Constellation Energy Corp 10-K

ceg-20221231 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 , 2022 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, 2022 was as follows: Constellation Energy Corporation $ 18,711,601,222 Constellation Energy Generation, LLC Not applicable The number of shares outstanding of each registrant’s common stock as of January 31, 2023 was as follows: Constellation Energy Corporation Common Stock, without par value 327,131,082 Constellation Energy Generation, LLC Not applicable Documents Incorporated by Reference Portions of the Registrants’ Definitive Proxy Statement relating to the 2023 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, 2022. TABLE OF CONTENTS Page No. GLOSSARY OF TERMS AND ABBREVIATIONS 1 FILING FORMAT 6 CAUTIONARY STATEMENTS REGARDING FORWARD-LOOKING INFORMATION 6 WHERE TO FIND MORE INFORMATION 6 PART I ITEM 1. BUSINESS 7 General 7 Constellations Strategy and Outlook 19 Employees 21 Environmental Matters and Regulation 23 ITEM 1A. RISK FACTORS 29 ITEM 1B. UNRESOLVED STAFF COMMENTS 43 ITEM 2. PROPERTIES 43 ITEM 3. LEGAL PROCEEDINGS 46 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 49 Executive Overview 49 Significant 202 2 Transactions and Developments 49 Other Key Business Drivers 50 Critical Accounting Policies and Estimates 51 Financial Results of Operations 58 Liquidity and Capital Resources 68 ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK 77 ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA 83 Constellation Energy Corporation 87 Constellation Energy Generation, LLC 93 Combined Notes to Consolidated Financial Statements 98 1. Basis of Presentation 98 2. Mergers, Acquisitions, and Dispositions 105 3. Regulatory Matters 106 4. Revenue from Contracts with Customers 112 5. Segment Information 114 6. Accounts Receivable 117 7. Early Plant Retirements 119 8. Property, Plant, and Equipment 121 9. Jointly Owned Electric Utility Plant 122 10. Asset Retirement Obligations 122 11. Leases 127 12. Asset Impairments 129 13. Intangible Assets 130 14. Income Taxes 131 15. Retirement Benefits 135 16. Derivative Financial Instruments 143 17. Debt and Credit Agreements 148 18. Fair Value of Financial Assets and Liabilities 154 19. Commitments and Contingencies 163 20. Stock-Based Compensation Plans 168 21. Changes in Accumulated Other Comprehensive Income 170 22. Variable Interest Entities 171 23. Supplemental Financial Information 174 24. Related Party Transactions 178 ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE 179 ITEM 9A. CONTROLS AND PROCEDURES 179 ITEM 9B. OTHER INFORMATION 180 ITEM 9C. DISCLOSURE REGARDING FOREIGN JURISDICTIONS THAT PREVENT INSPECTIONS 180 PART III ITEM 10. DIRECTORS, EXECUTIVE OFFICERS, AND CORPORATE GOVERNANCE 180 ITEM 11. EXECUTIVE COMPENSATION 181 ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS 182 ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR INDEPENDENCE 182 ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES 182 PART IV ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES 183 ITEM 16. FORM 10-K SUMMARY 189 SIGNATURES 190 Constellation Energy Corporation 190 Constellation Energy Generation, LLC 191 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 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 SolGen SolGen, LLC TMI Three Mile Island nuclear facility Former Related Entities Exelon Exelon Corporation ComEd Commonwealth Edison Company PECO PECO Energy Company BGE Baltimore Gas and Electric Company PHI Pepco Holdings LLC (formerly Pepco Holdings, Inc.) 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 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 CODM Chief Operating Decision Maker CORe Constellation Offsite Renewables CPP Clean Power Plan CTV Constellation Technology Ventures 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 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 ESG Environmental, Social, and Governance ERP Enterprise Resource Program EV Electric Vehicle 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 FRCC Florida Reliability Coordinating Council 2 Table of Contents FRR Fixed Resource Requirement GAAP Generally Accepted Accounting Principles in the United States GHG Greenhouse Gas GWh Gigawatt hour ICC Illinois Commerce Commission ICE Intercontinental Exchange IPA Illinois Power Agency IRA Inflation Reduction Act of 2022 IRC Internal Revenue Code 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 MATS U.S. EPA Mercury and Air Toxics Standards MDE Maryland Department of the Environment MDPSC Maryland Public Service Commission MISO Midcontinent Independent System Operator, Inc. MOPR Minimum Offer Price Rule MRV Market-Related Value MPSC Missouri Public Service Commission MW Megawatt MWh Megawatt hour N/A Not applicable NAV Net Asset Value NASDAQ Nasdaq Stock Market, Inc. 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. NJBPU New Jersey Board of Public Utilities 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 NOSA Nuclear Operating Services Agreement 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 OIESO Ontario Independent Electricity System Operator OPEB Other Postretirement Employee Benefits 3 Table of Contents PA DEP Pennsylvania Department of Environmental Protection PAPUC Pennsylvania Public Utility Commission PCAOB Public Company Accounting Oversight Board PBO Projected Benefit Obligation Pension Protection Act (the Act) Pension Protection Act of 2006 PG&E Pacific Gas and Electric Company PJM PJM Interconnection, LLC 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 PSDAR Post-shutdown Decommissioning Activities Report 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 Credit which is issued for each megawatt hour of generation 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 RFP Request for Proposal RGGI Regional Greenhouse Gas Initiative RIN Renewable Identification Number RMC Risk Management Committee RMP Risk Management Policy RNF Revenue 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 SPP Southwest Power Pool SSA Social Security Administration STEM Science, Technology, Engineering, and Mathematics TWh Terawatt-hour U.S. Court of Appeals for the D.C. Circuit United States Court of Appeals for the District of Columbia Circuit VIE Variable Interest Entity WECC Western Electric Coordinating Council ZEC Zero Emission Credit 4 Table of Contents ZES Zero Emission Standard 5 Table of Contents FILING FORMAT This combined Annual Report on Form 10-K is being filed separately by Constellation Energy Corporation and Constellation Energy Generation, LLC, (Registrants). Information contained herein relating to any individual Registrant is filed by the Registrant on its own behalf. 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. None of the Registrants 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. 6 Table of Contents PART I ITEM 1. 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, natural gas, and solar generation facilities has the generating capacity to power the equivalent of 15 million homes, producing 11 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 32,355 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 13,370 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 fourth largest generation portfolio in the U.S. in terms of total generation with meaningful geographic diversity. 7 Table of Contents At December 31, 2022, our generating resources consisted of the following: Type of Capacity MWs Owned generation assets (a) Nuclear 20,895 Natural gas and oil 8,807 Renewable (b) 2,653 Owned generation assets 32,355 Contracted generation (c) 3,883 Total generating resources 36,238 __________ (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. (c) Electric supply procured under unit-specific agreements. The following map illustrates the locations of our owned generation facilities as of December 31, 2022: The Company's Generation Fleet Map (a) Owned Assets (b) Nuclear Wind Gas/Other Solar Hydro __________ (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. 8 Table of Contents We have five reportable segments, as described in the table below, representing the different geographical areas 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 Geographical Area Mid-Atlantic 10,495 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 11,892 37 % Western half of PJM and the United States footprint of MISO, excluding MISO’s Southern Region New York 3,093 10 % NYISO ERCOT 3,610 11 % Electric Reliability Council of Texas Other Power Regions 3,265 10 % New England, South, West, and Canada Total 32,355 100 % __________ (a) Net generation capacity is stated at proportionate ownership share as of December 31, 2022. See ITEM 2. PROPERTIES for additional information. The following table shows sources of electric supply in GWhs for 2022 and 2021: Source of Electric Supply 2022 2021 Nuclear (a)(b) 173,350 172,990 Purchases — non-trading portfolio 70,682 67,605 Natural gas and oil 21,563 19,960 Renewable (c) 6,049 6,577 Total Supply 271,644 267,132 __________ (a) Includes the proportionate share of output where we have an undivided ownership interest in jointly-owned generating plants and includes the total output of plans that are fully consolidated. (b) 2021 values have been revised from those previously reported to correctly reflect our 82% undivided ownership interest in Nine Mile Point Unit 2. (c) Includes wind, hydroelectric, solar, and in 2021, biomass generating assets. See Note 2 — Mergers, Acquisitions, and Dispositions of the Combined Notes to Consolidated Financial Statements for additional information regarding the sale of our biomass facility. Nuclear Facilities Our nuclear fleet is the nation’s largest, with current generating capacity of approximately 21 gigawatts; it produced 173 terawatt hours of zero-emissions electricity during 2022 – enough to power 15.4 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 13 nuclear generating stations currently in service, consisting of 23 units. As of December 31, 2022, we wholly own all our nuclear generating stations, except for undivided ownership interests in four jointly owned nuclear stations: Quad Cities (75% ownership), Peach Bottom (50% ownership), Salem (42.59% ownership), and Nine Mile Point Unit 2 (82% ownership), which are consolidated 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 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 and Note 22 — Variable Interest Entities of the Combined Notes to Consolidated 9 Table of Contents 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 two units at Salem, which are operated by PSEG Nuclear, LLC (an indirect, wholly owned subsidiary of PSEG), and we have consistently operated our nuclear plants at best-in-class levels. During 2022, 2021, and 2020, our nuclear generating facilities achieved capacity factors (a) of 94.8%, 94.5%, and 95.4%, respectively, at ownership percentage. The nuclear capacity factor has been approximately four percentage points better than the industry average annually since 2013. Capacity factors, which are significantly affected by the number and duration of refueling and non-refueling outages, can have a significant impact on our results of operations. In 2022, we achieved an average refueling outage duration of 21 days for units we operate. We achieved an average refueling outage duration of 22 days in both 2021 and 2020, against industry averages of 32 and 34 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 2022, 2021, and 2020, electric supply (in GWhs) generated from our nuclear generating facilities was 64%, 65%, and 62%, respectively, of our total electric supply, which also includes natural gas, oil, and renewable generation and electric supply purchased for resale. See ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS for additional information on electric supply sources. 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. Peach Bottom has previously received a second 20-year license renewal from the NRC, for a total 80-year term, for Units 2 and 3. See Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information. __________ (a) Capacity factor 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 full average annual mean capacity for that time period. See ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS for additional information. 10 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 1 1969 2029 2 1988 2046 Peach Bottom (c) 2 1974 2033 3 1974 2034 Quad Cities 1 1973 2032 2 1973 2032 Ginna 1 1970 2029 Salem 1 1977 2036 2 1981 2040 __________ (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, 2022, except for Clinton, Dresden and Peach Bottom. We are currently seeking license renewals for our Clinton and Dresden units. Clinton depreciation provisions are based on an estimated useful life through 2047. Dresden Units 2 and 3 depreciation provisions are based on an estimated useful life through 2049 and 2051, respectively, in anticipation of the license renewals. Peach Bottom Units 2 and 3 depreciation provisions are based on an estimated useful life through 2053 and 2054 respectively, in anticipation of the license expiration dates being restored. See Note 3 — Regulatory Matters 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 11 Table of Contents the current NRC operating license for each unit consistent with the table above. See Note 3 — Regulatory Matters and Note 7 — Early Plant Retirements of the Combined Notes to Consolidated Financial Statements for additional information on Byron and Dresden and the Illinois CMC program. Natural Gas, Oil and Renewable Facilities (including Hydroelectric) We operate approximately 11 gigawatts 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 2022, 2021, and 2020, electric supply (in GWhs) generated from our owned natural gas, oil, and renewable generating facilities was 10%, 10%, and 9%, respectively, of our total electric supply. Much of this output was dispatched to support our wholesale and retail power customer-facing activities. Our natural gas, oil and renewable fleet has similarly demonstrated a track record of strong performance with a power dispatch match (a) of 98.4%, 72.4%, and 98.4% and renewables energy capture (b) of 95.8%, 95.7%, and 93.4% in 2022, 2021, and 2020, respectively. Our power dispatch match performance in 2021 was significantly impacted by the February 2021 extreme weather event in Texas, refer to Note 3 — Regulatory Matters 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 the estimated useful life, which corresponds with the available license term. In March 2021, FERC issued a new 50-year license for Conowingo, vacated in December 2022 on remand, 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 Conowingo. 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. 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. (b) Energy capture is an indicator of how efficiently the installed assets capture the natural energy available from the wind and the sun. Energy capture represents an energy-based fraction, the numerator of which is the energy produced by the sum of the wind turbines/solar panels 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. Energy capture for the combined wind and solar fleet is weighted by the relative site projected pre-tax variable revenue. 12 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, 2022: Region Number of Agreements Expiration Dates Capacity (MWs) Mid-Atlantic 6 2023 - 2035 279 Midwest 3 2026 - 2032 351 New York 4 2023 26 ERCOT 6 2026 - 2035 841 Other Power Regions 12 2023 - 2037 2,386 Total 31 3,883 2023 2024 2025 2026 2027 Thereafter Total Capacity Expiring (MW) 140 101 490 398 5 2,749 3,883 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 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 1.6 million unique residential customers. We are a leader in electric power supply, serving approximately 208 TWhs in 2022 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: 13 Table of Contents 2022 Electric Power Supply (TWhs) Served Across Regions (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 ISO in which our facility is located. Other includes New England, South, and West. We are active in all domestic wholesale power and gas markets that span the entire lower 48 states and have complementary retail activity across many of those states. We largely obtain physical power supply from 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 ratable hedging program. See further discussion of the ratable 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. 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 2022, we served approximately 65 TWhs of power load across competitive utility load procurement and bilateral sales to municipalities, co-ops, banks, and other wholesale entities. Complementary to our national 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 the 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 14 Table of Contents our wholesale gas business we participate across all parts of the gas value chain, including trading, transport and storage and physical supply. Retail Market Retail competition in states across the U.S. range from full competition of energy suppliers for all retail customers (commercial, industrial 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 800 Bcf of gas in 2022, 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. Retail customer renewal rates have been strong over the last six years across C&I power customer groups, with an average contract term of approximately two years and customer duration of more than six years, with many customers well beyond these metrics. Specifically, we enjoyed renewal rates of 79% for C&I power customers and 90% for C&I gas customers in 2022, higher than the previous five years, 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 delivering focused attention to our customers’ needs, resulting in industry-leading customer satisfaction. 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 power as well, acquiring nearly one out of every three new customers who have chosen to shop with us over the past four years. 15 Table of Contents High customer satisfaction levels, market expertise, stability and scale drive growth and result in historically proven business consistency and 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 services and products 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 sales with over 32% of the C&I market share of direct customer business driven by our highly experienced and long-tenor direct sales team. 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 technology 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 addition to larger-scale CORe offerings, we offer a range of sustainability solutions to customers (RECs, EFECs, RINs, RNG, carbon offsets, hourly carbon-free energy matching, etc.) to support their energy needs during the transition to a carbon-free energy ecosystem. In addition to sustainability products and services, 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. 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. 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 use a combination of wholesale and retail customer load sales, as well as non-derivative and derivative contracts, all with credit-approved counterparties, to hedge the commodity price risk of the generation portfolio. For merchant generation sales not already hedged via comprehensive state programs, such as the CMC program in Illinois, we typically utilize a three-year ratable sales plan to align our hedging strategy with our financial objectives. The prompt three-year merchant sales are hedged on an approximate rolling 90%/60%/30% basis, providing cash flow stability while still allowing commercial opportunities to generate value for the Company. We may also enter transactions that are outside of this ratable hedging program. We are exposed to commodity price risk for the portions of our electricity portfolio that are unhedged. As of December 31, 2022, the 16 Table of Contents percentage of expected generation hedged for the Mid-Atlantic, Midwest, New York, and ERCOT reportable segments is 94%-97% and 75%-78% for 2023 and 2024, respectively. Similarly, the scale and scope of the portfolio provides risk-mitigating technology, product, and geographical diversification. We will continue to be proactive in using hedging strategies to mitigate commodity price volatility. The percentage of expected generation hedged is the number of equivalent sales divided by the expected generation. Expected generation is the volume of energy that best represents our commodity position in energy markets from owned or contracted generation based on a simulated dispatch model that makes assumptions regarding future market conditions, which are calibrated to market quotes for power, fuel, load following products, and options. Equivalent sales represent all wholesale and retail load sales, as well as hedging products, which include economic hedges and certain non-derivative contracts. 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 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. We have inventory in various forms and engage a diverse set of suppliers to ensure we can secure the nuclear fuel needed to continue to operate our nuclear fleet long-term and 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 units. We manage various risks around our nuclear fuel requirements in accordance with our fuel procurement policy. 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. We engage a diverse set of domestic and international suppliers and limit our transactions with each supplier to mitigate concentration of risk. Refer to 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. 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 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 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. 17 Table of Contents 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. For additional information regarding property insurance, see ITEM 2. PROPERTIES, Note 17 — Debt and Credit Agreements for additional information on financing agreements, and Note 19 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for insurance specific to our nuclear facilities. Regulation We are a public utility as defined under the Federal Power Act and 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, third-party financings; review of mergers; dispositions of jurisdictional facilities and acquisitions of securities of another public utility or an existing operational generating facility; affiliate transactions; 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, the scheduling of physical power sales brokered through ICE and NYMEX, and the elimination or reduction of redundant transmission charges imposed by multiple transmission providers when wholesale customers take transmission service across several transmission systems. 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. 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. All nuclear generating stations operated by us are categorized by the NRC in the Licensee Response Column, which is the highest of five performance bands. The NRC may modify, suspend, or revoke operating licenses and impose civil penalties for failure to comply with the Atomic Energy Act or the terms of the operating licenses. Changes in regulations 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. The ultimate decommissioning obligation is expected to be funded by the 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 18 Table of Contents 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: 1. 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, 2. 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, and 3. Providing 100% of C&I customers with specific information about their GHG impact. The principles of our sustainable business strategy demonstrate our commitment to a carbon-free future while maintaining a strong balance sheet, advancing our ESG 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 producing clean hydrogen and other sustainable fuels to reduce industrial emissions. 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. 19 Table of Contents 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 repowering, co-location and other opportunities, • Grow sustainability products and services for our customers focused on clean energy, efficiency, storage and electrification; help our C&I customers develop and meet sustainability targets, • Produce clean hydrogen using our carbon-free fleet, • Engagement with the technology and innovation ecosystem through continued partnerships with national labs, universities, startups, and research institutions, and • Explore advanced nuclear technology for investment and participation via advisory services 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, clean power and benefit from growing demand for carbon-free electricity. Key drivers of increased demand for clean 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 societal 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. 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 20 Table of Contents support nuclear generation, driven by factors that include 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. A 2018 study by the Massachusetts Institute of Technology, “The Future of Nuclear Energy in a Carbon-Constrained World,” found that the costs of achieving transformational decarbonization targets would increase significantly without the contribution of nuclear power. 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, and direct air capture could result in 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 2022 Rhodium Group study forecasts that as much as 57% of light duty vehicles sold in 2030 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 residential rooftop solar, EV charging, smart, energy-efficient home technologies, 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 must create the best teams and these teams must reflect the diversity of the communities that we serve. Therefore, we strive to attract highly qualified and diverse talent and routinely review our hiring, development and promotion practices to ensure we maintain equitable and bias free processes. We have undertaken our first employee engagement survey as a company 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. Career Development We provide our employees with growth opportunities, competitive compensation and benefits, and a variety of education and development programs. We are committed to helping employees advance their skills and careers, largely through educational opportunities in technical, safety and business acumen areas. Additionally, we develop our employees through individual discussions, mentorship programs, continuous feedback, and evaluations. We understand that continued education leads to a more engaged, skilled, and productive workforce and we support our employees in their educational endeavors to attract and retain people who are committed to personal and professional development by offering tuition reimbursement for approved higher education, certification or licensing courses. 21 Table of Contents Well-Being and Benefits We are committed to helping our employees maintain and improve their health and wellness, and we offer a wide range of benefits designed to help our employees thrive professionally and personally. We take a holistic approach to health and wellness, providing support for our employees’ physical health, mental well-being, family, as well as financial and legal strength. Community We are also committed to helping improve the quality of life for people in the communities where we live, work and serve. We provide opportunities for company-sponsored volunteerism and charitable matching gifts programs. Our employees donated $4.6 million to non-profit organizations and provided just over 80,000 volunteer hours in 2022. Next Generation of Talent We are also committed to exposing underrepresented and underserved individuals within our communities to career opportunities in the energy industry. Through internships and scholarships, university and veteran recruiting, STEM education and training programs, and partnerships with diverse talent organizations such as the Society of Women Engineers and the National Society of Black Engineers, we are committed to providing equitable access to professional development and opportunities for the next generation of our workforce. Major focus areas include: • Creating educational and awareness opportunities within STEM and the trades through curriculum development, early engagement, and educational partnerships, • Reducing or removing access and opportunity barriers faced by young people and underrepresented and underserved members of the community, and • Deepening current and executing new approaches and partnerships with industry employers, nonprofits, and community groups to provide entry and advancement opportunities for work-ready adults and youth through upskilling and reskilling training efforts. Diversity Metrics The following table shows diversity metrics for all employees and management as of December 31, 2022: Metric All Employees Management (d) Female (a)(b) 2,889 474 People of Color (a)(b) 2,569 331 Aged <30 1,680 50 Aged 30-50 7,420 1,474 Aged >50 4,270 855 Within 10 years of retirement eligibility 5,724 1,197 Total Employees (c) 13,370 2,379 __________ (a) We conduct an annual analysis on gender and racial pay equity. We also review hiring and promotion processes to neutralize any unconscious bias and embed equal pay efforts into broader company-wide equity initiatives. These actions reflect our commitment to create an environment where all employees can thrive and advance as equal members of the workforce. (b) This is based on self-disclosed information. (c) Total employees represents the sum of the aged categories. (d) Management is defined as executive/senior level officials and managers as well as all employees who have direct reports and supervisory responsibilities. Turnover Rates 22 Table of Contents As turnover is inherent, management succession planning is performed and tracked for all executives and critical key manager positions. Management frequently reviews succession planning to ensure we are prepared when positions become available. The table below shows the average turnover rate for all employees for the last three years of 2020 to 2022: All Retirement Age 4.30 % Voluntary 6.00 % Non-Voluntary 1.20 % Collective Bargaining Agreements Approximately 25% of employees participate in CBAs. The following table presents employee information, including information about CBAs, as of December 31, 2022: Total Employees Covered by CBAs Number of CBAs CBAs New and Renewed in 2022 (a) Total Employees Under CBAs New and Renewed in 2022 3,342 21 1 74 __________ (a) Does not include CBAs that were extended in 2022 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, our Sustainability and Climate Strategy team, 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 societal 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. 23 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 such that our generation emissions intensity is already 80% less than 2005 levels in support of achieving economy-wide GHG emissions reduction goals. Our Scope 1 and 2 GHG emissions in 2021 were 8.3 million metric tons carbon dioxide equivalent, of which 8.0 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 GHG emissions, most notably CO2. In addition, we sell natural gas t hrough 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 2022, we achieved a 94.8% percent capacity factor across our nuclear fleet and our ownership of 21 gigawatts of carbon-free generation capacity at 23 nuclear units produced 173 TWhs of electricity in 2022. 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 most recent Conference of Parties (COP27) held in Sharm el-Sheikh, Egypt recommitted countries to their pledges in the Glasgow Climate Pact. Federal Climate Change Legislation. On August 16, 2022, the U.S. Congress passed and 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 and hydrogen production facilities. 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 Hydrogen PTC provides a 10-year federal tax credit of up to $3 per kilogram for clean hydrogen produced after 2022 from facilities that begin construction prior to 2033. Both the Nuclear and Hydrogen PTCs include adjustments for inflation. The Hydrogen PTC creates additional opportunities for our nuclear fleet to enable decarbonization of other industries through the production of clean hydrogen. With this policy support, we expect that many of our nuclear assets will operate through the end of the Nuclear PTC period. The U.S. Department of Treasury has begun the process of issuing guidance on the relevant tax provisions included in the legislation. 24 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. In July 2019, the EPA published the Affordable Clean Energy rule, which repealed the CPP and replaced it with less stringent emissions guidelines based on heat rate improvement measures. We, as part of Exelon, together with a coalition of other electric utilities, filed a lawsuit in the U.S. Court of Appeals for the D.C. Circuit on September 6, 2019, challenging the Affordable Clean Energy rule as unlawful. On January 19, 2021, the U.S. Court of Appeals for the D.C. Circuit vacated the Affordable Clean Energy Rule. On October 29, 2021, the U.S. Supreme Court granted certiorari to examine the extent of the EPA’s authority to regulate GHGs from power plants. The electric utilities coalition filed a brief and participated in oral argument before the U.S. Supreme Court. 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. The EPA has indicated it will propose new GHG limits for power plants in April 2023 and finalize them 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 See Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information on the New Jersey Clean Energy Legislation and the Illinois Clean Energy Law. 25 Table of Contents Regional Greenhouse Gas Initiative. On July 1, 2022, Pennsylvania formally began participation in RGGI, joining Connecticut, Delaware, Maine, Maryland, Massachusetts, New Hampshire, New Jersey, New York, Rhode Island, Vermont, and Virginia. The 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. Pennsylvania’s participation in RGGI was accomplished through a PA DEP regulation that became effective on July 1, 2022 that was challenged in the Commonwealth Court of Pennsylvania, which has enjoined the state from implementing the regulation pending resolution of the proceeding. The Commonwealth Court of Pennsylvania heard oral arguments in November 2022 on the merits of the challenges to Pennsylvania entering RGGI. In the interim, the state has petitioned the Pennsylvania Supreme Court to vacate the lower court’s injunction order. Briefing of the appeal was completed on December 4, 2022. On January 15, 2022, Governor Youngkin directed the Virginia Department of Environmental Quality to reevaluate the state’s participation in RGGI and begin a regulatory process to consider repeal of the regulations providing for RGGI participation. On September 26, 2022, the Virginia State Air Pollution Control Board published a Notice of Intended Regulatory Action seeking public comment on the proposed repeal of the state’s regulations implementing its participation in RGGI. This matter remains pending. Renewable and Clean Energy Standards. 31 states and the District of Columbia, incorporating most of the states where we operate, have adopted some form of renewable or clean energy procurement requirement. These standards impose varying levels of mandates for procurement of renewable or clean electricity (the definition of which varies by state) and/or energy efficiency. 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 or RECs 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. Both energy storage and clean hydrogen continue to gain political and business support and 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. 26 Table of Contents 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. MATS requires coal-fired power plants to achieve high removal rates of mercury, acid gases, and other metals, and to make capital investments in pollution control equipment and incur higher operating expenses. 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 reversed course, publishing a final rule revoking 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. On January 20, 2021, President Biden issued an Executive Order directing the EPA to reconsider its May 22, 2020, revised supplemental finding, and the EPA subsequently moved for the D.C. Circuit to place the cases challenging that finding in abeyance pending its reconsideration, which the court did on February 21, 2021. On February 9, 2022 the EPA published a proposal to revoke the 2020 revised supplemental finding and reaffirm that it is "appropriate and necessary" to regulate hazardous air pollutant emissions from coal- and oil-fired power plants. Additionally, in February 2022, the D.C. Circuit granted unopposed motions to substitute Constellation in place of Exelon in these cases. The EPA has indicated that they will issue the final regulation in March 2023. If the EPA promulgates a final rule revoking the 2020 revised supplemental finding determination, then the cases currently before the D.C. Circuit concerning MATS may be dismissed as moot or placed in abeyance pending the disposition of any petitions for review that may be filed challenging that final rule. We cannot reasonably predict the outcome of this matter. Good Neighbor Rule. On April 6, 2022, the EPA published a proposed rule called “Federal Implementation Plan Addressing Regional Ozone Transport for the 2015 Ozone National Ambient Air Quality Standards” also known as the "Good Neighbor Rule" or the "Transport Rule". The proposed rule, among other things, established nitrogen oxides emissions budgets requiring fossil fuel-fired power plants in 25 states to participate in an allowance-based ozone season trading program beginning in 2023. Comments on the proposed rule were due June 6, 2022 and the EPA has indicated it will issue a final rule in early 2023. When the EPA finalizes this proposed rule, there may be impacts on the electric power market. We cannot reasonably predict the outcome of this rule. Oil and Gas Methane Rule . On December 6, 2022, the EPA published a supplemental proposed rule setting methane emissions standards for certain new and existing oil and gas facilities. The supplemental proposal updates the proposed regulation issued in November 2021. Comments on the proposed regulation were due on February 13, 2023. When the EPA finalizes this proposed rule, there may be indirect impacts on the electric power market through the supply of gas. We cannot reasonably predict the outcome of this rule. 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 electric power plants 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 27 Table of Contents renewal of these facilities’ NPDES permits. Until the compliance requirements are determined by the applicable state permitting director 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. 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. On July 28, 2016, the NJDEP issued a final permit for Salem that did not require the installation of cooling towers and allows Salem to continue to operate utilizing the existing cooling water system with certain required system 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. Where our facilities are required to secure a federal license or permit for activities that may result in a discharge to covered waters, we may be required to obtain a state water quality certification for those facilities under Clean Water Act section 401. We are also subject to the jurisdiction of the Delaware River Basin Commission and the Susquehanna River Basin Commission, regional agencies that primarily regulate water usage. Solid and Hazardous Waste and Environmental Remediation CERCLA authorizes response to releases or threatened releases of hazardous substances into the environment. 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, and Pennsylvania. 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, 2022, 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 3 — Regulatory Matters and 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 28 Table of Contents 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, 2022, we had approximately 91,500 SNF assemblies (22,400 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. 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 1A. RISK FACTORS 29 Table of Contents 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, • 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 design of power markets, • the renewal of permits and 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, • the ability of energy transmission and distribution companies to maintain the reliability, resiliency and safety of their energy delivery systems, which could affect our ability to deliver energy to our customers and affect our operating costs, and • physical and cyber security 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: • challenges to achieving the benefits of separation, including the need to replicate certain services provided by Exelon (e.g. information technology), which will require additional resources and expense, • performance by Exelon and us under the transaction agreements, including indemnification responsibilities tied to the allocation of businesses and liabilities, and • limitations on future capital-raising or strategic transactions during the two-year period following the distribution arising from the need to protect the tax-free treatment of the distribution. 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, natural gas and oil. 30 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 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 31 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, 2022, approximately 38%, 13%, and 19% 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. 32 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 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 commercial and industrial 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 for additional information on our credit risk. Our results were negatively affected by the impacts of COVID-19 in 2020 and future pandemics or other significant health issues could also adversely affect our results. 33 Table of Contents COVID-19 has previously disrupted economic activity in our markets and negatively affected our results of operations. The estimated impact of COVID-19 to our Net income was approximately $170 million for the year ended December 31, 2020 and was not material for the years ended December 31, 2021 and 2022. Any future widespread pandemic or other local or global health issue could adversely affect customer demand and our ability to operate our generation assets. We could be negatively affected by the impacts of weather. 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 capacity at a time when markets are weak. 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. By comparison, the estimated impact reduced our overall Net loss by approximately $50 million for the year ended December 31, 2022, see Note 3 — Regulatory Matters and Note 19 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for additional information. Long-lived assets and other assets could become impaired. Long-lived assets – principally, generation assets – represent the single largest asset class on our Consolidated Balance Sheets. 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. An impairment would require us to reduce the carrying value of the long-lived asset 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 8 — Property, Plant, and Equipment and Note 12 — Asset Impairments 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. 34 Table of Contents In the bilateral markets, we are exposed to the risk that counterparties that owe us money or are obligated to purchase energy or fuel from us, will not perform under their obligations for operational or financial reasons. In the event the counterparties to these arrangements fail to perform, we could be forced to purchase or sell energy or fuel in the wholesale markets at less favorable prices and incur additional losses, to the extent amounts, if any, were already paid to the counterparties. In the spot markets, we are exposed to risk as a result of default sharing mechanisms that exist within certain markets, primarily RTOs and ISOs. We are also a party to agreements with entities in the energy sector that have experienced rating downgrades or other financial difficulties. In addition, our retail sales subject us to credit risk through competitive electricity and natural gas supply activities to serve commercial and industrial 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 3 — Regulatory Matters 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. See Note 3 — Regulatory Matters and Note 7 — Early Plant Retirements of the Combined Notes to Consolidated Financial Statements for additional information. 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. 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. 35 Table of Contents Spent Nuclear Fuel Storage. The approval of a national repository for the storage of SNF and the timing of that facility opening, will significantly affect the costs associated with storage of SNF and the ultimate amounts received from the DOE to reimburse us for these costs. Any regulatory action relating to the timing and availability of a repository for SNF could adversely affect our ability to decommission fully our nuclear units. We cannot predict whether a fee may be established or to what extent, in the future for SNF disposal. See Note 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 36 Table of Contents increase in capital expenditures, result in increased operating costs or render the project uneconomic. Similar effects could result from a change in the Federal Power Act or the applicable regulations due to events at hydroelectric facilities owned by others, as well as those owned by us. See Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information regarding the license renewal for the Conowingo hydroelectric project. We could be negatively affected by challenges to tax positions taken, tax law changes and the inherent difficulty in quantifying potential tax effects of business decisions. We are required to make judgments in order to estimate our obligations to taxing authorities. These tax obligations include income, real estate, sales and use and employment-related taxes and ongoing appeal issues related to these tax matters. These judgments include reserves established for potential adverse outcomes regarding tax positions that have been taken that could be subject to challenge by the tax authorities. See Note 1 — Basis of Presentation and Note 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. The material ones 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 and East Coast of the United States, 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 37 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 and fuel expense to meet supply commitments. Further, our nuclear operations produce various types of nuclear waste materials, including SNF. The approval of a national repository for the storage of SNF and the timing of that facility opening, will significantly affect the costs associated with storage of SNF and the ultimate amounts received from the DOE to reimburse us for these costs. Any regulatory action relating to the timing and availability of a repository for SNF could adversely affect our ability to decommission fully our nuclear units. We cannot predict whether in the future a fee for SNF disposal may be reestablished or to what extent. If we are required to arrange for the safe and permanent disposal of spent fuel beyond current expectations, this could lead to substantial expense or capital expenditures. 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. 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. 38 Table of Contents As required by the Price-Anderson Act, we carry the maximum available amount of nuclear liability insurance, $450 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 $13.7 billion limit for a single incident. 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 make contributions to certain trust funds of the former PECO units based on amounts being collected by PECO from its customers and remitted to us. While we, through PECO, have recourse to collect additional amounts from PECO customers (subject to certain limitations and thresholds), we have no recourse to collect additional amounts from utility customers for any of our other nuclear units if there is a shortfall of funds necessary for decommissioning. If circumstances changed such that there was an inability to continue to make contributions to the trust funds of the former PECO units based on amounts collected from PECO customers, or if we no longer had recourse to collect additional amounts from PECO customers if there was a shortfall of funds for decommissioning, the adequacy of the trust funds related to the former PECO units could be negatively affected. Any changes to the PECO regulatory agreements could impact our ability to offset decommissioning-related activities within the Consolidated Statement 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 Statements of Operations and Comprehensive Income for decommissioning-related activities that were not offset for the Byron units due to contractual offset being temporarily suspended. 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 physical security and cybersecurity risks. We face physical security and cybersecurity risks. Threat sources continue to seek to exploit potential vulnerabilities in the electric generation and natural gas industry 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. Continued implementation of advanced digital technologies increases the potentially unfavorable impacts of such attacks. We expect these attacks and disruptions to continue to occur in the future and we are constantly managing efforts to infiltrate and compromise our physical assets and information technology systems and data. A security breach, including physical or electronic break-ins, computer viruses, malware, attacks by hackers, ransomware attacks, phishing attacks, supply chain attacks, breaches due to employee error or misconduct and other similar breaches, of our physical assets or information systems, or those of our competitors, vendors, 39 Table of Contents business partners and interconnected entities in RTOs and ISOs, or regulators could impact the operation of the generation fleet and/or reliability of the transmission and distribution system or result in the theft or inappropriate release of certain types of information, including critical infrastructure information, sensitive customer, vendor and employee data, trading or other confidential data. The risk of these system-related events and security breaches occurring continues to intensify, and while we have not directly experienced a material breach or disruption to our network or information systems or our operations to-date, such attacks continue to increase in sophistication and frequency, and we may be unable to prevent all such attacks in the future. If a significant 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 or operations shutdown. Moreover, the amount and scope of insurance maintained against losses resulting from any such events or security breaches may not be sufficient to cover losses or otherwise adequately compensate for any disruptions to business that could result. Furthermore, in the future, such insurance may not be available on commercially reasonable terms, or at all. In addition, new or updated security regulations or unforeseen threat sources could require changes in current measures taken by us or our business operations and could adversely affect our consolidated financial statements. Our employees, contractors, customers and the general public could be exposed to a risk of injury due to the nature of the energy industry. Employees and contractors throughout the organization work in, and the general public could be exposed to, potentially dangerous environments near our operations. As a result, employees, contractors and the general public are at some risk for serious injury, including loss of life. These risks include, but are not limited to, nuclear accidents, dam failure, gas explosions, and electric contact cases. Natural disasters, war, acts and threats of terrorism, pandemic and other significant events could negatively impact our results of operations, ability to raise capital and future growth. Our fleet of power plants and the transmission infrastructure to which they are connected could be affected by natural disasters and extreme weather events, which could result in increased costs, including supply chain costs. Natural disasters and other significant events increase our risk that the NRC or other regulatory or 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. 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. 40 Table of Contents 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 utility 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 the separation transaction, 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 repowering, co-location and the production of hydrogen, growing sustainability products and services for our customers, and investment opportunities in other emerging technologies and innovation. Such initiatives could involve significant risks and uncertainties, including distraction of management from current operations, inadequate return on capital, and unidentified issues not discovered during diligence performed prior to launching an initiative or entering a market. Additionally, it is possible that FERC, state public utility commissions or others could 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 We may not achieve some or all the expected benefits of the separation, and the separation may materially adversely affect our business. We may not be able to achieve the full strategic and financial benefits expected to result from the separation, or such benefits may be delayed or not occur at all. If we fail to achieve some or all the benefits expected to result from the separation, or if such benefits are delayed, it could have a material adverse effect on our competitive position, business, financial condition, results of operations and cash flows. 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. 41 Table of Contents 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 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. We may not be able to engage in desirable strategic transactions or capital-raising following the separation. Under current U.S. federal income tax law, a spin-off that otherwise qualifies for tax-free treatment can be rendered taxable to the parent corporation and its shareholders as a result of certain post-spin-off transactions, including certain acquisitions of shares or assets of the spun-off corporation. To preserve the tax-free treatment of the distribution, and in addition to potential tax indemnity obligations, we agreed to certain limitations or prohibitions in the tax matters agreement that may prohibit us, for the two-year period following the distribution and except in specific circumstances, from, among other things: 42 Table of Contents • entering into any transaction pursuant to which all or a portion of the shares of our stock, or substantially all of our assets, would be acquired, whether by merger or otherwise; • issuing equity securities beyond certain thresholds; • repurchasing shares of our stock other than in certain open-market transactions. The tax matters agreement prohibits us from taking or failing to take any other action that would prevent the distribution and certain related transactions from qualifying as a transaction that is generally tax-free for U.S. federal income tax purposes under Sections 355 and 368(a)(1)(D) of the IRC. These restrictions may limit our ability to pursue certain equity issuances, strategic transactions, repurchases or other transactions that we may believe to be in the best interests of our shareholders or that might increase the value of our business. ITEM 1B. UNRESOLVED STAFF COMMENTS None. ITEM 2. PROPERTIES The following table presents our interests in net electric generating capacity by station at December 31, 2022: 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 (f) Clinton Clinton, IL 1 Uranium Base-load 1,080 Michigan Wind 2 Sanilac Co., MI 50 51 (g) Wind Intermittent 46 (f) Beebe Gratiot Co., MI 34 51 (g) Wind Intermittent 42 (f) Michigan Wind 1 Huron Co., MI 46 51 (g) Wind Intermittent 35 (f) Harvest 2 Huron Co., MI 33 51 (g) Wind Intermittent 30 (f) Harvest Huron Co., MI 31 51 (g) Wind Intermittent 26 (f) Beebe 1B Gratiot Co., MI 21 51 (g) Wind Intermittent 26 (f) Blue Breezes Faribault Co., MN 2 Wind Intermittent 3 CP Windfarm Faribault Co., MN 2 51 (g) Wind Intermittent 2 (f) Southeast Chicago Chicago, IL 8 Gas Peaking 296 (h) Clinton Battery Storage Blanchester, OH 1 Energy Storage Peaking 5 Total Midwest 11,892 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 (f) Salem Lower Alloways Creek Township, NJ 2 42.59 Uranium Base-load 993 (f) Conowingo Darlington, MD 11 Hydroelectric Base-load 572 Criterion Oakland, MD 28 51 (g) Wind Intermittent 36 (f) 43 Table of Contents Station (a) Location No. of Units Percent Owned (b) Primary Fuel Type Primary Dispatch Type (c) Net Generation Capacity (MWs) (d) Fair Wind Garrett County, MD 12 Wind Intermittent 30 Fourmile Ridge Garrett County, MD 16 51 (g) Wind Intermittent 20 (f) Solar Horizons Emmitsburg, MD 1 51 (g) Solar Intermittent 8 (f) Solar New Jersey 3 Middle Township, NJ 5 51 (g) Solar Intermittent 1 (f) Muddy Run Drumore, PA 8 Hydroelectric Intermediate 1,070 Eddystone 3, 4 Eddystone, PA 2 Oil/Gas Peaking 760 Perryman Aberdeen, MD 5 Oil/Gas Peaking 404 Croydon West Bristol, PA 8 Oil Peaking 391 Handsome Lake Kennerdell, PA 5 Gas Peaking 268 Richmond Philadelphia, PA 2 Oil Peaking 98 Philadelphia Road Baltimore, MD 4 Oil Peaking 61 Eddystone Eddystone, PA 4 Oil Peaking 60 Delaware Philadelphia, PA 4 Oil Peaking 56 Southwark Philadelphia, PA 4 Oil Peaking 52 Falls Morrisville, PA 3 Oil Peaking 51 Moser Lower Pottsgrove Twp., PA 3 Oil Peaking 51 Chester Chester, PA 3 Oil Peaking 39 Schuylkill Philadelphia, PA 2 Oil Peaking 30 Salem Lower Alloways Creek Township, NJ 1 42.59 Oil Peaking 16 (f) Total Mid-Atlantic 10,495 ERCOT Whitetail Webb County, TX 57 51 (g) Wind Intermittent 47 (f) Sendero Jim Hogg and Zapata County, TX 39 51 (g) Wind Intermittent 40 (f) Colorado Bend II Wharton, TX 3 Gas Intermediate 1,143 Wolf Hollow II Granbury, TX 3 Gas Intermediate 1,115 Handley 3 Fort Worth, TX 1 Gas Intermediate 395 Handley 4, 5 Fort Worth, TX 2 Gas Peaking 870 Total ERCOT 3,610 New York Nine Mile Point Scriba, NY 2 (i) Uranium Base-load 1,675 (f) 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 44 Table of Contents Station (a) Location No. of Units Percent Owned (b) Primary Fuel Type Primary Dispatch Type (c) Net Generation Capacity (MWs) (d) Bluestem Beaver County, OK 60 51 (g)(j) Wind Intermittent 101 (f) Shooting Star Kiowa County, KS 65 51 (g) Wind Intermittent 53 (f) Sacramento PV Energy Sacramento, CA 4 51 (g) Solar Intermittent 15 (f) Bluegrass Ridge King City, MO 27 51 (g) Wind Intermittent 29 (f) Conception Barnard, MO 24 51 (g) Wind Intermittent 26 (f) Cow Branch Rock Port, MO 24 51 (g) Wind Intermittent 26 (f) Mountain Home Glenns Ferry, ID 20 51 (g) Wind Intermittent 21 (f) High Mesa Elmore Co., ID 19 51 (g) Wind Intermittent 20 (f) Echo 1 Echo, OR 21 50.49 (g) Wind Intermittent 17 (f) Cassia Buhl, ID 13 51 (g) Wind Intermittent 14 (f) Wildcat Lovington, NM 13 51 (g) Wind Intermittent 14 (f) Echo 2 Echo, OR 9 51 (g) Wind Intermittent 9 (f) Tuana Springs Hagerman, ID 8 51 (g) Wind Intermittent 9 (f) Greensburg Greensburg, KS 10 51 (g) Wind Intermittent 6 (f) Three Mile Canyon Boardman, OR 6 51 (g) Wind Intermittent 5 (f) Loess Hills Rock Port, MO 4 Wind Intermittent 5 Denver Airport Solar Denver, CO 1 51 (g) Solar Intermittent 2 (f) 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 34 (f) West Medway II West Medway, MA 2 Oil/Gas Peaking 191 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 3,265 Total 32,355 __________ (a) All nuclear stations are boiling water reactors except Braidwood, Byron, Calvert Cliffs, Ginna, and Salem, which are pressurized water reactors. (b) 100%, unless otherwise indicated. (c) Base-load units are plants 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 plants with output controlled by the natural variability of the energy resource rather than dispatched based on system requirements. Intermediate units are plants 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) 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 facilities 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) Net generation capacity is stated at proportionate ownership share. (g) 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. (h) We have deactivated the site and are evaluating for potential return of service or retirement beyond 2023. (i) We wholly own Nine Mile Point Unit 1 and have an 82% undivided ownership interest in Nine Mile Point Unit 2. 45 Table of Contents (j) 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. 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 and Contingencies of the Combined Notes to Consolidated Financial Statements. Such descriptions are incorporated herein by these references. ITEM 4. MINE SAFETY DISCLOSURES Not Applicable 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, 2023 there were 327,131,082 shares of common stock outstanding and approximately 75,145 record holders of common stock. Stock Performance Graph The performance graph below illustrates a one-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 year 2022. 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 in 2022 2/1 12/31 CEG $100 $175 S&P 500 $100 $86 UTY $100 $107 Constellation As of January 31, 2023, 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. 47 Table of Contents Our Board of Directors approved an updated dividend policy for 2023. The 2023 quarterly dividend will be $0.2820 per share. The following table sets forth Constellation’s quarterly cash dividends per share paid during 2022. Fourth Quarter Third Quarter Second Quarter First Quarter $ 0.1410 $ 0.1410 $ 0.1410 $ 0.1410 First Quarter 2023 Dividend On February 15, 2023, our Board of Directors declared a regular quarterly dividend of $0.2820 per share on our common stock for the first quarter of 2023. The dividend is payable on Friday, March 10, 2023, to shareholders of record as of 5 p.m. Eastern time on Monday, February 27, 2023. Unregistered Sales of Equity Securities None. Issuer Purchases of Equity Securities None. ITEM 6. RESERVED Not Applicable 48 Table of Contents Item 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (Dollars in millions, unless otherwise noted) Executive Overview We are a supplier of clean 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, 2022 compared to the year ended December 31, 2021. For discussion of the year ended December 31, 2021 compared to the year ended December 31, 2020, refer to ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS in the 2021 Form 10-K, which was filed with the SEC on February 25, 2022. Capital Allocation and Growth Announcements We are announcing our capital allocation strategy for 2023 and 2024 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 double the annual dividend in 2023 from $0.5640 per share to $1.1280 per share while targeting growth of 10% annually. We are allocating capital towards our best-in-class generation fleet by committing $1.5 billion of growth capital expenditures over the next three years, including nuclear uprates, wind repowering and hydrogen. These organic growth opportunities are projected to exceed our double-digit return threshold. In our commitment to return value to shareholders, we have also authorized a share buyback program of $1.0 billion. Significant 2022 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 $140 million and $49 million for the twelve months ended December 31, 2022 and 2021, respectively, which are primarily recorded in Operating and maintenance expense. We expect to incur incremental costs of approximately $80 million in 2023. 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. PJM Performance Bonuses On December 23, 2022, and continuing through the morning of December 25, 2022, winter storm Elliott blanketed the entirety of PJM’s footprint with record low temperatures and extreme weather conditions. A significant portion of PJM's fossil generation fleet failed to perform as reserves were called. PJM’s initial estimate of non-performance charges ranges from $1 billion to $2 billion and, in accordance with its tariff, funds collected from those charges are redistributed to generating resources that performed above expectations during the event. PJM released preliminary invoices to generators subject to non-performance charges and bonuses on February 10, 2023. PJM indicated that these preliminary invoices are informational and subject to change for items that could have a material impact to the final amounts billed to non-performing generators, pending PJM’s 49 Table of Contents completion of their internal processes and data quality assurance reviews. Leveraging preliminary data from PJM and applying significant judgments and assumptions, we recognized an estimated benefit of $109 million (pre-tax) for performance bonuses (net of non-performance charges), primarily driven by the overperformance of our nuclear fleet. The ultimate impact to our consolidated financial statements may be affected by several factors, including final non-performance charges billed, the impacts of generator defaults, and related litigation and disputes. It is reasonably possible that the ultimate benefit could differ significantly once these uncertainties are resolved, which could have a material impact on our financial statements. Other Key Business Drivers Russia and Ukraine Conflict We are closely monitoring developments of the Russia and Ukraine conflict including United States sanctions against Russian energy exports, the potential for sanctions on Russian nuclear fuel supply, and enrichment activities, as well as yet undefined action by 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 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. Hedging Strategy We are exposed to commodity price risk associated with the unhedged portion of our electricity portfolio. We enter into non-derivative and derivative contracts, including options, swaps, and forward and futures contracts, all with credit-approved counterparties, to hedge this anticipated exposure. For merchant revenues not already hedged via comprehensive state programs, such as the CMC in Illinois, we typically utilize a three-year ratable sales plan to align our hedging strategy with our financial objectives. The prompt three-year merchant revenues are hedged on an approximate rolling 90%/60%/30% basis. We may also enter into transactions that are outside of this ratable hedging program. As of December 31, 2022, the percentage of expected generation hedged for the Mid-Atlantic, Midwest, New York, and ERCOT reportable segments is 94%-97% and 75%-78% for 2023 and 2024, respectively. We have been and will continue to be proactive in using hedging strategies to mitigate commodity price risk. 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, and contracted fuel fabrication services. The supply markets for uranium concentrates and certain nuclear fuel services are subject to price fluctuations and availability restrictions. Approximately 60% of our uranium concentrate requirements from 2023 through 2027 are supplied by three suppliers. 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 sanctions against Russia, have the potential to impact delivery from multiple suppliers in the international uranium processing industry. Non-performance by these counterparties could have a material adverse impact on our consolidated financial statements. See Note 16 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements and ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK for additional information. 50 Table of Contents 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 $12.5 billion at December 31, 2022. 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. 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. 51 Table of Contents 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 assumed plant shutdown timing scenarios include the following four alternatives: (1) the probability of operating through the original 40-year nuclear license term, (2) the probability of operating through an initial 20-year license renewal term, (3) the probability of a second, 20-year license renewal term, and (4) the probability of early plant retirement for certain sites due to changing market conditions and regulatory environments. 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 credit-adjusted, risk-free rates (CARFR) applicable to the various businesses in which each of the nuclear units originally operated. 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 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 $12.5 billion to approximately $10.5 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, 2022 2021 CARFR rather than the 2022 CARFR $ 3,470 2022 CARFR increased by 50 basis points (570) 2022 CARFR decreased by 50 basis points 710 52 Table of Contents 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, 2022 Cost escalation studies Uniform increase in escalation rates of 50 basis points $ 1,780 Probabilistic cash flow models Increase the estimated costs to decommission the nuclear plants by 10 percent 720 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) 280 Extend the estimated date for DOE acceptance of SNF to 2040 (70) __________ (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. Unamortized Energy Contract Assets and Liabilities Unamortized energy contract assets and liabilities represent the remaining unamortized balances of non-derivative energy 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 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 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 renewables). 53 Table of Contents 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 (Level 3), 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. 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. 54 Table of Contents NPNS. As part of our energy marketing business, we enter contracts to buy and sell energy to meet the requirements of our customers. These contracts include short-term and long-term commitments to purchase and sell energy and energy-related products in the retail and wholesale markets with the intent and ability to deliver or take delivery. While some of these contracts are considered derivative financial instruments under the authoritative guidance, certain of these qualifying transactions have been designated as NPNS transactions, and 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. Contracts that qualify for NPNS are those for which physical delivery is probable, quantities are expected to be used or sold in the normal course of business over a reasonable period, and the contract is not financially settled on a net basis. Revenues and expenses on contracts that qualify as NPNS are recognized when the underlying physical transaction is completed. 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 nonperformance risk, including credit risk in the valuation of derivative contracts, and both historical and current market data in our assessment of nonperformance risk. The impacts of nonperformance 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 18 — Fair Value of Financial Assets and Liabilities and Note 16 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information regarding derivative instruments. Defined Benefit Pension and Other Postretirement Employee Benefits We sponsor defined benefit pension and OPEB plans for most current employees. 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. 55 Table of Contents 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. 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, 2022, 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 2023 cost: Discount rate (a) 5.52 % 5.50 % 0.5 % $ (13) $ (1) $ (14) 5.52 % 5.50 % (0.5) % 16 2 18 EROA 6.50 % 6.50 % 0.5 % (40) (4) (44) 6.50 % 6.50 % (0.5) % 40 4 44 Change in benefit obligation: Discount rate (a) 5.52 % 5.50 % 0.5 % (345) (61) (406) 5.52 % 5.50 % (0.5) % 391 69 460 __________ (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. 56 Table of Contents 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 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. Upon separation, we now maintain insurance coverage for general liability, automotive liability, and workers’ compensation and are self-insured to the extent that losses are within policy deductibles or exceed the amount of insurance maintained. For personal injury claims, we 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: the sale of power and energy-related products, such as natural gas, capacity, and other 57 Table of Contents commodities in non-regulated markets (wholesale and retail) and the provision of other energy-related non-regulated products and services. 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 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 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 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 Loss Attributable to Common Shareholders for the twelve months ended December 31, 2022 compared to the same period in 2021. For additional information regarding the financial results for the twelve months ended December 31, 2022 and 2021 see the discussions of Results of Operations below. Twelve Months Ended December 31, Favorable Variance 2022 2021 GAAP Net Loss Attributable to Common Shareholders $ (160) $ (205) $ 45 Adjusted EBITDA (non-GAAP). In analyzing and planning for our business, we supplement our use of GAAP Net 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 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 loss attributable to common shareholders as determined in accordance with GAAP and Adjusted EBITDA (non-GAAP) for the twelve months ended December 31, 2022 compared to the same period in 2021. Twelve Months Ended December 31, 2022 2021 Net Loss Attributable to Common Shareholders $ (160) $ (205) Income Taxes (a) (339) 225 Depreciation and Amortization (b) 1,091 3,003 Interest Expense, Net 251 297 Unrealized Loss (Gain) on Fair Value Adjustments (c) 1,058 (420) Asset Impairments (d) — 541 Plant Retirements and Divestitures (11) (4) Decommissioning-Related Activities (e) 820 (1,289) Pension & OPEB Non-Service Credits (116) (50) Separation Costs (f) 140 49 COVID-19 Direct Costs (g) — 35 Acquisition-Related Costs (h) — 21 ERP System Implementation Costs (i) 22 14 Change in Environmental Liabilities 10 12 Cost Management Program — 9 Prior Merger Commitment (j) (50) — Noncontrolling Interests (k) (49) (53) Adjusted EBITDA (non-GAAP) $ 2,667 $ 2,185 __________ (a) In 2022, includes amounts contractually owed to Exelon under the Tax Matters Agreement (TMA) reflected in Other, net. (b) In 2021, includes the accelerated depreciation associated with early plant retirements. (c) Includes mark-to-market on economic hedges and fair value adjustments related to gas imbalances and equity investments. (d) Reflects an impairment in the New England asset group, an impairment recorded as a result of the sale of the Albany Green Energy biomass facility, and impairment of a wind project. (e) Reflects all gains and losses associated with NDTs, ARO accretion, ARO remeasurement, and any earnings neutral impacts of contractual offset for Regulatory Agreement Units. (f) 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 Transition Services Agreement (TSA). (g) Represents direct costs related to COVID-19 consisting primarily of costs to acquire personal protective equipment, costs for cleaning supplies and services, and costs to hire healthcare professionals to monitor the health of employees. (h) Reflects costs related to the acquisition of EDF's interest in CENG, which was completed in the third quarter of 2021. (i) Reflects costs related to a multi-year ERP system implementation. (j) Reversal of a charge related to a prior 2012 merger commitment. (k) Reflects elimination from results for the noncontrolling interests related to certain adjustments. In 2022, primarily relates to CRP and in 2021, primarily relates to CENG and the noncontrolling interest portion of a wind project impairment recognized within CRP. 59 Table of Contents Results of Operations 2022 2021 Favorable (Unfavorable) Variance Operating revenues $ 24,440 $ 19,649 $ 4,791 Operating expenses Purchased power and fuel 17,462 12,163 (5,299) Operating and maintenance 4,841 4,555 (286) Depreciation and amortization 1,091 3,003 1,912 Taxes other than income taxes 552 475 (77) Total operating expenses 23,946 20,196 (3,750) Gain on sales of assets and businesses 1 201 (200) Operating income (loss) 495 (346) 841 Other income and (deductions) Interest expense, net (251) (297) 46 Other, net (786) 795 (1,581) Total other income and (deductions) (1,037) 498 (1,535) (Loss) income before income taxes (542) 152 (694) Income taxes (388) 225 613 Equity in losses of unconsolidated affiliates (13) (10) (3) Net loss (167) (83) (84) Net (loss) income attributable to noncontrolling interests (7) 122 (129) Net loss attributable to common shareholders $ (160) $ (205) $ 45 Year Ended December 31, 2022 Compared to Year Ended December 31, 2021. Net loss attributable to common shareholders was favorable by $45 million primarily due to: • The absence of accelerated depreciation and amortization associated with our previous decision in the third quarter of 2020 to early retire Byron and Dresden nuclear facilities in 2021, a decision which was reversed on September 15, 2021, and the absence of the reversal of charges recorded in the third quarter of 2021 associated with the reversal of the previous decision; • The absence of impacts from the February 2021 extreme cold weather event; • The absence of impairments of the New England asset group, the Albany Green Energy biomass facility, and a wind project; • Impact of our annual update to the nuclear ARO for Non-Regulatory Agreement Units; • Lower nuclear fuel costs primarily due to the absence of accelerated amortization of nuclear fuel and lower prices; • Higher realized energy prices; • Favorable PJM performance bonus payment, net of non-performance charges; • The reversal of a charge related to a 2012 prior merger commitment; and • Favorable impacts of nuclear outages. The favorable items were partially offset by: • Unfavorable mark-to-market activity; • Unfavorable net realized and unrealized NDT activity; 60 Table of Contents • Lower capacity revenues; • Higher labor, contracting and materials; • Unfavorable impact of net realized and unrealized CTV investment activity; • Higher separation costs; • Lower NEIL distributions; and • The absence of a prior year gain on the sale of our solar business. 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 ISO/RTO and/or NERC regions, which utilize multiple supply sources to provide electricity through various distribution channels (wholesale and retail). Our hedging strategies and risk metrics are also aligned 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. 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. For the year ended December 31, 2022 compared to 2021, Operating revenues by region were as follows: 2022 vs. 2021 2022 2021 Variance % Change (a) Mid-Atlantic $ 5,164 $ 4,584 $ 580 12.7 % Midwest 4,650 4,060 590 14.5 % New York 1,595 1,575 20 1.3 % ERCOT 1,543 1,181 362 30.7 % Other Power Regions 6,732 4,890 1,842 37.7 % Total electric revenues 19,684 16,290 3,394 20.8 % Other 5,944 3,992 1,952 48.9 % Mark-to-market losses (1,188) (633) (555) Total Operating revenues $ 24,440 $ 19,649 $ 4,791 24.4 % __________ (a) % Change in mark-to-market is not a meaningful measure. 61 Table of Contents Sales and Supply Sources. Our sales and supply sources by region are summarized below: 2022 vs. 2021 Supply Source (GWhs) 2022 2021 Variance % Change Nuclear Generation (a) Mid-Atlantic 53,214 53,589 (375) (0.7) % Midwest 95,090 93,107 1,983 2.1 % New York (b) 25,046 26,294 (1,248) (4.7) % Total Nuclear Generation 173,350 172,990 360 0.2 % Natural Gas, Oil and Renewables Mid-Atlantic 2,097 2,271 (174) (7.7) % Midwest 1,202 1,083 119 11.0 % New York — 1 (1) (100.0) % ERCOT 14,124 13,187 937 7.1 % Other Power Regions 10,189 9,995 194 1.9 % Total Natural Gas, Oil and Renewables 27,612 26,537 1,075 4.1 % Purchased Power Mid-Atlantic 15,366 13,576 1,790 13.2 % Midwest 610 561 49 8.7 % ERCOT 3,575 3,256 319 9.8 % Other Power Regions 51,131 50,212 919 1.8 % Total Purchased Power 70,682 67,605 3,077 4.6 % Total Supply/Sales by Region Mid-Atlantic 70,677 69,436 1,241 1.8 % Midwest 96,902 94,751 2,151 2.3 % New York (b) 25,046 26,295 (1,249) (4.7) % ERCOT 17,699 16,443 1,256 7.6 % Other Power Regions 61,320 60,207 1,113 1.8 % Total Supply/Sales by Region 271,644 267,132 4,512 1.7 % __________ (a) Includes the proportionate share of output where we have an undivided ownership interest in jointly-owned generating plants. Includes the total output for fully owned plants and the total output for CENG prior to the acquisition of EDF’s interest on August 6, 2021 as CENG was fully consolidated. See Note 2 — Mergers, Acquisitions, and Dispositions of the Combined Notes to Consolidated Financial Statements for additional information on our acquisition of EDF’s interest in CENG. (b) 2021 values have been revised from those previously reported to correctly reflect our 82% undivided ownership interest in Nine Mile Point Unit 2. 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, which is operated by PSEG. 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. 2022 2021 Nuclear fleet capacity factor 94.8 % 94.5 % Refueling outage days 212 262 Non-refueling outage days 54 34 62 Table of Contents 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, 2022 and 2021. 2022 vs. 2021 State (Region) (a) 2022 2021 Variance % Change New Jersey (Mid-Atlantic) $ 10.00 $ 10.00 $ — — % Illinois (Midwest) 13.88 16.50 (2.62) (15.9) % New York (New York) 21.38 20.93 0.45 2.2 % __________ (a) See Note 7 — Early Plant Retirements of the Combined Notes to Consolidated Financial Statements for additional information on the plants receiving payments through state programs. 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). 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. For the year ended December 31, 2022 the average CMC price per MWh was a net negative value ($42.20). See Note 3 - Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information on the Illinois CMC program. Capacity Prices. We participate in capacity auctions in each of our major regions, except ERCOT which does not have a capacity market. We also incur capacity costs associated with load served, which are factored into customer sales prices. Capacity prices have a significant impact on our operating revenues and purchased power and fuel expense. We report capacity on a net monthly basis within each region in either Operating revenues or Purchased power and fuel expense, depending on our net monthly position. The following table presents the average capacity prices ($/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, 2022 and 2021. 2022 vs. 2021 Location (Region) 2022 2021 Variance % Change Eastern Mid-Atlantic Area Council (Mid-Atlantic and Midwest) $ 126.14 $ 174.96 $ (48.82) (27.9) % ComEd (Midwest) 121.71 192.45 (70.74) (36.8) % Rest of State (New York) 85.36 98.35 (12.99) (13.2) % Southeast New England (Other) 138.21 163.66 (25.45) (15.6) % 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. 63 Table of Contents 2022 vs. 2021 Location (Region) 2022 2021 Variance % Change PJM West (Mid-Atlantic) $ 72.90 $ 38.91 $ 33.99 87.4 % ComEd (Midwest) 60.24 34.76 25.48 73.3 % Central (New York) 57.52 29.90 27.62 92.4 % North (ERCOT) 64.38 146.63 (82.25) (56.1) % Southeast Massachusetts (Other) (a) 86.02 46.38 39.64 85.5 % __________ (a) Reflects New England, which comprises the majority of the activity in the Other region. For the year ended December 31, 2022 compared to 2021, changes in Operating revenues by region were approximately as follows: 2022 vs. 2021 Variance % Change (a) Description Mid-Atlantic $ 580 12.7 % • favorable retail load revenue of $525 primarily due to higher energy prices • favorable wholesale load revenue of $360 primarily due to higher volumes and energy prices; partially offset by • unfavorable settled economic hedges of ($280) due to settled prices relative to hedged prices Midwest 590 14.5 % • favorable net wholesale load and generation revenue of $630 primarily due to higher nuclear generation and energy prices, partially offset by CMC program activity and the absence of net capacity revenue • favorable retail load revenue of $275 primarily due to higher energy prices • favorable PJM performance bonuses of $116 due to generation performance against capacity requirements during December 2022 weather event; partially offset by • unfavorable settled economic hedges of ($430) due to settled prices relative to hedged prices New York 20 1.3 % • favorable retail load revenue of $295 primarily due to higher energy prices • favorable generation revenue of $150 due to higher energy prices, partially offset by lower nuclear generation due to an increase in outage days; partially offset by • unfavorable settled economic hedges of ($410) due to settled prices relative to hedged prices ERCOT 362 30.7 % • favorable settled economic hedges of $340 due to settled prices relative to hedged prices • favorable retail load revenue of $115 primarily due to higher volumes partially offset by lower energy prices relative to the prior year due to the February 2021 extreme cold weather event; partially offset by • unfavorable wholesale load revenue of ($70) primarily due to lower energy prices relative to the prior year due to the February 2021 extreme cold weather event Other Power Regions 1,842 37.7 % • favorable wholesale load revenue of $820 due to higher energy prices and volumes • favorable settled economic hedges of $540 due to settled prices relative to hedged prices • favorable retail load revenue of $430 due to higher energy prices and volumes 64 Table of Contents Other 1,952 48.9 % • favorable gas revenue, including settled financial hedges, of $1,655 primarily due to higher gas prices • favorable energy revenue of $370 primarily due to higher energy prices; partially offset by • unfavorable impact due to the absence of the customer pass through impact of LDC and pipeline penalties due to the February 2021 extreme cold weather event of ($70) Mark-to-market (b) (555) • losses on economic hedging activities of ($1,188) in 2022 compared to losses of ($633) in 2021 Total $ 4,791 24.4 % __________ (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. 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 purchased power and fuel expense or results of operations, and accelerated nuclear fuel amortization associated with nuclear decommissioning. For the year ended December 31, 2022 compared to 2021, Purchased power and fuel expense by region were as follows: 2022 vs. 2021 2022 2021 Variance % Change (a) Mid-Atlantic $ 3,026 $ 2,320 $ (706) (30.4) % Midwest 1,886 1,343 (543) (40.4) % New York 528 414 (114) (27.5) % ERCOT 1,136 2,006 870 43.4 % Other Power Regions 5,811 3,999 (1,812) (45.3) % Total electric purchased power and fuel 12,387 10,082 (2,305) (22.9) % Other 5,250 3,279 (1,971) (60.1) % Mark-to-market gains (175) (1,198) (1,023) Total purchased power and fuel $ 17,462 $ 12,163 $ (5,299) (43.6) % __________ (a) % Change in mark-to-market is not a meaningful measure. 65 Table of Contents For the year ended December 31, 2022 compared to 2021, changes in Purchased power and fuel expense by region were approximately as follows: 2022 vs. 2021 Variance % Change (a) Description Mid-Atlantic $ (706) (30.4) % • unfavorable purchased power and net capacity impact of ($660) primarily due to higher energy prices, higher load, and lower capacity prices earned • unfavorable PJM net non-performance charges of ($7) due to generation performance against capacity requirements during December 2022 weather event Midwest (543) (40.4) % • unfavorable purchased power and net capacity impact of ($590) primarily due to higher energy prices, lower capacity prices earned, and lower cleared capacity volumes; partially offset by • favorable nuclear fuel cost of $65 primarily due to the absence of accelerated amortization of nuclear fuel and lower nuclear fuel prices in the prior year New York (114) (27.5) % • unfavorable purchased power and net capacity impact of ($190) primarily due to higher energy prices, lower nuclear generation and lower capacity prices earned; partially offset by • favorable settlement of economic hedges of $90 due to settled prices relative to hedged prices ERCOT 870 43.4 % • favorable purchased power of $635 primarily due to lower energy prices relative to the prior year due to the February 2021 extreme cold weather event • favorable settlement of economic hedges of $140 due to settled prices relative to hedged prices • favorable fuel cost of $80 primarily due to lower gas prices relative to the prior year due to the February 2021 extreme cold weather event Other Power Regions (1,812) (45.3) % • unfavorable purchased power and net capacity impact of ($2,180) primarily due to higher energy prices, higher load, lower cleared capacity volumes and lower capacity prices earned • unfavorable fuel cost of ($400) primarily due to higher gas prices • unfavorable environmental products activity of ($415) primarily driven by lower optimization and higher RPS costs; partially offset by • favorable settlement of economic hedges of $1,210 due to settled prices relative to hedged prices Other (1,971) (60.1) % • unfavorable net gas purchase costs and settlement of economic hedges of ($1,885) • unfavorable energy purchases of ($290) primarily due to higher energy prices • unfavorable fair value adjustment related to gas imbalances of ($50); partially offset by • favorable impact due to the absence of LDC and pipeline penalties due to the February 2021 extreme cold weather event of $110 • favorable impact due to the absence of accelerated nuclear fuel amortization associated with announced early plant retirements of $150 66 Table of Contents Mark-to-market (b) (1,023) • gains on economic hedging activities of $175 in 2022 compared to gains of $1,198 in 2021 Total $ (5,299) (43.6) % __________ (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: 2022 vs. 2021 Increase (Decrease) Labor, other benefits, contracting, and materials (a) $ 317 Decommissioning-related activities (b) 298 NEIL insurance distributions 83 Plant retirements and divestitures (c) 78 Separation costs (d) 74 Loss on sale of receivables 33 Nuclear refueling outage costs, including the co-owned Salem plants 32 Credit loss expense (e) (23) Covid-19 direct costs (35) Prior merger commitment (f) (50) Asset impairments (541) Other 20 Total increase $ 286 __________ (a) Primarily reflects increased employee-related costs, including labor, stock-based compensation, and other incentives, etc. (b) Primarily reflects contractual offset of accelerated depreciation and amortization associated with our previous decision to early retire the Byron and Dresden nuclear facilities. See Note 10 — Asset Retirement Obligations of the Combined Notes to Consolidated Financial Statements for additional information. (c) Reflects the absence of the reversal of charges recorded in 2021 associated with the reversal of the previous decision to early retire Byron and Dresden. (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) Primarily a result of the February 2021 extreme cold weather event. (f) Reversal of a charge related to a prior merger commitment. Depreciation and amortization expense decreased for the year ended December 31, 2022 compared to the same period in 2021, primarily due to the accelerated depreciation and amortization associated with our previous decision to early retire the Byron and Dresden nuclear facilities. This decision was reversed on September 15, 2021 and depreciation for Byron and Dresden was adjusted beginning September 15, 2021 to reflect the extended useful life estimates. A portion of this accelerated depreciation and amortization is offset in Operating and maintenance expense. Gain on sales of assets and businesses decreased for the year ended December 31, 2022 compared to the same period in 2021, primarily due to gains on sales of equity investments and a gain on sale of our solar business which were recognized in 2021. Interest expense, net decreased for the year ended December 31, 2022 compared to the same period in 2021, primarily due to mark-to-market gains related to our CR and West Medway II interest rate swaps and the retirement of long-term debt in March 2022 . See Note 17 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information on the CR credit facility and interest rate swaps. Other, net decreased for the year ended December 31, 2022 compared to the same period in 2021, due to activity described in the table below: 67 Table of Contents 2022 2021 Net unrealized (losses) gains on NDT funds (a) $ (798) $ 204 Net realized gains on sale of NDT funds (a) 4 381 Interest and dividend income on NDT funds (a) 93 98 Contractual elimination of income tax (expense) benefit (b) (201) 226 Non-service net periodic benefit credit (c) 110 — Net realized and unrealized losses from equity investments (d) (13) (160) Return to provision adjustment (e) (49) — TSA billings (f) 44 — Other 24 46 Total Other, net $ (786) $ 795 _________ (a) Unrealized gains, realized gains, and interest and dividend income on the NDT funds are associated with the Non-Regulatory Agreement Units. (b) Contractual elimination of income tax (expense) benefit is associated with the income taxes on the NDT funds of the Regulatory Agreement Units. (c) Historically, we were allocated our portion of pension and OPEB non-service credit (cost) 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. (d) For 2022, includes net realized and unrealized (losses) gains from equity investments. For 2021, includes net unrealized (losses) gains from equity investments. (e) 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. (f) 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 71.6% and 148% for the years ended December 31, 2022 and 2021, respectively. The change in effective tax rate in 2022 is primarily due to the impacts of higher unrealized NDT losses on Income before income taxes and one-time income tax adjustments. See Note 14 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information. Net (loss) income attributable to noncontrolling interests primarily relates to CRP for the year ended December 31, 2022 and includes CENG and CRP for the same period in 2021. The decrease for the year ended December 31, 2022 for the same period in 2021 is primarily due to our acquisition of EDF's interest in CENG on August 6, 2021. See Note 2 — Mergers, Acquisitions, and Dispositions of the Combined Notes to Consolidated Financial Statements for additional information. Liquidity and Capital Resources For discussion of the year ended December 31, 2021 compared to the year ended December 31, 2020, refer to Liquidity and Capital Resources of MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS in the 2021 Form 10-K which was filed with the SEC on February 25, 2022. 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 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 68 Table of Contents 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 $5.8 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 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, 2022, 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. 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. 69 Table of Contents The following table provides a summary of the change in cash flows from operating activities for the years ended December 31, 2022 and 2021: For the Years Ended December 31, (Decrease) increase in cash flows from operating activities 2022 2021 Change Net loss $ (167) $ (83) $ (84) Adjustments to reconcile net loss to cash: Changes in working capital and other noncurrent assets and liabilities (a) (5,246) (3,608) (1,638) Collateral posted, net (351) (130) (221) Pension and non-pension postretirement benefit contributions (237) (259) 22 Option premiums paid, net (177) (338) 161 Total non-cash operating activities (b) 3,825 3,080 745 Decrease in cash flows from operating activities $ (2,353) $ (1,338) $ (1,015) __________ (a) Includes changes in Accounts receivable, Receivables from and payables to affiliates, 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 2022 and 2021 were as follows: • A reduction in cash inflows for changes in working capital and other noncurrent assets and liabilities primarily driven by activity related to the accounts receivable Facility, due to higher retail power sales and associated accounts receivables sold relative to the maximum funding limit of the Facility, partially offset by an increase in cash inflows from the Collection of DPP, net in Cash Flows from investing activities, which can be seen in the Cash Flows from Investing Activities section below. See Note 6 — Accounts Receivable of the Combined Notes to Consolidated Financial Statements for additional information on the sales of customer accounts receivables. • 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 prices. Note 16 — Derivative Financial Instruments of the Notes to Consolidated Financial Statements for additional information on derivative contracts. 70 Table of Contents 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, 2022 and 2021: For the Years Ended December 31, (Decrease) increase in cash flows from investing activities 2022 2021 Change Proceeds from sales of assets and businesses $ 52 $ 878 $ (826) Capital expenditures (1,689) (1,329) (360) Investment in NDT funds, net (221) (141) (80) Collection of DPP, net 4,964 3,902 1,062 Other investing activities (2) (28) 26 Decrease in cash flows from investing activities $ 3,104 $ 3,282 $ (178) Significant investing cash flow impacts for 2022 and 2021 were as follows: • Proceeds from sales of assets and businesses decreased primarily due to the sale of a significant portion of our solar business, sale of a biomass facility and proceeds received on sales of equity investments in 2021. See Note 2 — Mergers, Acquisitions, and Dispositions of the Combined Notes to Consolidated Financial Statements for additional information on the sale of our solar business and biomass facility. • Variances in capital expenditures are primarily due to the timing of cash expenditures 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 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 2022 compared to 2021. 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, 2022 and 2021: For the Years Ended December 31, Increase (decrease) in cash flows from financing activities 2022 2021 Change Distributions to Exelon $ — $ (1,832) $ 1,832 Contributions from Exelon 1,750 64 1,686 Acquisition of CENG noncontrolling interest — (885) 885 Change in money pool with Exelon — (285) 285 Dividends paid on common stock (185) — (185) Long-term debt, net (1,406) 47 (1,453) Changes in short-term borrowings, net (923) 1,242 (2,165) Other financing activities (35) (46) 11 Increase in cash flows from financing activities $ (799) $ (1,695) $ 896 Significant financing cash flow impacts for 2022 and 2021 were as follows: • Distributions to Exelon is related to distributions made prior to separation. See Note 1 — Basis of Presentation of the Combined Notes to Consolidated Financial Statements for additional information on the separation. 71 Table of Contents • 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. • See Note 2 — Mergers, Acquisitions, and Dispositions of the Combined Notes to Consolidated Financial Statements for additional information related to the acquisition of CENG noncontrolling interest. • Change in money pool with Exelon were driven by short-term borrowing needs prior to the separation on February 1, 2022. Exelon operated a money pool for its subsidiaries that provided an additional short-term borrowing option that was generally more favorable to the borrowing participants than the cost of external financing. • 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. • 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. 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 2022 and 2021 was as follows: 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 2021, the following long-term debt was issued: Type Interest Rate Maturity Amount Use of Proceeds West Medway II Nonrecourse Debt (a) 1 month LIBOR + 3% (b) March 31, 2026 $ 150 Funding for general corporate purposes. Energy Efficiency Project Financing (c) 2.53% - 4.24% January 31, 2022 - February 28, 2022 2 Funding to install energy conservation measures. __________ (a) See Note 17 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information of nonrecourse debt. (b) The nonrecourse debt has an average blended interest rate. (c) For Energy Efficiency Project Financing, the maturity dates represent the expected date of project completion, upon which the respective customer assumes the outstanding debt. 72 Table of Contents 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 __________ (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. During 2021, the following long-term debt was retired and/or redeemed: Type (a) Interest Rate Maturity Amount Continental Wind Nonrecourse Debt (b) 6.00% February 28, 2033 $ 35 CR Nonrecourse Debt (b) 3-month LIBOR + 2.50% (c) December 15, 2027 17 SolGen Nonrecourse Debt (b) 3.93% September 30, 2036 7 Antelope Valley DOE Nonrecourse Debt (b)(d) 2.29% - 3.56% January 5, 2037 24 West Medway II Nonrecourse Debt (b) LIBOR + 3% (e) March 31, 2026 13 RPG Nonrecourse Debt (b) 4.11% March 31, 2035 9 __________ (a) As part of the 2012 merger, Exelon entered intercompany loan agreements that mirrored the terms and amounts of third-party debt obligations. In connection with the separation, on January 31, 2022, we paid cash to Exelon Corporate of $258 million to settle the intercompany loan. See Note 17 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information on the mirror debt. (b) See Note 17 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information on nonrecourse debt. (c) The interest rate was amended to 3-month LIBOR + 2.50% on June 16, 2021. (d) On January 5, 2022, we redeemed $6 million of 2.29% - 3.56% Antelope Valley DOE nonrecourse debt. (e) The nonrecourse debt has an average blended interest rate. 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 the twelve months ended December 31, 2022 and for the first quarter of 2023 were as follows: Period Declaration Date Shareholder of Record Date Dividend Payable Date Cash per Share First Quarter of 2022 February 8, 2022 February 25, 2022 March 10, 2022 $ 0.1410 Second Quarter of 2022 April 26, 2022 May 13, 2022 June 10, 2022 $ 0.1410 Third Quarter of 2022 July 26, 2022 August 15, 2022 September 9, 2022 $ 0.1410 Fourth Quarter of 2022 October 31, 2022 November 15, 2022 December 9, 2022 $ 0.1410 First Quarter of 2023 February 15, 2023 February 27, 2023 March 10, 2023 $ 0.2820 73 Table of Contents Credit Matters and Cash Requirements We fund liquidity needs for capital expenditures, working capital, energy hedging and other financial commitments through cash flows from operations, public debt offerings, commercial paper markets and large, diversified credit facilities. As of December 31, 2022, we have access to facilities with aggregate bank commitments of $5.8 billion. We had access to the commercial paper markets and had availability under our revolving credit facilities during 2022 to fund our short-term liquidity needs, when necessary. We used our available credit facilities to manage short-term liquidity needs as a result of the impacts of the February 2021 extreme cold weather event. 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 rating as of December 31, 2022, we would have been required to provide incremental collateral estimated to be approximately $3.3 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 significant reduction in credit ratings from their current levels of BBB and Baa2 at S&P and Moody's, respectively, to BB+ and Ba1 or below. As of December 31, 2022, we had $2.2 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. Capital Expenditures Our most recent estimate of capital expenditures is approximately $2.6 billion for 2023 and approximately $5.0 billion for the period from 2024 to 2025. Approximately 45-47% 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. 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. Additionally, the above estimate of capital expenditures includes $1.5 billion of growth capital expenditures, including nuclear uprates, wind repowering, and hydrogen. See ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS, Executive Overview for additional information. The remaining amounts primarily reflect additions and upgrades to existing generation facilities (including material condition improvements during nuclear refueling outages). 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 solutions, 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 . 74 Table of Contents 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 2023 (including our benefit payments related to unfunded plans): Qualified Pension Plans Non-Qualified Pension Plans OPEB Planned contributions $ 21 $ 10 $ 17 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. Cash Requirements for Other Financial Commitments The following table summarizes our future estimated cash payments as of December 31, 2022 under existing financial commitments: 2023 Beyond 2023 Total Time Period Long-term debt $ 143 $ 4,507 $ 4,650 2023 - 2042 Interest payments on long-term debt (a) 225 2,448 2,673 2023 - 2042 Operating leases (b) 54 502 556 2023 - 2066 Purchase power obligations (c) 825 964 1,789 2023 - 2033 Fuel purchase agreements (d) 1,288 6,457 7,745 2023 - 2036 Other purchase obligations (e) 1,289 1,815 3,104 2023 - 2046 SNF obligation — 1,230 1,230 2023 - 2035 Pension contributions (f) 21 183 204 2023 - 2028 Total cash requirements $ 3,845 $ 18,106 $ 21,951 __________ (a) Interest payments are estimated based on final maturity dates of debt securities outstanding at December 31, 2022 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, 2022. (b) Capacity payments associated with contracted generation lease agreements are net of sublease and capacity offsets of $47 million and $322 million for 2023 and beyond 2023, respectively and $369 million in total. 75 Table of Contents (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, natural gas and related transportation, storage capacity and services. (e) Represents the future estimated value at December 31, 2022 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 2028 are not included. See Note 19 — Commitments and Contingencies and Note 3 — Regulatory Matters 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 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. 76 Table of Contents Capital Structure At December 31, 2022, our capital structure consisted of the following: Percentage of Capital Structure Commercial paper and notes payable 7 % Long-term debt 27 % Member’s equity 66 % 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. ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK We are exposed to market risks associated with adverse changes in commodity prices, counterparty credit, interest rates, and equity prices. We manage these risks through risk management policies and objectives for risk assessment, control and valuation, counterparty credit approval, and the monitoring and reporting of risk exposures. After the separation on February 1, 2022, reporting on risk management issues is to the Executive Committee, the Risk Management Committees of our generation and customer-facing businesses, 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 into 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 2023 through 2025. In general, increases and decreases in forward market prices have a positive and negative impact, respectively, on our owned and contracted generation positions which have not been hedged. For merchant generation sales 77 Table of Contents not already hedged via comprehensive state programs, such as the CMC in Illinois, we typically utilize a three-year ratable sales plan to align our hedging strategy with our financial objectives. The prompt three-year merchant sales are hedged on an approximate rolling 90%/60%/30% basis. We may also enter transactions that are outside of this ratable hedging program. As of December 31, 2022, the percentage of expected generation hedged for the Mid-Atlantic, Midwest, New York, and ERCOT reportable segments is 94%-97% and 75%-78% for 2023 and 2024, respectively. The percentage of expected generation hedged is the amount of equivalent sales divided by the expected generation. Expected generation is the volume of energy that best represents our commodity position in energy markets from owned or contracted generation based upon a simulated dispatch model that makes assumptions regarding future market conditions, which are calibrated to market quotes for power, fuel, load following products and options. Equivalent sales represent all hedging products, which include economic hedges, CMC payments, and certain non-derivative contracts. A portion of our hedging strategy may be accomplished with fuel products based on assumed correlations between power and fuel prices, which routinely change in the market. 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, 2022 market conditions and hedged position would be a decrease in pre-tax net income of approximately $8 million and $215 million for 2023 and 2024, respectively. Power price sensitivities are derived by adjusting power price assumptions while keeping all other price inputs constant. We actively manage our portfolio to mitigate market price risk exposure for our unhedged position. Actual results could differ depending on the specific timing of, and markets affected by, price changes, as well as future changes in our portfolio. 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 60% of our uranium concentrate requirements from 2023 through 2027 are supplied by three suppliers. To-date, we have not experienced any counterparty credit risk associated with these suppliers stemming from the Russian and Ukraine conflict. In the event of non-performance by these or other suppliers, we believe that replacement uranium concentrates 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 sanctions against Russia, have the potential to impact delivery from multiple suppliers in the international uranium industry. Non-performance by these counterparties could have a material adverse impact in our consolidated financial statements. To-date, we have not experienced any delivery or non-performance issues from our suppliers, nor any degradation in the 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 detailing our trading and non-trading marketing activities is included to address the recommended disclosures by the energy industry’s Committee of Chief Risk Officers (CCRO). 78 Table of Contents The following table provides detail on changes in our commodity mark-to-market net asset or liability balance sheet position from December 31, 2020 to December 31, 2022. 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, 2022 and 2021. Mark-to-Market Energy Contract Net Assets Balance as of December 31, 2020 $ 729 (a) Total change in fair value during 2021 of contracts recorded in result of operations 797 Reclassification to realized at settlement of contracts recorded in results of operations (228) Changes in allocated collateral 96 Net option premium paid 338 Option premium amortization (125) Upfront payments and amortizations (b) 15 Balance as of December 31, 2021 $ 1,622 (a) Total change in fair value during 2022 of contracts recorded in result of operations (647) Reclassification to realized at settlement of contracts recorded in results of operations (380) Changes in allocated collateral 386 Net option premium paid 177 Option premium amortization (293) Upfront payments and amortizations (b) 167 Foreign Currency Translation 14 Balance as of December 31, 2022 $ 1,046 (a) __________ (a) Amounts are shown net of collateral paid to and received from counterparties. (b) Includes derivative contracts acquired or sold through upfront payments or receipts of cash, excluding option premiums, and the associated amortizations. 79 Table of Contents Fair Values The following table presents maturity and source of fair value for mark-to-market commodity contract net assets (liabilities). The table provides two fundamental pieces of information. First, the table provides the source of fair value used in determining the carrying amount of our total mark-to-market net assets (liabilities), net of allocated collateral. Second, the table shows the maturity, by year, of our commodity contract net assets (liabilities), net of allocated collateral, giving an indication of when these mark-to-market amounts will settle and either generate or require cash. 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 2023 2024 2025 2026 2027 2028 and Beyond Normal Operations, Commodity derivative contracts (a)(b) : Actively quoted prices (Level 1) $ 264 $ 169 $ 128 $ 68 $ 33 $ — $ 662 Prices provided by external sources (Level 2) 238 4 (83) 6 — — 165 Prices based on model or other valuation methods (Level 3) 284 (107) 83 38 7 (86) 219 Total $ 786 $ 66 $ 128 $ 112 $ 40 $ (86) $ 1,046 __________ (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 $898 million at December 31, 2022. 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. The following tables provide information on our credit exposure for all derivative instruments, NPNS, and payables and receivables, net of collateral and instruments that are subject to master netting agreements, as of December 31, 2022. The tables further delineate that exposure by credit rating of the counterparties and provide guidance on the concentration of credit risk to individual counterparties and an indication of the duration of a company’s credit risk by credit rating of the counterparties. The figures in the table below exclude credit risk exposure from individual retail customers, uranium procurement contracts, and exposure through RTOs, ISOs, and commodity exchanges, which are discussed below. Rating as of December 31, 2022 Total Exposure Before Credit Collateral Credit Collateral (a) Net Exposure Number of Counterparties Greater than 10% of Net Exposure Net Exposure of Counterparties Greater than 10% of Net Exposure Investment grade $ 1,304 $ 135 $ 1,169 — $ — Non-investment grade 110 88 22 — — No external ratings Internally rated—investment grade 106 — 106 — — Internally rated—non-investment grade 374 40 334 — — Total $ 1,894 $ 263 $ 1,631 — $ — 80 Table of Contents __________ (a) As of December 31, 2022, credit collateral held from counterparties where we had credit exposure included $152 million of cash and $111 million of letters of credit. Maturity of Credit Risk Exposure Rating as of December 31, 2022 Less than 2 Years 2-5 Years Exposure Greater than 5 Years Total Exposure Before Credit Collateral Investment grade $ 1,276 $ 7 $ 21 $ 1,304 Non-investment grade 108 2 — 110 No external ratings Internally rated—investment grade 106 — — 106 Internally rated—non-investment grade 227 104 43 374 Total $ 1,717 $ 113 $ 64 $ 1,894 Net Credit Exposure by Type of Counterparty As of December 31, 2022 Investor-owned utilities, marketers, power producers $ 1,311 Energy cooperatives and municipalities 112 Financial Institutions 9 Other 199 Total $ 1,631 Credit-Risk-Related Contingent Features As part of the normal course of business, we routinely enter into physical or financial contracts for the sale and purchase of electricity, natural gas, and other commodities. 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, or some, of the established, wholesale spot energy markets that are administered by PJM, ISO-NE, NYISO, CAISO, MISO, SPP, AESO, OIESO, and ERCOT. ERCOT is not subject to regulation by FERC but performs a similar function in Texas to that performed by RTOs 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, 81 Table of Contents 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 counterparty could result in a material adverse impact on our consolidated financial statements. See Note 3 — Regulatory Matters 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. Exchange Traded Transactions We enter into commodity transactions on NYMEX, ICE, NASDAQ, NGX, and the Nodal exchange ("the 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 result in a material decrease in our pre-tax income for the year ended December 31, 2022. To manage foreign exchange rate exposure associated with international energy purchases in currencies other than U.S. dollars, we utilize foreign currency derivatives, which are typically designated as economic hedges. See Note 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 result in a $759 million reduction in the fair value of the trust assets as of December 31, 2022. 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 for additional information. 82 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, 2022. 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, 2022, 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, 2022, has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report which appears herein. February 16, 2023 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, 2022. 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, 2022, Constellation’s internal control over financial reporting was effective. February 16, 2023 83 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, 2022, 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, 2022 and 2021, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2022 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, 2022, 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. 84 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, 2022, the nuclear decommissioning ARO was $12.5 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 the significant judgment by management when estimating its decommissioning obligations; this in turn led to 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. In addition, 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, testing management’s process for estimating the decommissioning obligations by evaluating the appropriateness of the discounted cash flow model, testing the completeness and accuracy of data used by management, and 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 16, 2023 We have served as the Company's auditor since 2022. 85 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, 2022 and 2021, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2022 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, 2022, the nuclear decommissioning ARO was $12.5 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 the significant judgment by management when 86 Table of Contents estimating its decommissioning obligations; this in turn led to 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. In addition, 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, testing management’s process for estimating the decommissioning obligations by evaluating the appropriateness of the discounted cash flow model, testing the completeness and accuracy of data used by management, and 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 16, 2023 We have served as the Company's auditor since 2001. 87 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) 2022 2021 2020 Operating revenues Operating revenues $ 24,280 $ 18,461 $ 16,392 Operating revenues from affiliates 160 1,188 1,211 Total operating revenues 24,440 19,649 17,603 Operating expenses Purchased power and fuel 17,457 12,157 9,592 Purchased power and fuel from affiliates 5 6 ( 7 ) Operating and maintenance 4,797 3,934 4,613 Operating and maintenance from affiliates 44 621 555 Depreciation and amortization 1,091 3,003 2,123 Taxes other than income taxes 552 475 482 Total operating expenses 23,946 20,196 17,358 Gain on sales of assets and businesses 1 201 11 Operating income (loss) 495 ( 346 ) 256 Other income and (deductions) Interest expense, net ( 250 ) ( 282 ) ( 328 ) Interest expense to affiliates ( 1 ) ( 15 ) ( 29 ) Other, net ( 786 ) 795 937 Total other income and (deductions) ( 1,037 ) 498 580 (Loss) income before income taxes ( 542 ) 152 836 Income taxes ( 388 ) 225 249 Equity in losses of unconsolidated affiliates ( 13 ) ( 10 ) ( 8 ) Net (loss) income ( 167 ) ( 83 ) 579 Net (loss) income attributable to noncontrolling interests ( 7 ) 122 ( 10 ) Net (loss) income attributable to common shareholders $ ( 160 ) $ ( 205 ) $ 589 Comprehensive income (loss), net of income taxes Net (loss) income $ ( 167 ) $ ( 83 ) $ 579 Other comprehensive income (loss), net of income taxes Pension and non-pension postretirement benefit plans: Prior service benefit reclassified to periodic benefit cost ( 6 ) — — Actuarial loss reclassified to periodic cost 101 — — Pension and non-pension postretirement benefit plans valuation adjustment 186 — — Unrealized loss on cash flow hedges ( 1 ) ( 1 ) ( 2 ) Unrealized (loss) gain on foreign currency translation ( 3 ) — 4 Other comprehensive income (loss), net of income taxes 277 ( 1 ) 2 Comprehensive income (loss) $ 110 $ ( 84 ) $ 581 Comprehensive (loss) income attributable to noncontrolling interests ( 7 ) 122 ( 10 ) Comprehensive income (loss) attributable to common shareholders $ 117 $ ( 206 ) $ 591 Average shares of common stock outstanding: Basic 328 — — Assumed exercise and/or distributions of stock-based awards 1 — — Diluted 329 — — Earnings per average common share Basic $ ( 0.49 ) $ — $ — Diluted $ ( 0.49 ) $ — $ — 88 Table of Contents Constellation Energy Corporation and Subsidiary Companies Consolidated Statements of Cash Flows For the Years Ended December 31, (In millions) 2022 2021 2020 Cash flows from operating activities Net (loss) income $ ( 167 ) $ ( 83 ) $ 579 Adjustments to reconcile net (loss) income to net cash flows (used in) provided by operating activities Depreciation, amortization, and accretion, including nuclear fuel and energy contract amortization 2,427 4,540 3,636 Asset impairments — 545 563 Gain on sales of assets and businesses ( 1 ) ( 201 ) ( 11 ) Deferred income taxes and amortization of ITC ( 643 ) ( 205 ) 78 Net fair value changes related to derivatives 986 ( 568 ) ( 270 ) Net realized and unrealized losses (gains) on NDT funds 794 ( 586 ) ( 461 ) Net realized and unrealized losses (gains) on equity investments 13 160 ( 186 ) Other non-cash operating activities 249 ( 605 ) 18 Changes in assets and liabilities: Accounts receivable ( 868 ) ( 616 ) 1,125 Receivables from and payables to affiliates, net 20 14 24 Inventories ( 228 ) ( 68 ) ( 77 ) Accounts payable and accrued expenses 1,142 346 ( 343 ) Option premiums paid, net ( 177 ) ( 338 ) ( 139 ) Collateral (posted) received, net ( 351 ) ( 130 ) 479 Income taxes 162 256 186 Pension and non-pension postretirement benefit contributions ( 237 ) ( 259 ) ( 255 ) Other assets and liabilities ( 5,474 ) ( 3,540 ) ( 4,362 ) Net cash flows (used in) provided by operating activities ( 2,353 ) ( 1,338 ) 584 Cash flows from investing activities Capital expenditures ( 1,689 ) ( 1,329 ) ( 1,747 ) Proceeds from NDT fund sales 4,050 6,532 3,341 Investment in NDT funds ( 4,271 ) ( 6,673 ) ( 3,464 ) Collection of DPP, net 4,964 3,902 3,771 Proceeds from sales of assets and businesses 52 878 46 Other investing activities ( 2 ) ( 28 ) 11 Net cash flows provided by investing activities 3,104 3,282 1,958 Cash flows from financing activities Change in short-term borrowings 257 362 20 Proceeds from short-term borrowings with maturities greater than 90 days — 880 500 Repayments of short-term borrowings with maturities greater than 90 days ( 1,180 ) — — Issuance of long-term debt 14 152 3,155 Retirement of long-term debt ( 1,162 ) ( 105 ) ( 4,334 ) Retirement of long-term debt to affiliate ( 258 ) — ( 550 ) Change in money pool with Exelon — ( 285 ) 285 Acquisition of CENG noncontrolling interest — ( 885 ) — Distributions to Exelon — ( 1,832 ) ( 1,734 ) Contributions from Exelon 1,750 64 64 Dividends paid on common stock ( 185 ) — — Other financing activities ( 35 ) ( 46 ) ( 70 ) Net cash flows used in financing activities ( 799 ) ( 1,695 ) ( 2,664 ) (Decrease) increase in cash, restricted cash, and cash equivalents ( 48 ) 249 ( 122 ) Cash, restricted cash, and cash equivalents at beginning of period 576 327 449 Cash, restricted cash, and cash equivalents at end of period $ 528 $ 576 $ 327 Supplemental cash flow information (Decrease) increase in capital expenditures not paid $ ( 23 ) $ 96 $ ( 88 ) Increase in DPP 5,166 3,652 4,441 Increase in PP&E related to ARO update 343 618 850 See the Combined Notes to Consolidated Financial Statements 89 Table of Contents Constellation Energy Corporation and Subsidiary Companies Consolidated Balance Sheets December 31, (In millions) 2022 2021 ASSETS Current assets Cash and cash equivalents $ 422 $ 504 Restricted cash and cash equivalents 106 72 Accounts receivable Customer accounts receivable (net of allowance for credit losses of $ 46 and $ 55 as of December 31, 2022 and December 31, 2021, respectively) 2,585 1,669 Other accounts receivable (net of allowance for credit losses of $ 5 as of December 31, 2022 and December 31, 2021) 731 592 Mark-to-market derivative assets 2,368 2,169 Receivables from affiliates — 160 Inventories, net Natural gas, oil, and emission allowances 429 284 Materials and supplies 1,076 1,004 Renewable energy credits 617 520 Other 1,026 1,007 Total current assets 9,360 7,981 Property, plant, and equipment (net of accumulated depreciation and amortization of $ 16,726 and $ 15,873 as of December 31, 2022 and 2021, respectively) 19,822 19,612 Deferred debits and other assets Nuclear decommissioning trust funds 14,114 15,938 Investments 202 174 Mark-to-market derivative assets 1,261 949 Prepaid pension asset — 1,683 Deferred income taxes 44 32 Other 2,106 1,717 Total deferred debits and other assets 17,727 20,493 Total assets (a) $ 46,909 $ 48,086 See the Combined Notes to Consolidated Financial Statements 90 Table of Contents Constellation Energy Corporation and Subsidiary Companies Consolidated Balance Sheets December 31, (In millions) 2022 2021 LIABILITIES AND EQUITY Current liabilities Short-term borrowings $ 1,159 $ 2,082 Long-term debt due within one year 143 1,220 Accounts payable 2,828 1,757 Accrued expenses 906 737 Payables to affiliates — 131 Mark-to-market derivative liabilities 1,558 981 Renewable energy credit obligation 901 777 Other 344 311 Total current liabilities 7,839 7,996 Long-term debt 4,466 4,575 Long-term debt to affiliates — 319 Deferred credits and other liabilities Deferred income taxes and unamortized ITCs 3,031 3,703 Asset retirement obligations 12,699 12,819 Pension obligations 605 — Non-pension postretirement benefit obligations 609 847 Spent nuclear fuel obligation 1,230 1,210 Payables to affiliates — 3,357 Payables related to Regulatory Agreement Units 2,897 — Mark-to-market derivative liabilities 983 513 Other 1,178 1,133 Total deferred credits and other liabilities 23,232 23,582 Total liabilities (a) 35,537 36,472 Commitments and contingencies (Note 19) Shareholders' Equity Predecessor Member's Equity (b) — 11,250 Common stock ( No par value, 1,000 shares authorized, 327 shares outstanding as of December 31, 2022) 13,274 — Retained deficit ( 496 ) — Accumulated other comprehensive loss, net ( 1,760 ) ( 31 ) Total shareholders' equity 11,018 11,219 Noncontrolling interests 354 395 Total equity 11,372 11,614 Total liabilities and shareholders' equity $ 46,909 $ 48,086 __________ (a) Our consolidated assets include $ 2,641 million and $ 2,549 million at December 31, 2022 and 2021, respectively, of certain VIEs that can only be used to settle the liabilities of the VIE. Our consolidated liabilities include $ 1,041 million and $ 1,077 million at December 31, 2022 and 2021, respectively, of certain VIEs for which the VIE creditors do not have recourse to us. See Note 22–Variable Interest Entities for additional information. (b) 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 91 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 Deficit Accumulated Other Comprehensive Loss, net Balance, December 31, 2019 — $ — $ — $ ( 32 ) $ 2,346 $ 13,516 $ 15,830 Net (loss) income — — — — ( 10 ) 589 579 Sale of noncontrolling interest — — — — — 3 3 Changes in equity of noncontrolling interest — — — — ( 59 ) — ( 59 ) Distribution to member of deferred taxes associated with net retirement benefit obligation — — — — — ( 9 ) ( 9 ) Distribution to member — — — — — ( 1,734 ) ( 1,734 ) Contributions from member — — — — — 64 64 Other comprehensive income, net of income taxes — — — 2 — — 2 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 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 ($ 0.14 /common share) — — ( 185 ) — — — ( 185 ) Other comprehensive income , net of income taxes — — — 277 — — 277 Balance, December 31, 2022 327,130 $ 13,274 $ ( 496 ) $ ( 1,760 ) $ 354 $ — $ 11,372 __________ (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 92 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) 2022 2021 2020 Operating revenues Operating revenues $ 24,280 $ 18,461 $ 16,392 Operating revenues from affiliates 160 1,188 1,211 Total operating revenues 24,440 19,649 17,603 Operating expenses Purchased power and fuel 17,457 12,157 9,592 Purchased power and fuel from affiliates 5 6 ( 7 ) Operating and maintenance 4,797 3,934 4,613 Operating and maintenance from affiliates 44 621 555 Depreciation and amortization 1,091 3,003 2,123 Taxes other than income taxes 552 475 482 Total operating expenses 23,946 20,196 17,358 Gain on sales of assets and businesses 1 201 11 Operating income (loss) 495 ( 346 ) 256 Other income and (deductions) Interest expense, net ( 250 ) ( 282 ) ( 328 ) Interest expense to affiliates ( 1 ) ( 15 ) ( 29 ) Other, net ( 786 ) 795 937 Total other income and (deductions) ( 1,037 ) 498 580 (Loss) income before income taxes ( 542 ) 152 836 Income taxes ( 388 ) 225 249 Equity in losses of unconsolidated affiliates ( 13 ) ( 10 ) ( 8 ) Net (loss) income ( 167 ) ( 83 ) 579 Net (loss) income attributable to noncontrolling interests ( 7 ) 122 ( 10 ) Net (loss) income attributable to membership interest $ ( 160 ) $ ( 205 ) $ 589 Comprehensive income (loss), net of income taxes Net (loss) income $ ( 167 ) $ ( 83 ) $ 579 Other comprehensive income (loss), net of income taxes Pension and non-pension postretirement benefit plans: Prior service benefit reclassified to periodic benefit cost ( 6 ) — — Actuarial loss reclassified to periodic benefit cost 101 — — Pension and non-pension postretirement benefit plans valuation adjustment 186 — — Unrealized loss on cash flow hedges ( 1 ) ( 1 ) ( 2 ) Unrealized (loss) gain on foreign currency translation ( 3 ) — 4 Other comprehensive income (loss), net of income taxes 277 ( 1 ) 2 Comprehensive income (loss) 110 ( 84 ) 581 Comprehensive (loss) income attributable to noncontrolling interests ( 7 ) 122 ( 10 ) Comprehensive income (loss) attributable to membership interest $ 117 $ ( 206 ) $ 591 See the Combined Notes to Consolidated Financial Statements 93 Table of Contents Constellation Energy Generation, LLC and Subsidiary Companies Consolidated Statements of Cash Flows For the Years Ended December 31, (In millions) 2022 2021 2020 Cash flows from operating activities Net (loss) income $ ( 167 ) $ ( 83 ) $ 579 Adjustments to reconcile net (loss) income to net cash flows (used in) provided by operating activities Depreciation, amortization, and accretion, including nuclear fuel and energy contract amortization 2,427 4,540 3,636 Asset impairments — 545 563 Gain on sales of assets and businesses ( 1 ) ( 201 ) ( 11 ) Deferred income taxes and amortization of ITCs ( 643 ) ( 205 ) 78 Net fair value changes related to derivatives 986 ( 568 ) ( 270 ) Net realized and unrealized losses (gains) on NDT funds 794 ( 586 ) ( 461 ) Net realized and unrealized losses (gains) on equity investments 13 160 ( 186 ) Other non-cash operating activities 200 ( 605 ) 18 Changes in assets and liabilities: Accounts receivable ( 855 ) ( 616 ) 1,125 Receivables from and payables to affiliates, net 65 14 24 Inventories ( 228 ) ( 68 ) ( 77 ) Accounts payable and accrued expenses 1,112 346 ( 343 ) Option premiums paid, net ( 177 ) ( 338 ) ( 139 ) Collateral (posted) received, net ( 351 ) ( 130 ) 479 Income taxes 162 256 186 Pension and non-pension postretirement benefit contributions ( 237 ) ( 259 ) ( 255 ) Other assets and liabilities ( 5,540 ) ( 3,540 ) ( 4,362 ) Net cash flows (used in) provided by operating activities ( 2,440 ) ( 1,338 ) 584 Cash flows from investing activities Capital expenditures ( 1,689 ) ( 1,329 ) ( 1,747 ) Proceeds from NDT fund sales 4,050 6,532 3,341 Investment in NDT funds ( 4,271 ) ( 6,673 ) ( 3,464 ) Collection of DPP, net 4,964 3,902 3,771 Proceeds from sales of assets and businesses 52 878 46 Other investing activities ( 2 ) ( 28 ) 11 Net cash flows provided by investing activities 3,104 3,282 1,958 Cash flows from financing activities Change in short-term borrowings 257 362 20 Proceeds from short-term borrowings with maturities greater than 90 days — 880 500 Repayments of short-term borrowings with maturities greater than 90 days ( 1,180 ) — — Issuance of long-term debt 14 152 3,155 Retirement of long-term debt ( 1,162 ) ( 105 ) ( 4,334 ) Retirement of long-term debt to affiliate ( 258 ) — ( 550 ) Change in money pool with Exelon — ( 285 ) 285 Acquisition of CENG noncontrolling interest — ( 885 ) — Distributions to Exelon — ( 1,832 ) ( 1,734 ) Distributions to member ( 185 ) — — Contributions from Exelon 1,750 64 64 Contributions from member 82 — — Other financing activities ( 57 ) ( 46 ) ( 70 ) Net cash flows used in financing activities ( 739 ) ( 1,695 ) ( 2,664 ) (Decrease) increase in cash, restricted cash, and cash equivalents ( 75 ) 249 ( 122 ) Cash, restricted cash, and cash equivalents at beginning of period 576 327 449 Cash, restricted cash, and cash equivalents at end of period $ 501 $ 576 $ 327 Supplemental cash flow information (Decrease) increase in capital expenditures not paid $ ( 23 ) $ 96 $ ( 88 ) Increase in DPP 5,166 3,652 4,441 Increase in PP&E related to ARO update 343 618 850 See the Combined Notes to Consolidated Financial Statements 94 Table of Contents Constellation Energy Generation, LLC and Subsidiary Companies Consolidated Balance Sheets December 31, (In millions) 2022 2021 ASSETS Current assets Cash and cash equivalents $ 403 504 Restricted cash and cash equivalents 98 72 Accounts receivable Customer accounts receivable (net of allowance for credit losses of $ 46 and $ 55 as of December 31, 2022 and December 31, 2021, respectively) 2,585 1,669 Other accounts receivable (net of allowance for credit losses of $ 5 as of December 31, 2022 and December 31, 2021) 718 592 Mark-to-market derivative assets 2,368 2,169 Receivables from affiliates — 160 Inventories, net Natural gas, oil, and emission allowance 429 284 Materials and supplies 1,076 1,004 Renewable energy credits 617 520 Other 1,026 1,007 Total current assets 9,320 7,981 Property, plant, and equipment (net of accumulated depreciation and amortization of $ 16,726 and $ 15,873 as of December 31, 2022 and 2021, respectively) 19,822 19,612 Deferred debits and other assets Nuclear decommissioning trust funds 14,114 15,938 Investments 202 174 Mark-to-market derivative assets 1,261 949 Prepaid pension asset — 1,683 Deferred income taxes 44 32 Other 2,106 1,717 Total deferred debits and other assets 17,727 20,493 Total assets (a) $ 46,869 $ 48,086 See the Combined Notes to Consolidated Financial Statements 95 Table of Contents Constellation Energy Generation, LLC and Subsidiary Companies Consolidated Balance Sheets December 31, (In millions) 2022 2021 LIABILITIES AND EQUITY Current liabilities Short-term borrowings $ 1,159 $ 2,082 Long-term debt due within one year 143 1,220 Accounts payable 2,810 1,757 Accrued expenses 869 737 Payables to affiliates 45 131 Mark-to-market derivative liabilities 1,558 981 Renewable energy credit obligation 901 777 Other 344 311 Total current liabilities 7,829 7,996 Long-term debt 4,466 4,575 Long-term debt to affiliates — 319 Deferred credits and other liabilities Deferred income taxes and unamortized ITCs 3,031 3,703 Asset retirement obligations 12,699 12,819 Pension obligations 605 — Non-pension postretirement benefit obligations 609 847 Spent nuclear fuel obligation 1,230 1,210 Payables to affiliates — 3,357 Payables related to Regulatory Agreement Units 2,897 — Mark-to-market derivative liabilities 983 513 Other 1,106 1,133 Total deferred credits and other liabilities 23,160 23,582 Total liabilities (a) 35,455 36,472 Commitments and contingencies (Note 19) Equity Member’s equity Membership interest 12,408 10,482 Undistributed earnings 412 768 Accumulated other comprehensive loss, net ( 1,760 ) ( 31 ) Total member’s equity 11,060 11,219 Noncontrolling interests 354 395 Total equity 11,414 11,614 Total liabilities and equity $ 46,869 $ 48,086 __________ (a) Our consolidated assets include $ 2,641 million and $ 2,549 million as of December 31, 2022 and 2021, respectively, of certain VIEs that can only be used to settle the liabilities of the VIE. Our consolidated liabilities include $ 1,041 million and $ 1,077 million as of December 31, 2022 and 2021, 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 96 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 Loss, net Balance, December 31, 2019 $ 9,566 $ 3,950 $ ( 32 ) $ 2,346 $ 15,830 Net income (loss) — 589 — ( 10 ) 579 Sale of noncontrolling interests 3 — — — 3 Changes in equity of noncontrolling interests — — — ( 59 ) ( 59 ) Distribution to member of deferred taxes associated with net retirement benefit obligation ( 9 ) — — — ( 9 ) Distribution to member — ( 1,734 ) — — ( 1,734 ) Contribution from member 64 — — — 64 Other comprehensive income, net of income taxes — — 2 — 2 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 loss, net of income taxes — — ( 1 ) — ( 1 ) Balance, December 31, 2021 $ 10,482 $ 768 $ ( 31 ) $ 395 $ 11,614 Net loss — ( 160 ) — ( 7 ) ( 167 ) Separation-related adjustments 1,844 ( 11 ) ( 2,006 ) 7 ( 166 ) Changes in equity of noncontrolling interest — — — ( 41 ) ( 41 ) Distribution to member — ( 185 ) — — ( 185 ) Contributions from member 82 — — — 82 Other comprehensive income, net of income taxes — — 277 — 277 Balance, December 31, 2022 $ 12,408 $ 412 $ ( 1,760 ) $ 354 $ 11,414 See the Combined Notes to Consolidated Financial Statements 97 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 clean 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. 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 98 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. Beginning on February 1, 2022, the amounts Exelon billed us for services pursuant to the TSA were $ 266 million for the year ended December 31, 2022, and the amounts we billed Exelon for services pursuant to the TSA were $ 43 million for the year ended December 31, 2022. 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 impairment assessments, derivative instruments, unamortized energy contracts, fixed asset depreciation, environmental costs and other loss contingencies, taxes and unbilled energy revenues. Actual results could differ from those estimates. 99 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 the sale and delivery of energy commodities and related products and services and realized and unrealized revenues recognized under mark-to-market energy commodity derivative contracts. 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. Our primary source of revenue includes competitive sales of power, natural gas, and other energy-related products and services. At the end of each reporting period, we accrue an estimate for the unbilled amount of energy delivered or services provided to customers. Option Contracts, Swaps and Commodity Derivatives. Certain option contracts and swap arrangements that meet the definition of derivative instruments are recorded at fair value with subsequent changes in fair value recognized as 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. 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. Accordingly, revenues are recognized for the taxes collected from customers along with an offsetting expense. 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. 100 Table of Contents Combined Notes to Consolidated Financial Statements (Dollars in millions, unless otherwise noted) Note 1 — Basis of Presentation Our operating leases consist primarily of contracted generation, real estate including office buildings, and vehicles and equipment. We generally account for contracted generation in which the generating asset is not renewable as a lease if the customer has dispatch rights and obtains substantially all the economic benefits. We generally do not account for contracted generation in which the generating asset is renewable as a lease if the customer does not design the generating asset. We account for land right arrangements that provide for exclusive use as leases while shared use land arrangements are generally not leases. See Note 11 — Leases for additional information. Income Taxes Deferred federal and state income taxes are recorded on temporary differences between the book and tax basis of assets and liabilities and for tax benefits carried forward. ITCs have been deferred in the Consolidated Balance Sheets and are recognized in book income over the life of the related property. We account for uncertain income tax positions using a benefit recognition model with a two-step approach; a more-likely-than-not recognition criterion; and a measurement approach that measures the position as the largest amount of tax benefit that is greater than 50% likely of being realized upon ultimate settlement. If it is not more-likely-than-not that the benefit of the tax position will be sustained on its technical merits, no benefit is recorded. Uncertain tax positions that relate only to timing of when an item is included on a tax return are considered to have met the recognition threshold. We recognize accrued interest related to unrecognized tax benefits in Interest expense, net or Other, net (interest income) and recognize penalties related to unrecognized tax benefits in Other, net in the Consolidated Statements of Operations and Comprehensive Income. Cash and Cash Equivalents We consider investments purchased with an original maturity of three months or less to be cash equivalents. Restricted Cash and Cash Equivalents Restricted cash and cash equivalents represent funds that are restricted to satisfy designated current liabilities. As of December 31, 2022 and 2021, 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 Other deferred debits and other assets which primarily are with governmental agencies and other high-quality counterparties. 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, 101 Table of Contents Combined Notes to Consolidated Financial Statements (Dollars in millions, unless otherwise noted) Note 1 — Basis of Presentation • ongoing reconsideration of this assessment, and • where we consolidate a VIE (as primary beneficiary), disclosure of (1) the assets of the consolidated VIE, if they can be used to only settle specific obligations of the consolidated VIE, and (2) the liabilities of a consolidated VIE for which creditors do not have recourse to the general credit of the primary beneficiary. See Note 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. 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 tax, on our NDT funds associated with the Regulatory Agreement Units are included in Noncurrent payables related to Regulatory Agreement Units. Realized and unrealized gains and losses, net of tax, 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 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. 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. Property, Plant and Equipment Property, plant and equipment is recorded at original cost. Original cost includes construction-related direct labor and material costs. When appropriate, original 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. 102 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. Certain other capitalized software costs are being amortized over longer lives based on the expected life. 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 Utility 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. The group approach is typically for groups of similar assets that have approximately the same useful lives and the composite approach is used for dissimilar 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 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 a 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 with ComEd and PECO Based on the regulatory agreements with the ICC and PAPUC that dictate our obligations related to the shortfall or excess of NDT funds necessary for decommissioning the former ComEd units on a unit-by-unit basis and the former PECO units in total, 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. 103 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. 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 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. 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- 104 Table of Contents Combined Notes to Consolidated Financial Statements (Dollars in millions, unless otherwise noted) Note 1 — Basis of Presentation 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, 2022. The measurement 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. 2. Mergers, Acquisitions, and Dispositions 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 NOSA, 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. 105 Table of Contents Combined Notes to Consolidated Financial Statements (Dollars in millions, unless otherwise noted) Note 2 — Mergers, Acquisitions, and Dispositions 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. 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 significant portion of our solar business, including 360 MWs of generation in operation or under construction across more than 600 sites across the United States. We retained certain solar assets not included in this agreement, primarily Antelope Valley. Completion of the transaction contemplated by the sale agreement was subject to the satisfaction of several closing conditions that were satisfied in the first quarter of 2021. The sale was completed on March 31, 2021 for a purchase price of $ 810 million. We received cash proceeds of $ 675 million, net of $ 125 million long-term debt assumed by the buyer and certain working capital and other post-closing adjustments. We recognized a pre-tax gain of $ 68 million which is included in Gain on sales of assets and businesses in the Consolidated Statement of Operations and Comprehensive Income. 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. 3. Regulatory Matters The following matters below discuss the status of our material regulatory and legislative proceedings. Impacts of the February 2021 Extreme Cold Weather Event and Texas-based Generating Assets Outages In February 2021, our Texas-based generating assets within the ERCOT market, specifically Colorado Bend II, Wolf Hollow II, and Handley, experienced outages because of extreme cold weather conditions. In addition, those weather conditions drove increased demand for service, dramatically increased wholesale power prices, and increased gas prices in certain regions. As a result of the event and outages, we incurred a loss of approximately $ 800 million for the year ended December 31, 2021. The estimated impact reduced our overall Net loss by approximately $ 50 million for the year ended December 31, 2022, attributable to a payment to ERCOT from a defaulting market participant, the bankruptcy settlement of a defaulting ERCOT market participant, and the settlement of a dispute related to gas penalties. In response to the high demand and significantly reduced total generation on the system during the event, the PUCT directed ERCOT to use an administrative price cap of $ 9,000 /MWh during firm load shedding. We intervened in a third-party notice of appeal in the Court of Appeals for the Third District of Texas challenging the 106 Table of Contents Combined Notes to Consolidated Financial Statements (Dollars in millions, unless otherwise noted) Note 3 — Regulatory Matters validity of the PUCT’s action administratively setting prices at $ 9,000 /MWh. Additionally, we filed a request for declaratory judgment in Texas district court. Our request is being stayed at our request pending the outcome of the third party’s direct appeal to the Third Court of Appeals on similar grounds, in which briefing is complete, oral argument was held on April 27, 2022. We cannot reasonably predict the outcome of these proceedings or the potential financial statement impact. Due to the event, several ERCOT market participants experienced bankruptcies or defaulted on payments to ERCOT. As of December 31, 2021, there were approximately $ 2.5 billion of outstanding defaults. Under ERCOT rules, defaults are allocated to the remaining market participants. Accordingly, we recorded our estimated obligation of the outstanding defaults, net of legislative solutions, and on a discounted basis, of approximately $ 17 million as of December 31, 2021, which was expected to be paid over a term of 83 years. As of result of a market participant paying off their debt to ERCOT and a bankruptcy settlement, there were no outstanding defaults to be allocated to market participants as of December 31, 2022, as further discussed below. Additionally, several legislative proposals were introduced in the Texas legislature during February and March 2021 concerning the amount, timing and allocation of recovery of the defaults, as well as recovery of other costs associated with the PUCT's directive to set prices at $ 9,000 per MWh. Two of these proposals were enacted into law in June 2021 and establish financing mechanisms that ERCOT and certain market participants can utilize to fund amounts owed to ERCOT. Securitization of defaults of competitive retail providers has been completed and a market participant securitized its debt and repaid amounts owed to ERCOT, both of which reduced our obligation . We participated in proceedings before the PUCT addressing the proposed allocation of the $ 2.1 billion in securitized funds for reliability and ancillary service charges over $ 9,000 per MWh. In September 2021, we entered into a settlement agreement and stipulation to resolve the allocation issues. The PUCT approved the settlement agreement and stipulation on October 13, 2021, and in June 2022, we collected our outstanding receivable. In the first quarter of 2022, a hearing began on ERCOT’s $ 1.9 billion claim in another market participant’s bankruptcy for the entire outstanding default owed to ERCOT. The ERCOT claim was resolved through a settlement included in the Chapter 11 Plan of Reorganization filed by the Debtor (market participant) on September 1, 2022 and approved by the bankruptcy court, which became effective on December 15, 2022. The settlement avoids ERCOT allocating outstanding default charges to remaining market participants. In February 2021, more than 70 local distribution companies (LDCs) and natural gas pipelines in multiple states throughout the mid-continent region, where we serve natural gas customers, issued operational flow orders (OFOs), curtailments or other limitations on natural gas transportation or use to manage the operational integrity of the applicable LDC or pipeline system. When in effect, gas transportation or use above these limitations is subject to significant penalties according to the applicable LDCs’ and natural gas pipelines’ tariffs. Gas transportation and supply in many states became restricted due to wells freezing and pipeline compression disruption, while demand was increasing due to the extreme cold temperatures, resulting in extremely high natural gas prices. Due to the extraordinary circumstances, many LDCs and natural gas pipelines either voluntarily waived or sought applicable regulatory approvals to waive the tariff penalties associated with the extreme weather event. During May 2021, an LDC filed a motion with the Kansas Corporation Commission (KCC) requesting the KCC to grant a waiver from the tariff and allow the LDC to reduce the amounts assessed by permitting the removal of a multiplier from the penalty calculation. On March 3, 2022, the KCC approved a unanimous settlement, resolving this matter. Illinois Regulatory Matters Clean Energy Law. On September 15, 2021, the Illinois Public Act 102-0662 was signed into law by the Governor of Illinois ("Clean Energy Law"). 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. Among other things, the Clean Energy Law authorized the IPA to procure up to 54.5 million CMCs from qualifying nuclear plants for a five-year period beginning on June 1, 2022 through May 31, 2027. CMCs are credits for the carbon-free attributes of eligible nuclear power plants in PJM. Our Byron, Dresden, and Braidwood nuclear plants located in Illinois participated in the CMC procurement process and were awarded contracts that commit each plant to operate through May 31, 2027. Pursuant to these contracts, ComEd will procure CMCs based upon the number of MWhs produced annually by each plant, subject to minimum performance requirements. The price to be paid for each CMC was established through a competitive bidding process that included consumer-protection measures that capped the maximum acceptable bid amount and reduces CMC prices by an energy price index, the base residual auction capacity price in the ComEd zone of PJM, and the monetized value of any federal tax 107 Table of Contents Combined Notes to Consolidated Financial Statements (Dollars in millions, unless otherwise noted) Note 3 — Regulatory Matters credit or other subsidy, if applicable. The consumer protection measures contained in the new law will result in net payments to ComEd ratepayers if the energy index, the capacity price and applicable federal tax credits or subsidy exceed the CMC contract price. Regulatory or legal challenges regarding the validity or implementation of the Clean Energy Law are possible and we cannot reasonably predict the outcome of any such challenges. See Note 7 – Early Plant Retirements for the impacts of the provisions above on the Illinois nuclear plants and the consolidated financial statements. New Jersey Regulatory Matters New Jersey Clean Energy Legislation. On May 23, 2018, New Jersey enacted legislation that established a ZEC program that provides compensation for nuclear plants that demonstrate to the NJBPU that they meet certain requirements, including that they make a significant contribution to air quality in the state and that their revenues are insufficient to cover their costs and risks. Under the legislation, the NJBPU will issue ZECs to qualifying nuclear power plants and the electric distribution utilities in New Jersey will be required to purchase those ZECs. On April 18, 2019, the NJBPU approved the award of ZECs to Salem 1 and Salem 2. Upon approval, we began recognizing revenue for the sale of New Jersey ZECs in the month they are generated. On March 19, 2021, a three-judge panel of the Superior Court of New Jersey Appellate Division unanimously affirmed the NJBPU’s April 2019 order awarding ZECs for the first eligibility period. On April 8, 2021, New Jersey Rate Counsel filed a notice asking the New Jersey Supreme Court to hear the appeal of the Superior Court’s order. On July 9, 2021, the New Jersey Supreme Court declined to hear the appeal. On October 1, 2020, we and PSEG filed applications seeking ZECs for the second eligibility period (June 2022 through May 2025). On April 27, 2021, the NJBPU approved the award of ZECs to Salem 1 and Salem 2 for the second eligibility period. On May 11, 2021, the New Jersey Rate Counsel appealed the April 27, 2021 decision to the Superior Court of New Jersey Appellate Division. Briefing on the appeal has concluded, and we are awaiting the scheduling of oral argument. We cannot reasonably predict the outcome of this proceeding. New England Regulatory Matters Mystic Units 8 and 9 Cost of Service Agreement. On March 29, 2018, we notified grid operator ISO-NE of our plans to early retire Mystic Units 8 and 9 absent regulatory reforms on June 1, 2022. On May 16, 2018, we made a filing with FERC to establish cost-of-service compensation and terms and conditions of service for Mystic Units 8 and 9 for the period between June 1, 2022 to May 31, 2024. On December 20, 2018, FERC issued an order accepting the cost of service compensation, reflecting a number of adjustments to the annual fixed revenue requirement and allowing for recovery of a substantial portion of the costs associated with the adjacent EMT we acquired in October 2018. Those adjustments were reflected in a compliance filing made on March 1, 2019. In the December 20, 2018 order, FERC also directed a paper hearing on Return on Equity (“ROE”) using a new methodology. The ROE impacts the return Mystic collects on its rate base under the agreement. On January 22, 2019, we and several other parties filed requests for rehearing of certain findings in the order. On July 15, 2021, FERC issued an order establishing the ROE to be used in the cost of service agreement for Mystic 8 and 9 at 9.33 %. On August 16, 2021, we and several other parties filed requests for rehearing of certain aspects of the July 15, 2021 order. In November 2021, FERC issued an order directing a decrease to the ROE used in the Mystic Cost of Service Agreement (the “Mystic COS”) from 9.33 % to 9.19 %. Several parties, including us, have filed petitions for review with the U.S. Court of Appeals for the D.C. Circuit challenging the FERC orders establishing the ROE. These petitions are pending. We do not expect the outcome of this appeal to have a material financial statement impact. On July 17, 2020, FERC issued three orders, which together affirmed the recovery of key elements of Mystic's cost of service compensation, including recovery of costs associated with the operation of the EMT. FERC directed a downward adjustment to the rate base for Mystic Units 8 and 9, the effect of which will be partially offset by elimination of a crediting mechanism for third-party gas sales during the term of the cost of service agreement. In addition, several parties filed protests to a compliance filing by us on September 15, 2020, taking issue with how gross plant in-service was calculated, and we filed an answer to the protests on October 21, 2020. On December 21, 2020, FERC issued an order on rehearing of the three July 17, 2020 orders, clarifying several cost of service provisions. Several parties appealed the December 21, 2020 order to the U.S. Court of Appeals for the D.C. Circuit and that appeal was consolidated with appeals of orders issued December 20, 2018 and July 17, 2020 in the Mystic proceeding. On August 23, 2022, court issued its opinion and remanded several issues back to FERC, which include: (1) the amount of the EMT’s fixed costs that can be recovered via the Mystic COS, (2) whether some or all of EMT capital expenditures recovered during the term of the Mystic COS 108 Table of Contents Combined Notes to Consolidated Financial Statements (Dollars in millions, unless otherwise noted) Note 3 — Regulatory Matters will have to be returned if EMT continues operating after the Mystic COS terminates, and (3) the historical rate base for Mystic upon which we earn a return. We await FERC’s order on remand and cannot reasonably predict the outcome of this proceeding, which could have a material financial impact over the term of the Mystic COS. The Mystic COS requires an annual process whereby we identify and support our projected costs under the agreement and/or true-up previous projections to the actual costs incurred. The first annual process resulted in a filing at FERC on September 15, 2021 and included our projection of capital expenditures to be recovered under the Mystic COS between June 1, 2022 and December 31, 2022. On April 28, 2022, FERC issued an order setting for settlement and/or hearing the issue of whether our projected 2022 capital expenditures can be recovered. Settlement negotiations are currently ongoing. We cannot reasonably predict the outcome of the settlement and/or hearing. On September 15, 2022, we made our second annual filing at FERC, which included (1) our projection of capital expenditures to be recovered under the Mystic COS between January 1, 2023 and December 31, 2023, and (2) an updated projection of the Annual Fixed Revenue Requirement, the Maximum Monthly Fixed Cost Payment, and the Fixed Operating and Maintenance/Return on Investment component of the Monthly Fuel Cost Charge, including an update to rate base for the period between January 1, 2018 and December 31, 2021. That filing is currently pending at FERC. Following our separation from Exelon, we submitted a filing at FERC to update the capital structure and cost of debt used in the Mystic COS. The Mystic COS had previously used the Exelon capital structure and cost of debt in the rate, and we proposed post-separation to instead use Constellation's capital structure and cost of debt. On May 2, 2022, FERC accepted our filing, subject to refund, and set the matter for settlement and/or hearing. An unopposed offer of settlement was filed at FERC on September 8, 2022 and was approved by FERC on November 2, 2022. The settlement does not have a material financial impact. See Note 7 — Early Plant Retirements and Note 12 — Asset Impairments for additional information on the impacts of our August 2020 decision to retire Mystic Units 8 and 9 upon expiration of the cost of service agreement. Federal Regulatory Matters Inflation Reduction Act of 2022. On August 16, 2022, Congress passed and President Biden signed into law the IRA, which, among other things, includes federal tax credits, certain of which are trans