FULLTEXT DEL 3 AV 4
10-Q – 2025-11-04 – exc-20250930.htm
Other non-cash operating activities 172 96
Changes in assets and liabilities:
Accounts receivable ( 28 ) ( 116 )
Receivables from and payables to affiliates, net ( 17 ) ( 8 )
Inventories ( 36 ) ( 32 )
Accounts payable and accrued expenses 21 37
Collateral received, net 1 1
Income taxes ( 13 ) ( 55 )
Regulatory assets and liabilities, net ( 88 ) ( 158 )
Pension and non-pension postretirement benefit contributions ( 47 ) ( 79 )
Other assets and liabilities ( 20 ) ( 74 )
Net cash flows provided by operating activities 1,368 987
Cash flows from investing activities
Capital expenditures ( 1,552 ) ( 1,343 )
Proceeds from sales of long-lived assets 2 —
Net cash flows used in investing activities ( 1,550 ) ( 1,343 )
Cash flows from financing activities
Changes in short-term borrowings ( 364 ) ( 176 )
Issuance of long-term debt 500 1,100
Retirement of long-term debt — ( 583 )
Changes in Exelon intercompany money pool 1 10
Distributions to member ( 548 ) ( 549 )
Contributions from member 569 505
Other financing activities ( 19 ) ( 33 )
Net cash flows provided by financing activities 139 274
Decrease in cash, restricted cash, and cash equivalents ( 43 ) ( 82 )
Cash, restricted cash, and cash equivalents at beginning of period 163 204
Cash, restricted cash, and cash equivalents at end of period $ 120 $ 122
Supplemental cash flow information
Decrease in capital expenditures not paid $ ( 92 ) $ ( 27 )
See the Combined Notes to Consolidated Financial Statements
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Table of Contents
Pepco Holdings LLC and Subsidiary Companies
Consolidated Balance Sheets
(Unaudited)
(In millions) September 30, 2025 December 31, 2024
ASSETS
Current assets
Cash and cash equivalents $ 93 $ 139
Restricted cash and cash equivalents 27 24
Accounts receivable
Customer accounts receivable 829 827
Customer allowance for credit losses ( 123 ) ( 108 )
Customer accounts receivable, net 706 719
Other accounts receivable 281 284
Other allowance for credit losses ( 51 ) ( 49 )
Other accounts receivable, net 230 235
Receivables from affiliates 13 8
Inventories, net
Fossil fuel 9 7
Materials and supplies 360 325
Prepaid utility taxes 17 70
Regulatory assets 333 323
Prepaid renewable energy credits 155 194
Other 31 36
Total current assets 1,974 2,080
Property, plant, and equipment (net of accumulated depreciation and amortization of $ 4,196 and $ 3,728 as of September 30, 2025 and December 31, 2024, respectively)
20,925 20,053
Deferred debits and other assets
Regulatory assets 1,531 1,570
Goodwill 4,005 4,005
Investments 156 152
Prepaid pension asset 222 252
Other 134 185
Total deferred debits and other assets 6,048 6,164
Total assets $ 28,947 $ 28,297
See the Combined Notes to Consolidated Financial Statements
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Pepco Holdings LLC and Subsidiary Companies
Consolidated Balance Sheets
(Unaudited)
(In millions) September 30, 2025 December 31, 2024
LIABILITIES AND MEMBER'S EQUITY
Current liabilities
Short-term borrowings $ 166 $ 530
Long-term debt due within one year 214 290
Accounts payable 671 721
Accrued expenses 343 367
Payables to affiliates 54 66
Borrowings from Exelon intercompany money pool 64 63
Customer deposits 120 113
Regulatory liabilities 115 69
Unamortized energy contract liabilities 5 5
Renewable energy credit obligations 169 217
Other 97 124
Total current liabilities 2,018 2,565
Long-term debt 9,385 8,834
Deferred credits and other liabilities
Deferred income taxes and unamortized investment tax credits 3,337 3,190
Regulatory liabilities 731 794
Asset retirement obligations 65 67
Non-pension postretirement benefit obligations 26 31
Unamortized energy contract liabilities 17 21
Other 397 473
Total deferred credits and other liabilities 4,573 4,576
Total liabilities 15,976 15,975
Commitments and contingencies
Member's equity
Membership interest 13,131 12,562
Undistributed losses ( 160 ) ( 240 )
Total member's equity 12,971 12,322
Total liabilities and member's equity $ 28,947 $ 28,297
See the Combined Notes to Consolidated Financial Statements
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Pepco Holdings LLC and Subsidiary Companies
Consolidated Statements of Changes in Member's Equity
(Unaudited)
Nine Months Ended September 30, 2025
(In millions) Membership Interest Undistributed (Losses)/Gains Total Member's Equity
Balance at December 31, 2024 $ 12,562 $ ( 240 ) $ 12,322
Net income — 194 194
Distributions to member — ( 132 ) ( 132 )
Contributions from member 352 — 352
Balance at March 31, 2025 $ 12,914 $ ( 178 ) $ 12,736
Net income — 143 143
Distributions to member — ( 160 ) ( 160 )
Contributions from member 170 — 170
Balance at June 30, 2025 $ 13,084 $ ( 195 ) $ 12,889
Net income — 291 291
Distributions to member — ( 256 ) ( 256 )
Contributions from member 47 — 47
Balance at September 30, 2025 $ 13,131 $ ( 160 ) $ 12,971
Nine Months Ended September 30, 2024
(In millions) Membership Interest Undistributed (Losses)/Gains Total Member's Equity
Balance at December 31, 2023 $ 12,057 $ ( 275 ) $ 11,782
Net income — 168 168
Distributions to member — ( 118 ) ( 118 )
Contributions from member 487 — 487
Balance at March 31, 2024 $ 12,544 $ ( 225 ) $ 12,319
Net income — 158 158
Distributions to member — ( 164 ) ( 164 )
Contributions from member — — —
Balance at June 30, 2024 $ 12,544 $ ( 231 ) $ 12,313
Net income — 278 278
Distributions to member — ( 267 ) ( 267 )
Contributions from member 18 — 18
Balance at September 30, 2024 $ 12,562 $ ( 220 ) $ 12,342
See the Combined Notes to Consolidated Financial Statements
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Table of Contents
Potomac Electric Power Company
Statements of Operations and Comprehensive Income
(Unaudited)
Three Months Ended
September 30, Nine Months Ended
September 30,
(In millions) 2025 2024 2025 2024
Operating revenues
Electric operating revenues $ 995 854 $ 2,641 $ 2,273
Revenues from alternative revenue programs ( 5 ) 5 ( 19 ) 42
Operating revenues from affiliates 2 2 4 5
Total operating revenues 992 861 2,626 2,320
Operating expenses
Purchased power 367 294 942 808
Operating and maintenance 95 82 282 206
Operating and maintenance from affiliates 59 58 184 186
Depreciation and amortization 110 102 321 307
Taxes other than income taxes 122 114 344 317
Total operating expenses 753 650 2,073 1,824
Gain on sale of assets — — 1 —
Operating income 239 211 554 496
Other income and (deductions)
Interest expense, net ( 53 ) ( 50 ) ( 159 ) ( 142 )
Other, net 11 11 31 43
Total other income and (deductions) ( 42 ) ( 39 ) ( 128 ) ( 99 )
Income before income taxes 197 172 426 397
Income taxes 41 32 89 74
Net income $ 156 $ 140 $ 337 $ 323
Comprehensive income $ 156 $ 140 $ 337 $ 323
See the Combined Notes to Consolidated Financial Statements
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Table of Contents
Potomac Electric Power Company
Statements Of Cash Flows
(Unaudited)
Nine Months Ended
September 30,
(In millions) 2025 2024
Cash flows from operating activities
Net income $ 337 $ 323
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation, amortization, and accretion 322 307
Gain on sales of assets ( 1 ) —
Deferred income taxes and amortization of investment tax credits 34 22
Other non-cash operating activities 62 ( 11 )
Changes in assets and liabilities:
Accounts receivable ( 58 ) ( 37 )
Receivables from and payables to affiliates, net — 1
Inventories ( 11 ) ( 10 )
Accounts payable and accrued expenses 20 61
Collateral received (paid), net 2 ( 1 )
Income taxes ( 27 ) ( 45 )
Regulatory assets and liabilities, net ( 39 ) ( 54 )
Pension and non-pension postretirement benefit contributions ( 7 ) ( 7 )
Other assets and liabilities ( 5 ) ( 56 )
Net cash flows provided by operating activities 629 493
Cash flows from investing activities
Capital expenditures ( 690 ) ( 672 )
Proceeds from sales of long-lived assets 2 —
Net cash flows used in investing activities ( 688 ) ( 672 )
Cash flows from financing activities
Changes in short-term borrowings ( 137 ) ( 83 )
Issuance of long-term debt 275 675
Retirement of long-term debt — ( 400 )
Dividends paid on common stock ( 267 ) ( 286 )
Contributions from parent 192 260
Other financing activities ( 8 ) ( 19 )
Net cash flows provided by financing activities 55 147
Decrease in cash, restricted cash, and cash equivalents ( 4 ) ( 32 )
Cash, restricted cash, and cash equivalents at beginning of period 51 72
Cash, restricted cash, and cash equivalents at end of period $ 47 $ 40
Supplemental cash flow information
Decrease in capital expenditures not paid $ ( 34 ) $ ( 27 )
See the Combined Notes to Consolidated Financial Statements
37
Table of Contents
Potomac Electric Power Company
Balance Sheets
(Unaudited)
(In millions) September 30, 2025 December 31, 2024
ASSETS
Current assets
Cash and cash equivalents $ 25 $ 30
Restricted cash and cash equivalents 22 21
Accounts receivable
Customer accounts receivable 431 395
Customer allowance for credit losses ( 72 ) ( 59 )
Customer accounts receivable, net 359 336
Other accounts receivable 149 142
Other allowance for credit losses ( 28 ) ( 27 )
Other accounts receivable, net 121 115
Receivables from affiliates 1 1
Inventories, net 181 169
Regulatory assets 166 157
Prepaid renewable energy credits 132 165
Other 21 55
Total current assets 1,028 1,049
Property, plant, and equipment (net of accumulated depreciation and amortization of $ 4,719 and $ 4,522 as of September 30, 2025 and December 31, 2024, respectively)
10,493 10,097
Deferred debits and other assets
Regulatory assets 408 446
Investments 139 135
Prepaid pension asset 201 222
Other 57 51
Total deferred debits and other assets 805 854
Total assets $ 12,326 $ 12,000
See the Combined Notes to Consolidated Financial Statements
38
Table of Contents
Potomac Electric Power Company
Balance Sheets
(Unaudited)
(In millions) September 30, 2025 December 31, 2024
LIABILITIES AND SHAREHOLDER'S EQUITY
Current liabilities
Short-term borrowings $ 63 $ 200
Long-term debt due within one year 6 6
Accounts payable 351 360
Accrued expenses 167 201
Payables to affiliates 33 37
Customer deposits 60 55
Regulatory liabilities 12 17
Merger related obligation 20 22
Renewable energy credit obligations 134 169
Other 46 51
Total current liabilities 892 1,118
Long-term debt 4,626 4,356
Deferred credits and other liabilities
Deferred income taxes and unamortized investment tax credits 1,581 1,509
Regulatory liabilities 276 310
Asset retirement obligations 48 49
Other 206 223
Total deferred credits and other liabilities 2,111 2,091
Total liabilities 7,629 7,565
Commitments and contingencies
Shareholder's equity
Common stock 3,527 3,335
Retained earnings 1,170 1,100
Total shareholder's equity 4,697 4,435
Total liabilities and shareholder's equity $ 12,326 $ 12,000
See the Combined Notes to Consolidated Financial Statements
39
Table of Contents
Potomac Electric Power Company
Statements Of Changes In Shareholder's Equity
(Unaudited)
Nine Months Ended September 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
Net income — 156 156
Common stock dividends — ( 109 ) ( 109 )
Contributions from parent 35 — 35
Balance at September 30, 2025 $ 3,527 $ 1,170 $ 4,697
Nine Months Ended September 30, 2024
(In millions) Common Stock Retained Earnings Total Shareholder's Equity
Balance at December 31, 2023 $ 3,075 $ 1,069 $ 4,144
Net income — 75 75
Common stock dividends — ( 51 ) ( 51 )
Contributions from parent 251 — 251
Balance at March 31, 2024 $ 3,326 $ 1,093 $ 4,419
Net income — 108 108
Common stock dividends — ( 102 ) ( 102 )
Contributions from parent — — —
Balance at June 30, 2024 $ 3,326 $ 1,099 $ 4,425
Net income — 140 140
Common stock dividends — ( 133 ) ( 133 )
Contributions from parent 9 — 9
Balance at September 30, 2024 $ 3,335 $ 1,106 $ 4,441
See the Combined Notes to Consolidated Financial Statements
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Table of Contents
Delmarva Power & Light Company
Statements of Operations and Comprehensive Income
(Unaudited)
Three Months Ended
September 30, Nine Months Ended
September 30,
(In millions) 2025 2024 2025 2024
Operating revenues
Electric operating revenues $ 467 $ 440 $ 1,316 $ 1,215
Natural gas operating revenues 27 23 148 122
Revenues from alternative revenue programs ( 5 ) ( 3 ) ( 10 ) 1
Operating revenues from affiliates 2 2 6 5
Total operating revenues 491 462 1,460 1,343
Operating expenses
Purchased power 211 196 580 529
Purchased fuel 8 7 57 44
Operating and maintenance 51 49 162 151
Operating and maintenance from affiliates 43 43 134 133
Depreciation and amortization 63 62 189 183
Taxes other than income taxes 21 20 63 59
Total operating expenses 397 377 1,185 1,099
Operating income 94 85 275 244
Other income and (deductions)
Interest expense, net ( 26 ) ( 22 ) ( 75 ) ( 69 )
Other, net 4 6 12 20
Total other income and (deductions) ( 22 ) ( 16 ) ( 63 ) ( 49 )
Income before income taxes 72 69 212 195
Income taxes 17 14 49 39
Net income $ 55 $ 55 $ 163 $ 156
Comprehensive income $ 55 $ 55 $ 163 $ 156
See the Combined Notes to Consolidated Financial Statements
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Table of Contents
Delmarva Power & Light Company
Statements Of Cash Flows
(Unaudited)
Nine Months Ended
September 30,
(In millions) 2025 2024
Cash flows from operating activities
Net income $ 163 $ 156
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation and amortization 189 183
Deferred income taxes and amortization of investment tax credits 24 12
Other non-cash operating activities 42 29
Changes in assets and liabilities:
Accounts receivable 20 ( 1 )
Receivables from and payables to affiliates, net ( 3 ) ( 3 )
Inventories ( 16 ) ( 17 )
Accounts payable and accrued expenses 15 14
Collateral received, net — 2
Income taxes ( 1 ) ( 25 )
Regulatory assets and liabilities, net ( 32 ) ( 41 )
Pension and non-pension postretirement benefit contributions ( 1 ) ( 1 )
Other assets and liabilities 23 19
Net cash flows provided by operating activities 423 327
Cash flows from investing activities
Capital expenditures ( 402 ) ( 404 )
Net cash flows used in investing activities ( 402 ) ( 404 )
Cash flows from financing activities
Changes in short-term borrowings ( 111 ) ( 63 )
Issuance of long-term debt 125 175
Retirement of long-term debt — ( 33 )
Dividends paid on common stock ( 149 ) ( 162 )
Contributions from parent 107 160
Other financing activities ( 8 ) ( 6 )
Net cash flows (used in) provided by financing activities ( 36 ) 71
Decrease in cash, restricted cash, and cash equivalents ( 15 ) ( 6 )
Cash, restricted cash, and cash equivalents at beginning of period 23 16
Cash, restricted cash, and cash equivalents at end of period $ 8 $ 10
Supplemental cash flow information
(Decrease) increase in capital expenditures not paid $ ( 40 ) $ 9
See the Combined Notes to Consolidated Financial Statements
42
Table of Contents
Delmarva Power & Light Company
Balance Sheets
(Unaudited)
(In millions) September 30, 2025 December 31, 2024
ASSETS
Current assets
Cash and cash equivalents $ 6 $ 21
Restricted cash and cash equivalents 2 2
Accounts receivable
Customer accounts receivable 178 210
Customer allowance for credit losses ( 20 ) ( 17 )
Customer accounts receivable, net 158 193
Other accounts receivable 67 63
Other allowance for credit losses ( 9 ) ( 9 )
Other accounts receivable, net 58 54
Receivables from affiliates 1 —
Inventories, net
Fossil fuel 9 6
Materials and supplies 108 95
Prepaid utility taxes — 26
Regulatory assets 69 60
Prepaid renewable energy credits 22 29
Other 10 16
Total current assets 443 502
Property, plant, and equipment (net of accumulated depreciation and amortization of $ 2,196 and $ 2,075 as of September 30, 2025 and December 31, 2024, respectively)
5,733 5,540
Deferred debits and other assets
Regulatory assets 212 215
Prepaid pension asset 107 120
Other 45 44
Total deferred debits and other assets 364 379
Total assets $ 6,540 $ 6,421
See the Combined Notes to Consolidated Financial Statements
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Table of Contents
Delmarva Power & Light Company
Balance Sheets
(Unaudited)
(In millions) September 30, 2025 December 31, 2024
LIABILITIES AND SHAREHOLDER'S EQUITY
Current liabilities
Short-term borrowings $ 33 $ 144
Long-term debt due within one year 53 130
Accounts payable 147 187
Accrued expenses 71 55
Payables to affiliates 23 26
Customer deposits 35 34
Regulatory liabilities 38 42
Renewable energy credit obligations 35 48
Other 18 22
Total current liabilities 453 688
Long-term debt 2,291 2,090
Deferred credits and other liabilities
Deferred income taxes and unamortized investment tax credits 983 946
Regulatory liabilities 316 325
Asset retirement obligations 12 13
Non-pension postretirement benefit obligations 2 3
Other 120 114
Total deferred credits and other liabilities 1,433 1,401
Total liabilities 4,177 4,179
Commitments and contingencies
Shareholder's equity
Common stock 1,722 1,615
Retained earnings 641 627
Total shareholder's equity 2,363 2,242
Total liabilities and shareholder's equity $ 6,540 $ 6,421
See the Combined Notes to Consolidated Financial Statements
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Table of Contents
Delmarva Power & Light Company
Statements Of Changes In Shareholder's Equity
(Unaudited)
Nine Months Ended September 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
Net income — 55 55
Common stock dividends — ( 59 ) ( 59 )
Contributions from parent 8 — 8
Balance at September 30, 2025 $ 1,722 $ 641 $ 2,363
Nine Months Ended September 30, 2024
(In millions) Common Stock Retained Earnings Total Shareholder's Equity
Balance at December 31, 2023 $ 1,455 $ 638 $ 2,093
Net income — 66 66
Common stock dividends — ( 45 ) ( 45 )
Contributions from parent 154 — 154
Balance at March 31, 2024 $ 1,609 $ 659 $ 2,268
Net income — 34 34
Common stock dividends — ( 39 ) ( 39 )
Balance at June 30, 2024 $ 1,609 $ 654 $ 2,263
Net income — 55 55
Common stock dividends — ( 78 ) ( 78 )
Contributions from parent 6 — 6
Balance at September 30, 2024 $ 1,615 $ 631 $ 2,246
See the Combined Notes to Consolidated Financial Statements
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Table of Contents
Atlantic City Electric Company and Subsidiary Company
Consolidated Statements of Operations and Comprehensive Income
(Unaudited)
Three Months Ended
September 30, Nine Months Ended
September 30,
(In millions) 2025 2024 2025 2024
Operating revenues
Electric operating revenues $ 553 $ 533 $ 1,323 $ 1,281
Revenues from alternative revenue programs 16 6 2 ( 3 )
Operating revenues from affiliates 1 1 3 2
Total operating revenues 570 540 1,328 1,280
Operating expenses
Purchased power 286 245 616 557
Operating and maintenance 55 58 161 155
Operating and maintenance from affiliates 37 38 116 119
Depreciation and amortization 61 67 188 214
Taxes other than income taxes 2 2 7 7
Total operating expenses 441 410 1,088 1,052
Operating income 129 130 240 228
Other income and (deductions)
Interest expense, net ( 20 ) ( 21 ) ( 62 ) ( 59 )
Other, net 2 4 8 12
Total other income and (deductions) ( 18 ) ( 17 ) ( 54 ) ( 47 )
Income before income taxes 111 113 186 181
Income taxes 29 30 48 48
Net income $ 82 $ 83 $ 138 $ 133
Comprehensive income $ 82 $ 83 $ 138 $ 133
See the Combined Notes to Consolidated Financial Statements
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Table of Contents
Atlantic City Electric Company and Subsidiary Company
Statements Of Cash Flows
(Unaudited)
Nine Months Ended
September 30,
(In millions) 2025 2024
Cash flows from operating activities
Net income $ 138 $ 133
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation and amortization 188 214
Deferred income taxes and amortization of investment tax credits 32 33
Other non-cash operating activities 42 49
Changes in assets and liabilities:
Accounts receivable 9 ( 77 )
Receivables from and payables to affiliates, net ( 8 ) ( 8 )
Inventories ( 10 ) ( 5 )
Accounts payable and accrued expenses 5 ( 18 )
Income taxes 3 ( 2 )
Regulatory assets and liabilities, net ( 14 ) ( 62 )
Pension and non-pension postretirement benefit contributions ( 3 ) ( 7 )
Other assets and liabilities ( 21 ) ( 39 )
Net cash flows provided by operating activities 361 211
Cash flows from investing activities
Capital expenditures ( 292 ) ( 265 )
Net cash flows used in investing activities ( 292 ) ( 265 )
Cash flows from financing activities
Changes in short-term borrowings ( 116 ) ( 30 )
Issuance of long-term debt 100 250
Retirement of long-term debt — ( 150 )
Dividends paid on common stock ( 132 ) ( 100 )
Contributions from parent 98 85
Other financing activities ( 5 ) ( 5 )
Net cash flows (used in) provided by financing activities ( 55 ) 50
Increase (decrease) in cash and cash equivalents 14 ( 4 )
Cash and cash equivalents at beginning of period 14 21
Cash and cash equivalents at end of period $ 28 $ 17
Supplemental cash flow information
Decrease in capital expenditures not paid $ ( 19 ) $ ( 10 )
See the Combined Notes to Consolidated Financial Statements
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Table of Contents
Atlantic City Electric Company and Subsidiary Company
Consolidated Balance Sheets
(Unaudited)
(In millions) September 30, 2025 December 31, 2024
ASSETS
Current assets
Cash and cash equivalents $ 25 $ 14
Restricted cash and cash equivalents 3 —
Accounts receivable
Customer accounts receivable 221 223
Customer allowance for credit losses ( 31 ) ( 32 )
Customer accounts receivable, net 190 191
Other accounts receivable 64 79
Other allowance for credit losses ( 14 ) ( 13 )
Other accounts receivable, net 50 66
Receivables from affiliates 11 7
Inventories, net 72 62
Prepaid utility taxes 7 —
Regulatory assets 94 101
Other 8 6
Total current assets 460 447
Property, plant, and equipment (net of accumulated depreciation and amortization of $ 1,917 and $ 1,798 as of September 30, 2025 and December 31, 2024, respectively)
4,484 4,366
Deferred debits and other assets
Regulatory assets 526 502
Prepaid pension asset 3 1
Other 43 33
Total deferred debits and other assets 572 536
Total assets $ 5,516 $ 5,349
See the Combined Notes to Consolidated Financial Statements
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Table of Contents
Atlantic City Electric Company and Subsidiary Company
Consolidated Balance Sheets
(Unaudited)
(In millions) September 30, 2025 December 31, 2024
LIABILITIES AND SHAREHOLDER'S EQUITY
Current liabilities
Short-term borrowings $ 70 $ 186
Long-term debt due within one year 155 154
Accounts payable 164 163
Accrued expenses 47 52
Payables to affiliates 18 22
Customer deposits 25 24
Regulatory liabilities 66 10
Other 10 10
Total current liabilities 555 621
Long-term debt 1,880 1,779
Deferred credits and other liabilities
Deferred income taxes and unamortized investment tax credits 851 816
Regulatory liabilities 138 146
Other 64 62
Total deferred credits and other liabilities 1,053 1,024
Total liabilities 3,488 3,424
Commitments and contingencies
Shareholder's equity
Common stock 2,013 1,915
Retained earnings 15 10
Total shareholder's equity 2,028 1,925
Total liabilities and shareholder's equity $ 5,516 $ 5,349
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)
Nine Months Ended September 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
Net income — 82 82
Common stock dividends — ( 88 ) ( 88 )
Contributions from parent 4 — 4
Balance at September 30, 2025 $ 2,013 $ 15 $ 2,028
Nine Months Ended September 30, 2024
(In millions) Common Stock Retained (Deficit) Earnings Total Shareholder's Equity
Balance at December 31, 2023 $ 1,830 $ ( 18 ) $ 1,812
Net income — 29 29
Common stock dividends — ( 22 ) ( 22 )
Contributions from parent 81 — 81
Balance at March 31, 2024 $ 1,911 $ ( 11 ) $ 1,900
Net income — 21 21
Common stock dividends — ( 22 ) ( 22 )
Balance at June 30, 2024 $ 1,911 $ ( 12 ) $ 1,899
Net income — 83 83
Common stock dividends — ( 56 ) ( 56 )
Contributions from parent 4 — 4
Balance at September 30, 2024 $ 1,915 $ 15 $ 1,930
See the Combined Notes to Consolidated Financial Statements
50
Table of Contents
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
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
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 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.
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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
The accompanying consolidated financial statements as of September 30, 2025 and for the three and nine months ended September 30, 2025 and 2024 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, 2024 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, 2025. 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 September 30, 2025: 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 September 30, 2025. 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.
Improvement to Income Tax Disclosures (Issued December 2023). Provides additional disclosure requirements related to the effective tax rate reconciliation and income taxes paid. Under the revised guidance for the effective tax reconciliations, entities would be required to disclose: (1) eight specific categories in the effective tax rate reconciliation in both percentages and reporting currency amount, (2) additional information for reconciling items over a certain threshold, (3) explanation of individual reconciling items disclosed, and (4) provide a qualitative description of the state and local jurisdictions that contribute to the majority of the state income tax expense. For each annual period presented, the new standard requires disclosure of the year-to-date amount of income taxes paid (net of refunds received) disaggregated by federal, state, and foreign. It also requires additional disaggregated information on income taxes paid (net of refunds received) to an individual jurisdiction equal to or greater than 5% of total income taxes paid (net of refunds received). The standard is effective for annual periods beginning January 1, 2025.
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.
2. Regulatory Matters (All Registrants)
As discussed in Note 3 — Regulatory Matters of the 2024 Form 10-K, the Registrants are involved in rate and regulatory proceedings at FERC and their state commissions. The following discusses developments in 2025 and updates to the 2024 Form 10-K.
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(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 2025.
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 (a)
Electric $ 1,487 $ 1,045 8.905 % December 19, 2024 January 1, 2024
April 26, 2024 (amended on September 11, 2024) (b)
Electric $ 624 $ 623 9.89 % October 31, 2024 January 1, 2025
PECO - Pennsylvania March 28, 2024 Electric (c)(d)
$ 464 $ 354 N/A (e)
December 12, 2024 January 1, 2025
Natural Gas (d)
$ 111 $ 78
BGE - Maryland (f)
February 17, 2023 Electric $ 313 $ 179 9.50 % December 14, 2023 January 1, 2024
Natural Gas $ 289 $ 229 9.45 %
Pepco - District of Columbia (g)
April 13, 2023 (amended February 27, 2024) Electric $ 186 $ 123 9.50 % November 26, 2024 January 1, 2025
Pepco - Maryland (h)
May 16, 2023 (amended February 23, 2024) Electric $ 111 $ 45 9.50 % June 10, 2024 April 1, 2024
DPL - Maryland (i)
May 19, 2022 Electric $ 38 $ 29 9.60 % December 14, 2022 January 1, 2023
DPL - Delaware (j)
December 15, 2022 (amended September 29, 2023) Electric $ 39 $ 28 9.60 % April 18, 2024 July 15, 2023
ACE - New Jersey (k)
February 15, 2023 (amended August 21, 2023) Electric $ 92 $ 45 9.60 % November 17, 2023 December 1, 2023
__________
(a) Reflects a four-year cumulative multi-year rate plan for January 1, 2024 to 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 March 20, 2025, ComEd filed its annual revenue balancing reconciliation for 2024. This reconciliation, which is a component of revenue decoupling, reflected a revenue reduction of $ 55 million, effective January 1, 2026. On April 29, 2025, ComEd filed its 2024 MRP Reconciliation reflecting a revenue increase of $ 268 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.
(b) On October 31, 2024, the Delivery Reconciliation Amount for 2023 defined in Rider Delivery Service Pricing Reconciliation (Rider DSPR) was approved. Rider DSPR allows for the reconciliation of the revenue requirement in effect in the final years in which formula rates are determined and until such time as new rates are established under ComEd's approved MRP. The 2024 order reconciled the delivery service rates in effect in 2023 with the actual delivery service costs incurred in 2023. The reconciliation revenue requirement provides for a weighted average debt and equity return on distribution rate base of 7.02 %, inclusive of an allowed ROE of 9.89 %, reflecting the monthly yields on 30-year treasury bonds plus 580 basis points.
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(Dollars in millions, except per share data, unless otherwise noted)
Note 2 — Regulatory Matters
(c) 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.
(d) 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.
(e) The PECO electric and natural gas base rate case proceedings were resolved through settlement agreements, which did not specify an approved ROE.
(f) Reflects a three-year cumulative multi-year plan for January 1, 2024 through December 31, 2026. The MDPSC awarded BGE electric revenue requirement increases of $ 41 million, $ 113 million, and $ 25 million in 2024, 2025, and 2026, respectively, and natural gas revenue requirement increases of $ 126 million, $ 62 million, and $ 41 million in 2024, 2025, and 2026, respectively. 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 was recovered through separate electric and gas riders between March 2024 through February 2025. As such, the reconciliation amounts are not included in the approved revenue requirement 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.
(g) Reflects a two-year cumulative multi-year plan for 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.
(h) Reflects the amounts requested (before offsets) and awarded for a one-year multi-year plan for April 1, 2024 through March 31, 2025. The MDPSC awarded Pepco an electric incremental revenue requirement increase of $ 45 million for the 12-month period ending March 31, 2025. 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 $ 31 million for the 12-month period ended March 31, 2024, with supporting testimony and schedules.
(i) Reflects a three-year cumulative multi-year plan for January 1, 2023 through December 31, 2025. The MDPSC awarded DPL electric incremental revenue requirement increases of $ 17 million, $ 6 million, and $ 6 million for 2023, 2024, and 2025, respectively.
(j) On April 18, 2024, 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.
(k) Requested and approved increases are before New Jersey sales and use tax. The NJBPU awarded ACE electric revenue requirement increases of $ 36 million and $ 9 million effective December 1, 2023 and February 1, 2024, respectively.
Pending Distribution Base Rate Case Proceedings
Registrant/Jurisdiction Filing Date Service Requested Revenue Requirement Increase Requested ROE Expected Approval Timing
Pepco - Maryland October 14, 2025 Electric $ 133 10.50 % Third quarter of 2026
DPL - Delaware (a)
September 20, 2024 (amended September 5, 2025) Natural Gas $ 37 10.65 % First quarter of 2026
ACE - New Jersey (b)
November 21, 2024 Electric $ 109 10.70 % Fourth quarter of 2025
__________
(a) DPL implemented interim rates on April 20, 2025, subject to refund.
(b) Requested increases are before New Jersey sales and use tax. ACE may implement interim rates, subject to refund.
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(Dollars in millions, except per share data, unless otherwise noted)
Note 2 — Regulatory Matters
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 update for ComEd also reconciles any differences between the revenue requirement in effect beginning June 1 of the prior year and actual costs incurred for that year (annual reconciliation). 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 PECO, BGE, Pepco, DPL, and ACE also reconciles any differences between the actual costs and actual revenues for the calendar year (annual reconciliation).
For 2025, the following increases/(decreases) were included in the Utility Registrants' electric transmission formula rate updates:
Registrant (a)
Initial Revenue Requirement Increase (Decrease) Annual Reconciliation Increase (Decrease) Total Revenue Requirement Increase (Decrease) (b)
Allowed Return on Rate Base (c)
Allowed ROE (d)
ComEd $ 78 $ 49 $ 127 8.13 % 11.50 %
PECO $ 9 $ 13 $ 22 7.54 % 10.35 %
BGE $ 21 $ 21 $ 35 (e) 7.53 % 10.50 %
Pepco $ 35 $ 16 $ 51 7.71 % 10.50 %
DPL $ 32 $ ( 9 ) $ 23 7.48 % 10.50 %
ACE $ ( 11 ) $ ( 46 ) $ ( 57 ) 7.16 % 10.50 %
__________
(a) All rates are effective June 1, 2025 - May 31, 2026, 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.
(d) The rate of return on common equity for each Utility Registrant includes a 50 -basis-point incentive adder for being a member of an RTO.
(e) The increase in BGE's transmission revenue requirement includes a $ 7 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 (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
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(Dollars in millions, except per share data, unless otherwise noted)
Note 2 — Regulatory Matters
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 Grid Plan as non-compliant with certain requirements of CEJA and required ComEd to file a revised Grid Plan. In the absence of an approved Grid Plan, the ICC set ComEd’s forecast revenue requirements for 2024-2027 based on ComEd's approved year-end 2022 rate base. This resulted in a total cumulative revenue requirement increase of $ 501 million, a $ 986 million total revenue reduction from the requested cumulative revenue requirement increase but remained subject to annual reconciliation in accordance with CEJA. The final order approved the process and formulas associated with the MRP reconciliation mechanisms. The ICC's December 2023 order also denied ComEd's ability to earn a return on its pension asset.
On December 22, 2023, ComEd filed an application for rehearing on several findings in the final order including the use of the 2022 year-end rate base to establish forecast revenue requirements for 2024-2027, ROE, pension asset return, and capital structure. On January 10, 2024, ComEd’s application for rehearing was denied on all issues except for the order’s use of the 2022 year-end rate base. On April 18, 2024, the ICC issued its final order on rehearing, which approved the use of the forecasted year-end 2023 rate base that resulted in increased revenue requirements for 2024-2027. These revenue requirements determined during the rehearing process established base revenue requirements until the ICC approved the Refiled Grid Plan on December 19, 2024.
On January 10, 2024, ComEd filed an appeal in the Illinois Appellate Court of the issues on which rehearing was denied, 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 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 Grid Plan. On December 19, 2024, the ICC approved the Refiled 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.
In January 2022, ComEd filed a request with the ICC proposing performance metrics that would be used in determining ROE incentives and penalties in the event ComEd filed a MRP in January 2023. On September 27, 2022, the ICC issued a final order approving seven performance metrics that provide symmetrical performance adjustments of 32 total basis points to ComEd’s rate of return on common equity based on the extent to which ComEd achieves the annual performance goals. On November 10, 2022, the ICC granted ComEd's application for rehearing, in part. On April 5, 2023, the ICC issued its final order on rehearing for the performance and tracking metrics proceeding, in which the ICC declined to adopt ComEd's proposed modifications to the reliability and peak load reduction performance metrics.
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. As of September 30, 2025, the seller had not provided notification to ComEd or the IPA that any subsidies or tax credits, such as nuclear production tax credits that became available for electricity generated beginning January 1, 2024, have been monetized and the IPA has not adjusted the CMC price paid by ComEd. 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 is recorded for the difference between ComEd's costs associated with the procurement of CMCs from
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(Dollars in millions, except per share data, unless otherwise noted)
Note 2 — Regulatory Matters
participating nuclear power generating facilities and revenues received from customers. The balance as of September 30, 2025 is $ 94 million. On October 31, 2025, the seller provided notification to ComEd and the IPA that it has reflected on its 2024 federal income tax return $ 804 million of nuclear production tax credits associated with its participating nuclear power generating facilities. These amounts will be collected from the seller and returned to customers. In the fourth quarter of 2025, Exelon and ComEd’s Consolidated Balance Sheets will reflect these amounts as a receivable from the seller with an offsetting regulatory liability.
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). ComEd filed its annual energy efficiency formula rate update with the ICC on May 23, 2025. The revenue requirement is used to set the rates that will take effect in January 2026, subject to the ICC's review and approval. The requested revenue requirement update is based on a reconciliation of the 2024 actual costs plus projected 2026 expenditures.
Initial Revenue Requirement Increase Annual Reconciliation Decrease Total Revenue Requirement Increase Requested Return on Rate Base (a)
Requested ROE
$ 24 $ ( 4 ) $ 20 7.24 % 10.21 %
__________
(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 7.24 % inclusive of an allowed ROE of 10.21 %, reflecting the monthly average yields for 30-year treasury bonds plus 580 basis points. For the 2024 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 7.51 % inclusive of an allowed ROE of 10.75 %, 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.
Maryland Regulatory Matters
Next Generation Energy Act (Exelon, BGE, PHI, Pepco, and DPL). On May 20, 2025, the Governor of Maryland signed into law legislation that addresses several matters pertaining to electric and gas utilities, including affirming that the MDPSC may approve the use of multi-year rate plans that demonstrate customer benefits, among other things. It also prohibits utilities from filing after January 1, 2025, for the reconciliation of actuals costs and revenues to amounts approved within the multi-year plans. In the second quarter of 2025, BGE derecognized Regulatory assets of $ 10 million and Regulatory liabilities of $ 3 million for multi-year plan reconciliations that will no longer be filed. DPL also derecognized Regulatory liabilities of $ 0.4 million during the second quarter of 2025 for multi-year reconciliations yet to be filed. Multi-year plan reconciliations filed prior to January 1, 2025, remain lawful and will be resolved in their respective proceedings.
Summer Rate Mitigation (Exelon, BGE, PHI, Pepco, and DPL). As part of the passing of the Next Generation Energy Act by the Maryland General Assembly, the MDPSC issued an order on June 26, 2025, to implement the Legislative Energy Relief Refund program under which bill credits will be distributed to residential customers
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(Dollars in millions, except per share data, unless otherwise noted)
Note 2 — Regulatory Matters
based on their consumption of electricity supply that is subject to the renewable energy portfolio standard. On July 24, 2025, the MDPSC issued an order accepting BGE, Pepco, and DPL's proposal for the implementation of the program. As a result, BGE, Pepco, and DPL received $ 49 million, $ 21 million, and $ 8 million, respectively, from the MDPSC on August 6, 2025. These amounts were used to reduce residential customer account receivable balances within the third quarter of 2025. An additional disbursement from the state of Maryland is expected in the first quarter of 2026, which will also be used to reduce residential customer receivables upon receipt.
New Jersey Regulatory Matters
Summer Rate Mitigation (Exelon and ACE). In response to significant increases in electric supply costs, on April 23, 2025, the NJBPU issued an order directing the State's electric public utilities to file petitions proposing distribution side measures to mitigate residential customer bill impacts during summer months. As a result, on June 18, 2025, the NJBPU approved a stipulation of settlement for ACE to issue a bill credit of $ 30 per residential customer for the months of July and August 2025, which was deferred to a Regulatory asset. The amounts will subsequently be collected from September 2025 through February 2026 at a flat rate of $ 10 per residential customer. The bill credit and subsequent collections will not be subject to carrying costs.
Residential Universal Bill Credit (Exelon and ACE). In an effort to further reduce the burden of increased electric supply costs, on August 13, 2025, the NJBPU issued an order to establish the RUBC, which will be funded by the NJBPU. The program will provide a $ 50 bill credit per eligible residential customer for the months of September and October 2025. ACE received $ 51 million from the NJBPU on September 25, 2025, which was recognized as a Regulatory liability. ACE subsequently issued $ 25 million in bill credits to residential customers in September 2025 reducing the Regulatory liability to $ 26 million as of September 30, 2025. The remaining funds were disbursed in October 2025.
Other Federal Regulatory Matters
FERC Audit (Exelon and ComEd). The Utility Registrants are subject to periodic audits and investigations by FERC. FERC’s Division of Audits and Accounting initiated a nonpublic audit of ComEd in April 2021 evaluating ComEd’s compliance with (1) approved terms, rates and conditions of its federally regulated service; (2) accounting requirements of the Uniform System of Accounts; (3) reporting requirements of the FERC Form 1; and (4) the requirements for record retention. The audit period extended back to January 1, 2017.
On July 27, 2023, FERC published a final audit report which included, among other things, findings and recommendations related to ComEd's methodology regarding the allocation of certain overhead costs to capitalized construction costs under FERC regulations, including a suggestion that refunds may be due to customers for amounts collected in previous years. ComEd responded to that report and on August 28, 2023, ComEd filed a formal notice of the issues it contested within the audit report. On December 14, 2023, FERC appointed a settlement judge for the contested overhead allocation findings and set the matter for a trial-type hearing. That hearing process was held in abeyance while a formal settlement process, which began in February 2024, took place.
On July 30, 2024, ComEd reached an agreement in principle on the contested overhead allocation finding. As a result of the settlement process, ComEd recorded a charge for the probable disallowance of $ 70 million of certain currently capitalized construction costs to operating expenses, which are not expected to be recovered in future rates. The existing loss estimate was reflected in Exelon and ComEd's financial statements as of December 31, 2024. ComEd and FERC staff jointly filed the settlement agreement with FERC for approval on February 11, 2025. The settlement was approved by FERC on April 4, 2025.
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(Dollars in millions, except per share data, unless otherwise noted)
Note 2 — Regulatory Matters
Regulatory Assets and Liabilities
The Utility Registrants' regulatory assets and liabilities have not changed materially since December 31, 2024, unless noted below. See Note 3 — Regulatory Matters of the 2024 Form 10-K for additional information on the specific regulatory assets and liabilities.
ComEd. Regulatory assets decreased $ 370 million primarily due to a decrease of $ 453 million in the Electric distribution formula rate annual reconciliations, partially offset by an increase of $ 73 million in the Zero emission credit regulatory assets. Regulatory liabilities increased $ 644 million primarily due to an increase of $ 451 million in the Decommissioning the Regulatory Agreement Units and an increase of $ 193 million in Renewable portfolio standards costs regulatory liabilities.
PECO. Regulatory assets increased $ 229 million primarily due to an increase of $ 184 million in the Deferred income taxes regulatory asset and an increase of $ 53 million in the Deferred storm cost regulatory asset. Regulatory liabilities increased $ 212 million primarily due to an increase of $ 181 million in the Decommissioning the Regulatory Agreement Units and an increase of $ 44 million in the Electric energy and natural gas costs regulatory liabilities.
BGE. Regulatory liabilities decreased $ 28 million primarily due to a decrease of $ 41 million in the Deferred income taxes regulatory liability, partially offset by an increase of $ 10 million in the Transmission formula rate annual reconciliations regulatory liability.
Pepco. Regulatory liabilities decreased $ 39 million primarily due to a decrease of $ 37 million in the Deferred income taxes regulatory liability.
DPL. Regulatory assets increased $ 6 million primarily due to an increase of $ 16 million in the Electric energy and natural gas costs regulatory asset, partially offset by a decrease of $ 8 million in the Transmission formula rate annual reconciliations regulatory asset.
ACE. Regulatory assets increased $ 17 million primarily due to an increase of $ 26 million in the Summer rate mitigation regulatory asset. Regulatory liabilities increased $ 48 million primarily due to an increase of $ 26 million in the RUBC regulatory liability, an increase of $ 12 million in the Transmission formula rate annual reconciliations regulatory liability, and an increase of $ 6 million in the Electric energy and natural gas costs regulatory liability.
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 September 30, 2025 and December 31, 2024.
Exelon ComEd (a)
BGE (b)
PHI Pepco (c)
DPL (d)
ACE (e)
September 30, 2025 $ 67 $ 21 $ 5 $ 41 $ 23 $ 1 $ 17
December 31, 2024 117 46 16 55 40 1 14
__________
(a) Reflects ComEd's unrecognized equity returns earned for ratemaking purposes on its electric distribution rates and formula rates regulatory assets.
(b) BGE's amount capitalized for ratemaking purposes primarily relates to earnings on shareholders' investment on AMI programs and 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.
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Combined Notes to Consolidated Financial Statements — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Note 3 — Revenue from Contracts with Customers
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 4 — Revenue from Contracts with Customers of the 2024 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 4 — Revenue from Contracts with Customers of the 2024 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 nine months ended September 30, 2025 and 2024. At September 30, 2025 and December 31, 2024, ComEd's, PECO's, and BGE's contract liabilities were immaterial.
Exelon (a)
PHI (a)
Pepco (a)
DPL 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
Revenues recognized ( 1 ) ( 1 ) ( 1 ) — —
Balance at September 30, 2025 $ 122 $ 122 $ 97 $ 12 $ 13
Exelon (a)
PHI (a)
Pepco (a)
DPL ACE
Balance at December 31, 2023 $ 133 $ 133 $ 107 $ 13 $ 13
Revenues recognized ( 2 ) ( 2 ) ( 2 ) — —
Balance at March 31, 2024 $ 131 $ 131 $ 105 $ 13 $ 13
Revenues recognized ( 1 ) ( 1 ) ( 1 ) — —
Balance at June 30, 2024 $ 130 $ 130 $ 104 $ 13 $ 13
Revenues recognized ( 2 ) ( 2 ) ( 2 ) — —
Balance at September 30, 2024 $ 128 $ 128 $ 102 $ 13 $ 13
__________
(a) Revenues recognized in the three and nine months ended September 30, 2025 and 2024, were included in the contract liabilities at December 31, 2024 and 2023, 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 September 30, 2025. 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.
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Combined Notes to Consolidated Financial Statements — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Note 3 — Revenue from Contracts with Customers
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.
Year Exelon PHI Pepco DPL ACE
2025 $ 3 $ 3 $ 2 $ — $ 1
2026 5 5 5 — —
2027 6 6 5 1 —
2028 6 6 5 — 1
2029 and thereafter 102 102 80 11 11
Total $ 122 $ 122 $ 97 $ 12 $ 13
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.
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 nine months ended September 30, 2025 and 2024 is as follows:
Three Months Ended September 30, 2025 and 2024
ComEd PECO BGE PHI Other (a)
Intersegment
Eliminations Exelon
Operating revenues (b) :
2025
Electric revenues $ 2,275 $ 1,097 $ 1,091 $ 2,021 $ — $ ( 6 ) $ 6,478
Natural gas revenues — 83 118 27 — ( 1 ) 227
Shared service and other revenues — — — 3 447 ( 450 ) —
Total operating revenues $ 2,275 $ 1,180 $ 1,209 $ 2,051 $ 447 $ ( 457 ) $ 6,705
2024
Electric revenues $ 2,229 $ 960 $ 925 $ 1,836 $ — $ ( 6 ) $ 5,944
Natural gas revenues — 70 119 23 — ( 2 ) 210
Shared service and other revenues — — — 3 441 ( 444 ) —
Total operating revenues $ 2,229 $ 1,030 $ 1,044 $ 1,862 $ 441 $ ( 452 ) $ 6,154
Less:
Purchased power
2025 $ 806 $ 428 $ 547 $ 864 $ — $ — $ 2,645
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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
2024 835 372 407 735 — — 2,349
Purchased fuel
2025 $ — $ 18 $ 21 $ 8 $ — $ — $ 47
2024 — 14 13 7 — — 34
Operating and maintenance
2025 $ 313 $ 183 $ 179 $ 290 $ 409 $ ( 202 ) $ 1,172
2024 307 251 221 275 404 ( 183 ) 1,275
Operating and maintenance from affiliates
2025 $ 96 $ 58 $ 60 $ 45 $ 11 $ ( 270 ) $ —
2024 103 62 60 47 11 ( 283 ) —
Depreciation and amortization
2025 $ 395 $ 115 $ 155 $ 234 $ 13 $ — $ 912
2024 387 108 162 235 16 — 908
Taxes other than income taxes
2025 $ 107 $ 69 $ 93 $ 150 $ 10 $ — $ 429
2024 99 61 86 140 9 — 395
(Gain) on sale of assets
2025 $ — $ — $ — $ — $ — $ — $ —
2024 — — — — ( 3 ) — ( 3 )
Interest expense, net (c)
2025 $ 132 $ 63 $ 64 $ 102 $ 170 $ — $ 531
2024 125 55 57 95 158 — 490
Interest expense to affiliates, net (c)
2025 $ 3 $ 2 $ — $ — $ — $ 2 $ 7
2024 3 3 — — — — 6
Other, net
2025 $ ( 33 ) $ ( 11 ) $ ( 15 ) $ ( 18 ) $ ( 4 ) $ 13 $ ( 68 )
2024 ( 26 ) ( 9 ) ( 11 ) ( 22 ) ( 3 ) 14 ( 57 )
Income Taxes
2025 $ 83 $ 5 $ 23 $ 85 $ ( 41 ) $ — $ 155
2024 36 ( 4 ) 4 72 ( 58 ) — 50
Net income (loss) attributable to common shareholders
2025 $ 373 $ 250 $ 82 $ 291 $ ( 121 ) $ — $ 875
2024 360 117 45 278 ( 93 ) — 707
Supplemental segment information
Intersegment revenues (d)
2025 $ 2 $ 3 $ 2 $ 2 $ 444 $ ( 453 ) $ —
2024 2 4 3 3 438 ( 450 ) —
Capital Expenditures
2025 $ 781 $ 502 $ 407 $ 444 $ 2 $ — $ 2,136
2024 508 382 365 440 — — 1,695
__________
(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.
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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
PHI:
Pepco DPL ACE Other (a)
Intersegment
Eliminations PHI
Operating revenues (b) :
2025
Electric revenues $ 992 $ 464 $ 570 $ — $ ( 5 ) $ 2,021
Natural gas revenues — 27 — — — 27
Shared service and other revenues — — — 106 ( 103 ) 3
Total operating revenues $ 992 $ 491 $ 570 $ 106 $ ( 108 ) $ 2,051
2024
Electric revenues $ 861 $ 439 $ 540 $ — $ ( 4 ) $ 1,836
Natural gas revenues — 23 — — — 23
Shared service and other revenues — — — 103 ( 100 ) 3
Total operating revenues $ 861 $ 462 $ 540 $ 103 $ ( 104 ) $ 1,862
Less:
Purchased power
2025 $ 367 $ 211 $ 286 $ — $ — $ 864
2024 294 196 245 — — 735
Purchased fuel
2025 $ — $ 8 $ — $ — $ — $ 8
2024 — 7 — — — 7
Operating and maintenance
2025 $ 95 $ 51 $ 55 $ 89 $ — $ 290
2024 82 49 58 86 — 275
Operating and maintenance from affiliates
2025 $ 59 $ 43 $ 37 $ 14 $ ( 108 ) $ 45
2024 58 43 38 12 ( 104 ) 47
Depreciation and amortization
2025 $ 110 $ 63 $ 61 $ — $ — $ 234
2024 102 62 67 4 — 235
Taxes other than income taxes
2025 $ 122 $ 21 $ 2 $ 5 $ — $ 150
2024 114 20 2 4 — 140
Loss on sale of assets
2025 $ — $ — $ — $ — $ — $ —
2024 — — — — — —
Interest expense, net (c)
2025 $ 53 $ 26 $ 20 $ 3 $ — $ 102
2024 50 22 21 2 — 95
Interest expense to affiliates, net (c)
2025 $ — $ — $ — $ — $ — $ —
2024 — — — 1 ( 1 ) —
Other, net
2025 $ ( 11 ) $ ( 4 ) $ ( 2 ) $ ( 1 ) $ — $ ( 18 )
2024 ( 11 ) ( 6 ) ( 4 ) ( 2 ) 1 ( 22 )
Income Taxes
2025 $ 41 $ 17 $ 29 $ ( 2 ) $ — $ 85
2024 32 14 30 ( 4 ) — 72
Net income (loss) attributable to common shareholders
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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 $ 156 $ 55 $ 82 $ ( 2 ) $ — $ 291
2024 140 55 83 — — 278
Supplemental segment information
Intersegment revenues (d)
2025 $ 2 $ 2 $ 1 $ 106 $ ( 109 ) $ 2
2024 2 2 1 103 ( 105 ) 3
Capital Expenditures
2025 $ 221 $ 125 $ 96 $ 2 $ — $ 444
2024 218 136 85 1 — 440
__________
(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.
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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 September 30, 2025
Revenues from contracts with customers ComEd PECO BGE PHI Pepco DPL ACE
Electric revenues
Residential $ 1,365 $ 735 $ 684 $ 1,147 $ 501 $ 283 $ 363
Small commercial & industrial 645 167 113 210 56 72 82
Large commercial & industrial 217 101 172 406 331 32 43
Public authorities & electric railroads 14 8 8 16 8 4 4
Other (a)
229 78 122 235 98 77 62
Total electric revenues (b)
$ 2,470 $ 1,089 $ 1,099 $ 2,014 $ 994 $ 468 $ 554
Natural gas revenues
Residential $ — $ 50 $ 68 $ 13 $ — $ 13 $ —
Small commercial & industrial — 23 14 7 — 7 —
Large commercial & industrial — 1 37 1 — 1 —
Transportation — 7 — 4 — 4 —
Other (c)
— 1 6 2 — 2 —
Total natural gas revenues (d)
$ — $ 82 $ 125 $ 27 $ — $ 27 $ —
Total revenues from contracts with customers $ 2,470 $ 1,171 $ 1,224 $ 2,041 $ 994 $ 495 $ 554
Other revenues
Revenues from alternative revenue programs $ ( 206 ) $ 2 $ ( 20 ) $ 6 $ ( 5 ) $ ( 5 ) $ 16
Other electric revenues (e)
11 6 4 4 3 1 —
Other natural gas revenues (e)
— 1 1 — — — —
Total other revenues $ ( 195 ) $ 9 $ ( 15 ) $ 10 $ ( 2 ) $ ( 4 ) $ 16
Total revenues for reportable segments $ 2,275 $ 1,180 $ 1,209 $ 2,051 $ 992 $ 491 $ 570
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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 September 30, 2024
Revenues from contracts with customers ComEd PECO BGE PHI Pepco DPL ACE
Electric revenues
Residential $ 1,117 $ 641 $ 558 $ 1,016 $ 426 $ 267 $ 323
Small commercial & industrial 603 153 96 203 52 69 82
Large commercial & industrial 286 73 154 365 281 31 53
Public authorities & electric railroads 11 7 8 18 9 4 5
Other (a)
280 74 110 225 85 70 71
Total electric revenues (b)
$ 2,297 $ 948 $ 926 $ 1,827 $ 853 $ 441 $ 534
Natural gas revenues
Residential $ — $ 44 $ 58 $ 11 $ — $ 11 $ —
Small commercial & industrial — 17 11 6 — 6 —
Large commercial & industrial — — 32 1 — 1 —
Transportation — 7 — 4 — 4 —
Other (c)
— 2 3 1 — 1 —
Total natural gas revenues (d)
$ — $ 70 $ 104 $ 23 $ — $ 23 $ —
Total revenues from contracts with customers $ 2,297 $ 1,018 $ 1,030 $ 1,850 $ 853 $ 464 $ 534
Other revenues
Revenues from alternative revenue programs $ ( 76 ) $ 5 $ 9 $ 8 $ 5 $ ( 3 ) $ 6
Other electric revenues (e)
8 7 4 4 3 1 —
Other natural gas revenues (e)
— — 1 — — — —
Total other revenues $ ( 68 ) $ 12 $ 14 $ 12 $ 8 $ ( 2 ) $ 6
Total revenues for reportable segments $ 2,229 $ 1,030 $ 1,044 $ 1,862 $ 861 $ 462 $ 540
__________
(a) Includes transmission revenue from PJM, wholesale electric revenue, and mutual assistance revenue.
(b) Includes operating revenues from affiliates in 2025 and 2024 respectively of:
• $ 2 million, $ 2 million at ComEd
• $ 2 million, $ 3 million at PECO
• $ 1 million , $ 2 million at BGE
• $ 2 million, $ 3 million at PHI
• $ 2 million, $ 2 million at Pepco
• $ 2 million, $ 2 million at DPL
• $ 1 million, $ 1 million at ACE
(c) Includes revenues from off-system natural gas sales.
(d) Includes operating revenues from affiliates in 2025 and 2024 respectively of:
• $ 1 million, $ 1 million at PECO
• $ 1 million, $ 1 million at BGE
(e) Includes late payment charge revenues.
Nine Months Ended September 30, 2025 and 2024
ComEd PECO BGE PHI Other (a)
Intersegment
Eliminations Exelon
Operating revenues (b) :
2025
Electric revenues $ 6,176 $ 2,933 $ 2,951 $ 5,253 $ — $ ( 30 ) $ 17,283
Natural gas revenues — 580 840 148 — ( 5 ) 1,563
Shared service and other revenues — — — 7 1,381 ( 1,388 ) —
Total operating revenues $ 6,176 $ 3,513 $ 3,791 $ 5,408 $ 1,381 $ ( 1,423 ) $ 18,846
2024
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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
Electric revenues $ 6,403 $ 2,537 $ 2,588 $ 4,809 $ — $ ( 17 ) $ 16,320
Natural gas revenues — 438 680 122 — ( 3 ) 1,237
Shared service and other revenues — — — 7 1,369 ( 1,376 ) —
Total operating revenues $ 6,403 $ 2,975 $ 3,268 $ 4,938 $ 1,369 $ ( 1,396 ) $ 17,557
Less:
Purchased power
2025 $ 2,044 $ 1,093 $ 1,365 $ 2,138 $ — $ — $ 6,640
2024 2,504 977 1,108 1,895 ( 1 ) — 6,483
Purchased fuel
2025 $ — $ 195 $ 219 $ 57 $ — $ — $ 471
2024 — 136 120 44 1 — 301
Operating and maintenance
2025 $ 958 $ 690 $ 621 $ 876 $ 1,313 $ ( 618 ) $ 3,840
2024 970 695 613 780 1,277 ( 579 ) 3,756
Operating and maintenance from affiliates
2025 $ 296 $ 182 $ 186 $ 148 $ 32 $ ( 844 ) $ —
2024 307 181 182 147 29 ( 846 ) —
Depreciation and amortization
2025 $ 1,162 $ 336 $ 473 $ 701 $ 45 $ — $ 2,717
2024 1,124 318 474 716 49 — 2,681
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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
Taxes other than income taxes
2025 $ 303 $ 183 $ 273 $ 426 $ 31 $ — $ 1,216
2024 287 164 254 395 27 — 1,127
(Gain) on sale of assets
2025 $ — $ — $ — $ ( 1 ) $ — $ — $ ( 1 )
2024 ( 5 ) ( 4 ) — — ( 3 ) — ( 12 )
Interest expense, net (c)
2025 $ 385 $ 179 $ 183 $ 303 $ 510 $ — $ 1,560
2024 364 161 159 279 469 ( 4 ) 1,428
Interest expense to affiliates, net (c)
2025 $ 10 $ 9 $ — $ 2 $ ( 1 ) $ ( 2 ) $ 18
2024 10 9 — — ( 3 ) 2 18
Other, net
2025 $ ( 86 ) $ ( 29 ) $ ( 35 ) $ ( 54 ) $ ( 22 ) $ 41 $ ( 185 )
2024 ( 66 ) ( 27 ) ( 27 ) ( 79 ) ( 28 ) 31 ( 196 )
Income taxes
2025 $ 201 $ 23 $ 108 $ 184 $ ( 120 ) $ — $ 396
2024 85 9 32 158 ( 126 ) — 158
Net income (loss) attributable to common shareholders
2025 $ 903 $ 652 $ 398 $ 628 $ ( 407 ) $ — $ 2,174
2024 823 356 353 603 ( 322 ) — 1,813
Supplemental segment information
Intersegment revenues (d)
2025 $ 19 $ 9 $ 6 $ 7 $ 1,374 $ ( 1,415 ) $ —
2024 6 7 7 7 1,362 ( 1,389 ) —
Capital expenditures
2025 $ 1,970 $ 1,334 $ 1,211 $ 1,552 $ 28 $ — $ 6,095
2024 1,619 1,125 1,033 1,343 41 — 5,161
Total assets
September 30, 2025 $ 47,010 $ 19,227 $ 16,742 $ 28,947 $ 5,365 $ ( 3,752 ) $ 113,539
December 31, 2024 44,750 17,123 15,542 28,297 6,012 ( 3,940 ) 107,784
__________
(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) :
2025
Electric revenues $ 2,626 $ 1,312 $ 1,328 $ — $ ( 13 ) $ 5,253
Natural gas revenues — 148 — — — 148
Shared service and other revenues — — — 323 ( 316 ) 7
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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 $ 2,626 $ 1,460 $ 1,328 $ 323 $ ( 329 ) $ 5,408
2024
Electric revenues $ 2,320 $ 1,221 $ 1,280 $ — $ ( 12 ) $ 4,809
Natural gas revenues — 122 — — — 122
Shared service and other revenues — — — 328 ( 321 ) 7
Total operating revenues $ 2,320 $ 1,343 $ 1,280 $ 328 $ ( 333 ) $ 4,938
Less:
Purchased power
2025 $ 942 $ 580 $ 616 $ — $ — $ 2,138
2024 808 529 557 1 — 1,895
Purchased fuel
2025 $ — $ 57 $ — $ — $ — $ 57
2024 — 44 — — — 44
Operating and maintenance
2025 $ 282 $ 162 $ 161 $ 271 $ — $ 876
2024 206 151 155 268 — 780
Operating and maintenance from affiliates
2025 $ 184 $ 134 $ 116 $ 43 $ ( 329 ) $ 148
2024 186 133 119 41 ( 332 ) 147
Depreciation and amortization
2025 $ 321 $ 189 $ 188 $ 3 $ — $ 701
2024 307 183 214 12 — 716
Taxes other than income taxes
2025 $ 344 $ 63 $ 7 $ 12 $ — $ 426
2024 317 59 7 12 — 395
(Gain) on sale of assets
2025 $ ( 1 ) $ — $ — $ — $ — $ ( 1 )
2024 — — — — — —
Interest expense, net (c)
2025 $ 159 $ 75 $ 62 $ 7 $ — $ 303
2024 142 69 59 7 2 279
Interest expense to affiliates, net (c)
2025 $ — $ — $ — $ 2 $ — $ 2
2024 — — — 3 ( 3 ) —
Other, net
2025 $ ( 31 ) $ ( 12 ) $ ( 8 ) $ ( 3 ) $ — $ ( 54 )
2024 ( 43 ) ( 20 ) ( 12 ) ( 4 ) — ( 79 )
Income taxes
2025 $ 89 $ 49 $ 48 $ ( 2 ) $ — $ 184
2024 74 39 48 ( 3 ) — 158
Net income (loss) attributable to common shareholders
2025 $ 337 $ 163 $ 138 $ ( 10 ) $ — $ 628
2024 323 156 133 ( 9 ) — 603
Supplemental segment information
Intersegment revenues (d)
2025 $ 4 $ 6 $ 3 $ 323 $ ( 329 ) $ 7
2024 5 5 2 328 ( 333 ) 7
Capital expenditures
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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 $ 690 $ 402 $ 292 $ 168 $ — $ 1,552
2024 672 404 265 2 — 1,343
Total assets
September 30, 2025 $ 12,326 $ 6,540 $ 5,516 $ 4,604 $ ( 39 ) $ 28,947
December 31, 2024 12,000 6,421 5,349 4,567 ( 40 ) 28,297
__________
(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.
Nine Months Ended September 30, 2025
Revenues from contracts with customers ComEd PECO BGE PHI Pepco DPL ACE
Electric revenues
Residential $ 3,452 $ 1,921 $ 1,829 $ 2,847 $ 1,273 $ 792 $ 782
Small commercial & industrial 1,799 484 311 548 155 200 193
Large commercial & industrial 689 260 456 1,144 911 92 141
Public authorities & electric railroads 43 26 25 56 29 13 14
Other (a)
688 231 352 688 274 224 196
Total electric revenues (b)
$ 6,671 $ 2,922 $ 2,973 $ 5,283 $ 2,642 $ 1,321 $ 1,326
Natural gas revenues
Residential $ — $ 396 $ 555 $ 86 $ — $ 86 $ —
Small commercial & industrial — 140 100 35 — 35 —
Large commercial & industrial — 1 178 6 — 6 —
Transportation — 28 — 13 — 13 —
Other (c)
— 13 37 8 — 8 —
Total natural gas revenues (d)
$ — $ 578 $ 870 $ 148 $ — $ 148 $ —
Total revenues from contracts with customers $ 6,671 $ 3,500 $ 3,843 $ 5,431 $ 2,642 $ 1,469 $ 1,326
Other revenues
Revenues from alternative revenue programs $ ( 525 ) $ ( 6 ) $ ( 63 ) $ ( 27 ) $ ( 19 ) $ ( 10 ) $ 2
Other electric revenues (e)
30 17 9 4 3 1 —
Other natural gas revenues (e)
— 2 2 — — — —
Total other revenues $ ( 495 ) $ 13 $ ( 52 ) $ ( 23 ) $ ( 16 ) $ ( 9 ) $ 2
Total revenues for reportable segments $ 6,176 $ 3,513 $ 3,791 $ 5,408 $ 2,626 $ 1,460 $ 1,328
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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
Nine Months Ended September 30, 2024
Revenues from contracts with customers ComEd PECO BGE PHI Pepco DPL ACE
Electric revenues
Residential $ 3,017 $ 1,683 $ 1,556 $ 2,537 $ 1,085 $ 725 $ 727
Small commercial & industrial 1,755 407 274 519 141 191 187
Large commercial & industrial 875 191 425 1,034 794 91 149
Public authorities & electric railroads 43 21 24 52 26 12 14
Other (a)
803 221 303 623 224 198 206
Total electric revenues (b)
$ 6,493 $ 2,523 $ 2,582 $ 4,765 $ 2,270 $ 1,217 $ 1,283
Natural gas revenues
Residential $ — $ 300 $ 418 $ 72 $ — $ 72 $ —
Small commercial & industrial — 106 76 29 — 29 —
Large commercial & industrial — — 143 4 — 4 —
Transportation — 20 — 12 — 12 —
Other (c)
— 11 12 5 — 5 —
Total natural gas revenues (d)
$ — $ 437 $ 649 $ 122 $ — $ 122 $ —
Total revenues from contracts with customers $ 6,493 $ 2,960 $ 3,231 $ 4,887 $ 2,270 $ 1,339 $ 1,283
Other revenues
Revenues from alternative revenue programs $ ( 100 ) $ 3 $ 28 $ 40 $ 42 $ 1 $ ( 3 )
Other electric revenues (e)
10 11 7 11 8 3 —
Other natural gas revenues (e)
— 1 2 — — — —
Total other revenues $ ( 90 ) $ 15 $ 37 $ 51 $ 50 $ 4 $ ( 3 )
Total revenues for reportable segments $ 6,403 $ 2,975 $ 3,268 $ 4,938 $ 2,320 $ 1,343 $ 1,280
__________
(a) Includes transmission revenue from PJM, wholesale electric revenue, and mutual assistance revenue.
(b) Includes operating revenues from affiliates in 2025 and 2024 respectively of:
• $ 19 million, $ 6 million at ComEd
• $ 7 million, $ 5 million at PECO
• $ 4 million, $ 4 million at BGE
• $ 7 million, $ 7 million at PHI
• $ 4 million, $ 5 million at Pepco
• $ 6 million, $ 5 million at DPL
• $ 3 million, $ 2 million at ACE
(c) Includes revenues from off-system natural gas sales.
(d) Includes operating revenues from affiliates in 2025 and 2024 respectively of:
• $ 2 million, $ 2 million at PECO
• $ 2 million, $ 3 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 September 30, 2025
Exelon ComEd PECO BGE PHI Pepco DPL ACE
Balance at June 30, 2025 $ 465 $ 122 $ 154 $ 66 $ 123 $ 69 $ 21 $ 33
Plus: Current period provision for expected credit losses (a)(b)
82 37 22 8 15 11 3 1
Less: Write-offs (c)(d) , net of recoveries (e)
96 44 31 6 15 8 4 3
Balance at September 30, 2025 $ 451 $ 115 $ 145 $ 68 $ 123 $ 72 $ 20 $ 31
Three Months Ended September 30, 2024
Exelon ComEd PECO BGE PHI Pepco DPL ACE
Balance at June 30, 2024 $ 372 $ 112 $ 112 $ 45 $ 103 $ 53 $ 16 $ 34
Plus: Current period provision for expected credit losses
84 16 28 20 20 12 4 4
Less: Write-offs, net of recoveries
30 7 5 5 13 7 3 3
Balance at September 30, 2024 $ 426 $ 121 $ 135 $ 60 $ 110 $ 58 $ 17 $ 35
Nine Months Ended September 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 (f)(g)(h)
224 66 68 34 56 35 13 8
Less: Write-offs (i) , net of recoveries (e)
179 60 56 22 41 22 10 9
Balance at September 30, 2025 $ 451 $ 115 $ 145 $ 68 $ 123 $ 72 $ 20 $ 31
Nine Months Ended September 30, 2024
Exelon ComEd PECO BGE PHI Pepco DPL ACE
Balance at December 31, 2023 $ 317 $ 69 $ 95 $ 46 $ 107 $ 52 $ 19 $ 36
Plus: Current period provision for expected credit losses
221 77 63 34 47 30 8 9
Less: Write-offs, net of recoveries
112 25 23 20 44 24 10 10
Balance at September 30, 2024 $ 426 $ 121 $ 135 $ 60 $ 110 $ 58 $ 17 $ 35
_________
(a) For ComEd, the increase is primarily a result of increased aging of receivables.
(b) For PECO, BGE, and ACE, the decrease is primarily a result of decreased receivable balances.
(c) For ComEd, the increase is primarily a result of timing of write-offs.
(d) For PECO, the increase is primarily a result of increased disconnection activities.
(e) Recoveries were not material to the Registrants.
(f) For ComEd, the decrease is primarily a result of increased disconnection activities.
(g) For PECO, Pepco, and DPL, the increase is primarily a result of increased receivable balances.
(h) For ACE, the decrease is primarily a result of decreased receivable balances.
(i) For ComEd and PECO, the increase is primarily a 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
The following tables present the rollforward of Allowance for Credit Losses on Other Accounts Receivable.
Three Months Ended September 30, 2025
Exelon ComEd PECO BGE PHI Pepco DPL ACE
Balance at June 30, 2025 $ 107 $ 31 $ 19 $ 5 $ 52 $ 28 $ 9 $ 15
Plus: Current period provision (benefit) for expected credit losses (a)(b)
7 5 2 1 ( 1 ) — — ( 1 )
Less: Write-offs (c) , net of recoveries (d)
16 11 4 1 — — — —
Balance at September 30, 2025 $ 98 $ 25 $ 17 $ 5 $ 51 $ 28 $ 9 $ 14
Three Months Ended September 30, 2024
Exelon ComEd PECO BGE PHI Pepco DPL ACE
Balance at June 30, 2024 $ 108 $ 29 $ 20 $ 5 $ 54 $ 34 $ 7 $ 13
Plus: Current period provision (benefit) for expected credit losses
7 10 1 3 ( 7 ) ( 8 ) — 1
Less: Write-offs, net of recoveries
4 — 1 2 1 — — 1
Balance at September 30, 2024 $ 111 $ 39 $ 20 $ 6 $ 46 $ 26 $ 7 $ 13
Nine Months Ended September 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 (e)(f)
15 4 9 ( 1 ) 3 1 — 2
Less: Write-offs (g)(h) , net of recoveries (d)
24 13 10 — 1 — — 1
Balance at September 30, 2025 $ 98 $ 25 $ 17 $ 5 $ 51 $ 28 $ 9 $ 14
Nine Months Ended September 30, 2024
Exelon ComEd PECO BGE PHI Pepco DPL ACE
Balance at December 31, 2023 $ 82 $ 17 $ 8 $ 7 $ 50 $ 28 $ 8 $ 14
Plus: Current period provision (benefit) for expected credit losses
43 25 15 4 ( 1 ) ( 2 ) ( 1 ) 2
Less: Write-offs, net of recoveries
14 3 3 5 3 — — 3
Balance at September 30, 2024 $ 111 $ 39 $ 20 $ 6 $ 46 $ 26 $ 7 $ 13
_________
(a) For Pepco, the increase is primarily due to changes in risk profile.
(b) For ACE, the decrease is primarily a result of decreased receivable balances.
(c) For ComEd, the increase is primarily a result of increased disconnection activities.
(d) Recoveries were not material to the Registrants.
(e) For ComEd, the decrease is primarily a result of decreased aging of receivables.
(f) For PECO and BGE, the decrease is primarily a result of decreased receivable balances.
(g) For ComEd and PECO, the increase is primarily a result of increased disconnection activities.
(h) For BGE and ACE, the decrease is primarily a result of increased collection 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
Unbilled Customer Revenue
The following table provides additional information about unbilled customer revenues recorded in the Registrants' Consolidated Balance Sheets as of September 30, 2025 and December 31, 2024.
Unbilled customer revenues (a)
Exelon ComEd PECO BGE PHI Pepco DPL ACE
September 30, 2025 $ 1,002 $ 401 $ 207 $ 178 $ 216 $ 111 $ 51 $ 54
December 31, 2024 1,114 335 254 257 268 121 76 71
__________
(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 nine months ended September 30, 2025 and 2024, 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
Nine months ended September 30, 2025 $ 3,320 $ 814 $ 954 $ 550 $ 1,002 $ 624 $ 201 $ 177
Nine months ended September 30, 2024 3,177 750 854 606 967 607 191 169
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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
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 September 30, 2025 (a)
Exelon ComEd (b)
PECO (c)
BGE PHI Pepco DPL ACE
U.S. Federal statutory rate 21.0 % 21.0 % 21.0 % 21.0 % 21.0 % 21.0 % 21.0 % 21.0 %
Increase (decrease) due to:
State income taxes, net of federal income tax benefit
5.7 7.4 ( 1.4 ) 6.3 6.5 6.4 6.5 7.1
Plant basis differences ( 5.1 ) ( 0.9 ) ( 16.0 ) ( 1.3 ) ( 0.6 ) ( 0.9 ) ( 0.4 ) ( 0.1 )
Excess deferred tax amortization ( 6.4 ) ( 8.9 ) ( 1.6 ) ( 4.1 ) ( 4.0 ) ( 5.4 ) ( 3.2 ) ( 1.7 )
Amortization of investment tax credit, including deferred taxes on basis difference — ( 0.1 ) — — — — ( 0.1 ) ( 0.1 )
Tax credits ( 0.3 ) ( 0.1 ) — ( 0.6 ) ( 0.4 ) ( 0.2 ) ( 0.5 ) ( 0.3 )
Other 0.1 ( 0.2 ) — 0.6 0.1 ( 0.1 ) 0.3 0.2
Effective income tax rate 15.0 % 18.2 % 2.0 % 21.9 % 22.6 % 20.8 % 23.6 % 26.1 %
Three Months Ended September 30, 2024 (a)
Exelon
ComEd (b)
PECO (c)
BGE (d)
PHI
Pepco DPL
ACE
U.S. Federal statutory rate 21.0 % 21.0 % 21.0 % 21.0 % 21.0 % 21.0 % 21.0 % 21.0 %
Increase (decrease) due to:
State income taxes, net of federal income tax benefit
5.7 7.6 ( 2.1 ) 6.5 6.5 6.2 6.3 7.4
Plant basis differences ( 4.8 ) ( 0.8 ) ( 19.5 ) ( 0.8 ) ( 0.8 ) ( 1.2 ) ( 0.8 ) —
Excess deferred tax amortization ( 14.0 ) ( 16.6 ) ( 2.6 ) ( 18.6 ) ( 5.5 ) ( 6.7 ) ( 5.9 ) ( 1.6 )
Amortization of investment tax credit, including deferred taxes on basis difference ( 0.1 ) ( 0.1 ) — ( 0.1 ) ( 0.1 ) — ( 0.1 ) ( 0.1 )
Tax credits ( 0.9 ) ( 2.6 ) — ( 0.6 ) ( 0.6 ) ( 0.5 ) ( 0.6 ) ( 0.5 )
Other
( 0.3 ) 0.6 ( 0.3 ) 0.8 0.1 ( 0.2 ) 0.4 0.3
Effective income tax rate 6.6 % 9.1 % ( 3.5 ) % 8.2 % 20.6 % 18.6 % 20.3 % 26.5 %
__________
(a) Positive percentages represent income tax expense. Negative percentages represent income tax benefit.
(b) For ComEd, the lower effective tax rate is primarily due to CEJA which resulted in the acceleration of certain income tax benefits.
(c) For PECO, the lower effective tax rate is primarily related to plant basis differences attributable to tax repair deductions.
(d) For BGE, the lower effective tax rate is primarily due to the Maryland multi-year plan which resulted in the acceleration of certain income tax benefits.
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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
Nine Months Ended September 30, 2025 (a)
Exelon ComEd (b)
PECO (c)
BGE PHI Pepco DPL ACE
U.S. Federal statutory rate 21.0 % 21.0 % 21.0 % 21.0 % 21.0 % 21.0 % 21.0 % 21.0 %
Increase (decrease) due to:
State income taxes, net of federal income tax benefit
5.6 7.5 ( 2.3 ) 6.2 6.6 6.4 6.4 7.1
Plant basis differences ( 4.6 ) ( 0.9 ) ( 14.0 ) ( 1.5 ) ( 0.6 ) ( 0.9 ) ( 0.5 ) ( 0.1 )
Excess deferred tax amortization ( 6.5 ) ( 9.0 ) ( 1.6 ) ( 4.1 ) ( 4.1 ) ( 5.4 ) ( 3.5 ) ( 1.6 )
Amortization of investment tax credit, including deferred taxes on basis difference — ( 0.1 ) — — — — ( 0.1 ) ( 0.1 )
Tax credits ( 0.4 ) ( 0.4 ) — ( 0.4 ) ( 0.4 ) ( 0.3 ) ( 0.3 ) ( 0.3 )
Other 0.3 0.1 0.3 0.1 0.2 0.1 0.1 ( 0.2 )
Effective income tax rate 15.4 % 18.2 % 3.4 % 21.3 % 22.7 % 20.9 % 23.1 % 25.8 %
Nine Months Ended September 30, 2024 (a)
Exelon ComEd (b)
PECO (c)
BGE (d)
PHI Pepco DPL ACE
U.S. Federal statutory rate 21.0 % 21.0 % 21.0 % 21.0 % 21.0 % 21.0 % 21.0 % 21.0 %
Increase (decrease) due to:
State income taxes, net of federal income tax benefit
5.8 7.7 ( 1.2 ) 6.3 6.5 6.2 6.2 7.4
Plant basis differences ( 4.2 ) ( 0.8 ) ( 14.7 ) ( 1.2 ) ( 0.9 ) ( 1.3 ) ( 0.9 ) 0.1
Excess deferred tax amortization ( 14.1 ) ( 17.4 ) ( 2.4 ) ( 17.6 ) ( 5.4 ) ( 6.8 ) ( 5.8 ) ( 1.6 )
Amortization of investment tax credit, including deferred taxes on basis difference ( 0.1 ) ( 0.1 ) — — ( 0.1 ) — ( 0.1 ) ( 0.1 )
Tax credits ( 0.6 ) ( 1.4 ) — ( 0.4 ) ( 0.5 ) ( 0.4 ) ( 0.4 ) ( 0.4 )
Other 0.2 0.4 ( 0.2 ) 0.2 0.2 ( 0.1 ) — 0.1
Effective income tax rate 8.0 % 9.4 % 2.5 % 8.3 % 20.8 % 18.6 % 20.0 % 26.5 %
__________
(a) Positive percentages represent income tax expense. Negative percentages represent income tax benefit.
(b) For ComEd, the lower effective tax rate is primarily due to CEJA which resulted in the acceleration of certain income tax benefits.
(c) For PECO, the lower effective tax rate is primarily related to plant basis differences attributable to tax repair deductions.
(d) For BGE, the lower effective tax rate is primarily due to the Maryland multi-year plan which resulted in the acceleration of certain income tax benefits.
Unrecognized Tax Benefits
Exelon, PHI and DPL have the following unrecognized tax benefits at September 30, 2025 and December 31, 2024. ComEd's, PECO's, BGE's, Pepco's, and ACE's amounts are not material.
Exelon (a)
PHI DPL
September 30, 2025 $ 97 $ 47 $ 11
December 31, 2024 96 48 12
__________
(a) At September 30, 2025 and December 31, 2024, Exelon's unrecognized tax benefits is inclusive of $ 31 million related to Constellation's share of unrecognized tax benefits for periods prior to the separation. Exelon reflected an offsetting receivable of $ 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
Reasonably possible the total amount of unrecognized tax benefits could significantly increase or decrease within 12 months after the reporting date
At September 30, 2025, Exelon, PHI, and DPL have approximately $ 64 million, $ 6 million, and $ 1 million, respectively, of unrecognized federal tax benefits that could significantly change within the 12 months after the reporting date based on the outcome of pending refund claims that impacts the effective tax rate.
Other Tax Matters
One Big Beautiful Bill Act (All Registrants)
On July 4, 2025, the OBBBA was signed into law. The bill permanently extends expiring tax benefits of the TCJA and provides additional tax relief for individuals and businesses while accelerating the phase-out and curtailment for renewable energy tax credits enacted by the IRA. The tax law changes enacted as part of OBBBA will not have a direct material impact on the Registrants’ financial statements.
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 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.
Beginning in 2023, based on the existing statute, Exelon and each of the Utility Registrants will be subject to and will report the CAMT on a separate Registrant basis in the Consolidated Statements of Operations and Comprehensive Income and the Consolidated Balance Sheets. The deferred tax asset related to the minimum tax credit carryforward will be realized to the extent Exelon’s consolidated deferred tax liabilities exceed the minimum tax credit carryforward. Exelon’s deferred tax liabilities are expected to exceed the minimum tax credit carryforward for the foreseeable future and thus no valuation allowance is required.
On September 12, 2024, the U.S. Treasury issued proposed regulations providing further guidance addressing the implementation of CAMT. The proposed regulations are consistent with Exelon’s prior interpretation and therefore there are no financial statement impacts.
On September 30, 2025, the U.S. Treasury issued interim guidance addressing the implementation of CAMT in the form of a notice. The guidance allows entities with regulated operations a repairs adjustment for CAMT purposes, however the provision was drafted in a manner that does not achieve that intended result. Thus, the guidance does not benefit Exelon and has no financial statement impact. Exelon will continue to monitor and assess the potential financial statement impacts of future regulations or other guidance when issued.
Allocation of Tax Benefits (All Registrants)
The Utility Registrants are party to an agreement with Exelon that provides for the allocation of consolidated tax liabilities and benefits (Tax Sharing Agreement). The Tax Sharing Agreement provides that each party is allocated an amount of tax similar to that which would be owed had the party been separately subject to tax. In addition, any net benefit attributable to Exelon is reallocated to the Utility Registrants. That allocation is treated as a contribution to capital from Exelon to the party receiving the benefit.
The following table presents the allocation of tax benefits from Exelon under the Tax Sharing Agreement, for the three and nine months ended September 30, 2025, and 2024.
ComEd PECO BGE PHI Pepco DPL ACE
September 30, 2025 $ 20 $ 14 $ 12 $ 23 $ 12 $ 7 $ 4
September 30, 2024 30 15 14 16 9 5 2
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.
Tax Matters Agreement (Exelon)
In connection with the separation, Exelon entered into a TMA with Constellation. 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 September 30, 2025, 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 September 30, 2025, there is no balance due to or from Constellation.
Tax Attributes . At the date of separation certain tax attributes, primarily pre-closing tax credit carryforwards, that were generated by Constellation were required by law to be allocated to Exelon. The TMA also provides that Exelon will reimburse Constellation when those allocated tax attribute carryforwards are utilized. In 2025, Exelon remitted $ 127 million of payments to Constellation for the utilization of pre-closing tax credit carryforwards. At September 30, 2025, Exelon recorded a payable of $ 175 million and $ 38 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.
7. Retirement Benefits (All Registrants)
Defined Benefit Pension and OPEB
The majority of the 2025 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 5.68 %. The majority of the 2025 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 5.64 %.
During the first quarter of 2025, Exelon received an updated valuation of its pension and OPEB to reflect actual census data as of January 1, 2025. This valuation resulted in an increase to the pension obligation of $ 1 million and an increase to the OPEB obligation and asset of $ 6 million and $ 2 million, respectively. Additionally, AOCI decreased by $ 5 million (after-tax) and regulatory assets increased by $ 8 million and liabilities decreased by $ 3 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 nine months ended September 30, 2025 and 2024.
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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 September 30, Three Months Ended September 30,
2025 2024 2025 2024
Components of net periodic benefit cost
Service cost $ 38 $ 43 $ 7 $ 6
Interest cost 146 141 26 24
Expected return on assets ( 179 ) ( 184 ) ( 21 ) ( 21 )
Amortization of:
Prior service cost (credit) 1 1 ( 2 ) ( 2 )
Actuarial loss (gain) 53 53 ( 1 ) —
Net periodic benefit cost $ 59 $ 54 $ 9 $ 7
Pension Benefits OPEB
Nine Months Ended September 30, Nine Months Ended September 30,
2025 2024 2025 2024
Components of net periodic benefit cost
Service cost $ 115 $ 125 $ 19 $ 20
Interest cost 439 423 76 72
Expected return on assets ( 535 ) ( 552 ) ( 63 ) ( 63 )
Amortization of:
Prior service cost (credit) 2 2 ( 6 ) ( 6 )
Actuarial loss (gain) 159 160 ( 2 ) —
Net periodic benefit cost $ 180 $ 158 $ 24 $ 23
The amounts below represent the Registrants' allocated pension and OPEB costs (benefits). 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 September 30, Nine Months Ended September 30,
Pension and OPEB Costs (Benefits) 2025 2024 2025 2024
Exelon $ 68 $ 61 $ 204 $ 181
ComEd 22 17 64 53
PECO 2 ( 1 ) 5 ( 1 )
BGE 16 14 46 45
PHI 23 25 72 71
Pepco 8 8 26 24
DPL 4 4 12 11
ACE 3 3 10 10
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 nine months ended September 30, 2025 and 2024.
Three Months Ended September 30, Nine Months Ended September 30,
Savings Plan Employer Contributions 2025 2024 2025 2024
Exelon $ 30 $ 25 $ 86 $ 76
ComEd 12 12 34 32
PECO 4 3 12 11
BGE 3 2 9 8
PHI 5 4 15 12
Pepco 1 1 4 3
DPL 1 1 3 3
ACE 1 1 2 2
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
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 3 — Regulatory Matters of the 2024 Form 10-K for additional information.
(b) The fair value of the DPL economic hedge is not material at September 30, 2025 and December 31, 2024.
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 September 30, 2025 would result in an immaterial impact to Exelon's Consolidated Net income.
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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
Below is a summary of the interest rate hedge balances at September 30, 2025 and December 31, 2024 .
Derivatives Designated
as Hedging Instruments
September 30, 2025 December 31, 2024
Other current assets $ — $ 14
Other deferred debits (noncurrent assets) 2 12
Total derivative assets 2 26
Mark-to-market derivative liabilities (current liabilities) — ( 1 )
Mark-to-market derivative liabilities (noncurrent liabilities) ( 8 ) —
Total mark-to-market derivative liabilities ( 8 ) ( 1 )
Total mark-to-market derivative net assets (liabilities) $ ( 6 ) $ 25
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.
In February 2025, Exelon terminated the previously issued floating-to-fixed swaps with a total notional of $ 765 million upon issuance of $ 1 billion of debt. See Note 9 – Debt and Credit Agreements for additional information on the debt issuance. The settlements resulted in a cash receipt of $ 16 million. The accumulated AOCI gain of $ 13 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 third quarter of 2025, Exelon Corporate entered into $ 30 million notional of 5-year maturity floating-to-fixed swaps and $ 30 million notional of 10-year maturity floating-to-fixed swaps, for a total notional of $ 60 million designated as cash flow hedges. The following table provides the notional amounts outstanding held by Exelon at September 30, 2025 and December 31, 2024.
September 30, 2025 December 31, 2024
5-year maturity floating-to-fixed swaps $ 335 $ 657
10-year maturity floating-to-fixed swaps 335 658
Total $ 670 $ 1,315
The related AOCI derivative loss for the three and nine months ended September 30, 2025 was $ 1 million and $ 14 million (net of tax), respectively. The related AOCI derivative loss for the three and nine months ended September 30, 2024 was $ 29 million and $ 30 million (net of tax), respectively. See Note 13 – Changes in Accumulated Other Comprehensive Income (Loss) for additional information.
Credit Risk
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 September 30, 2025. 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, as of September 30, 2025 and December 31, 2024:
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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
September 30, 2025 December 31, 2024
Exelon $ 196 $ 181
ComEd 184 176
PECO (a)
6 —
BGE 2 1
PHI 5 4
Pepco 3 1
DPL 2 2
ACE (b)
— —
__________
(a) PECO had less than one million in cash collateral held from external parties at December 31, 2024.
(b) ACE had less than one million in cash collateral with external parties at September 30, 2025 and December 31, 2024.
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. As of September 30, 2025, 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 September 30, 2025, they could have been required to post collateral to their counterparties of $ 40 million, $ 23 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 requirements primarily through the issuance of commercial paper. PECO meets its short-term liquidity requirements primarily through the issuance of commercial paper and borrowings from the Exelon intercompany money pool. Pepco, DPL, and ACE meet their short-term liquidity requirements primarily through the issuance of commercial paper and borrowings from the PHI intercompany money pool. PHI Corporate meets its short-term liquidity requirements primarily through the issuance of short-term notes and borrowings from the Exelon intercompany money pool. The Registrants may use their respective credit facilities for general corporate purposes, including meeting short-term funding requirements and the issuance of letters of credit.
Commercial Paper
The following table reflects the Registrants' commercial paper programs supported by the revolving credit agreements at September 30, 2025 and December 31, 2024.
Outstanding Commercial
Paper at Average Interest Rate on
Commercial Paper Borrowings at
Commercial Paper Issuer September 30, 2025 December 31, 2024 September 30, 2025 December 31, 2024
Exelon (a)
$ 580 $ 1,359 4.29 % 4.66 %
ComEd $ — $ 36 — % 4.55 %
PECO $ — $ 192 — % 4.65 %
BGE $ — $ 175 — % 4.61 %
PHI (b)
$ 166 $ 530 4.30 % 4.70 %
Pepco $ 63 $ 200 4.30 % 4.69 %
DPL $ 33 $ 144 4.27 % 4.74 %
ACE $ 70 $ 186 4.30 % 4.67 %
__________
(a) Exelon Corporate had $ 414 million outstanding commercial paper borrowings at September 30, 2025 and $ 426 million in outstanding commercial paper borrowings at December 31, 2024.
(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 0.900 %
Pepco $ 300 SOFR plus 1.000 %
DPL $ 300 SOFR plus 1.000 %
ACE $ 300 SOFR plus 1.000 %
Exelon Corporate and the Utility Registrants had no outstanding amounts on the revolving credit facilities as of September 30, 2025.
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 16 — Debt and Credit Agreements of the 2024 Form 10-K for additional information on the Registrants' credit facilities.
Short-Term Loan Agreements
On March 14, 2024, Exelon Corporate amended and bifurcated the $ 500 million term loan agreement into two tranches of $ 350 million and $ 150 million. The loan agreements were renewed in the first quarter of 2025, extending the expiration date to March 13, 2026. Pursuant to the loan agreements, loans made thereunder bear interest at a variable rate equal to SOFR plus 1.00 % and all indebtedness thereunder is unsecured. The loan agreements are reflected in Exelon's Consolidated Balance Sheets 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 nine months ended September 30, 2025, the following long-term debt was issued:
Company Type Interest Rate Maturity Amount Use of Proceeds
Exelon Junior Subordinated Notes (a)
6.50 % March 15, 2055 $ 1,000 Repay outstanding commercial paper obligations, and for general corporate purposes.
Exelon Notes 5.125 % March 15, 2031 $ 500 Repay outstanding commercial paper obligations, and for general corporate purposes.
Exelon Notes 5.875 % March 15, 2055 $ 500 Repay outstanding commercial paper obligations, and for general corporate purposes.
ComEd First Mortgage Bonds 5.95 % June 1, 2055 $ 725 Repay outstanding commercial paper obligations, and for general corporate purposes.
PECO First Mortgage Bonds 4.875 % September 15, 2035 $ 525 Repay existing indebtedness, repay outstanding commercial paper obligations, and for general corporate purposes.
PECO First Mortgage Bonds 5.65 % September 15, 2055 $ 525 Repay existing indebtedness, repay outstanding commercial paper obligations, and for general corporate purposes.
BGE Notes 5.45 % June 1, 2035 $ 650 Repay outstanding commercial paper obligations, and for general corporate purposes.
Pepco First Mortgage Bonds 5.78 % September 17, 2055 $ 75 Repay existing indebtedness and for general corporate purposes.
Pepco First Mortgage Bonds 5.48 % March 26, 2040 $ 200 Repay existing indebtedness and for general corporate purposes.
DPL First Mortgage Bonds 5.28 % March 26, 2035 $ 125 Repay existing indebtedness and for general corporate purposes.
ACE (b)
First Mortgage Bonds 5.28 % March 26, 2035 $ 100 Repay existing indebtedness and for general corporate purposes.
__________
(a) The Junior Subordinated Notes bear interest at 6.50 % per annum, commencing February 19, 2025 to, but excluding March 15, 2035. Thereafter, the interest rate resets every five years on March 15 and will be set at a rate per annum equal to the Five-year U.S. Treasury Rate plus a spread of 1.975 %.
(b) On March 26, 2025, ACE entered into a purchase agreement of First Mortgage Bonds of $ 75 million and $ 75 million at 5.54 % and 5.81 % due on November 19, 2040 and November 19, 2055, respectively. The closing date of the issuance is expected to occur in November 2025.
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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
Reoffering of Tax-Exempt Bonds
On July 1, 2025, DPL completed the reoffering of $ 78.4 million aggregate principal amount of its Delaware Economic Development Authority’s Gas Facilities Refunding Revenue Bonds (Delmarva Power & Light Company Project) 2020 Series A (Non-AMT) (the "Bonds"). In connection with the reoffering of the Bonds, the interest rate was modified to 3.60 % per annum, and the maturity date was modified to January 1, 2031. DPL did not directly receive any proceeds from the reoffering.
Debt Covenants
As of September 30, 2025, 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 17 — Fair Value of Financial Assets and Liabilities of the 2024 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 September 30, 2025 and December 31, 2024. 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.
September 30, 2025 December 31, 2024
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 $ 48,451 $ — $ 40,212 $ 4,358 $ 44,570 $ 44,400 $ — $ 35,337 $ 3,720 $ 39,057
ComEd 12,751 — 11,371 — 11,371 12,030 — 10,260 — 10,260
PECO 6,746 — 6,019 — 6,019 5,704 — 4,816 — 4,816
BGE 6,041 — 5,549 — 5,549 5,395 — 4,702 — 4,702
PHI 9,599 — 4,240 4,358 8,598 9,124 — 4,093 3,720 7,813
Pepco 4,632 — 2,551 1,877 4,428 4,362 — 2,475 1,544 4,019
DPL 2,344 — 662 1,423 2,085 2,220 — 623 1,250 1,873
ACE 2,035 — 811 1,059 1,870 1,933 — 787 925 1,712
Long-Term Debt to Financing Trusts
Exelon $ 390 $ — $ — $ 403 $ 403 $ 390 $ — $ — $ 396 $ 396
ComEd 206 — — 215 215 206 — — 208 208
PECO 184 — — 188 188 184 — — 188 188
__________
(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 16 — Debt and Credit Agreements of the 2024 Form 10-K for unamortized debt issuance costs, unamortized debt discount and premium, net, and purchase accounting fair value adjustments and Note 10 — Leases of the 2024 Form 10-K for finance lease liabilities.
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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 September 30, 2025 and December 31, 2024. Exelon and the Utility Registrants have immaterial and no financial assets or liabilities measured using the NAV practical expedient, respectively:
Exelon
At September 30, 2025 At December 31, 2024
Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total
Assets
Cash equivalents (a)
$ 1,741 $ — $ — $ 1,741 $ 544 $ — $ — $ 544
Rabbi trust investments
Cash equivalents 99 — — 99 94 — — 94
Mutual funds 68 — — 68 65 — — 65
Fixed income — 6 — 6 — 6 — 6
Life insurance contracts — 76 23 99 — 73 22 95
Rabbi trust investments subtotal 167 82 23 272 159 79 22 260
Interest rate derivative assets
Derivatives designated as hedging instruments — 2 — 2 — 26 — 26
Interest rate derivative assets subtotal — 2 — 2 — 26 — 26
Total assets 1,908 84 23 2,015 703 105 22 830
Liabilities
Commodity derivative liabilities — — ( 128 ) ( 128 ) — — ( 132 ) ( 132 )
Interest rate derivative liabilities
Derivatives designated as hedging instruments — ( 8 ) — ( 8 ) — ( 1 ) — ( 1 )
Interest rate derivative liabilities subtotal — ( 8 ) — ( 8 ) — ( 1 ) — ( 1 )
Deferred compensation obligation — ( 69 ) — ( 69 ) — ( 74 ) — ( 74 )
Total liabilities — ( 77 ) ( 128 ) ( 205 ) — ( 75 ) ( 132 ) ( 207 )
Total net assets (liabilities) $ 1,908 $ 7 $ ( 105 ) $ 1,810 $ 703 $ 30 $ ( 110 ) $ 623
__________
(a) Exelon excludes cash of $ 170 million and $ 219 million at September 30, 2025 and December 31, 2024, respectively, and restricted cash of $ 187 million and $ 176 million at September 30, 2025 and December 31, 2024, respectively, and includes long-term restricted cash of $ 49 million and $ 41 million at September 30, 2025 and December 31, 2024, 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 September 30, 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)
$ 653 $ — $ — $ 653 $ 340 $ — $ — $ 340 $ 659 $ — $ — $ 659
Rabbi trust investments
Mutual funds — — — — 12 — — 12 10 — — 10
Life insurance contracts — — — — — 23 — 23 — — — —
Rabbi trust investments subtotal — — — — 12 23 — 35 10 — — 10
Total assets 653 — — 653 352 23 — 375 669 — — 669
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) $ 653 $ ( 9 ) $ ( 128 ) $ 516 $ 352 $ 16 $ — $ 368 $ 669 $ ( 4 ) $ — $ 665
ComEd PECO BGE
At December 31, 2024 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)
$ 390 $ — $ — $ 390 $ 29 $ — $ — $ 29 $ 1 $ — $ — $ 1
Rabbi trust investments
Mutual funds — — — — 12 — — 12 10 — — 10
Life insurance contracts — — — — — 22 — 22 — — — —
Rabbi trust investments subtotal — — — — 12 22 — 34 10 — — 10
Total assets 390 — — 390 41 22 — 63 11 — — 11
Liabilities
Commodity derivative liabilities (b)
— — ( 132 ) ( 132 ) — — — — — — — —
Deferred compensation obligation — ( 8 ) — ( 8 ) — ( 7 ) — ( 7 ) — ( 4 ) — ( 4 )
Total liabilities — ( 8 ) ( 132 ) ( 140 ) — ( 7 ) — ( 7 ) — ( 4 ) — ( 4 )
Total net assets (liabilities) $ 390 $ ( 8 ) $ ( 132 ) $ 250 $ 41 $ 15 $ — $ 56 $ 11 $ ( 4 ) $ — $ 7
__________
(a) ComEd excludes cash of $ 70 million and $ 66 million at September 30, 2025 and December 31, 2024, respectively, and restricted cash of $ 184 million and $ 176 million at September 30, 2025 and December 31, 2024, respectively. Additionally, ComEd includes long-term restricted cash of $ 49 million and $ 41 million at September 30, 2025 and December 31, 2024, respectively, which is reported in Other deferred debits and other assets in the Consolidated Balance Sheets. PECO
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Combined Notes to Consolidated Financial Statements — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Note 10 — Fair Value of Financial Assets and Liabilities
excludes cash of $ 24 million and $ 19 million at September 30, 2025 and December 31, 2024, respectively. BGE excludes cash of $ 6 million and $ 33 million at September 30, 2025 and December 31, 2024, respectively.
(b) The Level 3 balance consists of the current and noncurrent liability of $ 28 million and $ 100 million, respectively, at September 30, 2025 and $ 29 million and $ 103 million, respectively, at December 31, 2024 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 September 30, 2025 At December 31, 2024
PHI Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total
Assets
Cash equivalents (a)
$ 56 $ — $ — $ 56 $ 93 $ — $ — $ 93
Rabbi trust investments
Cash equivalents 97 — — 97 92 — — 92
Mutual funds 9 — — 9 9 — — 9
Fixed income — 6 — 6 — 6 — 6
Life insurance contracts — 22 21 43 — 23 21 44
Rabbi trust investments subtotal 106 28 21 155 101 29 21 151
Total assets 162 28 21 211 194 29 21 244
Liabilities
Deferred compensation obligation — ( 10 ) — ( 10 ) — ( 12 ) — ( 12 )
Total liabilities — ( 10 ) — ( 10 ) — ( 12 ) — ( 12 )
Total net assets $ 162 $ 18 $ 21 $ 201 $ 194 $ 17 $ 21 $ 232
Pepco DPL ACE
At September 30, 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)
$ 22 $ — $ — $ 22 $ 2 $ — $ — $ 2 $ — $ — $ — $ —
Rabbi trust investments
Cash equivalents 97 — — 97 — — — — — — — —
Life insurance contracts — 22 21 43 — — — — — — — —
Rabbi trust investments subtotal 97 22 21 140 — — — — — — — —
Total assets 119 22 21 162 2 — — 2 — — — —
Liabilities
Deferred compensation obligation — ( 1 ) — ( 1 ) — — — — — — — —
Total liabilities — ( 1 ) — ( 1 ) — — — — — — — —
Total net assets $ 119 $ 21 $ 21 $ 161 $ 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, 2024 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)
$ 21 $ — $ — $ 21 $ 3 $ — $ — $ 3 $ — $ — $ — $ —
Rabbi trust investments
Cash equivalents 91 — — 91 — — — — — — — —
Life insurance contracts — 23 21 44 — — — — — — — —
Rabbi trust investments subtotal 91 23 21 135 — — — — — — — —
Total assets 112 23 21 156 3 — — 3 — — — —
Liabilities
Deferred compensation obligation — ( 1 ) — ( 1 ) — — — — — — — —
Total liabilities — ( 1 ) — ( 1 ) — — — — — — — —
Total net assets $ 112 $ 22 $ 21 $ 155 $ 3 $ — $ — $ 3 $ — $ — $ — $ —
__________
(a) PHI excludes cash of $ 61 million and $ 70 million at September 30, 2025 and December 31, 2024, respectively, and restricted cash of $ 3 million and zero at September 30, 2025 and December 31, 2024. Pepco excludes cash of $ 25 million and $ 30 million at September 30, 2025 and December 31, 2024, respectively. DPL excludes cash of $ 6 million and $ 20 million at September 30, 2025 and December 31, 2024, respectively. ACE excludes cash of $ 25 million and $ 14 million at September 30, 2025 and December 31, 2024, respectively and restricted cash of $ 3 million and zero at September 30, 2025 and December 31, 2024, 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 nine months ended September 30, 2025 and 2024:
Exelon ComEd PHI and Pepco
Three Months Ended September 30, 2025 Total Commodity
Derivatives Life Insurance Contracts
Balance at June 30, 2025 $ ( 112 ) $ ( 135 ) $ 22
Total realized / unrealized gains (losses)
Included in net income (a)
1 — —
Included in regulatory assets/liabilities 7 7 (b)
—
Settlements ( 1 ) — ( 1 )
Balance at September 30, 2025 $ ( 105 ) $ ( 128 ) (c)
$ 21
The amount of total gains included in income attributed to the change in unrealized gains related to assets and liabilities at September 30, 2025 $ ( 1 ) $ — $ —
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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 September 30, 2024 Total Commodity
Derivatives Life Insurance Contracts
Balance at June 30, 2024 $ ( 116 ) $ ( 139 ) $ 22
Total realized / unrealized gains (losses)
Included in net income (a)
— — —
Included in regulatory assets/liabilities ( 26 ) ( 26 ) (b)
—
Settlements ( 1 ) — ( 1 )
Balance at September 30, 2024 $ ( 143 ) $ ( 165 ) $ 21
The amount of total gains included in income attributed to the change in unrealized gains related to assets and liabilities at September 30, 2024 $ — $ — $ —
Exelon ComEd PHI and Pepco
Nine Months Ended September 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)
2 — 1
Included in regulatory assets/liabilities 4 4 (b)
—
Settlements ( 1 ) — ( 1 )
Balance at September 30, 2025 $ ( 105 ) $ ( 128 ) (c)
$ 21
The amount of total gains included in income attributed to the change in unrealized gains related to assets and liabilities at September 30, 2025 $ 1 $ — $ 1
Exelon ComEd PHI and Pepco
Nine Months Ended September 30, 2024 Total Commodity
Derivatives Life Insurance Contracts
Balance at December 31, 2023 $ ( 90 ) $ ( 133 ) $ 41
Total realized / unrealized gains (losses)
Included in net income (a)
1 — 2
Included in regulatory assets/liabilities ( 32 ) ( 32 ) (b)
—
Settlements ( 22 ) — ( 22 )
Balance at September 30, 2024 $ ( 143 ) $ ( 165 ) $ 21
The amount of total gains included in income attributed to the change in unrealized gains related to assets and liabilities at September 30, 2024 $ 2 $ — $ 2
__________
(a) Classified in Operating and maintenance expense in the Consolidated Statements of Operations and Comprehensive Income.
(b) Includes $ 1 million of increases in fair value and an increase for realized gains due to settlements of $ 6 million recorded in Purchased power expense associated with floating-to-fixed energy swap contracts with unaffiliated suppliers for the three months ended September 30, 2025. Includes $ 31 million of decreases in fair value and an increase for realized gains due to settlements of $ 5 million recorded in Purchased power expense associated with floating-to-fixed energy swap contracts with unaffiliated suppliers for the three months ended September 30, 2024. Includes $ 29 million of decreases in fair value and an increase for realized gains due to settlements of $ 33 million recorded in Purchased power expense associated with floating-to-fixed energy swap contracts with unaffiliated suppliers for the nine months ended September 30, 2025. Includes $ 60 million of decreases in fair value and an increase for realized gains due to settlements of $ 28 million recorded in Purchased power expense associated with floating-to-fixed energy swap contracts with unaffiliated suppliers for the nine months ended September 30, 2024.
(c) The balance of the current and noncurrent asset was effectively zero as of September 30, 2025. The balance consists of a current and noncurrent liability of $ 28 million and $ 100 million, respectively, as of September 30, 2025.
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Combined Notes to Consolidated Financial Statements — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Note 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 September 30, 2025 Fair Value at December 31, 2024 Valuation
Technique Unobservable
Input 2025 Range & Arithmetic Average 2024 Range & Arithmetic Average
Commodity derivatives $ ( 128 ) $ ( 132 ) Discounted
Cash Flow Forward power price (a)
$ 29.88 - $ 59.41 $ 41.89 $ 30.31 - $ 59.88 $ 42.08
________
(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 18 — Commitments and Contingencies of the 2024 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 September 30, 2025:
Description Exelon PHI Pepco DPL ACE
Total commitments $ 513 $ 320 $ 120 $ 89 $ 111
Remaining commitments (a)
23 21 20 1 —
__________
(a) Remaining commitments extend through 2026 and include escrow funds, charitable contributions, 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 September 30, 2025, representing commitments potentially triggered by future events were as follows:
Expiration within
Total 2025 2026 2027 2028 2029 2030 and beyond
Exelon
Letters of credit (a)
$ 56 $ 11 $ 45 $ — $ — $ — $ —
Surety bonds (b)
273 83 110 2 78 — —
Financing trust guarantees (c)
378 — — — 78 — 300
Guaranteed lease residual values (d)
24 — 2 4 5 4 9
Total commercial commitments $ 731 $ 94 $ 157 $ 6 $ 161 $ 4 $ 309
ComEd
Letters of credit (a)
$ 18 $ 4 $ 14 $ — $ — $ — $ —
Surety bonds (b)
37 5 30 2 — — —
Financing trust guarantees (c)
200 — — — — — 200
Total commercial commitments $ 255 $ 9 $ 44 $ 2 $ — $ — $ 200
PECO
Letters of credit (a)
$ 5 $ — $ 5 $ — $ — $ — $ —
Surety bonds (b)
2 — 2 — — — —
Financing trust guarantees (c)
178 — — — 78 — 100
Total commercial commitments $ 185 $ — $ 7 $ — $ 78 $ — $ 100
BGE
Letters of credit (a)
$ 27 $ 6 $ 21 $ — $ — $ — $ —
Surety bonds (b)
3 1 2 — — — —
Total commercial commitments $ 30 $ 7 $ 23 $ — $ — $ — $ —
PHI
Letters of credit (a)
$ 4 $ — $ 4 $ — $ — $ — $ —
Surety bonds (b)
172 73 21 — 78 — —
Guaranteed lease residual values (d)
24 — 2 4 5 4 9
Total commercial commitments $ 200 $ 73 $ 27 $ 4 $ 83 $ 4 $ 9
Pepco
Letters of credit (a)
$ 2 $ — $ 2 $ — $ — $ — $ —
Surety bonds (b)
160 68 14 — 78 — —
Guaranteed lease residual values (d)
8 — 1 1 2 1 3
Total commercial commitments $ 170 $ 68 $ 17 $ 1 $ 80 $ 1 $ 3
DPL
Letters of credit (a)
$ 1 $ — $ 1 $ — $ — $ — $ —
Surety bonds (b)
7 3 4 — — — —
Guaranteed lease residual values (d)
9 — — 2 2 2 3
Total commercial commitments $ 17 $ 3 $ 5 $ 2 $ 2 $ 2 $ 3
ACE
Letters of credit (a)
$ 1 $ — $ 1 $ — $ — $ — $ —
Surety bonds (b)
5 2 3 — — — —
Guaranteed lease residual values (d)
7 — 1 1 1 1 3
Total commercial commitments $ 13 $ 2 $ 5 $ 1 $ 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 $ 17 million, $ 21 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 6 sites currently under some degree of active study and/or remediation. PECO expects the majority of the remediation at these sites to continue through at least 2030.
• BGE has 4 sites currently requiring some level of remediation and/or ongoing activity. BGE expects the majority of the remediation at these sites to continue through at least 2026.
• DPL has 1 site currently under study and the required cost at the site is not expected to be material.
The historical nature of the MGP and gas purification sites, and the fact that many of the sites have been buried and built over, impacts the ability to determine a precise estimate of the ultimate costs prior to initial sampling and determination of the exact scope and method of remedial activity. Management determines its best estimate of remediation costs using all available information at the time of each study, including probabilistic and deterministic modeling for ComEd and PECO, and the remediation standards currently required by the applicable state environmental agency. Prior to performing any significant clean up, each site remediation plan is approved by the appropriate state environmental agency.
ComEd, pursuant to an ICC order, and PECO, pursuant to a PAPUC order, are currently recovering environmental remediation costs of former MGP facility sites through customer rates. While BGE and DPL do not have riders for MGP clean-up costs, they have historically received recovery of actual clean-up costs in distribution rates.
During the third quarter of 2025, ComEd and PECO completed an annual study of their future estimated MGP remediation requirements. ComEd's study resulted in a $ 12 million increase to the environmental liability and related Regulatory asset, primarily due to increased costs resulting from inflation, adjustments to unit costs, and
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(Dollars in millions, except per share data, unless otherwise noted)
Note 11 — Commitments and Contingencies
changes in remediation plans. PECO's study resulted in a $ 2 million decrease to the environmental liability and related Regulatory asset, primarily due to decreased costs resulting from changes in remediation plans.
At September 30, 2025 and December 31, 2024, 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:
September 30, 2025 December 31, 2024
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 $ 387 $ 324 $ 403 $ 322
ComEd 290 290 285 284
PECO 25 24 29 28
BGE 13 10 13 10
PHI 57 — 75 —
Pepco 55 — 73 —
DPL 1 — 1 —
ACE 1 — 1 —
Benning Road Site (Exelon, PHI, and Pepco) . In September 2010, PHI received a letter from the EPA identifying the Benning Road site as one of six land-based sites potentially contributing to contamination of the lower Anacostia River. A portion of the site, which is owned by Pepco, was formerly the location of an electric generating facility owned by Pepco subsidiary, Pepco Energy Services (PES), which became a part of Generation 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 area closed on April 18, 2025 and the public comment period for the waterside area is scheduled to close on October 31, 2025. Pepco submitted a matrix of proposed responses to the public comments and a proposed Record of Decision (ROD) to the DOEE for the landside area on August 15, 2025. Following the close of the waterside area comment period, Pepco will submit a matrix of proposed responses to the public comments and a proposed ROD to the DOEE for the waterside area. The DOEE will issue RODs identifying the remedial actions determined to be necessary for the landside and waterside areas, which will be implemented by Pepco in accordance with the Benning Consent Decree.
As part of the separation between Exelon and Constellation in February 2022, the internal agreement between the Pepco Entities for completion and payment for the remaining Consent Decree work was memorialized in a formal agreement for post-separation activities. A second post-separation assumption agreement between Exelon and Constellation transferred any of the potential remaining remediation liability, if any, of PES/Generation
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(Dollars in millions, except per share data, unless otherwise noted)
Note 11 — Commitments and Contingencies
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 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. The funds were deposited into the DOEE’s Clean Land Fund for the District’s costs of the Interim ROD work. The Anacostia River Consent Decree caps Pepco’s liability for these costs and provides Pepco with the right to seek contributions from other PRPs. The Anacostia River Consent Decree was signed by the judge for the U.S. District Court for the District of Columbia and became effective on April 11, 2024. Exelon, PHI, and Pepco have accrued a liability for Pepco’s payment obligations under the Anacostia Consent Decree and management's best estimate of its share of any other future Anacostia River response costs. Pepco has concluded that incremental exposure remains reasonably possible, but management cannot reasonably estimate a range of loss beyond the amounts recorded, which are included in the table above.
In addition to the activities associated with the remedial process outlined above, CERCLA separately requires federal and state (here including Washington, D.C.) Natural Resource Trustees (federal or state agencies designated by the President or the relevant state, respectively, or Indian tribes) to conduct an assessment of any damages to natural resources within their jurisdiction as a result of the contamination that is being remediated. The Trustees can seek compensation from responsible parties for such damages, including restoration costs. During the second quarter of 2018, Pepco became aware that the Trustees are in the beginning stages of a NRD assessment, a process that often takes many years beyond the remedial decision to complete. Pepco has concluded that a loss associated with the eventual NRD assessment is reasonably possible. Due to the early stage of the NRD process, Pepco cannot reasonably estimate the final range of loss potentially resulting from this process. Pepco has become aware, however, that the District is pursuing claims against other parties. Specifically, in January 2025, D.C. OAG filed a lawsuit against the United States seeking to declare the United States liable under CERCLA and the District of Columbia’s Brownfield Revitalization Act of 2000 and to recover the District’s response costs associated with its investigation and remediation of Anacostia River sediment contamination and for future NRDs. Pepco is not a party to this suit, but Pepco, the United States, and the District of Columbia have entered mediation discussions to resolve their respective claims against one another under CERCLA and the Brownfield Revitalization Act with respect to the river. The court has put the case on hold pending the outcome of the mediation.
As noted in the Benning Road Site disclosure above, as part of the separation of Exelon and Constellation in February 2022, an assumption agreement was executed transferring any potential future remediation liabilities associated with the Benning Site remediation to a non-utility subsidiary of Exelon. Similarly, any potential future liability associated with the Anacostia River Sediment Project was also assumed by this entity.
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Combined Notes to Consolidated Financial Statements — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Note 11 — Commitments and Contingencies