FULLTEXT DEL 1 AV 2
10-Q – 2025-11-07 – ceg-20250930.htm
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2024-01-01 2024-09-30 UNITED STATES SECURITIES AND EXCHANGE COMMISSION WASHINGTON, D.C. 20549 FORM 10-Q ☒ QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the Quarterly Period Ended September 30, 2025 or ☐ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 Commission File Number Name of Registrant; State or Other Jurisdiction of Incorporation; Address of Principal Executive Offices; and Telephone Number IRS Employer Identification Number 001-41137 CONSTELLATION ENERGY CORPORATION 87-1210716 (a Pennsylvania corporation) 1310 Point Street Baltimore , Maryland 21231-3380 (833) 883-0162 333-85496 CONSTELLATION ENERGY GENERATION, LLC 23-3064219 (a Pennsylvania limited liability company) 200 Energy Way Kennett Square , Pennsylvania 19348-2473 (833) 883-0162 Securities registered pursuant to Section 12(b) of the Act: Title of each class Trading Symbol(s) Name of each exchange on which registered CONSTELLATION ENERGY CORPORATION: Common Stock, without par value CEG The Nasdaq Stock Market LLC Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Constellation Energy Corporation Yes x No ☐ Constellation Energy Generation, LLC Yes x No ☐ Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes ý No ¨ Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and "emerging growth company" in Rule 12b-2 of the Exchange Act. Constellation Energy Corporation Large Accelerated Filer x Accelerated Filer ☐ Non-accelerated Filer ☐ Smaller Reporting Company ☐ Emerging Growth Company ☐ Constellation Energy Generation, LLC Large Accelerated Filer ☐ Accelerated Filer ☐ Non-accelerated Filer x Smaller Reporting Company ☐ Emerging Growth Company ☐ If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. o Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes ☐ No x The number of shares outstanding of each registrant’s common stock as of October 31, 2025 was as follows: Constellation Energy Corporation Common Stock, without par value 312,290,080 Constellation Energy Generation, LLC Not applicable TABLE OF CONTENTS Page No. GLOSSARY OF TERMS AND ABBREVIATIONS 1 FILING FORMAT 4 CAUTIONARY STATEMENTS REGARDING FORWARD-LOOKING INFORMATION 4 AVAILABLE INFORMATION 4 PART I FINANCIAL INFORMATION 4 ITEM 1. FINANCIAL STATEMENTS 4 Constellation Energy Corporation Consolidated Statements of Operations and Comprehensive Income 5 Consolidated Statements of Cash Flows 6 Consolidated Balance Sheets 7 Consolidated Statements of Changes in Equity 9 Constellation Energy Generation, LLC Consolidated Statements of Operations and Comprehensive Income 11 Consolidated Statements of Cash Flows 12 Consolidated Balance Sheets 13 Consolidated Statements of Changes in Equity 15 Combined Notes to Consolidated Financial Statements 1. Basis of Presentation 17 2. Mergers, Acquisitions, and Dispositions 17 3 . Regulatory Matters 18 4. Revenue from Contracts with Customers 19 5. Segment Information 20 6. Government Assistance 22 7. Accounts Receivable 23 8. Nuclear Decommissioning 24 9. Income Taxes 26 10. Retirement Benefits 28 11. Derivative Financial Instruments 29 12. Debt and Credit Agreements 33 13. Fair Value of Financial Assets and Liabilities 36 14. Commitments and Contingencies 41 15. Shareholders' Equity 42 16. Variable Interest Entities 44 17. Supplemental Financial Information 46 ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS 48 Executive Overview 48 Significant Transactions and Developments 48 Other Key Business Drivers 49 Critical Accounting Policies and Estimates 50 Financial Results of Operations 50 Liquidity and Capital Resources 63 ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK 66 ITEM 4. CONTROLS AND PROCEDURES 70 PART II OTHER INFORMATION 71 ITEM 1. LEGAL PROCEEDINGS 71 ITEM 1A. RISK FACTORS 71 ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS 71 ITEM 4. MINE SAFETY DISCLOSURES 72 ITEM 5. OTHER INFORMATION 72 ITEM 6. EXHIBITS 73 SIGNATURES 74 Constellation Energy Corporation 74 Constellation Energy Generation, LLC 75 Table of Contents GLOSSARY OF TERMS AND ABBREVIATIONS Constellation Energy Corporation and Related Entities CEG Parent Constellation Energy Corporation Constellation Constellation Energy Generation, LLC Registrants CEG Parent and Constellation, collectively Antelope Valley Antelope Valley Solar Ranch One Continental Wind Continental Wind LLC CR Constellation Renewables, LLC Crane Crane Clean Energy Center (formerly known as Three Mile Island Unit 1) CRP Constellation Renewables Partners, LLC NER NewEnergy Receivables LLC RPG Renewable Power Generation, LLC STP South Texas Project nuclear generating station West Medway II West Medway Generating Station II Former Related Entities Exelon Exelon Corporation ComEd Commonwealth Edison Company PECO PECO Energy Company 1 Table of Contents GLOSSARY OF TERMS AND ABBREVIATIONS Other Terms and Abbreviations AEP Texas American Electric Power Texas AESO Alberta Electric Systems Operator AOCI Accumulated Other Comprehensive Income (Loss) ARC Asset Retirement Cost ARO Asset Retirement Obligation ASR Accelerated Share Repurchase CAISO California ISO CenterPoint CenterPoint Energy Houston Electric, LLC Clean Air Act Clean Air Act of 1963, as amended Clean Water Act Federal Water Pollution Control Amendments of 1972, as amended CMC Carbon Mitigation Credit CODM Chief Operating Decision Maker DOE United States Department of Energy DOI United States Department of the Interior DOJ United States Department of Justice DPP Deferred Purchase Price EPA United States Environmental Protection Agency ERCOT Electric Reliability Council of Texas ERISA Employee Retirement Income Security Act of 1974, as amended ERP Enterprise Resource Planning Exchange Act Securities Exchange Act of 1934, as amended FERC Federal Energy Regulatory Commission Former PECO Units Limerick, Peach Bottom, and Salem nuclear generating units Former ComEd Units Braidwood, Byron, Dresden, LaSalle and Quad Cities nuclear generating units FRCC Florida Reliability Coordinating Council GAAP Generally Accepted Accounting Principles in the United States GDP Gross Domestic Product GHG Greenhouse Gas GW Gigawatt GWh Gigawatt hour ICE Intercontinental Exchange IPA Illinois Power Agency IRA Inflation Reduction Act of 2022 IRS Internal Revenue Service ISO Independent System Operator ISO-NE ISO New England Inc. ITC Investment Tax Credit MDE Maryland Department of the Environment MISO Midcontinent Independent System Operator, Inc. MMBtu Million British thermal units Moody's Moody’s Investors Service, Inc. MW Megawatt MWh Megawatt hour NAV Net Asset Value NASDAQ Nasdaq Stock Market, LLC 2 Table of Contents NDT Nuclear Decommissioning Trust NERC North American Electric Reliability Corporation NGX Natural Gas Exchange, Inc. Non-Regulatory Agreement Units Nuclear generating units or portions thereof whose decommissioning-related activities are not subject to contractual elimination under regulatory accounting NPNS Normal Purchase Normal Sale scope exception NRC Nuclear Regulatory Commission NYISO New York ISO NYMEX New York Mercantile Exchange NYPSC New York Public Service Commission OBBBA One Big Beautiful Bill Act of 2025 OCI Other Comprehensive Income OIESO Ontario Independent Electricity System Operator OPEB Other Postretirement Employee Benefits Pension Protection Act Pension Protection Act of 2006 PG&E Pacific Gas and Electric Company PJM PJM Interconnection, LLC PPA Power Purchase Agreement PP&E Property, Plant, and Equipment PSDAR Post-shutdown Decommissioning Activities Report PSEG Public Service Enterprise Group Incorporated PTC Production Tax Credit PUCT Public Utility Commission of Texas Regulatory Agreement Units Nuclear generating units or portions thereof whose decommissioning-related activities are subject to contractual elimination under regulatory accounting (includes the Former ComEd Units, the Former PECO Units and STP) RNF Operating Revenues Net of Purchased Power and Fuel Expense RTO Regional Transmission Organization S&P S&P Global Ratings, a Standard & Poor’s Financial Services LLC business SEC United States Securities and Exchange Commission SERC SERC Reliability Corporation (formerly Southeast Electric Reliability Council) SNF Spent Nuclear Fuel SOFR Secured Overnight Financing Rate SPP Southwest Power Pool STPNOC STP Nuclear Operating Company TMA Tax Matters Agreement TWh Terawatt-hour U.S. Court of Appeals for the D.C. Circuit United States Court of Appeals for the District of Columbia Circuit U.S. Treasury U.S. Department of the Treasury VIE Variable Interest Entity WECC Western Electric Coordinating Council ZEC Zero Emission Credit 3 Table of Contents FILING FORMAT This combined Form 10-Q is being filed separately by Constellation Energy Corporation and Constellation Energy Generation, LLC, (the Registrants). Information contained herein relating to any individual Registrant is filed by the Registrant on its own behalf. Neither Registrant makes any representation as to information relating to the other Registrant. CAUTIONARY STATEMENTS REGARDING FORWARD-LOOKING INFORMATION This report contains certain forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995 that are subject to risks and uncertainties. Words such as “could,” “may,” “expects,” “anticipates,” “will,” “targets,” “goals,” “projects,” “intends,” “plans,” “believes,” “seeks,” “estimates,” “predicts,” and variations on such words, and similar expressions that reflect our current views with respect to future events and operational, economic, and financial performance, are intended to identify such forward-looking statements. These forward-looking statements include, but are not limited to, statements regarding the proposed transaction between Constellation and Calpine Corporation, the expected closing of the proposed transaction and the timing thereof. This includes statements regarding the financing of the proposed transaction and the pro forma combined company and its operations, strategies and plans, enhancements to investment-grade credit profile, synergies, opportunities and anticipated future performance and capital structure, and expected accretion to earnings per share and free cash flow. Information adjusted for the proposed transaction should not be considered a forecast of future results. Forward-looking statements are based on current expectations, estimates and assumptions that involve a number of risks and uncertainties that could cause actual results to differ materially from those projected. The factors that could cause actual results to differ materially from the forward-looking statements made by us include those factors discussed herein, as well as the items discussed in (1) the Registrants' combined 2024 Annual Report on Form 10-K in (a) Part I, ITEM 1A. Risk Factors, (b) Part II, ITEM 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations, and (c) Part II, ITEM 8. Financial Statements and Supplementary Data: Note 18 — Commitments and Contingencies; (2) this Quarterly Report on Form 10-Q in (a) Part II, ITEM 1A. Risk Factors, (b) Part I, ITEM 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations, and (c) Part I, ITEM 1. Financial Statements: Note 14 — Commitments and Contingencies; and (3) other factors discussed in filings with the SEC by the Registrants. Readers are cautioned not to place undue reliance on these forward-looking statements, which apply only as of the date of this report. Neither Registrant undertakes any obligation to publicly release any revision to its forward-looking statements to reflect events or circumstances after the date of this report. AVAILABLE INFORMATION The SEC maintains an Internet site at www.sec.gov that contains reports, proxy and information statements, and other information that we file electronically with the SEC. We file our Annual Report on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K, and all amendments to those reports with the SEC. In addition, as soon as reasonably practicable after such materials are furnished to the SEC, we make copies of these documents available to the public free of charge through our website at www.ConstellationEnergy.com. Information contained on our website shall not be deemed incorporated into, or to be a part of, this report. PART I. FINANCIAL INFORMATION ITEM 1. FINANCIAL STATEMENTS 4 Table of Contents Constellation Energy Corporation and Subsidiary Companies Consolidated Statements of Operations and Comprehensive Income (Unaudited) Three Months Ended September 30, Nine Months Ended September 30, (In millions, except per share data) 2025 2024 2025 2024 Operating revenues $ 6,570 $ 6,550 $ 19,459 $ 18,186 Operating expenses Purchased power and fuel 3,567 3,119 11,083 8,828 Operating and maintenance 1,511 1,535 4,673 4,666 Depreciation and amortization 241 266 743 868 Taxes other than income taxes 165 165 472 446 Total operating expenses 5,484 5,085 16,971 14,808 Gain (loss) on sales of assets and businesses — 2 — 2 Operating income (loss) 1,086 1,467 2,488 3,380 Other income and (deductions) Interest expense, net ( 134 ) ( 147 ) ( 398 ) ( 416 ) Other, net 443 325 729 693 Total other income and (deductions) 309 178 331 277 Income (loss) before income taxes 1,395 1,645 2,819 3,657 Income tax (benefit) expense 466 449 928 768 Equity in income (losses) of unconsolidated affiliates — — — ( 1 ) Net income (loss) 929 1,196 1,891 2,888 Net income (loss) attributable to noncontrolling interests ( 1 ) ( 4 ) 4 ( 9 ) Net income (loss) attributable to common shareholders $ 930 $ 1,200 $ 1,887 $ 2,897 Comprehensive income (loss), net of income taxes Net income (loss) $ 929 $ 1,196 $ 1,891 $ 2,888 Other comprehensive income (loss), net of income taxes Pension and non-pension postretirement benefit plans: Prior service benefit reclassified to periodic benefit cost ( 1 ) ( 1 ) ( 3 ) ( 3 ) Actuarial loss reclassified to periodic cost 19 15 54 53 Pension and non-pension postretirement benefit plan valuation adjustment — — ( 34 ) ( 4 ) Unrealized gain (loss) on cash flow hedges 2 1 5 3 Unrealized gain (loss) on foreign currency translation ( 8 ) 12 20 8 Other comprehensive income (loss), net of income taxes 12 27 42 57 Comprehensive income (loss) 941 1,223 1,933 2,945 Comprehensive income (loss) attributable to noncontrolling interests ( 1 ) ( 4 ) 4 ( 9 ) Comprehensive income (loss) attributable to common shareholders $ 942 $ 1,227 $ 1,929 $ 2,954 Average shares of common stock outstanding: Basic 313 313 313 315 Assumed exercise and/or distributions of stock-based awards — 1 1 1 Diluted 313 314 314 316 Earnings per average common share Basic $ 2.98 $ 3.83 $ 6.02 $ 9.20 Diluted $ 2.97 $ 3.82 $ 6.02 $ 9.17 See the Combined Notes to Consolidated Financial Statements 5 Table of Contents Constellation Energy Corporation and Subsidiary Companies Consolidated Statements of Cash Flows (Unaudited) Nine Months Ended September 30, (In millions) 2025 2024 Cash flows from operating activities Net income (loss) $ 1,891 $ 2,888 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 1,945 2,049 Deferred income taxes and amortization of ITCs 248 358 Net fair value changes related to derivatives 328 ( 1,161 ) Net realized and unrealized (gains) losses on NDT funds ( 588 ) ( 475 ) Net realized and unrealized (gains) losses on equity investments 256 115 Other non-cash operating activities ( 74 ) ( 161 ) Changes in assets and liabilities: Accounts receivable ( 184 ) 1,083 Inventories ( 62 ) 31 Accounts payable and accrued expenses ( 25 ) ( 38 ) Option premiums received (paid), net 49 159 Collateral received (posted), net ( 192 ) 1,495 Income taxes 423 154 Pension and non-pension postretirement benefit contributions ( 193 ) ( 178 ) Other assets and liabilities ( 390 ) ( 7,767 ) Net cash flows provided by (used in) operating activities 3,432 ( 1,448 ) Cash flows from investing activities Capital expenditures ( 1,963 ) ( 1,836 ) Proceeds from NDT fund sales 5,525 4,934 Investment in NDT funds ( 5,773 ) ( 5,140 ) Collection of DPP, net — 7,104 Acquisitions of assets and businesses ( 13 ) ( 22 ) Other investing activities 3 16 Net cash flows provided by (used in) investing activities ( 2,221 ) 5,056 Cash flows from financing activities Change in short-term borrowings — ( 1,105 ) Proceeds from short-term borrowings with maturities greater than 90 days 1,650 200 Repayments of short-term borrowings with maturities greater than 90 days — ( 739 ) Issuance of long-term debt — 900 Retirement of long-term debt ( 1,036 ) ( 99 ) Dividends paid on common stock ( 365 ) ( 333 ) Repurchases of common stock ( 400 ) ( 999 ) Other financing activities ( 98 ) ( 5 ) Net cash flows provided by (used in) financing activities ( 249 ) ( 2,180 ) Increase (decrease) in cash, restricted cash, and cash equivalents 962 1,428 Cash, restricted cash, and cash equivalents at beginning of period 3,129 454 Cash, restricted cash, and cash equivalents at end of period $ 4,091 $ 1,882 Supplemental disclosure of non-cash investing and financing activities Increase (decrease) in DPP $ — $ 7,682 Increase (decrease) in PP&E related to ARO update 188 ( 1,475 ) See the Combined Notes to Consolidated Financial Statements 6 Table of Contents Constellation Energy Corporation and Subsidiary Companies Consolidated Balance Sheets (Unaudited) (In millions) September 30, 2025 December 31, 2024 ASSETS Current assets Cash and cash equivalents $ 3,959 $ 3,022 Restricted cash and cash equivalents 132 107 Accounts receivable, net Customer accounts receivable (net of allowance for credit losses of $ 190 as of September 30, 2025 and December 31, 2024) 3,168 3,116 Other accounts receivable (net of allowance for credit losses of $ 8 and $ 6 as of September 30, 2025 and December 31, 2024, respectively) 612 602 Mark-to-market derivative assets 632 843 Inventories, net Natural gas, oil, and emission allowances 242 243 Materials and supplies 1,422 1,357 Renewable energy credits 786 797 Other 696 689 Total current assets 11,649 10,776 Property, plant, and equipment (net of accumulated depreciation and amortization of $ 18,932 and $ 18,088 as of September 30, 2025 and December 31, 2024, respectively) 21,990 21,235 Deferred debits and other assets Nuclear decommissioning trust funds 18,985 17,305 Investments 427 640 Goodwill 420 420 Mark-to-market derivative assets 459 372 Other 2,231 2,178 Total deferred debits and other assets 22,522 20,915 Total assets (a) $ 56,161 $ 52,926 See the Combined Notes to Consolidated Financial Statements 7 Table of Contents Constellation Energy Corporation and Subsidiary Companies Consolidated Balance Sheets (Unaudited) (In millions) September 30, 2025 December 31, 2024 LIABILITIES AND EQUITY Current liabilities Short-term borrowings $ 1,650 $ — Long-term debt due within one year 118 1,028 Accounts payable and accrued expenses 3,926 3,943 Mark-to-market derivative liabilities 474 467 Renewable energy credit obligation 956 1,076 Other 331 332 Total current liabilities 7,455 6,846 Long-term debt 7,269 7,384 Deferred credits and other liabilities Deferred income taxes and unamortized ITCs 3,578 3,331 Asset retirement obligations 13,032 12,449 Pension and non-pension postretirement benefit obligations 1,767 1,875 Spent nuclear fuel obligation 1,412 1,366 Payables related to Regulatory Agreement Units 5,222 4,518 Mark-to-market derivative liabilities 440 399 Other 1,294 1,219 Total deferred credits and other liabilities 26,745 25,157 Total liabilities (a) 41,469 39,387 Commitments and contingencies (Note 14) Shareholders' equity Common stock ( No par value, 1,000 shares authorized, 312 and 313 shares outstanding as of September 30, 2025 and December 31, 2024, respectively) 11,022 11,402 Retained earnings (deficit) 5,588 4,066 Accumulated other comprehensive income (loss), net ( 2,260 ) ( 2,302 ) Total shareholders' equity 14,350 13,166 Noncontrolling interests 342 373 Total equity 14,692 13,539 Total liabilities and shareholders' equity $ 56,161 $ 52,926 __________ (a) Our consolidated assets include $ 4,358 million and $ 4,318 million at September 30, 2025 and December 31, 2024, respectively, of certain VIEs that can only be used to settle the liabilities of the VIE. Our consolidated liabilities include $ 925 million and $ 968 million at September 30, 2025 and December 31, 2024, respectively, of certain VIEs for which the VIE creditors do not have recourse to us. See Note 16 — Variable Interest Entities for additional information. See the Combined Notes to Consolidated Financial Statements 8 Table of Contents Constellation Energy Corporation and Subsidiary Companies Consolidated Statements of Changes in Equity (Unaudited) Nine Months Ended September 30, 2025 Shareholders' Equity (In millions, shares in thousands) Issued Shares Common Stock Retained Earnings (Deficit) Accumulated Other Comprehensive Income (Loss), net Noncontrolling Interests Total Equity Balance, December 31, 2024 312,838 $ 11,402 $ 4,066 $ ( 2,302 ) $ 373 $ 13,539 Net Income (loss) — — 118 — 11 129 Employee incentive plans 547 ( 49 ) — — — ( 49 ) Changes in equity of noncontrolling interests — — — — ( 6 ) ( 6 ) Common stock dividends ($ 0.3878 /common share) — — ( 122 ) — — ( 122 ) Capped call option contracts — ( 150 ) — — — ( 150 ) Other comprehensive income (loss), net of income taxes — — — ( 7 ) — ( 7 ) Balance, March 31, 2025 313,385 $ 11,203 $ 4,062 $ ( 2,309 ) $ 378 $ 13,334 Net Income (loss) — — 839 — ( 6 ) 833 Employee incentive plans 117 37 — — — 37 Changes in equity of noncontrolling interests — — — — ( 15 ) ( 15 ) Common stock dividends ($ 0.3878 /common share) — — ( 122 ) — — ( 122 ) Common stock repurchased ( 1,099 ) ( 404 ) — — — ( 404 ) Capped call option contracts — 103 — — — 103 Other comprehensive income (loss), net of income taxes — — — 37 — 37 Balance, June 30, 2025 312,403 $ 10,939 $ 4,779 $ ( 2,272 ) $ 357 $ 13,803 Net Income (loss) — — 930 — ( 1 ) 929 Employee incentive plans 58 30 — — — 30 Changes in equity of noncontrolling interests — — — — ( 14 ) ( 14 ) Common stock dividends ($ 0.3878 /common share) — — ( 121 ) — — ( 121 ) Common stock repurchased ( 183 ) — — — — — Capped call option contracts — 53 — — — 53 Other comprehensive income (loss), net of income taxes — — — 12 — 12 Balance, September 30, 2025 312,278 $ 11,022 $ 5,588 $ ( 2,260 ) $ 342 $ 14,692 See the Combined Notes to Consolidated Financial Statements 9 Table of Contents Constellation Energy Corporation and Subsidiary Companies Consolidated Statements of Changes in Equity (Unaudited) Nine Months Ended September 30, 2024 Shareholders' Equity (In millions, shares in thousands) Issued Shares Common Stock Retained Earnings (Deficit) Accumulated Other Comprehensive Income (Loss), net Noncontrolling Interests Total Equity Balance, December 31, 2023 317,472 $ 12,355 $ 761 $ ( 2,191 ) $ 361 $ 11,286 Net Income (loss) — — 883 — — 883 Employee incentive plans 661 ( 4 ) — — — ( 4 ) Common stock dividends ($ 0.3525 /common share) — — ( 112 ) — — ( 112 ) Common stock repurchased ( 2,900 ) ( 504 ) — — — ( 504 ) Other comprehensive income (loss), net of income taxes — — — 11 — 11 Balance, March 31, 2024 315,233 $ 11,847 $ 1,532 $ ( 2,180 ) $ 361 $ 11,560 Net Income (loss) — — 814 — ( 5 ) 809 Employee incentive plans 72 8 — — — 8 Common stock dividends ($ 0.3525 /common share) — — ( 110 ) — — ( 110 ) Common stock repurchased ( 2,091 ) ( 505 ) — — — ( 505 ) Other comprehensive income (loss), net of income taxes — — — 19 — 19 Balance, June 30, 2024 313,214 $ 11,350 $ 2,236 $ ( 2,161 ) $ 356 $ 11,781 Net Income (loss) — — 1,200 — ( 4 ) 1,196 Employee incentive plans 78 29 — — — 29 Changes in equity of noncontrolling interests — — — — 19 19 Common stock dividends ($ 0.3525 /common share) — — ( 111 ) — — ( 111 ) Common stock repurchased ( 528 ) — — — — — Other comprehensive income, net of income taxes — — — 27 — 27 Balance, September 30, 2024 312,764 $ 11,379 $ 3,325 $ ( 2,134 ) $ 371 $ 12,941 See the Combined Notes to Consolidated Financial Statements 10 Table of Contents Constellation Energy Generation, LLC and Subsidiary Companies Consolidated Statements of Operations and Comprehensive Income (Unaudited) Three Months Ended September 30, Nine Months Ended September 30, (In millions) 2025 2024 2025 2024 Operating revenues $ 6,570 $ 6,550 $ 19,459 $ 18,186 Operating expenses Purchased power and fuel 3,567 3,119 11,083 8,828 Operating and maintenance 1,511 1,535 4,673 4,666 Depreciation and amortization 241 266 743 868 Taxes other than income taxes 165 165 472 446 Total operating expenses 5,484 5,085 16,971 14,808 Gain (loss) on sales of assets and businesses — 2 — 2 Operating income (loss) 1,086 1,467 2,488 3,380 Other income and (deductions) Interest expense, net ( 134 ) ( 147 ) ( 398 ) ( 416 ) Other, net 443 325 729 693 Total other income and (deductions) 309 178 331 277 Income (loss) before income taxes 1,395 1,645 2,819 3,657 Income tax (benefit) expense 466 449 928 768 Equity in income (losses) of unconsolidated affiliates — — — ( 1 ) Net income (loss) 929 1,196 1,891 2,888 Net income (loss) attributable to noncontrolling interests ( 1 ) ( 4 ) 4 ( 9 ) Net income (loss) attributable to membership interest $ 930 $ 1,200 $ 1,887 $ 2,897 Comprehensive income (loss), net of income taxes Net income (loss) $ 929 $ 1,196 $ 1,891 $ 2,888 Other comprehensive income (loss), net of income taxes Pension and non-pension postretirement benefit plans: Prior service benefit reclassified to periodic benefit cost ( 1 ) ( 1 ) ( 3 ) ( 3 ) Actuarial loss reclassified to periodic cost 19 15 54 53 Pension and non-pension postretirement benefit plan valuation adjustment — — ( 34 ) ( 4 ) Unrealized gain (loss) on cash flow hedges 2 1 5 3 Unrealized gain (loss) on foreign currency translation ( 8 ) 12 20 8 Other comprehensive income (loss), net of income taxes 12 27 42 57 Comprehensive income (loss) 941 1,223 1,933 2,945 Comprehensive income (loss) attributable to noncontrolling interests ( 1 ) ( 4 ) 4 ( 9 ) Comprehensive income (loss) attributable to membership interest $ 942 $ 1,227 $ 1,929 $ 2,954 See the Combined Notes to Consolidated Financial Statements 11 Table of Contents Constellation Energy Generation, LLC and Subsidiary Companies Consolidated Statements of Cash Flows (Unaudited) Nine Months Ended September 30, (In millions) 2025 2024 Cash flows from operating activities Net income (loss) $ 1,891 $ 2,888 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 1,945 2,049 Deferred income taxes and amortization of ITCs 248 358 Net fair value changes related to derivatives 328 ( 1,161 ) Net realized and unrealized (gains) losses on NDT funds ( 588 ) ( 475 ) Net realized and unrealized (gains) losses on equity investments 256 115 Other non-cash operating activities ( 139 ) ( 195 ) Changes in assets and liabilities: Accounts receivable ( 201 ) 1,085 Receivables from and payables to affiliates, net ( 51 ) 238 Inventories ( 62 ) 31 Accounts payable and accrued expenses ( 36 ) ( 38 ) Option premiums received (paid), net 49 159 Collateral received (posted), net ( 192 ) 1,495 Income taxes 423 154 Pension and non-pension postretirement benefit contributions ( 193 ) ( 178 ) Other assets and liabilities ( 346 ) ( 7,977 ) Net cash flows provided by (used in) operating activities 3,332 ( 1,452 ) Cash flows from investing activities Capital expenditures ( 1,963 ) ( 1,836 ) Proceeds from NDT fund sales 5,525 4,934 Investment in NDT funds ( 5,773 ) ( 5,140 ) Collection of DPP, net — 7,104 Acquisitions of assets and businesses ( 13 ) ( 22 ) Other investing activities 3 16 Net cash flows provided by (used in) investing activities ( 2,221 ) 5,056 Cash flows from financing activities Change in short-term borrowings — ( 1,105 ) Proceeds from short-term borrowings with maturities greater than 90 days 1,650 200 Repayments of short-term borrowings with maturities greater than 90 days — ( 739 ) Issuance of long-term debt — 900 Retirement of long-term debt ( 1,036 ) ( 99 ) Distributions to member ( 914 ) ( 1,331 ) Contributions from member 156 — Other financing activities ( 45 ) — Net cash flows provided by (used in) financing activities ( 189 ) ( 2,174 ) Increase (decrease) in cash, restricted cash, and cash equivalents 922 1,430 Cash, restricted cash, and cash equivalents at beginning of period 3,115 440 Cash, restricted cash, and cash equivalents at end of period $ 4,037 $ 1,870 Supplemental disclosure of non-cash investing and financing activities Increase (decrease) in DPP $ — $ 7,682 Increase (decrease) in PP&E related to ARO update 188 ( 1,475 ) See the Combined Notes to Consolidated Financial Statements 12 Table of Contents Constellation Energy Generation, LLC and Subsidiary Companies Consolidated Balance Sheets (Unaudited) (In millions) September 30, 2025 December 31, 2024 ASSETS Current assets Cash and cash equivalents $ 3,949 $ 3,018 Restricted cash and cash equivalents 88 97 Accounts receivable, net Customer accounts receivable (net of allowance for credit losses of $ 190 as of September 30, 2025 and December 31, 2024) 3,168 3,116 Other accounts receivable (net of allowance for credit losses of $ 8 and $ 6 as of September 30, 2025 and December 31, 2024, respectively) 614 587 Mark-to-market derivative assets 632 843 Inventories, net Natural gas, oil, and emission allowances 242 243 Materials and supplies 1,422 1,357 Renewable energy credits 786 797 Other 695 689 Total current assets 11,596 10,747 Property, plant, and equipment (net of accumulated depreciation and amortization of $ 18,932 and $ 18,088 as of September 30, 2025 and December 31, 2024, respectively) 21,990 21,235 Deferred debits and other assets Nuclear decommissioning trust funds 18,985 17,305 Investments 427 640 Goodwill 420 420 Mark-to-market derivative assets 459 372 Other 2,225 2,174 Total deferred debits and other assets 22,516 20,911 Total assets (a) $ 56,102 $ 52,893 See the Combined Notes to Consolidated Financial Statements 13 Table of Contents Constellation Energy Generation, LLC and Subsidiary Companies Consolidated Balance Sheets (Unaudited) (In millions) September 30, 2025 December 31, 2024 LIABILITIES AND EQUITY Current liabilities Short-term borrowings $ 1,650 $ — Long-term debt due within one year 118 1,028 Accounts payable and accrued expenses 3,668 3,696 Payables to affiliates 298 349 Mark-to-market derivative liabilities 474 467 Renewable energy credit obligation 956 1,076 Other 324 328 Total current liabilities 7,488 6,944 Long-term debt 7,269 7,384 Deferred credits and other liabilities Deferred income taxes and unamortized ITCs 3,578 3,331 Asset retirement obligations 13,032 12,449 Pension and non-pension postretirement benefit obligations 1,767 1,875 Spent nuclear fuel obligation 1,412 1,366 Payables related to Regulatory Agreement Units 5,222 4,518 Mark-to-market derivative liabilities 440 399 Other 1,171 1,044 Total deferred credits and other liabilities 26,622 24,982 Total liabilities (a) 41,379 39,310 Commitments and contingencies (Note 14) Equity Member’s equity Membership interest 10,144 10,538 Undistributed earnings (deficit) 6,497 4,974 Accumulated other comprehensive income (loss), net ( 2,260 ) ( 2,302 ) Total member’s equity 14,381 13,210 Noncontrolling interests 342 373 Total equity 14,723 13,583 Total liabilities and equity $ 56,102 $ 52,893 __________ (a) Our consolidated assets include $ 4,358 million and $ 4,318 million as of September 30, 2025 and December 31, 2024, respectively, of certain VIEs that can only be used to settle the liabilities of the VIE. Our consolidated liabilities include $ 925 million and $ 968 million as of September 30, 2025 and December 31, 2024, respectively, of certain VIEs for which the VIE creditors do not have recourse to us. See Note 16 — Variable Interest Entities for additional information. See the Combined Notes to Consolidated Financial Statements 14 Table of Contents Constellation Energy Generation, LLC and Subsidiary Companies Consolidated Statements of Changes in Equity (Unaudited) Nine Months Ended September 30, 2025 Member's Equity (In millions) Membership Interest Undistributed Earnings (Deficit) Accumulated Other Comprehensive Income (Loss), net Noncontrolling Interests Total Equity Balance, December 31, 2024 $ 10,538 $ 4,974 $ ( 2,302 ) $ 373 $ 13,583 Net Income (loss) — 118 — 11 129 Changes in equity of noncontrolling interests — — — ( 6 ) ( 6 ) Distributions to member ( 150 ) ( 122 ) — — ( 272 ) Other comprehensive income (loss), net of income taxes — — ( 7 ) — ( 7 ) Balance, March 31, 2025 $ 10,388 $ 4,970 $ ( 2,309 ) $ 378 $ 13,427 Net Income (loss) — 839 — ( 6 ) 833 Changes in equity of noncontrolling interests — — — ( 15 ) ( 15 ) Contribution from member 103 — — — 103 Distributions to member ( 400 ) ( 121 ) — — ( 521 ) Other comprehensive income (loss), net of income taxes — — 37 — 37 Balance, June 30, 2025 $ 10,091 $ 5,688 $ ( 2,272 ) $ 357 $ 13,864 Net Income (loss) — 930 — ( 1 ) 929 Changes in equity of noncontrolling interests — — — ( 14 ) ( 14 ) Contribution from member 53 — — — 53 Distribution to member — ( 121 ) — — ( 121 ) Other comprehensive income (loss), net of income taxes — — 12 — 12 Balance, September 30, 2025 $ 10,144 $ 6,497 $ ( 2,260 ) $ 342 $ 14,723 See the Combined Notes to Consolidated Financial Statements 15 Table of Contents Constellation Energy Generation, LLC and Subsidiary Companies Consolidated Statements of Changes in Equity (Unaudited) Nine Months Ended September 30, 2024 Member's Equity (In millions) Membership Interest Undistributed Earnings (Deficit) Accumulated Other Comprehensive Income (Loss), net Noncontrolling Interests Total Equity Balance, December 31, 2023 $ 11,537 $ 1,667 $ ( 2,191 ) $ 361 $ 11,374 Net Income (loss) — 883 — — 883 Distributions to member ( 499 ) ( 111 ) — — ( 610 ) Other comprehensive income (loss), net of income taxes — — 11 — 11 Balance, March 31, 2024 $ 11,038 $ 2,439 $ ( 2,180 ) $ 361 $ 11,658 Net Income (loss) — 814 — ( 5 ) 809 Distributions to member ( 500 ) ( 110 ) — — ( 610 ) Other comprehensive income (loss), net of income taxes — — 19 — 19 Balance, June 30, 2024 $ 10,538 $ 3,143 $ ( 2,161 ) $ 356 $ 11,876 Net Income (loss) — 1,200 — ( 4 ) 1,196 Changes in equity of noncontrolling interests — — — 19 19 Distributions to member — ( 111 ) — — ( 111 ) Other comprehensive income (loss), net of income taxes — — 27 — 27 Balance, September 30, 2024 $ 10,538 $ 4,232 $ ( 2,134 ) $ 371 $ 13,007 See the Combined Notes to Consolidated Financial Statements 16 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 The accompanying Consolidated Financial Statements as of September 30, 2025 and for the three and nine months ended September 30, 2025 and 2024 are unaudited but, in our opinion, include all adjustments that are considered necessary for a fair statement of the results for the periods reported herein in accordance with GAAP. All adjustments are of a normal, recurring nature, unless otherwise disclosed. The Consolidated Financial Statements include the accounts of our subsidiaries and all intercompany transactions have been eliminated. Constellation's December 31, 2024 Consolidated Balance Sheet was derived from audited financial statements. The interim financial statements are to be read in conjunction with prior annual financial statements and notes. Financial results for interim periods are not necessarily indicative of results that may be expected for any other interim period or for the fiscal year ending December 31, 2025. These Combined Notes to Consolidated Financial Statements have been prepared pursuant to the rules and regulations of the SEC for Quarterly Reports on Form 10-Q. Certain information and note disclosures normally included in financial statements prepared in accordance with GAAP have been condensed or omitted pursuant to such rules and regulations. Certain prior period amounts have been reclassified to conform to the presentation in the current period. Amounts disclosed relate to CEG Parent and Constellation unless specifically noted as relating to CEG Parent only. Unless otherwise indicated or the context otherwise requires, references herein to the terms “we,” “us,” and “our” refer collectively to CEG Parent and Constellation. Summary of Significant Accounting Policies See Note 1 — Basis of Presentation of our 2024 Form 10-K for additional information on significant accounting policies. 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. 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 acquired 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). See Note 2 — Mergers, Acquisitions, and Dispositions of our 2024 Form 10-K for additional information. We received regulatory approval for the merger from the PUCT and NYPSC in June 2025 and from the FERC in July 2025. Completion of the transaction is subject to the expiration or termination of any agreement with the DOJ to delay the consummation of the transaction and other customary closing conditions. 17 Table of Contents Combined Notes to Consolidated Financial Statements (Dollars in millions, unless otherwise noted) Note 2 — Mergers, Acquisitions, and Dispositions Fees incurred as part of the acquisition were not material to the Consolidated Statements of Operations and Comprehensive Income for the nine months ended September 30, 2025. 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, 16 %). In May 2024, we executed a settlement agreement with all parties (CPS/City of San Antonio, Austin, and NRG Energy, Inc.), 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 Energy, Inc. for our 44 % interest. We are working towards closing the transaction which remains subject to regulatory approvals (including the NRC and PUCT), the terms of settlement are not expected to have a material impact on our consolidated financial statements. See Note 2 — Mergers, Acquisitions, and Dispositions of our 2024 Form 10-K for additional information. 3. Regulatory Matters As discussed in Note 3 — Regulatory Matters of our 2024 Form 10-K, we are involved in various regulatory and legislative proceedings. The following discusses developments in 2025 and updates to the 2024 Form 10-K. Federal Regulatory Matters In July 2025, the OBBBA was signed into law, which, among other things, permanently extends key provisions of the 2017 Tax Cuts and Jobs Act, including full bonus depreciation and immediate deduction of research and development expenses. In addition, the OBBBA preserves transferability and certain federal tax credits from the IRA, specifically, 45U for existing nuclear plants through 2032 and 45Y for new nuclear projects, including uprates, restarts, and new reactors, through 2035, while enhancing the credit to allow advanced nuclear facilities to qualify for the energy communities bonus adder, subject to eligibility requirements. As it relates to both 45U and 45Y, certain foreign entity of concern rules must be met to qualify for the respective credits. Overall, the OBBBA reinforces the long-term economic viability of our nuclear generation assets. While the provisions of the OBBBA resulted in acceleration of cash benefits of approximately $ 200 million, the impact of these provisions recognized in the third quarter of 2025 was not material to our results of operations. 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 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, MDE would be resuming its administrative reconsideration of the 401 Certification. In September 2025, we reached a settlement agreement with MDE and the other parties to the MDE reconsideration proceeding, Lower Susquehanna Riverkeeper Association, and Waterkeepers Chesapeake, which resolves all outstanding issues relating to the 401 Certification. As a result, MDE issued a Revised Water Quality Certification, which is needed for FERC to move forward with the issuance of a new 50 -year license. The Revised Water Quality Certification and accompanying settlement agreement provide for a modified operational flow regime, funding for water quality and resiliency projects, commitments for trash and debris removal, fish and eel passage improvements, funding for freshwater mussel restoration and control of invasive species like 18 Table of Contents Combined Notes to Consolidated Financial Statements (Dollars in millions, unless otherwise noted) Note 3 — Regulatory Matters snakeheads and blue catfish, and funds to support additional studies on dredging and related activities. Our commitments under the various provisions of this settlement are not effective unless and until FERC approves and issues the new license. The terms of this settlement have no impact on the prior settlement agreement with the DOI. The financial impact of this settlement and other commitments related to this renewal are estimated to be $ 15 million to $ 20 million per year, on average, recognized over the term of the 50 -year renewal, inclusive of capital and operating costs. The actual timing and amount of the majority of these costs are not currently fixed and will vary from year to year throughout the life of the new license. We cannot currently predict when FERC will issue the new license. 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. In September 2025, the NRC completed its environmental impact review of Peach Bottom Units 2 and 3, restoring the expiration dates of the respective operating licenses to 2053 and 2054, consistent with current accounting estimates utilized for both depreciation and ARO assumed retirement dates. 4. Revenue from Contracts with Customers We recognize revenue from contracts with customers to depict the transfer of goods or services to customers at an amount that we expect to be entitled to in exchange for those goods or services. Our primary sources of revenue include competitive sales of power, natural gas, and other energy-related products and sustainable solutions. See Note 4 — Revenue from Contracts with Customers of our 2024 Form 10-K for additional information regarding the performance obligations, revenue recognition, and payment terms associated with these sources of revenue. Transaction Price Allocated to Remaining Performance Obligations The following table shows the amounts of future revenues expected to be recorded in each year for performance obligations that are unsatisfied or partially unsatisfied as of September 30, 2025. This disclosure only includes contracts for which the total consideration is fixed and determinable at contract inception. The average contract term varies by customer type and commodity but ranges from one month to several years. 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 $ 56 $ 287 $ 181 $ 116 $ 211 $ 851 Transaction Price Allocated to Previously Satisfied Performance Obligations Our Clinton and Quad Cities units contract with certain utilities in Illinois which 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, 19 Table of Contents Combined Notes to Consolidated Financial Statements (Dollars in millions, unless otherwise noted) Note 4 — Revenue from Contracts with Customers 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. The program commenced June 2017 and continues through May 2027. In various planning years since the program began, 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 2025 through May 2026 planning year, the ZEC price has been established at $1.17 per ZEC, subject to an annual cap of $224 million. ZECs generated and delivered during this planning year will not exceed the annual cap, and as a result we recognized $ 201 million of revenue during the second quarter of 2025 as a receivable for ZECs delivered in prior planning years, with payment expected in the third quarter of 2026. As of September 30, 2025, this receivable is included within Customer accounts receivable, net in the Consolidated Balance Sheets. For the June 2024 through May 2025 planning year, the ZEC price was established at $9.38 per ZEC, subject to an annual cap of $222 million. ZECs generated and delivered during this planning year did not exceed the annual cap, however the revenue recognized during the second quarter of 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. 20 Table of Contents Combined Notes to Consolidated Financial Statements (Dollars in millions, unless otherwise noted) Note 5 — Segment Information 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 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 our reportable segments for the three and nine months ended September 30, 2025 and 2024. Three Months Ended September 30, 2025 Revenues from contracts with customers Other revenues (a) Total Operating revenues Total Purchased power and fuel expenses Total RNF Mid-Atlantic $ 1,770 $ ( 7 ) $ 1,763 $ ( 871 ) $ 892 Midwest 1,222 168 1,390 ( 447 ) 943 New York 582 ( 24 ) 558 ( 159 ) 399 ERCOT 375 253 628 ( 213 ) 415 Other Power Regions 1,313 230 1,543 ( 1,200 ) 343 Total Reportable Segments 5,262 620 5,882 ( 2,890 ) 2,992 Other (b)(c) 441 247 688 ( 677 ) 11 Total Consolidated Results $ 5,703 $ 867 $ 6,570 $ ( 3,567 ) $ 3,003 Three Months Ended September 30, 2024 Mid-Atlantic $ 1,504 $ 99 $ 1,603 $ ( 794 ) $ 809 Midwest 958 317 1,275 ( 391 ) 884 New York 472 35 507 ( 150 ) 357 ERCOT 307 216 523 ( 120 ) 403 Other Power Regions 1,213 230 1,443 ( 1,010 ) 433 Total Reportable Segments 4,454 897 5,351 ( 2,465 ) 2,886 Other (b)(c) 319 880 1,199 ( 654 ) 545 Total Consolidated Results $ 4,773 $ 1,777 $ 6,550 $ ( 3,119 ) $ 3,431 21 Table of Contents Combined Notes to Consolidated Financial Statements (Dollars in millions, unless otherwise noted) Note 5 — Segment Information Nine Months Ended September 30, 2025 Revenues from contracts with customers Other revenues (a) Total Operating revenues Total Purchased power and fuel expenses Total RNF Mid-Atlantic $ 4,811 $ 65 $ 4,876 $ ( 2,393 ) $ 2,483 Midwest 3,958 359 4,317 ( 1,489 ) 2,828 New York 1,772 ( 117 ) 1,655 ( 458 ) 1,197 ERCOT 1,003 486 1,489 ( 589 ) 900 Other Power Regions 3,719 558 4,277 ( 3,560 ) 717 Total Reportable Segments 15,263 1,351 16,614 ( 8,489 ) 8,125 Other (b)(d) 1,706 1,139 2,845 ( 2,594 ) 251 Total Consolidated Results $ 16,969 $ 2,490 $ 19,459 $ ( 11,083 ) $ 8,376 Nine Months Ended September 30, 2024 Mid-Atlantic $ 4,154 $ ( 6 ) $ 4,148 $ ( 1,906 ) $ 2,242 Midwest 2,951 586 3,537 ( 1,185 ) 2,352 New York 1,428 106 1,534 ( 460 ) 1,074 ERCOT 819 382 1,201 ( 375 ) 826 Other Power Regions 3,673 579 4,252 ( 3,157 ) 1,095 Total Reportable Segments 13,025 1,647 14,672 ( 7,083 ) 7,589 Other (b)(d) 1,413 2,101 3,514 ( 1,745 ) 1,769 Total Consolidated Results $ 14,438 $ 3,748 $ 18,186 $ ( 8,828 ) $ 9,358 __________ (a) Includes revenues from nuclear PTCs 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. (c) Revenues from contracts with customers includes natural gas revenues of $ 237 million and $ 184 million and other revenues includes unrealized mark-to-market losses of ($ 156 ) million and gains of $ 516 million for the three months ended September 30, 2025 and 2024, respectively. (d) Revenues from contracts with customers includes natural gas revenues of $ 1,252 million and $ 1,024 million and other revenues includes unrealized mark-to-market losses of ($ 356 ) million and gains of $ 769 million for the nine months ended September 30, 2025 and 2024, respectively. 6. Government Assistance Beginning in 2024, our 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 and $26.00 per MWh and $44.75 per MWh for 2024 and 2025, respectively. We evaluated and expect to meet the annual prevailing wage requirements at all of 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 annually 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. In July 2025, Congress passed the OBBBA which affirmed the provisions of the nuclear PTC with no material changes. For the three and nine months ended September 30, 2025, our Consolidated Statements of Operations and Comprehensive Income included an estimated nuclear PTC benefit in Operating revenues of approximately $ 175 million and $ 220 million, respectively. For the three and nine months ended September 30, 2024, our Consolidated Statements of Operations and Comprehensive Income included an estimated nuclear PTC benefit in Operating revenues of approximately $ 670 million and $ 1,380 million, respectively. Our estimates require 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, from the U.S. Treasury and IRS, and may materially impact the total amount of the benefits we receive. 22 Table of Contents Combined Notes to Consolidated Financial Statements (Dollars in millions, unless otherwise noted) Note 6 — Government Assistance 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. There were no agreements for sales of nuclear PTCs executed in 2025. During the third quarter of 2024, we executed agreements for the sale of $ 1 billion of nuclear PTCs to unaffiliated third parties at a nominal discount, with approximately $ 670 million of cash proceeds received upon sale (included within Cash flows from operating activities in our Consolidated Statements of Cash Flows) and approximately $ 195 million received in the fourth quarter of 2024. Cash received in 2025 on sale agreements executed in 2024 was approximately $ 95 million. As of September 30, 2025, our Consolidated Balance Sheets reflect approximately $ 125 million of nuclear PTCs within Other deferred debits and other assets. As of December 31, 2024, our Consolidated Balance Sheets reflected $ 185 million of estimated nuclear PTCs within Other deferred debits and other assets, and $ 95 million within Other current assets. Additionally, as of September 30, 2025 and December 31, 2024, we recognized a reduction to Accounts payable and accrued expenses in our Consolidated Balance Sheets of $ 270 million and $ 150 million, respectively, 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 September 30, 2025 and December 31, 2024, we have recognized approximately $ 1,140 million and $ 1,030 million, respectively, of estimated payables within Other deferred credits and other liabilities , 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. During the three and nine months ended September 30, 2025, we recognized a reduction to net operating revenue of approximately $ 220 million and $ 30 million, respectively, associated with these programs in our Consolidated Statements of Operations and Comprehensive Income, compared to a reduction to net operating revenue of approximately $ 115 million and increase to net operating revenue (pre-tax) of approximately $ 10 million during the three and nine months ended September 30, 2024, respectively. As with the actual amount of the nuclear PTC earned, which cannot be determined until after the end of the calendar year, 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. The activity and balances were not material for the nine months ended September 30, 2024 given it did not include an allowance related to the sales of customer accounts receivable disclosed below . Balance as of December 31, 2024 $ 190 Current period provision for expected credit losses 35 Write-offs, net of recoveries (a) ( 35 ) Balance as of September 30, 2025 $ 190 __________ (a) Recoveries were not material. The Allowance for credit losses on Other accounts receivable was not material as of the balance sheet dates. Unbilled Customer Revenue We recorded $ 1,045 million and $ 1,109 million of unbilled customer revenues in Customer accounts receivables, net in the Consolidated Balance Sheets as of September 30, 2025 and December 31, 2024, respectively. 23 Table of Contents Combined Notes to Consolidated Financial Statements (Dollars in millions, unless otherwise noted) Note 7 — Accounts Receivable Sales of Customer Accounts Receivable In 2020, NER, a bankruptcy remote, special purpose entity, which is wholly owned by us, entered into a revolving accounts receivable financing arrangement with a number of financial institutions and a commercial paper conduit (Purchasers) to sell certain customer accounts receivable (Facility). On December 31, 2024, we amended the Facility. We no longer sell receivables to the Purchasers and all outstanding receivables were assigned back to us. 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 is referred to as the DPP. 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 resulted in the recognition of $ 1,529 million of Customer accounts receivable as of December 31, 2024. See Note 12 — Debt and Credit Agreements for terms of the amended Facility. The following table presents our cash proceeds associated with the Facility prior to the amendment. Nine Months Ended September 30, 2024 Proceeds from new transfers (a) $ 1,688 Cash collections received on DPP (b) 7,404 Cash collections reinvested in the Facility $ 9,092 __________ (a) Customer accounts receivable sold into the Facility was $ 9,370 million. (b) Does not include the $ 300 million net cash payments made to the Purchasers in order to reduce the outstanding borrowing amount under the Facility. We previously 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 was ($ 7,682 ) million for the nine months ended September 30, 2024. The collection and reinvestment of DPP was recognized in Cash flows from investing activities in the Collection of DPP, net line in the Consolidated Statements of Cash Flows, which was $ 7,104 million for the nine months ended September 30, 2024. See Note 16 — Variable Interest Entities for additional information on NER. Other Sales of Customer Accounts Receivables We are required, under supplier tariffs, to sell customer receivables to certain utility companies at a nominal discount. The total gross receivables sold were $ 3,207 million and $ 228 million for the nine months ended September 30, 2025 and 2024, respectively. Prior to the Facility amendment discussed in the preceding paragraphs, certain accounts receivable subject to these supplier tariffs were sold to the Purchasers under the Facility. 8. Nuclear Decommissioning Nuclear Decommissioning Asset Retirement Obligations We have a legal obligation to decommission our nuclear power plants following the permanent cessation of operations. See Note 10 — Asset Retirement Obligations of our 2024 Form 10-K for additional information regarding AROs and the financial statement impact of changes in estimates. The following table provides a rollforward of the nuclear decommissioning AROs reflected in the Consolidated Balance Sheets from December 31, 2024 to September 30, 2025: Balance as of December 31, 2024 $ 12,186 Accretion expense 467 Net increase due to changes in, and timing of, estimated future cash flows 108 Costs incurred related to decommissioning plants ( 12 ) Balance as of September 30, 2025 $ 12,749 24 Table of Contents Combined Notes to Consolidated Financial Statements (Dollars in millions, unless otherwise noted) Note 8 — Nuclear Decommissioning During the nine months ended September 30, 2025, the net $ 108 million increase in the ARO for the changes in, and timing of, estimated future cash flows was driven primarily by higher escalation rates partially offset by higher discount rates and revised cost studies for Braidwood, Byron, Clinton, and LaSalle plants. NDT Funds We had NDT funds totaling $ 19,040 million and $ 17,321 million as of September 30, 2025 and December 31, 2024, respectively. The current portions of the NDT funds, which are included in Other current assets in our Consolidated Balance Sheets, were not material as of September 30, 2025 and December 31, 2024. See Note 17 — Supplemental Financial Information for additional information on activities of the NDT funds. Accounting Implications of the Regulatory Agreement Units See Note 1 — Basis of Presentation and Note 10 — Asset Retirement Obligations of our 2024 Form 10-K for additional information on the Regulatory Agreement Units. The following table presents our noncurrent payables to ComEd, PECO, CenterPoint, and AEP Texas reflected as Payables related to Regulatory Agreement Units in the Consolidated Balance Sheets as of September 30, 2025 and December 31, 2024: September 30, 2025 December 31, 2024 ComEd $ 4,231 $ 3,780 PECO 427 247 CenterPoint 418 365 AEP Texas 146 126 Payables related to Regulatory Agreement Units $ 5,222 $ 4,518 NRC Minimum Funding Requirements NRC regulations require that licensees of nuclear generating facilities demonstrate reasonable assurance that funds will be available in specified minimum amounts for radiological decommissioning of the facility at the end of its life. We filed our biennial decommissioning funding status report with the NRC in March 2025 for all units, including our shutdown units, except for STP units which were included in a separate report to the NRC submitted by STPNOC. The status reports demonstrated adequate decommissioning funding assurance based on trust fund values as of December 31, 2024 for all our units except for Peach Bottom Unit 1. Financial assurance for decommissioning Peach Bottom Unit 1 is provided by collections from PECO customers. See Note 10 — Asset Retirement Obligations of our 2024 Form 10-K for additional information. 25 Table of Contents Combined Notes to Consolidated Financial Statements (Dollars in millions, unless otherwise noted) Note 9 — Income Taxes 9. Income Taxes Rate Reconciliation The effective income tax rate varies from the U.S. federal statutory rate principally due to the following: Three Months Ended September 30, 2025 2024 U.S. federal statutory income tax 21.0 % $ 293 21.0 % $ 345 (Decrease) increase due to: State income taxes, net of federal income tax benefit (a) 5.1 71 4.8 80 Foreign tax effects 0.1 1 0.1 1 Tax credits PTC ( 2.8 ) ( 40 ) ( 8.0 ) ( 132 ) Amortization of ITC, including deferred taxes on basis differences ( 0.3 ) ( 4 ) ( 0.3 ) ( 5 ) Other ( 0.2 ) ( 3 ) ( 0.1 ) ( 1 ) Nontaxable or nondeductible items Share-based payment awards — — ( 0.1 ) ( 1 ) Excess officers compensation 1.0 14 1.3 21 Other 0.9 12 0.4 6 Other adjustments Qualified NDT fund income and losses 8.6 122 8.2 135 Effective income tax (b) 33.4 % $ 466 27.3 % $ 449 Nine Months Ended September 30, 2025 2025 2024 U.S. federal statutory income tax 21.0 % $ 592 21.0 % $ 768 (Decrease) increase due to: State income taxes, net of federal income tax benefit (a) 4.2 118 1.1 39 Foreign tax effects 0.1 2 0.1 2 Tax credits PTC ( 1.9 ) ( 53 ) ( 7.7 ) ( 281 ) Amortization of ITC, including deferred taxes on basis differences ( 0.4 ) ( 10 ) ( 0.3 ) ( 10 ) Other ( 0.3 ) ( 8 ) ( 0.4 ) ( 14 ) Nontaxable or nondeductible items Share-based payment awards ( 1.4 ) ( 40 ) ( 0.4 ) ( 16 ) Excess officers compensation 1.1 30 0.8 30 Other 0.4 13 0.2 9 Other adjustments Qualified NDT fund income and losses 10.1 284 6.6 241 Effective income tax (b) 32.9 % $ 928 21.0 % $ 768 __________ (a) State taxes in California, Illinois, Maryland, Massachusetts, and New Jersey made up the majority (greater than 50%) of the tax effect in this category. (b) Amounts may not recalculate due to rounding. 26 Table of Contents Combined Notes to Consolidated Financial Statements (Dollars in millions, unless otherwise noted) Note 9 — Income Taxes Other Tax Matters One Big Beautiful Bill Act In July 2025, Congress passed the OBBBA which, among other things, included certain changes in tax law. See Note 3 — Regulatory Matters for additional information. 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 in which we were included in joint federal and state filings. However, the TMA specifies the portion of this tax liability for which we will bear contractual responsibility, and we and Exelon agreed to indemnify each other against any amounts for which such indemnified party is not responsible. Specifically, we will be liable for taxes due and payable in connection with tax returns that we are required to file. We will also be liable for our share of certain taxes required to be paid by Exelon with respect to taxable years or periods (or portions thereof) ending on or prior to the separation to the extent that we would have been responsible for such taxes under the Exelon tax sharing agreement then existing. As of September 30, 2025 and December 31, 2024, respectively, our Consolidated Balance Sheets reflect $ 42 million and $ 39 million in Other deferred credits and other liabilities, for tax liabilities where we maintain contractual responsibility to Exelon. Tax Refunds and Attributes. The TMA provides for the allocation of certain pre-closing tax attributes between us and Exelon. Tax attributes will be allocated in accordance with the principles set forth in the existing Exelon tax sharing agreement, unless otherwise required by law. Under the TMA, we will be entitled to refunds for taxes for which we are responsible. In addition, it is expected that Exelon will have tax attributes that may be used to offset Exelon’s future tax liabilities. A significant portion of such attributes were generated by our business. In February 2024, we executed an amendment to the TMA that modified the timing of Exelon's payment of amounts due to us. During the second quarter of 2025 and 2024, we received payments for tax attributes utilized by Exelon related to the 2024 and 2023 tax years of $ 127 million and $ 183 million, respectively. As of September 30, 2025 and December 31, 2024, respectively, we had $ 174 million and $ 138 million in Other accounts receivable and $ 38 million and $ 201 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. 27 Table of Contents Combined Notes to Consolidated Financial Statements (Dollars in millions, unless otherwise noted) Note 10 — Retirement Benefits 10. Retirement Benefits Components of Net Periodic Benefit (Credits) Costs See Note 1 — Basis of Presentation of our 2024 Form 10-K for additional information on where we report the service cost and other non-service cost (credit) components for all plans. T he following tables present the components of our net periodic benefit (credit) cost for the three and nine months ended September 30, 2025 and 2024. The amounts below are shown prior to capitalization and co-owner allocations, the effects of which were not material for any of the periods presented. Pension Benefits OPEB Total Pension Benefits and OPEB Three Months Ended September 30, 2025 2024 2025 2024 2025 2024 Components of net periodic benefit (credit) cost: Service cost $ 21 $ 22 $ 4 $ 4 $ 25 $ 26 Non-service components of pension benefits & OPEB (credit) cost: Interest cost 101 95 19 18 120 113 Expected return on assets ( 122 ) ( 123 ) ( 9 ) ( 11 ) ( 131 ) ( 134 ) Amortization of: Prior service (credit) cost 1 1 ( 2 ) ( 2 ) ( 1 ) ( 1 ) Actuarial (gain) loss 26 25 ( 2 ) ( 3 ) 24 22 Settlement charges 1 3 — — 1 3 Non-service components of pension benefits & OPEB (credit) cost 7 1 6 2 13 3 Net periodic benefit (credit) cost $ 28 $ 23 $ 10 $ 6 $ 38 $ 29 Pension Benefits OPEB Total Pension Benefits and OPEB Nine Months Ended September 30, 2025 2024 2025 2024 2025 2024 Components of net periodic benefit (credit) cost: Service cost $ 63 $ 67 $ 13 $ 13 $ 76 $ 80 Non-service components of pension benefits & OPEB (credit) cost: Interest cost 306 286 58 54 364 340 Expected return on assets ( 367 ) ( 371 ) ( 25 ) ( 32 ) ( 392 ) ( 403 ) Amortization of: Prior service (credit) cost 1 1 ( 5 ) ( 5 ) ( 4 ) ( 4 ) Actuarial (gain) loss 77 76 ( 6 ) ( 7 ) 71 69 Settlement charges 1 7 — — 1 7 Non-service components of pension benefits & OPEB (credit) cost 18 ( 1 ) 22 10 40 9 Net periodic benefit (credit) cost $ 81 $ 66 $ 35 $ 23 $ 116 $ 89 28 Table of Contents Combined Notes to Consolidated Financial Statements (Dollars in millions, unless otherwise noted) Note 11 — Derivative Financial Instruments 11. 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, including NPNS, are available through special election and designation, provided they meet specific, restrictive criteria both at the time of designation and on an ongoing basis. All derivative instruments, excluding NPNS, are recorded at fair value through earnings. For all NPNS derivative instruments, accounts receivable or accounts payable are recorded when derivatives settle, and revenue or expense is recognized in earnings as the underlying physical commodity is delivered. Authoritative guidance about offsetting assets and liabilities requires the fair value of derivative instruments to be shown in the Combined Notes to Consolidated Financial Statements on a gross basis, even when the derivative instruments are subject to legally enforceable master netting agreements and qualify for net presentation in the Consolidated Balance Sheets. A master netting agreement is an agreement between two counterparties that may have derivative and non-derivative contracts with each other providing for the net settlement of all referenced contracts via one payment stream, which takes place as the contracts deliver, when collateral is requested or in the event of default. In the tables below, which present fair value balances, our energy-related economic hedges are shown gross. The impact of the netting of fair value balances with the same counterparty that are subject to legally enforceable master netting agreements, as well as netting of cash collateral, including margin on exchange positions, is aggregated in the collateral and netting columns. Our use of cash collateral is generally unrestricted unless we were downgraded below investment grade. As our senior unsecured debt rating is currently rated at BBB+ and Baa1 by S&P and Moody's, respectively, it would take a three-notch downgrade by S&P or Moody's for our rating to go below investment grade. Commodity Price Risk We employ established policies and procedures to manage our risks associated with market fluctuations in commodity prices by entering into physical and financial derivative contracts, including swaps, futures, forwards, options, and short-term and long-term commitments to purchase and sell energy and energy-related products. We believe these instruments, which are either determined to be non-derivative or classified as economic hedges, mitigate exposure to fluctuations in commodity prices. To the extent the amount of energy we produce or procure differs from the amount of energy we have contracted to sell, we are exposed to market fluctuations in the prices of electricity, natural gas, and other commodities. We use a variety of derivative and non-derivative instruments to manage the commodity price risk of our electric generation facilities, including power and gas sales, fuel and power purchases, natural gas transportation and pipeline capacity agreements, and other energy-related products marketed and purchased. To manage these risks, we may enter into fixed-price derivative or non-derivative contracts to hedge the variability in future cash flows from expected sales of power and gas and purchases of power and fuel. The objectives for executing such hedges include fixing the price for a portion of anticipated future electricity sales at a level that provides an acceptable return. We are also exposed to differences between the locational settlement prices of certain economic hedges and the hedged generating units. This price difference is actively managed through other instruments which include derivative congestion products, whose changes in fair value are recognized in earnings each period, and auction revenue rights, which are accounted for on an accrual basis. In general, increases and decreases in forward market prices have a positive and negative impact, respectively, on owned and contracted generation positions that have not been hedged. Beginning in 2024, our existing nuclear fleet is eligible for a nuclear PTC, an important tool in managing commodity price risk for each nuclear unit not already receiving state support. The nuclear PTC provides increasing levels of support as unit revenues decline below levels established in the IRA and is further adjusted for inflation annually through the duration of the program based on the GDP price deflator for the preceding calendar year. See Note 6 — Government Assistance for additional information. 29 Table of Contents Combined Notes to Consolidated Financial Statements (Dollars in millions, unless otherwise noted) Note 11 — Derivative Financial Instruments 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. The following tables provide a summary of the commodity derivative fair value balances recorded as of September 30, 2025 and December 31, 2024: September 30, 2025 Economic Hedges Collateral (a) Netting (a) Total Mark-to-market derivative assets (current) $ 6,245 $ 218 $ ( 5,836 ) $ 627 Mark-to-market derivative assets (noncurrent) 4,444 166 ( 4,152 ) 458 Total mark-to-market derivative assets 10,689 384 ( 9,988 ) 1,085 Mark-to-market derivative liabilities (current) ( 6,495 ) 195 5,836 ( 464 ) Mark-to-market derivative liabilities (noncurrent) ( 4,788 ) 197 4,152 ( 439 ) Total mark-to-market derivative liabilities ( 11,283 ) 392 9,988 ( 903 ) Total mark-to-market derivative net assets (liabilities) $ ( 594 ) $ 776 $ — $ 182 December 31, 2024 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 _________ (a) We net all available amounts allowed in our Consolidated Balance Sheets in accordance with authoritative guidance for derivatives. These amounts include unrealized derivative transactions with the same counterparty under legally enforceable master netting agreements and cash collateral. The following table summarizes the net buy/(sell) notional position of commodity derivative transactions, excluding our NPNS derivatives that are not recorded at fair value, as of September 30, 2025 and December 31, 2024: Total Net Position (In Millions) Commodity Type September 30, 2025 December 31, 2024 Unit of Measure Electricity ( 261 ) ( 130 ) MWh Natural Gas ( 130 ) 33 MMBtu Emissions ( 32 ) ( 18 ) Short Ton 30 Table of Contents Combined Notes to Consolidated Financial Statements (Dollars in millions, unless otherwise noted) Note 11 — Derivative Financial Instruments Economic Hedges (Commodity Price Risk) For the three and nine months ended September 30, 2025 and 2024, 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. Three Months Ended September 30, Nine Months Ended September 30, Income Statement Location 2025 2024 2025 2024 Operating revenues $ ( 158 ) $ 519 $ ( 354 ) $ 774 Purchased power and fuel 28 ( 119 ) 67 404 Total $ ( 130 ) $ 400 $ ( 287 ) $ 1,178 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 $ 1,506 million and $ 592 million as of September 30, 2025 and December 31, 2024, respectively. The mark-to-market derivative assets and liabilities as of September 30, 2025 and December 31, 2024 and the mark-to-market gains and losses associated with management of interest rate and foreign currency risk for the three and nine months ended September 30, 2025 and 2024 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. Credit Risk We would be exposed to credit-related losses in the event of non-performance by counterparties on executed derivative instruments. The credit exposure of derivative contracts, before collateral, is represented by the fair value of contracts as of the reporting date. For commodity derivatives, we enter into enabling agreements that allow for payment netting with our counterparties, which reduces our exposure to counterparty risk by providing for the offset of amounts payable to the counterparty against amounts receivable from the counterparty. Typically, each enabling agreement is for a specific commodity and, with respect to each individual counterparty, netting is limited to t ransactions involving that specific commodity product, except where master netting agreements exist with a counterparty that allows for cross product netting. In addition to right of offset language in the enabling agreement, our credit department establishes credit limits, margining thresholds and collateral requirements for each counterparty, which are defined in the derivative contracts. Counterparty credit limits are based on an internal credit review process that considers a variety of factors, including the results of a scoring model, leverage, liquidity, profitability, credit ratings by credit rating agencies, and other risk management criteria. To the extent that a counterparty’s margining thresholds are exceeded, the counterparty is required to post collateral with us, as specified in each enabling agreement. Our credit department monitors current and forward credit exposure to counterparties and their affiliates, both on an individual and an aggregate basis. 31 Table of Contents Combined Notes to Consolidated Financial Statements (Dollars in millions, unless otherwise noted) Note 11 — Derivative Financial Instruments The following tables provide information on the credit exposure for derivative instruments, NPNS and payables and receivables, net of collateral and instruments that are subject to master netting agreements, as of September 30, 2025. The amounts in the tables below exclude credit risk exposure from individual retail counterparties, forward values on non-derivative contracts and exposure through RTOs, ISOs, as well as commodity exchanges. The tables further delineate that exposure by credit rating of the counterparties and provide guidance on the concentration of credit risk to individual counterparties. Rating as of September 30, 2025 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 $ 775 $ 13 $ 762 1 $ 151 Non-investment grade 7 — 7 — — No external ratings Internally rated — investment grade 134 6 128 — — Internally rated — non-investment grade 152 36 116 — — Total $ 1,068 $ 55 $ 1,013 1 $ 151 __________ (a) As of September 30, 2025, credit collateral held from counterparties where we had credit exposure inclu ded $ 1 million of cash a nd $ 54 million o f letters of credit. Net Credit Exposure by Type of Counterparty As of September 30, 2025 Investor-owned utilities, marketers, power producers $ 834 Energy cooperatives and municipalities 85 Financial Institutions 46 Other 48 Total $ 1,013 Credit-Risk-Related Contingent Features As part of the normal course of business, we routinely enter into physically and financially settled contracts for the purchase and sale of capacity, electricity, fuels, emissions allowances, and other energy-related products. Certain of our derivative instruments contain provisions that require us to post collateral. We also enter into commodity transactions on exchanges where the exchanges act as the counterparty to each trade. Transactions on the exchanges must adhere to comprehensive collateral and margining requirements. This collateral may be posted in the form of cash or credit support with thresholds contingent upon our credit ratings from S&P and Moody's. The collateral and credit support requirements vary by contract and by counterparty. These credit-risk-related contingent features stipulate that if we were to be downgraded or lose our investment grade credit ratings (based on our senior unsecured debt rating), we would be required to provide additional collateral. This incremental collateral requirement allows for the offsetting of derivative instruments that are assets with the same counterparty, where the contractual right of offset exists under applicable master netting agreements. In the absence of expressly agreed-to provisions that specify the collateral that must be provided, collateral requested will be a function of the facts and circumstances of the situation at the time of the demand. In such cases, we believe an amount of several months of future payments (e.g., capacity payments) rather than a calculation of fair value is a reasonable estimate for the contingent collateral obligation, which has been factored into the disclosure below. 32 Table of Contents Combined Notes to Consolidated Financial Statements (Dollars in millions, unless otherwise noted) Note 11 — Derivative Financial Instruments The aggregate fair value of all derivative instruments with credit-risk-related contingent features in a liability position that are not fully collateralized (excluding transactions on the exchanges that are fully collateralized) is detailed in the table below: Credit-Risk-Related Contingent Features September 30, 2025 December 31, 2024 Gross fair value of derivative contracts containing this feature $ ( 1,374 ) $ ( 1,346 ) Offsetting fair value of derivative contracts under master netting arrangements 575 602 Net fair value of derivative contracts containing this feature $ ( 799 ) $ ( 744 ) As of September 30, 2025 and December 31, 2024, 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. September 30, 2025 December 31, 2024 Cash collateral posted (a) $ 828 $ 635 Letters of credit posted (a) 900 890 Cash collateral held (a) 52 49 Letters of credit held (a) 130 91 Additional collateral required in the event of a credit downgrade below investment grade (at BB+/Ba1) (b)(c)(d) 2,440 1,949 __________ (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 current levels of BBB+ and Baa1 at S&P and Moody's, respectively. We routinely enter into supply forward contracts with certain utilities with one-sided collateral postings only from us. If market prices fall below the benchmark price levels in these contracts, the utilities are not required to post collateral. However, when market prices rise above the benchmark price levels, we are required to post collateral once certain unsecured credit limits are exceeded. 12. 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 September 2025, we amended our existing revolving credit facility (RCF) to increase the available aggregate commitment from $ 4.5 billion to $ 7.0 billion, which included incremental revolving credit commitments of $ 2.5 billion and extension of the maturity date to September 2030. The incremental commitments will be available upon the closing of the Calpine acquisition. See Note 2 — Mergers, Acquisitions, and Dispositions for additional information. The RCF may be drawn down in the form of loans and/or to support commercial paper and letter of credit issuances. The RCF fixed facility fee rate is 0.175 % and borrowings under the RCF bear interest at a rate based upon either the Daily Simple SOFR rate or a Term SOFR rate, plus an adder based upon our credit rating. The adders for the 33 Table of Contents Combined Notes to Consolidated Financial Statements (Dollars in millions, unless otherwise noted) Note 12 — Debt and Credit Agreements Daily Simple SOFR-based borrowings and Term SOFR borrowings are 0.075 % and 1.075 %, respectively. The letters of credit bear interest at a rate of 1.075 %. If we were to lose our investment grade credit rating, the maximum adders for Daily Simple SOFR rate borrowings and Term SOFR rate borrowings would be 1.00 % and 2.00 %, respectively. The credit agreements also require us to pay facility fees based upon the aggregate commitments. The fees vary depending upon our credit rating. Accounts Receivable Facility 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 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 September 30, 2025. 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. As of September 30, 2025 and December 31, 2024, we had the following aggregate bank commitments, credit facility borrowings and available capacity under our respective credit facilities: September 30, 2025 Facility Type Aggregate Bank Commitment Facility Draws Outstanding Letters of Credit (a) Outstanding Commercial Paper (b) Total Available Capacity Revolving Credit Facility $ 4,500 $ — $ 49 $ — $ 4,451 Bilaterals (c) 2,350 — 1,167 — 1,183 Accounts Receivable Facility 1,500 — — — 1,500 Liquidity Facility 971 — 789 — 159 (c) Project Finance 137 — 122 — 15 Total $ 9,458 $ — $ 2,127 $ — $ 7,308 December 31, 2024 Revolving Credit Facility $ 4,500 $ — $ 51 $ — $ 4,449 Bilaterals 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 __________ (a) Excludes an additional outstanding letter of credit which was not issued under these facilities of $ 15 million as of September 30, 2025 and December 31, 2024. See Note 14 — Commitments and Contingencies for additional information. (b) Our commercial paper program is supported by the revolving credit agreement. In order to maintain our commercial paper program in the amounts indicated above, we must have a credit facility in place, at least equal to the amount of our commercial paper program. As of September 30, 2025 and December 31, 2024, the maximum program size of our commercial paper program was $ 4.5 billion. 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 September 30, 2025 and December 31, 2024. 34 Table of Contents Combined Notes to Consolidated Financial Statements (Dollars in millions, unless otherwise noted) Note 12 — Debt and Credit Agreements (c) In January 2025, we initiated a new bilateral credit agreement for $ 200 million, with no maturity date. In March 2025, a bilateral credit agreement initiated in March 2023 was extended for an additional two years to March 2027. In March 2025, we initiated a new bilateral credit agreement for $ 300 million, scheduled to mature March 2026. (d) 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 September 30, 2025 and December 31, 2024, without posting additional collateral, the actual availability of facility, prior to outstanding letters of credit was $ 948 million and $ 928 million, respectively. Short-Term Loan Agreements As of September 30, 2025 we had the following short-term loan agreements, both of which are unsecured and reflected in Short-term borrowings in the Consolidated Balance Sheets: Month Initiated Interest Rate Maturity Outstanding Amount as of September 30, 2025 Outstanding Amount as of December 31, 2024 May 2025 1-month SOFR + 0.90 % May 2026 $ 900 $ — September 2025 1-month SOFR + 0.90 % September 2026 750 — Long-Term Debt Debt Issuances and Redemptions During the nine months ended September 30, 2025, the following long-term debt was issued (redeemed): Type Interest Rate Maturity Amount 2025 Senior Notes 3.25 % June 2025 $ ( 900 ) CR Nonrecourse Debt 3-month SOFR + 2.25 % December 2027 ( 34 ) Continental Wind Nonrecourse Debt 6.00 % February 2033 ( 31 ) West Medway II Nonrecourse Debt 1-month SOFR + 3.225 % - 3.350 % March 2026 ( 26 ) Tax Exempt Pollution Control Revenue Bonds 4.45 % March 2025 ( 23 ) Antelope Valley DOE Nonrecourse Debt 2.29 % - 3.56 % January 2037 ( 15 ) RPG Nonrecourse Debt 4.11 % March 2035 ( 7 ) Total long-term debt issued (redeemed) $ ( 1,036 ) Debt Covenants As of September 30, 2025, we are in compliance with all debt covenants. 35 Table of Contents Combined Notes to Consolidated Financial Statements (Dollars in millions, unless otherwise noted) Note 13 — Fair Value of Financial Assets and Liabilities 13. Fair Value of Financial Assets and Liabilities We measure and classify fair value measurements in accordance with the hierarchy as defined by GAAP. The hierarchy prioritizes the inputs to valuation techniques used to measure fair value into three levels as follows: • Level 1 — quoted prices (unadjusted) in active markets for identical assets or liabilities that we have the ability to liquidate as of the reporting date. • Level 2 — inputs other than quoted prices included within Level 1 that are directly observable for the asset or liability or indirectly observable through corroboration with observable market data. • Level 3 — unobservable inputs, such as internally developed pricing models or third-party valuations for the asset or liability due to little or no market activity for the asset or liability. Fair Value of Financial Liabilities Recorded at Amortized Cost The following table presents the carrying amounts and fair values of our long-term debt and SNF obligation as of September 30, 2025 and December 31, 2024. 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. September 30, 2025 December 31, 2024 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 $ 7,387 $ 7,060 $ 681 $ 7,741 $ 8,412 $ 7,805 $ 716 $ 8,521 SNF Obligation 1,412 1,407 — 1,407 1,366 1,278 — 1,278 Valuation Techniques Used to Determine Fair Value and Net Asset Value Our valuation techniques used to measure the fair value and net asset value of the assets and liabilities are in accordance with the policies discussed in Note 17 — Fair Value of Financial Assets and Liabilities of our 2024 Form 10-K. 36 Table of Contents Combined Notes to Consolidated Financial Statements (Dollars in millions, unless otherwise noted) Note 13 — Fair Value of Financial Assets and Liabilities Recurring Fair Value Measurements The following table presents assets and liabilities measured and recorded at fair value in the Consolidated Balance Sheets on a recurring basis and their level within the fair value hierarchy as of September 30, 2025 and December 31, 2024: September 30, 2025 December 31, 2024 Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total Assets Cash equivalents (a) $ 30 $ — $ — $ 30 $ 120 $ — $ — $ 120 NDT fund investments Cash equivalents (b) 368 172 — 540 187 163 — 350 Equities 6,291 1,537 — 7,828 5,230 1,897 — 7,127 Fixed income 2,209 1,564 387 4,160 2,089 1,462 368 3,919 Private credit — — 130 130 — — 134 134 Assets measured at NAV — — — 6,382 — — — 5,791 NDT fund investments subtotal (c) 8,868 3,273 517 19,040 7,506 3,522 502 17,321 Rabbi trust investments 63 43 1 107 58 41 1 100 Investments in equities 112 — — 112 389 — — 389 Mark-to-market derivative assets Economic hedges 1,264 4,893 4,538 10,695 1,278 5,306 2,641 9,225 Effect of netting and allocation of collateral ( 1,118 ) ( 4,645 ) ( 3,841 ) ( 9,604 ) ( 1,097 ) ( 4,790 ) ( 2,123 ) ( 8,010 ) Mark-to-market derivative assets subtotal 146 248 697 1,091 181 516 518 1,215 Total assets measured at fair value 9,219 3,564 1,215 20,380 8,254 4,079 1,021 19,145 Liabilities Mark-to-market derivative liabilities Economic hedges ( 1,270 ) ( 5,090 ) ( 4,934 ) ( 11,294 ) ( 1,222 ) ( 5,462 ) ( 2,778 ) ( 9,462 ) Effect of netting and allocation of collateral 1,207 4,991 4,182 10,380 1,180 5,157 2,259 8,596 Mark-to-market derivative liabilities subtotal ( 63 ) ( 99 ) ( 752 ) ( 914 ) ( 42 ) ( 305 ) ( 519 ) ( 866 ) Deferred compensation obligation — ( 116 ) — ( 116 ) — ( 93 ) — ( 93 ) Total liabilities measured at fair value ( 63 ) ( 215 ) ( 752 ) ( 1,030 ) ( 42 ) ( 398 ) ( 519 ) ( 959 ) Total net assets $ 9,156 $ 3,349 $ 463 $ 19,350 $ 8,212 $ 3,681 $ 502 $ 18,186 __________ (a) CEG Parent has $ 75 million and $ 130 million of Level 1 cash equivalents as of September 30, 2025 and December 31, 2024, respectively. We exclude cash of $ 3,928 million and $ 2,924 million, and restricted cash of $ 79 million and $ 71 million as of September 30, 2025 and December 31, 2024, respectively. CEG Parent has excluded an additional $ 9 million and $ 4 million of cash as of September 30, 2025 and December 31, 2024, respectively. (b) Includes net liabilities of $ 149 million and $ 148 million as of September 30, 2025 and December 31, 2024, respectively, which consist of receivables related to pending securities sales, interest and dividend receivables, repurchase agreement obligations, and payables related to pending securities purchases. The repurchase agreements are generally short-term in nature with durations generally of 30 days or less. (c) Includes total NDT derivative assets and liabilities that are not material, which have notional amounts of $ 1,173 million and $ 1,119 million as of September 30, 2025 and December 31, 2024, 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. As of September 30, 2025, our NDTs have outstanding commitments to invest in private credit, private equity, and real assets of $ 479 million, $ 451 million, and $ 673 million, respectively. These commitments will be funded by our existing NDT funds. 37 Table of Contents Combined Notes to Consolidated Financial Statements (Dollars in millions, unless otherwise noted) Note 13 — Fair Value of Financial Assets and Liabilities Equity Security Investments without Readily Determinable Fair Values. We hold investments without readily determinable fair values with carrying amounts of $ 206 million and $ 150 million as of September 30, 2025 and December 31, 2024, respectively. Changes in fair value, cumulative adjustments, and impairments were not material for the three and nine months ended September 30, 2025 and the year ended December 31, 2024. Reconciliation of Level 3 Assets and Liabilities The following tables present the fair value reconciliation of Level 3 assets and liabilities measured at fair value on a recurring basis during the three and nine months ended September 30, 2025 and 2024: Three Months Ended September 30, 2025 NDT Fund Investments Mark-to-Market Derivatives Rabbi Trust Investments Total Balance as of July 1, 2025 $ 504 $ 137 $ 1 $ 642 Total realized / unrealized gains (losses) Included in net income (loss) 4 ( 211 ) (a) — ( 207 ) Included in Payables related to Regulatory Agreement Units 9 — — 9 Change in collateral — 58 — 58 Purchases — 17 — 17 Transfers into Level 3 — ( 1 ) (b) — ( 1 ) Transfers out of Level 3 — ( 55 ) (b) — ( 55 ) Balance as of September 30, 2025 $ 517 $ ( 55 ) $ 1 $ 463 The amount of total gains (losses) included in income attributed to the change in unrealized gains (losses) related to assets and liabilities as of September 30, 2025 $ 4 $ ( 114 ) $ — $ ( 110 ) Three Months Ended September 30, 2024 NDT Fund Investments Mark-to-Market Derivatives Rabbi Trust Investments Total Balance as of July 1, 2024 $ 492 $ 312 $ 1 $ 805 Total realized / unrealized gains (losses) Included in net income (loss) 4 58 (a) — 62 Included in Payables related to Regulatory Agreement Units 9 — — 9 Change in collateral — ( 166 ) — ( 166 ) Purchases — 14 — 14 Settlements ( 7 ) — — ( 7 ) Transfers into Level 3 1 ( 12 ) (b) — ( 11 ) Transfers out of Level 3 — — (b) — — Balance as of September 30, 2024 $ 499 $ 206 $ 1 $ 706 The amount of total gains (losses) included in income attributed to the change in unrealized gains (losses) related to assets and liabilities as of September 30, 2024 $ 4 $ 191 $ — $ 195 38 Table of Contents Combined Notes to Consolidated Financial Statements (Dollars in millions, unless otherwise noted) Note 13 — Fair Value of Financial Assets and Liabilities Nine Months Ended September 30, 2025 NDT Fund Investments Mark-to-Market Derivatives Rabbi Trust Investments Total Balance as of January 1, 2025 $ 502 $ ( 1 ) $ 1 $ 502 Total realized / unrealized gains (losses) Included in net income (loss) 6 ( 248 ) (a) — ( 242 ) Included in Payables related to Regulatory Agreement Units 12 — — 12 Change in collateral — 205 — 205 Purchases — 68 — 68 Sales — ( 5 ) — ( 5 ) Settlements ( 4 ) — — ( 4 ) Transfers into Level 3 1 ( 44 ) (b) — ( 43 ) Transfers out of Level 3 — ( 30 ) (b) — ( 30 ) Balance as of September 30, 2025 $ 517 $ ( 55 ) $ 1 $ 463 The amount of total gains (losses) included in income attributed to the change in unrealized gains (losses) related to assets and liabilities as of September 30, 2025 $ 6 $ ( 4 ) $ — $ 2 Nine Months Ended September 30, 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) 4 ( 433 ) (a) — ( 429 ) Included in Payables related to Regulatory Agreement Units 13 — — 13 Change in collateral — ( 173 ) — ( 173 ) Purchases 66 32 — 98 Sales — ( 83 ) — ( 83 ) Settlements ( 14 ) ( 2 ) — ( 16 ) Transfers into Level 3 1 27 (b) — 28 Transfers out of Level 3 — ( 31 ) (b) — ( 31 ) Balance as of September 30, 2024 $ 499 $ 206 $ 1 $ 706 The amount of total gains (losses) included in income attributed to the change in unrealized gains (losses) related to assets and liabilities as of September 30, 2024 $ 4 $ 216 $ — $ 220 __________ (a) Includes a reduction of ($ 97 ) million and ($ 244 ) million for realized gains due to the settlement of derivative contracts for the three and nine months ended September 30, 2025, respectively. Includes a reduction of ($ 133 ) million and ($ 651 ) million for realized gains due to the settlement of derivative contracts for the three and nine months ended September 30, 2024, 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. 39 Table of Contents Combined Notes to Consolidated Financial Statements (Dollars in millions, unless otherwise noted) Note 13 — Fair Value of Financial Assets and Liabilities The following table presents the income statement classification of the total realized and unrealized gains (losses) included in income for Level 3 assets and liabilities measured at fair value on a recurring basis during the three and nine months ended September 30, 2025 and 2024: Three Months Ended September 30, Operating Revenues Purchased Power and Fuel Other, net 2025 2024 2025 2024 2025 2024 Total gains (losses) included in net income $ ( 272 ) $ 177 $ 61 $ ( 119 ) $ 4 $ 4 Total unrealized gains (losses) ( 186 ) 300 72 ( 109 ) 4 — Nine Months Ended September 30, Operating Revenues Purchased Power and Fuel Other, net 2025 2024 2025 2024 2025 2024 Total gains (losses) included in net income $ ( 271 ) $ ( 97 ) $ 23 $ ( 338 ) $ 6 $ 4 Total unrealized gains (losses) ( 120 ) 561 116 ( 345 ) 6 — 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 September 30, 2025 Fair Value as of December 31, 2024 Valuation Technique Unobservable Input 2025 Range & Arithmetic Average 2024 Range & Arithmetic Average Mark-to-market derivatives—Economic hedges (a)(b) $ ( 396 ) $ ( 137 ) Discounted Cash Flow Forward power price $ 5.83 - $ 154 $ 52 $ 2.57 - $ 140 $ 49 Forward gas price $( 0.22 ) - $ 14 $ 3.83 $ 2.09 - $ 15 $ 3.68 Option Model Volatility percentage 6 % - 174 % 61 % 23 % - 141 % 57 % __________ (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 $ 341 million and $ 136 million as of September 30, 2025 and December 31, 2024, 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 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. 40 Table of Contents Combined Notes to Consolidated Financial Statements (Dollars in millions, unless otherwise noted) Note 14 — Commitments and Contingencies 14. Commitments and Contingencies Commitments Commercial Commitments. Commercial commitments as of September 30, 2025, representing commitments potentially triggered by future events, were as follows: Expiration within 2025 2026 2027 2028 2029 2030 and beyond Total Letters of credit $ 1,320 $ 696 $ 2 $ 123 $ — $ 1 $ 2,142 Surety bonds (a) 219 462 — 214 — — 895 Total commercial commitments $ 1,539 $ 1,158 $ 2 $ 337 $ — $ 1 $ 3,037