Constellation Energy Corp (CEG) · Quarterly Report (10-Q) SEC Filing

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 8 Constellation Energy Generation, LLC Consolidated Statements of Operations and Comprehensive Income 10 Consolidated Statements of Cash Flows 11 Consolidated Balance Sheets 12 Consolidated Statements of Changes in Equity 13 Combined Notes to Consolidated Financial Statements 1. Basis of Presentation 14 2. Mergers, Acquisitions, and Dispositions 14 3. Regulatory Matters 18 4. Revenue from Contracts with Customers 19 5. Segment Information 21 6. Government Assistance 23 7. Accounts Receivable 24 8. Property, Plant, and Equipment 26 9. Asset Retirement Obligations 26 10. Income Taxes 28 11. Retirement Benefits 30 12. Derivative Financial Instruments 30 13. Debt and Credit Agreements 35 14. Fair Value of Financial Assets and Liabilities 41 15. Commitments and Contingencies 46 47 17. Variable Interest Entities 49 18. Supplemental Financial Information 51 MANAGEMENT S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS 54 Executive Overview 54 Significant Transactions and Developments 55 Other Key Business Drivers 56 Critical Accounting Policies and Estimates 57 Financial Results of Operations 58 Liquidity and Capital Resources 71 ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK 75 ITEM 4. CONTROLS AND PROCEDURES 81 PART II OTHER INFORMATION 79 ITEM 1. LEGAL PROCEEDINGS 79 ITEM 1A. RISK FACTORS 79 ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS 79 ITEM 4. MINE SAFETY DISCLOSURES 79 ITEM 5. OTHER INFORMATION 80 ITEM 6. EXHIBITS 80 SIGNATURES 82 Constellation Energy Corporation 82 Constellation Energy Generation, LLC 83 Table of Contents GLOSSARY OF TERMS AND ABBREVIATIONS Constellation Energy Corporation and Related Entities CEG ParentConstellation Energy Corporation ConstellationConstellation Energy Generation, LLC RegistrantsCEG Parent and Constellation, collectively Antelope ValleyAntelope Valley Solar Ranch One CalpineCalpine Corporation Calvert Cliffs Calvert Cliffs nuclear generating station CCFCCalpine Construction Finance Company, L.P. CDHICalpine Development Holdings, LLC Continental Wind LLC Crane Clean Energy Center (formerly known as Three Mile Island Unit 1) CRPConstellation Renewables Partners, LLC FitzPatrickJames A. FitzPatrick nuclear generating station Geysers Power Company, LLC Greenfield L.P. Greenfield Energy Centre L.P. LaSalleLaSalle nuclear generating station LimerickLimerick nuclear generating station NERNewEnergy Receivables LLC Nine Mile PointNine Mile Point nuclear generating station Nova Power Nova Power, LLC Pin Oak Creek Pin Oak Creek Energy Center RPGRenewable Power Generation, LLC South Texas Project nuclear generating station Other Terms and Abbreviations ABAssembly Bill American Electric Power Texas AESOAlberta Electric Systems Operator Accumulated Other Comprehensive Income (Loss) Asset Retirement Cost AROAsset Retirement Obligation Accelerated Share Repurchase California ISO CenterPoint Energy Houston Electric, LLC Carbon Mitigation Credit CO2Carbon Dioxide CODMChief Operating Decision Maker Commonwealth Edison Company CORRACanadian Overnight Repo Rate Average CWIPConstruction Work In Progress United States Department of Energy United States Department of Justice Electric Generating Units Equivalent Forced Outage Factor Electric Reliability Council of Texas ERISAEmployee Retirement Income Security Act of 1974, as amended Securities Exchange Act of 1934, as amended 1 Table of Contents GLOSSARY OF TERMS AND ABBREVIATIONS Other Terms and Abbreviations ExelonExelon Corporation Federal Energy Regulatory Commission Former ComEd UnitsBraidwood, Byron, Dresden, LaSalle and Quad Cities nuclear generating units Former PECO UnitsLimerick, Peach Bottom, and Salem nuclear generating units FRCCFlorida Reliability Coordinating Council Generally Accepted Accounting Principles in the United States GDP Gross Domestic Product Geysers AssetsGeothermal power plant assets acquired through Calpine, including steam extraction and gathering assets GHGGreenhouse Gas Gigawatt GWhGigawatt hour Heat Rate A measure of the amount of fuel required to produce a unit of power Intercontinental Exchange IPAIllinois Power Agency IRA Inflation Reduction Act of 2022 Internal Revenue Service ISOIndependent System Operator ISO-NEISO New England Inc. ITCInvestment Tax Credit Midcontinent Independent System Operator, Inc. MMBtu Million British thermal units Moody's Moody s Investors Service, Inc. Megawatt MWhMegawatt hour Nasdaq Stock Market, LLC NAVNet Asset Value NDTNuclear Decommissioning Trust North American Electric Reliability Corporation NGXNatural Gas Exchange, Inc. Nuclear generating units or portions thereof whose decommissioning-related activities are not subject to contractual elimination under regulatory accounting Nitrogen oxide Normal Purchase Normal Sale scope exception NRCNuclear Regulatory Commission New York ISO NYMEXNew York Mercantile Exchange Other Comprehensive Income OIESOOntario Independent Electricity System Operator OPEBOther Postretirement Employee Benefits PECO Energy Company Pension Protection Act Pension Protection Act of 2006 PG&EPacific Gas and Electric Company PJMPJM Interconnection, LLC PPAPower Purchase Agreement PP&EProperty, Plant, and Equipment Other Terms and Abbreviations PSDARPost-shutdown Decommissioning Activities Report PSEGPublic Service Enterprise Group Incorporated PTCProduction Tax Credit 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) Operating Revenues Net of Purchased Power and Fuel Expense Reliability Pricing Model RTORegional Transmission Organization S&PS&P Global Ratings, a Standard & Poor s Financial Services LLC business SB Senate Bill United States Securities and Exchange Commission SERCSERC Reliability Corporation (formerly Southeast Electric Reliability Council) Spent Nuclear Fuel SO2 Sulfur dioxide Secured Overnight Financing Rate Southwest Power Pool STP Nuclear Operating Company Tax Matters Agreement Terawatt-hour U.S. Department of the Treasury UECUnamortized Energy Contract Variable Interest Entity WECCWestern Electric Coordinating Council ZECZero Emission Credit Table of Contents Constellation Energy Corporation and Subsidiary Companies Consolidated Statements of Operations and Comprehensive Income (Unaudited) Three Months Ended June 30,Six Months Ended June 30, (In millions, except per share data)2026202520262025 Operating revenues$7,504 $6,101 $18,626 $12,889 Purchased power and fuel4,023 3,132 10,375 7,516 2,253 1,617 4,033 3,162 443 254 886 502 Taxes other than income taxes207 147 436 307 Total operating expenses6,926 5,150 15,730 11,487 2 16 580 951 2,912 1,402 Other income and (deductions) Interest expense, net(283)(118)(536)(264) 603 440 649 286 Total other income and (deductions)320 322 113 22 Income (loss) before income taxes900 1,273 3,025 1,424 Income tax (benefit) expense398 440 928 462 Equity in income (losses) of unconsolidated affiliates6 14 Net income (loss)508 833 2,111 962 Net income (loss) attributable to noncontrolling interests(5)(6)8 5 Net income (loss) attributable to common shareholders$513 $839 $2,103 $957 Comprehensive income (loss), net of income taxes Net income (loss)$508 $833 $2,111 $962 Other comprehensive income (loss), net of income taxes Pension and non-pension postretirement benefit plans: Prior service benefit reclassified to periodic benefit cost (2)(1)(2) Actuarial loss reclassified to periodic cost26 18 54 35 Pension and non-pension postretirement benefit plan valuation adjustment (25)(34) Unrealized gain (loss) on cash flow hedges2 1 3 3 Unrealized gain (loss) on foreign currency translation(1)20 (4)28 Other comprehensive income (loss), net of income taxes27 37 27 30 Comprehensive income (loss)535 870 2,138 992 Comprehensive income (loss) attributable to noncontrolling interests(5)(6)8 5 Comprehensive income (loss) attributable to common shareholders$540 $876 $2,130 $987 Average shares of common stock outstanding: Basic360 314 357 314 Assumed exercise and/or distributions of stock-based awards Diluted360 314 357 314 Earnings per average common share Basic$1.42 $2.67 $5.89 $3.05 Diluted$1.42 $2.67 $5.88 $3.05 See the Combined Notes to Consolidated Financial Statements 5 Table of Contents Constellation Energy Corporation and Subsidiary Companies Consolidated Statements of Cash Flows (Unaudited) Six Months Ended June 30, (In millions)20262025 Cash flows from operating activities Net income (loss)$2,111 $962 Adjustments to reconcile net income (loss) to net cash flows provided by (used in) operating activities Depreciation, amortization, and accretion, including nuclear fuel and contract amortization2,368 1,300 740 14 Net fair value changes related to derivatives(589)188 Net realized and unrealized (gains) losses on NDT funds(419)(336) Net realized and unrealized (gains) losses on equity investments24 275 Other non-cash operating activities(240)(21) Changes in assets and liabilities: Accounts receivable307 208 (63)17 Accounts payable and accrued expenses(1,277)(229) Option premiums received (paid), net(52)18 Collateral received (posted), net(357)(242) Income taxes13 209 Pension and non-pension postretirement benefit contributions(200)(181) Other assets and liabilities(813)(598) Net cash flows provided by (used in) operating activities1,553 1,584 Cash flows from investing activities Capital expenditures(2,521)(1,573) Proceeds from NDT fund sales4,737 3,830 Investment in NDT funds(4,911)(3,999) Acquisition of Calpine, net of cash and restricted cash acquired(2,537) 131 (16) Net cash flows provided by (used in) investing activities(5,101)(1,758) Cash flows from financing activities Change in short-term borrowings2,586 Proceeds from short-term borrowings with maturities greater than 90 days4,500 900 Repayments of short-term borrowings with maturities greater than 90 days(3,500) Issuance of long-term debt5,001 Retirement of long-term debt(5,352)(1,008) Dividends paid on common stock(309)(244) Repurchases of common stock(1,971)(400) Other financing activities(78)(141) Net cash flows provided by (used in) financing activities877 (893) Increase (decrease) in cash, restricted cash, and cash equivalents(2,671)(1,067) Cash, restricted cash, and cash equivalents at beginning of period3,748 3,129 Cash, restricted cash, and cash equivalents at end of period$1,077 $2,062 Supplemental disclosure of non-cash investing and financing activities Common stock issued for acquisition of Calpine $17,507 $ 2,290 (868)(6) See the Combined Notes to Consolidated Financial Statements 6 Table of Contents Constellation Energy Corporation and Subsidiary Companies Consolidated Balance Sheets (Unaudited) (In millions)June 30, 2026December 31, 2025 ASSETS Current assets Cash and cash equivalents$697 $3,641 Restricted cash and cash equivalents380 107 Accounts receivable, net4,661 4,266 2,167 945 3,368 1,736 784 789 Assets held for sale5,743 126 Other1,165 509 Total current assets18,965 12,119 Property, plant, and equipment (net of accumulated depreciation and amortization of $19,589 and $19,072, respectively) 41,228 22,474 Deferred debits and other assets 20,492 19,336 11,527 420 Derivative assets1,741 450 4,300 2,450 Total deferred debits and other assets38,060 22,656 Total assets(a) $98,253 $57,249 LIABILITIES AND EQUITY Current liabilities Short-term borrowings$5,226 $1,650 Long-term debt due within one year363 92 4,432 4,294 716 467 927 1,075 1,368 366 Total current liabilities13,032 7,944 Long-term debt19,111 7,250 Deferred income taxes and unamortized ITCs8,513 3,544 Asset retirement obligations12,612 13,193 Pension and non-pension postretirement benefit obligations1,844 1,977 5,914 5,334 Derivative liabilities601 414 4,304 2,740 Total deferred credits and other liabilities33,788 27,202 Total liabilities(a) 65,931 42,396 Commitments and contingencies (Note 15) Common stock (No par value, 1,000 shares authorized, 355 and 312 shares outstanding, respectively) 26,683 11,043 Retained earnings (deficit)7,692 5,899 Accumulated other comprehensive income (loss), net(2,398)(2,425) Total shareholders' equity31,977 14,517 Noncontrolling interests345 336 Total equity32,322 14,853 Total liabilities and shareholders' equity$98,253 $57,249 __________ (a)Our consolidated assets include $4,197 million and $4,551 million at June 30, 2026 and December 31, 2025, respectively, of certain VIEs that can only be used to settle the liabilities of the VIE. Our consolidated liabilities include $1,287 million and $914 million at June 30, 2026 and December 31, 2025, respectively, of certain VIEs for which the VIE creditors do not have recourse to us. See Note 17 Variable Interest Entities for additional information. See the Combined Notes to Consolidated Financial Statements 7 Table of Contents Constellation Energy Corporation and Subsidiary Companies Consolidated Statements of Changes in Equity (Unaudited) Six Months Ended June 30, 2026 Shareholders' Equity (In millions, shares in thousands)Issued SharesCommon StockRetained Earnings (Deficit)Accumulated Other Comprehensive Income (Loss), net Noncontrolling InterestsTotal Equity Balance, December 31, 2025312,355 $11,043 $5,899 $(2,425)$336 $14,853 Net income (loss) 1,590 13 1,603 Employee incentive plans628 24 24 Changes in equity of noncontrolling interests (12)(12) Common stock dividends ($0.4265/common share) (155) (155) 49,376 17,507 17,507 362,359 $28,574 $7,334 $(2,425)$337 $33,820 Net income (loss) 513 (5)508 Employee incentive plans81 71 71 Changes in equity of noncontrolling interests (21)(21) Common stock dividends ($0.4265/common share) (155) (155) Common stock repurchased(7,138)(1,971) (1,971) 9 34 43 Other comprehensive income (loss), net of income taxes 27 27 Balance, June 30, 2026355,302 $26,683 $7,692 $(2,398)$345 $32,322 Shareholders' Equity (In millions, shares in thousands)Issued SharesCommon StockRetained Earnings (Deficit)Accumulated Other Comprehensive Income (Loss), netNoncontrolling InterestsTotal Equity Balance, December 31, 2024312,838 $11,402 $4,066 $(2,302)$373 $13,539 Net income (loss) 118 11 129 Employee incentive plans547 (49) (49) Changes in equity of noncontrolling interests (6)(6) Common stock dividends ($0.3878/common share) (122) (122) (150) (150) Other comprehensive income (loss), net of income taxes (7) (7) Balance, March 31, 2025313,385 $11,203 $4,062 $(2,309)$378 $13,334 Net income (loss) 839 (6)833 Employee incentive plans117 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, 2025312,403 $10,939 $4,779 $(2,272)$357 $13,803 Six Months Ended June 30, (In millions)2026202520262025 Operating revenues$7,504 $6,101 $18,626 $12,889 Purchased power and fuel4,023 3,132 10,375 7,516 2,253 1,617 4,033 3,162 443 254 886 502 Taxes other than income taxes207 147 436 307 Total operating expenses6,926 5,150 15,730 11,487 2 16 580 951 2,912 1,402 Other income and (deductions) Interest expense, net(283)(118)(536)(264) 603 440 649 286 Total other income and (deductions)320 322 113 22 Income (loss) before income taxes900 1,273 3,025 1,424 Income tax (benefit) expense398 440 928 462 Equity in income (losses) of unconsolidated affiliates6 14 Net income (loss)508 833 2,111 962 Net income (loss) attributable to noncontrolling interests(5)(6)8 5 Net income (loss) attributable to membership interest$513 $839 $2,103 $957 Comprehensive income (loss), net of income taxes Net income (loss)$508 $833 $2,111 $962 Other comprehensive income (loss), net of income taxes Pension and non-pension postretirement benefit plans: Prior service benefit reclassified to periodic benefit cost (2)(1)(2) Actuarial loss reclassified to periodic cost26 18 54 35 Pension and non-pension postretirement benefit plan valuation adjustment (25)(34) Unrealized gain (loss) on cash flow hedges2 1 3 3 Unrealized gain (loss) on foreign currency translation(1)20 (4)28 Other comprehensive income (loss), net of income taxes27 37 27 30 Comprehensive income (loss)535 870 2,138 992 Comprehensive income (loss) attributable to noncontrolling interests(5)(6)8 5 Comprehensive income (loss) attributable to membership interest$540 $876 $2,130 $987 See the Combined Notes to Consolidated Financial Statements 10 Table of Contents Constellation Energy Generation, LLC and Subsidiary Companies Consolidated Statements of Cash Flows (Unaudited) Six Months Ended June 30, (In millions)20262025 Cash flows from operating activities Net income (loss)$2,111 $962 Adjustments to reconcile net income (loss) to net cash flows provided by (used in) operating activities Depreciation, amortization, and accretion, including nuclear fuel and contract amortization2,368 1,300 740 14 Net fair value changes related to derivatives(589)188 Net realized and unrealized (gains) losses on NDT funds(419)(336) Net realized and unrealized (gains) losses on equity investments24 275 Other non-cash operating activities(304)(70) Changes in assets and liabilities: Accounts receivable310 208 Receivables from and payables to affiliates, net(240)(118) Inventories(63)17 Accounts payable and accrued expenses(1,291)(238) Option premiums received (paid), net(52)18 Collateral received (posted), net(357)(242) Income taxes13 209 Pension and non-pension postretirement benefit contributions(200)(181) Other assets and liabilities(536)(504) Net cash flows provided by (used in) operating activities1,515 1,502 Cash flows from investing activities Capital expenditures(2,521)(1,573) Proceeds from NDT fund sales4,737 3,830 Investment in NDT funds(4,911)(3,999) (2,537) 133 (16) Net cash flows provided by (used in) investing activities(5,099)(1,758) Cash flows from financing activities Change in short-term borrowings2,586 Proceeds from short-term borrowings with maturities greater than 90 days4,500 900 Repayments of short-term borrowings with maturities greater than 90 days(3,500) Issuance of long-term debt5,001 Retirement of long-term debt(5,352)(1,008) Distributions to member(2,280)(793) Contributions from member 103 Other financing activities(57)(21) Net cash flows provided by (used in) financing activities898 (819) Increase (decrease) in cash, restricted cash, and cash equivalents(2,686)(1,075) Cash, restricted cash, and cash equivalents at beginning of period3,720 3,115 Cash, restricted cash, and cash equivalents at end of period$1,034 $2,040 Supplemental disclosure of non-cash investing and financing activities $17,503 $ Exchange of Calpine senior notes for Constellation senior notes2,290 Decrease in PP&E related to ARO update(868)(6) See the Combined Notes to Consolidated Financial Statements 11 Table of Contents Constellation Energy Generation, LLC and Subsidiary Companies Consolidated Balance Sheets (Unaudited) (In millions)June 30, 2026December 31, 2025 ASSETS Current assets Cash and cash equivalents$681 $3,641 Restricted cash and cash equivalents353 79 Accounts receivable, net4,643 4,251 2,167 945 3,368 1,736 784 789 Assets held for sale5,743 126 Other1,173 508 Total current assets18,912 12,075 Property, plant, and equipment (net of accumulated depreciation and amortization of $19,589 and $19,072, respectively) 41,228 22,474 Deferred debits and other assets 20,492 19,336 11,527 420 Derivative assets1,741 450 4,293 2,443 Total deferred debits and other assets38,053 22,649 Total assets(a) $98,193 $57,198 LIABILITIES AND EQUITY Current liabilities Short-term borrowings$5,226 $1,650 Long-term debt due within one year363 92 4,315 4,033 Payables to affiliates134 365 716 467 927 1,075 1,366 358 Total current liabilities13,047 8,040 Long-term debt19,111 7,250 Deferred income taxes and unamortized ITCs8,513 3,544 Asset retirement obligations12,612 13,193 Pension and non-pension postretirement benefit obligations1,844 1,977 5,914 5,334 Derivative liabilities601 414 4,265 2,583 Total deferred credits and other liabilities33,749 27,045 Total liabilities(a) 65,907 42,335 Commitments and contingencies (Note 15) Member s equity Membership interest25,737 10,144 Undistributed earnings (deficit)8,602 6,808 Accumulated other comprehensive income (loss), net(2,398)(2,425) Total member s equity31,941 14,527 Noncontrolling interests345 336 Total equity32,286 14,863 Total liabilities and equity$98,193 $57,198 __________ (a)Our consolidated assets include $4,197 million and $4,551 million as of June 30, 2026 and December 31, 2025, respectively, of certain VIEs that can only be used to settle the liabilities of the VIE. Our consolidated liabilities include $1,287 million and $914 million as of June 30, 2026 and December 31, 2025, respectively, of certain VIEs for which the VIE creditors do not have recourse to us. See Note 17 Variable Interest Entities for additional information. See the Combined Notes to Consolidated Financial Statements 12 Table of Contents Constellation Energy Generation, LLC and Subsidiary Companies Consolidated Statements of Changes in Equity (Unaudited) Six Months Ended June 30, 2026 Member's Equity (In millions)Membership InterestUndistributed Earnings (Deficit)Accumulated Other Comprehensive Income (Loss), netNoncontrolling InterestsTotal Equity Balance, December 31, 2025$10,144 $6,808 $(2,425)$336 $14,863 Net income (loss) 1,590 13 1,603 Changes in equity of noncontrolling interests (12)(12) Distributions to member (155) (155) Contribution from member30 30 Acquisition of Calpine17,503 17,503 $27,677 $8,243 $(2,425)$337 $33,832 Net income (loss) 513 (5)508 Changes in equity of noncontrolling interests (21)(21) Contribution from member22 22 Distributions to member(1,971)(154) (2,125) Sale of noncontrolling interests9 34 43 Other comprehensive income (loss), net of income taxes 27 27 Balance, June 30, 2026$25,737 $8,602 $(2,398)$345 $32,286 Member's Equity (In millions)Membership InterestUndistributed Earnings (Deficit)Accumulated Other Comprehensive Income (Loss), netNoncontrolling InterestsTotal 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 member103 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 $17,603 Cash consideration(b) 4,342 Fair value of common stock subject to vesting period attributable to post-combination expense(c) (96) Effective settlement of preexisting relationships(14) Total merger consideration$21,835 __________ (a)Represents the fair value of approximately 50 million shares of CEG Parent common stock issued in connection with the acquisition, calculated using CEG Parent s closing stock price of $354.58 on January 6, 2026, the last trading day prior to the Acquisition Date. The fair value of the stock consideration is based on an observable market price and represents a Level 1 fair value measurement. (b)Represents cash paid to Calpine shareholders in connection with the acquisition. The amount reflects the $4.5 billion base cash consideration per the Merger Agreement, reduced by certain adjustments based on contractual terms also specified in the Merger Agreement. (c)Certain CEG Parent common stock issued to Calpine employees in exchange for their equity interests is subject to a vesting period of up to 26 months and has been excluded from merger consideration. These amounts will be recognized as stock-based compensation expense over the applicable vesting period in accordance with authoritative guidance. 15 Table of Contents Combined Notes to Consolidated Financial Statements (Dollars in millions, unless otherwise noted) Note 2 Mergers, Acquisitions, and Dispositions Purchase Price Allocation The following table summarizes the acquisition date fair value of the consideration transferred and the identifiable assets acquired and liabilities assumed. Accounting guidance provides that the allocation of the purchase price may be modified up to one year from the date of acquisition to the extent that additional information is obtained about the facts and circumstances that existed as of the acquisition date. Any change could result in a change in the amount of goodwill recognized. Assets acquired: Cash and cash equivalents$1,540 Restricted cash and cash equivalents261 Accounts receivable761 Derivative assets2,140 Inventories989 Assets held for sale(a) 5,603 Property, plant, and equipment18,481 Renewable energy credits180 Unamortized energy contracts(b) 2,133 Other assets700 Total assets acquired$32,788 Liabilities assumed: Accounts payable and accrued expenses$1,601 Long-term debt (including amounts due within one year)(c) 12,551 Derivative liabilities644 Renewable energy credit obligation258 Deferred income taxes and unamortized ITCs4,083 Asset retirement obligations350 Unamortized energy contracts(b) 1,815 Other liabilities758 Total liabilities assumed22,060 Net identifiable assets acquired10,728 Goodwill(d) 11,107 Total consideration transferred$21,835 (a) Assets Held for Sale. Reflects the Acquisition Date fair value, less costs to sell, for the six generating assets required to be divested. Depreciation and amortization of these assets ceased upon classification as held for sale. No impairment has been recognized subsequent to initial classification. The following table presents the carrying amounts of the major classes of assets and liabilities classified as held for sale as of the Acquisition Date: Assets held for sale: Property, plant and equipment$5,454 Inventories136 Other assets13 Total assets held for sale$5,603 Liabilities associated with assets held for sale: Asset retirement obligations$16 Other liabilities82 Total liabilities associated with assets held for sale$98 16 Table of Contents Combined Notes to Consolidated Financial Statements (Dollars in millions, unless otherwise noted) Note 2 Mergers, Acquisitions, and Dispositions (b) Unamortized Energy Contracts. The following table summarizes the classification and amounts of UECs in the Consolidated Balance Sheets as of the Acquisition Date: Other current assets$517 Other deferred debits and other assets1,616 Other current liabilities367 Other deferred credits and other liabilities1,448 (c) Long-term Debt (including amounts due within one year). We assumed total debt of $12,551 million at estimated fair value as of the Acquisition Date, comprising $279 million classified as Long-term debt due within one year and $12,272 million classified as Long-term debt, in the Consolidated Balance Sheets. See Note 13 Debt and Credit Agreements for additional information. (d) Goodwill. Represents the excess of the purchase price over the estimated fair value of the net assets acquired. Goodwill recognized primarily reflects the expected benefits from increased scale and meaningful market diversification, complementary generation, development activities, retail capabilities, and an enhanced ability to meet growing demand with a broader array of energy and sustainability products, to the extent such benefits are not separately recognizable as identifiable intangible assets. Because the design, restructuring, and integration activities of the combined organization are still ongoing, the $11.1 billion of goodwill has been provisionally allocated to the Calpine segment as of June 30, 2026. This provisional allocation may be revised as future organizational, restructuring, and integration activities are completed. The goodwill recognized in connection with the acquisition is not expected to be deductible for income tax purposes. Valuation of Significant Assets and Liabilities The fair values assigned to the assets acquired and liabilities assumed were determined based on significant estimates and assumptions that are judgmental in nature, including projected future cash flows; discount rates reflecting the risks inherent in the future cash flows; and future market prices, among others. These estimates and assumptions were applied to the valuation of significant acquired assets and assumed liabilities, including property, plant and equipment, assets held for sale, and unamortized energy contracts, and required assessments of current and projected market conditions and operating strategies. Forecasting future cash flows requires assumptions regarding, among other things, forecasted commodity prices for the sale of power and purchases of fuel and the expected operations of the assets, and judgments are also made to determine the expected useful lives assigned to each class of assets acquired and the duration of liabilities assumed. Other Key Accounting Impacts & Judgments Identifiable intangible assets acquired and liabilities assumed in connection with the acquisition include customer relationships, trade names, and energy contracts, recorded at estimated fair value. The weighted average amortization periods reflect weighted average useful lives of 15 years for customer relationships, five years for trade names, and six years for energy contracts. We also recognized the fair value of acquired commodity and interest rate derivatives and related hedging relationships as of the Acquisition Date; related gains or losses subsequent to acquisition will be recognized in earnings consistent with our accounting policies. For additional information on derivative instruments, see Note 12 Derivative Financial Instruments. The amounts recognized for property, plant and equipment, identifiable intangible assets and liabilities (including customer relationships, trade names, and unamortized energy contracts) and their useful lives, lease assets and liabilities, asset retirement and environmental obligations, contingencies, and income taxes (including deferred taxes) are provisional and subject to revision during the measurement period. Acquisition-related costs (e.g., advisory, legal, valuation, and other professional fees) are expensed as incurred and reflected within Operating and maintenance expenses in the Consolidated Statements of Operations and Comprehensive Income. These costs, which are not included in the consideration transferred, were not material for the three and six months ended June 30, 2026. 17 Table of Contents Combined Notes to Consolidated Financial Statements (Dollars in millions, unless otherwise noted) Note 2 Mergers, Acquisitions, and Dispositions Unaudited Pro Forma Results The following unaudited pro forma financial information for the three and six months ended June 30, 2026 and 2025 assumes that the acquisition occurred on January 1, 2025. The unaudited pro forma financial information is provided for informational purposes only and is not necessarily indicative of the results of operations that would have occurred had the acquisition been completed on January 1, 2025. The unaudited pro forma financial information is not indicative of the future results of operations, which may differ materially from the pro forma financial information presented here. Three Months Ended June 30,Six Months Ended June 30, Unaudited pro forma financial information2026202520262025 Operating revenues$7,504 $8,479 $18,856 $17,800 Net income(a) 513 985 2,103 1,116 __________ (a)Reflects Net income attributable to common shareholders for CEG Parent and Net income attributable to membership interest for Constellation. The unaudited pro forma financial information presented above includes adjustments for incremental depreciation and amortization as a result of the fair value determination of the net assets acquired, the effects of the acquisition on tax expense (benefit), and other acquisition accounting adjustments. As discussed in Note 5 Segment Information, Calpine is now presented as a reportable segment, and RNF is the segment performance metric, a component of which includes revenue. Operating revenues attributable to Calpine following the Acquisition Date were $1,907 million and $5,043 million for the three and six months ended June 30, 2026. However, as a result of the commencement of integration activities for certain functions and the consolidation of financing activities (see Note 13 Debt and Credit Agreements), it is impracticable to determine Calpine s earnings since the Acquisition Date. 3. Regulatory Matters As discussed in Note 3 Regulatory Matters of our 2025 Form 10-K, we are involved in various regulatory and legislative proceedings. The following discusses developments in 2026 and updates to the 2025 Form 10-K. Capacity Interconnection Rights for Crane Clean Energy Center In 2024, we announced the restart of Three Mile Island Unit 1, renamed as the Crane Clean Energy Center. The restart is supported by a 20-year PPA with Microsoft to purchase the output generated from the renewed plant. The restart of the plant and delivery of electricity under the PPA is subject to certain regulatory approvals, including the NRC comprehensive safety and environmental review, as well as permits from relevant state and local agencies. PJM's Phase I System Impact Study for Crane identified contingent transmission upgrades that would need to be completed for Crane to be fully deliverable to the grid, some of which suggested projected in-service dates extending as late as December 2030. In March 2026, we filed a waiver request with FERC to allow the transfer of capacity interconnection rights (CIRs) from Eddystone to Crane with the aim of reducing the number of contingent upgrades that would need to be completed prior to Crane being fully deliverable to the grid. Eddystone Units 3 and 4 were previously announced as having a planned retirement date of May 31, 2025, but have been required to continue operating as energy-only resources under DOE emergency orders issued in 2025 and 2026 for grid reliability. Transferring the Eddystone CIRs to Crane will not affect PJM's ability to operate and dispatch Eddystone for reliability in compliance with the DOE's orders. In June 2026, FERC granted the waiver request. 18 Table of Contents Combined Notes to Consolidated Financial Statements (Dollars in millions, unless otherwise noted) Note 4 Revenue from Contracts with Customers 4. Revenue from Contracts with Customers We recognize revenue from contracts with customers to depict the transfer of goods or services to customers at an amount that we expect to be entitled to in exchange for those goods or services. Our primary sources of revenue include competitive sales of power, natural gas, and other energy-related products and sustainable solutions. See Note 4 Revenue from Contracts with Customers of our 2025 Form 10-K for additional information regarding the performance obligations, revenue recognition, and payment terms associated with these sources of revenue. Transaction Price Allocated to Remaining Performance Obligations The following table shows the amounts of future revenues expected to be recorded in each year for performance obligations that are unsatisfied or partially unsatisfied as of June 30, 2026. This disclosure only includes components of contracts for which consideration is fixed and determinable. The average contract term varies by customer type and commodity but ranges from one month to several years. This disclosure excludes derivatives and certain power and gas sales contracts which contain variable volumes and/or variable pricing. 202620272028202920302031 and thereafterTotal Remaining performance obligations$1,051 $1,797 $1,541 $1,420 $891 $5,155 $11,855 Transaction Price Allocated to Previously Satisfied Performance Obligations Our Clinton and Quad Cities units contract with certain utilities in Illinois which requires delivery of all ZECs produced during each planning year (June through May), with total compensation limited by an annual cap for each planning year designed to limit the cost of ZECs to each utility's customers. ZECs delivered that, if paid, would result in the annual cap being exceeded may be paid in subsequent years at the vintage year price as long as the payments would not exceed the annual cap in the year paid. 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 2026 through May 2027 planning year, the final year of the program, the ZEC price has been established at $1.02 per ZEC, subject to an annual cap of $228 million. ZECs generated and delivered during the current planning year will not exceed the annual cap, and as a result we recognized $85 million of revenue during the second quarter of 2026 as a receivable for all remaining ZECs delivered in prior planning years, with payment expected in the third quarter of 2027. As of June 30, 2026, this receivable is included within Other deferred debits and other assets in the Consolidated Balance Sheets. For the June 2025 through May 2026 planning year, the ZEC price was established at $1.17 per ZEC, subject to an annual cap of $224 million. ZECs generated and delivered during this planning year did 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 June 30, 2026, this receivable is included within Accounts receivable, net in the Consolidated Balance Sheets. 19 Table of Contents Combined Notes to Consolidated Financial Statements (Dollars in millions, unless otherwise noted) Note 4 Revenue from Contracts with Customers Revenue Disaggregation We disaggregate the revenue recognized from contracts with customers into categories that depict how the nature, amount, timing, and uncertainty of revenue and cash flows are affected by economic factors. The following tables disaggregate the revenue recognized from contracts with customers between power revenues, capacity revenues, natural gas revenues, and other revenues. Power revenues and capacity revenues are further disaggregated by ISO/RTO and/or geographic location, which include PJM, MISO, ERCOT, NYISO, ISO-NE, West (which includes operations in CAISO, Arizona and Oregon), SERC (which includes operations in SERC not included in MISO or PJM), SPP, and International Power (which includes operations in the United Kingdom and Canada). Three Months Ended June 30, 2026Power and Power-related Revenues(a) Capacity Revenues(b) Other RevenuesTotal PJM$2,744 $124 $ $2,868 MISO264 8 272 ERCOT422 97 519 NYISO515 13 528 ISO-NE655 2 657 West247 151 398 SERC/SPP27 1 28 International Power85 85 Total Power revenues4,959 396 5,355 Gas revenues(c) 327 327 Other revenues(d) 161 161 Total revenue from contracts with customers4,959 396 488 5,843 Other revenue sources(e) 1,661 1,661 Total Operating revenues$4,959 $396 $2,149 $7,504 Three Months Ended June 30, 2025Power and Power-related Revenues(a) Capacity Revenues(b) Other RevenuesTotal PJM$2,547 $37 $ $2,584 MISO291 291 ERCOT328 328 NYISO514 514 ISO-NE783 783 West178 1 179 SERC/SPP25 4 29 International Power42 42 Total Power revenues4,708 42 4,750 Gas revenues(c) 321 321 Other revenues(d) 90 90 Total revenue from contracts with customers4,708 42 411 5,161 Other revenue sources(e) 940 940 Total Operating revenues$4,708 $42 $1,351 $6,101 20 Table of Contents Combined Notes to Consolidated Financial Statements (Dollars in millions, unless otherwise noted) Note 4 Revenue from Contracts with Customers Six Months Ended June 30, 2026Power and Power-related Revenues(a) Capacity Revenues(b) Other RevenuesTotal PJM$6,074 $254 $ $6,328 MISO516 14 530 ERCOT782 196 978 NYISO1,260 26 1,286 ISO-NE1,669 6 1,675 West415 311 726 SERC/SPP86 5 91 International Power194 194 Total Power revenues10,996 812 11,808 Gas revenues(c) 1,270 1,270 Other revenues(d) 306 306 Total revenue from contracts with customers10,996 812 1,576 13,384 Other revenue sources(e) 5,242 5,242 Total Operating revenues$10,996 $812 $6,818 $18,626 Six Months Ended June 30, 2025Power and Power-related Revenues(a) Capacity Revenues(b) Other RevenuesTotal PJM$5,245 $45 $ $5,290 MISO505 505 ERCOT630 630 NYISO1,189 1,189 ISO-NE1,892 1,892 West324 2 326 SERC/SPP60 7 67 International Power90 90 Total Power revenues9,935 54 9,989 Gas revenues(c) 1,103 1,103 Other revenues(d) 175 175 Total revenue from contracts with customers9,935 54 1,278 11,267 Other revenue sources(e) 1,622 1,622 Total Operating revenues$9,935 $54 $2,900 $12,889 __________ (a)Represents power and power-related revenues, including state-sponsored program revenues, ancillary revenues, and revenues from bundled contracts with customers. (b)Represents revenues from regulated capacity auctions as well as bilateral capacity revenues recognized at negotiated contract prices. (c)Represents natural gas sales and other gas-related revenues. (d)Other revenues primarily includes the sales of other energy-related products and sustainable solutions. (e)Other revenue sources primarily includes revenues accounted for as derivatives, leases, and amortization of intangible assets and liabilities related to commodity contracts recorded at fair value from acquisitions. 5. Segment Information Operating segments are determined based on information used by the CODM in deciding how to evaluate performance and allocate resources. We have six reportable segments consisting of the Mid-Atlantic, Midwest, New York, ERCOT, all other power regions referred to collectively as Other Power Regions, and Calpine. Following the acquisition of Calpine on January 7, 2026, Calpine's operations are being reported as a new reportable segment given the results of its operations are currently reviewed by the CODM separately from our historical reporting segments. 21 Table of Contents Combined Notes to Consolidated Financial Statements (Dollars in millions, unless otherwise noted) Note 5 Segment Information With the exception of Calpine, the basis for our reportable segments is the integrated management of our electricity business that is located in different geographic regions, and largely representative of the footprints of ISO/RTO and/or NERC regions, which utilize multiple supply sources to provide electricity through various distribution channels (wholesale and retail). Our hedging strategies and risk metrics are also aligned to these same geographic regions. Descriptions of each of our six reportable segments are as follows: Mid-Atlantic represents operations in the eastern half of PJM, which includes New Jersey, Maryland, Virginia, West Virginia, Delaware, the District of Columbia, and parts of Pennsylvania and North Carolina. Midwest represents operations in the western half of PJM and the United States footprint of MISO, excluding MISO s Southern Region. New York represents operations within NYISO. ERCOT represents operations within Electric Reliability Council of Texas that covers a majority of the state of Texas. Other Power Regions: New England represents operations within ISO-NE. South represents operations in FRCC, MISO s Southern Region, and the remaining portions of SERC not included within MISO or PJM. West represents operations in WECC, which includes CAISO. Canada represents operations across the entire country of Canada and includes AESO, OIESO, and the Canadian portion of MISO. Calpine represents operations acquired through the merger with Calpine on January 7, 2026, which are located throughout the country, including CAISO, ERCOT, PJM, ISO-NE, NYISO, MISO, SERC, Arizona, Oregon, as well as Canada. Our CEO is considered the CODM and evaluates the performance of our electric business activities and allocates resources based on segment RNF, primarily through review of budget-to-actual variance analyses. RNF is Operating revenues net of Purchased power and fuel expenses. We believe this is a useful measurement of operational performance, although it is not a presentation defined under GAAP and may not be comparable to other companies presentations nor deemed more useful than the GAAP information provided elsewhere in this report. In our evaluation of operating segments, we noted the CODM reviews a variety of performance and profitability measures at a consolidated level with a primary focus on RNF reporting at the geographic regional level, with the exception of Calpine which is currently reviewed on a standalone basis. Our operating revenues include all sales to third parties as well as government assistance. Purchased power and fuel expenses are considered the most significant segment expense. Purchased power costs include all costs associated with the procurement and supply of electricity including capacity, energy, and ancillary services. Fuel expense includes the fuel costs for our owned generation and fuel costs associated with tolling agreements. The results of our other business activities are not regularly reviewed by the CODM and are therefore not classified as operating segments nor included in the reportable segment amounts. These activities include wholesale and retail sales of natural gas, with the exception of Calpine's natural gas sales which are included in the Calpine segment, energy-related sales in the United Kingdom, as well as sales of other energy-related products and sustainable solutions that are not significant to our overall results of operations. Further, our unrealized gains and losses on economic hedging activities and our amortization of certain intangible assets and liabilities relating to commodity contracts recorded at fair value from mergers and acquisitions are also excluded from the reportable segment amounts. The CODM does not use a measure of total assets in making decisions regarding allocating resources to or assessing the performance of these reportable segments. 22 Table of Contents Combined Notes to Consolidated Financial Statements (Dollars in millions, unless otherwise noted) Note 5 Segment Information 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 six months ended June 30, 2026 and 2025. Three Months Ended June 30,Total Purchased power and fuel expensesTotal RNFTotal Purchased power and fuel expensesTotal RNF Mid-Atlantic1,555 $(567)$988 1,448 $(666)$782 Midwest(589)979 (488)1,036 New York(174)390 (138)397 ERCOT(162)284 (193)271 Other Power Regions(677)287 (997)181 Calpine(1,119)1,028 Total Reportable Segments(3,288)3,956 (2,482)2,667 Other(a) (735)(475)(650)302 Total Consolidated Results7,504 $(4,023)$3,481 6,101 $(3,132)$2,969 3,402 $(1,602)$1,800 3,113 $(1,522)$1,591 Midwest(1,469)1,831 (1,042)1,886 New York(335)798 (299)798 ERCOT(323)493 (377)485 Other Power Regions(1,896)554 (2,359)375 Calpine (2,388)2,153 Total Reportable Segments(8,013)7,629 (5,599)5,135 Other(b) (2,362)622 (1,917)238 Total Consolidated Results18,626 $(10,375)$8,251 12,889 $(7,516)$5,373 __________ (a)Represents activities not allocated to a segment. See text above for a description of included activities. Operating revenues include unrealized losses of $320 million and gains of $86 million for the three months ended June 30, 2026 and 2025, respectively. Purchased power and fuel expenses include unrealized losses of $120 million and gains of $81 million for the three months ended June 30, 2026 and 2025, respectively. (b)Represents activities not allocated to a segment. See text above for a description of included activities. Operating revenues include unrealized gains of $995 million and losses of $201 million for the six months ended June 30, 2026 and 2025, respectively. Purchased power and fuel expenses include unrealized losses of $373 million and gains of $46 million for the six months ended June 30, 2026 and 2025, respectively. 6. Government Assistance Beginning in 2024, our nuclear units are eligible for a PTC extending through 2032. See Note 1 Basis of Presentation and Note 6 Government Assistance of our 2025 Form 10-K for additional information on nuclear PTCs. 23 Table of Contents Combined Notes to Consolidated Financial Statements (Dollars in millions, unless otherwise noted) Note 6 Government Assistance For the three and six months ended June 30, 2026 and 2025, we did not record a material nuclear PTC benefit as the estimate of full year gross receipts exceeded the phase-out for annual gross receipts per MWh for most units. As of June 30, 2026 and December 31, 2025, our Consolidated Balance Sheets reflect approximately $150 million and $120 million, respectively, of nuclear PTCs within Other deferred debits and other assets. For the six months ended June 30, 2026, we did not utilize any estimated nuclear PTCs as a credit against our current federal income taxes payable. For the year ended December 31, 2025, we recognized a reduction to Accounts payable and accrued expenses in our Consolidated Balance Sheets of $375 million for estimated nuclear PTCs that we have utilized as a credit against our current federal income taxes payable. Many of the state-sponsored programs providing compensation for the emissions-free attributes of generation from certain of our nuclear units include contractual or other provisions that require us to refund that compensation up to the amount of the nuclear PTC received or pass through the entirety of the nuclear PTC received. As of June 30, 2026 and December 31, 2025, we have recognized approximately $270 million and $1,190 million, respectively, of estimated payables within Other deferred credits and other liabilities, Accounts payable and accrued expenses or as offsets to Accounts receivable, net in our Consolidated Balance Sheets associated with programs requiring refunds or pass through of the nuclear PTC. In general, we expect to remit refunds or pass-throughs of state-sponsored program compensation related to nuclear PTCs in the year following the filing of the related tax return. During the six months ended June 30, 2026, we refunded or offset against outstanding receivables approximately $920 million associated with state-sponsored program compensation relating to the nuclear PTCs recorded in 2024. During the three and six months ended June 30, 2026, we recognized an increase to net operating revenue (pre-tax) of approximately $10 million and a reduction to net operating revenue of approximately $275 million, respectively, associated with these programs in our Consolidated Statements of Operations and Comprehensive Income, compared to an increase to net operating revenue (pre-tax) of approximately $75 million and $190 million during the three and six months ended June 30, 2025, respectively. 7. Accounts Receivable The following table provides additional information on the disaggregation of customer and other accounts receivable: Accounts receivable, net June 30, 2026CEG ParentConstellation Customer accounts receivable (net of allowance for credit losses of $165 for CEG Parent and Constellation) $3,767 $3,767 Other accounts receivable (net of allowance for credit losses of $ for CEG Parent and Constellation) 894 876 Total$4,661 $4,643 December 31, 2025 Customer accounts receivable (net of allowance for credit losses of $158 for CEG Parent and Constellation) $3,577 $3,577 Other accounts receivable (net of allowance for credit losses of $9 for CEG Parent and Constellation) 689 674 Total$4,266 $4,251 Allowance for Credit Losses on Accounts Receivable The following table presents the rollforward of allowance for credit losses on customer accounts receivable from January 1, 2026 to June 30, 2026. $158 Current period provision for expected credit losses 35 Write-offs, net of recoveries(a) (28) $165 __________ (a)Recoveries were not material. 24 Table of Contents Combined Notes to Consolidated Financial Statements (Dollars in millions, unless otherwise noted) Note 7 Accounts Receivable The allowance for credit losses on other accounts receivable was not material as of the balance sheet dates, therefore, a rollforward is not presented. Unbilled Customer Revenue We recorded $1,636 million and $1,305 million of unbilled customer revenues in Accounts receivable, net in the Consolidated Balance Sheets as of June 30, 2026 and December 31, 2025, respectively. Calpine Accounts Receivable Sales Program Following the acquisition of Calpine on January 7, 2026, the Company has assumed Calpine's Accounts Receivable Sales Program (Calpine AR Facility). The Calpine AR Facility was established by Calpine in December 2016 and was last renewed in November 2025 with a current expiration of November 2026. The Calpine AR Facility is a receivables purchase agreement between Calpine Energy Solutions, LLC and Calpine Receivables, LLC, a wholly-owned subsidiary that is accounted for as an unconsolidated VIE, along with an additional purchase and sale agreement between Calpine Receivables, LLC, and unaffiliated financial institutions, the combination of which allow for the revolving sale of up to $500 million in certain trade accounts receivables of Calpine Energy Solutions, LLC to third parties at a nominal discount. Receivables sold under the Calpine AR Facility are accounted for as sales and excluded from Accounts receivable, net in the Consolidated Balance Sheets and reflected as Cash provided by operating activities in the Consolidated Statements of Cash Flows. Any portion of the purchase price for the sold receivables which is not paid in cash is recorded as a short-term note receivable within Accounts receivable, net, which was not material as of June 30, 2026. Our risk of loss following the transfer of accounts receivable is limited to the note receivable outstanding. Payment of the note receivable is not subject to significant risks other than delinquencies and credit losses on accounts receivable transferred. The Company has guaranteed the performance of Calpine Energy Solutions, LLC to Calpine Receivables, LLC under the Calpine AR Facility, see Note 15 Commitments and Contingencies for additional information. Additionally, see Note 17 Variable Interest Entities for additional information on Calpine Receivables, LLC and its status as an unconsolidated VIE. There was $459 million in gross accounts receivable outstanding that were sold at a nominal discount under the Calpine AR Facility as of June 30, 2026, and $343 million of the $500 million facility amount was utilized. The following table summarizes certain activity for the period under the Calpine AR Facility: Six Months Ended June 30, 2026 Aggregate receivables sold during the period$2,040 Proceeds collected on sold receivables 2,066 Other Sales of Customer Accounts Receivables We are required, under supplier tariffs, to sell customer receivables to certain utility companies at a nominal discount. The total gross receivables sold were $1,833 million and $2,045 million for the six months ended June 30, 2026 and 2025, respectively. 25 Table of Contents Combined Notes to Consolidated Financial Statements (Dollars in millions, unless otherwise noted) Note 8 Property, Plant, and Equipment 8. Property, Plant, and Equipment The following table presents a summary of property, plant, and equipment balances by asset category as of June 30, 2026 and December 31, 2025: Asset CategoryJune 30, 2026December 31, 2025 Electric(a) $51,514 $33,253 Nuclear fuel6,485 6,298 CWIP(a) 2,818 1,995 60,817 41,546 Less: accumulated depreciation19,589 19,072 Property, plant, and equipment, net(b) $41,228 $22,474 __________ (a)Includes Electric and CWIP assets acquired as a result of the Calpine acquisition of $17,247 million and $1,234 million, respectively. (b)Excludes assets held for sale related to the acquisition of Calpine. See Note 2 Mergers, Acquisitions, and Dispositions for additional information. The estimated useful lives of our generating facilities are based on a combination of depreciation studies, historical retirements, site licenses and management estimates of operating costs and expected energy market conditions. As a result of the acquisition of Calpine, we added a fleet of natural gas, oil, geothermal, battery storage and solar assets. There were no material changes in the estimated useful lives of our combined oil and gas, battery storage, wind and solar facilities as a result. Geothermal facility depreciation provisions are based on an estimated useful life through 2066. For additional information about the useful lives of our generating facilities and depreciation provisions, see Note 8 Property, Plant, and Equipment of our 2025 Form 10-K. 9. Asset Retirement Obligations Nuclear Decommissioning Asset Retirement Obligations We have a legal obligation to decommission our nuclear power plants following the permanent cessation of operations. See Note 10 Asset Retirement Obligations of our 2025 Form 10-K for additional information regarding AROs and the financial statement impact of changes in estimates. The following table provides a rollforward of the nuclear decommissioning AROs reflected in the Consolidated Balance Sheets from December 31, 2025 to June 30, 2026: Balance as of December 31, 2025 $12,908 318 Net decrease due to changes in, and timing of, estimated future cash flows (1,277) Costs incurred related to decommissioning plants(7) $11,942 During the six months ended June 30, 2026, the net $1,277 million decrease in the ARO for the changes in, and timing of, estimated future cash flows was driven primarily by changes in assumed retirement dates for various plants, including Calvert Cliffs, Fitzpatrick, Limerick, and Nine Mile Point. The 2026 ARO updates resulted in a decrease of $285 million in Operating and maintenance expense for the six months ended June 30, 2026 in the Consolidated Statements of Operations and Comprehensive income. NDT Funds We had NDT funds totaling $20,583 million and $19,396 million as of June 30, 2026 and December 31, 2025, respectively. The current portions of the NDT funds, which are included in Other current assets in our Consolidated Balance Sheets, were not material as of June 30, 2026 and December 31, 2025. See Note 18 Supplemental Financial Information for additional information on activities of the NDT funds. 26 Table of Contents Combined Notes to Consolidated Financial Statements (Dollars in millions, unless otherwise noted) Note 9 Asset Retirement Obligations Accounting Implications of the Regulatory Agreement Units See Note 1 Basis of Presentation and Note 10 Asset Retirement Obligations of our 2025 Form 10-K for additional information on the Regulatory Agreement Units. The following table presents our noncurrent payables to ComEd, PECO, CenterPoint, and AEP Texas reflected as Payables related to Regulatory Agreement Units in the Consolidated Balance Sheets as of June 30, 2026 and December 31, 2025: June 30, 2026December 31, 2025 ComEd$4,638 $4,313 PECO642 442 CenterPoint 471 430 AEP Texas 163 149 Payables related to Regulatory Agreement Units$5,914 $5,334 NRC Minimum Funding Requirements NRC regulations require that licensees of nuclear generating facilities demonstrate reasonable assurance that funds will be available in specified minimum amounts for radiological decommissioning of the facility at the end of its life. We filed our annual decommissioning funding status report with the NRC for our shutdown units, and any units within five years of shutdown in March 2026. The status report demonstrated adequate decommissioning funding assurance as of December 31, 2025 for all units included in the report. See Note 10 Asset Retirement Obligations of our 2025 Form 10-K for additional information. Non-Nuclear Asset Retirement Obligations We have AROs for plant closure costs associated with our natural gas, oil, battery storage, and renewable generating facilities, including geothermal. The obligations include asbestos abatement, removal of certain storage tanks, restoring leased land to the condition it was in prior to construction of renewable generating stations, disposal of hazardous materials, plug and abandonment of wells, and other decommissioning-related activities. See Note 1 Basis of Presentation of our 2025 Form 10-K for additional information on the accounting policy for AROs. The following table provides a rollforward of the non-nuclear AROs reflected in the Consolidated Balance Sheets from December 31, 2025 to June 30, 2026: Balance as of December 31, 2025 $317 Acquisition of Calpine(a) 350 Development projects19 Accretion expense18 Net increase due to changes in, and timing of, estimated future cash flows2 Costs incurred related to decommissioning plants(2) Balance as of June 30, 2026 $704 __________ (a)Reflects our decommissioning obligations for Calpine plants acquired on January 7, 2026, which are recorded at estimated fair value. See Note 2 Mergers, Acquisitions, and Dispositions for additional information. Many of the facilities acquired from Calpine do not have AROs given the absence of legal requirements to perform retirement related activities. 27 Table of Contents Combined Notes to Consolidated Financial Statements (Dollars in millions, unless otherwise noted) Note 10 Income Taxes 10. Income Taxes Rate Reconciliation The effective income tax rate varies from the U.S. federal statutory rate principally due to the following: Three Months Ended June 30, 20262025 U.S. federal statutory income tax21.0 %$189 21.0 %$267 Increase (decrease) due to: State income taxes, net of federal income tax benefit(a) 2.6 23 3.8 48 PTC(0.6)(5)(0.9)(11) Amortization of ITC, including deferred taxes on basis differences(0.3)(3)(0.2)(3) Other(0.2)(2)(0.2)(3) Nontaxable or nondeductible items Share-based payment awards (0.1)(1) Excess officers compensation 0.7 9 Other1.0 10 Other adjustments Qualified NDT fund income and losses20.7 186 10.5 134 Effective income tax(b) 44.2 %$398 34.6 %$440 Six Months Ended June 30, 20262025 U.S. federal statutory income tax21.0 %$635 21.0 %$299 Increase (decrease) due to: State income taxes, net of federal income tax benefit(a) 3.2 96 3.3 47 Foreign tax effects 0.1 1 Tax credits PTC(0.3)(9)(0.9)(13) Amortization of ITC, including deferred taxes on basis differences(0.3)(8)(0.4)(5) Other(0.2)(6)(0.4)(5) Nontaxable or nondeductible items Share-based payment awards(0.5)(14)(2.8)(40) Excess officers compensation0.1 3 1.1 16 Other0.9 26 Other adjustments Qualified NDT fund income and losses6.8 205 11.4 162 Effective income tax(b) 30.7 %$928 32.4 %$462 __________ (a)In 2026, state taxes in California, Massachusetts, and New York made up the majority (greater than 50%) of the tax effect in this category. In 2025, state taxes in Illinois, Maryland, Massachusetts, California, Pennsylvania, and New Jersey made up the majority (greater than 50%) of the tax effect in this category. (b)Amounts may not recalculate due to rounding. 28 Table of Contents Combined Notes to Consolidated Financial Statements (Dollars in millions, unless otherwise noted) Note 10 Income Taxes Other Tax Matters Tax Matters Agreement In connection with the corporate separation transaction, we entered into a TMA with Exelon. The TMA governs the respective rights, responsibilities, and obligations between us and Exelon after the separation with respect to tax liabilities and benefits, tax attributes, tax returns, tax contests and other tax sharing regarding U.S. federal, state, local and foreign income taxes, other tax matters and related tax returns. Responsibility and Indemnification for Taxes. As a former subsidiary of Exelon, we have joint and several liability with Exelon to the IRS and certain state jurisdictions relating to the taxable periods in which we were included in joint federal and state filings. However, the TMA specifies the portion of this tax liability for which we will bear contractual responsibility, and we and Exelon agreed to indemnify each other against any amounts for which such indemnified party is not responsible. Specifically, we will be liable for taxes due and payable in connection with tax returns that we are required to file. We will also be liable for our share of certain taxes required to be paid by Exelon with respect to taxable years or periods (or portions thereof) ending on or prior to the separation to the extent that we would have been responsible for such taxes under the Exelon tax sharing agreement then existing. As of June 30, 2026 and December 31, 2025, respectively, our Consolidated Balance Sheets reflect $32 million and $43 million in Other deferred credits and other liabilities, for tax liabilities where we maintain contractual responsibility to Exelon. Tax Refunds and Attributes. The TMA provides for the allocation of certain pre-closing tax attributes between us and Exelon. Tax attributes will be allocated in accordance with the principles set forth in the existing Exelon tax sharing agreement, unless otherwise required by law. Under the TMA, we will be entitled to refunds for taxes for which we are responsible. In addition, it is expected that Exelon will have tax attributes that may be used to offset Exelon s future tax liabilities. A significant portion of such attributes were generated by our business. In March 2026, we adjusted our receivable under the TMA as a result of IRS Notice 2026-7, as discussed below. During the second quarter of 2026 and 2025, we received payments for tax attributes utilized by Exelon related to the 2025 and 2024 tax years of $53 million and $128 million, respectively. As of June 30, 2026 and December 31, 2025, respectively, we had $98 million and $175 million in Accounts receivable, net and $279 million and $21 million in Other deferred debits and other assets for the reclassified tax attributes expected to be utilized by Exelon after separation in accordance with the terms of the TMA. IRS Notice 2026-7. In February 2026, the IRS issued Notice 2026 7 (the Notice), which provides guidance on the implementation of the corporate alternative minimum tax (CAMT). The Notice permits taxpayers to deduct repair and maintenance costs under tax law principles in determining adjusted financial statement income and applies retroactively to previously filed tax returns. As a result of this Notice, Exelon amended its 2023 and 2024 tax returns to reflect less CAMT and thus lower utilization of previously refunded tax attributes. We received a demand letter from Exelon in February 2026, and as a result, in March 2026 we remitted $235 million to Exelon under the TMA related to prior periods. We increased our receivable for the $235 million in the first quarter of 2026, as reflected above, as we expect Exelon to pay us as it utilizes these tax attributes in future periods. 29 Table of Contents Combined Notes to Consolidated Financial Statements (Dollars in millions, unless otherwise noted) Note 11 Retirement Benefits 11. Retirement Benefits Components of Net Periodic Benefit (Credits) Costs See Note 1 Basis of Presentation of our 2025 Form 10-K for additional information on where we report the service cost and other non-service cost (credit) components for all plans. The following tables present the components of our net periodic benefit (credit) cost for the three and six months ended June 30, 2026 and 2025. The amounts below are shown prior to capitalization and co-owner allocations, the effects of which were not material for any of the periods presented. Pension BenefitsOPEBTotal Pension Benefits and OPEB Three Months Ended June 30,202620252026202520262025 Components of net periodic benefit (credit) cost: Service cost$21 $21 $5 $5 $26 $26 Non-service components of pension benefits & OPEB (credit) cost: Interest cost100 101 20 20 120 121 Expected return on assets(119)(123)(7)(8)(126)(131) Amortization of: Prior service (credit) cost (2)(1)(2)(1) Actuarial (gain) loss38 25 (1)(2)37 23 19 3 10 9 29 12 Net periodic benefit (credit) cost $40 $24 $15 $14 $55 $38 Components of net periodic benefit (credit) cost: Service cost$43 $42 $10 $9 $53 $51 Non-service components of pension benefits & OPEB (credit) cost: Interest cost199 203 40 39 239 242 Expected return on assets(238)(245)(15)(16)(253)(261) Amortization of: Prior service (credit) cost (3)(3)(3)(3) Actuarial (gain) loss76 51 (2)(4)74 47 37 9 20 16 57 25 Net periodic benefit (credit) cost $80 $51 $30 $25 $110 $76 12. Derivative Financial Instruments We use derivative instruments to manage commodity price risk and interest rate risk related to ongoing business operations. Authoritative guidance requires that derivative instruments be recognized as either assets or liabilities at fair value, with changes in fair value of the derivative recognized in earnings immediately. Other accounting treatments, including NPNS, are available through special election and designation, provided they meet specific, restrictive criteria both at the time of designation and on an ongoing basis. All derivative instruments, excluding NPNS, are recorded at fair value through earnings. For all NPNS derivative instruments, accounts receivable or accounts payable are recorded when derivatives settle, and revenue or expense is recognized in earnings as the underlying physical commodity is delivered. 30 Table of Contents Combined Notes to Consolidated Financial Statements (Dollars in millions, unless otherwise noted) Note 12 Derivative Financial Instruments 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. In general, increases and decreases in forward market prices have a positive and negative impact, respectively, on owned and contracted generation positions that have not been hedged. Beginning in 2024, our existing nuclear fleet is eligible for a nuclear PTC, an important tool in managing commodity price risk for each nuclear unit not already receiving state support. The nuclear PTC provides increasing levels of support as unit revenues decline below levels established in the IRA and is further adjusted for inflation annually through the duration of the program based on the GDP price deflator for the preceding calendar year. See Note 6 Government Assistance for additional information. In locations and periods where our load serving activities do not naturally offset existing generation portfolio risk, remaining commodity price exposure is managed through portfolio hedging activities. Portfolio hedging activities are generally concentrated in the prompt three years, when customer demand and market liquidity enable effective price risk mitigation. During this prompt three-year period, we seek to mitigate the price risk associated with our load serving contracts, non-nuclear generation, and any residual price risk for our nuclear generation that the nuclear PTC and state programs may not fully mitigate. We also enter into transactions that further optimize the economic benefits of our overall portfolio. To the extent the amount of energy we produce or procure differs from the amount of energy we have contracted to sell, we are exposed to market fluctuations in the prices of electricity, natural gas, and other commodities. We use a variety of derivative and non-derivative instruments to manage the commodity price risk of our electric generation facilities, including power and gas sales, fuel and power purchases, natural gas transportation and pipeline capacity agreements, and other energy-related products marketed and purchased. To manage these risks, we may enter into fixed-price derivative or non-derivative contracts to hedge the variability in future cash flows from expected sales of power and gas and purchases of power and fuel. The objectives for executing such hedges include fixing the price for a portion of anticipated future commodity sales and purchases 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. 31 Table of Contents Combined Notes to Consolidated Financial Statements (Dollars in millions, unless otherwise noted) Note 12 Derivative Financial Instruments The following tables provide a summary of the commodity derivative fair value balances recorded as of June 30, 2026 and December 31, 2025: Economic Hedges Netting(a) Total Derivative assets (current)$15,197 664 $(13,744)$2,117 Derivative assets (noncurrent)8,431 (7,071)1,709 Total derivative assets23,628 (20,815)3,826 Derivative liabilities (current)(15,279)13,744 (710) Derivative liabilities (noncurrent)(8,112)7,071 (596) Total derivative liabilities(23,391)20,815 (1,306) Total derivative net assets (liabilities) $237 2,283 $ $2,520 $7,349 375 $(6,791)$933 Derivative assets (noncurrent)5,030 (4,853)449 Total derivative assets12,379 (11,644)1,382 Derivative liabilities (current)(7,642)6,791 (465) Derivative liabilities (noncurrent)(5,585)4,853 (413) Total derivative liabilities(13,227)11,644 (878) Total derivative net assets (liabilities)$(848)1,352 $ $504 _________ (a)We net all available amounts allowed in our Consolidated Balance Sheets in accordance with authoritative guidance for derivatives. These amounts include unrealized derivative transactions with the same counterparty under legally enforceable master netting agreements and cash collateral. The following table summarizes the net buy/(sell) notional position of commodity derivative transactions, excluding our NPNS derivatives that are not recorded at fair value, as of June 30, 2026 and December 31, 2025: Total Net Position (In Millions) Commodity Type June 30, 2026December 31, 2025Unit of Measure Electricity(a) (691)(260)MWh Natural Gas(a) 1,56133MMBtu Emissions (20)(35)Short Ton _________ (a)The increase in our net notional position as of June 30, 2026 compared to December 31, 2025 is primarily driven by derivatives acquired from Calpine. See Note 2 Mergers, Acquisitions, and Dispositions for additional information. Economic Hedges (Commodity Price Risk) For the three and six months ended June 30, 2026 and 2025, we recognized the following net pre-tax commodity unrealized gains (losses), which are also included in the Net fair value changes related to derivatives line in the Consolidated Statements of Cash Flows. Three Months Ended June 30,Six Months Ended June 30, Income Statement Location2026202520262025 Operating revenues$(321)$89 $992 $(197) Purchased power and fuel(118)75 (368)39 Total$(439)$164 $624 $(158) Interest Rate Risk We utilize interest rate swaps to manage our interest rate exposure, which are treated as economic hedges. The notional amounts for interest rate swaps were approximately $4.0 billion and $1.4 billion as of June 30, 2026 and December 31, 2025, respectively. 32 Table of Contents Combined Notes to Consolidated Financial Statements (Dollars in millions, unless otherwise noted) Note 12 Derivative Financial Instruments The derivative assets and liabilities as of June 30, 2026 and December 31, 2025 and the gains and losses associated with management of interest rate risk for the three and six months ended June 30, 2026 and 2025 were not material. The gains and losses associated with management of interest rate risk are included in the Net fair value changes related to derivatives line in the Consolidated Statements of Cash Flows. Credit Risk We would be exposed to credit-related losses in the event of non-performance by counterparties on executed derivative instruments. The credit exposure of derivative contracts, before collateral, is represented by the fair value of contracts as of the reporting date. For commodity derivatives, we enter into enabling agreements that allow for payment netting with our counterparties, which reduces our exposure to counterparty risk by providing for the offset of amounts payable to the counterparty against amounts receivable from the counterparty. Typically, each enabling agreement is for a specific commodity and, with respect to each individual counterparty, netting is limited to transactions involving that specific commodity product, except where master netting agreements exist with a counterparty that allows for cross product netting. In addition to right of offset language in the enabling agreement, our credit department establishes credit limits, margining thresholds and collateral requirements for each counterparty, which are defined in the derivative contracts. Counterparty credit limits are based on an internal credit review process that considers a variety of factors, including the results of a scoring model, leverage, liquidity, profitability, credit ratings by credit rating agencies, and other risk management criteria. To the extent that a counterparty s margining thresholds are exceeded, the counterparty is required to post collateral with us, as specified in each enabling agreement. Our credit department monitors current and forward credit exposure to counterparties and their affiliates, both on an individual and an aggregate basis. The following tables provide information on the credit exposure for derivative instruments, inclusive of payables and receivables, net of collateral and instruments that are subject to master netting agreements, as of June 30, 2026. The amounts in the tables below exclude credit risk exposure from individual retail counterparties, NPNS contracts, forward values on non-derivative contracts and exposure through RTOs, ISOs, as well as commodity exchanges. The tables further delineate that exposure by credit rating of the counterparties and provide guidance on the concentration of credit risk to individual counterparties. Rating as of June 30, 2026Total Exposure Before Credit Collateral Credit Collateral(a) Net Exposure Number of Counterparties Greater than 10% of Net Exposure Net Exposure of Counterparties Greater than 10% of Net Exposure Investment grade$1,938 $59 $1,879 1 $321 Non-investment grade85 15 70 No external ratings Internally rated investment grade219 7 212 Internally rated non-investment grade313 68 245 Total$2,555 $149 $2,406 1 $321 __________ (a)As of June 30, 2026, credit collateral held from counterparties where we had credit exposure included $29 million of cash and $120 million of letters of credit. Net Credit Exposure by Type of CounterpartyAs of June 30, 2026 Investor-owned utilities, marketers, power producers$1,250 Financial Institutions484 Energy cooperatives and municipalities292 Other380 Total$2,406 33 Table of Contents Combined Notes to Consolidated Financial Statements (Dollars in millions, unless otherwise noted) Note 12 Derivative Financial Instruments Credit-Risk-Related Contingent Features As part of the normal course of business, we routinely enter into physically and financially settled contracts for the purchase and sale of capacity, electricity, fuels, emissions allowances, and other energy-related products. Certain of our derivative instruments contain provisions that require us to post collateral. We also enter into commodity transactions on exchanges where the exchanges act as the counterparty to each trade. Transactions on the exchanges must adhere to comprehensive collateral and margining requirements. This collateral may be posted in the form of cash or credit support with thresholds contingent upon our credit ratings from S&P and Moody's. The collateral and credit support requirements vary by contract and by counterparty. These credit-risk-related contingent features stipulate that if we were to be downgraded or lose our investment grade credit ratings (based on our senior unsecured debt rating), we would be required to provide additional collateral. This incremental collateral requirement allows for the offsetting of derivative instruments that are assets with the same counterparty, where the contractual right of offset exists under applicable master netting agreements. In the absence of expressly agreed-to provisions that specify the collateral that must be provided, collateral requested will be a function of the facts and circumstances of the situation at the time of the demand. In such cases, we believe an amount of several months of future payments (e.g., capacity payments) rather than a calculation of fair value is a reasonable estimate for the contingent collateral obligation, which has been factored into the disclosure below. The aggregate fair value of all derivative instruments with credit-risk-related contingent features in a liability position that are not fully collateralized (excluding transactions on the exchanges that are fully collateralized) is detailed in the table below: Credit-Risk-Related Contingent FeaturesJune 30, 2026December 31, 2025 Gross fair value of derivative contracts containing this feature $(2,477)$(1,307) Offsetting fair value of derivative contracts under master netting arrangements 1,344 554 Net fair value of derivative contracts containing this feature$(1,133)$(753) As of June 30, 2026 and December 31, 2025, we posted or held the following amounts of cash collateral and letters of credit on derivative contracts with external counterparties, after giving consideration to offsetting derivative and non-derivative positions under master netting agreements. June 30, 2026December 31, 2025 Cash collateral posted $2,456 $1,399 Letters of credit posted 1,359 718 Cash collateral held 173 47 Letters of credit held 168 115 Additional collateral required in the event of a credit downgrade below investment grade (at BB+/Ba1)(a)(b)(c) 3,441 2,670 __________ (a)Certain of our contracts contain provisions that allow a counterparty to request additional collateral when there has been a subjective determination that our credit quality has deteriorated, generally termed adequate assurance . Due to the subjective nature of these provisions, we estimate the amount of collateral that we may ultimately be required to post in relation to the maximum exposure with the counterparty. (b)The downgrade collateral is inclusive of all contracts in a liability position regardless of accounting treatment and excludes any contracts with individual retail counterparties. (c)A loss of investment grade credit rating would require a three-notch downgrade from current levels of BBB+ and Baa1 at S&P and Moody's, respectively. We routinely enter into supply forward contracts with certain utilities with one-sided collateral postings only from us. If market prices fall below the benchmark price levels in these contracts, the utilities are not required to post collateral. However, when market prices rise above the benchmark price levels, we are required to post collateral once certain unsecured credit limits are exceeded. 34 Table of Contents Combined Notes to Consolidated Financial Statements (Dollars in millions, unless otherwise noted) Note 13 Debt and Credit Agreements 13. Debt and Credit Agreements Long-Term Debt Calpine Acquisition Upon completion of the acquisition of Calpine in January 2026, we assumed approximately $12.6 billion of debt inclusive of approximately $7.6 billion of corporate long-term debt, including senior unsecured and secured notes and corporate term loans in addition to approximately $5.0 billion of various project financing arrangements. Pursuant to the Exchange Offers discussed below, we issued new notes in January 2026 effectively replacing $2.3 billion of Calpine's senior unsecured and secured notes with Constellation senior unsecured notes. Using the proceeds from our January 2026 bond issuance, as discussed below, along with cash on hand and short-term debt, we repaid $2.5 billion of Calpine corporate term loans immediately after the acquisition closing, $1.25 billion of Calpine senior secured first lien notes in February 2026, and $1.4 billion of Calpine senior unsecured notes in March 2026. As discussed above, the following project financing arrangements were assumed as part of the acquisition: Geysers Power Company, LLC. We acquired the GPC first lien senior secured term loan facility, which includes a term loan and $250 million letter of credit facility, up to $50 million of which may be used for loans to finance energy storage projects (the sub-facility). At acquisition, outstanding borrowings under the term loan and sub-facility were approximately $1.35 billion and $45 million, respectively. The GPC facility is secured by substantially all of the real and personal property of GPC and subsidiaries, primarily consisting of the Geysers Assets. The facility matures May 2029 and bears interest at SOFR plus 1.625%. As of June 30, 2026, there were $1.3 billion and $43 million of borrowings outstanding under the term loan and sub-facility, respectively. Calpine Construction Finance Company, L.P. We acquired the CCFC first lien senior secured term loan facility with $2.1 billion outstanding borrowings at acquisition. The CCFC term loan facility is secured by certain real and personal property of CCFC, primarily seven natural gas-fired power plants. One plant secured under the facility, the Brazos Valley Energy Center (Brazos), f/k/a Jack A. Fusco Energy Center, is subject to sale in accordance with the DOJ resolution. See Note 2 Mergers, Acquisitions, and Dispositions for additional information. Under the terms of the loan facility, CCFC may require the consent of certain lenders to release Brazos as guarantor depending on the application of net sales proceeds. The term loan matures July 2030 and bears interest at SOFR plus 1.75%. As of June 30, 2026, there was $2.1 billion of borrowings outstanding under the term loan. CDHI Intermediate Holdco, LLC. We acquired the CDHI facility (CDHI Revolver), a $1.2 billion letter of credit facility, up to $400 million of which can be used for revolving loans to finance construction of renewable energy projects. At acquisition, outstanding borrowings under the CDHI Revolver were $319 million. The CDHI Revolver is secured by substantially all of the assets of CDHI's subsidiaries in accordance with the terms of the agreement. The two York Energy Centers that partially secured the CDHI Revolver are subject to sale in accordance with the DOJ resolution. Under the terms of the CDHI revolver, consent of certain lenders was required to release these plants as collateral. In March 2026 and April 2026, the CDHI revolver's total capacity was reduced by $250 million and $568 million, respectively. In June 2026, in connection with the capacity reductions, the lenders agreed to release four plants from the collateral securing CDHI's obligations under the agreement; the two York Energy Centers, Sutter Energy Center, and South Point Energy Center. See Note 2 Mergers, Acquisitions, and Dispositions for additional information. Redemptions prior to March 2026 were based on SOFR plus 2.25%, and effective March 2026, redemptions bear interest at SOFR plus 2.375%. The CDHI Revolver matures March 2028. As of June 30, 2026, there was $290 million of borrowings outstanding under the credit facility. Nova Power, LLC. We acquired the Nova Power, LLC credit agreement, which is comprised of a term loan, with $591 million of outstanding borrowings at acquisition, and a $80 million letter of credit facility. The agreement financed a portion of the cost of the development, construction, maintenance, and operation of the Nova Power battery storage project, and is secured by Nova Power's real and personal property. The credit agreement matures September 2031 and bears interest at SOFR plus 1.75%. As of June 30, 2026, there was $572 million of borrowings outstanding under the credit agreement. 35 Table of Contents Combined Notes to Consolidated Financial Statements (Dollars in millions, unless otherwise noted) Note 13 Debt and Credit Agreements Greenfield L.P. We acquired the Greenfield L.P. credit facility, which includes a term loan, with $342 million of outstanding borrowings at acquisition, and several letters of credit facilities, with issuing capacity of approximately $75 million. The Greenfield L.P. credit facility is secured by certain real and personal property, primarily the Greenfield Energy Center in Ontario, Canada. The credit facility matures November 2030 and bears interest at CORRA plus 1.875%. As of June 30, 2026, there was $317 million of borrowings outstanding under the facility. Pin Oak Creek Energy Center LLC. We acquired Pin Oak Creek Energy Center's credit agreement pursuant with Texas Energy Fund (TEF), as lender, as administered by the Public Utility of Texas (PUCT). The loan proceeds were used to finance eligible costs for the development (as defined in the agreement), construction, and installation of Pin Oak Creek Energy Center in Fairfield, Texas. The loan had outstanding borrowings of $230 million at acquisition. The loan matures October 2045 and bears interest at 3%. As of June 30, 2026, there was $277 million of borrowings outstanding under the loan. Calpine Credit Agreements As a result of the acquisition, we assumed Calpine's corporate secured and unsecured letters of credit facilities with capacity totaling $525 million and $200 million, respectively, at the time of acquisition. The total capacity of assumed project and corporate credit facilities discussed above was approximately $2.3 billion at the time of acquisition, which was reduced by outstanding borrowings under the GPC facility and CDHI Revolver. At the time of acquisition, there were outstanding letters of credit on the assumed facilities of approximately $1.7 billion. See the Credit Facilities table below for additional information on credit facilities associated with these project financing arrangements. Debt Exchange Offering In December 2025, we announced that, in connection with the planned acquisition of Calpine, we commenced private exchange offers and related consent solicitations with respect to certain outstanding debt of Calpine (the Exchange Offers). Under the Exchange Offers, we solicited consents to holders of certain Calpine debt to amend the notes and the related indentures under which they were issued to eliminate substantially all of the restrictive covenants, restrictive provisions and events of default, other than payment-related and bankruptcy-related events of default. In January 2026, we completed the exchange offering, effectively replacing $2.3 billion of Calpine senior secured and unsecured notes with Constellation senior unsecured notes. The terms of the debt issued under the exchange are as follows: NoteInterest RateMaturityIssued Amount 2029 Senior Unsecured Notes4.625%February 2029$647 2031 Senior Unsecured Notes5.000%February 2031848 2031 Senior Unsecured Notes3.750%March 2031795 Total$2,290 Senior Note Issuance In January 2026, we issued senior unsecured notes totaling $2.75 billion, the proceeds from which were used to pay down Calpine debt assumed. In May 2026, we issued senior unsecured notes totaling $2.2 billion and used the net proceeds (i) to repay short-term borrowings, including commercial paper obligations and (ii) for general corporate purposes. The terms of the debt issuances are reflected in the Debt Issuances and Redemptions table below. 36 Table of Contents Combined Notes to Consolidated Financial Statements (Dollars in millions, unless otherwise noted) Note 13 Debt and Credit Agreements Long-term Debt Summary The following table presents the outstanding long-term debt, as of June 30, 2026 and December 31, 2025: RatesMaturity Date June 30, 2026December 31, 2025 Long-term debt Senior unsecured notes(a) 3.75% - 6.50% 2028 - 2066$13,033 $5,688 Tax-exempt notes(b) 4.10% - 4.45% 2029 - 2053412 412 Notes payable and other1.71% - 8.18% 2026 - 203585 53 Project finance:(a) Variable rates4.13% - 6.11% 2027 - 20305,172 597 Fixed rates2.29% - 8.64% 2031 - 2048904 653 Total long-term debt19,606 7,403 Unamortized debt discount and premium, net(20)(1) Unamortized fair value of debt (18) Unamortized debt issuance costs(94)(60) Long-term debt due within one year(363)(92) Long-term debt$19,111 $7,250 ________ (a)Includes debt assumed in acquisition of Calpine. (b)The Tax-exempt notes have a maturity date of June 2029 to April 2053, and a mandatory purchase date that ranges from April 2028 to June 2029. 37 Table of Contents Combined Notes to Consolidated Financial Statements (Dollars in millions, unless otherwise noted) Note 13 Debt and Credit Agreements Debt Issuances and Redemptions During the six months ended June 30, 2026, the following long-term debt was issued (redeemed): Interest RateMaturityAmount3.90 %January 2028$900 5.30 %June 2036850 5.88 %January 2066800 4.40 %January 2031750 4.55 %June 2029750 4.80 %January 2032600 SOFR + 0.60 % January 2028300 3.00 %October 204547 5.51 %December 20304 4.11 %March 2035(2)5.00 %August 2031(2)4.625 %August 2029(3)2.29 % - 3.56 % January 2037(9)CORRA + 1.875 % November 2030(14)6.00 %February 2033(18)SOFR + 1.75 % September 2031(19)SOFR + 2.25 % - 2.375 % March 2028(29)3m SOFR + 2.00 % December 2027(36)SOFR + 1.625 % May 2029(60)SOFR + 1.75 % February 2032(860)4.50 %February 2028(1,250)5.125 %March 2028(1,400)SOFR + 1.75 % January 2031(1,650)$(351)Aggregate Bank CommitmentFacility DrawsOutstanding Letters of Credit(a) Outstanding Commercial Paper(b) Total Available Capacity June 30, 2026 Revolving Credit Facility$7,000 $ $207 $2,586 $4,207 Bilateral and letter of credit facilities(c)(d) 4,100 2,691 1,409 Accounts Receivable Facility1,500 400 1,100 CDHI Revolver(d) 340 290 50 Liquidity Facility971 809 156 (e) Project Finance(d) 571 43 454 74 Total$14,482 $733 $4,161 $2,586 $6,996 39 Table of Contents Combined Notes to Consolidated Financial Statements (Dollars in millions, unless otherwise noted) Note 13 Debt and Credit Agreements Facility TypeAggregate Bank CommitmentFacility DrawsOutstanding Letters of Credit(a) Outstanding Commercial Paper(b) Total Available Capacity December 31, 2025 Revolving Credit Facility$4,500 $ $40 $ $4,460 Bilateral and letter of credit facilities2,350 1,276 1,074 Accounts Receivable Facility1,500 1,500 Liquidity Facility971 647 312 (e) Project Finance137 122 15 Total$9,458 $ $2,085 $ $7,361 __________ (a)Excludes an additional outstanding letter of credit which was not issued under these facilities of $15 million as of June 30, 2026 and December 31, 2025. See Note 15 Commitments and Contingencies for additional information. (b)Our commercial paper program is supported by the revolving credit agreement. In order to maintain our commercial paper program in the amounts indicated above, we must have a credit facility in place, at least equal to the amount of our commercial paper program. As of June 30, 2026 and December 31, 2025, the maximum program size of our commercial paper program was $7.0 billion and $4.5 billion, respectively. We do not issue commercial paper in an aggregate amount exceeding the then available capacity under our credit facility. The weighted average interest rate on commercial paper borrowings was 4.21% as of June 30, 2026. There were no commercial paper borrowings outstanding as of December 31, 2025. (c)In 2026, we entered into or amended several bilateral credit facilities increasing our letter of credit capacity totaling $1,025 million. Amendments to bilateral credit facilities included converting various committed facilities to uncommitted status, and extending maturity dates. (d)Includes corporate and project-related facilities assumed in connection with Calpine acquisition in January 2026. (e)The maximum amount of the bank commitment is not to exceed $971 million. The aggregate available capacity of the facility is subject to market fluctuations based on the value of U.S. Treasury Securities which determines the amount of collateral held in the trust. We may post additional collateral to borrow up to the maximum bank commitment. As of June 30, 2026 and December 31, 2025, without posting additional collateral, the actual availability of facility, prior to outstanding letters of credit was $965 million and $959 million, respectively. Short-Term Loan Agreements As of June 30, 2026 and December 31, 2025, we had the following short-term loan agreements, which are unsecured and reflected in Short-term borrowings in the Consolidated Balance Sheets: Month InitiatedInterest RateMaturityJune 30, 2026 December 31, 2025 May 20251-month SOFR + 0.90% May 2026$ $900 September 20251-month SOFR + 0.90% September 2026750 750 April 20261-month SOFR + 0.70% April 20271,500 Debt Covenants As of June 30, 2026, we are in compliance with all debt covenants. 40 Table of Contents Combined Notes to Consolidated Financial Statements (Dollars in millions, unless otherwise noted) Note 14 Fair Value of Financial Assets and Liabilities 14. Fair Value of Financial Assets and Liabilities We measure and classify fair value measurements in accordance with the hierarchy as defined by GAAP. The hierarchy prioritizes the inputs to valuation techniques used to measure fair value into three levels as follows: Level 1 quoted prices (unadjusted) in active markets for identical assets or liabilities that we have the ability to liquidate as of the reporting date. Level 2 inputs other than quoted prices included within Level 1 that are directly observable for the asset or liability or indirectly observable through corroboration with observable market data. Level 3 unobservable inputs, such as internally developed pricing models or third-party valuations for the asset or liability due to little or no market activity for the asset or liability. Fair Value of Financial Liabilities Recorded at Amortized Cost The following table presents the carrying amounts and fair values of our long-term debt and SNF obligation as of June 30, 2026 and December 31, 2025. We have no financial liabilities classified as Level 1. The carrying amounts of the short-term liabilities as presented in the Consolidated Balance Sheets are representative of their fair value (Level 2) because of the short-term nature of these instruments. June 30, 2026December 31, 2025 Carrying AmountFair ValueCarrying AmountFair Value Level 2Level 3TotalLevel 2Level 3Total Long-Term Debt, including amounts due within one year$19,474 $16,190 $3,446 $19,636 $7,342 $6,995 $666 $7,661 SNF Obligation(a) 1,454 1,342 1,342 1,426 1,406 1,406 __________ (a)SNF Obligation is included in Other deferred credits and other liabilities in the Consolidated Balance Sheets. Valuation Techniques Used to Determine Fair Value and Net Asset Value Our valuation techniques used to measure the fair value and net asset value of the assets and liabilities are in accordance with the policies discussed in Note 17 Fair Value of Financial Assets and Liabilities of our 2025 Form 10-K except for certain assumed variable rate project financings which are valued using a model that estimates pricing using an internal rate of return calculation and benchmark indices, which may be adjusted for company or security specific risks, resulting in these being classified as Level 3. 41 Table of Contents Combined Notes to Consolidated Financial Statements (Dollars in millions, unless otherwise noted) Note 14 Fair Value of Financial Assets and Liabilities 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 June 30, 2026 and December 31, 2025: June 30, 2026December 31, 2025 Level 1Level 2Level 3TotalLevel 1Level 2Level 3Total Assets Cash equivalents(a) $368 $ $ $368 $42 $ $ $42 NDT fund investments Cash equivalents(b) 420 198 618 72 165 237 Equities6,626 1,116 7,742 6,245 1,426 7,671 Fixed income2,428 1,599 399 4,426 2,201 1,566 395 4,162 Private credit 132 132 132 132 Assets measured at NAV 7,665 7,194 9,474 2,913 531 20,583 8,518 3,157 527 19,396 Rabbi trust investments72 49 2 123 66 45 1 112 Investments in equities63 63 87 87 Derivative assets Economic hedges1,528 12,835 9,348 23,711 1,114 7,449 3,830 12,393 (1,568)(11,289)(6,946)(19,803)(889)(6,853)(3,256)(10,998) Derivative assets subtotal(40)1,546 2,402 3,908 225 596 574 1,395 9,937 4,508 2,935 25,045 8,938 3,798 1,102 21,032 Derivative liabilities Economic hedges(1,865)(13,169)(8,369)(23,403)(1,148)(8,021)(4,062)(13,231) Effect of netting and allocation of collateral 1,839 12,617 7,630 22,086 1,065 7,657 3,628 12,350 Derivative liabilities subtotal(26)(552)(739)(1,317)(83)(364)(434)(881) Deferred compensation obligation (107) (107) (124) (124) Total liabilities measured at fair value(26)(659)(739)(1,424)(83)(488)(434)(1,005) Total net assets$9,911 $3,849 $2,196 $23,621 $8,855 $3,310 $668 $20,027 __________ (a)CEG Parent has $396 million and $70 million of Level 1 cash equivalents as of June 30, 2026 and December 31, 2025, respectively. We exclude cash of $622 million and $3,621 million, and restricted cash of $44 million and $57 million as of June 30, 2026 and December 31, 2025, respectively. CEG Parent has excluded an additional $15 million of cash as of June 30, 2026 and no additional cash exclusions as of December 31, 2025. (b)Includes net liabilities of $231 million and $166 million as of June 30, 2026 and December 31, 2025, respectively, which consist of receivables related to pending securities sales, interest and dividend receivables, repurchase agreement obligations, and payables related to pending securities purchases. The repurchase agreements are generally short-term in nature with durations generally of 30 days or less. (c)Includes total NDT derivative assets and liabilities that are not material, which have notional amounts of $995 million and $810 million as of June 30, 2026 and December 31, 2025, respectively. The notional principal amounts provide one measure of the transaction volume outstanding as of the periods ended and do not represent the amount of our exposure to credit or market loss. 42 Table of Contents Combined Notes to Consolidated Financial Statements (Dollars in millions, unless otherwise noted) Note 14 Fair Value of Financial Assets and Liabilities As of June 30, 2026, our NDTs have outstanding commitments to invest in private credit, private equity, and real assets of $690 million, $494 million, and $582 million, respectively. These commitments will be funded by our existing NDT funds. Equity Security Investments without Readily Determinable Fair Values. We hold investments without readily determinable fair values with carrying amounts of $122 million and $109 million as of June 30, 2026 and December 31, 2025, respectively. Changes in fair value, cumulative adjustments, and impairments were not material for the three and six months ended June 30, 2026 and the year ended December 31, 2025. Reconciliation of Level 3 Assets and Liabilities The following tables present the fair value reconciliation of Level 3 assets and liabilities measured at fair value on a recurring basis during the three and six months ended June 30, 2026 and 2025: Three Months Ended June 30, 2026 NDT Fund InvestmentsDerivativesRabbi Trust InvestmentsTotal Balance as of April 1, 2026$534 $2,173 $1 $2,708 Total realized / unrealized gains (losses) Included in net income (loss)(1)(514)(b) 1 (514) Included in Payables related to Regulatory Agreement Units (2) (2) Change in collateral 204 204 Purchases 24 24 Sales (1) (1) Settlements Transfers into Level 3 (22) (22) Transfers out of Level 3 10 10 Contract amortization (211) (211) Balance as of June 30, 2026 $531 $1,663 $2 $2,196 The amount of total gains (losses) included in income attributed to the change in unrealized gains (losses) related to assets and liabilities as of June 30, 2026 $(1)$(278)$1 $(278) Three Months Ended June 30, 2025 NDT Fund InvestmentsDerivativesRabbi Trust InvestmentsTotal Balance as of April 1, 2025$502 $(18)$1 $485 Total realized / unrealized gains (losses) Included in net income (loss)1 94 (b) 95 Included in Payables related to Regulatory Agreement Units 3 3 Change in collateral 80 80 Purchases 36 36 Sales (2) (2) Settlements(2) (2) Transfers into Level 3 (42)(c) (42) Transfers out of Level 3 (11)(c) (11) Balance as of June 30, 2025 $504 $137 $1 $642 The amount of total gains (losses) included in income attributed to the change in unrealized gains (losses) related to assets and liabilities as of June 30, 2025 $1 $206 $ $207 43 Table of Contents Combined Notes to Consolidated Financial Statements (Dollars in millions, unless otherwise noted) Note 14 Fair Value of Financial Assets and Liabilities Six Months Ended June 30, 2026 NDT Fund InvestmentsDerivativesRabbi Trust InvestmentsTotal Balance as of January 1, 2026 $527 $140 $1 $668 Contracts acquired at acquisition date 1,290 (a) 1,290 Total realized / unrealized gains (losses) Included in net income (loss)1 334 (b) 1 336 Included in Payables related to Regulatory Agreement Units 3 3 Change in collateral 102 102 Purchases 44 44 Sales (6) (6) Settlements Transfers into Level 3 (8)(c) (8) Transfers out of Level 3 169 (c) 169 Contract amortization (402) (402) Balance as of June 30, 2026 $531 $1,663 $2 $2,196 The amount of total gains (losses) included in income attributed to the change in unrealized gains (losses) related to assets and liabilities as of June 30, 2026 $1 $290 $1 $292 Six Months Ended June 30, 2025 NDT Fund InvestmentsDerivativesRabbi Trust InvestmentsTotal Balance as of January 1, 2025 $502 $(1)$1 $502 Total realized / unrealized gains (losses) Included in net income (loss)2 (37)(b) (35) Included in Payables related to Regulatory Agreement Units 3 3 Change in collateral 147 147 Purchases 51 51 Sales (5) (5) Settlements(4) (4) Transfers into Level 31 (43)(c) (42) Transfers out of Level 3 25 (c) 25 Balance as of June 30, 2025 $504 $137 $1 $642 The amount of total gains (losses) included in income attributed to the change in unrealized gains (losses) related to assets and liabilities as of June 30, 2025 $2 $110 $ $112 __________ (a)Represents contracts acquired as part of the Calpine acquisition in January 2026. See Note 2 Mergers, Acquisitions, and Dispositions for additional information. (b)Includes a reduction of ($447) million and ($358) million for realized gains due to the settlement of derivative contracts for the three and six months ended June 30, 2026, respectively. Includes a reduction of ($112) million and ($147) million for realized gains due to the settlement of derivative contracts for the three and six months ended June 30, 2025. (c)Transfers into and out of Level 3 generally occur when the contract tenor becomes less and more observable, respectively, primarily due to changes in market liquidity or assumptions for certain commodity contracts. 44 Table of Contents Combined Notes to Consolidated Financial Statements (Dollars in millions, unless otherwise noted) Note 14 Fair Value of Financial Assets and Liabilities The following table presents the income statement classification of the total realized and unrealized gains (losses) included in income for Level 3 assets and liabilities measured at fair value on a recurring basis during the three and six months ended June 30, 2026 and 2025: Three Months Ended June 30, Operating RevenuesPurchased Power and FuelOther, net 202620252026202520262025 Total gains (losses) included in net income$(457)$(37)$(268)$131 $ $1 Total unrealized gains (losses)3 74 (281)132 1 Operating RevenuesPurchased Power and FuelOther, net 202620252026202520262025 Total gains (losses) included in net income$125 $1 $(193)$(38)$2 $2 Total unrealized gains (losses)531 66 (241)44 2 2 Fair Value as of June 30, 2026Fair Value as of December 31, 2025Valuation Technique Unobservable Input 2026 Range & Arithmetic Average 2025 Range & Arithmetic Average Level 3 Derivatives Economic hedges(a)(b) $979 $(232)Discounted Cash FlowForward power price (Non-congestion)$0.32 - $164 $49$4.77 - $154 $54 Forward power price (Congestion)$11 - $168 $55$3.14 - $154 $50 Forward gas price$0.65 - $18 $3.21($0.46) - $15 $3.52 Option ModelVolatility percentage7% - 121% 58%14% - 197% 59% __________ (a)The valuation techniques, unobservable inputs, ranges, and arithmetic averages are the same for the asset and liability positions. (b)The fair values do not include cash collateral posted (received) on Level 3 positions of $684 million and $372 million as of June 30, 2026 and December 31, 2025, respectively. The inputs listed above, which are as of the balance sheet date, would have a direct impact on the fair values of the above instruments if they were adjusted. The significant unobservable inputs used in the fair value measurement of our commodity derivatives are forward commodity prices and for options is price volatility. Increases (decreases) in the forward commodity price in isolation would result in significantly higher (lower) fair values for long positions (contracts that give us the obligation or option to purchase a commodity), with offsetting impacts to short positions (contracts that give us the obligation or right to sell a commodity). Increases (decreases) in volatility would increase (decrease) the value for the holder of the option (writer of the option). Generally, a change in the estimate of forward commodity prices is unrelated to a change in the estimate of volatility of prices. 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. 45 Table of Contents Combined Notes to Consolidated Financial Statements (Dollars in millions, unless otherwise noted) Note 15 Commitments and Contingencies 15. Commitments and Contingencies Commitments Commercial Commitments. Commercial commitments as of June 30, 2026, representing commitments potentially triggered by future events, were as follows: Expiration within 202620272028202920302031 and thereafterTotal Letters of credit$2,899 $1,154 $122 $ $1 $ $4,176 Surety bonds(a) 443 389 78 557 1,467 Guarantee under the Calpine AR Facility(b) 459 459 Total commercial commitments $3,801 $1,543 $200 $ $1 $557 $6,102 __________ (a)Surety bonds Guarantees issued related to contract and commercial agreements, excluding bid bonds. (b)We have guaranteed the performance of Calpine Energy Solutions, LLC to Calpine Receivables, LLC under the Calpine AR Facility. The commitment represents the gross amount of sold receivables that are currently outstanding, limited to $550 million per the guarantee agreement. Refer to Note 7 Accounts Receivable for additional information. First Priority Liens for Commodity Procurement and Risk Management Activities Following the acquisition of Calpine in January 2026, the Company has assumed additional first-priority liens on Calpine assets, which are currently subject to first priority liens under various debt agreements, as collateral under certain of our power and natural gas agreements and certain of the interest rate swaps in order to reduce the cash collateral and letters of credit that would otherwise be provided to the counterparties under such agreements. The counterparties under such agreements share the benefits of the collateral subject to such first priority liens pro rata with the lenders under various debt agreements. As of June 30, 2026, the exposure was $167 million under these first priority liens for power and natural gas agreements and no exposure for the interest rate swaps. Environmental Remediation Matters General. Our operations have in the past, and may in the future, require substantial expenditures to comply with environmental laws. Additionally, under Federal and state environmental laws, we are generally liable for the costs of remediating environmental contamination of property currently or formerly owned by us and of property contaminated by hazardous substances generated by us. We own or lease several real estate parcels, including parcels on which our operations or the operations of others may have resulted in contamination by substances that are considered hazardous under environmental laws. In addition, we are currently involved in proceedings relating to sites where hazardous substances have been deposited and may be subject to additional proceedings in the future. Unless otherwise disclosed, we cannot reasonably estimate whether we will incur significant liabilities for additional investigation and remediation costs at these or additional sites identified by us, environmental agencies, or others. Additional costs could have a material, unfavorable impact on our consolidated financial statements. As of June 30, 2026 and December 31, 2025, we had accrued undiscounted amounts for environmental liabilities of $14 million and $9 million, respectively, in Accounts payable and accrued expenses and $162 million and $169 million, respectively, in Other deferred credits and other liabilities in the Consolidated Balance Sheets. See Note 18 Commitments and Contingencies of our 2025 Form 10-K for additional information on environmental remediation matters. As of June 30, 2026, and through the date of filing, there have been no material changes in amounts recognized for the matters discussed in our 2025 Form 10-K. 46 Table of Contents Combined Notes to Consolidated Financial Statements (Dollars in millions, unless otherwise noted) Note 15 Commitments and Contingencies Litigation We are involved in various litigation matters that are being defended and handled in the ordinary course of business. The assessment of whether a loss is probable or reasonably possible, and whether the loss or a range of loss is estimable, often involves a series of complex judgments about future events. We maintain accruals for such losses that are probable of being incurred and subject to reasonable estimation. Management is sometimes unable to estimate an amount or range of reasonably possible loss, particularly where (1) the damages sought are indeterminate, (2) the proceedings are in the early stages, or (3) the matters involve novel or unsettled legal theories. In such cases, there is considerable uncertainty regarding the timing or ultimate resolution of such matters, including a possible eventual loss. As of June 30, 2026 and December 31, 2025, we had accrued $28 million and $15 million, respectively, in Accounts payable and accrued expenses and $122 million and $113 million, respectively, in Other deferred credits and other liabilities in the Consolidated Balance Sheets for liabilities related to litigation matters, including asbestos personal injury claims. See Note 18 Commitments and Contingencies of our 2025 Form 10-K for additional information on asbestos personal injury claims. As of June 30, 2026, and through the date of filing, there have been no material changes in amounts recognized for the matters discussed in our 2025 Form 10-K. Impacts of the February 2021 Extreme Cold Weather Event and Texas-based Generating Assets Outages. Calpine was acquired on January 7, 2026, and is party to the same ongoing litigation proceedings as Constellation. See Note 18 Commitments and Contingencies of our 2025 Form 10-K for additional information on this matter, which is likewise representative of the ongoing proceedings as it pertains to Calpine. In March 2026, the Supreme Court of Texas denied plaintiffs petitions for a writ of mandamus in all five bellwether appeals. In July 2026, the Court denied plaintiffs' motions for rehearing. The parties will now return to the Multi-District-Litigation court to effect dismissal of all remaining Winter Storm Uri tort claims pending against the power generator defendants. 16. Shareholders' Equity Share Repurchase Program (CEG Parent) During 2026, our Board of Directors approved a $4.4 billion increase relative to the remaining $0.6 billion authorization under our share repurchase program. No other repurchase plans or programs have been authorized. As of the date of this filing, we have approximately $2.8 billion of remaining authority for repurchases, which includes the impact of the repurchases discussed below. See Note 19 Shareholders' Equity of our 2025 Form 10-K for additional information on our share repurchase program. During the three and six months ended June 30, 2026, we repurchased approximately 7.1 million shares of our common stock in the open market for approximately $2.0 billion, inclusive of open market purchases and the secondary public offering discussed further in Note 2 Mergers, Acquisitions, and Dispositions. In July 2026, we repurchased an additional one million shares for approximately $250 million. ASR Agreements. In June 2025, we entered into an ASR agreement with a financial institution to initiate share repurchases of our common stock. Under the ASR agreement, we paid a specified amount to the financial institution and received an initial delivery of shares of common stock based on 80% of the ASR agreement's cost, which resulted in an immediate reduction in the number of our shares outstanding, with incremental shares delivered upon settlement of the ASR. The following table summarizes the ASR agreement for the six months ended June 30, 2025: (in millions, except average price paid per share) ASR Agreement InitiationTotal CostInitial Shares ReceivedASR Agreement SettlementAdditional Shares ReceivedTotal Number of Shares PurchasedAverage Price Paid per Share June 2025$404 1.1 August 20250.2 1.3 $311.84 47 Table of Contents Combined Notes to Consolidated Financial Statements (Dollars in millions, unless otherwise noted) Note 16 Shareholders' Equity Capped Call Options. During the first quarter of 2025, we entered into two structured share repurchase agreements. Under these agreements, we made up-front cash payments of $150 million in the first quarter of 2025 in exchange for the right to receive a predetermined amount of shares of our common stock or cash at expiration. Neither option was exercised during the second and third quarter of 2025, therefore we did not receive any shares at expiration. As a result, we received our initial up-front cash payments of $150 million plus a nominal cash premium during the second and third quarters of 2025. The cash received restored the remaining authority available for repurchases. Changes in Accumulated Other Comprehensive Income (Loss) (All Registrants) The following tables present changes in AOCI, net of tax, by component: Three Months Ended June 30, 2026Gains (losses) on Cash Flow HedgesPension and OPEB Items(a) Foreign Currency ItemsTotal Beginning balance$2 $(2,411)$(16)$(2,425) OCI before reclassifications (1)(1) Amounts reclassified from AOCI2 26 28 Net current-period OCI2 26 (1)27 Ending balance$4 $(2,385)$(17)$(2,398) Three Months Ended June 30, 2025 Beginning balance$(4)$(2,279)$(26)$(2,309) OCI before reclassifications 20 20 Amounts reclassified from AOCI1 16 17 Net current-period OCI1 16 20 37 Ending balance$(3)$(2,263)$(6)$(2,272) Six Months Ended June 30, 2026 Beginning balance$1 $(2,413)$(13)$(2,425) OCI before reclassifications (25)(4)(29) Amounts reclassified from AOCI3 53 56 Net current-period OCI3 28 (4)27 Ending balance$4 $(2,385)$(17)$(2,398) Six Months Ended June 30, 2025 Beginning balance$(6)$(2,262)$(34)$(2,302) OCI before reclassifications (34)28 (6) Amounts reclassified from AOCI3 33 36 Net current-period OCI3 (1)28 30 Ending balance$(3)$(2,263)$(6)$(2,272) __________ (a)AOCI amounts are included in the computation of net periodic pension and OPEB cost. See Note 11 Retirement Benefits for additional information. See our Consolidated Statements of Operations and Comprehensive Income for individual components of AOCI. 48 Table of Contents Combined Notes to Consolidated Financial Statements (Dollars in millions, unless otherwise noted) Note 16 Shareholders' Equity The following table presents income tax (expense) benefit allocated to each component of our other comprehensive income (loss): Three Months Ended June 30,Six Months Ended June 30, 2026202520262025 Pension and OPEB plans: $(9)$(6)$(18)$(12) Pension and OPEB plans valuation adjustment 8 12 17. Variable Interest Entities At June 30, 2026 and December 31, 2025, we consolidated several VIEs or VIE groups for which we are the primary beneficiary (see Consolidated VIEs below) and had significant interests in several other VIEs for which we do not have the power to direct the entities activities and, accordingly, we were not the primary beneficiary (see Unconsolidated VIEs below). Consolidated and unconsolidated VIEs are aggregated to the extent that the entities have similar risk profiles. Consolidated VIEs The table below shows the carrying amounts and classification of the consolidated VIEs assets and liabilities included in the consolidated financial statements as of June 30, 2026 and December 31, 2025. The assets, except as noted in the footnotes to the table below, can only be used to settle obligations of the VIEs. The liabilities, except as noted in the footnotes to the table below, are such that creditors, or beneficiaries, do not have recourse to our general credit. June 30, 2026December 31, 2025 Cash and cash equivalents$95 $52 Restricted cash and cash equivalents54 48 Accounts receivable, net 2,132 2,477 Inventories, net13 13 Other current assets32 29 Total current assets2,326 2,619 Property, plant, and equipment, net 1,885 1,942 Other deferred debits and other assets111 123 Total assets(a) $4,322 $4,684 Short-term borrowings$400 $ Long-term debt due within one year67 66 Accounts payable and accrued expenses 33 34 Other current liabilities 1 3 Total current liabilities501 103 Long-term debt548 578 Asset retirement obligations237 231 Other deferred credits and other liabilities1 2 Total deferred credits and other liabilities 238 233 Total liabilities $1,287 $914 __________ (a)Our balances include unrestricted assets for current UEC assets of $17 million and $17 million, disclosed within other current assets in the table above, and noncurrent UEC assets of $108 million and $116 million, disclosed within other noncurrent assets in the table above, as of June 30, 2026 and December 31, 2025, respectively. 49 Table of Contents Combined Notes to Consolidated Financial Statements (Dollars in millions, unless otherwise noted) Note 17 Variable Interest Entities As of June 30, 2026 and December 31, 2025, our consolidated VIEs included the following: Consolidated VIE or VIE groups:Reason entity is a VIE:Reason we are the primary beneficiary: CRP - A collection of wind and solar project entities. We have a 51% equity ownership in CRP. See Note 21 - Variable Interest Entities of our 2025 Form 10-K for additional information. Similar structure to a limited partnership and the limited partners do not have kick-out rights with respect to the general partner. We conduct the operational activities. Bluestem Wind Energy Holdings, LLC - A Tax Equity structure which is consolidated by CRP.Similar structure to a limited partnership and the limited partners do not have kick-out rights with respect to the general partner. We conduct the operational activities. Antelope Valley - A solar generating facility, which is 100% owned by us. Antelope Valley sells all of its output to PG&E through a PPA. The PPA contract absorbs variability through a performance guarantee.We conduct all activities. NER - A bankruptcy remote, special purpose entity which is 100% owned by us, which purchases certain of our customer accounts receivable arising from the sale of retail electricity and gas. NER s assets will be available first and foremost to satisfy the claims of the creditors of NER. Refer to Note 7 Accounts Receivable for additional information on the sale of receivables. Equity capitalization is insufficient to support its operations.We conduct all activities. Unconsolidated VIEs Our variable interests in unconsolidated VIEs generally include an equity method investment and energy purchase and sale contracts. For the equity investment, the carrying amount of the investment is reflected in the Consolidated Balance Sheets in Other deferred debits and other assets, see Note 18 Supplemental Financial Information for additional information. For the energy purchase and sale contracts (commercial agreements), the carrying amount of assets and liabilities in the Consolidated Balance Sheets that relate to our involvement with the VIEs are predominantly related to working capital accounts and generally represent the amounts owed by, or owed to, us for the deliveries associated with the current billing cycles under the commercial agreements. As of June 30, 2026 and December 31, 2025, we had significant unconsolidated variable interests in several VIEs for which we were not the primary beneficiary. These interests include certain commercial and securitization agreements. 50 Table of Contents Combined Notes to Consolidated Financial Statements (Dollars in millions, unless otherwise noted) Note 17 Variable Interest Entities The following table presents summary information about our significant unconsolidated VIE entities: June 30, 2026December 31, 2025 Commercial Agreement VIEsEquity Investment VIEs Total Commercial Agreement VIEsEquity Investment VIEs Total Total assets(a) $711 $471 $1,182 $711 $ $711 Total liabilities(a) 94 440 534 95 95 617 31 648 616 616 Reason entity is a VIE:Reason we are not the primary beneficiary: Energy Purchase and Sale agreements - We have several energy purchase and sale agreements with generating facilities.PPA contracts that absorb variability through fixed pricing.We do not conduct the operational activities. Calpine Receivables, LLC(a) - A bankruptcy remote entity created for the special purpose of purchasing trade accounts receivable from Calpine Energy Solutions, LLC under the Accounts Receivable Sales Program Equity capitalization is insufficient to support its operations. We do not have the power to direct activities nor affect its financial performance __________ (a)Calpine Receivables, LLC became an unconsolidated VIE in January 2026 as a result of the Calpine acquisition. As such, it was not an unconsolidated VIE as of December 31, 2025. 18. Supplemental Financial Information Supplemental Consolidated Statements of Operations and Comprehensive Income Information The following tables provide additional information about items recorded in the Consolidated Statements of Operations and Comprehensive Income. Three Months Ended June 30,Six Months Ended June 30, Operating revenues2026202520262025 $84 $64 $182 $117 Three Months Ended June 30,Six Months Ended June 30, Taxes other than income taxes2026202520262025 Property$90 $71 $193 $142 Payroll60 39 118 83 Gross receipts(a) 52 39 116 77 Other 5 (2)9 5 Total$207 $147 $436 $307 __________ (a)Represent gross receipts taxes related to our retail operations. The offsetting collection of gross receipts taxes from customers is recorded in Operating revenues in the Consolidated Statements of Operations and Comprehensive Income. 51 Table of Contents Combined Notes to Consolidated Financial Statements (Dollars in millions, unless otherwise noted) Note 18 Supplemental Financial Information Three Months Ended June 30,Six Months Ended June 30, Other, net2026202520262025 Decommissioning-related activities: Net realized income on NDT funds(a) Regulatory Agreement Units$284 $131 $555 $375 Non-Regulatory Agreement Units170 73 325 167 Net unrealized gains (losses) on NDT funds Regulatory Agreement Units499 429 293 311 Non-Regulatory Agreement Units270 253 161 230 Regulatory offset to NDT fund-related activities(b) (625)(449)(677)(552) Total Decommissioning-related activities598 437 657 531 3 (7)(24)(275) 2 10 16 30 Total$603 $440 $649 $286 __________ (a)Realized income includes interest, dividends and realized gains and losses on sales of NDT fund investments. (b)Includes the elimination of decommissioning-related activities and the elimination of income taxes related to all NDT fund activity for the Regulatory Agreement Units. (c)Includes unrealized gains (losses) resulting from an equity investment in a publicly traded company. We record the fair value of this investment in Other deferred debits and other assets in the Consolidated Balance Sheets based on quoted market price of the stock. Supplemental Cash Flow Information The following tables provide additional information about items recorded within our Consolidated Statements of Cash Flows. Six Months Ended June 30, Depreciation, amortization, and accretionIncome statement location 20262025 PP&EDepreciation and amortization$870 $492 Nuclear fuelPurchased power and fuel496 468 Amortization of acquired derivative contracts(a) Operating revenues or purchased power and fuel423 ARO accretionOperating and maintenance338 318 Amortization of UECsOperating revenues or purchased power and fuel240 12 Amortization of intangible assets, net(b) Depreciation and amortization16 10 Other amortizationOperating revenues, purchased power and fuel, or interest expense, net(15) Total$2,368 $1,300 __________ (a)Related to the amortization of acquired derivative contracts from the acquisition of Calpine. (b)Primarily related to the amortization of customer relationships and trade names. 52 Table of Contents Combined Notes to Consolidated Financial Statements (Dollars in millions, unless otherwise noted) Note 18 Supplemental Financial Information CEG ParentConstellation Six Months Ended June 30,Six Months Ended June 30, Other non-cash operating activities 2026202520262025 Other decommissioning-related activity(a) $(536)$(224)$(536)$(224) Pension and non-pension postretirement benefit costs 101 76 101 76 195 127 131 78 Total$(240)$(21)$(304)$(70) __________ (a)Includes the elimination of decommissioning-related activities for the Regulatory Agreement Units, including the elimination of operating revenues, ARO accretion, ARC amortization, investment income, and income taxes related to all NDT fund activity for these units. The following table provides a reconciliation of cash, restricted cash, and cash equivalents reported within our Consolidated Balance Sheets that sum to the total of the same amounts in the Consolidated Statements of Cash Flows. June 30, 2026CEG ParentConstellation Cash and cash equivalents$697 $681 Restricted cash and cash equivalents380 353 $1,077 $1,034 December 31, 2025 Cash and cash equivalents$3,641 $3,641 Restricted cash and cash equivalents107 79 $3,748 $3,720 June 30, 2025 Cash and cash equivalents$1,974 $1,964 Restricted cash and cash equivalents88 76 $2,062 $2,040 June 30, 2026December 31, 2025 Materials and supplies$2,223 $1,485 Natural gas, oil, and emission allowances1,145 251 Total$3,368 $1,736 CEG ParentConstellation Accounts payable and accrued expensesJune 30, 2026December 31, 2025June 30, 2026December 31, 2025 Accounts payable $2,458 $2,813 $2,444 $2,801 Compensation-related accruals(a) 783 920 680 672 Taxes accrued(b) 395 246 395 245 Other accrued expenses 796 315 796 315 Total $4,432 $4,294 $4,315 $4,033 __________ (a)Primarily includes accrued payroll, bonuses and other incentives, vacation, and benefits. (b)Includes $375 million as of December 31, 2025, related to nuclear PTC that was used to offset the current tax liability. No credits were utilized during the six months ended June 30, 2026. See Note 6 Government Assistance for additional information on the nuclear PTC. The following table provides additional information about investments included in Other deferred debits and other assets in the Consolidated Balance Sheets. InvestmentsJune 30, 2026December 31, 2025 Equity method investments $45 $3 Other investments: Employee benefit trusts and investments(a) 124 112 Equity investments with readily determinable fair values(b) 61 82 Equity investments without readily determinable fair values122 109 Other available for sale debt security investments1 1 Total $353 $307 __________ (a)Debt and equity security investments are recorded at fair market value. (b)Does not include the equity investments with readily determinable fair values that are recorded in Other current assets in the Consolidated Balance Sheets. See Note 14 Fair Value of Financial Assets and Liabilities for additional information on investments in equities. Item 2.MANAGEMENT S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (Dollars in millions except per share data, unless otherwise noted) Executive Overview Constellation Energy Corporation, a Fortune 200 company headquartered in Baltimore, is the largest private-sector power producer in the world and the nation s largest producer of clean and reliable energy. With 55 gigawatts of capacity from nuclear, natural gas, oil, geothermal, hydro, wind and solar facilities, our fleet has the generating capacity to power the equivalent of 27 million homes, providing about 10% of the nation s clean energy and delivering the around-the-clock reliability needed to power America s growing economy. We are also the largest nuclear energy company in the U.S. and a leading competitive retail supplier, serving approximately 2.5 million customer accounts nationwide, including 80% of the Fortune 100. We are committed to investing in innovation and new technologies to drive the transition to a reliable, sustainable and secure energy future. 54 Table of Contents Significant Transactions and Developments Acquisition of Calpine Corporation On January 7, 2026, we acquired 100% of the outstanding equity of Calpine for a purchase price of approximately $21.8 billion. The merger consideration consisted of 50 million newly issued shares of our common stock, no par value, and approximately $4.5 billion in cash on hand. After considering divestitures connected with certain regulatory approvals, Calpine owns and operates a generation fleet of predominantly natural gas, geothermal, battery storage, and solar assets with approximately 23 GWs of generation capacity, in addition to a competitive retail electric supplier platform serving approximately 62 TWhs of load annually. This acquisition is complementary to, and aligns strategically with, our existing business operations and provides both increased scale and meaningful market diversification. The merger couples the largest producer of clean, emissions-free energy with the reliable, dispatchable natural gas assets of Calpine, and also creates the nation s leading competitive retail electric supplier, providing increased scale, diversification and complementary capabilities that enable us to meet growing demand with a broader array of energy and sustainability products. The addition of Calpine strengthens our essential role in providing clean, reliable energy as the nation seeks to transition to a more sustainable future, and will better position us to pursue investments in new and existing technologies to meet growing demand. In March 2026, we entered into an agreement with LS Power Equity Advisors, LLC to sell five natural gas-fired generating facilities with approximately 4.4 GWs of capacity from Calpine's portfolio of generation assets located in PJM to satisfy regulatory commitments related to our acquisition of Calpine. The transaction is valued at $5.0 billion before closing adjustments. In August 2026, we entered into an agreement with LS Power to divest the Brazos Valley Energy Center (f/k/a Jack A. Fusco Energy Center), a 606 MW natural gas-fired plant in ERCOT for $860 million before closing adjustments. Completion of these transactions is subject to customary closing conditions and receipt of applicable regulatory approvals, and is expected to satisfy the remaining regulatory commitments related to the merger. We expect the transactions to close by the end of this year. See Note 2 Mergers, Acquisitions, and Dispositions and Note 13 Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information. New Data Center Facility at Freestone Energy Center In the first quarter of 2026, we signed a new 380 MW agreement with Dallas-based CyrusOne, a leading global data center developer and operator, to connect and serve a new data center adjacent to the Freestone Energy Center, in Freestone County, Texas. The agreement provides CyrusOne with access to power, grid connectivity and site infrastructure needed to support development of the new facility, while ensuring electricity continues to flow to the regional grid and ensuring reliability for all customers and communities. We have also entered into an exclusive agreement to provide power, grid connectivity and site infrastructure for Phase 2, which will be an additional 380 MWs. These agreements are in addition to the 400 MW agreements announced in the second half of last year between Calpine and CyrusOne for the Thad Hill Energy Center in Bosque County, Texas. Pastoria Solar Project In April 2026, we celebrated the commissioning of the 105 MW Pastoria Solar Project, the largest renewable energy project contracted by the California Department of Water Resources to date in its mission to fully decarbonize its operations by 2035. The Pastoria Solar Project connects to the grid through the interconnection facilities at our highly efficient 750 MW natural gas-fired Pastoria facility. Also, co-located with the Pastoria Solar Project is the Pastoria Power Bank, a 80 MW/320 MWh Battery Energy Storage System, which came online in July 2026. The Pastoria Power Bank is contracted and supported by a 15-year power purchase agreement with Pacific Gas and Electric Company. 55 Table of Contents Pin Oak Creek Energy Center In April 2026, our Pin Oak Creek Energy Center achieved commercial operation. Pin Oak Creek is a 460 MW, state-of-the-art natural gas facility designed to provide reliable, dispatchable power to the ERCOT grid. As a peaking facility, it is built to operate when demand is highest and reliability matters most, while also maintaining the flexibility to run longer if system conditions require it. The project is a direct response to Texas continued growth and increasing electricity demand across homes, businesses, and industry. Pin Oak Creek will play a critical role in strengthening grid reliability and supporting the state s economic momentum. Long-term Nuclear PPAs We have signed an additional 920 MW of long-term PPAs for clean, reliable nuclear generation with a diverse set of investment grade customers to help them meet their evolving energy needs. These agreements are for 15-20 years in duration and are set to begin in 2029 through 2032. Among these PPAs, our 176 MW agreement with Walmart will enable a 30 MW capacity expansion at our Dresden Clean Energy Center in Illinois and facilitate additional investments to strengthen the local community by supporting jobs and enabling continued expansion of operations and workforce. Other Key Business Drivers PJM Market Reform In January 2026, the National Energy Dominance Council, with support from Governors within the PJM territory, urged PJM to file proposed tariff revisions at FERC to improve reliability and cost-effectiveness within its capacity auctions. During the first quarter of 2026, PJM began stakeholder discussions and preparatory work in response to this directive, including evaluation of a potential reliability backstop mechanism, enhancements to large load forecasting methodologies, and actions to accelerate generator interconnection studies. In February 2026, PJM filed tariff revisions proposing to extend the existing RPM capacity market price collar consisting of a price cap of approximately $325/MW day and a price floor of approximately $175/MW day for the 2028/2029 and 2029/2030 Base Residual Auctions. In an order issued by FERC in April 2026, FERC accepted PJM s tariff revisions, allowing the continued application of the price collar for the specified delivery years. FERC found the filing sufficiently justified to proceed, citing ongoing reliability concerns and extraordinary demand growth, including data center load expansion, and anticipated market reforms. In July 2026, PJM released the results of the 2028/2029 Base Residual Auction and the entire RTO, including all submitted CEG units, cleared at the price cap of $325/MW-day FERC Issues Order in PJM Show Cause Proceeding In December 2025, FERC issued an order finding the existing PJM Tariff to be unjust and unreasonable and directing PJM to take a number of actions. FERC ordered three new transmission services: an interim interruptible network integration transmission service (IT NITS), which will allow load to take service on an interruptible basis while waiting for the network upgrades required for traditional NITS, and two other services. The IT NITS service allows the load to elect to connect promptly and receive some service from the grid, while avoiding PJM purchases of capacity to serve it, as it will be interruptible. The other services include a firm and non-firm contract demand service for co-located load. FERC also directed several PJM compliance filings and a paper hearing. In June 2026, FERC ruled on a number of issues presented in the co-location paper hearing and on several PJM compliance filings implementing directives from the December 2025 order. Importantly, FERC pressed PJM to implement changes to accommodate co-located load prior to PJM s proposed June 2029 effective date. FERC also issued a series of orders in the various RTOs in response to the Advance Notice of Proposed Rulemaking (ANOPR) published by DOE last fall. The orders direct filings by RTOs and their transmission owners that are designed to expedite service to large load (regardless of whether it is co-located) and avoid the expense and delay associated with network upgrades to provide service to these loads. Constellation s Load Dependent Capacity at Existing Plants (LCEP) proposal, which would expedite connection of new generation when paired with a large load at an existing plant, was flagged in several RTO orders as a proposal to be considered. 56 Table of Contents Russia and Ukraine Conflict We are closely monitoring developments of the ongoing Russia and Ukraine conflict, including United States, United Kingdom, European Union, and Canadian sanctions, and legislation that may impact exports and imports of Russian nuclear fuel supply and enrichment activities, as well as the potential for Russia to limit fuel deliveries. The U.S. Prohibiting Russian Uranium Imports Act became effective in August 2024, banning the import of low-enriched uranium into the U.S. that is produced in Russia or by Russian entities, absent a waiver from the DOE. Under a corollary bill, the Department of Energy has begun the process of distributing billions of dollars to support expansion of the domestic nuclear fuel cycle within the United States to improve emissions-free energy security. In November 2024, the Russian government issued a decree imposing temporary restrictions on the export of enriched uranium from Russia to the U.S. but allowing for a special Russian export license to be issued for individual shipments. Our nuclear fuel is obtained predominantly through long-term uranium supply and service contracts. We work with a diverse set of domestic and international suppliers years in advance to procure our nuclear fuel to support our refueling needs and mitigate the risk of exposure to Russian nuclear fuel supply. Recognizing the potential for the continuing conflict to impact our longer-term security and cost of supply, we have entered into contracts to increase the size of our nuclear fuel inventory. Our fuel procurement activities comply with all U.S. and international trade laws and we continue to take advantage of all available avenues to maintain continuity in our nuclear fuel supply, including working with the U.S. Government and our diverse set of suppliers to secure the nuclear fuel needed to continue to operate our nuclear fleet long-term. Environmental Regulation California Assembly Bill 32, as amended by Senate Bill 32 in 2016, directed the California Air Resources Board (CARB) to adopt regulations to achieve the maximum technologically feasible and cost-effective reductions in GHG emissions, targeting statewide GHG emissions at 1990 levels by 2020 and to at least 40% below 1990 levels by 2030. The California Climate Crisis Act was enacted in 2022 and further establishes the state's policy to achieve net zero GHG emissions as soon as possible, but no later than 2045, and to reduce statewide anthropogenic GHG emissions to 85% below 1990 levels by 2045. To achieve these targets, CARB has promulgated complementary regulatory measures, including the Cap-and-Trade Program and Mandatory Greenhouse Gas Emissions Reporting Regulation. Covered entities, such as our power plants, must surrender compliance instruments, which include both allowances and offset credits, in an amount equivalent to their GHG emissions. Assembly Bill 398, enacted in 2017, authorized the extension of the Cap-and-Trade Program through 2030 and required several changes to the program, including establishing a price ceiling and other price mitigative mechanisms and limiting the amount of offsets allowed to comply with the regulation. In September 2025, California Governor Gavin Newsom signed AB 1207 and SB 840 into law, extending the state s Cap-and-Trade Program through January 1, 2046, and renaming it the Cap and Invest" Program. In September 2021, Illinois Governor JB Pritzker signed into law the Climate and Equitable Jobs Act, which, among other things, establishes a schedule for eliminating CO2 emissions by EGUs. Under that schedule, privately owned natural gas units that exceed an established level of NOx or SO2 emissions and are located within three miles of an environmental justice community, or an equity investment-eligible community must permanently eliminate CO2 and co-pollutant emissions by January 1, 2030, subject to certain reliability exceptions, such as a determination by PJM that the unit is needed for reliability. PJM made such a finding with respect to our natural gas generation facility Zion Energy Center, acquired as part of Calpine, and accordingly Zion plans to operate past January 2030. See ITEM 1. BUSINESS, Environmental Matters and Regulation of our 2025 Form 10-K for additional information on environmental legislation and regulation we are subject to. Critical Accounting Policies and Estimates Management makes a number of significant estimates, assumptions, and judgments in the preparation of our financial statements. At June 30, 2026, our critical accounting policies and estimates had not changed significantly from December 31, 2025. See ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS Critical Accounting Policies and Estimates of our 2025 Form 10-K for further information. 57 Table of Contents Financial Results of Operations GAAP Results of Operations. The following table sets forth our consolidated GAAP Net Income (Loss) Attributable to Common Shareholders for the three and six months ended June 30, 2026 compared to the same period in 2025. For additional information regarding the financial results for the three and six months ended June 30, 2026 and 2025, see the discussions of Results of Operations below. Three Months Ended June 30,$ Change Six Months Ended June 30,$ Change 2026202520262025 GAAP Net Income (Loss) Attributable to Common Shareholders $513 $839 $(326)$2,103 $957 $1,146 Adjusted (non-GAAP) Operating Earnings. We utilize Adjusted (non-GAAP) Operating Earnings (and/or its per share equivalent) in our internal analysis, and in communications with investors and analysts, as a consistent measure for comparing our financial performance and discussing the factors and trends affecting our business. The presentation of Adjusted (non-GAAP) Operating Earnings is intended to complement and should not be considered an alternative to, nor more useful than, the presentation of GAAP Net Income. The table below provides a reconciliation of GAAP Net Income to Adjusted (non-GAAP) Operating Earnings. Adjusted (non-GAAP) Operating Earnings is not a standardized financial measure and may not be comparable to other companies presentations of similarly titled measures. Unless otherwise noted, the income tax impact of each reconciling adjustment between GAAP Net Income (Loss) Attributable to Common Shareholders and Adjusted (non-GAAP) Operating Earnings is based on the marginal statutory federal and state income tax rates, taking into account whether the income or expense item is taxable or deductible, respectively, in whole or in part, which may result in an effective tax rate that differs from the marginal rate. The marginal statutory income tax rate was 25.5% for the three and six months ended June 30, 2026 and 2025. The following table provides a reconciliation between GAAP Net Income (Loss) Attributable to Common Shareholders and Adjusted (non-GAAP) Operating Earnings for the three and six months ended June 30, 2026 compared to the same period in 2025. Three Months Ended June 30, 20262025 (In millions, except per share data)Earnings Per Share(a) Earnings Per Share(a) GAAP Net Income (Loss) Attributable to Common Shareholders$513 $1.42 $839 $2.67 Unrealized (Gain) Loss on Fair Value Adjustments (net of taxes of $116 and $37, respectively)(b) 340 0.94 (121)(0.38) Decommissioning-Related Activities (net of taxes of $298 and $208, respectively)(c) (221)(0.61)(144)(0.46) Amortization of Acquired Commodity Contracts (net of taxes of $51 and $ , respectively)(d) 149 0.41 Calpine Merger and Integration Costs (net of taxes of $17 and $3, respectively)(e) 84 0.23 9 0.03 Plant Retirements and Divestitures (net of taxes of $ and $2, respectively) 7 0.02 Pension & OPEB Non-Service (Credits) Costs (net of taxes of $7 and $3, respectively) 20 0.06 9 0.03 Change in Legal and Environmental Liabilities (net of taxes of $12 and $ , respectively) 35 0.10 $920 $2.55 $599 $1.91 58 Table of Contents Six Months Ended June 30, 20262025 (In millions, except per share data)Earnings Per Share(a) Earnings Per Share(a) GAAP Net Income (Loss) Attributable to Common Shareholders$2,103 $5.88 $957 $3.05 Unrealized (Gain) Loss on Fair Value Adjustments (net of taxes of $131 and $131, respectively)(b) (381)(1.07)384 1.22 Decommissioning-Related Activities (net of taxes of $377 and $239, respectively)(c) (395)(1.11)(125)(0.40) Amortization of Acquired Commodity Contracts (net of taxes of $104 and $ , respectively)(d) 303 0.85 Calpine Merger and Integration Costs (net of taxes of $39 and $8, respectively)(e) 204 0.57 22 0.07 Plant Retirements and Divestitures (net of taxes of $ and $6, respectively) 18 0.06 Pension & OPEB Non-Service (Credits) Costs (net of taxes of $14 and $6, respectively) 40 0.11 18 0.06 Change in Legal and Environmental Liabilities (net of taxes of $12 and $ , respectively) 35 0.10 1 Income Tax-Related Adjustments(13)(0.04) Noncontrolling Interests(f) (3)(0.01)(3)(0.01) Adjusted (non-GAAP) Operating Earnings $1,893 $5.30 $1,272 $4.05 __________ (a)Amounts may not sum due to rounding. Earnings per share amount is based on average diluted common shares outstanding of 360 million and 314 million for the three months ended June 30, 2026 and 2025, respectively, and 357 million and 314 million for the six months ended June 30, 2026 and 2025, respectively. (b)Includes unrealized gains and losses on economic hedges, interest rate swaps, and fair value adjustments related to gas imbalances and equity investments. (c)Reflects all gains and losses associated with NDTs, ARO accretion, ARC depreciation, ARO remeasurement, and impacts of contractual offset for Regulatory Agreement Units. The tax effects of Regulatory Agreement Units result in a 100% effective tax rate under contractual offset accounting. Additionally, the tax effects of NDT investment returns result in different effective tax rates depending on whether the underlying funds are held within qualified or non-qualified trusts. (d)In 2026, reflects the non-cash impacts of the amortization of certain commodity contracts recorded at fair value associated with the Calpine acquisition. (e)Reflects costs associated with the completion of the Calpine merger and subsequent integration of its operations. Certain of these transaction-related expenses are not tax deductible. (f)Represents elimination of the noncontrolling interest portion of certain adjustments included above. 59 Table of Contents Results of Operations Three Months Ended June 30,$ Change Six Months Ended June 30,$ Change 2026202520262025 Operating revenues$7,504 $6,101 $1,403 $18,626 $12,889 $5,737 Operating expenses Purchased power and fuel4,023 3,132 891 10,375 7,516 2,859 Operating and maintenance2,253 1,617 636 4,033 3,162 871 Depreciation and amortization443 254 189 886 502 384 Taxes other than income taxes207 147 60 436 307 129 Total operating expenses6,926 5,150 1,776 15,730 11,487 4,243 2 2 16 16 580 951 (371)2,912 1,402 1,510 Other income and (deductions) Interest expense, net(283)(118)(165)(536)(264)(272) Other, net603 440 163 649 286 363 Total other income and (deductions)320 322 (2)113 22 91 Income (loss) before income taxes 900 1,273 (373)3,025 1,424 1,601 Income tax (benefit) expense 398 440 (42)928 462 466 Equity in income (losses) of unconsolidated affiliates 6 6 14 14 Net income (loss) 508 833 (325)2,111 962 1,149 Net income (loss) attributable to noncontrolling interests (5)(6)1 8 5 3 Net income (loss) attributable to common shareholders $513 $839 $(326)$2,103 $957 $1,146 Three Months Ended June 30, 2026 Compared to Three Months Ended June 30, 2025. The variance in Net income (loss) attributable to common shareholders was unfavorable by ($326) million primarily due to: Unfavorable net unrealized losses on economic hedges; Unfavorable Calpine merger and integration costs; and Unfavorable impacts from nuclear outages. The unfavorable items were partially offset by: Favorable net market and portfolio conditions primarily driven by higher capacity revenues partially offset by lower CMC program revenue; and Addition of Calpine operations acquired in January 2026, inclusive of the impacts of purchase accounting. See Note 2 Mergers, Acquisitions, and Dispositions of the Combined Notes to Consolidated Financial Statements for additional information. 60 Table of Contents Six Months Ended June 30, 2026 Compared to Six Months Ended June 30, 2025. The variance in Net income (loss) attributable to common shareholders was favorable by $1,146 million primarily due to: Addition of Calpine operations acquired in January 2026, inclusive of the impacts of purchase accounting. See Note 2 Mergers, Acquisitions, and Dispositions of the Combined Notes to Consolidated Financial Statements for additional information; Favorable net market and portfolio conditions primarily driven by higher capacity revenues partially offset by lower CMC program revenue; Favorable decommissioning-related activities primarily driven by the Q1 2026 nuclear ARO update. See Note 9 Asset Retirement Obligations of the Combined Notes to Consolidated Financial Statements for additional information; and Lower net unrealized loss on equity investments. The favorable items were partially offset by: Unfavorable Calpine merger and integration costs; and Unfavorable impacts from nuclear outages. Operating revenues. Our six reportable segments are Mid-Atlantic, Midwest, New York, ERCOT, Other Power Regions, and Calpine. See Note 5 Segment Information of the Combined Notes to Consolidated Financial Statements for additional information on these reportable segments. With the exception of Calpine's natural gas sales, which are included in the Calpine segment, wholesale and retail sales of natural gas, as well as sales of other energy-related products and sustainable solutions and other miscellaneous business activities that are not significant to overall results of operations, are reported under Other and not allocated to a segment. For the three and six months ended June 30, 2026 compared to 2025, Operating revenues were as follows: Three Months Ended June 30,Six Months Ended June 30, 20262025$ Change % Change20262025$ Change % Change Mid-Atlantic$1,555 $1,448 $107 7.4 %$3,402 $3,113 $289 9.3 % Midwest1,568 1,524 44 2.9 %3,300 2,928 372 12.7 % New York564 535 29 5.4 %1,133 1,097 36 3.3 % ERCOT446 464 (18)(3.9)%816 862 (46)(5.3)% Other Power Regions964 1,178 (214)(18.2)%2,450 2,734 (284)(10.4)% Calpine2,147 2,147 100.0 %4,541 4,541 100.0 % Total reportable segment revenues7,244 5,149 2,095 40.7 %15,642 10,734 4,908 45.7 % Other580 866 (286)(33.0)%1,989 2,356 (367)(15.6)% Unrealized gains (losses)(a) (320)86 (406)(a)995 (201)1,196 (a) Total Operating revenues$7,504 $6,101 $1,403 23.0 %$18,626 $12,889 $5,737 44.5 % __________ (a)% Change in unrealized gains (losses) is not a meaningful measure. 61 Table of Contents Sales and Supply Sources. Our sales and supply volumes (GWhs) by segment are summarized below: Three Months Ended June 30,Six Months Ended June 30, (GWhs) 20262025Change % Change20262025Change % Change Nuclear Generation(a) Mid-Atlantic12,676 12,263 413 3.4 %26,002 25,440 562 2.2 % Midwest23,112 23,760 (648)(2.7)%46,086 47,356 (1,270)(2.7)% New York6,336 6,632 (296)(4.5)%12,351 12,913 (562)(4.4)% ERCOT 2,036 2,515 (479)(19.0)%4,388 5,044 (656)(13.0)% Total Nuclear Generation44,160 45,170 (1,010)(2.2)%88,827 90,753 (1,926)(2.1)% Natural Gas, Oil, and Renewables(a) Mid-Atlantic611 810 (199)(24.6)%1,351 1,442 (91)(6.3)% Midwest273 258 15 5.8 %617 643 (26)(4.0)% 3,742 3,206 536 16.7 %6,480 6,290 190 3.0 % Other Power Regions1,109 1,286 (177)(13.8)%2,852 3,090 (238)(7.7)% Calpine 24,914 24,914 100.0 %51,411 51,411 100.0 % Total Natural Gas, Oil, and Renewables30,649 5,560 25,089 451.2 %62,711 11,465 51,246 447.0 % Purchased Power Mid-Atlantic 3,063 3,750 (687)(18.3)%7,157 8,544 (1,387)(16.2)% Midwest394 475 (81)(17.1)%811 963 (152)(15.8)% 640 837 (197)(23.5)%1,326 1,495 (169)(11.3)% Other Power Regions8,181 9,849 (1,668)(16.9)%17,496 20,844 (3,348)(16.1)% Calpine 2,728 2,728 100.0 %4,817 4,817 100.0 % Total Purchased Power15,006 14,911 95 0.6 %31,607 31,846 (239)(0.8)% Total Supply/Sales by Segment Mid-Atlantic16,350 16,823 (473)(2.8)%34,510 35,426 (916)(2.6)% Midwest23,779 24,493 (714)(2.9)%47,514 48,962 (1,448)(3.0)% New York6,336 6,632 (296)(4.5)%12,351 12,913 (562)(4.4)% ERCOT 6,418 6,558 (140)(2.1)%12,194 12,829 (635)(4.9)% Other Power Regions9,290 11,135 (1,845)(16.6)%20,348 23,934 (3,586)(15.0)% Calpine 27,642 27,642 100.0 %56,228 56,228 100.0 % Total Supply/Sales by Segment89,815 65,641 24,174 36.8 %183,145 134,064 49,081 36.6 % __________ (a)Includes the proportionate share of output where we have an undivided ownership interest in jointly-owned generating plants. 62 Table of Contents Nuclear Fleet Capacity Factor. The following table presents nuclear fleet operating data for our plants that reflects our ownership percentage for stations operated by us and excludes Salem and STP, which are operated by PSEG and STPNOC, respectively. The nuclear fleet capacity factor presented in the table is defined as the ratio of the actual output of a unit (or combination of units) over a period of time to its output if the unit had operated at net monthly mean capacity for that time period. We consider capacity factor to be a useful measure to analyze the nuclear fleet performance between periods. We have included the analysis below as a complement to the financial information provided in accordance with GAAP. However, these measures are not a presentation defined under GAAP and may not be comparable to other companies presentations or be more useful than the GAAP information provided elsewhere in this report. Three Months Ended June 30,Six Months Ended June 30, 2026202520262025 Nuclear fleet capacity factor93.0 %94.8 %92.7 %94.5 % Refueling outage days86 41 185 129 Non-refueling outage days20 22 20 22 Equivalent Forced Outage Factor (Natural Gas, Oil, and Pumped-storage Hydro). As a result of our expanded fleet following the acquisition of Calpine in January 2026, we now consider EFOF to be a key operational metric beginning in 2026. EFOF represents the percentage for which a generating unit is not available due to forced outages and forced deratings in a given period. We consider EFOF to be a useful measure in analyzing the reliability and performance of our natural gas, oil, and pumped-storage hydro fleet. The EFOF for the three and six months ended June 30, 2026 was 6.2% and 5.2%, respectively. This operational metric is being included as a complement to the financial information provided in accordance with GAAP. However, as an operational metric, it may not be calculated or presented in a manner comparable to similar metrics used by other companies. Electricity Prices. As a producer and supplier of electricity, the price of electricity has a significant impact on our operating revenues and purchased power cost. We report the sale and purchase of electricity in the spot market on a net hourly basis in either Operating revenues or Purchased power and fuel expense based on our net hourly position. We assess the net position by ISO/RTO across segments and, where applicable, by segment within the ISO/RTO. The price of electricity is impacted by several variables, including but not limited to, the price of fuels, generation resources in the geographic region, weather, ongoing competition, emerging technologies, as well as macroeconomic and regulatory factors. The following table presents an average day-ahead around-the-clock reference price ($/MWh) for the periods presented for zones/hubs in each ISO/RTO where we have significant activity. This does not reflect prices we ultimately realized. Three Months Ended June 30,Six Months Ended June 30, ISO/RTO 20262025$ Change % Change20262025$ Change % Change PJM - PJM West $51.40 $42.43 $8.97 21.1 %$74.28 $48.06 $26.22 54.6 % PJM - ComEd 29.32 31.09 (1.77)(5.7)%40.01 33.20 6.81 20.5 % NYISO - Central 40.51 37.40 3.11 8.3 %76.37 56.36 20.01 35.5 % ERCOT - North 29.58 32.75 (3.17)(9.7)%35.12 32.07 3.05 9.5 % ERCOT - Houston32.62 36.95 (4.33)(11.7)%35.59 34.34 1.25 3.6 % ISO-NE - Southeast Massachusetts 48.18 40.31 7.87 19.5 %83.50 72.53 10.97 15.1 % CAISO - NP15 17.28 26.62 (9.34)(35.1)%23.14 33.79 (10.65)(31.5)% 63 Table of Contents Capacity Prices. We participate in capacity auctions in each ISO/RTO where we have qualifying generating assets. We also incur capacity costs associated with load served, which are factored into customer sales prices. Capacity prices have a material impact on our operating revenues and purchased power and fuel expense. We report capacity on a net monthly basis in either Operating revenues or Purchased power and fuel expense. We assess the net position by ISO/RTO across segments and, where applicable, by segment within the ISO/RTO. The following table presents the average capacity prices ($/MW Day) for each ISO/RTO in which we have significant activity. Prices reflect the weighted average prices for the various auction periods within the three and six months ended June 30, 2026 and 2025. We also enter into bilateral capacity contracts at negotiated contract prices. These contracts primarily relate to resource adequacy in CAISO and have a material impact on our operating revenues. Negotiated contract prices from these bilateral contracts are not included in the table below. Three Months Ended June 30,Six Months Ended June 30, ISO/RTO 20262025$ Change % Change20262025$ Change % Change PJM - Eastern Mid-Atlantic Area Council $289.67 $125.71 $163.96 130.4 %$279.80 $89.65 $190.15 212.1 % PJM - ComEd 289.67 109.25 180.42 165.1 %279.80 69.09 210.71 305.0 % NYISO - Rest of State 195.67 132.89 62.78 47.2 %154.00 109.61 44.39 40.5 % ISO-NE - Rest of Pool(a) 84.99 83.17 1.82 2.2 %84.68 82.87 1.81 2.2 % __________ (a)We did not have significant activity at this zone for the three months ended June 30, 2025. ZEC Prices. We are compensated through state programs for the emissions-free attributes of our nuclear generation. The following table includes the average ZEC reference prices ($/MWh) for each state and associated segment in which state programs have been enacted. Gross prices reflect the weighted average price for the various delivery periods within the three and six months ended June 30, 2026 and 2025 and may not necessarily reflect prices we ultimately realized as a result of interaction with the nuclear PTC discussed below. Three Months Ended June 30,Six Months Ended June 30, State (Segment)(a) 20262025$ Change % Change20262025$ Change % Change New Jersey (Mid-Atlantic)(b) $ $10.00 $(10.00)(100.0)%$ $10.00 $(10.00)(100.0)% Illinois (Midwest) 1.12 6.64 (5.52)(83.1)%1.15 8.01 (6.86)(85.6)% New York (New York)14.76 14.76 %14.76 16.52 (1.76)(10.7)% __________ (a)See ITEM 1. BUSINESS, Environmental Matters and Regulation of our 2025 Form 10-K for additional information on the plants receiving payments through state programs. (b)The New Jersey ZEC program concluded in May 2025. Illinois CMC Price. The price received (paid) for each CMC is determined by the IPA monthly by subtracting energy and capacity index prices from the bid price, which resulted in $33.43 per MWh for the period June 2024 through May 2025, $33.50 per MWh for the period June 2025 through May 2026, and $34.50 per MWh for the period June 2026 through May 2027. If the monthly CMC price per MWh calculation results in a net positive value, ComEd will multiply that value by the delivered quantity and pay the total to us. If the CMC price per MWh calculation results in a net negative value, we will multiply this value by the delivered quantity and pay the net value to ComEd. The average CMC prices per MWh were ($5.91) and ($0.42) for the three months ended June 30, 2026 and 2025, respectively, and ($16.05) and ($1.23) for the six months ended June 30, 2026 and 2025, respectively. The average CMC prices may not necessarily reflect prices we ultimately realized as a result of interaction with the nuclear PTC discussed below. 64 Table of Contents Nuclear PTC. 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 and is subject to phase-out when annual gross receipts are between $26.00 per MWh and $44.75 per MWh for 2025 and 2026. Both the amount of the PTC and the gross receipts thresholds adjust for inflation annually through the duration of the program based on the GDP price deflator for the preceding calendar year. Many of the state-sponsored programs (e.g., ZECs and CMCs) providing compensation for the emissions-free attributes of generation from certain of our nuclear units include contractual or other provisions that require us to refund that compensation up to the amount of the nuclear PTC received or pass through the entirety of the nuclear PTC received. See Note 6 Government Assistance of the Combined Notes to Consolidated Financial Statements for additional information on the nuclear PTC. The following table summarizes the impacts to Operating revenues related to the benefits of nuclear PTC and state-sponsored programs subject to refund or pass through as described above for the three and six months ended June 30, 2026 compared to 2025: Three Months Ended June 30,Six Months Ended June 30, 20262025$ Change % Change20262025$ Change % Change Nuclear PTC revenue(a) $15 $45 $(30)(66.7)%$25 $45 $(20)(44.4)% State-sponsored programs net revenue(b) 10 75 (65)86.7 %(275)190 (465)(244.7)% __________ (a)Our estimate required the exercise of judgment in determining the amount of nuclear PTC expected for each of our nuclear units. Refer to Note 6 Government Assistance of the Combined Notes to Consolidated Financial Statements for additional information. (b)Includes only state-sponsored programs that have 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. For the three and six months ended June 30, 2026 compared to 2025, changes in Operating revenues by segment were approximately as follows: Three Months Ended June 30Six Months Ended June 30 $ Change% ChangeDescription$ Change% ChangeDescription Mid-Atlantic$107 7.4 % favorable retail load revenue of $160 primarily due to higher contracted energy prices; partially offset by unfavorable realized economic hedges of $90 due to settled prices relative to hedged prices$289 9.3 % favorable retail load revenue of $470 primarily due to higher contracted energy prices favorable wholesale load revenue of $145 primarily due to higher contracted energy prices, partially offset by lower load volumes; partially offset by unfavorable realized economic hedges of $305 due to settled prices relative to hedged prices 65 Table of Contents Three Months Ended June 30Six Months Ended June 30 $ Change% ChangeDescription$ Change% ChangeDescription Midwest44 2.9 % favorable retail load revenue of $110 primarily due to higher contracted energy prices favorable net capacity revenue of $65 primarily due to higher prices; partially offset by unfavorable ZEC program revenue of $135 primarily due to lower revenue recognized for Illinois ZECs delivered in prior planning years372 12.7 % favorable net generation and wholesale load revenue of $410 primarily due to higher energy prices and higher load volumes, partially offset by lower generation volumes favorable retail load revenue of $325 primarily due to higher contracted energy prices and higher load volumes favorable net capacity revenue of $155 primarily due to higher prices favorable realized economic hedges of $85 due to settled prices relative to hedged prices; partially offset by unfavorable CMC program revenue of $400 primarily due to higher energy and capacity prices unfavorable ZEC program revenue of $175 primarily due to lower revenue recognized for Illinois ZECs delivered in prior planning years and decrease in ZEC price New York29 5.4 % no individually significant drivers36 3.3 % favorable net generation revenue of $125 associated with the sale of generation volumes relative to purchased power to supply load primarily due to higher energy prices favorable retail load revenue of $50 primarily due to higher contracted energy prices, partially offset by lower load volumes; partially offset by unfavorable realized economic hedges of $90 due to settled prices relative to hedged prices ERCOT(18)(3.9)% no individually significant drivers(46)(5.3)% no individually significant drivers Other Power Regions(214)(18.2)% unfavorable wholesale load revenue of $105 and retail load revenue of $100 primarily due to lower load volumes in New England(284)(10.4)% unfavorable wholesale load revenue of $230 primarily due to lower load volumes in New England unfavorable retail load revenue of $100 primarily due to lower load volumes in New England and lower energy prices in the West 66 Table of Contents Three Months Ended June 30Six Months Ended June 30 $ Change% ChangeDescription$ Change% ChangeDescription Calpine2,147 100.0 % represents the operating revenues associated with our Calpine segment4,541 100.0 % represents the operating revenues associated with our Calpine segment since the date of acquisition Other(286)(33.0)% current year includes unfavorable amortization of $205 associated with certain commodity contracts related to the Calpine acquisition unfavorable retail gas revenue of $60 primarily due to lower gas prices(367)(15.6)% current year includes unfavorable amortization of $420 associated with certain commodity contracts related to the Calpine acquisition unfavorable revenues in the United Kingdom, inclusive of realized economic hedges, of $70 primarily due to lower energy prices; partially offset by favorable retail gas revenue of $100 primarily due to higher gas prices Unrealized gains or losses(a)(b) (406)(a) losses on economic hedging activities of $320 in 2026 compared to gains of $86 in 2025, inclusive of Calpine 1,196 (a) gains on economic hedging activities of $995 in 2026 compared to losses of $201 in 2025, inclusive of Calpine Total$1,403 23.0 %$5,737 44.5 % __________ (a)% Change in unrealized gains or losses is not a meaningful measure. (b)See Note 12 Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information on unrealized gains and losses. 67 Table of Contents Purchased power and fuel. See Operating revenues above for discussion of our reportable segments and hedging strategies and for supplemental statistical data, including sales and supply sources by segment, nuclear fleet capacity factor, EFOF, capacity prices, and electricity prices. With the exception of Calpine's natural gas activity, which is included in the Calpine segment, wholesale and retail natural gas activity, as well as other miscellaneous business activities that are not significant to overall results of operations are reported under Other and are not allocated to a segment. For the three and six months ended June 30, 2026 compared to 2025, Purchased power and fuel expense were as follows: Three Months Ended June 30,Six Months Ended June 30, 20262025$ Change % Change20262025$ Change % Change Mid-Atlantic$567 $666 $(99)(14.9)%$1,602 $1,522 $80 5.3 % Midwest589 488 101 20.7 %1,469 1,042 427 41.0 % New York174 138 36 26.1 %335 299 36 12.0 % ERCOT162 193 (31)(16.1)%323 377 (54)(14.3)% Other Power Regions677 997 (320)(32.1)%1,896 2,359 (463)(19.6)% Calpine 1,119 1,119 100.0 %2,388 2,388 100.0 % Total segment purchased power and fuel3,288 2,482 806 32.5 %8,013 5,599 2,414 43.1 % Other615 731 (116)(15.9)%1,989 1,963 26 1.3 % Unrealized losses (gains)(a) 120 (81)201 (a)373 (46)419 (a) Total purchased power and fuel$4,023 $3,132 $891 28.4 %$10,375 $7,516 $2,859 38.0 % __________ (a)% Change in unrealized losses (gains) is not a meaningful measure. Natural Gas Prices. As an owner-operator of a large fleet of natural gas-fired generation facilities, the cost of our natural gas supply has a significant impact on our Purchased power and fuel expense. The following table summarizes the average daily reference price ($/MMBtu) for the periods presented in each geographic region where we have significant activity. This does not reflect prices we ultimately realized. Three Months Ended June 30,Six Months Ended June 30, Location20262025$ Change% Change20262025$ Change% Change Henry Hub$2.93 $3.16 $(0.23)(7.3)%$3.91 $3.71 $0.20 5.4 % Transco Zone 6(a) 2.13 2.40 (0.27)(11.3)%5.78 4.22 1.56 37.0 % Houston Ship Channel(b) 2.45 2.74 (0.29)(10.6)%2.85 3.10 (0.25)(8.1)% PG&E Citygate(c) 1.55 2.81 (1.26)(44.8)%1.81 3.26 (1.45)(44.5)% Algonquin Citygate(d) 2.37 2.86 (0.49)(17.1)%8.19 7.32 0.87 11.9 % __________ (a)Transcontinental Gas pipeline located in Mid-Atlantic region. (b)Houston-area pipeline and industrial network located in ERCOT region. (c)Pacific Gas & Electric Company virtual trading point located in West region. (d)Algonquin Gas Transmission physical delivery point located in New England region. 68 Table of Contents For the three and six months ended June 30, 2026 compared to 2025, changes in Purchased power and fuel expense by segment were approximately as follows: Three Months Ended June 30Six Months Ended June 30 $ Change% ChangeDescription$ Change% ChangeDescription Mid-Atlantic$(99)(14.9)% favorable realized economic hedges of $85 due to settled prices relative to hedged prices favorable $65 due to financial transmission rights overfunding in 2026; partially offset by unfavorable $60 associated with purchased power to supply load, net of generation, primarily due to higher energy prices and higher prices associated with net capacity costs$80 5.3 % unfavorable $405 associated with purchased power to supply load, net of generation, primarily due to higher energy prices, higher prices associated with net capacity costs, and higher costs related to an extreme weather event in January 2026; partially offset by favorable realized economic hedges of $275 due to settled prices relative to hedged prices favorable $65 due to financial transmission rights overfunding in 2026 Midwest101 20.7 % unfavorable $80 associated with purchased power to supply load, net of generation, primarily due to higher net transmission costs427 41.0 % unfavorable $390 associated with purchased power to supply load, net of generation, primarily due to higher costs related to a significant weather event in January 2026 and net transmission costs New York36 26.1 % no individually significant drivers36 12.0 % no individually significant drivers ERCOT(31)(16.1)% no individually significant drivers(54)(14.3)% no individually significant drivers Other Power Regions(320)(32.1)% favorable $150 associated with purchased power to supply load primarily due to lower load volumes in New England, and lower load volumes and energy prices in the West favorable $120 primarily associated with environmental product sales favorable realized economic hedges of $55 due to settled prices relative to hedged prices (463)(19.6)% favorable $230 associated with purchased power to supply load primarily due to lower load volumes in New England, and lower energy prices in the West favorable $140 associated with environmental product sales and lower environmental obligations favorable realized economic hedges of $80 due to settled prices relative to hedged prices Calpine1,119 100.0 % represents the purchased power and fuel associated with our Calpine segment2,388 100.0 % represents the purchased power and fuel associated with our Calpine segment since the date of acquisition 69 Table of Contents Three Months Ended June 30Six Months Ended June 30 $ Change% ChangeDescription$ Change% ChangeDescription Other(116)(15.9)% favorable net wholesale gas purchases of $60, inclusive of realized economic hedges, primarily due to lower gas prices26 1.3 % unfavorable net wholesale gas purchases of $115, inclusive of realized economic hedges, primarily due to higher gas prices favorable purchases in the United Kingdom, inclusive of realized economic hedges, of $65 primarily due to lower energy prices Unrealized gains or losses(a)(b) 201 (a) losses on economic hedging activities of $120 in 2026 compared to gains of $81 in 2025, inclusive of Calpine 419 (a) losses on economic hedging activities of $373 in 2026 compared to gains of $46 in 2025, inclusive of Calpine Total$891 28.4 %$2,859 38.0 % __________ (a)% Change in unrealized gains or losses is not a meaningful measure. (b)See Note 12 Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information on unrealized gains and losses. The changes in Operating and maintenance expense consisted of the following: 2026 vs. 2025 Three Months Ended June 30,Six Months Ended June 30, Increase (Decrease) Labor, contracting, and materials(a) $228 $404 Calpine merger and integration costs 87 211 Nuclear refueling outage costs(b) 68 119 Changes in legal and environmental liabilities48 47 Decommissioning-related activities 4 (268) Other(c) 201 358 Total increase$636 $871 __________ (a)Primarily reflects increased employee-related costs, including labor and other incentives, as well as higher contracting expense, driven in large part by the addition of Calpine's operations beginning in January 2026. (b)Includes the co-owned Salem and STP generating units (c)Primarily includes administrative expenses such as information technology, regulatory fees, facilities and rentals, and insurance. The increase is driven primarily by the addition of Calpine's operations beginning in January 2026. Depreciation and amortization expense increased by $189 million for the three months ended June 30, 2026 compared to the same period in 2025, and increased by $384 million for the six months ended June 30, 2026 compared to the same period in 2025, primarily due to the additional depreciation and amortization associated with assets acquired from Calpine beginning in January 2026. See Note 2 Mergers, Acquisitions, and Dispositions of the Combined Notes to Consolidated Financial Statements for additional information. Interest expense, net increased by $165 million for the three months ended June 30, 2026 compared to the same period in 2025, and increased by $272 million for the six months ended June 30, 2026 compared to the same period in 2025, primarily due to a net increase in outstanding debt as a result of the debt assumed and related financing transactions following the acquisition of Calpine in January 2026. See Note 13 Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information. 70 Table of Contents Other, net was favorable for the three and six months ended June 30, 2026 compared to the same period in 2025, due to activity described in the table below: Income (Deductions) Three Months Ended June 30,Six Months Ended June 30, 2026202520262025 Decommissioning-related activities(a) $598 $437 $657 $531 Net unrealized gains (losses) from equity investments(b) 3 (7)(24)(275) Other 2 10 16 30 Other, net$603 $440 $649 $286 __________ (a)Includes net realized and net unrealized gains (losses) on NDT fund investments, the elimination of decommissioning-related activities, and the elimination of income taxes related to all NDT fund activity for the Regulatory Agreement Units. See Note 9 Asset Retirement Obligations and Note 18 Supplemental Financial Information of the Combined Notes to Consolidated Financial Statements for additional information. (b)Includes unrealized gains (losses) resulting from an equity investment in a publicly traded company. We record the fair value of this investment in Other deferred debits and other assets in the Consolidated Balance Sheets based on quoted market price of the stock. Effective income tax rates were 44.2% and 34.6% for the three months ended June 30, 2026 and 2025, respectively, and 30.7% and 32.4% for the six months ended June 30, 2026 and 2025, respectively. The increase in effective tax rate for the three months ended was primarily due to higher qualified NDT fund income in the second quarter of 2026 which is taxed at a higher rate. The decrease in effective tax rate for the six months ended was primarily due to proportionally lower qualified NDT fund income in 2026 which is taxed at a higher rate as well as a decrease in share-based payment awards. See Note 10 Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information. Liquidity and Capital Resources All results included throughout the liquidity and capital resources section are presented on a GAAP basis. Our operating and capital expenditures requirements are provided by internally generated cash flows from operations as well as funds from external sources in the capital markets and through bank borrowings. Our business is capital intensive and requires considerable capital resources. Annually, we evaluate our financing plan and credit line sizing, focusing on maintaining our investment grade ratings while meeting our cash needs to fund capital requirements, including construction expenditures, retire debt, pay dividends, fund pension and OPEB obligations, and invest in new and existing ventures, such as our acquisition of Calpine and planned restart of Crane. A broad spectrum of financing alternatives beyond the core financing options can be used to meet our needs and fund growth, including monetizing assets in the portfolio via project financing, asset sales, and the use of other financing structures (e.g., issuing equity, joint ventures, minority partners, etc.). Our access to external financing on reasonable terms depends on our credit ratings and current overall capital market business conditions. If these conditions deteriorate to the extent that we no longer have access to the capital markets at reasonable terms, we have access to credit facilities with aggregate bank commitments of $14.5 billion. We utilize our credit facilities to support our commercial paper programs, provide for other short-term borrowings and to issue letters of credit. See the Credit Matters and Cash Requirements section below for additional information. We expect cash flows to be sufficient to meet operating expenses, financing costs, and capital expenditure requirements. See Note 13 Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information. 71 Table of Contents Cash Flow Activities The following table summarizes our cash flow activities for the six months ended June 30, 2026 and 2025, respectively: Six Months Ended June 30, 20262025$ Change Cash, restricted cash, and cash equivalents at beginning of period $3,748 $3,129 $619 Net cash provided by (used in): Operating activities1,553 1,584 (31) Investing activities(5,101)(1,758)(3,343) Financing activities877 (893)1,770 Net increase (decrease) in cash, restricted cash, and cash equivalents (2,671)(1,067)(1,604) $1,077 $2,062 $(985) Net Cash Provided By (Used In) Operating Activities Cash provided by operating activities was $1,553 million and $1,584 million for the six months ended June 30, 2026 and 2025, respectively. Changes in our cash flows from operations were generally consistent with changes in results of operations, as adjusted for changes in working capital in the normal course of business. Included in net cash provided by operating activities for the six months ended June 30, 2026, are refunds to state programs associated with nuclear PTCs. See Note 6 Government Assistance of the Combined Notes to Consolidated Financial Statements for additional information. Net Cash Provided By (Used In) Investing Activities Cash used in investing activities was ($5,101) million and ($1,758) million for the six months ended June 30, 2026 and 2025, respectively. The change is primarily related to cash paid, net of cash acquired, for the Calpine acquisition and an increase in capital expenditures related to the planned restart of Crane, inclusion of Calpine, and co-location infrastructure. See Note 2 Mergers, Acquisitions, and Dispositions of the Combined Notes to Consolidated Financial Statements for additional information. Net Cash Provided By (Used In) Financing Activities Cash provided by financing activities was $877 million for the six months ended June 30, 2026, compared to cash used in financing activities of ($893) million for the six months ended June 30, 2025. The change primarily relates to long-term debt and changes in short-term borrowings. Debt issuances and redemptions or repayments vary each year. For the six months ended June 30, 2026, these activities reflect the impact of debt transactions associated with the acquisition of Calpine. The remaining change is related to repurchases of common stock. See Note 13 Debt and Credit Agreements and Note 16 Shareholders' Equity of the Combined Notes to Consolidated Financial Statements for additional information. Quarterly dividends declared by our Board of Directors during 2026 were as follows: PeriodDeclaration DateShareholder of Record DateDividend Payable DateCash per Share First Quarter of 2026 February 20, 2026March 9, 2026March 20, 2026$0.4265 Second Quarter of 2026 April 28, 2026May 15, 2026June 5, 20260.4265 Third Quarter of 2026 August 4, 2026August 18, 2026September 4, 20260.4265 QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK (Dollars in millions, unless otherwise noted) We are exposed to market risks associated with adverse changes in commodity prices, counterparty credit, interest rates, and equity prices. We manage these risks through risk management policies and objectives for risk assessment, control and valuation, counterparty credit approval, and the monitoring and reporting of risk exposures. The Executive Committee and the Audit and Risk Committee of the Board of Directors have oversight responsibilities for risk management. The following discussion serves as an update to ITEM 7A QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK of our 2025 Annual Report on Form 10-K incorporated herein by reference. Commodity Price Risk Commodity price risk is associated with price movements resulting from changes in supply and demand, fuel costs, market liquidity, weather conditions, governmental, regulatory and environmental policies, and other factors. To the extent the total 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 commodity prices. We seek to mitigate our commodity price risk through the sale and purchase of electricity, natural gas and oil, and other commodities. Electricity available from our owned or contracted generation supply in excess of our obligations to customers is sold into the wholesale markets. To reduce commodity price risk caused by market fluctuations, we enter into non-derivative contracts as well as derivative contracts, including swaps, futures, forwards, and options, with approved counterparties to hedge anticipated exposures in locations and periods where our load serving activities do not naturally offset existing generation portfolio risk. Portfolio hedging activities are generally concentrated in the prompt three years, when customer demand and market liquidity enable effective price risk mitigation. We expect the settlement of the majority of our economic hedges will occur during 2026 through 2028. We also enter into transactions that further optimize the economic benefits of our overall portfolio. 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 of the Combined Notes to Consolidated Financial Statements for additional information. 75 Table of Contents The forecasted market price risk exposure is the risk of a change in the value of unhedged positions. The forecasted market price risk exposure as of June 30, 2026 for our portfolio associated with a hypothetical $10/MWh reduction in the annual average around-the-clock energy price and $5/MWh reduction in around-the-clock spark spread results in an impact to earnings that is not material for 2026 and 2027. See Note 12 Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information. Fuel Procurement We procure natural gas through long-term and short-term contracts, and spot-market purchases. We also enter into natural gas transportation and storage contracts that allow us to source reliable and cost-effective natural gas for our fleet and to take advantage of favorable market pricing, regardless of when the gas is used in our operations. Fuel oil inventories are managed so that, in the winter months, sufficient volumes of fuel are available in the event of extreme weather conditions and during the remaining months to take advantage of favorable market pricing. Nuclear fuel is obtained predominantly through long-term contracts for uranium concentrates, conversion services, enrichment services, (or a combination thereof) and fabrication services, including contracts sourced from Russia. The supply markets for uranium concentrates and certain nuclear fuel services are subject to price fluctuations and availability restrictions. Supply market conditions may make our procurement contracts subject to credit risk related to the potential non-performance of counterparties to deliver the contracted commodity or service at the contracted prices. We engage a diverse set of suppliers to secure the nuclear fuel needed to continue to operate our nuclear fleet long-term. Approximately 30% of our uranium concentrate requirements for the remainder of 2026 through 2031 are supplied by three suppliers. To-date, we have not experienced any counterparty credit risk associated with these suppliers stemming from the Russia and Ukraine conflict. In the event of non-performance by these or other suppliers, we believe that replacement uranium concentrate can be obtained, although at prices that may be unfavorable when compared to the prices under the current supply agreements. Geopolitical developments, including the Russia and Ukraine conflict and United States, United Kingdom, European Union, and Canadian sanctions against Russia, have the potential to impact delivery from multiple suppliers in the international uranium processing industry. Non-performance by these counterparties could have a material adverse impact on our consolidated financial statements. See ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS Other Key Business Drivers for additional information on the Russia and Ukraine conflict. Commodity Derivative Activity The following table provides detail on changes in our commodity derivative contract net assets (liabilities) balance sheet position from December 31, 2025 to June 30, 2026. This table incorporates the unrealized gains and losses that are immediately recorded in earnings. This table excludes all NPNS contracts. See Note 12 Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information on the balance sheet classification of the commodity derivative contract net assets (liabilities) recorded as of June 30, 2026 and December 31, 2025. Balance as of December 31, 2025(a) $504 Net change in fair value of contracts recorded in results of operations 898 Reclassification to realized at settlement of contracts recorded in results of operations(274) Changes in allocated collateral335 Contracts acquired at acquisition date(b) 1,403 Amortization of acquired contracts(b) (423) Net option premium paid (received)52 Option premium amortization30 Upfront payments and amortizations(c) (4) Foreign currency translation(1) Balance as of June 30, 2026(a) $2,520 __________ (a)Amounts are shown net of collateral paid to and received from counterparties. (b)Includes amounts related to contracts acquired as part of the Calpine acquisition in January 2026. See Note 2 Mergers, Acquisitions, and Dispositions of the Combined Notes to Consolidated Financial Statements for additional information. 76 Table of Contents (c)Includes derivative contracts acquired or sold through upfront payments or receipts of cash, excluding option premiums, and the associated amortizations. Fair Values The following table presents maturity and source of fair value for commodity derivative contract net assets (liabilities). See Note 14 Fair Value of Financial Assets and Liabilities of the Combined Notes to Consolidated Financial Statements for additional information regarding fair value measurements and the fair value hierarchy. Maturities WithinTotal Fair Value 202620272028202920302031 and Beyond Commodity derivative contracts(a): Actively quoted prices (Level 1)$81 $(110)$(32)$(11)$1 $5 $(66) Prices provided by external sources (Level 2)601 327 24 (29) 923 Prices based on model or other valuation methods (Level 3)223 425 426 190 96 303 1,663 Total$905 $642 $418 $150 $97 $308 $2,520 __________ (a)Amounts are shown net of collateral paid to and received from counterparties (and offset against derivative assets and liabilities) of $2,283 million at June 30, 2026. Credit Risk We would be exposed to credit-related losses in the event of non-performance by counterparties that execute derivative instruments. The credit exposure of derivative contracts, before collateral, is represented by the fair value of contracts at the reporting date. See Note 12 Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for a detailed discussion of credit risk. Credit-Risk-Related Contingent Features As part of the normal course of business, we routinely enter into physically or financially settled contracts for the purchase and sale of capacity, electricity, fuels, emissions allowances, and other energy-related products. In accordance with the contracts and applicable law, if we are downgraded by a credit rating agency, especially if such downgrade is to a level below investment grade, it is possible that a counterparty would attempt to rely on such a downgrade as a basis for making a demand for adequate assurance of future performance. Depending on our net position with a counterparty, the demand could be for the posting of collateral. 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. See Note 12 Derivative Financial Instruments and Note 15 Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for additional information regarding the letters of credit supporting the cash collateral. We sell output through bilateral contracts. The bilateral contracts are subject to credit risk, which relates to the ability of counterparties to meet their contractual payment obligations. Any failure to collect these payments from counterparties could have a material impact on our consolidated financial statements. As market prices rise above or fall below contracted price levels, we are required to post collateral with purchasers; as market prices fall below contracted price levels, counterparties are required to post collateral with us. To post collateral, we depend on access to bank credit facilities, which serve as liquidity sources to fund collateral requirements. See ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS, Liquidity and Capital Resources Credit Matters and Cash Requirements Credit Facilities for additional information. 77 Table of Contents RTOs and ISOs We participate in all of the established wholesale energy markets that are administered by PJM, ISO-NE, NYISO, CAISO, MISO, SPP, AESO, OIESO, and ERCOT. ERCOT is not subject to regulation by FERC but performs a similar function in Texas to that performed by RTOs and ISOs in markets regulated by FERC. In these areas, power and related products are traded through bilateral agreements between buyers and sellers and in the energy markets that are administered by the RTOs or ISOs, as applicable. In areas where there is no RTO or ISO to administer energy markets, electricity and related products are purchased and sold primarily through bilateral agreements. For activities administered by an RTO or ISO, the RTO or ISO maintains financial assurance policies that are established and enforced by those administrators. The credit policies of the RTOs and ISOs may, under certain circumstances, require that losses arising from the default of one member be shared by the remaining participants. Non-performance or non-payment by a major member of an RTO or ISO could result in a material adverse impact on our consolidated financial statements. Exchange Traded Transactions We enter into commodity transactions on NYMEX, ICE, NASDAQ, NGX, and the Nodal exchange (each an Exchange and, collectively, Exchanges). The Exchange clearinghouses act as the counterparty to each trade. Transactions on the Exchanges must adhere to comprehensive collateral and margining requirements. As a result, transactions on Exchanges are significantly collateralized and have limited counterparty credit risk. Interest Rate Risk We use a combination of fixed-rate and variable-rate debt to manage interest rate exposure. We may also utilize interest rate swaps to manage our interest rate exposure, including derivatives to lock in rate levels in anticipation of future financings. A hypothetical 50 basis points change in interest rates associated with unhedged variable-rate long-term debt and interest rate swaps would not have resulted in a material impact to our earnings for the six months ended June 30, 2026. See Note 12 Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information. Equity Price Risk We maintain trust funds, as required by the NRC, to fund the costs of decommissioning our nuclear plants. Our NDT funds are reflected at fair value in the Consolidated Balance Sheets. The mix of securities in the trust funds is designed to provide returns to be used to fund decommissioning and to compensate us for inflationary increases in decommissioning costs; however, the equity securities in the trust funds are exposed to price fluctuations in equity markets, and the value of fixed-rate, fixed-income securities are exposed to changes in interest rates. We actively monitor the investment performance of the trust funds and periodically review asset allocations in accordance with our NDT fund investment policy. A hypothetical 25 basis points increase in interest rates and 10% decrease in equity prices would have resulted in a $1,129 million reduction in the fair value of our NDT trust assets as of June 30, 2026. This calculation holds all other variables constant and assumes only the discussed changes in interest rates and equity prices. See Note 9 Asset Retirement Obligations of the Combined Notes to Consolidated Financial Statements and Liquidity and Capital Resources section of ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS for additional information. Our employee benefit plan trusts also hold investments in equity and debt securities. See ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS Critical Accounting Policies and Estimates of our 2025 Form 10-K for further information. 78 Table of Contents PART II. OTHER INFORMATION (Dollars in millions except per share data, unless otherwise noted) ITEM 1. LEGAL PROCEEDINGS We are parties to various lawsuits and regulatory proceedings in the ordinary course of business. For information regarding material lawsuits and proceedings, see Note 3 Regulatory Matters and Note 15 Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements in PART I, ITEM 1. FINANCIAL STATEMENTS of this report. Such descriptions are incorporated herein by these references. ITEM 1A. RISK FACTORS At June 30, 2026, our risk factors were consistent with the risk factors described in our 2025 Form 10-K in ITEM 1A. RISK FACTORS which was inclusive of the risks related to the Calpine acquisition and its operations. ITEM 2.UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS Issuer Purchases of Equity Securities (CEG Parent) During 2026, our Board of Directors approved a $4.4 billion increase relative to the remaining $0.6 billion authorization under our share repurchase program. No other repurchase plans or programs have been authorized. As of the date of this filing, we have approximately $2.8 billion of remaining authority for repurchases. See Note 16 Shareholders' Equity of the Combined Notes to Consolidated Financial Statements for additional information regarding our share repurchase program. No accelerated share repurchases occurred under the program during the six months ended June 30, 2026. The following table provides information regarding our share repurchases under the program during the three months ended June 30, 2026. PeriodTotal Number of Shares Purchased(a) Average Price Paid per ShareApproximate Dollar Value of Shares that May Yet Be Purchased Under the Programs(b) April 1, 2026 to April 30, 2026(c) 1,175,521 $284.75 $4,658 May 1, 2026 to May 31, 2026(c) 2,088,837 276.71 4,080 June 1, 2026 to June 30, 2026(c)(d) 3,873,974 273.10 3,022 Total7,138,332 $276.08 $3,022 __________ (a)We have not made any purchases of shares other than in connection with the publicly announced share repurchase program described above. (b)Approximate dollar value of shares that may yet be purchased under the program includes taxes and commissions. (c)Includes repurchases under open market repurchase agreements. See Note 16 Shareholders' Equity of the Combined Notes to Consolidated Financial Statements for additional information. (d)Includes repurchases under secondary public offering. See Note 2 Mergers, Acquisitions, and Dispositions of the Combined Notes to Consolidated Financial Statements for additional information. ITEM 4.MINE SAFETY DISCLOSURES Not Applicable. 79 Table of Contents ITEM 5.OTHER INFORMATION Rule 10b5-1 Trading Plans Except as set forth below, during the three months ended June 30, 2026, none of our directors or executive officers (as defined in Rule 16a-1 under the Exchange Act) adopted or terminated any contract, instruction or written plan for the purchase or sale of our securities that was intended to satisfy the affirmative defense conditions of Rule 10b5-1(c) or any "non-Rule 10b5-1 trading arrangement" (as defined in Item 408 under Regulation S-K of the Exchange Act). On May 18, 2026, Andrew Novotny, Senior Executive Vice President, Constellation Power Operations, and President and CEO, Calpine, entered into a stock trading plan designed to comply with Rule 10b5-1 under the Exchange Act. Under the terms of the plan, Mr. Novotny is scheduled to sell an aggregate of 118,915 shares of common stock in trades scheduled from August 2026 through January 2027. The plan will terminate on January 15, 2027. ITEM 6.EXHIBITS Certain of the following exhibits are incorporated herein by reference under Rule 12b-32 of the Exchange Act. Exhibit No.Description 4.1 Form of 4.550% Senior Notes due June 1, 2029 (File No. 333-85496, Form 8-K dated May 14, 2026, Exhibit 4.1) 4.2 Form of 4.800% Senior Notes due January 15, 2032 (File No. 333-85496, Form 8-K dated May 14, 2026, Exhibit 4.2) 4.3 Form of 5.300% Senior Notes due June 1, 2036 (File No. 333-85496, Form 8-K dated May 14, 2026, Exhibit 4.3) Certifications Pursuant to Rule 13a-14(a) and 15d-14(a) of the Exchange Act as to the Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2026 filed by the following officers for the following registrants: Exhibit No.Description 31.1 Filed by Joseph Dominguez for Constellation Energy Corporation 31.2 Filed by Shane P. Smith for Constellation Energy Corporation 31.3 Filed by Joseph Dominguez for Constellation Energy Generation, LLC 31.4 Filed by Shane P. Smith for Constellation Energy Generation, LLC Certifications Pursuant to Section 1350 of Chapter 63 of Title 18 United States Code as to the Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2026 filed by the following officers for the following registrants: Exhibit No.Description 32.1 Filed by Joseph Dominguez for Constellation Energy Corporation 32.2 Filed by Shane P. Smith for Constellation Energy Corporation 32.3 Filed by Joseph Dominguez for Constellation Energy Generation, LLC 32.4 Filed by Shane P. Smith for Constellation Energy Generation, LLC 80 Table of Contents Exhibit No.Description 101.INSInline XBRL Instance Document - the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document. 101.SCHInline XBRL Taxonomy Extension Schema Document. 101.CALInline XBRL Taxonomy Extension Calculation Linkbase Document. 101.DEFInline XBRL Taxonomy Extension Definition Linkbase Document. 101.LABInline XBRL Taxonomy Extension Label Linkbase Document. 101.PREInline XBRL Taxonomy Extension Presentation Linkbase Document. 104Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101) ITEM 4.CONTROLS AND PROCEDURES Disclosure Controls and Procedures During the second quarter of 2026, our principal executive officer and principal financial officer, evaluated the effectiveness of our disclosure controls and procedures related to the recording, processing, summarizing, and reporting of information in periodic reports that we file or submit with the SEC. These disclosure controls and procedures have been designed to ensure that (a) information relating to our consolidated subsidiaries, is accumulated and made known to our management, including our principal executive officer and principal financial officer, by other employees as appropriate to allow timely decisions regarding required disclosure, and (b) this information is recorded, processed, summarized, and reported, as applicable, within the time periods specified in the SEC's rules and forms. Due to the inherent limitations of control systems, not all misstatements may be detected. These inherent limitations include the realities that judgments in decision-making can be faulty and that breakdowns can occur because of simple error or mistake. Additionally, controls could be circumvented by the individual acts of some persons or by collusion of two or more people. Accordingly, as of June 30, 2026, our principal executive officer and principal financial officer concluded that our disclosure controls and procedures were effective to accomplish their objectives. Changes in Internal Control Over Financial Reporting We continually strive to improve our disclosure controls and procedures to enhance the quality of our financial reporting and to maintain dynamic systems that change as conditions warrant. There have been no changes in internal control over financial reporting that occurred during the second quarter of 2026 that have materially affected, or are reasonably likely to materially affect, any of our internal control over financial reporting. 81 Table of Contents SIGNATURES Pursuant to requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized. CONSTELLATION ENERGY CORPORATION /s/ JOSEPH DOMINGUEZ/s/ SHANE P. SMITH Joseph DominguezShane P. Smith President and Chief Executive Officer (Principal Executive Officer) Executive Vice President and Chief Financial Officer (Principal Financial Officer) /s/ MATTHEW N. BAUER Matthew N. Bauer Senior Vice President and Controller (Principal Accounting Officer) August 6, 2026 82 Table of Contents Pursuant to requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized. CONSTELLATION ENERGY GENERATION, LLC /s/ JOSEPH DOMINGUEZ/s/ SHANE P. SMITH Joseph DominguezShane P. Smith President and Chief Executive Officer (Principal Executive Officer)Executive Vice President and Chief Financial Officer (Principal Financial Officer) /s/ MATTHEW N. BAUER Matthew N. Bauer Senior Vice President and Controller (Principal Accounting Officer) August 6, 2026 83