, ComEd recognized changes in the distributed generation rebates programs of $29 million and $19 million for the three months ended March 31, 2026 and 2025, respectively. Also included within the changes is energy efficiency and demand response programs spend for DPL and ACE of $1 million and $15 million for the three
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months ended March 31, 2026 and $3 million, and $5 million for the three months ended March 31, 2025, respectively. BGE and Pepco had no energy efficiency and demand response programs spend recorded to the regulatory asset for the three months ended March 31, 2026 and $22 million and $6 million for three months ended March 31, 2025. PECO had no energy efficiency and demand response programs spend recorded to the regulatory asset for the three months ended March 31, 2026 and 2025.
• Changes in working capital and other assets and liabilities for the Utility Registrants and Exelon Corporate totaled $922 million and $1,036 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 three months ended March 31, 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 decrease in the Carbon mitigation credit regulatory liability. 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 three months ended March 31, 2026 and 2025 by Registrant:
(Decrease) increase in cash flows from investing activities Exelon ComEd PECO BGE PHI Pepco DPL ACE
Capital expenditures $ (412) $ (295) $ (45) $ (31) $ (45) $ (45) $ 9 $ (17)
Proceeds from sales of assets — — — — — — — —
Changes in intercompany money pool — — (5) — — — 12 —
Other investing activities (2) (1) (3) 1 — — — —
(Decrease) increase in cash flows from investing activities $ (414) $ (296) $ (53) $ (30) $ (45) $ (45) $ 21 $ (17)
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 three months ended March 31, 2026 and 2025 by Registrant:
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(Decrease) increase in cash flows from financing activities Exelon ComEd PECO BGE PHI Pepco DPL ACE
Changes in short-term borrowings, net $ 828 $ (265) $ 192 $ (62) $ 37 $ (30) $ 29 $ 38
Long-term debt, net (1,305) — — — (80) (30) (50) —
Changes in intercompany money pool — — — — 29 — — (12)
Issuance of common stock (173) — — — — — — —
Dividends paid on common stock (27) (15) — (16) — 2 (4) (5)
Distributions to member — — — — (7) — — —
Contributions from parent/member — 169 4 — (77) (18) (54) (3)
Other financing activities 20 — — — 1 2 — 1
(Decrease) increase in cash flows from financing activities $ (657) $ (111) $ 196 $ (78) $ (97) $ (74) $ (79) $ 19
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 first quarter of 2025. See Note 12 — Shareholders' Equity of the Combined Notes to Consolidated Financial Statements for additional information.
• Exelon’s ability to pay dividends on its common stock depends on the receipt of dividends paid by its operating subsidiaries. The payments of dividends to Exelon by its subsidiaries in turn depend on their results of operations and cash flows and other items affecting retained earnings. See Note 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 three months ended March 31, 2026, no long-term debt was retired and/or redeemed. Exelon repaid $750 million of its Senior Notes on the maturity date of April 15, 2026.
Dividends
Quarterly dividends declared by the Exelon Board of Directors during the three months ended March 31, 2026 and for the second 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
__________
(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 $3.8 billion was available to support additional commercial paper as of March 31, 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 three months ended March 31, 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.
In the first quarter of 2026, Exelon entered into various forward sale agreements under the 2025 ATM programs. The forward sale agreements require Exelon to, at its election prior to the maturity date, either (i) physically settle the transactions by issuing shares of its Common stock to the forward counterparties in exchange for net proceeds at the then-applicable forward sale price specified by the agreements or (ii) net settle the transactions in whole or in part through the delivery to the forward counterparties or receipt from the forward counterparties of cash or shares in accordance with the provisions of the agreements. The following forward sale agreements were entered into under Exelon’s ATM program in the first quarter of 2026:
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:
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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 months ended March 31, 2026, approximately 26.5 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 March 31, 2026.
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 March 31, 2026 and available credit facility capacity prior to any incremental collateral at March 31, 2026:
PJM Credit Policy Collateral Other Incremental Collateral Required (a)
Available Credit Facility Capacity Prior to Any Incremental Collateral
ComEd $ 19 $ — $ 936
PECO 4 38 595
BGE 5 20 573
Pepco — — 225
DPL — 23 253
ACE — — 299
__________
(a) Represents incremental collateral related to natural gas procurement contracts.
Capital Expenditure Spending
As of March 31, 2026, the most recent estimates of capital expenditures for plant additions and improvements for 2026 are as follows:
(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
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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 requirements primarily through the issuance of commercial paper. PECO meets its short-term liquidity requirements primarily through the issuance of commercial paper and borrowings from the Exelon intercompany money pool. Pepco, DPL, and ACE meet their short-term liquidity requirements primarily through the issuance of commercial paper and borrowings from the PHI intercompany money pool. PHI Corporate meets its short-term liquidity requirements primarily through the issuance of short-term notes and the Exelon intercompany money pool. The Registrants may use their respective credit facilities for general corporate purposes, including meeting short-term funding requirements and the issuance of letters of credit.
See Note 9 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information on the Registrants’ credit facilities and short term borrowing activity.
Security Ratings
The Registrants’ access to the capital markets, including the commercial paper market, and their respective financing costs in those markets, may depend on the securities ratings of the entity that is accessing the capital markets.
The Registrants’ borrowings are not subject to default or prepayment as a result of a downgrading of securities, although such a downgrading of a Registrant’s securities could increase fees and interest charges under that Registrant’s credit agreements.
As part of the normal course of business, the Registrants enter into contracts that contain express provisions or otherwise permit the Registrants and their counterparties to demand adequate assurance of future performance when there are reasonable grounds for doing so. In accordance with the contracts and applicable contracts law, if the Registrants are downgraded by a credit rating agency, it is possible that a counterparty would attempt to rely on such a downgrade as a basis for making a demand for adequate assurance of future performance, which could include the posting of collateral. See Note 8 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information on collateral provisions.
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The credit ratings for the Registrants did not change for the three months ended March 31, 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-'. S&P also lowered its short-term and commercial paper rating for BGE from 'A-1' to 'A-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 March 31, 2026, are presented in the following table:
During the Three Months Ended March 31, 2026 At March 31, 2026
Exelon Intercompany Money Pool Maximum
Contributed Maximum
Borrowed Contributed
(Borrowed)
Exelon Corporate $ 502 $ — $ 373
PECO 343 (63) 5
BSC — (461) (322)
PHI Corporate — (134) (120)
PCI 64 — 64
During the Three Months Ended March 31, 2026 At March 31, 2026
PHI Intercompany Money Pool Maximum
Contributed Maximum
Borrowed
Contributed
(Borrowed)
Pepco $ 6 $ — $ —
DPL — (6) —
ACE — — —
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 factors at the time of the proposed sale, including other required regulatory approvals, as applicable, the current financial condition of the Registrant, its securities ratings, and market conditions.
Pepco, DPL, and ACE periodically issue securities through the private placement markets. Pepco, DPL and ACE's ability to access the private placement markets will depend on a number of factors at the time of the proposed sale, including other required regulatory approvals, as applicable, current financial condition, securities ratings and market conditions.
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Regulatory Authorizations
The Utility Registrants are required to obtain short-term and long-term financing authority from Federal and State Commissions as follows:
At March 31, 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 $ 4,393
PECO FERC December 31, 2027 1,500 PAPUC December 31, 2027 1,850
BGE FERC December 31, 2027 900 MDPSC N/A 1,850
Pepco (a)
FERC December 31, 2027 700 MDPSC / DCPSC December 31, 2028 930
DPL (a)
FERC December 31, 2027 700 MDPSC / DEPSC December 31, 2028 625
ACE 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.
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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) $ (15) $ (22) $ (22) $ (23) $ (21) $ (30) $ (133)
_________
(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 March 31, 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 first 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 March 31, 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 first quarter of 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 March 31, 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 March 31, 2026, except as follows:
On March 13, 2026 , Calvin G. Butler, Jr. , President and Chief Executive Officer, Exelon Corporation, adopted a Rule 10b5-1 trading arrangement that is intended to satisfy the affirmative defense of Rule 10b5-1(c) for the sale of up to 246,000 shares of Exelon's common stock in multiple transactions, subject to certain price limitations set forth in the trading arrangement. Mr. Butler's 10b5-1 trading arrangement will terminate on December 19, 2026 , unless sooner terminated according to 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
Exelon Corporation
Exhibit No. Description Location
4-1
Ninth Supplemental Indenture, dated as of February 1, 2026, among Exelon Corporation and The Bank of New York Mellon Trust Company, N.A., as trustee File No. 001-16169, Form 8-K dated February 20, 2026, Exhibit 4.2
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Atlantic City Electric Company
Exhibit No. Description Location
4-2
ACE Supplemental Indenture to the Mortgage and Deed of Trust, dated as of March 1, 2026 File No. 001-03559, Form 8-K dated March 19, 2026, Exhibit 4.2
Delmarva Power & Light Company
Exhibit No. Description Location
4-3
DPL Supplemental Indenture to the Mortgage and Deed of Trust, dated as of March 1, 2026 File No. 001-01405, Form 8-K dated March 19, 2026, Exhibit 4.4
Potomac Electric Power Company
Exhibit No. Description Location
4-4
Pepco Supplemental Indenture to the Mortgage and Deed of Trust, dated as of March 1, 2026 File No. 001-01072, Form 8-K dated March 19, 2026, Exhibit 4.6
(10) Material Contracts
Exelon Corporation
Exhibit No. Description Location
10-1
Form of Restricted Stock Unit Award Notice and Agreement under the Non-Employee Directors’ Restricted Stock Unit Program Filed herewith.
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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 March 31, 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. Innocen zo 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 March 31, 2026 filed by the following officers for the following companies:
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Table of Contents
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)
May 6, 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)
May 6, 2026
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Table of Contents
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)
May 6, 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