Constellation Energy Corp 10-Q

ITEM 1. FINANCIAL STATEMENTS Table of Contents Constellation Energy Corporation and Subsidiary Companies Consolidated Statements of Operations and Comprehensive Income (Unaudited) Three Months Ended March 31, (In millions, except per share data) 2026 2025 Operating revenues $ 11,122 $ 6,788 Operating expenses Purchased power and fuel 6,352 4,384 Operating and maintenance 1,780 1,545 Depreciation and amortization 443 248 Taxes other than income taxes 229 160 Total operating expenses 8,804 6,337 Gain (loss) on sales of assets 14 — Operating income (loss) 2,332 451 Other income and (deductions) Interest expense, net ( 253 ) ( 146 ) Other, net 46 ( 154 ) Total other income and (deductions) ( 207 ) ( 300 ) Income (loss) before income taxes 2,125 151 Income tax (benefit) expense 530 22 Equity in income (losses) of unconsolidated affiliates 8 — Net income (loss) 1,603 129 Net income (loss) attributable to noncontrolling interests 13 11 Net income (loss) attributable to common shareholders $ 1,590 $ 118 Comprehensive income (loss), net of income taxes Net income (loss) $ 1,603 $ 129 Other comprehensive income (loss), net of income taxes Pension and non-pension postretirement benefit plans: Prior service benefit reclassified to periodic benefit cost ( 1 ) — Actuarial loss reclassified to periodic cost 28 17 Pension and non-pension postretirement benefit plan valuation adjustment ( 25 ) ( 34 ) Unrealized gain (loss) on cash flow hedges 1 2 Unrealized gain (loss) on foreign currency translation ( 3 ) 8 Other comprehensive income (loss), net of income taxes — ( 7 ) Comprehensive income (loss) 1,603 122 Comprehensive income (loss) attributable to noncontrolling interests 13 11 Comprehensive income (loss) attributable to common shareholders $ 1,590 $ 111 Average shares of common stock outstanding: Basic 354 313 Assumed exercise and/or distributions of stock-based awards — 1 Diluted 354 314 Earnings per average common share Basic $ 4.49 $ 0.38 Diluted $ 4.49 $ 0.38 See the Combined Notes to Consolidated Financial Statements 5 Table of Contents Constellation Energy Corporation and Subsidiary Companies Consolidated Statements of Cash Flows (Unaudited) Three Months Ended March 31, (In millions) 2026 2025 Cash flows from operating activities Net income (loss) $ 1,603 $ 129 Adjustments to reconcile net income (loss) to net cash flows provided by (used in) operating activities Depreciation, amortization, and accretion, including nuclear fuel and contract amortization 1,202 640 Deferred income taxes and amortization of ITCs 440 ( 98 ) Net fair value changes related to derivatives ( 1,040 ) 356 Net realized and unrealized (gains) losses on NDT funds ( 17 ) ( 44 ) Net realized and unrealized (gains) losses on equity investments 27 268 Other non-cash operating activities ( 199 ) 47 Changes in assets and liabilities: Accounts receivable 323 ( 15 ) Inventories 106 98 Accounts payable and accrued expenses ( 1,377 ) ( 290 ) Option premiums received (paid), net ( 15 ) 26 Collateral received (posted), net 249 ( 486 ) Income taxes 103 120 Pension and non-pension postretirement benefit contributions ( 191 ) ( 174 ) Other assets and liabilities ( 789 ) ( 470 ) Net cash flows provided by (used in) operating activities 425 107 Cash flows from investing activities Capital expenditures ( 1,275 ) ( 806 ) Proceeds from NDT fund sales 2,504 2,084 Investment in NDT funds ( 2,572 ) ( 2,152 ) Acquisition of Calpine, net of cash and restricted cash acquired ( 2,537 ) — Other investing activities 148 ( 12 ) Net cash flows provided by (used in) investing activities ( 3,732 ) ( 886 ) Cash flows from financing activities Change in short-term borrowings 1,957 — Proceeds from short-term borrowings with maturities greater than 90 days 3,000 — Repayments of short-term borrowings with maturities greater than 90 days ( 1,500 ) — Issuance of long-term debt 2,770 — Retirement of long-term debt ( 5,254 ) ( 57 ) Dividends paid on common stock ( 155 ) ( 122 ) Other financing activities ( 88 ) ( 229 ) Net cash flows provided by (used in) financing activities 730 ( 408 ) Increase (decrease) in cash, restricted cash, and cash equivalents ( 2,577 ) ( 1,187 ) Cash, restricted cash, and cash equivalents at beginning of period 3,748 3,129 Cash, restricted cash, and cash equivalents at end of period $ 1,171 $ 1,942 Supplemental disclosure of non-cash investing and financing activities Common stock issued for acquisition of Calpine $ 17,507 $ — Exchange of Calpine senior notes for Constellation senior notes 2,290 — Decrease in PP&E related to ARO update ( 889 ) ( 6 ) See the Combined Notes to Consolidated Financial Statements 6 Table of Contents Constellation Energy Corporation and Subsidiary Companies Consolidated Balance Sheets (Unaudited) (In millions) March 31, 2026 December 31, 2025 ASSETS Current assets Cash and cash equivalents $ 800 $ 3,641 Restricted cash and cash equivalents 371 107 Accounts receivable, net 4,414 4,266 Derivative assets 1,795 945 Inventories, net 2,582 1,736 Renewable energy credits 1,038 789 Assets held for sale 5,735 126 Other 1,274 509 Total current assets 18,009 12,119 Property, plant, and equipment (net of accumulated depreciation and amortization of $ 19,524 and $ 19,072 , respectively) 40,769 22,474 Deferred debits and other assets Nuclear decommissioning trust funds 19,366 19,336 Goodwill 11,527 420 Derivative assets 2,113 450 Other 5,127 2,450 Total deferred debits and other assets 38,133 22,656 Total assets (a) $ 96,911 $ 57,249 LIABILITIES AND EQUITY Current liabilities Short-term borrowings $ 5,102 $ 1,650 Long-term debt due within one year 370 92 Accounts payable and accrued expenses 4,449 4,294 Derivative liabilities 810 467 Renewable energy credit obligation 1,193 1,075 Other 1,291 366 Total current liabilities 13,215 7,944 Long-term debt 16,994 7,250 Deferred credits and other liabilities Deferred income taxes and unamortized ITCs 8,199 3,544 Asset retirement obligations 12,433 13,193 Pension and non-pension postretirement benefit obligations 1,835 1,977 Payables related to Regulatory Agreement Units 5,389 5,334 Derivative liabilities 518 414 Other 4,508 2,740 Total deferred credits and other liabilities 32,882 27,202 Total liabilities (a) 63,091 42,396 Commitments and contingencies (Note 15) Shareholders' equity Common stock ( No par value, 1,000 shares authorized, 362 and 312 shares outstanding, respectively) 28,574 11,043 Retained earnings (deficit) 7,334 5,899 Accumulated other comprehensive income (loss), net ( 2,425 ) ( 2,425 ) Total shareholders' equity 33,483 14,517 Noncontrolling interests 337 336 Total equity 33,820 14,853 Total liabilities and shareholders' equity $ 96,911 $ 57,249 __________ (a) Our consolidated assets include $ 4,609 million and $ 4,551 million at March 31, 2026 and December 31, 2025, respectively, of certain VIEs that can only be used to settle the liabilities of the VIE. Our consolidated liabilities include $ 2,381 million and $ 914 million at March 31, 2026 and December 31, 2025, respectively, of certain VIEs for which the VIE creditors do not have recourse to us. See Note 17 — Variable Interest Entities for additional information. See the Combined Notes to Consolidated Financial Statements 7 Table of Contents Constellation Energy Corporation and Subsidiary Companies Consolidated Statements of Changes in Equity (Unaudited) Three Months Ended March 31, 2026 Shareholders' Equity (In millions, shares in thousands) Issued Shares Common Stock Retained Earnings (Deficit) Accumulated Other Comprehensive Income (Loss), net Noncontrolling Interests Total Equity Balance, December 31, 2025 312,355 $ 11,043 $ 5,899 $ ( 2,425 ) $ 336 $ 14,853 Net Income (loss) — — 1,590 — 13 1,603 Employee incentive plans 628 24 — — — 24 Changes in equity of noncontrolling interests — — — — ( 12 ) ( 12 ) Common stock dividends ($ 0.4265 /common share) — — ( 155 ) — — ( 155 ) Common stock issued to acquire Calpine 49,376 17,507 — — — 17,507 Balance, March 31, 2026 362,359 $ 28,574 $ 7,334 $ ( 2,425 ) $ 337 $ 33,820 Three Months Ended March 31, 2025 Shareholders' Equity (In millions, shares in thousands) Issued Shares Common Stock Retained Earnings (Deficit) Accumulated Other Comprehensive Income (Loss), net Noncontrolling Interests Total Equity Balance, December 31, 2024 312,838 $ 11,402 $ 4,066 $ ( 2,302 ) $ 373 $ 13,539 Net Income (loss) — — 118 — 11 129 Employee incentive plans 547 ( 49 ) — — — ( 49 ) Changes in equity of noncontrolling interests — — — — ( 6 ) ( 6 ) Common stock dividends ($ 0.3878 /common share) — — ( 122 ) — — ( 122 ) Capped call option contracts — ( 150 ) — — — ( 150 ) Other comprehensive income (loss), net of income taxes — — — ( 7 ) — ( 7 ) Balance, March 31, 2025 313,385 $ 11,203 $ 4,062 $ ( 2,309 ) $ 378 $ 13,334 See the Combined Notes to Consolidated Financial Statements 8 Table of Contents Constellation Energy Generation, LLC and Subsidiary Companies Consolidated Statements of Operations and Comprehensive Income (Unaudited) Three Months Ended March 31, (In millions) 2026 2025 Operating revenues $ 11,122 $ 6,788 Operating expenses Purchased power and fuel 6,352 4,384 Operating and maintenance 1,780 1,545 Depreciation and amortization 443 248 Taxes other than income taxes 229 160 Total operating expenses 8,804 6,337 Gain (loss) on sales of assets 14 — Operating income (loss) 2,332 451 Other income and (deductions) Interest expense, net ( 253 ) ( 146 ) Other, net 46 ( 154 ) Total other income and (deductions) ( 207 ) ( 300 ) Income (loss) before income taxes 2,125 151 Income tax (benefit) expense 530 22 Equity in income (losses) of unconsolidated affiliates 8 — Net income (loss) 1,603 129 Net income (loss) attributable to noncontrolling interests 13 11 Net income (loss) attributable to membership interest $ 1,590 $ 118 Comprehensive income (loss), net of income taxes Net income (loss) $ 1,603 $ 129 Other comprehensive income (loss), net of income taxes Pension and non-pension postretirement benefit plans: Prior service benefit reclassified to periodic benefit cost ( 1 ) — Actuarial loss reclassified to periodic cost 28 17 Pension and non-pension postretirement benefit plan valuation adjustment ( 25 ) ( 34 ) Unrealized gain (loss) on cash flow hedges 1 2 Unrealized gain (loss) on foreign currency translation ( 3 ) 8 Other comprehensive income (loss), net of income taxes — ( 7 ) Comprehensive income (loss) 1,603 122 Comprehensive income (loss) attributable to noncontrolling interests 13 11 Comprehensive income (loss) attributable to membership interest $ 1,590 $ 111 See the Combined Notes to Consolidated Financial Statements 9 Table of Contents Constellation Energy Generation, LLC and Subsidiary Companies Consolidated Statements of Cash Flows (Unaudited) Three Months Ended March 31, (In millions) 2026 2025 Cash flows from operating activities Net income (loss) $ 1,603 $ 129 Adjustments to reconcile net income (loss) to net cash flows provided by (used in) operating activities Depreciation, amortization, and accretion, including nuclear fuel and contract amortization 1,202 640 Deferred income taxes and amortization of ITCs 440 ( 98 ) Net fair value changes related to derivatives ( 1,040 ) 356 Net realized and unrealized (gains) losses on NDT funds ( 17 ) ( 44 ) Net realized and unrealized (gains) losses on equity investments 27 268 Other non-cash operating activities ( 229 ) 24 Changes in assets and liabilities: Accounts receivable 330 ( 15 ) Receivables from and payables to affiliates, net ( 272 ) ( 259 ) Inventories 106 98 Accounts payable and accrued expenses ( 1,386 ) ( 301 ) Option premiums received (paid), net ( 15 ) 26 Collateral received (posted), net 249 ( 486 ) Income taxes 103 120 Pension and non-pension postretirement benefit contributions ( 191 ) ( 174 ) Other assets and liabilities ( 527 ) ( 257 ) Net cash flows provided by (used in) operating activities 383 27 Cash flows from investing activities Capital expenditures ( 1,275 ) ( 806 ) Proceeds from NDT fund sales 2,504 2,084 Investment in NDT funds ( 2,572 ) ( 2,152 ) Acquisition of Calpine, net of cash and restricted cash acquired ( 2,537 ) — Other investing activities 150 ( 12 ) Net cash flows provided by (used in) investing activities ( 3,730 ) ( 886 ) Cash flows from financing activities Change in short-term borrowings 1,957 — Proceeds from short-term borrowings with maturities greater than 90 days 3,000 — Repayments of short-term borrowings with maturities greater than 90 days ( 1,500 ) — Issuance of long-term debt 2,770 — Retirement of long-term debt ( 5,254 ) ( 57 ) Distributions to member ( 155 ) ( 272 ) Other financing activities ( 55 ) ( 5 ) Net cash flows provided by (used in) financing activities 763 ( 334 ) Increase (decrease) in cash, restricted cash, and cash equivalents ( 2,584 ) ( 1,193 ) Cash, restricted cash, and cash equivalents at beginning of period 3,720 3,115 Cash, restricted cash, and cash equivalents at end of period $ 1,136 $ 1,922 Supplemental disclosure of non-cash investing and financing activities Acquisition of Calpine $ 17,503 $ — Exchange of Calpine senior notes for Constellation senior notes 2,290 — Decrease in PP&E related to ARO update ( 889 ) ( 6 ) See the Combined Notes to Consolidated Financial Statements 10 Table of Contents Constellation Energy Generation, LLC and Subsidiary Companies Consolidated Balance Sheets (Unaudited) (In millions) March 31, 2026 December 31, 2025 ASSETS Current assets Cash and cash equivalents $ 785 $ 3,641 Restricted cash and cash equivalents 351 79 Accounts receivable, net 4,392 4,251 Derivative assets 1,795 945 Inventories, net 2,582 1,736 Renewable energy credits 1,038 789 Assets held for sale 5,735 126 Other 1,282 508 Total current assets 17,960 12,075 Property, plant, and equipment (net of accumulated depreciation and amortization of $ 19,524 and $ 19,072 , respectively) 40,769 22,474 Deferred debits and other assets Nuclear decommissioning trust funds 19,366 19,336 Goodwill 11,527 420 Derivative assets 2,113 450 Other 5,120 2,443 Total deferred debits and other assets 38,126 22,649 Total assets (a) $ 96,855 $ 57,198 LIABILITIES AND EQUITY Current liabilities Short-term borrowings $ 5,102 $ 1,650 Long-term debt due within one year 370 92 Accounts payable and accrued expenses 4,324 4,033 Payables to affiliates 102 365 Derivative liabilities 810 467 Renewable energy credit obligation 1,193 1,075 Other 1,289 358 Total current liabilities 13,190 8,040 Long-term debt 16,994 7,250 Deferred credits and other liabilities Deferred income taxes and unamortized ITCs 8,199 3,544 Asset retirement obligations 12,433 13,193 Pension and non-pension postretirement benefit obligations 1,835 1,977 Payables related to Regulatory Agreement Units 5,389 5,334 Derivative liabilities 518 414 Other 4,465 2,583 Total deferred credits and other liabilities 32,839 27,045 Total liabilities (a) 63,023 42,335 Commitments and contingencies (Note 15) Equity Member’s equity Membership interest 27,677 10,144 Undistributed earnings (deficit) 8,243 6,808 Accumulated other comprehensive income (loss), net ( 2,425 ) ( 2,425 ) Total member’s equity 33,495 14,527 Noncontrolling interests 337 336 Total equity 33,832 14,863 Total liabilities and equity $ 96,855 $ 57,198 __________ (a) Our consolidated assets include $ 4,609 million and $ 4,551 million as of March 31, 2026 and December 31, 2025, respectively, of certain VIEs that can only be used to settle the liabilities of the VIE. Our consolidated liabilities include $ 2,381 million and $ 914 million as of March 31, 2026 and December 31, 2025, respectively, of certain VIEs for which the VIE creditors do not have recourse to us. See Note 17 — Variable Interest Entities for additional information. See the Combined Notes to Consolidated Financial Statements 11 Table of Contents Constellation Energy Generation, LLC and Subsidiary Companies Consolidated Statements of Changes in Equity (Unaudited) Three Months Ended March 31, 2026 Member's Equity (In millions) Membership Interest Undistributed Earnings (Deficit) Accumulated Other Comprehensive Income (Loss), net Noncontrolling Interests Total Equity Balance, December 31, 2025 $ 10,144 $ 6,808 $ ( 2,425 ) $ 336 $ 14,863 Net Income (loss) — 1,590 — 13 1,603 Changes in equity of noncontrolling interests — — — ( 12 ) ( 12 ) Distributions to member — ( 155 ) — — ( 155 ) Contribution from member 30 — — — 30 Acquisition of Calpine 17,503 — — — 17,503 Balance, March 31, 2026 $ 27,677 $ 8,243 $ ( 2,425 ) $ 337 $ 33,832 Three Months Ended March 31, 2025 Member's Equity (In millions) Membership Interest Undistributed Earnings (Deficit) Accumulated Other Comprehensive Income (Loss), net Noncontrolling Interests Total Equity Balance, December 31, 2024 $ 10,538 $ 4,974 $ ( 2,302 ) $ 373 $ 13,583 Net Income (loss) — 118 — 11 129 Changes in equity of noncontrolling interests — — — ( 6 ) ( 6 ) Distributions to member ( 150 ) ( 122 ) — — ( 272 ) Other comprehensive income (loss), net of income taxes — — ( 7 ) — ( 7 ) Balance, March 31, 2025 $ 10,388 $ 4,970 $ ( 2,309 ) $ 378 $ 13,427 See the Combined Notes to Consolidated Financial Statements 12 Table of Contents Combined Notes to Consolidated Financial Statements (Dollars in millions, unless otherwise noted) 1. Basis of Presentation Description of Business We are the nation's largest producer of clean and reliable energy and a leading supplier of energy products and services. Our fleet of generation assets includes nuclear, natural gas, oil, hydroelectric, geothermal, wind, and solar facilities. Through our integrated business operations, we sell electricity, natural gas, and other energy-related products and sustainable solutions to various types of customers, including distribution utilities, municipalities, cooperatives, and commercial, industrial, public sector, and residential customers in markets across multiple geographic regions. We have six reportable segments: Mid-Atlantic, Midwest, New York, ERCOT, Other Power Regions, and Calpine. Basis of Presentation The accompanying Consolidated Financial Statements as of March 31, 2026 and for the three months ended March 31, 2026 and 2025 are unaudited but, in our opinion, include all adjustments that are considered necessary for a fair statement of the results for the periods reported herein in accordance with GAAP. All adjustments are of a normal, recurring nature, unless otherwise disclosed. The Consolidated Financial Statements include the accounts of our subsidiaries and all intercompany transactions have been eliminated in consolidation. Our December 31, 2025 Consolidated Balance Sheet was derived from audited financial statements. The interim financial statements are to be read in conjunction with prior annual financial statements and notes. Financial results for interim periods are not necessarily indicative of results that may be expected for any other interim period or for the fiscal year ending December 31, 2026. These Combined Notes to Consolidated Financial Statements have been prepared pursuant to the rules and regulations of the SEC for Quarterly Reports on Form 10-Q. Certain information and note disclosures normally included in financial statements prepared in accordance with GAAP have been condensed or omitted pursuant to such rules and regulations. Certain prior period amounts have been reclassified to conform to the presentation in the current period. Amounts disclosed relate to CEG Parent and Constellation unless specifically noted as relating to CEG Parent only. Unless otherwise indicated or the context otherwise requires, references herein to the terms “we,” “us,” and “our” refer collectively to CEG Parent and Constellation. Summary of Significant Accounting Policies See Note 1 — Basis of Presentation of our 2025 Form 10-K for additional information on significant accounting policies. 2. Mergers, Acquisitions, and Dispositions Acquisition of Calpine Corporation On January 7, 2026 (the “Acquisition Date”), we acquired all of the outstanding equity interests in Calpine in a cash and stock transaction. Pursuant to the Merger Agreement and related transaction steps, Calpine was converted into a limited liability company, Calpine LLC, and became a wholly owned subsidiary of Constellation. This acquisition is complementary to, and aligns strategically with, our existing business operations and provides both increased scale and meaningful market diversification. The merger couples the largest producer of clean, emissions-free energy with the reliable, dispatchable natural gas assets of Calpine, and also creates the nation’s leading competitive retail electric supplier, providing increased scale, diversification and complementary capabilities that enable us to meet growing demand with a broad array of energy and sustainability products. The addition of Calpine strengthens our essential role in providing clean, reliable energy as the nation seeks to transition to a more sustainable future, and will improve our position to pursue investments in new and existing technologies to meet growing demand. The merger consideration consisted of 50 million newly issued shares of our common stock, no par value, and approximately $ 4.5 billion in cash. In connection with the merger, certain of the newly issued shares will be subject to a lock-up period, which expires on June 30, 2026, for 50 % of the shares and on June 30, 2027, for the remaining 50 %. 13 Table of Contents Combined Notes to Consolidated Financial Statements (Dollars in millions, unless otherwise noted) Note 2 — Mergers, Acquisitions, and Dispositions Calpine operates a competitive retail electric supplier platform serving approximately 62 TWhs of load annually. Calpine also owns and operates a generation fleet of natural gas, oil, geothermal, battery storage, and solar assets with approximately 23 GWs of generation capacity, after considering divestitures required by certain regulatory approvals for the transaction. The final regulatory clearance for the merger was the DOJ resolution, which requires the divestiture of five generating assets located in PJM, one in ERCOT, and Calpine's minority interest in the Gregory Power Plant, also in ERCOT. The DOJ resolution requires us to enter into definitive agreement(s) to divest these assets within 240 days of closing the acquisition, by September 4, 2026. The transaction was accounted for as a business combination using the acquisition method of accounting where we are considered the acquirer for accounting purposes. We recognized the identifiable assets acquired and liabilities assumed at their estimated fair values as of January 7, 2026, with any excess of the consideration transferred over the fair value of net identifiable assets recognized as goodwill. In January 2026, we completed the divestiture of Calpine's minority ownership interest in the Gregory Power Plant, as required under the terms of the DOJ resolution. In March 2026, we entered into an agreement with LS Power Equity Advisors, LLC ("LS Power") whereby we will sell five generation assets in PJM to LS Power, which comprise approximately 4.4 GW of predominantly natural gas-fired generation capacity located in Delaware and Pennsylvania, for aggregate consideration of $ 5.0 billion before closing adjustments. Closing of the sale is subject to receipt of applicable regulatory approvals, including review by the DOJ and FERC, and other customary closing conditions. We are taking steps to divest the ERCOT plant, the last asset sale required to satisfy our regulatory commitments under the merger. Certain of the generation assets being sold are currently secured under project financing arrangements, see Note 13 — Debt and Credit Agreements for additional information. Consideration Transferred The following table summarizes the components of the total merger consideration transferred. There was no contingent consideration associated with the acquisition. Fair value of CEG Parent common stock issued (a) $ 17,603 Cash consideration (b) 4,342 Fair value of common stock subject to vesting period attributable to post-combination expense (c) ( 96 ) Effective settlement of preexisting relationships ( 14 ) Total merger consideration $ 21,835 __________ (a) Represents the fair value of approximately 50 million shares of CEG Parent common stock issued in connection with the acquisition, calculated using CEG Parent’s closing stock price of $ 354.58 on January 6, 2026, the last trading day prior to the Acquisition Date. The fair value of the stock consideration is based on an observable market price and represents a Level 1 fair value measurement. (b) Represents cash paid to Calpine shareholders in connection with the acquisition. The amount reflects the $ 4.5 billion base cash consideration per the Merger Agreement, reduced by certain adjustments based on contractual terms also specified in the Merger Agreement. (c) Certain CEG Parent common stock issued to Calpine employees in exchange for their equity interests is subject to a vesting period of up to 26 months and has been excluded from merger consideration. These amounts will be recognized as stock-based compensation expense over the applicable vesting period in accordance with authoritative guidance. 14 Table of Contents Combined Notes to Consolidated Financial Statements (Dollars in millions, unless otherwise noted) Note 2 — Mergers, Acquisitions, and Dispositions Purchase Price Allocation The following table presents the preliminary allocation of the total merger consideration to the identifiable assets acquired and liabilities assumed as of the Acquisition Date. The allocation is preliminary and subject to revision during the measurement period, which will not exceed one year from the Acquisition Date. Adjustments to provisional amounts will be recognized in the reporting period in which they are identified, with a corresponding adjustment to goodwill. Assets acquired: Cash and cash equivalents $ 1,540 Restricted cash and cash equivalents 261 Accounts receivable 761 Derivative assets 2,140 Inventories 989 Assets held for sale (a) 5,603 Property, plant, and equipment 18,481 Renewable energy credits 180 Unamortized energy contracts (b) 2,133 Other assets 700 Total assets acquired $ 32,788 Liabilities assumed: Accounts payable and accrued expenses $ 1,601 Long-term debt (including amounts due within one year) (c) 12,551 Derivative liabilities 644 Renewable energy credit obligation 258 Deferred income taxes and unamortized ITCs 4,083 Asset retirement obligations 350 Unamortized energy contracts (b) 1,815 Other liabilities 758 Total liabilities assumed 22,060 Net identifiable assets acquired 10,728 Goodwill (d) 11,107 Total consideration transferred $ 21,835 (a) Assets Held for Sale. Reflects the Acquisition Date fair value, less costs to sell, for the six generating assets required to be divested. Depreciation and amortization of these assets ceased upon classification as held for sale. No impairment has been recognized subsequent to initial classification. The following table presents the carrying amounts of the major classes of assets and liabilities classified as held for sale as of the Acquisition Date: Assets held for sale: Property, plant and equipment $ 5,454 Inventories 136 Other assets 13 Total assets held for sale $ 5,603 Liabilities associated with assets held for sale: Asset retirement obligations $ 16 Other liabilities 82 Total liabilities associated with assets held for sale $ 98 15 Table of Contents Combined Notes to Consolidated Financial Statements (Dollars in millions, unless otherwise noted) Note 2 — Mergers, Acquisitions, and Dispositions (b) Unamortized Energy Contracts. The following table summarizes the classification and amounts of UECs in the Consolidated Balance Sheets as of the Acquisition Date: Other current assets $ 517 Other deferred debits and other assets 1,616 Other current liabilities 367 Other deferred credits and other liabilities 1,448 (c) Long-term Debt (including amounts due within one year). We assumed total debt of $ 12,551 million at estimated fair value as of the Acquisition Date, comprising $ 279 million classified as Long-term debt due within one year and $ 12,272 million classified as Long-term debt, in the Consolidated Balance Sheets. See Note 13 — Debt and Credit Agreements for additional information. (d) Goodwill. Represents the excess of the purchase price over the estimated fair value of the net assets acquired. Goodwill recognized primarily reflects the expected benefits from increased scale and meaningful market diversification, complementary generation and retail capabilities, and an enhanced ability to meet growing demand with a broader array of energy and sustainability products, to the extent such benefits are not separately recognizable as identifiable intangible assets. Goodwill will be assigned to the reporting units expected to benefit from the acquisition. The assignment of goodwill to the reporting units has not been completed as of the date of these financial statements due to the preliminary nature of the purchase price allocation. The goodwill recognized in connection with the acquisition is not expected to be deductible for income tax purposes. Valuation of Significant Assets and Liabilities The preliminary fair values assigned to the assets acquired and liabilities assumed were determined based on significant estimates and assumptions that are judgmental in nature, including projected future cash flows; discount rates reflecting the risks inherent in the future cash flows; and future market prices, among others. These estimates and assumptions were applied to the valuation of significant acquired assets and assumed liabilities, including property, plant and equipment, assets held for sale, and unamortized energy contracts, and required assessments of current and projected market conditions and operating strategies. Forecasting future cash flows requires assumptions regarding, among other things, forecasted commodity prices for the sale of power and purchases of fuel and the expected operations of the assets, and judgments are also made to determine the expected useful lives assigned to each class of assets acquired and the duration of liabilities assumed. Other Key Accounting Impacts & Judgments Identifiable intangible assets acquired and liabilities assumed in connection with the acquisition include customer relationships, trade names, and energy contracts, recorded at estimated fair value. The weighted average amortization periods reflect weighted average useful lives of 15 years for customer relationships, five years for trade names, and six years for energy contracts. We also recognized the fair value of acquired commodity and interest rate derivatives and related hedging relationships as of the Acquisition Date; related gains or losses subsequent to acquisition will be recognized in earnings consistent with our accounting policies. For additional information on derivative instruments, see Note 12 — Derivative Financial Instruments. The amounts recognized for property, plant and equipment, identifiable intangible assets and liabilities (including customer relationships, trade names, and unamortized energy contracts) and their useful lives, lease assets and liabilities, asset retirement and environmental obligations, contingencies, and income taxes (including deferred taxes) are provisional and subject to revision during the measurement period. Acquisition-related costs (e.g., advisory, legal, valuation, and other professional fees) are expensed as incurred and reflected within Operating and maintenance expenses in the Consolidated Statements of Operations and Comprehensive Income. These costs, which are not included in the consideration transferred, were not material for the three months ended March 31, 2026. 16 Table of Contents Combined Notes to Consolidated Financial Statements (Dollars in millions, unless otherwise noted) Note 2 — Mergers, Acquisitions, and Dispositions Unaudited Pro Forma Results The following unaudited pro forma financial information for the three months ended March 31, 2026 and 2025 assumes that the acquisition occurred on January 1, 2025. The unaudited pro forma financial information is provided for informational purposes only and is not necessarily indicative of the results of operations that would have occurred had the acquisition been completed on January 1, 2025. The unaudited pro forma financial information is not indicative of the future results of operations, which may differ materially from the pro forma financial information presented here. Three Months Ended March 31, Unaudited pro forma financial information 2026 2025 Operating revenues $ 11,352 $ 9,321 Net income (a) 1,590 147 __________ (a) Reflects Net income attributable to common shareholders for CEG Parent and Net income attributable to membership interest for Constellation . The unaudited pro forma financial information presented above includes adjustments for incremental depreciation and amortization as a result of the fair value determination of the net assets acquired, the effects of the acquisition on tax expense (benefit), and other acquisition accounting adjustments. As discussed in Note 5 — Segment Information, Calpine is now presented as a reportable segment, and RNF is the segment performance metric, a component of which includes revenue. From the Acquisition Date through March 31, 2026, Operating revenues attributable to Calpine were $ 3,136 million . However, as a result of the commencement of integration activities for certain functions and the consolidation of financing activities (see Note 13 — Debt and Credit Agreements), it is impracticable to determine Calpine’s earnings since the Acquisition Date. 3. Regulatory Matters As discussed in Note 3 — Regulatory Matters of our 2025 Form 10-K, we are involved in various regulatory and legislative proceedings. The following discusses developments in 2026 and updates to the 2025 Form 10-K. Capacity Interconnection Rights for Crane Clean Energy Center In 2024, we announced the restart of Three Mile Island Unit 1, renamed as the Crane Clean Energy Center. The restart is supported by a 20-year PPA with Microsoft to purchase the output generated from the renewed plant. The restart of the plant and delivery of electricity under the PPA is subject to certain regulatory approvals, including the NRC comprehensive safety and environmental review, as well as permits from relevant state and local agencies. PJM's Phase I System Impact Study for Crane identified contingent transmission upgrades that would need to be completed for Crane to be fully deliverable to the grid, some of which suggested projected in-service dates extending as late as December 2030. In March 2026, we filed a waiver request with FERC to allow the transfer of capacity interconnection rights (CIRs) from Eddystone to Crane with the aim of reducing the number of contingent upgrades that would need to be completed prior to Crane being fully deliverable to the grid. Eddystone Units 3 and 4 were previously announced as having a planned retirement date of May 31, 2025, but have been required to continue operating as energy-only resources under DOE emergency orders issued in 2025 and 2026 for grid reliability. Transferring the Eddystone CIRs to Crane will not affect PJM's ability to operate and dispatch Eddystone for reliability in compliance with the DOE's orders. We have requested that FERC grant the requested waiver no later than June 1, 2026. 17 Table of Contents Combined Notes to Consolidated Financial Statements (Dollars in millions, unless otherwise noted) Note 4 — Revenue from Contracts with Customers 4. Revenue from Contracts with Customers We recognize revenue from contracts with customers to depict the transfer of goods or services to customers at an amount that we expect to be entitled to in exchange for those goods or services. Our primary sources of revenue include competitive sales of power, natural gas, and other energy-related products and sustainable solutions. See Note 4 — Revenue from Contracts with Customers of our 2025 Form 10-K for additional information regarding the performance obligations, revenue recognition, and payment terms associated with these sources of revenue. 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 March 31, 2026. This disclosure only includes components of contracts for which consideration is fixed and determinable. The average contract term varies by customer type and commodity but ranges from one month to several years. This disclosure excludes derivatives and certain power and gas sales contracts which contain variable volumes and/or variable pricing. 2026 2027 2028 2029 2030 2031 and thereafter Total Remaining performance obligations $ 1,342 $ 1,757 $ 1,494 $ 1,415 $ 889 $ 5,137 $ 12,034 Revenue Disaggregation We disaggregate the 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. The following tables disaggregate the revenue recognized from contracts with customers between power revenues, capacity revenues, natural gas revenues, and other revenues. Power revenues and capacity revenues are further disaggregated by ISO/RTO and/or geographic location, which include PJM, MISO, ERCOT, NYISO, ISO-NE, West (which includes operations in CAISO, Arizona and Oregon), SERC/SPP, and International Power (which includes operations in the United Kingdom and Canada). Three Months Ended March 31, 2026 Power and Power-related Revenues (a) Capacity Revenues (b) Other Revenues Total PJM $ 3,330 $ 130 $ — $ 3,460 MISO 252 6 — 258 ERCOT 360 99 — 459 NYISO 745 13 — 758 ISO-NE 1,014 4 — 1,018 West 168 160 — 328 SERC/SPP 59 4 — 63 International Power 109 — — 109 Total Power revenues 6,037 416 — 6,453 Gas revenues (c) — — 943 943 Other revenues (d) — — 145 145 Total revenue from contracts with customers 6,037 416 1,088 7,541 Other revenue sources (e) — — 3,581 3,581 Total Operating revenues $ 6,037 $ 416 $ 4,669 $ 11,122 18 Table of Contents Combined Notes to Consolidated Financial Statements (Dollars in millions, unless otherwise noted) Note 4 — Revenue from Contracts with Customers Three Months Ended March 31, 2025 Power and Power-related Revenues (a) Capacity Revenues (b) Other Revenues Total PJM $ 2,698 $ 8 $ — $ 2,706 MISO 214 — — 214 ERCOT 301 — — 301 NYISO 675 — — 675 ISO-NE 1,109 — — 1,109 West 146 1 — 147 SERC/SPP 35 3 — 38 International Power 48 — — 48 Total Power revenues 5,226 12 — 5,238 Gas revenues (c) — — 782 782 Other revenues (d) — — 86 86 Total revenue from contracts with customers 5,226 12 868 6,106 Other revenue sources (e) — — 682 682 Total Operating revenues $ 5,226 $ 12 $ 1,550 $ 6,788 __________ (a) Represents power and power-related revenues, including state-sponsored program revenues, ancillary revenues, and revenues from bundled contracts with customers. (b) Represents revenues from regulated capacity auctions as well as bilateral capacity revenues recognized at negotiated contract prices. (c) Represents natural gas sales and other gas-related revenues. (d) Other revenues primarily includes the sales of other energy-related products and sustainable solutions. (e) Other revenue sources primarily includes revenues accounted for as derivatives, leases, and amortization of certain intangible assets and liabilities related to commodity contracts recorded at fair value from acquisitions. 5. Segment Information Operating segments are determined based on information used by the CODM in deciding how to evaluate performance and allocate resources. We have six reportable segments consisting of the Mid-Atlantic, Midwest, New York, ERCOT, all other power regions referred to collectively as “Other Power Regions,” and Calpine. Following the acquisition of Calpine on January 7, 2026, Calpine's operations are being reported as a new reportable segment given the results of its operations will be reviewed by the CODM separately from our historical reporting segments. With the exception of Calpine, the basis for our reportable segments is the integrated management of our electricity business that is located in different geographic regions, and largely representative of the footprints of ISO/RTO and/or NERC regions, which utilize multiple supply sources to provide electricity through various distribution channels (wholesale and retail). Our hedging strategies and risk metrics are also aligned to these same geographic regions. Descriptions of each of our six reportable segments are as follows: • Mid-Atlantic represents operations in the eastern half of PJM, which includes New Jersey, Maryland, Virginia, West Virginia, Delaware, the District of Columbia, and parts of Pennsylvania and North Carolina. • Midwest represents operations in the western half of PJM and the United States footprint of MISO, excluding MISO’s Southern Region. • New York represents operations within NYISO. • ERCOT represents operations within Electric Reliability Council of Texas that covers a majority of the state of Texas. 19 Table of Contents Combined Notes to Consolidated Financial Statements (Dollars in millions, unless otherwise noted) Note 5 — Segment Information • Other Power Regions: • New England represents operations within ISO-NE. • South represents operations in FRCC, MISO’s Southern Region, and the remaining portions of SERC not included within MISO or PJM. • West represents operations in WECC, which includes CAISO. • Canada represents operations across the entire country of Canada and includes AESO, OIESO, and the Canadian portion of MISO. • Calpine represents operations acquired through the merger with Calpine on January 7, 2026, which are located throughout the country, including CAISO, ERCOT, PJM, ISO-NE, NYISO, MISO, SERC, Arizona, Oregon, and Canada. Constellation's CEO is considered the CODM and evaluates the performance of our electric business activities and allocates resources based on segment RNF, primarily through review of budget-to-actual variance analyses. RNF is Operating revenues net of Purchased power and fuel expenses. We believe this is a useful measurement of operational performance, although it is not a presentation defined under GAAP and may not be comparable to other companies’ presentations nor deemed more useful than the GAAP information provided elsewhere in this report. In our evaluation of operating segments, we noted the CODM reviews a variety of performance and profitability measures at a consolidated level with a primary focus on RNF reporting at the geographic regional level, with the exception of Calpine which is reviewed on a standalone basis. Our operating revenues include all sales to third parties as well as government assistance. Purchased power and fuel expenses are considered the most significant segment expense. Purchased power costs include all costs associated with the procurement and supply of electricity including capacity, energy, and ancillary services. Fuel expense includes the fuel costs for our owned generation and fuel costs associated with tolling agreements. The results of our other business activities are not regularly reviewed by the CODM and are therefore not classified as operating segments nor included in the reportable segment amounts. These activities include wholesale and retail sales of natural gas, with the exception of Calpine's natural gas sales which are included in the Calpine segment, energy-related sales in the United Kingdom, as well as sales of other energy-related products and sustainable solutions that are not significant to our overall results of operations. Further, our unrealized gains and losses on economic hedging activities and our amortization of certain intangible assets and liabilities relating to commodity contracts recorded at fair value from mergers and acquisitions are also excluded from the reportable segment amounts. The CODM does not use a measure of total assets in making decisions regarding allocating resources to or assessing the performance of these reportable segments. The following tables, which relate directly to our Consolidated Statements of Operations and Comprehensive Income, provide the reconciliation of operating revenues, purchased power and fuel expenses, and RNF for our reportable segments for the three months ended March 31, 2026 and 2025. Three Months Ended March 31, 2026 Total Operating revenues Total Purchased power and fuel expenses Total RNF Mid-Atlantic $ 1,847 $ ( 1,035 ) $ 812 Midwest 1,732 ( 878 ) 854 New York 569 ( 160 ) 409 ERCOT 370 ( 161 ) 209 Other Power Regions 1,487 ( 1,220 ) 267 Calpine 2,395 ( 1,269 ) 1,126 Total Reportable Segments 8,400 ( 4,723 ) 3,677 Other (a) 2,722 ( 1,629 ) 1,093 Total Consolidated Results $ 11,122 $ ( 6,352 ) $ 4,770 20 Table of Contents Combined Notes to Consolidated Financial Statements (Dollars in millions, unless otherwise noted) Note 5 — Segment Information Three Months Ended March 31, 2025 Total Operating revenues Total Purchased power and fuel expenses Total RNF Mid-Atlantic $ 1,665 $ ( 856 ) $ 809 Midwest 1,404 ( 554 ) 850 New York 562 ( 161 ) 401 ERCOT 398 ( 184 ) 214 Other Power Regions 1,556 ( 1,362 ) 194 Total Reportable Segments 5,585 ( 3,117 ) 2,468 Other (a) 1,203 ( 1,267 ) ( 64 ) Total Consolidated Results $ 6,788 $ ( 4,384 ) $ 2,404 __________ (a) Represents activities not allocated to a segment. See text above for a description of included activities. Operating revenues include unrealized gains of $ 1,315 million and losses of $ 287 million for the three months ended March 31, 2026 and 2025, respectively. Purchased power and fuel expenses include unrealized losses of $ 254 million and $ 34 million for the three months ended March 31, 2026 and 2025, respectively. 6. Government Assistance Beginning in 2024, our nuclear units are eligible for a PTC extending through 2032. See Note 1 — Basis of Presentation and Note 6 — Government Assistance of our 2025 Form 10-K for additional information on nuclear PTCs. For the three months ended March 31, 2026 and 2025, we did not record a material nuclear PTC benefit as the estimate of full year gross receipts exceeded the phase-out for annual gross receipts per MWh for most units. As of March 31, 2026 and December 31, 2025, our Consolidated Balance Sheets reflect approximately $ 125 million and $ 120 million, respectively, of nuclear PTCs within Other deferred debits and other assets. For the three months ended March 31, 2026, we did not utilize any estimated nuclear PTCs as a credit against our current federal income taxes payable. For the year ended December 31, 2025, we recognized a reduction to Accounts payable and accrued expenses in our Consolidated Balance Sheets of $ 375 million for estimated nuclear PTCs that we have utilized as a credit against our current federal income taxes payable. Many of the state-sponsored programs providing compensation for the emissions-free attributes of generation from certain of our nuclear units include contractual or other provisions that require us to refund that compensation up to the amount of the nuclear PTC received or pass through the entirety of the nuclear PTC received. As of March 31, 2026 and December 31, 2025, we have recognized approximately $ 740 million and $ 1,190 million, respectively, of estimated payables within Other deferred credits and other liabilities , Accounts payable and accrued expenses or as offsets to Accounts receivable, net in our Consolidated Balance Sheets associated with programs requiring refunds or pass through of the nuclear PTC. In general, we expect to remit refunds or pass-throughs of state-sponsored program compensation related to nuclear PTCs in the year following the filing of the related tax return. During the three months ended March 31, 2026, we refunded or offset against outstanding receivables approximately $ 450 million associated with state-sponsored program compensation relating to the nuclear PTCs recorded in 2024. During the three months ended March 31, 2026, we recognized a reduction to net operating revenue of approximately $ 285 million associated with these programs in our Consolidated Statements of Operations and Comprehensive Income, compared to an increase to net operating revenue (pre-tax) of approximately $ 110 million for the three months ended March 31, 2025. 21 Table of Contents Combined Notes to Consolidated Financial Statements (Dollars in millions, unless otherwise noted) Note 7 — Accounts Receivable 7. Accounts Receivable The following table provides additional information on the disaggregation of customer and other accounts receivable: Accounts receivable, net March 31, 2026 CEG Parent Constellation Customer accounts receivable (net of allowance for credit losses of $ 157 for CEG Parent and Constellation) $ 3,960 $ 3,960 Other accounts receivable (net of allowance for credit losses of $ — for CEG Parent and Constellation) 454 432 Total $ 4,414 $ 4,392 December 31, 2025 Customer accounts receivable (net of allowance for credit losses of $ 158 for CEG Parent and Constellation) $ 3,577 $ 3,577 Other accounts receivable (net of allowance for credit losses of $ 9 for CEG Parent and Constellation) 689 674 Total $ 4,266 $ 4,251 Allowance for Credit Losses on Accounts Receivable The following table presents the rollforward of allowance for credit losses on customer accounts receivable from January 1, 2026 to March 31, 2026. Balance as of January 1, 2026 $ 158 Current period provision for expected credit losses 15 Write-offs, net of recoveries (a) ( 16 ) Balance as of March 31, 2026 $ 157 __________ (a) Recoveries were not material. The allowance for credit losses on other accounts receivable was not material as of the balance sheet dates, therefore, a rollforward is not presented. Unbilled Customer Revenue We recorded $ 1,465 million and $ 1,305 million of unbilled customer revenues in Accounts receivable, net in the Consolidated Balance Sheets as of March 31, 2026 and December 31, 2025, respectively. Calpine Accounts Receivable Sales Program Following the acquisition of Calpine on January 7, 2026, the Company has assumed Calpine's Accounts Receivable Sales Program (Calpine AR Facility). The Calpine AR Facility was established by Calpine in December 2016 and was last renewed in November 2025 with a current expiration of November 2026. The Calpine AR Facility is a receivables purchase agreement between Calpine Energy Solutions, LLC and Calpine Receivables, LLC, a wholly-owned subsidiary that is accounted for as an unconsolidated VIE, along with an additional purchase and sale agreement between Calpine Receivables, LLC, and unaffiliated financial institutions, the combination of which allow for the revolving sale of up to $ 500 million in certain trade accounts receivables of Calpine Energy Solutions, LLC to third parties at a nominal discount. 22 Table of Contents Combined Notes to Consolidated Financial Statements (Dollars in millions, unless otherwise noted) Note 7 — Accounts Receivable Receivables sold under the Calpine AR Facility are accounted for as sales and excluded from Accounts receivable, net in the Consolidated Balance Sheets and reflected as Cash provided by operating activities in the Consolidated Statements of Cash Flows. Any portion of the purchase price for the sold receivables which is not paid in cash is recorded as a short-term note receivable within Accounts receivable, net, which was not material as of March 31, 2026. Our risk of loss following the transfer of accounts receivable is limited to the note receivable outstanding. Payment of the note receivable is not subject to significant risks other than delinquencies and credit losses on accounts receivable transferred. The Company has guaranteed the performance of Calpine Energy Solutions, LLC to Calpine Receivables, LLC under the Calpine AR Facility, see Note 15 — Commitments and Contingencies for additional information. Additionally, see Note 17 — Variable Interest Entities for additional information on Calpine Receivables, LLC and its status as an unconsolidated VIE. There was $ 564 million in gross accounts receivable outstanding that were sold at a nominal discount under the Calpine AR Facility as of March 31, 2026 and the $ 500 million facility amount was fully utilized. The following table summarizes certain activity for the period under the Calpine AR Facility: Three Months Ended March 31, 2026 Aggregate receivables sold during the period $ 1,205 Proceeds collected on sold receivables 1,126 Other Sales of Customer Accounts Receivables We are required, under supplier tariffs, to sell customer receivables to certain utility companies at a nominal discount. The total gross receivables sold were $ 1,244 million and $ 1,147 million for the three months ended March 31, 2026 and 2025, respectively. 8. Property, Plant, and Equipment The following table presents a summary of property, plant, and equipment by asset category as of March 31, 2026 and December 31, 2025: Asset Category March 31, 2026 December 31, 2025 Electric (a) $ 49,844 $ 33,253 Nuclear fuel 6,712 6,298 CWIP (a) 3,737 1,995 Total property, plant, and equipment 60,293 41,546 Less: accumulated depreciation 19,524 19,072 Property, plant, and equipment, net (b) $ 40,769 $ 22,474 __________ (a) Includes Electric and CWIP assets acquired as a result of the Calpine acquisition of $ 17,247 million and $ 1,234 million, respectively. (b) Excludes assets held for sale related to acquisition of Calpine. See Note 2 — Mergers, Acquisitions, and Dispositions for additional information. The estimated useful lives of our generating facilities are based on a combination of depreciation studies, historical retirements, site licenses and management estimates of operating costs and expected energy market conditions. As a result of the acquisition of Calpine, we added a fleet of natural gas, oil, geothermal, battery storage and solar assets. There were no material changes in the estimated useful lives of our combined oil and gas, battery storage, wind and solar facilities as a result. Geothermal facility depreciation provisions are based on an estimated useful life through 2066. For additional information about the useful lives of our generating facilities and depreciation provisions see Note 8 — Property, Plant, and Equipment of our 2025 Form 10-K. 23 Table of Contents Combined Notes to Consolidated Financial Statements (Dollars in millions, unless otherwise noted) Note 9 — Asset Retirement Obligations 9. Asset Retirement Obligations Nuclear Decommissioning Asset Retirement Obligations We have a legal obligation to decommission our nuclear power plants following the permanent cessation of operations. See Note 10 — Asset Retirement Obligations of our 2025 Form 10-K for additional information regarding AROs and the financial statement impact of changes in estimates. The following table provides a rollforward of the nuclear decommissioning AROs reflected in the Consolidated Balance Sheets from December 31, 2025 to March 31, 2026: Balance as of December 31, 2025 $ 12,908 Accretion expense 165 Net decrease due to changes in, and timing of, estimated future cash flows ( 1,277 ) Costs incurred related to decommissioning plants ( 4 ) Balance as of March 31, 2026 $ 11,792 During the three months ended March 31, 2026, the net $ 1,277 million decrease in the ARO for the changes in, and timing of, estimated future cash flows was driven primarily by c hanges in assumed retirement dates for various plants, including Calvert Cliffs, Fitzpatrick, Limerick, and Nine Mile Point. The 2026 ARO update resulted in a decrease of $ 285 million in Operating and maintenance expense for the three months ended March 31, 2026 in the Consolidated Statements of Operations and Comprehensive income. NDT Funds We had NDT funds totaling $ 19,494 million and $ 19,396 million as of March 31, 2026 and December 31, 2025, respectively. The current portions of the NDT funds, which are included in Other current assets in our Consolidated Balance Sheets, wer e not material as of March 31, 2026 and December 31, 2025. See Note 18 — Supplemental Financial Information for additional information on activities of the NDT funds. Accounting Implications of the Regulatory Agreement Units See Note 1 — Basis of Presentation and Note 10 — Asset Retirement Obligations of our 2025 Form 10-K for additional information on the Regulatory Agreement Units. The following table presents our noncurrent payables to ComEd, PECO, CenterPoint, and AEP Texas reflected as Payables related to Regulatory Agreement Units in the Consolidated Balance Sheets as of March 31, 2026 and December 31, 2025: March 31, 2026 December 31, 2025 ComEd $ 4,297 $ 4,313 PECO 533 442 CenterPoint 416 430 AEP Texas 143 149 Payables related to Regulatory Agreement Units $ 5,389 $ 5,334 NRC Minimum Funding Requirements NRC regulations require that licensees of nuclear generating facilities demonstrate reasonable assurance that funds will be available in specified minimum amounts for radiological decommissioning of the facility at the end of its life. We filed our annual decommissioning funding status report with the NRC for our shutdown units, and any units within five years of shutdown in March 2026. The status report demonstrated adequate decommissioning funding assurance as of December 31, 2025 for all units included in the report. See Note 10 — Asset Retirement Obligations of our 2025 Form 10-K for additional information. 24 Table of Contents Combined Notes to Consolidated Financial Statements (Dollars in millions, unless otherwise noted) Note 9 — Asset Retirement Obligations Non-Nuclear Asset Retirement Obligations We have AROs for plant closure costs associated with our natural gas, oil, battery storage, and renewable generating facilities. The obligations include asbestos abatement, removal of certain storage tanks, restoring leased land to the condition it was in prior to construction of renewable generating stations, disposal of hazardous materials, plug and abandonment of wells, and other decommissioning-related activities. See Note 1 — Basis of Presentation of our 2025 Form 10-K for additional information on the accounting policy for AROs. The following table provides a rollforward of the non-nuclear AROs reflected in the Consolidated Balance Sheets from December 31, 2025 to March 31, 2026: Balance as of December 31, 2025 $ 317 Acquisition of Calpine (a) 350 Accretion expense 9 Costs incurred related to decommissioning plants ( 1 ) Balance as of March 31, 2026 $ 675 __________ (a) Reflects our decommissioning obligations for Calpine plants acquired on January 7, 2026, which are recorded at estimated fair value. See Note 2 — Mergers, Acquisitions, and Dispositions for additional information. Many of the facilities acquired from Calpine do not have AROs given the absence of legal requirements to perform retirement related activities. 10. Income Taxes Rate Reconciliation The effective income tax rate varies from the U.S. federal statutory rate principally due to the following: Three Months Ended March 31, 2026 2025 U.S. federal statutory income tax 21.0 % $ 446 21.0 % $ 32 Increase (decrease) due to: State income taxes, net of federal income tax benefit (a) 3.4 73 ( 0.7 ) ( 1 ) Foreign tax effects — — 0.7 1 Tax credits PTC ( 0.2 ) ( 4 ) ( 1.3 ) ( 2 ) Amortization of ITC, including deferred taxes on basis differences ( 0.2 ) ( 5 ) ( 2.0 ) ( 3 ) Other ( 0.2 ) ( 5 ) ( 2.0 ) ( 3 ) Nontaxable or nondeductible items Share-based payment awards ( 0.7 ) ( 14 ) ( 25.2 ) ( 38 ) Excess officers compensation 0.1 3 4.6 7 Other 0.8 17 0.9 1 Other adjustments Qualified NDT fund income and losses 0.9 19 18.6 28 Effective income tax (b) 24.9 % $ 530 14.6 % $ 22 __________ (a) In 2026, state taxes in California, Massachusetts, and New York made up the majority (greater than 50%) of the tax effect in this category. In 2025, state taxes in Illinois, Maryland, Massachusetts, California, Pennsylvania, and New Jersey made up the majority (greater than 50%) of the tax effect in this category. (b) Amounts may not recalculate due to rounding. 25 Table of Contents Combined Notes to Consolidated Financial Statements (Dollars in millions, unless otherwise noted) Note 10 — Income Taxes Other Tax Matters Tax Matters Agreement In connection with the separation, we entered into a TMA with Exelon. The TMA governs the respective rights, responsibilities, and obligations between us and Exelon after the separation with respect to tax liabilities and benefits, tax attributes, tax returns, tax contests and other tax sharing regarding U.S. federal, state, local and foreign income taxes, other tax matters and related tax returns. Responsibility and Indemnification for Taxes. As a former subsidiary of Exelon, we have joint and several liability with Exelon to the IRS and certain state jurisdictions relating to the taxable periods in which we were included in joint federal and state filings. However, the TMA specifies the portion of this tax liability for which we will bear contractual responsibility, and we and Exelon agreed to indemnify each other against any amounts for which such indemnified party is not responsible. Specifically, we will be liable for taxes due and payable in connection with tax returns that we are required to file. We will also be liable for our share of certain taxes required to be paid by Exelon with respect to taxable years or periods (or portions thereof) ending on or prior to the separation to the extent that we would have been responsible for such taxes under the Exelon tax sharing agreement then existing. As of March 31, 2026 and December 31, 2025, respectively, our Consolidated Balance Sheets reflect $ 32 million and $ 43 million in Other deferred credits and other liabilities, for tax liabilities where we maintain contractual responsibility to Exelon. Tax Refunds and Attributes. The TMA provides for the allocation of certain pre-closing tax attributes between us and Exelon. Tax attributes will be allocated in accordance with the principles set forth in the existing Exelon tax sharing agreement, unless otherwise required by law. Under the TMA, we will be entitled to refunds for taxes for which we are responsible. In addition, it is expected that Exelon will have tax attributes that may be used to offset Exelon’s future tax liabilities. A significant portion of such attributes were generated by our business. In February 2024, we executed an amendment to the TMA that modified the timing of Exelon's payment of amounts due to us. In March 2026, we adjusted our receivable under the TMA as a result of IRS Notice 2026-7, as discussed below. As of March 31, 2026 and December 31, 2025, respectively, we had $ 58 million and $ 175 million in Accounts receivable, net and $ 373 million and $ 21 million in Other deferred debits and other assets for the reclassified tax attributes expected to be utilized by Exelon after separation in accordance with the terms of the TMA. IRS Notice 2026-7. In February 2026, the IRS issued Notice 2026‑7 (the “Notice”), which provides guidance on the implementation of the corporate alternative minimum tax (CAMT). The Notice permits taxpayers to deduct repair and maintenance costs under tax law principles in determining adjusted financial statement income and applies retroactively to previously filed tax returns. As a result of this Notice, Exelon amended its 2023 and 2024 tax returns to reflect less CAMT and thus lower utilization of previously refunded tax attributes. We received a demand letter from Exelon in February 2026, and as a result, in March 2026 we remitted $ 235 million to Exelon under the TMA related to prior periods. We increased our receivable for the $ 235 million in the first quarter of 2026, as reflected above, as we expect Exelon to pay us as it utilizes these tax attributes in future periods. 26 Table of Contents Combined Notes to Consolidated Financial Statements (Dollars in millions, unless otherwise noted) Note 11 — Retirement Benefits 11. Retirement Benefits Components of Net Periodic Benefit (Credits) Costs See Note 1 — Basis of Presentation of our 2025 Form 10-K for additional information on where we report the service cost and other non-service cost (credit) components for all plans. T he following tables present the components of our net periodic benefit (credit) cost for the three months ended March 31, 2026 and 2025. The amounts below are shown prior to capitalization and co-owner allocations, the effects of which were not material for any of the periods presented. Pension Benefits OPEB Total Pension Benefits and OPEB Three Months Ended March 31, 2026 2025 2026 2025 2026 2025 Components of net periodic benefit (credit) cost: Service cost $ 22 $ 21 $ 5 $ 4 $ 27 $ 25 Non-service components of pension benefits & OPEB (credit) cost: Interest cost 99 102 20 19 119 121 Expected return on assets ( 119 ) ( 122 ) ( 8 ) ( 8 ) ( 127 ) ( 130 ) Amortization of: Prior service (credit) cost — — ( 1 ) ( 2 ) ( 1 ) ( 2 ) Actuarial (gain) loss 38 26 ( 1 ) ( 2 ) 37 24 Non-service components of pension benefits & OPEB (credit) cost 18 6 10 7 28 13 Net periodic benefit (credit) cost $ 40 $ 27 $ 15 $ 11 $ 55 $ 38 12. Derivative Financial Instruments We use derivative instruments to manage commodity price risk and interest rate risk related to ongoing business operations. 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, including NPNS, are available through special election and designation, provided they meet specific, restrictive criteria both at the time of designation and on an ongoing basis. All derivative instruments, excluding NPNS, are recorded at fair value through earnings. 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 delivered. Authoritative guidance about offsetting assets and liabilities requires the fair value of derivative instruments to be shown in the Combined Notes to Consolidated Financial Statements on a gross basis, even when the derivative instruments are subject to legally enforceable master netting agreements and qualify for net presentation in the Consolidated Balance Sheets. A master netting agreement is an agreement between two counterparties that may have derivative and non-derivative contracts with each other providing for the net settlement of all referenced contracts via one payment stream, which takes place as the contracts deliver, when collateral is requested or in the event of default. In the tables below, which present fair value balances, our energy-related economic hedges are shown gross. The impact of the netting of fair value balances with the same counterparty that are subject to legally enforceable master netting agreements, as well as netting of cash collateral, including margin on exchange positions, is aggregated in the collateral and netting columns. Our use of cash collateral is generally unrestricted unless we were downgraded below investment grade. As our senior unsecured debt rating is currently rated at BBB+ and Baa1 by S&P and Moody's, respectively, it would take a three-notch downgrade by S&P or Moody's for our rating to go below investment grade. 27 Table of Contents Combined Notes to Consolidated Financial Statements (Dollars in millions, unless otherwise noted) Note 12 — Derivative Financial Instruments Commodity Price Risk We employ established policies and procedures to manage our risks associated with market fluctuations in commodity prices by entering into physical and financial derivative contracts, including swaps, futures, forwards, options, and short-term and long-term commitments to purchase and sell energy and energy-related products. We believe these instruments, which are either determined to be non-derivative or classified as economic hedges, mitigate exposure to fluctuations in commodity prices. In general, increases and decreases in forward market prices have a positive and negative impact, respectively, on owned and contracted generation positions that have not been hedged. Beginning in 2024, our existing nuclear fleet is eligible for a nuclear PTC, an important tool in managing commodity price risk for each nuclear unit not already receiving state support. The nuclear PTC provides increasing levels of support as unit revenues decline below levels established in the IRA and is further adjusted for inflation annually through the duration of the program based on the GDP price deflator for the preceding calendar year. See Note 6 — Government Assistance for additional information. In locations and periods where our load serving activities do not naturally offset existing generation portfolio risk, remaining commodity price exposure is managed through portfolio hedging activities. Portfolio hedging activities are generally concentrated in the prompt three years, when customer demand and market liquidity enable effective price risk mitigation. During this prompt three-year period, we seek to mitigate the price risk associated with our load serving contracts, non-nuclear generation, and any residual price risk for our nuclear generation that the nuclear PTC and state programs may not fully mitigate. We also enter into transactions that further optimize the economic benefits of our overall portfolio. To the extent the amount of energy we produce or procure differs from the amount of energy we have contracted to sell, we are exposed to market fluctuations in the prices of electricity, natural gas, and other commodities. We use a variety of derivative and non-derivative instruments to manage the commodity price risk of our electric generation facilities, including power and gas sales, fuel and power purchases, natural gas transportation and pipeline capacity agreements, and other energy-related products marketed and purchased. To manage these risks, we may enter into fixed-price derivative or non-derivative contracts to hedge the variability in future cash flows from expected sales of power and gas and purchases of power and fuel. The objectives for executing such hedges include fixing the price for a portion of anticipated future electricity sales at a level that provides an acceptable return. We are also exposed to differences between the locational settlement prices of certain economic hedges and the hedged generating units. This price difference is actively managed through other instruments which include derivative congestion products, whose changes in fair value are recognized in earnings each period, and auction revenue rights, which are accounted for on an accrual basis. 28 Table of Contents Combined Notes to Consolidated Financial Statements (Dollars in millions, unless otherwise noted) Note 12 — Derivative Financial Instruments The following tables provide a summary of the commodity derivative fair value balances recorded as of March 31, 2026 and December 31, 2025: March 31, 2026 Economic Hedges Collateral (a) Netting (a) Total Derivative assets (current) $ 13,711 $ 453 $ ( 12,436 ) $ 1,728 Derivative assets (noncurrent) 8,352 306 ( 6,573 ) 2,085 Total derivative assets 22,063 759 ( 19,009 ) 3,813 Derivative liabilities (current) ( 13,807 ) 564 12,436 ( 807 ) Derivative liabilities (noncurrent) ( 7,446 ) 360 6,573 ( 513 ) Total derivative liabilities ( 21,253 ) 924 19,009 ( 1,320 ) Total derivative net assets (liabilities) $ 810 $ 1,683 $ — $ 2,493 December 31, 2025 Derivative assets (current) $ 7,349 $ 375 $ ( 6,791 ) $ 933 Derivative assets (noncurrent) 5,030 272 ( 4,853 ) 449 Total derivative assets 12,379 647 ( 11,644 ) 1,382 Derivative liabilities (current) ( 7,642 ) 386 6,791 ( 465 ) Derivative liabilities (noncurrent) ( 5,585 ) 319 4,853 ( 413 ) Total derivative liabilities ( 13,227 ) 705 11,644 ( 878 ) Total derivative net assets (liabilities) $ ( 848 ) $ 1,352 $ — $ 504 _________ (a) We net all available amounts allowed in our Consolidated Balance Sheets in accordance with authoritative guidance for derivatives. These amounts include unrealized derivative transactions with the same counterparty under legally enforceable master netting agreements and cash collateral. The following table summarizes the net buy/(sell) notional position of commodity derivative transactions, excluding our NPNS derivatives that are not recorded at fair value, as of March 31, 2026 and December 31, 2025: Total Net Position (In Millions) Commodity Type March 31, 2026 December 31, 2025 Unit of Measure Electricity (a) ( 638 ) ( 260 ) MWh Natural Gas (a) 1,576 33 MMBtu Emissions ( 28 ) ( 35 ) Short Ton _________ (a) The increase of net notional position at March 31, 2026 compared to December 31, 2025 is primarily driven by derivatives acquired from Calpine. See Note 2 — Mergers, Acquisitions, and Dispositions for additional information. Economic Hedges (Commodity Price Risk) For the three months ended March 31, 2026 and 2025, we recognized the following net pre-tax commodity unrealized gains (losses), which are also included in the Net fair value changes related to derivatives line in the Consolidated Statements of Cash Flows. Three Months Ended March 31, Income Statement Location 2026 2025 Operating revenues $ 1,311 $ ( 287 ) Purchased power and fuel ( 252 ) ( 37 ) Total $ 1,059 $ ( 324 ) 29 Table of Contents Combined Notes to Consolidated Financial Statements (Dollars in millions, unless otherwise noted) Note 12 — Derivative Financial Instruments Interest Rate Risk We utilize interest rate swaps to manage our interest rate exposure, which are treated as economic hedges. The notional amounts for interest rate swaps were approximately $ 4.6 billion and $ 1.4 billion as of March 31, 2026 and December 31, 2025, respectively. The derivative assets and liabilities as of March 31, 2026 and December 31, 2025 and the gains and losses associated with management of interest rate risk for the three months ended March 31, 2026 and 2025 were not material. The gains and losses associated with management of interest rate risk are included in the Net fair value changes related to derivatives line in the Consolidated Statements of Cash Flows. Credit Risk We 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 as of the reporting date. For commodity derivatives, we enter into enabling agreements that allow for payment netting with our counterparties, which reduces our exposure to counterparty risk by providing for the offset of amounts payable to the counterparty against amounts receivable from the counterparty. Typically, each enabling agreement is for a specific commodity and, with respect to each individual counterparty, netting is limited to t ransactions involving that specific commodity product, except where master netting agreements exist with a counterparty that allows for cross product netting. In addition to right of offset language in the enabling agreement, our credit department establishes credit limits, margining thresholds and collateral requirements for each counterparty, which are defined in the derivative contracts. Counterparty credit limits are based on an internal credit review process that considers a variety of factors, including the results of a scoring model, leverage, liquidity, profitability, credit ratings by credit rating agencies, and other risk management criteria. To the extent that a counterparty’s margining thresholds are exceeded, the counterparty is required to post collateral with us, as specified in each enabling agreement. Our credit department monitors current and forward credit exposure to counterparties and their affiliates, both on an individual and an aggregate basis. The following tables provide information on the credit exposure for derivative instruments, inclusive of payables and receivables, net of collateral and instruments that are subject to master netting agreements, as of March 31, 2026. The amounts in the tables below exclude credit risk exposure from individual retail counterparties, NPNS contracts, forward values on non-derivative contracts and exposure through RTOs, ISOs, as well as commodity exchanges. The tables further delineate that exposure by credit rating of the counterparties and provide guidance on the concentration of credit risk to individual counterparties. Rating as of March 31, 2026 Total Exposure Before Credit Collateral Credit Collateral (a) Net Exposure Number of Counterparties Greater than 10% of Net Exposure Net Exposure of Counterparties Greater than 10% of Net Exposure Investment grade $ 1,979 $ 41 $ 1,938 1 $ 457 Non-investment grade 86 18 68 — — No external ratings Internally rated — investment grade 151 5 146 — — Internally rated — non-investment grade 319 58 261 — — Total $ 2,535 $ 122 $ 2,413 1 $ 457 __________ (a) As of March 31, 2026, credit collateral held from counterparties where we had credit exposure included $ 36 million of cash and $ 86 million of letters of credit. 30 Table of Contents Combined Notes to Consolidated Financial Statements (Dollars in millions, unless otherwise noted) Note 12 — Derivative Financial Instruments Net Credit Exposure by Type of Counterparty As of March 31, 2026 Investor-owned utilities, marketers, power producers $ 1,218 Financial Institutions 599 Energy cooperatives and municipalities 223 Other 373 Total $ 2,413 Credit-Risk-Related Contingent Features As part of the normal course of business, we routinely enter into physically and financially settled contracts for the purchase and sale of capacity, electricity, fuels, emissions allowances, and other energy-related products. Certain of our derivative instruments contain provisions that require us to post collateral. We also enter into commodity transactions on exchanges where the exchanges act as the counterparty to each trade. Transactions on the exchanges must adhere to comprehensive collateral and margining requirements. This collateral may be posted in the form of cash or credit support with thresholds contingent upon our credit ratings from S&P and Moody's. The collateral and credit support requirements vary by contract and by counterparty. These credit-risk-related contingent features stipulate that if we were to be downgraded or lose our investment grade credit ratings (based on our senior unsecured debt rating), we would be required to provide additional collateral. This incremental collateral requirement allows for the offsetting of derivative instruments that are assets with the same counterparty, where the contractual right of offset exists under applicable master netting agreements. In the absence of expressly agreed-to provisions that specify the collateral that must be provided, collateral requested will be a function of the facts and circumstances of the situation at the time of the demand. In such cases, we believe an amount of several months of future payments (e.g., capacity payments) rather than a calculation of fair value is a reasonable estimate for the contingent collateral obligation, which has been factored into the disclosure below. The aggregate fair value of all derivative instruments with credit-risk-related contingent features in a liability position that are not fully collateralized (excluding transactions on the exchanges that are fully collateralized) is detailed in the table below: Credit-Risk-Related Contingent Features March 31, 2026 December 31, 2025 Gross fair value of derivative contracts containing this feature $ ( 2,321 ) $ ( 1,307 ) Offsetting fair value of derivative contracts under master netting arrangements 1,192 554 Net fair value of derivative contracts containing this feature $ ( 1,129 ) $ ( 753 ) 31 Table of Contents Combined Notes to Consolidated Financial Statements (Dollars in millions, unless otherwise noted) Note 12 — Derivative Financial Instruments As of March 31, 2026 and December 31, 2025, we posted or held the following amounts of cash collateral and letters of credit on derivative contracts with external counterparties, after giving consideration to offsetting derivative and non-derivative positions under master netting agreements. March 31, 2026 December 31, 2025 Cash collateral posted $ 1,904 $ 1,399 Letters of credit posted 1,303 718 Cash collateral held 221 47 Letters of credit held 157 115 Additional collateral required in the event of a credit downgrade below investment grade (at BB+/Ba1) (a)(b)(c) 2,972 2,670 __________ (a) Certain of our contracts contain provisions that allow a counterparty to request additional collateral when there has been a subjective determination that our credit quality has deteriorated, generally termed “adequate assurance”. Due to the subjective nature of these provisions, we estimate the amount of collateral that we may ultimately be required to post in relation to the maximum exposure with the counterparty. (b) The downgrade collateral is inclusive of all contracts in a liability position regardless of accounting treatment and excludes any contracts with individual retail counterparties. (c) A loss of investment grade credit rating would require a three-notch downgrade from current levels of BBB+ and Baa1 at S&P and Moody's, respectively. We routinely enter into supply forward contracts with certain utilities with one-sided collateral postings only from us. If market prices fall below the benchmark price levels in these contracts, the utilities are not required to post collateral. However, when market prices rise above the benchmark price levels, we are required to post collateral once certain unsecured credit limits are exceeded. 13. Debt and Credit Agreements Long-Term Debt Calpine Acquisition Upon completion of the acquisition of Calpine in January 2026, we assumed approximately $ 12.6 billion of debt inclusive of approximately $ 7.6 billion of corporate long-term debt, including senior unsecured and secured notes and corporate term loans in addition to approximately $ 5.0 billion of various project financing arrangements. Pursuant to the Exchange Offers discussed below, we issued new notes in January 2026 effectively replacing $ 2.3 billion of Calpine's senior unsecured and secured notes with Constellation senior unsecured notes. Using the proceeds from our January 2026 bond issuance, as discussed below, along with cash on hand and short-term debt, we repaid $ 2.5 billion of Calpine corporate term loans immediately after the acquisition closing, $ 1.25 billion of Calpine senior secured first lien notes in February 2026, and $ 1.4 billion of Calpine senior unsecured notes in March 2026. As discussed above, the following project financing arrangements were assumed as part of the acquisition: Geysers Power Company, LLC. We acquired the GPC first lien senior secured term loan facility, which includes a term loan and $ 250 million letter of credit facility, up to $ 50 million of which may be used for loans to finance energy storage projects ("sub-facility"). At acquisition, outstanding borrowings under the term loan and sub-facility were approximately $ 1.35 billion and $ 45 million, respectively. The GPC facility is secured by substantially all of the real and personal property of GPC and subsidiaries, primarily consisting of the Geysers Assets. The facility matures May 2029 and bears interest at SOFR plus 1.625 %. As of March 31, 2026, there were $ 1.3 billion and $ 44 million of borrowings outstanding under the term loan and sub-facility, respectively. Calpine Construction Finance Company, L.P. We acquired the CCFC first lien senior secured term loan facility with $ 2.1 billion outstanding borrowings at acquisition. The CCFC term loan facility is secured by certain real and personal property of CCFC, primarily seven natural gas-fired power plants. One plant secured under the facility, the Jack A. Fusco Energy Center (Fusco), is subject to sale in accordance with the DOJ resolution. See Note 2 — Mergers, Acquisitions, and Dispositions for additional information. Under the terms of the loan facility, CCFC may require the consent of certain lenders to release Fusco as guarantor depending on the application of 32 Table of Contents Combined Notes to Consolidated Financial Statements (Dollars in millions, unless otherwise noted) Note 13 — Debt and Credit Agreements net sales proceeds. The term loan matures July 2030 and bears interest at SOFR plus 1.75 %. As of March 31, 2026, there was $ 2.1 billion of borrowings outstanding under the term loan. CDHI Intermediate Holdco, LLC. We acquired the CDHI facility (CDHI Revolver), a $ 1.20 billion letter of credit facility, up to $ 400 million of which can be used for revolving loans to finance construction of renewable energy projects. At acquisition, outstanding borrowings under the CDHI Revolver were $ 319 million. The CDHI Revolver is secured by substantially all of the assets of CDHI's subsidiaries in accordance with the terms of the agreement. The York Energy Centers that partially secure the CDHI Revolver are subject to sale in accordance with the DOJ resolution. Under the terms of the CDHI revolver, consent of certain lenders is required to release these plants as collateral. See Note 2 — Mergers, Acquisitions, and Dispositions for additional information. Redemptions prior to March 2026 were based on SOFR plus 2.25 %, and effective March 2026, redemptions bear interest at SOFR plus 2.375 %. The CDHI Revolver matures March 2028. In March 2026 and April 2026, the CDHI revolver's total capacity was reduced by $ 250 million and $ 568 million, respectively. As of March 31, 2026, there was $ 309 million of borrowings outstanding under the credit facility. Nova Power, LLC. We acquired the Nova Power, LLC credit agreement, which is comprised of a term loan, with $ 591 million of outstanding borrowings at acquisition, and a $ 80 million letter of credit facility. The agreement finances a portion of the cost of the development, construction, maintenance, and operation of the Nova Power battery storage project, and is secured by Nova Power's real and personal property. The credit agreement matures September 2031 and bears interest at SOFR plus 1.75 %. As of March 31, 2026, there was $ 581 million of borrowings outstanding under the credit agreement. Greenfield L.P. We acquired the Greenfield L.P. credit facility, which includes a term loan, with $ 342 million of outstanding borrowings at acquisition, and several letters of credit facilities, with issuing capacity of approximately $ 75 million. The Greenfield L.P. credit facility is secured by certain real and personal property, primarily the Greenfield Energy Center in Ontario, Canada. The credit facility matures November 2030 and bears interest at CORRA plus 1.875 %. As of March 31, 2026, there was $ 330 million of borrowings outstanding under the facility. Pin Oak Creek Energy Center LLC. We acquired Pin Oak Creek Energy Center's credit agreement pursuant with Texas Energy Fund (TEF), as lender, as administered by the Public Utility of Texas (PUCT). The loan proceeds are being used to finance eligible costs for the development (as defined in the agreement), construction, and installation of Pin Oak Creek Energy Center in Fairfield, Texas. The loan had outstanding borrowings of $ 230 million at acquisition. The loan matures October 2045 and bears interest at 3 %. As of March 31, 2026, there was $ 246 million of borrowings outstanding under the loan. Calpine Credit Agreements As a result of the acquisition, we acquired Calpine's corporate secured and unsecured letters of credit facilities with capacity totaling $ 525 million and $ 200 million, respectively, at the time of acquisition. The total capacity of assumed project and corporate credit facilities discussed above was approximately $ 2.3 billion at the time of acquisition, which is reduced by outstanding borrowings under the GPC facility and CDHI Revolver. At the time of acquisition, there were outstanding letters of credit on the assumed facilities of approximately $ 1.7 billion. See the Credit Facilities table below for additional information on credit facilities associated with these project financing arrangements. Debt Exchange Offering In December 2025, we announced that, in connection with the planned acquisition of Calpine by CEG Parent, we commenced private exchange offers and related consent solicitations with respect to certain outstanding debt of Calpine ("Exchange Offers"). Under the Exchange Offers, we solicited consents to holders of certain Calpine debt to amend the notes and the related indentures under which they were issued to eliminate substantially all of the restrictive covenants, restrictive provisions and events of default, other than payment-related and bankruptcy-related events of default. In January 2026, we completed the exchange offering, effectively replacing $ 2.3 billion of Calpine senior secured and unsecured notes with Constellation senior unsecured notes. 33 Table of Contents Combined Notes to Consolidated Financial Statements (Dollars in millions, unless otherwise noted) Note 13 — Debt and Credit Agreements The terms of the debt issuance under the exchange are as follows: Note Interest Rate Maturity Issued Amount 2029 Senior Unsecured Notes 4.625 % February 2029 $ 647 2031 Senior Unsecured Notes 5.000 % February 2031 848 2031 Senior Secured Notes 3.750 % March 2031 795 Total $ 2,290 Senior Note Issuance In January 2026, we issued senior unsecured notes totaling $ 2.75 billion, the proceeds from which were used to pay down Calpine debt assumed. The terms of the debt issuance are reflected in the Debt Issuances and Redemptions table below. Long-term Debt Summary The following table presents the outstanding long-term debt, as of March 31, 2026 and December 31, 2025: Rates Maturity Date March 31, 2026 December 31, 2025 Long-term debt Senior unsecured notes (a)(b) 3.75 % - 6.50 % 2028 - 2066 $ 10,833 $ 5,688 Tax-exempt notes (c) 4.10 % - 4.45 % 2029 - 2053 412 412 Notes payable and other 1.71 % - 8.18 % 2026 - 2035 85 53 Project finance: (b) Variable rates 4.13 % - 5.98 % 2027 - 2030 5,274 597 Fixed rates 2.29 % - 8.64 % 2031 - 2048 876 653 Total long-term debt 17,480 7,403 Unamortized debt discount and premium, net ( 16 ) ( 1 ) Unamortized fair value of debt ( 19 ) — Unamortized debt issuance costs ( 81 ) ( 60 ) Long-term debt due within one year ( 370 ) ( 92 ) Long-term debt $ 16,994 $ 7,250 ________ (a) Includes January 2026 debt issuance of $ 2.75 billion and exchanged debt of $ 2.3 billion. (b) Includes debt assumed in acquisition of Calpine. (c) The Tax-exempt notes have a maturity date of June 2029 to April 2053, and a mandatory purchase date that ranges from April 2028 to June 2029. 34 Table of Contents Combined Notes to Consolidated Financial Statements (Dollars in millions, unless otherwise noted) Note 13 — Debt and Credit Agreements Debt Issuances and Redemptions During the three months ended March 31, 2026, the following long-term debt was issued (redeemed): Type (a) Interest Rate Maturity Amount 2028 Senior Notes (b) 3.90 % January 2028 $ 900 2066 Senior Notes (b) 5.875 % January 2066 800 2031 Senior Notes (b) 4.40 % January 2031 750 2028 Floating Rate Senior Notes (b) SOFR + 0.60 % January 2028 300 Pin Oak Creek Energy Center 3.00 % October 2045 16 Energy Efficiency Project Financing (c) 5.51 % December 2030 4 RPG Nonrecourse Debt 4.11 % March 2035 ( 2 ) 2031 Unsecured Notes 5.00 % August 2031 ( 2 ) 2029 Unsecured Notes 4.625 % August 2029 ( 3 ) Antelope Valley DOE Nonrecourse Debt 2.29 % - 3.56 % January 2037 ( 6 ) Greenfield CORRA + 1.875 % November 2030 ( 7 ) Nova Power SOFR + 1.75 % March 2028 ( 10 ) Calpine Development Holdings SOFR + 2.25 % March 2028 ( 11 ) Continental Wind Nonrecourse Debt 6.00 % February 2033 ( 18 ) Geysers Power Company SOFR + 1.625 % May 2029 ( 35 ) Calpine Term Loan SOFR + 1.75 % February 2032 ( 860 ) Calpine 2028 Senior Secured Notes 4.50 % February 2028 ( 1,250 ) Calpine 2028 Senior Unsecured Notes 5.125 % March 2028 ( 1,400 ) Calpine Term Loan SOFR + 1.75 % January 2031 ( 1,650 ) Total long-term debt issued (redeemed) $ ( 2,484 ) __________ (a) Does not include debt exchange activity discussed above. (b) Relates to January 2026 debt issuance used to pay down Calpine corporate debt assumed. (c) Represents funding to install energy conservation measures. The maturity dates represent the expected date of project completion, upon which the respective customer assumes the outstanding debt. DOE Loan Guarantee In November 2025, the DOE Office of Energy Dominance Financing issued a guarantee for up to $ 1.0 billion for an unsecured loan from the Federal Financing Bank to support the restart of the Crane Clean Energy Center. The loan matures November 2055. Interest rates on the loan is fixed upon each advance at a spread of 0.375 % above U.S. Treasuries of comparable maturity. There have been no borrowings on this loan as of the date of this filing. Short-Term Borrowings We meet our short-term liquidity requirements primarily through the issuance of commercial paper. We may use our credit facility for general corporate purposes, including meeting short-term funding requirements and the issuance of letters of credit. Credit Agreements In September 2025, we amended our existing revolving credit facility (RCF) to increase the available aggregate commitment from $ 4.5 billion to $ 7.0 billion, which included incremental revolving credit commitments of $ 2.5 billion and extension of the maturity date to September 2030. The incremental commitments became available upon the closing of the Calpine acquisition in January 2026. The RCF may be drawn down in the form of loans and/or to support commercial paper and letter of credit issuances. The RCF fixed facility fee rate is 0.175 % and borrowings under the RCF bear interest at a rate based upon either the Daily Simple SOFR rate or a Term SOFR rate, plus an adder based upon our credit rating. The adders for the 35 Table of Contents Combined Notes to Consolidated Financial Statements (Dollars in millions, unless otherwise noted) Note 13 — Debt and Credit Agreements Daily Simple SOFR-based borrowings and Term SOFR borrowings are 0.075 % and 1.075 %, respectively. The letters of credit bear interest at a rate of 1.075 %. If we were to lose our investment grade credit rating, the maximum adders for Daily Simple SOFR rate borrowings and Term SOFR rate borrowings would be 1.00 % and 2.00 %, respectively. The credit agreements also require us to pay facility fees based upon the aggregate commitments. The fees vary depending upon our credit rating. Accounts Receivable Facility The Accounts Receivable Facility (the Facility) provides NER access to revolving loans from a number of financial institutions (Lenders) secured by certain customer accounts receivable. The maximum funding limit of the Facility is $ 1.5 billion and matures December 2027. Draws and repayments related to the Facility will be reflected as Proceeds from short-term borrowings and Repayments of short-term borrowings, respectively, in the Consolidated Statements of Cash Flows. Draws on the Facility bear interest at a commercial paper rate or a Daily One Month Term SOFR or Term SOFR rate, plus an adder of 0.10 % per annum. Interest is payable monthly. In January 2026, we drew on and repaid the full amount of the Facility. Subsequently, in February and March 2026, we drew on the Facility in the amounts of $ 600 million and $ 900 million, respectively. The Facility was fully drawn on and outstanding as of March 31, 2026. In April 2026, we issued a $ 1.5 billion term loan, as discussed below, and used the proceeds to repay $ 400 million of the Facility. The Facility requires the balance of eligible receivables to be maintained at or above the balance of cash proceeds received from the Lenders. To the extent the eligible receivables decrease below such balance, we are required to repay cash to the Lenders. When eligible receivables exceed cash proceeds, we have the ability to increase the cash proceeds received up to the maximum funding limit. As of March 31, 2026, the balance of our eligible receivables exceeded the cash proceeds outstanding from the Lenders. Credit Facilities Summary As of March 31, 2026 and December 31, 2025, we had the following aggregate bank commitments, credit facility borrowings and available capacity under our respective credit facilities: Facility Type Aggregate Bank Commitment Facility Draws Outstanding Letters of Credit (a) Outstanding Commercial Paper (b) Total Available Capacity March 31, 2026 Revolving Credit Facility $ 7,000 $ — $ 701 $ 1,957 $ 4,342 Bilateral and letter of credit facilities (c)(d) 4,100 — 2,632 — 1,468 Accounts Receivable Facility 1,500 1,500 — — — CDHI Revolver (d) 908 309 — — 599 Liquidity Facility 971 — 758 — 199 (e) Project Finance (d) 571 44 453 — 74 Total $ 15,050 $ 1,853 $ 4,544 $ 1,957 $ 6,682 36 Table of Contents Combined Notes to Consolidated Financial Statements (Dollars in millions, unless otherwise noted) Note 13 — Debt and Credit Agreements Facility Type Aggregate Bank Commitment Facility Draws Outstanding Letters of Credit (a) Outstanding Commercial Paper (b) Total Available Capacity December 31, 2025 Revolving Credit Facility $ 4,500 $ — $ 40 $ — $ 4,460 Bilaterals 2,350 — 1,276 — 1,074 Accounts Receivable Facility 1,500 — — — 1,500 Liquidity Facility 971 — 647 — 312 (e) Project Finance 137 — 122 — 15 Total $ 9,458 $ — $ 2,085 $ — $ 7,361 __________ (a) Excludes an additional outstanding letter of credit which was not issued under these facilities of $ 15 million as of March 31, 2026 and December 31, 2025. See Note 15 — Commitments and Contingencies for additional information. (b) Our commercial paper program is supported by the revolving credit agreement. In order to maintain our commercial paper program in the amounts indicated above, we must have a credit facility in place, at least equal to the amount of our commercial paper program. As of March 31, 2026 and December 31, 2025, the maximum program size of our commercial paper program was $ 7.0 billion and $ 4.5 billion, respectively. We do not issue commercial paper in an aggregate amount exceeding the then available capacity under our credit facility. The weighted average interest rate on commercial paper borrowings was 3.98 % as of March 31, 2026. There were no commercial paper borrowings outstanding as of December 31, 2025. (c) In February 2026, we increased the capacity to issue letters of credit by an additional $ 100 million each for two existing uncommitted bilateral facilities, and an additional $ 200 million for a third uncommitted bilateral facility. In February 2026, we initiated a new bilateral credit agreement for $ 400 million, with no maturity date. In February 2026, we entered into a $ 75 million uncommitted bilateral credit agreement. In March 2026, we increased the capacity to issue letters of credit for one committed bilateral facility by an additional $ 300 million and converted it to an uncommitted facility. In March 2026, a bilateral credit agreement initiated in March 2025 was extended for an additional two years to mature March 2028. (d) Includes corporate and project-related facilities assumed in connection with Calpine acquisition in January 2026. (e) The maximum amount of the bank commitment is not to exceed $ 971 million. The aggregate available capacity of the facility is subject to market fluctuations based on the value of U.S. Treasury Securities which determines the amount of collateral held in the trust. We may post additional collateral to borrow up to the maximum bank commitment. As of March 31, 2026 and December 31, 2025, without posting additional collateral, the actual availability of facility, prior to outstanding letters of credit was $ 957 million and $ 959 million, respectively. Short-Term Loan Agreements As of March 31, 2026 and December 31, 2025, we had the following short-term loan agreements, both of which are unsecured and reflected in Short-term borrowings in the Consolidated Balance Sheets: Month Initiated Interest Rate Maturity March 31, 2026 December 31, 2025 May 2025 (a) 1-month SOFR + 0.90 % May 2026 $ 900 $ 900 September 2025 1-month SOFR + 0.90 % September 2026 750 750 __________ (a) In April 2026, we initiated a term loan for $ 1.5 billion, the proceeds of which were used to repay the May 2025 term loan. Debt Covenants As of March 31, 2026, we are in compliance with all debt covenants. 37 Table of Contents Combined Notes to Consolidated Financial Statements (Dollars in millions, unless otherwise noted) Note 14 — Fair Value of Financial Assets and Liabilities 14. Fair Value of Financial Assets and Liabilities We measure and classify 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 we 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. Fair Value of Financial Liabilities Recorded at Amortized Cost The following table presents the carrying amounts and fair values of our long-term debt and SNF obligation as of March 31, 2026 and December 31, 2025. We have no financial liabilities classified as Level 1. The carrying amounts of the short-term liabilities as presented in the Consolidated Balance Sheets are representative of their fair value (Level 2) because of the short-term nature of these instruments. March 31, 2026 December 31, 2025 Carrying Amount Fair Value Carrying Amount Fair Value Level 2 Level 3 Total Level 2 Level 3 Total Long-Term Debt, including amounts due within one year $ 17,364 $ 13,994 $ 3,475 $ 17,469 $ 7,342 $ 6,995 $ 666 $ 7,661 SNF Obligation (a) 1,440 1,308 — 1,308 1,426 1,406 — 1,406 __________ (a) SNF Obligation is included in Other deferred credits and other liabilities in the Consolidated Balance Sheets. Valuation Techniques Used to Determine Fair Value and Net Asset Value Our valuation techniques used to measure the fair value and net asset value of the assets and liabilities are in accordance with the policies discussed in Note 17 — Fair Value of Financial Assets and Liabilities of our 2025 Form 10-K except for certain assumed variable rate project financings which are valued using a model that estimates pricing using an internal rate of return calculation and benchmark indices, which may be adjusted for company or security specific risks, resulting in these being classified as Level 3. 38 Table of Contents Combined Notes to Consolidated Financial Statements (Dollars in millions, unless otherwise noted) Note 14 — Fair Value of Financial Assets and Liabilities Recurring Fair Value Measurements The following table presents assets and liabilities measured and recorded at fair value in the Consolidated Balance Sheets on a recurring basis and their level within the fair value hierarchy as of March 31, 2026 and December 31, 2025: March 31, 2026 December 31, 2025 Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total Assets Cash equivalents (a) $ 332 $ — $ — $ 332 $ 42 $ — $ — $ 42 NDT fund investments Cash equivalents (b) 290 163 — 453 72 165 — 237 Equities 6,000 1,072 — 7,072 6,245 1,426 — 7,671 Fixed income 2,536 1,478 401 4,415 2,201 1,566 395 4,162 Private credit — — 133 133 — — 132 132 Assets measured at NAV — — — 7,421 — — — 7,194 NDT fund investments subtotal (c) 8,826 2,713 534 19,494 8,518 3,157 527 19,396 Rabbi trust investments 65 43 1 109 66 45 1 112 Investments in equities 60 — — 60 87 — — 87 Derivative assets Economic hedges 2,102 11,063 8,994 22,159 1,114 7,449 3,830 12,393 Effect of netting and allocation of collateral ( 1,940 ) ( 10,361 ) ( 5,950 ) ( 18,251 ) ( 889 ) ( 6,853 ) ( 3,256 ) ( 10,998 ) Derivative assets subtotal 162 702 3,044 3,908 225 596 574 1,395 Total assets measured at fair value 9,445 3,458 3,579 23,903 8,938 3,798 1,102 21,032 Liabilities Derivative liabilities Economic hedges ( 2,349 ) ( 11,613 ) ( 7,300 ) ( 21,262 ) ( 1,148 ) ( 8,021 ) ( 4,062 ) ( 13,231 ) Effect of netting and allocation of collateral 2,222 11,283 6,429 19,934 1,065 7,657 3,628 12,350 Derivative liabilities subtotal ( 127 ) ( 330 ) ( 871 ) ( 1,328 ) ( 83 ) ( 364 ) ( 434 ) ( 881 ) Deferred compensation obligation — ( 110 ) — ( 110 ) — ( 124 ) — ( 124 ) Total liabilities measured at fair value ( 127 ) ( 440 ) ( 871 ) ( 1,438 ) ( 83 ) ( 488 ) ( 434 ) ( 1,005 ) Total net assets $ 9,318 $ 3,018 $ 2,708 $ 22,465 $ 8,855 $ 3,310 $ 668 $ 20,027 __________ (a) CEG Parent has $ 352 million and $ 70 million of Level 1 cash equivalents as of March 31, 2026 and December 31, 2025, respectively. We exclude cash of $ 734 million and $ 3,621 million, and restricted cash of $ 70 million and $ 57 million as of March 31, 2026 and December 31, 2025, respectively. CEG Parent has excluded an additional $ 15 million of cash as of March 31, 2026 and no additional cash exclusions as of December 31, 2025. (b) Includes net liabilities of $ 231 million and $ 166 million as of March 31, 2026 and December 31, 2025, respectively, which consist of receivables related to pending securities sales, interest and dividend receivables, repurchase agreement obligations, and payables related to pending securities purchases. The repurchase agreements are generally short-term in nature with durations generally of 30 days or less. (c) Includes total NDT derivative assets and liabilities that are not material, which have notional amounts of $ 1,053 million and $ 810 million as of March 31, 2026 and December 31, 2025, respectively. The notional principal amounts provide one measure of the transaction volume outstanding as of the periods ended and do not represent the amount of our exposure to credit or market loss. 39 Table of Contents Combined Notes to Consolidated Financial Statements (Dollars in millions, unless otherwise noted) Note 14 — Fair Value of Financial Assets and Liabilities As of March 31, 2026, our NDTs have outstanding commitments to invest in private credit, private equity, and real assets of $ 493 million, $ 445 million, and $ 656 million, respectively. These commitments will be funded by our existing NDT funds. Equity Security Investments without Readily Determinable Fair Values. We hold investments without readily determinable fair values with carrying amounts of $ 113 million and $ 109 million as of March 31, 2026 and December 31, 2025, respectively. Changes in fair value, cumulative adjustments, and impairments were not material for the three months ended March 31, 2026 and the year ended December 31, 2025. Reconciliation of Level 3 Assets and Liabilities The following tables present the fair value reconciliation of Level 3 assets and liabilities measured at fair value on a recurring basis during the three months ended March 31, 2026 and 2025: Three Months Ended March 31, 2026 NDT Fund Investments Derivatives Rabbi Trust Investments Total Balance as of January 1, 2026 $ 527 $ 140 $ 1 $ 668 Contracts acquired at acquisition date — 1,290 (a) — 1,290 Total realized / unrealized gains (losses) Included in net income (loss) 2 848 (b) — 850 Included in Payables related to Regulatory Agreement Units 5 — — 5 Change in collateral — ( 102 ) — ( 102 ) Purchases — 20 — 20 Sales — ( 5 ) — ( 5 ) Transfers into Level 3 — 14 (c) — 14 Transfers out of Level 3 — 159 (c) — 159 Amortization of acquired contracts — ( 191 ) — ( 191 ) Balance as of March 31, 2026 $ 534 $ 2,173 $ 1 $ 2,708 The amount of total gains (losses) included in income attributed to the change in unrealized gains (losses) related to assets and liabilities as of March 31, 2026 $ 2 $ 568 $ — $ 570 40 Table of Contents Combined Notes to Consolidated Financial Statements (Dollars in millions, unless otherwise noted) Note 14 — Fair Value of Financial Assets and Liabilities Three Months Ended March 31, 2025 NDT Fund Investments Derivatives Rabbi Trust Investments Total Balance as of January 1, 2025 $ 502 $ ( 1 ) $ 1 $ 502 Total realized / unrealized gains (losses) Included in net income (loss) 1 ( 131 ) (b) — ( 130 ) Change in collateral — 67 — 67 Purchases — 15 — 15 Sales — ( 3 ) — ( 3 ) Settlements ( 2 ) — — ( 2 ) Transfers into Level 3 1 ( 1 ) (c) — — Transfers out of Level 3 — 36 (c) — 36 Balance as of March 31, 2025 $ 502 $ ( 18 ) $ 1 $ 485 The amount of total gains (losses) included in income attributed to the change in unrealized gains (losses) related to assets and liabilities as of March 31, 2025 $ 1 $ ( 96 ) $ — $ ( 95 ) __________ (a) Represents contracts acquired as part of the Calpine acquisition in January 2026. See Note 2 — Mergers, Acquisitions, and Dispositions for additional information. (b) Includes an addition of $ 89 million for realized losses and reduction of ($ 35 ) million for realized gains due to the settlement of derivative contracts for the three months ended March 31, 2026 and 2025, respectively. (c) Transfers into and out of Level 3 generally occur when the contract tenor becomes less and more observable, respectively, primarily due to changes in market liquidity or assumptions for certain commodity contracts. The following table presents the income statement classification of the total realized and unrealized gains (losses) included in income for Level 3 assets and liabilities measured at fair value on a recurring basis during the three months ended March 31, 2026 and 2025: Three Months Ended March 31, Operating Revenues Purchased Power and Fuel Other, net 2026 2025 2026 2025 2026 2025 Total gains (losses) included in net income $ 582 $ 38 $ 75 $ ( 169 ) $ 2 $ 1 Total unrealized gains (losses) 528 ( 8 ) 40 ( 88 ) 2 1 41 Table of Contents Combined Notes to Consolidated Financial Statements (Dollars in millions, unless otherwise noted) Note 14 — Fair Value of Financial Assets and Liabilities Derivatives The following table presents the significant inputs to the forward curve used to value these positions: Type of trade Fair Value as of March 31, 2026 Fair Value as of December 31, 2025 Valuation Technique Unobservable Input 2026 Range & Arithmetic Average 2025 Range & Arithmetic Average Level 3 Derivatives—Economic hedges (a)(b) $ 1,694 $ ( 232 ) Discounted Cash Flow Forward power price (Non-congestion) $ 2.43 - $ 181 $ 49 $ 4.77 - $ 154 $ 54 Forward power price (Congestion) $ 1.61 - $ 180 $ 52 $ 3.14 - $ 154 $ 50 Forward gas price ($ 2.93 ) - $ 21 $ 3.20 ($ 0.46 ) - $ 15 $ 3.52 Option Model Volatility percentage 10 % - 110 % 57 % 14 % - 197 % 59 % __________ (a) The valuation techniques, unobservable inputs, ranges, and arithmetic averages are the same for the asset and liability positions. (b) The fair values do not include cash collateral posted (received) on Level 3 positions of $ 479 million and $ 372 million as of March 31, 2026 and December 31, 2025, respectively. The inputs listed above, which are as of the balance sheet date, would have a direct impact on the fair values of the above instruments if they were adjusted. The significant unobservable inputs used in the fair value measurement of our commodity derivatives are forward commodity prices and for options is price volatility. Increases (decreases) in the forward commodity price in isolation would result in significantly higher (lower) fair values for long positions (contracts that give us the obligation or option to purchase a commodity), with offsetting impacts to short positions (contracts that give us the obligation or right to sell a commodity). Increases (decreases) in volatility would increase (decrease) the value for the holder of the option (writer of the option). Generally, a change in the estimate of forward commodity prices is unrelated to a change in the estimate of volatility of prices. An increase to the heat rate or renewable factors would increase the fair value accordingly. Generally, interrelationships exist between market prices of natural gas and power. As such, an increase in natural gas pricing would potentially have a similar impact on forward power markets. 15. Commitments and Contingencies Commitments Commercial Commitments. Commercial commitments as of March 31, 2026, representing commitments potentially triggered by future events, were as follows: Expiration within 2026 2027 2028 2029 2030 2031 and thereafter Total Letters of credit $ 3,402 $ 1,036 $ 120 $ — $ 1 $ — $ 4,559 Surety bonds (a) 581 261 78 — — 545 1,465 Guarantee under the Calpine AR Facility (b) 550 — — — — — 550 Total commercial commitments $ 4,533 $ 1,297 $ 198 $ — $ 1 $ 545 $ 6,574 __________ (a) Surety bonds — Guarantees issued related to contract and commercial agreements, excluding bid bonds. (b) We have guaranteed the performance of Calpine Energy Solutions, LLC to Calpine Receivables, LLC under the Calpine AR Facility. The commitment represents the gross amount of sold receivables that are currently outstanding, limited to $ 550 million per the guarantee agreement. Refer to Note 7 — Accounts Receivable for additional information. 42 Table of Contents Combined Notes to Consolidated Financial Statements (Dollars in millions, unless otherwise noted) Note 15 — Commitments and Contingencies First Priority Liens for Commodity Procurement and Risk Management Activities Following the acquisition of Calpine in January 2026, the Company has assumed additional first-priority liens on Calpine assets, which are currently subject to first priority liens under various debt agreements, as collateral under certain of our power and natural gas agreements and certain of the interest rate swaps in order to reduce the cash collateral and letters of credit that would otherwise be provided to the counterparties under such agreements. The counterparties under such agreements share the benefits of the collateral subject to such first priority liens pro rata with the lenders under various debt agreements. As of March 31, 2026, the exposure was $ 220 million under these first priority liens for power and natural gas agreements and no exposure for the interest rate swaps. Environmental Remediation Matters General. Our 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, we are generally liable for the costs of remediating environmental contamination of property currently or formerly owned by us and of property contaminated by hazardous substances generated by us. We own or lease several real estate parcels, including parcels on which our operations or the operations of others may have resulted in contamination by substances that are considered hazardous under environmental laws. In addition, we are currently involved in proceedings relating to sites where hazardous substances have been deposited and may be subject to additional proceedings in the future. Unless otherwise disclosed, we cannot reasonably estimate whether we will incur significant liabilities for additional investigation and remediation costs at these or additional sites identified by us, environmental agencies, or others. Additional costs could have a material, unfavorable impact on our consolidated financial statements. As of March 31, 2026 and December 31, 2025, we had accrued undiscounted amounts for environmental liabilities of $ 9 million in Accounts payable and accrued expenses and $ 169 million in Other deferred credits and other liabilities in the Consolidated Balance Sheets. See Note 18 — Commitments and Contingencies of our 2025 Form 10-K for additional information on environmental remediation matters. As of March 31, 2026, and through the date of filing, there have been no material changes in amounts recognized for the matters discussed in our 2025 Form 10-K. Litigation We are involved in various litigation matters that are being defended and handled in the ordinary course of business. The assessment of whether a loss is probable or reasonably possible, and whether the loss or a range of loss is estimable, often involves a series of complex judgments about future events. We maintain accruals for such losses that are probable of being incurred and subject to reasonable estimation. Management is sometimes unable to estimate an amount or range of reasonably possible loss, particularly where (1) the damages sought are indeterminate, (2) the proceedings are in the early stages, or (3) the matters involve novel or unsettled legal theories. In such cases, there is considerable uncertainty regarding the timing or ultimate resolution of such matters, including a possible eventual loss. As of March 31, 2026 and December 31, 2025, we had accrued $ 28 million and $ 15 million, respectively, in Accounts payable and accrued expenses and $ 108 million and $ 113 million, respectively, in Other deferred credits and other liabilities in the Consolidated Balance Sheets for liabilities related to litigation matters, including asbestos personal injury claims. See Note 18 — Commitments and Contingencies of our 2025 Form 10-K for additional information on asbestos personal injury claims Impacts of the February 2021 Extreme Cold Weather Event and Texas-based Generating Assets Outages. Calpine was acquired on January 7, 2026, and is party to the same ongoing litigation proceedings as Constellation. See Note 18 — Commitments and Contingencies of our 2025 Form 10-K for additional information on this matter, which is likewise representative of the ongoing proceedings as it pertains to Calpine. In March 2026, the Supreme Court of Texas denied plaintiffs’ petitions for a writ of mandamus in all five bellwether appeals. Plaintiffs have stated that they intend to seek rehearing before the Court. If the rehearing petitions in the bellwether cases are denied, the parties would return to the Multi-District-Litigation court to dispose of all of the remaining Winter Storm Uri tort claims pending against the power generator defendants. 43 Table of Contents Combined Notes to Consolidated Financial Statements (Dollars in millions, unless otherwise noted) Note 16 — Shareholders' Equity 16. Shareholders' Equity Share Repurchase Program (CEG Parent) During 2026, our Board of Directors approved a $ 4.4 billion increase relative to the remaining authorized amount to repurchase our outstanding common stock. No other repurchase plans or programs have been authorized. As of the date of this filing, we have approximately $ 4.7 billion of remaining authority for repurchases, which includes the impact of the open market repurchases, as discussed below. See Note 19 — Shareholders' Equity of our 2025 Form 10-K for additional information on our share repurchase program. During the three months ended March 31, 2026 and 2025, no open market repurchases occurred. During April and May 2026, prior to this filing, we repurchased from the open market approximately 1.2 million shares of our common stock for a total cost, inclusive of taxes and transaction costs, of $ 338 million. Capped Call Options. During the first quarter of 2025, we entered into two structured share repurchase agreements. Under these agreements, we made up-front cash payments of $ 150 million in the first quarter of 2025 in exchange for the right to receive a predetermined amount of shares of our common stock or cash at expiration. Neither option was exercised during the second and third quarter of 2025, therefore we did not receive any shares at expiration. As a result, we received our initial up-front cash payments of $ 150 million plus a nominal cash premium during the second and third quarters of 2025. The cash received restored the remaining authority available for repurchases. Changes in Accumulated Other Comprehensive Income (Loss) (All Registrants) The following tables present changes in AOCI, net of tax, by component: Three Months Ended March 31, 2026 Gains (losses) on Cash Flow Hedges Pension and OPEB Items (a) Foreign Currency Items Total Beginning balance $ 1 $ ( 2,413 ) $ ( 13 ) $ ( 2,425 ) OCI before reclassifications — ( 25 ) ( 3 ) ( 28 ) Amounts reclassified from AOCI 1 27 — 28 Net current-period OCI 1 2 ( 3 ) — Ending balance $ 2 $ ( 2,411 ) $ ( 16 ) $ ( 2,425 ) Three Months Ended March 31, 2025 Beginning balance $ ( 6 ) $ ( 2,262 ) $ ( 34 ) $ ( 2,302 ) OCI before reclassifications — ( 34 ) 8 ( 26 ) Amounts reclassified from AOCI 2 17 — 19 Net current-period OCI 2 ( 17 ) 8 ( 7 ) Ending balance $ ( 4 ) $ ( 2,279 ) $ ( 26 ) $ ( 2,309 ) __________ (a) AOCI amounts are included in the computation of net periodic pension and OPEB cost. See Note 11 — Retirement Benefits for additional information. See our Consolidated Statements of Operations and Comprehensive Income for individual components of AOCI. The following table presents income tax (expense) benefit allocated to each component of our other comprehensive income (loss): Three Months Ended March 31, 2026 2025 Pension and OPEB plans: Actuarial loss reclassified to periodic benefit cost $ ( 9 ) $ ( 6 ) Pension and OPEB plans valuation adjustment 8 12 44 Table of Contents Combined Notes to Consolidated Financial Statements (Dollars in millions, unless otherwise noted) Note 17 — Variable Interest Entities 17. Variable Interest Entities At March 31, 2026 and December 31, 2025, we consolidated several VIEs or VIE groups for which we are the primary beneficiary (see Consolidated VIEs below) and had significant interests in several other VIEs for which we do not have the power to direct the entities’ activities and, accordingly, we were not the primary beneficiary (see Unconsolidated VIEs below). Consolidated and unconsolidated VIEs are aggregated to the extent that the entities have similar risk profiles. Consolidated VIEs The table below shows the carrying amounts and classification of the consolidated VIEs’ assets and liabilities included in the consolidated financial statements as of March 31, 2026 and December 31, 2025. The assets, except as noted in the footnotes to the table below, can only be used to settle obligations of the VIEs. The liabilities, except as noted in the footnotes to the table below, are such that creditors, or beneficiaries, do not have recourse to our general credit. March 31, 2026 December 31, 2025 Cash and cash equivalents $ 69 $ 52 Restricted cash and cash equivalents 32 48 Accounts receivable, net 2,561 2,477 Inventories, net 13 13 Other current assets 34 29 Total current assets 2,709 2,619 Property, plant, and equipment, net 1,912 1,942 Other noncurrent assets 117 123 Total assets (a) $ 4,738 $ 4,684 Short-term borrowings $ 1,500 $ — Long-term debt due within one year 67 66 Accounts payable and accrued expenses 26 34 Other current liabilities 2 3 Total current liabilities 1,595 103 Long-term debt 551 578 Asset retirement obligations 234 231 Other deferred credits and other liabilities 1 2 Total deferred credits and other liabilities 235 233 Total liabilities $ 2,381 $ 914 __________ (a) Our balances include unrestricted assets for current UEC assets of $ 17 million and $ 17 million, disclosed within other current assets in the table above, and noncurrent UEC assets of $ 112 million and $ 116 million, disclosed within other noncurrent assets in the table above, as of March 31, 2026 and December 31, 2025, respectively. 45 Table of Contents Combined Notes to Consolidated Financial Statements (Dollars in millions, unless otherwise noted) Note 17 — Variable Interest Entities As of March 31, 2026 and December 31, 2025, our consolidated VIEs included the following: Consolidated VIE or VIE groups: Reason entity is a VIE: Reason we are the primary beneficiary: CRP - A collection of wind and solar project entities. We have a 51 % equity ownership in CRP. See additional discussion below. Similar structure to a limited partnership and the limited partners do not have kick-out rights with respect to the general partner. We conduct the operational activities. Bluestem Wind Energy Holdings, LLC - A Tax Equity structure which is consolidated by CRP. Similar structure to a limited partnership and the limited partners do not have kick-out rights with respect to the general partner. We conduct the operational activities. Antelope Valley - A solar generating facility, which is 100 % owned by us. Antelope Valley sells all of its output to PG&E through a PPA. The PPA contract absorbs variability through a performance guarantee. We conduct all activities. NER - A bankruptcy remote, special purpose entity which is 100 % owned by us, which purchases certain of our customer accounts receivable arising from the sale of retail electricity and gas. NER’s assets will be available first and foremost to satisfy the claims of the creditors of NER. Refer to Note 7 —Accounts Receivable for additional information on the sale of receivables. Equity capitalization is insufficient to support its operations. We conduct all activities. Unconsolidated VIEs Our variable interests in unconsolidated VIEs generally include an equity method investment and energy purchase and sale contracts. For the equity investment, the carrying amount of the investment is reflected in the Consolidated Balance Sheets in Other deferred debits and other assets, see Note 18 — Supplemental Financial Information for additional information . For the energy purchase and sale contracts (commercial agreements), the carrying amount of assets and liabilities in the Consolidated Balance Sheets that relate to our involvement with the VIEs are predominantly related to working capital accounts and generally represent the amounts owed by, or owed to, us for the deliveries associated with the current billing cycles under the commercial agreements. As of March 31, 2026 and December 31, 2025, we had significant unconsolidated variable interests in several VIEs for which we were not the primary beneficiary. These interests include certain commercial and securitization agreements. The following table presents summary information about our significant unconsolidated VIE entities: March 31, 2026 December 31, 2025 Commercial Agreement VIEs Equity Investment VIEs Total Commercial Agreement VIEs Equity Investment VIEs Total Total assets (a) $ 710 $ 575 $ 1,285 $ 711 $ — $ 711 Total liabilities (a) 97 550 647 95 — 95 Other ownership interests in VIE (a) 613 25 638 616 — 616 __________ (a) These items represent amounts on the unconsolidated VIE balance sheets, not in the Consolidated Balance Sheets. These items are included to provide information regarding the relative size of the unconsolidated VIEs. 46 Table of Contents Combined Notes to Consolidated Financial Statements (Dollars in millions, unless otherwise noted) Note 17 — Variable Interest Entities As of March 31, 2026 and December 31, 2025, the unconsolidated VIEs consist of: Unconsolidated VIE or VIE groups: Reason entity is a VIE: Reason we are not the primary beneficiary: Energy Purchase and Sale agreements - We have several energy purchase and sale agreements with generating facilities. PPA contracts that absorb variability through fixed pricing. We do not conduct the operational activities. Calpine Receivables, LLC - A bankruptcy remote entity created for the special purpose of purchasing trade accounts receivable from Calpine Energy Solutions, LLC under the Accounts Receivable Sales Program Equity capitalization is insufficient to support its operations. We do not have the power to direct activities nor affect its financial performance 18. Supplemental Financial Information Supplemental Consolidated Statements of Operations and Comprehensive Income Information The following tables provide additional information about items recorded in the Consolidated Statements of Operations and Comprehensive Income. Three Months Ended March 31, Operating revenues 2026 2025 Variable lease income $ 97 $ 52 Three Months Ended March 31, Taxes other than income taxes 2026 2025 Property $ 102 $ 72 Payroll 58 44 Gross receipts (a) 64 38 Other 5 6 Total $ 229 $ 160 __________ (a) Represent gross receipts taxes related to our retail operations. The offsetting collection of gross receipts taxes from customers is recorded in Operating revenues in the Consolidated Statements of Operations and Comprehensive Income. 47 Table of Contents Combined Notes to Consolidated Financial Statements (Dollars in millions, unless otherwise noted) Note 18 — Supplemental Financial Information Three Months Ended March 31, Other, net 2026 2025 Decommissioning-related activities: Net realized income on NDT funds (a) Regulatory Agreement Units $ 271 $ 243 Non-Regulatory Agreement Units 155 94 Net unrealized gains (losses) on NDT funds Regulatory Agreement Units ( 206 ) ( 117 ) Non-Regulatory Agreement Units ( 109 ) ( 23 ) Regulatory offset to NDT fund-related activities (b) ( 52 ) ( 103 ) Total Decommissioning-related activities 59 94 Net unrealized gains (losses) from equity investments (c) ( 27 ) ( 268 ) Other 14 20 Total $ 46 $ ( 154 ) __________ (a) Realized income includes interest, dividends and realized gains and losses on sales of NDT fund investments. (b) Includes the elimination of decommissioning-related activities and the elimination of income taxes related to all NDT fund activity for the Regulatory Agreement Units. (c) Includes unrealized gains (losses) resulting from an equity investment in a publicly traded company. We record the fair value of this investment in Other deferred debits and other assets in the Consolidated Balance Sheets based on quoted market price of the stock. Supplemental Cash Flow Information The following tables provide additional information about items recorded within our Consolidated Statements of Cash Flows. Three Months Ended March 31, Depreciation, amortization, and accretion Income statement location 2026 2025 PP&E Depreciation and amortization $ 436 $ 243 Nuclear fuel Purchased power and fuel 244 232 Amortization of acquired derivative contracts (a) Operating revenues or purchased power and fuel 228 — ARO accretion Operating and maintenance 174 158 Amortization of UECs Operating revenues or purchased power and fuel 128 2 Amortization of intangible assets, net (b) Depreciation and amortization 7 5 Other amortization Operating revenues, purchased power and fuel, or interest expense, net ( 15 ) — Total $ 1,202 $ 640 __________ (a) Related to the amortization of acquired derivative contracts from the acquisition of Calpine. (b) Primarily related to the amortization of customer relationships and trade names. 48 Table of Contents Combined Notes to Consolidated Financial Statements (Dollars in millions, unless otherwise noted) Note 18 — Supplemental Financial Information CEG Parent Constellation Three Months Ended March 31, Three Months Ended March 31, Other non-cash operating activities 2026 2025 2026 2025 Other decommissioning-related activity (a) $ ( 349 ) $ ( 74 ) $ ( 349 ) $ ( 74 ) Pension and non-pension postretirement benefit costs 50 38 50 38 Other 100 83 70 60 Total $ ( 199 ) $ 47 $ ( 229 ) $ 24 __________ (a) Includes the elimination of decommissioning-related activities for the Regulatory Agreement Units, including the elimination of operating revenues, ARO accretion, ARC amortization, investment income, and income taxes related to all NDT fund activity for these units. The following table provides a reconciliation of cash, restricted cash, and cash equivalents reported within our Consolidated Balance Sheets that sum to the total of the same amounts in the Consolidated Statements of Cash Flows. March 31, 2026 CEG Parent Constellation Cash and cash equivalents $ 800 $ 785 Restricted cash and cash equivalents 371 351 Total cash, restricted cash, and cash equivalents $ 1,171 $ 1,136 December 31, 2025 Cash and cash equivalents $ 3,641 $ 3,641 Restricted cash and cash equivalents 107 79 Total cash, restricted cash, and cash equivalents $ 3,748 $ 3,720 March 31, 2025 Cash and cash equivalents $ 1,846 $ 1,836 Restricted cash and cash equivalents 96 86 Total cash, restricted cash, and cash equivalents $ 1,942 $ 1,922 For additional information on restricted cash, see Note 1 — Basis of Presentation of our 2025 Form 10-K. Calpine's restricted cash balances, included in our balances as of March 31, 2026, align with our current policy or represent other agreements that require us to establish and maintain segregated cash accounts, the use of which is restricted, making these cash funds unavailable for general use. 49 Table of Contents Combined Notes to Consolidated Financial Statements (Dollars in millions, unless otherwise noted) Note 18 — Supplemental Financial Information Supplemental Balance Sheet Information The following tables provides additional information about material items recorded in the Consolidated Balance Sheets. Inventories, net March 31, 2026 December 31, 2025 Materials and supplies $ 2,200 $ 1,485 Natural gas, oil, and emission allowances 382 251 Total $ 2,582 $ 1,736 CEG Parent Constellation Accounts payable and accrued expenses March 31, 2026 December 31, 2025 March 31, 2026 December 31, 2025 Accounts payable $ 2,708 $ 2,813 $ 2,697 $ 2,801 Compensation-related accruals (a) 557 920 445 672 Taxes accrued (b) 484 246 483 245 Other accrued expenses 700 315 699 315 Total $ 4,449 $ 4,294 $ 4,324 $ 4,033 __________ (a) Primarily includes accrued payroll, bonuses and other incentives, vacation, and benefits. (b) Includes $ 375 million as of December 31, 2025, related to nuclear PTC that was used to offset the current tax liability. No credits were utilized in the first quarter of 2026. See Note 6 — Government Assistance for additional information on the nuclear PTC. The following table provides additional information about investments included in Other deferred debits and other assets in the Consolidated Balance Sheets. Investments March 31, 2026 December 31, 2025 Equity method investments $ 26 $ 3 Other investments: Employee benefit trusts and investments (a) 110 112 Equity investments with readily determinable fair values (b) 64 82 Equity investments without readily determinable fair values 113 109 Other available for sale debt security investments 1 1 Total $ 314 $ 307 __________ (a) Debt and equity security investments are recorded at fair market value. (b) Does not include the equity investments with readily determinable fair values that are recorded in Other current assets in the Consolidated Balance Sheets. See Note 14 — Fair Value of Financial Assets and Liabilities for additional information on investments in equities.