FULLTEXT DEL 3 AV 4
10-Q – 2026-07-30 – exc-20260630.htm
Supplemental cash flow information
Decrease in capital expenditures not paid $ ( 68 ) $ ( 64 )
See the Combined Notes to Consolidated Financial Statements
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Potomac Electric Power Company
Balance Sheets
(Unaudited)
(In millions) June 30, 2026 December 31, 2025
ASSETS
Current assets
Cash and cash equivalents $ 21 $ 22
Restricted cash and cash equivalents 31 33
Accounts receivable
Customer accounts receivable 495 484
Customer allowance for credit losses ( 77 ) ( 69 )
Customer accounts receivable, net 418 415
Other accounts receivable 165 154
Other allowance for credit losses ( 25 ) ( 26 )
Other accounts receivable, net 140 128
Receivable from PHI intercompany money pool 95 —
Inventories, net 186 174
Regulatory assets 162 182
Prepaid renewable energy credits 89 171
Other 17 59
Total current assets 1,159 1,184
Property, plant, and equipment (net of accumulated depreciation and amortization of $ 4,933 and $ 4,784 as of June 30, 2026 and December 31, 2025, respectively)
11,007 10,747
Deferred debits and other assets
Regulatory assets 391 405
Investments 144 141
Prepaid pension asset 182 194
Other 68 57
Total deferred debits and other assets 785 797
Total assets $ 12,951 $ 12,728
See the Combined Notes to Consolidated Financial Statements
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Potomac Electric Power Company
Balance Sheets
(Unaudited)
(In millions) June 30, 2026 December 31, 2025
LIABILITIES AND SHAREHOLDER'S EQUITY
Current liabilities
Short-term borrowings $ — $ 303
Long-term debt due within one year 7 6
Accounts payable 383 418
Accrued expenses 172 173
Payables to affiliates 41 37
Customer deposits 65 61
Regulatory liabilities 14 13
Renewable energy credit obligations 90 174
Other 86 84
Total current liabilities 858 1,269
Long-term debt 4,924 4,626
Deferred credits and other liabilities
Deferred income taxes and unamortized investment tax credits 1,664 1,604
Regulatory liabilities 279 268
Asset retirement obligations 39 45
Other 203 214
Total deferred credits and other liabilities 2,185 2,131
Total liabilities 7,967 8,026
Commitments and contingencies
Shareholder's equity
Common stock 3,798 3,528
Retained earnings 1,186 1,174
Total shareholder's equity 4,984 4,702
Total liabilities and shareholder's equity $ 12,951 $ 12,728
See the Combined Notes to Consolidated Financial Statements
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Potomac Electric Power Company
Statements Of Changes In Shareholder's Equity
(Unaudited)
Six Months Ended June 30, 2026
(In millions) Common Stock Retained Earnings Total Shareholder's Equity
Balance at December 31, 2025 $ 3,528 $ 1,174 $ 4,702
Net income — 68 68
Common stock dividends — ( 64 ) ( 64 )
Contributions from parent 139 — 139
Balance at March 31, 2026 $ 3,667 $ 1,178 $ 4,845
Net income — 65 65
Common stock dividends — ( 57 ) ( 57 )
Contributions from parent 131 — 131
Balance at June 30, 2026 $ 3,798 $ 1,186 $ 4,984
Six Months Ended June 30, 2025
(In millions) Common Stock Retained Earnings Total Shareholder's Equity
Balance at December 31, 2024 $ 3,335 $ 1,100 $ 4,435
Net income — 97 97
Common stock dividends — ( 66 ) ( 66 )
Contributions from parent 157 — 157
Balance at March 31, 2025 $ 3,492 $ 1,131 $ 4,623
Net income — 84 84
Common stock dividends — ( 92 ) ( 92 )
Contributions from parent — — —
Balance at June 30, 2025 $ 3,492 $ 1,123 $ 4,615
See the Combined Notes to Consolidated Financial Statements
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Delmarva Power & Light Company
Statements of Operations and Comprehensive Income
(Unaudited)
Three Months Ended
June 30, Six Months Ended
June 30,
(In millions) 2026 2025 2026 2025
Operating revenues
Electric operating revenues $ 410 $ 386 $ 920 $ 850
Natural gas operating revenues 40 33 157 120
Revenues from alternative revenue programs 2 — ( 5 ) ( 5 )
Operating revenues from affiliates 2 2 4 4
Total operating revenues 454 421 1,076 969
Operating expenses
Purchased power 176 161 410 370
Purchased fuel 19 11 73 49
Operating and maintenance 62 50 134 110
Operating and maintenance from affiliates 50 45 97 91
Depreciation and amortization 67 63 133 126
Taxes other than income taxes 24 20 50 41
Total operating expenses 398 350 897 787
Operating income 56 71 179 182
Other income and (deductions)
Interest expense, net ( 26 ) ( 25 ) ( 53 ) ( 50 )
Other, net 4 4 8 8
Total other income and (deductions) ( 22 ) ( 21 ) ( 45 ) ( 42 )
Income before income taxes 34 50 134 140
Income taxes 8 11 31 32
Net income $ 26 $ 39 $ 103 $ 108
Comprehensive income $ 26 $ 39 $ 103 $ 108
See the Combined Notes to Consolidated Financial Statements
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Delmarva Power & Light Company
Statements Of Cash Flows
(Unaudited)
Six Months Ended
June 30,
(In millions) 2026 2025
Cash flows from operating activities
Net income $ 103 $ 108
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation and amortization 133 126
Deferred income taxes and amortization of investment tax credits 28 15
Other non-cash operating activities 29 30
Changes in assets and liabilities:
Accounts receivable 55 11
Receivables from and payables to affiliates, net 2 ( 3 )
Inventories 1 ( 11 )
Accounts payable and accrued expenses ( 11 ) 3
Collateral (paid) received, net ( 1 ) 3
Income taxes ( 14 ) ( 2 )
Regulatory assets and liabilities, net ( 4 ) ( 22 )
Pension and non-pension postretirement benefit contributions ( 1 ) ( 1 )
Other assets and liabilities 30 24
Net cash flows provided by operating activities 350 281
Cash flows from investing activities
Capital expenditures ( 300 ) ( 277 )
Other investing activities 1 —
Net cash flows used in investing activities ( 299 ) ( 277 )
Cash flows from financing activities
Changes in short-term borrowings ( 129 ) ( 142 )
Issuance of long-term debt 75 125
Changes in PHI intercompany money pool 47 —
Dividends paid on common stock ( 86 ) ( 90 )
Contributions from parent 45 99
Other financing activities ( 5 ) ( 5 )
Net cash flows used in financing activities ( 53 ) ( 13 )
Decrease in cash, restricted cash, and cash equivalents ( 2 ) ( 9 )
Cash, restricted cash, and cash equivalents at beginning of period 12 23
Cash, restricted cash, and cash equivalents at end of period $ 10 $ 14
Supplemental cash flow information
Decrease in capital expenditures not paid $ ( 60 ) $ ( 45 )
See the Combined Notes to Consolidated Financial Statements
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Delmarva Power & Light Company
Balance Sheets
(Unaudited)
(In millions) June 30, 2026 December 31, 2025
ASSETS
Current assets
Cash and cash equivalents $ 8 $ 9
Restricted cash and cash equivalents 2 3
Accounts receivable
Customer accounts receivable 196 253
Customer allowance for credit losses ( 21 ) ( 19 )
Customer accounts receivable, net 175 234
Other accounts receivable 72 75
Other allowance for credit losses ( 11 ) ( 10 )
Other accounts receivable, net 61 65
Receivables from affiliates 4 2
Inventories, net
Fossil fuel 7 9
Materials and supplies 108 107
Prepaid utility taxes — 29
Regulatory assets 82 72
Prepaid renewable energy credits 16 30
Other 26 13
Total current assets 489 573
Property, plant, and equipment (net of accumulated depreciation and amortization of $ 2,330 and $ 2,241 as of June 30, 2026 and December 31, 2025, respectively)
5,977 5,855
Deferred debits and other assets
Regulatory assets 215 214
Other 143 147
Total deferred debits and other assets 358 361
Total assets $ 6,824 $ 6,789
See the Combined Notes to Consolidated Financial Statements
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Delmarva Power & Light Company
Balance Sheets
(Unaudited)
(In millions) June 30, 2026 December 31, 2025
LIABILITIES AND SHAREHOLDER'S EQUITY
Current liabilities
Short-term borrowings $ 32 $ 161
Long-term debt due within one year 63 53
Accounts payable 147 218
Accrued expenses 59 70
Payables to affiliates 28 25
Borrowings from PHI intercompany money pool 47 —
Customer deposits 39 36
Regulatory liabilities 43 42
Renewable energy credit obligations 50 49
Other 20 22
Total current liabilities 528 676
Long-term debt 2,358 2,291
Deferred credits and other liabilities
Deferred income taxes and unamortized investment tax credits 1,032 996
Regulatory liabilities 330 316
Asset retirement obligations 13 12
Other 130 127
Total deferred credits and other liabilities 1,505 1,451
Total liabilities 4,391 4,418
Commitments and contingencies
Shareholder's equity
Common stock 1,767 1,722
Retained earnings 666 649
Total shareholder's equity 2,433 2,371
Total liabilities and shareholder's equity $ 6,824 $ 6,789
See the Combined Notes to Consolidated Financial Statements
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Delmarva Power & Light Company
Statements Of Changes In Shareholder's Equity
(Unaudited)
Six Months Ended June 30, 2026
(In millions) Common Stock Retained Earnings Total Shareholder's Equity
Balance at December 31, 2025 $ 1,722 $ 649 $ 2,371
Net income — 77 77
Common stock dividends — ( 50 ) ( 50 )
Contributions from parent 45 — 45
Balance at March 31, 2026 $ 1,767 $ 676 $ 2,443
Net income — 26 26
Common stock dividends — ( 36 ) ( 36 )
Contributions from parent — — —
Balance at June 30, 2026 $ 1,767 $ 666 $ 2,433
Six Months Ended June 30, 2025
(In millions) Common Stock Retained Earnings Total Shareholder's Equity
Balance at December 31, 2024 $ 1,615 $ 627 $ 2,242
Net income — 69 69
Common stock dividends — ( 46 ) ( 46 )
Contributions from parent 99 — 99
Balance at March 31, 2025 $ 1,714 $ 650 $ 2,364
Net income — 39 39
Common stock dividends — ( 44 ) ( 44 )
Contributions from parent — — $ —
Balance at June 30, 2025 $ 1,714 $ 645 $ 2,359
See the Combined Notes to Consolidated Financial Statements
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Atlantic City Electric Company and Subsidiary Company
Consolidated Statements of Operations and Comprehensive Income
(Unaudited)
Three Months Ended
June 30, Six Months Ended
June 30,
(In millions) 2026 2025 2026 2025
Operating revenues
Electric operating revenues $ 411 $ 397 $ 849 $ 769
Revenues from alternative revenue programs ( 11 ) ( 13 ) ( 29 ) ( 13 )
Operating revenues from affiliates 1 — 2 1
Total operating revenues 401 384 822 757
Operating expenses
Purchased power 187 173 392 329
Operating and maintenance 55 55 105 106
Operating and maintenance from affiliates 44 40 87 79
Depreciation and amortization 63 62 128 127
Taxes other than income taxes 3 3 5 5
Total operating expenses 352 333 717 646
Operating income 49 51 105 111
Other income and (deductions)
Interest expense, net ( 22 ) ( 20 ) ( 44 ) ( 41 )
Other, net 3 2 5 6
Total other income and (deductions) ( 19 ) ( 18 ) ( 39 ) ( 35 )
Income before income taxes 30 33 66 76
Income taxes 8 9 17 20
Net income $ 22 $ 24 $ 49 $ 56
Comprehensive income $ 22 $ 24 $ 49 $ 56
See the Combined Notes to Consolidated Financial Statements
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Atlantic City Electric Company and Subsidiary Company
Statements Of Cash Flows
(Unaudited)
Six Months Ended
June 30,
(In millions) 2026 2025
Cash flows from operating activities
Net income $ 49 $ 56
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation and amortization 128 127
Deferred income taxes and amortization of investment tax credits 35 13
Other non-cash operating activities 48 33
Changes in assets and liabilities:
Accounts receivable ( 9 ) ( 18 )
Receivables from and payables to affiliates, net 10 ( 4 )
Inventories ( 4 ) ( 9 )
Accounts payable and accrued expenses 6 37
Collateral (paid) received, net ( 5 ) 4
Income taxes ( 11 ) ( 2 )
Regulatory assets and liabilities, net ( 2 ) ( 27 )
Pension and non-pension postretirement benefit contributions ( 14 ) ( 2 )
Other assets and liabilities ( 48 ) ( 49 )
Net cash flows provided by operating activities 183 159
Cash flows from investing activities
Capital expenditures ( 240 ) ( 196 )
Other investing activities 1 —
Net cash flows used in investing activities ( 239 ) ( 196 )
Cash flows from financing activities
Changes in short-term borrowings ( 148 ) ( 107 )
Issuance of long-term debt 100 100
Changes in PHI intercompany money pool 48 —
Dividends paid on common stock ( 40 ) ( 44 )
Contributions from parent 91 94
Other financing activities ( 4 ) ( 3 )
Net cash flows provided by financing activities 47 40
(Decrease) increase in cash and cash equivalents ( 9 ) 3
Cash and cash equivalents at beginning of period 24 14
Cash and cash equivalents at end of period $ 15 $ 17
Supplemental cash flow information
Decrease in capital expenditures not paid $ ( 28 ) $ ( 28 )
See the Combined Notes to Consolidated Financial Statements
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Atlantic City Electric Company and Subsidiary Company
Consolidated Balance Sheets
(Unaudited)
(In millions) June 30, 2026 December 31, 2025
ASSETS
Current assets
Cash and cash equivalents $ 13 $ 22
Restricted cash and cash equivalents 2 2
Accounts receivable
Customer accounts receivable 236 239
Customer allowance for credit losses ( 30 ) ( 27 )
Customer accounts receivable, net 206 212
Other accounts receivable 70 64
Other allowance for credit losses ( 12 ) ( 13 )
Other accounts receivable, net 58 51
Receivables from affiliates 1 12
Inventories, net 80 76
Prepaid utility taxes 48 —
Regulatory assets 75 93
Other 8 8
Total current assets 491 476
Property, plant, and equipment (net of accumulated depreciation and amortization of $ 2,037 and $ 1,956 as of June 30, 2026 and December 31, 2025, respectively)
4,657 4,556
Deferred debits and other assets
Regulatory assets 588 559
Other 59 41
Total deferred debits and other assets 647 600
Total assets $ 5,795 $ 5,632
See the Combined Notes to Consolidated Financial Statements
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Atlantic City Electric Company and Subsidiary Company
Consolidated Balance Sheets
(Unaudited)
(In millions) June 30, 2026 December 31, 2025
LIABILITIES AND SHAREHOLDER'S EQUITY
Current liabilities
Short-term borrowings $ — $ 148
Long-term debt due within one year 4 5
Accounts payable 164 168
Accrued expenses 54 64
Payables to affiliates 23 24
Borrowings from PHI intercompany money pool 48 —
Customer deposits 27 26
Regulatory liabilities 102 48
Other 11 13
Total current liabilities 433 496
Long-term debt 2,130 2,028
Deferred credits and other liabilities
Deferred income taxes and unamortized investment tax credits 906 869
Regulatory liabilities 129 137
Other 69 74
Total deferred credits and other liabilities 1,104 1,080
Total liabilities 3,667 3,604
Commitments and contingencies
Shareholder's equity
Common stock 2,104 2,013
Retained earnings 24 15
Total shareholder's equity 2,128 2,028
Total liabilities and shareholder's equity $ 5,795 $ 5,632
See the Combined Notes to Consolidated Financial Statements
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Atlantic City Electric Company and Subsidiary Company
Consolidated Statements Of Changes In Shareholder's Equity
(Unaudited)
Six Months Ended June 30, 2026
(In millions) Common Stock Retained (Deficit) Earnings Total Shareholder's Equity
Balance at December 31, 2025 $ 2,013 $ 15 $ 2,028
Net income — 27 27
Common stock dividends — ( 25 ) ( 25 )
Contributions from parent 91 — 91
Balance at March 31, 2026 $ 2,104 $ 17 $ 2,121
Net income — 22 22
Common stock dividends — ( 15 ) ( 15 )
Contributions from parent — — —
Balance at June 30, 2026 $ 2,104 $ 24 $ 2,128
Six Months Ended June 30, 2025
(In millions) Common Stock Retained (Deficit) Earnings Total Shareholder's Equity
Balance at December 31, 2024 $ 1,915 $ 10 $ 1,925
Net income — 31 31
Common stock dividends — ( 20 ) ( 20 )
Contributions from parent 94 — 94
Balance at March 31, 2025 $ 2,009 $ 21 $ 2,030
Net income — 24 24
Common stock dividends — ( 24 ) ( 24 )
Contributions from parent — — —
Balance at June 30, 2025 $ 2,009 $ 21 $ 2,030
See the Combined Notes to Consolidated Financial Statements
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Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data, unless otherwise noted)
Note 1 — Significant Accounting Policies
1. Significant Accounting Policies (All Registrants)
Description of Business (All Registrants)
Exelon is a utility services holding company engaged in the energy transmission and distribution businesses through ComEd, PECO, BGE, Pepco, DPL, and ACE.
Name of Registrant Business Service Territories
Commonwealth Edison Company Purchase and regulated retail sale of electricity Northern Illinois, including the City of Chicago (and, through its subsidiary ComEd of Indiana, transmission in a small portion of northwestern Indiana)
Transmission and distribution of electricity to retail customers
PECO Energy Company Purchase and regulated retail sale of electricity and natural gas Southeastern Pennsylvania, including the City of Philadelphia (electricity)
Transmission and distribution of electricity and distribution of natural gas to retail customers Pennsylvania counties surrounding the City of Philadelphia (natural gas)
Baltimore Gas and Electric Company Purchase and regulated retail sale of electricity and natural gas Central Maryland, including the City of Baltimore (electricity and natural gas)
Transmission and distribution of electricity and distribution of natural gas to retail customers
Pepco Holdings LLC Utility services holding company engaged, through its reportable segments Pepco, DPL, and ACE Service Territories of Pepco, DPL, and ACE
Potomac Electric
Power Company Purchase and regulated retail sale of electricity District of Columbia, and major portions of Montgomery and Prince George’s Counties, Maryland
Transmission and distribution of electricity to retail customers
Delmarva Power &
Light Company Purchase and regulated retail sale of electricity and natural gas Portions of Delaware and Maryland (electricity)
Transmission and distribution of electricity and distribution of natural gas to retail customers Portions of New Castle County, Delaware (natural gas)
Atlantic City Electric Company Purchase and regulated retail sale of electricity Portions of Southern New Jersey
Transmission and distribution of electricity to retail customers
Prior Period Adjustments (ACE)
In the first quarter of 2026, management identified an error in the historical rate classification for a limited number of ACE customers that resulted in the overstatement of Regulatory assets and Revenues from alternative revenue programs. Management has concluded that the error was not material to previously issued or to the current period financial statements.
The impact of the error correction recognized in the first quarter of 2026 was a $ 14 million decrease to ACE’s Revenues from alternative revenue programs, a $ 4 million decrease to Income taxes, and a corresponding decrease of $ 14 million in Regulatory assets. The overall impact on ACE’s Operating income was a decrease of $ 14 million, and the impact on ACE’s Net income was $ 10 million. The error did not impact any net cash flow subtotal for the three months ended March 31, 2026.
Basis of Presentation (All Registrants)
This is a combined quarterly report of all Registrants. The Notes to the Consolidated Financial Statements apply to the Registrants as indicated parenthetically next to each corresponding disclosure. When appropriate, the Registrants are named specifically for their related activities and disclosures. Each of the Registrants' Consolidated Financial Statements includes the accounts of its subsidiaries. All intercompany transactions have been eliminated.
Through its business services subsidiary, BSC, Exelon provides its subsidiaries with a variety of support services at cost, including legal, human resources, financial, information technology, and supply management services. PHI also has a business services subsidiary, PHISCO, which provides a variety of support services at cost, including legal, finance, engineering, customer operations, transmission and distribution planning, asset management, system operations, and power procurement, to PHI operating Registrants. The costs of BSC and
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Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data, unless otherwise noted)
Note 1 — Significant Accounting Policies
PHISCO are directly charged or allocated to the applicable subsidiaries. The results of Exelon’s corporate operations are presented as “Other” within the consolidated financial statements and include intercompany eliminations unless otherwise disclosed.
The accompanying consolidated financial statements as of June 30, 2026 and for the three and six months ended June 30, 2026 and 2025 are unaudited but, in the opinion of each Registrant's management, the Registrants include all adjustments that are considered necessary for a fair statement of the Registrants’ respective financial statements in accordance with GAAP. All adjustments are of a normal, recurring nature, except as otherwise disclosed. The December 31, 2025 Consolidated Balance Sheets were derived from audited financial statements. The interim financial statements are to be read in conjunction with prior annual financial statements and notes. Additionally, financial results for interim periods are not necessarily indicative of results that may be expected for any other interim period or for the fiscal year ending December 31, 2026. These Combined Notes to Consolidated Financial Statements have been prepared pursuant to the rules and regulations of the SEC for Quarterly Reports on Form 10-Q. Certain information and note disclosures normally included in financial statements prepared in accordance with GAAP have been condensed or omitted pursuant to such rules and regulations.
New Accounting Standards (All Registrants)
New Accounting Standards Issued and Not Yet Adopted as of June 30, 2026: The following new authoritative accounting guidance issued by the FASB has not yet been adopted and reflected by the Registrants in their consolidated financial statements as of June 30, 2026. Unless otherwise indicated, the Registrants are currently assessing the impacts such guidance may have (which could be material) in their Consolidated Balance Sheets, Consolidated Statements of Operations and Comprehensive Income, Consolidated Statements of Cash Flows and disclosures, as well as the potential to early adopt where applicable. The Registrants have assessed other FASB issuances of new standards which are not listed below given the current expectation that such standards will not significantly impact the Registrants' financial reporting.
Disaggregation of Income Statement Expenses (Issued November 2024) . Provides additional disclosure requirements related to relevant expense captions of income statement expense line items. The revised guidance requires a new tabular disclosure of disaggregated income statement expenses including a break out of (1) purchases of inventory, (2) employee compensation, (3) depreciation, (4) intangible asset amortization, (5) depreciation, depletion, and amortization recognized as part of oil and gas producing activities included in each relevant expense line item on the income statement. The tabular disaggregation should include certain amounts already required to be disclosed under GAAP elsewhere. Any remaining amounts not separately disaggregated quantitatively should include a qualitative description. Additionally, on an annual basis, the standard requires disclosure of management’s definition of selling expenses and the amount of expense. The standard is effective January 1, 2027, with early adoption permitted.
Environmental Credits and Environmental Credit Obligations (Issued May 2026). Establishes guidance for the recognition, measurement, presentation and disclosure of environmental credits and compliance obligations that may be settled by using environmental credits. The guidance is effective for annual and interim periods beginning January 1, 2028 with early adoption permitted. The guidance is adopted on a retrospective basis by recognizing a cumulative effect adjustment to retained earnings at the date of initial application.
2. Regulatory Matters (All Registrants)
As discussed in Note 2 — Regulatory Matters of the 2025 Form 10-K, the Registrants are involved in rate and regulatory proceedings at FERC and their state commissions. The following discusses developments in 2026 and updates to 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 2 — Regulatory Matters
Distribution Base Rate Case Proceedings
The following tables show the completed and pending distribution base rate case proceedings in 2026.
Completed Distribution Base Rate Case Proceedings
Registrant/Jurisdiction Filing Date Service Requested Revenue Requirement Increase Approved Revenue Requirement Increase Approved ROE Approval Date Rate Effective Date
ComEd - Illinois January 17, 2023 Electric $ 1,487 $ 1,045 8.905 % December 19, 2024 January 1, 2024
April 26, 2024 (amended on September 11, 2024) Electric $ 624 $ 623 9.89 % October 31, 2024 January 1, 2025
PECO - Pennsylvania March 28, 2024 Electric $ 464 $ 354 N/A December 12, 2024 January 1, 2025
Natural Gas $ 111 $ 78
BGE - Maryland February 17, 2023 Electric $ 313 $ 179 9.50 % December 14, 2023 January 1, 2024
Natural Gas $ 289 $ 229 9.45 %
Pepco - District of Columbia April 13, 2023 (amended February 27, 2024) Electric $ 186 $ 123 9.50 % November 26, 2024 January 1, 2025
Pepco - Maryland May 16, 2023 (amended February 23, 2024) Electric $ 111 $ 45 9.50 % June 10, 2024 April 1, 2024
DPL - Maryland May 19, 2022 Electric $ 38 $ 29 9.60 % December 14, 2022 January 1, 2023
DPL - Delaware December 15, 2022 (amended September 29, 2023) Electric $ 39 $ 28 9.60 % April 18, 2024 July 15, 2023
September 20, 2024 (amended September 5, 2025) Natural Gas $ 37 $ 22 9.60 % December 17, 2025 January 1, 2026
ACE - New Jersey November 21, 2024 Electric $ 109 $ 54 9.60 % November 21, 2025 December 1, 2025
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Combined Notes to Consolidated Financial Statements — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Note 2 — Regulatory Matters
Pending Distribution Base Rate Case Proceedings
Registrant/Jurisdiction Filing Date Service Requested Revenue Requirement Increase Requested ROE Expected Approval Timing
Pepco - Maryland (a)
October 14, 2025 (amended April 16, 2026) Electric $ 120 10.50 % Third quarter of 2026
DPL - Delaware (b)
December 9, 2025 (amended June 1, 2026) Electric $ 45 10.50 % Third quarter of 2027
BGE - Maryland July 2, 2026 Electric $ 156 10.40 % First quarter of 2027
__________
(a) On April 14, 2026, Pepco notified the MDPSC of pursuing a traditional base rate case.
(b) DPL implemented interim rates on July 9, 2026, subject to refund.
ComEd Distribution Base Rate Case Proceedings
The ICC approved ComEd's four-year MRP for the period January 1, 2024 through December 31, 2027. The MRP was originally approved by the ICC on December 14, 2023 and was subsequently amended on January 10, 2024, April 18, 2024 and December 19, 2024. The December 19, 2024 order provided a total revenue requirement increase of $ 1.045 billion inclusive of rate increases of approximately $ 752 million in 2024, $ 80 million in 2025, $ 102 million in 2026, and $ 111 million in 2027.
On December 18, 2025, the ICC approved ComEd's 2024 MRP Reconciliation reflecting a revenue increase of $ 243 million, including the tax benefit of NOLCs. While NOLCs are included in the MRP Reconciliation per the final order, the impacts of the NOLCs will not be reflected in the financial statements until the PLR is received from the IRS. See Note 6 — Income Taxes for additional information on NOLCs.
On March 20, 2026, ComEd filed its annual revenue balancing reconciliation for 2025. The July 16, 2026 order approved the reconciliation, which is a component of revenue decoupling, reflecting a revenue reduction of $ 128 million. The reconciliation is effective January 1, 2027.
On May 1, 2026, ComEd filed its 2025 MRP Reconciliation reflecting a revenue increase of $ 234 million, which includes the tax benefit of NOLCs. While NOLCs were included in the MRP Reconciliation, the impacts of the NOLCs will not be reflected in the financial statements until the PLR is received from the IRS. See Note 6 — Income Taxes for additional information on NOLCs.
PECO Distribution Base Rate Case Proceedings
On December 12, 2024, the PAPUC issued their Opinions and Orders which approved the non-unanimous partial settlements with limited modifications for both the electric and natural gas base rate cases, and denied the Weather Normalization Adjustment requested in the natural gas base rate case.
PECO’s approved annual electric revenue requirement increase of $ 354 million is partially offset by a one-time credit of $ 64 million in 2025. In addition, the PAPUC approved the recovery of storm damage costs incurred by PECO in January 2024, up to $ 23 million, subject to review for reasonableness and prudency in PECO’s next distribution rate case.
BGE Distribution Base Rate Case Proceedings
In February 2023, BGE filed its three-year cumulative multi-year plan for January 1, 2024 through December 31, 2026 to the MDPSC, which was approved in December 2023 and went into effect on January 1, 2024. The MDSPC awarded BGE electric revenue requirement increases of $ 41 million, $ 113 million, and $ 25 million with an approved ROE of 9.50 % in 2024, 2025, and 2026, respectively, and natural gas revenue requirement increases of $ 126 million, $ 62 million, and $ 41 million with an approved ROE of 9.45 % in 2024, 2025, and 2026,
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Combined Notes to Consolidated Financial Statements — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Note 2 — Regulatory Matters
respectively. The requested revenue requirement increases will be used to recover capital investments designed to increase the resilience of the electric and gas distribution systems and support Maryland's climate and regulatory initiatives.
The MDPSC also approved a portion of the requested 2021 and 2022 reconciliation amounts, which were recovered through separate electric and gas riders between March 2024 and February 2025. As such, the reconciliation amounts are not included in the approved revenue increases. The 2021 reconciliation amounts are $ 13 million and $ 7 million for electric and gas, respectively, and the 2022 reconciliation amounts are $ 39 million and $ 15 million for electric and gas, respectively. In April 2024, BGE filed with the MDPSC its request for recovery of the 2023 reconciliation amounts of $ 79 million and $ 73 million for electric and gas, respectively, with supporting testimony and schedules. In December 2025, the MDPSC authorized BGE to recover $ 31 million and $ 46 million for electric and gas, respectively, beginning in February 2026 and extending through December 2027, in the reconciliation rider. In addition to the amounts approved in the reconciliation rider, the MDPSC provided for additional regulatory assets related to minor storms of $ 24 million (to be recovered over 5 years) and the Baltimore City conduit of $ 4 million. Recovery of these two regulatory assets was requested in BGE's recent MDPSC rate case filing submitted on July 2, 2026.
Pepco District of Columbia Distribution Base Rate Case Proceedings
On April 13, 2023, Pepco filed an electric base rate case with the DCPSC (amended February 27, 2024) requesting a total revenue requirement increase of $ 186 million and an ROE of 10.50 %. The DCPSC issued an order approving the two-year cumulative multi-year plan on November 26, 2024, which included a total revenue requirement increase of $ 123 million with an ROE of 9.50 % effective January 1, 2025 through December 31, 2026. The DCPSC awarded Pepco electric incremental revenue requirement increases of $ 99 million and $ 24 million for 2025 and 2026, respectively. Subsequent to DCPSC approval of the order, interveners appealed the order on several grounds including that the DCPSC did not hold evidentiary hearings. On March 5, 2026, the District of Columbia Court of Appeals remanded the November 26, 2024, order back to the DCPSC to hold evidentiary hearings. On May 8, 2026, the DCPSC issued an order adopting a revised procedural schedule which additionally reaffirmed that current rates should remain in effect during the remand period and refunds for previous amounts collected are not required at this time. On June 30, 2026, the Commission issued a subsequent order revising the procedural schedule to update the due date for final briefs. Pepco is preparing for the proceeding and will continue to monitor developments.
Pepco Maryland Distribution Base Rate Case Proceedings
On May 16, 2023, Pepco filed an electric base rate case with the MDPSC (amended February 23, 2024) requesting a total revenue requirement increase of $ 111 million (before offsets) and an ROE of 10.50 %. The MDPSC issued an order on June 10, 2024 awarding Pepco a one-year multi-year plan for April 1, 2024 through March 31, 2025 which included an incremental revenue requirement increase of $ 45 million and an ROE of 9.50 %. The MDPSC did not adopt the requested revenue requirement increases of $ 80 million (before offsets), $ 51 million, and $ 14 million as filed for 2025, 2026, and the 2027 nine-month extension period, respectively. The MDPSC also approved the requested reconciliation amounts for the 12-month periods ending March 31, 2022, and March 31, 2023, which will be recovered through a rider between August 2024 through March 2026. As such, the reconciliation amounts are not included in the approved revenue requirement increases. The reconciliation amounts are $ 1 million and $ 7 million, for the 12-month periods ending March 31, 2022, and March 31, 2023, respectively. In July 2024, Pepco filed its request with the MDPSC, for recovery of the reconciliation amounts of $ 31 million for the 12-month period ended March 31, 2024, with supporting testimony and schedules. On March 31, 2026, the MDPSC issued an order authorizing Pepco to recover approximately $ 13 million through the reconciliation rider. This will be recovered through rates between May 2026 through April 2027. Additionally, the order disallowed the recovery of various assets. The order resulted in the write off of $ 11 million of Regulatory assets and $ 15 million of Property, plant and equipment with a total of $ 26 million recorded in Operations and maintenance expense.
DPL Maryland Distribution Base Rate Case Proceedings
On May 19, 2022, DPL filed an electric base rate case with the MDPSC requesting a total revenue requirement increase of $ 38 million based on an ROE of 10.25 %. On December 14, 2022, the MDPSC issued an order awarding DPL a total revenue requirement increase of $ 29 million with an ROE of 9.60 %. The order reflects a three-year cumulative multi-year plan for January 1, 2023 through December 31, 2025, with rates remaining in
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(Dollars in millions, except per share data, unless otherwise noted)
Note 2 — Regulatory Matters
effect subsequent to the multi-year plan period. The MDPSC awarded DPL electric incremental revenue requirement increases of $ 17 million, $ 6 million, and $ 6 million for 2023, 2024, and 2025, respectively.
DPL Delaware Distribution Base Rate Case Proceedings
On December 15, 2022, DPL filed an electric base rate case with the DEPSC (amended September 29, 2023) requesting a total revenue requirement increase of $ 39 million and an ROE of 10.50 %. On April 18, 2024, the DEPSC issued an order awarding DPL a total revenue requirement increase of $ 28 million with an ROE of 9.60 %, effective July 15, 2023. As part of the approved order, the DEPSC approved the Significant Storm Expense Rate Rider (Rider SSER) which will allow DPL to recover expenses associated with qualified storms. A qualified storm will be an individual storm for which DPL incurs expenses between $ 5 million and $ 15 million. The Rider SSER allows DPL to recover significant storm damage expenses for the previous 12-month period over a future 24-month period. For individual storm events for which DPL incurs expenses of more than $ 15 million, the future recovery period will be evaluated on a case-by-case basis and the unamortized balance will earn a return at DPL's authorized long-term cost of debt. The Rider SSER will have an annual true-up filing, subject to DEPSC review and approval.
ACE New Jersey Distribution Base Rate Case Proceedings
On November 21, 2024, ACE filed an electric base rate case with the NJBPU requesting a total revenue requirement increase of $ 109 million, before NJ sales and use tax, and an ROE of 10.70 %. On November 21, 2025, the NJBPU issued an order awarding ACE an electric revenue requirement increase, before NJ sales and use tax, of $ 54 million effective December 1, 2025, with an ROE of 9.60 %. In addition, the NJBPU approved the recovery through a regulatory asset of work stoppage costs that were incurred by ACE in 2023 of $ 38 million.
Transmission Formula Rates
The Utility Registrants' transmission rates are each established based on a FERC-approved formula. ComEd, BGE, Pepco, DPL, and ACE are required to file an annual update to the FERC-approved formula on or before May 15, and PECO is required to file on or before May 31, with the resulting rates effective on June 1 of the same year. The annual update for ComEd is based on prior year actual costs and current year projected capital additions (initial year revenue requirement). The annual update for PECO is based on prior year actual costs and current year projected capital additions, accumulated depreciation, and accumulated deferred income taxes. The annual update for BGE, Pepco, DPL, and ACE is based on prior year actual costs and current year projected capital additions, accumulated depreciation, depreciation and amortization expense, and accumulated deferred income taxes. The update for ComEd, PECO, BGE, Pepco, DPL, and ACE also reconciles any differences between the actual costs and actual revenues for the calendar year (annual reconciliation).
For 2026, the following increases/(decreases) were included in the Utility Registrants' electric transmission formula rate updates:
Registrant (a)
Initial Revenue Requirement Increase (Decrease) Annual Reconciliation (Decrease) Increase Total Revenue Requirement (Decrease) Increase (b)
Allowed Return on Rate Base (c)
Allowed ROE (d)
ComEd $ 31 $ ( 52 ) $ ( 21 ) 8.15 % 11.50 %
PECO $ 20 $ 20 $ 40 7.62 % 10.35 %
BGE $ 16 $ ( 40 ) $ ( 30 ) (e) 7.51 % 10.50 %
Pepco $ 12 $ ( 21 ) $ ( 9 ) 7.72 % 10.50 %
DPL $ 3 $ 1 $ 4 7.53 % 10.50 %
ACE $ 1 $ 16 $ 17 7.26 % 10.50 %
__________
(a) All rates are effective June 1, 2026 - May 31, 2027, subject to review by interested parties pursuant to review protocols of each Utility Registrants' tariffs.
(b) For the Utility Registrants, except for PECO, while the transmission filing reflects the tax benefit of NOLCs, the impacts of the NOLCs will not be reflected in the financial statements until the PLR is received from the IRS. See Note 6 — Income Taxes for additional information on NOLCs.
(c) Represents the weighted average debt and equity return on transmission rate base.
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(Dollars in millions, except per share data, unless otherwise noted)
Note 2 — Regulatory Matters
(d) The rate of return on common equity for each Utility Registrant includes a 50 -basis-point incentive adder for being a voluntary member of an RTO. Recently passed legislation in Maryland and New Jersey requires utilities to become a member of an RTO.
(e) The decrease in BGE's transmission revenue requirement includes a $ 6 million reduction related to a FERC-approved dedicated facilities charge to recover the costs of providing transmission service to specifically designated load by BGE.
Other State Regulatory Matters
Illinois Regulatory Matters
CEJA (Exelon and ComEd). On September 15, 2021, the Governor of Illinois signed into law CEJA. CEJA includes, among other features, (1) procurement of CMCs from qualifying nuclear-powered generating facilities, (2) a requirement to file a general rate case or a new four-year MRP no later than January 20, 2023 to establish rates effective after ComEd’s existing performance-based distribution formula rate sunsets, (3) requirements that ComEd and the ICC initiate and conduct various regulatory proceedings on subjects including ethics, spending, grid investments, and performance metrics.
ComEd Electric Distribution Rates
Beginning in 2024, ComEd recovers from retail customers, subject to certain exceptions, the costs it incurs to provide electric delivery services either through its electric distribution rate or other recovery mechanisms authorized by CEJA. On January 17, 2023, ComEd filed a petition with the ICC seeking approval of a MRP for 2024-2027. The MRP supports a multi-year grid plan (2024-2027 Grid Plan), also filed on January 17, covering planned investments on the electric distribution system within ComEd’s service area through 2027. Costs incurred during each year of the MRP are subject to ICC review and the plan’s revenue requirement for each year will be reconciled with the actual costs that the ICC determines are prudently and reasonably incurred for that year. The reconciliation is subject to adjustment for certain costs, including a limitation on recovery of costs that are more than 105 % of certain costs in the previously approved MRP revenue requirement, absent a modification of the rate plan itself. Thus, for example, the rate adjustments necessary to reconcile 2024 revenues to ComEd’s actual 2024 costs incurred would take effect in January 2026 after the ICC’s review during 2025.
On December 14, 2023, the ICC issued a final order. The ICC rejected ComEd’s 2024-2027 Grid Plan as non-compliant with certain requirements of CEJA and required ComEd to file a revised 2024-2027 Grid Plan. On January 10, 2024, ComEd filed an appeal in the Illinois Appellate Court of portions of the ICC's December 2023 order, including but not limited to the allowed ROE, 50 % equity ratio, and denial of a return on ComEd’s pension asset. There is no deadline by when the appellate court must rule. On March 13, 2024, ComEd filed its Refiled 2024-2027 Grid Plan with supporting testimony and schedules with the ICC and subsequently on March 15, 2024, ComEd also filed a petition to adjust its MRP to authorize increased rates consistent with the Refiled 2024-2027 Grid Plan. On December 19, 2024, the ICC approved the Refiled 2024-2027 Grid Plan and adjusted the approved MRP with rates effective on January 1, 2025. The final approved MRP, as adjusted, which reflects the Refiled Grid Plan, resulted in a total cumulative revenue requirement increase of $ 1.045 billion over the 2024-2027 plan years and remains subject to annual reconciliations in accordance with CEJA. ComEd filed timely requests for rehearing and an appeal of the MRP order, again limited to the issues on which rehearing of the December 2023 order was denied, including the allowed ROE, 50 % equity ratio, and denial of a return on ComEd's pension asset.
On January 16, 2026, ComEd filed a multi-year integrated grid plan (2028-2031 Grid Plan), seeking approval for planned investments on the electric distribution system within ComEd's service area in 2028-2031. The ICC must issue an order by December 15, 2026.
Carbon Mitigation Credit
CEJA establishes decarbonization requirements for Illinois as well as programs to support the retention and development of emissions-free sources of electricity. ComEd is required to purchase CMCs from participating nuclear power generating facilities between June 1, 2022 and May 31, 2027. The price to be paid for each CMC was established through a competitive bidding process that included consumer-protection measures that capped the maximum acceptable bid amount and a formula that reduces CMC prices by an energy price index, the base residual auction capacity price in the ComEd zone of PJM, and the monetized value of any federal tax credit or other subsidy if applicable. On October 31, 2025, the seller provided notification to ComEd and the IPA that it has reflected on its 2024 federal tax return $ 804 million of nuclear production tax credits associated with its
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(Dollars in millions, except per share data, unless otherwise noted)
Note 2 — Regulatory Matters
participating nuclear power generating facilities. These amounts will be collected from the seller through an adjustment to the CMC price to be paid by ComEd and returned to customers in 2026. As of December 31, 2025, Exelon and ComEd's Consolidated Balance Sheets reflected these amounts as a receivable from the seller with an offsetting balance within the Carbon mitigation credit regulatory liability. These adjustments had no net impact on Exelon and ComEd’s Consolidated Statements of Operations and Comprehensive Income. The seller has not provided notification to ComEd or the IPA that any subsidies or tax credits, such as nuclear production tax credits, have been monetized for 2025. The consumer protection measures contained in CEJA will result in net payments to ComEd ratepayers if the energy index, the capacity price and applicable federal tax credits or subsidy exceed the CMC contract price. Beginning with the June 2022 monthly billing period, ComEd began issuing credits and/or charges to its retail customers under its CMC rider, the Rider Carbon-Free Resource Adjustment (Rider CFRA). A regulatory asset or liability is recorded for the difference between ComEd's costs associated with the procurement of CMCs from participating nuclear power generating facilities and revenues received from customers. The balance of the asset as of June 30, 2026 is $ 150 million.
On February 2, 2024, ComEd filed a petition with the ICC to initiate the reconciliation proceeding for the costs incurred in connection with the procurement of CMC’s during the delivery year beginning June 1, 2022 and extending through May 31, 2023. While both Staff and the Administrative Law Judge's proposed order supported ComEd’s proposed reconciliation adjustment, on September 4, 2025, the ICC issued its final order rejecting the proposed reconciliation adjustment. Specifically, the order disallowed portions of the administrative costs as well as a portion of ComEd's interest costs on the balance of credit extended to customers under the applicable tariff that were not yet funded by payments from the generator. The CMC costs themselves were not disallowed. The order resulted in an immaterial impact to the financial statements and on October 3, 2025 ComEd filed its Application for Rehearing. On October 16, 2025, the ICC denied ComEd's Application. On October 17, 2025, ComEd filed its appeal with the Illinois Appellate Court for review of the ICC's order and its denial of rehearing.
Energy Efficiency
CEJA extends ComEd’s current cumulative annual energy efficiency MWh savings goals through 2040, adds expanded electrification measures to those goals, increases low-income commitments, and adds a new performance adjustment to the energy efficiency formula rate. ComEd expects its annual spend to increase through 2040 to achieve these energy efficiency MWh savings goals, which is deferred as a separate regulatory asset that is recovered through the energy efficiency formula rate over the weighted average useful life, as approved by the ICC, of the related energy efficiency measures.
Energy Efficiency Formula Rate (Exelon and ComEd). In 2026, Illinois enacted the CRGA, which makes certain changes to the energy efficiency framework established under CEJA.
CRGA modifies the manner in which ComEd’s energy efficiency savings goals are calculated by establishing a flat incremental annual savings requirement that applies indefinitely. CRGA also increases energy efficiency budget and low‑income commitments from levels established under CEJA, expands the categories of savings that may be credited toward annual goals, and revises the return on equity applicable to the energy efficiency regulatory asset to align with the distribution return on equity.
ComEd filed its annual energy efficiency formula rate update with the ICC on May 29, 2026. The filing establishes the revenue requirement used to set the rates that will take effect in January 2027, subject to the ICC's review and approval. The requested revenue requirement update is based on a reconciliation of the 2025 actual costs plus projected 2027 expenditures.
Initial Revenue Requirement Increase Annual Reconciliation Decrease Total Revenue Requirement Decrease Requested Return on Rate Base (a)
Requested ROE
$ 28 $ ( 56 ) $ ( 28 ) 6.62 % 8.905 %
__________
(a) The requested revenue requirement increase provides for a weighted average debt and equity return on the energy efficiency regulatory asset and rate base of 6.62 % inclusive of an allowed ROE of 8.905 %. For the 2025 reconciliation year, the requested revenue requirement provides for a weighted average debt and equity return on the energy efficiency regulatory asset and rate base of 7.67 % inclusive of an allowed ROE of 11.0 %, which includes an upward performance adjustment that increased the ROE. The performance adjustment can either increase or decrease the ROE based upon the achievement of energy efficiency savings goals.
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(Dollars in millions, except per share data, unless otherwise noted)
Note 2 — Regulatory Matters
Beginning in 2027, ComEd expects that implementation of CRGA may result in higher annual energy efficiency spending. Incremental costs incurred in advance of recovery are expected to be deferred as a regulatory asset and recovered through ComEd’s energy efficiency formula rate over the weighted‑average useful life of the related measures, subject to approval by the Illinois Commerce Commission.
Maryland Regulatory Matters
Summer and Winter Rate Mitigation (Exelon, BGE, PHI, Pepco, and DPL). As part of the passing of the Next Generation Energy Act of 2025 by the Maryland General Assembly, the MDPSC issued an order on June 26, 2025, to implement the Legislative Energy Relief Refund program under which bill credits were distributed to residential customers based on their consumption of electricity supply that was subject to the renewable energy portfolio standard. On July 24, 2025, the MDPSC issued an order accepting BGE, Pepco, and DPL's proposal for the implementation of the program. As a result, BGE, Pepco, and DPL received $ 49 million, $ 21 million, and $ 8 million, respectively, from the MDPSC on February 3, 2026. These amounts were used to reduce residential customer account receivable balances within the first quarter of 2026.
Maryland Utility Relief Act (Exelon, BGE, PHI, Pepco, and DPL). On May 12, 2026, the Governor of Maryland signed into law legislation that addresses several matters pertaining to electric and gas utilities, including a moratorium on rate cases with forecasted test years until April 1, 2027. Additionally, BGE, Pepco and DPL are required to participate as a member in an RTO effective July 1, 2026, which resulted in a complaint filed on July 2, 2026 against Maryland Transmission Operators, including BGE, Pepco, and DPL, at FERC for the removal of the 50 -basis-point incentive adder in the transmission formula rates. The final outcome and resolution of the complaint filing cannot be predicted and the results are not expected to be material to Exelon, BGE, PHI, Pepco, and DPL financial statements.
Delaware Regulatory Matters
Delaware Senate Bill 326 (Exelon, PHI, and DPL). On July 13, 2026, the Governor of Delaware signed into law legislation that addresses several matters pertaining to public utility companies. As part of the law, DPL’s non-mandatory capital spend eligible to be recovered in rates will be limited to $ 70 million in each of the years ended 2026 and 2027 unless the spend falls within an exception or the commission orders otherwise. Further, beginning in 2028, DPL’s non-mandatory capital spend eligible to be recovered in rates shall not exceed 5 % of DPL’s rate base approved in its most recent base rate case. The legislation also modifies the timing of interim rate recovery in base rate case proceedings. If the DEPSC has not issued a decision within 7 months of a filing, DPL may implement 50 % of the proposed rate increase, subject to refund. If no decision has been issued after 12 months, DPL may implement 75 % of the proposed increase, also subject to refund. DPL is continuing to evaluate the overall potential impacts of the legislation and will continue to monitor related regulatory developments.
New Jersey Regulatory Matters
New Jersey Repeal RTO Adder Bill (Exelon, PHI, and ACE). On July 7, 2026, the Governor of New Jersey signed into law legislation that addresses several matters pertaining to electric utility companies. As part of the legislation ACE is required to participate as a member in an RTO effective January 1, 2027, which could result in a complaint filed for the removal of the 50 -basis-point incentive adder in the transmission formula rates.
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(Dollars in millions, except per share data, unless otherwise noted)
Note 2 — Regulatory Matters
Other Federal Regulatory Matters
PJM Cost Allocation Methodology (All Registrants). On March 6, 2026, FERC issued an order requiring the removal of the de minimis threshold exemption in the calculation of the cost responsibility of certain transmission reliability upgrade costs allocated to the rate zones of PJM Transmission Owners, including the Utility Registrants. FERC further ordered PJM to recalculate historical cost allocations for the period beginning June 18, 2015, and to pass through additional charges or payments to PJM customers, including Utility Registrants, as applicable, with interest within 90 days. On April 29, 2026, the time for those calculations was extended until further order from FERC. The Utility Registrants expect to recover any incremental charges incurred or reimburse any payments received through prospective electric customer rates. On April 6, 2026, a number of parties filed requests for rehearing or clarification, which were denied by operation of law on May 7, 2026. On May 12, 2026, PJM Transmission Owners, including Exelon, on behalf of the Utility Registrants, filed a petition for review at the United States Court of Appeals for the D.C. Circuit.
The final impacts of the decision cannot be predicted and the results, while not reasonably estimable at this time, could be material to the financial statements.
Regulatory Assets and Liabilities
The Utility Registrants' regulatory assets and liabilities have not changed materially since December 31, 2025, unless noted below. See Note 2 — Regulatory Matters of the 2025 Form 10-K for additional information on the specific regulatory assets and liabilities.
ComEd. Regulatory assets increased $ 223 million primarily due to an increase of $ 150 million in the Carbon mitigation credit regulatory asset. Regulatory liabilities decreased $ 72 million primarily due to a decrease of $ 670 million in the Carbon mitigation credit regulatory liability, partially offset by an increase of $ 325 million in the Decommissioning the Regulatory Agreement Units regulatory liability.
PECO. Regulatory assets increased $ 151 million primarily due to an increase of $ 102 million in the Deferred income taxes regulatory asset. Regulatory liabilities increased $ 189 million primarily due to an increase of $ 200 million in the Decommissioning the Regulatory Agreement Units.
BGE. Regulatory assets decreased $ 104 million primarily due to a decrease of $ 52 million in the Electric energy and natural gas costs regulatory asset and a decrease of $ 47 million in the Energy efficiency and demand response programs regulatory asset. Regulatory liabilities decreased $ 33 million primarily due to a decrease of $ 36 million in the Deferred income taxes regulatory liability.
Pepco. Regulatory assets decreased $ 34 million primarily due to a decrease of $ 34 million in the Energy efficiency and demand response programs regulatory asset. Regulatory liabilities increased $ 12 million primarily due to an increase of $ 23 million in the Removal costs regulatory liability, partially offset by a decrease of $ 17 million in the Deferred income taxes regulatory liability.
DPL. Regulatory assets increased $ 11 million primarily due to an increase of $ 12 million in the Electric energy and natural gas costs regulatory asset and an increase of $ 10 million in the Removal costs regulatory asset, partially offset by a decrease of $ 17 million in the Energy efficiency and demand response programs regulatory asset.
ACE. Regulatory assets increased $ 11 million primarily due to an increase of $ 34 million in the Energy efficiency and demand response programs regulatory asset and an increase of $ 23 million in the Deferred storm costs regulatory asset, partially offset by a decrease of $ 38 million in the Under-recovered revenue decoupling regulatory asset. Regulatory liabilities increased $ 46 million primarily due to an increase of $ 34 million in the Zero emissions credit regulatory liability and an increase of $ 25 million in the Electric energy and natural gas costs regulatory liability, partially offset by a decrease of $ 10 million in the Transmission formula rate annual reconciliations regulatory liability.
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(Dollars in millions, except per share data, unless otherwise noted)
Note 2 — Regulatory Matters
Capitalized Ratemaking Amounts Not Recognized
The following table presents authorized amounts capitalized for ratemaking purposes related to earnings on shareholders' investment that are not recognized for financial reporting purposes in the Registrants' Consolidated Balance Sheets. These amounts will be recognized as revenues in the related Consolidated Statements of Operations and Comprehensive Income in the periods they are billable to the Utility Registrants' customers. PECO had no related amounts at June 30, 2026 and December 31, 2025.
Exelon ComEd (a)
BGE (b)
PHI Pepco (c)
DPL (d)
ACE (e)
June 30, 2026 $ 72 $ 10 $ 34 $ 28 $ 12 $ — $ 16
December 31, 2025 98 12 47 39 22 1 16
__________
(a) For the six months ended June 30, 2026, reflects ComEd's unrecognized equity returns earned for ratemaking purposes on its electric distribution rate, distributed generation, and energy efficiency regulatory assets. For the year ended December 31, 2025, reflects ComEd's unrecognized equity returns earned for ratemaking purposes on its electric distribution rates and distributed generation regulatory assets.
(b) BGE's amount capitalized for ratemaking purposes primarily relates to investments in rate base included in the multi-year plan reconciliations.
(c) Pepco's authorized amounts capitalized for ratemaking purposes relate to earnings on shareholders' investment on AMI programs, Energy efficiency and demand response programs, investments in rate base and revenues included in the multi-year plan reconciliations, and a portion of Pepco District of Columbia's revenue decoupling.
(d) DPL's authorized amounts capitalized for ratemaking purposes relate to earnings on shareholders' investment on AMI programs and Energy efficiency and demand response programs.
(e) ACE's authorized amounts capitalized for ratemaking purposes primarily relate to earnings on shareholders' investment on AMI programs.
3. Revenue from Contracts with Customers (All Registrants)
The Registrants recognize revenue from contracts with customers to depict the transfer of goods or services to customers at an amount that the entities expect to be entitled to in exchange for those goods or services. The primary sources of revenue include regulated electric and gas tariff sales, distribution, and transmission services.
See Note 3 — Revenue from Contracts with Customers of the 2025 Form 10-K for additional information regarding the primary sources of revenue for the Registrants.
Contract Liabilities
The Registrants record contract liabilities when consideration is received or due prior to the satisfaction of the performance obligations. The Registrants record contract liabilities in Other current liabilities and Other noncurrent deferred credits and other liabilities in their Consolidated Balance Sheets.
For Pepco, DPL, and ACE these contract liabilities primarily relate to upfront consideration received in the third quarter of 2020 for a collaborative arrangement ("Agreement") with an unrelated owner and manager of communication infrastructure, as well as additional consideration received for the payment option amendment ("Amendment") executed during the fourth quarter of 2023, which is discussed in further detail within Note 3 — Revenue from Contracts with Customers of the 2025 Form 10-K. The contract liability balance attributable to the Agreement and the Amendment is being recognized as Electric operating revenues over a 35 year period and 31 year period, respectively.
The following table provides a rollforward of the contract liabilities reflected in Exelon's, PHI's, Pepco's, DPL's, and ACE's Consolidated Balance Sheets for the three and six months ended June 30, 2026 and 2025. At June 30, 2026 and December 31, 2025, ComEd's, PECO's, and BGE's contract liabilities were immaterial.
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(Dollars in millions, except per share data, unless otherwise noted)
Note 3 — Revenue from Contracts with Customers
Exelon (a)
PHI (a)
Pepco (a)
DPL (a)
ACE
Balance at December 31, 2025 $ 119 $ 119 $ 95 $ 12 $ 12
Revenues recognized ( 1 ) ( 1 ) ( 1 ) — —
Balance at March 31, 2026 $ 118 $ 118 $ 94 $ 12 $ 12
Revenues recognized ( 1 ) ( 1 ) ( 1 ) — —
Balance at June 30, 2026 $ 117 $ 117 $ 93 $ 12 $ 12
Exelon (a)
PHI (a)
Pepco (a)
DPL (a)
ACE
Balance at December 31, 2024 $ 127 $ 127 $ 101 $ 13 $ 13
Revenues recognized ( 1 ) ( 1 ) ( 1 ) — —
Balance at March 31, 2025 $ 126 $ 126 $ 100 $ 13 $ 13
Revenues recognized ( 3 ) ( 3 ) ( 2 ) ( 1 ) —
Balance at June 30, 2025 $ 123 $ 123 $ 98 $ 12 $ 13
__________
(a) Revenues recognized in the three and six months ended June 30, 2026 and 2025, were included in the contract liabilities at December 31, 2025 and 2024, respectively.
Transaction Price Allocated to Remaining Performance Obligations
The following table shows the amounts of future revenues expected to be recorded in each year for performance obligations that are unsatisfied or partially unsatisfied as of June 30, 2026. This disclosure only includes contracts for which the total consideration is fixed and determinable at contract inception. The average contract term varies by customer type and commodity but ranges from one month to several years.
This disclosure excludes the Utility Registrants' gas and electric tariff sales contracts and transmission revenue contracts as they generally have an original expected duration of one year or less and, therefore, do not contain any future, unsatisfied performance obligations to be included in this disclosure. This disclosure also excludes transmission service agreements as the total consideration is not fixed and determinable at contract inception.
Year Exelon PHI Pepco DPL ACE
2026 $ 3 $ 3 $ 3 $ — $ —
2027 6 6 5 1 —
2028 6 6 5 — 1
2029 7 7 6 1 —
2030 and thereafter 95 95 74 10 11
Total $ 117 $ 117 $ 93 $ 12 $ 12
Revenue Disaggregation
The Registrants disaggregate revenue recognized from contracts with customers into categories that depict how the nature, amount, timing, and uncertainty of revenue and cash flows are affected by economic factors. See Note 4 — Segment Information for the presentation of the Registrants' revenue disaggregation.
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(Dollars in millions, except per share data, unless otherwise noted)
Note 4 — Segment Information
4. Segment Information (All Registrants)
Operating segments for each of the Registrants are determined based on information used by the CODMs in deciding how to evaluate performance and allocate resources at each of the Registrants. The Chief Executive Officer is the CODM for Exelon. For PHI and each of the Utility Registrants, CODM responsibilities are shared by Exelon's Chief Operating Officer and the Utility Registrant's Chief Executive Officer.
Exelon has six reportable segments, which include ComEd, PECO, BGE, and PHI's three reportable segments consisting of Pepco, DPL, and ACE. ComEd, PECO, BGE, Pepco, DPL, and ACE each represent a single reportable segment, and as such, no separate segment information is provided for these Registrants. Exelon, ComEd, PECO, BGE, PHI, Pepco, DPL, and ACE's CODMs rely on a variety of business considerations, including net income, in evaluating segment performance, determining reinvestment of profits, and establishing the amounts of dividend distributions.
An analysis and reconciliation of the Registrants’ reportable segment information to the respective information in the consolidated financial statements for the three and six months ended June 30, 2026 and 2025 is as follows:
Three Months Ended June 30, 2026 and 2025
ComEd PECO BGE PHI Other (a)
Intersegment
Eliminations Exelon
Operating revenues (b) :
2026
Electric revenues $ 1,985 $ 941 $ 1,050 $ 1,670 $ — $ ( 7 ) $ 5,639
Natural gas revenues — 121 168 40 — ( 1 ) 328
Shared service and other revenues — — — 2 471 ( 473 ) —
Total operating revenues $ 1,985 $ 1,062 $ 1,218 $ 1,712 $ 471 $ ( 481 ) $ 5,967
2025
Electric revenues $ 1,836 $ 880 $ 849 $ 1,544 $ — $ ( 13 ) $ 5,096
Natural gas revenues — 120 180 33 — ( 2 ) 331
Shared service and other revenues — — — 2 468 ( 470 ) —
Total operating revenues $ 1,836 $ 1,000 $ 1,029 $ 1,579 $ 468 $ ( 485 ) $ 5,427
Less:
Purchased power
2026 $ 579 $ 352 $ 522 $ 679 $ — $ — $ 2,132
2025 550 304 367 590 — — 1,811
Purchased fuel
2026 $ — $ 37 $ 23 $ 19 $ — $ — $ 79
2025 — 35 39 11 — — 85
Operating and maintenance
2026 $ 339 $ 232 $ 222 $ 337 $ 430 $ ( 174 ) $ 1,386
2025 322 242 201 291 477 ( 212 ) 1,321
Operating and maintenance from affiliates
2026 $ 110 $ 68 $ 71 $ 58 $ 11 $ ( 318 ) $ —
2025 100 63 63 49 10 ( 285 ) —
Depreciation and amortization
2026 $ 416 $ 125 $ 166 $ 245 $ 16 $ — $ 968
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Combined Notes to Consolidated Financial Statements — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Note 4 — Segment Information
2025 387 112 154 233 16 — 902
Taxes other than income taxes
2026 $ 107 $ 62 $ 96 $ 145 $ 13 $ — $ 423
2025 97 54 85 136 11 — 383
(Gain) on sale of assets
2026 $ — $ — $ — $ — $ — $ — $ —
2025 — — — ( 2 ) — — ( 2 )
Interest expense, net (c)
2026 $ 140 $ 70 $ 68 $ 107 $ 183 $ — $ 568
2025 128 57 61 102 176 — 524
Interest expense to affiliates, net (c)
2026 $ 3 $ 2 $ — $ 1 $ — $ — $ 6
2025 3 3 — 1 — — 7
Other, net
2026 $ ( 41 ) $ ( 13 ) $ ( 22 ) $ ( 20 ) $ ( 5 ) $ 11 $ ( 90 )
2025 ( 31 ) ( 10 ) ( 11 ) ( 17 ) ( 8 ) 12 ( 65 )
Income Taxes
2026 $ 83 $ 8 $ 17 $ 32 $ ( 41 ) $ — $ 99
2025 52 4 15 42 ( 43 ) — 70
Net income (loss) attributable to common shareholders
2026 $ 249 $ 119 $ 55 $ 109 $ ( 136 ) $ — $ 396
2025 228 136 55 143 ( 171 ) — 391
Supplemental segment information
Intersegment revenues (d)
2026 $ 2 $ 3 $ 3 $ 2 $ 469 $ ( 479 ) $ —
2025 10 3 2 2 466 ( 483 ) —
Capital Expenditures
2026 $ 786 $ 495 $ 385 $ 504 $ 30 $ — $ 2,200
2025 599 408 398 595 13 — 2,013
__________
(a) Other primarily includes Exelon’s corporate operations, shared service entities, and other financing and investment activities.
(b) Includes gross utility tax receipts from customers. The offsetting remittance of utility taxes to the governing bodies is recorded in Taxes other than income taxes in the Registrants’ Consolidated Statements of Operations and Comprehensive Income. See Note 14 — Supplemental Financial Information for additional information on total utility taxes.
(c) Interest expense, net and Interest expense to affiliates, net are primarily inclusive of Interest expense, which is partially offset by an immaterial amount of Interest income.
(d) See Note 15 — Related Party Transactions for additional information on intersegment revenues.
PHI:
Pepco DPL ACE Other (a)
Intersegment
Eliminations PHI
Operating revenues (b) :
2026
Electric revenues $ 859 $ 414 $ 401 $ — $ ( 4 ) $ 1,670
Natural gas revenues — 40 — — — 40
Shared service and other revenues — — — 120 ( 118 ) 2
Total operating revenues $ 859 $ 454 $ 401 $ 120 $ ( 122 ) $ 1,712
2025
Electric revenues $ 776 $ 388 $ 384 $ — $ ( 4 ) $ 1,544
Natural gas revenues — 33 — — — 33
Shared service and other revenues — — — 111 ( 109 ) 2
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Combined Notes to Consolidated Financial Statements — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Note 4 — Segment Information
Total operating revenues $ 776 $ 421 $ 384 $ 111 $ ( 113 ) $ 1,579
Less:
Purchased power
2026 $ 316 $ 176 $ 187 $ — $ — $ 679
2025 256 161 173 — — 590
Purchased fuel
2026 $ — $ 19 $ — $ — $ — $ 19
2025 — 11 — — — 11
Operating and maintenance
2026 $ 118 $ 62 $ 55 $ 102 $ — $ 337
2025 91 50 55 95 — 291
Operating and maintenance from affiliates
2026 $ 72 $ 50 $ 44 $ 14 $ ( 122 ) $ 58
2025 64 45 40 13 ( 113 ) 49
Depreciation and amortization
2026 $ 114 $ 67 $ 63 $ 1 $ — $ 245
2025 107 63 62 1 — 233
Taxes other than income taxes
2026 $ 113 $ 24 $ 3 $ 5 $ — $ 145
2025 109 20 3 4 — 136
(Gain) on sale of assets
2026 $ — $ — $ — $ — $ — $ —
2025 ( 2 ) — — — — ( 2 )
Interest expense, net (c)
2026 $ 56 $ 26 $ 22 $ 3 $ — $ 107
2025 54 25 20 3 — 102
Interest expense to affiliates, net (c)
2026 $ — $ — $ — $ 1 $ — $ 1
2025 — — — 1 — 1
Other, net
2026 $ ( 12 ) $ ( 4 ) $ ( 3 ) $ ( 1 ) $ — $ ( 20 )
2025 ( 9 ) ( 4 ) ( 2 ) ( 2 ) — ( 17 )
Income Taxes
2026 $ 17 $ 8 $ 8 $ ( 1 ) $ — $ 32
2025 22 11 9 — — 42
Net income (loss) attributable to common shareholders
2026 $ 65 $ 26 $ 22 $ ( 4 ) $ — $ 109
2025 84 39 24 ( 4 ) — 143
Supplemental segment information
Intersegment revenues (d)
2026 $ 1 $ 2 $ 1 $ 119 $ ( 121 ) $ 2
2025 1 2 — 111 ( 112 ) 2
Capital Expenditures
2026 $ 232 $ 153 $ 118 $ 1 $ — $ 504
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Combined Notes to Consolidated Financial Statements — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Note 4 — Segment Information
2025 229 121 91 154 — 595
__________
(a) Other primarily includes PHI’s corporate operations, shared service entities, and other financing and investment activities.
(b) Includes gross utility tax receipts from customers. The offsetting remittance of utility taxes to the governing bodies is recorded in Taxes other than income taxes in the Registrants’ Consolidated Statements of Operations and Comprehensive Income. See Note 14 — Supplemental Financial Information for additional information on total utility taxes.
(c) Interest expense, net and Interest expense to affiliates, net are primarily inclusive of Interest expense, which is partially offset by an immaterial amount of Interest income.
(d) Includes intersegment revenues with ComEd, PECO, and BGE, which are eliminated at Exelon.
Electric and Gas Revenue by Customer Class (Utility Registrants):
The following tables disaggregate the Registrants' revenues recognized from contracts with customers into categories that depict how the nature, amount, timing, and uncertainty of revenue and cash flows are affected by economic factors. For the Utility Registrants, the disaggregation of revenues reflects the two primary utility services of electric sales and natural gas sales (where applicable), with further disaggregation of these tariff sales provided by major customer groups. Exelon’s disaggregated revenues are consistent with the Utility Registrants, but exclude any intercompany revenues.
Three Months Ended June 30, 2026
Revenues from contracts with customers ComEd PECO BGE PHI Pepco DPL ACE
Electric revenues
Residential $ 1,101 $ 601 $ 641 $ 867 $ 396 $ 230 $ 241
Small commercial & industrial 527 157 108 180 49 66 65
Large commercial & industrial 131 85 161 397 321 33 43
Public authorities & electric railroads 12 9 8 20 11 4 5
Other (a)
255 77 121 228 94 78 58
Total electric revenues (b)
$ 2,026 $ 929 $ 1,039 $ 1,692 $ 871 $ 411 $ 412
Natural gas revenues
Residential $ — $ 84 $ 93 $ 18 $ — $ 18 $ —
Small commercial & industrial — 29 17 9 — 9 —
Large commercial & industrial — — 48 1 — 1 —
Transportation — 6 — 4 — 4 —
Other (c)
— 1 7 8 — 8 —
Total natural gas revenues (d)
$ — $ 120 $ 165 $ 40 $ — $ 40 $ —
Total revenues from contracts with customers $ 2,026 $ 1,049 $ 1,204 $ 1,732 $ 871 $ 451 $ 412
Other revenues
Revenues from alternative revenue programs $ ( 55 ) $ 5 $ 5 $ ( 24 ) $ ( 15 ) $ 2 $ ( 11 )
Other electric revenues (e)
14 7 7 4 3 1 —
Other natural gas revenues (e)
— 1 2 — — — —
Total other revenues $ ( 41 ) $ 13 $ 14 $ ( 20 ) $ ( 12 ) $ 3 $ ( 11 )
Total revenues for reportable segments $ 1,985 $ 1,062 $ 1,218 $ 1,712 $ 859 $ 454 $ 401
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Combined Notes to Consolidated Financial Statements — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Note 4 — Segment Information
Three Months Ended June 30, 2025
Revenues from contracts with customers ComEd PECO BGE PHI Pepco DPL ACE
Electric revenues
Residential $ 1,094 $ 555 $ 497 $ 780 $ 348 $ 210 $ 222
Small commercial & industrial 553 155 90 168 48 64 56
Large commercial & industrial 177 75 140 370 292 31 47
Public authorities & electric railroads 12 10 8 22 12 5 5
Other (a)
224 77 118 233 91 77 67
Total electric revenues (b)
$ 2,060 $ 872 $ 853 $ 1,573 $ 791 $ 387 $ 397
Natural gas revenues
Residential $ — $ 79 $ 108 $ 17 $ — $ 17 $ —
Small commercial & industrial — 31 23 8 — 8 —
Large commercial & industrial — — 46 1 — 1 —
Transportation — 8 — 4 — 4 —
Other (c)
— 2 7 3 — 3 —
Total natural gas revenues (d)
$ — $ 120 $ 184 $ 33 $ — $ 33 $ —
Total revenues from contracts with customers $ 2,060 $ 992 $ 1,037 $ 1,606 $ 791 $ 420 $ 397
Other revenues
Revenues from alternative revenue programs $ ( 234 ) $ 1 $ ( 13 ) $ ( 29 ) $ ( 16 ) $ — $ ( 13 )
Other electric revenues (e)
10 7 4 2 1 1 —
Other natural gas revenues (e)
— — 1 — — — —
Total other revenues $ ( 224 ) $ 8 $ ( 8 ) $ ( 27 ) $ ( 15 ) $ 1 $ ( 13 )
Total revenues for reportable segments $ 1,836 $ 1,000 $ 1,029 $ 1,579 $ 776 $ 421 $ 384
__________
(a) Includes transmission revenue from PJM, wholesale electric revenue, and mutual assistance revenue.
(b) Includes operating revenues from affiliates in 2026 and 2025 respectively of:
• $ 2 million, $ 10 million at ComEd
• $ 2 million, $ 3 million at PECO
• $ 2 million , $ 1 million at BGE
• $ 2 million, $ 2 million at PHI
• $ 1 million, $ 1 million at Pepco
• $ 2 million, $ 2 million at DPL
• $ 1 million, less than $1 million at ACE
(c) Includes revenues from off-system natural gas sales.
(d) Includes operating revenues from affiliates in 2026 and 2025 respectively of:
• $ 1 million, less than $1 million at PECO
• $ 1 million, $ 1 million at BGE
(e) Includes late payment charge revenues
Six Months Ended June 30, 2026 and 2025
ComEd PECO BGE PHI Other (a)
Intersegment
Eliminations Exelon
Operating revenues (b) :
2026
Electric revenues $ 3,898 $ 2,023 $ 2,295 $ 3,580 $ — $ ( 23 ) $ 11,773
Natural gas revenues — 531 751 157 — ( 3 ) 1,436
Shared service and other revenues — — — 5 959 ( 964 ) —
Total operating revenues $ 3,898 $ 2,554 $ 3,046 $ 3,742 $ 959 $ ( 990 ) $ 13,209
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Combined Notes to Consolidated Financial Statements — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Note 4 — Segment Information
2025
Electric revenues $ 3,901 $ 1,836 $ 1,861 $ 3,232 $ — $ ( 26 ) $ 10,804
Natural gas revenues — 497 722 120 — ( 2 ) 1,337
Shared service and other revenues — — — 5 934 ( 939 ) —
Total operating revenues $ 3,901 $ 2,333 $ 2,583 $ 3,357 $ 934 $ ( 967 ) $ 12,141
Less:
Purchased power
2026 $ 1,031 $ 803 $ 1,152 $ 1,529 $ — $ — $ 4,515
2025 1,239 665 818 1,273 — — 3,995
Purchased fuel
2026 $ — $ 198 $ 201 $ 73 $ — $ — $ 472
2025 — 176 198 49 — — 423
Operating and maintenance
2026 $ 674 $ 502 $ 481 $ 702 $ 878 $ ( 385 ) $ 2,852
2025 645 507 443 586 904 ( 417 ) 2,668
Operating and maintenance from affiliates
2026 $ 212 $ 134 $ 138 $ 118 $ 23 $ ( 625 ) $ —
2025 200 124 125 103 22 ( 574 ) —
Depreciation and amortization
2026 $ 820 $ 247 $ 334 $ 491 $ 28 $ — $ 1,920
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Combined Notes to Consolidated Financial Statements — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Note 4 — Segment Information
2025 767 221 318 467 32 — 1,805
Taxes other than income taxes
2026 $ 212 $ 131 $ 200 $ 296 $ 27 $ — $ 866
2025 196 115 181 276 20 — 788
(Gain) on sale of assets
2026 $ — $ — $ — $ — $ — $ — $ —
2025 — — — ( 1 ) — — ( 1 )
Interest expense, net (c)
2026 $ 272 $ 139 $ 129 $ 213 $ 363 $ — $ 1,116
2025 253 117 120 201 337 — 1,028
Interest expense to affiliates, net (c)
2026 $ 7 $ 5 $ — $ 2 $ — $ ( 2 ) $ 12
2025 7 7 — 2 — ( 4 ) 12
Other, net
2026 $ ( 73 ) $ ( 25 ) $ ( 38 ) $ ( 39 ) $ ( 6 ) $ 22 $ ( 159 )
2025 ( 53 ) ( 18 ) ( 20 ) ( 35 ) ( 19 ) 28 ( 117 )
Income taxes
2026 $ 184 $ 23 $ 96 $ 79 $ ( 82 ) $ — $ 300
2025 117 17 85 99 ( 78 ) — 240
Net income (loss) attributable to common shareholders
2026 $ 559 $ 397 $ 353 $ 278 $ ( 272 ) $ — $ 1,315
2025 530 402 315 337 ( 284 ) — 1,300
Supplemental segment information
Intersegment revenues (d)
2026 $ 13 $ 7 $ 5 $ 5 $ 954 $ ( 984 ) $ —
2025 17 6 4 5 929 ( 961 ) —
Capital expenditures
2026 $ 1,671 $ 964 $ 822 $ 1,062 $ 39 $ — $ 4,558
2025 1,189 832 804 1,108 26 — 3,959
Total assets
June 30, 2026 $ 49,947 $ 20,495 $ 18,173 $ 30,008 $ 6,086 $ ( 4,204 ) $ 120,505
December 31, 2025 48,285 19,362 17,184 29,715 6,170 ( 4,146 ) 116,570
__________
(a) Other primarily includes Exelon’s corporate operations, shared service entities, and other financing and investment activities.
(b) Includes gross utility tax receipts from customers. The offsetting remittance of utility taxes to the governing bodies is recorded in Taxes other than income taxes in the Registrants’ Consolidated Statements of Operations and Comprehensive Income. See Note 14 — Supplemental Financial Information for additional information on total utility taxes.
(c) Interest expense, net and Interest expense to affiliates, net are primarily inclusive of Interest expense, which is partially offset by an immaterial amount of Interest income.
(d) See Note 15 — Related Party Transactions for additional information on intersegment revenues.
PHI:
Pepco DPL ACE Other (a)
Intersegment
Eliminations PHI
Operating revenues (b) :
2026
Electric revenues $ 1,849 $ 919 $ 822 $ — $ ( 10 ) $ 3,580
Natural gas revenues — 157 — — — 157
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Combined Notes to Consolidated Financial Statements — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Note 4 — Segment Information
Shared service and other revenues — — — 229 ( 224 ) 5
Total operating revenues $ 1,849 $ 1,076 $ 822 $ 229 $ ( 234 ) $ 3,742
2025
Electric revenues $ 1,635 $ 849 $ 757 $ — $ ( 9 ) $ 3,232
Natural gas revenues — 120 — — — 120
Shared service and other revenues — — — 217 ( 212 ) 5
Total operating revenues $ 1,635 $ 969 $ 757 $ 217 $ ( 221 ) $ 3,357
Less:
Purchased power
2026 $ 727 $ 410 $ 392 $ — $ — $ 1,529
2025 574 370 329 — — 1,273
Purchased fuel
2026 $ — $ 73 $ — $ — $ — $ 73
2025 — 49 — — — 49
Operating and maintenance
2026 $ 270 $ 134 $ 105 $ 193 $ — $ 702
2025 187 110 106 183 — 586
Operating and maintenance from affiliates
2026 $ 139 $ 97 $ 87 $ 29 $ ( 234 ) $ 118
2025 126 91 79 28 ( 221 ) 103
Depreciation and amortization
2026 $ 228 $ 133 $ 128 $ 2 $ — $ 491
2025 212 126 127 2 — 467
Taxes other than income taxes
2026 $ 231 $ 50 $ 5 $ 10 $ — $ 296
2025 222 41 5 8 — 276
(Gain) on sale of assets
2026 $ — $ — $ — $ — $ — $ —
2025 ( 1 ) — — — — ( 1 )
Interest expense, net (c)
2026 $ 111 $ 53 $ 44 $ 5 $ — $ 213
2025 106 50 41 4 — 201
Interest expense to affiliates, net (c)
2026 $ — $ — $ — $ 2 $ — $ 2
2025 — — — 2 — 2
Other, net
2026 $ ( 23 ) $ ( 8 ) $ ( 5 ) $ ( 3 ) $ — $ ( 39 )
2025 ( 20 ) ( 8 ) ( 6 ) ( 1 ) — ( 35 )
Income taxes
2026 $ 33 $ 31 $ 17 $ ( 2 ) $ — $ 79
2025 48 32 20 ( 1 ) — 99
Net income (loss) attributable to common shareholders
2026 $ 133 $ 103 $ 49 $ ( 7 ) $ — $ 278
2025 181 108 56 ( 8 ) — 337
Supplemental segment information
Intersegment revenues (d)
2026 $ 4 $ 4 $ 2 $ 229 $ ( 234 ) $ 5
2025 4 4 1 217 ( 221 ) 5
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Combined Notes to Consolidated Financial Statements — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Note 4 — Segment Information
Capital expenditures
2026 $ 517 $ 300 $ 240 $ 5 $ — $ 1,062
2025 469 277 196 166 — 1,108
Total assets
June 30, 2026 $ 12,951 $ 6,824 $ 5,795 $ 4,586 $ ( 148 ) $ 30,008
December 31, 2025 12,728 6,789 5,632 4,602 ( 36 ) 29,715
__________
(a) Other primarily includes PHI’s corporate operations, shared service entities, and other financing and investment activities.
(b) Includes gross utility tax receipts from customers. The offsetting remittance of utility taxes to the governing bodies is recorded in Taxes other than income taxes in the Registrants’ Consolidated Statements of Operations and Comprehensive Income. See Note 14 — Supplemental Financial Information for additional information on total utility taxes.
(c) Interest expense, net and Interest expense to affiliates, net are primarily inclusive of Interest expense, which is partially offset by an immaterial amount of Interest income.
(d) Includes intersegment revenues with ComEd, PECO, and BGE, which are eliminated at Exelon.
Electric and Gas Revenue by Customer Class (Utility Registrants):
The following tables disaggregate the Registrants' revenues recognized from contracts with customers into categories that depict how the nature, amount, timing, and uncertainty of revenue and cash flows are affected by economic factors. For the Utility Registrants, the disaggregation of revenues reflects the two primary utility services of electric sales and natural gas sales (where applicable), with further disaggregation of these tariff sales provided by major customer groups. Exelon’s disaggregated revenues are consistent with the Utility Registrants, but exclude any intercompany revenues.
Six Months Ended June 30, 2026
Revenues from contracts with customers ComEd PECO BGE PHI Pepco DPL ACE
Electric revenues
Residential $ 2,126 $ 1,326 $ 1,459 $ 1,960 $ 902 $ 559 $ 499
Small commercial & industrial 1,011 329 238 373 103 137 133
Large commercial & industrial 251 172 342 793 642 64 87
Public authorities & electric railroads 23 17 17 40 21 9 10
Other (a)
504 154 237 458 188 153 122
Total electric revenues (b)
$ 3,915 $ 1,998 $ 2,293 $ 3,624 $ 1,856 $ 922 $ 851
Natural gas revenues
Residential $ — $ 369 $ 494 $ 92 $ — $ 92 $ —
Small commercial & industrial — 125 80 38 — 38 —
Large commercial & industrial — — 141 5 — 5 —
Transportation — 26 — 10 — 10 —
Other (c)
— 9 38 12 — 12 —
Total natural gas revenues (d)
$ — $ 529 $ 753 $ 157 $ — $ 157 $ —
Total revenues from contracts with customers $ 3,915 $ 2,527 $ 3,046 $ 3,781 $ 1,856 $ 1,079 $ 851
Other revenues
Revenues from alternative revenue programs $ ( 46 ) $ 10 $ ( 18 ) $ ( 48 ) $ ( 14 ) $ ( 5 ) $ ( 29 )
Other electric revenues (e)
29 15 13 9 7 2 —
Other natural gas revenues (e)
— 2 5 — — — —
Total other revenues $ ( 17 ) $ 27 $ — $ ( 39 ) $ ( 7 ) $ ( 3 ) $ ( 29 )
Total revenues for reportable segments $ 3,898 $ 2,554 $ 3,046 $ 3,742 $ 1,849 $ 1,076 $ 822
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Combined Notes to Consolidated Financial Statements — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Note 4 — Segment Information
Six Months Ended June 30, 2025
Revenues from contracts with customers ComEd PECO BGE PHI Pepco DPL ACE
Electric revenues
Residential $ 2,087 $ 1,186 $ 1,145 $ 1,698 $ 772 $ 508 $ 418
Small commercial & industrial 1,153 317 199 338 99 128 111
Large commercial & industrial 472 159 284 738 581 60 97
Public authorities & electric railroads 29 18 17 39 20 9 10
Other (a)
461 153 230 454 176 148 134
Total electric revenues (b)
$ 4,202 $ 1,833 $ 1,875 $ 3,267 $ 1,648 $ 853 $ 770
Natural gas revenues
Residential $ — $ 346 $ 486 $ 73 $ — $ 73 $ —
Small commercial & industrial — 117 86 28 — 28 —
Large commercial & industrial — — 142 4 — 4 —
Transportation — 21 — 9 — 9 —
Other (c)
— 12 31 6 — 6 —
Total natural gas revenues (d)
$ — $ 496 $ 745 $ 120 $ — $ 120 $ —
Total revenues from contracts with customers $ 4,202 $ 2,329 $ 2,620 $ 3,387 $ 1,648 $ 973 $ 770
Other revenues
Revenues from alternative revenue programs $ ( 319 ) $ ( 8 ) $ ( 43 ) $ ( 32 ) $ ( 14 ) $ ( 5 ) $ ( 13 )
Other electric revenues (e)
18 11 5 2 1 1 —
Other natural gas revenues (e)
— 1 1 — — — —
Total other revenues $ ( 301 ) $ 4 $ ( 37 ) $ ( 30 ) $ ( 13 ) $ ( 4 ) $ ( 13 )
Total revenues for reportable segments $ 3,901 $ 2,333 $ 2,583 $ 3,357 $ 1,635 $ 969 $ 757
__________
(a) Includes transmission revenue from PJM, wholesale electric revenue, and mutual assistance revenue.
(b) Includes operating revenues from affiliates in 2026 and 2025 respectively of:
• $ 13 million, $ 17 million at ComEd
• $ 6 million, $ 5 million at PECO
• $ 4 million, $ 3 million at BGE
• $ 5 million, $ 5 million at PHI
• $ 4 million, $ 4 million at Pepco
• $ 4 million, $ 4 million at DPL
• $ 2 million, $ 1 million at ACE
(c) Includes revenues from off-system natural gas sales.
(d) Includes operating revenues from affiliates in 2026 and 2025 respectively of:
• $ 1 million, $ 1 million at PECO
• $ 1 million, $ 1 million at BGE
(e) Includes late payment charge revenues.
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Combined Notes to Consolidated Financial Statements — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Note 5 — Accounts Receivable
5. Accounts Receivable (All Registrants)
Allowance for Credit Losses on Accounts Receivable
The following tables present the rollforward of Allowance for Credit Losses on Customer Accounts Receivable.
Three Months Ended June 30, 2026
Exelon ComEd (b)
PECO (b)(c)
BGE (d)
PHI Pepco DPL ACE
Balance at March 31, 2026 $ 522 $ 130 $ 160 $ 101 $ 131 $ 76 $ 24 $ 31
Plus: Current period provision (benefit) for expected credit losses
46 ( 6 ) ( 1 ) 45 8 8 ( 1 ) 1
Less: Write-offs, net of recoveries (a)
60 22 17 10 11 7 2 2
Balance at June 30, 2026 $ 508 $ 102 $ 142 $ 136 $ 128 $ 77 $ 21 $ 30
Three Months Ended June 30, 2025
Exelon ComEd PECO BGE PHI Pepco DPL ACE
Balance at March 31, 2025 $ 486 $ 125 $ 160 $ 72 $ 129 $ 69 $ 23 $ 37
Plus: Current period provision (benefit) for expected credit losses
9 ( 4 ) 5 3 5 7 — ( 2 )
Less: Write-offs, net of recoveries
30 ( 1 ) 11 9 11 7 2 2
Balance at June 30, 2025 $ 465 $ 122 $ 154 $ 66 $ 123 $ 69 $ 21 $ 33
_________
(a) Recoveries were not material to the Registrants.
(b) For ComEd and PECO, the increase in write-offs, net of recoveries when comparing to three months ended June 30, 2025, is primarily the result of increased disconnection activities.
(c) For PECO, the decrease in current period provision for expected credit losses when comparing to three months ended June 30, 2025, is primarily the result of decreased receivable balances.
(d) For BGE, the increase in current period provision for expected credit losses when comparing to three months ended June 30, 2025, is primarily the result of increased receivable balances.
Six Months Ended June 30, 2026
Exelon ComEd (b)
PECO (b)(c)
BGE (d)
PHI Pepco DPL (e)
ACE (f)
Balance at December 31, 2025 $ 435 $ 115 $ 137 $ 68 $ 115 $ 69 $ 19 $ 27
Plus: Current period provision for expected credit losses
192 26 37 88 41 25 7 9
Less: Write-offs, net of recoveries (a)
119 39 32 20 28 17 5 6
Balance at June 30, 2026 $ 508 $ 102 $ 142 $ 136 $ 128 $ 77 $ 21 $ 30
Six Months Ended June 30, 2025
Exelon ComEd PECO BGE PHI Pepco DPL ACE
Balance at December 31, 2024 $ 406 $ 109 $ 133 $ 56 $ 108 $ 59 $ 17 $ 32
Plus: Current period provision for expected credit losses
142 29 46 26 41 24 10 7
Less: Write-offs, net of recoveries
83 16 25 16 26 14 6 6
Balance at June 30, 2025 $ 465 $ 122 $ 154 $ 66 $ 123 $ 69 $ 21 $ 33
_________
(a) Recoveries were not material to the Registrants.
(b) For ComEd and PECO, the increase in write-offs, net of recoveries when comparing to six months ended June 30, 2025, is primarily the result of increased disconnection activities.
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Combined Notes to Consolidated Financial Statements — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Note 5 — Accounts Receivable
(c) For PECO, the decrease in current provision for expected credit losses when comparing to six months ended June 30, 2025, is primarily the result of decreased receivable balances.
(d) For BGE, the increase in current provision for expected credit losses when comparing to six months ended June 30, 2025 , is primarily the result of increased receivable balances.
(e) For DPL, the decrease in current provision for expected credit losses when comparing to six months ended June 30, 2025, is primarily the result of favorable customer behavior.
(f) For ACE, the increase in current provision for expected credit losses when comparing to six months ended June 30, 2025, is primarily the result of increased aging of receivables.
The following tables present the rollforward of Allowance for Credit Losses on Other Accounts Receivable.
Three Months Ended June 30, 2026
Exelon ComEd PECO BGE PHI Pepco DPL ACE (b)
Balance at March 31, 2026 $ 102 $ 27 $ 22 $ 4 $ 49 $ 26 $ 11 $ 12
Plus: Current period provision (benefit) for expected credit losses
1 — ( 2 ) 1 2 ( 1 ) 1 2
Less: Write-offs, net of recoveries (a)
9 2 2 2 3 — 1 2
Balance at June 30, 2026 $ 94 $ 25 $ 18 $ 3 $ 48 $ 25 $ 11 $ 12
Three Months Ended June 30, 2025
Exelon ComEd PECO BGE PHI Pepco DPL ACE
Balance at March 31, 2025 $ 113 $ 34 $ 22 $ 6 $ 51 $ 27 $ 9 $ 15
Plus: Current period (benefit) provision for expected credit losses
( 7 ) ( 3 ) ( 2 ) ( 3 ) 1 1 — —
Less: Write-offs, net of recoveries
( 1 ) — 1 ( 2 ) — — — —
Balance at June 30, 2025 $ 107 $ 31 $ 19 $ 5 $ 52 $ 28 $ 9 $ 15
_________
(a) Recoveries were not material to the Registrants.
(b) For ACE, the increase in current provision for expected credit losses when comparing to three months ended June 30, 2025, is primarily the result of increased aging of receivables.
Six Months Ended June 30, 2026
Exelon ComEd PECO BGE PHI Pepco DPL (b)
ACE
Balance at December 31, 2025 $ 94 $ 23 $ 18 $ 4 $ 49 $ 26 $ 10 $ 13
Plus: Current period provision for expected credit losses
18 8 4 2 4 — 2 2
Less: Write-offs, net of recoveries (a)
18 6 4 3 5 1 1 3
Balance at June 30, 2026 $ 94 $ 25 $ 18 $ 3 $ 48 $ 25 $ 11 $ 12
Six Months Ended June 30, 2025
Exelon ComEd PECO BGE PHI Pepco DPL ACE
Balance at December 31, 2024 $ 107 $ 34 $ 18 $ 6 $ 49 $ 27 $ 9 $ 13
Plus: Current period provision (benefit) for expected credit losses
8 ( 1 ) 7 ( 2 ) 4 1 — 3
Less: Write-offs, net of recoveries
8 2 6 ( 1 ) 1 — — 1
Balance at June 30, 2025 $ 107 $ 31 $ 19 $ 5 $ 52 $ 28 $ 9 $ 15
_________
(a) Recoveries were not material to the Registrants.
(b) For DPL, the increase in current provision for expected credit losses when comparing to six months ended June 30, 2025, is primarily due to changes in risk profile.
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Combined Notes to Consolidated Financial Statements — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Note 5 — Accounts Receivable
Unbilled Customer Revenue
The following table provides additional information about unbilled customer revenues recorded in the Registrants' Consolidated Balance Sheets as of June 30, 2026 and December 31, 2025.
Unbilled customer revenues (a)
Exelon ComEd PECO BGE PHI Pepco DPL ACE
June 30, 2026 $ 1,073 $ 367 $ 211 $ 206 $ 289 $ 147 $ 67 $ 75
December 31, 2025 1,231 301 278 325 327 155 100 72
__________
(a) Unbilled customer revenues are classified in Customer accounts receivable, net in the Registrants' Consolidated Balance Sheets.
Other Purchases of Customer and Other Accounts Receivables
For the six months ended June 30, 2026 and 2025, the Utility Registrants were required, under separate legislation and regulations in Illinois, Pennsylvania, Maryland, District of Columbia, Delaware, and New Jersey, to purchase certain receivables from alternative retail electric and, as applicable, natural gas suppliers that participated in the utilities' consolidated billing. The following table presents the total receivables purchased.
Total receivables purchased
Exelon ComEd PECO BGE PHI Pepco DPL ACE
Six months ended June 30, 2026 $ 2,333 $ 571 $ 707 $ 325 $ 730 $ 472 $ 132 $ 126
Six months ended June 30, 2025 2,054 464 598 375 617 383 126 108
6. Income Taxes (All Registrants)
Rate Reconciliation
The effective income tax rate from continuing operations varies from the U.S. federal statutory rate principally due to the following:
Three Months Ended June 30, 2026 (a)(b)
Exelon ComEd PECO (c)
BGE
U.S. Federal statutory rate $ 104 21.0 % $ 70 21.0 % $ 26 21.0 % $ 15 21.0 %
Increase (decrease) due to:
State income taxes, net of Federal income tax benefit
31 6.3 25 7.5 ( 1 ) ( 0.8 ) 4 5.6
Tax credits ( 2 ) ( 0.4 ) ( 2 ) ( 0.6 ) — — — —
Change in Unrecognized Tax Benefits
— — — — — — — —
Nontaxable or nondeductible items
5 0.9 — — 1 0.3 1 1.2
Other Adjustments
Plant Basis differences ( 22 ) ( 4.4 ) ( 4 ) ( 1.2 ) ( 16 ) ( 12.6 ) — —
Excess deferred tax
( 17 ) ( 3.4 ) ( 6 ) ( 1.7 ) ( 2 ) ( 1.6 ) ( 3 ) ( 4.2 )
Amortization of ITC, net deferred taxes
— — — — — — — —
Effective Tax Rate
$ 99 20.0 % $ 83 25.0 % $ 8 6.3 % $ 17 23.6 %
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Combined Notes to Consolidated Financial Statements — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Note 6 — Income Taxes
Three Months Ended June 30, 2026 (a)(b)
PHI PEPCO DPL ACE
U.S. Federal statutory rate $ 30 21.0 % $ 17 21.0 % $ 7 21.0 % $ 6 21.0 %
Increase (decrease) due to:
State income taxes, net of Federal income tax benefit
9 6.4 5 6.1 3 8.8 2 5.7
Tax credits — — — — — — — —
Change in Unrecognized Tax Benefits
— — — — — — — —
Nontaxable or nondeductible items
1 1.0 — — — — — —
Other Adjustments
Plant Basis differences ( 1 ) ( 0.7 ) ( 1 ) ( 1.2 ) — — — —
Excess deferred tax
( 7 ) ( 5.0 ) ( 4 ) ( 5.2 ) ( 2 ) ( 6.3 ) — —
Amortization of ITC, net deferred taxes
— — — — — — — —
Effective Tax Rate
$ 32 22.7 % $ 17 20.7 % $ 8 23.5 % $ 8 26.7 %
Three Months Ended June 30, 2025 (a)(b)
Exelon ComEd (d)
PECO (c)
BGE
U.S. Federal statutory rate $ 96 21.0 % $ 59 21.0 % $ 29 21.0 % $ 15 21.0 %
Increase (decrease) due to:
State income taxes, net of Federal income tax benefit
28 6.1 21 7.6 ( 2 ) ( 1.4 ) 4 5.9
Tax credits ( 2 ) ( 0.4 ) ( 2 ) ( 0.7 ) — — ( 1 ) ( 1.4 )
Nontaxable or nondeductible items
1 0.2 ( 1 ) ( 0.4 ) 1 0.7 — —
Other Adjustments
Plant Basis differences ( 24 ) ( 5.2 ) ( 2 ) ( 0.7 ) ( 22 ) ( 16.0 ) ( 1 ) ( 1.4 )
Excess deferred tax
( 29 ) ( 6.4 ) ( 23 ) ( 8.2 ) ( 2 ) ( 1.4 ) ( 2 ) ( 2.7 )
Amortization of ITC, net deferred taxes
— ( 0.1 ) — — — — — —
Effective Tax Rate
$ 70 15.2 % $ 52 18.6 % $ 4 2.9 % $ 15 21.4 %
Three Months Ended June 30, 2025 (a)(b)
PHI PEPCO DPL ACE
U.S. Federal statutory rate $ 39 21.0 % $ 22 21.0 % $ 10 21.0 % $ 7 21.0 %
Increase (decrease) due to:
State income taxes, net of Federal income tax benefit
13 7.0 6 5.7 3 5.0 2 6.3
Tax credits ( 1 ) ( 0.5 ) — — — — — —
Nontaxable or nondeductible items
— — — — — — — —
Other Adjustments
Plant Basis differences ( 1 ) ( 0.5 ) ( 1 ) ( 0.9 ) — — — —
Excess deferred tax
( 8 ) ( 4.3 ) ( 5 ) ( 5.0 ) ( 2 ) ( 4.0 ) — —
Amortization of ITC, net deferred taxes
— — — — — — — —
Effective Tax Rate
$ 42 22.7 % $ 22 20.8 % $ 11 22.0 % $ 9 27.3 %
__________
(a) Positive amounts and percentages represent income tax expense. Negative amounts and percentages represent income tax benefit.
(b) Exelon and Registrants had no adjustments to the following disclosure categories: Foreign Tax Effects, Effects of Changes in Tax Law or Rates Enacted in the Current Period, Effects of Cross-Border Tax Laws, and Changes in Valuation Allowances.
(c) F or PECO, the lower effective tax rate is primarily related to state income taxes, net of federal income tax benefit and plant basis differences attributable to tax repair deductions.
(d) For ComEd, the lower effective tax rate is primarily due to CEJA which resulted in the acceleration of certain income tax benefits being provided to customers.
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Combined Notes to Consolidated Financial Statements — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Note 6 — Income Taxes
Six Months Ended June 30, 2026 (a)(b)
Exelon ComEd PECO (c)
BGE
U.S. Federal statutory rate $ 339 21.0 % $ 156 21.0 % $ 88 21.0 % $ 94 21.0 %
Increase (decrease) due to:
State income taxes, net of Federal income tax benefit
95 5.9 55 7.4 ( 4 ) ( 1.0 ) 27 6.0
Tax credits ( 5 ) ( 0.3 ) ( 3 ) ( 0.4 ) — — ( 1 ) ( 0.2 )
Change in Unrecognized Tax Benefits
( 17 ) ( 1.1 ) ( 2 ) ( 0.3 ) — — ( 1 ) ( 0.2 )
Nontaxable or nondeductible items
16 1.0 1 0.2 1 0.3 1 0.2
Other Adjustments
Plant Basis differences ( 75 ) ( 4.6 ) ( 9 ) ( 1.2 ) ( 55 ) ( 13.1 ) ( 8 ) ( 1.8 )
Excess deferred tax
( 52 ) ( 3.2 ) ( 14 ) ( 1.9 ) ( 7 ) ( 1.7 ) ( 16 ) ( 3.6 )
Amortization of ITC, net deferred taxes
( 1 ) ( 0.1 ) — — — — — —
Effective Tax Rate
$ 300 18.6 % $ 184 24.8 % $ 23 5.5 % $ 96 21.4 %
Six Months Ended June 30, 2026 (a)(b)
PHI PEPCO DPL ACE
U.S. Federal statutory rate $ 75 21.0 % $ 35 21.0 % $ 28 21.0 % $ 14 21.0 %
Increase (decrease) due to:
State income taxes, net of Federal income tax benefit
23 6.4 10 6.0 9 6.7 5 7.6
Tax credits ( 1 ) ( 0.3 ) — — — — — —
Change in Unrecognized Tax Benefits
— — — — — — — —
Nontaxable or nondeductible items
1 0.3 — — — — — —
Other Adjustments
Plant Basis differences ( 3 ) ( 0.8 ) ( 2 ) ( 1.2 ) ( 1 ) ( 0.8 ) — —
Excess deferred tax
( 16 ) ( 4.5 ) ( 10 ) ( 5.9 ) ( 5 ) ( 3.8 ) ( 2 ) ( 2.8 )
Amortization of ITC, net deferred taxes
— — — — — — — —
Effective Tax Rate
$ 79 22.1 % $ 33 19.9 % $ 31 23.1 % $ 17 25.8 %
Six Months Ended June 30, 2025 (a)(b)
Exelon ComEd (d)
PECO (c)
BGE
U.S. Federal statutory rate $ 323 21.0 % $ 136 21.0 % $ 88 21.0 % $ 84 21.0 %
Increase (decrease) due to:
State income taxes, net of Federal income tax benefit
85 5.5 49 7.6 ( 12 ) ( 2.9 ) 25 6.3
Tax credits ( 7 ) ( 0.5 ) ( 4 ) ( 0.6 ) — — ( 2 ) ( 0.5 )
Nontaxable or nondeductible items
5 0.4 — — 1 0.3 — —
Other Adjustments
Plant Basis differences ( 66 ) ( 4.3 ) ( 6 ) ( 0.9 ) ( 54 ) ( 12.9 ) ( 6 ) ( 1.5 )
Excess deferred tax
( 99 ) ( 6.4 ) ( 58 ) ( 9.0 ) ( 6 ) ( 1.4 ) ( 16 ) ( 4.0 )
Amortization of ITC, net deferred taxes
( 1 ) ( 0.1 ) — — — — — —
Effective Tax Rate
$ 240 15.6 % $ 117 18.1 % $ 17 4.1 % $ 85 21.3 %
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Combined Notes to Consolidated Financial Statements — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Note 6 — Income Taxes
Six Months Ended June 30, 2025 (a)(b)
PHI PEPCO DPL ACE
U.S. Federal statutory rate $ 92 21.0 % $ 48 21.0 % $ 29 21.0 % $ 16 21.0 %
Increase (decrease) due to:
State income taxes, net of Federal income tax benefit
29 6.7 14 6.1 9 6.3 5 6.6
Tax credits ( 2 ) ( 0.5 ) ( 1 ) ( 0.4 ) — — — —
Nontaxable or nondeductible items
1 0.3 1 0.4 — — — —
Other Adjustments
Plant Basis differences ( 3 ) ( 0.7 ) ( 2 ) ( 0.9 ) ( 1 ) ( 0.7 ) — —
Excess deferred tax
( 18 ) ( 4.1 ) ( 12 ) ( 5.2 ) ( 5 ) ( 3.7 ) ( 1 ) ( 1.3 )
Amortization of ITC, net deferred taxes
— — — — — — — —
Effective Tax Rate
$ 99 22.7 % $ 48 21.0 % $ 32 22.9 % $ 20 26.3 %
__________
(a) Positive amounts and percentages represent income tax expense. Negative amounts and percentages represent income tax benefit.
(b) Exelon and Registrants had no adjustments to the following disclosure categories: Foreign Tax Effects, Effects of Changes in Tax Law or Rates Enacted in the Current Period, Effects of Cross-Border Tax Laws, and Changes in Valuation Allowances.
(c) For PECO, the lower effective tax rate is primarily related to plant basis differences attributable to tax repair deductions.
(d) For ComEd, the lower effective tax rate is primarily due to CEJA which resulted in the acceleration of certain income tax benefits.
State and local Income Tax (Major Jurisdictions)
The state and local jurisdictions that comprise the majority of the effect of the state and local income tax, net of federal income taxes category by Registrant are presented below:
2026 2025
Exelon IL, MD IL, MD
ComEd IL IL
PECO PA PA
BGE MD MD
PHI MD, NJ MD, NJ
Pepco MD MD
DPL DE DE
ACE NJ NJ
Unrecognized Tax Benefits
Exelon, PHI and DPL have the following unrecognized tax benefits at June 30, 2026 and December 31, 2025. ComEd's, PECO's, BGE's, Pepco's, and ACE's amounts are not material.
Exelon (a)
PHI DPL
June 30, 2026 $ 87 $ 52 $ 16
December 31, 2025 100 48 12
__________
(a) At June 30, 2026 and December 31, 2025, Exelon's unrecognized tax benefits is inclusive of $ 20 million and $ 31 million , respectively, related to Constellation's share of unrecognized tax benefits for periods prior to the separation. Exelon reflected an offsetting receivable of $ 20 million and $ 31 million in Other deferred debits and other assets in the Consolidated Balance Sheet for these amounts.
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Combined Notes to Consolidated Financial Statements — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Note 6 — Income Taxes
Other Tax Matters
Tax Matters Agreement (Exelon)
In February 2022, in connection with the separation between Exelon and Constellation, the parties entered into a TMA. The TMA governs the respective rights, responsibilities, and obligations between Exelon and Constellation after the separation with respect to tax liabilities, refunds and attributes for open tax years that Constellation was part of Exelon’s consolidated group for U.S. federal, state, and local tax purposes.
Indemnification for Taxes. As a former subsidiary of Exelon, Constellation has joint and several liability with Exelon to the IRS and certain state jurisdictions relating to the taxable periods prior to the separation. The TMA specifies that Constellation is liable for their share of taxes required to be paid by Exelon with respect to taxable periods prior to the separation to the extent Constellation would have been responsible for such taxes under the Exelon tax sharing agreement when Constellation was included in Exelon's consolidated group. At June 30, 2026, there is no balance due to or from Constellation.
Tax Refunds. The TMA specifies that Constellation is entitled to their share of any future tax refunds claimed by Exelon with respect to taxable periods prior to the separation to the extent that Constellation would have received such tax refunds under the Exelon tax sharing agreement when Constellation was included in Exelon's consolidated group. At June 30, 2026, there is no balance due to or from Constellation.
Tax Attributes . At the date of separation certain tax attributes, primarily pre-separation tax credit carryforwards, that were generated by Constellation were required by law to be allocated to Exelon. The TMA provides that Exelon will reimburse Constellation when those allocated tax attribute carryforwards are utilized. In Q1 2026, Exelon received $ 235 million of payments from Constellation as reimbursement for a reduction in previously utilized pre-separation tax credit carryforwards due to the filing of amended federal tax returns. In Q2 2026, Exelon remitted $ 53 million of payments to Constellation for the utilization of pre-separation tax credit carryforwards. At June 30, 2026, Exelon recorded a payable of $ 99 million and $ 279 million in Other current liabilities and Other deferred credits and other liabilities, respectively, in the Consolidated Balance Sheet for tax attribute carryforwards that are expected to be utilized and reimbursed to Constellation.
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 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.
The impact of the notice was recorded as of March 31, 2026.
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
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Combined Notes to Consolidated Financial Statements — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Note 6 — Income Taxes
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. 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.
7. Retirement Benefits (All Registrants)
Defined Benefit Pension and OPEB
The majority of the 2026 pension benefit cost for the Exelon-sponsored plans is calculated using an expected long-term rate of return on plan assets of 7.00 % and a discount rate of 5.42 %. The majority of the 2026 OPEB cost is calculated using an expected long-term rate of return on plan assets of 6.50 % for funded plans and a discount rate of 5.34 %.
During the first quarter of 2026, Exelon received an updated valuation of its pension and OPEB to reflect actual census data as of January 1, 2026. This valuation resulted in an increase to the pension obligation of $ 6 million and an increase to the OPEB obligation of $ 10 million and a decrease to the asset of $ 2 million, respectively. Additionally, AOCI decreased by $ 4 million (after-tax) and regulatory assets increased by $ 23 million and liabilities increased by $ 1 million.
A portion of the net periodic benefit cost for all plans is capitalized within the Consolidated Balance Sheets. The following table presents the components of Exelon's net periodic benefit costs, prior to capitalization, for the three and six months ended June 30, 2026 and 2025.
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Combined Notes to Consolidated Financial Statements — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Note 7 — Retirement Benefits
Pension Benefits OPEB
Three Months Ended June 30, Three Months Ended June 30,
2026 2025 2026 2025
Components of net periodic benefit cost
Service cost $ 40 $ 39 $ 7 $ 6
Interest cost 142 147 25 25
Expected return on assets ( 176 ) ( 178 ) ( 21 ) ( 21 )
Amortization of:
Prior service credit — — ( 2 ) ( 2 )
Actuarial loss (gain) 50 53 ( 1 ) ( 1 )
Net periodic benefit cost $ 56 $ 61 $ 8 $ 7
Pension Benefits OPEB
Six Months Ended June 30, Six Months Ended June 30,
2026 2025 2026 2025
Components of net periodic benefit cost
Service cost $ 80 $ 77 $ 14 $ 12
Interest cost 285 293 50 50
Expected return on assets ( 352 ) ( 356 ) ( 43 ) ( 42 )
Amortization of:
Prior service cost (credit) 1 1 ( 4 ) ( 4 )
Actuarial loss (gain) 100 106 ( 1 ) ( 1 )
Net periodic benefit cost $ 114 $ 121 $ 16 $ 15
The amounts below represent the Registrants' allocated pension and OPEB costs. For Exelon, the service cost component is included in Operating and maintenance expense and Property, plant, and equipment, net while the non-service cost components are included in Other, net and Regulatory assets. For PHI and each of the Utility Registrants, which apply multi-employer accounting, the service cost and non-service cost components are included in Operating and maintenance expense and Property, plant, and equipment, net in their consolidated financial statements.
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Combined Notes to Consolidated Financial Statements — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Note 7 — Retirement Benefits
Three Months Ended June 30, Six Months Ended June 30,
Pension and OPEB Costs 2026 2025 2026 2025
Exelon $ 64 $ 68 $ 129 $ 136
ComEd 27 21 54 42
PECO 4 1 8 3
BGE 7 14 14 30
PHI 21 24 41 49
Pepco 7 10 14 18
DPL 3 4 7 8
ACE 3 3 5 6
Defined Contribution Savings Plan
The Registrants participate in a 401(k) defined contribution savings plan that is sponsored by Exelon. The plan is qualified under applicable sections of the IRC and allows employees to contribute a portion of their pre-tax and/or after-tax income in accordance with specified guidelines. All Registrants match a percentage of the employee contributions up to certain limits. The following table presents the employer contributions and employer matching contributions to the savings plan for the three and six months ended June 30, 2026 and 2025.
Three Months Ended June 30, Six Months Ended June 30,
Savings Plan Employer Contributions 2026 2025 2026 2025
Exelon $ 32 $ 30 $ 64 $ 56
ComEd 13 12 24 22
PECO 5 4 9 8
BGE 3 3 6 6
PHI 7 5 12 10
Pepco 2 2 3 3
DPL 1 1 2 2
ACE 1 — 2 1
8. Derivative Financial Instruments (All Registrants)
The Registrants use derivative instruments to manage commodity price risk and interest rate risk related to ongoing business operations. The Registrants do not execute derivatives for speculative or proprietary trading purposes.
Authoritative guidance requires that derivative instruments be recognized as either assets or liabilities at fair value, with changes in fair value of the derivative recognized in earnings immediately. Other accounting treatments are available through special election and designation, provided they meet specific, restrictive criteria both at the time of designation and on an ongoing basis. These alternative permissible accounting treatments include NPNS, cash flow hedges, and fair value hedges. At ComEd, derivative economic hedges related to commodities are recorded at fair value and offset by a corresponding regulatory asset or liability. For all NPNS derivative instruments, accounts receivable or accounts payable are recorded when derivatives settle and revenue or expense is recognized in earnings as the underlying physical commodity is sold or consumed. At Exelon, derivative hedges that qualify and are designated as cash flow hedges are recorded at fair value and offsets are recorded to AOCI.
Commodity Price Risk (All Registrants)
The Utility Registrants employ established policies and procedures to manage their risks associated with market fluctuations in commodity prices by entering into physical and financial derivative contracts, which are either determined to be non-derivative or classified as economic hedges. The Utility Registrants procure electric and natural gas supply through a competitive procurement process approved by each of the respective state utility commissions. The Utility Registrants’ hedging programs are intended to reduce exposure to energy and natural gas price volatility and have no direct earnings impact as the costs are fully recovered from customers through
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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
regulatory-approved recovery mechanisms. The following table provides a summary of the Utility Registrants’ primary derivative hedging instruments, listed by commodity and accounting treatment.
Registrant Commodity Accounting Treatment Hedging Instrument
ComEd Electricity NPNS Fixed price contracts based on all requirements in the IPA procurement plans.
Electricity Changes in fair value of economic hedge recorded to an offsetting regulatory asset or liability (a)
20-year floating-to-fixed energy swap contracts beginning June 2012 based on the renewable energy resource procurement requirements in the Illinois Settlement Legislation of approximately 1.3 million MWhs per year.
PECO Electricity NPNS Fixed price contracts for default supply requirements through full requirements contracts.
Gas NPNS Fixed price contracts to cover about 10 % of planned natural gas purchases in support of projected firm sales.
BGE Electricity NPNS Fixed price contracts for all SOS requirements through full requirements contracts.
Gas NPNS Fixed price purchases associated with forecasted gas supply requirements.
Pepco Electricity NPNS Fixed price contracts for all SOS requirements through full requirements contracts.
DPL Electricity NPNS Fixed price contracts for all SOS requirements through full requirements contracts.
Gas NPNS Fixed and index priced contracts through full requirements contracts.
Gas Changes in fair value of economic hedge recorded to an offsetting regulatory asset or liability (b)
Exchange traded future contracts for up to 50 % of estimated monthly purchase requirements each month, including purchases for storage injections.
ACE Electricity NPNS Fixed price contracts for all BGS requirements through full requirements contracts.
__________
(a) See Note 2 — Regulatory Matters of the 2025 Form 10-K for additional information.
(b) The fair value of the DPL economic hedge is not material at June 30, 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 June 30, 2026 would result in an immaterial impact to Exelon's Consolidated Net income.
Below is a summary of the interest rate hedge balances at June 30, 2026 and December 31, 2025 .
Derivatives Designated
as Hedging Instruments
June 30, 2026 December 31, 2025
Other current assets $ — $ 3
Other deferred debits (noncurrent assets) 3 —
Total derivative assets 3 3
Mark-to-market derivative liabilities (current liabilities) — ( 4 )
Mark-to-market derivative liabilities (noncurrent liabilities) — —
Total mark-to-market derivative liabilities — ( 4 )
Total mark-to-market derivative net assets (liabilities) $ 3 $ ( 1 )
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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
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 and six months ended June 30, 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 second 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 June 30, 2026 and December 31, 2025.
June 30, 2026 December 31, 2025
5-year maturity floating-to-fixed swaps $ 60 $ 335
10-year maturity floating-to-fixed swaps 150 365
Total $ 210 $ 700
The related AOCI derivative gain for the three and six months ended June 30, 2026 was $ 1 million and $ 2 million (net of tax), respectively. The related AOCI derivative loss for the three and six months ended June 30, 2025 was $ 4 million and $ 13 million (net of tax), respectively. 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 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 June 30, 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 June 30, 2026 and December 31, 2025:
June 30, 2026 December 31, 2025
Exelon $ 244 $ 223
ComEd 221 192
PECO 6 6
BGE 2 4
PHI 15 21
Pepco 13 13
DPL 2 3
ACE (a)
— 5
__________
(a) ACE had less than one million in cash collateral with external parties at June 30, 2026.
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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
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 June 30, 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 June 30, 2026, they could have been required to post collateral to their counterparties of $ 26 million, $ 16 million, and $ 13 million, respectively.
9. Debt and Credit Agreements (All Registrants)
Short-Term Borrowings
Exelon Corporate, ComEd, and BGE meet their short-term liquidity needs primarily through commercial paper issuances. PECO also utilizes commercial paper, supplemented by borrowings from the Exelon intercompany money pool. Pepco, DPL, and ACE similarly rely on commercial paper, along with borrowings from the PHI intercompany money pool. PHI Corporate meets its short-term liquidity needs through borrowings from the Exelon intercompany money pool. The Registrants may use their respective credit facilities for general corporate purposes, including meeting short-term funding requirements and the issuance of letters of credit.
Commercial Paper
The following table reflects the Registrants' commercial paper programs supported by the revolving credit agreements at June 30, 2026 and December 31, 2025.
Outstanding Commercial
Paper at Average Interest Rate on
Commercial Paper Borrowings at
Commercial Paper Issuer June 30, 2026 December 31, 2025 June 30, 2026 December 31, 2025
Exelon (a)
$ 743 $ 612 3.88 % 3.94 %
ComEd $ — $ — — % — %
PECO $ 81 $ — 3.80 % — %
BGE $ — $ — — % — %
PHI (b)
$ 32 $ 612 3.95 % 3.94 %
Pepco $ — $ 303 — % 3.93 %
DPL $ 32 $ 161 3.95 % 3.94 %
ACE $ — $ 148 — % 3.94 %
__________
(a) Exelon Corporate had $ 630 million outstanding commercial paper borrowings at June 30, 2026 and no outstanding commercial paper borrowings at December 31, 2025.
(b) Represents the consolidated amounts of Pepco, DPL, and ACE.
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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
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 1.000 %
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 June 30, 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 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.
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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
Long-Term Debt
Issuance of Long-Term Debt
During the six months ended June 30, 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.
ComEd First Mortgage Bonds 4.55 % June 1, 2031 600 Repay existing indebtedness and for general corporate purposes.
ComEd First Mortgage Bonds 5.85 % June 1, 2056 825 Repay existing indebtedness and for general corporate purposes.
BGE Notes 5.15 % June 1, 2033 500 Repay existing indebtedness and for general corporate purposes.
BGE Notes 6.05 % June 1, 2056 425 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.
Pepco First Mortgage Bonds 5.74 % June 17, 2056 130 Repay existing indebtedness and for general corporate purposes.
DPL (a)
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.
__________
(a) On March 19, 2026, DPL entered into a purchase agreement of First Mortgage Bonds of $ 75 million and $ 75 million at 5.00 % and 5.74 % due on September 16, 2036 and March 19, 2056, respectively. The closing date of the 5.00 % issuance is expected to occur in September 2026.
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 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.
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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
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 18 shares per $ 1,000 principal amount, which is equivalent to an initial conversion price of approximately 57 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 June 30, 2026, no shares of the Convertible Senior Notes have been converted.
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 three and six months ended June 30, 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 June 30, 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 June 30, 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 June 30, 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.
June 30, 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)
$ 51,040 $ — $ 41,613 $ 4,723 $ 46,336 $ 49,078 $ — $ 40,637 $ 4,318 $ 44,955
ComEd 13,665 — 12,086 — 12,086 12,753 — 11,291 — 11,291
PECO 6,398 — 5,526 — 5,526 6,396 — 5,593 — 5,593
BGE 6,609 — 6,011 — 6,011 6,041 — 5,510 — 5,510
PHI 10,054 — 4,162 4,723 8,885 9,590 — 4,236 4,318 8,554
Pepco 4,931 — 2,492 2,129 4,621 4,632 — 2,546 1,861 4,407
DPL 2,421 — 648 1,462 2,110 2,344 — 657 1,410 2,067
ACE 2,134 — 813 1,132 1,945 2,033 — 819 1,047 1,866
Long-Term Debt to Financing Trusts
Exelon $ 390 $ — $ — $ 399 $ 399 $ 390 $ — $ — $ 403 $ 403
ComEd 206 — — 214 214 206 — — 216 216
PECO 184 — — 185 185 184 — — 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 June 30, 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 June 30, 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 June 30, 2026 At December 31, 2025
Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total
Assets
Cash equivalents (a)
$ 2,026 $ — $ — $ 2,026 $ 825 $ — $ — $ 825
Rabbi trust investments
Cash equivalents 108 — — 108 101 — — 101
Mutual funds 77 — — 77 71 — — 71
Fixed income — 6 — 6 — 6 — 6
Life insurance contracts — 81 19 100 — 79 21 100
Rabbi trust investments subtotal 185 87 19 291 172 85 21 278
Interest rate derivative assets
Derivatives designated as hedging instruments — 3 — 3 — 3 — 3
Interest rate derivative assets subtotal — 3 — 3 — 3 — 3
Total assets 2,211 90 19 2,320 997 88 21 1,106
Liabilities
Commodity derivative liabilities — — ( 128 ) ( 128 ) — — ( 131 ) ( 131 )
Interest rate derivative liabilities
Derivatives designated as hedging instruments — — — — — ( 4 ) — ( 4 )
Interest rate derivative liabilities subtotal — — — — — ( 4 ) — ( 4 )
Deferred compensation obligation — ( 66 ) — ( 66 ) — ( 71 ) — ( 71 )
Total liabilities — ( 66 ) ( 128 ) ( 194 ) — ( 75 ) ( 131 ) ( 206 )
Total net assets (liabilities) $ 2,211 $ 24 $ ( 109 ) $ 2,126 $ 997 $ 13 $ ( 110 ) $ 900
__________
(a) Exelon excludes cash of $ 180 million and $ 180 million at June 30, 2026 and December 31, 2025, respectively, and restricted cash of $ 224 million and $ 196 million at June 30, 2026 and December 31, 2025, respectively, and includes long-term restricted cash of $ 9 million and $ 50 million at June 30, 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 June 30, 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)
$ 949 $ — $ — $ 949 $ 2 $ — $ — $ 2 $ 1,006 $ — $ — $ 1,006
Rabbi trust investments
Cash equivalents — — — — 2 — — 2 — — — —
Mutual funds — — — — 14 — — 14 16 — — 16
Life insurance contracts — — — — — 25 — 25 — — — —
Rabbi trust investments subtotal — — — — 16 25 — 41 16 — — 16
Total assets 949 — — 949 18 25 — 43 1,022 — — 1,022
Liabilities
Commodity derivative liabilities (b)
— — ( 128 ) ( 128 ) — — — — — — — —
Deferred compensation obligation — ( 9 ) — ( 9 ) — ( 7 ) — ( 7 ) — ( 4 ) — ( 4 )
Total liabilities — ( 9 ) ( 128 ) ( 137 ) — ( 7 ) — ( 7 ) — ( 4 ) — ( 4 )
Total net assets (liabilities) $ 949 $ ( 9 ) $ ( 128 ) $ 812 $ 18 $ 18 $ — $ 36 $ 1,022 $ ( 4 ) $ — $ 1,018
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 $ 75 million and $ 77 million at June 30, 2026 and December 31, 2025, respectively, and restricted cash of $ 222 million and $ 193 million at June 30, 2026 and December 31, 2025, respectively. Additionally,
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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 includes long-term restricted cash of $ 9 million and $ 50 million at June 30, 2026 and December 31, 2025, respectively, which is reported in Other deferred debits and other assets in the Consolidated Balance Sheets. PECO excludes cash of $ 37 million and $ 23 million at June 30, 2026 and December 31, 2025, respectively. BGE excludes cash of $ 8 million and $ 15 million at June 30, 2026 and December 31, 2025, respectively.
(b) The Level 3 balance consists of the current and noncurrent liability of $ 23 million and $ 105 million, respectively, at June 30, 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 June 30, 2026 At December 31, 2025
PHI Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total
Assets
Cash equivalents (a)
$ 34 $ — $ — $ 34 $ 83 $ — $ — $ 83
Rabbi trust investments
Cash equivalents 103 — — 103 99 — — 99
Mutual funds 9 — — 9 9 — — 9
Fixed income — 6 — 6 — 6 — 6
Life insurance contracts — 23 19 42 — 23 20 43
Rabbi trust investments subtotal 112 29 19 160 108 29 20 157
Total assets 146 29 19 194 191 29 20 240
Liabilities
Deferred compensation obligation — ( 8 ) — ( 8 ) — ( 9 ) — ( 9 )
Total liabilities — ( 8 ) — ( 8 ) — ( 9 ) — ( 9 )
Total net assets $ 146 $ 21 $ 19 $ 186 $ 191 $ 20 $ 20 $ 231
Pepco DPL ACE
At June 30, 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)
$ 32 $ — $ — $ 32 $ 2 $ — $ — $ 2 $ — $ — $ — $ —
Rabbi trust investments
Cash equivalents 102 — — 102 — — — — — — — —
Life insurance contracts — 23 19 42 — — — — — — — —
Rabbi trust investments subtotal 102 23 19 144 — — — — — — — —
Total assets 134 23 19 176 2 — — 2 — — — —
Liabilities
Deferred compensation obligation — ( 1 ) — ( 1 ) — — — — — — — —
Total liabilities — ( 1 ) — ( 1 ) — — — — — — — —
Total net assets $ 134 $ 22 $ 19 $ 175 $ 2 $ — $ — $ 2 $ — $ — $ — $ —
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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 $ 47 million and $ 56 million at June 30, 2026 and December 31, 2025, respectively, and restricted cash of $ 2 million and $ 2 million at June 30, 2026 and December 31, 2025. Pepco excludes cash of $ 20 million and $ 22 million at June 30, 2026 and December 31, 2025, respectively. DPL excludes cash of $ 8 million and $ 9 million at June 30, 2026 and December 31, 2025, respectively. ACE excludes cash of $ 13 million and $ 22 million at June 30, 2026 and December 31, 2025, respectively and restricted cash of $ 2 million and $ 2 million at June 30, 2026 and December 31, 2025, respectively.
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 and six months ended June 30, 2026 and 2025:
Exelon ComEd PHI and Pepco
Three Months Ended June 30, 2026 Total Commodity
Derivatives Life Insurance Contracts
Balance at March 31, 2026 $ ( 112 ) $ ( 133 ) $ 20
Total realized / unrealized gains (losses)
Included in net income (a)
— — —
Included in regulatory assets/liabilities (b)
5 5 —
Settlements ( 2 ) — ( 1 )
Balance at June 30, 2026 (c)
$ ( 109 ) $ ( 128 ) $ 19
The amount of total gains included in income attributed to the change in unrealized gains related to assets and liabilities at June 30, 2026 $ — $ — $ —
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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
Exelon ComEd PHI and Pepco
Three Months Ended June 30, 2025 Total Commodity
Derivatives Life Insurance Contracts
Balance at March 31, 2025 $ ( 129 ) $ ( 151 ) $ 21
Total realized / unrealized gains (losses)
Included in net income (a)
1 — 1
Included in regulatory assets/liabilities (b)
16 16 —
Balance at June 30, 2025 (c)
$ ( 112 ) $ ( 135 ) $ 22
The amount of total gains included in income attributed to the change in unrealized gains related to assets and liabilities at June 30, 2025 $ 1 $ — $ 1
Exelon ComEd PHI and Pepco
Six Months Ended June 30, 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)
3 3 —
Settlements ( 2 ) — ( 1 )
Balance at June 30, 2026 (c)
$ ( 109 ) $ ( 128 ) $ 19
The amount of total gains included in income attributed to the change in unrealized gains related to assets and liabilities at June 30, 2026 $ — $ — $ —
Exelon ComEd PHI and Pepco
Six Months Ended June 30, 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)
1 — 1
Included in regulatory assets/liabilities (b)
( 3 ) ( 3 ) —
Balance at June 30, 2025 (c)
$ ( 112 ) $ ( 135 ) $ 22
The amount of total gains included in income attributed to the change in unrealized gains related to assets and liabilities at June 30, 2025 $ 1 $ — $ 1
__________
(a) Classified in Operating and maintenance expense in the Consolidated Statements of Operations and Comprehensive Income.
(b) For ComEd, this includes $ 7 million of decreases in fair value and an increase for realized gains due to settlements of $ 12 million recorded in Purchased power expense associated with floating-to-fixed energy swap contracts with unaffiliated suppliers for the three months ended June 30, 2026. Includes $ 5 million of increases 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 June 30, 2025. Includes $ 17 million of decreases in fair value and an increase for realized gains due to settlements of $ 20 million recorded in Purchased power expense associated with floating-to-fixed energy swap contracts with unaffiliated suppliers for the six months ended June 30, 2026. Includes $ 17 million of decreases in fair value and an increase for realized gains due to settlements of $ 20 million recorded in Purchased power expense associated with floating-to-fixed energy swap contracts with unaffiliated suppliers for the six months ended June 30, 2025.
(c) For ComEd, the balance of the current and noncurrent asset was zero as of June 30, 2026. The balance consists of a current and noncurrent liability of $ 23 million and $ 105 million, respectively, as of June 30, 2026.
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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
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 June 30, 2026 Fair Value at December 31, 2025 Valuation
Technique Unobservable
Input 2026 Range & Arithmetic Average 2025 Range & Arithmetic Average
Commodity derivatives $ ( 128 ) $ ( 131 ) Discounted
Cash Flow Forward power price (a)
$ 24.82 - $ 68.10 $ 40.37 $ 29.75 - $ 61.84 $ 41.95
________
(a) An increase to the forward power price would increase the fair value.
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 June 30, 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 June 30, 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)
$ 59 $ 31 $ 28 $ — $ — $ — $ —
Surety bonds (b)
468 166 137 165 — — —
Financing trust guarantees (c)
378 — — 78 — — 300
Guaranteed lease residual values (d)
24 — 1 6 4 4 9
Total commercial commitments $ 929 $ 197 $ 166 $ 249 $ 4 $ 4 $ 309
ComEd
Letters of credit (a)
$ 18 $ 13 $ 5 $ — $ — $ — $ —
Surety bonds (b)
131 34 97 — — — —
Financing trust guarantees (c)
200 — — — — — 200
Total commercial commitments $ 349 $ 47 $ 102 $ — $ — $ — $ 200
PECO
Letters of credit (a)
$ 5 $ — $ 5 $ — $ — $ — $ —
Surety bonds (b)
10 1 9 — — — —
Financing trust guarantees (c)
178 — — 78 — — 100
Total commercial commitments $ 193 $ 1 $ 14 $ 78 $ — $ — $ 100
BGE
Letters of credit (a)
$ 27 $ 14 $ 13 $ — $ — $ — $ —
Surety bonds (b)
93 1 5 87 — — —
Total commercial commitments $ 120 $ 15 $ 18 $ 87 $ — $ — $ —
PHI
Letters of credit (a)
$ 6 $ 2 $ 4 $ — $ — $ — $ —
Surety bonds (b)
175 76 21 78 — — —
Guaranteed lease residual values (d)
24 — 1 6 4 4 9
Total commercial commitments $ 205 $ 78 $ 26 $ 84 $ 4 $ 4 $ 9
Pepco
Letters of credit (a)
$ 2 $ 2 $ — $ — $ — $ — $ —
Surety bonds (b)
161 69 14 78 — — —
Guaranteed lease residual values (d)
8 — — 2 1 2 3
Total commercial commitments $ 171 $ 71 $ 14 $ 80 $ 1 $ 2 $ 3
DPL
Letters of credit (a)
$ 1 $ — $ 1 $ — $ — $ — $ —
Surety bonds (b)
7 3 4 — — — —
Guaranteed lease residual values (d)
9 — 1 2 2 1 3
Total commercial commitments $ 17 $ 3 $ 6 $ 2 $ 2 $ 1 $ 3
ACE
Letters of credit (a)
$ 3 $ — $ 3 $ — $ — $ — $ —
Surety bonds (b)
7 4 3 — — — —
Guaranteed lease residual values (d)
7 — — 2 1 1 3
Total commercial commitments $ 17 $ 4 $ 6 $ 2 $ 1 $ 1 $ 3
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(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 $ 55 million guaranteed by Exelon and PHI, of which $ 18 million, $ 20 million, and $ 17 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 2027.
• 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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(Dollars in millions, except per share data, unless otherwise noted)
Note 11 — Commitments and Contingencies
At June 30, 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:
June 30, 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 $ 362 $ 311 $ 386 $ 321
ComEd 285 285 289 289
PECO 19 16 23 22
BGE 13 10 13 10
PHI 44 — 57 —
Pepco 43 — 55 —
DPL 1 — 1 —
ACE — — 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. 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.
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
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(Dollars in millions, except per share data, unless otherwise noted)
Note 11 — Commitments and Contingencies
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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(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