Constellation Energy Corp 10-K

ceg-20251231 UNITED STATES SECURITIES AND EXCHANGE COMMISSION WASHINGTON, D.C. 20549 FORM 10-K ☒ ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the Fiscal Year Ended December 31 , 2025 or ☐ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 Commission File Number Name of Registrant; State or Other Jurisdiction of Incorporation; Address of Principal Executive Offices; and Telephone Number IRS Employer Identification Number 001-41137 CONSTELLATION ENERGY CORPORATION 87-1210716 (a Pennsylvania corporation) 1310 Point Street Baltimore , Maryland 21231-3380 (833) 883-0162 333-85496 CONSTELLATION ENERGY GENERATION, LLC 23-3064219 (a Pennsylvania limited liability company) 200 Energy Way Kennett Square , Pennsylvania 19348-2473 (833) 883-0162 Securities registered pursuant to Section 12(b) of the Act: Title of each class Trading Symbol(s) Name of each exchange on which registered CONSTELLATION ENERGY CORPORATION: Common Stock, without par value CEG The Nasdaq Stock Market LLC Securities registered pursuant to Section 12(g) of the Act: None Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Constellation Energy Corporation Yes x No ☐ Constellation Energy Generation, LLC Yes ☐ No x Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Constellation Energy Corporation Yes ☐ No x Constellation Energy Generation, LLC Yes ☐ No x Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Constellation Energy Corporation Yes x No ☐ Constellation Energy Generation, LLC Yes x No ☐ Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes ý No ¨ 2 Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act. Constellation Energy Corporation Large Accelerated Filer x Accelerated Filer ☐ Non-accelerated Filer ☐ Smaller Reporting Company ☐ Emerging Growth Company ☐ Constellation Energy Generation, LLC Large Accelerated Filer ☐ Accelerated Filer ☐ Non-accelerated Filer x Smaller Reporting Company ☐ Emerging Growth Company ☐ If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. o Indicate by check mark whether the registrant has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act by the registered public accounting firm that prepared or issued its audit report. ☒ If securities are registered pursuant to Section 12(b) of the Act, indicate by check mark whether the financial statements of the registrant included in the filing reflect the correction of an error to previously issued financial statements. o Indicate by check mark whether any of those error corrections are restatements that required a recovery analysis of incentive-based compensation received by any of the registrant’s executive officers during the relevant recovery period pursuant to §240.10D-1(b). o Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes ☐ No x The estimated aggregate market value of the voting and non-voting common equity held by nonaffiliates of each registrant as of June 30, 2025 was as follows: Constellation Energy Corporation $ 100,560,269,473 Constellation Energy Generation, LLC Not applicable The number of shares outstanding of each registrant’s common stock as of February 1, 2026 was as follows: Constellation Energy Corporation Common Stock, without par value 361,990,335 Constellation Energy Generation, LLC Not applicable Documents Incorporated by Reference Portions of the Registrants’ Definitive Proxy Statement relating to the 2026 Annual Meeting of Shareholders are incorporated by reference into Part III of this report. The Registrants expect to file the Definitive Proxy Statement with the Securities and Exchange Commission within 120 days after December 31, 2025. 3 TABLE OF CONTENTS Page No. GLOSSARY OF TERMS AND ABBREVIATIONS 1 FILING FORMAT 6 CAUTIONARY STATEMENTS REGARDING FORWARD-LOOKING INFORMATION 6 AVAILABLE INFORMATION 6 PART I ITEM 1. BUSINESS 7 General 7 Strategy and Outlook 21 Environmental Matters and Regulation 23 Employees 27 ITEM 1A. RISK FACTORS 29 ITEM 1B. UNRESOLVED STAFF COMMENTS 45 ITEM 1C. CYBERSECURITY 45 ITEM 2. PROPERTIES 47 ITEM 3. LEGAL PROCEEDINGS 49 ITEM 4. MINE SAFETY DISCLOSURES 49 PART II ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS, AND ISSUER PURCHASES OF EQUITY SECURITIES 50 ITEM 6. RESERVED 51 ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS 52 Executive Overview 52 Significant Transactions and Developments 52 Other Key Business Drivers 53 Critical Accounting Policies and Estimates 54 Financial Results of Operations 62 Liquidity and Capital Resources 71 ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK 78 ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA 82 Management's Report on Internal Control Over Financial Reporting 82 Report of Independent Registered Public Accounting Firm 83 Constellation Energy Corporation 87 Constellation Energy Generation, LLC 91 Combined Notes to Consolidated Financial Statements 95 1. Basis of Presentation 95 2. Mergers, Acquisitions, and Dispositions 101 3. Regulatory Matters 102 4. Revenue from Contracts with Customers 104 5. Segment Information 106 6. Government Assistance 108 7. Accounts Receivable 109 8. Property, Plant, and Equipment 110 9. Jointly-Owned Electric Plants 111 10. Asset Retirement Obligations 111 4 11. Leases 116 12. Intangible Assets 118 13. Income Taxes 119 14. Retirement Benefits 123 15. Derivative Financial Instruments 131 16. Debt and Credit Agreements 136 17. Fair Value of Financial Assets and Liabilities 142 18. Commitments and Contingencies 150 19. Shareholders' Equity 155 20. Stock-Based Compensation Plans 157 21. Variable Interest Entities 159 22. Supplemental Financial Information 161 ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE 165 ITEM 9A. CONTROLS AND PROCEDURES 165 ITEM 9B. OTHER INFORMATION 165 ITEM 9C. DISCLOSURE REGARDING FOREIGN JURISDICTIONS THAT PREVENT INSPECTIONS 165 PART III ITEM 10. DIRECTORS, EXECUTIVE OFFICERS, AND CORPORATE GOVERNANCE 166 ITEM 11. EXECUTIVE COMPENSATION 167 ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS 168 ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR INDEPENDENCE 168 ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES 168 PART IV ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES 169 ITEM 16. FORM 10-K SUMMARY 177 SIGNATURES 178 Constellation Energy Corporation 178 Constellation Energy Generation, LLC 179 5 Table of Contents GLOSSARY OF TERMS AND ABBREVIATIONS Constellation Energy Corporation and Related Entities CEG Parent Constellation Energy Corporation Constellation Constellation Energy Generation, LLC Registrants CEG Parent and Constellation, collectively Antelope Valley Antelope Valley Solar Ranch One Calpine Calpine Corporation Calvert Cliffs Calvert Cliffs nuclear generating station Continental Wind Continental Wind LLC CENG Constellation Energy Nuclear Group, LLC CR Constellation Renewables, LLC Crane Crane Clean Energy Center (formerly known as Three Mile Island Unit 1) CRP Constellation Renewables Partners, LLC FitzPatrick James A. FitzPatrick nuclear generating station Ginna R. E. Ginna nuclear generating station LaSalle LaSalle nuclear generating station NER NewEnergy Receivables LLC NMP Nine Mile Point nuclear generating station RPG Renewable Power Generation, LLC STP South Texas Project nuclear generating station West Medway II West Medway Generating Station II Former Related Entities Exelon Exelon Corporation ComEd Commonwealth Edison Company PECO PECO Energy Company BGE Baltimore Gas and Electric Company 1 Table of Contents GLOSSARY OF TERMS AND ABBREVIATIONS Other Terms and Abbreviations ABO Accumulated Benefit Obligation AEP Texas American Electric Power Texas, Inc. AESO Alberta Electric Systems Operator AI Artificial Intelligence AOCI Accumulated Other Comprehensive Income (Loss) APBO Accumulated Postretirement Benefit Obligation ARC Asset Retirement Cost ARO Asset Retirement Obligation ASR Accelerated Share Repurchase Atomic Energy Act Atomic Energy Act of 1954, as amended Bcf Billion cubic feet C&I Commercial and Industrial CAISO California ISO CARFR Credit-Adjusted, Risk-Free Rates CBAs Collective Bargaining Agreements CCUS Carbon Capture, Utilization, and Storage CenterPoint CenterPoint Energy Houston Electric, LLC CERCLA Comprehensive Environmental Response, Compensation, and Liability Act of 1980, as amended CHIPS and Science Act CHIPS and Science Act of 2022 Clean Air Act Clean Air Act of 1963, as amended Clean Energy Law Illinois Public Act 102-0062 signed into law on September 15, 2021 Clean Water Act Federal Water Pollution Control Amendments of 1972, as amended CMC Carbon Mitigation Credit CO2 Carbon Dioxide CODM Chief Operating Decision Maker CORe+ Constellation Offsite Renewables CWIP Construction Work In Progress DOE United States Department of Energy DOJ United States Department of Justice DPP Deferred Purchase Price EEI Edison Electric Institute EFEC Emissions-Free Energy Certificate EMT Everett Marine Terminal EPA United States Environmental Protection Agency ERCOT Electric Reliability Council of Texas ERISA Employee Retirement Income Security Act of 1974, as amended EROA Expected Rate of Return on Assets ERM ERM International Group Limited ERP Enterprise Resource Program EV Electric Vehicle Exchange Act Securities Exchange Act of 1934. as amended Federal Power Act Federal Power Act of 1920, as amended 2 Table of Contents GLOSSARY OF TERMS AND ABBREVIATIONS Other Terms and Abbreviations FERC Federal Energy Regulatory Commission Former ComEd Units Braidwood, Byron, Dresden, LaSalle and Quad Cities nuclear generating units Former PECO Units Limerick, Peach Bottom, and Salem nuclear generating units FRCC Florida Reliability Coordinating Council GAAP Generally Accepted Accounting Principles in the United States GDP Gross Domestic Product Geysers Assets Geothermal power plant assets acquired through Calpine, including steam extraction and gathering assets GHG Greenhouse Gas GW Gigawatt GWh Gigawatt hour ICC Illinois Commerce Commission ICE Intercontinental Exchange IPA Illinois Power Agency IRA Inflation Reduction Act of 2022 IRS Internal Revenue Service ISO Independent System Operator ISO-NE ISO New England Inc. ITC Investment Tax Credit kWh Kilowatt-hour LIBOR London Interbank Offered Rate LLRW Low-Level Radioactive Waste LTIP Long-Term Incentive Plan MDE Maryland Department of the Environment MISO Midcontinent Independent System Operator, Inc. MMBtu Million Btu Moody's Moody’s Investors Service, Inc. MRV Market-Related Value MW Megawatt MWh Megawatt-hour Mystic COS Mystic Cost of Service Agreement N/A Not applicable NASDAQ Nasdaq Stock Market, LLC NAV Net Asset Value NDT Nuclear Decommissioning Trust NEIL Nuclear Electric Insurance Limited NERC North American Electric Reliability Corporation NGX Natural Gas Exchange, Inc. NJDEP New Jersey Department of Environmental Protection Non-Regulatory Agreement Units Nuclear generating units or portions thereof whose decommissioning-related activities are not subject to contractual elimination under regulatory accounting NPDES National Pollutant Discharge Elimination System NPNS Normal Purchase Normal Sale scope exception NRC Nuclear Regulatory Commission 3 Table of Contents GLOSSARY OF TERMS AND ABBREVIATIONS Other Terms and Abbreviations NYISO New York ISO NYMEX New York Mercantile Exchange NYPSC New York Public Service Commission OBBBA One Big Beautiful Bill Act of 2025 OCI Other Comprehensive Income (Loss) OIESO Ontario Independent Electricity System Operator OPEB Other Postretirement Employee Benefits PAPUC Pennsylvania Public Utility Commission PBO Projected Benefit Obligation Pension Protection Act (the Act) Pension Protection Act of 2006 PG&E Pacific Gas and Electric Company PJM PJM Interconnection, LLC PP&E Property, Plant, and Equipment PPA Power Purchase Agreement Price-Anderson Act Price-Anderson Nuclear Industries Indemnity Act of 1957 PRP Potentially Responsible Parties PSEG Public Service Enterprise Group Incorporated PTC Production Tax Credit PUCT Public Utility Commission of Texas PV Photovoltaic RCF Revolving credit facility RCRA Resource Conservation and Recovery Act of 1976, as amended REC Renewable Energy Certificate (Credit), which is the environmental attribute associated with each megawatt hour of production from a qualified renewable energy source Regulatory Agreement Units Nuclear generating units or portions thereof whose decommissioning-related activities are subject to contractual elimination under regulatory accounting (includes the Former ComEd units, the Former PECO units, and STP) RIN Renewable Identification Number RMP Risk Management Policy RNF Operating Revenues Net of Purchased Power and Fuel Expense RNG Renewable Natural Gas ROU Right-of-use RPS Renewable Portfolio Standards RTO Regional Transmission Organization S&P Standard & Poor’s Ratings Services SEC United States Securities and Exchange Commission SERC SERC Reliability Corporation (formerly Southeast Electric Reliability Council) SNF Spent Nuclear Fuel SOA Society of Actuaries SOFR Secured Overnight Financing Rate SPDES State Pollutant Discharge Elimination System SPP Southwest Power Pool STEM Science, Technology, Engineering, and Mathematics 4 Table of Contents GLOSSARY OF TERMS AND ABBREVIATIONS Other Terms and Abbreviations STPNOC STP Nuclear Operating Company TEF Texas Energy Fund TMA Tax Matters Agreement TWh Terawatt-hour U.S. Court of Appeals for the D.C. Circuit United States Court of Appeals for the District of Columbia Circuit U.S. Treasury U.S. Department of the Treasury UEC Unamortized Energy Contract VIE Variable Interest Entity WECC Western Electric Coordinating Council ZEC Zero Emission Credit 5 Table of Contents FILING FORMAT This combined Annual Report on Form 10-K is being filed separately by Constellation Energy Corporation and Constellation Energy Generation, LLC, (the Registrants). Information contained herein relating to any individual Registrant is filed by the Registrant on its own behalf. Neither Registrant makes any representation as to information relating to the other Registrant. CAUTIONARY STATEMENTS REGARDING FORWARD-LOOKING INFORMATION This report contains certain forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995 that are subject to risks and uncertainties. Words such as “could,” “may,” “expects,” “anticipates,” “will,” “targets,” “goals,” “projects,” “intends,” “plans,” “believes,” “seeks,” “estimates,” “predicts,” and variations on such words, and similar expressions that reflect our current views with respect to future events and operational, economic and financial performance, are intended to identify such forward-looking statements. These forward-looking statements include, but are not limited to, statements regarding the acquisition of Calpine Corporation, the pro forma combined company and its operations, strategies and plans, enhancements to investment-grade credit profile, synergies, opportunities and anticipated future performance and capital structure, and expected accretion to earnings per share and free cash flow. Information adjusted for the acquisition should not be considered a forecast of future results. Forward-looking statements are based on current expectations, estimates and assumptions that involve a number of risks and uncertainties that could cause actual results to differ materially from those projected. The factors that could cause actual results to differ materially from the forward-looking statements made by us include those factors discussed herein, including those factors discussed in (a) Part I, ITEM 1A. Risk Factors, (b) Part II, ITEM 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations, (c) Part II, ITEM 8. Financial Statements and Supplementary Data: Note 18 — Commitments and Contingencies, and (d) other factors discussed in filings with the SEC by the Registrants. Readers are cautioned not to place undue reliance on these forward-looking statements, which apply only as of the date of this report. Neither Registrant undertakes any obligation to publicly release any revision to its forward-looking statements to reflect events or circumstances after the date of this report. AVAILABLE INFORMATION The SEC maintains an Internet site at www.sec.gov that contains reports, proxy and information statements, and other information that we file electronically with the SEC. We file our Annual Report on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K, and all amendments to those reports with the SEC. In addition, as soon as reasonably practicable after such materials are furnished to the SEC, we make copies of these documents available to the public free of charge through our website at www.ConstellationEnergy.com. Information contained on our website shall not be deemed incorporated into, or to be a part of, this report. 6 Table of Contents PART I ITEM 1. BUSINESS General On February 21, 2021, the Board of Directors of Exelon authorized management to pursue a plan to separate its competitive generation and customer-facing energy businesses, conducted through Constellation and its subsidiaries, into an independent, publicly traded company. CEG Parent, a Pennsylvania corporation and a direct, wholly owned subsidiary of Exelon, was newly formed for the purpose of separation and had not engaged in any activities except in preparation for the distribution. On February 1, 2022, Exelon completed the separation by distributing all the outstanding shares of the Company’s common stock, on a pro rata basis to the holders of Exelon’s common stock, with the Company holding all the interests in Constellation previously held by Exelon (the “Separation”). As of 2002, Constellation has been an individual registrant concurrent with the registration of its public debt under the Securities Act. As an individual registrant, Constellation has historically filed consolidated financial statements to reflect their financial position and operating results as a stand-alone, wholly owned subsidiary of Exelon. Unless otherwise indicated or the context otherwise requires, references herein to the terms “we,” “our,” “us” and “the Company” refer collectively to CEG Parent and Constellation. See Glossary for defined terms. On January 7, 2026, Constellation acquired all of the outstanding equity interests of Calpine in a cash and stock transaction. Unless otherwise noted, information in this Form 10-K excludes Calpine. For further information regarding the transaction, refer to Note 2 — Mergers, Acquisitions, and Dispositions of the Combined Notes to Consolidated Financial Statements. Our Business Following the merger with Calpine in January 2026, we are the largest private-sector power producer in the world and the nation’s largest producer of clean and reliable energy. With 55 GWs of capacity from nuclear, natural gas, 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 three-fourths 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. After considering divestitures connected with certain regulatory approvals, our merger with Calpine added approximately 23 GWs across 72 generation and battery storage assets, providing reliable power resources in areas experiencing significant demand growth. Calpine is the nation’s largest generator of electricity from natural gas and geothermal resources, according to S&P Global Market Intelligence, with a strong footprint in Texas, California, and the Northeast regions of the U.S. Natural gas‑fired generation remains an essential component of the U.S. energy transition due to its low emissions profile, high reliability, and potential for future emissions‑abatement technologies. Calpine’s portfolio also includes solar and battery storage assets, strengthening our ability to deliver a balanced mix of baseload, intermediate, and peak generation necessary to maintain reliability of the electrical grid. The high-quality and geographic concentration of Calpine’s dispatchable fleet complements our existing portfolio and enhances our ability to meet growing demand for clean, reliable power nationwide. Calpine's retail energy platform adds approximately 62 TWhs of annual load to our business, and allows us to expand our C&I and residential customer base, creating incremental sales channels across the country. With the addition of Calpine, we add approximately 2,500 employees who are dedicated to operational excellence and a shared commitment to serving customers. Refer to Note 2 — Mergers, Acquisitions, and Dispositions of the Combined Notes to Consolidated Financial Statements for additional information on our acquisition of Calpine. 7 Table of Contents Our Operations We operate the largest emissions-free generation fleet in the nation and are one of the largest competitive electric generation companies in the nation, as measured by owned and contracted MWs. Our fleet is the cleanest large generation portfolio in the country according to the 2025 ERM Report: Benchmarking Air Emissions of the 100 Largest Electric Power Producers in the United States. At December 31, 2025, our owned generating resources had a total capacity of 31,676 MWs, consisting of the following: __________ (a) Net generation capacity is stated at proportionate ownership share. See ITEM 2. PROPERTIES for additional information. (b) Includes wind, hydroelectric, and solar generating assets. In addition to the owned generating resources above, at December 31, 2025, we had contracted generation with a total capacity of 4,798 MWs, which represents electric supply procured under unit-specific agreements. 8 Table of Contents The following map illustrates the locations of our owned generation facilities as of December 31, 2025: Our Owned Generation Fleet Map (a)(b) Owned Assets __________ (a) One symbol is included per location. Some locations may have multiple generating units. Locations in tight geographic proximity may appear as one symbol. Units that are not currently operational are not captured. (b) Does not reflect Grand Prairie Generating Station (Gas/Other), located in Alberta, Canada. 9 Table of Contents We have five reportable segments, as described in the table below, representing the different geographic regions in which our owned generating resources are located and our customer-facing activities are conducted. Segment (a) Net Generation Capacity (MWs) (b) % of Net Generation Capacity Geographic Regions Mid-Atlantic 10,386 33 % 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 11,606 37 % Western half of PJM and the United States footprint of MISO, excluding MISO’s Southern Region New York 3,093 10 % NYISO ERCOT 4,742 15 % Electric Reliability Council of Texas Other Power Regions 1,849 5 % New England, South, West, and Canada Total 31,676 100 % __________ (a) See Note 5 — Segment Information of the Combined Notes to Consolidated Financial Statements for additional information on reportable segments. (b) Net generation capacity is stated at proportionate ownership share as of December 31, 2025. See ITEM 2. PROPERTIES for additional information. The following table shows our total owned sources of electric supply of 204,944 GWhs and 208,434 GWhs for 2025 and 2024, respectively, which includes the proportionate share of output where we have an undivided ownership interest in jointly-owned generating plants. _________ (a) Includes wind, hydroelectric, and solar generating assets. In addition to the owned generation above, we also had purchased power from the spot energy markets that are administered by the RTOs/ISOs and bilateral transactions of 63,999 GWhs and 60,983 GWhs for the years ended December 31, 2025 and 2024, respectively. See ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS for additional information on electric supply sources. 10 Table of Contents Nuclear Facilities Our nuclear fleet is the nation’s largest, with current generating capacity of approximately 22 GWs, producing 183 TWhs of zero-emissions electricity during 2025 – enough to power 16 million homes and avoid more than 122 million metric tons of carbon emissions according to the EPA GHG Equivalencies Calculator. We have ownership interests in 14 nuclear generating stations currently in service, consisting of 25 units. As of December 31, 2025, we wholly own all our nuclear generating stations, except for undivided ownership interests in five jointly-owned nuclear stations: Quad Cities (75% ownership), Peach Bottom (50% ownership), Salem (42.59% ownership), NMP Unit 2 (82% ownership), and STP (44% ownership), that are reflected in our consolidated financial statements relative to our proportionate ownership interest in each unit. See ITEM 2. PROPERTIES for additional information on our nuclear facilities. In September 2024, we executed a 20-year PPA with Microsoft that will support the restart of Three Mile Island Unit 1, renamed as the Crane Clean Energy Center, which was retired in 2019 for economic reasons. Under the agreement, Microsoft will purchase the output generated from the renewed plant which includes energy, capacity and emissions-free attributes as part of its goal to help power its data centers in PJM with clean reliable energy. The site, once operational, will have approximately 835 MWs of emissions-free capacity. The timing of the restart is subject to certain regulatory approvals, interconnection-related construction, permitting, and obtaining a renewed operating license. In November 2025, the DOE Office of Energy Dominance Financing issued a guarantee for up to $1.0 billion as an unsecured loan to support the restart of the Crane Clean Energy Center. See Note 16 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information. We operate all of our nuclear generating stations, except for the units at Salem and STP, which are operated by PSEG Nuclear, LLC (an indirect, wholly owned subsidiary of PSEG) and STPNOC, respectively. We have consistently operated our nuclear plants at best-in-class levels. During 2025, 2024, and 2023, our nuclear generating facilities achieved capacity factors (a) of 94.7%, 94.6%, and 94.4%, respectively, at ownership percentage. The nuclear capacity factor has been approximately four percentage points better than the industry average annually since 2013. Capacity factors, which are significantly affected by the number and duration of refueling and non-refueling outages, can have a material impact on our results of operations. In 2025, we achieved an average refueling outage duration of 22 days for units we operate. We achieved an average refueling outage duration of 19 and 21 days in 2024 and 2023, respectively, against industry averages of 33 and 38 days, respectively. We manage our scheduled refueling outages to minimize their duration and to maintain high nuclear generating capacity factors, resulting in a stable supply position for our wholesale and retail power marketing activities. In 2025, 2024, and 2023, electric supply (in GWhs) generated from our nuclear generating facilities was 68%, 67%, and 65%, respectively, of our total electric supply. During scheduled refueling outages, we perform maintenance and equipment upgrades in order to maintain safe, reliable operations and to minimize the occurrence of unplanned outages. In addition to the maintenance and equipment upgrades performed by us during scheduled refueling outages, we have extensive operating and security procedures in place to ensure the safe operation of our nuclear units. We also have extensive safety systems in place to protect the plant, personnel, and surrounding area in the unlikely event of an accident or other incident. __________ (a) Capacity factor 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. See ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS — Financial Results of Operations for additional information. 11 Table of Contents All of our nuclear units were originally licensed by the NRC for 40 years and have since received 20-year operating license renewals. Additionally, PSEG and STPNOC have received 20-year license renewals for the Salem and STP units, respectively. Peach Bottom and Dresden have received subsequent license renewal from the NRC for a second 20-year term, extending their operating period to a total 80-year term. We plan to pursue a subsequent license renewal for Crane in 2029. PSEG has also announced plans to pursue a subsequent license renewal for Salem in 2027. See Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information on Peach Bottom's subsequent license renewal. The following table summarizes the current license expiration dates for our nuclear facilities currently in service: Station Unit In-Service Date (a) Current License Expiration Braidwood 1 1988 2046 2 1988 2047 Byron 1 1985 2044 2 1987 2046 Calvert Cliffs 1 1975 2034 2 1977 2036 Clinton 1 1987 2047 Dresden 2 1970 2049 3 1971 2051 FitzPatrick 1 1975 2034 LaSalle 1 1984 2042 2 1984 2043 Limerick 1 1986 2044 2 1990 2049 NMP 1 1969 2029 2 1988 2046 Peach Bottom 2 1974 2053 3 1974 2054 Quad Cities 1 1973 2032 2 1973 2032 Ginna 1 1970 2029 Salem 1 1977 2036 2 1981 2040 STP 1 1988 2047 2 1989 2048 __________ (a) Denotes year in which nuclear unit began commercial operations. Following recent improvements by the NRC, the operating license renewal process takes approximately three years from commencement, which includes approximately two years for us to develop the application and approximately 12 months for the NRC to review the application. Future rulemaking could further reduce the timelines for developing and reviewing the application. Depreciation provisions correspond with the expiration of the current NRC operating license denoted in the table above, except for Braidwood, Byron, LaSalle, NMP Unit 1, Quad Cities, Ginna, and Salem, which are based on the estimated useful lives of the stations including expectations for an additional 20-year term beyond current license expiration. See Note 3 — Regulatory Matters and Note 8 — Property, Plant, and Equipment of the Combined Notes to Consolidated Financial Statements for additional information. While the table above provides the date through which we are licensed to operate our nuclear plants, we may choose to retire certain plants earlier than the license expiration date if the economics do not support our continued operation of those plants. 12 Table of Contents Natural Gas and Oil Facilities We operate approximately 7 GWs of natural gas and oil-fueled generation assets which provide a mix of baseload, intermediate, and peak power generation. We wholly own all our natural gas and oil facilities except for Wyman, which is operated by the principal owner, NextEra Energy Resources LLC, a subsidiary of NextEra Energy, Inc. See ITEM 2. PROPERTIES for additional information regarding these generating facilities. Natural gas and oil generation plants are generally not licensed, and therefore, the decision on when to retire plants is, fundamentally, a commercial one. In 2025, 2024, and 2023, electric supply (in GWhs) generated from our owned natural gas and oil generating facilities was 6%, 8%, and 9%, respectively, of our total electric supply. Our natural gas and oil fleet has similarly demonstrated a track record of strong performance with a Dispatch Match (a) of 97.9%, 97.4%, and 98.5% in 2025, 2024, and 2023, respectively. With our acquisition of Calpine in January 2026, the composition of our fleet changes materially with a higher concentration of natural gas facilities. Calpine owns 21 GWs of natural gas-fired generation, primarily consisting of combined cycle gas turbine plants in the Texas, California, and Northeast regions of the United States. Calpine's modern natural gas fleet is part of the backbone of the U.S. electrical grid, enabling the transition away from coal-fired generation and supporting the growth of intermittent renewable resources while maintaining reliability. Renewable Facilities (including Hydroelectric) Our renewable portfolio includes approximately 2.6 GWs of hydroelectric, wind, and solar generation assets, of which the electric supply (in GWhs) generated in 2025, 2024, and 2023 represented 2% of our total electric supply. Our Renewables Energy Capture (b) was 96.6%, 96.1%, and 96.4% in 2025, 2024, and 2023, respectively. We wholly own our renewable facilities except for certain wind project entities and CRP. See ITEM 2. PROPERTIES for additional information regarding these generating facilities and Note 21 — Variable Interest Entities of the Combined Notes to Consolidated Financial Statements for additional information regarding CRP, which is a VIE. FERC has the exclusive authority to license most non-federal hydropower projects located on navigable waterways or federal lands, or connected to the interstate electrical grid, which include our Conowingo Hydroelectric Project (Conowingo) and Muddy Run Pumped Storage Facility Project (Muddy Run). Muddy Run's license expires on December 1, 2055 and is currently being depreciated over an estimated useful life that corresponds with the available license term. In March 2021, FERC issued a new 50-year license for Conowingo, which was subsequently vacated in December 2022. In September 2025, we reached a settlement agreement with MDE, Lower Susquehanna Riverkeeper Association, and Waterkeepers Chesapeake which allows us to move forward with resubmitting the license application with FERC. We cannot currently predict when FERC will issue the new license. Depreciation provisions continue to assume an estimated useful life through 2071 in anticipation of the license expiration date being restored. See Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information on the status of Conowingo's license. Wind and solar generation assets are generally not licensed, and therefore, the decision on when to retire plants is, fundamentally, a commercial one. __________ (a) Dispatch Match is used to measure the responsiveness of a unit to the market, expressed as the total actual energy revenue net of fuel cost relative to the total desired energy revenue net of fuel cost. Factors having an adverse effect on Dispatch Match include forced outages, derates, and failure to operate to the desired generation signal. (b) Renewable Energy Capture is an indicator of how efficiently the installed assets capture the natural energy available from the wind, the sun, and water. Renewable Energy Capture represents an energy-based fraction, the numerator of which is the energy produced by the sum of the wind turbines, solar panels, and run-of-river hydroelectric operations in the year, and the denominator of which is the total expected energy to be produced during the year, with adjustments made for certain events that are considered non-controllable, such as force majeure events, serial design-manufacturing equipment failures, and transmission curtailments. Renewable Energy Capture for the combined wind, solar, and run-of-river hydroelectric fleet is weighted by the relative site projected pre-tax variable revenue. 13 Table of Contents The acquisition of Calpine in January 2026 adds the Geysers Assets to our renewable portfolio, which is the largest geothermal power generation portfolio in the U.S., and the largest single renewable energy asset in California. The Geysers Assets consist of 13 operating geothermal plants located in Northern California, with an operating capacity of approximately 730 MWs. Calpine also contributes approximately 800 MWs of battery storage facilities to our portfolio, largely based in California. Contracted Generation In addition to energy produced by our owned generation assets, we source electricity from generators we do not own under long-term contracts. The following tables summarize our long-term contracts to purchase unit-specific physical power with an original term in excess of one year in duration, by segment, in effect as of December 31, 2025: Segment Number of Agreements Expiration Dates Capacity (MWs) Mid-Atlantic 22 2027-2045 564 Midwest 8 2026-2044 855 ERCOT 8 2026-2040 1,140 Other Power Regions 18 2026-2045 2,239 Total 56 4,798 2026 2027 2028 2029 2030 2031 and thereafter Total Capacity Expiring (MWs) 398 16 75 98 1,015 3,196 4,798 14 Table of Contents Customer-Facing Business Based on data from EEI, we are the nation’s largest energy supplier for C&I and residential power volumes. Through our integrated business operations, we sell electricity, natural gas, and other energy-related products and sustainable solutions to various types of customers, including distribution utilities, municipalities, cooperatives, and commercial, industrial, public sector, and residential customers in markets across multiple geographic regions. We serve approximately 2 million total customer accounts, including three-fourths of Fortune 100 companies, and approximately 1.4 million residential customers. We are a leader in electric power supply, serving approximately 204 TWhs in 2025 through sales to retail customers and wholesale load auctions to a geographically diverse customer base. The following table illustrates these volumes across our five reportable segments: 2025 Electric Power Supply (TWhs) Served (a ) __________ (a) Includes retail load and wholesale load auction volumes only. Electric generation in excess of our total retail and wholesale load would be sold in the respective RTO or ISO in which our facility is located. Other includes New England, South, and West. We are active in all domestic wholesale power and gas markets that span the entire lower 48 states and have complementary retail activity across many of those states. We typically obtain power supply from the market to meet our wholesale and retail obligations. Our market risk is mitigated by our owned and contracted generation located in multiple geographic regions. The commodity risks associated with the output from owned and contracted generation are managed using various commodity transactions including sales to retail customers, trades on commodity exchanges, bilateral contracts, and sales to wholesale counterparties in accordance with our hedging program. See further discussion of the hedging program in the Price and Supply Risk Management section below. The main objective is to obtain low-cost energy supply to meet physical delivery obligations to both our wholesale and retail customers. 15 Table of Contents Retail Market Retail competition in states across the U.S. range from full competition of energy suppliers for all retail customers (commercial, industrial, public sector, and residential) to partial retail competition available up to a capped amount for C&I customers only. We are a leader in retail energy supply, serving approximately 147 TWhs of electric power retail load primarily to C&I customers across multiple geographic regions in the U.S. We also served approximately 800 Bcf of gas in 2025. Geographically Diverse Footprint in Retail Market Strong customer relationships are a key part of our customer-facing business strategy, as demonstrated by our high renewal rates. Retail customer renewal rates have been strong over the last ten years across C&I power customer groups with average contract terms of approximately two years and customer duration of approximately six years, with many customers well beyond these metrics. Specifically, we enjoyed renewal rates of 77% for C&I power customers and 84% for C&I gas customers in 2025, owing to both our competitive pricing as well as our strong customer relationships. Our consistently high renewal rates are driven by our ability to provide customized solutions and deliver focused attention to our customers’ needs. We are also successful at acquiring new customers by offering innovative products and solutions that meet their needs. In addition to our high customer renewal rates, we have produced consistently high new win rates within C&I power as well, acquiring nearly one out of every three new customers who have chosen to shop with us over the past seven years. High customer satisfaction levels, market expertise, stability, and scale-driven growth have resulted in a historically proven business with consistent margins. While providing customers with a competitive price is a key focus, we leverage our broad suite of electric and gas product structures, oftentimes customized, to provide customers with the commodity solution and information that best fits their needs. It is this attention to the customer that creates the durable and repeatable value highlighted in these statistics. 16 Table of Contents Consumer purchasing strategies have trended from direct supply relationships to third-party relationships with several customers looking to third-party consultants and brokers to find suppliers like us to reduce costs and evaluate the increasing number of options available for expanding energy solutions beyond the commodity. In response, we have expanded our third-party capabilities, created scale through a comprehensive support structure, and enhanced digital applications providing tools, tracking, and measurement, as well as the ability to extend the reach of our sustainability solutions to drive additional market share. While this trend of customers using third parties to find suppliers has slowed in recent years, we have remained the market leader in direct C&I sales with over 32% of the C&I market share of direct customer business, driven by our highly experienced and long-tenor direct sales team. Wholesale Market Our wholesale channel-to-market involves the sale of electricity among electric utilities and electricity marketers before it is eventually sold to end-use consumers. In 2025, we served approximately 57 TWhs of power load across competitive utility load procurement and bilateral sales to municipalities, co-ops, and other wholesale entities. Complementary to our national retail customer portfolio, we have several decades of relationships with wholesale counterparties across all domestic power markets as a means of both monetizing our own generation, as well as sourcing contracted generation to meet customer and portfolio needs. With increased customer demand for sustainability and reliability, our ability to source contracted generation has provided a capital-light way for us to provide customers with long-term solutions they are demanding to support a clean and resilient energy ecosystem. This creates durable customer relationships and repeatable business through the ability to respond to customer and marketplace trends. Similarly, this contracting acumen provides the ability to supplement our native generation with other non-renewable assets to meet changing portfolio needs in a financially efficient manner. In our wholesale gas business, we participate across all parts of the gas value chain, including trading, transport and storage, and physical supply. Energy Solutions As one of the largest customer-facing platforms in the U.S., we benefit from significant economies of scale, that allow us to provide our customers with competitively priced energy and to structure highly tailored solutions targeted to a customer’s unique power needs and clean energy goals. Our CORe+ product serves C&I customers' sustainability needs by matching contracted, third-party new-build renewable generation with customer desire to add additional carbon-free generation to the grid with a preference to be located within the same region as their load. In 2025, we continued to see growing demand for our Hourly Carbon-Free Energy (CFE) product and platform, as we have closed several additional Hourly CFE transactions with a strong pipeline of interested prospects. Achieving 100% carbon-free power is a key sustainability goal for many organizations. As customers make the transition to 100% hourly carbon-free power, many are looking to bridge the gap between their real-time electricity demand and available sources of carbon-free power. Our Hourly CFE platform and associated products match carbon-free generation every hour with a customer’s load, along with appropriate tracking and retirement of hourly attributes in the applicable registry. Many existing CORe+ customers are converting to 100% Hourly CFE with existing nuclear filling in the gaps of the hours renewable generation is not producing. Further, we are seeing interest from large C&I customers in long-term contracting for our nuclear facilities for energy, capacity, and carbon-free attributes. In addition to larger-scale CORe+ offerings, bundled and unbundled long-term nuclear agreements, and Hourly CFE, we offer a range of sustainability solutions to customers (e.g., RECs, EFECs, RINs, RNG, carbon offsets, Demand Response, etc.) as well as offers for carbon-free generation attributes to support their needs during the transition to a carbon-free energy ecosystem. We also partner with our customers to provide energy efficiency options to meet their emissions-free energy goals. Our energy efficiency products provide the ability to optimize performance and maximize efficiency across customer facilities and operations through contract structures that include implementation of energy efficiency upgrades and behind-the-meter solutions with no upfront capital requirements. Additionally, these service offerings provide scalable solutions to meet sustainability goals through investment across the life of the facility or operations and allow for greater budget certainty. The ongoing ability to optimize energy consumption for customers allows us to support customer demands with the right combination of technology and efficiency program options. 17 Table of Contents In addition to sustainability solutions, data and analytics have also become increasingly important for our customers. Constellation Navigator delivers customized paths and sustainable solutions for customers to set and meet their environmental and energy management goals. Driven by advanced technology platforms and experienced advisors, it provides strategies to help organizations understand their baseline emissions and reduce their carbon footprints. Constellation Navigator helps businesses solve challenges across the energy lifecycle including utility bill management, carbon accounting, rebate administration, energy efficiency audits, and sustainability advisory services. These platforms and services provide new avenues for incremental growth by coupling the opportunities for customer usage optimization with accompanying products and sustainable solutions that we can provide to customers. These types of data and analytical services allow us to grow our customer base in previously inaccessible regulated markets by offering non-commodity energy-related products and sustainable solutions. We continue to look for new and innovative products and solutions to bring to our customers. Constellation Technology Ventures (CTV) is our venture investing business, focused on championing innovation and scaling breakthrough technologies. CTV invests in a broad range of companies developing products and solutions that expedite the shift towards cleaner, resilient, and sustainable forms of energy. Our portfolio spans diverse areas, and consists of both established and emerging companies looking to advance the energy industry. CTV collaborates with Constellation's operating businesses and customers, harnessing portfolio companies' strengths to propel mutual growth and value for all stakeholders. Price and Supply Risk Management We leverage a combination of wholesale and retail customer load sales, federal and state programs, as well as non-derivative and derivative contracts, all with credit-approved counterparties, to hedge the commodity price risk of our generation portfolio. 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 3 — Regulatory Matters and Note 6 — Government Assistance of the Combined Notes to Consolidated Financial Statements 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 price risk associated with our load serving contracts, non-nuclear generation, and any residual price risk for our nuclear generation that the nuclear PTC and state programs may not fully mitigate. We also enter transactions that further optimize the economic benefits of our overall portfolio. A portion of our hedging strategy may be implemented using fuel products based on assumed correlations between power and fuel prices. Our risk management group monitors the financial risks of the wholesale and retail power marketing activities. The cycle of production and utilization of nuclear fuel includes the mining and milling of uranium ore into uranium concentrates, the conversion of uranium concentrates to uranium hexafluoride, the enrichment of the uranium hexafluoride, and the fabrication of fuel assemblies. 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. We have inventory in various forms and engage a diverse set of domestic and international suppliers to secure the nuclear fuel needed to continue to operate our nuclear fleet. We manage various risks around our nuclear fuel requirements in accordance with our fuel procurement policy limiting our transactions with each supplier to mitigate concentration of risk. The size of our inventory holdings and forward contractual coverage considers our refueling needs across multiple years to protect against supply disruptions and near-term price volatility, while allowing for capital flexibility. Our fuel procurement activities comply with all U.S. and international trade laws and we continue to take advantage of all available avenues to ensure 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. 18 Table of Contents Natural gas is procured through long-term and short-term contracts, as well as through 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. See ITEM 1A. RISK FACTORS, ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS, Critical Accounting Policies and Estimates and Note 15 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information regarding derivative financial instruments. See ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK for additional information on hedging and risk management. Seasonality Our operations are affected by weather, which affects demand for electricity and natural gas. The market price for electricity is also affected by changes in the demand for electricity and the available supply of electricity. With respect to the electric business, very warm weather in summer months and, with respect to the electric and natural gas businesses, very cold weather in winter months is generally referred to as “favorable weather conditions” because those weather conditions result in increased demand for electricity and natural gas. Conversely, mild weather reduces demand. As a result, our operating results in the future may fluctuate substantially on a seasonal basis, especially when more severe weather conditions such as heat waves or extreme winter weather make such fluctuations more pronounced. The pattern of this fluctuation may change depending on the type and location of the facilities owned, the wholesale and retail load served and the terms of contracts to purchase or sell electricity. See ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK for additional information. Weather can also impact our operating conditions. See ITEM 1A RISK FACTORS for additional information regarding risks related to operational factors. To mitigate the potential for weather to impact our operations, we conduct seasonal readiness reviews at our power plants to ensure availability of fuel supplies and equipment performance before entering the summer and winter seasons. We also consider and review national climate assessments to inform our longer-term planning. Our nuclear assets are resilient to weather extremes and are capable of generating emissions-free electricity 24 hours a day, even during unexpectedly cold winter events and hot summer events. Insurance We are subject to liability, property damage, and other risks associated with major incidents at our generating stations. We have reduced our financial exposure to these risks through insurance, both property damage and liability, and other industry risk-sharing provisions. We also maintain business interruption insurance for certain of our renewable assets, but not for our other generating stations unless required by contract or financing agreements. We are self-insured to the extent that any losses may exceed the amount of insurance maintained or are within the policy deductible for our insured losses. See Note 18 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for insurance specific to our nuclear facilities. 19 Table of Contents Regulation FERC Regulation. CEG Parent's subsidiaries include public utilities as defined under the Federal Power Act that are subject to FERC’s exclusive ratemaking jurisdiction over wholesale sales of electricity and the transmission of electricity in interstate commerce. Under the Federal Power Act, FERC has the authority to grant or deny market-based rates for sales of energy, capacity, and ancillary services to ensure that such sales are just and reasonable. FERC’s jurisdiction over ratemaking includes the authority to suspend the market-based rates of utilities and set cost-based rates should FERC find that its previous grant of market-based rates authority is no longer just and reasonable. Other matters subject to FERC jurisdiction include, but are not limited to, emergency orders requiring power plants to operate or mandate temporary electricity connections; certain third-party financings; review of certain mergers involving public utilities; certain dispositions of jurisdictional facilities and acquisitions of securities of another public utility or an existing operational generating facility; certain affiliate transactions; certain intercompany financings and cash management arrangements; certain internal corporate reorganizations; and certain holding company acquisitions of public utility and holding company securities. RTOs and ISOs are FERC-regulated entities that exist in several regions to provide transmission service across multiple transmission systems. FERC has approved PJM, MISO, ISO-NE, and SPP as RTOs and CAISO and NYISO as ISOs. These entities are responsible for regional planning, managing transmission congestion, developing wholesale markets for energy and capacity, maintaining reliability, market monitoring, and the scheduling of physical power transactions in the region. 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. NRC Regulation. We are subject to the jurisdiction of the NRC with respect to the operation of our nuclear generating facilities, including the licensing for operation of each unit. The NRC subjects nuclear generating stations to continuing review and regulation covering, among other things, operations, maintenance, emergency planning, security, and environmental and radiological aspects of those stations. As part of its Reactor Oversight Process, the NRC continuously assesses unit performance indicators and inspection results and communicates its assessment on a semi-annual basis. The NRC may modify, suspend, or revoke operating licenses and impose violations and/or civil penalties for failure to comply with the Atomic Energy Act, NRC regulations, or the terms of the operating licenses or orders. Changes in requirements by the NRC may require a substantial increase in capital expenditures and/or operating costs for our nuclear generating facilities. NRC regulations also require that licensees of nuclear generating facilities demonstrate reasonable assurance that funds will be available in specified minimum amounts at the end of the life of the facility to decommission the facility. We meet the ultimate decommissioning funding obligation through the use of dedicated NDT funds. See ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS — Liquidity and Capital Resources; Critical Accounting Policies and Estimates — Nuclear Decommissioning Asset Retirement Obligations; and Note 10 — Asset Retirement Obligations and Note 17 — Fair Value of Financial Assets and Liabilities of the Combined Notes to Consolidated Financial statements for additional information regarding our NDT funds and decommissioning obligations. Our operations are also subject to the jurisdiction of various other federal, state, regional, and local agencies, and federal and state environmental protection agencies. Additionally, we are subject to NERC mandatory reliability standards, which protect the nation’s bulk power system against potential disruptions from cyber and physical security breaches. Active External Engagement Our business is at the intersection of heavy capital deployment, complex microeconomics and high-profile public policy. Through active external engagement with key stakeholders on behalf of our business and customers, we believe we can support the effective design and operation of the electric markets. We are the nation’s largest producer of clean and reliable energy and following the Calpine merger we are the largest private-sector power producer in the world, and we bring an informed perspective to public policy discussions at the state, regional and national levels. Our consistently rigorous and balanced advocacy has made our perspective one that is sought out by key decision makers when considering the path forward in legislative and policy arenas. 20 Table of Contents Strategy and Outlook Strategy We believe shareholder value is built on a foundation of operational excellence and the pairing of our reliable energy fleet with our customer-facing platform. We are committed to maintaining investment grade credit ratings. We focus on optimizing cash returns through a disciplined approach to safe and efficient operations and cost management, underpinned by stable and durable margins from our customer-facing business and coupled with distinct payments to our generation plants for the clean, reliable, and available energy they provide to customers. We may pursue future growth opportunities that provide additional value building on our core businesses, or expanding our competitive advantages. We are committed to maintaining a strong balance sheet, providing our customers with cost-effective and sustainable solutions to meet their energy needs, and returning value to our shareholders. The demand for reliable, emissions-free energy and sustainability solutions continues to grow across the country. We aim to meet the growing energy needs of all our customers. We continue to serve as a partner to businesses and public entities to help meet their energy and sustainability needs. We are committed to maintaining sufficient financial liquidity and an appropriate capital structure to support safe, secure and reliable operations, even in volatile market conditions. We believe our investment grade credit rating is a competitive advantage and we intend to maintain our credit position and best-in-class balance sheet. In line with that commitment, available cash flow will first be used to meet investment grade credit targets, with incremental capital allocated towards disciplined growth and shareholder return. We will build upon a strong compliance and risk management foundation and recognize the critical role this serves in maximizing operational results. We will continue to manage cash flow volatility through prudent risk management strategies across our business. Growth Opportunities. We continually evaluate growth opportunities aligned with our businesses, assets, and markets leveraging our expertise in those areas and offering durable returns. We may pursue growth opportunities that optimize our core business or expand upon our strengths, including, but not limited to the following: • Opportunistic energy acquisitions and generation development opportunities with a focus on reliability, • Create new value from the existing fleet through nuclear uprates and license extensions, repowering of renewables, serving data economy customers, long-term power purchase agreements, and other opportunities, • Grow solutions for our customers focused on clean energy, efficiency, storage and electrification; help our C&I customers develop and meet sustainability targets, and • Continue to monitor opportunities to participate in advanced nuclear and CCUS as well as investments in battery storage and solar to maintain our leadership position as stewards of an emissions-free energy future. We will employ a disciplined approach to acquisitions that grow future cash flow and support strategic initiatives. This strategy was realized, in part, with the acquisition of Calpine, a combination that brings together premier nuclear, natural gas, and geothermal fleets with a leading commercial platform to deliver innovative customer solutions and strengthen U.S. energy leadership, national security, and economic prosperity. See Note 2 — Mergers, Acquisitions, and Dispositions of the Combined Notes to Consolidated Financial Statements for additional information on our acquisition of Calpine. Various market, financial, regulatory, legislative and operational factors could affect our success in pursuing these strategies. We continue to assess infrastructure, operational, policy, and legal solutions to these issues. See ITEM 1A. RISK FACTORS for additional information. 21 Table of Contents Outlook The U.S. energy sector is undergoing unprecedented transformation, which we believe will drive significant growth in demand for reliable, clean power generation and benefit our business. Our diversified generation fleet, including our industry-leading nuclear assets, is well-positioned to meet this rising demand for dependable emissions-free electricity. Key drivers of increased demand include: • Expanded policy support for nuclear energy that enhances energy security, reliability and system diversity, • Federal and state incentives for new and resilient generation to support grid stability, • Rapid data center growth, increasing large-scale, around-the-clock load requirements, • Electrification across the economy, including transportation, buildings, and industrial processes, • Onshoring and expansion of domestic manufacturing to strengthen U.S. supply chains, and • Evolving customer preferences that favor clean energy, greater choice, transparency, and digitization. Policy Support for Nuclear Energy. We expect our nuclear generation fleet to continue playing a vital role in meeting the nation's baseload power needs. Nuclear energy remains the largest source of zero-emissions electricity in the U.S., providing more than half of all emissions-free power. Our nuclear plants are significant contributors to the clean energy mix in the states in which they operate. Federal policymakers from both parties have underscored the importance of preserving existing nuclear assets through the nuclear PTC enacted in the IRA and maintained under the OBBBA. The action by New York to extend the NY ZEC program in January 2026 reaffirms that states recognize that existing nuclear generation facilities are essential to meeting their policy objectives to reduce GHG emissions. In addition, a number of states including Delaware, New Jersey, Illinois, Maryland, New York, and Texas, are currently drafting bills to add nuclear energy to clean energy targets by repealing bans, studying methods to accelerate their development, or in some cases, providing financial incentives to drive their construction. Beyond emissions reductions, nuclear energy supports high-quality jobs, strengthens regional economies, and enhances the reliability and security of the electrical grid. In alignment with this supportive policy landscape, we intend to file applications to extend the licenses of our nuclear units to 80 years where long-term policy support continues to be available. Policy Support for New, Reliable Generation. With our significantly increased presence in Texas following the Calpine acquisition, our fleet is positioned to play a critical role in ensuring reliability within ERCOT. In November 2023, Texas voters approved a state constitutional amendment to create the TEF, which provides up to $7.2 billion in low-interest loans and completion bonuses to support as much as 10 GW of new dispatchable generation statewide. Project selections announced in Fall 2025 included a $278 million loan for Calpine's 460 MW Pin Oak Creek peaking facility. Policy mechanisms like the TEF are essential to maintaining the reliability of the Texas energy market by enhancing the economic viability of new dispatchable generation. In Maryland, the Next Generation Energy Act of 2025 directed the Maryland Public Service Commission (MPSC) to solicit and approve applications for dispatchable and large-capacity resources through an expedited Certification of Public Convenience and Necessity process. We submitted multiple proposals, and the MPSC approved our application to advance more than 700 MW of natural gas generation under the streamlined pathway. We are also continuing to evaluate additional resource options for Maryland, including battery storage projects, under a separate solicitation established by the Next Generation Energy Act. Data Center Growth. The rapid expansion of data centers continues to accelerate, driven by widespread adoption of AI technologies and large-scale infrastructure investments by major hyperscalers such as Microsoft, Google, Meta, and Amazon. This growth is creating unprecedented demand for reliable, around-the-clock electricity in the U.S. and globally. According to the DOE, data centers are amongst the most energy-intensive building types, consuming 10 to 50 times more energy per square foot than a typical commercial office building. As AI workloads scale and computing needs increase, the energy requirements of data centers are expected to grow substantially, further reinforcing the need for dependable, 24/7 power supply. 22 Table of Contents Electrification. Efforts to optimize our energy infrastructure and reduce GHG emissions are expected to drive continued electrification of the U.S. economy, including transportation, industrial processes, heating and cooling, and household appliances. This transition has the potential to materially increase overall electricity demand. For companies like ours, whose core strength lies in safely generating and delivering electricity and related energy solutions, this growing demand represents a natural and meaningful opportunity for long-term growth. Onshoring of Manufacturing. Recent federal industrial policy, most notably the CHIPS and Science Act and the IRA, explicitly incentivize the return of manufacturing and supply‑chain capacity back to the United States. This resurgence in domestic industrial activity is driving a meaningful increase in electricity demand, as new facilities are both expanding and becoming more energy intensive. These trends are further amplified by broader shifts such as electrification and rapid data center growth. The resulting load growth presents a strategic opportunity for our business as our expanded generation fleet is well positioned to enable this national policy objective. Evolving Customer Preferences. Consumers are increasingly purpose-driven and knowledgeable about solutions that reduce emissions. As a result, they place greater value on being able to trace the sources of their clean energy. Rising awareness of climate change and clean energy options is fueling demand for value-added products and services, such as solar, behind-the-meter storage, EV charging, and the ability to choose 100% clean power 24/7 in competitive retail energy markets. Customers are also showing heightened interest in long-term energy agreements that provide price stability and reliability. At the same time, continued innovation and digitization across the economy are empowering customers with more visibility and control over their energy usage. This increased engagement enables both residential and business customers to make more informed choices about their energy supply and the products and solutions we provide. Environmental Matters and Regulation We are subject to comprehensive and complex environmental legislation and regulation at the federal, state, and local levels, including requirements relating to climate change, air and water quality, solid and hazardous waste, and impacts on species and habitats. Our Board of Directors is responsible for overseeing the management of environmental matters. We have a management team to address environmental compliance and strategy, including the CEO, and other members of senior management. Performance of those individuals directly involved in environmental compliance and strategy is reviewed and affects compensation as part of the annual individual performance review process. Our Board of Directors has delegated to its Nuclear Oversight Committee and the Corporate Governance Committee the authority to oversee our compliance with health, environmental, and safety laws and regulations and strategies and efforts to protect the environment as discussed in further detail below. GHG & Climate Risks Many states, corporations, and investors have advocated for the reduction of GHG emissions across all sectors of the economy, including GHG emissions from the energy sector. Additionally, many large corporations have adopted targets to reduce the carbon emissions in their business operations. We believe our fleet is well-positioned to benefit from policy for decarbonization. We also face climate mitigation and transition risks as well as adaptation risks. Mitigation and transition risks include changes to the energy systems as a result of new technologies, changing customer expectations, and/or voluntary GHG reduction goals, as well as policies intended to reduce GHG emissions. Adaptation risk refers to risks to our facilities or operations that may result from changes in the physical climate, such as changes to temperatures, weather patterns, and sea level rise. See ITEM 1A. RISK FACTORS for additional information. We produce electricity predominantly from low- and emissions-free generating facilities (such as nuclear, natural gas, hydroelectric, geothermal, wind, and solar) and neither own nor operate any coal-fueled generating assets. Our natural gas and oil generating plants produce GHGs, most notably CO2. We have made investments in developing CCUS technologies to reduce GHG emissions. In addition, we sell natural gas through our customer-facing business; and consumers’ use of such natural gas produces GHG emissions. In 2025, we achieved a 94.7% capacity factor across our nuclear fleet and our ownership of 22 GWs of emissions-free generation capacity at 25 nuclear units produced 183 TWhs of electricity. Our Scope 1 and 2 market-based GHG emissions in 2024 were 8.5 million metric tons carbon dioxide equivalent, of which 8.2 million metric tons were from our 23 Table of Contents natural gas and oil-fueled generation fleet, significantly less than our peers with similar volume of power generation. We continue to have the lowest carbon intensity (rate of carbon dioxide equivalent (CO2e) emitted per unit of electricity generated) among the ten largest U.S. generators following the acquisition of Calpine. Regulation of GHGs from Power Plants under the Clean Air Act. In April 2024, EPA issued a final rule that regulates greenhouse gases from existing coal, new natural gas-fired power plants, and existing oil/gas steam generators under Clean Air Act section 111. In June 2025, EPA issued a proposal to repeal its regulations addressing GHG emissions from the sector. In February 2026, EPA issued a final rule to repeal the 2009 “Endangerment Finding” underpinning all GHG regulation by EPA. EPA is expected to separately finalize its repeal of power sector GHG regulations in 2026, which will directly address the compliance obligations under those rules. State Climate Legislation and Regulation. Many states in which we operate have state and regional programs to reduce GHG emissions and renewable and other portfolio standards, which impact the power sector. 25 states and the District of Columbia have 100% clean energy targets, deep GHG reduction targets, or both, encompassing 55% of U.S. residential electricity customers. As the nation’s largest generator of emissions-free electricity, our fleet supports these efforts to produce safe, reliable, clean electricity. In 2019, New York enacted the Climate Leadership and Community Protection Act, which commits the state to achieving net-zero emissions by 2050, with requirements in 2030 and 2040. New Jersey’s Energy Master Plan supports the state’s goal of a 100% clean energy economy by 2050. The state's Global Warming Response Act targeted GHG emissions reductions of 80% below 2006 levels by 2050 which was subsequently accelerated by Executive Order 315 targeting 100% clean energy by 2035. The 2021 Illinois Clean Energy Law is designed to achieve 100% carbon-free power by 2045. It establishes decarbonization requirements for Illinois as well as programs to support the retention and development of emissions-free sources of electricity. Our nuclear plants are meaningful contributors to the clean energy mix where they operate. States may not be able to meet their emissions-reduction goals without our nuclear plants, which provide a significant portion of the current emissions-free power. Several states have established policies to support nuclear generation driven by recognition that existing nuclear generation facilities are essential to meeting policy objectives on GHG emissions, supporting jobs and regional economies, and ensuring reliability and security of the electrical grid through resource diversity. These policies preserve the environmental attributes of our nuclear facilities, and include the following: Policy Name Year Enacted Nuclear Facilities Impacted Type of Program Year of Expiration New York Clean Energy Standard 2016 FitzPatrick, Ginna, and NMP ZEC 2049 Illinois Zero Emission Standard 2016 Clinton and Quad Cities ZEC 2027 New Jersey Clean Energy Legislation 2018 Salem ZEC 2025 (a) Illinois Clean Energy Law 2021 Byron, Braidwood, and Dresden CMC 2027 __________ (a) The contracts entered into under the New Jersey Clean Energy Legislation program concluded in May 2025. In January 2026, the NYPSC approved a 20-year extension of its ZEC program to sustain the state’s nuclear power plants through 2049. The extension is designed to preserve the state's carbon-free electricity supply and ensure grid reliability. The structure of the NY ZEC program remains largely intact, with similar rate-setting methodology, adjusted over time for inflation through 2049. Regional Greenhouse Gas Initiative (RGGI). The RGGI program requires most fossil fuel-fired power plants in the region to hold allowances, sold at auction or on the secondary market, for each ton of CO2 emissions. The following states are currently participants in RGGI; Connecticut, Delaware, Maine, Maryland, Massachusetts, New Hampshire, New Jersey, New York, Rhode Island, and Vermont. Pennsylvania never entered the RGGI program, and its budget bill for fiscal year 2025-2026 legislatively abrogated the state’s RGGI regulations. 24 Table of Contents Renewable and Clean Energy Standards. Most states where we operate have adopted some form of renewable or clean energy procurement requirement. These standards impose varying levels of mandates for procurement of renewable or clean electricity (the definition of which varies by state) and/or energy efficiency, generally expressed as a percentage of annual electric load, often increasing by year. Load serving entities comply with these various requirements through purchasing qualifying renewables, acquiring sufficient certificates (e.g., RECs), paying an alternative compliance payment, and/or a combination of these compliance alternatives. Corporate Clean Energy Targets. Corporations face incentives from their customers and investors to align their businesses with environmental and sustainability objectives, including goals to reduce GHG emissions in their business operations. A number of corporations are making commitments to reducing their GHG emissions, either through procuring increasing amounts of clean energy, such as RECs, EFECs, or emissions offsets, to offset their carbon footprint over time. Recent examples include the PPA with Microsoft that will support the restart of Crane and the PPA with Meta for the output of Clinton which supports Meta's clean energy goals and the continued operations of Clinton. Emerging Clean Technologies. The need for new clean, reliable sources of power that can scale, decarbonize the system, and meet new load requirements is leading to rapid advancements in emerging technologies like advanced nuclear power, CCUS, energy storage, advanced geothermal and hydrogen. The improvements in advanced nuclear including Small Modular Reactors (SMR), growing state and federal support, and the potential to rapidly reduce costs with scaled deployment create a potential path to market for new nuclear within the next decade. CCUS is similarly experiencing substantial investment. It also is expected that energy storage will continue to see high levels of investment driven by lower costs and improved technology, state mandates, a backlog of storage projects in the interconnection queue, and utilities seeking large-scale storage capacity to support higher renewables penetration. Advanced geothermal has similar opportunities to scale supply with early deployments de-risking the technologies. Collectively, advanced nuclear, carbon sequestration, energy storage, geothermal, and clean hydrogen are expected to help support emissions reduction goals. Other Environmental Regulation Water Quality Clean Water Act Section 316(b) requires that the cooling water intake structures at facilities that withdraw more than 2 million gallons of water per day for cooling reflect the best technology available to minimize adverse environmental impacts. Our power generation facilities with cooling water intake systems are subject to the EPA’s 2014 regulations, which are implemented through NPDES permit renewals. We have completed all required studies and have submitted recommendations for compliance as part of the NPDES/SPDES renewal process. We have submitted the NPDES/SPDES renewal timely for all our owned and operated nuclear stations. Six of the twelve stations we operate and STP have been deemed compliant with the 316(b) rule using existing technology. Until the compliance requirements are determined by the applicable state permitting director for each of the six remaining nuclear stations, on a site-specific basis, we cannot estimate the effect that compliance with the EPA’s 2014 rule will have on the operation of our generating facilities and our consolidated financial statements. EPA's rule does not mandate cooling towers or wedge wire screens and allows state permitting directors to require alternative, less costly technologies and/or operational measures, based on a site-specific assessment of the feasibility, costs, and benefits of available options. Should a state permitting director determine that a facility must install cooling towers or wedge wire screens to comply with the rule, that facility’s economic viability could be called into question. In July 2016, the NJDEP issued a final permit for Salem requiring 316(b) studies and deferring the Agency's selection of a final compliance technology. The permit allows Salem to continue to operate utilizing the existing cooling water intake system. The permit was challenged by an environmental organization, and in August 2025, NJDEP Commissioner issued the final agency decision adopting the Office of Administrative Law's initial decision from November 2024 in full. This upheld the 2016 permit and rejected all challenges from the petitioners. Our hydroelectric and nuclear facilities are required to secure a federal license or permit for activities that may result in a discharge to covered waters. We are required to obtain a state water quality certification for those facilities under Clean Water Act section 401. See Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information on the status of the 401 Certification from MDE for Conowingo. 25 Table of Contents We are also subject to the jurisdiction of the Delaware River Basin Commission and the Susquehanna River Basin Commission, regional agencies that primarily regulate water usage. Solid and Hazardous Waste and Environmental Remediation CERCLA authorizes response to releases or threatened releases of hazardous substances into the environment, while RCRA primarily regulates ongoing hazardous waste handling and disposal. Under CERCLA, generators and transporters of hazardous substances, and past and present owners and operators of hazardous waste sites, are strictly, jointly and severally liable for the cleanup costs of hazardous substances at sites. These PRPs can be ordered to perform a cleanup, can be sued for costs associated with an EPA-directed cleanup, may voluntarily settle with the EPA concerning their liability for cleanup costs, or may voluntarily begin a site investigation and site remediation under state oversight. Most states have also enacted similar statutes that may apply in many states where we currently own or operate, or previously owned or operated facilities. In addition, RCRA governs treatment, storage, and disposal of solid and hazardous waste and cleanup of sites where such activities were conducted. Our operations have in the past, and may in the future, require substantial expenditures to comply with these federal and state environmental laws. We may be liable for the costs of remediating environmental contamination of property now or formerly owned by us and of property contaminated by hazardous substances generated or transported 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. We are, or could become in the future, parties to proceedings initiated by the EPA, state agencies, and/or other responsible parties under CERCLA and RCRA or similar state laws with respect to several sites, or may undertake to investigate and remediate sites for which we may be subject to enforcement actions by an agency or third party. We have established appropriate contingent liabilities for environmental remediation requirements. In addition, we may be required to make significant additional expenditures not presently determinable for other environmental remediation costs. See Note 18 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for additional information regarding our environmental matters, remediation efforts, and related impacts to our consolidated financial statements. Nuclear Waste Storage and Disposal There are no facilities for the reprocessing or permanent disposal of SNF currently in operation in the United States, nor has the NRC licensed any such facilities. We currently store all SNF generated by our nuclear generating facilities on-site in storage pools or in dry cask storage facilities. Since our SNF storage pools generally do not have sufficient storage capacity for the life of the respective plant, we have developed dry cask storage facilities to support operations. All our nuclear sites have on-site dry cask storage. On-site dry cask storage in concert with on-site storage pools can meet all current and future SNF storage requirements at each of our sites, including Crane, for the duration of both current and subsequent license periods of all stations and through decommissioning. As of December 31, 2025, we had approximately 97,600 SNF assemblies (23,900 tons) stored on-site in SNF pools or dry cask storage. For a discussion of matters associated with our contracts with the DOE for the disposal of SNF, see Note 18 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements. As a by-product of their operations, nuclear generating units produce LLRW. LLRW is accumulated at each generating station and permanently disposed of at licensed disposal facilities. The Federal Low-Level Radioactive Waste Policy Act of 1980 provides that states may enter into agreements to provide regional disposal facilities for LLRW and restrict use of those facilities to waste generated within the region. Illinois and Kentucky have entered into such an agreement, although neither state currently has an operational site, and none is anticipated to be operational for the next ten years. We ship our Class A LLRW, which represents 93% of LLRW generated at our stations, to disposal facilities in Utah and South Carolina, which have enough storage capacity to store all Class A LLRW for the duration of both current and subsequent license periods for all the stations in our nuclear fleet. 26 Table of Contents We utilize on-site storage capacity at all our stations to store and stage for shipping Class B and Class C LLRW. We have a contract through 2040 to ship Class B and Class C LLRW to a disposal facility in Texas. The agreement provides for disposal of all Class B and Class C LLRW currently stored at each station as well as the Class B and Class C LLRW generated during the term of the agreement. However, because the production of LLRW from our nuclear fleet will exceed the capacity at the Texas site (3.9 million curies through 2027, with applications submitted by the facility for a 10-year extension and an increase in storage capacity), we will still be required to utilize on-site storage at our stations for Class B and Class C LLRW. We currently have enough storage capacity to store all Class B and Class C LLRW for the duration of both current and subsequent license periods for of all the stations in our nuclear fleet and we continue to pursue alternative disposal strategies for LLRW, including an LLRW reduction program to minimize on-site storage and cost impacts. Employees Engaged Workforce Our employees are our greatest strength. We strive to create a workplace that is inclusive, innovative, and safe for our employees. In order to provide the services and products that our customers expect, we focus on creating the best teams to foster teamwork, mutual respect and the empowerment of employees to contribute at their full potential. We strive to attract highly qualified talent and review our hiring, development and promotion practices to maintain equal opportunity and non-discriminatory processes. We develop our future highly skilled workforce by focusing on three main areas: (1) elevating career awareness by promoting STEM and energy career pathways; (2) fostering equal opportunities for all individuals; and (3) advancing the skills of workers by investing in training, reskilling, and upskilling programs. We conducted an employee engagement survey in 2024 to gain insight into engagement and job satisfaction within our workforce, followed by a pulse survey in 2025. We use these surveys to help identify our successes and opportunities for growth. The survey results are shared with leaders at all levels and they are also part of action planning to increase engagement. A robust action planning process is implemented that integrates both centralized action for organization-wide issues and leader-led action for areas unique to their own work groups and/or business areas. Career Development We strive to prepare our workforce for the future and help our employees develop competencies to progress in their careers. We work to continuously enhance the knowledge and skills of our workforce through formal assessments, feedback, coaching, mentoring, training, leadership and other development programs. Well-Being and Benefits We help our employees maintain and improve their overall well-being, and we offer a wide range of benefits that support physical, mental, financial, and family health. Our comprehensive benefits help our employees care for themselves and their families, now and in the future. Community We actively invest in community development through philanthropic giving and employee volunteerism. We work to build a future in which all our employees, customers, business associates and communities benefit from social, environmental and economic progress. We provide opportunities for company-sponsored volunteerism and charitable matching gifts programs. Our employees donated $5.6 million to non-profit organizations of their choice and provided 128,900 volunteer service hours in 2025. Next Generation of Talent We aim to attract, retain and advance a world-class workforce that effectively serves our customers and communities. We work toward this objective by sourcing from and developing a broad talent pipeline and cultivating an inclusive and respectful culture where all individuals can develop to reach their full potential. In 2025, we hired over 2,100 employees. 27 Table of Contents Through our talent acquisition strategy, we work with universities and organizations to attract and recruit STEM-focused students and professionals. Through these collaborations, we participate in mentoring programs, conferences, career fairs and industry events to identify highly skilled talent who may be interested in applying for employment. Workforce We provide training and review hiring and promotion processes and perform pay equity analyses. These actions help to create an environment where all employees can thrive and advance based on merit. The following table shows total number of employees, management, and executives as of December 31, 2025: Metric All Employees Full-Time 15,291 Part-Time 48 Total Employees 15,339 Metric All Employees Regular (a) 15,279 Temporary (b) 60 Total Employees 15,339 __________ (a) Regular employees hold a position where employment is for an indeterminate period and the position is expected to continue on an ongoing basis. (b) Temporary employees hold a position (with or without a contract) for a limited period with an expected end date, typically based on completion of a specific assignment, project, or event. Turnover Rates As turnover is inherent, management succession planning is performed and tracked for executives enterprise-wide. Management frequently reviews succession planning to be prepared when positions become available. The table below shows the turnover rate for regular employees for the year ended December 31, 2025: Involuntary Termination 1.3 % Retirement (a) 2.3 % Voluntary Resignation 3.3 % __________ (a) For reporting purposes, reflects employees who were at least 55 years of age and had at least 10 years of service at the time they ended employment. Collective Bargaining Agreements As of December 31, 2025 approximately 23% of all employees participate in CBAs. The following table presents employee information, including information about CBAs, as of December 31, 2025: Total Employees Covered by CBAs (a) Total Number of CBAs (a) New and Renewed CBAs in 2025 (b) Total Employees Under New and Renewed CBAs in 2025 3,584 21 3 597 __________ (a) Does not include 8 CBAs that were assumed following the acquisition of Calpine in January 2026, representing 177 employees. (b) Does not include CBAs that expired in 2025 but are operating under interim extension agreements while negotiations are ongoing for renewal. 28 Table of Contents ITEM 1A. RISK FACTORS We operate in a complex market and regulatory environment that involves significant risks, many of which are beyond our direct control. Such risks, which could negatively affect our results of operations or financial condition, fall primarily under the categories below: Risks related to market and financial factors primarily include: • the price and availability of fuels, • the generation resources in the markets in which we operate, • the design of power markets, • our ability to operate our generating assets, • our ability to access capital markets, • the impacts of ongoing competition, and • emerging technologies, business models, and demand driven by industry trends, including those related to climate change mitigation and transition to a low-emissions economy. Risks related to legislative, regulatory, and legal factors primarily include changes to, and compliance with, the laws and regulations that govern: • the renewal of operating licenses, • the ability to retire or repower units, • energy policy, including market design, • environmental and climate policy, and • tax policy. Risks related to operational factors primarily include: • changes in the global climate could produce extreme weather events, which could put our facilities at risk, and such changes could also affect the levels and patterns of demand for energy and related services, • the safe, secure and effective operation of our facilities and the ability to effectively manage nuclear decommissioning obligations, • physical, cybersecurity, and third-party reliability risks for us as an owner-operator of generation facilities and as a participant in commodities trading, • rapid development and integration of AI technologies, • ability to attract and retain an appropriately qualified workforce, and • acquisitions or investments in new business initiatives and new markets. Risks related to the acquisition of Calpine primarily include: • no assurance of the dividends at the current rate post-acquisition, reduced ownership and voting power for current shareholders, and potential dilution to earnings per share, • integration challenges including the complex, costly and time-consuming integration process with potential unknown liabilities, and the possible loss of key employees and customers, and 29 Table of Contents • legal and regulatory risks such as potential lawsuits and substantial costs, as well as valuation risk, which could negatively impact future operating results. Risks Related to Market and Financial Factors We are exposed to price volatility associated with both the wholesale and retail power markets and the procurement of nuclear fuel, natural gas, and oil. We are exposed to commodity price risk for fuel and the unhedged portion of our generation portfolio. Our earnings and cash flows are therefore exposed to variability of spot and forward market prices in the markets in which we operate. Price of Fuels. The spot market price of electricity for each hour is generally determined by the marginal cost of supplying the next unit of electricity to the market during that hour. Thus, the market price of power is affected by the market price of the marginal fuel, in particular the price of natural gas, used to generate the electricity unit. Cost and Availability of Fuel. We depend on nuclear fuel, natural gas, and oil to operate most of our generating facilities. The supply markets for nuclear fuel, natural gas, and oil are subject to price fluctuations, availability restrictions, tariffs, counterparty default, and geopolitical risk, which could have a material adverse impact on our results of operations or financial condition. Geopolitical risks specific to nuclear fuel include the ongoing Russia and Ukraine conflict which has yielded sanctions and legislation by the United States, United Kingdom, European Union, Russia, and Canada impacting the exports and imports of Russian nuclear fuel. An example of such sanctions includes the “Prohibiting Russian Uranium Imports Act” which bans 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. The cycle of production and utilization of nuclear fuel is complex, and we engage a diverse set of suppliers to secure the nuclear fuel needed to continue to operate our nuclear fleet long-term. Non-performance by these suppliers could have a material adverse impact on our results of operations or financial condition. See ITEM 1. BUSINESS – Price and Supply Risk Management and ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK for additional information on the nuclear fuel cycle and procurement. Demand and Supply. The market price for electricity is also affected by changes in the demand for electricity and the available supply of electricity. Unfavorable economic conditions, milder than normal weather, regulatory intervention, and the growth of energy efficiency and demand response programs can rapidly increase supply or depress demand. In addition, in some markets, the supply of electricity can exceed demand during some hours of the day, resulting in lower market prices, including periods of negative pricing, and loss of revenue for baseload generating plants such as our nuclear plants. Retail Competition. Our retail operations compete for customers in a competitive environment, which affects the margins we can earn and the volumes we are able to serve. In periods of sustained low natural gas and power prices and low market volatility, retail competitors can aggressively pursue market share because the barriers to entry can be low and wholesale generators (including us) use their retail operations to hedge generation output. Likewise, retail competition is dependent upon continued support of the host state, and state legislative sessions can present repeated opportunities for adjustment and full or partial repeal of retail competition in certain markets. Market Design. The wholesale markets vary from region to region with distinct rules, practices, and procedures. Changes in these market rules, problems with rule implementation, or failure of any of these markets could adversely affect our business with little notice. The imposition of price caps, the issuance of orders extending the operation of generation resources slated for retirement, the imposition of requirements that new large load secure supply from new generation resources or agree to be interrupted, policies allowing utility-owned generation in restructured states, and policies favoring new resources at the expense of existing resources may lead to a market design that results in the premature retirement of existing resources, which would negatively affect our portfolio of assets as well as the market as a whole. For example, PJM is considering market rule changes as part of its stakeholder process, and the Trump administration, in conjunction with Governors of PJM states, have proposed a framework to govern new load connection and the generation that can serve that load. The outcome of this process is uncertain. See Item 7. Management’s Discussion and Analysis of Financial 30 Table of Contents Condition and Results of Operations - Other Key Business Drivers for additional information on proposed PJM market reforms. Our risk management policies cannot fully eliminate the risk associated with our commodity trading activities. Our asset-based power position as well as our power marketing, fuel procurement and other commodity trading activities expose us to risks of commodity price movements. We buy and sell energy and other products and enter financial contracts to manage risk and hedge various positions in our portfolio. We are exposed to volatility in financial results for unhedged positions as well as the risk of ineffective hedges. We attempt to manage this exposure through enforcement of established risk limits and risk management procedures. These risk limits and risk management procedures may not work as planned and cannot eliminate all risks associated with these activities. Even when our policies and procedures are followed, and decisions are made based on projections and estimates of future performance, results of operations could be diminished if the judgments and assumptions underlying those decisions prove to be incorrect. Factors, such as future prices and demand for power, natural gas and other energy-related commodities, become more difficult to predict and the calculations become less reliable the further into the future estimates are made. As a result, we cannot predict the impact that our commodity trading activities and risk management decisions could have on our results of operations or financial condition. Financial performance and load requirements could be negatively affected if we are unable to effectively manage our power portfolio. A significant portion of our power portfolio is used to provide power under procurement contracts with load serving entities and other customers. To the extent portions of the power portfolio are not needed for that purpose, our output is sold in the wholesale power markets. To the extent our power portfolio is not sufficient to meet the requirements of our customers under the related agreements, we must purchase power in the wholesale power markets. Our financial results could be negatively affected if we are unable to cost-effectively meet the load requirements of our customers, manage our power portfolio or effectively address the changes in the wholesale power markets. We may be affected by emerging technologies that could, over time, affect or transform the energy industry. Advancements in both distributed and utility-scale power generation technology could impact market prices and demand size and behaviors. For instance, commercial and residential solar generation installations, energy storage improvements that include batteries and fuel cells, and other emerging technologies are improving the cost-effectiveness of customer self-supply of electricity. Improvements in energy efficiency of lighting, appliances, equipment and building materials will also affect energy consumption by customers. Advancements in nuclear technology, CCUS, storage and advanced geothermal may contribute to a substantial increase in the supply of clean, reliable baseload power, impacting market prices. CCUS technology may also allow for gas generation to continue to be a viable source of clean electricity and provide for future growth of clean gas-powered generation. Further, advancements in AI and other technology could lead to reduced barriers of entry resulting in increased competition from new market participants. These developments could affect the price of energy, levels of customer-owned generation, customer expectations and current business models and make portions of our generation facilities uneconomic prior to the end of their useful lives. These technologies could also result in further declines in commodity prices or demand for delivered energy. Each of these factors could affect our results of operations or financial condition through, among other things, reduced operating revenues, increased operating and maintenance expenses, increased capital expenditures, and potential asset impairment charges or accelerated depreciation and decommissioning expenses over shortened remaining asset useful lives. Market performance and other factors could decrease the value of our NDT funds and employee benefit plan assets, which then could require significant additional funding. Disruptions in the capital markets and their actual or perceived effects on particular businesses and the broader economy could adversely affect the value of the investments held within our NDTs and employee benefit plan trusts. We have significant obligations in these areas and hold substantial assets in these trusts to meet those 31 Table of Contents obligations. The asset values are subject to market fluctuations and will yield uncertain returns, which could fall below our projected return rates. A decline in the market value of the NDT fund investments could increase our funding requirements to decommission our nuclear plants. A decline in the market value of the pension and OPEB plan assets would increase the funding requirements associated with our pension and OPEB plan obligations. Additionally, our pension and OPEB plan liabilities are sensitive to changes in interest rates. As interest rates decrease, the liabilities increase, potentially increasing benefit costs and funding requirements. See Note 10 — Asset Retirement Obligations and Note 14 — Retirement Benefits of the Combined Notes to Consolidated Financial Statements for additional information. We could be negatively affected by unstable capital and credit markets and increased volatility in commodity markets. We rely on the capital markets, particularly for publicly offered debt, as well as the banking and commercial paper markets, to meet our financial commitments and short-term liquidity needs. Disruptions in the capital and credit markets in the United States or abroad could negatively affect our ability to access the capital markets or draw on our bank revolving credit facilities. The banks may not be able to meet their funding commitments to us if they experience shortages of capital and liquidity or if they experience excessive volumes of borrowing requests within a short period of time. The inability to access capital markets or credit facilities, and longer-term disruptions in the capital and credit markets as a result of uncertainty, changing or increased regulation, reduced alternatives or failures of significant financial institutions could result in the deferral of discretionary capital expenditures, affect our ability to effectively hedge our generation portfolio, require changes to our hedging strategy in order to reduce collateral posting requirements, or require a reduction in discretionary uses of cash. In addition, we have exposure to worldwide financial markets, including Europe, Canada, and Asia. Disruptions in these markets could reduce or restrict our ability to secure sufficient liquidity or secure liquidity at reasonable terms. As of December 31, 2025, approximately 26%, 8%, and 13% of our available credit facilities were with European, Canadian, and Asian banks, respectively. The strength and depth of competition in energy markets depend heavily on active participation by multiple trading parties, which could be negatively affected by disruptions in the capital and credit markets and legislative and regulatory initiatives that could affect participants in commodities transactions. Reduced capital and liquidity and failures of significant institutions that participate in the energy markets could diminish the liquidity and competitiveness of energy markets that are important to our business. Perceived weaknesses in the competitive strength of the energy markets could lead to pressures for greater regulation of those markets or attempts to replace market structures with other mechanisms for the sale of power, including the requirement of long-term contracts. If we were to experience a downgrade in our credit ratings to below investment grade or otherwise fail to satisfy the credit standards in our agreements with our counterparties or regulatory financial requirements, we would be required to provide significant amounts of collateral that could affect our liquidity and we could experience higher borrowing costs. Our business is subject to credit quality standards that could require us to post collateral for our obligations upon a decline in ratings. We are also subject to certain financial requirements under NRC regulations as a result of our operation of nuclear power plants that could require us to provide cash collateral or surety bonds if those requirements are not met. One or both events could adversely affect available liquidity and, in the case of a rating downgrade, borrowing and credit support costs. See ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS – Liquidity and Capital Resources – Credit Matters and Cash Requirements – Security Ratings and Note 15 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information regarding the potential impacts of credit downgrades on our cash flows. If we fail to meet project-specific financing agreement requirements, we could experience an impairment or loss of the financed project. We have project-specific financing arrangements and must meet the requirements of various agreements relating to those financings. Failure to meet those arrangements could give rise to a project-specific financing default which, if not cured or waived, could result in the specific project being required to repay the associated debt or 32 Table of Contents other borrowings earlier than otherwise anticipated, and if such repayment were not made, the lenders or security holders would generally have broad remedies, including rights to foreclose against the project assets and related collateral or to force our subsidiaries in the project-specific financings to enter bankruptcy proceedings. The impact of bankruptcy could result in the impairment or loss of certain project assets. See Note 16 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information. The impacts of significant economic downturns (i.e., recession) could lead to decreased volumes delivered and increased expense for uncollectible customer balances. The impacts of significant economic downturns on our retail customers, such as less demand for the products and services provided by our C&I customers, could result in an increase in the number of uncollectible customer balances and related expense. See ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK and Note 15 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information on our credit risk. We may be adversely affected by the effects of sustained inflation. An increase in inflation rates could result in higher interest rates and capital costs, increased costs of labor, and other similar effects. If inflation rates rise or become elevated for a sustained period, they could have a material adverse effect on our business, financial condition, results of operations and liquidity. Although we may take measures to mitigate the impact of inflation, those measures may not be effective. Long-lived assets, goodwill, and other assets could become impaired. Long-lived assets – principally, generation assets – represent the single largest asset class on our Consolidated Balance Sheets. In addition, we expect to have a significant goodwill balance following the acquisition of Calpine in January 2026. In accordance with GAAP, the acquisition of Calpine will be accounted for as a business combination. We expect that the consideration transferred is greater than the fair value of the net assets acquired, and therefore we anticipate recording goodwill on the opening balance sheet. The acquired goodwill will be allocated to the appropriate reporting units of the combined company. We evaluate the recoverability of the carrying value of long-lived assets to be held and used whenever events or circumstances indicating a potential impairment may exist. Factors such as, but not limited to, the business climate, including current and future energy and market conditions, environmental regulation, and the condition of assets are considered. We assess goodwill for impairment at least annually or more frequently if an event occurs or circumstances change that would more likely than not reduce the fair value of the reporting units below their carrying amount. Changes in significant assumptions, including discount rates, energy prices, projected operating costs, and cash flows could potentially result in future impairments of goodwill. An impairment would require us to reduce the carrying value of the long-lived asset and goodwill to fair value through a non-cash charge to expense by the amount of the impairment and could have a material adverse impact on our future operating results or financial condition. See ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS – Critical Accounting Policies and Estimates, Note 1 — Basis of Presentation, Note 8 — Property, Plant, and Equipment, and Note 12 — Intangible Assets of the Combined Notes to Consolidated Financial Statements for additional information on long-lived asset impairments. We could incur substantial costs in the event of non-performance by third parties under indemnification agreements. We are exposed to other credit risks in the power markets that are beyond our control. We have entered into various agreements with counterparties that require those counterparties to reimburse us and hold us harmless against specified obligations and claims. To the extent that any of these counterparties are 33 Table of Contents affected by deterioration in their creditworthiness or the agreements are otherwise determined to be unenforceable, we could be held responsible for the obligations. We have issued indemnities to third parties regarding environmental or other matters in connection with purchases and sales of assets, including several of the Exelon utilities in connection with our absorption of their former generating assets. We could incur substantial costs to fulfill our obligations under these indemnities. In the bilateral markets, we are exposed to the risk that counterparties that owe us money or are obligated to purchase energy or fuel from us will not perform under their obligations for operational or financial reasons. In the event the counterparties to these arrangements fail to perform, we could be forced to purchase or sell energy or fuel in the wholesale markets at less favorable prices and incur additional losses, to the extent amounts, if any, were already paid to the counterparties. In the spot markets, we are exposed to risk as a result of default sharing mechanisms that exist within certain markets, primarily RTOs and ISOs. We are also a party to agreements with entities in the energy sector that have experienced rating downgrades or other financial difficulties. In addition, our retail sales subject us to credit risk through competitive electricity and natural gas supply activities to serve C&I companies, governmental entities, and residential customers. Retail credit risk results when customers default on their contractual obligations. This risk represents the loss that could be incurred due to the nonpayment of a customer’s account balance, as well as the loss from the resale of energy previously committed to serve the customer. Expiration or termination of our PPAs and other contractual agreements may significantly reduce our revenue and allow the counterparty or customer to seek liquidated damages. A material portion of our portfolio is sold under PPAs that expire at various times. We seek to extend contracts or sell any generation not sold under PPAs on a short-term basis as market opportunities arise. Our non-contracted generation is generally sold on the spot market at current market prices as merchant energy. When the terms of each of our various PPAs expire, it is possible that the price paid to us for generation under subsequent arrangements or in short-term markets may be significantly less than the price paid to us under the PPA. Without the benefit of PPAs, we may not be able to sell any or all of the capacity from these generation facilities at commercially attractive rates, and these generation facilities may not be able to operate profitably. The counterparty or customer may terminate or fail to comply with the terms of our PPAs, construction agreements, commodity contracts, maintenance agreements and other contractual arrangements. Additionally, if we fail to meet our contractual obligations they may seek to enforce the liquidated damages provisions contained in such agreements. Risks Related to Legislative, Regulatory, and Legal Factors Federal or state legislative or regulatory actions could negatively affect the scope and functioning of the wholesale markets. Approximately 70% of our generating resources, which include directly owned assets and capacity obtained through long-term contracts, are in the area encompassed by PJM. Our future results of operations are impacted by (1) FERC’s and PJM's level of support for policies that favor the preservation of competitive wholesale power markets, recognize the value of emissions-free electricity and resiliency, complement states' energy objectives and policies and (2) the absence of material changes to market structures that would limit or otherwise negatively affect us. Market rules in other regions could affect us in a similar fashion. We could also be affected by state laws, regulations or initiatives to subsidize existing or new generation. FERC’s requirements for market-based rate authority could pose a risk that we may no longer satisfy FERC’s tests for market-based rates. A loss of market-based rate authority would mean that we would sell power at cost-based rates. Our business is highly regulated and could be negatively affected by legislative and/or regulatory actions. Substantial aspects of our business are subject to comprehensive federal or state legislation and/or regulation. 34 Table of Contents Our results of operations and financial condition are significantly affected by our sales and purchases of commodities at market-based rates, as opposed to cost-based or other similarly regulated rates. Federal and state regulatory and legislative action designed to limit market-based rates through capacity market mitigation, energy and capacity pricing restrictions, new generation mandates, or other means, may negatively impact our results of operations. Federal or state legislative and regulatory efforts to preserve the environmental attributes and reliability benefits of zero-emission nuclear-powered generating facilities could be subject to legal and regulatory challenges and, if overturned, could result in the early retirement of certain of our nuclear plants. The PTC benefiting existing nuclear plants included in the IRA (starting January 1, 2024) and affirmed by the OBBBA continues to be the subject of additional guidance issued from the U.S. Treasury and IRS, which may negatively impact the amount of benefits we ultimately receive. In addition, the duration of the PTC program, the value of the PTC, and/or the existence of the PTC could be affected by legislative action and may have significant adverse effects on our financial performance depending on the future gross receipts received by our nuclear units. Additionally, Federal Power Act Section 202(c) authorizes the issuance of emergency orders requiring power plants to operate or to mandate temporary electricity connections to prevent grid failure during emergencies such as severe weather, fuel shortages, or sudden demand spikes. The exercise of such authority could have an adverse impact on our results of operations if we are required to operate units when it is not economical. Fundamental changes in regulations or other adverse legislative actions affecting our business would require changes in our business planning models and operations. We cannot predict when or whether legislative and regulatory proposals could become law or what their effect would be. See Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information. NRC actions could negatively affect the operations and profitability of our nuclear generating fleet. Regulatory Risk. A change in the Atomic Energy Act or the applicable regulations or licenses could require a substantial increase in capital expenditures or could result in increased operating or decommissioning costs. Events at nuclear plants owned by others, as well as those owned by us, could cause the NRC to initiate such actions. Spent Nuclear Fuel Storage. Our nuclear operations produce various types of nuclear waste materials, including SNF. The approval of a national repository for the storage of SNF and the timing of that facility opening will significantly affect the costs associated with storage of SNF and the ultimate amounts received from the DOE to reimburse us for these costs. Any regulatory action relating to the timing and availability of a repository for SNF could adversely affect our ability to decommission fully our nuclear units. We cannot predict whether a fee may be established or to what extent, in the future for SNF disposal. See Note 18 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for additional information. We could be subject to higher costs and/or penalties related to mandatory reliability standards. We, as a user of the bulk power transmission system, are subject to mandatory reliability standards promulgated by NERC and enforced by FERC. The standards are based on the functions that need to be performed to ensure the bulk power system operates reliably and are guided by reliability and market interface principles. Compliance with or changes in the reliability standards could subject us to higher operating costs and/or increased capital expenditures. If we were found in non-compliance with the federal and state mandatory reliability standards, we could be subject to remediation costs as well as sanctions, which could include substantial monetary penalties. We could incur substantial costs to fulfill our obligations related to environmental and other matters. We are subject to extensive environmental regulation and legislation by local, state and federal authorities. These laws and regulations affect the way we conduct our operations and make capital expenditures, including how we handle air and water emissions, hazardous and solid waste, and activities affecting surface waters, groundwater, and aquatic and other species. Violations of these requirements could subject us to enforcement actions, capital expenditures to bring existing facilities into compliance, additional operating costs for remediation and cleanup 35 Table of Contents costs, civil penalties and exposure to third parties’ claims for alleged health or property damages or operating restrictions to achieve compliance. In addition, we are subject to liability under these laws for the remediation costs for environmental contamination of property currently or formerly owned by us and of property contaminated by hazardous substances we generated or released. Also, we are currently involved in several proceedings relating to sites where hazardous substances have been deposited and could be subject to additional proceedings in the future. See ITEM 1. BUSINESS – Environmental Matters and Regulation and Note 18 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for additional information. We could be negatively affected by federal and state RPS and/or energy conservation legislation, along with energy conservation by customers. Changes to current state legislation or the development of federal legislation that requires the use of clean, renewable and alternate fuel sources could significantly impact us. The impact could include reduced use of some of our generating facilities with effects on our operating revenues and costs. Federal and state legislation mandating the implementation of energy conservation programs, GHG emission limitations, and new energy consumption technologies could cause declines in customer energy consumption and lead to a decline in our operating revenues. We could incur costs to further limit the GHG emissions from our operations or otherwise comply with applicable requirements. To the extent such additional regulation or legislation does not become effective, the potential competitive advantage offered by our low-emissions profile may be reduced. See ITEM 1. BUSINESS – Environmental Matters and Regulation – Renewable and Clean Energy Standards and “We may be affected by emerging technologies that could, over time, affect or transform the energy industry” above for additional information. Our financial performance could be negatively affected by risks arising from our ownership and operation of hydroelectric facilities. FERC has the exclusive authority to license most non-federal hydropower projects located on navigable waterways, federal lands, or connected to the interstate electrical grid. If FERC does not issue new operating licenses for our hydroelectric facilities in the future or a station cannot be operated through the end of its current operating license, our results of operations could be adversely affected by increased depreciation rates and accelerated future decommissioning costs, since depreciation rates and decommissioning cost estimates are currently based on the available license term for each facility. We could also lose operating revenues and incur increased purchased power and fuel expense to meet our supply commitments. In addition, conditions could be imposed as part of the license renewal process that could adversely affect operations, require a substantial increase in capital expenditures, result in increased operating costs or render the project uneconomic. Similar effects could result from a change in the Federal Power Act or the applicable regulations due to events at hydroelectric facilities owned by others, as well as those owned by us. See Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information regarding the license renewal for the Conowingo hydroelectric project. We could be negatively affected by challenges to tax positions taken, tax law changes and the inherent difficulty in quantifying potential tax effects of business decisions. We are required to make judgments in order to estimate our obligations to taxing authorities. These tax obligations include income, real estate, sales and use, and employment-related taxes and ongoing appeal issues related to these tax matters. These judgments include reserves established for potential adverse outcomes regarding tax positions that have been taken that could be subject to challenge by the tax authorities. See Note 1 — Basis of Presentation and Note 13 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information. Following the Calpine acquisition in January 2026, we have several government awards for projects involving cost-share agreements with the DOE, which could be affected by our inadvertent failure to comply with certain laws, rules, and regulations. At five facilities, Calpine has completed or commenced front-end engineering design studies for post-combustion CCUS technology and has also received funding from the DOE for certain geothermal drilling technologies for the Geysers Assets. 36 Table of Contents As a recipient of federal funds under grants and cooperative agreements, in addition to our ordinary contractual obligations, we must comply with various rules and regulations applicable to entities that perform awards in support of government entities. Many of these additional obligations are contained in the terms of the awards themselves and in federal regulations, which regulate the formation, administration and performance of non-procurement federal financial assistance awards, which are subject to change. We must also comply with various national policy requirements prescribed by statute, executive order, policy guidance issued by the Executive Office of the President or other regulations subject to change. Additionally, our contractors must also comply with these federal requirements, and any non-compliance by our contractors or their subcontractors could similarly affect our grant status and expose us to additional risks and liabilities. While we will continue to implement audits and monitor contractual rights for our contractors, failure by our contractors to comply with all regulatory requirements fully could materially affect our business and prospects. Our performance under our U.S. government awards and our compliance with the terms of those awards and applicable laws and regulations are subject to periodic investigation audits, reviews and investigations by various U.S. government agencies. The current environment may lead to increased regulatory scrutiny and sanctions for non-compliance by such agencies. Compliance with these laws and regulations affects how we do business and may impose added costs on our business. Failure to comply may lead to penalties, including whole or partial suspension or termination of our U.S. government awards and/or suspension or debarment from contracting with federal agencies. Legal proceedings could result in a negative outcome, which we cannot predict. We are involved in legal proceedings, claims, and litigation arising from our business operations. Our material legal proceedings, claims, and litigation are summarized in Note 3 — Regulatory Matters and Note 18 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements. Adverse outcomes in these proceedings could lead to significant expenditures, loss of revenue, or the restriction of existing business activities. We could be subject to adverse publicity and reputational risks, which make us vulnerable to negative customer perception and could lead to increased regulatory oversight or other consequences. We could be the subject of public criticism. Adverse publicity of this nature could render public service commissions and other regulatory and legislative authorities less likely to view energy companies in a favorable light, and could cause those companies, including us, to be susceptible to less favorable legislative and regulatory outcomes, as well as increased regulatory oversight and more stringent legislative or regulatory requirements. Risks Related to Operational Factors We are subject to risks associated with weather, including its effect on the supply and demand for electricity, as well as impacts from climate change, including extreme weather events. Our operations are affected by weather, which impacts demand for electricity and natural gas, the price of energy commodities, and operating conditions. Warmer weather in the summer or colder weather in the winter than assumed could require greater resources to meet our contractual commitments. Extreme weather conditions or storms could affect the availability of generation and the transmission of electricity, limiting our ability to source electricity or transmit it to our customers. It could also impair our ability to transport natural gas to our generating assets and regassification facilities as well as our ability to supply natural gas to our customers. Drought-like conditions limiting water usage could impact our ability to run certain generating assets at full capacity. These conditions, which cannot be accurately predicted, could cause us to seek additional replacement supply at a time when supply is constrained. Various forms of power generation and energy-intensive activities, such as data centers, depend on water access to operate. Certain of our assets in the West and Texas Regions, including Calpine's Geysers Assets acquired in January 2026, have experienced drought conditions in the recent past. Disruptions in water 37 Table of Contents availability such as droughts, curtailment, or high prices may impact our ability to generate energy or serve customers, adversely impacting our operations and financial condition. Further, disruptions in water availability at the Geysers Assets may affect the water injection program, steam production and generation levels. Weather projections suggest increases to summer temperature, humidity trends, and more erratic precipitation and storm patterns over the long term in the areas where we have generation assets. The frequency of weather conditions outside the current expected climate norms could contribute to the weather-related impacts discussed above. We primarily operate in areas that have historically been prone to various types of severe weather events. Our physical facilities could be placed at greater risk of damage should changes in the global climate impact temperature and weather patterns, and result in more intense, frequent and extreme weather events, unprecedented levels of precipitation, sea level rise, increased surface water temperatures, and/or other effects. Over time, we may need to make additional investments to protect our facilities from physical climate-related risks. We may be exposed to climate mitigation and transition risks if we are adversely affected by changes to the energy systems as a result of new technologies, changing customer expectations and/or voluntary GHG goals, as well as local, state or federal regulatory requirements intended to reduce GHG emissions. See ITEM 1. BUSINESS – Environmental Matters and Regulation – GHG & Climate Risks for additional information. We are subject to certain risks associated with the operation and maintenance of generation facilities. Operations at any of our generation facilities that we operate as well as those that we own and are operated by others could degrade to the point where the operator must shut down the plant or operate at less than full capacity. If this were to happen, identifying and correcting the causes could require significant time and expense. The operator could choose to close a plant rather than incurring the expense of restarting it or returning the plant to full capacity. In either event, we could lose revenue and incur increased purchased power and fuel expense to meet supply commitments. In addition, we depend on facilities and assets that we do not own or control for the transmission to our customers or the distribution to our generation facilities. If these transmission and distribution systems are disrupted or the capacity of those systems is inadequate, our ability to sell and deliver power products or obtain fuel may be hindered. Our financial performance could be negatively affected by matters arising from our ownership and operation of nuclear facilities. Nuclear capacity factors. Capacity factors for nuclear generating units significantly affect our results of operations. Lower capacity factors could decrease our revenues and increase operating costs by requiring us to produce additional energy from our natural gas and oil-fueled facilities or purchase additional energy in the spot or forward markets in order to satisfy our supply obligations to committed third-party sales. These sources generally have higher costs to produce energy relative to our nuclear stations. Nuclear refueling outages. In general, refueling outages are planned to occur once every 18 to 24 months. The total number of refueling outages, along with their duration, could have a significant impact on our results of operations. When refueling outages last longer than anticipated or we experience unplanned outages, capacity factors decrease, and we face lower margins due to higher energy replacement costs and/or lower energy sales and higher operating and maintenance costs. Nuclear fuel. In addition to the risks around the cost and availability of nuclear fuel discussed previously, the quality of nuclear fuel we use could affect the efficiency and costs of our operations. Remediation actions could result in increased costs due to accelerated fuel amortization, increased outage costs and/or increased costs due to decreased generation capabilities. We do not procure the fuel for the sites we do not operate. If the operator is unable to procure fuel sufficient to operate the plant or at an uneconomical price, our results of operations could be adversely impacted. 38 Table of Contents Additionally, if we are required to arrange for the safe and permanent disposal of SNF beyond current expectations, this could lead to substantial expense or capital expenditures. See “NRC actions could negatively affect the operations and profitability of our nuclear generating fleet” above for additional information on the storage of SNF. Nuclear major incident risk and insurance. The consequences of a major incident could be severe and include loss of life and property damage. Any resulting liability from a nuclear plant major incident within the United States, owned or operated by us or owned by others, could exceed our resources, including insurance coverage. We are a member of an industry mutual insurance company, NEIL, which provides property and accidental outage insurance for our nuclear operations. Uninsured losses and other expenses, to the extent not recovered from insurers or the nuclear industry, could be borne by us. Additionally, an accident or other significant event at a nuclear plant within the United States or abroad, whether owned by us or others, could result in increased regulation and reduced public support for nuclear-fueled energy. As required by the Price-Anderson Act, we carry the maximum available amount of nuclear liability insurance, $500 million for each operating site. Claims exceeding that amount are covered through mandatory participation in a financial protection pool. In addition, the U.S. Congress could impose revenue-raising measures on the nuclear industry to pay claims exceeding the $16.3 billion limit for a single incident. See Note 18 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for additional information on nuclear insurance. Decommissioning obligation and funding. NRC regulations require that licensees of nuclear generating facilities demonstrate reasonable assurance that funds will be available in certain minimum amounts at the end of the life of the facility to decommission the facility. Actual costs to decommission our nuclear facilities may substantially exceed our estimates as a result of changes in the approach and timing of decommissioning activities, changes in decommissioning costs, changes in federal or state regulatory requirements, other changes in our estimates or our ability to effectively execute on planned decommissioning activities. We have recourse to collect additional amounts from utility customers through PECO (subject to certain limitations and thresholds) for former PECO units and through CenterPoint and AEP Texas for STP units. If circumstances changed such that there was an inability to continue to make contributions to the trust funds of the former PECO or STP units based on amounts collected from utility customers, or if we no longer had recourse to collect additional amounts from the respective utility customers if there was a shortfall of funds for decommissioning, the adequacy of the trust funds related to these units could be negatively affected. Any changes to the utilities' regulatory agreements could impact our ability to offset decommissioning-related activities for these units within our results of operations, and the impact to our results of operations or financial condition could be material. Should the expected value of the NDT fund for any former ComEd unit fall below the amount of the expected decommissioning obligation for that unit, the accounting to offset decommissioning-related activities for that unit may be temporarily suspended or discontinued, and the decommissioning-related activities would be recognized in our results of operations, the impact of which could be material. Forecasting trust fund investment earnings and costs to decommission nuclear generating stations requires significant judgment, and actual results could differ significantly from current estimates. If the investments held by our NDT funds are not sufficient to fund the decommissioning of our nuclear units, we could be required to take steps, such as providing financial guarantees through letters of credit or parent company guarantees or making additional contributions to the trusts, which could be significant, to ensure that the trusts are adequately funded and that current and future NRC minimum funding requirements are met. See Note 10 — Asset Retirement Obligations of the Combined Notes to Consolidated Financial Statements for additional information. 39 Table of Contents The productivity of Calpine's geothermal resources acquired in January 2026 may be lower than expected, and it is possible that certain of leases for geothermal steam fields may not be renewed or may be renewed at less favorable terms. Geothermal resource productivity can decline unexpectedly, leading to insufficient reserves for sustained power generation at desired power capacity. Mismanagement or inaccurate estimates of steam reserves could adversely affect our results of operations or financial condition. Geothermal steam fields are leased for the Geysers Assets, with most leases lasting 5 to 20 years initially and continuing as long as resources are produced and sold. Many leases are over 30 years old and remain active. Federal leases start at 10 years and can be renewed for up to 50 years. Most other leases continue for the economic life of the assets, with renewal options if resources remain commercially viable. While we expect to renew leases as needed, some may not be renewed or could have less favorable terms. We are subject to evolving physical security, cybersecurity, and third-party reliability risks. Threat actors continue to seek to exploit potential vulnerabilities in the energy sector associated with protection of sensitive and confidential information, grid infrastructure, and other energy infrastructures. These attacks and disruptions, both physical and cyber, are becoming increasingly sophisticated and dynamic. Security incidents such as ransomware attacks are becoming increasingly prevalent and severe, as well as increasingly difficult to detect. In addition, geopolitical issues, to include conflicts in the Ukraine and the Middle East, as well as tensions between the U.S. and China, may motivate cyber-attacks which could impact the U.S. energy sector and our Company via supply chain disruptions or direct targeting. A security breach, including, but not limited to, physical or electronic intrusions, computer viruses, malware, attacks by cyber criminals or nation state threat actors, ransomware attacks, phishing attacks, supply chain attacks, third-party breaches, and other similar breaches of our physical assets or information systems, or those of our competitors, vendors, business partners and interconnected entities in RTOs, ISOs, and other energy markets, or regulators have the potential to disrupt our business and result in harm to the Company. Security breaches can also occur as a result of non-technical issues, including intentional or inadvertent actions by our employees, third-party service providers or their personnel or other parties. Our customers depend on the continuous availability of our commercial and generation operations. A failure, interruption, or breach of our operational or information security systems, or those of our third-party service providers, as a result of cyber-attacks or information security breaches could disrupt our business, result in the disclosure or misuse of confidential or proprietary information, damage our reputation, cause loss of customers or revenue, increase our costs, result in litigation and/or regulatory action, and/or cause other losses, any of which might have a materially adverse impact on our business operations and our financial condition or results of operations. Operational harm could be in the form of impact to the generation fleet, our commercial operations, and/or reliability of the bulk power system. Impacts to confidential or proprietary information could include inappropriate release of certain types of information, including critical infrastructure, sensitive customer, vendor and employee, trading, export control or other confidential information. If a significant security breach were to occur, our reputation could be negatively affected, customer confidence in us or others in the industry could be diminished, or we could be subject to legal claims, loss of revenues, increased costs, regulatory penalties, or operational shutdown. We currently utilize a mix of third-party managed service providers to host and support our information technology, customer support, and generation operations. For example, our data centers are hosted in vendor-managed co-location facilities; we also host infrastructure with major cloud service providers and utilize enterprise business systems. Consequently, we may be subject to short- and long-term interruptions, delays and outages in service and availability due to third-party cybersecurity or reliability incidents that are outside of our direct control. In the future we may experience interruptions, delays and outages in service and availability from time to time due to a variety of factors, including infrastructure changes, human or software errors, website hosting disruptions and capacity constraints. Coordinated physical and or cyber-attacks that disrupt multiple key electric or natural gas assets of unaffiliated, interconnected parties (such as parties responsible for real-time planning and management of the bulk power system) could impact our ability to provide generation, potentially resulting in localized and regional blackouts affecting third parties and the public, many of which might have no direct commercial relationship with the Company. 40 Table of Contents We cannot anticipate, detect, repel, or implement fully effective preventative measures against all cyber threats, particularly because the techniques used are constantly evolving. Similarly, we cannot guarantee uninterrupted availability of third-party managed systems that may be affected by factors unrelated to cybersecurity incidents. Our implementation of generative AI to improve business and operational performance has led to the introduction of enhanced technologies that pose distinct governance and security risk management challenges. Continued implementation of advanced digital technologies, including generative AI and machine learning, increases the potentially unfavorable impacts of such attacks and reliability, and may introduce new vulnerabilities and threat tactics. For example, threat actors could use AI to develop malicious code and sophisticated phishing attempts. As threats continue to evolve, we may be required to expend additional resources to continue to enhance our information security measures and/or to investigate and remediate information security vulnerabilities. While we have not experienced a material breach or disruption to our network or information systems or our operations to date, future attacks or reliability may negatively impact our business, reputation, or financial results. Although we maintain insurance coverage for cyber events, the amount and scope of insurance maintained against losses resulting from a significant event or security breach may not be sufficient to cover losses or otherwise adequately compensate for any business disruptions that could result. There can be no assurance that such insurance will be available on commercially reasonable terms in the future. In addition, new or updated security regulations or new vulnerabilities identified by security researchers, third-party suppliers, or threat actors could require changes in current measures taken by security or our business operations and could adversely affect our results of operations or financial condition. Our acquisition of Calpine in January 2026 introduces expanded cybersecurity and physical security risks. As part of the integration, we have and expect to continue to evolve our systems, processes, and technical controls in connection with Calpine's information technology and operational technology. Our acquisition of Calpine and the visibility of the transaction will likely increase attention from potential cyber threat actors, potential insider threats, and opportunistic adversaries. We are continuously evolving our cybersecurity strategy and technical controls to prepare for, identify, protect, detect, respond, and recover our technology systems, information and operations from such attacks. See ITEM 1C. CYBERSECURITY for more information. The rapid development and integration of AI technologies into our processes presents several risks to our business. The use of AI technologies in our operations presents risks that could adversely affect our business, financial condition, results of operations and reputation. AI systems, whether developed internally or used by our vendors, service providers or business partners, may produce inaccurate, biased or misleading outputs or experience errors, security vulnerabilities or other failures, which could result in operational disruptions, flawed decision‑making, data loss, cybersecurity incidents or reputational harm. The use of AI may also increase the risk of inadvertent disclosure or misuse of proprietary, confidential or personal information. In addition, the legal and regulatory landscape governing AI technologies is rapidly evolving and uncertain, and compliance with new or changing requirements may impose significant costs or limit our ability to develop, deploy or use AI. If we fail to keep pace with the rapid evolution of AI technologies in our industry and the segments we serve, our competitive position and business results could be negatively impacted. Our employees, contractors, customers and the general public could be exposed to a risk of injury due to the nature of the energy industry. Employees and contractors throughout the organization work in, and the general public could be exposed to, potentially dangerous environments near our operations. As a result, employees, contractors and the general public are at some risk for serious injury, including loss of life. These risks include, but are not limited to, nuclear accidents, dam failure, gas explosions, and electric contact cases. Natural disasters, war, acts and threats of terrorism, pandemic and other significant events could negatively impact our results of operations, ability to raise capital, and future growth. Our fleet of power plants and the transmission infrastructure to which they are connected could be affected by natural disasters and extreme weather events, which could result in increased costs, including supply chain costs. Natural disasters and other significant events increase our risk that the NRC or other regulatory or 41 Table of Contents legislative bodies could change the laws or regulations governing, among other things, operations, maintenance, operating licenses, decommissioning, SNF storage, insurance, emergency planning, security and environmental and radiological matters. In addition, natural disasters could affect the availability of a secure and economical supply of water in some locations, which is essential for our continued operation, particularly the cooling of generating units. Some of Calpine's geothermal, natural gas power plants, and battery storage sites, which were acquired in January 2026 are exposed to frequent minor earthquakes and wildfire risks, mainly in the West. Severe weather and wildfires, especially in California, have disrupted operations and damaged assets like the Geysers Assets. Such events can cause injuries, property damage, and service interruptions, resulting in significant liabilities. Electric utilities may shut down power for public safety reasons during periods of extreme fire hazard. Any shutdown that halts operation at our power plants may reduce our revenues. The impact that potential terrorist attacks could have on the industry and on us is uncertain. We face a risk that our operations would be direct targets or indirect casualties of an act of terror. Any retaliatory military strikes or sustained military campaign could affect our operations in unpredictable ways, such as changes in insurance markets and disruptions of fuel supplies and markets, particularly uranium and oil. Furthermore, these catastrophic events could compromise the physical or cybersecurity of our facilities, which could adversely affect our ability to manage our business effectively. Instability in the financial markets as a result of terrorism, war, natural disasters, pandemic, credit crises, recession or other factors also could result in a decline in energy consumption or interruption of fuel or the supply chain. In addition, the implementation of security guidelines and measures has resulted in and is expected to continue to result in increased costs. We could be significantly affected by the outbreak of a pandemic. We have plans in place to respond to a pandemic. However, depending on the severity of a pandemic and the resulting impacts to workforce and other resource availability, the ability to operate our generating assets could be adversely affected. We maintain a level of insurance coverage consistent with industry practices against property, casualty, and cybersecurity losses subject to unforeseen occurrences or catastrophic events that could damage or destroy assets or interrupt operations. However, there can be no assurance that the amount of insurance will be adequate to address such property and casualty losses. Furthermore, the scenarios above could result in adverse changes in insurance deductibles, premiums, coverage and/or limits. Our business is capital intensive, and our assets could require significant expenditures to maintain and are subject to operational failure, which could result in potential liability. Our business is capital intensive and requires significant investments in electric generating facilities. The operation of power plants and battery storage facilities involves risks, including the breakdown or failure of power generation or storage equipment, transmission lines, pipelines or other equipment or processes, performance below expected levels of output or efficiency, and other issues beyond our control that could be costly to remedy. Our results of operations or financial condition could be negatively affected if we were unable to effectively manage our capital projects or raise the necessary capital. See ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS – Liquidity and Capital Resources for additional information regarding our potential future capital expenditures. Our performance could be negatively affected if we fail to attract and retain an appropriately qualified workforce. Certain events, such as an employee strike, loss of employees, loss of contract resources due to a major event, and an aging workforce without appropriate replacements, could lead to operating challenges and increased costs for us. The challenges include lack of resources, loss of knowledge, and a lengthy time period associated with skill development. In this case, costs, including costs for contractors to replace employees, productivity costs and safety costs, could arise. We are particularly affected due to the specialized knowledge required of the technical and support employees for generation operations. 42 Table of Contents We could make acquisitions or investments in new business initiatives and new markets, which may not be successful or achieve the intended financial results. We could continue to pursue growth in our existing businesses and markets and seek further diversification across the competitive energy value chain. This could include opportunistic emissions-free energy acquisitions, creating new value from our existing fleet through nuclear uprates, renewable repowerings, development of additional capacity for battery storage, natural gas, and CCUS, co-location of customer load, growing sustainability solutions for our customers, and investment opportunities in other emerging technologies and innovations. Such initiatives could involve significant risks and uncertainties, including distraction of management from current operations, inadequate return on capital, and unidentified issues not discovered during diligence performed prior to launching an initiative or entering a market. Additionally, it is possible that FERC, state public utility commissions, or others could limit our ability to make acquisitions or investments or otherwise impose certain restrictions on such transactions due to market power concerns in certain regions or other factors. All these factors could result in higher costs or lower revenues than expected, resulting in lower than planned returns on investment. We are actively implementing the restart of our Crane nuclear generation facility. The restart is subject to certain regulatory approvals, including the NRC comprehensive safety and environmental review, as well as permits from relevant state and local agencies. Additionally, through separate requests, we will pursue obtaining a renewed license to operate the plant and a FERC interconnection agreement. Failure to obtain the necessary approvals could result in the impairment of amounts capitalized. The restart is a complex undertaking including procuring or restoring specialized components on a critical timeline. Failure to meet contractual timelines could result in significant penalties. Overages in costs, potential interconnection delays, or other unforeseen issues could result in lower than planned returns on the investment. The demand for our generation may be impacted by changes in industry trends, including the demand associated with the developing data economy. Industry trends can significantly impact the demand and market pricing of our generation portfolio. This includes the demand and perceived value of certain attributes of our generation, such as reliability or clean energy, as well as the overall demand for energy in the markets in which we operate. Recently, we have benefited from increased demand for our generation as a result of the developing data economy, including demand driven by data centers and AI and other high-performance computing applications, evidenced by the execution of long-term contracts with technology companies as well as increased interest in prospective contracts from our customers. Demand associated with data centers and AI applications may be subject to technological change, shifts in customer behavior, regulatory developments, or changes in capital investment cycles and may not grow at the pace currently anticipated by the market. Our results of operations, growth opportunities, and the price of our common stock could be adversely impacted if the demand for energy driven by the data economy does not continue or fails to achieve current market expectations. Risks Related to the Acquisition of Calpine We cannot assure that we will continue paying dividends at the current rate. We currently expect to pay dividends in an amount consistent with the dividend policy in effect prior to the completion of the merger. However, there is no assurance that our shareholders will receive the same dividends following the merger for reasons that may include capital spending plans, financing agreements, cash flow or financial condition. Decisions on whether, when, and in which amounts to make any future distributions will remain at all times entirely at the discretion of our Board of Directors, which reserves the right to change our dividend practices at any time and for any reason. Our shareholders prior to the merger have a reduced ownership and voting power after the merger, and former Calpine stockholders are not obligated to maintain their ownership interest indefinitely. We issued 50 million newly issued shares of common stock to Calpine stockholders as noted in the Merger Agreement (including shares of our common stock issuable pursuant to Calpine restricted stock units and other 43 Table of Contents equity-based awards). Our prior shareholders and former Calpine stockholders owned approximately 86% and 14% of the outstanding shares of our common stock, respectively, immediately following the consummation of the merger. Each shareholder prior to the merger that remained a shareholder has a percentage ownership of the combined company that is smaller than the shareholder’s percentage held prior to the merger. As a result of this reduced ownership percentage, prior shareholders will have less influence on the policies of the combined company. Additionally, upon the expiration of certain lock-up restrictions on transfers or sales of our securities, former Calpine stockholders will not be subject to any obligation to maintain their ownership interest in us and reducing their ownership interest could adversely impact the price of our common stock. See Note 2 — Mergers, Acquisitions, and Dispositions of the Combined Notes to Consolidated Financial Statements for additional information. The merger may not be accretive to earnings and may cause dilution to our earnings per share, which may negatively affect the market price of our common stock. We currently anticipate that the merger will be accretive to earnings per share in 2026. This expectation is based on preliminary estimates that are subject to change. We may also encounter additional transaction and integration-related costs, may fail to realize all the benefits anticipated in the merger, or be subject to other factors that affect preliminary estimates. Any of these factors could negatively impact our operating results or decrease or delay the expected accretive effect of the merger and contribute to a decrease in the price of our common stock. We have incurred and will incur significant transaction- and merger-related costs, and these costs may be more than anticipated, negatively impacting our operating results. We have incurred and expect to incur non-recurring costs associated with consummation of the transaction. Most of these costs will be transaction-related, including fees paid to financial and legal advisors for the merger and related financing arrangements, and employment-related costs, such as change-in-control payments made to certain Calpine executives. We will also incur transition costs related to formulating integration plans. We may incur additional unanticipated costs in the integration of the businesses, which could negatively impact our operating results. We expect that the elimination of costs, as well as the realization of other efficiencies related to the integration of the businesses, will exceed incremental transaction- and merger-related costs over time. We may not realize all the expected benefits of the merger because of integration challenges. The success of the merger will depend, in part, on our ability to realize all or some of the anticipated benefits from integrating Calpine’s business with our existing businesses. The integration process will be complex, costly and time-consuming. Even if achieved, anticipated benefits and efficiencies from the merger may take longer to realize, or require greater costs to achieve, than currently expected. The challenges associated with integrating the operations of Calpine’s business include, among others: • customer retention risk, as well as the inability to finalize certain transactions currently in progress between Calpine and its customers; • delay in implementation of our business plan for the combined business; • unanticipated issues or costs in integrating financial, information technology, communications and other systems; • complexities associated with managing the larger, more complex, combined business; • potential unknown liabilities and unforeseen expenses, delays or regulatory conditions associated with the merger; • integrating relationships with industry contacts and business partners; • possible inconsistencies in standards, controls, procedures and policies, and compensation structures; and • performance of Calpine’s generating assets and the costs to operate and maintain them, relative to expectations. 44 Table of Contents It is possible that the integration process could result in the disruption of, or the loss of momentum in, our ongoing businesses or inconsistencies in standards, controls, procedures and policies, which could negatively impact the combined company. Uncertainties associated with the merger may cause a loss of management personnel and other key employees, which could adversely affect the future business and operations of the combined company. We are dependent on the experience and industry knowledge of our officers and other key employees to execute our business plans. The success of the combined company will depend in part upon our ability to retain key management personnel and other key employees of both companies. Employees may experience uncertainty about their future roles within the combined company following completion of the merger, which may have an adverse effect on our ability to attract or retain key management and other key personnel. Accordingly, no assurance can be given that the combined company will be able to attract or retain key management personnel and other key employees to the same extent that we have previously been able to attract or retain our employees. The merger may divert significant attention of our management team, which could detract from efforts to meet business goals. Merger integration efforts could place a burden on management and internal resources. Any significant diversion of management attention away from ongoing business concerns and any difficulties encountered in the transition and integration process may negatively impact our results of operations or financial condition. ITEM 1B. UNRESOLVED STAFF COMMENTS None. ITEM 1C. CYBERSECURITY Risk Management and Strategy We have established technical systems programs and processes to manage material risks from cybersecurity threats including assessing and identifying existing cybersecurity risks, as well as continuously monitoring for developing risks. Our cybersecurity risk management strategy is established at the executive level and is implemented through our cybersecurity program which deploys risk-based security controls and services to protect our customers, personnel, information and cyber assets. The program aligns enterprise cyber and physical security controls with the National Institute of Standards & Technology (NIST) Cybersecurity Framework (CSF) and other industry standards such as the NERC and NRC cybersecurity standards. Our cybersecurity program is aligned to the five functions of the NIST Cybersecurity Framework – identify, detect, protect, respond, and recover. Cybersecurity risk is assessed and reported in our enterprise risk management program, which utilizes the Three Lines Model adapted from the Institute of Internal Auditors, for risk management to assign clear risk responsibilities across the enterprise. Through coordination with operational teams, we align on cybersecurity risk classification, categorization, likelihood, and potential impact to the Company. At the highest level, our program includes multi-layered oversight by the Board of Directors and Board Committees. Our cybersecurity and physical security controls are implemented through technical systems, policies and procedures we utilize for planning, performing, managing, assessing, innovating, and improving our security controls. To protect our information and cyber assets, we implement practices for training and screening of personnel, access management, network defense, asset configuration management, vulnerability assessment (including penetration testing), third-party security, and privacy and information protection. Our defense-in-depth strategy to protect our cyber assets and sensitive information reduces the potential severity and duration of a cybersecurity incident by leveraging security measures across various layers of the enterprise. Cross-functional executive steering committees and peer groups, with business unit and technical stakeholder participation, are maintained to support oversight, security controls development, change management, implementation, evaluation, continuous improvement, and sustainment. 45 Table of Contents To assist in detecting cybersecurity events, we deploy security logging and monitoring, malicious code detection, and data loss protection tools. If we are the target of a cybersecurity attack, we have established processes for incident response and crisis management to triage potential incidents, determine severity, contain, and eradicate a threat. These processes require notifications to regulatory and other governmental authorities of cybersecurity events as required by law, including providing notice to investors for material cybersecurity events. To recover our systems and information, we utilize established system recovery plans, data and configuration backup strategies, and business continuity plans. As part of our process to continuously improve, we utilize our internal audit, risk, and legal functions to evaluate security controls and risk management practices. We also engage third-party subject matter experts to independently assess our programs, processes and technical controls, as needed. For our regulated cyber assets associated with critical infrastructure, such as those within the scope of NERC and the NRC, regulatory auditors and inspectors monitor our adherence to mandatory cybersecurity requirements on a regular frequency using a variety of compliance monitoring and enforcement mechanisms. Board Governance and Management Our Board is actively engaged in monitoring the performance of the Company's cybersecurity program and maintains oversight of the Company’s enterprise risk program, including with respect to commodity markets, market design, enterprise security (physical and cyber), operating risks, and financial performance. While the full Board retains ultimate responsibility and oversight of the Company's cybersecurity risk management practices, the Nuclear Oversight Committee and the Audit and Risk Committee also have cybersecurity risk management as part of their charters. The Nuclear Oversight Committee is tasked with overseeing compliance with policies and procedures to manage and mitigate cybersecurity risks associated with our nuclear assets. The Audit and Risk Committee oversees policies and processes established by management to identify, assess, monitor, manage and control technology and cyber risks, among other risks. Our Chief Information Officer (CIO) and Chief Information Security Officer (CISO) provide regular reports to the Board, or one or both of its designated Committees, regarding the security of our operational and information technology programs, systems, and risks. We also report on the state of our cybersecurity program, provide key risk indicators to track performance, and schedule additional informational sessions on cybersecurity practices, as needed. Emergent matters or events are reported to the Board between scheduled meetings on an ad hoc basis through our incident response and crisis management protocols. At the executive and management level, the Chief Administration Officer, via delegations to the cybersecurity organization, is authorized to govern and functionally oversee our security controls and services on behalf of the enterprise. Our cybersecurity organization, under the direction of the CISO who reports to the CIO, implements and provides governance and functional oversight for cybersecurity controls and services, including coordination with our corporate security function. Our CIO has over 20 years of experience with information systems, including management roles in operational security, technical design and engineering, and platform architecture cybersecurity, governance and compliance, and business continuity. Our CISO has over 20 years of experience in cybersecurity, governance and compliance, physical security and business continuity. In addition, cybersecurity risk is assessed and tracked through the Company's enterprise risk management program. Although the risks from cyber threats have not materially affected our business strategy, results of operations, or financial condition to date, we continue to closely monitor cyber risk. Overall, our Company has implemented tactical processes for assessing, identifying, and managing material risks from cybersecurity threats to the Company including governance at the Board level and accountability in our executive management for the execution of our cyber risk management strategy and the controls designed to protect our operations. See ITEM 1A. RISK FACTORS for additional information regarding the Company’s cybersecurity risks. 46 Table of Contents ITEM 2. PROPERTIES The following table presents our interests in net electric generating capacity by station at December 31, 2025: Station (a) Location No. of Units Percent Owned (b) Primary Fuel Type Primary Dispatch Type (c) Net Generation Capacity (MWs) (d) Midwest Braidwood Braidwood, IL 2 Uranium Baseload 2,386 Byron Byron, IL 2 Uranium Baseload 2,350 LaSalle Seneca, IL 2 Uranium Baseload 2,320 Dresden Morris, IL 2 Uranium Baseload 1,845 Quad Cities Cordova, IL 2 75 Uranium Baseload 1,403 Clinton Clinton, IL 1 Uranium Baseload 1,092 Michigan Wind 2 Sanilac County, MI 50 51 (e) Wind Intermittent 46 Beebe Gratiot County, MI 34 51 (e) Wind Intermittent 42 Michigan Wind 1 Huron County, MI 46 51 (e) Wind Intermittent 35 Harvest 2 Huron County, MI 33 51 (e) Wind Intermittent 30 Harvest Huron County, MI 31 51 (e) Wind Intermittent 26 Beebe 1B Gratiot County, MI 21 51 (e) Wind Intermittent 26 Clinton Battery Storage Blanchester, OH 1 Energy Storage Peaking 5 Total Midwest 11,606 Mid-Atlantic Limerick Sanatoga, PA 2 Uranium Baseload 2,315 Calvert Cliffs Lusby, MD 2 Uranium Baseload 1,789 Peach Bottom Delta, PA 2 50 Uranium Baseload 1,324 Salem Lower Alloways Creek Township, NJ 2 42.59 Uranium Baseload 988 Conowingo Darlington, MD 11 Hydroelectric Baseload 497 Criterion Oakland, MD 28 51 (e) Wind Intermittent 36 Fair Wind Garrett County, MD 12 Wind Intermittent 30 Fourmile Ridge Garrett County, MD 16 51 (e) Wind Intermittent 20 Solar Horizons Emmitsburg, MD 1 51 (e) Solar Intermittent 8 Solar New Jersey 3 Middle Township, NJ 4 51 (e) Solar Intermittent 1 Muddy Run Drumore, PA 8 Hydroelectric Intermediate 1,058 Eddystone 3, 4 Eddystone, PA 2 Oil/Gas Peaking 760 Perryman Aberdeen, MD 5 Oil/Gas Peaking 404 Croydon West Bristol, PA 8 Oil Peaking 391 Handsome Lake Kennerdell, PA 5 Gas Peaking 268 Richmond Philadelphia, PA 2 Oil Peaking 98 Philadelphia Road Baltimore, MD 4 Oil Peaking 60 Eddystone Eddystone, PA 4 Oil Peaking 60 Delaware Philadelphia, PA 4 Oil Peaking 56 Southwark Philadelphia, PA 4 Oil Peaking 52 Falls Morrisville, PA 3 Oil Peaking 51 47 Table of Contents Station (a) Location No. of Units Percent Owned (b) Primary Fuel Type Primary Dispatch Type (c) Net Generation Capacity (MWs) (d) Moser Lower Pottsgrove Township, PA 3 Oil Peaking 51 Chester Chester, PA 3 Oil Peaking 39 Schuylkill Philadelphia, PA 2 Oil Peaking 30 Total Mid-Atlantic 10,386 ERCOT STP Bay City, TX 2 44 (g) Uranium Baseload 1,164 Whitetail Webb County, TX 57 51 (e) Wind Intermittent 47 Sendero Jim Hogg and Zapata Counties, TX 39 51 (e) Wind Intermittent 40 Colorado Bend II Wharton, TX 3 Gas Intermediate 1,143 Wolf Hollow II Granbury, TX 3 Gas Intermediate 1,103 Handley 3 Fort Worth, TX 1 Gas Intermediate 375 Handley 4, 5 Fort Worth, TX 2 Gas Peaking 870 Total ERCOT 4,742 New York NMP 1 Scriba, NY 1 Uranium Baseload 620 NMP 2 Scriba, NY 1 82 Uranium Baseload 1,055 FitzPatrick Scriba, NY 1 Uranium Baseload 842 Ginna Ontario, NY 1 Uranium Baseload 576 Total New York 3,093 Other Antelope Valley Lancaster, CA 1 Solar Intermittent 242 Bluestem Beaver County, OK 60 51 (e)(f) Wind Intermittent 101 Shooting Star Kiowa County, KS 65 51 (e) Wind Intermittent 53 Bluegrass Ridge King City, MO 26 51 (e) Wind Intermittent 29 Conception Barnard, MO 23 51 (e) Wind Intermittent 26 Cow Branch Rock Port, MO 23 51 (e) Wind Intermittent 26 Mountain Home Glenns Ferry, ID 20 51 (e) Wind Intermittent 21 High Mesa Elmore County, ID 19 51 (e) Wind Intermittent 20 Echo 1 Echo, OR 21 50.49 (e) Wind Intermittent 17 Sacramento PV Energy Sacramento, CA 4 51 (e) Solar Intermittent 15 Cassia Buhl, ID 13 51 (e) Wind Intermittent 14 Wildcat Lovington, NM 13 51 (e) Wind Intermittent 14 Echo 2 Echo, OR 9 51 (e) Wind Intermittent 9 Tuana Springs Hagerman, ID 8 51 (e) Wind Intermittent 9 Greensburg Greensburg, KS 10 51 (e) Wind Intermittent 6 Threemile Canyon Boardman, OR 6 51 (e) Wind Intermittent 5 Loess Hills Rock Port, MO 4 Wind Intermittent 5 Denver Airport Solar Denver, CO 1 51 (e) Solar Intermittent 2 Hillabee Alexander City, AL 3 Gas Intermediate 753 48 Table of Contents Station (a) Location No. of Units Percent Owned (b) Primary Fuel Type Primary Dispatch Type (c) Net Generation Capacity (MWs) (d) Wyman 4 Yarmouth, ME 1 5.9 Oil Intermediate 34 West Medway II West Medway, MA 2 Oil/Gas Peaking 189 West Medway West Medway, MA 3 Oil Peaking 123 Grand Prairie Alberta, Canada 1 Gas Peaking 105 Framingham Framingham, MA 3 Oil Peaking 31 Total Other 1,849 Total 31,676 __________ (a) All nuclear stations are boiling water reactors except Braidwood, Byron, Calvert Cliffs, Ginna, Salem, and STP units which are pressurized water reactors. (b) 100%, unless otherwise indicated. (c) Baseload units are those that normally operate to take all or part of the minimum continuous load of a system and, consequently, produce electricity at an essentially constant rate. Intermittent units are those with output controlled by the natural variability of the energy resource rather than dispatched based on system requirements. Intermediate units are those that normally operate to take load of a system during the daytime higher load hours and, consequently, produce electricity by cycling on and off daily. Peaking units consist of lower-efficiency, quick response steam units, gas turbines and diesels normally used during the maximum load periods. (d) Net generation capacity is stated at proportionate ownership share. For nuclear stations, capacity reflects the annual mean rating. All other facilities reflect a summer rating. (e) Reflects the prior sale of 49% of CRP to a third party. See Note 21 — Variable Interest Entities of the Combined Notes to Consolidated Financial Statements for additional information. (f) CRP owns 100% of the Class A membership interests and a tax equity investor owns 100% of the Class B membership interests of the entity that owns the Bluestem generating assets. (g) Within the 44% undivided ownership interest in STP, 2% interest was recorded as held for sale as of December 31, 2025. See Note 2 — Mergers, Acquisitions, and Dispositions of the Combined Notes to Consolidated Financial Statements for additional information. The net generation capability available for operation at any time may be less due to regulatory restrictions, transmission congestion, fuel restrictions, efficiency of cooling facilities, level of water supplies, or generating units being temporarily out of service for inspection, maintenance, refueling, repairs, or modifications required by regulatory authorities. We also own EMT, which is a liquefied natural gas import facility located on the Mystic River in Everett, MA. EMT connects to two interstate pipeline systems as well as a local gas utility's distribution system. We maintain property insurance against loss or damage to our principal plants and properties by fire or other perils, subject to certain exceptions. For additional information on insurance specific to our nuclear facilities, see Note 18 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements. For our insured losses, we are self-insured to the extent that any losses are within the policy deductible or exceed the amount of insurance maintained. Any such losses could have a material adverse effect on our results of operation or financial condition. ITEM 3. 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 18 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements. Such descriptions are incorporated herein by these references. ITEM 4. MINE SAFETY DISCLOSURES Not Applicable. 49 Table of Contents PART II ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES CEG Parent Our common stock is listed on the Nasdaq (trading symbol: CEG). As of January 31, 2026, there were approximately 62,892 record holders of common stock. Stock Performance Graph The performance graph below illustrates a four-year comparison of cumulative total returns based on an initial investment of $100 in CEG Parent common stock, as compared with the S&P 500 Stock Index and the Philadelphia Utility Sector Index (UTY), for the period 2022 through 2025. This performance chart assumes: • $100 invested on February 1, 2022, in CEG Parent common stock, the S&P 500 Stock Index, and the UTY, and • All dividends are reinvested. Value of Investment 2/1/22 12/31/22 12/31/23 12/31/24 12/31/25 CEG $100 $175 $240 $462 $734 S&P 500 $100 $86 $108 $135 $160 UTY $100 $107 $96 $116 $136 50 Table of Contents Constellation As of January 31, 2026, CEG Parent directly held the entire membership interest in Constellation. Dividends Our Board of Directors approved a 10% increase in the 2026 quarterly dividend per share compared to the 2025 quarterly dividend per share. The 2026 quarterly dividend will be $0.4265 per share. The following table sets forth Constellation’s quarterly cash dividends per share paid during 2025 and 2024. 2025 2024 Fourth Quarter Third Quarter Second Quarter First Quarter Fourth Quarter Third Quarter Second Quarter First Quarter $ 0.3878 $ 0.3878 $ 0.3878 $ 0.3878 $ 0.3525 $ 0.3525 $ 0.3525 $ 0.3525 First Quarter 2026 Dividend On February 20, 2026, our Board of Directors declared a regular quarterly dividend of $0.4265 per share on our common stock for the first quarter of 2026. The dividend is payable on Friday, March 20, 2026, to shareholders of record as of 5 p.m. Eastern time on Monday, March 9, 2026. Unregistered Sales of Equity Securities None. Issuer Purchases of Equity Securities Our Board of Directors considers share buybacks to be one of several ways we can provide value to our shareholders through our deployment of capital. The first is to maintain strong investment grade metrics in addition to the pursuit of organic and inorganic growth consistent with our role as a leader in the clean energy transition. Our deployment of capital can also include the repurchase of shares if they can be acquired at attractive prices and increases to our dividend, which currently targets a 10% annual growth rate. We take into account the excise taxes imposed and other administrative costs when assessing our repurchase program. We believe that our share buyback policy is in the best interests of our Company and its shareholders and is also consistent with the interest of our other stakeholders. Since 2023, our Board of Directors authorized the repurchase of up to $3 billion of the Company's outstanding common stock. See Note 19 — Shareholders' Equity of the Combined Notes to Consolidated Financial Statements for additional information regarding our share repurchase program. There were no share repurchases under our share repurchase program during the three months ended December 31, 2025. As of December 31, 2025, there was $593 million of remaining authority to repurchase shares of the Company's outstanding common stock. ITEM 6. RESERVED Not Applicable. 51 Table of Contents ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (Dollars in millions, unless otherwise noted) Executive Overview We are the nation's largest producer of clean energy and a leading supplier of energy products and services. Our generating capacity includes primarily nuclear, wind, solar, natural gas, and hydroelectric assets. Through our integrated business operations, we sell electricity, natural gas, and other energy-related products and sustainable solutions to various types of customers, including distribution utilities, municipalities, cooperatives, and commercial, industrial, public sector, and residential customers in markets across multiple geographic regions. We have five reportable segments: Mid-Atlantic, Midwest, New York, ERCOT, and Other Power Regions. The following Management’s Discussion and Analysis of Financial Condition and Results of Operations summarizes results for the year ended December 31, 2025 compared to the year ended December 31, 2024. For discussion of the year ended December 31, 2024 compared to the year ended December 31, 2023, refer to ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS in the 2024 Form 10-K, which was filed with the SEC on February 18, 2025. 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 $22 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 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. See Note 2 — Mergers, Acquisitions, and Dispositions and Note 16 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information. 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. In November 2025, the DOE Office of Energy Dominance Financing issued a guarantee for up to $1.0 billion for an unsecured loan from the Federal Financing Bank to support the restart of the Crane Clean Energy Center. The loan will mature in October 2055. Interest rates on the loan will be fixed upon each advance at a spread of 37.5 basis points above U.S. Treasuries of comparable maturity. Cash from operations will fund the remaining capital expenditures. 52 Table of Contents Conowingo Hydroelectric Project License Renewal In September 2025, we reached a settlement agreement with MDE, Lower Susquehanna Riverkeeper Association, and Waterkeepers Chesapeake, that resolves all outstanding issues related to obtaining a water quality certification from MDE. As a result, MDE issued a water quality certification, clearing the way for the re-licensing and continued operation of our Conowingo hydroelectric facility. The terms of the agreement include operational improvements and commitments for water quality and resiliency, trash and debris removal, aquatic life passage, freshwater mussel restoration, dredging and invasive species management. See Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for more information. Clinton Clean Energy Center In June 2025, we signed a 20-year PPA with Meta Platforms, Inc. (Meta) for the output of the Clinton Clean Energy Center to support Meta’s clean energy goals and operations in the region with emissions-free nuclear energy. The agreement, beginning in June 2027, supports the relicensing and continued operations of Clinton for another two decades after the state’s ZEC program expires. This deal will expand Clinton’s clean energy output by 30 megawatts through plant uprates, expected to be fully complete in 2029, and will enable the Clinton Clean Energy Center to continue to flow power onto the local grid, providing grid reliability and low-cost power to the region for decades to come. The uprates are expected to qualify for the technology-neutral clean electricity PTC (45Y) provided for by the IRA and preserved by the OBBBA for its first 10 years of operations. Other Key Business Drivers PJM Market Reform On January 16, 2026, the National Energy Dominance Council, with support from Governors within the PJM territory, urged PJM to file proposed tariff revisions at FERC to address reliability and pricing within its capacity auctions. These changes aim to increase supply which is increasingly important as energy-intensive sectors expand. The proposed changes include: 1) providing revenue certainty to new generation (for instance, through a Reliability Backstop Auction to procure new, out of market capacity resources), 2) protecting residential customers from capacity price increases, 3) allocating costs to data centers through the Reliability Backstop Auctions, 4) improving load forecasting, specifically large load modeling, 5) accelerating ongoing generator interconnection studies, and 6) performing market studies to ensure the long-term viability of the PJM capacity market. While this is an emerging issue and tariff revisions have not been developed, this has the potential to impact future revenues received by our fleet. FERC Issues Order in PJM Show Cause Proceeding In December 2025, FERC found PJM's tariff unjust and unreasonable because it lacked sufficient clarity and consistency regarding rates, terms, and conditions of service for serving co-located load. The order also found that the existing behind-the-meter generation rules permitting netting of load and supply were no longer just and reasonable, with certain limited exceptions. FERC also directed that PJM make three new transmission services available to co-located loads: an interim, interruptible network integration transmission service, a permanent firm contract demand service, and a non-firm contract demand service. The rates, terms and conditions for these services will be developed in upcoming compliance filings and a paper hearing at FERC in 2026, as will the scope of technical studies required to pursue service of co-located load ion such services. One Big Beautiful Bill Act We continue to see legislative support for nuclear energy generation, including the passage of the OBBBA. Signed into law in July 2025, the OBBBA both preserves certain federal tax credits from the IRA and enhances certain credits to allow advanced nuclear facilities to qualify for the energy communities bonus adder, subject to eligibility requirements. It also preserves tax credits which benefit our efforts to commercialize CCUS for natural gas power generation and maintains tax credits for geothermal and certain other investments. Overall, the OBBBA reinforces the long-term economic viability of our nuclear generation assets. See Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for more information. 53 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 that were previously appropriated 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 regardless of the risk 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. Critical Accounting Policies and Estimates The preparation of financial statements in conformity with GAAP requires that management apply accounting policies and make estimates and assumptions that affect results of operations and the amounts of assets and liabilities reported in the consolidated financial statements. Management believes that the accounting policies described below require significant judgment in their application or incorporate estimates and assumptions that are inherently uncertain and that may change in subsequent periods, which could have a material impact to our results of operations or financial condition. Additional information on the application of these accounting policies can be found in the Combined Notes to Consolidated Financial Statements. Nuclear Decommissioning Asset Retirement Obligations The AROs associated with decommissioning our nuclear un its were $12.9 billion at December 31, 2025. The authoritative guidance requires that we estimate our obligation for the future decommissioning of our nuclear generating plants. To estimate that liability, we use an internally-developed, probability-weighted, discounted cash flow model which, on a unit-by-unit basis, considers multiple decommissioning outcome scenarios. Over the past decade, nuclear operators and third-party service providers have continued to obtain more information about costs associated with decommissioning activities. At the same time, regulators are gaining more information about decommissioning activities which could result in changes to existing decommissioning requirements. In addition, over time, it is possible that technological advances will be identified that could create efficiencies and lead to a reduction in decommissioning costs. The amount of NDT funds could also impact the timing of the decommissioning activities. Additionally, certain factors such as changes in regulatory requirements during plant operations or the profitability of a nuclear plant could impact the timing of plant retirements. These factors could result in material changes to our current estimates as more information becomes available and could change the timing of plant retirements and the probability assigned to the decommissioning outcome scenarios. The nuclear decommissioning obligation is adjusted on a regular basis due to the passage of time and revisions to the key assumptions for the expected timing and/or estimated amounts of the future undiscounted cash flows required to decommission the nuclear plants, based upon the following methodologies and significant estimates and assumptions: 54 Table of Contents Decommissioning Cost Studies. We use unit-by-unit decommissioning cost studies to provide a marketplace assessment of the expected costs (in current year dollars) and timing of decommissioning activities, which are validated by comparison to current decommissioning projects within the industry and other estimates. Decommissioning cost studies are updated, on a rotational basis, for each of our nuclear units at least every five years, unless circumstances warrant more frequent updates. As part of the annual cost study update process, we evaluate newly assumed costs or substantive changes in previously assumed costs to determine if the cost estimate impacts are sufficiently material to warrant application of the updated estimates to the AROs across the nuclear fleet outside of the normal five-year rotating cost study update cycle. Cost Escalation Factors. We use cost escalation factors to escalate the decommissioning costs from the decommissioning cost studies discussed above through the assumed decommissioning period for each of the units. Cost escalation studies, updated on an annual basis, are used to determine escalation factors, and are based on inflation indices for labor, equipment and materials, energy, LLRW disposal, and other costs. All the nuclear AROs are adjusted each year for updated cost escalation factors. Probabilistic Cash Flow Models. Our probabilistic cash flow models include the assignment of probabilities to various scenarios for decommissioning cost levels, decommissioning approaches, and timing of plant shutdown on a unit-by-unit basis. Probabilities assigned to cost levels include an assessment of the likelihood of costs 20% higher (high-cost scenario) or 15% lower (low-cost scenario) than the base-cost scenario. The assumed decommissioning scenarios generally include the following three alternatives: (1) DECON, which assumes major decommissioning activities begin shortly after the cessation of operation, (2) Shortened SAFSTOR, which generally assumes a 30-year delay prior to onset of major decommissioning activities, and (3) SAFSTOR, which assumes the nuclear facility is placed and maintained in such condition during decommissioning, so that the nuclear facility can be safely stored and subsequently decontaminated within 60 years after cessation of operations. In each decommissioning scenario, spent fuel is transferred to dry cask storage as soon as possible until DOE acceptance for disposal. The actual decommissioning approach selected will be determined at the time of shutdown and may be influenced by multiple factors including the funding status of the NDT funds at the time of shutdown and regulatory or other commitments. The plant shutdown timing scenarios consider four alternatives: (1) the probability of early plant retirement, (2) the probability of operating through the original 40-year nuclear license term, (3) the probability of operating through an initial 20-year license renewal term, and (4) the probability of a second 20-year license renewal term. As power market and regulatory environment developments occur, we evaluate and incorporate, as necessary, the impacts of such developments into our nuclear ARO assumptions and estimates. Our probabilistic cash flow models also include an assessment of the timing of DOE acceptance of SNF for disposal. We currently assume DOE will begin accepting SNF from the industry in 2040. The SNF acceptance date assumption is based on management’s estimates of the amount of time required for DOE to select a site location and develop the necessary infrastructure for long-term SNF storage. For additional information regarding SNF, see Note 18 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements. Discount Rates. The probability-weighted estimated future cash flows for the various assumed scenarios are discounted using our specific credit-adjusted, risk-free rates (CARFR) or a AAA-rated U.S. company proxy CARFR for the units that maintain the ability to collect decommissioning costs from utility customers (former PECO and STP units). We initially recognize an ARO at fair value and subsequently adjust it for changes to estimated costs, timing of future cash flows and modifications to decommissioning assumptions. An ARO is not required or permitted to be remeasured for changes in the CARFR that occur in isolation. Increases in an ARO due to upward revisions in estimated undiscounted cash flows are considered new obligations and are measured using a current CARFR as the increase creates a new cost layer within the ARO. Any decrease in the estimated undiscounted future cash flows relating to an ARO are treated as a modification of an existing ARO cost layer and, therefore, are measured using the average historical CARFR used in creating the initial ARO cost layers. If all our future nominal cash flows associated with AROs were to be discounted at the current prevailing CARFR, the obligation would decrease from approximately $12.9 billion to approximately $11.3 billion. 55 Table of Contents The following table illustrates the impact that changes in the CARFR, when combined with changes in projected amounts and expected timing of cash flows, can have on the valuation of our AROs: Change in the CARFR applied to the annual ARO update Increase (Decrease) to AROs as of December 31, 2025 2024 CARFR rather than the 2025 CARFR $ 100 2025 CARFR increased by 50 basis points (100) 2025 CARFR decreased by 50 basis points 125 ARO Sensitivities. Changes in the assumptions underlying an ARO could materially affect the decommissioning obligation. The impact of a change in any one of these assumptions to an ARO is highly dependent on how the other assumptions may correspondingly change. The following table illustrates the effects of changing certain ARO assumptions while holding all other assumptions constant: Change in ARO Assumption Increase (Decrease) to AROs as of December 31, 2025 Cost escalation studies Uniform increase in escalation rates of 50 basis points $ 2,175 Probabilistic cash flow models Increase the estimated costs to decommission the nuclear plants by 10% 750 Increase the likelihood of the DECON scenario by 10% and decrease the likelihood of the SAFSTOR scenario by 10% (a) 100 Shorten each unit's probability-weighted operating life assumption by 10% (b) 250 Extend the estimated date for DOE acceptance of SNF to 2045 (75) __________ (a) Excludes any sites in which management has committed to a specific decommissioning approach. (b) Excludes Zion as the ARO is associated with its SNF storage facility. See Note 1 — Basis of Presentation and Note 10 — Asset Retirement Obligations of the Combined Notes to Consolidated Financial Statements for additional information regarding accounting for nuclear AROs. Acquisition Accounting In accordance with authoritative guidance, the assets acquired and liabilities assumed in a business combination are recorded at their estimated fair values on the date of acquisition. Determining the fair value of assets acquired and liabilities assumed requires management’s judgment, often utilizes independent valuation experts and involves the use of significant estimates and assumptions with respect to the timing and amounts of future cash inflows and outflows, discount rates, market prices and asset lives, among other items. Changes to these estimates and assumptions could result in material changes to the fair value of assets and liabilities as of the acquisition date. The judgments made in the determination of the estimated fair value assigned to the assets acquired and liabilities assumed, as well as the estimated useful life of each asset and the duration of each liability, could significantly impact the financial statements in periods after acquisition, such as through depreciation and amortization expense. Authoritative guidance provides that the allocation of the purchase price may be modified up to one year after the acquisition date as more information is obtained about the fair value of assets acquired and liabilities assumed. See Note 2 — Mergers, Acquisitions, and Dispositions of the Combined Notes to Consolidated Financial Statements for additional information. The difference between the purchase price and the net fair value of assets acquired and liabilities assumed is recognized as goodwill on the balance sheet if the purchase price exceeds the estimated net fair value, or as a bargain purchase gain on the income statement if the purchase price is less than the estimated net fair value. Goodwill is assigned to reporting units that are expected to benefit from the acquisition. See Note 1 — Basis of Presentation, Note 2 — Mergers, Acquisitions, and Dispositions, and Note 12 — Intangible Assets of the Combined Notes to Consolidated Financial Statements for additional information. 56 Table of Contents Goodwill Goodwill is not amortized, but rather is subject to an impairment assessment at least annually or more frequently if an event occurs or circumstances change that would more likely than not reduce the fair value of the reporting units below their carrying amount. A reporting unit is an operating segment or one level below an operating segment (known as a component) and is the level at which goodwill is tested for impairment. Our current operating segments and reporting units are Mid-Atlantic, Midwest, New York, ERCOT, and Other Power Regions. See Note 5 — Segment Information of the Combined Notes to Consolidated Financial Statements for additional information on our reportable segments. Goodwill is primarily reported within our ERCOT segment. See Note 12 — Intangible Assets of the Combined Notes to Consolidated Financial Statements for additional information. For reporting units with goodwill, we perform a qualitative assessment to determine whether it is more likely than not that the fair value of the reporting unit is less than its carrying value. As part of the qualitative assessment, we evaluate macroeconomic conditions, such as deterioration in general economic conditions, industry and market considerations, cost factors, and overall financial performance. If we determine, on the basis of qualitative factors, that the fair value of the reporting unit is more likely than not greater than the carrying amount, no further testing is required. If the qualitative test determines that it is more likely than not that the fair value of the reporting unit is less than its carrying amount, a quantitative goodwill impairment test is performed by calculating the fair value of the reporting unit and comparing it to its carrying amount. The fair value of the reporting units is calculated using a weighted combination of the income approach, which estimates fair value based on discounted cash flows, and the market approach, which estimates fair value based on market comparables in our industry. The income approach uses our internal forecasts to determine estimated cash flows and uses significant assumptions including, but not limited to growth rates, discount rates, customer attrition rates, useful lives, and tax rates. These assumptions are used to arrive at estimated cash flows which are inherently uncertain. Similarly, while comparables used in the market approach are determined to be a reasonable proxy for the fair value of the reporting unit, there is judgment involved and the actual fair value may be different than the fair value implied by the market approach. If the carrying amount of the reporting unit is greater than its fair value, the reporting unit’s goodwill is impaired. The goodwill impairment loss is the difference between the reporting unit’s fair value and carrying amount, and is recorded as a reduction to goodwill and a charge to operating expense. The 2025 annual assessments indicated no impairments. Adverse regulatory actions or changes in significant assumptions could result in future impairments of our goodwill. The acquisition of Calpine is expected to add a significant amount of goodwill to our balance sheet which will be assessed for impairment in accordance with our policy described above. See Note 1 — Basis of Presentation, Note 2 — Mergers, Acquisitions, and Dispositions, and Note 12 — Intangible Assets of the Combined Notes to Consolidated Financial Statements for additional information. Unamortized Energy Contract Assets and Liabilities UEC assets and liabilities represent the remaining unamortized balances of non-derivative energy and fuel contracts that we have acquired. The initial amount recorded represents the fair value of the contracts at the time of acquisition. The UEC assets and liabilities are amortized over the life of the contract in accordance with the expected realization of the underlying cash flows. Amortization of the unamortized energy and fuel contract assets and liabilities are recorded through Operating revenues or Purchased power and fuel expense, depending on the nature of the underlying contract. See Note 12 — Intangible Assets of the Combined Notes to Consolidated Financial Statements for additional information. Impairment of Long-Lived Assets We regularly monitor and evaluate the carrying value of long-lived assets or asset groups for recoverability whenever events or changes in circumstances indicate that the carrying value of those assets may not be recoverable. Indicators of potential impairment may include a deteriorating business climate, including, but not limited to, declines in energy prices, condition of the asset, or plans to dispose of a long-lived asset significantly before the end of its useful life. 57 Table of Contents The review of long-lived assets or asset groups for impairment utilizes significant assumptions about operating strategies and estimates of future cash flows, which require assessments of current and projected market conditions. Forecasting future cash flows requires assumptions regarding forecasted commodity prices for the sale of power and purchases of fuel and the expected operations of assets. A variation in the assumptions used could lead to a different conclusion regarding the recoverability of an asset or asset group and, thus, could potentially result in material future impairments. An impairment evaluation is based on an undiscounted cash flow analysis at the lowest level at which cash flows of the long-lived assets or asset groups are largely independent of the cash flows of other assets and liabilities. The lowest level of independent cash flows is determined by the evaluation of several factors, including the geographic dispatch of the generating units and the hedging strategies related to those units. The cash flows from our generating units are generally evaluated at a regional portfolio level (asset group), given the interdependency of cash flows generated from the customer supply and risk management activities within each region. In certain cases, our generating assets may be evaluated on an individual basis where those assets are contracted on a long-term basis with a third party and operations are independent of other generating assets. On a quarterly basis, we assess our long-lived assets or asset groups for indicators of potential impairment. If indicators are present for a long-lived asset or asset group, a comparison of the undiscounted expected future cash flows to the carrying value is performed. When the undiscounted cash flow analysis indicates the carrying value of a long-lived asset or asset group may not be recoverable, the amount of the impairment loss is determined by measuring the excess of the carrying amount of the long-lived asset or asset group over its fair value. The fair value of the long-lived asset or asset group is dependent upon a market participant’s view of the exit price of the long-lived asset or asset group. This includes significant assumptions of the estimated future cash flows generated by the long-lived assets or asset groups and market discount rates. Events and circumstances often do not occur as expected, resulting in differences between prospective financial information and actual results, which may be material. The determination of fair value is driven by both internal assumptions that include significant unobservable inputs, such as revenue and generation forecasts, projected capital investments, maintenance expenditures, and discount rates, as well as information from various public, financial and industry sources. Depreciable Lives of Property, Plant, and Equipment We have significant investments in electric generating assets. These assets are generally depreciated on a straight-line basis, using the group, composite or unitary methods of depreciation. The group approach is typically for groups of similar assets that have approximately the same useful lives and the composite approach is used for heterogeneous assets that have different lives. Under both methods, a reporting entity depreciates the assets over the average life of the assets in the group. The estimation of asset useful lives requires management judgment, informed by formal depreciation studies of historical asset retirement experiences conducted at least every five years and other factors, including expected energy market conditions, operating costs, and capital investment requirements. Management reassesses these estimates when events or changes in circumstances indicate that revisions may be necessary. When a determination has been made that an asset's current estimated useful life will be shortened or extended, depreciation provisions will be adjusted which could have a material impact on future results of operations. See Note 1 — Basis of Presentation and Note 8 — Property, Plant, and Equipment of the Combined Notes to Consolidated Financial Statements for information regarding depreciation and estimated useful lives of the property, plant and equipment. Accounting for Derivative Instruments We use derivative instruments to manage commodity price risk, foreign currency exchange risk and interest rate risk related to ongoing business operations. Our derivative activities are in accordance with our RMP. See Note 15 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information. We account for derivative financial instruments under the applicable authoritative guidance. Determining whether a contract qualifies as a derivative requires that management exercise significant judgment, including assessing market liquidity as well as determining whether a contract has one or more underlying and one or more notional quantities. Changes in management’s assessment of contracts and the liquidity of their markets, and changes in 58 Table of Contents authoritative guidance, could result in previously excluded contracts becoming in scope of existing authoritative guidance. All derivatives are recognized on the balance sheet at their fair value, except for certain derivatives that qualify for, and are elected under, NPNS. Derivatives executed for economic hedging purposes are recorded at fair value through earnings. NPNS transactions are not required to be recorded at fair value, but rather on an accrual basis of accounting. Determining whether a contract qualifies for NPNS requires judgment as to whether the contract will physically deliver and requires that management ensure compliance with all associated qualification and documentation requirements. Commodity Contracts. Identification of a commodity contract as an economic hedge requires us to determine that the contract is in accordance with the RMP. We make estimates and assumptions concerning future commodity prices, load requirements, interest rates, the timing of future transactions and their probable cash flows, the fair value of contracts and expected changes in fair value in deciding whether to enter derivative transactions, and in determining the initial accounting treatment for derivative transactions. Under the authoritative guidance for fair value measurements, we categorize these derivatives under a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value. Derivative contracts are traded in both exchange-based and non-exchange-based markets. Exchange-based derivatives that are valued using unadjusted quoted prices in active markets are generally categorized in Level 1 in the fair value hierarchy. Certain derivative pricing is verified using indicative price quotations available through brokers or over-the-counter, online exchanges. The price quotations reflect the average of the mid-point of the bid-ask spread from observable markets that we believe provide the most liquid market for the commodity. The price quotations are reviewed and corroborated to ensure the prices are observable and representative of an orderly transaction between market participants. Our derivatives are traded predominantly at liquid trading points. The remaining derivative contracts are valued using models that consider inputs such as contract terms, including maturity, and market parameters, and assumptions of the future prices of commodities, interest rates, volatility, credit worthiness and credit spread. For derivatives that trade in liquid markets, such as generic forwards, swaps, and options, the model inputs are generally observable. Such instruments are categorized in Level 2. For derivatives that trade in less liquid markets with limited pricing information, the model inputs generally would include both observable and unobservable inputs and are categorized in Level 3. We consider non-performance risk, including credit risk in the valuation of derivative contracts, and both historical and current market data in our assessment of non-performance risk. The impacts of non-performance and credit risk to date have not been material to the consolidated financial statements. See ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK and Note 15 — Derivative Financial Instruments and Note 17 — Fair Value of Financial Assets and Liabilities of the Combined Notes to Consolidated Financial Statements for additional information regarding derivative instruments. Defined Benefit Pension and Other Postretirement Employee Benefits Approximately half of our employees participate in the defined benefit pension and OPEB plans that we sponsor. Measuring plan obligations and costs involves various factors, including valuation assumptions and inputs and accounting policy elections. When developing the required assumptions, we consider historical information as well as future expectations. The measurement of these benefit obligations and costs is affected by several assumptions including the discount rate, the long-term expected rate of return on plan assets, the anticipated rate of increase of health care costs, our contributions, the rate of compensation increases, and the long-term expected investment rate credited to employees of certain plans, among others. The assumptions are updated annually and during any interim remeasurement. Pension and OPEB plan assets include U.S. and international equity securities, fixed income securities, and alternative investments such as real assets, private equity, private credit, and hedge funds. Expected Rate of Return on Plan Assets. To determine the EROA, we consider forecasted future long-term capital market performance, weighted by our target asset class allocations. We calculate the expected return on pension and OPEB plan assets by multiplying the EROA by the MRV of plan assets at the beginning of the year, 59 Table of Contents considering anticipated contributions and benefit payments to be made during the year. The MRV for pension and OPEB plan assets is based on either fair value or a calculated value that systematically and rationally recognizes changes in fair value over multiple years. For the majority of pension plan assets, we use a calculated value that adjusts for 20% of the difference between fair value and expected MRV, resulting in less volatile expected asset returns to be recognized as a component of pension cost from year to year. For OPEB plan assets and certain pension plan assets, we use fair value to calculate the MRV. Discount Rate. Discount rates are determined by developing a spot rate curve based on the yield to maturity of high-quality corporate bonds with similar maturities to the pension and OPEB obligations. These spot rates discount the estimated future benefit distribution amounts for the pension and OPEB plans. The discount rate is the single level rate that matches the spot rate curve. We utilize an analytical tool developed by our actuaries to determine these rates. Mortality. The mortality assumption includes a base table for the current expectation of life expectancy of the population adjusted by an improvement scale that attempts to anticipate future improvements in life expectancy. Upon remeasurement as of December 31, 2024 and 2025, we utilized the mortality tables and projection scales released by the SOA. Sensitivity to Changes in Key Assumptions. The following table illustrates the effects of changing certain of the actuarial assumptions reflected above and as discussed in Note 14 — Retirement Benefits of the Combined Notes to Consolidated Financial Statements, while holding all other assumptions constant: Pension OPEB Change in Assumption Increase / (Decrease) Actuarial Assumption Pension OPEB Total Change in 2026 cost: Discount rate (a) 5.38 % 5.30 % 0.5 % $ (19) $ 2 $ (17) 5.38 % 5.30 % (0.5) % 19 3 22 EROA 6.50 % 6.00 % 0.5 % (36) (3) (39) 6.50 % 6.00 % (0.5) % 36 3 39 Change in benefit obligation as of December 31, 2025: Discount rate (a) 5.38 % 5.30 % 0.5 % (328) (63) (391) 5.38 % 5.30 % (0.5) % 356 69 425 __________ (a) Generally, the discount rate will have a larger impact on the pension and OPEB cost and obligation as the rate moves closer to 0%. Therefore, the sensitivities above cannot be extrapolated for larger changes in the discount rate. Additionally, our liability-driven hedging investment strategy for our pension asset portfolio is not reflected in the sensitivities shown, which do not account for the offsetting impact that discount rate changes may have on pension asset returns. See Note 1 — Basis of Presentation and Note 14 — Retirement Benefits of the Combined Notes to Consolidated Financial Statements for additional information regarding the accounting for the defined benefit pension and OPEB plans. Taxation Significant management judgment is required in determining our provision for income taxes, primarily due to the uncertainty related to tax positions taken, as well as deferred tax assets and liabilities and valuation allowances. We account for uncertain income tax positions using a benefit recognition model with a two-step approach, including a more-likely-than-not recognition threshold and a measurement approach based on the largest amount of tax benefit that is greater than 50% likely of being realized upon ultimate settlement. Management evaluates each position based on the technical merits and facts and circumstances of the position, assuming the position will be examined by a taxing authority having full knowledge of all relevant information. Significant judgment is required to determine whether the recognition threshold has been met and, if so, the appropriate amount of tax benefits to be recorded in the consolidated financial statements. We evaluate quarterly the probability of realizing deferred tax assets by reviewing a forecast of future taxable income and our intent and ability to implement tax planning strategies, if necessary, to realize deferred tax 60 Table of Contents assets. We also assess negative evidence, such as the expiration of historical operating loss or tax credit carryforwards, that could indicate our inability to realize our deferred tax assets. Based on the combined assessment, we record valuation allowances for deferred tax assets when it is more likely than not such benefit will not be realized in future periods. Actual income taxes could vary from estimated amounts due to the future impacts of various items, including future changes in income tax laws, our forecasted financial condition and results of operations, failure to successfully implement tax planning strategies, as well as results of audits and examinations of filed tax returns by taxing authorities. See Note 13 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information. Accounting for Loss Contingencies In the preparation of our financial statements, we make judgments regarding the future outcome of contingent events and record liabilities for loss contingencies that are probable and can be reasonably estimated based upon available information. The amount recorded may differ from the actual expense incurred when the uncertainty is resolved and may have a material impact to our results of operations or financial condition. Environmental Costs. Environmental investigation and remediation liabilities are based upon estimates with respect to the number of sites for which we will be responsible, the scope and cost of work to be performed at each site, the portion of costs that will be shared with other parties, the timing of the remediation work, regulations, and the requirements of local governmental authorities. These matters, if resolved in a manner different from the estimate, could have a material impact to our results of operations or financial condition. See Note 18 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for additional information. Other, Including Personal Injury Claims. For accidents we maintain insurance coverage for general liability, automotive liability, workers’ compensation, and personal injury claims and are self-insured to the extent that losses are within policy deductibles or exceed the amount of insurance maintained. We have reserves for both open claims asserted, and an estimate of claims incurred but not reported (IBNR). The IBNR reserve is estimated based on actuarial assumptions and analysis and is updated annually. Future events, such as the number of new claims to be filed each year, the average cost of disposing of claims, as well as the numerous uncertainties surrounding litigation and possible state and national legislative measures could cause the actual costs to be higher or lower than estimated. Accordingly, these claims, if resolved in a manner different from the estimate, could have a material impact to our results of operations or financial condition. Revenue Recognition Sources of Revenue and Determination of Accounting Treatment. We earn revenue from various business activities including competitive sales of power, natural gas, and other energy-related products and sustainable solutions. The accounting treatment for revenue recognition is based on the nature of the underlying transaction and applicable authoritative guidance. We primarily apply the Revenue from Contracts with Customer, Government Assistance, and Derivatives and Hedging guidance to recognize revenue, as discussed in more detail below. Revenue from Contracts with Customers. We recognize revenues in the period in which the performance obligations within contracts with customers are satisfied, which generally occurs when power, natural gas and other energy-related products and sustainable solutions are provided to the customer. Transactions within the scope of Revenue from Contracts with Customers generally include non-derivative agreements, contracts that are designated as NPNS and spot-market energy commodity sales, including settlements with RTOs and ISOs. The determination of our retail power and natural gas sales to individual customers is based on systematic readings of customer meters, generally monthly. Energy delivered to customers that has not yet been billed as of the reporting period is estimated and corresponding unbilled revenue is recorded. The measurement of unbilled revenue is based upon individual customer meter readings, forecasted volumes, and applicable rates. See Note 1 — Basis of Presentation and Note 4 — Revenue from Contracts with Customers of the Combined Notes to Consolidated Financial Statements for additional information. 61 Table of Contents Government Assistance. Our existing nuclear plants are eligible for federal government incentives including transferable tax credits for qualifying electric production volumes. The nuclear PTC is subject to legislative and regulatory changes, which can affect the availability and amount of credits. Repeal or significant reduction or modification of the PTC could have a material impact on our financial performance depending on gross receipts received by our nuclear units each year. Further, the nuclear PTC continues to be the subject of additional guidance, from the U.S. Treasury and IRS, and may materially impact the total amount of benefits we receive. Absence of prescriptive guidance requires the application of judgment in determining annual gross receipts, a primary component in the determination of the credit. We closely monitor developments in relevant tax laws and regulations to anticipate and mitigate potential risks. Given that the nuclear PTC is a function of annual gross receipts, quarterly results rely on forecasted gross receipts for the fiscal year. Energy prices are volatile and are impacted by various factors beyond our control. Significant deviations in market prices from those we’ve forecasted could materially impact our quarterly recognition of nuclear PTC revenues as we progress through the calendar year. See ITEM 1. BUSINESS – Price and Supply Risk Management for additional information on how we mitigate market price risk. See Note 6 — Government Assistance of the Combined Notes to the Consolidated Financial Statements for additional information. Derivative Revenues. We record revenues and expenses using the fair value method of accounting for transactions that are accounted for as derivatives. These derivative transactions primarily relate to commodity price risk management activities. Derivative revenues and expenses include inception gains or losses on new transactions where the fair value is observable, unrealized gains and losses from changes in the fair value of open contracts, and realized gains and losses. 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 year ended December 31, 2025 compared to 2024. For additional information regarding the financial results for the years ended December 31, 2025 and 2024, see the discussions of Results of Operations below. For the Years Ended December 31, $ Change 2025 2024 GAAP Net Income (Loss) Attributable to Common Shareholders $ 2,319 $ 3,749 $ (1,430) 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. 62 Table of Contents 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 25.6% and 25.5% for the years ended December 31, 2025 and 2024, respectively. The following table provides a reconciliation between GAAP Net Income (Loss) Attributable to Common Shareholders and Adjusted (non-GAAP) Operating Earnings for the year ended December 31, 2025 compared to 2024. For the Years Ended December 31, 2025 2024 Earnings Per Share (a) Earnings Per Share (a) GAAP Net Income (Loss) Attributable to Common Shareholders $ 2,319 $ 7.40 $ 3,749 $ 11.89 Unrealized (Gain) Loss on Fair Value Adjustments (net of taxes $243 and $346, respectively) (b) 709 2.26 (1,026) (3.25) Plant Retirements and Divestitures (net of taxes $5 and $9, respectively) 15 0.05 28 0.09 Decommissioning-Related Activities (net of taxes $535 and $244, respectively) (c) (254) (0.81) (50) (0.16) Pension & OPEB Non-Service (Credits) Costs (net of taxes $13 and $2, respectively) 38 0.12 5 0.02 Acquisition-Related Costs (net of taxes $4 and $2, respectively) (d) 97 0.31 6 0.02 Change in Environmental Liabilities (net of taxes $2 and $22, respectively) 5 0.02 65 0.21 Separation Costs (net of taxes $— and $3, respectively) — — 9 0.03 ERP System Implementation Costs (net of taxes $— and $3, respectively) — — 8 0.02 Income Tax-Related Adjustments (e) 22 0.07 (52) (0.17) Noncontrolling Interests (f) (7) (0.02) (7) (0.02) Adjusted (non-GAAP) Operating Earnings $ 2,944 $ 9.39 $ 2,735 $ 8.67 __________ (a) Amounts may not sum due to rounding. Earnings per share amount is based on average diluted common shares outstanding of 314 million and 315 million for the years ended December 31, 2025 and 2024, 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) Reflects acquisition-related costs associated with the Calpine merger. The majority of these expenses are not tax deductible. (e) Adjustment to deferred income taxes due to changes in forecasted apportionment. (f) Represents elimination of the noncontrolling interest portion of certain adjustments included above. 63 Table of Contents Results of Operations 2025 2024 $ Change Operating revenues $ 25,533 $ 23,568 $ 1,965 Operating expenses Purchased power and fuel 14,681 11,419 3,262 Operating and maintenance 6,159 6,159 — Depreciation and amortization 985 1,123 (138) Taxes other than income taxes 622 586 36 Total operating expenses 22,447 19,287 3,160 Gain (loss) on sales of assets and businesses — 71 (71) Operating income (loss) 3,086 4,352 (1,266) Other income and (deductions) Interest expense, net (511) (506) (5) Other, net 936 670 266 Total other income and (deductions) 425 164 261 Income (loss) before income taxes 3,511 4,516 (1,005) Income tax (benefit) expense 1,187 774 413 Equity in income (losses) of unconsolidated affiliates (1) (4) 3 Net income (loss) 2,323 3,738 (1,415) Net income (loss) attributable to noncontrolling interests 4 (11) 15 Net income (loss) attributable to common shareholders $ 2,319 $ 3,749 $ (1,430) Year Ended December 31, 2025 Compared to Year Ended December 31, 2024. The variance in Net income (loss) attributable to common shareholders was unfavorable by $1,430 million primarily due to: • Lower Nuclear PTC revenues in 2025. See Note 6 — Government Assistance of the Combined Notes to Consolidated Financial Statements for additional information; • Unfavorable net unrealized losses on economic hedges; and • Higher net unrealized losses on equity investments. The unfavorable items were partially offset by: • Favorable market and portfolio conditions primarily driven by higher capacity revenues and generation-to-load optimization; • Favorable net ZEC revenues, including the impacts of higher revenue recognized for ZECs delivered under the Illinois ZEC program in prior planning years; and • Favorable net realized and unrealized NDT fund investment activity. Operating revenues. Our five reportable segments are Mid-Atlantic, Midwest, New York, ERCOT, and Other Power Regions. See Note 5 — Segment Information of the Combined Notes to Consolidated Financial Statements for additional information on these reportable segments. 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 region. 64 Table of Contents For the year ended December 31, 2025 compared to 2024, Operating revenues were as follows: 2025 vs. 2024 2025 2024 $ Change % Change Mid-Atlantic $ 6,487 $ 5,522 $ 965 17.5 % Midwest 5,804 4,805 999 20.8 % New York 2,190 2,050 140 6.8 % ERCOT 1,904 1,550 354 22.8 % Other Power Regions 5,583 5,506 77 1.4 % Total reportable segment electric revenues 21,968 19,433 2,535 13.0 % Other 4,370 3,819 551 14.4 % Unrealized gains (losses) (a) (805) 316 (1,121) Total Operating revenues $ 25,533 $ 23,568 $ 1,965 8.3 % __________ (a) % Change in unrealized gains (losses) is not a meaningful measure. Sales and Supply Sources. Our sales and supply volumes (GWhs) by region are summarized below: 2025 vs. 2024 (GWhs) 2025 2024 Change % Change Nuclear Generation (a) Mid-Atlantic 52,914 52,898 16 — % Midwest 93,866 95,321 (1,455) (1.5) % New York 26,339 25,134 1,205 4.8 % ERCOT 9,571 8,358 1,213 14.5 % Total Nuclear Generation 182,690 181,711 979 0.5 % Natural Gas, Oil and Renewables (a) Mid-Atlantic 1,966 2,137 (171) (8.0) % Midwest 1,121 1,116 5 0.4 % ERCOT 12,933 14,778 (1,845) (12.5) % Other Power Regions 6,234 8,692 (2,458) (28.3) % Total Natural Gas, Oil and Renewables 22,254 26,723 (4,469) (16.7) % Purchased Power Mid-Atlantic 17,140 15,729 1,411 9.0 % Midwest 1,777 928 849 91.5 % ERCOT 3,028 3,249 (221) (6.8) % Other Power Regions 42,054 41,077 977 2.4 % Total Purchased Power 63,999 60,983 3,016 4.9 % Total Supply/Sales by Region Mid-Atlantic 72,020 70,764 1,256 1.8 % Midwest 96,764 97,365 (601) (0.6) % New York 26,339 25,134 1,205 4.8 % ERCOT 25,532 26,385 (853) (3.2) % Other Power Regions 48,288 49,769 (1,481) (3.0) % Total Supply/Sales 268,943 269,417 (474) (0.2) % __________ (a) Includes the proportionate share of output where we have an undivided ownership interest in jointly-owned generating plants. 65 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. 2025 2024 Nuclear fleet capacity factor 94.7 % 94.6 % Refueling outage days 215 230 Non-refueling outage days 57 36 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 within each region, depending on our net hourly position. The price of electricity is impacted by several variables, including but not limited to, the price of fuels, generation resources in the 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 each of our major regions and does not necessarily reflect prices we ultimately realized. 2025 vs. 2024 Location (Region) 2025 2024 $ Change % Change PJM West (Mid-Atlantic) $ 50.19 $ 33.74 $ 16.45 48.8 % ComEd (Midwest) 36.62 25.50 11.12 43.6 % Central (New York) 56.31 34.12 22.19 65.0 % North (ERCOT) 32.94 26.97 5.97 22.1 % Southeast Massachusetts (Other) (a) 68.56 41.70 26.86 64.4 % __________ (a) Reflects New England, which comprises the majority of the activity in the Other region. Capacity Prices. We participate in capacity auctions in each of our major regions, except ERCOT which does not have a capacity market. 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 within each region in either Operating revenues or Purchased power and fuel expense, depending on our net monthly position. The following table presents the average capacity prices ($/MW Day) for each of our major regions. Prices reflect the weighted average prices for the various auction periods within the years ended December 31, 2025 and 2024. 2025 vs. 2024 Location (Region) 2025 2024 $ Change % Change Eastern Mid-Atlantic Area Council (Mid-Atlantic) $ 179.79 $ 51.89 $ 127.90 246.5 % ComEd (Midwest) 169.50 31.09 138.41 445.2 % Rest of State (New York) 134.56 106.44 28.12 26.4 % Southeast New England (Other) 446.97 581.69 (134.72) (23.2) % 66 Table of Contents 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 of our major regions in which state programs have been enacted. Gross prices reflect the weighted average price for the various delivery periods within the years ended December 31, 2025 and 2024 and may not necessarily reflect prices we ultimately realize as a result of interaction with the nuclear PTC discussed below. 2025 vs. 2024 State (Region) (a) 2025 2024 $ Change % Change New Jersey (Mid-Atlantic) (b) $ 10.00 $ 9.98 $ 0.02 0.2 % Illinois (Midwest) (c) 4.59 5.60 (1.01) (18.0) % New York (New York) 15.64 18.27 (2.63) (14.4) % __________ (a) See ITEM 1. BUSINESS, Environmental Matters and Regulation for additional information on the plants receiving payments through state programs. (b) The New Jersey ZEC program concluded in May 2025. (c) See Note 4 — Revenue from Contracts with Customers of the Combined Notes to Consolidated Financial Statements for additional information on the Illinois ZEC program. 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 $32.50 per MWh for the period June 2023 through May 2024, $33.43 per MWh for the period June 2024 through May 2025 and $33.50 per MWh for the period June 2025 through May 2026. 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 ($7.58) and $8.05 for the years ended December 31, 2025 and 2024, respectively. The average CMC prices may not necessarily reflect prices we ultimately realize as a result of interaction with the nuclear PTC discussed below. 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 $25.00 per MWh and $43.75 per MWh and $26.00 per MWh and $44.75 per MWh for 2024 and 2025, respectively. 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 year ended December 31, 2025 compared to 2024: 2025 vs. 2024 2025 2024 $ Change % Change Nuclear PTC revenue (a) $ 320 $ 2,080 $ (1,760) (84.6) % State-sponsored programs net revenue (b) (125) (50) (75) 150.0 % __________ (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. 67 Table of Contents For the year ended December 31, 2025 compared to 2024, changes in Operating revenues by segment were approximately as follows: 2025 vs. 2024 $ Change % Change Description Mid-Atlantic $ 965 17.5 % • favorable retail load revenue of $700 primarily due to higher contracted energy prices and load volumes • favorable realized economic hedges of $450 due to settled prices relative to hedged prices • favorable wholesale load revenue of $325 primarily due to higher contracted energy prices; partially offset by • unfavorable activity due to absence of nuclear PTC revenue of $515 due to higher energy and capacity prices in the current year Midwest 999 20.8 % • favorable net generation and wholesale load revenue of $730 primarily due to higher energy prices, partially offset by lower generation volumes • favorable realized economic hedges of $720 due to settled prices relative to hedged prices • favorable retail load revenue of $520 primarily due to higher contracted energy prices and load volumes • favorable net capacity revenue of $195 primarily due to higher prices • favorable net ZEC revenue of $130 primarily due to revenue recognized for Illinois ZECs delivered in prior planning years; partially offset by • unfavorable activity due to lower nuclear PTC revenue of $1,090 and lower net CMC program revenue of $210 due to higher energy and capacity prices in the current year New York 140 6.8 % • favorable net generation revenue of $255 associated with the sale of generation volumes relative to purchase power to supply load primarily due to higher energy prices and generation volumes • favorable retail load revenue of $110 primarily due to higher contracted energy prices • favorable ZEC program revenue of $105 primarily due to the absence of the refund associated with nuclear PTC revenue; partially offset by • unfavorable activity due to absence of nuclear PTC revenue of $150 due to higher energy prices in the current year • unfavorable realized economic hedges of $185 due to settled prices relative to hedged prices ERCOT 354 22.8 % • favorable realized economic hedges of $150 due to settled prices relative to hedged prices • favorable wholesale load revenue of $120 primarily due to higher contracted energy prices, partially offset by lower load volumes • favorable retail load revenue of $75 primarily due to higher contracted energy prices and load volumes 68 Table of Contents 2025 vs. 2024 $ Change % Change Description Other Power Regions 77 1.4 % • favorable retail load revenue of $50 primarily due to higher contracted energy prices Other 551 14.4 % • favorable retail gas revenue of $410 primarily due to higher gas prices • favorable revenues in the United Kingdom, inclusive of realized economic hedges, of $160 primarily due to higher energy prices Unrealized gains or losses (a)(b) (1,121) • losses on economic hedging activities of $805 in 2025 compared to gains of $316 in 2024 Total $ 1,965 8.3 % __________ (a) % Change in unrealized gains or losses is not a meaningful measure. (b) See Note 15 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information on unrealized gains and losses. 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 region, nuclear fleet capacity factor, capacity prices, and electricity prices. Wholesale and retail natural gas activity, energy-related activity in the United Kingdom, 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 region. For the year ended December 31, 2025 compared to 2024, Purchased power and fuel expense were as follows: 2025 vs. 2024 2025 2024 $ Change % Change Mid-Atlantic $ 3,076 $ 2,442 $ 634 26.0 % Midwest 2,102 1,603 499 31.1 % New York 590 597 (7) (1.2) % ERCOT 767 503 264 52.5 % Other Power Regions 4,764 4,238 526 12.4 % Total electric purchased power and fuel 11,299 9,383 1,916 20.4 % Other 3,569 2,997 572 19.1 % Unrealized losses (gains) (a) (187) (961) 774 Total purchased power and fuel $ 14,681 $ 11,419 $ 3,262 28.6 % __________ (a) % Change in unrealized losses (gains) is not a meaningful measure. For the year ended December 31, 2025 compared to 2024, changes in Purchased power and fuel expense by segment were approximately as follows: 2025 vs. 2024 $ Change % Change Description Mid-Atlantic $ 634 26.0 % • unfavorable cost of $660 associated with purchased power to supply load, net of generation, primarily due to higher energy prices, as well as higher prices associated with net capacity costs; partially offset by • favorable realized economic hedges of $105 due to settled prices relative to hedged prices Midwest 499 31.1 % • unfavorable cost of $460 associated with purchased power to supply load, net of generation, primarily due to higher transmission costs and energy prices 69 Table of Contents 2025 vs. 2024 $ Change % Change Description New York (7) (1.2) % • no individually significant drivers ERCOT 264 52.5 % • unfavorable cost of $210 associated with purchased power to supply load, net of generation, primarily due to higher energy prices • unfavorable realized economic hedges of $60, due to settled prices relative to hedged prices Other Power Regions 526 12.4 % • unfavorable purchased power of $1,330 primarily due to lower generation volumes driven by the retirement of Mystic Units 8 and 9, higher energy prices, and higher ancillary charges; partially offset by • favorable realized economic hedges of $835 due to settled prices relative to hedged prices Other 572 19.1 % • unfavorable net wholesale gas purchases, inclusive of realized economic hedges, of $315 primarily due to higher gas prices • unfavorable purchases in the United Kingdom, inclusive of realized economic hedges, of $190 primarily due to higher energy prices • unfavorable fair value adjustments related to gas imbalances of $65 Unrealized gains or losses (a)(b) 774 • gains on economic hedging activities of $187 in 2025 compared to gains of $961 in 2024 Total $ 3,262 28.6 % __________ (a) % Change in unrealized gains or losses is not a meaningful measure. (b) See Note 15 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information on unrealized gains and losses. Other, net was favorable for the year ended December 31, 2025 compared to 2024, due to activity described in the table below: Income (Deductions) For the Years Ended December 31, 2025 2024 Decommissioning-related activities (a) $ 1,112 $ 567 Net unrealized gains (losses) from equity investments (b) (304) 11 Other 128 92 Other, net $ 936 $ 670 __________ (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 10 — Asset Retirement Obligations and Note 22 — 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 33.8% and 17.1% for the years ended December 31, 2025 and 2024, respectively. The change in effective tax rate in 2025 compared to 2024 is primarily due to the decrease in nuclear PTCs generated, which are not taxable, as well as higher qualified NDT fund income that is taxed at a higher rate. See Note 13 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information. 70 Liquidity and Capital Resources For discussion of the year ended December 31, 2024 compared to the year ended December 31, 2023, refer to the Liquidity and Capital Resources section of MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS in the 2024 Form 10-K which was filed with the SEC on February 18, 2025. All results included throughout the liquidity and capital resources section are presented on a GAAP basis. Our operating and capital expenditure requirements are provided by internally generated cash flows from operations, as well as funds from bank borrowings and other capital market sources. Our business is capital intensive and requires considerable capital resources. We regularly evaluate our financing plan and credit line sizing, focusing on maintaining our investment grade credit ratings while meeting our cash needs to fund capital requirements, including funding construction expenditures, retiring debt, paying dividends, funding pension and OPEB obligations, and investing 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 $9.5 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 16 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information. Cash Flow Activities The following table summarizes our cash flow activities for the years ended December 31, 2025 and 2024, respectively: For the Years Ended December 31, 2025 2024 $ Change Cash, restricted cash, and cash equivalents at beginning of period $ 3,129 $ 454 $ 2,675 Net cash provided by (used in): Operating activities 4,237 (2,464) 6,701 Investing activities (3,198) 7,428 (10,626) Financing activities (420) (2,289) 1,869 Net increase (decrease) in cash, restricted cash, and cash equivalents 619 2,675 (2,056) Cash, restricted cash, and cash equivalents at end of period $ 3,748 $ 3,129 $ 619 71 Table of Contents Net Cash Provided By (Used In) Operating Activities Cash provided by operating activities was $4,237 million for the year ended December 31, 2025, compared to cash used in operating activities of ($2,464) million for the year ended December 31, 2024. 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. In December 2024, we amended our Accounts Receivable Facility whereby we now retain the rights to our receivables and any changes in our receivable balance flow through operating activities. This increase in cash flows from operating activities was partially offset by cash outflows associated with an increase in collateral postings. See Note 7 — Accounts Receivable and Note 15 — Derivative Financial Instruments 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 ($3,198) million for the year ended December 31, 2025, compared to cash provided by investing activities of $7,428 million for the year ended December 31, 2024. The change was primarily due to an amendment of our Accounts Receivable Facility. Prior to the amendment, the collection and reinvestment of proceeds associated with the sale of receivables were treated as cash flows from investing activities in the Consolidated Statements of Cash Flows. As a result of the amendment, cash collections of accounts receivable are now treated as Cash flows from operating activities in the Consolidated Statements of Cash Flows. See Note 7 — Accounts Receivable of the Combined Notes to Consolidated Financial Statements for additional information. Net Cash Provided By (Used In) Financing Activities Cash used in financing activities was ($420) million for the year ended December 31, 2025, compared to cash used in financing activities of ($2,289) million for the year ended December 31, 2024. The change primarily relates to long-term debt and changes in short-term borrowings. Debt issuances and redemptions or repayments vary each year. The remaining change primarily relates to repurchases of common stock during each period. See Note 16 — Debt and Credit Agreements and Note 19 — Shareholders' Equity of the Combined Notes to Consolidated Financial Statements for additional information. Debt Issuances and Redemptions See Note 16 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information on our long-term debt. Debt activity for 2025 and 2024 was as follows: During 2025, the following long-term debt was issued (redeemed): Type Interest Rate Maturity Amount 2025 Senior Notes 3.25% June 2025 $ (900) West Medway II Nonrecourse Debt 1-month SOFR + 3.225% - 3.350% March 2026 (52) CR Nonrecourse Debt 3-month SOFR + 2.00% - 2.25% (a) December 2027 (34) Continental Wind Nonrecourse Debt 6.00% February 2033 (31) Antelope Valley DOE Nonrecourse Debt 2.29% - 3.56% January 2037 (26) Tax Exempt Pollution Control Revenue Bonds 4.45% March 2025 (23) RPG Nonrecourse Debt 4.11% March 2035 (7) Energy Efficiency Project Financing (b) 2.20% - 4.96% December 2025 - March 2026 (3) Total long-term debt issued (redeemed) $ (1,076) __________ (a) The interest rate for long-term debt redemptions prior to October 2025 were based on SOFR + 2.25%. Beginning in October 2025, these redemptions are based on SOFR + 2.00%. (b) Represents funding to install energy conservation measures. The maturity dates represent the expected date of project completion, upon which the respective customer assumes the outstanding debt. 72 Table of Contents During 2024, the following long-term debt was issued (redeemed): Type Interest Rate Maturity Amount Green Senior Notes (a) 5.75% March 2054 $ 900 Energy Efficiency Project Financing (b) 2.20% - 5.51% March 2025 - April 2028 21 CR Nonrecourse Debt 3-month SOFR + 2.25% (c) December 2027 (22) Continental Wind Nonrecourse Debt 6.00% February 2033 (28) West Medway II Nonrecourse Debt 1-month SOFR + 3.225% March 2026 (36) Antelope Valley DOE Nonrecourse Debt 2.29% - 3.56% January 2037 (26) RPG Nonrecourse Debt 4.11% March 2035 (9) Total long-term debt issued (redeemed) $ 800 __________ (a) Issued to finance or refinance, in whole or in part, one or more new or existing Eligible Projects. Eligible Projects are defined as investments and expenditures made by us in the 24 months prior to or after the issuance of the notes within the following eligible green categories: clean generation fleet, clean hydrogen, energy storage, and clean commercial offerings. (b) Represents funding to install energy conservation measures. The maturity dates represent the expected date of project completion, upon which the respective customer assumes the outstanding debt. (c) The interest rate for long-term debt redemptions prior to July 2024 were based on SOFR + 2.76%. Beginning in July 2024 these redemptions are based on SOFR + 2.25%. Calpine Acquisition In January 2026, upon completion of the acquisition of Calpine, we assumed all of Calpine's outstanding obligations including approximately $12.6 billion of debt composed of approximately $7.6 billion of long-term debt and approximately $5 billion of various project financing arrangements. The acquisition of Calpine had the following impacts on our liquidity position: • The purchase price included cash consideration of approximately $4.5 billion which was funded through cash on hand from normal operating activities at the time of acquisition. • We assumed approximately $7.6 billion of long-term debt including senior unsecured and secured notes, and corporate term loans. In December 2025, we commenced private exchange offers and related consent solicitations (“Exchange Offers”) with respect to certain outstanding debt of Calpine. Pursuant to the Exchange Offers, we issued new notes in January 2026 effectively replacing $2.3 billion of Calpine's senior unsecured and secured notes. Using the proceeds from our January 2026 bond issuance, as described more fully below, along with cash on hand and short-term debt, we repaid Calpine corporate term loans totaling $2.5 billion immediately after the acquisition closing and repaid additional Calpine senior secured first lien notes totaling $1.25 billion in February 2026. Following the debt exchange and redemptions discussed, approximately $1.5 billion of long-term Calpine corporate debt remains outstanding, which matures primarily in March 2028. See Note 16 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information. • We assumed approximately $5 billion of various project financing arrangements including: ◦ Calpine Construction Finance Company, L.P. (CCFC) term loan, a first lien senior secured facility with $2.1 billion outstanding at acquisition. The CCFC term loan matures July 2030 and is secured by certain real and personal property of CCFC, primarily seven natural gas-fired power plants. ◦ Geysers Power Company, LLC (GPC) term loan and credit facility, a first lien senior secured term loan facility, with approximately $1.35 billion and $45 million of borrowings outstanding under the term loan and credit facility, respectively, at acquisition. The GPC term loan and credit facility mature May 2029. The GPC term loan and credit facility is secured by certain real and personal property of GPC and subsidiaries primarily consisting of the Geysers Assets. 73 Table of Contents ◦ Nova Power, LLC (Nova Power) credit agreement, comprising credit facilities intended to finance a portion of the cost of the development, construction and operation of the Nova Power battery storage project. These facilities include a first lien term loan with $591 million outstanding at acquisition and letter of credit facilities. The Nova Power credit agreement matures September 2031 and is secured by Nova Power's real and personal property. ◦ Greenfield LP (Greenfield) loan facility which includes a term loan with $342 million outstanding at acquisition and several letters of credit facilities. The Greenfield loan facility matures November 2030 and is secured by certain real and personal property, primarily the Greenfield Energy Center in Ontario, Canada. ◦ Pin Oak Creek Energy Center loan pursuant to the TEF with lender, PUCT, with an outstanding amount of $230 million at acquisition. The proceeds were used to finance anticipated eligible costs for the development, construction, and installation of Pin Oak Creek Energy Center in Texas. The loan will mature in October 2045. ◦ Calpine Development Holdings, LLC Revolver (CDHI Revolver) with total capacity of approximately $1.2 billion and borrowings totaling $319 million outstanding at acquisition. The CDHI Revolver matures March 2028. • During 2025, we amended our RCF to increase the capacity from $4.5 billion to $7.0 billion, of which the incremental $2.5 billion became available upon closing of the Calpine acquisition. As a result, Calpine's revolving credit facility and commodity linked revolver were both paid off and terminated at the time of acquisition. See Note 16 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information. • We issued senior unsecured notes in January 2026 totaling $2.75 billion, the proceeds from which were used to retire certain outstanding indebtedness of Calpine following completion of the Calpine acquisition. See Note 16 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information. • In addition to the Calpine revolving credit facility and commodity linked revolver referenced above, we assumed credit facilities totaling approximately $2.3 billion of capacity, which is reduced by outstanding borrowings under the GPC term loan facility and CDHI Revolver totaling $364 million. At the time of the acquisition, there were outstanding letters of credit on the assumed facilities of approximately $1.7 billion. These facilities consist of secured and unsecured Calpine facilities and project facilities including the CDHI Revolver. • We assumed Calpine's accounts receivable sales program with a financial institution which allows for the sale of, at a discount, up to $500 million of certain Calpine receivables. The program is set to mature November 2026. At the time of acquisition, there was $399 million of accounts receivable sold into the program outstanding. Dividends Quarterly dividends declared by our Board of Directors during 2025 and for the first quarter of 2026 were as follows: Period Declaration Date Shareholder of Record Date Dividend Payable Date Cash per Share First Quarter of 2025 February 18, 2025 March 7, 2025 March 18, 2025 $ 0.3878 Second Quarter of 2025 April 29, 2025 May 16, 2025 June 6, 2025 $ 0.3878 Third Quarter of 2025 August 5, 2025 August 18, 2025 September 5, 2025 $ 0.3878 Fourth Quarter of 2025 October 29, 2025 November 17, 2025 December 5, 2025 $ 0.3878 First Quarter of 2026 February 20, 2026 March 9, 2026 March 20, 2026 $ 0.4265 74 Table of Contents Credit Matters and Cash Requirements We fund liquidity needs for capital expenditures, working capital, energy hedging and other financial commitments through cash flows from operations, public debt offerings, commercial paper markets and large, diversified credit facilities. As of December 31, 2025, we have access to facilities with aggregate bank commitments of $9.5 billion. We had access to the commercial paper markets and had availability under our revolving credit facilities during 2025 to fund our short-term liquidity needs, when necessary. We routinely review the sufficiency of our liquidity position, including appropriate sizing of credit facility commitments, by performing various stress test scenarios, such as commodity price movements, increases in margin-related transactions, changes in hedging levels, and the impacts of hypothetical credit downgrades. We closely monitor events in the financial markets and the financial institutions associated with the credit facilities, including monitoring credit ratings and outlooks, credit default swap levels, capital raising, and merger activity. See PART I, ITEM 1A. RISK FACTORS for additional information regarding the effects of uncertainty in the capital and credit markets. We believe our cash flow from operating activities, access to credit markets and our credit facilities provide sufficient liquidity to support the estimated future cash requirements discussed below, including the cash consideration used to close on our acquisition of Calpine. See Note 2 — Mergers, Acquisitions, and Dispositions of the Combined Notes to Consolidated Financial Statements for additional information. Security Ratings Our access to the capital markets, including the commercial paper market, and our financing costs in those markets, may depend on our security ratings. A loss of investment grade credit rating would have required a three-notch downgrade by S&P or Moody's from their current levels as of December 31, 2025 of BBB+ and Baa1, to BB+ and Ba1 or below, respectively. As of December 31, 2025, we had $7.4 billion of available capacity under our credit facilities and $3.6 billion of cash on hand. In the event of a credit downgrade below investment grade and a resulting requirement to provide incremental collateral exceeding available capacity under our credit facilities and cash on hand, we would be required to access additional liquidity through the capital markets. Our borrowings are not subject to default or prepayment as a result of a downgrade of our securities, although such a downgrade could increase fees and interest charges under our credit agreements. Our credit ratings were affirmed by Moody’s and S&P in January 2026 following the completion of the acquisition of Calpine. If we had lost our investment grade credit ratings as of December 31, 2025, we would have been required to provide incremental collateral estimated to be approximately $2.7 billion to meet collateral obligations for derivatives, non-derivatives, NPNS, and applicable payables and receivables, net of the contractual right of offset under master netting agreements. See Note 15 — Derivative Financial Instruments and Note 16 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information. Capital Expenditures Our most recent estimate of capital expenditures, inclusive of Calpine, is approximately $5.7 billion and $4.7 billion for 2026 and 2027, respectively. Approximately 29% of projected capital expenditures is for the acquisition of nuclear fuel, which includes additional nuclear fuel to increase inventory levels in response to the potential for the continuing Russia and Ukraine conflict to impact our long-term nuclear fuel supply. Additionally, the above estimates of capital expenditures include $3.9 billion of growth capital expenditures, including our planned restart of Crane, nuclear uprates, co-location infrastructure, and license renewals. The remaining amounts primarily reflect additions and upgrades to existing generation facilities (including material condition improvements during nuclear refueling outages). See ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS, Other Key Business Drivers for more information on the Russia and Ukraine conflict. Planned additions, upgrades and other investments are subject to periodic review and revision to reflect changes in economic conditions impacting our generating assets and other factors, including, but not limited to, market power prices, results of capacity auctions, potential legislative and regulatory actions, impacts of inflation, changes in the cost of materials and labor, and financing costs. We anticipate funding these capital expenditures with a combination of internally generated funds and borrowings. 75 Table of Contents Pension and Other Postretirement Benefits We consider various factors when making qualified pension funding decisions, including actuarially determined minimum contribution requirements under ERISA, contributions required to avoid benefit restrictions and at-risk status as defined by the Pension Protection Act, and management of the pension obligation. The Pension Protection Act requires the attainment of certain funding levels to avoid benefit restrictions (such as an inability to pay lump sums or to accrue benefits prospectively) and at-risk status (which triggers higher minimum contribution requirements and participant notification). The contributions in the table below reflect a funding strategy to make annual contributions to offset the growth of the liability. Unlike the qualified pension plans, our non-qualified pension plans are not subject to statutory minimum contribution requirements. OPEB plans are also not subject to statutory minimum contribution requirements, though we have funded a portion of our plans. Annually, we evaluate whether additional funding for those plans is needed. For our funded OPEB plans, we consider several factors in determining the level of our contributions, including liabilities management and levels of benefit claims paid. Expected contributions in 2026 or future years could be affected by adjustments in our pension and OPEB funding strategy, market conditions, or pension regulation changes. See Note 14 — Retirement Benefits of the Combined Notes to Consolidated Financial Statements for additional information on pension and OPEB contributions. Cash Requirements for Other Financial Commitments The following table summarizes our projected cash payments as of December 31, 2025 under existing financial commitments with fixed or minimum payments required: 2026 Beyond 2026 Total Time Period Long-term debt $ 92 $ 7,311 $ 7,403 2026 - 2054 Interest payments on long-term debt (a) 415 5,377 5,792 2026 - 2054 Operating leases (b) 56 353 409 2026 - 2056 Purchase power obligations (c) 772 1,199 1,971 2026 - 2043 Fuel purchase agreements (d) 1,742 9,087 10,829 2026 - 2040 Other purchase obligations (e) 1,873 2,825 4,698 2026 - 2057 SNF obligation — 1,426 1,426 2026 - 2040 Pension contributions (f) 162 650 812 2026 - 2031 Cash consideration for the acquisition of Calpine (g) 4,500 — 4,500 2026 Total cash requirements $ 9,612 $ 28,228 $ 37,840 __________ (a) Interest payments are estimated based on final maturity dates of debt securities outstanding at December 31, 2025 and do not reflect anticipated future refinancing, early redemptions, or debt issuances. Variable rate interest obligations are estimated based on rates as of December 31, 2025. (b) Capacity payments associated with contracted generation lease agreements are net of sublease and capacity offsets of $48 million and $181 million for 2026 and beyond 2026, respectively and $229 million in total. (c) Purchase power obligations primarily include REC purchases and capacity payments that are not unit contingent. (d) Represents commitments to purchase nuclear fuel and related services and natural gas-related transportation and capacity. (e) Represents the future estimated value at December 31, 2025 of the cash flows associated with all contracts, both cancellable and non-cancellable, entered into with third parties for the provision of services and materials, entered into in the normal course of business not specifically reflected elsewhere in this table. These estimates are subject to significant variability from period to period. (f) These amounts represent our expected contributions to our qualified pension plans. (g) In January 2026, we acquired all of the outstanding equity interest of Calpine in a cash and stock transaction. The aggregate purchase price included approximately $4.5 billion in cash. See Note 2 — Mergers, Acquisitions, and Dispositions of the Combined Notes to the Combined Consolidated for additional information. 76 Table of Contents See Note 18 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for additional information on our other commitments potentially triggered by future events. Additionally, see below for where to find additional information regarding the financial commitments in the table above in the Combined Notes to Consolidated Financial Statements. Item Location within Combined Notes to Consolidated Financial Statements Long-term debt Note 16 — Debt and Credit Agreements Interest payments on long-term debt Note 16 — Debt and Credit Agreements Operating leases Note 11 — Leases SNF obligation Note 18 — Commitments and Contingencies Pension contributions Note 14 — Retirement Benefits Accounts Receivable Facility We have an accounts receivable financing facility that provides us access to revolving loans from a number of financial institutions secured by certain customer accounts receivables. See Note 16 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information. Project Financing Project financing is based upon a nonrecourse financial structure, in which project debt is paid back from the cash generated by a specific asset or portfolio of assets. Borrowings under these agreements are secured by the assets and equity of each respective project. Lenders do not have recourse against us in the event of a default. If a project financing entity does not maintain compliance with its specific debt covenants, there could be a requirement to accelerate repayment of the associated debt or other project-related borrowings earlier than the stated maturity dates. In these instances, if such repayment were not satisfied, or restructured, the lenders or security holders would generally have rights to foreclose against the project-specific assets and related collateral. The potential requirement to repay the debt or other borrowings earlier than otherwise anticipated could lead to impairments due to a higher likelihood of disposing of the respective project-specific assets significantly before the end of their useful lives. See Note 16 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information on project finance credit facilities and nonrecourse debt. Credit Facilities We meet our short-term liquidity requirements primarily through the issuance of commercial paper. We may use our credit facilities for general corporate purposes, including meeting short-term funding requirements and the issuance of letters of credit. During 2025, we increased the capacity of our RCF from $4.5 billion to $7.0 billion, of which the incremental $2.5 billion became available upon closing of the Calpine acquisition in January 2026. See Note 16 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information on our credit facilities. Capital Structure At December 31, 2025, our capital structure consisted of the following: Percentage of Capital Structure Commercial paper and notes payable 7 % Long-term debt 31 % Member’s equity 62 % NRC Minimum Funding Requirements NRC regulations require that licensees of nuclear generating facilities demonstrate reasonable assurance that sufficient funds will be available in certain minimum amounts for radiological decommissioning of the facility. These NRC minimum funding levels are typically based upon the assumption that decommissioning activities will commence after the end of the current licensed life of each unit. If a unit fails the NRC minimum funding test, then the plant’s owners or parent companies would be required to take steps, such as providing financial 77 Table of Contents guarantees through surety bonds, letters of credit, or parent company guarantees or making additional cash contributions to the NDT fund to ensure sufficient funds are available. See Note 10 — Asset Retirement Obligations of the Combined Notes to Consolidated Financial Statements for additional information. If a nuclear plant were to retire before the end of its licensed life, there is a risk that it will no longer meet the NRC minimum funding requirements due to the earlier commencement of decommissioning activities and a shorter time period over which the NDT funds could appreciate in value. A shortfall could require that we address the shortfall by providing additional financial assurances, such as surety bonds, letters of credit, or parent company guarantees for our share of the funding assurance. However, the amount of any assurance will ultimately depend on the decommissioning approach, the associated level of costs, and the NDT fund investment performance going forward. No later than two years after shutting down a plant, we must submit a Post-shutdown Decommissioning Activities Report (PSDAR) to the NRC that includes the planned option for decommissioning the site. Upon issuance of any additional financial assurance mechanisms to address a decommissioning funding shortfall, subject to satisfying various regulatory preconditions, each site would be able to utilize the respective NDT funds for radiological decommissioning costs, which represent the majority of the total expected decommissioning costs. However, under the regulations, the NRC must approve an exemption in order for us to utilize the NDT funds to pay for non-radiological decommissioning costs (i.e., spent fuel management and site restoration costs, if applicable). Any amounts not covered by an exemption would be borne by us without reimbursement. As of December 31, 2025, the Crane NDT is fully funded under the SAFSTOR scenario that was the planned decommissioning option, as described in the Crane PSDAR filed with the NRC in April 2019. We will continue to file Crane's decommissioning funding status with the NRC annually until restart, at which point we will file decommissioning funding status reports in accordance with applicable NRC requirements. Additionally, as of December 31, 2025, we have adequate NDT funds for the remaining radiological decommissioning cost at Zion Station related to the Independent Spent Fuel Storage Installation. Decommissioning costs other than radiological may require funding from us. See Note 10 — Asset Retirement Obligations of the Combined Notes to Consolidated Financial Statements for additional information. ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK 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. 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 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 78 Table of Contents 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. 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 December 31, 2025 for our portfolio associated with a hypothetical $5/MWh reduction in the annual average around-the-clock energy price results in an impact to earnings that is not material for 2026 and 2027. See Note 15 — 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. 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 35% of our uranium concentrate requirements from 2026 through 2030 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 results of operation or financial condition. See ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS — Other Key Business Drivers for more 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 January 1, 2024 to December 31, 2025. This table incorporates the unrealized gains and losses that are immediately recorded in earnings. This table excludes all NPNS contracts. See Note 15 — 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 December 31, 2025 and 2024. 2025 2024 Beginning balance as of January 1 (a) $ 317 $ 1,108 Total change in fair value of contracts recorded in results of operations (725) (654) Reclassification to realized at settlement of contracts recorded in results of operations 104 1,934 Changes in allocated collateral 764 (1,813) Net option premium paid (received) (38) (216) Option premium amortization 103 (32) Upfront payments and amortizations (b) (23) (10) Foreign currency translation 2 — Ending balance as of December 31 (a) $ 504 $ 317 __________ (a) Amounts are shown net of collateral paid to and received from counterparties. (b) Includes derivative contracts acquired or sold through upfront payments or receipts of cash, excluding option premiums, and the associated amortizations. 79 Table of Contents Fair Values The following table presents maturity and source of fair value for commodity derivative contract net assets (liabilities). See Note 17 — 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 Within Total Fair Value 2026 2027 2028 2029 2030 2031 and Beyond Commodity derivative contracts (a) : Actively quoted prices (Level 1) $ 145 $ 26 $ (17) $ (12) $ — $ — $ 142 Prices provided by external sources (Level 2) 86 99 31 6 — — 222 Prices based on model or other valuation methods (Level 3) 236 (130) 14 (10) (28) 58 140 Total $ 467 $ (5) $ 28 $ (16) $ (28) $ 58 $ 504 __________ (a) Amounts are shown net of collateral paid to and received from counterparties (and offset against derivative assets and liabilities) of $1,352 million at December 31, 2025. 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 15 — 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 15 — Derivative Financial Instruments and Note 18 — 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 results of operation or financial condition. 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 7. 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. 80 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, 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 solely 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 results of operations or financial condition. 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 and Foreign Exchange 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 year ended December 31, 2025. To manage foreign exchange rate exposure associated with international energy purchases in currencies other than U.S. dollars, we utilize foreign currency derivatives, which are typically designated as economic hedges. See Note 15 — 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 point increase in interest rates and 10% decrease in equity prices would have resulted in a $1,099 million reduction in the fair value of our NDT trust assets as of December 31, 2025. This calculation holds all other variables constant and assumes only the discussed changes in interest rates and equity prices. See Liquidity and Capital Resources section of ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS, and Note 10 — Asset Retirement Obligations of the Combined Notes to Consolidated Financial Statements 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 for sensitivity analysis of key assumptions in the valuation of our Pension and OPEB obligations. 81 Table of Contents ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA Management’s Report on Internal Control Over Financial Reporting The management of Constellation Energy Corporation (CEG Parent) is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rule 13a-15(f). Internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. CEG Parent’s management assessed the effectiveness of CEG Parent’s internal control over financial reporting as of December 31, 2025. In making this assessment, management used the criteria in Internal Control—Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this assessment, CEG Parent’s management concluded that, as of December 31, 2025, CEG Parent’s internal control over financial reporting was effective. The effectiveness of CEG Parent’s internal control over financial reporting as of December 31, 2025, has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report which appears herein. February 24, 2026 Management’s Report on Internal Control Over Financial Reporting The management of Constellation Energy Generation, LLC (Constellation) is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rule 13a-15(f). Internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. Constellation’s management assessed the effectiveness of Constellation’s internal control over financial reporting as of December 31, 2025. In making this assessment, management used the criteria in Internal Control—Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this assessment, Constellation’s management concluded that, as of December 31, 2025, Constellation’s internal control over financial reporting was effective. February 24, 2026 82 Table of Contents Report of Independent Registered Public Accounting Firm To the Board of Directors and Shareholders of Constellation Energy Corporation Opinions on the Financial Statements and Internal Control over Financial Reporting We have audited the consolidated financial statements, including the related notes, as listed in the index appearing under Item 15(a)(1)(i), and the financial statement schedule listed in the index appearing under Item 15(a)(1)(ii), of Constellation Energy Corporation and its subsidiaries (the “Company”) (collectively referred to as the “consolidated financial statements”). We also have audited the Company's internal control over financial reporting as of December 31, 2025, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of the Company as of December 31, 2025 and 2024, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2025 in conformity with accounting principles generally accepted in the United States of America. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2025, based on criteria established in Internal Control - Integrated Framework (2013) issued by the COSO. Basis for Opinions The Company's management is responsible for these consolidated financial statements, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting, included in Management’s Report on Internal Control Over Financial Reporting appearing under Item 8. Our responsibility is to express opinions on the Company’s consolidated financial statements and on the Company's internal control over financial reporting based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB. We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud, and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the consolidated financial statements included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions. Definition and Limitations of Internal Control over Financial Reporting A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements. 83 Table of Contents Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. Critical Audit Matters The critical audit matter communicated below is a matter arising from the current period audit of the consolidated financial statements that was communicated or required to be communicated to the audit committee and that (i) relates to accounts or disclosures that are material to the consolidated financial statements and (ii) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates. Nuclear Decommissioning Asset Retirement Obligations (ARO) Assessment As described in Notes 1 and 10 to the consolidated financial statements, the Company has a legal obligation to decommission its nuclear power plants following the permanent cessation of operations. To estimate its decommissioning obligations management uses a probability- weighted, discounted cash flow model which, on a unit-by-unit basis, considers multiple outcome scenarios that include significant estimates and assumptions, and are based on decommissioning cost studies, cost escalation rates, probabilistic cash flow models, and discount rates. Management updates its ARO annually, unless circumstances warrant more frequent updates, based on its review of updated cost studies and its annual evaluation of cost escalation factors and probabilities assigned to various scenarios. As of December 31, 2025, the nuclear decommissioning ARO was $12.9 billion. The principal considerations for our determination that performing procedures relating to the Company’s nuclear decommissioning ARO assessment is a critical audit matter are (i) the significant judgment by management when estimating its decommissioning obligations; (ii) a high degree of auditor judgment, subjectivity, and effort in performing procedures and evaluating the reasonableness of management’s discounted cash flow model and significant assumptions related to decommissioning cost studies; and (iii) the audit effort involved the use of professionals with specialized skill and knowledge. Addressing the matter involved performing procedures and evaluating audit evidence in connection with forming our overall opinion on the consolidated financial statements. These procedures included testing the effectiveness of controls relating to management’s development of the inputs, assumptions, and discounted cash flow model used in management’s ARO assessment. These procedures also included, among others (i) testing management’s process for estimating the decommissioning obligations by evaluating the appropriateness of the discounted cash flow model; (ii) testing the completeness and accuracy of data used by management; and (iii) evaluating the reasonableness of management’s significant assumptions related to decommissioning cost studies. Professionals with specialized skill and knowledge were used to assist in evaluating the results of decommissioning cost studies. /s/ PricewaterhouseCoopers LLP Baltimore, Maryland February 24, 2026 We have served as the Company's auditor since 2022. 84 Table of Contents Report of Independent Registered Public Accounting Firm To the Board of Directors and Member of Constellation Energy Generation, LLC Opinion on the Financial Statements We have audited the consolidated financial statements, including the related notes, as listed in the index appearing under Item 15(a)(2)(i), and the financial statement schedule listed in the index appearing under Item 15(a)(2)(ii), of Constellation Energy Generation, LLC and its subsidiaries (the “Company”) (collectively referred to as the “consolidated financial statements”). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2025 and 2024, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2025 in conformity with accounting principles generally accepted in the United States of America. Basis for Opinion These consolidated financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on the Company’s consolidated financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB. We conducted our audits of these consolidated financial statements in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion. Our audits included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. We believe that our audits provide a reasonable basis for our opinion. Critical Audit Matters The critical audit matter communicated below is a matter arising from the current period audit of the consolidated financial statements that was communicated or required to be communicated to the audit committee and that (i) relates to accounts or disclosures that are material to the consolidated financial statements and (ii) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates. Nuclear Decommissioning Asset Retirement Obligations (ARO) Assessment As described in Notes 1 and 10 to the consolidated financial statements, the Company has a legal obligation to decommission its nuclear power plants following the permanent cessation of operations. To estimate its decommissioning obligations management uses a probability- weighted, discounted cash flow model which, on a unit-by-unit basis, considers multiple outcome scenarios that include significant estimates and assumptions, and are based on decommissioning cost studies, cost escalation rates, probabilistic cash flow models, and discount rates. Management updates its ARO annually, unless circumstances warrant more frequent updates, based on its review of updated cost studies and its annual evaluation of cost escalation factors and probabilities assigned to various scenarios. As of December 31, 2025, the nuclear decommissioning ARO was $12.9 billion. The principal considerations for our determination that performing procedures relating to the Company’s nuclear decommissioning ARO assessment is a critical audit matter are (i) the significant judgment by management when 85 Table of Contents estimating its decommissioning obligations; (ii) a high degree of auditor judgment, subjectivity, and effort in performing procedures and evaluating the reasonableness of management’s discounted cash flow model and significant assumptions related to decommissioning cost studies; and (iii) the audit effort involved the use of professionals with specialized skill and knowledge. Addressing the matter involved performing procedures and evaluating audit evidence in connection with forming our overall opinion on the consolidated financial statements. These procedures included testing the effectiveness of controls relating to management’s development of the inputs, assumptions, and discounted cash flow model used in management’s ARO assessment. These procedures also included, among others (i) testing management’s process for estimating the decommissioning obligations by evaluating the appropriateness of the discounted cash flow model; (ii) testing the completeness and accuracy of data used by management; and (iii) evaluating the reasonableness of management’s significant assumptions related to decommissioning cost studies. Professionals with specialized skill and knowledge were used to assist in evaluating the results of decommissioning cost studies. /s/ PricewaterhouseCoopers LLP Baltimore, Maryland February 24, 2026 We have served as the Company's auditor since 2001. 86 Table of Contents Constellation Energy Corporation and Subsidiary Companies Consolidated Statements of Operations and Comprehensive Income For the Years Ended December 31, (In millions, except per share data) 2025 2024 2023 Operating revenues $ 25,533 $ 23,568 $ 24,918 Operating expenses Purchased power and fuel 14,681 11,419 16,001 Operating and maintenance 6,159 6,159 5,685 Depreciation and amortization 985 1,123 1,096 Taxes other than income taxes 622 586 553 Total operating expenses 22,447 19,287 23,335 Gain (loss) on sales of assets and businesses — 71 27 Operating income (loss) 3,086 4,352 1,610 Other income and (deductions) Interest expense, net ( 511 ) ( 506 ) ( 431 ) Other, net 936 670 1,268 Total other income and (deductions) 425 164 837 Income (loss) before income taxes 3,511 4,516 2,447 Income tax (benefit) expense 1,187 774 859 Equity in income (losses) of unconsolidated affiliates ( 1 ) ( 4 ) ( 11 ) Net income (loss) 2,323 3,738 1,577 Net income (loss) attributable to noncontrolling interests 4 ( 11 ) ( 46 ) Net income (loss) attributable to common shareholders $ 2,319 $ 3,749 $ 1,623 Comprehensive income (loss), net of income taxes Net income (loss) $ 2,323 $ 3,738 $ 1,577 Other comprehensive income (loss), net of income taxes Pension and non-pension postretirement benefit plans: Prior service benefit reclassified to periodic benefit cost ( 4 ) ( 4 ) ( 4 ) Actuarial loss reclassified to periodic cost 72 75 25 Pension and non-pension postretirement benefit plans valuation adjustment ( 219 ) ( 176 ) ( 453 ) Unrealized gain (loss) on cash flow hedges 7 4 ( 1 ) Unrealized gain (loss) on foreign currency translation 21 ( 10 ) 2 Other comprehensive income (loss), net of income taxes ( 123 ) ( 111 ) ( 431 ) Comprehensive income (loss) $ 2,200 $ 3,627 $ 1,146 Comprehensive income (loss) attributable to noncontrolling interests 4 ( 11 ) ( 46 ) Comprehensive income (loss) attributable to common shareholders $ 2,196 $ 3,638 $ 1,192 Average shares of common stock outstanding: Basic 313 315 323 Assumed exercise and/or distributions of stock-based awards 1 — 1 Diluted 314 315 324 Earnings per average common share Basic $ 7.40 $ 11.91 $ 5.02 Diluted $ 7.40 $ 11.89 $ 5.01 See the Combined Notes to Consolidated Financial Statements 87 Table of Contents Constellation Energy Corporation and Subsidiary Companies Consolidated Statements of Cash Flows For the Years Ended December 31, (In millions) 2025 2024 2023 Cash flows from operating activities Net income (loss) $ 2,323 $ 3,738 $ 1,577 Adjustments to reconcile net income (loss) to net cash flows provided by (used in) operating activities Depreciation, amortization, and accretion, including nuclear fuel and energy contract amortization 2,601 2,700 2,514 Deferred income taxes and amortization of ITCs 273 222 251 Net fair value changes related to derivatives 645 ( 1,297 ) 996 Net realized and unrealized (gains) losses on NDT funds ( 708 ) ( 311 ) ( 476 ) Net realized and unrealized (gains) losses on equity investments 279 ( 11 ) ( 307 ) Other non-cash operating activities ( 223 ) ( 172 ) 18 Changes in assets and liabilities: Accounts receivable ( 363 ) 688 396 Inventories ( 134 ) ( 99 ) 60 Accounts payable and accrued expenses 316 1,121 ( 1,330 ) Option premiums received (paid), net 38 216 26 Collateral received (posted), net ( 773 ) 1,803 ( 1,491 ) Income taxes 625 296 325 Pension and non-pension postretirement benefit contributions ( 211 ) ( 184 ) ( 54 ) Other assets and liabilities ( 451 ) ( 11,174 ) ( 7,806 ) Net cash flows provided by (used in) operating activities 4,237 ( 2,464 ) ( 5,301 ) Cash flows from investing activities Capital expenditures ( 2,949 ) ( 2,565 ) ( 2,422 ) Proceeds from NDT fund sales 6,946 6,005 5,822 Investment in NDT funds ( 7,284 ) ( 6,282 ) ( 6,050 ) Collection of DPP, net — 10,217 7,340 Acquisitions of assets and businesses ( 14 ) ( 32 ) ( 1,690 ) Other investing activities 103 85 31 Net cash flows provided by (used in) investing activities ( 3,198 ) 7,428 3,031 Cash flows from financing activities Change in short-term borrowings — ( 1,105 ) 146 Proceeds from short-term borrowings with maturities greater than 90 days 1,650 200 539 Repayments of short-term borrowings with maturities greater than 90 days — ( 739 ) ( 200 ) Issuance of long-term debt — 920 3,195 Retirement of long-term debt ( 1,076 ) ( 121 ) ( 168 ) Dividends paid on common stock ( 486 ) ( 444 ) ( 366 ) Repurchases of common stock ( 400 ) ( 999 ) ( 992 ) Other financing activities ( 108 ) ( 1 ) 42 Net cash flows provided by (used in) financing activities ( 420 ) ( 2,289 ) 2,196 Increase (decrease) in cash, restricted cash, and cash equivalents 619 2,675 ( 74 ) Cash, restricted cash, and cash equivalents at beginning of period 3,129 454 528 Cash, restricted cash, and cash equivalents at end of period $ 3,748 $ 3,129 $ 454 Supplemental disclosure of non-cash investing and financing activities Increase (decrease) in DPP $ — $ 9,045 $ 8,097 Increase (decrease) in PP&E related to ARO update 187 ( 1,486 ) 501 See the Combined Notes to Consolidated Financial Statements 88 Table of Contents Constellation Energy Corporation and Subsidiary Companies Consolidated Balance Sheets December 31, (In millions) 2025 2024 ASSETS Current assets Cash and cash equivalents $ 3,641 $ 3,022 Restricted cash and cash equivalents 107 107 Accounts receivable, net 4,266 3,718 Derivative assets 945 843 Inventories, net 1,736 1,600 Renewable energy credits 789 797 Other 635 689 Total current assets 12,119 10,776 Property, plant, and equipment (net of accumulated depreciation and amortization of $ 19,072 and $ 18,088 , respectively) 22,474 21,235 Deferred debits and other assets Nuclear decommissioning trust funds 19,336 17,305 Goodwill 420 420 Derivative assets 450 372 Other 2,450 2,818 Total deferred debits and other assets 22,656 20,915 Total assets (a) $ 57,249 $ 52,926 LIABILITIES AND EQUITY Current liabilities Short-term borrowings $ 1,650 $ — Long-term debt due within one year 92 1,028 Accounts payable and accrued expenses 4,294 3,943 Derivative liabilities 467 467 Renewable energy credit obligation 1,075 1,076 Other 366 332 Total current liabilities 7,944 6,846 Long-term debt 7,250 7,384 Deferred credits and other liabilities Deferred income taxes and unamortized ITCs 3,544 3,331 Asset retirement obligations 13,193 12,449 Pension and non-pension postretirement benefit obligations 1,977 1,875 Payables related to Regulatory Agreement Units 5,334 4,518 Derivative liabilities 414 399 Other 2,740 2,585 Total deferred credits and other liabilities 27,202 25,157 Total liabilities (a) 42,396 39,387 Commitments and contingencies (Note 18) Shareholders' equity Common stock ( No par value, 1,000 shares authorized, 312 shares and 313 shares outstanding, respectively) 11,043 11,402 Retained earnings (deficit) 5,899 4,066 Accumulated other comprehensive income (loss), net ( 2,425 ) ( 2,302 ) Total shareholders' equity 14,517 13,166 Noncontrolling interests 336 373 Total equity 14,853 13,539 Total liabilities and shareholders' equity $ 57,249 $ 52,926 __________ (a) Our consolidated assets include $ 4,551 million and $ 4,318 million at December 31, 2025 and 2024, respectively, of certain VIEs that can only be used to settle the liabilities of the VIE. Our consolidated liabilities include $ 914 million and $ 968 million at December 31, 2025 and 2024, respectively, of certain VIEs for which the VIE creditors do not have recourse to us. See Note 21–Variable Interest Entities for additional information. See the Combined Notes to Consolidated Financial Statements 89 Table of Contents Constellation Energy Corporation and Subsidiary Companies Consolidated Statements of Changes in Equity Shareholders' Equity Noncontrolling Interests Total Equity (In millions, shares in thousands) Issued Shares Common Stock Retained Earnings (Deficit) Accumulated Other Comprehensive Income (Loss), net Balance, December 31, 2022 327,130 $ 13,274 $ ( 496 ) $ ( 1,760 ) $ 354 $ 11,372 Net Income (loss) — — 1,623 — ( 46 ) 1,577 Employee incentive plans 902 81 — — — 81 Changes in equity of noncontrolling interest — — — — 53 53 Common stock dividends ($ 0.2820 /common share) — — ( 366 ) — — ( 366 ) Common stock repurchased ( 10,560 ) ( 1,000 ) — — — ( 1,000 ) Other comprehensive income (loss), net of income taxes — — — ( 431 ) — ( 431 ) Balance, December 31, 2023 317,472 $ 12,355 $ 761 $ ( 2,191 ) $ 361 $ 11,286 Net Income (loss) — — 3,749 — ( 11 ) 3,738 Employee incentive plans 885 56 — — — 56 Changes in equity of noncontrolling interest — — — — 23 23 Common stock dividends ($ 0.3525 /common share) — — ( 444 ) — — ( 444 ) Common stock repurchased ( 5,519 ) ( 1,009 ) — — — ( 1,009 ) Other comprehensive income (loss), net of income taxes — — — ( 111 ) — ( 111 ) Balance, December 31, 2024 312,838 $ 11,402 $ 4,066 $ ( 2,302 ) $ 373 $ 13,539 Net Income (loss) — — 2,319 — 4 2,323 Employee incentive plans 799 39 — — — 39 Changes in equity of noncontrolling interest — — — — ( 41 ) ( 41 ) Common stock dividends ($ 0.3878 /common share) — — ( 486 ) — — ( 486 ) Common stock repurchased ( 1,282 ) ( 404 ) — — — ( 404 ) Capped call option contracts — 6 — — — 6 Other comprehensive income (loss), net of income taxes — — — ( 123 ) — ( 123 ) Balance, December 31, 2025 312,355 $ 11,043 $ 5,899 $ ( 2,425 ) $ 336 $ 14,853 See the Combined Notes to Consolidated Financial Statements 90 Table of Contents Constellation Energy Generation, LLC and Subsidiary Companies Consolidated Statements of Operations and Comprehensive Income For the Years Ended December 31, (In millions) 2025 2024 2023 Operating revenues $ 25,533 $ 23,568 $ 24,918 Operating expenses Purchased power and fuel 14,681 11,419 16,001 Operating and maintenance 6,159 6,159 5,685 Depreciation and amortization 985 1,123 1,096 Taxes other than income taxes 622 586 553 Total operating expenses 22,447 19,287 23,335 Gain (loss) on sales of assets and businesses — 71 27 Operating income (loss) 3,086 4,352 1,610 Other income and (deductions) Interest expense, net ( 511 ) ( 506 ) ( 431 ) Other, net 936 670 1,268 Total other income and (deductions) 425 164 837 Income (loss) before income taxes 3,511 4,516 2,447 Income tax (benefit) expense 1,187 774 859 Equity in income (losses) of unconsolidated affiliates ( 1 ) ( 4 ) ( 11 ) Net income (loss) 2,323 3,738 1,577 Net income (loss) attributable to noncontrolling interests 4 ( 11 ) ( 46 ) Net income (loss) attributable to membership interest $ 2,319 $ 3,749 $ 1,623 Comprehensive income (loss), net of income taxes Net income (loss) $ 2,323 $ 3,738 $ 1,577 Other comprehensive income (loss), net of income taxes Pension and non-pension postretirement benefit plans: Prior service benefit reclassified to periodic benefit cost ( 4 ) ( 4 ) ( 4 ) Actuarial loss reclassified to periodic benefit cost 72 75 25 Pension and non-pension postretirement benefit plans valuation adjustment ( 219 ) ( 176 ) ( 453 ) Unrealized gain (loss) on cash flow hedges 7 4 ( 1 ) Unrealized gain (loss) on foreign currency translation 21 ( 10 ) 2 Other comprehensive income (loss), net of income taxes ( 123 ) ( 111 ) ( 431 ) Comprehensive income (loss) $ 2,200 $ 3,627 $ 1,146 Comprehensive income (loss) attributable to noncontrolling interests 4 ( 11 ) ( 46 ) Comprehensive income (loss) attributable to membership interest $ 2,196 $ 3,638 $ 1,192 See the Combined Notes to Consolidated Financial Statements 91 Table of Contents Constellation Energy Generation, LLC and Subsidiary Companies Consolidated Statements of Cash Flows For the Years Ended December 31, (In millions) 2025 2024 2023 Cash flows from operating activities Net income (loss) $ 2,323 $ 3,738 $ 1,577 Adjustments to reconcile net income (loss) to net cash flows provided by (used in) operating activities Depreciation, amortization, and accretion, including nuclear fuel and energy contract amortization 2,601 2,700 2,514 Deferred income taxes and amortization of ITCs 273 222 251 Net fair value changes related to derivatives 645 ( 1,297 ) 996 Net realized and unrealized (gains) losses on NDT funds ( 708 ) ( 311 ) ( 476 ) Net realized and unrealized (gains) losses on equity investments 279 ( 11 ) ( 307 ) Other non-cash operating activities ( 304 ) ( 218 ) ( 44 ) Changes in assets and liabilities: Accounts receivable ( 363 ) 697 389 Receivables from and payables to affiliates, net 16 231 73 Inventories ( 134 ) ( 99 ) 60 Accounts payable and accrued expenses 326 1,116 ( 1,330 ) Option premiums received (paid), net 38 216 26 Collateral received (posted), net ( 773 ) 1,803 ( 1,491 ) Income taxes 625 296 325 Pension and non-pension postretirement benefit contributions ( 211 ) ( 184 ) ( 54 ) Other assets and liabilities ( 464 ) ( 11,369 ) ( 7,897 ) Net cash flows provided by (used in) operating activities 4,169 ( 2,470 ) ( 5,388 ) Cash flows from investing activities Capital expenditures ( 2,949 ) ( 2,565 ) ( 2,422 ) Proceeds from NDT fund sales 6,946 6,005 5,822 Investment in NDT funds ( 7,284 ) ( 6,282 ) ( 6,050 ) Collection of DPP, net — 10,217 7,340 Acquisitions of assets and businesses ( 14 ) ( 32 ) ( 1,690 ) Other investing activities 103 85 31 Net cash flows provided by (used in) investing activities ( 3,198 ) 7,428 3,031 Cash flows from financing activities Change in short-term borrowings — ( 1,105 ) 146 Proceeds from short-term borrowings with maturities greater than 90 days 1,650 200 539 Repayments of short-term borrowings with maturities greater than 90 days — ( 739 ) ( 200 ) Issuance of long-term debt — 920 3,195 Retirement of long-term debt ( 1,076 ) ( 121 ) ( 168 ) Distributions to member ( 1,035 ) ( 1,441 ) ( 1,239 ) Contributions from member 156 — — Other financing activities ( 61 ) 3 23 Net cash flows provided by (used in) financing activities ( 366 ) ( 2,283 ) 2,296 Increase (decrease) in cash, restricted cash, and cash equivalents 605 2,675 ( 61 ) Cash, restricted cash, and cash equivalents at beginning of period 3,115 440 501 Cash, restricted cash, and cash equivalents at end of period $ 3,720 $ 3,115 $ 440 Supplemental disclosure of non-cash investing and financing activities Increase (decrease) in DPP $ — $ 9,045 $ 8,097 Increase (decrease) in PP&E related to ARO update 187 ( 1,486 ) 501 See the Combined Notes to Consolidated Financial Statements 92 Table of Contents Constellation Energy Generation, LLC and Subsidiary Companies Consolidated Balance Sheets December 31, (In millions) 2025 2024 ASSETS Current assets Cash and cash equivalents $ 3,641 $ 3,018 Restricted cash and cash equivalents 79 97 Accounts receivable, net 4,251 3,703 Derivative assets 945 843 Inventories, net 1,736 1,600 Renewable energy credits 789 797 Other 634 689 Total current assets 12,075 10,747 Property, plant, and equipment (net of accumulated depreciation and amortization of $ 19,072 and $ 18,088 , respectively) 22,474 21,235 Deferred debits and other assets Nuclear decommissioning trust funds 19,336 17,305 Goodwill 420 420 Derivative assets 450 372 Other 2,443 2,814 Total deferred debits and other assets 22,649 20,911 Total assets (a) $ 57,198 $ 52,893 LIABILITIES AND EQUITY Current liabilities Short-term borrowings $ 1,650 $ — Long-term debt due within one year 92 1,028 Accounts payable and accrued expenses 4,033 3,696 Payables to affiliates 365 349 Derivative liabilities 467 467 Renewable energy credit obligation 1,075 1,076 Other 358 328 Total current liabilities 8,040 6,944 Long-term debt 7,250 7,384 Deferred credits and other liabilities Deferred income taxes and unamortized ITCs 3,544 3,331 Asset retirement obligations 13,193 12,449 Pension and non-pension postretirement benefit obligations 1,977 1,875 Payables related to Regulatory Agreement Units 5,334 4,518 Derivative liabilities 414 399 Other 2,583 2,410 Total deferred credits and other liabilities 27,045 24,982 Total liabilities (a) 42,335 39,310 Commitments and contingencies (Note 18) Equity Member’s equity Membership interest 10,144 10,538 Undistributed earnings (deficit) 6,808 4,974 Accumulated other comprehensive income (loss), net ( 2,425 ) ( 2,302 ) Total member’s equity 14,527 13,210 Noncontrolling interests 336 373 Total equity 14,863 13,583 Total liabilities and equity $ 57,198 $ 52,893 __________ (a) Our consolidated assets include $ 4,551 million and $ 4,318 million as of December 31, 2025 and 2024, respectively, of certain VIEs that can only be used to settle the liabilities of the VIE. Our consolidated liabilities include $ 914 million and $ 968 million as of December 31, 2025 and 2024, respectively, of certain VIEs for which the VIE creditors do not have recourse to us. See Note 21–Variable Interest Entities for additional information. See the Combined Notes to Consolidated Financial Statements 93 Table of Contents Constellation Energy Generation, LLC and Subsidiary Companies Consolidated Statements of Changes in Equity Member’s Equity Noncontrolling Interests Total Equity (In millions) Membership Interest Undistributed Earnings (Deficit) Accumulated Other Comprehensive Income (Loss), net Balance, December 31, 2022 $ 12,408 $ 412 $ ( 1,760 ) $ 354 $ 11,414 Net Income (loss) — 1,623 — ( 46 ) 1,577 Changes in equity of noncontrolling interests — — — 53 53 Distribution to member ( 871 ) ( 368 ) — — ( 1,239 ) Other comprehensive income (loss), net of income taxes — — ( 431 ) — ( 431 ) Balance, December 31, 2023 $ 11,537 $ 1,667 $ ( 2,191 ) $ 361 $ 11,374 Net Income (loss) — 3,749 — ( 11 ) 3,738 Changes in equity of noncontrolling interests — — — 23 23 Distribution to member ( 999 ) ( 442 ) — — ( 1,441 ) Other comprehensive income (loss), net of income taxes — — ( 111 ) — ( 111 ) Balance, December 31, 2024 $ 10,538 $ 4,974 $ ( 2,302 ) $ 373 $ 13,583 Net Income (loss) — 2,319 — 4 2,323 Changes in equity of noncontrolling interest — — — ( 41 ) ( 41 ) Contribution from member 156 — — — 156 Distribution to member ( 550 ) ( 485 ) — — ( 1,035 ) Other comprehensive income (loss), net of income taxes — — ( 123 ) — ( 123 ) Balance, December 31, 2025 $ 10,144 $ 6,808 $ ( 2,425 ) $ 336 $ 14,863 See the Combined Notes to Consolidated Financial Statements 94 Table of Contents Combined Notes to Consolidated Financial Statements (Dollars in millions, unless otherwise noted) 1. Basis of Presentation Description of Business We are the nation's largest producer of clean energy and a leading supplier of energy products and services. Our generating capacity includes primarily nuclear, wind, solar, and hydroelectric assets. Through our integrated business operations, we sell electricity, natural gas, and other energy-related products and sustainable solutions to various types of customers, including distribution utilities, municipalities, cooperatives, and commercial, industrial, public sector, and residential customers in markets across multiple geographic regions. We have five reportable segments: Mid-Atlantic, Midwest, New York, ERCOT, and Other Power Regions. Basis of Presentation Constellation Energy Corporation (“CEG Parent” or the “Company”), a Pennsylvania corporation, was formed for the purpose of separation of Constellation Energy Generation, LLC (“Constellation”, formerly Exelon Generation Company, LLC) and its subsidiaries from its predecessor parent company, Exelon Corporation (“Exelon”), into an independent, publicly traded company. On February 1, 2022, the separation was completed by distributing all the outstanding shares of the Company’s common stock, on a pro rata basis to the holders of its predecessor’s common stock, with the Company holding all the interests in Constellation previously held by Exelon (the “Separation”). Constellation has been an individual registrant since 2002 with the registration of its public debt securities under the Securities Act. Prior to the Separation, Constellation historically filed consolidated financial statements as an individual registrant to reflect its financial position and operating results as a stand-alone, wholly owned subsidiary of Exelon. The accompanying Consolidated Financial Statements have been prepared in accordance with GAAP for annual financial statements and in accordance with the instructions to Form 10-K and Regulation S-X promulgated by the SEC. The Consolidated Financial Statements include the accounts of our subsidiaries and all intercompany transactions have been eliminat ed. Certain prior period amounts have been reclassified to conform to the presentation in the current period. Amounts disclosed relate to CEG Parent and Constellation unless specifically noted as relating to CEG Parent only. Unless otherwise indicated or the context otherwise requires, references herein to the terms “we,” “us,” and “our” refer collectively to CEG Parent and Constellation. We own 100% of our significant consolidated subsidiaries, either directly or indirectly, except for certain consolidated VIEs. The remaining interests in the consolidated VIEs are included in noncontrolling interests in the Consolidated Balance Sheets. See Note 21 — Variable Interest Entities for additional information on consolidated VIEs. We consolidate the accounts of entities in which we have a controlling financial interest, after the elimination of intercompany transactions. Where we do not have a controlling financial interest in an entity, proportionate consolidation, equity method accounting or accounting for investments in equity securities with or without readily determinable fair value is applied. We proportionately consolidate our undivided ownership interest in jointly-owned electric plants. Under proportionate consolidation, we separately record our proportionate share of the assets, liabilities, revenues and expenses related to the undivided interest in the asset. See Note 9 — Jointly-Owned Electric Plants for additional information on the application of proportionate consolidation. We apply equity method accounting when we have a significant influence over an investee through an ownership in equity, which generally approximates to a 20% to 50% voting interest. We apply equity method accounting to certain investments and joint ventures. Under equity method accounting, we report our interest in the entity as an investment and our percentage share of the earnings from the entity as single line items in our consolidated financial statements. We use accounting for investments in equity securities with or without readily determinable fair values if we lack significant influence, which generally results when we hold less than 20% of the common stock of an entity. Under accounting for investments in equity securities with readily determinable fair values, the investments are reported based on quoted prices in active markets and realized and unrealized gains and losses are included in earnings. Under accounting for investments in equity securities without readily determinable fair values, the investments are reported at cost, adjusted for changes from observable transactions for identical or similar investments of the same issuer, less impairment, and changes in measurement are reported in earnings. 95 Table of Contents Combined Notes to Consolidated Financial Statements (Dollars in millions, unless otherwise noted) Note 1 — Basis of Presentation Use of Estimates The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the amounts reported in the financial statements and accompanying notes. Areas in which significant estimates have been made include, but are not limited to, the accounting for nuclear decommissioning costs and other AROs, pension and OPEB plans, inventory reserves, allowance for credit losses, long-lived asset valuations and impairment assessments, derivative instruments, goodwill, UECs, fixed asset depreciation, environmental costs and other loss contingencies, taxes and unbilled energy revenues. Actual results could differ materially from those estimates. Revenues Operating Revenues. Our operating revenues generally consist of revenues from contracts with customers involving competitive sales of power, natural gas, and other energy-related products and sustainable solutions. We recognize revenue from contracts with customers to depict the transfer of goods or services to customers in an amount that we expect to be entitled to in exchange for those goods or services. At the end of each reporting period, we accrue an estimate for the unbilled amount of power and natural gas delivered or services provided to customers. Commodity Derivatives. Derivative instruments are generally recorded at fair value with subsequent changes in fair value recognized as realized and unrealized revenue or expense. The classification of revenue or expense is based on the intent of the transaction. See Note 15 — Derivative Financial Instruments for additional information. Taxes Directly Imposed on Revenue-Producing Transactions. We collect certain taxes from customers such as sales and gross receipts taxes, along with other taxes, surcharges and fees, that are levied by state or local governments on the sale or distribution of electricity and natural gas and any taxable energy-related products and sustainable solutions. Some of these taxes are imposed on the customer, but paid by us, while others are imposed on us. Where these taxes are imposed on the customer, such as sales taxes, they are reported on a net basis in revenues. However, where these taxes are imposed on us, such as gross receipts taxes, they are reported on a gross basis in revenue and expense in the Consolidated Statements of Operations and Comprehensive Income. Government Assistance. As a result of the enactment of the IRA, we qualify for certain federal government incentives through eligible activities. These incentives include both refundable and transferable tax credits. The current U.S. GAAP framework does not address the receipt of government assistance by for-profit entities. We account for this government assistance by analogy to International Accounting Standard (IAS) 20, Accounting for Government Grants and Disclosure of Government Assistance, and recognize the benefits when there is reasonable assurance that we will comply with the required conditions and that the benefits will be received. We believe the reasonable assurance term as used in IAS 20 is analogous to the term probable as defined under GAAP related to accounting for contingencies. See Note 6 — Government Assistance for additional information. Leases We recognize a ROU asset and lease liability for operating leases with a term of greater than one year. Operating lease ROU assets are included in Other deferred debits and other assets and operating lease liabilities are included in Other current liabilities and Other deferred credits and other liabilities in the Consolidated Balance Sheets. The ROU asset is measured as the sum of (1) the present value of all remaining fixed and in-substance fixed payments using the rate implicit in the lease whenever that is readily determinable or our incremental borrowing rate, (2) any lease payments made at or before the commencement date (less any lease incentives received) and (3) any initial direct costs incurred. The lease liability is measured the same as the ROU asset, but excludes any payments made before the commencement date and initial direct costs incurred. Lease terms include options to extend or terminate the lease if it is reasonably certain they will be exercised. We include non-lease components for most asset classes, which are service-related costs that are not integral to the use of the asset, in the measurement of the ROU asset and lease liability. Expense for operating leases and leases with a term of one year or less is recognized on a straight-line basis over the term of the lease, unless another systematic and rational basis is more representative of the derivation of benefit from use of the leased property. Variable lease payments are recognized in the period in which the related obligation is incurred and consist primarily of payments for purchases of electricity under contracted 96 Table of Contents Combined Notes to Consolidated Financial Statements (Dollars in millions, unless otherwise noted) Note 1 — Basis of Presentation generation that are based on the electricity produced by those generating assets. Operating lease expense and variable lease payments are recorded to Purchased power and fuel expense for contracted generation or Operating and maintenance expense for all other lease agreements in the Consolidated Statements of Operations and Comprehensive Income. Income from operating leases, including subleases, is recognized on a straight-line basis over the term of the lease, unless another systematic and rational basis is more representative of the pattern in which income is earned over the term of the lease. Variable lease payments are recognized in the period in which the related obligation is performed and consist primarily of payments received from sales of electricity under contracted generation that are based on the electricity produced by those generating assets. Operating lease income and variable lease payments are recorded to Operating revenues in the Consolidated Statements of Operations and Comprehensive Income. Our operating leases consist primarily of contracted generation, real estate including office buildings, and vehicles and equipment. We generally account for contracted generation in which the generating asset is not renewable as a lease if the customer has dispatch rights and obtains substantially all the economic benefits. We generally do not account for contracted generation in which the generating asset is renewable as a lease if the customer does not design the generating asset. We account for land right arrangements that provide for exclusive use as leases while shared use land arrangements are generally not leases. See Note 11 — Leases for additional information. Income Taxes Deferred federal and state income taxes are recorded on temporary differences between the book and tax basis of assets and liabilities and for tax benefits carried forward. ITCs have been deferred in the Consolidated Balance Sheets and are recognized in book income over the life of the related property. We account for uncertain income tax positions using a benefit recognition model with a two-step approach; a more-likely-than-not recognition criterion and a measurement approach that measures the position as the largest amount of tax benefit that is greater than 50% likely of being realized upon ultimate settlement. If it is not more likely than not that the benefit of the tax position will be sustained on its technical merits, no benefit is recorded. Uncertain tax positions that relate only to timing of when an item is included on a tax return are considered to have met the recognition threshold. We recognize accrued interest related to unrecognized tax benefits in Interest expense, net or Other, net (interest income) and recognize penalties related to unrecognized tax benefits in Other, net in the Consolidated Statements of Operations and Comprehensive Income. Cash and Cash Equivalents We consider investments purchased with an original maturity of three months or less to be cash equivalents. Restricted Cash and Cash Equivalents Restricted cash and cash equivalents represent funds that are restricted to satisfy designated current liabilities. As of December 31, 2025 and 2024, restricted cash and cash equivalents primarily represented the payment of medical, dental, vision, and long-term disability benefits and project-specific nonrecourse financing structures for debt service and financing of operations of the underlying entities. See Note 16 — Debt and Credit Agreements and Note 22 — Supplemental Financial Information for additional information. Allowance for Credit Losses on Accounts Receivables The allowance for credit losses reflects our best estimate of losses on the customers' accounts receivable balances based on historical experience and current information. The allowance for credit losses for our retail and wholesale customers is based on accounts receivable aging historical experience coupled with specific identification through a credit monitoring process, which considers current conditions such as industry trends, macroeconomic factors, changes in the regulatory environment, external credit ratings, publicly available news, payment status, payment history, and the exercise of collateral calls. When a wholesale customer’s risk characteristics are no longer aligned with the pooled population, we use specific identification to develop an allowance for credit losses. Adjustments to the allowance for credit losses are 97 Table of Contents Combined Notes to Consolidated Financial Statements (Dollars in millions, unless otherwise noted) Note 1 — Basis of Presentation recorded in Operating and maintenance expense in the Consolidated Statements of Operations and Comprehensive Income. We have certain non-customer receivables in Current Assets and Other deferred debits and other assets which primarily are with governmental agencies. The allowance for credit losses related to these receivables is not material. We monitor these balances and will record an allowance if there are indicators of a decline in credit quality. Variable Interest Entities We account for our investments in and arrangements with VIEs based on the following specific requirements: • qualitative assessment of factors determinant in whether we have a controlling financial interest, • ongoing reconsideration of this assessment, and • where we consolidate a VIE (as primary beneficiary), disclosure of (1) the assets of the consolidated VIE, if they can be used to only settle specific obligations of the consolidated VIE, and (2) the liabilities of a consolidated VIE for which creditors do not have recourse to the general credit of the primary beneficiary. See Note 21 — Variable Interest Entities for additional information. Inventories Inventory is recorded at the lower of weighted average cost or net realizable value. Reserves are recorded for excess and obsolete inventory. Natural gas, oil, and emission allowances are generally included in Inventory when delivered and are expensed to Purchased power and fuel expense when consumed. Materials and supplies are generally included in Inventory when delivered and are expensed to Operating and maintenance, or capitalized to Property, plant and equipment, as appropriate, when installed or used. Debt and Equity Security Investments Debt and Equity Investments within NDT funds. We have debt and equity securities held in our NDT funds which are measured and recorded at fair value. Realized and unrealized gains and losses, net of trust-level taxes, on our NDT funds associated with the Regulatory Agreement Units are offset in Noncurrent payables related to Regulatory Agreement Units. Realized and unrealized gains and losses, net of trust-level taxes, on our NDT funds associated with the Non-Regulatory Agreement Units are included in Other, net in the Consolidated Statements of Operations and Comprehensive Income. For equity securities without readily determinable fair values, we have elected to use the NAV for qualifying investments as a practical expedient to determine the fair values. Our NDT funds are classified as current or noncurrent assets, depending on the timing of the decommissioning activities and expected payment of income taxes on trust earnings. See Note 10 — Asset Retirement Obligations and Note 17 — Fair Value of Financial Assets and Liabilities for additional information. Equity Security Investments. We hold equity securities both with and without readily determinable fair values. For those with readily determinable fair values, realized and unrealized gains and losses are recognized in Other, net within the Consolidated Statements of Operations and Comprehensive Income. For those without readily determinable fair values, we have elected the measurement alternative, which records investments at cost adjusted for observable transactions involving identical or similar investments of the same issuer, less impairment. Changes in measurement under this alternative are also reported in Other, net within the Consolidated Statements of Operations and Comprehensive Income. Investments in equity securities without readily determinable fair values are qualitatively assessed for impairment each reporting period. If it is determined that the equity security is impaired, an impairment loss will be recognized in Other, net in the Consolidated Statements of Operations and Comprehensive Income in the amount by which the security’s carrying amount exceeds its fair value. See Note 17 — Fair Value of Financial Assets and Liabilities for additional information. Property, Plant and Equipment Property, plant and equipment is recorded at acquired cost. Acquired cost includes construction-related direct labor and material costs. When appropriate, acquired cost also includes capitalized interest. Costs associated 98 Table of Contents Combined Notes to Consolidated Financial Statements (Dollars in millions, unless otherwise noted) Note 1 — Basis of Presentation with outages and planned major maintenance activities are expensed to Operating and maintenance expense or capitalized to Property, plant, and equipment based on the nature of the activities in the period incurred. The cost of repairs and maintenance and minor replacements of property are charged to Operating and maintenance expense in the Consolidated Statements of Operations and Comprehensive Income as incurred. Upon retirement, the cost of property is generally charged to accumulated depreciation in accordance with the composite and group methods of depreciation. Upon replacement of an asset, the costs to remove the asset, net of salvage, are capitalized to gross plant when incurred as part of the cost of the newly installed asset and recorded to depreciation expense over the life of the new asset. Removal costs, net of salvage, incurred for property that will not be replaced is charged to Operating and maintenance expense as incurred. Certain assets follow the unitary method of depreciation and recognize gains and losses in the period of replacement or retirement. These gains and losses are recorded in Operating and maintenance expense in the Consolidated Statements of Operations and Comprehensive Income. Capitalized Software. Certain costs, such as design, coding, and testing incurred during the application development stage of software projects that are internally developed or purchased for operational use are capitalized in Property, plant and equipment in the Consolidated Balance Sheets. Similar costs incurred for cloud-based solutions treated as service arrangements are capitalized in Other current assets and Deferred debits and other assets in the Consolidated Balance Sheets. Such capitalized amounts are amortized ratably over the expected lives of the projects when they become operational, generally not to exceed five years . Capitalized Interest. During construction, we capitalize the costs of debt funds. Most projects will use a debt rate calculated using the general corporate debt pool. In some cases, projects are specifically financed and use a project-specific debt rate, which is excluded from the general corporate debt pool. Capitalization of debt funds is recorded as a charge to construction work in progress and as a non-cash credit to interest expense. See Note 8 — Property, Plant, and Equipment, Note 9 — Jointly-Owned Electric Plants and Note 22 — Supplemental Financial Information for additional information. Nuclear Fuel The cost of nuclear fuel is capitalized in Property, plant and equipment and charged to Purchased power and fuel using the unit-of-production method. Any potential future SNF disposal fees will also be expensed through Purchased power and fuel expense. Additionally, certain on-site SNF storage costs are being reimbursed by the DOE since a DOE (or government-owned) long-term storage facility has not been completed. See Note 18 — Commitments and Contingencies for additional information regarding the cost of SNF storage and disposal. Depreciation and Amortization Except for the amortization of nuclear fuel, depreciation, inclusive of ARC, is generally recorded over the estimated useful lives of property, plant and equipment on a straight-line basis using the group, composite or unitary methods of depreciation. Two methods of depreciating multiple asset groups exist: the group method and the composite method. The group method is typically for groups of assets that are largely homogenous and have approximately the same useful lives. The composite method is used when the assets are heterogeneous and have different lives. Under both methods, a reporting entity depreciates the assets over the average life of the assets in the group. The estimated useful lives are based on a combination of depreciation studies, historical retirements, site licenses and management estimates of operating costs and expected future energy market conditions. See Note 8 — Property, Plant, and Equipment for additional information regarding depreciation, and Note 22 — Supplemental Financial Information for additional information regarding amortization expense of nuclear fuel. Asset Retirement Obligations We estimate and recognize a liability for our legal obligation to perform asset retirement activities even though the timing and/or methods of settlement may be conditional on future events. We generally update our nuclear decommissioning AROs annually, unless circumstances warrant more frequent updates, based on our annual evaluation of cost escalation factors and probabilities assigned to the multiple outcome scenarios within our probability-weighted discounted cash flow models. Our multiple outcome scenarios are generally based on decommissioning cost studies which are updated, on a rotational basis, for each of our nuclear units at least every five years, unless circumstances warrant more frequent updates. AROs are accreted throughout each year to reflect the time value of money for these present value obligations through a charge to Operating and 99 Table of Contents Combined Notes to Consolidated Financial Statements (Dollars in millions, unless otherwise noted) Note 1 — Basis of Presentation maintenance expense in the Consolidated Statements of Operations and Comprehensive Income for Non-Regulatory Agreement Units and through an offsetting decrease in noncurrent payables related to Regulatory Agreement Units. See Note 10 — Asset Retirement Obligations for additional information. Accounting Implications of the Regulatory Agreement Units Based on the requirements of the ICC, PAPUC, and PUCT that dictate our obligations related to the shortfall or excess of NDT funds necessary for decommissioning the former ComEd, former PECO, and STP units, decommissioning-related activities net of applicable taxes, including realized and unrealized gains and losses on the NDT funds, depreciation of the ARC, and accretion of the decommissioning obligation are generally offset in the Consolidated Statements of Operations and Comprehensive Income and are recorded as noncurrent payables within Payables related to Regulatory Agreement Units in the Consolidated Balance Sheets. See Note 10 — Asset Retirement Obligations for additional information. Asset Impairments Long-Lived Assets. We regularly monitor and evaluate the carrying value of long-lived assets or asset groups for recoverability whenever events or changes in circumstances indicate that the carrying value of those assets may not be recoverable. Indicators of impairment may include a deteriorating business climate, including, but not limited to, declines in energy prices, condition of the asset, or plans to dispose of a long-lived asset significantly before the end of its useful life. We determine if long-lived assets or asset groups are potentially impaired by comparing the undiscounted expected future cash flows to the carrying value when indicators of impairment exist. When the undiscounted cash flow analysis indicates a long-lived asset or asset group may not be recoverable, the amount of the impairment loss is determined by measuring the excess of the carrying amount of the long-lived asset or asset group over its fair value. Impairment losses are recorded in Operating and maintenance expense in the Consolidated Statements of Operations and Comprehensive Income. Goodwill. Goodwill represents the excess of the purchase price paid over the estimated fair value of the net assets acquired and liabilities assumed in the acquisition of a business. Goodwill is not amortized, but is tested for impairment at least annually or on an interim basis if an event occurs or circumstances change that would more likely than not reduce the fair value of a reporting unit below its carrying value. See Note 2 — Mergers, Acquisitions, and Dispositions and Note 12 — Intangible Assets for additional information. Equity Method Investments. We regularly monitor and evaluate equity method investments to determine whether they are impaired. An impairment is recorded when the investment has experienced a decline in value that is other-than-temporary in nature. Additionally, if the entity in which we hold an investment recognizes an impairment loss, we would record the proportionate share of that impairment loss and evaluate the investment for an other-than-temporary decline in value. These impairment losses are recorded in Equity in income (losses) of unconsolidated affiliates in the Consolidated Statements of Operations and Comprehensive Income. Derivative Financial Instruments All derivatives are recognized on the balance sheet at their fair value unless they qualify for certain exceptions, including NPNS. For derivatives intended to serve as economic hedges, changes in fair value are recognized in earnings each period. Amounts classified in earnings are included in Operating revenues, Purchased power and fuel, or Interest expense in the Consolidated Statements of Operations and Comprehensive Income based on the activity the transaction is economically hedging. Cash inflows and outflows related to derivative instruments are included as a component of operating, investing, or financing cash flows in the Consolidated Statements of Cash Flows, depending on the nature of each transaction. As part of our customer-facing business, we enter into contracts to buy and sell energy to meet the requirements of our customers. These contracts include short-term and long-term commitments to purchase and sell energy and energy-related products in the energy markets with the intent and ability to deliver or take delivery of the underlying physical commodity. NPNS are contracts where physical delivery is probable, quantities are expected to be used or sold in the normal course of business over a reasonable period and will not be financially settled. Revenues and expenses on derivative contracts that qualify, and are designated, as NPNS are recognized when the underlying physical transaction is completed. While these contracts are considered derivative financial instruments, they are not required to be recorded at fair value. See Note 15 — Derivative Financial Instruments for additional information. 100 Table of Contents Combined Notes to Consolidated Financial Statements (Dollars in millions, unless otherwise noted) Note 1 — Basis of Presentation Retirement Benefits We sponsor defined benefit pension and OPEB plans as described in Note 14 — Retirement Benefits. The plan obligations and costs of providing benefits under these plans are remeasured annually as of year end. The measurements involve various factors, assumptions, and accounting policy elections. The impact of assumption changes or experiences different from that assumed on pension and OPEB obligations are recognized over time, not immediately in the Consolidated Statements of Operations and Comprehensive Income. For defined benefit pension plans, gains or losses exceeding the greater of 10% of the PBO or the MRV of plan assets are amortized over the expected average remaining service period of plan participants. For OPEB plans, gains or losses exceeding the greater of 10% of the APBO or the MRV of plan assets are amortized over the average future remaining lifetime of the current inactive population. We separately report the pension and OPEB service cost and non-service cost (credit) components of net periodic benefit costs (credits) for all plans in our Consolidated Statements of Operations and Comprehensive Income. The service cost component remains in Operating and maintenance expense and Property, plant, and equipment, net (where criteria for capitalization of direct labor has been met) while the non-service cost (credit) components are included in Other, net, in accordance with single-employer plan accounting. Renewable Energy Certificates/Credits RECs are included in Renewable energy credits in the Consolidated Balance Sheets. Purchased RECs are recorded at cost when delivered and internally generated RECs are recognized at a zero-cost basis when generated. The cost of RECs purchased on a stand-alone basis is based on the transaction price, while the cost of RECs acquired through PPAs represents the relative fair value at contract inception. Generally, revenue for RECs that are sold to a counterparty under a contract that specifically identifies a power plant is recognized at a point in time when the power is produced. This includes both bundled and unbundled REC sales. Otherwise, the revenue is recognized upon physical transfer of the REC to the customer. 2. Mergers, Acquisitions, and Dispositions Acquisition of Calpine Corporation On January 7, 2026, we acquired all the outstanding equity interest of Calpine in a cash and stock transaction for a purchase price of approximately $ 22 billion. The merger consideration consisted of an aggregate of 50 million newly issued shares of our common stock, no par value, and approximately $ 4.5 billion in cash. In connection with the merger, the newly issued shares will be subject to a lock-up period which expires on June 30, 2026 for 50 % of the shares and on June 30, 2027 for the remaining 50 %. For information on the debt assumed as part of the transaction, see Note 16 — Debt and Credit Agreements. Calpine owns and operates a generation fleet of natural gas, geothermal, battery storage, and solar assets with approximately 23 GWs of generation capacity, after considering divestitures required by certain regulatory approvals for the transaction, including the DOJ resolution. This resolution was the final regulatory clearance to complete the merger of Calpine and Constellation. The DOJ resolution requires that we divest five generating assets located in PJM, one in ERCOT, and Calpine's minority interest in the Gregory Power Plant, also in ERCOT. Four of these assets were already subject to FERC divestiture requirements. The DOJ resolution requires us to enter into definitive agreement(s) to divest these assets within 240 days of closing the Calpine acquisition, i.e., by September 4, 2026. In January 2026, Calpine completed the divestiture of its minority ownership interest in the Gregory Power Plant as required under the terms of the DOJ resolution. We are taking steps to divest the remaining six power plants. In addition to operating a large generation fleet, Calpine also operates a competitive retail electric supplier platform serving approximately 62 TWhs of load annually. The transaction will be accounted for as a business combination using the acquisition method of accounting and we will record the fair value of the assets acquired and liabilities assumed as of the acquisition date. We expect that the consideration transferred is greater than the fair value of the net assets acquired, and therefore we anticipate recording goodwill on the opening balance sheet. Due to the recency of the acquisition date, the preliminary acquisition valuation for the business combination is incomplete at this time. Disclosures related to the acquisition date fair value of the assets acquired and liabilities assumed, among other acquisition-related disclosures, will be included in our March 31, 2026 Form 10-Q. 101 Table of Contents Combined Notes to Consolidated Financial Statements (Dollars in millions, unless otherwise noted) Note 2 — Mergers, Acquisitions, and Dispositions Fees incurred as part of the acquisition were not material to the Consolidated Statements of Operations and Comprehensive Income for the twelve months ended December 31, 2025. Acquisition of Joint Ownership in South Texas Project In November 2023, we completed the acquisition of NRG South Texas LP (renamed and converted as Constellation South Texas, LLC), which owns a 44 % undivided ownership interest in the jointly-owned STP, a 2,645 MW, dual-unit nuclear plant located in Bay City, Texas. The consideration transferred was $ 1.66 billion. Other owners include City Public Service Board of San Antonio (CPS, 40 %) and the City of Austin, Texas (Austin, 16 %). This acquisition is complementary to and aligned strategically with our existing clean energy business operations. The operating revenues and results of operations for STP have been included in the Consolidated Statements of Operations and Comprehensive Income from the date of acquisition and were not material for the year ended December 31, 2023. The pro forma effects of this acquisition were not significant to our reported results for the period of acquisition. Accordingly, no pro forma financial information has been presented herein. In May 2024, we executed a settlement agreement with all parties (CPS/City of San Antonio, Austin, and NRG Energy, Inc.), resolving all litigation involving our purchase of the ownership interest in STP. The terms of the settlement include us selling a 2 % ownership interest in STP to CPS at the same price and terms that we paid NRG Energy Inc. for our 44 % interest. We are working towards closing the transaction which has already received regulatory approvals (including the NRC and PUCT). The terms of settlement are not expected to have a material impact on our results of operations and financial condition. 3. Regulatory Matters The following matters below discuss the status of our material regulatory and legislative proceedings. New England Regulatory Matters Mystic Units 8 and 9 Cost of Service Agreement. In December 2018, FERC issued an order accepting a cost of service agreement for Mystic Units 8 and 9 for the period between June 1, 2022 to May 31, 2024. The agreement preserved the two gas-fired electric generating units for the period while allowing the Mystic units to recover their costs of operating, including a substantial portion of the costs associated with the adjacent EMT. Upon the expiration of the agreement on May 31, 2024, the two generating units retired. The Mystic COS required an annual process whereby we identified and supported our projected costs under the agreement and/or true-up previous projections to the actual costs incurred. Interested parties then had the opportunity to challenge our filings. All proceedings related to the annual files or outstanding matters related to the Mystic COS have been settled and approved by FERC. The settlements did not have a material financial impact on our consolidated financial statements. Federal Regulatory Matters One Big Beautiful Bill Act of 2025. In July 2025, the OBBBA was signed into law, which, among other things, permanently extends key provisions of the 2017 Tax Cuts and Jobs Act, including full bonus depreciation and immediate deduction of research and development expenses. In addition, the OBBBA preserves transferability and certain federal tax credits from the IRA, specifically, 45U for existing nuclear plants through 2032 and 45Y for new nuclear projects, including uprates, restarts, and new reactors, through 2035, while enhancing the credit to allow advanced nuclear facilities to qualify for the energy communities bonus adder, subject to eligibility requirements. As it relates to both 45U and 45Y, certain foreign entity of concern rules must be met to qualify for the respective credits. Overall, the OBBBA reinforces the long-term economic viability of our nuclear generation assets. While the provisions of the OBBBA resulted in acceleration of cash benefits of approximately $ 200 million, the impact of these provisions recognized in the year ended December 31, 2025 was not material to our results of operations. 102 Table of Contents Combined Notes to Consolidated Financial Statements (Dollars in millions, unless otherwise noted) Note 3 — Regulatory Matters Operating License Renewals Conowingo Hydroelectric Project. In 2012, we submitted an application to FERC for a new license for the Conowingo Hydroelectric Project (Conowingo). In connection with our efforts to obtain a water quality certification pursuant to Section 401 of the Clean Water Act (401 Certification) from MDE for Conowingo, we had been working with MDE and other stakeholders to resolve water quality licensing issues, including: (1) water quality, (2) fish habitat, and (3) sediment. In 2019, we and MDE filed with FERC a Joint Offer of Settlement (Offer of Settlement) that would resolve all outstanding issues relating to the 401 Certification. FERC subsequently issued a new 50-year license for Conowingo, effective March 1, 2021. Several environmental groups appealed FERC’s ruling to the U.S. Court of Appeals for the D.C. Circuit. The court of appeals issued a decision vacating FERC’s decision to grant Conowingo its license renewal and sending the matter back to FERC for further proceedings. Upon issuance of the mandate from the U.S. Court of Appeals for the D.C. Circuit, we began operating under an annual license, which renews automatically, containing the same terms as the license that was in effect prior to the 2021 FERC order. MDE informed us that as a result of the U.S. Court of Appeals decision, MDE would be resuming its administrative reconsideration of the 401 Certification. In September 2025, we reached a settlement agreement with MDE and the other parties to the MDE reconsideration proceeding, Lower Susquehanna Riverkeeper Association, and Waterkeepers Chesapeake, which resolves all outstanding issues relating to the 401 Certification. As a result, MDE issued a Revised Water Quality Certification, which is needed for FERC to move forward with the issuance of a new 50-year license. The Revised Water Quality Certification and accompanying settlement agreement provide for a modified operational flow regime, funding for water quality and resiliency projects, commitments for trash and debris removal, fish and eel passage improvements, funding for freshwater mussel restoration and control of invasive species like snakeheads and blue catfish, and funds to support additional studies on dredging and related activities. Our commitments under the various provisions of this settlement are not effective unless and until FERC approves and issues the new license. The terms of this settlement have no impact on the prior settlement agreement with the DOI. The financial impact of this settlement and other commitments related to this renewal are estimated to be $ 15 million to $ 20 million per year, on average, recognized over the term of the 50-year renewal, inclusive of capital and operating costs. The actual timing and amount of the majority of these costs are not currently fixed and will vary from year to year throughout the life of the new license. We cannot currently predict when FERC will issue the new license. Depreciation provisions continue to assume operation through 2071 given our expectation that a 50-year license will be issued. Peach Bottom Units 2 and 3. In March 2020, the NRC approved a second 20-year license renewal for Peach Bottom Units 2 and 3. As a result, Peach Bottom Units 2 and 3 were granted the authority to operate through 2053 and 2054, respectively. Notwithstanding its 2020 approval, in February 2022, the NRC took action to modify Peach Bottom's subsequently renewed licenses in response to a request for hearing that the NRC had not previously adjudicated. In its February 2022 decision, the NRC reversed itself and concluded that the previous environmental review required by the National Environmental Policy Act (NEPA) for the Peach Bottom subsequently renewed licenses was incomplete because it did not adequately address environmental impacts resulting from renewing the units’ licenses for an additional 20 years. As a result, the NRC undertook a rulemaking to modify its regulations and guidance to specifically address environmental impacts during the period of subsequent license renewal. In addition, the NRC modified the expiration dates for the Peach Bottom licenses from 2053 and 2054 to 2033 and 2034, respectively, pending the completion of the updated NEPA analysis. In September 2025, the NRC completed its environmental impact review of Peach Bottom Units 2 and 3, restoring the expiration dates of the respective operating licenses to 2053 and 2054, consistent with current accounting estimates utilized for both depreciation and ARO assumed retirement dates. 103 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. The performance obligations, revenue recognition, and payment terms associated with these sources of revenue are further discussed in the table below. There are no significant financing components for these sources of revenue. Unless otherwise noted, for each of the significant revenue categories and related performance obligations described below, we have the right to consideration from the customer in an amount that corresponds directly with the value transferred to the customer for the performance completed to date. Therefore, we generally recognize revenue in the amount for which we have the right to invoice the customer. As a result, there are generally no significant judgments used in determining or allocating the transaction price. Revenue Source Description Performance Obligation Timing of Revenue Recognition Payment Terms Power Sales Sales of power and other energy-related products to wholesale and retail customers through our customer-facing business Various, including the delivery of power (generally delivered over time) and other energy-related products such as capacity (generally delivered over time), CMCs, ZECs, RECs or other ancillary services (generally delivered at a point in time) Concurrently as power is generated for bundled power sale contracts (a) Generally within the month following delivery to the customer Natural Gas Sales Sales of natural gas to wholesale and retail customers through our customer-facing business Various, including the delivery of natural gas (generally delivered overtime) and sustainable natural gas attributes (generally delivered at a point in time) Over time as the natural gas is delivered to the customer Generally within the month following delivery to the customer Other Products and Services Sales of other energy-related products and sustainable solutions, such as long-term construction and installation of energy efficiency assets and new power generating facilities, primarily to C&I customers Construction and/or installation of the asset for the customer Revenues and associated costs are recognized throughout the contract term using an input method to measure progress towards completion (b) Generally within 30 or 45 days from the invoice date __________ (a) Certain contracts may contain limits on the total amount of revenue we are able to collect over the entire term of the contract. In such cases, we estimate the total consideration expected to be received over the term of the contract net of the constraint and allocate the expected consideration to the performance obligations in the contract such that revenue is recognized ratably over the term of the entire contract as the performance obligations are satisfied. (b) The method recognizes revenue based on the various inputs used to satisfy the performance obligation, such as costs incurred and total labor hours expended. The total amount of revenue that will be recognized is based on the agreed upon contractually-stated amount. The average contract term for these projects is approximately 18 months. 104 Table of Contents Combined Notes to Consolidated Financial Statements (Dollars in millions, unless otherwise noted) Note 4 — Revenue from Contracts with Customers We incur incremental costs in order to execute certain retail power and gas sales contracts. These costs, which primarily relate to retail broker fees and sales commissions, are capitalized when incurred as contract acquisition costs and generally amortized over the corresponding term of the contract. These capitalized costs and related amortization were not material as of and for the years ended December 31, 2025 and 2024. Transaction Price Allocated to Remaining Performance Obligations The following table shows the amounts of future revenues expected to be recorded in each year for performance obligations that are unsatisfied or partially unsatisfied as of December 31, 2025. This disclosure only includes contracts for which the total consideration is fixed and determinable at contract inception. The average contract term varies by customer type and commodity but ranges from one month to several years. This disclosure excludes mark-to-market derivatives and certain power and gas sales contracts which contain variable volumes and/or variable pricing. 2026 2027 2028 2029 2030 2031 and thereafter Total Remaining performance obligations $ 386 $ 269 $ 135 $ 117 $ 61 $ 79 $ 1,047 Transaction Price Allocated to Previously Satisfied Performance Obligations Our Clinton and Quad Cities units contract with certain utilities in Illinois which require delivery of all ZECs produced during each planning year (June through May), with total compensation limited by an annual cap for each planning year designed to limit the cost of ZECs to each utility's customers. ZECs delivered that, if paid, would result in the annual cap being exceeded may be paid in subsequent years at the vintage year price as long as the payments would not exceed the annual cap in the year paid. The program commenced June 2017 and continues through May 2027. In various planning years since the program began, we delivered ZECs to the utilities in excess of the annual compensation cap. The ZEC price and annual compensation cap effective for each planning year are administratively determined by the IPA. For the June 2025 through May 2026 planning year, the ZEC price has been established at $1.17 per ZEC, subject to an annual cap of $224 million. ZECs generated and delivered during this planning year will not exceed the annual cap and, as a result, we recognized $ 201 million of revenue during the second quarter of 2025 as a receivable for ZECs delivered in prior planning years, with payment expected in the third quarter of 2026. As of December 31, 2025, this receivable is included within Accounts receivable, net in the Consolidated Balance Sheets. For the June 2024 through May 2025 planning year, the ZEC price was established at $9.38 per ZEC, subject to an annual cap of $222 million. ZECs generated and delivered during this planning year did not exceed the annual cap, however the revenue recognized during the second quarter of 2024 for ZECs delivered in prior planning years was not material. For the June 2023 through May 2024 planning year, the ZEC price was established at $0.30 per ZEC, subject to an annual cap of $224 million. ZECs generated and delivered during the planning year did not exceed the annual cap, and as a result we recognized $ 218 million of revenue during the second quarter of 2023, with payment received in the third quarter of 2024. Revenue Disaggregation We disaggregate the revenue recognized from contracts with customers into categories that depict how the nature, amount, timing, and uncertainty of revenue and cash flows are affected by economic factors. See Note 5 — Segment Information for the presentation of revenue disaggregation. 105 Table of Contents Combined Notes to Consolidated Financial Statements (Dollars in millions, unless otherwise noted) Note 5 — Segment Information 5. Segment Information Operating segments are determined based on information used by the CODM in deciding how to evaluate performance and allocate resources. We have five reportable segments consisting of the Mid-Atlantic, Midwest, New York, ERCOT, and all other power regions referred to collectively as “Other Power Regions.” The basis for our reportable segments is the integrated management of our electricity business that is located in different geographic regions, and largely representative of the footprints of ISO/RTO and/or NERC regions, which utilize multiple supply sources to provide electricity through various distribution channels (wholesale and retail). Our hedging strategies and risk metrics are also aligned to these same geographic regions. Descriptions of each of our five reportable segments are as follows: • Mid-Atlantic represents operations in the eastern half of PJM, which includes New Jersey, Maryland, Vi