Constellation Energy Corp 10-K

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA Management’s Report on Internal Control Over Financial Reporting The management of Constellation Energy Corporation (CEG Parent) is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rule 13a-15(f). Internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. CEG Parent’s management assessed the effectiveness of CEG Parent’s internal control over financial reporting as of December 31, 2024. In making this assessment, management used the criteria in Internal Control—Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this assessment, CEG Parent’s management concluded that, as of December 31, 2024, CEG Parent’s internal control over financial reporting was effective. The effectiveness of CEG Parent’s internal control over financial reporting as of December 31, 2024, has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report which appears herein. February 18, 2025 Management’s Report on Internal Control Over Financial Reporting The management of Constellation Energy Generation, LLC (Constellation) is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rule 13a-15(f). Internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. Constellation’s management assessed the effectiveness of Constellation’s internal control over financial reporting as of December 31, 2024. In making this assessment, management used the criteria in Internal Control—Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this assessment, Constellation’s management concluded that, as of December 31, 2024, Constellation’s internal control over financial reporting was effective. February 18, 2025 80 Table of Contents Report of Independent Registered Public Accounting Firm To the Board of Directors and Shareholders of Constellation Energy Corporation Opinions on the Financial Statements and Internal Control over Financial Reporting We have audited the consolidated financial statements, including the related notes, as listed in the index appearing under Item 15(a)(1)(i), and the financial statement schedule listed in the index appearing under Item 15(a)(1)(ii), of Constellation Energy Corporation and its subsidiaries (the “Company”) (collectively referred to as the “consolidated financial statements”). We also have audited the Company's internal control over financial reporting as of December 31, 2024, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of the Company as of December 31, 2024 and 2023, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2024 in conformity with accounting principles generally accepted in the United States of America. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2024, based on criteria established in Internal Control - Integrated Framework (2013) issued by the COSO. Basis for Opinions The Company's management is responsible for these consolidated financial statements, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting, included in Management’s Report on Internal Control Over Financial Reporting appearing under Item 8. Our responsibility is to express opinions on the Company’s consolidated financial statements and on the Company's internal control over financial reporting based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB. We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud, and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the consolidated financial statements included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions. Definition and Limitations of Internal Control over Financial Reporting A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that: (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding 81 Table of Contents prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. Critical Audit Matters The critical audit matter communicated below is a matter arising from the current period audit of the consolidated financial statements that was communicated or required to be communicated to the audit committee and that (i) relates to accounts or disclosures that are material to the consolidated financial statements and (ii) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates. Nuclear Decommissioning Asset Retirement Obligations (ARO) Assessment As described in Notes 1 and 10 to the consolidated financial statements, the Company has a legal obligation to decommission its nuclear power plants following the permanent cessation of operations. To estimate its decommissioning obligations management uses a probability- weighted, discounted cash flow model which, on a unit-by-unit basis, considers multiple outcome scenarios that include significant estimates and assumptions, and are based on decommissioning cost studies, cost escalation rates, probabilistic cash flow models, and discount rates. Management updates its ARO annually, unless circumstances warrant more frequent updates, based on its review of updated cost studies and its annual evaluation of cost escalation factors and probabilities assigned to various scenarios. As of December 31, 2024, the nuclear decommissioning ARO was $12.2 billion. The principal considerations for our determination that performing procedures relating to the Company’s nuclear decommissioning ARO assessment is a critical audit matter are (i) the significant judgment by management when estimating its decommissioning obligations; (ii) a high degree of auditor judgment, subjectivity, and effort in performing procedures and evaluating the reasonableness of management’s discounted cash flow model and significant assumptions related to decommissioning cost studies; and (iii) the audit effort involved the use of professionals with specialized skill and knowledge. Addressing the matter involved performing procedures and evaluating audit evidence in connection with forming our overall opinion on the consolidated financial statements. These procedures included testing the effectiveness of controls relating to management’s development of the inputs, assumptions, and discounted cash flow model used in management’s ARO assessment. These procedures also included, among others (i) testing management’s process for estimating the decommissioning obligations by evaluating the appropriateness of the discounted cash flow model; (ii) testing the completeness and accuracy of data used by management; and (iii) evaluating the reasonableness of management’s significant assumptions related to decommissioning cost studies. Professionals with specialized skill and knowledge were used to assist in evaluating the results of decommissioning cost studies. /s/ PricewaterhouseCoopers LLP Baltimore, Maryland February 18, 2025 We have served as the Company's auditor since 2022. 82 Table of Contents Report of Independent Registered Public Accounting Firm To the Board of Directors and Member of Constellation Energy Generation, LLC Opinion on the Financial Statements We have audited the consolidated financial statements, including the related notes, as listed in the index appearing under Item 15(a)(2)(i), and the financial statement schedule listed in the index appearing under Item 15(a)(2)(ii), of Constellation Energy Generation, LLC and its subsidiaries (the “Company”) (collectively referred to as the “consolidated financial statements”). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2024 and 2023, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2024 in conformity with accounting principles generally accepted in the United States of America. Basis for Opinion These consolidated financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on the Company’s consolidated financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB. We conducted our audits of these consolidated financial statements in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion. Our audits included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. We believe that our audits provide a reasonable basis for our opinion. Critical Audit Matters The critical audit matter communicated below is a matter arising from the current period audit of the consolidated financial statements that was communicated or required to be communicated to the audit committee and that (i) relates to accounts or disclosures that are material to the consolidated financial statements and (ii) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates. Nuclear Decommissioning Asset Retirement Obligations (ARO) Assessment As described in Notes 1 and 10 to the consolidated financial statements, the Company has a legal obligation to decommission its nuclear power plants following the permanent cessation of operations. To estimate its decommissioning obligations management uses a probability- weighted, discounted cash flow model which, on a unit-by-unit basis, considers multiple outcome scenarios that include significant estimates and assumptions, and are based on decommissioning cost studies, cost escalation rates, probabilistic cash flow models, and discount rates. Management updates its ARO annually, unless circumstances warrant more frequent updates, based on its review of updated cost studies and its annual evaluation of cost escalation factors and probabilities assigned to various scenarios. As of December 31, 2024, the nuclear decommissioning ARO was $12.2 billion. The principal considerations for our determination that performing procedures relating to the Company’s nuclear decommissioning ARO assessment is a critical audit matter are (i) the significant judgment by management when 83 Table of Contents estimating its decommissioning obligations; (ii) a high degree of auditor judgment, subjectivity, and effort in performing procedures and evaluating the reasonableness of management’s discounted cash flow model and significant assumptions related to decommissioning cost studies; and (iii) the audit effort involved the use of professionals with specialized skill and knowledge. Addressing the matter involved performing procedures and evaluating audit evidence in connection with forming our overall opinion on the consolidated financial statements. These procedures included testing the effectiveness of controls relating to management’s development of the inputs, assumptions, and discounted cash flow model used in management’s ARO assessment. These procedures also included, among others; (i) testing management’s process for estimating the decommissioning obligations by evaluating the appropriateness of the discounted cash flow model; (ii) testing the completeness and accuracy of data used by management; and (iii) evaluating the reasonableness of management’s significant assumptions related to decommissioning cost studies. Professionals with specialized skill and knowledge were used to assist in evaluating the results of decommissioning cost studies. /s/ PricewaterhouseCoopers LLP Baltimore, Maryland February 18, 2025 We have served as the Company's auditor since 2001. 84 Table of Contents Constellation Energy Corporation and Subsidiary Companies Consolidated Statements of Operations and Comprehensive Income For the Years Ended December 31, (In millions, except per share data) 2024 2023 2022 Operating revenues Operating revenues $ 23,568 $ 24,918 $ 24,280 Operating revenues from affiliates — — 160 Total operating revenues 23,568 24,918 24,440 Operating expenses Purchased power and fuel 11,419 16,001 17,457 Purchased power and fuel from affiliates — — 5 Operating and maintenance 6,159 5,685 4,797 Operating and maintenance from affiliates — — 44 Depreciation and amortization 1,123 1,096 1,091 Taxes other than income taxes 586 553 552 Total operating expenses 19,287 23,335 23,946 Gain (loss) on sales of assets and businesses 71 27 1 Operating income (loss) 4,352 1,610 495 Other income and (deductions) Interest expense, net ( 506 ) ( 431 ) ( 250 ) Interest expense to affiliates — — ( 1 ) Other, net 670 1,268 ( 786 ) Total other income and (deductions) 164 837 ( 1,037 ) Income (loss) before income taxes 4,516 2,447 ( 542 ) Income tax (benefit) expense 774 859 ( 388 ) Equity in income (losses) of unconsolidated affiliates ( 4 ) ( 11 ) ( 13 ) Net income (loss) 3,738 1,577 ( 167 ) Net income (loss) attributable to noncontrolling interests ( 11 ) ( 46 ) ( 7 ) Net income (loss) attributable to common shareholders $ 3,749 $ 1,623 $ ( 160 ) Comprehensive income (loss), net of income taxes Net income (loss) $ 3,738 $ 1,577 $ ( 167 ) Other comprehensive income (loss), net of income taxes Pension and non-pension postretirement benefit plans: Prior service benefit reclassified to periodic benefit cost ( 4 ) ( 4 ) ( 6 ) Actuarial loss reclassified to periodic cost 75 25 101 Pension and non-pension postretirement benefit plans valuation adjustment ( 176 ) ( 453 ) 186 Unrealized gain (loss) on cash flow hedges 4 ( 1 ) ( 1 ) Unrealized gain (loss) on foreign currency translation ( 10 ) 2 ( 3 ) Other comprehensive income (loss), net of income taxes ( 111 ) ( 431 ) 277 Comprehensive income (loss) $ 3,627 $ 1,146 $ 110 Comprehensive income (loss) attributable to noncontrolling interests ( 11 ) ( 46 ) ( 7 ) Comprehensive income (loss) attributable to common shareholders $ 3,638 $ 1,192 $ 117 Average shares of common stock outstanding: Basic 315 323 328 Assumed exercise and/or distributions of stock-based awards — 1 1 Diluted 315 324 329 Earnings per average common share Basic $ 11.91 $ 5.02 $ ( 0.49 ) Diluted $ 11.89 $ 5.01 $ ( 0.49 ) See the Combined Notes to Consolidated Financial Statements 85 Table of Contents Constellation Energy Corporation and Subsidiary Companies Consolidated Statements of Cash Flows For the Years Ended December 31, (In millions) 2024 2023 2022 Cash flows from operating activities Net income (loss) $ 3,738 $ 1,577 $ ( 167 ) Adjustments to reconcile net income (loss) to net cash flows provided by (used in) operating activities Depreciation, amortization, and accretion, including nuclear fuel and energy contract amortization 2,700 2,514 2,427 Deferred income taxes and amortization of ITC 222 251 ( 643 ) Net fair value changes related to derivatives ( 1,297 ) 996 986 Net realized and unrealized (gains) losses on NDT funds ( 311 ) ( 476 ) 794 Net realized and unrealized (gains) losses on equity investments ( 11 ) ( 307 ) 13 Other non-cash operating activities ( 172 ) 18 248 Changes in assets and liabilities: Accounts receivable 688 396 ( 868 ) Receivables from and payables to affiliates, net — — 20 Inventories ( 99 ) 60 ( 228 ) Accounts payable and accrued expenses 1,121 ( 1,330 ) 1,142 Option premiums received (paid), net 216 26 ( 177 ) Collateral received (posted), net 1,803 ( 1,491 ) ( 351 ) Income taxes 296 325 162 Pension and non-pension postretirement benefit contributions ( 184 ) ( 54 ) ( 237 ) Other assets and liabilities ( 11,174 ) ( 7,806 ) ( 5,474 ) Net cash flows provided by (used in) operating activities ( 2,464 ) ( 5,301 ) ( 2,353 ) Cash flows from investing activities Capital expenditures ( 2,565 ) ( 2,422 ) ( 1,689 ) Proceeds from NDT fund sales 6,005 5,822 4,050 Investment in NDT funds ( 6,282 ) ( 6,050 ) ( 4,271 ) Collection of DPP, net 10,217 7,340 4,964 Acquisitions of assets and businesses ( 32 ) ( 1,690 ) ( 29 ) Other investing activities 85 31 79 Net cash flows provided by (used in) investing activities 7,428 3,031 3,104 Cash flows from financing activities Change in short-term borrowings ( 1,105 ) 146 257 Proceeds from short-term borrowings with maturities greater than 90 days 200 539 — Repayments of short-term borrowings with maturities greater than 90 days ( 739 ) ( 200 ) ( 1,180 ) Issuance of long-term debt 920 3,195 14 Retirement of long-term debt ( 121 ) ( 168 ) ( 1,162 ) Retirement of long-term debt to affiliate — — ( 258 ) Contributions from Exelon — — 1,750 Dividends paid on common stock ( 444 ) ( 366 ) ( 185 ) Repurchases of common stock ( 999 ) ( 992 ) — Other financing activities ( 1 ) 42 ( 35 ) Net cash flows provided by (used in) financing activities ( 2,289 ) 2,196 ( 799 ) Increase (decrease) in cash, restricted cash, and cash equivalents 2,675 ( 74 ) ( 48 ) Cash, restricted cash, and cash equivalents at beginning of period 454 528 576 Cash, restricted cash, and cash equivalents at end of period $ 3,129 $ 454 $ 528 Supplemental cash flow information Increase (decrease) in capital expenditures not paid $ 129 $ 16 $ ( 23 ) Increase (decrease) in DPP 9,045 8,097 5,166 Increase (decrease) in PP&E related to ARO update ( 1,486 ) 501 343 See the Combined Notes to Consolidated Financial Statements 86 Table of Contents Constellation Energy Corporation and Subsidiary Companies Consolidated Balance Sheets December 31, (In millions) 2024 2023 ASSETS Current assets Cash and cash equivalents $ 3,022 $ 368 Restricted cash and cash equivalents 107 86 Accounts receivable Customer accounts receivable (net of allowance for credit losses of $ 190 and $ 56 as of December 31, 2024 and 2023, respectively) 3,116 1,934 Other accounts receivable (net of allowance for credit losses of $ 6 and $ 5 as of December 31, 2024 and 2023, respectively) 602 917 Mark-to-market derivative assets 843 1,179 Inventories, net Natural gas, oil, and emission allowances 243 284 Materials and supplies 1,357 1,216 Renewable energy credits 797 660 Other 689 1,655 Total current assets 10,776 8,299 Property, plant, and equipment (net of accumulated depreciation and amortization of $ 18,088 and $ 17,423 as of December 31, 2024 and 2023, respectively) 21,235 22,116 Deferred debits and other assets Nuclear decommissioning trust funds 17,305 16,398 Investments 640 563 Goodwill 420 425 Mark-to-market derivative assets 372 995 Deferred income taxes — 52 Other 2,178 1,910 Total deferred debits and other assets 20,915 20,343 Total assets (a) $ 52,926 $ 50,758 See the Combined Notes to Consolidated Financial Statements 87 Table of Contents Constellation Energy Corporation and Subsidiary Companies Consolidated Balance Sheets December 31, (In millions) 2024 2023 LIABILITIES AND EQUITY Current liabilities Short-term borrowings $ — $ 1,644 Long-term debt due within one year 1,028 121 Accounts payable and accrued expenses 3,943 2,612 Mark-to-market derivative liabilities 467 632 Renewable energy credit obligation 1,076 972 Other 332 338 Total current liabilities 6,846 6,319 Long-term debt 7,384 7,496 Deferred credits and other liabilities Deferred income taxes and unamortized ITCs 3,331 3,209 Asset retirement obligations 12,449 14,118 Pension and non-pension postretirement benefit obligations 1,875 1,802 Spent nuclear fuel obligation 1,366 1,296 Payables related to Regulatory Agreement Units 4,518 3,688 Mark-to-market derivative liabilities 399 419 Other 1,219 1,125 Total deferred credits and other liabilities 25,157 25,657 Total liabilities (a) 39,387 39,472 Commitments and contingencies (Note 18) Shareholders' equity Common stock ( No par value, 1,000 shares authorized, 313 shares and 317 shares outstanding as of December 31, 2024 and 2023, respectively) 11,402 12,355 Retained earnings (deficit) 4,066 761 Accumulated other comprehensive income (loss), net ( 2,302 ) ( 2,191 ) Total shareholders' equity 13,166 10,925 Noncontrolling interests 373 361 Total equity 13,539 11,286 Total liabilities and shareholders' equity $ 52,926 $ 50,758 __________ (a) Our consolidated assets include $ 4,318 million and $ 3,355 million at December 31, 2024 and 2023, respectively, of certain VIEs that can only be used to settle the liabilities of the VIE. Our consolidated liabilities include $ 968 million and $ 990 million at December 31, 2024 and 2023, respectively, of certain VIEs for which the VIE creditors do not have recourse to us. See Note 21–Variable Interest Entities for additional information. See the Combined Notes to Consolidated Financial Statements 88 Table of Contents Constellation Energy Corporation and Subsidiary Companies Consolidated Statements of Changes in Equity Shareholder's Equity Noncontrolling Interests Predecessor Member's Equity (a) Total Equity (In millions, shares in thousands) Issued Shares Common Stock Retained Earnings (Deficit) Accumulated Other Comprehensive Income (Loss), net Balance, December 31, 2021 — $ — $ — $ ( 31 ) $ 395 $ 11,250 $ 11,614 Net Income (loss) from January 1, 2022 to January 31, 2022 — — — — — 151 151 Separation related adjustments — — — ( 2,006 ) 7 1,802 ( 197 ) Changes in equity of noncontrolling interest from January 1, 2022 to January 31, 2022 — — — — ( 7 ) — ( 7 ) Consummation of separation 326,664 13,203 — — — ( 13,203 ) — Net Income (loss) from February 1, 2022 to December 31, 2022 — — ( 311 ) — ( 7 ) — ( 318 ) Employee incentive plans 466 71 — — — — 71 Changes in equity of noncontrolling interest — — — — ( 34 ) — ( 34 ) Common stock dividends $ 0.1410 /common share) — — ( 185 ) — — — ( 185 ) Other comprehensive income (loss), net of income taxes — — — 277 — — 277 Balance, December 31, 2022 327,130 $ 13,274 $ ( 496 ) $ ( 1,760 ) $ 354 $ — $ 11,372 Net Income (loss) — — 1,623 — ( 46 ) — 1,577 Employee incentive plans 902 81 — — — — 81 Changes in equity of noncontrolling interest — — — — 53 — 53 Common stock dividends $ 0.2820 /common share) — — ( 366 ) — — — ( 366 ) Common stock repurchased ( 10,560 ) ( 1,000 ) — — — — ( 1,000 ) Other comprehensive income (loss), net of income taxes — — — ( 431 ) — — ( 431 ) Balance, December 31, 2023 317,472 $ 12,355 $ 761 $ ( 2,191 ) $ 361 $ — $ 11,286 Net Income (loss) — — 3,749 — ( 11 ) — 3,738 Employee incentive plans 885 56 — — — — 56 Changes in equity of noncontrolling interest — — — — 23 — 23 Common stock dividends ($ 0.3525 /common share) — — ( 444 ) — — — ( 444 ) Common stock repurchased ( 5,519 ) ( 1,009 ) — — — — ( 1,009 ) Other comprehensive income (loss), net of income taxes — — — ( 111 ) — — ( 111 ) Balance, December 31, 2024 312,838 $ 11,402 $ 4,066 $ ( 2,302 ) $ 373 $ — $ 13,539 __________ (a) Represents Constellation’s predecessor member's equity prior to the separation transaction. Upon completion of the separation, the predecessor member's equity was transferred to CEG Parent’s Common stock. See Note 1 — Basis of Presentation for additional information on the separation. See the Combined Notes to Consolidated Financial Statements 89 Table of Contents Constellation Energy Generation, LLC and Subsidiary Companies Consolidated Statements of Operations and Comprehensive Income For the Years Ended December 31, (In millions) 2024 2023 2022 Operating revenues Operating revenues $ 23,568 $ 24,918 $ 24,280 Operating revenues from affiliates — — 160 Total operating revenues 23,568 24,918 24,440 Operating expenses Purchased power and fuel 11,419 16,001 17,457 Purchased power and fuel from affiliates — — 5 Operating and maintenance 6,159 5,685 4,797 Operating and maintenance from affiliates — — 44 Depreciation and amortization 1,123 1,096 1,091 Taxes other than income taxes 586 553 552 Total operating expenses 19,287 23,335 23,946 Gain (loss) on sales of assets and businesses 71 27 1 Operating income (loss) 4,352 1,610 495 Other income and (deductions) Interest expense, net ( 506 ) ( 431 ) ( 250 ) Interest expense to affiliates — — ( 1 ) Other, net 670 1,268 ( 786 ) Total other income and (deductions) 164 837 ( 1,037 ) Income (loss) before income taxes 4,516 2,447 ( 542 ) Income tax (benefit) expense 774 859 ( 388 ) Equity in income (losses) of unconsolidated affiliates ( 4 ) ( 11 ) ( 13 ) Net income (loss) 3,738 1,577 ( 167 ) Net income (loss) attributable to noncontrolling interests ( 11 ) ( 46 ) ( 7 ) Net income (loss) attributable to membership interest $ 3,749 $ 1,623 $ ( 160 ) Comprehensive income (loss), net of income taxes Net income (loss) $ 3,738 $ 1,577 $ ( 167 ) Other comprehensive income (loss), net of income taxes Pension and non-pension postretirement benefit plans: Prior service benefit reclassified to periodic benefit cost ( 4 ) ( 4 ) ( 6 ) Actuarial loss reclassified to periodic benefit cost 75 25 101 Pension and non-pension postretirement benefit plans valuation adjustment ( 176 ) ( 453 ) 186 Unrealized gain (loss) on cash flow hedges 4 ( 1 ) ( 1 ) Unrealized gain (loss) on foreign currency translation ( 10 ) 2 ( 3 ) Other comprehensive income (loss), net of income taxes ( 111 ) ( 431 ) 277 Comprehensive income (loss) 3,627 1,146 110 Comprehensive income (loss) attributable to noncontrolling interests ( 11 ) ( 46 ) ( 7 ) Comprehensive income (loss) attributable to membership interest $ 3,638 $ 1,192 $ 117 See the Combined Notes to Consolidated Financial Statements 90 Table of Contents Constellation Energy Generation, LLC and Subsidiary Companies Consolidated Statements of Cash Flows For the Years Ended December 31, (In millions) 2024 2023 2022 Cash flows from operating activities Net income (loss) $ 3,738 $ 1,577 $ ( 167 ) Adjustments to reconcile net income (loss) to net cash flows provided by (used in) operating activities Depreciation, amortization, and accretion, including nuclear fuel and energy contract amortization 2,700 2,514 2,427 Deferred income taxes and amortization of ITCs 222 251 ( 643 ) Net fair value changes related to derivatives ( 1,297 ) 996 986 Net realized and unrealized (gains) losses on NDT funds ( 311 ) ( 476 ) 794 Net realized and unrealized (gains) losses on equity investments ( 11 ) ( 307 ) 13 Other non-cash operating activities ( 218 ) ( 44 ) 199 Changes in assets and liabilities: Accounts receivable 697 389 ( 855 ) Receivables from and payables to affiliates, net 231 73 65 Inventories ( 99 ) 60 ( 228 ) Accounts payable and accrued expenses 1,116 ( 1,330 ) 1,112 Option premiums received (paid), net 216 26 ( 177 ) Collateral received (posted), net 1,803 ( 1,491 ) ( 351 ) Income taxes 296 325 162 Pension and non-pension postretirement benefit contributions ( 184 ) ( 54 ) ( 237 ) Other assets and liabilities ( 11,369 ) ( 7,897 ) ( 5,540 ) Net cash flows provided by (used in) operating activities ( 2,470 ) ( 5,388 ) ( 2,440 ) Cash flows from investing activities Capital expenditures ( 2,565 ) ( 2,422 ) ( 1,689 ) Proceeds from NDT fund sales 6,005 5,822 4,050 Investment in NDT funds ( 6,282 ) ( 6,050 ) ( 4,271 ) Collection of DPP, net 10,217 7,340 4,964 Acquisitions of assets and businesses ( 32 ) ( 1,690 ) ( 29 ) Other investing activities 85 31 79 Net cash flows provided by (used in) investing activities 7,428 3,031 3,104 Cash flows from financing activities Change in short-term borrowings ( 1,105 ) 146 257 Proceeds from short-term borrowings with maturities greater than 90 days 200 539 — Repayments of short-term borrowings with maturities greater than 90 days ( 739 ) ( 200 ) ( 1,180 ) Issuance of long-term debt 920 3,195 14 Retirement of long-term debt ( 121 ) ( 168 ) ( 1,162 ) Retirement of long-term debt to affiliate — — ( 258 ) Distributions to member ( 1,441 ) ( 1,239 ) ( 185 ) Contributions from Exelon — — 1,750 Contributions from member — — 82 Other financing activities 3 23 ( 57 ) Net cash flows provided by (used in) financing activities ( 2,283 ) 2,296 ( 739 ) Increase (decrease) in cash, restricted cash, and cash equivalents 2,675 ( 61 ) ( 75 ) Cash, restricted cash, and cash equivalents at beginning of period 440 501 576 Cash, restricted cash, and cash equivalents at end of period $ 3,115 $ 440 $ 501 Supplemental cash flow information Increase (decrease) in capital expenditures not paid $ 129 $ 16 $ ( 23 ) Increase (decrease) in DPP 9,045 8,097 5,166 Increase (decrease) in PP&E related to ARO update ( 1,486 ) 501 343 See the Combined Notes to Consolidated Financial Statements 91 Table of Contents Constellation Energy Generation, LLC and Subsidiary Companies Consolidated Balance Sheets December 31, (In millions) 2024 2023 ASSETS Current assets Cash and cash equivalents $ 3,018 $ 366 Restricted cash and cash equivalents 97 74 Accounts receivable Customer accounts receivable (net of allowance for credit losses of $ 190 and $ 56 as of December 31, 2024 and 2023, respectively) 3,116 1,934 Other accounts receivable (net of allowance for credit losses of $ 6 and $ 5 as of December 31, 2024 and 2023, respectively) 587 911 Mark-to-market derivative assets 843 1,179 Inventories, net Natural gas, oil, and emission allowance 243 284 Materials and supplies 1,357 1,216 Renewable energy credits 797 660 Other 689 1,655 Total current assets 10,747 8,279 Property, plant, and equipment (net of accumulated depreciation and amortization of $ 18,088 and $ 17,423 as of December 31, 2024 and 2023, respectively) 21,235 22,116 Deferred debits and other assets Nuclear decommissioning trust funds 17,305 16,398 Investments 640 563 Goodwill 420 425 Mark-to-market derivative assets 372 995 Deferred income taxes — 52 Other 2,174 1,910 Total deferred debits and other assets 20,911 20,343 Total assets (a) $ 52,893 $ 50,738 See the Combined Notes to Consolidated Financial Statements 92 Table of Contents Constellation Energy Generation, LLC and Subsidiary Companies Consolidated Balance Sheets December 31, (In millions) 2024 2023 LIABILITIES AND EQUITY Current liabilities Short-term borrowings $ — $ 1,644 Long-term debt due within one year 1,028 121 Accounts payable and accrued expenses 3,696 2,486 Payables to affiliates 349 118 Mark-to-market derivative liabilities 467 632 Renewable energy credit obligation 1,076 972 Other 328 338 Total current liabilities 6,944 6,311 Long-term debt 7,384 7,496 Deferred credits and other liabilities Deferred income taxes and unamortized ITCs 3,331 3,209 Asset retirement obligations 12,449 14,118 Pension and non-pension postretirement benefit obligations 1,875 1,802 Spent nuclear fuel obligation 1,366 1,296 Payables related to Regulatory Agreement Units 4,518 3,688 Mark-to-market derivative liabilities 399 419 Other 1,044 1,025 Total deferred credits and other liabilities 24,982 25,557 Total liabilities (a) 39,310 39,364 Commitments and contingencies (Note 18) Equity Member’s equity Membership interest 10,538 11,537 Undistributed earnings (deficit) 4,974 1,667 Accumulated other comprehensive income (loss), net ( 2,302 ) ( 2,191 ) Total member’s equity 13,210 11,013 Noncontrolling interests 373 361 Total equity 13,583 11,374 Total liabilities and equity $ 52,893 $ 50,738 __________ (a) Our consolidated assets include $ 4,318 million and $ 3,355 million as of December 31, 2024 and 2023, respectively, of certain VIEs that can only be used to settle the liabilities of the VIE. Our consolidated liabilities include $ 968 million and $ 990 million as of December 31, 2024 and 2023, respectively, of certain VIEs for which the VIE creditors do not have recourse to us. See Note 21–Variable Interest Entities for additional information. See the Combined Notes to Consolidated Financial Statements 93 Table of Contents Constellation Energy Generation, LLC and Subsidiary Companies Consolidated Statements of Changes in Equity Member’s Equity Noncontrolling Interests Total Equity (In millions) Membership Interest Undistributed Earnings (Deficit) Accumulated Other Comprehensive Income (Loss), net Balance, December 31, 2021 $ 10,482 $ 768 $ ( 31 ) $ 395 $ 11,614 Net Income (loss) — ( 160 ) — ( 7 ) ( 167 ) Separation-related adjustments 1,844 ( 11 ) ( 2,006 ) 7 ( 166 ) Changes in equity of noncontrolling interests — — — ( 41 ) ( 41 ) Distribution to member — ( 185 ) — — ( 185 ) Contribution from member 82 — — — 82 Other comprehensive income (loss), net of income taxes — — 277 — 277 Balance, December 31, 2022 $ 12,408 $ 412 $ ( 1,760 ) $ 354 $ 11,414 Net Income (loss) — 1,623 — ( 46 ) 1,577 Changes in equity of noncontrolling interests — — — 53 53 Distribution to member ( 871 ) ( 368 ) — — ( 1,239 ) Other comprehensive income (loss), net of income taxes — — ( 431 ) — ( 431 ) Balance, December 31, 2023 $ 11,537 $ 1,667 $ ( 2,191 ) $ 361 $ 11,374 Net Income (loss) — 3,749 — ( 11 ) 3,738 Changes in equity of noncontrolling interest — — — 23 23 Distribution to member ( 999 ) ( 442 ) — — ( 1,441 ) Other comprehensive income (loss), net of income taxes — — ( 111 ) — ( 111 ) Balance, December 31, 2024 $ 10,538 $ 4,974 $ ( 2,302 ) $ 373 $ 13,583 See the Combined Notes to Consolidated Financial Statements 94 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 carbon-free energy and a supplier of energy products and services. Our generating capacity includes primarily nuclear, wind, solar, natural gas, and hydroelectric assets. 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 five reportable segments: Mid-Atlantic, Midwest, New York, ERCOT and Other Power Regions. Basis of Presentation Constellation Energy Corporation (“CEG Parent” or the “Company”), a Pennsylvania corporation, was formed for the purpose of separation of Constellation Energy Generation, LLC (“Constellation”, formerly Exelon Generation Company, LLC) and its subsidiaries from its predecessor parent company, Exelon Corporation (“Exelon”), into an independent, publicly traded company. On February 1, 2022, the separation was completed by distributing all the outstanding shares of the Company’s common stock, on a pro rata basis to the holders of its predecessor’s common stock, with the Company holding all the interests in Constellation previously held by Exelon (the "Separation"). Constellation has been an individual registrant since 2002 with the registration of its public debt securities under the Securities Act. Prior to the Separation, Constellation historically filed consolidated financial statements as an individual registrant to reflect its financial position and operating results as a stand-alone, wholly owned subsidiary of Exelon. The accompanying Consolidated Financial Statements have been prepared in accordance with GAAP for annual financial statements and in accordance with the instructions to Form 10-K and Regulation S-X promulgated by the SEC. The Consolidated Financial Statements include the accounts of our subsidiaries and all intercompany transactions have been eliminat ed. CEG Parent's prior period financial statements have been adjusted to reflect the balances of Constellation in accordance with applicable guidance. 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. We own 100% of our significant consolidated subsidiaries, either directly or indirectly, except for certain consolidated VIEs. The remaining interests in the consolidated VIEs are included in noncontrolling interests on the Consolidated Balance Sheets. See Note 21 — Variable Interest Entities for additional information on consolidated VIEs. We consolidate the accounts of entities in which we have a controlling financial interest, after the elimination of intercompany transactions. Where we do not have a controlling financial interest in an entity, proportionate consolidation, equity method accounting or accounting for investments in equity securities with or without readily determinable fair value is applied. We proportionately consolidate our undivided ownership interest in jointly-owned electric plants. Under proportionate consolidation, we separately record our proportionate share of the assets, liabilities, revenues and expenses related to the undivided interest in the asset. See Note 9 — Jointly-Owned Electric Plants for additional information on application of proportionate consolidation. We apply equity method accounting when we have a significant influence over an investee through an ownership in equity, which generally approximates to a 20% to 50% voting interest. We apply equity method accounting to certain investments and joint ventures. Under equity method accounting, we report our interest in the entity as an investment and our percentage share of the earnings from the entity as single line items in our consolidated financial statements. We use accounting for investments in equity securities with or without readily determinable fair values if we lack a significant influence, which generally results when we hold less than 20% of the common stock of an entity. Under accounting for investments in equity securities with readily determinable fair values, the investments are reported based on quoted prices in active markets and realized and unrealized gains and losses are included in earnings. Under accounting for investments in equity securities without readily determinable fair values, the investments are reported at cost, adjusted for changes from observable transactions for identical or similar investments of the same issuer, less impairment, and changes in measurement are reported in earnings. 95 Table of Contents Combined Notes to Consolidated Financial Statements (Dollars in millions, unless otherwise noted) Note 1 — Basis of Presentation Separation from Exelon Prior to completion of the separation, our financial statements include certain transactions with affiliates of Exelon, which are disclosed as related party transactions. After February 1, 2022, all transactions with Exelon or its affiliates are no longer related party transactions. In order to govern the ongoing relationships with Exelon after the separation, and to facilitate an orderly transition, we entered into several agreements with Exelon, including the following: • Separation Agreement – sets forth the principal actions to be taken in connection with the separation, including the transfer of assets and assumption of liabilities and establishes certain rights and obligations between us following the distribution • TSA – governs all matters relating to the provision of services between us and Exelon on a transitional basis, in addition to providing us with certain services. The services include support for information technology, accounting, finance, human resources, security, and various other administrative and operational services (the TSA ended in June 2024) • Employee Matters Agreement (EMA) – addresses certain employment, compensation and benefits matters, including the allocation of employees between us and Exelon and the allocation and treatment of certain assets and liabilities relating to our employees and former employees • TMA – governs the respective rights, responsibilities, and obligations between us and Exelon with respect to all tax matters (excluding employee-related taxes covered under the EMA) Pursuant to the Separation Agreement, we received a cash contribution of $ 1.75 billion from Exelon on January 31, 2022, the proceeds of which were used to settle $ 258 million of an intercompany loan from Exelon and $ 200 million of short-term debt outstanding prior to separation, in addition to a $ 192 million contribution to our pension plans. The amounts Exelon billed us for services pursuant to the TSA were not material in 2024 and $ 151 million and $ 266 million for the years ended December 31, 2023, and 2022, respectively. The amounts we billed Exelon for services pursuant to the TSA were not material to the periods presented. Use of Estimates The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the amounts reported in the financial statements and accompanying notes. Areas in which significant estimates have been made include, but are not limited to, the accounting for nuclear decommissioning costs and other AROs, pension and OPEB plans, inventory reserves, allowance for credit losses, long-lived asset valuations and impairment assessments, derivative instruments, goodwill, unamortized energy contracts, fixed asset depreciation, environmental costs and other loss contingencies, taxes and unbilled energy revenues. Actual results could differ from those estimates. Revenues Operating Revenues. Our operating revenues generally consist of revenues from contracts with customers involving competitive sales of power, natural gas, and other energy-related products and sustainable solutions. We recognize revenue from contracts with customers to depict the transfer of goods or services to customers in an amount that we expect to be entitled to in exchange for those goods or services. At the end of each reporting period, we accrue an estimate for the unbilled amount of power and natural gas delivered or services provided to customers. Commodity Derivatives. Derivative instruments are generally recorded at fair value with subsequent changes in fair value recognized as realized and unrealized revenue or expense. The classification of revenue or expense is based on the intent of the transaction. See Note 15 — Derivative Financial Instruments for additional information. Taxes Directly Imposed on Revenue-Producing Transactions. We collect certain taxes from customers such as sales and gross receipts taxes, along with other taxes, surcharges and fees, that are levied by state or local 96 Table of Contents Combined Notes to Consolidated Financial Statements (Dollars in millions, unless otherwise noted) Note 1 — Basis of Presentation governments on the sale or distribution of electricity and natural gas and any taxable energy-related products and services. Some of these taxes are imposed on the customer, but paid by us, while others are imposed on us. Where these taxes are imposed on the customer, such as sales taxes, they are reported on a net basis in revenues. However, where these taxes are imposed on us, such as gross receipts taxes, they are reported on a gross basis in revenue and expense in the Consolidated Statements of Operations and Comprehensive Income. Government Assistance. As a result of the enactment of the IRA, we qualify for certain federal government incentives through eligible activities. These incentives include both refundable and transferable tax credits. The current U.S. GAAP framework does not address the receipt of government assistance by for-profit entities. We account for this government assistance by analogy to International Accounting Standard (IAS) 20, Accounting for Government Grants and Disclosure of Government Assistance, and recognize the benefits when there is reasonable assurance that we will comply with the required conditions and that the benefits will be received. We believe the reasonable assurance term as used in IAS 20 is analogous to the term probable as defined under GAAP related to accounting for contingencies. See Note 6 — Government Assistance for additional information. Leases We recognize a ROU asset and lease liability for operating leases with a term of greater than one year. Operating lease ROU assets are included in Other deferred debits and other assets and operating lease liabilities are included in Other current liabilities and Other deferred credits and other liabilities on the Consolidated Balance Sheets. The ROU asset is measured as the sum of (1) the present value of all remaining fixed and in-substance fixed payments using the rate implicit in the lease whenever that is readily determinable or our incremental borrowing rate, (2) any lease payments made at or before the commencement date (less any lease incentives received) and (3) any initial direct costs incurred. The lease liability is measured the same as the ROU asset, but excludes any payments made before the commencement date and initial direct costs incurred. Lease terms include options to extend or terminate the lease if it is reasonably certain they will be exercised. We include non-lease components for most asset classes, which are service-related costs that are not integral to the use of the asset, in the measurement of the ROU asset and lease liability. Expense for operating leases and leases with a term of one year or less is recognized on a straight-line basis over the term of the lease, unless another systematic and rational basis is more representative of the derivation of benefit from use of the leased property. Variable lease payments are recognized in the period in which the related obligation is incurred and consist primarily of payments for purchases of electricity under contracted generation that are based on the electricity produced by those generating assets. Operating lease expense and variable lease payments are recorded to Purchased power and fuel expense for contracted generation or Operating and maintenance expense for all other lease agreements in the Consolidated Statements of Operations and Comprehensive Income. Income from operating leases, including subleases, is recognized on a straight-line basis over the term of the lease, unless another systematic and rational basis is more representative of the pattern in which income is earned over the term of the lease. Variable lease payments are recognized in the period in which the related obligation is performed and consist primarily of payments received from sales of electricity under contracted generation that are based on the electricity produced by those generating assets. Operating lease income and variable lease payments are recorded to Operating revenues in the Consolidated Statements of Operations and Comprehensive Income. Our operating leases consist primarily of contracted generation, real estate including office buildings, and vehicles and equipment. We generally account for contracted generation in which the generating asset is not renewable as a lease if the customer has dispatch rights and obtains substantially all the economic benefits. We generally do not account for contracted generation in which the generating asset is renewable as a lease if the customer does not design the generating asset. We account for land right arrangements that provide for exclusive use as leases while shared use land arrangements are generally not leases. See Note 11 — Leases for additional information. Income Taxes Deferred federal and state income taxes are recorded on temporary differences between the book and tax basis of assets and liabilities and for tax benefits carried forward. ITCs have been deferred in the Consolidated Balance Sheets and are recognized in book income over the life of the related property. We account for uncertain 97 Table of Contents Combined Notes to Consolidated Financial Statements (Dollars in millions, unless otherwise noted) Note 1 — Basis of Presentation income tax positions using a benefit recognition model with a two-step approach; a more-likely-than-not recognition criterion and a measurement approach that measures the position as the largest amount of tax benefit that is greater than 50% likely of being realized upon ultimate settlement. If it is not more-likely-than-not that the benefit of the tax position will be sustained on its technical merits, no benefit is recorded. Uncertain tax positions that relate only to timing of when an item is included on a tax return are considered to have met the recognition threshold. We recognize accrued interest related to unrecognized tax benefits in Interest expense, net or Other, net (interest income) and recognize penalties related to unrecognized tax benefits in Other, net in the Consolidated Statements of Operations and Comprehensive Income. Cash and Cash Equivalents We consider investments purchased with an original maturity of three months or less to be cash equivalents. Restricted Cash and Cash Equivalents Restricted cash and cash equivalents represent funds that are restricted to satisfy designated current liabilities. As of December 31, 2024 and 2023, restricted cash and cash equivalents primarily represented the payment of medical, dental, vision, and long-term disability benefits and project-specific nonrecourse financing structures for debt service and financing of operations of the underlying entities. See Note 16 — Debt and Credit Agreements and Note 22 — Supplemental Financial Information for additional information. Allowance for Credit Losses on Accounts Receivables The allowance for credit losses reflects our best estimate of losses on the customers' accounts receivable balances based on historical experience, current information, and reasonable and supportable forecasts. The allowance for credit losses for our retail and wholesale customers is based on accounts receivable aging historical experience coupled with specific identification through a credit monitoring process, which considers current conditions and forward-looking information such as industry trends, macroeconomic factors, changes in the regulatory environment, external credit ratings, publicly available news, payment status, payment history, and the exercise of collateral calls. When a wholesale customer’s risk characteristics are no longer aligned with the pooled population, we use specific identification to develop an allowance for credit losses. Adjustments to the allowance for credit losses are recorded in Operating and maintenance expense in the Consolidated Statements of Operations and Comprehensive Income. We have certain non-customer receivables in Current Assets and Other deferred debits and other assets which primarily are with governmental agencies. The allowance for credit losses related to these receivables is not material. We monitor these balances and will record an allowance if there are indicators of a decline in credit quality. Variable Interest Entities We account for our investments in and arrangements with VIEs based on the following specific requirements: • qualitative assessment of factors determinant in whether we have a controlling financial interest, • ongoing reconsideration of this assessment, and • where we consolidate a VIE (as primary beneficiary), disclosure of (1) the assets of the consolidated VIE, if they can be used to only settle specific obligations of the consolidated VIE, and (2) the liabilities of a consolidated VIE for which creditors do not have recourse to the general credit of the primary beneficiary. See Note 21 — Variable Interest Entities for additional information. Inventories Inventory is recorded at the lower of weighted average cost or net realizable value. Provisions are recorded for excess and obsolete inventory. Natural gas, oil, and emission allowances are generally included in Inventory when purchased and are expensed to Purchased power and fuel expense when consumed. Materials and supplies are generally included in Inventory when purchased and are expensed to Operating and maintenance, or capitalized to Property, plant and equipment, as appropriate, when installed or used. 98 Table of Contents Combined Notes to Consolidated Financial Statements (Dollars in millions, unless otherwise noted) Note 1 — Basis of Presentation Debt and Equity Security Investments Debt and Equity Investments within NDT funds. We have debt and equity securities held in our NDT funds which are measured and recorded at fair value. Realized and unrealized gains and losses, net of trust level taxes, on our NDT funds associated with the Regulatory Agreement Units are offset in Noncurrent payables related to Regulatory Agreement Units. Realized and unrealized gains and losses, net of trust level taxes, on our NDT funds associated with the Non-Regulatory Agreement Units are included in Other, net in the Consolidated Statements of Operations and Comprehensive Income. For equity securities without readily determinable fair values, we have elected to use the NAV for qualifying investments as a practical expedient to determine the fair values. Our NDT funds are classified as current or noncurrent assets, depending on the timing of the decommissioning activities and expected payment of income taxes on trust earnings. See Note 10 — Asset Retirement Obligations and Note 17 — Fair Value of Financial Assets and Liabilities for additional information. Equity Security Investments with Readily Determinable Fair Values. We have certain equity securities with readily determinable fair values. Realized and unrealized gains and losses are included in Other, net in the Consolidated Statements of Operations and Comprehensive Income. See Note 17 — Fair Value of Financial Assets and Liabilities for additional information. Equity Security Investments without Readily Determinable Fair Values. We have certain equity securities without readily determinable fair values. We have elected to use the measurement alternative to measure these investments, defined as cost adjusted for changes from observable transactions for identical or similar investments of the same issuer, less impairment. Changes in measurement, are reported in Other, net in the Consolidated Statements of Operations and Comprehensive Income. See Note 17 — Fair Value of Financial Assets and Liabilities for additional information. Property, Plant and Equipment Property, plant and equipment is recorded at acquired cost. Acquired cost includes construction-related direct labor and material costs. When appropriate, acquired cost also includes capitalized interest. Costs associated with nuclear outages and planned major maintenance activities, are expensed to Operating and maintenance expense or capitalized to Property, plant, and equipment based on the nature of the activities in the period incurred. The cost of repairs and maintenance and minor replacements of property is charged to Operating and maintenance expense in the Consolidated Statements of Operations and Comprehensive Income as incurred. Upon retirement, the cost of property is generally charged to accumulated depreciation in accordance with the composite and group methods of depreciation. Upon replacement of an asset, the costs to remove the asset, net of salvage, are capitalized to gross plant when incurred as part of the cost of the newly installed asset and recorded to depreciation expense over the life of the new asset. Removal costs, net of salvage, incurred for property that will not be replaced is charged to Operating and maintenance expense as incurred. Certain assets follow the unitary method of depreciation and recognize gains and losses in the period of replacement or retirement. These gains and losses are recorded in Operating and maintenance expense in the Consolidated Statements of Operations and Comprehensive Income. Capitalized Software. Certain costs, such as design, coding, and testing incurred during the application development stage of software projects that are internally developed or purchased for operational use are capitalized in Property, plant and equipment in the Consolidated Balance Sheets. Similar costs incurred for cloud-based solutions treated as service arrangements are capitalized in Other current assets and Deferred debits and other assets in the Consolidated Balance Sheets. Such capitalized amounts are amortized ratably over the expected lives of the projects when they become operational, generally not to exceed five years . Capitalized Interest. During construction, we capitalize the costs of debt funds. Most projects will use a debt rate calculated using the general corporate debt pool. In some cases, projects are specifically financed and use a project specific debt rate, which is excluded from the general corporate debt pool. Capitalization of debt funds is recorded as a charge to construction work in progress and as a non-cash credit to interest expense. See Note 8 — Property, Plant, and Equipment, Note 9 — Jointly-Owned Electric Plants and Note 22 — Supplemental Financial Information for additional information. 99 Table of Contents Combined Notes to Consolidated Financial Statements (Dollars in millions, unless otherwise noted) Note 1 — Basis of Presentation Nuclear Fuel The cost of nuclear fuel is capitalized in Property, plant and equipment and charged to Purchased power and fuel using the unit-of-production method. Any potential future SNF disposal fees will also be expensed through Purchased power and fuel expense. Additionally, certain on-site SNF storage costs are being reimbursed by the DOE since a DOE (or government-owned) long-term storage facility has not been completed. See Note 18 — Commitments and Contingencies for additional information regarding the cost of SNF storage and disposal. Depreciation and Amortization Except for the amortization of nuclear fuel, depreciation, inclusive of ARC, is generally recorded over the estimated useful lives of property, plant and equipment on a straight-line basis using the group, composite or unitary methods of depreciation. Two methods of depreciating multiple asset groups exist: the group method and the composite method. The group method is typically for groups of assets that are largely homogenous and have approximately the same useful lives. The composite method is used when the assets are heterogeneous and have different lives. Under both methods, a reporting entity depreciates the assets over the average life of the assets in the group. The estimated useful lives are based on a combination of depreciation studies, historical retirements, site licenses and management estimates of operating costs and expected future energy market conditions. See Note 8 — Property, Plant, and Equipment for additional information regarding depreciation, and Note 22 — Supplemental Financial Information for additional information regarding amortization expense of nuclear fuel. Asset Retirement Obligations We estimate and recognize a liability for our legal obligation to perform asset retirement activities even though the timing and/or methods of settlement may be conditional on future events. We generally update our nuclear decommissioning ARO annually, unless circumstances warrant more frequent updates, based on our annual evaluation of cost escalation factors and probabilities assigned to the multiple outcome scenarios within our probability-weighted discounted cash flow models. Our multiple outcome scenarios are generally based on decommissioning cost studies which are updated, on a rotational basis, for each of our nuclear units at least every five years, unless circumstances warrant more frequent updates. AROs are accreted throughout each year to reflect the time value of money for these present value obligations through a charge to Operating and maintenance expense in the Consolidated Statements of Operations and Comprehensive Income for Non-Regulatory Agreement Units and through an offsetting decrease in noncurrent payables related to Regulatory Agreement Units. See Note 10 — Asset Retirement Obligations for additional information. Accounting Implications of the Regulatory Agreement Units Based on the requirements of the ICC, PAPUC, and PUCT that dictate our obligations related to the shortfall or excess of NDT funds necessary for decommissioning the former ComEd, former PECO, and STP units, decommissioning-related activities net of applicable taxes, including realized and unrealized gains and losses on the NDT funds, depreciation of the ARC, and accretion of the decommissioning obligation are generally offset in the Consolidated Statements of Operations and Comprehensive Income and are recorded as noncurrent payables in the Consolidated Balance Sheets (within Payables related to Regulatory Agreement Units). See Note 10 — Asset Retirement Obligations for additional information. Asset Impairments Long-Lived Assets. We regularly monitor and evaluate the carrying value of long-lived assets or asset groups for recoverability whenever events or changes in circumstances indicate that the carrying value of those assets may not be recoverable. Indicators of impairment may include a deteriorating business climate, including, but not limited to, declines in energy prices, condition of the asset, or plans to dispose of a long-lived asset significantly before the end of its useful life. We determine if long-lived assets or asset groups are potentially impaired by comparing the undiscounted expected future cash flows to the carrying value when indicators of impairment exist. When the undiscounted cash flow analysis indicates a long-lived asset or asset group may not be recoverable, the amount of the impairment loss is determined by measuring the excess of the carrying amount of the long-lived asset or asset group over its fair value. Impairment losses are recorded in Operating and maintenance expense in the Consolidated Statements of Operations and Comprehensive Income. 100 Table of Contents Combined Notes to Consolidated Financial Statements (Dollars in millions, unless otherwise noted) Note 1 — Basis of Presentation Goodwill. Goodwill represents the excess of the purchase price paid over the estimated fair value of the net assets acquired and liabilities assumed in the acquisition of a business. Goodwill is not amortized, but is tested for impairment at least annually or on an interim basis if an event occurs or circumstances change that would more likely than not reduce the fair value of a reporting unit below its carrying value. See Note 2 — Mergers, Acquisitions, and Dispositions and Note 12 — Intangible Assets for additional information. Equity Method Investments. We regularly monitor and evaluate equity method investments to determine whether they are impaired. An impairment is recorded when the investment has experienced a decline in value that is other-than-temporary in nature. Additionally, if the entity in which we hold an investment recognizes an impairment loss, we would record the proportionate share of that impairment loss and evaluate the investment for an other-than-temporary decline in value. These impairment losses are recorded in Equity in income (losses) of unconsolidated affiliates in the Consolidated Statements of Operations and Comprehensive Income. Equity Security Investments. Equity investments with readily determinable fair values are measured and recorded at fair value with any changes in fair value recorded in Other, net in the Consolidated Statements of Operations and Comprehensive Income. For equity securities without readily determinable fair values, we have elected to use the measurement alternative to measure these investments, defined as cost adjusted for changes from observable transactions for identical or similar investments of the same issuer, less impairment. Investments in equity securities without readily determinable fair values are qualitatively assessed for impairment each reporting period. If it is determined that the equity security is impaired, an impairment loss will be recognized in Other, net in the Consolidated Statements of Operations and Comprehensive Income in the amount by which the security’s carrying amount exceeds its fair value. Derivative Financial Instruments All derivatives are recognized on the balance sheet at their fair value unless they qualify for certain exceptions, including NPNS. For derivatives intended to serve as economic hedges, changes in fair value are recognized in earnings each period. Amounts classified in earnings are included in Operating revenues, Purchased power and fuel, or Interest expense in the Consolidated Statements of Operations and Comprehensive Income based on the activity the transaction is economically hedging. While most of the derivatives serve as economic hedges, there are also derivatives entered into for proprietary trading purposes, subject to our RMP, and changes in the fair value of those derivatives are recorded in Operating revenues in the Consolidated Statements of Operations and Comprehensive Income. Cash inflows and outflows related to derivative instruments are included as a component of operating, investing, or financing cash flows in the Consolidated Statements of Cash Flows, depending on the nature of each transaction. As part of the energy marketing business, we enter contracts to buy and sell energy to meet the requirements of our customers. These contracts include short-term and long-term commitments to purchase and sell energy and energy-related products in the energy markets with the intent and ability to deliver or take delivery of the underlying physical commodity. NPNS are contracts where physical delivery is probable, quantities are expected to be used or sold in the normal course of business over a reasonable period and will not be financially settled. Revenues and expenses on derivative contracts that qualify, and are designated, as NPNS are recognized when the underlying physical transaction is completed. While these contracts are considered derivative financial instruments, they are not required to be recorded at fair value. See Note 15 — Derivative Financial Instruments for additional information. Retirement Benefits Effective upon separation, we sponsor defined benefit pension and OPEB plans as described in Note 14 — Retirement Benefits. The plan obligations and costs of providing benefits under these plans were measured upon separation as of February 1, 2022 and are remeasured annually as of year-end. The measurements involved various factors, assumptions, and accounting elections. The impact of assumption changes or experiences different from that assumed on pension and OPEB obligations is recognized over time, not immediately in the Consolidated Statements of Operations and Comprehensive Income. For defined benefit pension plans, gains or losses exceeding the greater of ten percent of the PBO or the MRV of plan assets are amortized over the expected average remaining service period of plan participants. For OPEB plans, gains or losses exceeding the greater of ten percent of the APBO or the MRV of plan assets are amortized over the average future remaining lifetime of the current inactive population. 101 Table of Contents Combined Notes to Consolidated Financial Statements (Dollars in millions, unless otherwise noted) Note 1 — Basis of Presentation We separately report the pension and OPEB service cost and non-service cost (credit) components of net periodic benefit costs (credits) for all plans in our Consolidated Statements of Operations and Comprehensive Income. Effective February 1, 2022 , the service cost component remains in Operating and maintenance expense and Property, plant, and equipment, net (where criteria for capitalization of direct labor has been met) while the non-service cost (credit) components are included in Other, net, in accordance with single employer plan accounting. Renewable Energy Credits RECs are included in Renewable energy credits in the Consolidated Balance Sheets. Purchased RECs are recorded at cost on the date they are purchased and internally generated RECs are recognized at a zero-cost basis when generated. The cost of RECs purchased on a stand-alone basis is based on the transaction price, while the cost of RECs acquired through PPAs represents the relative fair value at contract inception. Generally, revenue for RECs that are sold to a counterparty under a contract that specifically identifies a power plant are recognized at a point in time when the power is produced. This includes both bundled and unbundled REC sales. Otherwise, the revenue is recognized upon physical transfer of the REC to the customer. 2. Mergers, Acquisitions, and Dispositions Proposed Acquisition of Calpine Corporation On January 10, 2025, we entered an agreement and plan of merger (Merger Agreement) with Calpine Corporation (Calpine) under which we will acquire all the outstanding equity interests of Calpine in a cash and stock transaction. Calpine owns and operates a generation fleet of natural gas, geothermal, battery storage, and solar assets with over 27 GWs of generation capacity, in addition to a competitive retail electric supplier platform serving approximately 60 TWhs of load annually. This acquisition is complementary to and aligns strategically with our existing business operations and provides both increased scale and meaningful market diversification. The merger consideration at closing will consist of an aggregate of 50 million newly issued shares of our common stock, no par value, and $ 4.5 billion in cash. We will also assume approximately $ 12.7 billion of Calpine’s outstanding debt. We expect to fund the cash portion of the transaction through a combination of cash on hand and cash flow generated by Calpine in the period between signing and closing of the transaction (that will be assumed at closing). Per the terms of the Merger Agreement, consummation of the transaction is to occur by December 31, 2025 (which date may be automatically extended to June 1, 2026, as further provided in the Merger Agreement). The Merger Agreement also provides for certain termination rights, and under certain specified circumstances, we may be required to pay Calpine a termination fee of $ 500 million. Completion of the transaction is conditioned upon review of the transaction by the DOJ, the expiration or termination of the applicable waiting period under the HSR Act, and approval by the FERC, NYPSC, and PUCT, in addition to other regulatory bodies, and is subject to other customary closing conditions. In connection with certain of the regulatory approvals required for the transaction, the companies will propose to divest certain generating assets located in PJM, the only market where there is a material overlap of generation owned by both companies. The transaction will be accounted for as a business combination using the acquisition method of accounting and we will record the fair value of the assets acquired and liabilities assumed as of the acquisition date. To the extent that the consideration transferred is greater than the fair value of the net assets acquired, goodwill will be recorded. To the extent the fair value of the net assets acquired is greater than the consideration transferred, a bargain purchase gain will be recorded. Through December 31, 2024, fees incurred as part of the acquisition were not material to the Consolidated Statements of Operations and Comprehensive Income. Acquisition of Joint Ownership in South Texas Project In November 2023, we completed the acquisition of NRG South Texas LP (renamed and converted as Constellation South Texas, LLC), which owns a 44 % undivided ownership interest in the jointly-owned STP, a 2,645 MW, dual-unit nuclear plant located in Bay City, Texas. The consideration transferred was $ 1.66 billion. Other owners include City Public Service Board of San Antonio (CPS, 40 %) and the City of Austin, Texas (Austin 102 Table of Contents Combined Notes to Consolidated Financial Statements (Dollars in millions, unless otherwise noted) Note 2 — Mergers, Acquisitions, and Dispositions Energy, 16 %). This acquisition is complementary to and aligned strategically with our existing clean energy business operations. The acquisition was accounted for using the acquisition method of accounting in accordance with authoritative guidance, which requires, among other things, the assets acquired and liabilities assumed to be recognized at their respective fair value as of the acquisition date. The excess of the purchase price over fair value of our proportionate share of the assets acquired and liabilities assumed was recorded to goodwill. The goodwill recognized is primarily driven by the opportunity for continued operations through 80 years and the value of STP’s carbon-free energy that is not fully reflected by the markets. The goodwill amount has been assigned entirely to the ERCOT operating segment. See Note 12 — Intangible Assets for additional information. The total amount of goodwill is expected to be deductible for tax purposes over the tax amortization period. The fair values of STP’s assets and liabilities were determined based on significant estimates and assumptions that are judgmental in nature, including projected future cash flows (including timing), discount rates reflecting risk inherent in the future cash flows and future power and fuel market prices. The following table summarizes the final acquisition-date fair value of the consideration transferred and the assets and liabilities assumed for the STP acquisition: Cash paid for purchase price $ 1,657 Identifiable assets acquired and liabilities assumed Property, plant, and equipment 1,254 Nuclear decommissioning trust funds 869 Inventories, net 47 Other long-term assets 40 Other current assets 11 Total assets 2,221 Asset retirement obligations 429 Payables related to Regulatory Agreement Units 376 Deferred income taxes and unamortized investment tax credits 65 Accounts payable and accrued expenses 42 Pension and OPEB obligations 25 Other long-term liabilities 5 Total liabilities 942 Total net identifiable assets, at fair value 1,279 Goodwill $ 378 The operating revenues and results of operations for STP have been included in the Consolidated Statements of Operations and Comprehensive Income from the date of acquisition and were not material for the year ended December 31, 2023. The pro forma effects of this acquisition are not significant to our reported results for any periods presented. Accordingly, no pro forma financial information has been presented herein. In July 2023, NRG Energy, Inc. (NRG) accepted service of a lawsuit filed by the City of San Antonio, Texas, acting by and through CPS, in the 130th District Court of Matagorda County, Texas against NRG and certain of its subsidiaries, claiming the existence of a right of first refusal that applies to the transaction contemplated between us and NRG. In July 2023, we intervened in the lawsuit and Austin Energy also intervened in the lawsuit claiming a similar right of first refusal. Per the terms of the Equity Purchase Agreement, NRG made representations that no right of first refusal applied to the transaction contemplated between us. In May 2024, we executed a settlement agreement with all parties (CPS/City of San Antonio, Austin, and NRG), resolving all litigation involving our purchase of the ownership interest in STP. The terms of the settlement include us selling a 2 % ownership interest in STP to CPS at the same price and terms that we paid NRG for our 44 % 103 Table of Contents Combined Notes to Consolidated Financial Statements (Dollars in millions, unless otherwise noted) Note 2 — Mergers, Acquisitions, and Dispositions interest, subject to regulatory approvals from the NRC and the Public Utility Commission of Texas. Pursuant to the settlement, CPS and Austin filed Notices of Dismissal with Prejudice with the Court, which ends the litigation, and likewise withdrew their pending objections to the sale with the NRC. As a result of the settlement, we have reflected assets and liabilities associated with a 2 % undivided ownership interest in STP as held for sale. The held for sale amounts are included in the Other current assets and Other current liabilities balances in the Consolidated Balance Sheets as of December 31, 2024. Closing is expected to occur within the first half of 2025. Upon closing of the sale, we and CPS will each own a 42 % interest in STP, and Austin’s interest will remain at 16 %. The terms of settlement are not expected to have a material impact on our consolidated financial statements. 3. Regulatory Matters The following matters below discuss the status of our material regulatory and legislative proceedings. New England Regulatory Matters Mystic Units 8 and 9 Cost of Service Agreement. In December 2018, FERC issued an order accepting a cost of service agreement for Mystic Units 8 and 9 for the period between June 1, 2022 to May 31, 2024. The agreement was intended to preserve the two gas-fired electric generating units for the two-year period while allowing the Mystic units to recover their costs of operating, including a substantial portion of the costs associated with the adjacent EMT. Upon the expiration of the agreement on May 31, 2024, the two generating units retired. The Mystic COS requires an annual process whereby we identify and support our projected costs under the agreement and/or true-up previous projections to the actual costs incurred. Interested parties then have the opportunity to challenge our filings. In September 2022, we made our second of the five annual filings at FERC. In December 2023, FERC issued an order setting for settlement/hearing certain components of the second annual filing, including the issue of Mystic’s recovery of historical rate base costs. In July 2024, the active parties to the proceeding reached a settlement in principle to resolve the second annual filing. The same parties then proceeded to reach a global settlement that would resolve all outstanding matters related to the Mystic COS, including the fourth and fifth annual filing proceedings. A global settlement was filed with FERC in November 2024, and FERC approved the settlement in January 2025. The global settlement does not have a material financial impact on our consolidated financial statements. Federal Regulatory Matters Inflation Reduction Act of 2022. In August 2022, President Biden signed into law the IRA, which, among other things, includes federal tax credits, certain of which are transferable or fully refundable, for a number of clean energy technologies including existing nuclear plants (45U). In addition, the IRA provides for a federal tax credit for technology-neutral clean energy production (45Y PTC or 48E ITC). We believe the planned restart of Crane and our planned nuclear uprates will be eligible for these credits. The nuclear PTC recognizes the contributions of carbon-free nuclear power by providing a federal tax credit of up to $15/MWh, subject to phase-out, beginning in 2024 and continuing through 2032. The nuclear PTC includes adjustments for inflation. The PTC benefiting existing nuclear plants included in the IRA continues to be the subject of additional guidance issued from the U.S. Treasury and IRS. Operating License Renewals Conowingo Hydroelectric Project. In 2012, we submitted an application to FERC for a new license for the Conowingo Hydroelectric Project (Conowingo). In connection with our efforts to obtain a water quality certification pursuant to Section 401 of the Clean Water Act (401 Certification) from MDE for Conowingo, we had been working with MDE and other stakeholders to resolve water quality licensing issues, including: (1) water quality, (2) fish habitat, and (3) sediment. In 2019, we and MDE filed with FERC a Joint Offer of Settlement (Offer of Settlement) that would resolve all outstanding issues relating to the 401 Certification. FERC subsequently issued a new 50-year license for Conowingo, effective March 1, 2021. Several environmental groups appealed FERC’s ruling to the U.S. Court of Appeals for the D.C. Circuit. The court of appeals issued a decision vacating FERC’s decision to grant Conowingo its license renewal and sending the matter back to FERC for further proceedings. Upon issuance of 104 Table of Contents Combined Notes to Consolidated Financial Statements (Dollars in millions, unless otherwise noted) Note 3 — Regulatory Matters the mandate from the U.S. Court of Appeals for the D.C. Circuit, we began operating under an annual license, which renews automatically, containing the same terms as the license that was in effect prior to the 2021 FERC order. MDE informed us that as a result of the U.S. Court of Appeals decision, they would be resuming their administrative reconsideration of the 401 Certification. In response to the procedure outlined by the MDE, supplemental briefs on the 401 Certification were filed by the Lower Susquehanna Riverkeeper Association and Waterkeepers Chesapeake (jointly) and us. In addition, we filed a supplemental reply brief. We are currently participating in mediation with MDE and the parties that sought reconsideration of the 401 Certification. We are unable to further predict the outcome of this proceeding at this time. Depreciation provisions continue to assume operation through 2071 given our expectation that a 50-year license will be issued. Peach Bottom Units 2 and 3. In March 2020, the NRC approved a second 20-year license renewal for Peach Bottom Units 2 and 3. As a result, Peach Bottom Units 2 and 3 were granted the authority to operate through 2053 and 2054, respectively. Notwithstanding its 2020 approval, in February 2022, the NRC took action to modify Peach Bottom's subsequently renewed licenses in response to a request for hearing that the NRC had not previously adjudicated. In its February 2022 decision, the NRC reversed itself and concluded that the previous environmental review required by the National Environmental Policy Act (NEPA) for the Peach Bottom subsequently renewed licenses was incomplete because it did not adequately address environmental impacts resulting from renewing the units’ licenses for an additional 20 years. As a result, the NRC undertook a rulemaking to modify its regulations and guidance to specifically address environmental impacts during the period of subsequent license renewal. In addition, the NRC modified the expiration dates for the Peach Bottom licenses from 2053 and 2054 to 2033 and 2034, respectively, pending the completion of the updated NEPA analysis. The NRC approved final revisions to the rule in May 2024, and we have begun working with the NRC to close out the remaining environmental issues and restore the Peach Bottom expiration dates to 2053 and 2054. Depreciation provisions and ARO assumed retirement dates continue to assume Peach Bottom Units 2 and 3 will operate through 2053 and 2054, respectively, given our expectation that the previously approved expiration dates will be restored. 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. The performance obligations, revenue recognition, and payment terms associated with these sources of revenue are further discussed in the table below. There are no significant financing components for these sources of revenue. Unless otherwise noted, for each of the significant revenue categories and related performance obligations described below, we have the right to consideration from the customer in an amount that corresponds directly with the value transferred to the customer for the performance completed to date. Therefore, we generally recognize revenue in the amount for which we have the right to invoice the customer. As a result, there are generally no significant judgments used in determining or allocating the transaction price. 105 Table of Contents Combined Notes to Consolidated Financial Statements (Dollars in millions, unless otherwise noted) Note 4 — Revenue from Contracts with Customers Revenue Source Description Performance Obligation Timing of Revenue Recognition Payment Terms Power Sales Sales of power and other energy-related products to wholesale and retail customers through our customer-facing business Various, including the delivery of power (generally delivered over time) and other energy-related products such as capacity (generally delivered over time), CMCs, ZECs, RECs or other ancillary services (generally delivered at a point in time) Concurrently as power is generated for bundled power sale contracts (a) Generally within the month following delivery to the customer Natural Gas Sales Sales of natural gas to wholesale and retail customers through our customer-facing business Various, including the delivery of natural gas (generally delivered overtime) and sustainable natural gas attributes (generally delivered at a point in time) Over time as the natural gas is delivered to the customer Generally within the month following delivery to the customer Other Products and Services Sales of other energy-related products and sustainable solutions, such as long-term construction and installation of energy efficiency assets and new power generating facilities, primarily to C&I customers Construction and/or installation of the asset for the customer Revenues and associated costs are recognized throughout the contract term using an input method to measure progress towards completion (b) Generally within 30 or 45 days from the invoice date __________ (a) Certain contracts may contain limits on the total amount of revenue we are able to collect over the entire term of the contract. In such cases, we estimate the total consideration expected to be received over the term of the contract net of the constraint and allocate the expected consideration to the performance obligations in the contract such that revenue is recognized ratably over the term of the entire contract as the performance obligations are satisfied. (b) The method recognizes revenue based on the various inputs used to satisfy the performance obligation, such as costs incurred and total labor hours expended. The total amount of revenue that will be recognized is based on the agreed upon contractually-stated amount. The average contract term for these projects is approximately 18 months. We incur incremental costs in order to execute certain retail power and gas sales contracts. These costs, which primarily relate to retail broker fees and sales commissions, are capitalized when incurred as contract acquisition costs and generally amortized over the corresponding term of the contract. These capitalized costs and related amortization were not material as of and for the years ended December 31, 2024 and 2023. Contract Balances Contract Assets We record contract assets for the revenue recognized on the construction and installation of energy efficiency assets and new power generating facilities before we have an unconditional right to bill for and receive the consideration from the customer. These contract assets are subsequently reclassified to receivables when the right to payment becomes unconditional. We record contract assets and contract receivables in Other current assets and Customer accounts receivable, net, respectively, in the Consolidated Balance Sheets. 106 Table of Contents Combined Notes to Consolidated Financial Statements (Dollars in millions, unless otherwise noted) Note 4 — Revenue from Contracts with Customers The following table provides a rollforward of the contract assets reflected in the Consolidated Balance Sheets: 2024 2023 Beginning balance as of January 1 $ 82 $ 130 Amounts reclassified to receivables ( 95 ) ( 127 ) Revenues recognized 103 79 Ending balance as of December 31 $ 90 $ 82 Contract Liabilities We record contract liabilities when consideration is received or due prior to the satisfaction of the performance obligations. We record contract liabilities in Other current liabilities and Other deferred credits and other liabilities in the Consolidated Balance Sheets. These contract liabilities primarily relate to upfront consideration received or due for equipment service plans, the Mystic COS, and the Illinois ZEC program. The Mystic COS, which ended in May 2024, included upfront consideration received that differs from the recognized earnings over the cost of the service period. The Illinois ZEC program introduces an annual cap on the total consideration to be received by us for each delivery period. The ZEC price is established on a per MWh of production basis with a maximum annual cap for total compensation to be received for each planning year (June through May), while requiring delivery of all ZECs produced by our participating facilities during each delivery period. ZECs delivered to Illinois utilities in excess of the annual cost cap may be paid in subsequent years if the payments do not exceed the prescribed annual cost cap for that year. The contract liability balance as of December 31, 2024 primarily related to equipment service plans. The balance as of December 31, 2023 primarily related to equipment services plans and the Mystic COS. The following table provides a rollforward of the contract liabilities reflected in the Consolidated Balance Sheets: 2024 2023 2022 Beginning balance as of January 1 $ 40 $ 47 $ 75 Consideration received 120 331 339 Revenues recognized ( 127 ) ( 338 ) ( 367 ) Ending balance as of December 31 $ 33 $ 40 $ 47 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 December 31, 2024. This disclosure only includes contracts for which the total consideration is fixed and determinable at contract inception. The average contract term varies by customer type and commodity but ranges from one month to several years. This disclosure excludes mark-to-market derivatives and certain power and gas sales contracts which contain variable volumes and/or variable pricing. 2025 2026 2027 2028 2029 and thereafter Total Remaining performance obligations $ 251 $ 211 $ 147 $ 95 $ 211 $ 915 Transaction Price Allocated to Previously Satisfied Performance Obligations Our Clinton and Quad Cities units contract with certain utilities in Illinois that require delivery of all ZECs produced during each planning year (June through May), with total compensation limited by an annual cap for each planning year designed to limit the cost of ZECs to each utility's customers. ZECs delivered that, if paid, would result in the annual cap being exceeded may be paid in subsequent years at the vintage year price as long as the payments would not exceed the annual cap in the year paid. In each planning year since the program commenced in June 2017, we delivered ZECs to the utilities in excess of the annual compensation cap. The ZEC price and annual compensation cap effective for each planning year are administratively determined by the IPA. For the June 2023 through May 2024 planning year, the ZEC price was established at $0.30 per ZEC, subject to an annual cap of $224 million. ZECs generated and delivered during the planning year did not exceed 107 Table of Contents Combined Notes to Consolidated Financial Statements (Dollars in millions, unless otherwise noted) Note 4 — Revenue from Contracts with Customers the annual cap, providing capacity to compensate for ZECs delivered in prior planning years in excess of the compensation cap. In 2023, we recognized $ 218 million of revenue as a receivable for ZECs delivered in prior planning years, with payment received in the third quarter of 2024. For the June 2024 through May 2025 planning year, the ZEC price has been established at $9.38 per ZEC, subject to an annual cap of $222 million. Revenue recognized in 2024 for ZECs delivered in prior planning years was not material. 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. See Note 5 — Segment Information for the presentation of revenue disaggregation. 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 five reportable segments consisting of the Mid-Atlantic, Midwest, New York, ERCOT, and all other power regions referred to collectively as “Other Power Regions.” 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 five 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. • 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. 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 or 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 regional level. Our operating revenues include all sales to third parties as well as government assistance. Purchased power and fuel expenses are considered the 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 or included in the regional reportable segment amounts. These activities include wholesale 108 Table of Contents Combined Notes to Consolidated Financial Statements (Dollars in millions, unless otherwise noted) Note 5 — Segment Information and retail sales of natural gas, 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 mark-to-market 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 regional 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 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 disaggregation of revenues reflects our power sales by geographic region. 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 reportable segments for the years ended December 31, 2024, 2023, and 2022. 2024 Revenues from contracts with customers Other revenues (a) Total Operating revenues Total Purchased power and fuel expenses Total RNF Mid-Atlantic $ 5,429 $ 93 $ 5,522 $ ( 2,442 ) $ 3,080 Midwest 3,848 957 4,805 ( 1,603 ) 3,202 New York 1,937 113 2,050 ( 597 ) 1,453 ERCOT 1,053 497 1,550 ( 503 ) 1,047 Other Power Regions 4,749 757 5,506 ( 4,238 ) 1,268 Total Reportable Segments 17,016 2,417 19,433 ( 9,383 ) 10,050 Other (b) 1,948 2,187 4,135 ( 2,036 ) 2,099 Total Consolidated Results $ 18,964 $ 4,604 $ 23,568 $ ( 11,419 ) $ 12,149 109 Table of Contents Combined Notes to Consolidated Financial Statements (Dollars in millions, unless otherwise noted) Note 5 — Segment Information 2023 Revenues from contracts with customers Other revenues (a) Total Operating revenues Total Purchased power and fuel expenses Total RNF Mid-Atlantic $ 5,453 $ ( 315 ) $ 5,138 $ ( 2,214 ) $ 2,924 Midwest 4,846 ( 188 ) 4,658 ( 1,403 ) 3,255 New York 1,910 111 2,021 ( 770 ) 1,251 ERCOT 1,232 114 1,346 ( 764 ) 582 Other Power Regions 4,956 895 5,851 ( 4,611 ) 1,240 Total Reportable Segments 18,397 617 19,014 ( 9,762 ) 9,252 Other (b) 2,444 3,460 5,904 ( 6,239 ) ( 335 ) Total Consolidated Results $ 20,841 $ 4,077 $ 24,918 $ ( 16,001 ) $ 8,917 2022 Revenues from contracts with customers Other revenues (a) Total Operating revenues Total Purchased power and fuel expenses Total RNF Mid-Atlantic $ 5,264 $ ( 100 ) $ 5,164 $ ( 3,026 ) $ 2,138 Midwest 5,164 ( 514 ) 4,650 ( 1,886 ) 2,764 New York 2,004 ( 409 ) 1,595 ( 528 ) 1,067 ERCOT 954 589 1,543 ( 1,136 ) 407 Other Power Regions 5,035 1,697 6,732 ( 5,811 ) 921 Total Reportable Segments 18,421 1,263 19,684 ( 12,387 ) 7,297 Other (b) 3,150 1,606 4,756 ( 5,075 ) ( 319 ) Total Consolidated Results (c) $ 21,571 $ 2,869 $ 24,440 $ ( 17,462 ) $ 6,978 __________ (a) Includes revenues from nuclear PTCs beginning in 2024 as well as derivatives and leases. Intersegment activity in all periods presented is not material. (b) Represents revenue activities not allocated to a region. See text above for a description of included activities, includes unrealized mark-to-market gains of $ 316 million and $ 1,399 million and losses of $ 1,188 million, and natural gas revenues from contracts with customers of $ 1,429 million, $ 1,859 million, and $ 2,559 million, for the years ended December 31, 2024, 2023, and 2022, respectively. (c) Includes all wholesale and retail electric sales to third parties and affiliated sales to Exelon's utility subsidiaries prior to the separation on February 1, 2022. See Note 24 — Related Party Transactions for additional information. 110 Table of Contents Combined Notes to Consolidated Financial Statements (Dollars in millions, unless otherwise noted) Note 6 — Government Assistance 6. Government Assistance Beginning in 2024, our existing nuclear units are eligible for a PTC extending through 2032. The nuclear PTC provides a transferable credit up to $15 per MWh (a base credit of $3 per MWh with a five times multiplier provided certain prevailing wage requirements are met) and is subject to phase-out when annual gross receipts are between $25.00 per MWh and $43.75 per MWh. We have evaluated and expect to meet the annual prevailing wage requirements at all our nuclear units and are eligible for the five times multiplier. Both the amount of the PTC and the gross receipts thresholds adjust for inflation after 2024 through the duration of the program based on the GDP price deflator for the preceding calendar year. The benefits of the PTC may be realized through a credit against our federal income taxes or transferred via sale to an unrelated party. For the year ended December 31, 2024, our Consolidated Statements of Operations and Comprehensive Income include a nuclear PTC benefit of approximately $ 2,080 million in Operating revenues. Our estimate required the exercise of judgment in determining the amount of nuclear PTC expected for each of our nuclear units. The nuclear PTC continues to be the subject of additional guidance, which may be issued from the U.S. Treasury and IRS sometime in 2025, and may materially impact the total amount of the benefits we receive. Nuclear PTCs are initially recorded within Other deferred debits and other assets within the Consolidated Balance Sheets and reclassified as a reduction to Accounts payable and accrued expenses when used to reduce our federal income tax payable, or an increase in Cash and cash equivalents or Other current assets when sold, depending on the specific payment terms of each contract. In 2024, we executed agreements for the sale of $ 1,750 million of nuclear PTCs to unaffiliated third parties at a nominal discount, with approximately $ 1,570 million of cash proceeds received upon sale (included within Cash flows from operating activities in our Consolidated Statements of Cash Flows) and approximately $ 95 million to be received in the first quarter of 2025. As of December 31, 2024, our Consolidated Balance Sheets reflect approximately $ 185 million of estimated nuclear PTCs within Other deferred debits and other assets , $ 95 million within Other current assets , and a reduction to Accounts payable and accrued expenses of $ 150 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 December 31, 2024, we have recognized approximately $ 1,030 million of estimated payables within Accounts payable and accrued expenses or as offsets to Customer accounts receivable in our Consolidated Balance Sheets associated with programs requiring refunds or pass through of the nuclear PTC. We recognized a reduction to net operating revenue of approximately $ 50 million (pre-tax) for the year ended December 31, 2024 associated with these programs in our Consolidated Statements of Operations and Comprehensive Income. As with the actual amount of the PTC earned, any change resulting from additional guidance received may materially impact amounts due under state-sponsored programs. 7. Accounts Receivable Allowance for Credit Losses on Accounts Receivable The following table presents the rollforward of allowance for credit losses on Customer accounts receivable, which does not include any allowance related to the sales of customer accounts receivable disclosed below. Allowance for credit losses on Other accounts receivable was not material as of the balance sheet dates. Balance as of December 31, 2023 (a) 56 Plus: Current period provision for expected credit losses 17 Less: Write-offs, net of recoveries (b) 21 Plus: Facility amendment impact (c) 138 Balance as of December 31, 2024 $ 190 __________ (a) 2023 beginning balance and activity were not material. (b) Recoveries were not material. (c) Impact as a result of the December 2024 Facility amendment. See below for details. 111 Table of Contents Combined Notes to Consolidated Financial Statements (Dollars in millions, unless otherwise noted) Note 7 — Accounts Receivable Unbilled Customer Revenue We recorded $ 1,109 million and $ 372 million of unbilled customer revenues in Customer accounts receivables, net in the Consolidated Balance Sheets as of December 31, 2024 and 2023, respectively. Sales of Customer Accounts Receivable In 2020, NER, a bankruptcy remote, special purpose entity, which is wholly owned by us, entered a revolving accounts receivable financing arrangement with a number of financial institutions and a commercial paper conduit (Purchasers) to sell certain customer accounts receivables (Facility). On December 31, 2024, we amended the Facility. We will no longer sell receivables to the Purchasers and all outstanding receivables were assigned back to us. Prior to the amendment, the maximum funding limit of the Facility was $ 1.1 billion. Under the Facility's prior terms, NER sold eligible short-term customer accounts receivable to the Purchasers in exchange for cash and subordinated interest. The transfers were reported as sales of receivables in the consolidated financial statements. The subordinated interest in collections upon the receivables sold to the Purchasers was referred to as the DPP, which was reflected in Other current assets in the Consolidated Balance Sheets prior to the amendment. See Note 16 — Debt and Credit Agreements for terms of the amended Facility. The following table summarizes the impact of the sale of certain receivables: As of December 31, 2024 2023 Derecognized receivables transferred at fair value $ — $ 1,516 Less: Cash proceeds received — 300 DPP (a) $ — $ 1,216 _________ (a) As a result of the Facility amendment, DPP of $ 1,529 million was reclassified to Customer accounts receivable as of December 31, 2024. For the Years Ended December 31, 2024 2023 2022 Loss on sale of receivables (a) $ 61 $ 75 $ 69 _________ (a) Reflected in Operating and maintenance expense in the Consolidated Statements of Operations and Comprehensive Income. This represents the amount by which the accounts receivable sold into the Facility are discounted, limited to credit losses. For the Years Ended December 31, 2024 2023 2022 Proceeds from new transfers (a) $ 1,688 $ 3,649 $ 6,108 Cash collections received on DPP (b) 10,517 8,140 4,764 Cash collections reinvested in the Facility $ 12,205 $ 11,789 $ 10,872 _________ (a) Customer accounts receivable sold into the Facility were $ 12,262 million, $ 11,746 million, and $ 11,274 million for the years ended December 31, 2024, 2023, and 2022, respectively. (b) Does not include the $ 300 million and $ 800 million net cash payments to the Purchasers in 2024 and 2023, respectively, or the $ 200 million net cash proceeds received from the Purchases in 2022. We recognized the cash proceeds received upon sale in Cash flows from operating activities within the Changes in Other assets and liabilities line in the Consolidated Statements of Cash Flows, which were ($ 10,574 ) million, ($ 8,097 ) million, and ($ 5,166 ) million for the years ended December 31, 2024, 2023, and 2022, respectively. The collection and reinvestment of DPP is recognized in Cash flows from investing activities in the Collection of DPP, net line in the Consolidated Statements of Cash Flows, which were $ 10,217 million, $ 7,340 million, and $ 4,964 million for the years ended December 31, 2024, 2023, and 2022, respectively. As a result of the receivables being assigned back to NER under the amended Facility, NER forgave any and all remaining DPP owed by the Purchasers. The reassignment of receivables and unwind of DPP will be treated as a non-cash activity and therefore have no impact in the Consolidated Statements of Cash Flows. 112 Table of Contents Combined Notes to Consolidated Financial Statements (Dollars in millions, unless otherwise noted) Note 7 — Accounts Receivable See Note 17 — Fair Value of Financial Assets and Liabilities and Note 21 — Variable Interest Entities for additional information on DPP and NER, respectively. Other Sales of Customer Accounts Receivables We are required, under supplier tariffs, to sell customer receivables to certain utility companies. The total receivables sold was $ 280 million, $ 356 million, and $ 423 million for the years ended December 31, 2024, 2023, and 2022, respectively. 8. Property, Plant, and Equipment The following table presents a summary of property, plant, and equipment by asset category as of December 31, 2024 and 2023: Asset Category December 31, 2024 December 31, 2023 Electric $ 32,141 $ 32,889 Nuclear fuel (a) 5,894 5,503 Construction work in progress 1,273 1,133 Other property, plant, and equipment 15 14 Total property, plant, and equipment 39,323 39,539 Less: accumulated depreciation (b) 18,088 17,423 Property, plant, and equipment, net $ 21,235 $ 22,116 __________ (a) Includes nuclear fuel that is in the fabrication and installation phase of $ 1,485 million and $ 1,265 million as of December 31, 2024 and 2023, respectively. (b) Includes accumulated amortization of nuclear fuel in the reactor core of $ 2,447 million and $ 2,484 million as of December 31, 2024 and 2023, respectively. 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 future energy market conditions. The estimated useful lives of our nuclear stations generally include expectations for an additional 20-year term beyond current license expiration, except for Calvert Cliffs, FitzPatrick, Limerick, NMP Unit 2, Salem, and STP where depreciation provisions correspond with the expiration of the current NRC operating license. Generally, our oil and gas plants have estimated useful lives of 40 - 45 year with wind and solar generating facilities having estimated useful lives of 25 and 35 years, respectively. The estimated useful lives of our hydroelectric facilities also generally align with their FERC operating licenses. Conowingo depreciation provisions are based on an estimated useful life through 2071, in anticipation that a 50-year license will be issued. See Note 3 — Regulatory Matters for additional information regarding license renewals for Peach Bottom and Conowingo. Annual depreciation rates for electric generation were 3.43 %, 3.26 %, and 3.46 % for the years ended December 31, 2024, 2023, and 2022, respectively. Nuclear fuel amortization is charged to fuel expense using the unit-of-production method and not included in the annual depreciation rates. See Note 22 — Supplemental Financial Information for additional information on nuclear fuel amortization. 113 Table of Contents Combined Notes to Consolidated Financial Statements (Dollars in millions, unless otherwise noted) Note 9 — Jointly-Owned Electric Plant 9. Jointly-Owned Electric Plants Our material undivided ownership interests in jointly-owned nuclear plants as of December 31, 2024 and 2023 were as follows: NMP Unit 2 Quad Cities Peach Bottom STP (a) Salem Operator Constellation Constellation Constellation STPNOC PSEG Nuclear Ownership interest 82.00 % 75.00 % 50.00 % 44.00 % 42.59 % Our share as of December 31, 2024 Plant in service $ 1,122 $ 1,294 $ 1,570 $ 1,040 $ 791 Accumulated depreciation 327 840 721 52 387 Construction work in progress 27 13 15 25 68 Our share as of December 31, 2023 Plant in service $ 1,073 $ 1,263 $ 1,552 $ 1,089 $ 781 Accumulated depreciation 292 805 689 5 357 Construction work in progress 35 8 14 13 49 __________ (a) Within the 44 % undivided ownership interest in STP, 2 % interest was recorded as held for sale as of December 31, 2024. See Note 2 — Mergers, Acquisitions, and Dispositions for additional information. Our undivided ownership interests are financed with our funds and all operations are proportionately consolidated consistent with our ownership interest in the Consolidated Statements of Operations and Comprehensive Income. 10. 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. To estimate our nuclear decommissioning obligations we use a probability-weighted, discounted cash flow model which, on a unit-by-unit basis, considers multiple outcome scenarios that include significant estimates and assumptions, and are based on decommissioning cost studies, cost escalation rates, probabilistic cash flow models, and discount rates. We update our AROs annually, unless circumstances warrant more frequent updates, based on our review of updated cost studies and our annual evaluation of cost escalation factors and probabilities assigned to various scenarios. The financial statement impact for changes in the ARO, on an individual unit basis, due to the changes in and timing of estimated cash flows generally result in a corresponding change in the unit’s ARC in Property, plant, and equipment in the Consolidated Balance Sheets. If the ARO decreases for a Non-Regulatory Agreement Unit without any remaining ARC, the corresponding change is recorded as a decrease in Operating and maintenance expense in the Consolidated Statements of Operations and Comprehensive Income, whereas the corresponding decrease for Regulatory Agreement Units without any remaining ARC results in an increase to the Payables related to Regulatory Agreement Units in the Consolidated Balance Sheets. The following table provides a rollforward of the nuclear decommissioning AROs reflected in the Consolidated Balance Sheets from January 1, 2023 to December 31, 2024: 2024 2023 Beginning balance as of January 1 $ 13,891 $ 12,500 Net (decrease) increase due to changes in, and timing of, estimated future cash flows ( 2,299 ) 411 Accretion expense 640 582 Costs incurred related to decommissioning plants (a) ( 24 ) ( 31 ) Acquisition of joint ownership in STP (b) ( 22 ) 429 Ending balance as of December 31 (c) $ 12,186 $ 13,891 __________ 114 Table of Contents Combined Notes to Consolidated Financial Statements (Dollars in millions, unless otherwise noted) Note 10 — Asset Retirement Obligations (a) We began decommissioning Crane upon permanently ceasing operations in 2019 and in 2024 commenced efforts to restart. See below for further discussion of the decommissioning of Zion Station. (b) Reflects our estimated share of the STP decommissioning obligation acquired in 2023 and the portion subsequently transferred to Liabilities held for sale in 2024. See Note 2 — Mergers, Acquisitions, and Dispositions for additional information. (c) Includes $ 18 million and $ 30 million as the current portion of the ARO as of December 31, 2024 and 2023, respectively, which is included in Other current liabilities in the Consolidated Balance Sheets. The net $ 2,299 million decrease in the ARO during 2024 for changes in the amounts and timing of estimated decommissioning cash flows was driven by multiple adjustments, including the following: • Net decrease of $ 3,036 million due to changes in assumed retirement dates for various plants, including Braidwood, Byron, Calvert Cliffs, FitzPatrick, LaSalle, Limerick, NMP Unit 2, Quad Cities, Salem and Crane • A decrease of $ 154 million related to a change in assumed timing of DOE acceptance of SNF and a revised cost study for Salem • An increase of $ 891 million due to an increase in cost escalation rates and lower discount rates The 2024 ARO updates resulted in a decrease of $ 78 million in Operati ng and maintenance expense for the year ended December 31, 2024 in the Consolidated Statements of Operations and Comprehensive Income. The net $ 411 million increase in the ARO during 2023 for changes in the amounts and timing of estimated decommissioning cash flows was driven by multiple adjustments, including the following: • Net increase of approximately $ 610 million due to an increase in cost escalation rates partly offset by an increase in discount rates . • Net increase of approximately $ 470 million due to updated cost assumptions for dry cask storage across the fleet and revised cost studies for Dresden, Limerick and Peach Bottom . • Net decrease of approximately $ 675 million due to changes in assumed retirement dates for Ginna, NMP Unit 1 and Salem . The 2023 ARO updates resulted i n a decrease of $ 68 million in Operating and maintenance expense for the year ended December 31, 2023 in the Consolidated Statements of Operations and Comprehensive Income. NDT Funds NDT funds have been established for each of our nuclear units to satisfy our nuclear decommissioning obligations, as required by the NRC, and withdrawals from these funds for reasons other than to pay for decommissioning are restricted pursuant to NRC requirements until all decommissioning activities have been completed. Generally, NDT funds established for a particular unit may not be used to fund the decommissioning obligations of any other unit. The NDT funds associated with our nuclear units have been funded with amounts collected from the previous owners and their respective utility customers. PECO is authorized to collect funds, in revenues, through regulated rates for decommissioning the former PECO nuclear plants, and these collections are scheduled through the operating lives of these former PECO plants. The amounts collected from PECO customers are remitted to us and deposited into the NDT funds for the unit for which funds are collected. Every five years, PECO files a rate adjustment with the PAPUC that reflects PECO’s calculations of the estimated amount needed to decommission each of the former PECO units based on updated fund balances and estimated decommissioning costs. The rate adjustment is used to determine the amount collectible from PECO customers. In March 2022, PECO filed its Nuclear Decommissioning Cost Adjustment with the PAPUC proposing an annual recovery from customers of approximately $ 4 million. In August 2022, the PAPUC approved the filing, and the new rates became effective January 1, 2023. Additionally, for the STP units, we maintain decommissioning trust funds for those units proportionate to our ownership. We also retain the authority through the PUCT to obtain additional decommissioning funding through AEP Texas and CenterPoint. Every five years, owners of each Texas jurisdictional nuclear generation unit are 115 Table of Contents Combined Notes to Consolidated Financial Statements (Dollars in millions, unless otherwise noted) Note 10 — Asset Retirement Obligations required to file an update of decommissioning costs with the PUCT in support of appropriate utility rates for decommissioning trust funding. In July 2023, the decommissioning cost update for our share of the STP decommissioning obligation was filed, proposing annual funding amounts from AEP Texas and CenterPoint totaling approximately $ 1 million. In March 2024, the PUCT approved the filing, and AEP Texas and CenterPoint tariffs were adjusted accordingly in May and August 2024, respectively. Any shortfall of funds necessary for decommissioning, determined for each generating station unit, are generally required to be funded by us, with the exception of STP and the former PECO units. We have recourse to collect additional amounts from the respective utility customers through the utility commissions for the former PECO units and STP in the event of a shortfall of NDT funds. Collection of additional amounts for the former PECO units are subject to certain limitations and thresholds, as prescribed by an order from the PAPUC that limits collection of amounts associated with the first $ 50 million of any shortfall of trust funds compared to decommissioning costs, as well as 5 % of any additional shortfalls, on an aggregate basis for all former PECO units. The initial $ 50 million and up to 5 % of any additional shortfalls would be borne by us. No such limitations exist for the STP units, however PUCT regulations require that any funds remaining in the trust after completion of decommissioning to be refunded to utility customers in a manner determined by the commission. Aside from the former PECO units and STP, no recourse exists to collect additional amounts from utility customers for any of our other nuclear units. With respect to the Regulatory Agreement Units, any funds remaining in the NDTs after all decommissioning has been completed are required to be refunded to the respective utility customers, subject to certain limitations that allow sharing of excess funds with us related to the former PECO units. With respect to our other nuclear units, we retain any funds remaining after decommissioning. However, in connection with CENG's acquisition of the NMP and Ginna plants and settlements with certain regulatory agencies, certain conditions pertaining to NDT funds apply that, if met, could possibly result in obligations to make payments to certain third parties (clawbacks). For NMP and Ginna, the clawback provisions are triggered only in the event that the required decommissioning activities are discontinued or not started or completed in a timely manner. In the event that the clawback provisions are triggered for NMP, then, depending upon the triggering event, an amount equal to 50 % of the total amount withdrawn from the funds for non-decommissioning activities as defined in the agreement or 50 % of any excess funds in the trust funds above the amounts required for decommissioning (including SNF management and site restoration) is to be paid to the NMP sellers. In the event that the clawback provisions are triggered for Ginna, then an amount equal to any estimated cost savings realized by not completing any of the required decommissioning activities is to be paid to the Ginna sellers. We expect to comply with applicable regulations and timely commence and complete all required decommissioning activities. We had NDT funds totali ng $ 17,321 million and $ 16,398 million as of December 31, 2024 and 2023, respectively. As of December 31, 2024, $ 16 million of the NDT funds were current and included in Other current assets in the Consolidated Balance Sheets. As of December 31, 2023, none of the NDT funds were reflected in Other current assets. See Note 22 — 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 for additional information on the accounting policy for Regulatory Agreement Units. For the former PECO units and STP, given the symmetric settlement provisions that allow for continued recovery of decommissioning costs from the respective utility customers in the event of a shortfall and the obligation for us to ultimately return excess funds to the respective utility customers (on an aggregate basis for all seven former PECO units and on the underlying utility customer basis for STP) decommissioning-related activities are generally offset in the Consolidated Statements of Operations and Comprehensive Income, regardless of whether the NDT funds are expected to exceed or fall short of the total estimated decommissioning obligation. The offset of decommissioning-related activities in the Consolidated Statements of Operations and Comprehensive Income results in an equal adjustment to noncurrent payables or noncurrent receivables. Any changes to the existing PECO or STP regulatory agreements could impact our ability to offset decommissioning-related activities in the Consolidated Statements of Operations and Comprehensive Income, and the potential impact to our consolidated financial statements could be material. 116 Table of Contents Combined Notes to Consolidated Financial Statements (Dollars in millions, unless otherwise noted) Note 10 — Asset Retirement Obligations For the former ComEd units, given no further recovery from ComEd customers is permitted and we retain an obligation to ultimately return any unused NDTs to ComEd customers (on a unit-by-unit basis), to the extent the related NDT investment balances are expected to exceed the total estimated decommissioning obligation for each unit, decommissioning-related activities are offset in the Consolidated Statements of Operations and Comprehensive Income which results in us recognizing a noncurrent payable. However, given the asymmetric settlement provision that does not allow for continued recovery from ComEd customers in the event of a shortfall, recognition of a receivable related to former ComEd Units is not permissible and accounting for decommissioning-related activities for that unit would not be offset, and the impact to the Consolidated Statements of Operations and Comprehensive Income could be material during such periods. 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 December 31, 2024 and 2023: As of December 31, 2024 2023 ComEd $ 3,780 $ 2,955 PECO 247 278 CenterPoint 365 338 AEP Texas 126 117 Payables related to Regulatory Agreement Units $ 4,518 $ 3,688 As of December 31, 2024, decommissioning-related activities for all of the former ComEd units, except for Zion (see Zion Station Decommissioning below), are currently offset in the Consolidated Statements of Operations and Comprehensive Income. The decommissioning-related activities for the Non-Regulatory Agreement Units are reflected in the Consolidated Statements of Operations and Comprehensive Income within Operating and maintenance expense, Depreciation and amortization expense, and Other, net. Zion Station Decommissioning In 2010, we completed an asset sale agreement under which ZionSolutions assumed responsibility for decommissioning Zion Station and we transferred to ZionSolutions substantially all the Zion Station’s assets, including the related NDT funds. In November 2023, ZionSolutions completed its contractual obligations and transferred the NRC license back to us. We will store the SNF at Zion Station until it is transferred to the DOE for ultimate disposal and complete all remaining decommissioning activities associated with the SNF dry storage facility. Any shortage of funds necessary to maintain the SNF and decommission the SNF storage facility is ultimately required to be funded by us. As of December 31, 2024 and 2023, the ARO associated with Zion's SNF storage facility is $ 163 million and $ 139 million, respectively, and the NDT funds available to fund this obligation ar e $ 63 million and $ 62 million, respectively. 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. The estimated decommissioning obligations are calculated using an NRC methodology that is different from the ARO recorded in the Consolidated Balance Sheets primarily due to differences in the type of costs included in the estimates, the basis for estimating such costs, and assumptions regarding the decommissioning alternatives to be used, potential license renewals, decommissioning cost escalation, and the growth rate in the NDT funds. Under NRC regulations, if the minimum funding requirements for radiological decommissioning calculated under the NRC methodology are greater than the future value of the NDT funds, also calculated under the NRC methodology, then the NRC requires resolution of the shortfalls which could include further funding or other financial guarantees. 117 Table of Contents Combined Notes to Consolidated Financial Statements (Dollars in millions, unless otherwise noted) Note 10 — Asset Retirement Obligations Key assumptions used in the minimum funding calculation for radiological decommissioning costs using the NRC methodology at December 31, 2024 include: (1) consideration of costs only for the removal of radiological contamination at each unit; (2) the option on a unit-by-unit basis to use generic, non-site specific cost estimates; (3) consideration of only one decommissioning scenario for each unit; (4) the plants cease operation at the end of their current license lives (with no assumed license renewals for those units that have not already received renewals); (5) the assumption of current nominal dollar cost estimates that are neither escalated through the anticipated period of decommissioning, nor discounted using the CARFR; and (6) assumed annual after-tax returns on the NDT funds of 2 % ( 3 % for the former PECO units, as specified by the PAPUC). In contrast, the key criteria and assumptions used by us to determine the ARO and to forecast the target growth in the NDT funds as of December 31, 2024 include: (1) the use of site specific cost estimates that are updated at least once every five years; (2) the inclusion in the ARO estimate of all legally unavoidable costs required to decommission the unit (e.g., radiological decommissioning and full site restoration for certain units, on-site SNF maintenance and storage subsequent to ceasing operations and until DOE acceptance, and disposal of certain LLRW); (3) as applicable, the consideration of multiple scenarios where decommissioning and site restoration activities, as applicable, are completed under possible scenarios ranging from 10 to 70 years after the cessation of plant operations or the end of the current licensed operating life; (4) the consideration of multiple end of life scenarios; (5) the measurement of the obligation at the present value of the future estimated costs and an annual accretion of the ARO; and (6) an estimated targeted annual pre-tax return on the NDT funds of 6.3 % to 7.1 % (as compared to a historical 5-year annual average pre-tax return of approximately 6.5 % ). We are required to provide to the NRC a biennial report by unit (annually for units that have been retired or are within five years of license expiration), based on values as of December 31, addressing our ability to meet the NRC minimum funding levels. Depending on the value of the trust funds, we may be required to take steps, such as providing financial guarantees through surety bonds, letters of credit, or parent company guarantees or making additional contributions to the trusts, which could be significant, to ensure that the trusts are adequately funded and that NRC minimum funding requirements are met. As a result, our cash flows and financial position may be significantly adversely affected. We filed our biennial decommissioning funding status report with the NRC in March 2023 for all units, including our shutdown units, except for Zion Station which was included in a separate report to the NRC submitted by ZionSolutions, LLC. The status report demonstrated adequate decommissioning funding assurance based on trust fund values as of December 31, 2022 for all units except for Peach Bottom Unit 1. As a former PECO plant, financial assurance for decommissioning Peach Bottom Unit 1 is provided by the NDT fund, collections from PECO customers, and the ability to adjust those collections in accordance with the approved PAPUC tariff. See NDT Funds section above for additional information. Additionally, the STP units demonstrated adequate decommissioning funding assurance as of December 31, 2022 in the decommissioning funding status report filed with the NRC by STPNOC in March 2023. In March 2024, we filed our annual decommissioning funding status report with the NRC for our shutdown units, including Zion Station which was transferred back to us in November 2023. The status report demonstrated adequate decommissioning funding assurance based on trust fund values as of December 31, 2023 for all shutdown units except for Peach Bottom Unit 1. Financial assurance for decommissioning Peach Bottom Unit 1 is provided by collections from PECO customers. Additionally in March 2024, STPNOC filed the decommissioning funding status report for STP. The status report demonstrated adequate funding assurance as of December 31, 2023. We will file the next decommissioning funding status report with the NRC in M arch 2025. This report will reflect the status of decommissioning funding as of December 31, 2024 for all units, except for STP which will be filed separately by STPNOC. We expect the funding status reports to demonstrate adequate funding assurance based on the value of trust funds as of December 31, 2024, for all units except for Peach Bottom Unit 1. Financial assurance for decommissioning Peach Bottom Unit 1 is provided by the collections from PECO customers as mentioned above. As the future values of trust funds change due to market conditions, the NRC minimum funding status of our units will change. In addition, if changes occur to the regulatory agreements with the PAPUC or the PUCT that currently allow amounts to be collected from utility customers for decommissioning the former PECO and STP units, the NRC minimum funding status of those plants could change at subsequent NRC filing dates. 118 Table of Contents Combined Notes to Consolidated Financial Statements (Dollars in millions, unless otherwise noted) Note 10 — Asset Retirement Obligations Non-Nuclear Asset Retirement Obligations We have AROs for plant closure costs associated with our natural gas, oil, and renewable generating facilities, including 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, and other decommissioning-related activities. See Note 1 — Basis of Presentation 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 January 1, 2023 to December 31, 2024: 2024 2023 Beginning balance as of January 1 $ 257 $ 239 Net increase (decrease) due to changes in, and timing of, estimated future cash flows 19 14 Accretion expense 15 14 Asset divestitures — ( 9 ) Costs incurred related to decommissioning plants ( 3 ) ( 1 ) Ending balance as of December 31 $ 288 $ 257 11. Leases Lessee We have operating leases for which we are the lessee. The significant types of leases are contracted generation, real estate, and vehicles and equipment. The following table outlines other terms and conditions of the lease agreements as of December 31, 2024. We did not have material finance leases in 2024, 2023, or 2022. In Years Remaining lease terms 1 - 31 Options to extend the term 2 - 30 The components of operating lease costs were as follows: For the Years Ended December 31, 2024 2023 2022 Operating lease costs $ 105 $ 96 $ 109 Variable lease costs 145 146 169 Total lease costs (a) $ 250 $ 242 $ 278 __________ (a) Excludes $ 50 million, $ 50 million, $ 49 million of sublease income recorded for the years ended December 31, 2024, 2023, and 2022, respectively. 119 Table of Contents Combined Notes to Consolidated Financial Statements (Dollars in millions, unless otherwise noted) Note 11 — Leases The following table provides additional information regarding the presentation of operating lease ROU assets and lease liabilities in the Consolidated Balance Sheets: As of December 31, 2024 2023 Operating lease ROU assets (a) Other deferred debits and other assets $ 436 $ 494 Operating lease liabilities (a) Other current liabilities 72 67 Other deferred credits and other liabilities 511 583 Total operating lease liabilities $ 583 $ 650 __________ (a) The operating ROU assets and lease liabilities include $ 176 million and $ 289 million, respectively, related to contracted generation as of December 31, 2024, and $ 212 million and $ 334 million, respectively, as of December 31, 2023. The weighted average remaining lease terms, in years, and the weighted average discount rates for operating leases were as follows: As of December 31, 2024 2023 2022 Weighted average remaining lease term 7.4 8.4 9.3 Weighted average discount rate 5.0 % 5.0 % 5.0 % The following table reconciles the undiscounted cash flows for our operating leases to the operating lease liabilities recorded on our consolidated balance sheet as of December 31, 2024: 2025 $ 105 2026 105 2027 104 2028 105 2029 103 2030 and thereafter 222 Total lease payments 744 Less: Imputed interest 161 Operating lease liabilities $ 583 Supplemental cash flow information related to operating leases was as follows: For the Years Ended December 31, 2024 2023 2022 Cash paid for amounts included in the measurement of operating lease liabilities $ 87 $ 102 $ 114 ROU assets obtained in exchange for operating lease obligations 6 13 14 120 Table of Contents Combined Notes to Consolidated Financial Statements (Dollars in millions, unless otherwise noted) Note 11 — Leases Lessor We have operating leases for which we are the lessor. The significant types of leases are contracted generation and real estate. The following table outlines other terms and conditions of the lease agreements as of December 31, 2024. In Years Remaining lease terms 2 - 16 Options to extend the term 5 - 20 The components of lease income were as follows: For the Years Ended December 31, 2024 2023 2022 Operating lease income $ 51 $ 51 $ 51 Variable lease income 244 248 258 The following table presents the lease payments we expect to receive over the remaining terms as of December 31, 2024: 2025 $ 48 2026 49 2027 49 2028 48 2029 48 2030 and thereafter 38 Total $ 280 12. Intangible Assets Goodwill The following table presents the carrying amount of goodwill as of December 31, 2024, 2023 and 2022. There were no impairment losses during the years ended December 31, 2024, 2023, and 2022 . Goodwill Balance at December 31, 2022 $ 47 Goodwill resulting from acquisition of STP (a) 378 Balance at December 31, 2023 425 Goodwill allocated to Assets held for sale (a) ( 5 ) Balance at December 31, 2024 $ 420 __________ (a) Within the 44 % undivided ownership interest in STP, 2 % interest was recorded as held for sale as of December 31, 2024. See Note 2 — Mergers, Acquisitions, and Dispositions for additional information on the STP acquisition in November 2023 and held for sale reclassification in 2024. See Note 1 — Basis of Presentation for our policy regarding goodwill. Our operating segments are also considered reporting units for goodwill impairment assessment purposes. The goodwill recognized in 2023 has been assigned entirely to the ERCOT operating segment. 121 Table of Contents Combined Notes to Consolidated Financial Statements (Dollars in millions, unless otherwise noted) Note 12 — Intangible Assets Other Intangible Assets and Liabilities Our other intangible assets and liabilities included in Other current assets, Other deferred debits and other assets, Other current liabilities, and Other deferred credits and other liabilities in the Consolidated Balance Sheets, consisted of the following as of December 31, 2024 and 2023. The customer relationships are generally amortized on a straight line basis, while the unamortized energy contracts are amortized in relation to the expected realization of the underlying cash flows: December 31, 2024 December 31, 2023 Gross Accumulated Amortization Net Gross Accumulated Amortization Net Unamortized Energy Contracts $ 1,850 $ ( 1,669 ) $ 181 $ 1,892 $ ( 1,631 ) $ 261 Customer Relationships 244 ( 189 ) 55 242 ( 167 ) 75 Total $ 2,094 $ ( 1,858 ) $ 236 $ 2,134 $ ( 1,798 ) $ 336 The following table summarizes the amortization expense related to our other intangible assets and liabilities for the years ended December 31, 2024, 2023, and 2022: For the Years Ended December 31, Amortization Expense (a) 2024 $ 60 2023 58 2022 61 __________ (a) See Note 22 — Supplemental Financial Information for additional information related to the amortization of unamortized energy contracts. The following table summarizes the estimated future amortization expense related to our other intangible assets and liabilities as of December 31, 2024: For the Years Ending December 31, Estimated Future Amortization Expense 2025 $ 36 2026 40 2027 32 2028 28 2029 19 2030 and thereafter 81 13. Income Taxes Components of Income Tax Expense or Benefit Income taxes are comprised of the following components: For the Years Ended December 31, 2024 2023 2022 Federal Current $ 426 $ 464 $ 219 Deferred 274 301 ( 655 ) ITC amortization ( 14 ) ( 15 ) ( 15 ) State Current 127 142 34 Deferred ( 39 ) ( 33 ) 29 Total income tax (benefit) expense $ 774 $ 859 $ ( 388 ) 122 Table of Contents Combined Notes to Consolidated Financial Statements (Dollars in millions, unless otherwise noted) Note 13 — Income Taxes Rate Reconciliation The effective income tax rate varies from the U.S. federal statutory rate principally due to the following: For the Years Ended December 31, 2024 2023 2022 (a) U.S. federal statutory rate 21.0 % 21.0 % 21.0 % (Decrease) increase due to: State income taxes, net of federal income tax benefit (b) 1.5 3.5 ( 9.2 ) Qualified NDT fund income and losses 4.0 10.3 46.3 Amortization of ITC, including deferred taxes on basis differences ( 0.2 ) ( 0.5 ) 2.2 PTCs and other credits ( 9.8 ) ( 0.6 ) 7.7 Noncontrolling interests 0.1 0.4 ( 0.3 ) Other 0.6 1.0 3.9 Effective income tax rate (c) 17.1 % 35.1 % 71.6 % _________ (a) As there was a pre-tax loss during 2022, negative percentages represent income tax expense. Positive percentages represent income tax benefit. (b) Includes ($ 42 ) million, ($ 4 ) million and $ 30 million related to state rate changes and certain state tax positions in 2024, 2023, and 2022, respectively. (c) The change in effective tax rate in 2024 is primarily due to the increase in pre-tax book income inclusive of the nuclear PTC, which is not taxable. The change in effective tax rate in 2023 is primarily due to the impacts of higher realized NDT Income and significant pretax income in 2023 compared to pretax loss in 2022. Tax Differences and Carryforwards The tax effects of temporary differences and carryforwards, which give rise to significant portions of the deferred tax assets (liabilities), as of December 31, 2024 and 2023 are presented below: December 31, 2024 December 31, 2023 Plant basis differences $ ( 3,138 ) $ ( 3,130 ) Accrual-based contracts ( 30 ) ( 32 ) Derivatives and other financial instruments 700 984 Deferred pension and postretirement obligation ( 336 ) ( 314 ) Nuclear decommissioning activities ( 256 ) ( 640 ) Tax loss carryforward, net of valuation allowances 16 47 Investment in partnerships ( 204 ) ( 193 ) Other, net 242 460 Deferred income tax liabilities (net) ( 3,006 ) ( 2,818 ) Unamortized ITCs ( 325 ) ( 339 ) Total deferred income tax liabilities (net) and unamortized ITCs $ ( 3,331 ) $ ( 3,157 ) 123 Table of Contents Combined Notes to Consolidated Financial Statements (Dollars in millions, unless otherwise noted) Note 13 — Income Taxes The following table provides our carryforwards, of which the state-related items are presented on a post-apportioned basis, and any corresponding valuation allowances as of December 31, 2024: Federal December 31, 2024 Federal general business credits carryforwards and other carryforwards $ — State State net operating losses and other carryforwards 365 Deferred taxes on state tax attributes (net) 14 Valuation allowance on state tax attributes ( 3 ) Foreign Foreign net operating losses and other carryforwards 20 Deferred taxes on foreign tax attributes (net) 5 Unrecognized Tax Benefits Our unrecognized tax benefits were not material as of and for the years ended December 31 , 2024, 2023, and 2022, and if recognized, would not significantly impact our effective tax rate. Further, these amounts are not expected to significantly increase or decrease within the next twelve months. Total amounts of interest and penalties recognized Interest and penalty expenses are recorded in Interest expense, net and Other, net, respectively, in the Consolidated Statements of Operations and Comprehensive Income. There was no material interest and penalty expense related to our tax positions for the years ended December 31 , 2024, 2023, and 2022. Description of tax years open to assessment by major jurisdiction Major Jurisdiction Open Years (a) Federal consolidated income tax returns 2010-2023 Illinois unitary corporate income tax returns 2012-2023 Texas combined corporate income tax returns 2020-2023 New Jersey combined corporate income tax returns 2020-2023 Maryland separate corporate income tax returns 2021-2023 Massachusetts combined corporate income tax returns 2021-2023 New York combined corporate income tax returns 2019-2023 Pennsylvania separate corporate income tax returns 2021-2023 California combined corporate income tax returns 2010-2023 __________ (a) Tax years open to assessment include years when we were consolidated by Exelon. See discussion below under the Tax Matters Agreement for responsibility of taxes of these open years. Constellation participates in the IRS Compliance Assurance Process which provides the opportunity to resolve complex tax matters with the IRS prior to filing its federal income tax returns with a goal to achieve certainty with respect to tax matters. Constellation entered the program for the 2024 tax year. Other Tax Matters Tax Matters Agreement In connection with the separation, we entered 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 that we were included 124 Table of Contents Combined Notes to Consolidated Financial Statements (Dollars in millions, unless otherwise noted) Note 13 — Income Taxes in 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 December 31, 2024 and 2023, respectively, our Consolidated Balance Sheets reflect $ 39 million and $ 37 million in Other deferred credits and other liabilities, respectively, for tax liabilities where we maintain contractual responsibility to Exelon. There were no payables in Accounts payable and accrued expenses for both periods. 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. As of December 31, 2024 and 2023, respectively, we had $ 138 million and $ 336 million in Other accounts receivable and $ 201 million and $ 178 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. 14. Retirement Benefits Defined Benefit Pension and OPEB The majority of current employees participate in the defined benefit pension and OPEB plans that we sponsor. As the plan sponsor, our Consolidated Balance Sheets reflect underfunded pension and OPEB liabilities equal to an excess of either the PBO or APBO over the fair value of the plan assets, consistent with a single employer benefit plan. Newly hired employees are generally not eligible for either pension or OPEB benefits; instead, these employees are eligible to receive an enhanced non-discretionary fixed employer contribution under our sponsored defined contribution savings plan. Benefit Obligations, Plan Assets, and Funded Status As of February 1, 2022, we assumed from Exelon the PBO, APBO, and plan assets for our plan participants in connection with the separation. The defined benefit pension and OPEB plans were remeasured to determine the obligations and related plan assets to be transferred to us as of that date. The pension assets allocated to us were based on the rules prescribed by ERISA for transfers of assets in connection with a pension plan separation. A portion of the Exelon OPEB plan assets, which are held in VEBA trusts, were also allocated to us separately for each funding vehicle based on the ratio of the APBO assumed by us to the total APBO attributed to each funding vehicle. As a result of the remeasurement completed at separation we recognized $ 2,006 million (after-tax) in Accumulated other comprehensive income (loss) for actuarial losses and prior service costs that had accrued over the lives of the plans prior to separation, primarily based on our proportionate share of the total projected pension and OPEB obligations at Exelon prior to separation. We use a December 31 measurement date for our pension and OPEB obligations and the related plan assets. The actuarial losses experienced upon remeasurement as of December 31, 2024 were offset against AOCI, net of deferred taxes. See the table below for changes associated with the pension valuation. 125 Table of Contents Combined Notes to Consolidated Financial Statements (Dollars in millions, unless otherwise noted) Note 14 — Retirement Benefits The following tables provide a rollforward of the changes in the benefit obligations and plan assets for the years ended December 31, 2024 and 2023 for all plans combined: Pension Benefits OPEB 2024 2023 2024 2023 Change in benefit obligation: Benefit obligation as of the beginning of the year $ 7,770 $ 7,275 $ 1,443 $ 1,360 Service cost 90 89 17 16 Interest cost 391 394 72 74 Plan participants' contributions — — 24 23 Actuarial loss (gain), net ( 269 ) 368 12 99 Acquisition-related adjustments (a) ( 9 ) 187 ( 1 ) 14 Settlements ( 13 ) — — — Gross benefits paid ( 563 ) ( 543 ) ( 145 ) ( 143 ) Benefit obligation as of the end of year $ 7,397 $ 7,770 $ 1,422 $ 1,443 __________ (a) Pension and OPEB adjustments related to held for sale impacts of the settlement agreement entered into in 2024 and acquisition of STP in 2023, respectively. See Note 2 — Mergers, Acquisitions, and Dispositions for additional information. Pension Benefits OPEB 2024 2023 2024 2023 Change in plan assets: Plan assets as of the beginning of year $ 6,687 $ 6,660 $ 692 $ 734 Employer contributions 177 26 — — Plan participants' contributions — — 18 18 Actual return (loss) on plan assets 37 374 22 50 Acquisition-related adjustment (a) ( 8 ) 170 — — Settlements ( 13 ) — — — Gross benefits paid ( 563 ) ( 543 ) ( 134 ) ( 110 ) Fair value of plan assets as of the end of year $ 6,317 $ 6,687 $ 598 $ 692 Over (under) funded status (Plan assets less benefit obligations) $ ( 1,080 ) $ ( 1,083 ) $ ( 824 ) $ ( 751 ) __________ (a) Pension and OPEB adjustments related to held for sale impacts of the settlement agreement in 2024 and the acquisition of STP in 2023, respectively. See Note 2 — Mergers, Acquisitions, and Dispositions for additional information. We present our benefit obligations net of plan assets on our Consolidated Balance Sheets within the following line items: Pension Benefits OPEB 2024 2023 2024 2023 Other current liabilities $ ( 9 ) $ ( 13 ) $ ( 20 ) $ ( 19 ) Pension and non-pension benefit obligations ( 1,071 ) ( 1,070 ) ( 804 ) ( 732 ) The following table provides the ABO and fair value of plan assets for all pension plans with an ABO in excess of plan assets. ABO in Excess of Plan Assets December 31, 2024 December 31, 2023 ABO $ ( 7,225 ) $ ( 7,567 ) Fair value of plan assets 6,317 6,687 126 Table of Contents Combined Notes to Consolidated Financial Statements (Dollars in millions, unless otherwise noted) Note 14 — Retirement Benefits Components of Net Periodic Benefit (Credit) Cost See Note 1 — Basis of Presentation for additional information on where we report the service cost and other non-service cost (credit) components for all plans. The following table presents the components of our net periodic benefit (credits) costs, prior to capitalization and co-owner allocations, for the years ended December 31, 2024, 2023 and 2022: Pension Benefits OPEB Total Pension Benefits and OPEB 2024 2023 2022 2024 2023 2022 2024 2023 2022 Components of net periodic benefit (credit) cost: Service cost $ 90 $ 89 $ 126 $ 17 $ 16 $ 25 $ 107 $ 105 $ 151 Non-service components of pension benefits & OPEB (credit) cost: Interest cost 391 404 290 72 76 55 463 480 345 Expected return on assets ( 506 ) ( 520 ) ( 565 ) ( 42 ) ( 45 ) ( 55 ) ( 548 ) ( 565 ) ( 620 ) Amortization of: Prior service (credit) cost 1 1 1 ( 6 ) ( 10 ) ( 7 ) ( 5 ) ( 9 ) ( 6 ) Actuarial (gain) loss 102 48 148 ( 9 ) ( 12 ) ( 1 ) 93 36 147 Settlement charges 6 — 6 — — — 6 — 6 Non-service components of pension benefits & OPEB credit (cost) ( 6 ) ( 67 ) ( 120 ) 15 9 ( 8 ) 9 ( 58 ) ( 128 ) Net periodic benefit (credit) cost (a(b) $ 84 $ 22 $ 6 $ 32 $ 25 $ 17 $ 116 $ 47 $ 23 __________ (a) Reflected above and in the Consolidated Statements of Operations and Comprehensive Income for the years ended December 31, 2024, 2023, and 2022, are pension benefit and OPEB service costs of $ 99 million, $ 94 million, and $ 131 million, respectively, and non-service costs (credits) of $ 8 million, ($ 54 ) million, and ($ 116 ) million, respectively. (b) Our portion of the total net periodic benefit (credits) costs allocated to us from Exelon in January 2022 prior to separation was not material and remains in total Operating and maintenance expense. 127 Table of Contents Combined Notes to Consolidated Financial Statements (Dollars in millions, unless otherwise noted) Note 14 — Retirement Benefits Components of AOCI We recognize the overfunded or underfunded status of defined benefit pension and OPEB plans as an asset or liability on our balance sheet, with offsetting entries to AOCI. The following tables provide the pre-tax components of AOCI for the years ended December 31, 2024 and 2023, for all plans combined: Pension Benefits OPEB 2024 2023 2024 2023 Changes in plan assets and benefit obligations recognized in AOCI: Current year actuarial (gain) loss $ 202 $ 509 $ 33 $ 94 Amortization of actuarial (loss) gain ( 102 ) ( 46 ) 9 14 Amortization of prior service (cost) credit ( 1 ) ( 1 ) 6 6 Settlements ( 6 ) — — — Total recognized in AOCI $ 93 $ 462 $ 48 $ 114 The following table provides the components of gross accumulated other comprehensive income (loss) that have not been recognized as components of periodic benefit cost as of December 31, 2024 and 2023, for all plans combined: Pension Benefits OPEB 2024 2023 2024 2023 Prior service (credit) cost $ 8 $ 9 $ ( 18 ) $ ( 24 ) Actuarial (gain) loss 3,080 2,985 ( 43 ) ( 85 ) Total $ 3,088 $ 2,994 $ ( 61 ) $ ( 109 ) Average Remaining Service Period For pension benefits, we amortize the unrecognized prior service (credits) costs and certain actuarial gains and losses reflected in AOCI, as applicable, based on participants’ average remaining service periods. For OPEB, we amortize the unrecognized prior service (credits) costs reflected in AOCI over participants’ average remaining service period to benefit eligibility age, and amortize certain actuarial gains and losses reflected in AOCI over participants’ average remaining service period to expected retirement. The resulting average remaining service periods for pension and OPEB as of December 31, 2024 and 2023 were as follows: December 31, 2024 December 31, 2023 Pension plans 11 12 OPEB plans: Benefit Eligibility Age 8 8 Expected Retirement 9 8 Assumptions The measurement of the plan obligations and costs of providing benefits under our defined benefit pension and OPEB plans involves various factors, including the development of valuation assumptions and inputs and accounting policy elections. The measurement of benefit obligations and costs is impacted by several assumptions and inputs, as shown below, among other factors. When developing the required assumptions, we consider historical information as well as future expectations. Discount Rate. The discount rates are determined by developing a spot rate curve based on the yield to maturity of a universe of high-quality non-callable (or callable with make whole provisions) bonds with similar maturities to the related pension and OPEB obligations. The spot rates are used to discount the estimated future benefit distribution amounts under the pension and OPEB plans. The discount rate is the single level rate that 128 Table of Contents Combined Notes to Consolidated Financial Statements (Dollars in millions, unless otherwise noted) Note 14 — Retirement Benefits produces the same result as the spot rate curve. We utilize an analytical tool developed by our actuaries to determine the discount rates. Expected Rate of Return. To determine the EROA, we use third-party expectations for future long-term capital market performance, weighted by our target asset class allocations. Mortality. The mortality assumption is composed of a base table that represents the current expectation of life expectancy of the population adjusted by an improvement scale that attempts to anticipate future improvements in life expectancy. Upon remeasurement as of December 31, 2024 and December 31, 2023, we utilized the mortality tables and projection scales released by the SOA. The following assumptions were used to determine the benefit obligations for the plans as of December 31, 2024 and December 31, 2023. Assumptions used to determine year-end benefit obligations are the assumptions used to estimate the subsequent year’s net periodic benefit costs. Pension Benefits OPEB December 31, 2024 December 31, 2023 December 31, 2024 December 31, 2023 Discount rate (a) 5.66 % 5.17 % 5.63 % 5.15 % Investment crediting rate (b) 5.72 % 5.07 % N/A N/A Rate of compensation increase (c) 4.25 % 4.25 % 4.25 % 4.25 % Mortality table Pri-2012 table with MP-2021 improvement scale (adjusted) Pri-2012 table with MP-2021 improvement scale (adjusted) Pri-2012 table with MP-2021 improvement scale (adjusted) Pri-2012 table with MP-2021 improvement scale (adjusted) Healthcare cost trend on covered charges N/A N/A 7.00 % initial, 5.00 % ultimate Initial and ultimate rate of 5.00 % __________ (a) The discount rates above represent the blended rates used to calculate the majority of Constellation's pension and OPEB costs. (b) The investment crediting rate above represents a weighted average rate. (c) Includes 4.25 % average for the four-year period (2025-2028) and 3.75 % average thereafter. 129 Table of Contents Combined Notes to Consolidated Financial Statements (Dollars in millions, unless otherwise noted) Note 14 — Retirement Benefits The following assumptions were used to determine the net periodic benefit cost for the plans for the years ended December 31, 2024 and 2023. Pension Benefits OPEB 2024 2023 2024 2023 Discount rate (a) 5.17 % 5.52 % 5.15 % 5.50 % Investment crediting rate (b) 5.07 % 5.15 % N/A N/A Expected return on plan assets (c) 6.50 % 6.50 % 6.50 % 6.51 % Rate of compensation increase (d) 4.25 % 3.75 % 4.25 % 3.75 % Mortality table Pri-2012 table with MP-2021 improvement scale (adjusted) Pri-2012 table with MP-2021 improvement scale (adjusted) Pri-2012 table with MP-2021 improvement scale (adjusted) Pri-2012 table with MP-2021 improvement scale (adjusted) Healthcare cost trend on covered charges N/A N/A Initial and ultimate rate of 5.00 % Initial and ultimate rate of 5.00 % __________ (a) The discount rates above represent the blended rates used to calculate the majority of Constellation's pension and OPEB costs. (b) The investment crediting rate above represents a weighted average rate. (c) Applicable to our pension and OPEB plans with plan assets, with the OPEB rate representing a weighted average. (d) Includes 4.25 % average for the five-year period (2025-2028) and 3.75 % average thereafter. Contributions We consider various factors when making qualified pension funding decisions, including actuarially determined minimum contribution requirements under ERISA, contributions required to avoid benefit restrictions and at-risk status as defined by the Pension Protection Act, and management of the pension obligation. The Pension Protection Act requires the attainment of certain funding levels to avoid benefit restrictions (such as an inability to pay lump sums or to accrue benefits prospectively), and at-risk status (which triggers higher minimum contribution requirements and participant notification). The projected contributions below reflect a funding strategy to make levelized annual contributions to offset some of the growth of the liability (e.g., from service cost). Based on this funding strategy and current market conditions, which are both subject to change, we made our annual qualified pension contribution in February 2025. Our non-qualified pension plans are not funded, given that they are not subject to statutory minimum contribution requirements. OPEB plans are also not subject to statutory minimum contribution requirements, though we have funded some of our plans. Annually, we evaluate whether additional funding for those plans is needed, and the OPEB values below reflect both plan contributions (if applicable) and benefit payments for unfunded plans. The following table provides our contributions paid to our qualified pension plans, non-qualified pension plans, and OPEB plans for the years ended December 31, 2024, 2023, and 2022: 2024 2023 2022 Pension contributions (a) $ 177 $ 26 $ 212 OPEB contributions 7 28 26 Total contributions $ 184 $ 54 $ 238 __________ (a) In 2024 and 2023, our annual qualified pension contributions were $ 161 million and $ 21 million, respectively. The benefit payments to the non-qualified pension plans in 2024 and 2023 were not material. 130 Table of Contents Combined Notes to Consolidated Financial Statements (Dollars in millions, unless otherwise noted) Note 14 — Retirement Benefits The following table provides our planned contributions to our qualified pension plans, non-qualified pension plans, and OPEB plans in 2025 (including our benefit payments related to unfunded plans): Qualified Pension Plans Non-Qualified Pension Plans OPEB Total Planned contributions $ 163 $ 12 $ 20 $ 195 Estimated Future Benefit Payments Estimated future benefit payments to participants over the next ten years in all pension and OPEB plans as of December 31, 2024 are as follows: Pension Benefits OPEB 2025 $ 580 $ 122 2026 575 122 2027 584 122 2028 591 121 2029 586 120 2030 through 2034 2,870 571 Total estimated future benefits payments through 2034 $ 5,786 $ 1,178 Plan Assets On a regular basis, we evaluate our investment strategy to ensure that plan assets will be sufficient to pay plan benefits when due. We have developed and implemented a liability hedging investment strategy for the majority of our qualified pension plans which has reduced the volatility of these pension assets relative to the associated pension obligations. We are likely to continue to gradually increase the liability hedging portfolios as the funded statuses of the plans improve. The overall objective is to achieve attractive risk-adjusted returns that will satisfy the liquidity requirements of the plans’ liabilities while striving to minimize the risk of significant losses. Trust assets for our OPEB plans are managed in a diversified investment strategy that prioritizes maximizing liquidity and returns while minimizing asset volatility. Actual asset returns have an impact on the costs reported for the pension and OPEB plans. The actual asset returns across our pension and OPEB plans for the year ended December 31, 2024 were 0.70 % and 6.80 %, respectively, compared to an expected long-term return assumption of 6.50 % and 6.50 %, respectively. We used an EROA of 6.50 % and 6.00 % to estimate our 2025 pension and OPEB costs. Our pension and OPEB plan target asset allocations as of December 31, 2024 and 2023 were as follows: December 31, 2024 December 31, 2023 Asset Category Pension Benefits OPEB Pension Benefits OPEB Equity securities 21 % 20 % 21 % 17 % Fixed income securities 54 % 66 % 54 % 70 % Alternative investments (a) 25 % 14 % 25 % 13 % Total 100 % 100 % 100 % 100 % __________ (a) Alternative investments include private equity, hedge funds, real assets, and private credit. We evaluated our pension and OPEB plans’ asset portfolios for the existence of significant concentrations of credit risk as of December 31, 2024. Types of concentrations that were evaluated include, but are not limited to, investment concentrations in a single entity, type of industry, foreign country, and individual fund. As of December 31, 2024, our pension and OPEB plans held no credit risk concentrations surpassing 10% of plan assets. 131 Table of Contents Combined Notes to Consolidated Financial Statements (Dollars in millions, unless otherwise noted) Note 14 — Retirement Benefits Fair Value Measurements The following table presents pension and OPEB plan assets measured and recorded at fair value as a net component of Pension and non-pension postretirement benefit obligations in our Consolidated Balance Sheets on a recurring basis and their level within the fair value hierarchy as of December 31, 2024 and 2023: December 31, 2024 December 31, 2023 Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total Pension plan assets (a) Cash equivalents $ 170 $ — $ — $ 170 $ 192 $ — $ — $ 192 Equities (b) 1,041 — — 1,041 598 — — 598 Fixed income 675 1,795 — 2,470 740 2,137 — 2,877 Total assets measured at fair value 1,886 1,795 — 3,681 1,530 2,137 — 3,667 Assets measured at NAV — — — 2,869 — — — 3,283 Pension plan assets subtotal 1,886 1,795 — 6,550 1,530 2,137 — 6,950 OPEB plan assets (a) Cash equivalents 18 — — 18 — — — — Equities 96 — — 96 232 — — 232 Fixed income 132 39 — 171 62 94 — 156 Total assets measured at fair value 246 39 — 285 294 94 — 388 Assets measured at NAV — — — 309 — — — 304 OPEB plan assets subtotal 246 39 — 594 294 94 — 692 Total pension and OPEB plan assets (c) $ 2,132 $ 1,834 $ — $ 7,144 $ 1,824 $ 2,231 $ — $ 7,642 __________ (a) See Note 17 — Fair Value of Financial Assets and Liabilities for a description of levels within the fair value hierarchy. (b) Includes total derivative assets and liabilities that are not material, which have total notional amounts of $ 2,635 million and $ 2,001 million as of December 31, 2024 and 2023, respectively. The notional principal amounts for these instruments provide one measure of the transaction volume outstanding as of the fiscal years ended and do not represent the amount of the company’s exposure to credit or market loss. (c) Excludes net liabilities of $ 229 million and $ 263 million as of December 31, 2024 and 2023, respectively. These items are required to reconcile to the fair value of net plan assets and consist primarily of receivables or payables related to pending securities sales and purchases, and interest and dividends receivable. There were no assets or liabilities valued at level 3 for the year ended December 31, 2024. The following table presents the reconciliation of Level 3 assets and liabilities measured at fair value for pension and OPEB plans for the year ended December 31, 2023: Pension Assets Fixed Income Private Equity Total Balance as of January 1, 2023 $ 8 $ 180 $ 188 Actual return on plan assets: Relating to assets still held as of the reporting date — 12 12 Relating to assets sold during the period — ( 13 ) ( 13 ) Purchases and settlements: Purchases — 8 8 Settlements (a) — ( 187 ) ( 187 ) Transfers out of Level 3 ( 8 ) — ( 8 ) Balance as of December 31, 2023 $ — $ — $ — __________ (a) Represents cash settlements only. 132 Table of Contents Combined Notes to Consolidated Financial Statements (Dollars in millions, unless otherwise noted) Note 14 — Retirement Benefits Valuation Techniques Used to Determine Fair Value The techniques used to determine the fair value of the pension and OPEB assets invested in cash equivalents, equities, fixed income, derivatives, private equity, real assets, and private credit investments are the same as the valuation techniques for these types of investments in the NDT funds. See Cash Equivalents and NDT Fund Investments in Note 17 — Fair Value of Financial Assets and Liabilities for further information. Pension and OPEB assets also include investments in hedge funds. Hedge fund investments include those that employ a broad range of strategies to enhance returns and provide additional diversification. The fair value of hedge funds is determined using NAV or its equivalent as a practical expedient, and therefore, hedge funds are not classified within the fair value hierarchy. We have the ability to redeem these investments at NAV or its equivalent subject to certain restrictions, which may include a lock-up period or a gate. Defined Contribution Savings Plan We sponsor the Constellation Employee Savings Plan, a 401(k) defined contribution savings plan. The plan allows employees to contribute a portion of their pre-tax and/or after-tax income in accordance with specified guidelines. We match a percentage of the employee contributions up to certain limits. In addition, certain employees are eligible for a fixed non-discretionary employer contribution in lieu of a pension benefit. The employer contributions to the savings plan were $ 117 million, $ 106 million, and $ 90 million for the years ended December 31, 2024, 2023, and 2022, respectively. 15. Derivative Financial Instruments We use derivative instruments to manage commodity price risk, interest rate risk, and foreign exchange 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 are available through special election and designation, provided they meet specific, restrictive criteria both at the time of designation and on an ongoing basis. These alternative permissible accounting treatments include NPNS, cash flow hedges, and fair value hedges. All derivative instruments, excluding NPNS and cash flow hedges, 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 and proprietary trading derivatives 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. Commodity Price Risk We employ established policies and procedures to manage our risks associated with market fluctuations in commodity prices by entering 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. 133 Table of Contents Combined Notes to Consolidated Financial Statements (Dollars in millions, unless otherwise noted) Note 15 — Derivative Financial Instruments 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 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. 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 the nuclear PTC provided by the IRA, 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 after 2024 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 on the nuclear PTC. 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 transactions that further optimize the economic benefits of our overall portfolio. Additionally, we are exposed to certain market risks through our proprietary trading activities. The proprietary trading activities are a complement to our energy marketing portfolio but represent a small portion of our overall energy marketing activities and are subject to limits established by the Executive Committee. Proprietary trading includes all contracts executed with the intent of benefiting from shifts or changes in market prices as opposed to those executed with the intent of hedging or managing risk. Gains and losses associated with proprietary trading are reported as Operating revenues in the Consolidated Statements of Operations and Comprehensive Income and are included in the Net fair value changes related to derivatives line in the Consolidated Statements of Cash Flows. For the years ended December 31, 2024, 2023, and 2022, net pre-tax commodity mark-to-market gains and losses associated with proprietary trading activities were not material. 134 Table of Contents Combined Notes to Consolidated Financial Statements (Dollars in millions, unless otherwise noted) Note 15 — Derivative Financial Instruments The following tables provide a summary of the derivative fair value balances recorded as of December 31, 2024 and 2023: December 31, 2024 Economic Hedges Proprietary Trading Collateral (a)(b) Netting (a) Total Mark-to-market derivative assets (current) $ 5,518 $ — $ 152 $ ( 4,860 ) $ 810 Mark-to-market derivative assets (noncurrent) 3,672 — 120 ( 3,421 ) 371 Total mark-to-market derivative assets 9,190 — 272 ( 8,281 ) 1,181 Mark-to-market derivative liabilities (current) ( 5,498 ) — 173 4,860 ( 465 ) Mark-to-market derivative liabilities (noncurrent) ( 3,961 ) — 141 3,421 ( 399 ) Total mark-to-market derivative liabilities ( 9,459 ) — 314 8,281 ( 864 ) Total mark-to-market derivative net assets (liabilities) $ ( 269 ) $ — $ 586 $ — $ 317 December 31, 2023 Mark-to-market derivative assets (current) $ 7,927 $ 2 $ 703 $ ( 7,472 ) $ 1,160 Mark-to-market derivative assets (noncurrent) 3,345 — 330 ( 2,682 ) 993 Total mark-to-market derivative assets 11,272 2 1,033 ( 10,154 ) 2,153 Mark-to-market derivative liabilities (current) ( 9,019 ) ( 2 ) 922 7,472 ( 627 ) Mark-to-market derivative liabilities (noncurrent) ( 3,545 ) — 445 2,682 ( 418 ) Total mark-to-market derivative liabilities ( 12,564 ) ( 2 ) 1,367 10,154 ( 1,045 ) Total mark-to-market derivative net assets (liabilities) $ ( 1,292 ) $ — $ 2,400 $ — $ 1,108 _________ (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. (b) Includes $ 351 million and $ 1,712 million of variation margin posted on the exchanges as of December 31, 2024 and 2023, respectively. Economic Hedges (Commodity Price Risk) For the years ended December 31, 2024, 2023, and 2022, we recognized the following net pre-tax commodity mark-to-market gains (losses), which are also included in the Net fair value changes related to derivatives line in the Consolidated Statements of Cash Flows. For the Years Ended December 31, Income Statement Location 2024 2023 2022 Operating revenues $ 313 $ 1,402 $ ( 1,193 ) Purchased power and fuel 963 ( 2,368 ) 167 Total $ 1,276 $ ( 966 ) $ ( 1,026 ) Interest Rate and Foreign Exchange Risk We utilize interest rate swaps to manage our interest rate exposure and foreign currency derivatives to manage foreign exchange rate exposure associated with international commodity purchases in currencies other than U.S. dollars, both of which are treated as economic hedges. The notional amounts were $ 592 million and $ 562 million as of December 31, 2024 and 2023, respectively. The mark-to-market derivative assets and liabilities for the years ended December 31, 2024 and 2023 and the mark-to-market gains and losses associated with management of interest rate and foreign currency risk for the years ended December 31, 2024, 2023, and 2022 were not material. The mark-to-market gains and losses associated with management of interest rate and foreign currency exchange rate risk are also included in the Net fair value changes related to derivatives line in the Consolidated Statements of Cash Flows. 135 Table of Contents Combined Notes to Consolidated Financial Statements (Dollars in millions, unless otherwise noted) Note 15 — Derivative Financial Instruments 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 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 payment netting 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 all derivative instruments, NPNS and payables and receivables, net of collateral and instruments that are subject to master netting agreements, as of December 31, 2024. The tables further delineate that exposure by credit rating of the counterparties and provide guidance on the concentration of credit risk to individual counterparties. The amounts in the tables below exclude credit risk exposure from individual retail counterparties and exposure through RTOs, ISOs, as well as NYMEX, ICE, NASDAQ, NGX, and Nodal commodity exchanges. Rating as of December 31, 2024 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 $ 842 $ 10 $ 832 — $ — Non-investment grade 25 3 22 — — No external ratings Internally rated — investment grade 178 2 176 — — Internally rated — non-investment grade 137 27 110 — — Total $ 1,182 $ 42 $ 1,140 — $ — __________ (a) As of December 31, 2024, credit collateral held from counterparties where we had credit exposure included $ 3 million of cash and $ 39 million of letters of credit. Net Credit Exposure by Type of Counterparty As of December 31, 2024 Investor-owned utilities, marketers, power producers $ 899 Energy cooperatives and municipalities 108 Financial Institutions 62 Other 71 Total $ 1,140 Credit-Risk-Related Contingent Features As part of the normal course of business, we routinely enter physically or 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 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 136 Table of Contents Combined Notes to Consolidated Financial Statements (Dollars in millions, unless otherwise noted) Note 15 — Derivative Financial Instruments 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 this case, 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: As of December 31, Credit-Risk-Related Contingent Features 2024 2023 Gross fair value of derivative contracts containing this feature $ ( 1,346 ) $ ( 1,894 ) Offsetting fair value of contracts under master netting arrangements 602 925 Net fair value of derivative contracts containing this feature $ ( 744 ) $ ( 969 ) As of December 31, 2024 and 2023, 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. As of December 31, 2024 2023 Cash collateral posted (a) $ 635 $ 2,449 Letters of credit posted (a) 890 777 Cash collateral held (a) 49 64 Letters of credit held (a) 91 61 Additional collateral required in the event of a credit downgrade below investment grade (at BB+/Ba1) (b)(c)(d) 1,949 1,914 _________ (a) The cash collateral and letters of credit amounts are inclusive of NPNS contracts. (b) 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. (c) The downgrade collateral is inclusive of all contracts in a liability position regardless of accounting treatment and excludes any contracts with individual retail counterparties. (d) A loss of investment grade credit rating would require a three-notch downgrade from their current levels of BBB+ and Baa1 at S&P and Moody's, respectively. We routinely enter 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. 137 Table of Contents Combined Notes to Consolidated Financial Statements (Dollars in millions, unless otherwise noted) Note 16 — Debt and Credit Agreements 16. Debt and Credit Agreements 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 February 2022, we entered into a credit agreement establishing a $ 3.5 billion five-year revolving credit facility (RCF) at a variable interest rate of SOFR plus 1.275 % and we entered into a $ 1 billion five-year liquidity facility with the primary purpose of supporting our letter of credit issuances. In June 2024, we amended the RCF to increase the available aggregate commitment to $ 4.5 billion and extend the maturity date from January 2027 to June 2029. The RCF may be drawn down in the form of loans and/or to support commercial paper and letters 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 ratings. The adders for the Daily Simple SOFR-based borrowings and Term SOFR borrowings are 7.5 basis points and 107.5 basis points, 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 100 basis points and 200 basis points, 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 In December 2024, we amended the Facility to provide NER access to revolving loans from a number of financial institutions (Lenders) secured by certain customer accounts receivable. As part of the amendment, the maximum funding limit of the of the Facility was increased from $ 1.1 billion to $ 1.5 billion and the maturity date was extended to December 2027. Under previous terms of the Facility, certain customer accounts receivable were sold to the Purchasers. Immediately following the amendment, all receivables previously sold were assigned back to us and receivables will no longer be sold to the Purchasers under the amendment. Subsequent to the amendment, 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. There were no draws on the Facility as of December 31, 2024. The amended 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. 138 Table of Contents Combined Notes to Consolidated Financial Statements (Dollars in millions, unless otherwise noted) Note 16 — Debt and Credit Agreements As of December 31, 2024 and 2023 we had the following aggregate bank commitments, credit facility borrowings and available capacity under our respective credit facilities: December 31, 2024 Facility Type Aggregate Bank Commitment Facility Draws Outstanding Letters of Credit Outstanding Commercial Paper (a) Total Available Capacity Revolving Credit Facility $ 4,500 $ — $ 51 $ — $ 4,449 Bilaterals (b) 1,850 — 1,095 — 755 Accounts Receivable Facility 1,500 — — — 1,500 Liquidity Facility 971 — 907 — 21 (c) Project Finance 137 — 120 — 17 Total $ 8,958 $ — $ 2,173 $ — $ 6,742 December 31, 2023 Revolving Credit Facility $ 3,500 $ — $ 60 $ 1,107 $ 2,333 Bilaterals 1,500 — 878 — 622 Liquidity Facility 971 — 720 — 191 (c) Project Finance 137 — 117 — 20 Total $ 6,108 $ — $ 1,775 $ 1,107 $ 3,166 __________ (a) 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 December 31, 2024 and 2023, the maximum program size of our commercial paper program was $ 4.5 billion and $ 3.5 billion, respectively. We do not issue commercial paper in an aggregate amount exceeding the then available capacity under our credit facility. There were no commercial paper borrowings outstanding as of December 31, 2024. The weighted average interest rate on commercial paper borrowings was 5.66 % as of December 31, 2023. (b) Refer to table below for additional information on our bilateral credit agreements. (c) 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 December 31, 2024 and 2023, without posting additional collateral, the actual availability of facility, prior to outstanding letters of credit was $ 928 million and $ 911 million, respectively. Bilateral Credit Agreements The following table reflects the bilateral credit agreements at December 31, 2024: Date Initiated (b) Latest Amendment Date Maturity Date (a) Amount January 2016 April 2023 April 2026 $ 150 October 2019 N/A N/A 200 November 2019 N/A N/A 300 November 2019 N/A N/A 100 November 2019 June 2024 June 2026 100 May 2020 March 2023 N/A 300 August 2022 N/A N/A 50 March 2023 N/A March 2025 100 December 2023 N/A N/A 200 March 2024 N/A N/A 200 May 2024 N/A N/A 150 __________ (a) Credit facilities that do not contain a maturity date are specific to the agreements set within each contract. In some instances, credit facilities are automatically renewed based on the contingency standards set within the specific agreement. (b) Bilateral credit agreements solely support the issuance of letters of credit and do not back our commercial paper program. 139 Table of Contents Combined Notes to Consolidated Financial Statements (Dollars in millions, unless otherwise noted) Note 16 — Debt and Credit Agreements In January 2025, we initiated a new bilateral credit agreement for $ 200 million, with no maturity date. Short-Term Loan Agreements As of December 31, 2024 and 2023, we had the following short-term loan agreements: Month Initiated Interest Rate Maturity Outstanding Amount as of December 31, 2024 Outstanding Amount as of December 31, 2023 January 2023 1-month SOFR + 0.80 % January 2024 $ — $ 100 February 2023 1-month SOFR + 1.05 % February 2024 — 400 Long-Term Debt The following table presents the outstanding long-term debt as of December 31, 2024 and 2023: December 31, Rates Maturity Date 2024 2023 Long-term debt Senior unsecured notes 3.25 % - 6.50 % 2025 - 2054 $ 6,588 $ 5,688 Tax-exempt notes 4.10 % - 4.45 % 2025 - 2053 (a) 435 435 Notes payable and other 2.20 % - 6.10 % 2025 - 2034 51 34 Nonrecourse debt: Fixed rates 2.29 % - 6.00 % 2031 - 2037 720 780 Variable rates 6.76 % - 8.58 % 2026 - 2027 680 740 Total long-term debt 8,474 7,677 Unamortized debt discount and premium, net ( 4 ) ( 4 ) Unamortized debt issuance costs ( 58 ) ( 56 ) Long-term debt due within one year ( 1,028 ) ( 121 ) Long-term debt $ 7,384 $ 7,496 ________ (a) The Tax-exempt notes have a maturity date of March 2025 to April 2053, and a mandatory purchase date that ranges from March 2025 to June 2029. Long-term debt maturities in the periods 2025 through 2029 and thereafter are as follows: 2025 $ 1,028 2026 114 2027 691 2028 847 2029 156 2030 and thereafter 5,638 Total $ 8,474 Debt Covenants As of December 31, 2024, we are in compliance with all debt covenants. Nonrecourse Debt We have also issued nonrecourse debt, for which approximately $ 2 billion of generating assets have been pledged as collateral as of both December 31, 2024 and 2023, respectively. Borrowings under these agreements 140 Table of Contents Combined Notes to Consolidated Financial Statements (Dollars in millions, unless otherwise noted) Note 16 — Debt and Credit Agreements are secured by the assets and equity of each respective project. The lenders do not have recourse against us in the event of a default. If a specific project financing entity does not maintain compliance with its specific nonrecourse debt covenants, there could be a requirement to accelerate repayment of the associated debt or other borrowings earlier than the stated maturity dates. In these instances, if such repayment was not satisfied, the lenders or security holders would generally have rights to foreclose against the project-specific assets and related collateral. The potential requirement to satisfy the associated debt or other borrowings earlier than otherwise anticipated could lead to impairments due to a higher likelihood of disposing of the respective project-specific assets significantly before the end of their useful lives. Antelope Valley Solar Ranch One. In December 2011, the DOE Loan Programs Office issued a guarantee for up to $ 646 million for a nonrecourse loan from the Federal Financing Bank to support the financing of the construction of the Antelope Valley facility. The project became fully operational in 2014. The loan will mature in January 2037. Interest rates on the loan were fixed upon each advance at a spread of 37.5 basis points above U.S. Treasuries of comparable maturity. The advances were completed in December 2015 and the outstanding loan balance bears interest at an average blended interest rate of 2.82 %. As of December 31, 2024 and 2023, approximately $ 365 million and $ 390 million were outstanding, respectively. In addition, we have issued letters of credit to support the equity investment in the project, with $ 36 million outstanding as of December 31, 2024 and 2023. In December 2017, our interests in Antelope Valley were contributed to and are pledged as collateral for the CR financing structures referenced below. Continental Wind, LLC. In September 2013, Continental Wind, our indirect subsidiary, completed the issuance and sale of $ 613 million senior secured notes. Continental Wind owns and operates a portfolio of wind farms in Idaho, Kansas, Michigan, Oregon, New Mexico and Texas with a total net capacity of 667 MWs. The net proceeds were distributed to us for general business purposes. The notes are scheduled to mature in February 2033. The notes bear interest at a fixed rate of 6.00 % with interest payable semi-annually. As of December 31, 2024 and 2023, approximately $ 290 million and $ 315 million were outstanding, respectively. In addition, Continental Wind has a $ 128 million letter of credit facility and $ 4 million working capital revolver facility. Continental Wind has issued letters of credit to satisfy certain of its credit support and security obligations. As of December 31, 2024 and 2023, the Continental Wind letter of credit facility had $ 119 million and $ 116 million in letters of credit outstanding related to the project, respectively. In 2017, our interests in Continental Wind were contributed to CRP, whose assets were contributed to and are pledged as collateral for the CR financing structure referenced below. Renewable Power Generation. In March 2016, RPG, our indirect subsidiary, issued $ 150 million aggregate principal amount of nonrecourse senior secured notes. The net proceeds were distributed to us for paydown of long-term debt obligations at Sacramento PV Energy and Constellation Solar Horizons and for general business purposes. The loan is scheduled to mature in March 2035. The term loan bears interest at a fixed rate of 4.11 % payable semi-annually. As of December 31, 2024 and 2023, approximately $ 60 million and $ 70 million were outstanding, respectively. In 2017, our interests in RPG were contributed to CRP, whose assets were contributed to and are pledged as collateral for the CR financing structure referenced below. Constellation Renewables. In December 2020, CR entered into a financing agreement for a $ 750 million nonrecourse senior secured term loan credit facility, scheduled to mature in December 2027. Beginning in July 2024, the term loan bears interest at a variable rate equal to 3-month SOFR + 2.25 %, subject to a 1 % SOFR floor with interest payable quarterly. Redemptions from June 2023 through June 2024 were based on 3-month SOFR + 2.76 %. Redemptions prior to June 2023 were based on LIBOR + 2.50 %. In addition to the financing, CR entered interest rate swaps to manage a portion of the interest rate exposure in connection with the financing. The swap had an initial notional amount of $ 516 million and fixed the 3-month LIBOR at 1.05 %. Beginning in June 2023, the swap fixed the 3-month SOFR at 0.8295 %. The swap expired in December 2024. In January 2024, CR entered an additional interest rate swap to manage a portion of the interest rate exposure in connection with the financing. The swap had a notional amount of $ 120 M and fixed the 3-month SOFR to 3.98 %. Our interests in CRP and Antelope Valley are contributed to and pledged as collateral for this financing. As of December 31, 2024 and 2023, $ 630 million and $ 650 million was outstanding, respectively. See Note 21 — Variable Interest Entities for additional information on CRP and Note 15 — Derivative Financial Instruments for additional information on interest rate swaps. 141 Table of Contents Combined Notes to Consolidated Financial Statements (Dollars in millions, unless otherwise noted) Note 16 — Debt and Credit Agreements West Medway II, LLC. In May 2021, West Medway II, LLC (West Medway II), our indirect subsidiary, entered into a financing agreement for a $ 150 million nonrecourse senior secured term loan credit facility with a maturity date in March 2026. Beginning in May 2023, the term loan bears interest at a variable rate equal to 1-month SOFR plus the variable interest rate of 2.975 % - 3.225 %, paid quarterly. Redemptions prior to May 2023 were based on LIBOR + 2.875 %. In addition to the financing, West Medway II entered interest rate swaps to manage a portion of the interest rate exposure in connection with the financing. The swaps had an initial notional amount of $ 113 million and fixed the 1-month LIBOR at 0.61 %. Beginning in May 2023, the swap fixed the 1-month SOFR at 0.5365 %. We used the net proceeds for general corporate purposes. Our interests in West Medway II, were pledged as collateral for this financing. As of December 31, 2024 and 2023, approximately $ 50 million and $ 85 million was outstanding, respectively. See Note 15 — Derivative Financial Instruments for additional information on interest rate swaps. 17. 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 tables present the carrying amounts and fair values of our long-term debt and the SNF obligation as of December 31, 2024 and 2023. 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. December 31, 2024 December 31, 2023 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 $ 8,412 $ 7,805 $ 716 $ 8,521 $ 7,617 $ 7,140 $ 774 $ 7,914 SNF Obligation 1,366 1,278 — 1,278 1,296 1,222 — 1,222 142 Table of Contents Combined Notes to Consolidated Financial Statements (Dollars in millions, unless otherwise noted) Note 17 — Fair Value of Financial Assets and Liabilities We use the following methods and assumptions to estimate fair value of our financial liabilities recorded at carrying cost: Type Level Valuation Long-term Debt, including amounts due within one year Taxable Debt Securities 2 The fair value is determined by a valuation model that is based on a conventional discounted cash flow methodology and utilizes assumptions of current market pricing curves. We obtain credit spreads based on trades of our existing debt securities as well as other issuers in the utility sector with similar credit ratings. The yields are then converted into discount rates of various tenors that are used for discounting the respective cash flows of the same tenor for each bond or note. Variable Rate Financing Debt 2 Debt rates are reset on a regular basis and the carrying value approximates fair value. Government-Backed Fixed Rate Project Financing Debt 3 The fair value is similar to the process for taxable debt securities. Due to the lack of market trading data on similar debt, the discount rates are derived based on the original loan interest rate spread to the applicable U.S. Treasury rate as well as a current market curve derived from government-backed securities. Non-Government-Backed Fixed Rate Nonrecourse Debt 3 Fair value is based on market and quoted prices for its own and other nonrecourse debt with similar risk profiles. Given the low trading volume in the nonrecourse debt market, the price quotes used to determine fair value will reflect certain qualitative factors, such as market conditions, investor demand, new developments that might significantly impact the project cash flows or off-taker credit, and other circumstances related to the project. SNF Obligation SNF Obligation 2 The carrying amount is derived from a contract with the DOE to provide for disposal of SNF from certain of our nuclear generating stations. See Note 18 — Commitments and Contingencies for further details. When determining the fair value of the obligation, the future carrying amount of the SNF obligation is calculated by compounding the current book value of the SNF obligation at the 13-week U.S. Treasury rate. The compounded obligation amount is discounted back to present value using our discount rate, which is calculated using the same methodology as described above for the taxable debt securities, and an estimated maturity date of 2040 and 2035 for the years ended December 31, 2024 and 2023, respectively. 143 Table of Contents Combined Notes to Consolidated Financial Statements (Dollars in millions, unless otherwise noted) Note 17 — Fair Value of Financial Assets and Liabilities Recurring Fair Value Measurements The following tables present assets and liabilities measured and recorded at fair value in the Consolidated Balance Sheets on a recurring basis and their level within the fair value hierarchy as of December 31, 2024 and 2023: As of December 31, 2024 As of December 31, 2023 Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total Assets Cash equivalents (a) $ 120 $ — $ — $ 120 $ 42 $ — $ — $ 42 NDT fund investments Cash equivalents (b) 187 163 — 350 356 87 — 443 Equities 5,230 1,897 — 7,127 4,574 1,990 1 6,565 Fixed income 2,089 1,462 368 3,919 2,043 1,523 277 3,843 Private credit — — 134 134 — — 151 151 Assets measured at NAV — — — 5,791 — — — 5,396 NDT fund investments subtotal (c) 7,506 3,522 502 17,321 6,973 3,600 429 16,398 Rabbi trust investments 58 41 1 100 48 33 1 82 Investments in equities 389 — — 389 372 — — 372 Mark-to-market derivative assets Economic hedges 1,278 5,306 2,641 9,225 2,330 5,821 3,143 11,294 Proprietary trading — — — — — — 2 2 Effect of netting and allocation of collateral ( 1,097 ) ( 4,790 ) ( 2,123 ) ( 8,010 ) ( 1,996 ) ( 5,195 ) ( 1,931 ) ( 9,122 ) Mark-to-market derivative assets subtotal 181 516 518 1,215 334 626 1,214 2,174 DPP consideration — — — — — 1,216 — 1,216 Total assets measured at fair value 8,254 4,079 1,021 19,145 7,769 5,475 1,644 20,284 Liabilities Mark-to-market derivative liabilities Economic hedges ( 1,222 ) ( 5,462 ) ( 2,778 ) ( 9,462 ) ( 2,681 ) ( 7,154 ) ( 2,736 ) ( 12,571 ) Proprietary trading — — — — — — ( 2 ) ( 2 ) Effect of netting and allocation of collateral 1,180 5,157 2,259 8,596 2,587 6,542 2,393 11,522 Mark-to-market derivative liabilities subtotal ( 42 ) ( 305 ) ( 519 ) ( 866 ) ( 94 ) ( 612 ) ( 345 ) ( 1,051 ) Deferred compensation obligation — ( 93 ) — ( 93 ) — ( 69 ) — ( 69 ) Total liabilities measured at fair value ( 42 ) ( 398 ) ( 519 ) ( 959 ) ( 94 ) ( 681 ) ( 345 ) ( 1,120 ) Total net assets $ 8,212 $ 3,681 $ 502 $ 18,186 $ 7,675 $ 4,794 $ 1,299 $ 19,164 __________ (a) CEG Parent has $ 130 million and $ 54 million of Level 1 cash equivalents as of December 31, 2024 and 2023, respectively. We exclude cash of $ 2,924 million and $ 349 million, and restricted cash of $ 71 million and $ 49 million, as of December 31, 2024 and 2023, respectively. CEG Parent has excluded an additional $ 4 million and $ 2 million of cash as of December 31, 2024 and 2023, respectively. (b) Includes net liabilities of $ 148 million and $ 115 million as of December 31, 2024 and 2023, 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 total notional amounts of $ 1,119 million and $ 948 million as of December 31, 2024 and 2023, 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. 144 Table of Contents Combined Notes to Consolidated Financial Statements (Dollars in millions, unless otherwise noted) Note 17 — Fair Value of Financial Assets and Liabilities As of December 31, 2024, our NDTs have outstanding commitments to invest in private credit, private equity, and real assets of $ 482 million, $ 311 million, and $ 791 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 $ 150 million and $ 103 million as of December 31, 2024 and 2023, respectively. Changes in fair value, cumulative adjustments, and impairments were not material for the years ended December 31, 2024 and 2023. 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 years ended December 31, 2024 and 2023: For the Year Ended December 31, 2024 NDT Fund Investments Mark-to-Market Derivatives Rabbi Trust Investments Total Balance as of January 1, 2024 $ 429 $ 869 $ 1 $ 1,299 Total realized / unrealized gains (losses) Included in net income (loss) 5 ( 861 ) (a) — ( 856 ) Included in Payables related to Regulatory Agreement Units 16 — — 16 Change in collateral — ( 325 ) — ( 325 ) Purchases, sales, issuances and settlements Purchases 66 61 — 127 Sales — ( 83 ) — ( 83 ) Settlements ( 15 ) 29 — 14 Transfers into Level 3 1 44 (b) — 45 Transfers out of Level 3 — 265 (b) — 265 Balance as of December 31, 2024 $ 502 $ ( 1 ) $ 1 $ 502 The amount of total gains (losses) included in income attributed to the change in unrealized gains (losses) related to assets and liabilities as of December 31, 2024 $ 5 $ ( 126 ) $ — $ ( 121 ) 145 Table of Contents Combined Notes to Consolidated Financial Statements (Dollars in millions, unless otherwise noted) Note 17 — Fair Value of Financial Assets and Liabilities For the Year Ended December 31, 2023 NDT Fund Investments Mark-to-Market Derivatives Rabbi Trust Investments Total Balance as of January 1, 2023 $ 423 $ 219 $ 1 $ 643 Total realized / unrealized gains (losses) Included in net income (loss) 2 171 (a) — 173 Included in Payables related to Regulatory Agreement Units 10 — — 10 Change in collateral — 243 — 243 Purchases, sales, issuances and settlements Purchases — 160 — 160 Sales 1 ( 29 ) — ( 28 ) Settlements ( 7 ) 32 — 25 Transfers into Level 3 — 46 (b) — 46 Transfers out of Level 3 — 27 (b) — 27 Balance as of December 31, 2023 $ 429 $ 869 $ 1 $ 1,299 The amount of total gains (losses) included in income attributed to the change in unrealized gains (losses) related to assets and liabilities as of December 31, 2023 $ 2 $ 1,194 $ — $ 1,196 __________ (a) Includes a reduction of ($ 706 ) million and ($ 991 ) million for realized gains due to the settlement of derivative contracts for the years ended December 31, 2024 and 2023, respectively. (b) 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 years ended December 31, 2024, 2023, and 2022: Operating Revenues Purchased Power and Fuel Other, net 2024 2023 2022 2024 2023 2022 2024 2023 2022 Total gains (losses) included in net income $ ( 539 ) $ 706 $ ( 860 ) $ ( 293 ) $ ( 503 ) $ 5 $ 5 $ 2 $ ( 4 ) Total unrealized gains (losses) 207 1,673 ( 1,330 ) ( 333 ) ( 479 ) 65 5 2 ( 2 ) Valuation Techniques Used to Determine Fair Value Cash Equivalents. Investments with original maturities of three months or less when purchased, including mutual and money market funds, are considered cash equivalents. The fair values are based on observable market prices and, therefore, are included in the recurring fair value measurements hierarchy as Level 1. NDT Fund Investments. The trust fund investments have been established to satisfy our nuclear decommissioning obligations as required by the NRC. The NDT funds hold debt and equity securities directly and indirectly through commingled funds and mutual funds, which are included in equities and fixed income. Our NDT fund investments policies outline investment guidelines for the trusts and limit the trust funds’ exposures to investments in highly illiquid markets and other alternative investments, including private credit, private equity, and real assets. Investments with maturities of three months or less when purchased, including certain short-term fixed income securities are considered cash equivalents and included in the recurring fair value measurements hierarchy as Level 1 or Level 2. 146 Table of Contents Combined Notes to Consolidated Financial Statements (Dollars in millions, unless otherwise noted) Note 17 — Fair Value of Financial Assets and Liabilities Equities. These investments consist of individually held equity securities, equity mutual funds, and equity commingled funds in domestic and foreign markets. With respect to individually held equity securities, the trustees obtain prices from pricing services, whose prices are generally obtained from direct feeds from market exchanges, which we are able to independently corroborate. Equity securities held individually, including real estate investment trusts, rights, and warrants, are primarily traded on exchanges that contain only actively traded securities due to the volume trading requirements imposed by these exchanges. The equity securities that are held directly by the trust funds are valued based on quoted prices in active markets and categorized as Level 1. Certain equity securities have been categorized as Level 2 because they are based on evaluated prices that reflect observable market information, such as actual trade information or similar securities. Certain private placement equity securities are categorized as Level 3 because they are not publicly traded and are priced using significant unobservable inputs. Equity commingled funds and mutual funds are maintained by investment companies, and fund investments are held in accordance with a stated set of fund objectives. The values of some of these funds are publicly quoted. For mutual funds which are publicly quoted, the funds are valued based on quoted prices in active markets and have been categorized as Level 1. For equity commingled funds and mutual funds which are not publicly quoted, the fund administrators value the funds using the NAV per fund share, derived from the quoted prices in active markets on the underlying securities and are not classified within the fair value hierarchy. These investments can typically be redeemed monthly or more frequently, with 30 or less days of notice and without further restrictions. Fixed income. For fixed income securities, which consist primarily of corporate debt securities, U.S. government securities, foreign government securities, municipal bonds, asset and mortgage-backed securities, commingled funds, mutual funds, and derivative instruments, the trustees obtain multiple prices from pricing vendors whenever possible, which enables cross-provider validations in addition to checks for unusual daily movements. A primary price source is identified based on asset type, class, or issue for each security. With respect to individually held fixed income securities, the trustees monitor prices supplied by pricing services and may use a supplemental price source or change the primary price source of a given security if the portfolio managers challenge an assigned price and the trustees determine that another price source is preferable. We have obtained an understanding of how these prices are derived, including the nature and observability of the inputs used in deriving such prices. Additionally, we selectively corroborate the fair values of securities by comparison to other market-based price sources. Investments in U.S. Treasury securities have been categorized as Level 1 because they trade in highly-liquid and transparent markets. Certain private placement fixed income securities have been categorized as Level 3 because they are priced using certain significant unobservable inputs and are typically illiquid. The remaining fixed income securities, including certain other fixed income investments, are based on evaluated prices that reflect observable market information, such as actual trade information of similar securities, adjusted for observable differences and are categorized as Level 2. This includes equity investments sold short during the period, which represent liabilities. Other fixed income investments primarily consist of fixed income commingled funds and mutual funds, which are maintained by investment companies and hold fund investments in accordance with a stated set of fund objectives. The values of some of these funds are publicly quoted. For mutual funds which are publicly quoted, the funds are valued based on quoted prices in active markets and have been categorized as Level 1. For fixed income commingled funds and mutual funds which are not publicly quoted, the fund administrators value the funds using the NAV per fund share, derived from the quoted prices in active markets of the underlying securities and are not classified within the fair value hierarchy. These investments typically can be redeemed monthly or more frequently, with 30 or less days of notice and without further restrictions. Derivative instruments. These instruments, consisting primarily of futures and swaps to manage risk, are recorded at fair value. Over-the-counter derivatives are valued daily, based on quoted prices in active markets and trade in open markets, and have been categorized as Level 1. Derivative instruments other than over-the-counter derivatives are valued based on external price data of comparable securities and have been categorized as Level 2. Private credit. Private credit investments primarily consist of investments in private debt strategies. These investments are generally less liquid assets with an underlying term of 3 to 5 years and are intended to be held to maturity. The fair value of these investments is determined by the fund manager or administrator using a combination of valuation models including cost models, market models, and income models and typically cannot be redeemed until maturity of the term loan. Private credit investments held directly by us are categorized as Level 3 because they are based largely on inputs that are unobservable and utilize complex valuation models. 147 Table of Contents Combined Notes to Consolidated Financial Statements (Dollars in millions, unless otherwise noted) Note 17 — Fair Value of Financial Assets and Liabilities For certain private credit funds, the fair value is determined using a combination of valuation models including cost models, market models, and income models and typically cannot be redeemed until maturity of the term loan. These investments are not classified within the fair value hierarchy because their fair value is determined using NAV or its equivalent as a practical expedient. Private equity. These investments include those in limited partnerships that invest in operating companies that are not publicly traded on a stock exchange such as leveraged buyouts, growth capital, venture capital, distressed investments, and investments in natural resources. These investments typically cannot be redeemed and are generally liquidated over a period of 8 to 10 years from the initial investment date, which is based on our understanding of the investment funds. Private equity valuations are reported by the fund manager and are based on the valuation of the underlying investments, which include unobservable inputs such as cost, operating results, discounted future cash flows, and market-based comparable data. These valuation inputs are unobservable. The fair value of private equity investments is determined using NAV or its equivalent as a practical expedient, and therefore, these investments are not classified within the fair value hierarchy. Real assets. These investments are funds with a direct investment in pools of real estate properties or infrastructure assets. These funds are reported by the fund manager and are generally based on independent appraisals of the underlying investments from sources with professional qualifications, typically using a combination of market-based comparable data and discounted cash flows. These valuation inputs are unobservable. Certain real asset investments cannot be redeemed and are generally liquidated over a period of 8 to 25 years from the initial investment date, which is based on our understanding of the investment funds. The remaining liquid real asset investments are generally redeemable from the investment vehicle quarterly, with 30 to 90 days of notice. The fair value of real asset investments is determined using NAV or its equivalent as a practical expedient, and therefore, these investments are not classified within the fair value hierarchy. We evaluated our NDT portfolios for the existence of significant concentrations of credit risk as of December 31, 2024. Types of concentrations that were evaluated include, but are not limited to, investment concentrations in a single entity, type of industry, foreign country, and individual fund. As of December 31, 2024, there were no significant concentrations (generally defined as greater than 10 percent) of risk in the NDT assets. See Note 10 — Asset Retirement Obligations for additional information on the NDT fund investments. Rabbi Trust Investments. The Rabbi trusts were established to hold assets related to deferred compensation plans existing for certain active and retired members of executive management and directors. The Rabbi trusts' assets are included in investments in the Consolidated Balance Sheets and consist primarily of money market funds, mutual funds, and life insurance policies. Money market funds and mutual funds are publicly quoted and have been categorized as Level 1 given the clear observability of the prices. The life insurance policies are valued using the cash surrender value of the policies, net of loans against those policies, which is provided by a third-party. Certain life insurance policies, which consist primarily of mutual funds that are priced based on observable market data, have been categorized as Level 2 because the life insurance policies can be liquidated at the reporting date for the value of the underlying assets. Deferred Compensation Obligations. Our deferred compensation plans allow participants to defer certain cash compensation into a notional investment account. We include such plans in other current and noncurrent liabilities in the Consolidated Balance Sheets. The value of our deferred compensation obligations is based on the market value of the participants’ notional investment accounts. The underlying notional investments are comprised primarily of equities, mutual funds, commingled funds, and fixed income securities which are based on directly and indirectly observable market prices. Since the deferred compensation obligations themselves are not exchanged in an active market, they are categorized as Level 2 in the fair value hierarchy. The value of certain employment agreement obligations (which are included with the Deferred compensation obligation in the table above) are based on a known and certain stream of payments to be made over time and are categorized as Level 2 within the fair value hierarchy. Investments in Equities. We hold certain investments in equity securities with readily determinable fair values in addition to those held within the NDT funds. These equity securities are valued based on quoted prices in active markets and are categorized as Level 1. 148 Table of Contents Combined Notes to Consolidated Financial Statements (Dollars in millions, unless otherwise noted) Note 17 — Fair Value of Financial Assets and Liabilities Deferred Purchase Price Consideration. We had DPP consideration for the sale of certain receivables of retail electricity. This amount was valued based on the sales price of the receivables net of allowance for credit losses (see Note 1 — Basis of Presentation for additional details on our policy for credit losses). Since the DPP consideration was based on the sales price of the receivables, it was categorized as Level 2 in the fair value hierarchy. See Note 7 — Accounts Receivable for additional information on the sale of certain customer accounts receivables. Mark-to-Market Derivatives. Derivative contracts are traded in both exchange-based and non-exchange-based markets. Exchange-based derivatives that are valued using unadjusted quoted prices in active markets are categorized in Level 1 in the fair value hierarchy. Certain derivatives’ pricing is verified using indicative price quotations available through brokers, over-the-counter, or exchanges and are categorized in Level 2. These price quotations reflect the average of the bid-ask, mid-point prices and are obtained from sources that we believe provide the most liquid market for the commodity. The price quotations are reviewed and corroborated to ensure the prices are observable and representative of an orderly transaction between market participants. This includes consideration of actual transaction volumes, market delivery points, bid-ask spreads, and contract duration. The remainder of derivative contracts are valued using the Black model, an industry standard option valuation model. The Black model considers inputs such as contract terms, including maturity, and market parameters, including assumptions of the future prices of energy, interest rates, volatility, credit worthiness, and credit spread. For derivatives that trade in liquid markets, such as generic forwards, swaps, and options, model inputs are generally observable. Such instruments are categorized in Level 2. Our derivatives are predominantly at liquid trading points. For derivatives that trade in less liquid markets with limited pricing information, model inputs generally would include both observable and unobservable inputs. These valuations may include an estimated basis adjustment from an illiquid trading point to a liquid trading point for which active price quotations are available. Such instruments are categorized in Level 3. For valuations that include both observable and unobservable inputs, if the unobservable input is determined to be significant to the overall inputs, the entire valuation is categorized in Level 3. This includes derivatives valued using indicative price quotations whose contract tenure extends into unobservable periods. In instances where observable data is unavailable, consideration is given to the assumptions that market participants would use in valuing the asset or liability. This includes assumptions about market risks such as liquidity, volatility, and contract duration. Such instruments are categorized in Level 3 as the model inputs generally are not observable. We consider credit and non-performance risk in the valuation of derivative contracts categorized in Level 2 and 3, including both historical and current market data, in our assessment of credit and non-performance risk by counterparty. Due to master netting agreements and collateral posting requirements, the impacts of credit and non-performance risk were not material to the consolidated financial statements. Disclosed below is detail surrounding our significant Level 3 valuations. The calculated fair value includes marketability discounts for margining provisions and other attributes. The Level 3 balance generally consists of forward sales and purchases of power and natural gas and certain transmission congestion contracts. We utilize various inputs and factors including market data and assumptions that market participants would use in pricing assets or liabilities as well as assumptions about the risks inherent in the inputs to the valuation technique. The inputs and factors include forward commodity prices, commodity price volatility, contractual volumes, delivery location, interest rates, credit quality of counterparties, and credit enhancements. For commodity derivatives, the primary input to the valuation models is the forward commodity price curve for each instrument. All locations are reviewed and verified by risk management considering published exchange transaction prices, executed bilateral transactions, broker quotes, and other observable or public data sources. The relevant forward commodity curve used to value each of the derivatives depends on a number of factors, including commodity type, delivery location, and delivery period. Price volatility varies by commodity and location. When appropriate, we discount future cash flows using risk-free interest rates with adjustments to reflect the credit quality of each counterparty for assets and our own credit quality for liabilities. The level of observability of a forward commodity price varies generally due to the delivery location and delivery period. Certain delivery locations including PJM West Hub (for power) and Henry Hub (for natural gas) are more liquid and prices are observable for up to three years in the future. The observability period of volatility is generally shorter than the underlying power curve used in option valuations. The forward curve for a less liquid location is estimated by using the forward curve from the liquid location and applying a spread to represent the cost to transport the commodity to the delivery location. This spread does not typically represent a majority of the instrument’s market price. As a result, the change in fair value is closely tied to liquid market movements and not a change in the applied spread. The change in fair value associated with a change in the spread is generally immaterial. An 149 Table of Contents Combined Notes to Consolidated Financial Statements (Dollars in millions, unless otherwise noted) Note 17 — Fair Value of Financial Assets and Liabilities average spread calculated across all Level 3 power and gas delivery locations is approximately $ 48.71 and $ 3.68 for power and natural gas, respectively as of December 31, 2024. Many of the commodity derivatives are short term in nature and thus a majority of the fair value may be based on observable inputs even though the contract as a whole must be classified as Level 3. See Note 15 — Derivative Financial Instruments for additional information on mark-to-market derivatives. The following table presents the significant inputs to the forward curve used to value these positions: Type of trade Fair Value as of December 31, 2024 Fair Value as of December 31, 2023 Valuation Technique Unobservable Input 2024 Range & Arithmetic Average 2023 Range & Arithmetic Average Mark-to-market derivatives—Economic hedges (a)(b) $ ( 137 ) $ 407 Discounted Cash Flow Forward power price $ 2.57 - $ 140 $ 49 $ 9.64 - $ 216 $ 48 Forward gas price $ 2.09 - $ 15 $ 3.68 $ 1.20 - $ 14 $ 3.09 Option Model Volatility percentage 23 % - 141 % 57 % 23 % - 200 % 87 % __________ (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 $ 136 million and $ 462 million as of December 31, 2024 and 2023, 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. 18. Commitments and Contingencies Commercial Commitments. Commercial commitments as of December 31, 2024, representing commitments potentially triggered by future events, were as follows: Expiration within 2025 2026 2027 2028 2029 2030 and beyond Total Letters of credit $ 1,924 $ 127 $ 1 $ 120 $ — $ 1 $ 2,173 Surety bonds (a) 526 1 — 214 — — 741 Total commercial commitments $ 2,450 $ 128 $ 1 $ 334 $ — $ 1 $ 2,914 __________ (a) Surety bonds — Guarantees issued related to contract and commercial agreements, excluding bid bonds. Nuclear Insurance We are subject to liability, property damage and other risks associated with major incidents at any of our nuclear stations. Our financial exposure to these risks is mitigated through insurance and other industry risk-sharing provisions. The Price-Anderson Act was enacted to ensure the availability of funds for public liability claims arising from an incident at any of the U.S. licensed nuclear facilities and to limit the liability of nuclear reactor owners for such 150 Table of Contents Combined Notes to Consolidated Financial Statements (Dollars in millions, unless otherwise noted) Note 18 — Commitments and Contingencies claims from any single incident. As of December 31, 2024, the current liability limit per incident is $ 16.3 billion and is subject to change to account for the effects of inflation and changes in the number of licensed reactors at least once every five years with the last adjustment effective January 1, 2024. In accordance with the Price-Anderson Act, we maintain financial protection at levels equal to the amount of liability insurance available from private sources through the purchase of private nuclear energy liability insurance for public liability claims that could arise in the event of an incident. Effective January 1, 2024, the required amount of nuclear energy liability insurance purchased is $ 500 million for each operating site. Claims exceeding that amount are covered through mandatory participation in a financial protection pool, as required by the Price Anderson-Act, which could provide up to approximately an additional $ 15.8 billion per incident at any U.S. nuclear power reactor in funds available for public liability claims. Participation in this secondary financial protection pool requires the operator of each reactor to fund its proportionate share of costs for any single incident at any U.S. nuclear power reactor that exceeds the primary layer of financial protection. Our share of this secondary layer would be approximately $ 3.5 billion, based on our ownership interest in the insured nuclear reactors, however, any amounts payable under this secondary layer would be capped at $ 520 million per incident within one calendar year. In addition, the U.S. Congress could impose revenue-raising measures on the nuclear industry to pay public liability claims exceeding the $ 16.3 billion limit for a single incident. We are required by the NRC to maintain minimal levels of property insurance that demonstrates to the satisfaction of the NRC that we possess an equivalent amount of protection covering the licensee's obligation, in the event of an accident at the licensee's reactor, to stabilize and decontaminate the reactor and the reactor station site at which the reactor experiencing the accident is located. The insurance maintained for each facility is currently provided through insurance policies purchased from NEIL, an industry mutual insurance company of which we are a member. Currently, NRC requires that we maintain a minimum coverage limit for each reactor site of $ 1.06 billion, and we currently have coverage of $ 1.5 billion for each site. NEIL may declare distributions to its members as a result of favorable operating experience. In recent years, NEIL has made distributions to its members. Our portion of the annual distribution declared by NEIL is estimated to be $ 43 million for 2024, and was $ 59 million and $ 30 million for 2023 and 2022, respectively. The distributions were recorded as a reduction to Operating and maintenance expense in the Consolidated Statements of Operations and Comprehensive Income. Premiums paid to NEIL by its members are also subject to a potential assessment for adverse loss experience in the form of a retrospective premium obligation. NEIL has never assessed this retrospective premium since its formation in 1973, and we cannot predict the level of future assessments, if any. The current maximum aggregate annual retrospective premium obligation for our interests is approximately $ 268 million. NEIL requires its members to maintain an investment grade credit rating or to ensure collectability of their annual retrospective premium obligation by providing a financial guarantee, letter of credit, deposit premium, or some other means of assurance. NEIL provides “all risk” property damage, decontamination, and premature decommissioning insurance for each station for losses resulting from damage to its nuclear plants, either due to accidents or acts of terrorism. If the decision is made to decommission the facility, a portion of the insurance proceeds will be allocated to a fund, which we are required by the NRC to maintain, to provide for decommissioning the facility. In the event of an insured loss, we are unable to predict the timing of the availability of insurance proceeds to us and the amount of such proceeds that would be available. In the event that one or more acts of terrorism cause accidental property damage within a twelve-month period from the first accidental property damage under one or more policies for all insured plants, the maximum recovery by us will be an aggregate of $ 3.2 billion plus such additional amounts as the insurer may recover for all such losses from reinsurance, indemnity and any other source, applicable to such losses. For our insured losses, we are self-insured to the extent that losses are within the policy deductible or exceed the amount of insurance maintained. Uninsured losses and other expenses, to the extent not recoverable from insurers or the nuclear industry, could also be borne by us. Any such losses could have a material adverse effect on our consolidated financial statements. 151 Table of Contents Combined Notes to Consolidated Financial Statements (Dollars in millions, unless otherwise noted) Note 18 — Commitments and Contingencies Spent Nuclear Fuel Obligation Under the Nuclear Waste Policy Act of 1982 (NWPA), the DOE is responsible for the development of a geologic repository for and the disposal of SNF and high-level radioactive waste. As required by the NWPA, we are a party to contracts with the DOE (Standard Contracts) to provide for disposal of SNF from our nuclear generating stations. In accordance with the NWPA and the Standard Contracts, we had previously paid the DOE one mill ($0.001) per kWh of net nuclear generation for the cost of SNF disposal. The DOE reduced the SNF disposal fee to zero in May 2014. Until a new fee structure is in effect, we will not accrue any further costs related to SNF disposal fees. This fee may be adjusted prospectively to ensure full cost recovery. We currently assume the DOE will begin accepting SNF in 2040 and use that date for purposes of estimating the nuclear decommissioning AROs. The SNF acceptance date assumption is based on management’s estimate of the amount of time required for DOE to select a site location and develop the necessary infrastructure for long-term SNF storage. The NWPA and the Standard Contracts required the DOE to begin taking possession of SNF generated by nuclear generating units no later than January 31, 1998. The DOE, however, failed to meet that deadline and its performance has been, and is expected to remain, delayed. In August 2004, we and the DOJ, in close consultation with the DOE, reached a settlement under which the government agreed to reimburse us, subject to certain damage limitations based on the extent of the government’s breach, for costs associated with storage of SNF at our nuclear stations pending the DOE’s fulfillment of its obligations. That settlement agreement does not expire until all SNF has been collected from the sites that it covers. Calvert Cliffs, Ginna, NMP, Fitzpatrick, and STP each have separate settlement agreements in place with the DOE which were extended during 2023 to provide for the reimbursement of SNF storage costs through December 31, 2025. We and the DOE have the option to extend those settlements every three years upon mutual consent. Under the settlement agreements, we received total cumulative cash reimbursements of $ 2,099 million through December 31, 2024 for costs incurred. After considering the amounts due to co-owners of certain nuclear stations and to the current owner of Oyster Creek Nuclear Generating Station, we received net cumulative cash reimbursements of $ 1,829 million. As of December 31, 2024 and 2023, the amount of SNF storage costs for which reimbursement has been or will be requested from the DOE under the DOE settlement agreements is as follows: December 31, 2024 December 31, 2023 DOE receivable - current (a) $ 124 $ 229 DOE receivable - noncurrent (b) 42 40 Amounts owed to co-owners (c) ( 40 ) ( 23 ) __________ (a) Recorded in Other accounts receivable. (b) Recorded in Other deferred debits and other assets. (c) Recorde d primarily in Accounts payable and accrued expenses and Other accounts receivable. Represents amounts owed to the co-owners of Peach Bottom, Quad Cities, and NMP Unit 2 generating facilitie s . The Standard Contracts with the DOE also required the payment to the DOE of a one-time fee applicable to nuclear plants that generated SNF prior to April 7, 1983. The below table outlines the SNF liability recorded as of December 31, 2024 and 2023: December 31, 2024 December 31, 2023 Former ComEd units (a) $ 1,219 $ 1,158 Fitzpatrick (b) 147 138 Total SNF Obligation $ 1,366 $ 1,296 __________ (a) ComEd previously elected to defer payment of the one-time fee of $ 277 million for its units that began operations before April 7, 1983, with interest to the date of payment, until just prior to the first delivery of SNF to the DOE. The unfunded liabilities for SNF disposal costs, including the one-time fee, were transferred to us as part of Exelon’s 2001 corporate restructuring. See Note 10 — Asset Retirement Obligations for additional detail on Zion Station’s SNF obligation which is included in the table above. (b) A prior owner of FitzPatrick elected to defer payment of the one-time fee of $ 34 million, with interest to the date of payment, for the FitzPatrick unit. As part of the FitzPatrick acquisition on March 31, 2017, we assumed a SNF liability for 152 Table of Contents Combined Notes to Consolidated Financial Statements (Dollars in millions, unless otherwise noted) Note 18 — Commitments and Contingencies the DOE one-time fee obligation with interest related to FitzPatrick along with an offsetting asset, included in Other deferred debits and other assets, for the contractual right to reimbursement from NYPA, a prior owner of FitzPatrick, for amounts paid for the FitzPatrick DOE one-time fee obligation. Interest for our SNF liabilities accrues at the 13-week Treasury Rate. The 13-week Treasury Rate in effect for calculation of the interest accrual at December 31, 2024 was 4.553 % for the deferred amount transferred from ComEd and 4.615 % for the deferred FitzPatrick amount. The following table summarizes sites for which we do not have an outstanding SNF Obligation: Description Sites Fees have been paid or began operations after April 7, 1983 Former PECO units, Braidwood, Byron, Calvert Cliffs, Clinton, LaSalle Unit 2, NMP Unit 2, and STP Outstanding SNF Obligation remains with former owners NMP Unit 1, Ginna, and Crane 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 now 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 December 31, 2024 and 2023, we had accrued undiscounted amounts for environmental liabilities of $ 60 million and $ 61 million, respectively, in Accounts payable and accrued expenses and $ 169 million and $ 88 million, respectively, in Other deferred credits and other liabilities in the Consolidated Balance Sheets. Cotter Corporation. The EPA has advised Cotter Corporation (N.S.L.) (Cotter), a former ComEd subsidiary, that it is potentially liable in connection with radiological contamination at two sites in Missouri. In 2000, ComEd sold Cotter to an unaffiliated third-party. As part of the sale, ComEd agreed to indemnify Cotter for any liability arising from these two Missouri superfund sites, West Lake Landfill and Latty Avenue. In connection with Exelon’s 2001 corporate restructuring, this responsibility to indemnify Cotter was transferred to us, and ultimately retained by us per the terms of our separation from Exelon. Refer to Note 1 — Basis of Presentation for additional information on the separation. West Lake Landfill. Including Cotter, there are three PRPs currently participating in the West Lake Landfill remediation proceeding. West Lake Landfill; Operable Unit 1 (OU1); Landfill Remediation. In September 2018, the EPA issued its Record of Decision Amendment (RODA) for the selection of a final remedy that requires partial excavation of the radiological materials and capping the landfill. The EPA and the PRPs have entered into a Consent Agreement to perform the Remedial Design, which is expected to be completed in 2025. In March 2019, the PRPs received Special Notice Letters from the EPA to perform the Remedial Action work. The total estimated cost of the remedy, considering the current EPA technical requirements, is approximately $ 530 million, including cost escalation on an undiscounted basis. West Lake Landfill; Operable Unit 3 (OU3); Groundwater Study. In September 2018, the three identified PRPs, including Cotter, signed an Administrative Settlement Agreement and Order on Consent for the performance by the PRPs of the groundwater Remedial Investigation Feasibility Study (RI/FS). The purpose of this RI/FS is to define the nature and extent of any groundwater contamination from the West Lake Landfill site and evaluate remedial alternatives. We estimate the undiscounted cost for the groundwater RI/FS to be approximately $ 60 million. At this time we cannot predict the likelihood, or the extent to which remediation activities, if any, may be 153 Table of Contents Combined Notes to Consolidated Financial Statements (Dollars in millions, unless otherwise noted) Note 18 — Commitments and Contingencies required and therefore cannot estimate a reasonably possible range of loss for response costs beyond those associated with the RI/FS component. We determined a loss associated with the EPA's partial excavation and landfill cover remedy and the groundwater RI/FS is probable and have recorded a liability for each, both of which are included in the total amount as discussed above, that reflects management’s best estimate of Cotter’s allocable share of the cost among the PRPs. Given the joint and several nature of these two liabilities, the amount of our ultimate liability will depend on the actual costs incurred to implement the required remedy at OU1 and the required study at OU3, as well as on the nature and terms of any cost-sharing arrangements with the final group of PRPs. It is reasonably possible that the ultimate cost and Cotter's associated allocable share could differ significantly once these uncertainties are resolved, which could have a material impact on our consolidated financial statements. Latty Avenue and Vicinity Properties . In August 2011, Cotter was notified by the DOJ that Cotter is considered a PRP with respect to the government’s clean-up costs for contamination attributable to low-level radioactive residues at a former storage and reprocessing facility named Latty Avenue near St. Louis, Missouri. Latty Avenue was investigated and remediated by the United States Army Corps of Engineers pursuant to funding under the Formerly Utilized Sites Remedial Action Program. The PRPs reached a settlement of this matter and the government filed a motion for entry of a Consent Decree, which was entered by the Court on January 24, 2025. Payment of $ 50 million plus statutory interest was made on January 30, 2025. The consent decree settles past and future responses costs incurred by the United States Army Corp of Engineers and DOE for their response actions conducted in connection with the release or threatened release of hazardous substances, including radioactive substances at Latty Avenue and certain additional adjacent properties. The settlement amount for this matter is included in the total amount of environmental liabilities recognized as of December 31, 2024, referenced previously. Litigation General. We are involved in various other 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. Impacts of the February 2021 Extreme Cold Weather Event and Texas-based Generating Assets Outages. Beginning on February 15, 2021, our Texas-based generating assets within the ERCOT market, specifically Colorado Bend II, Wolf Hollow II, and Handley, experienced outages as a result of extreme cold weather conditions. Various lawsuits have been filed against us since the February 2021 event and outages. In March 2021, we, along with more than 150 power generators and transmission and distribution companies, were sued by approximately 160 individually named plaintiffs, purportedly on behalf of all Texans who allegedly suffered loss of life or sustained personal injury, property damage, or other losses as a result of the weather events. The plaintiffs alleged that the defendants failed to properly prepare for the cold weather and failed to properly conduct their operations, seeking compensatory as well as punitive damages. Thereafter, numerous other plaintiffs filed multiple lawsuits against more than 300 defendants, including us, involving similar allegations of liability and claims of personal injury and property damage all arising out of the February weather events. These additional lawsuits allege wrongful death, property damage, or other losses. Co-defendants in these lawsuits include ERCOT, transmission and distribution utilities and other generators. In December 2021, approximately 130 insurance companies which insured Texas homeowners and businesses filed a subrogation lawsuit against multiple defendants alleging that defendants were at fault for the energy failure that resulted from the winter storm, causing significant property damage to the insureds. Subsequently, several hundred other insurance companies filed similar claims. All of these cases were combined in a Multi-District-Litigation (MDL) pending in Texas state court, which established a bellwether process to consider initial motions to dismiss by the different industry groups of defendants. Defendants filed motions to dismiss the amended 154 Table of Contents Combined Notes to Consolidated Financial Statements (Dollars in millions, unless otherwise noted) Note 18 — Commitments and Contingencies complaints in five bellwether cases in July 2022. In February 2023, the court granted the motions to dismiss pertaining to us in part and denied them in part, leaving the plaintiffs' negligence and nuisance claims to proceed. Since the motions to dismiss were partially denied, thousands of new claimants, many in multiple mass tort actions, filed lawsuits in various Texas state courts naming us, among hundreds of other defendants. The majority of these cases were transferred to the MDL. The MDL involves over 200 cases brought by approximately 30,000 plaintiffs, including more than 1,300 insurance companies, and we are defendants in the majority of them. We are also named in an alleged class action that seeks to assert claims on behalf of over 4.1 million Texans within ERCOT who lost power during Winter Storm Uri. In December 2023, the Court of Appeals for the First District of Texas granted the power generator defendants' Petition for a Writ of Mandamus in the five bellwether cases and ordered the MDL court to dismiss the remaining claims against the power generator defendants, including our entities. The motions to dismiss in the five bellwether cases are expected to be applied to all the claims against the power generator defendants in the MDL. In January 2024, plaintiffs filed motions for en banc reconsideration of the order with the full court of appeals in all five bellwether cases. In November 2024, the court denied plaintiffs' motions. In January 2025, plaintiffs petitioned the Supreme Court of Texas for mandamus review, requesting that the court reinstate the MDL court's denial of the generator defendants' motions to dismiss and thereby permit plaintiffs' claims to proceed. In addition to the cases pending in the MDL in Texas state court, in January 2025, the Attorney General of the State of Oklahoma filed a lawsuit in state court against us, along with 10 other defendants, alleging antitrust and consumer protection act violations as well as unjust enrichment in connection with the sale, transport and marketing of natural gas to state agencies, municipalities and the people of the state of Oklahoma during the extreme cold weather event. The Attorney General seeks compensatory and punitive damages. We dispute liability and deny that we are responsible for any of plaintiffs’ alleged claims and are vigorously contesting them. No loss contingencies have been reflected in the consolidated financial statements with respect to these matters, nor can we currently estimate a range of loss. It is reasonably possible, however, that resolution of these matters could have a material, unfavorable impact on our consolidated financial statements. Asbestos Personal Injury Claims. We maintain a reserve for claims associated with asbestos-related personal injury actions at certain facilities that are currently owned by us or were previously owned by ComEd, PECO, or BGE. The estimated liabilities are recorded on an undiscounted basis and exclude the estimated legal costs associated with handling these matters, which could be material. At December 31, 2024 and 2023, we recorded estimated liabilities of approximately $ 125 million and $ 131 million, respectively, in total for asbestos-related bodily injury claims. As of December 31, 2024, approximately $ 14 million of this amount related to 203 open claims presented to us, while the remaining $ 111 million is for estimated future asbestos-related bodily injury claims anticipated to arise through 2055, based on actuarial assumptions and analyses, which are updated on an annual basis. On a quarterly basis, we monitor actual experience against the number of forecasted claims to be received and expected claim payments and evaluate whether adjustments to the estimated liabilities are necessary. 19. Shareholders' Equity Share Repurchase Program (CEG Parent) Since 2023, our Board of Directors authorized the repurchase of up to $ 3 billion of the Company's outstanding common stock. Share repurchases may be made through a variety of methods, which may include open market transactions, privately negotiated transactions, or purchases pursuant to a Rule 10b5-1 trading plan, provided that the amounts spent do not exceed what is authorized. Any repurchased shares are constructively retired and cancelled. The program does not obligate us to acquire a minimum number of shares during any period and our repurchase of CEG's common stock may be limited, suspended, or discontinued at any time at our discretion and without prior notice. No other repurchase plans or programs have been authorized. As of December 31, 2024, there was $ 991 million of remaining authority to repurchase shares of the Company's outstanding common stock. During 2024 and 2023, we repurchased from the open market approximately 1.2 million and 10.6 million shares, respectively, of our common stock for a total cost, inclusive of taxes and transaction costs, of $ 150 million and $ 1 billion, respectively. 155 Table of Contents Combined Notes to Consolidated Financial Statements (Dollars in millions, unless otherwise noted) Note 19 — Shareholders' Equity In 2024, we entered into ASR agreements with financial institutions to initiate share repurchases of our common stock. Under the ASR agreements, we paid a specified amount to the financial institution and received an initial delivery of shares of common stock, which resulted in an immediate reduction in the number of our shares outstanding. Based on the terms of the ASR agreements below, we received an initial share delivery based on 80 % of the ASR agreements' cost. Upon settlement of the ASR agreements, the financial institution delivers additional incremental shares. The total number of shares ultimately delivered, and therefore the average price paid per share, is determined at the end of the applicable purchase period of each ASR agreement based on the average of the daily volume weighted average share price, less a discount. The following table summarizes each ASR agreement for the year ended December 31, 2024: (in millions, except average price paid per share) ASR Agreement Initiation Total Cost Initial Shares Received ASR Agreement Settlement Additional Shares Received (a) Total Number of Shares Purchased Average Price Paid per Share March 2024 $ 354 1.7 May 2024 0.2 1.9 $ 182.65 May 2024 $ 505 1.8 July 2024 0.6 2.4 $ 211.40 __________ (a) The 0.6 million additional shares received and settled in July 2024 were rounded for footing. Changes in Accumulated Other Comprehensive Income (Loss) (All Registrants) The following tables present changes in AOCI, net of tax, by component: Gains (losses) on Cash Flow Hedges Pension and OPEB Plan Items (a) Foreign Currency Items Total Balance at December 31, 2021 $ ( 8 ) $ — $ ( 23 ) $ ( 31 ) Separation-related adjustments — ( 2,006 ) — ( 2,006 ) OCI before reclassifications ( 1 ) 186 ( 3 ) 182 Amounts reclassified from AOCI — 95 — 95 Net current-period OCI ( 1 ) ( 1,725 ) ( 3 ) ( 1,729 ) Balance at December 31, 2022 $ ( 9 ) $ ( 1,725 ) $ ( 26 ) $ ( 1,760 ) OCI before reclassifications ( 2 ) ( 453 ) 2 ( 453 ) Amounts reclassified from AOCI 1 21 — 22 Net current-period OCI ( 1 ) ( 432 ) 2 ( 431 ) Balance at December 31, 2023 $ ( 10 ) $ ( 2,157 ) $ ( 24 ) $ ( 2,191 ) OCI before reclassifications — ( 176 ) ( 10 ) ( 186 ) Amounts reclassified from AOCI 4 71 — 75 Net current-period OCI 4 ( 105 ) ( 10 ) ( 111 ) Balance at December 31, 2024 $ ( 6 ) $ ( 2,262 ) $ ( 34 ) $ ( 2,302 ) __________ (a) AOCI amounts are included in the computation of net periodic pension and OPEB cost. See Note 14 — 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): Year Ended December 31, 2024 2023 2022 Pension and OPEB plans: Actuarial loss reclassified to periodic benefit cost $ ( 24 ) $ ( 10 ) $ ( 33 ) Pension and OPEB plans valuation adjustment (a) 59 151 619 __________ (a) Includes $ 680 million of income tax benefit related to the separation adjustment for the year ended December 31, 2022. 156 Table of Contents Combined Notes to Consolidated Financial Statements (Dollars in millions, unless otherwise noted) Note 20 — Stock-Based Compensation Plans 20. Stock-Based Compensation Plans Effective February 1, 2022, we established our own LTIP and began granting cash and stock-based awards that primarily include performance share awards and restricted stock units. Our LTIP authorized 20,000,000 shares of common stock for these awards. The existing, unvested cash and stock-based awards issued through the Exelon LTIP were modified in connection with the separation to align with our performance metrics and maintain an equivalent value immediately before and after separation. The impact of this modification was not material to our stock-based compensation expense for the year ended December 31, 2022. Our employees were granted stock-based awards through the Exelon LTIP prior to separation, which primarily included performance share awards and restricted stock units. We also granted cash awards. The following table presents the stock-based compensation expense included in the Consolidated Statements of Operations and Comprehensive Income. The information does not include expenses related to the cash awards as they are not considered stock-based compensation plans under the applicable authoritative guidance: For the Years Ended December 31, 2024 2023 2022 Total stock-based compensation expense included in operating and maintenance expense $ 332 $ 178 $ 116 Income tax benefit ( 85 ) ( 45 ) ( 29 ) Total after-tax stock-based compensation expense $ 247 $ 133 $ 87 We receive a tax deduction based on the intrinsic value of the award on the distribution date for performance share awards and restricted stock units. The tax deduction related to performance share awards and restricted stock units was not material for the years ended December 31, 2024, 2023, and 2022. For each award, throughout the requisite service period, we recognize the tax benefit related to compensation costs. For performance share awards and restricted stock units, our realized tax benefit when distributed was not material for the years ended December 31, 2024, 2023, and 2022. Performance Share Awards Performance share awards are granted under the LTIP. The performance share awards are typically settled 50 % in common stock and 50 % in cash at the end of the three-year performance period, subject to certain ownership thresholds that, if met, may result in cash settlement of the entire award. The common stock portion of the performance share awards is considered an equity award and is valued based on our stock price on the grant date. The cash portion of the performance share awards is considered a liability award which is remeasured each reporting period based on the current stock price. As the value of the common stock and cash portions of the awards are based on the stock price during the performance period, coupled with changes in the total expected payout of the award, the compensation costs are subject to volatility until payment is made. For nonretirement-eligible employees, performance share awards are recognized over the vesting period of three years using the straight-line method. For performance share awards granted to retirement-eligible employees, the value of the performance shares is recognized ratably over the vesting period, which is the year of grant. We process forfeitures as they occur for employees who do not complete the requisite service period. 157 Table of Contents Combined Notes to Consolidated Financial Statements (Dollars in millions, unless otherwise noted) Note 20 — Stock-Based Compensation Plans The following table summarizes our unvested performance share awards activity: Shares Weighted Average Grant Date Fair Value (per share) Unvested at December 31, 2023 836,325 $ 61.47 Granted 257,792 127.03 Change in performance 116,090 130.06 Forfeited ( 11,526 ) 96.27 Undistributed vested awards (a) ( 663,055 ) 207.72 Unvested at December 31, 2024 535,626 $ 99.06 __________ (a) Represents performance share awards that vested but were not distributed to retirement-eligible employees during 2024 and 2023. The following table summarizes the weighted average grant date fair value and the total fair value of performance share awards vested: December 31, 2024 (a) December 31, 2023 (a) Weighted average grant date fair value (per share) $ 127.03 $ 83.26 Total fair value of performance shares vested 138 76 __________ (a) As of December 31, 2024 and 2023 , $ 50 million and $ 39 million of total unrecognized compensation costs related to unvested performance shares are expected to be recognized over the remaining weighted average period of 1.5 years and 1.6 years, respectively. Restricted Stock Units Restricted stock units are granted under the LTIP with the majority being settled in a specific number of shares of common stock after the service condition has been met. The corresponding cost is measured based on the grant date fair value of the restricted stock unit issued. The value of the restricted stock units is expensed over the requisite service period using the straight-line method. The requisite service period for restricted stock units is generally three to five years . However, certain restricted stock unit awards become fully vested upon the employee reaching retirement eligibility. The value of the restricted stock units granted to retirement-eligible employees is recognized ratably over the vesting period, which is the year of grant. We process forfeitures as they occur for employees who do not complete the requisite service period. The following table summarizes our unvested restricted stock unit activity: Shares Weighted Average Grant Date Fair Value (per share) Unvested at December 31, 2023 864,805 $ 69.42 Granted 490,112 134.18 Vested ( 376,121 ) 60.19 Forfeited ( 18,525 ) 107.49 Undistributed vested awards (a) ( 151,178 ) 129.44 Unvested at December 31, 2024 809,093 $ 96.53 __________ (a) Represents restricted stock units that vested but were not distributed to retirement-eligible employees during 2024 and 2023. 158 Table of Contents Combined Notes to Consolidated Financial Statements (Dollars in millions, unless otherwise noted) Note 20 — Stock-Based Compensation Plans The following table summarizes the weighted average grant date fair value and the total fair value of restricted stock units vested: December 31, 2024 (a) December 31, 2023 (a) Weighted average grant date fair value (per share) $ 134.18 $ 86.10 Total fair value of restricted stock units vested 42 34 __________ (a) As of December 31, 2024 and 2023, $ 41 million and $ 35 million of total unrecognized compensation costs related to unvested restricted stock units are expected to be recognized over the remaining weighted average period of 1.8 years and 1.9 years, respectively. 21. Variable Interest Entities As of December 31, 2024 and 2023, 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 December 31, 2024 and 2023. 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. December 31, 2024 December 31, 2023 Cash and cash equivalents $ 59 $ 48 Restricted cash and cash equivalents 50 47 Accounts receivable Customer accounts receivable, net 2,134 19 Other accounts receivable, net 12 10 Inventories, net Materials and supplies 13 14 Other current assets 38 1,249 Total current assets 2,306 1,387 Property, plant and equipment, net 2,025 1,979 Other noncurrent assets 142 166 Total noncurrent assets 2,167 2,145 Total assets (a) $ 4,473 $ 3,532 Long-term debt due within one year $ 64 $ 63 Accounts payable and accrued expenses 54 31 Total current liabilities 118 94 Long-term debt 642 704 Asset retirement obligations 206 190 Other noncurrent liabilities 2 2 Total noncurrent liabilities 850 896 Total liabilities $ 968 $ 990 __________ (a) Our balances include unrestricted assets f or current unamortized energy contract assets of $ 22 million and $ 22 million, disclosed within other current assets in the table above and noncurrent unamortized energy contract assets of $ 133 million and $ 155 million, disclosed within other noncurrent assets in the table above as of December 31, 2024 and 2023, respectively. 159 Table of Contents Combined Notes to Consolidated Financial Statements (Dollars in millions, unless otherwise noted) Note 21 — Variable Interest Entities As of December 31, 2024 and 2023, 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. 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. CRP - CRP is a collection of wind and solar project entities and some of these project entities are VIEs that are consolidated by CRP. While we or CRP own 100 % of the solar entities and 100 % of the majority of the wind entities, it has been determined that the wholly owned solar and wind entities are VIEs because the entities' customers absorb price variability from the entities through fixed price power and/or REC purchase agreements. Additionally, for the wind entities that have minority interests, it has been determined that these entities are VIEs because the governance rights of some investors are not proportional to their financial rights. We are the primary beneficiary of these solar and wind entities that qualify as VIEs because we control operations and direct all activities of the facilities. There is limited recourse to us related to certain solar and wind entities. In 2017, our interests in CRP were contributed to and are pledged for the CR nonrecourse debt project financing structure. Refer to Note 16 — Debt and Credit Agreements for additional information. Unconsolidated VIEs Our variable interests in unconsolidated VIEs generally include equity investments and energy purchase and sale contracts. For the equity investments, the carrying amount of the investments is reflected in the Consolidated Balance Sheets in Investments. 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 December 31, 2024 and 2023, we had significant unconsolidated variable interests in several VIEs for which we were not the primary beneficiary. These interests include certain equity method investments and certain commercial agreements. 160 Table of Contents Combined Notes to Consolidated Financial Statements (Dollars in millions, unless otherwise noted) Note 21 — Variable Interest Entities The following table presents summary information about our significant unconsolidated VIE entities: December 31, 2024 December 31, 2023 Commercial Agreement VIEs Equity Investment VIEs Total Commercial Agreement VIEs Equity Investment VIEs Total Total assets (a) $ 617 $ — $ 617 $ 704 $ — $ 704 Total liabilities (a) 42 — 42 77 — 77 Other ownership interests in VIE (a) 575 — 575 627 — 627 __________ (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. We do not have any exposure to loss as we do not have a carrying amount in the equity investment VIEs as o f December 31, 2024 and 2023. As of December 31, 2024 and 2023, the unconsolidated VIEs consist of: Unconsolidated 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. 22. Supplemental Financial Information Supplemental Statement of Operations and Comprehensive Income Information The following tables provide additional information about material items recorded in the Consolidated Statements of Operations and Comprehensive Income. Taxes other than income taxes For the Years Ended December 31, 2024 2023 2022 Gross receipts (a) $ 134 $ 139 $ 130 Property 285 253 274 Payroll 152 142 130 __________ (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. 161 Table of Contents Combined Notes to Consolidated Financial Statements (Dollars in millions, unless otherwise noted) Note 22 — Supplemental Financial Information Other, net For the Years Ended December 31, 2024 2023 2022 Decommissioning-related activities: Net realized income on NDT funds (a) Regulatory Agreement Units $ 553 $ 657 $ 333 Non-Regulatory Agreement Units 266 335 97 Net unrealized gains (losses) on NDT funds Regulatory Agreement Units 184 397 ( 1,354 ) Non-Regulatory Agreement Units 156 259 ( 798 ) Regulatory offset to NDT fund-related activities (b) ( 592 ) ( 845 ) 820 Total Decommissioning-related activities 567 803 ( 902 ) Non-service net periodic benefit credit (cost) ( 8 ) 54 110 Net realized and unrealized gains (losses) from equity investments 11 307 ( 13 ) Other 100 104 19 Total Other, net $ 670 $ 1,268 $ ( 786 ) __________ (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. Supplemental Cash Flow Information The following tables provide additional information about material items recorded in the Consolidated Statements of Cash Flows. Depreciation, amortization and accretion For the Years Ended December 31, 2024 2023 2022 Property, plant, and equipment (a) $ 1,101 $ 1,073 $ 1,065 Amortization of intangible assets, net (a) 22 23 26 Amortization of energy contract assets and liabilities (b) 38 35 35 Nuclear fuel (c) 884 787 758 ARO accretion (d) 655 596 543 Total depreciation, amortization, and accretion $ 2,700 $ 2,514 $ 2,427 _________ (a) Included in Depreciation and amortization expense in the Consolidated Statements of Operations and Comprehensive Income. (b) Included in Operating revenues or Purchased power and fuel expense in the Consolidated Statements of Operations and Comprehensive Income. (c) Included in Purchased power and fuel expense in the Consolidated Statements of Operations and Comprehensive Income. (d) Included in Operating and maintenance expense in the Consolidated Statements of Operations and Comprehensive Income. Cash paid during the year For the Years Ended December 31, 2024 2023 2022 Interest (net of amount capitalized) $ 375 $ 264 $ 230 Income taxes (net of refunds) 436 466 287 162 Table of Contents Combined Notes to Consolidated Financial Statements (Dollars in millions, unless otherwise noted) Note 22 — Supplemental Financial Information Other non-cash operating activities CEG Parent Constellation For the Years Ended December 31, For the Years Ended December 31, 2024 2023 2022 2024 2023 2022 Pension and non-pension postretirement benefit costs $ 107 $ 47 $ 17 $ 107 $ 47 $ 17 Other decommissioning-related activity (a) ( 485 ) ( 534 ) ( 263 ) ( 485 ) ( 534 ) ( 263 ) Energy-related options (b) 32 183 293 32 183 293 Other (c) 174 322 201 128 260 152 Total other non-cash operating activities $ ( 172 ) $ 18 $ 248 $ ( 218 ) $ ( 44 ) $ 199 __________ (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. (b) Includes option premiums reclassified to realized at the settlement of the underlying contracts and recorded to results of operations. (c) Includes items that are not individually material. The following table provides a reconciliation of cash, restricted cash, and cash equivalents reported in the Consolidated Balance Sheets that sum to the total of the same amounts in the Consolidated Statements of Cash Flows. December 31, 2024 CEG Parent Constellation Cash and cash equivalents $ 3,022 $ 3,018 Restricted cash and cash equivalents 107 97 Total cash, restricted cash, and cash equivalents $ 3,129 $ 3,115 December 31, 2023 CEG Parent Constellation Cash and cash equivalents $ 368 $ 366 Restricted cash and cash equivalents 86 74 Total cash, restricted cash, and cash equivalents $ 454 $ 440 December 31, 2022 CEG Parent Constellation Cash and cash equivalents $ 422 $ 403 Restricted cash and cash equivalents 106 98 Total cash, restricted cash, and cash equivalents $ 528 $ 501 For additional information on restricted cash, see Note 1 — Basis of Presentation. 163 Table of Contents Combined Notes to Consolidated Financial Statements (Dollars in millions, unless otherwise noted) Note 22 — Supplemental Financial Information Supplemental Balance Sheet Information The following tables provide additional information about material items recorded in the Consolidated Balance Sheets. Investments December 31, 2024 December 31, 2023 Equity method investments $ 2 $ 7 Other investments: Employee benefit trusts and investments (a) 100 82 Equity investments with readily determinable fair values (b) 387 369 Equity investments without readily determinable fair values 150 103 Other available for sale debt security investments 1 2 Total investments $ 640 $ 563 __________ (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 17 — Fair Value of Financial Assets and Liabilities for additional information on Investments in equities. Accounts payable and accrued expenses December 31, 2024 CEG Parent Constellation Accounts payable $ 2,369 $ 2,348 Compensation-related accruals (a) 907 689 Taxes accrued (b) 232 223 Accounts payable and accrued expenses December 31, 2023 CEG Parent Constellation Accounts payable $ 1,302 $ 1,289 Compensation-related accruals (a) 680 576 Taxes accrued 399 390 __________ (a) Primarily includes accrued payroll, bonuses and other incentives, vacation, and benefits. (b) Includes $ 150 million related to nuclear PTC that was used to offset the current tax liability. See Note 6 — Government Assistance for additional information on the nuclear PTC. 23. Related Party Transactions Prior to completion of the separation on February 1, 2022, we engaged in transactions with affiliates of Exelon in the normal course of business. These affiliate transactions are summarized in the tables below. After February 1, 2022, all transactions with Exelon or its affiliates are no longer related party transactions. 164 Table of Contents Combined Notes to Consolidated Financial Statements (Dollars in millions, unless otherwise noted) Note 23 — Related Party Transactions Operating revenues from affiliates The following table presents our Operating revenues from affiliates: For the Year Ended December 31, 2022 (a) ComEd (b) $ 58 PECO (c) 33 BGE (d) 18 PHI 51 Pepco (e) 39 DPL (f) 10 ACE (g) 2 Total operating revenues from affiliates $ 160 __________ (a) Represents only January 2022 revenues prior to separation on February 1, 2022. (b) We have an ICC-approved RFP contract with ComEd to provide a portion of ComEd’s electricity supply requirements. We also sell RECs and ZECs to ComEd. (c) We provide electric supply to PECO under contracts executed through PECO’s competitive procurement process. In addition, we have a ten-year agreement with PECO to sell solar AECs. (d) We provide a portion of BGE’s energy requirements under its MDPSC-approved market-based SOS and gas commodity programs. (e) We provide electric supply to Pepco under contracts executed through Pepco's competitive procurement process approved by the MDPSC and DCPSC. (f) We provide a portion of DPL's energy requirements under its MDPSC and DEPSC approved market-based SOS commodity programs. (g) We provide electric supply to ACE under contracts executed through ACE's competitive procurement process. Service Company Costs for Corporate Support We received a variety of corporate support services from Exelon. Through its business services subsidiary, BSC, Exelon provided support services at cost, including legal, human resources, financial, information technology, and supply management services. The costs of BSC were directly charged or allocated to us. Certain of these services continued after the separation and were covered by the TSA. See Note 1 — Basis of Presentation for additional information. The operating and maintenance service and the capitalized service company costs from affiliates allocated to us prior to separation were immaterial for the year ended December 31, 2022. ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE None.