Constellation Energy Corp 10-K

ceg-20231231 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 , 2023 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 Exelon 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 ¨ 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, 2023 was as follows: Constellation Energy Corporation $ 29,396,464,132 Constellation Energy Generation, LLC Not applicable The number of shares outstanding of each registrant’s common stock as of January 31, 2024 was as follows: Constellation Energy Corporation Common Stock, without par value 316,666,538 Constellation Energy Generation, LLC Not applicable Documents Incorporated by Reference Portions of the Registrants’ Definitive Proxy Statement relating to the 2024 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, 2023. TABLE OF CONTENTS Page No. GLOSSARY OF TERMS AND ABBREVIATIONS 1 FILING FORMAT 5 CAUTIONARY STATEMENTS REGARDING FORWARD-LOOKING INFORMATION 5 WHERE TO FIND MORE INFORMATION 5 PART I ITEM 1. BUSINESS 6 General 6 Constellations Strategy and Outlook 17 Employees 19 Environmental Matters and Regulation 22 ITEM 1A. RISK FACTORS 33 ITEM 1B. UNRESOLVED STAFF COMMENTS 28 ITEM 1C. CYBERSECURITY 28 ITEM 2. PROPERTIES 30 ITEM 3. LEGAL PROCEEDINGS 32 ITEM 4. MINE SAFETY DISCLOSURES 46 PART II ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS, AND ISSUER PURCHASES OF EQUITY SECURITIES 46 ITEM 6. RESERVED 48 ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS 48 Executive Overview 48 Significant Transactions and Developments 49 Other Key Business Drivers 50 Critical Accounting Policies and Estimates 50 Financial Results of Operations 58 Liquidity and Capital Resources 67 ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK 76 ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA 81 Management's Report on Internal Control Over Financial Reporting 81 Report of Independent Registered Public Accounting Firm 82 Constellation Energy Corporation 86 Constellation Energy Generation, LLC 91 Combined Notes to Consolidated Financial Statements 96 1. Basis of Presentation 96 2. Mergers, Acquisitions, and Dispositions 103 3. Regulatory Matters 106 4. Revenue from Contracts with Customers 108 5. Segment Information 111 6. Accounts Receivable 114 7. Early Plant Retirements 115 8. Property, Plant, and Equipment 117 9. Jointly Owned Electric Plant 118 10. Asset Retirement Obligations 118 11. Leases 124 12. Asset Impairments 125 13. Intangible Assets 126 14. Income Taxes 127 15. Retirement Benefits 130 16. Derivative Financial Instruments 140 17. Debt and Credit Agreements 144 18. Fair Value of Financial Assets and Liabilities 149 19. Commitments and Contingencies 157 20. Shareholders' Equity 162 21. Stock-Based Compensation Plans 163 22. Variable Interest Entities 166 23. Supplemental Financial Information 169 24. Related Party Transactions 173 ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE 174 ITEM 9A. CONTROLS AND PROCEDURES 174 ITEM 9B. OTHER INFORMATION 174 ITEM 9C. DISCLOSURE REGARDING FOREIGN JURISDICTIONS THAT PREVENT INSPECTIONS 174 PART III ITEM 10. DIRECTORS, EXECUTIVE OFFICERS, AND CORPORATE GOVERNANCE 175 ITEM 11. EXECUTIVE COMPENSATION 176 ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS 176 ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR INDEPENDENCE 177 ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES 177 PART IV ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES 177 ITEM 16. FORM 10-K SUMMARY 184 SIGNATURES 185 Constellation Energy Corporation 185 Constellation Energy Generation, LLC 186 Table of Contents GLOSSARY OF TERMS AND ABBREVIATIONS Constellation Energy Corporation and Related Entities CEG Parent Constellation Energy Corporation Constellation Constellation Energy Generation, LLC (formerly Exelon Generation Company, LLC) Registrants CEG Parent and Constellation, collectively Antelope Valley Antelope Valley Solar Ranch One Continental Wind Continental Wind LLC CENG Constellation Energy Nuclear Group, LLC CR Constellation Renewables, LLC (formerly ExGen Renewables IV, LLC) CRP Constellation Renewables Partners, LLC (formerly ExGen Renewables Partners, LLC) FitzPatrick James A. FitzPatrick nuclear generating station Ginna R. E. Ginna 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 TMI Three Mile Island nuclear facility 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 PHI Pepco Holdings LLC Pepco Potomac Electric Power Company DPL Delmarva Power & Light Company ACE Atlantic City Electric Company BSC Exelon Business Services Company, LLC 1 Table of Contents GLOSSARY OF TERMS AND ABBREVIATIONS Other Terms and Abbreviations ABO Accumulated Benefit Obligation AEC Alternative Energy Credit that is issued for each megawatt hour of generation from a qualified alternative energy source AEP Texas American Electric Power Texas AESO Alberta Electric Systems Operator AOCI Accumulated Other Comprehensive Income (Loss) APBO Accumulated Post-Retirement Benefit Obligation ARC Asset Retirement Cost ARO Asset Retirement Obligation ASA Asset Sale Agreement Atomic Energy Act Atomic Energy Act of 1954, as amended Bcf Billion cubic feet Brookfield Renewable Brookfield Renewable Partners, L.P. CAISO California ISO CBAs Collective Bargaining Agreements CERCLA Comprehensive Environmental Response, Compensation, and Liability Act of 1980, as amended CES Clean Energy Standard C&I Commercial and Industrial 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 DCPSC District of Columbia Public Service Commission DEPSC Delaware Public Service Commission DOE United States Department of Energy DOJ United States Department of Justice DPP Deferred Purchase Price EBITDA Earnings Before Interest, Tax, Depreciation and Amortization EDF Electricite de France SA and its subsidiaries EFEC Emissions-Free Energy Certificate EMA Employee Matters Agreement 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 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 FERC Federal Energy Regulatory Commission Former PECO Units Limerick, Peach Bottom, and Salem nuclear generating units Former ComEd Units Braidwood, Byron, Dresden, LaSalle and Quad Cities nuclear generating units 2 Table of Contents FRCC Florida Reliability Coordinating Council GAAP Generally Accepted Accounting Principles in the United States 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 MDPSC Maryland Public Service Commission MISO Midcontinent Independent System Operator, Inc. MRV Market-Related Value MW Megawatt MWh Megawatt-hour Mystic COS Mystic Cost of Service Agreement N/A Not applicable NAV Net Asset Value NASDAQ Nasdaq Stock Market, LLC NDT Nuclear Decommissioning Trust NEIL Nuclear Electric Insurance Limited NEPA National Environmental Policy Act of 1969 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 NWPA Nuclear Waste Policy Act of 1982 NYISO New York ISO NYMEX New York Mercantile Exchange NYPSC New York Public Service Commission OCI Other Comprehensive Income OIESO Ontario Independent Electricity System Operator OPEB Other Postretirement Employee Benefits PAPUC Pennsylvania Public Utility Commission PCAOB Public Company Accounting Oversight Board PBO Projected Benefit Obligation 3 Table of Contents Pension Protection Act (the Act) Pension Protection Act of 2006 PG&E Pacific Gas and Electric Company PJM PJM Interconnection, LLC PPA Power Purchase Agreement PP&E Property, Plant, and Equipment 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 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) RFP Request for Proposal RGGI Regional Greenhouse Gas Initiative RIN Renewable Identification Number RNF Operating Revenues Net of Purchased Power and Fuel Expense RNG Renewable Natural Gas ROE Return on equity ROU Right-of-use RPS Renewable Energy 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 SOS Standard Offer Service SPDES State Pollutant Discharge Elimination System SPP Southwest Power Pool STEM Science, Technology, Engineering, and Mathematics STPNOC STP Nuclear Operating Company TMA Tax Matters Agreement TSA Transition Services 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 VEBA Voluntary Employees' Beneficiary Associations VIE Variable Interest Entity WECC Western Electric Coordinating Council ZEC Zero Emission Credit ZES Zero Emission Standard 4 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, (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. 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 19, 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. WHERE TO FIND MORE 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. These documents are also available to the public from commercial document retrieval services and 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. 5 Table of Contents PART I ITEM 1. BUSINESS General On February 21, 2021, the Board of Directors of Exelon Corporation (“Exelon”) authorized management to pursue a plan to separate its competitive generation and customer-facing energy businesses, conducted through Constellation Energy Generation, LLC (“Constellation”, formerly Exelon Generation Company, LLC) and its subsidiaries, into an independent, publicly traded company. Constellation Energy Corporation (“CEG Parent” or the “Company”), 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 since the registration of their public debt securities 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. Our Business We are the nation’s largest producer of carbon-free energy and a leading supplier of energy products and services to businesses, homes, community aggregations and public sector customers across the continental United States, including three-fourths of Fortune 100 companies. Our generation fleet of nuclear, hydro, wind, and solar generation facilities has the generating capacity to power the equivalent of 16 million homes, producing about 10 percent of the carbon-free energy in the United States. Constellation’s fleet is helping to accelerate the nation’s transition to a carbon-free future with more than 33,094 megawatts of capacity and an annual output that is nearly 90 percent carbon-free. This makes us an important partner to businesses and state and local governments that are setting ambitious carbon-reduction goals and seeking long-term solutions to the climate crisis. We employ approximately 13,871 people, and do business in 48 states, the District of Columbia, Canada, and the United Kingdom. Our generation fleet produces more clean, carbon-free energy than any other company in the United States. We are committed to a clean energy future, and we believe our generation fleet is essential to helping meet clean energy targets, at both the state and national level. Our customer-facing business is one of the nation's largest competitive energy suppliers, offering innovative solutions along the sustainability continuum to meet customer clean energy and climate goals. Our Operations We operate the largest carbon-free generation fleet in the nation and are one of the largest competitive electric generation companies in the country, as measured by owned and contracted MWs. Collectively, the combined fleet is nearly 90% carbon-free (based on generation output of electricity) and is the third largest generation portfolio in the U.S. in terms of total generation with meaningful geographic diversity, according to the 2023 Ceres Benchmarking Air Emissions of the 100 Largest Electric Power Producers in the United States. 6 Table of Contents At December 31, 2023, our owned generating resources total capacity of 33,094 MWs consisted 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, 2023 we have contracted generation with a total capacity of 4,103 MWs, which represents electric supply procured under unit-specific agreements. The following map illustrates the locations of our owned generation facilities as of December 31, 2023: The Company's Generation Fleet Map (a)(b) Owned Assets __________ (a) Note: 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. 7 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 Net Generation Capacity (MWs) (a) % of Net Generation Capacity Geographic Regions Mid-Atlantic 10,393 32 % 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 11,605 35 % Western half of PJM and the United States footprint of MISO, excluding MISO’s Southern Region New York 3,093 9 % NYISO ERCOT 4,734 14 % Electric Reliability Council of Texas Other Power Regions 3,269 10 % New England, South, West, and Canada Total 33,094 100 % __________ (a) Net generation capacity is stated at proportionate ownership share as of December 31, 2023. See ITEM 2. PROPERTIES for additional information. The following table shows our total owned sources of electric supply of 202,474 GWhs and 200,962 GWhs for 2023 and 2022, respectively: _________ (a) Includes the proportionate share of output where we have an undivided ownership interest in jointly-owned generating plants. (b) 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 67,215 GWhs and 70,682 GWhs for the years ended December 31, 2023 and 2022, respectively. See ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS for additional information on electric supply sources. 8 Table of Contents Nuclear Facilities Our nuclear fleet is the nation’s largest, with current generating capacity of approximately 22 GWs; it produced 174 TWhs of zero-emissions electricity during 2023 – enough to power 16 million homes and avoid more than 123 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, 2023, 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), Nine Mile Point Unit 2 (82% ownership), and STP 44% ownership), that are included 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. On November 1, 2023. we acquired NRG South Texas LP, which owns a 44% undivided ownership interest in the jointly owned STP. See Note 2 — Mergers, Acquisitions, and Dispositions of the Combined Notes to Consolidated Financial Statements for additional information regarding the acquisition of STP. On August 6, 2021, Constellation and EDF entered into a settlement agreement pursuant to which we, through a wholly owned subsidiary, purchased EDF’s equity interest in CENG, a joint venture with EDF, which wholly owned the Calvert Cliffs and Ginna nuclear stations and Nine Mile Point Unit 1, in addition to the 82% undivided ownership interest in Nine Mile Point Unit 2. Prior to August 6, 2021, we had a 50.01% membership interest in CENG, however CENG is consolidated within our results for all periods presented. See Note 2 — Mergers, Acquisitions, and Dispositions of the Combined Notes to Consolidated Financial Statements for additional information regarding the acquisition of EDF's equity interest in CENG and the CENG consolidation. We operate all of these 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 2023, 2022, and 2021, our nuclear generating facilities achieved capacity factors (a) of 94.4%, 94.8%, and 94.5%, 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 significant impact on our results of operations. In 2023, we achieved an average refueling outage duration of 21 days for units we operate. We achieved an average refueling outage duration of 21 and 22 days in 2022 and 2021, respectively, against industry averages of 40 and 32 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 2023, 2022, and 2021, electric supply (in GWhs) generated from our nuclear generating facilities was 65%, 64%, 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. We have original 40-year operating licenses from the NRC for each of our nuclear units and have received 20-year operating license renewals from the NRC for all our nuclear units except Clinton. PSEG has received 20-year operating license renewals for Salem Units 1 and 2. STPNOC has received 20-year operating license renewals for STP Units 1 and 2. Peach Bottom has previously received a second 20-year license renewal from the NRC for Units 2 and 3, for a total 80-year term. See Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information on the status of Peach Bottom's license renewal. __________ (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 for additional information. 9 Table of Contents 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 (b) 1 1987 2027 Dresden (b) 2 1970 2029 3 1971 2031 FitzPatrick 1 1975 2034 LaSalle 1 1984 2042 2 1984 2043 Limerick 1 1986 2044 2 1990 2049 Nine Mile Point (b) 1 1969 2029 2 1988 2046 Peach Bottom (c) 2 1974 2033 3 1974 2034 Quad Cities 1 1973 2032 2 1973 2032 Ginna (b) 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. (b) We are currently seeking license renewals for Clinton and Dresden Units 2 and 3 to extend the operating licenses by an additional 20 years. (c) In February 2022, the NRC issued an order related to its review of our subsequent license renewal application for Peach Bottom and the NRC directed its staff to change the expiration dates for the licenses back to 2033 and 2034. We expect that the license expiration dates will be restored to 2053 and 2054, respectively. See Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information. The operating license renewal process takes approximately four years from commencement, which includes approximately two years for us to develop the application and approximately two additional years for the NRC to review the application. Depreciation provisions are based on the estimated useful lives of the stations, which generally correspond with the term of the NRC operating licenses denoted in the table above as of December 31, 2023, except for Clinton, Dresden Units 2 and 3, Ginna, NMP Unit 1, and Peach Bottom Units 2 and 3 which all assume an additional 20 years 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. From August 27, 2020 through September 15, 2021, Byron and Dresden depreciation provisions were accelerated to reflect the previously announced shutdown dates of September 2021 and November 2021, respectively. On September 15, 2021, we updated the estimated useful lives for both facilities to reflect the end of 10 Table of Contents the current NRC operating license for each unit consistent with the table above. Beginning in the third quarter of 2022, we updated Dresden depreciation provisions consistent with the license renewal as described above. See Note 7 — Early Plant Retirements and Note 8 — Property, Plant, and Equipment of the Combined Notes to Consolidated Financial Statements for additional information on Byron and Dresden. Natural Gas, Oil and Renewable Facilities (including Hydroelectric) We operate approximately 11 GWs of natural gas, oil, hydroelectric, wind, and solar generation assets, which provide a mix of baseload, intermediate, and peak power generation. We wholly own all our natural gas, oil, and renewable generating stations, except for: (1) Wyman 4; (2) certain wind project entities; and (3) CRP, which is owned 49% by another unrelated party. We operate all of these facilities, except for Wyman 4, 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 and Note 22 — Variable Interest Entities of the Combined Notes to Consolidated Financial Statements for additional information regarding CRP, which is a VIE. In 2023, 2022, and 2021, electric supply (in GWhs) generated from our owned natural gas, oil, and renewable generating facilities was 11%, 10%, and 10%, respectively, of our total electric supply. Our natural gas, oil and renewable fleet has similarly demonstrated a track record of strong performance with a Dispatch Match (a) of 98.5%, 98.2%, and 71.7% and Renewables Energy Capture (b) of 96.4%, 96.5%, and 96.6% in 2023, 2022, and 2021, respectively. Our Dispatch Match performance in 2021 was significantly impacted by the February 2021 extreme weather event in Texas. See Note 19 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for additional information. Natural gas, oil, wind and solar generation plants are generally not licensed, and, therefore, the decision on when to retire plants is, fundamentally, a commercial one. FERC has the exclusive authority to license most non-federal hydropower projects located on navigable waterways or federal lands, or connected to the interstate electric 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; however, 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. On March 31, 2021 and June 30, 2021, we completed the sale of a significant portion of our solar business and our interest in the Albany Green Energy biomass facility, respectively. See Note 2 — Mergers, Acquisitions, and Dispositions of the Combined Notes to Consolidated Financial Statements for additional information on these dispositions. __________ (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. Beginning in 2023, Dispatch Match reflects a change to remove the Conowingo run-of-river hydroelectric operational performance. Prior year Dispatch Match for 2022 and 2021 was previously reported as 98.4% and 72.4%, respectively. (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. Beginning in 2023, Renewable Energy Capture reflects a change to include the Conowingo run-of-river hydroelectric operational performance. Prior year Renewable Energy Capture for 2022 and 2021 was previously reported as 95.8% and 95.7%, respectively. 11 Table of Contents Contracted Generation In addition to energy produced by 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 region, in effect as of December 31, 2023: Region Number of Agreements Expiration Dates Capacity (MWs) Mid-Atlantic 8 2024 - 2035 319 Midwest 3 2026 - 2032 351 ERCOT 7 2025 - 2035 981 Other Power Regions 16 2024 - 2037 2,452 Total 34 4,103 2024 2025 2026 2027 2028 Thereafter Total Capacity Expiring (MW) 101 501 398 5 58 3,040 4,103 Customer-Facing Business We are one of the nation’s largest energy suppliers. 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 customers, including three-fourths of Fortune 100 companies, and approximately 1.7 million unique residential customers. We are a leader in electric power supply, serving approximately 205 TWhs in 2023 through sales to retail customers and wholesale load auctions to a diverse geographic customer base. The following table illustrates these volumes across our five reportable segments: 2023 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 marketed to the respective RTO or ISO in which our facility is located. Other includes New England, South, and West. 12 Table of Contents 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, 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. 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 markets, serving approximately 143 TWhs of electric power retail load and approximately 800 Bcf of gas in 2023, primarily to C&I customers across multiple geographic regions in the U.S. Constellation Retail has a Diverse Geographic Footprint 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 seven 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 75% for C&I power customers and 90% for C&I gas customers in 2023, 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, resulting in an industry-leading C&I customer-service business ranking in the DNV 2023 Energy Blueprint: Sales Strategies report. We are also successful at acquiring new customers by offering innovative services and products that meet their needs. In addition to our high customer renewal rates, we have produced consistently high new win rates for C&I 13 Table of Contents power as well, acquiring nearly one out of every three new customers who have chosen to shop with us over the past five years. High customer satisfaction levels, market expertise, stability and scale drive growth and result in historically proven business with consistent margins. While providing customers with the best possible 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, repeatable value highlighted in these statistics. Consumer purchasing strategies have trended from direct supply relationships to third-party relationships with a number of 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 33% 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 2023, we served approximately 62 TWhs of power load across competitive utility load procurement and bilateral sales to municipalities, co-ops, and other wholesale entities. Complementary to our national 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, our ability to source contracted generation has provided a capital-light way for us to provide customers with long-term sustainable solutions they are demanding to support a cleaner 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. We partner with our customers to provide options along the sustainability continuum, including renewable, efficiency and digital solutions to meet their carbon-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 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 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. 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 geographic preference. In 2023 we rolled out our Hourly Carbon-Free Energy (CFE) platform and closed two landmark transactions with Microsoft and Commonwealth Edison. Achieving 100% carbon-free power is a key sustainability goal for many organizations. As customers make the transition to 100% 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. In addition to larger-scale CORe+ offerings and Hourly CFE, we offer a range of sustainability solutions to customers (e.g., RECs, CORe, EFECs, RINs, RNG, carbon offsets, etc.) to support their energy needs during the transition to a carbon-free energy ecosystem. 14 Table of Contents In addition to sustainability solutions, data and analytics have also become increasingly important for our customers. Our smart utility expense management platform helps customers proactively manage utility costs, understand trends, and develop strategies to optimize spend and drive sustainability objectives, while also providing utility bill payment services. This platform provides new avenues for incremental growth by coupling the opportunities for customer usage optimization with accompanying products and 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 services. Our Constellation Technology Ventures’ commercialization team invests in, and collaborates with, portfolio companies to deploy products and technologies across our broad customer base to drive value for both us and portfolio companies. Portfolio company solutions have included EV and charging infrastructure, sustainability monitoring and reporting tools, distributed energy resources, financing solutions, and more. 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 nuclear fleet is eligible for the nuclear PTC provided by the IRA, an important tool in managing commodity price risk for each nuclear unit not already receiving state support. The nuclear PTC provides increasing levels of support as unit revenues decline below levels established in the IRA and is further adjusted annually for inflation over the duration of the program. 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. We also use financial and commodity contracts for proprietary trading purposes, but this activity accounts for only a small portion of our efforts and is not material to our results. The proprietary trading portfolio is subject to a risk management policy that includes stringent risk management limits. See ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK for additional information. 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 uranium concentrate supply contracts, contracted conversion services, contracted enrichment services, or a combination thereof, including contracts sourced from Russia, and contracted fuel fabrication services. We have inventory in various forms and engage a diverse set of domestic and international suppliers to ensure we can secure the nuclear fuel needed to continue to operate our nuclear fleet. We do not anticipate difficulty in obtaining the necessary uranium concentrates or conversion, enrichment, or fabrication services to meet the nuclear fuel requirements of 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. See ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK for additional information. Natural gas is procured through long-term and short-term contracts, as well as spot-market purchases. 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. 15 Table of Contents 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 16 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information regarding derivative financial instruments. Seasonality Our operations are affected by weather, which affects demand for electricity and natural gas, as well as operating conditions. 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 deliveries of 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. 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 our renewable projects, 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 ITEM 2. PROPERTIES for additional information regarding property insurance and Note 19 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for insurance specific to our nuclear facilities. 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, 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. 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 16 Table of Contents 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 3 — Regulatory Matters, Note 10 — Asset Retirement Obligations, and Note 18 — 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. Constellation's Strategy and Outlook Strategy We believe shareholder value is built on a foundation of operational excellence and the pairing of our majority carbon-free energy fleet with our customer-facing platform. We are committed to maintaining investment grade credit ratings. We are focused 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 businesses and coupled with distinct payments to our generation plants for the clean energy attributes. 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, returning value to our shareholders, and investing in clean energy and sustainable solutions. As environmental sustainability continues to build momentum for businesses across the country, the demand for carbon-free and sustainability solutions increases. We are committed to a carbon-free energy future and aim to serve as a partner to businesses and the federal, state and local governments that are setting ambitious carbon-reduction goals and seeking long-term solutions to the climate crisis. We will be a leading advocate at the federal level and in our states for policies that will reduce GHG emissions and preserve and grow clean energy. We are committed to reducing our GHG emissions and enabling our C&I customers through the following: • Achieving a generation portfolio mix with 100% of our owned generation carbon-free by 2040, including an interim goal of 95% carbon-free by 2030, subject to policy support and technology advancements, • A 100% reduction of our operations-driven emissions by 2040, including an interim goal to reduce carbon emissions by 65% from 2020 levels by 2030 and reduce methane emissions 30% from 2020 by 2030, subject to policy support and technology advancements and • Prior to the end of 2022, successfully delivered on our commitment to provide 100% of our C&I customers with customer-specific information on their GHG impact for facilities contracting for power or gas supply from Constellation, that include hourly carbon-free energy matching. The principles of our sustainable business strategy demonstrate our commitment to a carbon-free future while maintaining a strong balance sheet, advancing our Environmental, Social, and Governance initiatives and investing in clean energy solutions. Power America's Clean Energy Future. We will operate and grow the nation’s largest fleet of clean, zero-emissions generation facilities, with world-class levels of safety, reliability and resiliency. Expand America's Largest Fleet of Clean Energy Centers. We will leverage and expand our state-of-the-art clean energy assets by exploring co-location of customer load, direct air capture of CO2, and, if supported by policy, producing clean hydrogen and other sustainable fuels to reduce industrial emissions. 17 Table of Contents Uplift and Strengthen our Communities. We will advance respect, belonging, diversity and equity by driving community investment and creating family-sustaining clean energy jobs. Provide Energy and Sustainability Solutions for Customers. We will provide reliable, resilient energy and deliver innovative sustainability solutions that help customers achieve their clean energy goals. 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 carbon-free energy acquisitions, particularly nuclear plants with supportive policy, • Create new value from the existing fleet through nuclear uprates, repowering of renewables, co-location of customer load (including hydrogen with supportive policy), and other opportunities, • Grow sustainability solutions for our customers focused on clean energy, efficiency, storage and electrification; help our C&I customers develop and meet sustainability targets, • Engagement with the technology and innovation ecosystem through continued partnerships with national labs, universities, startups, and research institutions, and • Continue to monitor opportunities to participate in advanced nuclear to maintain our leadership position as stewards of a carbon-free energy future. We will employ a disciplined approach to acquisitions that grow future cash flow and support strategic initiatives. We will also continue to evaluate asset and business divestitures to rationalize the portfolio and optimize cash proceeds. 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. Outlook The U.S. energy sector is experiencing unprecedented changes that we believe will increase the demand for reliable, clean power generation and benefit our business. We believe our generation fleet, including our nuclear assets, is well-positioned to deliver reliable, carbon-free power and benefit from growing demand for carbon-free electricity. Key drivers of increased demand for carbon-free energy include: • Governmental and corporate policies designed to accelerate the decarbonization of the economy, • Policy support for nuclear energy sources that also enable energy security, reliability and diversification, • Rapid electrification of the U.S. economy, and • Evolving customer preferences favoring clean energy, choice and digitization. Policy Support for Decarbonization and Emerging Carbon-Free Technologies. Driven by concerns about climate change, governments, corporations, and investors are increasingly advocating for the reduction of GHG emissions across all sectors of the economy, with reduction of GHG emissions by the energy sector being a key focus. Governments at the international, national and state levels have established or are currently contemplating 18 Table of Contents increasingly stringent policies that require the reduction of GHG emissions over time. Corporations have also adopted targets to reduce the carbon emissions in their business operations, spurred in part by demand from investors and customers for sustainable, environment-friendly business practices. These governmental and corporate policies support the retention and expansion of carbon-free generation and the development and use of clean fuels like hydrogen. We are committed to a clean energy future and we believe our business is well-positioned to benefit from growing policy support for decarbonization as our generation fleet is essential to helping meet climate goals at both the state and federal levels. Policy Support for Nuclear Energy. As decarbonization accelerates, we expect our generation fleet will continue to play a critical role in meeting baseload power needs. Nuclear energy is currently the largest source of zero-emissions electricity in the U.S., accounting for over 50% of the nation’s carbon-free power and our nuclear plants are meaningful contributors to the clean energy mix in the states in which they operate. Through enactment of the nuclear PTC in the IRA, federal policymakers have recognized the need to ensure the continued operation of the nation’s nuclear power plants. This federal support builds on actions taken by states to recognize that existing nuclear generation facilities are essential to meeting policy objectives to reduce GHG emissions, with 10 states introducing bills in 2023 to add nuclear energy to clean energy targets and four of those states, including Connecticut, Michigan, North Carolina and Tennessee, finalizing such legislation. In addition, nuclear energy generation supports jobs and regional economies, and helps to ensure reliability and security of the electrical grid. For these reasons, the International Energy Agency concluded in a 2022 report, “Nuclear Power and Secure Energy Transitions,” that extending the lifetimes of existing nuclear plants is an indispensable part of a cost-effective path to net zero by 2050. As such, we plan to file applications to extend the licenses of our nuclear fleet to 80 years for our units that receive continued policy support for their long-term operation. Electrification of the U.S Economy. The push to significantly reduce or eliminate GHG emissions could lead to acceleration of the electrification of the U.S. economy, including electrification of transportation, industrial operations, heating and cooling, and appliances, which could materially increase demand for electricity. We expect widespread electrification, hydrogen production, data centers, and direct air capture could cause U.S. electricity demand to more than double from what it is today by 2050. Although EV sales in North America are well behind Europe and China, increased policy support through the IRA and other federal and state policies, together with an increasing number of EV offerings hitting the market over the next five years, will drive market share gains in the U.S. market. A 2023 Rhodium Group study forecasts as much as 66% of light duty vehicles sold in 2035 will be electric. Electrification of industrial processes, commercial equipment and residential appliances that currently utilize gas and oil as a fuel source will also play a role in increasing the net demand for electricity. According to the International Energy Agency, heat makes up two-thirds of industrial energy demand, and almost one-fifth of global energy consumption, prompting efforts by energy companies and industrial manufacturers to electrify their thermal processes. For companies like us whose core competency is safely generating and serving electricity and related products to its customers, the increasing demand from electrification provides natural growth opportunities. Evolving Customer Preferences. Consumers are increasingly purpose-driven and knowledgeable of services that drive decarbonization, leading them to value the ability to be connected to and trace the source of their clean energy choices. Growing awareness of climate change and green energy helps drive customer interest in value-add services and products around their energy usage, such as solar, behind-the-meter storage, EV charging, and the ability to choose 100 percent clean power 24 hours a day, 365 days a year in competitive retail energy markets. Continuing innovation in the digitization of the broader economy will facilitate greater control and opportunities for customers and businesses to more frequently engage with their energy providers and become more knowledgeable of their energy choices, including the solutions we provide. Employees Engaged Workforce Our employees are our greatest assets. We strive to create a workplace that is diverse, 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 community, mutual respect and the empowerment of employees to be their authentic selves. We strive to attract highly qualified and diverse talent and routinely review our hiring, development and promotion practices to maintain equal opportunity and bias free processes. 19 Table of Contents We develop our future workforce by focusing on three main areas: (1) elevating career awareness by promoting STEM and energy career pathways; (2) fostering equitable access by reducing and eliminating barriers; and (3) advancing the skills of workers by investing in training, reskilling and upskilling programs. To advance this strategy, in February 2023, we launched Powering Change, a $1 million workforce development program that provides grants to five non-profit organizations with a focus on these three areas. In July 2023, we expanded this effort with an additional investment of $250,000 to include a sixth organization dedicated to this work. We conducted an employee engagement survey at the end of 2022 to gain insight into engagement and job satisfaction within our workforce and will use it and future 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 expand the knowledge and skills of our workforce through formal assessments, feedback, coaching, mentoring, training, leadership development programs and targeted developmental experiences. 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 our employees, customers, business associates and communities benefit equitably from social, environmental and economic progress. We provide opportunities for company-sponsored volunteerism and charitable matching gifts programs. Our employees donated $5.1 million to non-profit organizations and provided just over 102,000 volunteer hours in 2023. 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 and developing a diverse talent pipeline and cultivating an inclusive and respectful culture where all individuals can develop to reach their full potential. Through our talent acquisition strategy, we work with universities and organizations to attract and recruit STEM-focused students and professionals from diverse backgrounds. Our diversified sourcing strategy includes collaboration with specific universities, technical schools and other organizations. We established relationships with diversity-focused organizations, including Disability:IN, Recruit Military, Society of Women Engineers and National Society of Black Engineers. Through these collaborations, we participate in mentoring programs, conferences, career fairs and industry events to assist with recruiting interns and full-time employees. In 2023, we hired just over 1,500 employees. Diversity Metrics We conduct analyses of gender and racial pay equity. We also provide training and review hiring and promotion processes to avoid unconscious bias and include equal pay efforts in broader company-wide equity initiatives. These actions help to create an environment where all employees can thrive and advance as equal members of the workforce. 20 Table of Contents The following table shows diversity metrics for all employees, management, and executives based on self-disclosed information as of December 31, 2023: Metric All Employees Full-Time 13,813 Part-Time 58 Total Employees 13,871 Metric All Employees Regular (a) 13,833 Temporary (b) 38 Total Employees 13,871 Metric All Employees Management (c) Executives (d) Male 10,672 2,178 112 Female 3,078 522 32 Undisclosed 83 11 — Total Employees 13,833 2,711 144 Metric All Employees Management (c) Executives (d) Aged <30 (e) 13 % 2 % — % Aged 30-50 (e) 56 % 63 % 47 % Aged >50 (e) 31 % 35 % 53 % Metric All Employees Management (c) Executives (d) Employees within 10 years of retirement (f) 5,778 1,298 113 Metric All Employees Management (c) Executives (d) People of Color (e) 20 % 14 % 13 % __________ (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. (c) Management is defined as managers as well as all employees who have direct reports and supervisory responsibilities. (d) Executives are defined as vice presidents and senior level officials that plan, direct, or coordinate activities typically with the support of subordinate executives and managers. See ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE for a discussion of certain executive officers. (e) Metric is based on the number of regular employees. (f) For reporting purposes, "Employees within 10 years of retirement" are those employees who are within 10 years of age 55 and are within 10 years of service. 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. 21 Table of Contents The table below shows the turnover rate for all employees, excluding temporary employees, for the year ended December 31, 2023: All Involuntary Termination 1.40 % Retirement (a) 2.20 % Voluntary Resignation 4.10 % __________ (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 Approximately 25% of employees participate in CBAs. The following table presents employee information, including information about CBAs, as of December 31, 2023: Total Employees Covered by CBAs Number of CBAs CBAs New and Renewed in 2023 (a) Total Employees Under CBAs New and Renewed in 2023 3,343 21 4 410 __________ (a) Does not include CBAs that were extended in 2023 while negotiations are ongoing for renewal. 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 its strategies and efforts to protect and improve the quality of the environment, including our internal climate change and sustainability policies and programs, as discussed in further detail below. Climate Change Driven by concerns about climate change, governments, corporations, and investors are increasingly advocating for the reduction of GHG emissions across all sectors of the economy, with reduction of GHG emissions by the energy sector being a key focus. Governments at the international, national and state levels have established or are currently contemplating increasingly stringent policies that require the reduction of GHG emissions over time. Corporations have also adopted targets to reduce the carbon emissions in their business operations, spurred in part by demand from investors and customers for sustainable, environment-friendly business practices. Emerging technologies like storage and hydrogen are also helping to advance decarbonization. We believe our business is well-positioned to benefit from growing policy support for decarbonization. However, as detailed below, we also face climate change 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 local, state or federal regulatory requirements 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. 22 Table of Contents Climate Change Mitigation and Transition We support comprehensive federal climate legislation that addresses the climate crisis and would ensure the country meets the targets set by the Paris Climate Accord. Independent of additional legislation, we support the EPA moving forward with meaningful regulation of GHG emissions under the Clean Air Act. We currently are subject to, and may become subject to additional, federal and/or state legislation and/or regulations addressing GHG emissions. We are deliberately positioned as a low-carbon generation company. We have minimized GHG emitting assets in our portfolio and maximized carbon-free electric production in support of achieving economy-wide GHG emissions reduction goals. Our Scope 1 and 2 market-based GHG emissions in 2022 were 9.2 million metric tons carbon dioxide equivalent, of which 8.6 million metric tons were from our natural gas and oil fueled generation fleet, significantly less than our peers with similar volume of power generation. We produce electricity predominantly from low and carbon-free generating facilities (such as nuclear, hydroelectric, natural gas, wind, and solar) and neither own nor operate any coal-fueled generating assets. Our natural gas and oil generating plants produce some GHG emissions, most notably CO2. In addition, we sell natural gas through our customer-facing business; and consumers’ use of such natural gas produces GHG emissions. However, our owned-asset emission intensity, or rate of carbon dioxide equivalent (CO2e) emitted per unit of electricity generated, is among the lowest in the industry. In 2023, we achieved a 94.4% percent capacity factor across our nuclear fleet and our ownership of 22 GWs of carbon-free generation capacity at 25 nuclear units produced 174 TWhs of electricity in 2023. The electric sector plays a key role in lowering GHG emissions across the rest of the economy. Electrification of other sectors such as transportation and buildings coupled with simultaneous decarbonization of electric generation is a key lever for emissions reductions. To support this transition, we are advocating for public policy supportive of vehicle electrification, investing in enabling infrastructure and technology, and supporting customer education and adoption. We also continue to explore other decarbonization opportunities, supporting pilots of emerging energy technologies and development of clean fuels. International Climate Change Agreements. At the international level, the United States is a party to the United Nations Framework Convention on Climate Change (UNFCCC). The Parties to the UNFCCC adopted the Paris Agreement at the 21st session of the UNFCCC Conference of the Parties (COP 21) on December 12, 2015. Under the Agreement, which became effective on November 4, 2016, the parties committed to try to limit the global average temperature increase and to develop national GHG reduction commitments. On November 4, 2020, the United States formally withdrew from the Paris Agreement, retracting its commitment to reduce domestic GHG emissions by 26%-28% by 2025 compared with 2005 levels. However, on January 20, 2021, President Biden accepted the Paris Agreement, which resulted in the United States’ formal re-entry on February 19, 2021. The United States has now set an economy-wide target of reducing its net GHG emissions by 50-52% below 2005 levels by 2030. The 2021 UNFCCC Conference of the Parties (COP26) and resulting Glasgow Climate Pact indicated important global support for the Paris Agreement and continued progress toward decarbonization. The 2022 UNFCCC Conference of the Parties (COP27) held in Sharm el-Sheikh, Egypt recommitted countries to their pledges in the Glasgow Climate Pact. In December of 2023, the UNFCCC Conference of Parties (COP28) was held in Dubai, United Arab Emirates. One key outcome of COP28 was an agreement for a global "transition away from fossil fuels in energy systems, in a just, orderly, and equitable manner, accelerating action in this critical decade, to achieve net zero by 2050 in keeping with the science." Federal Climate Change Legislation. On August 16, 2022, President Biden signed into law the Inflation Reduction Act of 2022, which, among other things, includes federal tax credits, certain of which are transferable or fully refundable, for clean energy technologies including existing nuclear plants. The nuclear PTC recognizes the contributions of carbon-free nuclear power by providing a federal tax credit of up to $15 per MWh, subject to phase-out, beginning in 2024 and continuing through 2032. The nuclear PTC includes annual adjustments for inflation. With the nuclear PTC policy support, we expect our nuclear assets will operate through the end of the nuclear PTC period. Further, the IRA includes a 15% book-minimum tax on applicable corporations that we do not expect to have a material impact to our consolidated financial statements. The U.S. Department of Treasury has begun the process of issuing guidance on the relevant tax provisions included in the legislation but has not yet addressed the nuclear PTC. 23 Table of Contents Regulation of GHGs from Power Plants under the Clean Air Act. The EPA’s 2015 Clean Power Plan (CPP) established regulations addressing carbon dioxide emissions from existing fossil-fired power plants under Clean Air Act Section 111(d). The CPP’s carbon pollution limits could be met through shifting generation from higher-emitting units to lower- or zero-emitting units. On June 30, 2022, the U.S. Supreme Court issued a decision holding that the EPA did not have the authority to require “generation shifting” from coal to natural gas and renewables to reduce sector-wide emissions, as it had done in CPP. The remainder of the litigation was remanded to the U.S. Court of Appeals for the D.C. Circuit and held in abeyance in light of forthcoming actions from the EPA. In May 2023, the EPA proposed new GHG standards for power plants, which is expected to be finalized in 2024. State Climate Change 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 and other sectors as well. 25 states and the District of Columbia have 100% clean energy targets, deep GHG reductions, or both, encompassing 53% of U.S residential electricity customers. See discussion below for additional information on renewable and other portfolio standards. As the nation’s largest generator of carbon-free electricity, our fleet supports these efforts to produce safe, reliable electricity with minimal GHGs. In 2019, New York enacted the Climate Leadership and Community Protection Act, which commits the state to achieving net-zero emissions by 2050, with interim emission reduction and renewable energy requirements in 2030 and 2040. New Jersey’s Energy Master Plan, released in 2020, provides a comprehensive roadmap for achieving the state’s goal of a 100% clean energy economy by 2050 and its Global Warming Response Act’s stated GHG emissions reductions of 80% below 2006 levels by 2050. On September 15, 2021, Illinois Public Act 102-0662 was signed into law by the Governor of Illinois. The Clean Energy Law is designed to achieve 100% carbon-free power by 2045 to enable the state’s transition to a clean energy economy. The Clean Energy Law 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 in the states in which they operate. States may not be able to meet their zero-carbon goals without our nuclear plants, as our plants provide a significant portion of the current carbon-free power. Several states in which our nuclear facilities operate have established policies to support nuclear generation. The supportive policies are driven by several factors, including recognition by governments and policy makers that existing nuclear generation facilities are essential to meeting policy objectives on reduction of GHG emissions, the desire to support jobs and regional economies, and the need to ensure reliability and security of the electrical grid through resource diversity. These state-specific 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 2029 Illinois Zero Emission Standard 2016 Clinton and Quad Cities ZEC 2027 New Jersey Clean Energy Legislation 2018 Salem ZEC 2025 Illinois Clean Energy Law 2021 Byron, Braidwood, and Dresden CMC 2027 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. Non-emitting resources do not have to purchase or hold these allowances. The following states are participants in RGGI; Connecticut, Delaware, Maine, Maryland, Massachusetts, New Hampshire, New Jersey, New York, Rhode Island, and Vermont. Pennsylvania’s participation in RGGI is currently being litigated at the Pennsylvania Supreme Court. Renewable and Clean Energy Standards. According to the U.S. Energy Information Administration, 36 states and the District of Columbia, inc l uding most of the states where we operate, have adopted some form of renewable or clean energy procurement requirement. Of these 36 states, eight states have non-enforceable 24 Table of Contents renewable energy goals. 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. These are 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. While we cannot predict the nature of future regulations or how such regulations might impact future financial statements, we have a low emission portfolio, and GHG restrictions would likely benefit our zero- and low-emission generating units relative to other higher-emission fossil fuel-fired generating units. Corporate Clean Energy Targets. Corporations are facing increasing pressure from their customers and investors to align their businesses with international and national environmental and sustainability objectives, including supporting goals to reduce GHG emissions in their business operations. Leading institutional investors and money managers are increasingly considering sustainability as a key factor in investment decisions and are increasingly advocating for more transparency in disclosure on climate-related matters and pledging to align proxy voting to climate-rated proposals with its fiduciary duty. An increasing number of corporations are also proactively making commitments to reducing their GHG emissions footprint, either through procuring increasing amounts of clean energy, such as RECs, EFECs, or emissions offsets, to offset their carbon footprint over time. As the nation’s largest producer of carbon-free energy, we support taking bold action to address the climate crisis and reestablish leadership in both emerging technologies and existing clean infrastructure that together will power the future. Emerging Carbon-Free Technologies. Emerging carbon-free technologies like storage and hydrogen are expected to help accelerate the economy’s decarbonization. Lower costs, state-directed mandates, a backlog of storage projects in the interconnection queue, and utilities seeking large-scale storage capacity to support higher renewables penetration have created conditions for rapid growth of this technology in the U.S. Clean hydrogen also has the potential to drive decarbonization, particularly as it relates to more challenging sectors like long-haul transportation, steel, chemicals, heating, agriculture, and long-term power storage. Nuclear power can be used to produce clean hydrogen, and our nuclear fleet positions us well to explore this emerging space with supportive policy. Both energy storage and clean hydrogen are expected to help support net-zero carbon goals. Climate Change Adaptation Our facilities and operations are subject to the global impacts of climate change. Long-term shifts in climactic patterns, such as sustained higher temperatures and sea level rise, may present challenges for our facilities and services. We believe our operations could be significantly affected by the physical risks of climate change. See ITEM 1A. RISK FACTORS, for additional information. 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 and we consider and review national climate assessments to inform our longer-term planning. Our nuclear fleet is resilient to weather extremes and generates emissions-free electricity 24 hours a day even during unexpectedly cold winter events and hot summer events. Other Environmental Regulation Air Quality Mercury and Air Toxics Standards (MATS). In 2011, the EPA signed a final rule, known as MATS, to reduce emissions of hazardous air pollutants from power plants. In 2016, in response to a U.S. Supreme Court decision requiring the EPA to consider costs in determining whether it was appropriate and necessary to regulate power plant emissions of hazardous air pollutants, the EPA issued a supplemental finding that, after considering costs, it remained appropriate and necessary. On May 22, 2020, the EPA revoked the "appropriate and necessary" finding underpinning MATS. A lawsuit in the D.C. Circuit sought vacatur of MATS based on the EPA’s May 22, 2020 finding; on September 11, 2020, the Court granted a motion by Exelon and two other entities to intervene in that lawsuit to defend MATS, and on September 28, 2020, the Court held this portion of the litigation in abeyance. On July 21, 2020, we, as part of Exelon, and two other entities filed a lawsuit in the D.C. Circuit challenging the EPA’s May 22, 2020 rescission of the “appropriate and necessary” finding. In February 2022, the D.C. Circuit granted unopposed motions to substitute Constellation in place of Exelon in these cases. On March 6, 2023, the EPA published a regulation revoking the 2020 revised supplemental finding and reaffirming that it is 25 Table of Contents "appropriate and necessary" to regulate hazardous air pollutant emissions from coal- and oil-fired power plants. On July 7, 2023, the D.C. Circuit granted unopposed motions to dismiss all three lawsuits, concluding the MATS litigation. The EPA's March 2023 rule remains in place. Good Neighbor Rule. On June 5, 2023, the EPA published a final rule called “Federal 'Good Neighbor Plan' for the 2015 Ozone National Ambient Air Quality Standards” also known as the "Transport Rule". The rule, among other things, establishes nitrogen oxides emissions budgets requiring fossil fuel-fired power plants in 23 states to participate in an allowance-based ozone season trading program beginning in 2023. On February 13, 2023, EPA published a final action fully or partially disapproving state implementation plans submitted by 21 states to address their obligations under the "good neighbor" provisions of the Clean Air Act. However, several Regional Courts of Appeals issued orders staying, pending judicial review, EPA's disapproval of several state plans (including Texas). On September 29, 2023, the EPA issued an interim-final rule clarifying the current scope of applicability of the Federal Plan. A petition for a nationwide stay was denied by the D.C. Circuit and is now pending before the Supreme Court. We cannot reasonably predict the outcome of this litigation. Water Quality Under the federal Clean Water Act, NPDES permits for discharges into waterways are required to be obtained from the EPA or from the state environmental agency to which the permit program has been delegated, and permits must be renewed periodically. Certain of our facilities discharge water into waterways and are therefore, subject to these regulations and operate under NPDES permits. Clean Water Act Section 316(b) is implemented through the NDPES program and 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 Section 316(b) regulations finalized in 2014; the regulation’s requirements have been or will be addressed through renewal of these facilities’ NPDES permits. 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 of our owned and operated nuclear stations. Five of the twelve stations 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 seven remaining nuclear stations, on a site-specific basis for each plant, 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. As a result, in some instances, such as Peach Bottom, the permit expiration dates have elapsed and have been administratively extended. Should a state permitting director determine that a facility must install cooling towers to comply with the rule, that facility’s economic viability could be called into question. However, the final rule does not mandate cooling towers 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. There is no regulatory established timeline for NPDES permit renewals. On July 28, 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 with certain required modifications. However, the permit is being challenged by an environmental organization, and if successful, could result in additional costs for Clean Water Act compliance. Potential cooling water system modification costs could be material and could adversely impact the economic competitiveness of this facility. Under Clean Water Act Section 404 and state laws and regulations, we may be required to obtain permits for projects involving dredge or fill activities in Waters of the United States. 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. 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. 26 Table of Contents Solid and Hazardous Waste and Environmental Remediation CERCLA authorizes response to releases or threatened releases of hazardous substances into the environment. CERCLA authorities complement those of the RCRA, which primarily regulates ongoing hazardous waste handling and disposal. Under CERCLA, generators and transporters of hazardous substances, as well as 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, many of which are listed by the EPA on the National Priorities List. 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 statutes that contain provisions substantially like CERCLA. Such statutes apply in many states where we currently own or operate, or previously owned or operated facilities, including Illinois, Maryland, New Jersey, Pennsylvania, New York, and Texas. In addition, RCRA governs treatment, storage and disposal of solid and hazardous wastes and cleanup of sites where such activities were conducted. Our operations have in the past, and may in the future, require substantial expenditures in order to comply with these federal and state environmental laws. Under these 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. As of December 31, 2023, 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 19 — 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. As of December 31, 2023, we had approximately 93,600 SNF assemblies (22,900 tons) stored on site in SNF pools or dry cask storage that includes SNF assemblies at Zion Station, for which we retain ownership and responsibility for the decommissioning of the Zion Independent Spent Fuel Storage Installation. All our nuclear sites have on-site dry cask storage. On-site dry cask storage in concert with on-site storage pools will be capable of meeting all current and future SNF storage requirements at each of our sites for the duration of both current and subsequent license periods of all stations and through decommissioning. For a discussion of matters associated with our contracts with the DOE for the disposal of SNF, see Note 19 — 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. The disposal facility in South Carolina at present is only receiving LLRW from LLRW generators in South Carolina, New Jersey (which includes Salem), and Connecticut. 27 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 for 15 years beginning in 2012), 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. Corporate Information CEG Parent’s principal executive office is located at 1310 Point Street, Baltimore, Maryland 21231-3380. Constellation’s principal executive office is located at 200 Exelon Way, Kennett Square, Pennsylvania 19348-2473. The telephone number for our principal executive offices is (833) 883-0162. We maintain a website located at www.ConstellationEnergy.com. The information contained on, or accessible from, our website is not part of this annual report by reference or otherwise. Available Information 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. You may obtain copies of these documents by accessing the SEC’s website at www.sec.gov. 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 or by contacting our corporate secretary at the applicable address set forth above under "—Corporate Information." ITEM 1B. UNRESOLVED STAFF COMMENTS None. ITEM 1C. CYBERSECURITY Risk Management and Strategy Constellation has established 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. 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 policies and procedures which form the comprehensive framework we utilize for planning, performing, managing, assessing, innovating, and improving our security controls. 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. 28 Table of Contents Our cybersecurity program is aligned to the five functions of the NIST Cybersecurity Framework – identify, detect, protect, respond, and recover. 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. In addition, to detect cybersecurity events, we deploy security logging and monitoring, malicious code detection, and data loss protection tools. If the company is the target of a cybersecurity attack, we have established processes for incident response and crisis management to detect and triage potential incidents and determine severity, contain, and eradicate a threat. These processes also include steps to recover our systems and information through established and exercised system recovery plans and business continuity plans. Our incident response process includes steps to notify regulatory and other governmental authorities of cybersecurity events as required by law, including providing notice to investors for material cybersecurity events. As part of our process to continuously improve, we utilize internal functions such as our internal audit and risk 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 and provide key risk indicators to track performance. 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 Cyber and Physical Security organizations, 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. 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. 29 Table of Contents ITEM 2. PROPERTIES The following table presents our interests in net electric generating capacity by station at December 31, 2023: 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 Base-load 2,386 Byron Byron, IL 2 Uranium Base-load 2,347 (e) LaSalle Seneca, IL 2 Uranium Base-load 2,320 Dresden Morris, IL 2 Uranium Base-load 1,845 (e) Quad Cities Cordova, IL 2 75 Uranium Base-load 1,403 Clinton Clinton, IL 1 Uranium Base-load 1,092 Michigan Wind 2 Sanilac Co., MI 50 51 (f) Wind Intermittent 46 Beebe Gratiot Co., MI 34 51 (f) Wind Intermittent 42 Michigan Wind 1 Huron Co., MI 46 51 (f) Wind Intermittent 35 Harvest 2 Huron Co., MI 33 51 (f) Wind Intermittent 30 Harvest Huron Co., MI 31 51 (f) Wind Intermittent 26 Beebe 1B Gratiot Co., MI 21 51 (f) Wind Intermittent 26 CP Windfarm Faribault Co., MN 2 51 (f) Wind Intermittent 2 Clinton Battery Storage Blanchester, OH 1 Energy Storage Peaking 5 Total Midwest 11,605 Mid-Atlantic Limerick Sanatoga, PA 2 Uranium Base-load 2,315 Calvert Cliffs Lusby, MD 2 Uranium Base-load 1,789 Peach Bottom Delta, PA 2 50 Uranium Base-load 1,324 Salem Lower Alloways Creek Township, NJ 2 42.59 Uranium Base-load 995 Conowingo Darlington, MD 11 Hydroelectric Base-load 497 Criterion Oakland, MD 28 51 (f) Wind Intermittent 36 Fair Wind Garrett County, MD 12 Wind Intermittent 30 Fourmile Ridge Garrett County, MD 16 51 (f) Wind Intermittent 20 Solar Horizons Emmitsburg, MD 1 51 (f) Solar Intermittent 8 Solar New Jersey 3 Middle Township, NJ 5 51 (f) Solar Intermittent 1 Muddy Run Drumore, PA 8 Hydroelectric Intermediate 1,058 Eddystone 3, 4 Eddystone, PA 2 Oil/Gas Peaking 760 (i) 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 30 Table of Contents Station (a) Location No. of Units Percent Owned (b) Primary Fuel Type Primary Dispatch Type (c) Net Generation Capacity (MWs) (d) Southwark Philadelphia, PA 4 Oil Peaking 52 Falls Morrisville, PA 3 Oil Peaking 51 Moser Lower Pottsgrove Twp., PA 3 Oil Peaking 51 Chester Chester, PA 3 Oil Peaking 39 Schuylkill Philadelphia, PA 2 Oil Peaking 30 Total Mid-Atlantic 10,393 ERCOT South Texas Project Bay City, TX 2 44 Uranium Base-load 1,161 Whitetail Webb County, TX 57 51 (f) Wind Intermittent 47 Sendero Jim Hogg and Zapata County, TX 39 51 (f) Wind Intermittent 40 Colorado Bend II Wharton, TX 3 Gas Intermediate 1,138 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 4,734 New York Nine Mile Point Scriba, NY 2 (g) Uranium Base-load 1,675 FitzPatrick Scriba, NY 1 Uranium Base-load 842 Ginna Ontario, NY 1 Uranium Base-load 576 Total New York 3,093 Other Antelope Valley Lancaster, CA 1 Solar Intermittent 242 Bluestem Beaver County, OK 60 51 (f)(h) Wind Intermittent 101 Shooting Star Kiowa County, KS 65 51 (f) Wind Intermittent 53 Bluegrass Ridge King City, MO 27 51 (f) Wind Intermittent 29 Conception Barnard, MO 24 51 (f) Wind Intermittent 26 Cow Branch Rock Port, MO 24 51 (f) Wind Intermittent 26 Mountain Home Glenns Ferry, ID 20 51 (f) Wind Intermittent 21 High Mesa Elmore Co., ID 19 51 (f) Wind Intermittent 20 Echo 1 Echo, OR 21 50.49 (f) Wind Intermittent 17 Sacramento PV Energy Sacramento, CA 4 51 (f) Solar Intermittent 15 Cassia Buhl, ID 13 51 (f) Wind Intermittent 14 Wildcat Lovington, NM 13 51 (f) Wind Intermittent 14 Echo 2 Echo, OR 9 51 (f) Wind Intermittent 9 Tuana Springs Hagerman, ID 8 51 (f) Wind Intermittent 9 Greensburg Greensburg, KS 10 51 (f) Wind Intermittent 6 Threemile Canyon Boardman, OR 6 51 (f) Wind Intermittent 5 Loess Hills Rock Port, MO 4 Wind Intermittent 5 Denver Airport Solar Denver, CO 1 51 (f) Solar Intermittent 2 31 Table of Contents Station (a) Location No. of Units Percent Owned (b) Primary Fuel Type Primary Dispatch Type (c) Net Generation Capacity (MWs) (d) Mystic 8, 9 Charlestown, MA 6 Gas Intermediate 1,413 (e) Hillabee Alexander City, AL 3 Gas Intermediate 753 Wyman 4 Yarmouth, ME 1 5.9 Oil Intermediate 36 West Medway II West Medway, MA 2 Oil/Gas Peaking 193 West Medway West Medway, MA 3 Oil Peaking 124 Grand Prairie Alberta, Canada 1 Gas Peaking 105 Framingham Framingham, MA 3 Oil Peaking 31 Total Other 3,269 Total 33,094 __________ (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) Base-load 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. Natural gas and oil stations and wind and solar facilities reflect a summer rating. (e) On August 9, 2020, we announced we would permanently cease generation operations at Byron and Dresden nuclear stations in 2021 and Mystic Units 8 and 9 in 2024. On September 15, 2021, we reversed the previous decision to retire Byron and Dresden. See Note 7 — Early Plant Retirements of the Combined Notes to Consolidated Financial Statements for additional information. (f) Reflects the prior sale of 49% of CRP to a third party. See Note 22 — Variable Interest Entities of the Combined Notes to Consolidated Financial Statements for additional information. (g) We wholly own Nine Mile Point Unit 1 and have an 82% undivided ownership interest in Nine Mile Point Unit 2. (h) 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. (i) Eddystone stations 3 and 4 will be retiring in June 2025. 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 (LNG) 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 and the Mystic Generating Station. 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 19 — 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 consolidated financial condition or results of operations. 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 19 — Commitments 32 Table of Contents and Contingencies of the Combined Notes to Consolidated Financial Statements. Such descriptions are incorporated herein by these references. 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 consolidated financial statements, fall primarily under the categories below: Risks related to market and financial factors primarily include: • the price of fuels, in particular the price of natural gas, which affects power prices, • 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 on-going competition, and • emerging technologies and business models, including those related to climate change mitigation and transition to a low-carbon 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, • 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 nuclear facilities and the ability to effectively manage the associated decommissioning obligations, and • physical and cybersecurity risks for us as an owner-operator of generation facilities and as a participant in commodities trading. Risks related to our separation from Exelon primarily include: • replicate certain services provided by Exelon (e.g., information technology), which will require additional resources and expense, and • performance by Exelon and us under the transaction agreements, including indemnification responsibilities tied to the allocation of businesses and liabilities. 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. 33 Table of Contents We are exposed to commodity price risk for natural gas 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 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, counterparty default, and geopolitical risk, including the current Russia and Ukraine conflict and the potential for additional United States sanctions against Russia. The cycle of production and utilization of nuclear fuel is complex, and we engage a diverse set of suppliers to ensure we can 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 consolidated financial statements. See ITEM 1. BUSINESS – Price and Supply Risk Management and See 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, and the growth of energy efficiency and demand response programs can depress demand. In addition, in some markets, the supply of electricity can exceed demand during some hours of the day, resulting in loss of revenue for base-load generating plants such as our nuclear plants. Conversely, new demand sources such as electrification of transportation could increase demand and change demand patterns. 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. Market Designs. 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. In addition, a significant decrease in market participation could affect market liquidity and have a detrimental effect on market stability. We may be adversely affected by the effects of sustained inflation. The existence of inflation in the economy has resulted in, or may result in, higher interest rates and capital costs, increased costs of labor, and other similar effects. If inflation rates continue to rise or remain 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. We are potentially affected by emerging technologies that could over time affect or transform the energy industry. Advancements in power generation technology, including commercial and residential solar generation installations and commercial micro turbine installations, are improving the cost-effectiveness of customer self-supply of electricity. Improvements in energy storage technology, including batteries and fuel cells, could also better position customers to meet their around-the-clock electricity requirements. Improvements in energy efficiency of lighting, appliances, equipment and building materials will also affect energy consumption by customers. Changes in power generation, storage, and use technologies could have significant effects on customer behaviors and their energy consumption. 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 consolidated financial statements through, among other things, reduced operating revenues, increased operating and maintenance expenses, increased capital 34 Table of Contents 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 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. Changes in demographics, including increased numbers of retirements or changes in life expectancy assumptions or changes to Social Security or Medicare eligibility requirements could also increase the costs and funding requirements of the obligations related to the pension and OPEB plans. See Note 10 — Asset Retirement Obligations and Note 15 — 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, 2023, approximately 37%, 12%, and 17% 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 market participants to post collateral for their 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. 35 Table of Contents 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 16 — 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 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 into bankruptcy proceedings. The impact of bankruptcy could result in the impairment of certain project assets. See Note 17 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information. 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 consolidated financial statements. 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. 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 products and services provided by 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 16 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information on our credit risk. We could be negatively affected by the impacts of weather. 36 Table of Contents Our operations are affected by weather, which impacts demand for electricity and natural gas, the price of energy commodities, as well as operating conditions. To the extent that weather is warmer in the summer or colder in the winter than assumed, we could require greater resources to meet our contractual commitments. Extreme weather conditions or storms have affected the availability of generation and its transmission, limiting our ability to source or send power to where it is sold, and have also impaired the transportation of natural gas to our generating assets and our ability to supply natural gas to our customers. In addition, 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. Climate change projections suggest increases to summer temperature and humidity trends, as well as more erratic precipitation and storm patterns over the long term in the areas where we have generation assets. The frequency in which weather conditions emerge outside the current expected climate norms could contribute to the weather-related impacts discussed above. Beginning on February 15, 2021, our Texas-based generating assets within the ERCOT market, specifically Colorado Bend II, Wolf Hollow II, and Handley, experienced periodic outages as a result of historically severe cold weather conditions. As a result of this weather event, we incurred a loss of approximately $800 million for the year ended December 31, 2021. See Note 19 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for additional information. 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 have a material goodwill balance as of December 31, 2023. 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. 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, Note 12 — Asset Impairments, and Note 13 — 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 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 37 Table of Contents 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. See Note 19 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for additional information on the February 2021 extreme cold weather event and Texas-based generating asset outages. 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 and recognize the value of carbon-free electricity and resiliency and for 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. Our consolidated financial statements are significantly affected by our sales and purchases of commodities at market-based rates, as opposed to cost-based or other similarly regulated rates, and federal and state regulatory and legislative developments related to emissions, climate change, capacity market mitigation, energy price information, resilience, fuel diversity and RPS. 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) 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 with respect to some of our units. 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 and Note 7 — Early Plant Retirements 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, 38 Table of Contents 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 19 — 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 clean-up 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 now 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 19 — 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 and new energy consumption technologies could cause declines in customer energy consumption and lead to a decline in our operating revenues. See ITEM 1. BUSINESS – Environmental Matters and Regulation – Renewable and Clean Energy Standards and “We are potentially 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 electric 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 39 Table of Contents 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 14 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information. 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 19 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements. Adverse outcomes in these proceedings could require significant expenditures, result in lost revenue, or restrict 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 climate change. Climate 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. We periodically perform analyses to better understand how climate change could affect our facilities and operations. We primarily operate in the Midwest, East Coast of the United States, and Texas areas that have historically been prone to various types of severe weather events, and as such we have well-developed response and recovery programs based on these historical events. However, 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. In addition, changes to the climate may impact levels and patterns of demand for energy and related services, which could affect our operations. Over time, we may need to make additional investments to adapt to changes in operational requirements as a result of climate change. Climate mitigation and transition risks include 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. We also periodically perform analyses of potential pathways to reduce power sector and economy-wide GHG emissions to mitigate climate change. To the extent additional GHG reduction regulation or legislation becomes 40 Table of Contents effective at the federal and/or state levels, 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-carbon emission profile may be reduced. See ITEM 1. BUSINESS – Environmental Matters and Regulation – Climate Change for additional information. 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 than we incur to produce energy from 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 quality. The quality of nuclear fuel utilized by us 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. Operational risk. Operations at any of our nuclear generation plants could degrade to the point where we 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. We could choose to close a plant rather than incur the expense of restarting it or returning the plant to full capacity. In either event, we could lose revenue and incur increased purchased power costs and fuel expense to meet supply commitments. 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. For plants operated but not wholly owned by us, we could also incur liability to our co-owners. For nuclear plants not operated and not wholly owned by us, from which we receive a portion of the plants’ output, our results of operations are dependent on the operational performance of the operators and could be adversely affected by a significant event at those plants. We do not procure the fuel for the sites we do not operate. The operator's nuclear fuel procurement plan could impact our results of operations. Additionally, poor operating performance at nuclear plants not owned by us could result in increased regulation and reduced public support for nuclear-fueled energy. Closure of generating plants owned by others, or extended interruptions of generating plants or failure of transmission lines, could adversely affect transmission systems and the sale and delivery of electricity in markets served by us. 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 $16.2 billion limit for a single incident. 41 Table of Contents See Note 19 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for additional information of 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 ability to effectively execute on our 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 Energy Houston Electric 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 the Consolidated Statements of Operations and Comprehensive Income, and the impact to our consolidated financial statements 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 the Consolidated Statements of Operations and Comprehensive Income, the impact of which could be material. For the year ended December 31, 2021, a pre-tax charge of $193 million was recorded in the Consolidated Statement of Operations and Comprehensive Income for decommissioning-related activities that were not offset for the Byron units due to contractual offset being temporarily suspended. See Note 7 — Early Plant Retirements and Note 10 — Asset Retirement Obligations of the Combined Notes to Consolidated Financial Statements for additional information. 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. We are subject to evolving physical security and cybersecurity 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 42 Table of Contents 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 position or results of operations. Operational harm could be in the form of impact to the operation of the generation fleet and/or reliability of the bulk electric 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. Furthermore, 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. As an example, our data centers are hosted in vendor-managed co-location facilities. Consequently, we may be subject to short- and long-term interruptions, delays and outages in service and availability due to third-party cybersecurity incidents that are outside of our direct control. We expect that 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 assets of unaffiliated parties responsible for real-time planning and management of the bulk electric system which could impact our ability to provide generation potentially resulting in localized and regional blackouts affecting third parties and the public, many of which will have no direct commercial relationship with the Company. We also cannot anticipate, detect, repel, or implement fully effective preventative measures against all cyber threats, particularly because the techniques used are constantly evolving. Continued implementation of advanced digital technologies increases the potentially unfavorable impacts of such attacks and may introduce new vulnerabilities and threat tactics. For example, as Artificial Intelligence (AI) continues to evolve, 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 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 consolidated financial statements. 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. 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. 43 Table of Contents 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 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. Also, the ability of energy transmission and distribution companies to maintain the reliability, resiliency and safety of their energy delivery systems could affect our ability to deliver energy to our customers and affect our operating costs. 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. In addition, 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. 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. Equipment, even if maintained in accordance with good industry practices, is subject to operational failure, including events that are beyond our control, and could require significant expenditures to remedy. Our consolidated financial statements 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. 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 further diversification across the competitive energy value chain. This could include opportunistic carbon-free energy acquisitions, creating new value from our existing fleet through nuclear uprates, renewable repowerings, co-location of customer load, growing sustainability solutions for our customers, and investment opportunities in other emerging technologies and innovation. Such initiatives could involve significant risks and uncertainties, including distraction of 44 Table of Contents 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 impose certain other restrictions on such transactions. All these factors could result in higher costs or lower revenues than expected, resulting in lower than planned returns on investment. Risks Related to Our Separation from Exelon The terms in our agreements with Exelon could be less beneficial than the terms we may have otherwise received from unaffiliated third parties. The agreements entered with Exelon in connection with the separation, including the separation agreement, a tax matters agreement, an employee matters agreement, and a transition services agreement, were prepared in the context of the separation while we were still a wholly owned subsidiary of Exelon. Accordingly, during the period in which the terms of those agreements were prepared, we did not have an independent Board of Directors or a management team that was independent of Exelon. As a result, the terms of those agreements may not reflect terms that would have resulted from negotiations between unaffiliated third parties. Exelon may fail to perform under various transaction agreements that were executed as part of the separation, which could cause us to incur expenses or losses we would not otherwise incur. In connection with the separation and prior to the distribution, we and Exelon entered into the separation agreement and entered into various other agreements, including a tax matters agreement, an employee matters agreement, and a transition services agreement. The separation agreement, the tax matters agreement and the employee matters agreement determined the allocation of assets and liabilities between the companies following the separation for those respective areas and include any necessary indemnifications related to liabilities and obligations. We will rely on Exelon to satisfy its performance and payment obligations under these agreements. If Exelon is unable or unwilling to satisfy its obligations under these agreements, including its indemnification obligations, we could incur operational difficulties and/or losses. In connection with the separation into two public companies, we and Exelon indemnified each other for certain liabilities. If we are required to pay under these indemnities to Exelon, our financial results could be negatively impacted. The Exelon indemnities may not be sufficient to hold us harmless from the full amount of liabilities for which Exelon will be allocated responsibility, and Exelon may not be able to satisfy its indemnification obligations in the future. Pursuant to the separation agreement and certain other agreements between Exelon and us, each party will agree to indemnify the other for certain liabilities, in each case for uncapped amounts. Indemnities that we may be required to provide Exelon are not subject to any cap, may be significant and could negatively impact our business. Third parties could also seek to hold us responsible for any of the liabilities that Exelon has agreed to retain. Any amounts we are required to pay pursuant to these indemnification obligations and other liabilities could require us to divert cash that would otherwise have been used in furtherance of our operating business. Further, the indemnities from Exelon for our benefit may not be sufficient to protect us against the full amount of such liabilities, and Exelon may not be able to fully satisfy its indemnification obligations. Moreover, even if we ultimately succeed in recovering from Exelon any amounts for which we are held liable, we may be temporarily required to bear these losses ourselves. Each of these risks could negatively affect our business, results of operations and financial condition. We may fail to have necessary systems and services in place when certain of the transaction agreements expire. If we do not have in place our own systems and services, or if we do not have agreements with other providers of these services once certain separation transaction agreements expire, we may not be able to operate our business effectively, and our profitability may decline. We are in the process of creating our own, or engaging third parties to provide, systems and services to replace many of the systems and services that Exelon currently 45 Table of Contents provides to us. We may incur temporary interruptions in business operations if we cannot transition effectively from Exelon’s existing operating systems, databases and programming languages that support these functions to our own systems. Our failure to implement the new systems and transition our data successfully and cost-effectively could disrupt our business operations and have a material adverse effect on our profitability. In addition, our costs for the operation of these systems may be higher than the amounts reflected in our historical financial statements. ITEM 4. MINE SAFETY DISCLOSURES Not Applicable. 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, 2024 there were 316,666,538 shares of common stock outstanding and approximately 70,439 record holders of common stock. Stock Performance Graph The performance graph below illustrates a two-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, or UTY, for the period 2022 through 2023. 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. 46 Table of Contents Value of Investment 2/1/22 12/31/22 12/31/23 CEG $100 $175 $240 S&P 500 $100 $86 $108 UTY $100 $107 $96 Constellation As of January 31, 2024, CEG Parent directly held the entire membership interest in Constellation. Dividends As a Pennsylvania corporation, Constellation is subject to certain restrictions on dividends under Pennsylvania corporate law. Generally, a corporation may only pay dividends under the Pennsylvania Business Corporation Law if the total assets of the corporation would be more than the sum of its total liabilities plus the amount that would be needed, if the corporation were to be dissolved at the time as of which the distribution is measured, to satisfy the preferential rights upon dissolution of shareholders whose preferential rights are superior to those receiving the distribution. Constellation's revolving credit facility contains a covenant requiring it to maintain a consolidated leverage ratio calculated as the ratio of its consolidated indebtedness to its consolidated earnings before interest, taxes, depreciation and amortization. Maintaining that ratio may affect Constellation's ability to make distributions to the CEG Parent. Our Board of Directors approved an updated dividend policy for 2024. The 2024 quarterly dividend will be $0.3525 per share. The following table sets forth Constellation’s quarterly cash dividends per share paid during 2023 and 2022. 2023 2022 Fourth Quarter Third Quarter Second Quarter First Quarter Fourth Quarter Third Quarter Second Quarter First Quarter $ 0.2820 $ 0.2820 $ 0.2820 $ 0.2820 $ 0.1410 $ 0.1410 $ 0.1410 $ 0.1410 First Quarter 2024 Dividend On February 26, 2024, our Board of Directors declared a regular quarterly dividend of $0.3525 per share on our common stock for the first quarter of 2024. The dividend is payable on Tuesday, March 19, 2024, to shareholders of record as of 5 p.m. Eastern time on Friday, March 8, 2024. 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 interests of our other stakeholders. 47 Table of Contents On February 16, 2023, as part of our capital allocation plan, our Board of Directors announced a share repurchase program with a $1 billion authority without expiration. Repurchases under this program commenced in March 2023. Shares repurchased were made through open market transactions and purchases pursuant to a Rule 10b5-1 trading plan. All repurchased shares were constructively retired and cancelled. On December 12, 2023, our Board of Directors approved an increase to our previously announced $1 billion share repurchase program, authorizing the repurchase of up to an additional $1 billion of the Company’s outstanding common stock. On November 9, 2023, we entered into a stock purchase plan for the purchase of shares of our common stock (November 2023 Stock Purchase Plan), designed to comply with Rule 10b5-1 under the Exchange Act. Under its terms, the November 2023 Stock Purchase Plan would expire at the later of the completion of the maximum purchase amount of $250 million of shares of our common stock, or December 31, 2023. During 2023, we repurchased from the open market approximately 10.6 million shares of our common stock for a total cost, inclusive of taxes and transaction costs, of $1 billion. As of December 31, 2023, there was $1 billion of remaining authority to repurchase shares. The following table provides information regarding our share repurchases under the program during the three months ended December 31, 2023. All repurchases disclosed were made pursuant to the November 2023 Stock Purchase Plan: Period Total Number of Shares Purchased (a) Average Price Paid per Share (b) Approximate Dollar Value of Shares that May Yet Be Purchased Under the Programs (c) October 1, 2023 to October 31, 2023 — $ — $ 244,000,000 November 1, 2023 to November 30, 2023 993,800 $ 122.84 $ 121,000,000 December 1, 2023 to December 31, 2023 (d) 1,031,569 $ 115.75 $ 1,000,000,000 Total 2,025,369 $ 119.22 $ 1,000,000,000 __________ (a) We have not made any purchases of shares other than in connection with the publicly announced share repurchase program described above. (b) Average price paid per share for open market transactions excludes taxes and commissions. (c) Approximate dollar value of shares that may yet be purchased under the program includes taxes and commissions. (d) Includes increase of additional $1 billion of share repurchase authority. ITEM 6. RESERVED Not Applicable. Item 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (Dollars in millions, unless otherwise noted) Executive Overview We are a supplier of carbon-free energy. Our generating capacity primarily consists of 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, governmental, and residential customers in competitive 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, 2023 compared to the year ended December 31, 2022. For discussion of the year ended December 31, 2022 48 Table of Contents compared to the year ended December 31, 2021, refer to ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS in the 2022 Form 10-K, which was filed with the SEC on February 16, 2023. Capital Allocation and Growth Announcements We are announcing our capital allocation strategy for 2024 and 2025 supporting our core principles outlined in our Strategy and Outlook discussion. See ITEM 1. BUSINESS – Constellation's Strategy and Outlook for additional information about our strategy. We will increase the quarterly dividend by 25% to $0.3525 per share starting in 2024, while targeting growth of 10% annually. We are allocating capital towards our best-in-class generation fleet by committing $875 million of growth capital expenditures over the next two years, including nuclear uprates and license renewals, wind repowering, and hydrogen with policy support. These organic growth opportunities are projected to exceed our double-digit return threshold. In our commitment to return value to shareholders, we have also approved an increase to our previously announced $1 billion share buyback program, authorizing the repurchase of up to an additional $1 billion of company stock. See Note 20 — Shareholders' Equity of the Combined Notes to the Consolidated Financial Statements for additional information on completed and authorized share buybacks. Significant Transactions and Developments Separation from Exelon On February 21, 2021, Exelon’s Board of Directors approved a plan to separate its competitive generation and customer-facing energy businesses into a stand-alone publicly traded company (the "separation"). Exelon completed the separation on February 1, 2022. In order to govern the ongoing relationships between us and Exelon after the separation, and to facilitate an orderly transition, we and Exelon have entered into several agreements, including a Separation Agreement, Tax Matters Agreement, a Transition Services Agreement, and an Employee Matters Agreement and other ancillary agreements. See Note 1 — Basis of Presentation of the Combined Notes to Consolidated Financial Statements for additional information. We incurred separation costs of $101 million and $140 million for the years ended December 31, 2023 and 2022, respectively, which are primarily recorded in Operating and maintenance expense. The separation costs are primarily comprised of system-related costs, third-party costs paid to advisors, consultants, lawyers, and other experts assisting in the separation. Share Repurchase Program On February 16, 2023, our Board of Directors announced a share repurchase program with a $1 billion authority without expiration. Repurchases under this program commenced in March 2023. On December 12, 2023, the Board of Directors approved an increase to our previously announced $1 billion share repurchase program, authorizing the repurchase of up to an additional $1 billion of our outstanding common stock. During 2023, we repurchased from the open market 10.6 million shares of our common stock for a total cost, inclusive of taxes and transaction costs, of $1 billion. See Note 20 — Shareholders' Equity of the Combined Notes to Consolidated Financial Statements for additional information. Acquisition of Joint Ownership in South Texas Project On November 1, 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 net cash paid was $1.65 billion, after certain purchase price adjustments. This acquisition is complementary to and aligned strategically with our existing clean energy business operations. See Note 2 — Mergers, Acquisitions, and Dispositions of the Combined Notes to the Consolidated Financial Statements for additional information on this acquisition. The STP operating results are included in the ERCOT operating segment. See Note 5 — Segment Information additional information on our reportable segments. Revenue Recognized for Illinois ZECs Delivered in Prior Planning Years 49 Table of Contents Our Clinton and Quad Cities units contract with certain utilities in Illinois which requires delivery of all ZECs produced during each planning year (June 1 to May 31), with total compensation limited by an annual cap for each planning year designed to limit the cost of ZECs to each utility's customers. ZECs delivered that, if paid, would result in the annual cap being exceeded may be paid in subsequent years at the vintage year price as long as the payments would not exceed the annual cap in the year paid. In each planning year since the program commenced on June 1, 2017, we delivered ZECs to the utilities in excess of the annual compensation cap. The ZEC price and annual compensation cap effective for each planning year are administratively determined by the IPA. In 2023, we recognized $218 million of revenue as a receivable for ZECs delivered in prior planning years, with payment expected in the third quarter of 2024. As of December 31, 2023, this receivable is included within Customer accounts receivable, net in the Consolidated Balance Sheets. See Note 4 — Revenue from Contracts with Customers of the Combined Notes to the Consolidated Financial Statements for additional information on this acquisition. Other Key Business Drivers Russia and Ukraine Conflict We are closely monitoring developments of the Russia and Ukraine conflict including United States, United Kingdom, European Union, and Canadian sanctions, and pending legislation that may impact exports and imports of Russian nuclear fuel supply and enrichment activities, as well as the potential for Russia to limit energy deliveries. To-date, our nuclear fuel deliveries have not been affected by the Russia and Ukraine conflict. 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 and generally have enough nuclear fuel to support all our refueling needs for multiple years regardless of sanctions. 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. We are taking this affirmative action by working with our diverse set of suppliers to ensure we can secure the nuclear fuel needed to continue to operate our nuclear fleet long-term and provide the necessary fuel to bridge potential Russian supply disruption through 2028, which is the date multiple suppliers are expected to have incremental additional capacity online. We are also continuing to work with federal policymakers and other stakeholders to facilitate the expansion of the domestic nuclear fuel cycle within the United States to improve carbon-free energy security. 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. 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 $13.9 billion at December 31, 2023. 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. As a result of nuclear plant retirements in the industry, in recent years, nuclear operators and third-party service providers are obtaining 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, as more nuclear plants are retired, 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. 50 Table of Contents 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: 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 2035. 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 19 — 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. The ARO is not required or permitted to be re-measured for changes in the CARFR that occur in isolation. Increases in the 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 the ARO are treated as a modification of an existing ARO cost layer and, therefore, are measured using the average historical CARFR rates used in creating the initial ARO cost 51 Table of Contents layers. If all our future nominal cash flows associated with the ARO were to be discounted at the current prevailing CARFR, the obligation would decrease from approximately $13.9 billion to approximately $11.3 billion. The following table illustrates the significant 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 the ARO: Change in the CARFR applied to the annual ARO update Increase (Decrease) to ARO as of December 31, 2023 2022 CARFR rather than the 2023 CARFR $ 520 2023 CARFR increased by 50 basis points (290) 2023 CARFR decreased by 50 basis points 350 ARO Sensitivities. Changes in the assumptions underlying the ARO could materially affect the decommissioning obligation. The impact of a change in any one of these assumptions to the 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 ARO as of December 31, 2023 Cost escalation studies Uniform increase in escalation rates of 50 basis points $ 1,860 Probabilistic cash flow models Increase the estimated costs to decommission the nuclear plants by 10 percent 770 Increase the likelihood of the DECON scenario by 10 percent and decrease the likelihood of the SAFSTOR scenario by 10 percent (a) 140 Shorten each unit's probability-weighted operating life assumption by 10 percent (b) 220 Extend the estimated date for DOE acceptance of SNF to 2040 (80) __________ (a) Excludes any sites in which management has committed to a specific decommissioning approach. (b) Excludes any retired sites. 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. Purchase Accounting In accordance with authoritative guidance, the assets acquired and liabilities assumed in an acquired business 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 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 amount 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. Goodwill is not amortized, instead it is subject to an impairment assessment at least annually to consider whether the 52 Table of Contents reporting unit fair value is more likely than not less than the carrying amount. See Note 1 — Basis of Presentation, Note 2 — Mergers, Acquisitions, and Dispositions, and Note 13 — Intangible Assets of the Combined Notes to Consolidated Financial Statements for additional information. Goodwill We are required to perform an assessment for impairment of goodwill 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 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 segments. Goodwill is primarily reported within our ERCOT segment. See Note 13 — Intangible Assets of the Combined Notes to Consolidated Financial Statements for additional information. Entities assessing goodwill for impairment have the option of first performing a qualitative assessment to determine whether a quantitative assessment is necessary. As part of the qualitative assessment, we evaluate, among other things, management’s best estimate of projected operating and capital cash flows for the reporting units and changes in certain market conditions, including the discount rate. Significant assumptions used in these fair value analyses include discount and growth rates, energy prices, and projected operating and capital cash flows. While the 2023 annual assessments indicated no impairments, certain assumptions used in the assessment are highly sensitive to changes. Adverse regulatory actions or changes in significant assumptions could potentially result in future impairments of our goodwill, which could be material. See Note 1 — Basis of Presentation, Note 2 — Mergers, Acquisitions, and Dispositions, and Note 13 — Intangible Assets of the Combined Notes to Consolidated Financial Statements for additional information. Unamortized Energy Contract Assets and Liabilities Unamortized energy contract assets and liabilities represent the remaining unamortized balances of non-derivative energy contracts and fuel contracts that we have acquired. The initial amount recorded represents the difference between the fair value of the contracts at the time of acquisition and the contract value based on the terms of each contract. The unamortized energy contract assets and liabilities are amortized over the life of the contract in relation to 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 13 — 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. 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 generation 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 53 Table of Contents 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 (typically contracted renewable generation). 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 asset or asset groups. This includes significant assumptions of the estimated future cash flows generated by the asset 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, maintenance expenditures, and discount rates, as well as information from various public, financial and industry sources. See Note 12 — Asset Impairments of the Combined Notes to Consolidated Financial Statements for a discussion of asset impairment assessments. Depreciable Lives of Property, Plant, and Equipment We have significant investments in electric generation 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, supported by formal depreciation studies of historical asset retirement experience. Depreciation studies are generally conducted periodically if an event, regulatory action, or change in retirement patterns indicate an update is necessary. Along with depreciation study results, management considers expected future energy market conditions and generation plant operating costs and capital investment requirements in determining the estimated service lives of our generating facilities and reassesses the reasonableness of estimated useful lives whenever events or changes in circumstances warrant. When a determination has been made that an asset will be retired before the end of its current estimated useful life, depreciation provisions will be accelerated to reflect the shortened estimated useful life, which could have a material unfavorable impact on future results of operations. See Note 7 — Early Plant Retirements of the Combined Notes to Consolidated Financial Statements for additional information. Changes in estimated useful lives of electric generation assets could have a significant 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 service 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 Risk Management Policy (RMP). See Note 16 — 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 authoritative guidance, could result in previously excluded contracts becoming in scope of new authoritative guidance. 54 Table of Contents 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 entered for economic hedging and for proprietary trading 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 on 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 reassess our economic hedges on a regular basis to determine if they continue to be within the guidelines of the RMP. As a part of the authoritative guidance, 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 the expected changes in the 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 generally not been material to the consolidated financial statements. See ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK and Note 16 — Derivative Financial Instruments and Note 18 — 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 The majority of our current employees participate in defined benefit pension and OPEB plans we sponsor. The measurement of the plan obligations and costs of providing benefits involves various factors, including the development of 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 projected 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 upon any interim remeasurement of the plan obligations. Pension and OPEB plan assets include equity securities, including U.S. and international securities, and fixed income securities, as well as certain alternative investment classes such as real estate, private equity, private credit, and hedge funds. 55 Table of Contents Expected Rate of Return on Plan Assets. In determining the EROA, we consider expectations regarding future long-term capital market performance, weighted by our target asset class allocations. We calculate the amount of expected return on pension and OPEB plan assets by multiplying the EROA by the MRV of plan assets at the beginning of the year, taking into consideration anticipated contributions and benefit payments to be made during the year. In determining MRV, the authoritative guidance for pensions and postretirement benefits allows the use of either fair value or a calculated value that recognizes changes in fair value in a systematic and rational manner over not more than five 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 of plan assets. Use of this calculated value approach enables 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. The discount rates are determined by developing a spot rate curve based on the yield to maturity of a universe of high-quality non-callable (or callable with make-whole provisions) bonds with similar maturities to the related pension and OPEB obligations. The spot rates are used to discount the estimated future benefit distribution amounts under the pension and OPEB plans. The discount rate is the single level rate that produces the same result as the spot rate curve. We utilize an analytical tool developed by our actuaries to determine the discount rates. Mortality. The mortality assumption is composed of a base table that represents the current expectation of life expectancy of the population adjusted by an improvement scale that attempts to anticipate future improvements in life expectancy. At separation and upon remeasurement as of December 31, 2023, 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 15 — Retirement Benefits of the Combined Notes to Consolidated Financial Statements, while holding all other assumptions constant: Actual Assumption Pension OPEB Assumption Increase / (Decrease) Actuarial Assumption Pension OPEB Total Change in 2024 cost: Discount rate (a) 5.52 % 5.50 % 0.5 % $ (14) $ — $ (14) 5.52 % 5.50 % (0.5) % 14 1 15 EROA 6.50 % 6.51 % 0.5 % (39) (4) (43) 6.50 % 6.51 % (0.5) % 39 4 43 Change in benefit obligation: Discount rate (a) 5.17 % 5.15 % 0.5 % (349) (64) (413) 5.17 % 5.15 % (0.5) % 380 69 449 __________ (a) In general, 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 discount rate sensitivities above cannot necessarily be extrapolated for larger increases or decreases in the discount rate. Additionally, we utilize a liability-driven hedging investment strategy for our pension asset portfolio. The sensitivities shown above do not reflect the offsetting impact that changes in discount rates may have on pension asset returns. See Note 1 — Basis of Presentation and Note 15 — 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 solely on the technical merits and facts and circumstances of the position, assuming the 56 Table of Contents 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 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 14 — 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. Such difference could have a significant impact in the consolidated financial statements. 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. In addition, periodic reviews are performed to assess the adequacy of other environmental reserves. These matters, if resolved in a manner different from the estimate, could have a significant impact in the consolidated financial statements. See Note 19 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for additional information. Other, Including Personal Injury Claims. Prior to our separation from Exelon, we were self-insured for general liability, automotive liability, and workers’ compensation claims. For accidents occurring post-separation, 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 the consolidated financial statements. 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 Customers and Derivatives Revenues 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 commodities and services are provided to the customer. Transactions within the scope of 57 Table of Contents 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. Derivative Revenues. We record revenues and expenses using the mark-to-market method of accounting for transactions that are accounted for as derivatives. These derivative transactions primarily relate to commodity price risk management activities. Mark-to-market 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 GAAP consolidated Net Income (Loss) Attributable to Common Shareholders for the year ended December 31, 2023 compared to the same period in 2022. For additional information regarding the financial results for the years ended December 31, 2023 and 2022 see the discussions of Results of Operations below. For the Years Ended December 31, Favorable Variance 2023 2022 GAAP Net Income (Loss) Attributable to Common Shareholders $ 1,623 $ (160) $ 1,783 Adjusted EBITDA (non-GAAP). In analyzing and planning for our business, we supplement our use of GAAP Net Income (Loss) Attributable to Common Shareholders with Adjusted EBITDA (non-GAAP) as a performance measure. Adjusted EBITDA (non-GAAP) reflects an additional way of viewing our business that, when viewed with our GAAP results and the accompanying reconciliation to GAAP Net Income (Loss) Attributable to Common Shareholders included in the table below, may provide a more complete understanding of factors and trends affecting our business. Adjusted EBITDA (non-GAAP) should not be relied upon to the exclusion of GAAP financial measures and is, by definition, an incomplete understanding of our business, and must be considered in conjunction with GAAP measures. In addition, Adjusted EBITDA (non-GAAP) is neither a standardized financial measure, nor a presentation defined under GAAP and may not be comparable to other companies’ presentations or deemed more useful than the GAAP information provided elsewhere in this report. 58 Table of Contents The following table provides a reconciliation between Net income (loss) attributable to common shareholders as determined in accordance with GAAP and Adjusted EBITDA (non-GAAP) for the year ended December 31, 2023 compared to the same period in 2022. For the Years Ended December 31, 2023 2022 Net Income (Loss) Attributable to Common Shareholders $ 1,623 $ (160) Income Tax (Benefit) Expense (a) 840 (339) Depreciation and Amortization 1,096 1,091 Interest Expense, Net 431 251 Unrealized (Gain) Loss on Fair Value Adjustments (b) 658 1,058 Asset Impairments 71 — Plant Retirements and Divestitures (28) (11) Decommissioning-Related Activities (c) (716) 820 Pension & OPEB Non-Service Credits (54) (116) Separation Costs (d) 101 140 Acquisition-Related Costs 12 — ERP System Implementation Costs (e) 25 22 Change in Environmental Liabilities 43 10 Prior Merger Commitment (f) — (50) Noncontrolling Interests (g) (77) (49) Adjusted EBITDA (non-GAAP) $ 4,025 $ 2,667 __________ (a) Includes amounts contractually owed to Exelon under the TMA reflected in Other, net. (b) Includes mark-to-market on economic hedges and fair value adjustments related to gas imbalances and equity investments. (c) Reflects all gains and losses associated with NDTs, ARO accretion, ARO remeasurement, and impacts of contractual offset for Regulatory Agreement Units. (d) Represents certain incremental costs related to the separation (system-related costs, third-party costs paid to advisors, consultants, lawyers, and other experts assisting in the separation), including a portion of the amounts billed to us pursuant to the TSA. (e) Reflects costs related to a multi-year ERP system implementation. (f) Reversal of a charge related to a 2012 merger commitment. (g) Represents elimination from results for the noncontrolling interests related to certain adjustments. 59 Table of Contents Results of Operations 2023 2022 Favorable (Unfavorable) Variance Operating revenues $ 24,918 $ 24,440 $ 478 Operating expenses Purchased power and fuel 16,001 17,462 1,461 Operating and maintenance 5,685 4,841 (844) Depreciation and amortization 1,096 1,091 (5) Taxes other than income taxes 553 552 (1) Total operating expenses 23,335 23,946 611 Gain (loss) on sales of assets and businesses 27 1 26 Operating income (loss) 1,610 495 1,115 Other income and (deductions) Interest expense, net (431) (251) (180) Other, net 1,268 (786) 2,054 Total other income and (deductions) 837 (1,037) 1,874 Income (loss) before income taxes 2,447 (542) 2,989 Income tax (benefit) expense 859 (388) (1,247) Equity in income (losses) of unconsolidated affiliates (11) (13) 2 Net income (loss) 1,577 (167) 1,744 Net income (loss) attributable to noncontrolling interests (46) (7) (39) Net income (loss) attributable to common shareholders $ 1,623 $ (160) $ 1,783 Year Ended December 31, 2023 Compared to Year Ended December 31, 2022. Net income (loss) attributable to common shareholders was favorable by $1,783 million primarily due to: • Favorable market and portfolio conditions primarily driven by higher realized margins on load contracts and generation-to-load optimization; • Favorable net realized and unrealized NDT activity; and • Unrealized gains resulting from an investment that became a publicly traded company in the second quarter of 2023. The favorable items were partially offset by: • Higher labor, contracting and materials; • Lower capacity revenues; • Impact of our annual update to the nuclear ARO for Non-Regulatory Agreement Units; • Unfavorable impacts of nuclear outages; and • Higher interest expense. Operating revenues. 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 RTO/ISO 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 with these same geographic regions. 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. 60 Table of Contents 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. For the year ended December 31, 2023 compared to 2022, Operating revenues were as follows: 2023 vs. 2022 2023 2022 Variance % Change (a) Mid-Atlantic $ 5,138 $ 5,164 $ (26) (0.5) % Midwest 4,658 4,650 8 0.2 % New York 2,021 1,595 426 26.7 % ERCOT 1,346 1,543 (197) (12.8) % Other Power Regions 5,851 6,732 (881) (13.1) % Total reportable segment electric revenues 19,014 19,684 (670) (3.4) % Other 4,505 5,944 (1,439) (24.2) % Mark-to-market gains (losses) 1,399 (1,188) 2,587 Total Operating revenues $ 24,918 $ 24,440 $ 478 2.0 % __________ (a) % Change in mark-to-market is not a meaningful measure. Sales and Supply Sources. Our sales and supply sources by region are summarized below: 2023 vs. 2022 Supply Source (GWhs) 2023 2022 Variance % Change Nuclear Generation (a) Mid-Atlantic 53,012 53,214 (202) (0.4) % Midwest 93,768 95,090 (1,322) (1.4) % New York 25,546 25,046 500 2.0 % ERCOT 1,721 — 1,721 100.0 % Total Nuclear Generation 174,047 173,350 697 0.4 % Natural Gas, Oil and Renewables Mid-Atlantic 2,014 2,097 (83) (4.0) % Midwest 1,024 1,202 (178) (14.8) % ERCOT 16,877 14,124 2,753 19.5 % Other Power Regions 8,512 10,189 (1,677) (16.5) % Total Natural Gas, Oil and Renewables 28,427 27,612 815 3.0 % Purchased Power Mid-Atlantic 16,509 15,366 1,143 7.4 % Midwest 984 610 374 61.3 % ERCOT 5,530 3,575 1,955 54.7 % Other Power Regions 44,192 51,131 (6,939) (13.6) % Total Purchased Power 67,215 70,682 (3,467) (4.9) % Total Supply/Sales by Region Mid-Atlantic 71,535 70,677 858 1.2 % Midwest 95,776 96,902 (1,126) (1.2) % New York 25,546 25,046 500 2.0 % ERCOT 24,128 17,699 6,429 36.3 % Other Power Regions 52,704 61,320 (8,616) (14.1) % Total Supply/Sales by Region 269,689 271,644 (1,955) (0.7) % __________ (a) Includes the proportionate share of output where we have an undivided ownership interest in jointly-owned generating plants. 61 Table of Contents Nuclear Fleet Capacity Factor. The following table presents nuclear fleet operating data for our plants, which reflects ownership percentage of stations operated by us, excluding 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 plant over a period of time to its output if the plant had operated at its 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. 2023 2022 Nuclear fleet capacity factor 94.4 % 94.8 % Refueling outage days 256 212 Non-refueling outage days 51 54 ZEC Prices. We are compensated through state programs for the carbon-free attributes of our nuclear generation. ZEC programs are a significant contributor to our total operating revenues. The following table includes the average ZEC reference prices ($/MWh) for each of our major regions in which state programs have been enacted. Prices reflect the weighted average price for the various delivery periods within the years ended December 31, 2023 and 2022. 2023 vs. 2022 State (Region) (a) 2023 2022 Variance % Change New Jersey (Mid-Atlantic) (b) $ 9.95 $ 9.93 $ 0.02 0.2 % Illinois (Midwest) (c) 5.18 13.88 (8.70) (62.7) % New York (New York) 19.05 21.38 (2.33) (10.9) % __________ (a) See ITEM 1. BUSINESS, Environmental Matters for additional information on the plants receiving payments through state programs. (b) The ZEC price is expected to be $10.00/MWh for each delivery period and is subject to an annual update once full year generation is known. Following the latest annual update, on August 16, 2023 the ZEC price for the delivery period beginning June 1, 2022 through May 31, 2023 was calculated to be $9.88. (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 and is based on the accepted CMC bid, less the sum of (a) monthly weighted average PJM busbar price, (b) ComEd zone capacity price and (c) any federal tax credit or subsidy received, and is subject to a customer protection cap ($30.30 per MWh for initial delivery period June 1, 2022 through May 31, 2023 and $32.50 per MWh for the period June 1, 2023 through May 31, 2024). 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 $4.13 and ($42.20) for the years ended December 31, 2023 and 2022, respectively. Capacity Prices. We participate in capacity auctions in each of our major regions, except ERCOT which does not have a capacity market. We also incur capacity costs associated with load served, which are factored into customer sales prices. Capacity prices have a significant impact on our operating revenues and purchased power and fuel expense. We report capacity on a net monthly basis within each region in either Operating revenues or Purchased power and fuel expense, depending on our net monthly position. The following table presents the average capacity prices ($/MW Day) for each of our major regions. Prices reflect the weighted average price for the various auction periods within the years ended December 31, 2023 and 2022. 62 Table of Contents 2023 vs. 2022 Location (Region) 2023 2022 Variance % Change Eastern Mid-Atlantic Area Council (Mid-Atlantic and Midwest) $ 69.64 $ 126.14 $ (56.50) (44.8) % ComEd (Midwest) 48.64 121.71 (73.07) (60.0) % Rest of State (New York) 137.88 85.36 52.52 61.5 % Southeast New England (Other) 91.67 138.21 (46.54) (33.7) % 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, on-going 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. 2023 vs. 2022 Location (Region) 2023 2022 Variance % Change PJM West (Mid-Atlantic) $ 33.06 $ 72.90 $ (39.84) (54.7) % ComEd (Midwest) 26.64 60.24 (33.60) (55.8) % Central (New York) 26.97 57.52 (30.55) (53.1) % North (ERCOT) 55.15 64.38 (9.23) (14.3) % Southeast Massachusetts (Other) (a) 37.35 86.02 (48.67) (56.6) % __________ (a) Reflects New England, which comprises the majority of the activity in the Other region. For the year ended December 31, 2023 compared to 2022, changes in Operating revenues by region were approximately as follows: 2023 vs. 2022 Variance % Change (a) Description Mid-Atlantic $ (26) (0.5) % • unfavorable settled economic hedges of ($305) due to settled prices relative to hedged prices • unfavorable retail load revenue of ($40) primarily due to lower contracted energy prices; partially offset by • favorable wholesale load revenue of $250 due to higher contracted energy prices and higher volumes • favorable PJM net performance bonuses of $45 associated with the December 2022 weather event (b) Midwest 8 0.2 % • favorable settled economic hedges of $210 due to settled prices relative to hedged prices • favorable ZEC revenue of $85 primarily due to revenue recognized for Illinois ZECs delivered in prior planning years partially offset by a decrease in the ZEC price in current planning year • favorable retail load revenue of $25 primarily due to higher load volumes, partially offset by lower contracted energy prices; partially offset by • unfavorable net generation and wholesale load revenue of ($280) primarily due to lower nuclear generation and lower load volumes, partially offset by CMC program activity and net capacity revenue • unfavorable PJM performance bonuses of ($40), associated with the December 2022 weather event (b) , 63 Table of Contents 2023 vs. 2022 Variance % Change (a) Description New York 426 26.7 % • favorable settled economic hedges of $520 due to settled prices relative to hedged prices • favorable retail load revenue of $105 primarily due to higher contracted energy prices; partially offset by • unfavorable net generation revenue of ($150) primarily due to lower energy prices • unfavorable ZEC revenue of ($50) primarily due to lower ZEC price partially offset by higher generation volumes ERCOT (197) (12.8) % • unfavorable settled economic hedges of ($570) due to settled prices relative to hedged prices; partially offset by • favorable wholesale load revenue of $330 due to higher volumes and higher contracted energy prices Other Power Regions (881) (13.1) % • unfavorable settled economic hedges of ($845) due to settled prices relative to hedged prices • unfavorable wholesale load revenue of ($190) primarily due to lower volumes; partially offset by • favorable retail load revenue of $175 primarily due to higher contracted energy prices Other (1,439) (24.2) % • unfavorable gas revenue, including settled economic hedges, of ($1,240) primarily due to lower gas prices • unfavorable revenues in the United Kingdom of ($225) primarily due to lower energy prices Mark-to-market (c) 2,587 • gains on economic hedging activities of $1,399 in 2023 compared to losses of ($1,188) in 2022 Total $ 478 2.0 % __________ (a) % Change in mark-to-market is not a meaningful measure. (b) See Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information on PJM performance bonuses (c) See Note 16 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information on mark-to-market 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 supply sources by region, nuclear fleet capacity factor, capacity prices, and electricity prices. The following business activities are not allocated to a region and are reported under Other: wholesale and retail sales of natural gas, as well as other miscellaneous business activities that are not significant to overall results of operations. 64 Table of Contents For the year ended December 31, 2023 compared to 2022, Purchased power and fuel expense were as follows: 2023 vs. 2022 2023 2022 Variance % Change (a) Mid-Atlantic $ 2,214 $ 3,026 $ 812 26.8 % Midwest 1,403 1,886 483 25.6 % New York 770 528 (242) (45.8) % ERCOT 764 1,136 372 32.7 % Other Power Regions 4,611 5,811 1,200 20.7 % Total electric purchased power and fuel 9,762 12,387 2,625 21.2 % Other 3,868 5,250 1,382 26.3 % Mark-to-market losses (gains) 2,371 (175) (2,546) Total purchased power and fuel $ 16,001 $ 17,462 $ 1,461 8.4 % __________ (a) % Change in mark-to-market is not a meaningful measure. For the year ended December 31, 2023 compared to 2022, changes in Purchased power and fuel expense by region were approximately as follows: 2023 vs. 2022 Variance % Change (a) Description Mid-Atlantic $ 812 26.8 % • favorable purchased power and net capacity impact of $960 primarily due to lower energy and capacity prices; partially offset by • unfavorable environmental products activity of ($160) primarily due to higher load served and REC prices Midwest 483 25.6 % • favorable cost associated with power delivery and net capacity impact of $525 primarily due to lower energy and capacity prices earned New York (242) (45.8) % • unfavorable settlement of economic hedges of ($360) due to settled prices relative to hedged prices; partially offset by • favorable cost associated with power delivery and net capacity impact of $130 primarily due to lower energy prices and partially offset by higher capacity prices ERCOT 372 32.7 % • favorable settlement of economic hedges of $245 due to settled prices relative to hedged prices • favorable fuel cost of $70 primarily due to lower gas prices partially offset by higher generation • favorable purchased power of $65 primarily due to lower energy prices and higher generation partially offset by higher load served Other Power Regions 1,200 20.7 % • favorable purchased power and fuel of $3,235 primarily due to lower energy prices and lower load served; partially offset by • unfavorable settlement of economic hedges of ($1,965) due to settled prices relative to hedged prices • unfavorable environmental products activity of ($55) primarily driven higher REC prices 65 Table of Contents 2023 vs. 2022 Variance % Change (a) Description Other 1,382 26.3 % • favorable net gas purchase costs and settlement of economic hedges of $1,160 primarily due to lower gas prices • favorable purchases in the United Kingdom of $180 primarily due to lower energy prices • favorable fair value adjustment related to gas imbalances of $45 Mark-to-market (b) (2,546) • losses on economic hedging activities of ($2,371) in 2023 compared to gains of $175 in 2022 Total $ 1,461 8.4 % __________ (a) % Change in mark-to-market is not a meaningful measure. (b) See Note 16 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information on mark-to-market gains and losses. The changes in Operating and maintenance expense consisted of the following: 2023 vs. 2022 Increase (Decrease) Labor, other benefits, contracting, and materials (a) $ 349 Decommissioning-related activities (b) 169 Nuclear refueling outage costs, including the co-owned Salem plants 157 Asset impairments 71 Prior merger commitment 50 Change in environmental liabilities 34 Other 14 Total increase $ 844 __________ (a) Primarily reflects increased employee-related costs, including labor and other incentives, and certain non-essential maintenance work. (b) Primarily reflects a decreased benefit related to the annual nuclear ARO update for non-regulatory agreement units. Interest expense, net increased for the year ended December 31, 2023 compared to the same period in 2022, primarily due to the issuance of senior notes and tax exempt bonds, increased fees and interest on short term borrowings, and changes in the 13-week Treasury rate for our SNF obligation. See Note 17 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information on our senior notes, tax-exempt bonds, and short-term borrowings. See Note 19 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for additional information on our SNF obligation. 66 Table of Contents Other, net was favorable for the year ended December 31, 2023 compared to the same period in 2022, due to activity described in the table below: Other, net For the Years Ended December 31, Income (Deductions) Income (Deductions) 2023 2022 Decommissioning-related activities (a) $ 803 $ (902) Non-service net periodic benefit credit (cost) (b) 54 110 Net realized and unrealized gains (losses) from equity investments (c) 307 (13) Return to provision adjustment (d) 19 (49) Other (e) 85 68 Other, net $ 1,268 $ (786) __________ (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 except for decommissioning-related impacts that were not offset for the Byron units starting in the second quarter of 2021. With our September 15, 2021 reversal of the previous decision to retire Byron, we resumed contractual offset for Byron as of that date. See Note 10 — Asset Retirement Obligations of the Combined Notes to Consolidated Financial Statements for additional information regarding the accounting for nuclear decommissioning and the contractual offset suspension for the Byron units. See Note 23 — Supplemental Financial Information of the Combined Notes to Consolidated Financial Statements for additional information. (b) Prior to separation, we were allocated our portion of pension and OPEB non-service credits (costs) from Exelon, which was included in Operating and maintenance expense. Effective February 1, 2022, the non-service credit (cost) components are included in Other, net, in accordance with single employer plan accounting. See Note 15 — Retirement Benefits of the Combined Notes to Consolidated Financial Statements for additional information. (c) For 2023, includes unrealized gain resulting from equity investment that became publicly traded in the second quarter of 2023 and now has a readily determinable fair value (and no longer is accounted for as an equity method investment due to lack of significant influence). We record the fair value of this investment in Investments on the Consolidated Balance Sheets based on quoted market price of the stock. See Note 18 — Fair Value of Financial Assets and Liabilities of the Combined Notes to Consolidated Financial Statements for additional information. For 2022, represents Net realized and unrealized (losses) gains from equity investments. (d) This reflects amounts contractually owed to Exelon under the TMA, which is offset in Income taxes. See Note 14 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information. (e) Includes amounts we billed Exelon for services pursuant to the TSA. See Note 1 — Basis of Presentation of the Combined Notes to Consolidated Financial Statements for additional information. Effective income tax rates were 35.1% and 71.6% for the years ended December 31, 2023 and 2022, respectively. We do not expect the effective tax rate to deviate from the statutory tax rate with the exception of realized and unrealized gains and losses of the nuclear decommissioning trust funds. In 2022, the rate was also impacted by one-time adjustments. See Note 14 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information. Net income attributable to noncontrolling interests primarily relates to CRP for the years ended December 31, 2023 and 2022. Liquidity and Capital Resources For discussion of the year ended December 31, 2022 compared to the year ended December 31, 2021, refer to Liquidity and Capital Resources of MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS in the 2022 Form 10-K which was filed with the SEC on February 16, 2023. All results included throughout the liquidity and capital resources section are presented on a GAAP basis. Our operating and capital expenditures requirements are provided by internally generated cash flows from operations, the sale of certain receivables, as well as funds from external sources in the capital markets and through bank borrowings. Our business is capital intensive and requires considerable capital resources. We 67 Table of Contents annually evaluate our financing plan and credit line sizing, focusing on maintaining our investment grade ratings while meeting our cash needs to fund capital requirements, including construction expenditures, retire debt, pay dividends, fund pension and OPEB obligations, and invest in new and existing ventures. 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., 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 $6.1 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 17 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information on our debt and credit agreements. Pursuant to the Separation Agreement between us and Exelon, we received a cash payment of $1.75 billion from Exelon on January 31, 2022. See Note 1 — Basis of Presentation of the Combined Notes to Consolidated Financial Statements for additional information on the separation. 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 to decommission 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 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, 2023, we are not required to provide any additional financial assurance for TMI Unit 1 under the SAFSTOR scenario that is the planned decommissioning option, as described in the TMI Unit 1 PSDAR filed with the NRC on April 5, 2019. On October 16, 2019, the NRC granted our exemption request to use the TMI Unit 1 NDT funds for spent fuel management costs. On June 8, 2022, the NRC granted our exemption request to use the TMI Unit 1 NDT funds for site restoration costs. On November 16, 2023, Zion Station was transferred back to us from ZionSolutions. As of December 31, 2023, we have adequate NDT funds for the remaining radiological decommissioning cost at Zion Station. 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 on Zion Station Decommissioning. 68 Table of Contents Cash Flows from Operating Activities Our cash flows from operating activities primarily result from the sale of electric energy and energy-related products and services to customers. Our future cash flows from operating activities may be affected by future demand for, and market prices of, energy and our ability to continue to produce and supply power at competitive costs, as well as to obtain collections from customers and the sale of certain receivables. See Note 3 — Regulatory Matters and Note 19 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for additional information on regulatory and legal proceedings and proposed legislation. The following table provides a summary of the change in cash flows from operating activities for the years ended December 31, 2023 and 2022: For the Years Ended December 31, Cash flows from operating activities 2023 2022 Change Net income (loss) $ 1,577 $ (167) $ 1,744 Adjustments to reconcile net income (loss) to cash: Changes in working capital and other noncurrent assets and liabilities (a) (8,355) (5,246) (3,109) Collateral received (posted), net (1,491) (351) (1,140) Option premiums received (paid), net 26 (177) 203 Pension and non-pension postretirement benefit contributions (54) (237) 183 Total non-cash operating activities (b) 2,996 3,825 (829) Net cash flows provided by (used in) operating activities $ (5,301) $ (2,353) $ (2,948) __________ (a) Includes changes in Accounts receivable, Receivables from and payables to affiliates, net, Inventories, Accounts payable and accrued expenses, Income taxes, and Other assets and liabilities. (b) See the Consolidated Statements of Cash Flows for details of non-cash operating activities, includes Depreciation, amortization, and accretion, Asset impairments, Gain on sales of assets and businesses, Deferred income taxes and amortization of ITCs, Net fair value changes related to derivatives, and Net realized and unrealized activity associated with NDTs and equity investments. See Note 23 — Supplemental Financial Information of the Combined Notes to Consolidated Financial Statements for additional information on the Other non-cash operating activities line. Changes in our cash flows from operations were generally consistent with changes in results of operations, as adjusted by changes in working capital in the normal course of business, except as discussed below. In addition, significant operating cash flow impacts for 2023 and 2022 were as follows: • A net increase in cash outflows for changes in working capital and other noncurrent assets and liabilities primarily relates to a decrease in Accounts payable and accrued expenses, primarily driven by lower gas prices and a decrease in CMC program activity for the current year. This was partially offset by a decrease in Accounts receivable, mainly driven by higher contracted prices and volumes at year end 2022, including the impact of the December 2022 weather event. Additionally, there was a decrease in Other assets and liabilities, primarily driven by an increase in cash collections applied to DPP due to a decrease in the drawn customer accounts receivable Facility balance in 2023 compared to 2022 . See Note 6 — Accounts Receivable of the Combined Notes to Consolidated Financial Statements for additional information on the sales of customer accounts receivable. • Depending upon whether we are in a net mark-to-market liability or asset position, collateral may be required to be posted with or collected from our counterparties. In addition, the collateral posting and collection requirements differ depending on whether the transactions are on an exchange or in the over-the-counter markets. See Note 16 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information on collateral. • Option premiums paid, net relate to options contracts that we purchase and sell as part of our established policies and procedures to manage risks associated with market fluctuations in commodity 69 Table of Contents prices. Note 16 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information on derivative contracts. • Decrease in cash outflows for pension and non-pension postretirement benefit contributions is primarily due to our annual qualified pension contribution of $21 million and $192 million made in July 2023 and February 2022, respectively. See Note 15 — Retirement Benefits of the Combined Notes to Consolidated Financial Statements for additional information on pension and non-pension postretirement benefit plans. Cash Flows from Investing Activities The following table provides a summary of the change in cash flows from investing activities for the years ended December 31, 2023 and 2022: For the Years Ended December 31, Cash flows from investing activities 2023 2022 Change Acquisitions of assets and businesses $ (1,690) $ (29) $ (1,661) Capital expenditures (2,422) (1,689) (733) Proceeds from sales of assets and businesses 24 52 (28) Investment in NDT funds, net (228) (221) (7) Collection of DPP, net 7,340 4,964 2,376 Other investing activities 7 27 (20) Net cash flows provided by (used in) investing activities $ 3,031 $ 3,104 $ (73) Significant investing cash flow impacts for 2023 and 2022 were as follows: • See Note 2 — Mergers, Acquisitions, and Dispositions of the Combined Notes to Consolidated Financial Statements for additional information related to the STP acquisition . • Variances in capital expenditures are primarily due to the timing of cash payments for capital projects. See the "Credit Matters and Cash Requirements" section below for additional information on projected capital expenditure spending. • Collection of DPP, net increased due to cash collections from the customer accounts receivable Facility, as discussed in the Cash Flows from Operating Activities section above. This was partially offset by a reduction in cash proceeds received from the Purchasers in 2023 compared to 2022. See Note 6 — Accounts Receivable of the Combined Notes to Consolidated Financial Statements for additional information. Cash Flows from Financing Activities The following table provides a summary of the change in cash flows from financing activities for the years ended December 31, 2023 and 2022: For the Years Ended December 31, Cash flows from financing activities 2023 2022 Change Long-term debt, net $ 3,027 $ (1,406) $ 4,433 Changes in short-term borrowings, net 485 (923) 1,408 Dividends paid on common stock (366) (185) (181) Repurchases of common stock (992) — (992) Contributions from Exelon — 1,750 (1,750) Other financing activities 42 (35) 77 Net cash flows provided by (used in) financing activities $ 2,196 $ (799) $ 2,995 70 Table of Contents Significant financing cash flow impacts for 2023 and 2022 were as follows: • Long-term debt, net, varies due to debt issuances and redemptions each year. Refer to debt issuances and redemptions tables below for additional information. • Changes in short-term borrowings, net , is driven by repayments on and issuances of notes due in less than 365 days. Refer to Note 17 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information on short-term borrowings. • Refer to ITEM 5. — MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES for additional information on dividend restrictions. See below for quarterly dividends declared. • Repurchases of common stock is related to our share repurchase program that commenced in March 2023. See Note 20 — Shareholders' Equity of the Combined Notes to Consolidated Financial Statements for additional information. • Contributions from Exelon is primarily related to a cash contribution of $1.75 billion from Exelon on January 31, 2022, pursuant to the Separation Agreement. See Note 1 — Basis of Presentation of the Combined Notes to Consolidated Financial Statements for additional information on the separation. Debt Issuances and Redemptions See Note 17 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information on our long-term debt. Debt activity for 2023 and 2022 was as follows: During 2023, the following long-term debt was issued: Type Interest Rate Maturity Amount Use of Proceeds 2053 Senior Notes 6.50 % October 1, 2053 $ 900 To fund the acquisition of STP and general corporate purposes 2028 Senior Notes 5.60 % March 1, 2028 750 To fund general corporate purposes, including repayment of short-term borrowings 2033 Senior Notes 5.80 % March 1, 2033 600 To fund general corporate purposes, including repayment of short-term borrowings 2034 Senior Notes 6.13 % January 15, 2034 500 To fund the acquisition of STP and general corporate purposes Tax-Exempt Notes Reoffering 4.10% - 4.45% 2025-2053 (b) 435 To fund general corporate purposes, including repayment of short-term borrowings Energy Efficiency Project Financing (a) 2.20% - 4.96% March 31, 2024 - June 30, 2024 11 Funding to install energy conservation measures Total $ 3,196 __________ (a) For Energy Efficiency Project Financing, the maturity dates represent the expected date of project completion, upon which the respective customer assumes the outstanding debt. (b) The Tax-Exempt Notes have a maturity date of March 1, 2025 - April 1, 2053, and a mandatory purchase date that ranges from March 1, 2025 - June 1, 2029. 71 Table of Contents During 2022, the following long-term debt was issued: Type Interest Rate Maturity Amount Use of Proceeds Energy Efficiency Project Financing (a) 2.20% - 6.96% March 31, 2023 - May 1, 2024 $ 14 Funding to install energy conservation measures __________ (a) For Energy Efficiency Project Financing, the maturity dates represent the expected date of project completion, upon which the respective customer assumes the outstanding debt. During 2023, the following long-term debt was retired and/or redeemed: Type Interest Rate Maturity Amount Energy Efficiency Project Financing 2.44% - 6.96% May 31, 2023 - March 31, 2024 $ 44 CR Nonrecourse Debt 3-month SOFR + 2.76% (a) December 15, 2027 39 West Medway II Nonrecourse Debt 1-month SOFR + 2.975% - 3.225% (b)(d) March 31, 2026 26 Continental Wind Nonrecourse Debt 6.00% February 28, 2033 25 Antelope Valley DOE Nonrecourse Debt (c) 2.29% - 3.56% January 5, 2037 25 RPG Nonrecourse Debt 4.11% March 31, 2035 9 Total $ 168 __________ (a) The interest rate for long-term debt redemptions prior to June 2023 were based on LIBOR + 2.50%. Beginning in June 2023, these redemptions are based on SOFR + 2.76%. See Note 17 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information on the CR nonrecourse debt. (b) The interest rate for long-term debt redemptions prior to May 2023 were based on LIBOR + 2.875%. Beginning in May 2023, these redemptions are based on SOFR + the variable interest rate of 2.975% - 3.225%. See Note 17 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information on the West Medway II nonrecourse debt. (c) On January 5, 2024, we redeemed $5.5 million of 2.29% - 3.56% Antelope Valley DOE nonrecourse debt. (d) The nonrecourse debt has an average blended interest rate. During 2022, the following long-term debt was retired and/or redeemed: Type Interest Rate Maturity Amount Senior Notes 3.40% March 15, 2022 $ 500 Senior Notes 4.25% June 15, 2022 523 CR Nonrecourse Debt (a) 3-month LIBOR + 2.50% December 15, 2027 41 Continental Wind Nonrecourse Debt (a) 6.00% February 28, 2033 37 West Medway II Nonrecourse Debt (a) 1 month LIBOR + 2.875% (c) March 31, 2026 24 Antelope Valley DOE Nonrecourse Debt (a)(b) 2.29% - 3.56% January 5, 2037 25 RPG Nonrecourse Debt (a) 4.11% March 31, 2035 9 Energy Efficiency Project Financing 3.71% December 31, 2022 3 Total $ 1,162 __________ (a) See Note 17 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information on nonrecourse debt. (b) On January 6, 2023, we redeemed $5 million of 2.29% - 3.56% Antelope Valley DOE nonrecourse debt. (c) The nonrecourse debt has an average blended interest rate. 72 Table of Contents From time to time and as market conditions warrant, we may engage in long-term debt retirements via tender offers, open market repurchases or other viable options to reduce debt. Dividends Quarterly dividends declared by our Board of Directors during 2023 and for the first quarter of 2024 were as follows: Period Declaration Date Shareholder of Record Date Dividend Payable Date Cash per Share First Quarter of 2023 February 15, 2023 February 27, 2023 March 10, 2023 $ 0.2820 Second Quarter of 2023 April 25, 2023 May 12, 2023 June 9, 2023 $ 0.2820 Third Quarter of 2023 August 1, 2023 August 14, 2023 September 8, 2023 $ 0.2820 Fourth Quarter of 2023 November 1, 2023 November 17, 2023 December 8, 2023 $ 0.2820 First Quarter of 2024 February 26, 2024 March 8, 2024 March 19, 2024 $ 0.3525 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, 2023, we have access to facilities with aggregate bank commitments of $6.1 billion. We had access to the commercial paper markets and had availability under our revolving credit facilities during 2023 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. If we had lost our investment grade credit ratings as of December 31, 2023, we would have been required to provide incremental collateral estimated to be approximately $1.9 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. A loss of investment grade credit rating would have required a three notch downgrade by S&P or a two notch downgrade by Moody's from their current levels of BBB+ and Baa2, to BB+ and Ba1 or below. respectively. As of December 31, 2023, we had $3.1 billion of available capacity and $0.4 billion of cash on hand. In the event of a credit downgrade below investment grade and a resulting requirement to provide incremental collateral exceeding our available capacity and cash on hand, we would be required to access additional liquidity through the capital markets. See Note 16 — Derivative Financial Instruments and Note 17 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information. 73 Table of Contents Capital Expenditures Our most recent estimate of capital expenditures is approximately $2.8 billion and $2.3 billion for 2024 and 2025 respectively. Approximately 44% - 47% of projected capital expenditures are for the acquisition of nuclear fuel, which includes additional nuclear fuel to increase inventory levels. This is a strategic decision 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 includes $875 million of growth capital expenditures, including nuclear uprates and license renewals, wind repowering, and hydrogen with policy support. 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 and 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. Pension and Other Postretirement Benefits We consider various factors when making 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 below reflect a funding strategy to make levelized annual contributions with the objective of achieving 100% funded status over time. This level-funding strategy helps minimize volatility of future period required pension contributions. Unlike the qualified pension plans, our non-qualified pension plans are not funded, given that they are not subject to statutory minimum contribution requirements. OPEB plans are also not subject to statutory minimum contribution requirements, though we have funded certain of our plans. For our funded OPEB plans, we consider several factors in determining the level of contributions including liabilities management and levels of benefit claims paid. The following table provides our planned contributions to our qualified pension plans, non-qualified pension plans, and OPEB plans in 2024 (including our benefit payments related to unfunded plans): Qualified Pension Plans Non-Qualified Pension Plans OPEB Total Planned contributions $ 161 $ 13 $ 20 $ 194 To the extent interest rates decline significantly or the pension and OPEB plans earn less than the expected asset returns, annual pension contribution requirements in future years could increase. Conversely, to the extent interest rates increase significantly or the pension and OPEB plans earn greater than the expected asset returns, annual pension and OPEB contribution requirements in future years could decrease. Additionally, expected contributions could change if we change our pension or OPEB funding strategy. See Note 15 — Retirement Benefits of the Combined Notes to Consolidated Financial Statements for additional information on pension and OPEB contributions. 74 Table of Contents Cash Requirements for Other Financial Commitments The following table summarizes our future estimated cash payments as of December 31, 2023 under existing financial commitments: 2024 Beyond 2024 Total Time Period Long-term debt $ 121 $ 7,556 $ 7,677 2024 - 2053 Interest payments on long-term debt (a) 403 4,699 5,102 2024 - 2053 Operating leases (b) 54 463 517 2024 - 2056 Purchase power obligations (c) 958 1,164 2,122 2024 - 2033 Fuel purchase agreements (d) 1,464 8,634 10,098 2024 - 2040 Other purchase obligations (e) 1,198 1,121 2,319 2024 - 2049 SNF obligation — 1,296 1,296 2024 - 2035 Pension contributions (f) 161 672 833 2024 - 2029 Total cash requirements $ 4,359 $ 25,605 $ 29,964 __________ (a) Interest payments are estimated based on final maturity dates of debt securities outstanding at December 31, 2023 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, 2023. (b) Capacity payments associated with contracted generation lease agreements are net of sublease and capacity offsets of $47 million and $275 million for 2024 and beyond 2024, respectively and $322 million in total. (c) Purchase power obligations primarily include expected payments for REC purchases and capacity payments associated with contracted generation agreements, which may be reduced based on plant availability. Expected payments exclude payments on renewable generation contracts that are contingent in nature. (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, 2023 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. Qualified pension contributions for years after 2029 are not included. See Note 3 — Regulatory Matters and Note 19 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for additional information of 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 17 — Debt and Credit Agreements Interest payments on long-term debt Note 17 — Debt and Credit Agreements Operating leases Note 11 — Leases SNF obligation Note 19 — Commitments and Contingencies Pension contributions Note 15 — Retirement Benefits Sales of Customer Accounts Receivable We have an accounts receivable financing facility with a number of financial institutions and a commercial paper conduit to sell certain receivables, which expires on August 15, 2025 unless renewed by the mutual consent of the parties in accordance with its terms. See Note 6 — Accounts Receivable 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 75 Table of Contents 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 17 — 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. See Note 17 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information on our credit facilities. Capital Structure At December 31, 2023, our capital structure consisted of the following: Percentage of Capital Structure Commercial paper and notes payable 8 % Long-term debt 37 % Member’s equity 55 % Security Ratings Our access to the capital markets, including the commercial paper market, and our financing costs in those markets, may depend on our securities ratings. 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. As part of the normal course of business, we enter into contracts that contain express provisions or otherwise permit us and our counterparties to demand adequate assurance of future performance when there are reasonable grounds for doing so. In accordance with the contracts and applicable contracts law, if we are downgraded by a credit rating agency, 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, which could include the posting of additional collateral. See Note 16 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information on collateral provisions. At separation, S&P and Moody's affirmed our senior unsecured ratings of BBB- and Baa2, respectively. Fitch also affirmed their final rating of BBB, prior to formally withdrawing coverage on January 5th, 2022. We have only engaged S&P and Moody's for ratings coverage following separation. On October 13, 2022, S&P raised our senior unsecured debt rating to 'BBB' from 'BBB-' citing the passage of the IRA as a material credit positive for us. On November 22, 2023, S&P further raised our senior unsecured debt rating to 'BBB+' from 'BBB' citing the expected benefits from nuclear PTCs. 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 76 Table of Contents exposures. After the separation on February 1, 2022, reporting on risk management issues is to the Executive Committee and the Audit and Risk Committee of the Board of Directors. 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 non-derivative contracts as well as derivative contracts, including swaps, futures, forwards, and options, with approved counterparties to hedge anticipated exposures. We use derivative instruments as economic hedges to mitigate exposure to fluctuations in commodity prices. We expect the settlement of the majority of our economic hedges will occur during 2024 through 2026. 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 nuclear fleet is eligible for the nuclear PTC provided by the IRA, an important tool in managing commodity price risk for each nuclear unit not already receiving state support. The nuclear PTC provides increasing levels of support as unit revenues decline below levels established in the IRA and is further adjusted annually for inflation over the duration of the program. 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. Market price risk exposure is the risk of a change in the value of unhedged positions. The forecasted market price risk exposure is the risk of a change in the value of unhedged positions. The forecasted market price risk exposure for our entire economic hedge portfolio associated with a $5/MWh reduction in the annual average around-the-clock energy price based on December 31, 2023 market conditions and hedged position results in an immaterial impact to net income (loss) for 2024 and 2025, respectively. See Note 16 — 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 assemblies are obtained predominantly through long-term uranium concentrate supply contracts, contracted conversion services, contracted enrichment services, or a combination thereof, including contracts sourced from Russia, and contracted fuel fabrication services. 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 ensure we can secure the nuclear fuel needed to continue to operate our nuclear fleet long-term. Approximately 55% of our uranium concentrate requirements from 2024 through 2028 are supplied by three suppliers. To-date, we have not experienced any counterparty credit risk associated with these suppliers stemming from the Russia and Ukraine conflict. In the event of non-performance by these or other suppliers, we believe that replacement uranium concentrate can be obtained, although at prices that may be unfavorable when compared to the prices under the current supply agreements. Geopolitical developments, including the Russia and Ukraine conflict and United States, United Kingdom, European Union, and Canadian sanctions against Russia, have the potential to impact delivery from multiple suppliers in the international uranium processing industry. Non-performance by these counterparties could have a material adverse impact on our consolidated financial statements. To-date, we have not experienced any delivery or non-performance issues from our suppliers, nor any degradation in the 77 Table of Contents quality of fuel we have received, and we are closely monitoring developments from the conflict. 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. Trading and Non-Trading Marketing Activities The following table provides detail on changes in our commodity mark-to-market net asset or liability balance sheet position from December 31, 2021 to December 31, 2023. It indicates the drivers behind changes in the balance sheet amounts. This table incorporates the mark-to-market activities that are immediately recorded in earnings. This table excludes all NPNS contracts and does not segregate proprietary trading activity. See Note 16 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information on the balance sheet classification of the mark-to-market energy contract net assets (liabilities) recorded as of December 31, 2023 and 2022. 2023 2022 Beginning balance as of January 1 (a) $ 1,046 $ 1,622 Total change in fair value of contracts recorded in result of operations (2,530) (647) Reclassification to realized at settlement of contracts recorded in results of operations 1,561 (380) Changes in allocated collateral 1,502 386 Net option premium paid (received) (26) 177 Option premium amortization (183) (293) Upfront payments and amortizations (b) (249) 167 Foreign currency translation (13) 14 Ending balance as of December 31 (a) $ 1,108 $ 1,046 __________ (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. Fair Values The following table presents maturity and source of fair value for mark-to-market commodity contract net assets (liabilities). See Note 18 — 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 2024 2025 2026 2027 2028 2029 and Beyond Normal Operations, Commodity derivative contracts (a)(b) : Actively quoted prices (Level 1) $ 103 $ 90 $ 46 $ 9 $ (8) $ — $ 240 Prices provided by external sources (Level 2) (276) 186 91 (1) (1) — (1) Prices based on model or other valuation methods (Level 3) 712 133 (9) 9 1 23 869 Total $ 539 $ 409 $ 128 $ 17 $ (8) $ 23 $ 1,108 __________ (a) Mark-to-market gains and losses on other economic hedge and trading derivative contracts that are recorded in the results of operations. (b) Amounts are shown net of collateral paid/(received) from counterparties (and offset against mark-to-market assets and liabilities) of $2,400 million at December 31, 2023. 78 Table of Contents 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 16 — 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 16 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information regarding collateral requirements and Note 19 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for additional information regarding the letters of credit supporting the cash collateral. We transact output through bilateral contracts. The bilateral contracts are subject to credit risk, which relates to the ability of counterparties to meet their contractual payment obligations. Any failure to collect these payments from counterparties could have a material impact on our consolidated financial statements. As market prices rise above or fall below contracted price levels, we are required to post collateral with purchasers; as market prices fall below contracted price levels, counterparties are required to post collateral with us. To post collateral, we depend on access to bank credit facilities, which serve as liquidity sources to fund collateral requirements. See ITEM 7. Liquidity and Capital Resources — Credit Matters and Cash Requirements — Credit Facilities for additional information. RTOs and ISOs We participate in all of the established wholesale spot 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 in markets regulated by FERC. In these areas, power is traded through bilateral agreements between buyers and sellers and on the spot energy markets that are administered by the RTOs or ISOs, as applicable. In areas where there is no spot energy market, electricity is purchased and sold solely through bilateral agreements. For sales into the spot markets 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 on spot energy market transactions be shared by the remaining participants. Non-performance or non-payment by a major member of an RTO/ISO could result in a material adverse impact on our consolidated financial statements. Exchange Traded Transactions We enter into commodity transactions on NYMEX, ICE, NASDAQ, NGX, and the Nodal exchange (each an Exchange and, collectively, Exchanges). The Exchange clearinghouses act as the counterparty to each trade. Transactions on the Exchanges must adhere to comprehensive collateral and margining requirements. As a result, transactions on Exchanges are significantly collateralized and have limited counterparty credit risk. Interest Rate 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. A hypothetical 50 basis point increase in the interest rates associated with unhedged variable-rate debt (excluding Commercial Paper) and fixed-to-floating swaps would not have resulted in a material decrease in our pre-tax income for the year ended December 31, 2023. 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 79 Table of Contents Note 16 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information. Equity Price Risk We maintain trust funds, as required by the NRC, to fund the costs of decommissioning our nuclear plants. Our NDT funds are reflected at fair value in the Consolidated Balance Sheets. The mix of securities in the trust funds is designed to provide returns to be used to fund decommissioning and to compensate us for inflationary increases in decommissioning costs; however, the equity securities in the trust funds are exposed to price fluctuations in equity markets, and the value of fixed-rate, fixed-income securities are exposed to changes in interest rates. We actively monitor the investment performance of the trust funds and periodically review asset allocations in accordance with our NDT fund investment policy. A hypothetical 25 basis points increase in interest rates and 10% decrease in equity prices would have resulted in a $885 million reduction in the fair value of our NDT trust assets as of December 31, 2023. 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. 80 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, 2023. 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, 2023, 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, 2023, has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report which appears herein. February 27, 2024 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, 2023. 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, 2023, Constellation’s internal control over financial reporting was effective. February 27, 2024 81 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, 2023, 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, 2023 and 2022, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2023 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, 2023, 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. 82 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, 2023, the nuclear decommissioning ARO was $13.9 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 27, 2024 We have served as the Company's auditor since 2022. 83 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, 2023 and 2022, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2023 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 audit 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, 2023, the nuclear decommissioning ARO was $13.9 billion. 84 Table of Contents 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 27, 2024 We have served as the Company's auditor since 2001. 85 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) 2023 2022 2021 Operating revenues Operating revenues $ 24,918 $ 24,280 $ 18,461 Operating revenues from affiliates — 160 1,188 Total operating revenues 24,918 24,440 19,649 Operating expenses Purchased power and fuel 16,001 17,457 12,157 Purchased power and fuel from affiliates — 5 6 Operating and maintenance 5,685 4,797 3,934 Operating and maintenance from affiliates — 44 621 Depreciation and amortization 1,096 1,091 3,003 Taxes other than income taxes 553 552 475 Total operating expenses 23,335 23,946 20,196 Gain (loss) on sales of assets and businesses 27 1 201 Operating income (loss) 1,610 495 ( 346 ) Other income and (deductions) Interest expense, net ( 431 ) ( 250 ) ( 282 ) Interest expense to affiliates — ( 1 ) ( 15 ) Other, net 1,268 ( 786 ) 795 Total other income and (deductions) 837 ( 1,037 ) 498 Income (loss) before income taxes 2,447 ( 542 ) 152 Income tax (benefit) expense 859 ( 388 ) 225 Equity in income (losses) of unconsolidated affiliates ( 11 ) ( 13 ) ( 10 ) Net income (loss) 1,577 ( 167 ) ( 83 ) Net income (loss) attributable to noncontrolling interests ( 46 ) ( 7 ) 122 Net income (loss) attributable to common shareholders $ 1,623 $ ( 160 ) $ ( 205 ) Comprehensive income (loss), net of income taxes Net income (loss) $ 1,577 $ ( 167 ) $ ( 83 ) Other comprehensive income (loss), net of income taxes Pension and non-pension postretirement benefit plans: Prior service benefit reclassified to periodic benefit cost ( 4 ) ( 6 ) — Actuarial loss reclassified to periodic cost 25 101 — Pension and non-pension postretirement benefit plans valuation adjustment ( 453 ) 186 — Unrealized gain (loss) on cash flow hedges ( 1 ) ( 1 ) ( 1 ) Unrealized gain (loss) on foreign currency translation 2 ( 3 ) — Other comprehensive income (loss), net of income taxes ( 431 ) 277 ( 1 ) Comprehensive income (loss) $ 1,146 $ 110 $ ( 84 ) Comprehensive income (loss) attributable to noncontrolling interests ( 46 ) ( 7 ) 122 Comprehensive income (loss) attributable to common shareholders $ 1,192 $ 117 $ ( 206 ) Average shares of common stock outstanding: Basic 323 328 — Assumed exercise and/or distributions of stock-based awards 1 1 — Diluted 324 329 — Earnings per average common share Basic $ 5.02 $ ( 0.49 ) $ — Diluted $ 5.01 $ ( 0.49 ) $ — 86 Table of Contents Constellation Energy Corporation and Subsidiary Companies Consolidated Statements of Cash Flows For the Years Ended December 31, (In millions) 2023 2022 2021 Cash flows from operating activities Net income (loss) $ 1,577 $ ( 167 ) $ ( 83 ) 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 2,514 2,427 4,540 Deferred income taxes and amortization of ITC 251 ( 643 ) ( 205 ) Net fair value changes related to derivatives 996 986 ( 568 ) Net realized and unrealized (gains) losses on NDT funds ( 476 ) 794 ( 586 ) Net realized and unrealized (gains) losses on equity investments ( 307 ) 13 160 Other non-cash operating activities 18 248 ( 261 ) Changes in assets and liabilities: Accounts receivable 396 ( 868 ) ( 616 ) Receivables from and payables to affiliates, net — 20 14 Inventories 60 ( 228 ) ( 68 ) Accounts payable and accrued expenses ( 1,330 ) 1,142 346 Option premiums received (paid), net 26 ( 177 ) ( 338 ) Collateral received (posted), net ( 1,491 ) ( 351 ) ( 130 ) Income taxes 325 162 256 Pension and non-pension postretirement benefit contributions ( 54 ) ( 237 ) ( 259 ) Other assets and liabilities ( 7,806 ) ( 5,474 ) ( 3,540 ) Net cash flows provided by (used in) operating activities ( 5,301 ) ( 2,353 ) ( 1,338 ) Cash flows from investing activities Capital expenditures ( 2,422 ) ( 1,689 ) ( 1,329 ) Proceeds from NDT fund sales 5,822 4,050 6,532 Investment in NDT funds ( 6,050 ) ( 4,271 ) ( 6,673 ) Collection of DPP, net 7,340 4,964 3,902 Proceeds from sales of assets and businesses 24 52 878 Acquisitions of assets and businesses ( 1,690 ) ( 29 ) ( 30 ) Other investing activities 7 27 2 Net cash flows provided by (used in) investing activities 3,031 3,104 3,282 Cash flows from financing activities Change in short-term borrowings 146 257 362 Proceeds from short-term borrowings with maturities greater than 90 days 539 — 880 Repayments of short-term borrowings with maturities greater than 90 days ( 200 ) ( 1,180 ) — Issuance of long-term debt 3,195 14 152 Retirement of long-term debt ( 168 ) ( 1,162 ) ( 105 ) Retirement of long-term debt to affiliate — ( 258 ) — Change in money pool with Exelon — — ( 285 ) Acquisition of CENG noncontrolling interest — — ( 885 ) Distributions to Exelon — — ( 1,832 ) Contributions from Exelon — 1,750 64 Dividends paid on common stock ( 366 ) ( 185 ) — Repurchases of common stock ( 992 ) — — Other financing activities 42 ( 35 ) ( 46 ) Net cash flows provided by (used in) financing activities 2,196 ( 799 ) ( 1,695 ) Increase (decrease) in cash, restricted cash, and cash equivalents ( 74 ) ( 48 ) 249 Cash, restricted cash, and cash equivalents at beginning of period 528 576 327 Cash, restricted cash, and cash equivalents at end of period $ 454 $ 528 $ 576 Supplemental cash flow information Increase (decrease) in capital expenditures not paid $ 16 $ ( 23 ) $ 96 Increase (decrease) in DPP 8,097 5,166 3,652 Increase (decrease) in PP&E related to ARO update 501 343 618 See the Combined Notes to Consolidated Financial Statements 87 Table of Contents Constellation Energy Corporation and Subsidiary Companies Consolidated Balance Sheets December 31, (In millions) 2023 2022 ASSETS Current assets Cash and cash equivalents $ 368 $ 422 Restricted cash and cash equivalents 86 106 Accounts receivable Customer accounts receivable (net of allowance for credit losses of $ 56 and $ 46 as of December 31, 2023 and 2022, respectively) 1,934 2,585 Other accounts receivable (net of allowance for credit losses of $ 5 as of December 31, 2023 and 2022) 917 731 Mark-to-market derivative assets 1,179 2,368 Inventories, net Natural gas, oil, and emission allowances 284 429 Materials and supplies 1,216 1,076 Renewable energy credits 660 617 Other 1,655 1,026 Total current assets 8,299 9,360 Property, plant, and equipment (net of accumulated depreciation and amortization of $ 17,423 and $ 16,726 as of December 31, 2023 and 2022, respectively) 22,116 19,822 Deferred debits and other assets Nuclear decommissioning trust funds 16,398 14,114 Investments 563 202 Goodwill 425 47 Mark-to-market derivative assets 995 1,261 Deferred income taxes 52 44 Other 1,910 2,059 Total deferred debits and other assets 20,343 17,727 Total assets (a) $ 50,758 $ 46,909 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) 2023 2022 LIABILITIES AND EQUITY Current liabilities Short-term borrowings $ 1,644 $ 1,159 Long-term debt due within one year 121 143 Accounts payable and accrued expenses 2,612 3,734 Mark-to-market derivative liabilities 632 1,558 Renewable energy credit obligation 972 901 Other 338 344 Total current liabilities 6,319 7,839 Long-term debt 7,496 4,466 Deferred credits and other liabilities Deferred income taxes and unamortized ITCs 3,209 3,031 Asset retirement obligations 14,118 12,699 Pension obligations 1,070 605 Non-pension postretirement benefit obligations 732 609 Spent nuclear fuel obligation 1,296 1,230 Payables related to Regulatory Agreement Units 3,688 2,897 Mark-to-market derivative liabilities 419 983 Other 1,125 1,178 Total deferred credits and other liabilities 25,657 23,232 Total liabilities (a) 39,472 35,537 Commitments and contingencies (Note 19) Shareholders' equity Common stock ( No par value, 1,000 shares authorized, 317 shares and 327 shares outstanding as of December 31, 2023 and 2022, respectively) 12,355 13,274 Retained earnings (deficit) 761 ( 496 ) Accumulated other comprehensive income (loss), net ( 2,191 ) ( 1,760 ) Total shareholders' equity 10,925 11,018 Noncontrolling interests 361 354 Total equity 11,286 11,372 Total liabilities and shareholders' equity $ 50,758 $ 46,909 __________ (a) Our consolidated assets include $ 3,355 million and $ 2,641 million at December 31, 2023 and 2022, respectively, of certain VIEs that can only be used to settle the liabilities of the VIE. Our consolidated liabilities include $ 990 million and $ 1,041 million at December 31, 2023 and 2022, respectively, of certain VIEs for which the VIE creditors do not have recourse to us. See Note 22–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 Shareholder's Equity Noncontrolling Interests Predecessor Member's Equity (a) Total Equity (In millions, shares in thousands) Issued Shares Common Stock Retained Earnings (Deficit) Accumulated Other Comprehensive Income (Loss), net Balance, December 31, 2020 — $ — $ — $ ( 30 ) $ 2,277 $ 12,429 $ 14,676 Net income (loss) — — — — 122 ( 205 ) ( 83 ) Changes in equity of noncontrolling interest — — — — ( 37 ) — ( 37 ) Acquisition of CENG noncontrolling Interest — — — — ( 1,965 ) 1,080 ( 885 ) Deferred tax adjustment related to acquisition of CENG noncontrolling interest — — — — — ( 288 ) ( 288 ) Distribution to member — — — — — ( 1,832 ) ( 1,832 ) Contributions from member — — — — — 64 64 Acquisition of noncontrolling interest — — — — ( 2 ) 2 — Other comprehensive income (loss), net of income taxes — — — ( 1 ) — — ( 1 ) Balance, December 31, 2021 — $ — $ — $ ( 31 ) $ 395 $ 11,250 $ 11,614 Net income from January 1, 2022 to January 31, 2022 — — — — — 151 151 Separation-related adjustments — — — ( 2,006 ) 7 1,802 ( 197 ) Changes in equity of noncontrolling interests from January 1, 2022 to January 31, 2022 — — — — ( 7 ) — ( 7 ) Consummation of separation 326,664 13,203 — — — ( 13,203 ) — Net loss from February 1, 2022 to December 31, 2022 — — ( 311 ) — ( 7 ) — ( 318 ) Employee incentive plans 466 71 — — — — 71 Changes in equity of noncontrolling interest — — — — ( 34 ) — ( 34 ) Common stock dividends ( 0.1410 /common share) — — ( 185 ) — — — ( 185 ) Other comprehensive income (loss) , net of income taxes — — — 277 — — 277 Balance, December 31, 2022 327,130 $ 13,274 $ ( 496 ) $ ( 1,760 ) $ 354 $ — $ 11,372 Net income (loss) — — 1,623 — ( 46 ) — 1,577 Employee incentive plans 902 81 — — — — 81 Changes in equity of noncontrolling interest — — — — 53 — 53 Common stock dividends ($ 0.2820 /common share) — — ( 366 ) — — — ( 366 ) Common stock repurchased ( 10,560 ) ( 1,000 ) — — — — ( 1,000 ) Other comprehensive income (loss) , net of income taxes — — — ( 431 ) — — ( 431 ) Balance, December 31, 2023 317,472 $ 12,355 $ 761 $ ( 2,191 ) $ 361 $ — $ 11,286 __________ (a) Represents Constellation’s predecessor member's equity prior to the separation transaction. Upon completion of the separation, the predecessor member's equity was transferred to CEG Parent’s Common stock. See Note 1 — Basis of Presentation for additional information on the separation. See the Combined Notes to Consolidated Financial Statements 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) 2023 2022 2021 Operating revenues Operating revenues $ 24,918 $ 24,280 $ 18,461 Operating revenues from affiliates — 160 1,188 Total operating revenues 24,918 24,440 19,649 Operating expenses Purchased power and fuel 16,001 17,457 12,157 Purchased power and fuel from affiliates — 5 6 Operating and maintenance 5,685 4,797 3,934 Operating and maintenance from affiliates — 44 621 Depreciation and amortization 1,096 1,091 3,003 Taxes other than income taxes 553 552 475 Total operating expenses 23,335 23,946 20,196 Gain (loss) on sales of assets and businesses 27 1 201 Operating income (loss) 1,610 495 ( 346 ) Other income and (deductions) Interest expense, net ( 431 ) ( 250 ) ( 282 ) Interest expense to affiliates — ( 1 ) ( 15 ) Other, net 1,268 ( 786 ) 795 Total other income and (deductions) 837 ( 1,037 ) 498 Income (loss) before income taxes 2,447 ( 542 ) 152 Income tax (benefit) expense 859 ( 388 ) 225 Equity in income (losses) of unconsolidated affiliates ( 11 ) ( 13 ) ( 10 ) Net income (loss) 1,577 ( 167 ) ( 83 ) Net income (loss) attributable to noncontrolling interests ( 46 ) ( 7 ) 122 Net income (loss) attributable to membership interest $ 1,623 $ ( 160 ) $ ( 205 ) Comprehensive income (loss), net of income taxes Net income (loss) $ 1,577 $ ( 167 ) $ ( 83 ) Other comprehensive income (loss), net of income taxes Pension and non-pension postretirement benefit plans: Prior service benefit reclassified to periodic benefit cost ( 4 ) ( 6 ) — Actuarial loss reclassified to periodic benefit cost 25 101 — Pension and non-pension postretirement benefit plans valuation adjustment ( 453 ) 186 — Unrealized gain (loss) on cash flow hedges ( 1 ) ( 1 ) ( 1 ) Unrealized gain (loss) on foreign currency translation 2 ( 3 ) — Other comprehensive income (loss), net of income taxes ( 431 ) 277 ( 1 ) Comprehensive income (loss) 1,146 110 ( 84 ) Comprehensive income (loss) attributable to noncontrolling interests ( 46 ) ( 7 ) 122 Comprehensive income (loss) attributable to membership interest $ 1,192 $ 117 $ ( 206 ) 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) 2023 2022 2021 Cash flows from operating activities Net income (loss) $ 1,577 $ ( 167 ) $ ( 83 ) 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 2,514 2,427 4,540 Deferred income taxes and amortization of ITCs 251 ( 643 ) ( 205 ) Net fair value changes related to derivatives 996 986 ( 568 ) Net realized and unrealized (gains) losses on NDT funds ( 476 ) 794 ( 586 ) Net realized and unrealized (gains) losses on equity investments ( 307 ) 13 160 Other non-cash operating activities ( 44 ) 199 ( 261 ) Changes in assets and liabilities: Accounts receivable 389 ( 855 ) ( 616 ) Receivables from and payables to affiliates, net 73 65 14 Inventories 60 ( 228 ) ( 68 ) Accounts payable and accrued expenses ( 1,330 ) 1,112 346 Option premiums received (paid), net 26 ( 177 ) ( 338 ) Collateral received (posted), net ( 1,491 ) ( 351 ) ( 130 ) Income taxes 325 162 256 Pension and non-pension postretirement benefit contributions ( 54 ) ( 237 ) ( 259 ) Other assets and liabilities ( 7,897 ) ( 5,540 ) ( 3,540 ) Net cash flows provided by (used in) operating activities ( 5,388 ) ( 2,440 ) ( 1,338 ) Cash flows from investing activities Capital expenditures ( 2,422 ) ( 1,689 ) ( 1,329 ) Proceeds from NDT fund sales 5,822 4,050 6,532 Investment in NDT funds ( 6,050 ) ( 4,271 ) ( 6,673 ) Collection of DPP, net 7,340 4,964 3,902 Proceeds from sales of assets and businesses 24 52 878 Acquisitions of assets and businesses ( 1,690 ) ( 29 ) ( 30 ) Other investing activities 7 27 2 Net cash flows provided by (used in) investing activities 3,031 3,104 3,282 Cash flows from financing activities Change in short-term borrowings 146 257 362 Proceeds from short-term borrowings with maturities greater than 90 days 539 — 880 Repayments of short-term borrowings with maturities greater than 90 days ( 200 ) ( 1,180 ) — Issuance of long-term debt 3,195 14 152 Retirement of long-term debt ( 168 ) ( 1,162 ) ( 105 ) Retirement of long-term debt to affiliate — ( 258 ) — Change in money pool with Exelon — — ( 285 ) Acquisition of CENG noncontrolling interest — — ( 885 ) Distributions to Exelon — — ( 1,832 ) Distributions to member ( 1,239 ) ( 185 ) — Contributions from Exelon — 1,750 64 Contributions from member — 82 — Other financing activities 23 ( 57 ) ( 46 ) Net cash flows provided by (used in) financing activities 2,296 ( 739 ) ( 1,695 ) Increase (decrease) in cash, restricted cash, and cash equivalents ( 61 ) ( 75 ) 249 Cash, restricted cash, and cash equivalents at beginning of period 501 576 327 Cash, restricted cash, and cash equivalents at end of period $ 440 $ 501 $ 576 Supplemental cash flow information Increase (decrease) in capital expenditures not paid $ 16 $ ( 23 ) $ 96 Increase (decrease) in DPP 8,097 5,166 3,652 Increase (decrease) in PP&E related to ARO update 501 343 618 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) 2023 2022 ASSETS Current assets Cash and cash equivalents $ 366 403 Restricted cash and cash equivalents 74 98 Accounts receivable Customer accounts receivable (net of allowance for credit losses of $ 56 and $ 46 as of December 31, 2023 and 2022, respectively) 1,934 2,585 Other accounts receivable (net of allowance for credit losses of $ 5 as of December 31, 2023 and 2022) 911 718 Mark-to-market derivative assets 1,179 2,368 Inventories, net Natural gas, oil, and emission allowance 284 429 Materials and supplies 1,216 1,076 Renewable energy credits 660 617 Other 1,655 1,026 Total current assets 8,279 9,320 Property, plant, and equipment (net of accumulated depreciation and amortization of $ 17,423 and $ 16,726 as of December 31, 2023 and 2022, respectively) 22,116 19,822 Deferred debits and other assets Nuclear decommissioning trust funds 16,398 14,114 Investments 563 202 Goodwill 425 47 Mark-to-market derivative assets 995 1,261 Deferred income taxes 52 44 Other 1,910 2,059 Total deferred debits and other assets 20,343 17,727 Total assets (a) $ 50,738 $ 46,869 See the Combined Notes to Consolidated Financial Statements 93 Table of Contents Constellation Energy Generation, LLC and Subsidiary Companies Consolidated Balance Sheets December 31, (In millions) 2023 2022 LIABILITIES AND EQUITY Current liabilities Short-term borrowings $ 1,644 $ 1,159 Long-term debt due within one year 121 143 Accounts payable and accrued expenses 2,486 3,679 Payables to affiliates 118 45 Mark-to-market derivative liabilities 632 1,558 Renewable energy credit obligation 972 901 Other 338 344 Total current liabilities 6,311 7,829 Long-term debt 7,496 4,466 Deferred credits and other liabilities Deferred income taxes and unamortized ITCs 3,209 3,031 Asset retirement obligations 14,118 12,699 Pension obligations 1,070 605 Non-pension postretirement benefit obligations 732 609 Spent nuclear fuel obligation 1,296 1,230 Payables related to Regulatory Agreement Units 3,688 2,897 Mark-to-market derivative liabilities 419 983 Other 1,025 1,106 Total deferred credits and other liabilities 25,557 23,160 Total liabilities (a) 39,364 35,455 Commitments and contingencies (Note 19) Equity Member’s equity Membership interest 11,537 12,408 Undistributed earnings 1,667 412 Accumulated other comprehensive income (loss), net ( 2,191 ) ( 1,760 ) Total member’s equity 11,013 11,060 Noncontrolling interests 361 354 Total equity 11,374 11,414 Total liabilities and equity $ 50,738 $ 46,869 __________ (a) Our consolidated assets include $ 3,355 million and $ 2,641 million as of December 31, 2023 and 2022, respectively, of certain VIEs that can only be used to settle the liabilities of the VIE. Our consolidated liabilities include $ 990 million and $ 1,041 million as of December 31, 2023 and 2022, respectively, of certain VIEs for which the VIE creditors do not have recourse to us. See Note 22–Variable Interest Entities for additional information. See the Combined Notes to Consolidated Financial Statements 94 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 Accumulated Other Comprehensive Income (Loss), net Balance, December 31, 2020 $ 9,624 $ 2,805 $ ( 30 ) $ 2,277 $ 14,676 Net (loss) income — ( 205 ) — 122 ( 83 ) Changes in equity of noncontrolling interests — — — ( 37 ) ( 37 ) Acquisition of CENG noncontrolling Interest 1,080 — — ( 1,965 ) ( 885 ) Deferred tax adjustment related to acquisition of CENG noncontrolling interest ( 288 ) — — — ( 288 ) Distribution to member — ( 1,832 ) — — ( 1,832 ) Contribution from member 64 — — — 64 Acquisition of noncontrolling interest 2 — — ( 2 ) — Other comprehensive income (loss), net of income taxes — — ( 1 ) — ( 1 ) Balance, December 31, 2021 $ 10,482 $ 768 $ ( 31 ) $ 395 $ 11,614 Net (loss) income — ( 160 ) — ( 7 ) ( 167 ) Separation-related adjustments 1,844 ( 11 ) ( 2,006 ) 7 ( 166 ) Changes in equity of noncontrolling interests — — — ( 41 ) ( 41 ) Distribution to member — ( 185 ) — — ( 185 ) Contribution from member 82 — — — 82 Other comprehensive income (loss), net of income taxes — — 277 — 277 Balance, December 31, 2022 $ 12,408 $ 412 $ ( 1,760 ) $ 354 $ 11,414 Net income (loss) — 1,623 — ( 46 ) 1,577 Changes in equity of noncontrolling interest — — — 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 See the Combined Notes to Consolidated Financial Statements 95 Table of Contents Combined Notes to Consolidated Financial Statements (Dollars in millions, unless otherwise noted) 1. Basis of Presentation Description of Business We are a producer of carbon-free energy and a supplier of energy products and services. Our generating capacity includes primarily nuclear, wind, solar, natural gas and hydroelectric assets. Through our integrated business operations, we sell electricity, natural gas, and other energy-related products and sustainable solutions to various types of customers, including distribution utilities, municipalities, cooperatives, and commercial, industrial, governmental, 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 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 Energy Generation, LLC ( “ Constellation ” , formerly Exelon Generation Company, LLC) and its subsidiaries, into an independent, publicly-traded company. CEG Parent, a direct, wholly owned subsidiary of Exelon, was newly formed for the purpose of separation and had not engaged in any business activities nor had any assets or liabilities prior to the separation. On February 1, 2022, the separation was completed and CEG Parent holds all the interests in Constellation previously held by Exelon. As an individual registrant, Constellation has historically filed consolidated financial statements 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 eliminated. CEG Parent's prior period financial statements have been adjusted to reflect the balances of Constellation in accordance with applicable guidance. Amounts disclosed relate to CEG Parent and Constellation unless specifically noted as relating to CEG Parent only. Unless otherwise indicated or the context otherwise requires, references herein to the terms “we,” “us,” and “our” refer collectively to CEG Parent and Constellation. We own 100% of our significant consolidated subsidiaries, either directly or indirectly, except for certain consolidated VIEs, including CRP, of which we hold a 51 % interest. The remaining interests in the consolidated VIEs are included in noncontrolling interests on the Consolidated Balance Sheets. See Note 22 — 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 apply proportionate consolidation when we have an undivided interest in an asset and are proportionately liable for our share of each liability associated with the asset. 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 Plant for additional information on application of proportionate consolidation. We apply equity method accounting when we have a significant influence over an investee through an ownership in equity, which generally approximates a 20% to 50% voting interest. We apply equity method accounting to certain investments and joint ventures. Under equity method accounting, we report our interest in the entity as an investment and our percentage share of the earnings from the entity as single line items in our consolidated financial statements. We use accounting for investments in equity securities with or without readily determinable fair values if we lack a significant influence, which generally results when we hold less than 20% of the common stock of an entity. Under accounting for investments in equity securities with readily determinable fair values, the investments are reported based on quoted prices in active markets and realized and unrealized gains and losses are included in earnings. Under accounting for investments in equity securities without readily determinable fair values, the investments are reported at cost adjusted for changes 96 Table of Contents Combined Notes to Consolidated Financial Statements (Dollars in millions, unless otherwise noted) Note 1 — Basis of Presentation from observable transactions for identical or similar investments of the same issuer, less impairment, and changes in measurement are reported in earnings. Separation from Exelon On February 1, 2022, Exelon completed the separation through a pro-rata distribution of all of the outstanding shares of our common stock, no par value, on the basis of one such share for every three shares of Exelon common stock held on January 20, 2022, the record date of the distribution. We are an independent, publicly traded company listed on the Nasdaq Stock Market under the symbol “CEG”, and regular-way trading began on February 2, 2022. Exelon no longer retains any ownership interest in CEG Parent or Constellation. Prior to completion of the separation, our financial statements include certain transactions with affiliates of Exelon, which are disclosed as related party transactions. After February 1, 2022, all transactions with Exelon or its affiliates are no longer related party transactions. In order to govern the ongoing relationships with Exelon after the separation, and to facilitate an orderly transition, we entered into several agreements with Exelon, including the following: • Separation Agreement – sets forth the principal actions to be taken in connection with the separation, including the transfer of assets and assumption of liabilities and establishes certain rights and obligations between us following the distribution • Transition Services Agreement (TSA) – governs all matters relating to the provision of services between us and Exelon on a transitional basis, in addition to providing us with certain services for an expected period of two-years, provided that certain services may be longer than the term and services may be extended with approval from both parties; the services include support for information technology, accounting, finance, human resources, security, and various other administrative and operational services • Employee Matters Agreement (EMA) – addresses certain employment, compensation and benefits matters, including the allocation of employees between us and Exelon and the allocation and treatment of certain assets and liabilities relating to our employees and former employees • Tax Matters Agreement (TMA) - governs the respective rights, responsibilities, and obligations between us and Exelon with respect to all tax matters (excluding employee-related taxes covered under EMA), in addition to certain restrictions which generally prohibit us from taking or failing to take any action in the two-year period following the distribution that would prevent the distribution from qualifying as tax-free for U.S. federal income tax purposes, including limitations on our ability to pursue certain equity issuances, strategic transactions, repurchases or other transactions Pursuant to the Separation Agreement, we received a cash contribution of $ 1.75 billion from Exelon on January 31, 2022, the proceeds of which were used to settle $ 258 million of an intercompany loan from Exelon and $ 200 million of short-term debt outstanding prior to separation, in addition to a $ 192 million contribution to our pension plans. We also entered into two new five-year credit facility agreements providing $ 4.5 billion of capacity. See Note 17 — Debt and Credit Agreements for additional information on these facility agreements. The amounts Exelon billed us for services pursuant to the TSA were $ 151 million and $ 266 million for the years ended December 31, 2023 and 2022, respectively. The amounts we billed Exelon for services pursuant to the TSA were $ 14 million and $ 43 million for the years ended December 31, 2023 and 2022, respectively. Use of Estimates The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the amounts reported in the financial statements and accompanying notes. Areas in which significant estimates have been made include, but are not limited to, the accounting for nuclear decommissioning costs and other AROs, pension and OPEB plans, inventory reserves, allowance for credit losses, long-lived asset valuations and impairment assessments, derivative instruments, goodwill, unamortized energy contracts, fixed asset depreciation, environmental costs and other loss contingencies, taxes and unbilled energy revenues. Actual results could differ from those estimates. 97 Table of Contents Combined Notes to Consolidated Financial Statements (Dollars in millions, unless otherwise noted) Note 1 — Basis of Presentation 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 16 — 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 services. Some of these taxes are imposed on the customer, but paid by us, while others are imposed on us. Where these taxes are imposed on the customer, such as sales taxes, they are reported on a net basis in revenues. However, where these taxes are imposed on us, such as gross receipts taxes, they are reported on a gross basis in expense. Accordingly, revenues are recognized for the taxes collected from customers along with an offsetting expense in Taxes other than income taxes in the Consolidated Statements of Operations and Comprehensive Income. Se e Note 23 — Supplemental Financial Information for the taxes that are presented on a gross basis. Leases We recognize a ROU asset and lease liability for operating leases with a term of greater than one year. Operating lease ROU assets are included in Other deferred debits and other assets and operating lease liabilities are included in Other current liabilities and Other deferred credits and other liabilities on the Consolidated Balance Sheets. The ROU asset is measured as the sum of (1) the present value of all remaining fixed and in-substance fixed payments using the rate implicit in the lease whenever that is readily determinable or our incremental borrowing rate, (2) any lease payments made at or before the commencement date (less any lease incentives received) and (3) any initial direct costs incurred. The lease liability is measured the same as the ROU asset, but excludes any payments made before the commencement date and initial direct costs incurred. Lease terms include options to extend or terminate the lease if it is reasonably certain they will be exercised. We include non-lease components for most asset classes, which are service-related costs that are not integral to the use of the asset, in the measurement of the ROU asset and lease liability. Expense for operating leases and leases with a term of one year or less is recognized on a straight-line basis over the term of the lease, unless another systematic and rational basis is more representative of the derivation of benefit from use of the leased property. Variable lease payments are recognized in the period in which the related obligation is incurred and consist primarily of payments for purchases of electricity under contracted generation that are based on the electricity produced by those generating assets. Operating lease expense and variable lease payments are recorded to Purchased power and fuel expense for contracted generation or Operating and maintenance expense for all other lease agreements in the Consolidated Statements of Operations and Comprehensive Income. Income from operating leases, including subleases, is recognized on a straight-line basis over the term of the lease, unless another systematic and rational basis is more representative of the pattern in which income is earned over the term of the lease. Variable lease payments are recognized in the period in which the related obligation is performed and consist primarily of payments received from sales of electricity under contracted generation that are based on the electricity produced by those generating assets. Operating lease income and variable lease payments are recorded to Operating revenues in the Consolidated Statements of Operations and Comprehensive Income. Our operating leases consist primarily of contracted generation, real estate including office buildings, and vehicles and equipment. We generally account for contracted generation in which the generating asset is not renewable as a lease if the customer has dispatch rights and obtains substantially all the economic benefits. We 98 Table of Contents Combined Notes to Consolidated Financial Statements (Dollars in millions, unless otherwise noted) Note 1 — Basis of Presentation 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, 2023 and 2022, 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 17 — Debt and Credit Agreements and Note 23 — Supplemental Financial Information for additional information. Allowance for Credit Losses on Accounts Receivables The allowance for credit losses reflects our best estimate of losses on the customers' accounts receivable balances based on historical experience, current information, and reasonable and supportable forecasts. The allowance for credit losses for our retail customers is based on accounts receivable aging historical experience coupled with specific identification through a credit monitoring process, which considers current conditions and forward-looking information such as industry trends, macroeconomic factors, changes in the regulatory environment, external credit ratings, publicly available news, payment status, payment history, and the exercise of collateral calls. The allowance for credit losses for our wholesale customers is developed using a credit monitoring process, like that used for retail customers. When a wholesale customer’s risk characteristics are no longer aligned with the pooled population, we use specific identification to develop an allowance for credit losses. Adjustments to the allowance for credit losses are recorded in Operating and maintenance expense in the Consolidated Statements of Operations and Comprehensive Income. We have certain non-customer receivables in Current Assets and Other deferred debits and other assets which primarily are with governmental agencies. As such, 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 99 Table of Contents Combined Notes to Consolidated Financial Statements (Dollars in millions, unless otherwise noted) Note 1 — Basis of Presentation • 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 22 — Variable Interest Entities for additional information. Inventories Inventory is recorded at the lower of weighted average cost or net realizable value. Provisions are recorded for excess and obsolete inventory. Natural gas, oil, materials and supplies, and emissions allowances are generally included in inventory when purchased. Natural gas, oil, and emissions allowances are expensed to Purchased power and fuel expense when consumed. Materials and supplies generally include items utilized within our generating plants 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 measurement alternative to measure these investments, defined as cost adjusted for changes from observable transactions for identical or similar investments of the same issuer, less impairment. Our NDT funds are classified as current or noncurrent assets, depending on the timing of the decommissioning activities and income taxes on trust earnings. See Note 18 — Fair Value of Financial Assets and Liabilities and Note 10 — Asset Retirement Obligations for additional information. Equity Security Investments with Readily Determinable Fair Values. We have certain equity securities with readily determinable fair values. Realized and unrealized gains and losses are included in Other, net in the Consolidated Statements of Operations and Comprehensive Income. See Note 18 — Fair Value of Financial Assets and Liabilities for additional information. Equity Security Investments without Readily Determinable Fair Values. We have certain equity securities without readily determinable fair values. We have elected to use the measurement alternative to measure these investments, defined as cost adjusted for changes from observable transactions for identical or similar investments of the same issuer, less impairment. Changes in measurement are reported in Other, net in the Consolidated Statements of Operations and Comprehensive Income. See Note 18 — Fair Value of Financial Assets for additional information. Property, Plant and Equipment Property, plant and equipment is recorded at acquired cost. Acquired cost includes construction-related direct labor and material costs. When appropriate, acquired cost also includes capitalized interest. Costs associated with nuclear outages and planned major maintenance activities, are expensed to Operating and maintenance expense or capitalized to Property, plant, and equipment based on the nature of the activities in the period incurred. The cost of repairs and maintenance and minor replacements of property is charged to Operating and maintenance expense 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. 100 Table of Contents Combined Notes to Consolidated Financial Statements (Dollars in millions, unless otherwise noted) Note 1 — Basis of Presentation 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 Plant and Note 23 — 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 19 — 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 service 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 service 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 7 — Early Plant Retirements for additional information on the impacts of early plant retirements, Note 8 — Property, Plant, and Equipment for additional information regarding depreciation, and Note 23 — Supplemental Financial Information for additional information regarding nuclear fuel. Asset Retirement Obligations We estimate and recognize a liability for our legal obligation to perform asset retirement activities even though the timing and/or methods of settlement may be conditional on future events. We generally update our nuclear decommissioning ARO annually, unless circumstances warrant more frequent updates, based on our annual evaluation of cost escalation factors and probabilities assigned to the multiple outcome scenarios within our probability-weighted discounted cash flow models. Our multiple outcome scenarios are generally based on decommissioning cost studies which are updated, on a rotational basis, for each of our nuclear units at least every five years, unless circumstances warrant more frequent updates. AROs are accreted throughout each year to reflect the time value of money for these present value obligations through a charge to Operating and maintenance expense in the Consolidated Statements of Operations and Comprehensive Income for Non-Regulatory Agreement Units and through an offsetting decrease in noncurrent payables related to Regulatory Agreement Units. See Note 10 — Asset Retirement Obligations for additional information. Accounting Implications of the Regulatory Agreement Units Based on the requirements of the ICC, PAPUC, and PUCT that dictate our obligations related to the shortfall or excess of NDT funds necessary for decommissioning the former ComEd, former PECO, and STP units, decommissioning-related activities net of applicable taxes, including realized and unrealized gains and losses on the NDT funds, depreciation of the ARC, and accretion of the decommissioning obligation are generally offset in the Consolidated Statements of Operations and Comprehensive Income and are recorded as noncurrent payables in the Consolidated Balance Sheets (within Payables related to Regulatory Agreement Units). See Note 10 — Asset Retirement Obligations for additional information. 101 Table of Contents Combined Notes to Consolidated Financial Statements (Dollars in millions, unless otherwise noted) Note 1 — Basis of Presentation 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. Generally, pre-tax impairment losses are recorded in Operating and maintenance expense in the Consolidated Statements of Operations and Comprehensive Income. See Note 12 — Asset Impairments for additional information. 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 in 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 13 — 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 their 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 (losses) earnings of unconsolidated affiliates in the Consolidated Statements of Operations and Comprehensive Income. Equity Security Investments. Equity investments with readily determinable fair values are measured and recorded at fair value with any changes in fair value recorded in Other, net in the Consolidated Statements of Operations and Comprehensive Income. 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 to the amount by which the security’s carrying amount exceeds its fair value. Derivative Financial Instruments All derivatives are recognized on the balance sheet at their fair value unless they qualify for certain exceptions, including NPNS. For derivatives intended to serve as economic hedges, changes in fair value are recognized in earnings each period. Amounts classified in earnings are included in Operating revenues, Purchased power and fuel, or Interest expense in the Consolidated Statements of Operations and Comprehensive Income based on the activity the transaction is economically hedging. While most of the derivatives serve as economic hedges, there are also derivatives entered into for proprietary trading purposes, subject to our RMP, and changes in the fair value of those derivatives are recorded in Operating revenues in the Consolidated Statements of Operations and Comprehensive Income. Cash inflows and outflows related to derivative instruments are included as a component of operating, investing, or financing cash flows in the Consolidated Statements of Cash Flows, depending on the nature of each transaction. As part of the energy marketing business, we enter 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 16 — Derivative Financial Instruments for additional information. 102 Table of Contents Combined Notes to Consolidated Financial Statements (Dollars in millions, unless otherwise noted) Note 1 — Basis of Presentation Retirement Benefits Prior to separation, Exelon sponsored defined benefit pension plans and OPEB plans as described in Note 15 — Retirement Benefits. The plan obligations and costs of providing benefits under these plans were measured as of December 31, 2021. We accounted for our participation in Exelon’s pension and OPEB plans by applying multi-employer accounting. Exelon allocated costs related to its pension and OPEB plans to its subsidiaries based on both active and retired employee participation in each plan. We included the service cost and non-service cost components in Operating and maintenance expense and Property, plant, and equipment, net in the consolidated financial statements. Effective upon separation, we sponsor defined benefit pension and OPEB plans as described in Note 15 — Retirement Benefits. The plan obligations and costs of providing benefits under these plans were measured upon separation as of February 1, 2022 and remeasured as of December 31, 2023 and 2022. The measurements involved various factors, assumptions, and accounting elections. The impact of assumption changes or experience different from that assumed on pension and OPEB obligations is recognized over time rather than immediately recognized in the Consolidated Statements of Operations and Comprehensive Income. Gains or losses more than the greater of ten percent of the PBO or the MRV of plan assets are amortized over the expected average remaining service period of plan participants. Gains or losses more than the greater of ten percent of the APBO or the MRV of plan assets are amortized over the average future remaining lifetime of the current inactive population for the OPEB plans. We report the pension and OPEB service cost and non-service cost (credit) components of net periodic benefit costs (credits) for all plans separately in our Consolidated Statements of Operations and Comprehensive Income. Effective February 1, 2022 , the service cost component continues to be included in Operating and maintenance expense and Property, plant, and equipment, net (where criteria for capitalization of direct labor has been met) while the non-service cost (credit) components are included in Other, net, in accordance with single employer plan accounting. Renewable Energy Credits RECs are included in Renewable energy credits in the Consolidated Balance Sheets. Purchased RECs are recorded at cost on the date they are purchased and internally generated RECs are recognized at a zero-cost basis when generated. The cost of RECs purchased on a stand-alone basis is based on the transaction price, while the cost of RECs acquired through PPAs represents the difference between the total contract price and the market price of energy at contract inception. Generally, revenue for RECs that are sold to a counterparty under a contract that specifically identifies a power plant are recognized at a point in time when the power is produced. This includes both bundled and unbundled REC sales. Otherwise, the revenue is recognized upon physical transfer of the REC to the customer. 2. Mergers, Acquisitions, and Dispositions Acquisition of Joint Ownership in South Texas Project On November 1, 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 net cash paid was $ 1.65 billion, after certain purchase price adjustments. The current renewed NRC licenses for the STP units expire in 2047 and 2048, and the NRC licensed operator is STP Nuclear Operating Company (STPNOC), acting on behalf of the joint owners. Other owners include City Public Service Board of San Antonio (CPS, 40 %) and the City of Austin, Texas (Austin Energy, 16 %). This acquisition is complementary to and aligned strategically with our existing clean energy business operations. As part of the transaction, we acquired ownership of two decommissioning trust funds established to provide funding for decontamination and decommissioning of STP. The trust funds have been funded with amounts collected from predecessor utilities. We maintain the ability to collect additional funds from utility customers in the event of a shortfall and are required to return any excess funds to utility customers upon completion of decommissioning. As such, our accounting for the future decommissioning of our interest in STP will mirror that of our existing Regulatory Agreement Units. See Note 1 — Basis of Presentation and Note 10 — Asset Retirement Obligations for additional information on our accounting policy for Regulatory Agreement Units. 103 Table of Contents Combined Notes to Consolidated Financial Statements (Dollars in millions, unless otherwise noted) Note 2 — Mergers, Acquisitions, and Dispositions The acquisition was accounted for using the acquisition method of accounting in accordance with authoritative guidance, which requires, among other things, the assets acquired and liabilities assumed to be recognized at their respective fair value as of the acquisition date. The excess of the purchase price over fair value of our proportionate share of the assets acquired and liabilities assumed was recorded to goodwill. The goodwill recognized is primarily driven by the opportunity for continued operations through 80 years and the value of STP’s carbon-free energy that is not fully reflected by the markets. The goodwill amount has been assigned entirely to the ERCOT operating segment. See Note 13 — Intangible Assets for additional information. The total amount of goodwill is expected to be deductible for tax purposes over the amortization period. The fair values of STP’s assets and liabilities were determined based on significant estimates and assumptions that are judgmental in nature, including projected future cash flows (including timing), discount rates reflecting risk inherent in the future cash flows and future power and fuel market prices. Accounting guidance provides that the allocation of the purchase price may be modified up to one year from the date of the acquisition to the extent that additional information is obtained about the facts and circumstances that existed as of the acquisition date. Any changes could result in a change in the amount of goodwill recorded. The following table summarizes the acquisition-date fair value of the consideration transferred and the assets and liabilities assumed for the STP acquisition: Cash paid for purchase price $ 1,654 Identifiable assets acquired and liabilities assumed Property, plant, and equipment 1,254 Nuclear decommissioning trust funds 869 Inventories, net 47 Other long-term assets 40 Other current assets 11 Total assets 2,221 Asset retirement obligations 429 Payables related to Regulatory Agreement Units 376 Deferred income taxes and unamortized investment tax credits 65 Accounts payable and accrued expenses 45 Pension and OPEB obligations 25 Other long-term liabilities 5 Total liabilities 945 Total net identifiable assets, at fair value 1,276 Goodwill $ 378 For the year ended December 31, 2023, we incurred immaterial merger and integration-related costs which are included within Operating and maintenance expense in our Consolidated Statements of Operations and Comprehensive Income. The operating revenues and results of operations for STP have been included in the Consolidated Statements of Operations and Comprehensive Income from the date of acquisition and were not material for the year ended December 31, 2023. The pro forma effects of this acquisition are not significant to our reported results for any periods presented. Accordingly, no pro forma financial statements have been presented herein. On July 28, 2023 NRG accepted service of a lawsuit filed by the City of San Antonio, Texas, acting by and through CPS, in the 130th District Court of Matagorda County, Texas against NRG and certain of its subsidiaries, claiming the existence of a right of first refusal that applies to the transaction contemplated between us and NRG. On July 31, 2023 we intervened in the lawsuit and Austin Energy also intervened in the lawsuit claiming a similar right of first refusal. Per the terms of the Equity Purchase Agreement, NRG made representations that no right of first refusal applied to the transaction contemplated between us. 104 Table of Contents Combined Notes to Consolidated Financial Statements (Dollars in millions, unless otherwise noted) Note 2 — Mergers, Acquisitions, and Dispositions Separately, on July 31, 2023, San Antonio and Austin filed motions to dismiss and (in the alternative) immediately stay proceedings and petitions to intervene on the application for June 12, 2023 license transfer application that was filed with the NRC. These motions and petitions remain pending before the NRC. Notwithstanding this, the NRC issued approval of the license transfer application on October 30, 2023. However, the NRC staff’s approval of the license transfer is subject to the Commission’s authority to rescind, modify, or condition the approved transfer based on the outcome of any post-effectiveness hearing or motions on the license transfer application. On February 20, 2024, we (along with San Antonio, Austin and NRG) jointly filed a motion to stay of the issuance of a decision by the NRC on the pending petition and motions. The motion requested that the NRC stay any decision so that the parties can attempt to finalize a settlement agreement that would result in the withdrawal of San Antonio’s pending petition and motions. The ongoing legal proceedings did not prohibit NRG and CEG from consummating the transaction, and Constellation is working with all parties to reach a resolution to the matter. We cannot reasonably predict the outcome of the lawsuit or NRC litigation; however, we do not expect it to have a material impact to our consolidated financial statements. CENG Put Option Prior to August 6, 2021, we owned a 50.01 % membership interest in CENG, a joint venture with EDF, which wholly owned the Calvert Cliffs and Ginna nuclear stations and Nine Mile Point Unit 1, in addition to an 82 % undivided ownership interest in Nine Mile Point Unit 2. CENG is 100% consolidated in our financial statements. On April 1, 2014, we entered into various agreements with EDF including a Nuclear Operating Services Agreement, an amended LLC Operating Agreement, an Employee Matters Agreement, and a Put Option Agreement, among others. Under the amended LLC Operating Agreement, CENG made a $ 400 million special distribution to EDF and committed to make preferred distributions to us until we had received aggregate distributions of $ 400 million plus a return of 8.50 % per annum. Under the terms of the Put Option Agreement, EDF had the option to sell its 49.99 % equity interest in CENG exercisable beginning on January 1, 2016 and thereafter until June 30, 2022. On November 20, 2019, we received notice of EDF’s intention to exercise the put option, and the put automatically exercised on January 19, 2020 at the end of the sixty-day advance notice period. The transaction required approval by FERC and the NYPSC, which approvals were received on July 30, 2020 and April 15, 2021, respectively. On August 6, 2021, we entered into a settlement agreement pursuant to which we purchased EDF's equity interest in CENG for a net purchase price of $ 885 million, which included, among other things, an adjustment for EDF's share of the outstanding balance of the preferred distribution payable to us by CENG. The difference between the net purchase price and EDF's noncontrolling interest as of August 6, 2021 was recorded to Membership interest in the Consolidated Balance Sheet. As a result of the transaction, we also recorded deferred tax liabilities of $ 288 million in Membership interest in the Consolidated Balance Sheet. See Note 14 — Income Taxes for additional information. The following table summarizes the effects of the changes in our ownership interest in CENG in Member's Equity: For the Year Ended December 31, 2021 Net loss attributable to membership interest $ ( 205 ) Pre-tax increase in membership interest for purchase of EDF's 49.99 % equity interest (a) 1,080 Decrease in membership interest due to deferred tax liabilities resulting from purchase of EDF's equity interest (a) ( 288 ) Change from net loss attributable to membership interest and transfers from noncontrolling interest $ 587 __________ (a) Represents non-cash activity in the consolidated financial statements. 105 Table of Contents Combined Notes to Consolidated Financial Statements (Dollars in millions, unless otherwise noted) Note 2 — Mergers, Acquisitions, and Dispositions Agreement for Sale of Our Biomass Facility On April 28, 2021, we entered into a purchase agreement with ReGenerate Energy Holdings, LLC ("ReGenerate"), under which ReGenerate agreed to purchase our interest in the Albany Green Energy biomass facility. As a result, in the second quarter of 2021, we recorded a pre-tax impairment charge of $ 140 million in Operating and maintenance expense in the Consolidated Statement of Operations and Comprehensive Income. Completion of the transaction was subject to the satisfaction of various customary closing conditions that were satisfied in the second quarter of 2021. The sale was completed on June 30, 2021 for a net purchase price of $ 36 million. Agreement for Sale of Our Solar Business On December 8, 2020, we entered into an agreement with an affiliate of Brookfield Renewable, for the sale of a signi