10-K – 2026-02-24 – ceg-20251231.htm

guarantees through surety bonds, letters of credit, or parent company guarantees or making additional cash contributions to the NDT fund to ensure sufficient funds are available. See Note 10 — Asset Retirement Obligations of the Combined Notes to Consolidated Financial Statements for additional information.
If a nuclear plant were to retire before the end of its licensed life, there is a risk that it will no longer meet the NRC minimum funding requirements due to the earlier commencement of decommissioning activities and a shorter time period over which the NDT funds could appreciate in value. A shortfall could require that we address the shortfall by providing additional financial assurances, such as surety bonds, letters of credit, or parent company guarantees for our share of the funding assurance. However, the amount of any assurance will ultimately depend on the decommissioning approach, the associated level of costs, and the NDT fund investment performance going forward. No later than two years after shutting down a plant, we must submit a Post-shutdown Decommissioning Activities Report (PSDAR) to the NRC that includes the planned option for decommissioning the site.
Upon issuance of any additional financial assurance mechanisms to address a decommissioning funding shortfall, subject to satisfying various regulatory preconditions, each site would be able to utilize the respective NDT funds for radiological decommissioning costs, which represent the majority of the total expected decommissioning costs. However, under the regulations, the NRC must approve an exemption in order for us to utilize the NDT funds to pay for non-radiological decommissioning costs (i.e., spent fuel management and site restoration costs, if applicable). Any amounts not covered by an exemption would be borne by us without reimbursement.
As of December 31, 2025, the Crane NDT is fully funded under the SAFSTOR scenario that was the planned decommissioning option, as described in the Crane PSDAR filed with the NRC in April 2019. We will continue to file Crane's decommissioning funding status with the NRC annually until restart, at which point we will file decommissioning funding status reports in accordance with applicable NRC requirements. Additionally, as of December 31, 2025, we have adequate NDT funds for the remaining radiological decommissioning cost at Zion Station related to the Independent Spent Fuel Storage Installation. Decommissioning costs other than radiological may require funding from us. See Note 10 — Asset Retirement Obligations of the Combined Notes to Consolidated Financial Statements for additional information.

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
We are exposed to market risks associated with adverse changes in commodity prices, counterparty credit, interest rates, and equity prices. We manage these risks through risk management policies and objectives for risk assessment, control and valuation, counterparty credit approval, and the monitoring and reporting of risk exposures. The Executive Committee and the Audit and Risk Committee of the Board of Directors have oversight responsibilities for risk management.
Commodity Price Risk
Commodity price risk is associated with price movements resulting from changes in supply and demand, fuel costs, market liquidity, weather conditions, governmental, regulatory, and environmental policies, and other factors. To the extent the total amount of energy we produce or procure differs from the amount of energy we have contracted to sell, we are exposed to market fluctuations in commodity prices. We seek to mitigate our commodity price risk through the sale and purchase of electricity, natural gas and oil, and other commodities.
Electricity available from our owned or contracted generation supply in excess of our obligations to customers is sold into the wholesale markets. To reduce commodity price risk caused by market fluctuations, we enter into non-derivative contracts as well as derivative contracts, including swaps, futures, forwards, and options, with approved counterparties to hedge anticipated exposures in locations and periods where our load serving activities do not naturally offset existing generation portfolio risk. Portfolio hedging activities are generally concentrated in the prompt three years, when customer demand and market liquidity enable effective price risk mitigation. We expect the settlement of the majority of our economic hedges will occur during 2026 through 2028. We also enter transactions that further optimize the economic benefits of our overall portfolio.
In general, increases and decreases in forward market prices have a positive and negative impact, respectively, on owned and contracted generation positions that have not been hedged. Beginning in 2024, our existing nuclear fleet is eligible for a nuclear PTC, an important tool in managing commodity price risk for each nuclear unit not already receiving state support. The nuclear PTC provides increasing levels of support as unit revenues

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decline below levels established in the IRA and is further adjusted for inflation annually through the duration of the program based on the GDP price deflator for the preceding calendar year. See Note 6 — Government Assistance of the Combined Notes to Consolidated Financial Statements for additional information.
The forecasted market price risk exposure is the risk of a change in the value of unhedged positions. The forecasted market price risk exposure as of December 31, 2025 for our portfolio associated with a hypothetical $5/MWh reduction in the annual average around-the-clock energy price results in an impact to earnings that is not material for 2026 and 2027. See Note 15 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information.
Fuel Procurement
We procure natural gas through long-term and short-term contracts, and spot-market purchases. Nuclear fuel is obtained predominantly through long-term contracts for uranium concentrates, conversion services, enrichment services, (or a combination thereof) and fabrication services, including contracts sourced from Russia. The supply markets for uranium concentrates and certain nuclear fuel services are subject to price fluctuations and availability restrictions. Supply market conditions may make our procurement contracts subject to credit risk related to the potential non-performance of counterparties to deliver the contracted commodity or service at the contracted prices. We engage a diverse set of suppliers to secure the nuclear fuel needed to continue to operate our nuclear fleet long-term. Approximately 35% of our uranium concentrate requirements from 2026 through 2030 are supplied by three suppliers. To-date, we have not experienced any counterparty credit risk associated with these suppliers stemming from the Russia and Ukraine conflict. In the event of non-performance by these or other suppliers, we believe that replacement uranium concentrate can be obtained, although at prices that may be unfavorable when compared to the prices under the current supply agreements. Geopolitical developments, including the Russia and Ukraine conflict and United States, United Kingdom, European Union, and Canadian sanctions against Russia, have the potential to impact delivery from multiple suppliers in the international uranium processing industry. Non-performance by these counterparties could have a material adverse impact on our results of operation or financial condition. See ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS — Other Key Business Drivers for more information on the Russia and Ukraine conflict.
Commodity Derivative Activity
The following table provides detail on changes in our commodity derivative contract net assets (liabilities) balance sheet position from January 1, 2024 to December 31, 2025. This table incorporates the unrealized gains and losses that are immediately recorded in earnings. This table excludes all NPNS contracts. See Note 15 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information on the balance sheet classification of the commodity derivative contract net assets (liabilities) recorded as of December 31, 2025 and 2024.

2025 2024
Beginning balance as of January 1 (a)
$ 317  $ 1,108 
Total change in fair value of contracts recorded in results of operations
(725) (654)
Reclassification to realized at settlement of contracts recorded in results of operations 104  1,934 
Changes in allocated collateral 764  (1,813)
Net option premium paid (received)
(38) (216)
Option premium amortization 103  (32)
Upfront payments and amortizations (b) 
(23) (10)
Foreign currency translation
2  — 
Ending balance as of December 31 (a)
$ 504  $ 317 

__________
(a) Amounts are shown net of collateral paid to and received from counterparties.
(b) Includes derivative contracts acquired or sold through upfront payments or receipts of cash, excluding option premiums, and the associated amortizations.

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Fair Values
The following table presents maturity and source of fair value for commodity derivative contract net assets (liabilities). See Note 17 — Fair Value of Financial Assets and Liabilities of the Combined Notes to Consolidated Financial Statements for additional information regarding fair value measurements and the fair value hierarchy.

Maturities Within Total Fair Value

2026 2027 2028 2029 2030 2031 and Beyond
Commodity derivative contracts (a) :

Actively quoted prices (Level 1) $ 145  $ 26  $ (17) $ (12) $ —  $ —  $ 142 
Prices provided by external sources (Level 2) 86  99  31  6  —  —  222 
Prices based on model or other valuation methods (Level 3) 236  (130) 14  (10) (28) 58  140 
Total $ 467  $ (5) $ 28  $ (16) $ (28) $ 58  $ 504 
__________
(a) Amounts are shown net of collateral paid to and received from counterparties (and offset against derivative assets and liabilities) of $1,352 million at December 31, 2025.
Credit Risk
We would be exposed to credit-related losses in the event of non-performance by counterparties that execute derivative instruments. The credit exposure of derivative contracts, before collateral, is represented by the fair value of contracts at the reporting date. See Note 15 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for a detailed discussion of credit risk.
Credit-Risk-Related Contingent Features
As part of the normal course of business, we routinely enter into physically or financially settled contracts for the purchase and sale of capacity, electricity, fuels, emissions allowances, and other energy-related products. In accordance with the contracts and applicable law, if we are downgraded by a credit rating agency, especially if such downgrade is to a level below investment grade, it is possible that a counterparty would attempt to rely on such a downgrade as a basis for making a demand for adequate assurance of future performance. Depending on our net position with a counterparty, the demand could be for the posting of collateral. In the absence of expressly agreed-to provisions that specify the collateral that must be provided, collateral requested will be a function of the facts and circumstances of the situation at the time of the demand. See Note 15 — Derivative Financial Instruments and Note 18 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for additional information regarding the letters of credit supporting the cash collateral.
We sell output through bilateral contracts. The bilateral contracts are subject to credit risk, which relates to the ability of counterparties to meet their contractual payment obligations. Any failure to collect these payments from counterparties could have a material impact on our results of operation or financial condition. As market prices rise above or fall below contracted price levels, we are required to post collateral with purchasers; as market prices fall below contracted price levels, counterparties are required to post collateral with us. To post collateral, we depend on access to bank credit facilities, which serve as liquidity sources to fund collateral requirements. See ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS, Liquidity and Capital Resources — Credit Matters and Cash Requirements — Credit Facilities for additional information.

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RTOs and ISOs
We participate in all of the established wholesale energy markets that are administered by PJM, ISO-NE, NYISO, CAISO, MISO, SPP, AESO, and ERCOT. ERCOT is not subject to regulation by FERC but performs a similar function in Texas to that performed by RTOs and ISOs in markets regulated by FERC. In these areas, power and related products are traded through bilateral agreements between buyers and sellers and in the energy markets that are administered by the RTOs or ISOs, as applicable. In areas where there is no RTO or ISO to administer energy markets, electricity and related products are purchased and sold solely through bilateral agreements. For activities administered by an RTO or ISO, the RTO or ISO maintains financial assurance policies that are established and enforced by those administrators. The credit policies of the RTOs and ISOs may, under certain circumstances, require that losses arising from the default of one member be shared by the remaining participants. Non-performance or non-payment by a major member of an RTO or ISO could result in a material adverse impact on our results of operations or financial condition.
Exchange Traded Transactions
We enter into commodity transactions on NYMEX, ICE, NASDAQ, NGX, and the Nodal exchange (each an Exchange and, collectively, Exchanges). The Exchange clearinghouses act as the counterparty to each trade. Transactions on the Exchanges must adhere to comprehensive collateral and margining requirements. As a result, transactions on Exchanges are significantly collateralized and have limited counterparty credit risk.
Interest Rate and Foreign Exchange Risk
We use a combination of fixed-rate and variable-rate debt to manage interest rate exposure. We may also utilize interest rate swaps to manage our interest rate exposure, including derivatives to lock in rate levels in anticipation of future financings. A hypothetical 50 basis points change in interest rates associated with unhedged variable-rate long term debt and interest rate swaps would not have resulted in a material impact to our earnings for the year ended December 31, 2025. To manage foreign exchange rate exposure associated with international energy purchases in currencies other than U.S. dollars, we utilize foreign currency derivatives, which are typically designated as economic hedges. See Note 15 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information.
Equity Price Risk
We maintain trust funds, as required by the NRC, to fund the costs of decommissioning our nuclear plants. Our NDT funds are reflected at fair value in the Consolidated Balance Sheets. The mix of securities in the trust funds is designed to provide returns to be used to fund decommissioning and to compensate us for inflationary increases in decommissioning costs; however, the equity securities in the trust funds are exposed to price fluctuations in equity markets, and the value of fixed-rate, fixed-income securities are exposed to changes in interest rates. We actively monitor the investment performance of the trust funds and periodically review asset allocations in accordance with our NDT fund investment policy.
A hypothetical 25 basis point increase in interest rates and 10% decrease in equity prices would have resulted in a $1,099 million reduction in the fair value of our NDT trust assets as of December 31, 2025. This calculation holds all other variables constant and assumes only the discussed changes in interest rates and equity prices. See Liquidity and Capital Resources section of ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS, and Note 10 — Asset Retirement Obligations of the Combined Notes to Consolidated Financial Statements for additional information.
Our employee benefit plan trusts also hold investments in equity and debt securities. See ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS — Critical Accounting Policies and Estimates for sensitivity analysis of key assumptions in the valuation of our Pension and OPEB obligations.

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

Management’s Report on Internal Control Over Financial Reporting
The management of Constellation Energy Corporation (CEG Parent) is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rule 13a-15(f). Internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
CEG Parent’s management assessed the effectiveness of CEG Parent’s internal control over financial reporting as of December 31, 2025. In making this assessment, management used the criteria in Internal Control—Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this assessment, CEG Parent’s management concluded that, as of December 31, 2025, CEG Parent’s internal control over financial reporting was effective.
The effectiveness of CEG Parent’s internal control over financial reporting as of December 31, 2025, has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report which appears herein.
February 24, 2026
Management’s Report on Internal Control Over Financial Reporting
The management of Constellation Energy Generation, LLC (Constellation) is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rule 13a-15(f). Internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
Constellation’s management assessed the effectiveness of Constellation’s internal control over financial reporting as of December 31, 2025. In making this assessment, management used the criteria in Internal Control—Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this assessment, Constellation’s management concluded that, as of December 31, 2025, Constellation’s internal control over financial reporting was effective.
February 24, 2026

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Report of Independent Registered Public Accounting Firm
To the Board of Directors and Shareholders of Constellation Energy Corporation
Opinions on the Financial Statements and Internal Control over Financial Reporting
We have audited the consolidated financial statements, including the related notes, as listed in the index appearing under Item 15(a)(1)(i), and the financial statement schedule listed in the index appearing under Item 15(a)(1)(ii), of Constellation Energy Corporation and its subsidiaries (the “Company”) (collectively referred to as the “consolidated financial statements”). We also have audited the Company's internal control over financial reporting as of December 31, 2025, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of the Company as of December 31, 2025 and 2024, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2025 in conformity with accounting principles generally accepted in the United States of America. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2025, based on criteria established in Internal Control - Integrated Framework (2013) issued by the COSO.
Basis for Opinions
The Company's management is responsible for these consolidated financial statements, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting, included in Management’s Report on Internal Control Over Financial Reporting appearing under Item 8. Our responsibility is to express opinions on the Company’s consolidated financial statements and on the Company's internal control over financial reporting based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud, and whether effective internal control over financial reporting was maintained in all material respects.
Our audits of the consolidated financial statements included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.
Definition and Limitations of Internal Control over Financial Reporting
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

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Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
Critical Audit Matters
The critical audit matter communicated below is a matter arising from the current period audit of the consolidated financial statements that was communicated or required to be communicated to the audit committee and that (i) relates to accounts or disclosures that are material to the consolidated financial statements and (ii) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.
Nuclear Decommissioning Asset Retirement Obligations (ARO) Assessment
As described in Notes 1 and 10 to the consolidated financial statements, the Company has a legal obligation to decommission its nuclear power plants following the permanent cessation of operations. To estimate its decommissioning obligations management uses a probability- weighted, discounted cash flow model which, on a unit-by-unit basis, considers multiple outcome scenarios that include significant estimates and assumptions, and are based on decommissioning cost studies, cost escalation rates, probabilistic cash flow models, and discount rates. Management updates its ARO annually, unless circumstances warrant more frequent updates, based on its review of updated cost studies and its annual evaluation of cost escalation factors and probabilities assigned to various scenarios. As of December 31, 2025, the nuclear decommissioning ARO was $12.9 billion.
The principal considerations for our determination that performing procedures relating to the Company’s nuclear decommissioning ARO assessment is a critical audit matter are (i) the significant judgment by management when estimating its decommissioning obligations; (ii) a high degree of auditor judgment, subjectivity, and effort in performing procedures and evaluating the reasonableness of management’s discounted cash flow model and significant assumptions related to decommissioning cost studies; and (iii) the audit effort involved the use of professionals with specialized skill and knowledge.
Addressing the matter involved performing procedures and evaluating audit evidence in connection with forming our overall opinion on the consolidated financial statements. These procedures included testing the effectiveness of controls relating to management’s development of the inputs, assumptions, and discounted cash flow model used in management’s ARO assessment. These procedures also included, among others (i) testing management’s process for estimating the decommissioning obligations by evaluating the appropriateness of the discounted cash flow model; (ii) testing the completeness and accuracy of data used by management; and (iii) evaluating the reasonableness of management’s significant assumptions related to decommissioning cost studies. Professionals with specialized skill and knowledge were used to assist in evaluating the results of decommissioning cost studies.

/s/ PricewaterhouseCoopers LLP

Baltimore, Maryland
February 24, 2026

We have served as the Company's auditor since 2022.

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Report of Independent Registered Public Accounting Firm
To the Board of Directors and Member of Constellation Energy Generation, LLC
Opinion on the Financial Statements
We have audited the consolidated financial statements, including the related notes, as listed in the index appearing under Item 15(a)(2)(i), and the financial statement schedule listed in the index appearing under Item 15(a)(2)(ii), of Constellation Energy Generation, LLC and its subsidiaries (the “Company”) (collectively referred to as the “consolidated financial statements”). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2025 and 2024, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2025 in conformity with accounting principles generally accepted in the United States of America.
Basis for Opinion
These consolidated financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on the Company’s consolidated financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits of these consolidated financial statements in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion.
Our audits included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. We believe that our audits provide a reasonable basis for our opinion.
Critical Audit Matters
The critical audit matter communicated below is a matter arising from the current period audit of the consolidated financial statements that was communicated or required to be communicated to the audit committee and that (i) relates to accounts or disclosures that are material to the consolidated financial statements and (ii) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.
Nuclear Decommissioning Asset Retirement Obligations (ARO) Assessment
As described in Notes 1 and 10 to the consolidated financial statements, the Company has a legal obligation to decommission its nuclear power plants following the permanent cessation of operations. To estimate its decommissioning obligations management uses a probability- weighted, discounted cash flow model which, on a unit-by-unit basis, considers multiple outcome scenarios that include significant estimates and assumptions, and are based on decommissioning cost studies, cost escalation rates, probabilistic cash flow models, and discount rates. Management updates its ARO annually, unless circumstances warrant more frequent updates, based on its review of updated cost studies and its annual evaluation of cost escalation factors and probabilities assigned to various scenarios. As of December 31, 2025, the nuclear decommissioning ARO was $12.9 billion.
The principal considerations for our determination that performing procedures relating to the Company’s nuclear decommissioning ARO assessment is a critical audit matter are (i) the significant judgment by management when

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estimating its decommissioning obligations; (ii) a high degree of auditor judgment, subjectivity, and effort in performing procedures and evaluating the reasonableness of management’s discounted cash flow model and significant assumptions related to decommissioning cost studies; and (iii) the audit effort involved the use of professionals with specialized skill and knowledge.
Addressing the matter involved performing procedures and evaluating audit evidence in connection with forming our overall opinion on the consolidated financial statements. These procedures included testing the effectiveness of controls relating to management’s development of the inputs, assumptions, and discounted cash flow model used in management’s ARO assessment. These procedures also included, among others (i) testing management’s process for estimating the decommissioning obligations by evaluating the appropriateness of the discounted cash flow model; (ii) testing the completeness and accuracy of data used by management; and (iii) evaluating the reasonableness of management’s significant assumptions related to decommissioning cost studies. Professionals with specialized skill and knowledge were used to assist in evaluating the results of decommissioning cost studies.

/s/ PricewaterhouseCoopers LLP

Baltimore, Maryland
February 24, 2026

We have served as the Company's auditor since 2001.

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Constellation Energy Corporation and Subsidiary Companies
Consolidated Statements of Operations and Comprehensive Income

For the Years Ended December 31,
(In millions, except per share data) 2025 2024 2023
Operating revenues $ 25,533   $ 23,568   $ 24,918  

Operating expenses
Purchased power and fuel 14,681   11,419   16,001  

Operating and maintenance 6,159   6,159   5,685  

Depreciation and amortization 985   1,123   1,096  
Taxes other than income taxes 622   586   553  
Total operating expenses 22,447   19,287   23,335  
Gain (loss) on sales of assets and businesses —   71   27  
Operating income (loss) 3,086   4,352   1,610  
Other income and (deductions)
Interest expense, net ( 511 ) ( 506 ) ( 431 )

Other, net 936   670   1,268  
Total other income and (deductions) 425   164   837  
Income (loss) before income taxes 3,511   4,516   2,447  
Income tax (benefit) expense 1,187   774   859  
Equity in income (losses) of unconsolidated affiliates ( 1 ) ( 4 ) ( 11 )
Net income (loss) 2,323   3,738   1,577  
Net income (loss) attributable to noncontrolling interests 4   ( 11 ) ( 46 )
Net income (loss) attributable to common shareholders $ 2,319   $ 3,749   $ 1,623  
Comprehensive income (loss), net of income taxes
Net income (loss) $ 2,323   $ 3,738   $ 1,577  
Other comprehensive income (loss), net of income taxes
Pension and non-pension postretirement benefit plans:
Prior service benefit reclassified to periodic benefit cost ( 4 ) ( 4 ) ( 4 )
Actuarial loss reclassified to periodic cost 72   75   25  
Pension and non-pension postretirement benefit plans valuation adjustment ( 219 ) ( 176 ) ( 453 )
Unrealized gain (loss) on cash flow hedges 7   4   ( 1 )

Unrealized gain (loss) on foreign currency translation 21   ( 10 ) 2  
Other comprehensive income (loss), net of income taxes ( 123 ) ( 111 ) ( 431 )
Comprehensive income (loss) $ 2,200   $ 3,627   $ 1,146  
Comprehensive income (loss) attributable to noncontrolling interests 4   ( 11 ) ( 46 )
Comprehensive income (loss) attributable to common shareholders $ 2,196   $ 3,638   $ 1,192  

Average shares of common stock outstanding:
Basic 313   315   323  
Assumed exercise and/or distributions of stock-based awards 1   —   1  
Diluted 314   315   324  

Earnings per average common share
Basic $ 7.40   $ 11.91   $ 5.02  
Diluted $ 7.40   $ 11.89   $ 5.01  

See the Combined Notes to Consolidated Financial Statements

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Constellation Energy Corporation and Subsidiary Companies
Consolidated Statements of Cash Flows

For the Years Ended December 31,
(In millions) 2025 2024 2023
Cash flows from operating activities
Net income (loss) $ 2,323   $ 3,738   $ 1,577  
Adjustments to reconcile net income (loss) to net cash flows provided by (used in) operating activities
Depreciation, amortization, and accretion, including nuclear fuel and energy contract amortization 2,601   2,700   2,514  

Deferred income taxes and amortization of ITCs
273   222   251  
Net fair value changes related to derivatives 645   ( 1,297 ) 996  
Net realized and unrealized (gains) losses on NDT funds
( 708 ) ( 311 ) ( 476 )
Net realized and unrealized (gains) losses on equity investments
279   ( 11 ) ( 307 )
Other non-cash operating activities ( 223 ) ( 172 ) 18  
Changes in assets and liabilities:
Accounts receivable ( 363 ) 688   396  

Inventories ( 134 ) ( 99 ) 60  
Accounts payable and accrued expenses 316   1,121   ( 1,330 )
Option premiums received (paid), net 38   216   26  
Collateral received (posted), net ( 773 ) 1,803   ( 1,491 )
Income taxes
625   296   325  
Pension and non-pension postretirement benefit contributions ( 211 ) ( 184 ) ( 54 )
Other assets and liabilities ( 451 ) ( 11,174 ) ( 7,806 )
Net cash flows provided by (used in) operating activities 4,237   ( 2,464 ) ( 5,301 )
Cash flows from investing activities
Capital expenditures ( 2,949 ) ( 2,565 ) ( 2,422 )
Proceeds from NDT fund sales 6,946   6,005   5,822  
Investment in NDT funds ( 7,284 ) ( 6,282 ) ( 6,050 )
Collection of DPP, net —   10,217   7,340  

Acquisitions of assets and businesses
( 14 ) ( 32 ) ( 1,690 )
Other investing activities 103   85   31  
Net cash flows provided by (used in) investing activities
( 3,198 ) 7,428   3,031  
Cash flows from financing activities
Change in short-term borrowings —   ( 1,105 ) 146  
Proceeds from short-term borrowings with maturities greater than 90 days 1,650   200   539  
Repayments of short-term borrowings with maturities greater than 90 days —   ( 739 ) ( 200 )
Issuance of long-term debt —   920   3,195  
Retirement of long-term debt ( 1,076 ) ( 121 ) ( 168 )

Dividends paid on common stock ( 486 ) ( 444 ) ( 366 )

Repurchases of common stock ( 400 ) ( 999 ) ( 992 )
Other financing activities ( 108 ) ( 1 ) 42  
Net cash flows provided by (used in) financing activities ( 420 ) ( 2,289 ) 2,196  
Increase (decrease) in cash, restricted cash, and cash equivalents 619   2,675   ( 74 )
Cash, restricted cash, and cash equivalents at beginning of period 3,129   454   528  
Cash, restricted cash, and cash equivalents at end of period $ 3,748   $ 3,129   $ 454  

Supplemental disclosure of non-cash investing and financing activities

Increase (decrease) in DPP
$ —   $ 9,045   $ 8,097  
Increase (decrease) in PP&E related to ARO update
187   ( 1,486 ) 501  

See the Combined Notes to Consolidated Financial Statements

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Constellation Energy Corporation and Subsidiary Companies
Consolidated Balance Sheets

December 31,
(In millions) 2025 2024
ASSETS
Current assets
Cash and cash equivalents $ 3,641   $ 3,022  
Restricted cash and cash equivalents 107   107  
Accounts receivable, net
4,266   3,718  

Derivative assets
945   843  

Inventories, net 1,736   1,600  

Renewable energy credits 789   797  

Other 635   689  
Total current assets 12,119   10,776  
Property, plant, and equipment (net of accumulated depreciation and amortization of $ 19,072 and $ 18,088 , respectively)
22,474   21,235  
Deferred debits and other assets

Nuclear decommissioning trust funds 19,336   17,305  

Goodwill 420   420  
Derivative assets
450   372  

Other 2,450   2,818  
Total deferred debits and other assets 22,656   20,915  
Total assets (a)
$ 57,249   $ 52,926  

LIABILITIES AND EQUITY
Current liabilities
Short-term borrowings $ 1,650   $ —  
Long-term debt due within one year 92   1,028  

Accounts payable and accrued expenses 4,294   3,943  

Derivative liabilities
467   467  

Renewable energy credit obligation 1,075   1,076  

Other 366   332  
Total current liabilities 7,944   6,846  
Long-term debt 7,250   7,384  

Deferred credits and other liabilities
Deferred income taxes and unamortized ITCs 3,544   3,331  
Asset retirement obligations 13,193   12,449  
Pension and non-pension postretirement benefit obligations 1,977   1,875  

Payables related to Regulatory Agreement Units 5,334   4,518  
Derivative liabilities
414   399  

Other 2,740   2,585  
Total deferred credits and other liabilities 27,202   25,157  
Total liabilities (a)
42,396   39,387  
Commitments and contingencies (Note 18)

Shareholders' equity

Common stock ( No par value, 1,000 shares authorized, 312 shares and 313 shares outstanding, respectively)
11,043   11,402  
Retained earnings (deficit) 5,899   4,066  
Accumulated other comprehensive income (loss), net ( 2,425 ) ( 2,302 )
Total shareholders' equity 14,517   13,166  
Noncontrolling interests 336   373  
Total equity 14,853   13,539  
Total liabilities and shareholders' equity $ 57,249   $ 52,926  

__________
(a) Our consolidated assets include $ 4,551  million and $ 4,318  million at December 31, 2025 and 2024, respectively, of certain VIEs that can only be used to settle the liabilities of the VIE. Our consolidated liabilities include $ 914  million and $ 968  million at December 31, 2025 and 2024, respectively, of certain VIEs for which the VIE creditors do not have recourse to us. See Note 21–Variable Interest Entities for additional information.
See the Combined Notes to Consolidated Financial Statements

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Table of Contents

Constellation Energy Corporation and Subsidiary Companies
Consolidated Statements of Changes in Equity

Shareholders' Equity
Noncontrolling Interests
Total Equity

(In millions, shares in thousands) Issued Shares
Common Stock
Retained Earnings (Deficit)
Accumulated Other Comprehensive Income (Loss), net

Balance, December 31, 2022 327,130   $ 13,274   $ ( 496 ) $ ( 1,760 ) $ 354   $ 11,372  
Net Income (loss) —  —  1,623   —  ( 46 ) 1,577  
Employee incentive plans 902   81   —  —  —  81  
Changes in equity of noncontrolling interest —  —  —  —  53   53  

Common stock dividends
($ 0.2820 /common share)
—  —  ( 366 ) —  —  ( 366 )
Common stock repurchased ( 10,560 ) ( 1,000 ) —  —  —  ( 1,000 )
Other comprehensive income (loss), net of income taxes —  —  —  ( 431 ) —  ( 431 )
Balance, December 31, 2023 317,472   $ 12,355   $ 761   $ ( 2,191 ) $ 361   $ 11,286  
Net Income (loss) —  —  3,749   —  ( 11 ) 3,738  
Employee incentive plans 885   56   —  —  —  56  
Changes in equity of noncontrolling interest —  —  —  —  23   23  
Common stock dividends
($ 0.3525 /common share)
—  —  ( 444 ) —  —  ( 444 )
Common stock repurchased ( 5,519 ) ( 1,009 ) —  —  —  ( 1,009 )
Other comprehensive income (loss), net of income taxes —  —  —  ( 111 ) —  ( 111 )
Balance, December 31, 2024 312,838   $ 11,402   $ 4,066   $ ( 2,302 ) $ 373   $ 13,539  
Net Income (loss) —  —  2,319   —  4   2,323  
Employee incentive plans 799   39   —  —  —  39  
Changes in equity of noncontrolling interest —  —  —  —  ( 41 ) ( 41 )
Common stock dividends
($ 0.3878 /common share)
—  —  ( 486 ) —  —  ( 486 )
Common stock repurchased ( 1,282 ) ( 404 ) —  —  —  ( 404 )
Capped call option contracts —  6   —  —  —  6  
Other comprehensive income (loss), net of income taxes —  —  —  ( 123 ) —  ( 123 )
Balance, December 31, 2025 312,355   $ 11,043   $ 5,899   $ ( 2,425 ) $ 336   $ 14,853  

See the Combined Notes to Consolidated Financial Statements

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Constellation Energy Generation, LLC and Subsidiary Companies
Consolidated Statements of Operations and Comprehensive Income

For the Years Ended December 31,
(In millions) 2025 2024 2023
Operating revenues $ 25,533   $ 23,568   $ 24,918  

Operating expenses
Purchased power and fuel 14,681   11,419   16,001  

Operating and maintenance 6,159   6,159   5,685  

Depreciation and amortization 985   1,123   1,096  
Taxes other than income taxes 622   586   553  
Total operating expenses 22,447   19,287   23,335  
Gain (loss) on sales of assets and businesses —   71   27  
Operating income (loss) 3,086   4,352   1,610  
Other income and (deductions)
Interest expense, net ( 511 ) ( 506 ) ( 431 )

Other, net 936   670   1,268  
Total other income and (deductions) 425   164   837  
Income (loss) before income taxes 3,511   4,516   2,447  
Income tax (benefit) expense 1,187   774   859  
Equity in income (losses) of unconsolidated affiliates ( 1 ) ( 4 ) ( 11 )
Net income (loss) 2,323   3,738   1,577  
Net income (loss) attributable to noncontrolling interests 4   ( 11 ) ( 46 )
Net income (loss) attributable to membership interest $ 2,319   $ 3,749   $ 1,623  
Comprehensive income (loss), net of income taxes
Net income (loss) $ 2,323   $ 3,738   $ 1,577  
Other comprehensive income (loss), net of income taxes
Pension and non-pension postretirement benefit plans:
Prior service benefit reclassified to periodic benefit cost ( 4 ) ( 4 ) ( 4 )
Actuarial loss reclassified to periodic benefit cost 72   75   25  
Pension and non-pension postretirement benefit plans valuation adjustment ( 219 ) ( 176 ) ( 453 )
Unrealized gain (loss) on cash flow hedges 7   4   ( 1 )

Unrealized gain (loss) on foreign currency translation 21   ( 10 ) 2  

Other comprehensive income (loss), net of income taxes ( 123 ) ( 111 ) ( 431 )
Comprehensive income (loss) $ 2,200   $ 3,627   $ 1,146  
Comprehensive income (loss) attributable to noncontrolling interests 4   ( 11 ) ( 46 )
Comprehensive income (loss) attributable to membership interest $ 2,196   $ 3,638   $ 1,192  

See the Combined Notes to Consolidated Financial Statements

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Constellation Energy Generation, LLC and Subsidiary Companies
Consolidated Statements of Cash Flows

For the Years Ended December 31,
(In millions) 2025 2024 2023
Cash flows from operating activities
Net income (loss) $ 2,323   $ 3,738   $ 1,577  
Adjustments to reconcile net income (loss) to net cash flows provided by (used in) operating activities
Depreciation, amortization, and accretion, including nuclear fuel and energy contract amortization 2,601   2,700   2,514  

Deferred income taxes and amortization of ITCs 273   222   251  
Net fair value changes related to derivatives 645   ( 1,297 ) 996  
Net realized and unrealized (gains) losses on NDT funds
( 708 ) ( 311 ) ( 476 )
Net realized and unrealized (gains) losses on equity investments
279   ( 11 ) ( 307 )
Other non-cash operating activities ( 304 ) ( 218 ) ( 44 )
Changes in assets and liabilities:
Accounts receivable ( 363 ) 697   389  
Receivables from and payables to affiliates, net 16   231   73  
Inventories ( 134 ) ( 99 ) 60  
Accounts payable and accrued expenses 326   1,116   ( 1,330 )
Option premiums received (paid), net 38   216   26  
Collateral received (posted), net ( 773 ) 1,803   ( 1,491 )
Income taxes
625   296   325  
Pension and non-pension postretirement benefit contributions ( 211 ) ( 184 ) ( 54 )
Other assets and liabilities ( 464 ) ( 11,369 ) ( 7,897 )
Net cash flows provided by (used in) operating activities 4,169   ( 2,470 ) ( 5,388 )
Cash flows from investing activities
Capital expenditures ( 2,949 ) ( 2,565 ) ( 2,422 )
Proceeds from NDT fund sales 6,946   6,005   5,822  
Investment in NDT funds ( 7,284 ) ( 6,282 ) ( 6,050 )
Collection of DPP, net —   10,217   7,340  

Acquisitions of assets and businesses
( 14 ) ( 32 ) ( 1,690 )

Other investing activities 103   85   31  
Net cash flows provided by (used in) investing activities
( 3,198 ) 7,428   3,031  
Cash flows from financing activities
Change in short-term borrowings —   ( 1,105 ) 146  
Proceeds from short-term borrowings with maturities greater than 90 days 1,650   200   539  
Repayments of short-term borrowings with maturities greater than 90 days —   ( 739 ) ( 200 )
Issuance of long-term debt —   920   3,195  
Retirement of long-term debt ( 1,076 ) ( 121 ) ( 168 )

Distributions to member ( 1,035 ) ( 1,441 ) ( 1,239 )

Contributions from member 156   —   —  

Other financing activities ( 61 ) 3   23  
Net cash flows provided by (used in) financing activities ( 366 ) ( 2,283 ) 2,296  
Increase (decrease) in cash, restricted cash, and cash equivalents 605   2,675   ( 61 )
Cash, restricted cash, and cash equivalents at beginning of period 3,115   440   501  
Cash, restricted cash, and cash equivalents at end of period $ 3,720   $ 3,115   $ 440  

Supplemental disclosure of non-cash investing and financing activities

Increase (decrease) in DPP
$ —   $ 9,045   $ 8,097  
Increase (decrease) in PP&E related to ARO update
187   ( 1,486 ) 501  

See the Combined Notes to Consolidated Financial Statements

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Constellation Energy Generation, LLC and Subsidiary Companies
Consolidated Balance Sheets

December 31,
(In millions) 2025 2024
ASSETS
Current assets
Cash and cash equivalents $ 3,641   $ 3,018  
Restricted cash and cash equivalents 79   97  
Accounts receivable, net
4,251   3,703  

Derivative assets
945   843  

Inventories, net 1,736   1,600  

Renewable energy credits 789   797  

Other 634   689  
Total current assets 12,075   10,747  
Property, plant, and equipment (net of accumulated depreciation and amortization of $ 19,072 and $ 18,088 , respectively)
22,474   21,235  
Deferred debits and other assets

Nuclear decommissioning trust funds 19,336   17,305  

Goodwill 420   420  
Derivative assets
450   372  

Other 2,443   2,814  
Total deferred debits and other assets 22,649   20,911  
Total assets (a)
$ 57,198   $ 52,893  

LIABILITIES AND EQUITY
Current liabilities
Short-term borrowings $ 1,650   $ —  
Long-term debt due within one year 92   1,028  

Accounts payable and accrued expenses 4,033   3,696  
Payables to affiliates 365   349  

Derivative liabilities
467   467  

Renewable energy credit obligation 1,075   1,076  

Other 358   328  
Total current liabilities 8,040   6,944  
Long-term debt 7,250   7,384  

Deferred credits and other liabilities
Deferred income taxes and unamortized ITCs 3,544   3,331  
Asset retirement obligations 13,193   12,449  
Pension and non-pension postretirement benefit obligations 1,977   1,875  

Payables related to Regulatory Agreement Units 5,334   4,518  
Derivative liabilities
414   399  

Other 2,583   2,410  
Total deferred credits and other liabilities 27,045   24,982  
Total liabilities (a)
42,335   39,310  
Commitments and contingencies (Note 18)

Equity
Member’s equity
Membership interest 10,144   10,538  
Undistributed earnings (deficit) 6,808   4,974  
Accumulated other comprehensive income (loss), net ( 2,425 ) ( 2,302 )
Total member’s equity 14,527   13,210  
Noncontrolling interests 336   373  
Total equity 14,863   13,583  
Total liabilities and equity $ 57,198   $ 52,893  

__________
(a) Our consolidated assets include $ 4,551  million and $ 4,318 million as of December 31, 2025 and 2024, respectively, of certain VIEs that can only be used to settle the liabilities of the VIE. Our consolidated liabilities include $ 914 million and $ 968 million as of December 31, 2025 and 2024, respectively, of certain VIEs for which the VIE creditors do not have recourse to us. See Note 21–Variable Interest Entities for additional information.
See the Combined Notes to Consolidated Financial Statements

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Constellation Energy Generation, LLC and Subsidiary Companies
Consolidated Statements of Changes in Equity

Member’s Equity Noncontrolling Interests
Total Equity

(In millions) Membership Interest
Undistributed Earnings (Deficit)
Accumulated Other Comprehensive Income (Loss), net
Balance, December 31, 2022 $ 12,408   $ 412   $ ( 1,760 ) $ 354   $ 11,414  
Net Income (loss) —  1,623   —  ( 46 ) 1,577  
Changes in equity of noncontrolling interests —  —  —  53   53  
Distribution to member ( 871 ) ( 368 ) —  —  ( 1,239 )
Other comprehensive income (loss), net of income taxes —  —  ( 431 ) —  ( 431 )
Balance, December 31, 2023 $ 11,537   $ 1,667   $ ( 2,191 ) $ 361   $ 11,374  
Net Income (loss) —  3,749   —  ( 11 ) 3,738  
Changes in equity of noncontrolling interests —  —  —  23   23  
Distribution to member ( 999 ) ( 442 ) —  —  ( 1,441 )
Other comprehensive income (loss), net of income taxes —  —  ( 111 ) —  ( 111 )
Balance, December 31, 2024 $ 10,538   $ 4,974   $ ( 2,302 ) $ 373   $ 13,583  
Net Income (loss) —  2,319   —  4   2,323  
Changes in equity of noncontrolling interest —  —  —  ( 41 ) ( 41 )
Contribution from member 156   —  —  —  156  
Distribution to member ( 550 ) ( 485 ) —  —  ( 1,035 )
Other comprehensive income (loss), net of income taxes —  —  ( 123 ) —  ( 123 )
Balance, December 31, 2025 $ 10,144   $ 6,808   $ ( 2,425 ) $ 336   $ 14,863  

See the Combined Notes to Consolidated Financial Statements

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Combined Notes to Consolidated Financial Statements
(Dollars in millions, unless otherwise noted)

1. Basis of Presentation
Description of Business
We are the nation's largest producer of clean energy and a leading supplier of energy products and services. Our generating capacity includes primarily nuclear, wind, solar, and hydroelectric assets. Through our integrated business operations, we sell electricity, natural gas, and other energy-related products and sustainable solutions to various types of customers, including distribution utilities, municipalities, cooperatives, and commercial, industrial, public sector, and residential customers in markets across multiple geographic regions. We have five reportable segments: Mid-Atlantic, Midwest, New York, ERCOT, and Other Power Regions.
Basis of Presentation
Constellation Energy Corporation (“CEG Parent” or the “Company”), a Pennsylvania corporation, was formed for the purpose of separation of Constellation Energy Generation, LLC (“Constellation”, formerly Exelon Generation Company, LLC) and its subsidiaries from its predecessor parent company, Exelon Corporation (“Exelon”), into an independent, publicly traded company. On February 1, 2022, the separation was completed by distributing all the outstanding shares of the Company’s common stock, on a pro rata basis to the holders of its predecessor’s common stock, with the Company holding all the interests in Constellation previously held by Exelon (the “Separation”). Constellation has been an individual registrant since 2002 with the registration of its public debt securities under the Securities Act. Prior to the Separation, Constellation historically filed consolidated financial statements as an individual registrant to reflect its financial position and operating results as a stand-alone, wholly owned subsidiary of Exelon.
The accompanying Consolidated Financial Statements have been prepared in accordance with GAAP for annual financial statements and in accordance with the instructions to Form 10-K and Regulation S-X promulgated by the SEC. The Consolidated Financial Statements include the accounts of our subsidiaries and all intercompany transactions have been eliminat ed. Certain prior period amounts have been reclassified to conform to the presentation in the current period. Amounts disclosed relate to CEG Parent and Constellation unless specifically noted as relating to CEG Parent only. Unless otherwise indicated or the context otherwise requires, references herein to the terms “we,” “us,” and “our” refer collectively to CEG Parent and Constellation.
We own 100% of our significant consolidated subsidiaries, either directly or indirectly, except for certain consolidated VIEs. The remaining interests in the consolidated VIEs are included in noncontrolling interests in the Consolidated Balance Sheets. See Note 21 — Variable Interest Entities for additional information on consolidated VIEs.
We consolidate the accounts of entities in which we have a controlling financial interest, after the elimination of intercompany transactions. Where we do not have a controlling financial interest in an entity, proportionate consolidation, equity method accounting or accounting for investments in equity securities with or without readily determinable fair value is applied. We proportionately consolidate our undivided ownership interest in jointly-owned electric plants. Under proportionate consolidation, we separately record our proportionate share of the assets, liabilities, revenues and expenses related to the undivided interest in the asset. See Note 9 — Jointly-Owned Electric Plants for additional information on the application of proportionate consolidation.
We apply equity method accounting when we have a significant influence over an investee through an ownership in equity, which generally approximates to a 20% to 50% voting interest. We apply equity method accounting to certain investments and joint ventures. Under equity method accounting, we report our interest in the entity as an investment and our percentage share of the earnings from the entity as single line items in our consolidated financial statements. We use accounting for investments in equity securities with or without readily determinable fair values if we lack significant influence, which generally results when we hold less than 20% of the common stock of an entity. Under accounting for investments in equity securities with readily determinable fair values, the investments are reported based on quoted prices in active markets and realized and unrealized gains and losses are included in earnings. Under accounting for investments in equity securities without readily determinable fair values, the investments are reported at cost, adjusted for changes from observable transactions for identical or similar investments of the same issuer, less impairment, and changes in measurement are reported in earnings.
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Combined Notes to Consolidated Financial Statements
(Dollars in millions, unless otherwise noted)

Note 1 — Basis of Presentation

Use of Estimates
The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the amounts reported in the financial statements and accompanying notes. Areas in which significant estimates have been made include, but are not limited to, the accounting for nuclear decommissioning costs and other AROs, pension and OPEB plans, inventory reserves, allowance for credit losses, long-lived asset valuations and impairment assessments, derivative instruments, goodwill, UECs, fixed asset depreciation, environmental costs and other loss contingencies, taxes and unbilled energy revenues. Actual results could differ materially from those estimates.
Revenues
Operating Revenues. Our operating revenues generally consist of revenues from contracts with customers involving competitive sales of power, natural gas, and other energy-related products and sustainable solutions. We recognize revenue from contracts with customers to depict the transfer of goods or services to customers in an amount that we expect to be entitled to in exchange for those goods or services. At the end of each reporting period, we accrue an estimate for the unbilled amount of power and natural gas delivered or services provided to customers.
Commodity Derivatives. Derivative instruments are generally recorded at fair value with subsequent changes in fair value recognized as realized and unrealized revenue or expense. The classification of revenue or expense is based on the intent of the transaction. See Note 15 — Derivative Financial Instruments for additional information.
Taxes Directly Imposed on Revenue-Producing Transactions. We collect certain taxes from customers such as sales and gross receipts taxes, along with other taxes, surcharges and fees, that are levied by state or local governments on the sale or distribution of electricity and natural gas and any taxable energy-related products and sustainable solutions. Some of these taxes are imposed on the customer, but paid by us, while others are imposed on us. Where these taxes are imposed on the customer, such as sales taxes, they are reported on a net basis in revenues. However, where these taxes are imposed on us, such as gross receipts taxes, they are reported on a gross basis in revenue and expense in the Consolidated Statements of Operations and Comprehensive Income.
Government Assistance. As a result of the enactment of the IRA, we qualify for certain federal government incentives through eligible activities. These incentives include both refundable and transferable tax credits. The current U.S. GAAP framework does not address the receipt of government assistance by for-profit entities. We account for this government assistance by analogy to International Accounting Standard (IAS) 20, Accounting for Government Grants and Disclosure of Government Assistance, and recognize the benefits when there is reasonable assurance that we will comply with the required conditions and that the benefits will be received. We believe the reasonable assurance term as used in IAS 20 is analogous to the term probable as defined under GAAP related to accounting for contingencies. See Note 6 — Government Assistance for additional information.
Leases
We recognize a ROU asset and lease liability for operating leases with a term of greater than one year. Operating lease ROU assets are included in Other deferred debits and other assets and operating lease liabilities are included in Other current liabilities and Other deferred credits and other liabilities in the Consolidated Balance Sheets. The ROU asset is measured as the sum of (1) the present value of all remaining fixed and in-substance fixed payments using the rate implicit in the lease whenever that is readily determinable or our incremental borrowing rate, (2) any lease payments made at or before the commencement date (less any lease incentives received) and (3) any initial direct costs incurred. The lease liability is measured the same as the ROU asset, but excludes any payments made before the commencement date and initial direct costs incurred. Lease terms include options to extend or terminate the lease if it is reasonably certain they will be exercised. We include non-lease components for most asset classes, which are service-related costs that are not integral to the use of the asset, in the measurement of the ROU asset and lease liability.
Expense for operating leases and leases with a term of one year or less is recognized on a straight-line basis over the term of the lease, unless another systematic and rational basis is more representative of the derivation of benefit from use of the leased property. Variable lease payments are recognized in the period in which the related obligation is incurred and consist primarily of payments for purchases of electricity under contracted
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Combined Notes to Consolidated Financial Statements
(Dollars in millions, unless otherwise noted)

Note 1 — Basis of Presentation

generation that are based on the electricity produced by those generating assets. Operating lease expense and variable lease payments are recorded to Purchased power and fuel expense for contracted generation or Operating and maintenance expense for all other lease agreements in the Consolidated Statements of Operations and Comprehensive Income.
Income from operating leases, including subleases, is recognized on a straight-line basis over the term of the lease, unless another systematic and rational basis is more representative of the pattern in which income is earned over the term of the lease. Variable lease payments are recognized in the period in which the related obligation is performed and consist primarily of payments received from sales of electricity under contracted generation that are based on the electricity produced by those generating assets. Operating lease income and variable lease payments are recorded to Operating revenues in the Consolidated Statements of Operations and Comprehensive Income.
Our operating leases consist primarily of contracted generation, real estate including office buildings, and vehicles and equipment. We generally account for contracted generation in which the generating asset is not renewable as a lease if the customer has dispatch rights and obtains substantially all the economic benefits. We generally do not account for contracted generation in which the generating asset is renewable as a lease if the customer does not design the generating asset. We account for land right arrangements that provide for exclusive use as leases while shared use land arrangements are generally not leases.
See Note 11 — Leases for additional information.
Income Taxes
Deferred federal and state income taxes are recorded on temporary differences between the book and tax basis of assets and liabilities and for tax benefits carried forward. ITCs have been deferred in the Consolidated Balance Sheets and are recognized in book income over the life of the related property. We account for uncertain income tax positions using a benefit recognition model with a two-step approach; a more-likely-than-not recognition criterion and a measurement approach that measures the position as the largest amount of tax benefit that is greater than 50% likely of being realized upon ultimate settlement. If it is not more likely than not that the benefit of the tax position will be sustained on its technical merits, no benefit is recorded. Uncertain tax positions that relate only to timing of when an item is included on a tax return are considered to have met the recognition threshold. We recognize accrued interest related to unrecognized tax benefits in Interest expense, net or Other, net (interest income) and recognize penalties related to unrecognized tax benefits in Other, net in the Consolidated Statements of Operations and Comprehensive Income.
Cash and Cash Equivalents
We consider investments purchased with an original maturity of three months or less to be cash equivalents.
Restricted Cash and Cash Equivalents
Restricted cash and cash equivalents represent funds that are restricted to satisfy designated current liabilities. As of December 31, 2025 and 2024, restricted cash and cash equivalents primarily represented the payment of medical, dental, vision, and long-term disability benefits and project-specific nonrecourse financing structures for debt service and financing of operations of the underlying entities. See Note 16 — Debt and Credit Agreements and Note 22 — Supplemental Financial Information for additional information.
Allowance for Credit Losses on Accounts Receivables
The allowance for credit losses reflects our best estimate of losses on the customers' accounts receivable balances based on historical experience and current information.
The allowance for credit losses for our retail and wholesale customers is based on accounts receivable aging historical experience coupled with specific identification through a credit monitoring process, which considers current conditions such as industry trends, macroeconomic factors, changes in the regulatory environment, external credit ratings, publicly available news, payment status, payment history, and the exercise of collateral calls. When a wholesale customer’s risk characteristics are no longer aligned with the pooled population, we use specific identification to develop an allowance for credit losses. Adjustments to the allowance for credit losses are
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Combined Notes to Consolidated Financial Statements
(Dollars in millions, unless otherwise noted)

Note 1 — Basis of Presentation

recorded in Operating and maintenance expense in the Consolidated Statements of Operations and Comprehensive Income.
We have certain non-customer receivables in Current Assets and Other deferred debits and other assets which primarily are with governmental agencies. The allowance for credit losses related to these receivables is not material. We monitor these balances and will record an allowance if there are indicators of a decline in credit quality.
Variable Interest Entities
We account for our investments in and arrangements with VIEs based on the following specific requirements:
• qualitative assessment of factors determinant in whether we have a controlling financial interest,
• ongoing reconsideration of this assessment, and
• where we consolidate a VIE (as primary beneficiary), disclosure of (1) the assets of the consolidated VIE, if they can be used to only settle specific obligations of the consolidated VIE, and (2) the liabilities of a consolidated VIE for which creditors do not have recourse to the general credit of the primary beneficiary.
See Note 21 — Variable Interest Entities for additional information.
Inventories
Inventory is recorded at the lower of weighted average cost or net realizable value. Reserves are recorded for excess and obsolete inventory. Natural gas, oil, and emission allowances are generally included in Inventory when delivered and are expensed to Purchased power and fuel expense when consumed. Materials and supplies are generally included in Inventory when delivered and are expensed to Operating and maintenance, or capitalized to Property, plant and equipment, as appropriate, when installed or used.
Debt and Equity Security Investments
Debt and Equity Investments within NDT funds. We have debt and equity securities held in our NDT funds which are measured and recorded at fair value. Realized and unrealized gains and losses, net of trust-level taxes, on our NDT funds associated with the Regulatory Agreement Units are offset in Noncurrent payables related to Regulatory Agreement Units. Realized and unrealized gains and losses, net of trust-level taxes, on our NDT funds associated with the Non-Regulatory Agreement Units are included in Other, net in the Consolidated Statements of Operations and Comprehensive Income. For equity securities without readily determinable fair values, we have elected to use the NAV for qualifying investments as a practical expedient to determine the fair values. Our NDT funds are classified as current or noncurrent assets, depending on the timing of the decommissioning activities and expected payment of income taxes on trust earnings. See Note 10 — Asset Retirement Obligations and Note 17 — Fair Value of Financial Assets and Liabilities for additional information.
Equity Security Investments. We hold equity securities both with and without readily determinable fair values. For those with readily determinable fair values, realized and unrealized gains and losses are recognized in Other, net within the Consolidated Statements of Operations and Comprehensive Income. For those without readily determinable fair values, we have elected the measurement alternative, which records investments at cost adjusted for observable transactions involving identical or similar investments of the same issuer, less impairment. Changes in measurement under this alternative are also reported in Other, net within the Consolidated Statements of Operations and Comprehensive Income. Investments in equity securities without readily determinable fair values are qualitatively assessed for impairment each reporting period. If it is determined that the equity security is impaired, an impairment loss will be recognized in Other, net in the Consolidated Statements of Operations and Comprehensive Income in the amount by which the security’s carrying amount exceeds its fair value. See Note 17 — Fair Value of Financial Assets and Liabilities for additional information.
Property, Plant and Equipment
Property, plant and equipment is recorded at acquired cost. Acquired cost includes construction-related direct labor and material costs. When appropriate, acquired cost also includes capitalized interest. Costs associated
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with outages and planned major maintenance activities are expensed to Operating and maintenance expense or capitalized to Property, plant, and equipment based on the nature of the activities in the period incurred. The cost of repairs and maintenance and minor replacements of property are charged to Operating and maintenance expense in the Consolidated Statements of Operations and Comprehensive Income as incurred.
Upon retirement, the cost of property is generally charged to accumulated depreciation in accordance with the composite and group methods of depreciation. Upon replacement of an asset, the costs to remove the asset, net of salvage, are capitalized to gross plant when incurred as part of the cost of the newly installed asset and recorded to depreciation expense over the life of the new asset. Removal costs, net of salvage, incurred for property that will not be replaced is charged to Operating and maintenance expense as incurred. Certain assets follow the unitary method of depreciation and recognize gains and losses in the period of replacement or retirement. These gains and losses are recorded in Operating and maintenance expense in the Consolidated Statements of Operations and Comprehensive Income.
Capitalized Software. Certain costs, such as design, coding, and testing incurred during the application development stage of software projects that are internally developed or purchased for operational use are capitalized in Property, plant and equipment in the Consolidated Balance Sheets. Similar costs incurred for cloud-based solutions treated as service arrangements are capitalized in Other current assets and Deferred debits and other assets in the Consolidated Balance Sheets. Such capitalized amounts are amortized ratably over the expected lives of the projects when they become operational, generally not to exceed five years .
Capitalized Interest. During construction, we capitalize the costs of debt funds. Most projects will use a debt rate calculated using the general corporate debt pool. In some cases, projects are specifically financed and use a project-specific debt rate, which is excluded from the general corporate debt pool. Capitalization of debt funds is recorded as a charge to construction work in progress and as a non-cash credit to interest expense. See Note 8 — Property, Plant, and Equipment, Note 9 — Jointly-Owned Electric Plants and Note 22 — Supplemental Financial Information for additional information.
Nuclear Fuel
The cost of nuclear fuel is capitalized in Property, plant and equipment and charged to Purchased power and fuel using the unit-of-production method. Any potential future SNF disposal fees will also be expensed through Purchased power and fuel expense. Additionally, certain on-site SNF storage costs are being reimbursed by the DOE since a DOE (or government-owned) long-term storage facility has not been completed. See Note 18 — Commitments and Contingencies for additional information regarding the cost of SNF storage and disposal.
Depreciation and Amortization
Except for the amortization of nuclear fuel, depreciation, inclusive of ARC, is generally recorded over the estimated useful lives of property, plant and equipment on a straight-line basis using the group, composite or unitary methods of depreciation. Two methods of depreciating multiple asset groups exist: the group method and the composite method. The group method is typically for groups of assets that are largely homogenous and have approximately the same useful lives. The composite method is used when the assets are heterogeneous and have different lives. Under both methods, a reporting entity depreciates the assets over the average life of the assets in the group. The estimated useful lives are based on a combination of depreciation studies, historical retirements, site licenses and management estimates of operating costs and expected future energy market conditions. See Note 8 — Property, Plant, and Equipment for additional information regarding depreciation, and Note 22 — Supplemental Financial Information for additional information regarding amortization expense of nuclear fuel.
Asset Retirement Obligations
We estimate and recognize a liability for our legal obligation to perform asset retirement activities even though the timing and/or methods of settlement may be conditional on future events. We generally update our nuclear decommissioning AROs annually, unless circumstances warrant more frequent updates, based on our annual evaluation of cost escalation factors and probabilities assigned to the multiple outcome scenarios within our probability-weighted discounted cash flow models. Our multiple outcome scenarios are generally based on decommissioning cost studies which are updated, on a rotational basis, for each of our nuclear units at least every five years, unless circumstances warrant more frequent updates. AROs are accreted throughout each year to reflect the time value of money for these present value obligations through a charge to Operating and
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maintenance expense in the Consolidated Statements of Operations and Comprehensive Income for Non-Regulatory Agreement Units and through an offsetting decrease in noncurrent payables related to Regulatory Agreement Units. See Note 10 — Asset Retirement Obligations for additional information.
Accounting Implications of the Regulatory Agreement Units
Based on the requirements of the ICC, PAPUC, and PUCT that dictate our obligations related to the shortfall or excess of NDT funds necessary for decommissioning the former ComEd, former PECO, and STP units, decommissioning-related activities net of applicable taxes, including realized and unrealized gains and losses on the NDT funds, depreciation of the ARC, and accretion of the decommissioning obligation are generally offset in the Consolidated Statements of Operations and Comprehensive Income and are recorded as noncurrent payables within Payables related to Regulatory Agreement Units in the Consolidated Balance Sheets. See Note 10 — Asset Retirement Obligations for additional information.
Asset Impairments
Long-Lived Assets. We regularly monitor and evaluate the carrying value of long-lived assets or asset groups for recoverability whenever events or changes in circumstances indicate that the carrying value of those assets may not be recoverable. Indicators of impairment may include a deteriorating business climate, including, but not limited to, declines in energy prices, condition of the asset, or plans to dispose of a long-lived asset significantly before the end of its useful life. We determine if long-lived assets or asset groups are potentially impaired by comparing the undiscounted expected future cash flows to the carrying value when indicators of impairment exist. When the undiscounted cash flow analysis indicates a long-lived asset or asset group may not be recoverable, the amount of the impairment loss is determined by measuring the excess of the carrying amount of the long-lived asset or asset group over its fair value. Impairment losses are recorded in Operating and maintenance expense in the Consolidated Statements of Operations and Comprehensive Income.
Goodwill. Goodwill represents the excess of the purchase price paid over the estimated fair value of the net assets acquired and liabilities assumed in the acquisition of a business. Goodwill is not amortized, but is tested for impairment at least annually or on an interim basis if an event occurs or circumstances change that would more likely than not reduce the fair value of a reporting unit below its carrying value. See Note 2 — Mergers, Acquisitions, and Dispositions and Note 12 — Intangible Assets for additional information.
Equity Method Investments. We regularly monitor and evaluate equity method investments to determine whether they are impaired. An impairment is recorded when the investment has experienced a decline in value that is other-than-temporary in nature. Additionally, if the entity in which we hold an investment recognizes an impairment loss, we would record the proportionate share of that impairment loss and evaluate the investment for an other-than-temporary decline in value. These impairment losses are recorded in Equity in income (losses) of unconsolidated affiliates in the Consolidated Statements of Operations and Comprehensive Income.
Derivative Financial Instruments
All derivatives are recognized on the balance sheet at their fair value unless they qualify for certain exceptions, including NPNS. For derivatives intended to serve as economic hedges, changes in fair value are recognized in earnings each period. Amounts classified in earnings are included in Operating revenues, Purchased power and fuel, or Interest expense in the Consolidated Statements of Operations and Comprehensive Income based on the activity the transaction is economically hedging. Cash inflows and outflows related to derivative instruments are included as a component of operating, investing, or financing cash flows in the Consolidated Statements of Cash Flows, depending on the nature of each transaction.
As part of our customer-facing business, we enter into contracts to buy and sell energy to meet the requirements of our customers. These contracts include short-term and long-term commitments to purchase and sell energy and energy-related products in the energy markets with the intent and ability to deliver or take delivery of the underlying physical commodity. NPNS are contracts where physical delivery is probable, quantities are expected to be used or sold in the normal course of business over a reasonable period and will not be financially settled. Revenues and expenses on derivative contracts that qualify, and are designated, as NPNS are recognized when the underlying physical transaction is completed. While these contracts are considered derivative financial instruments, they are not required to be recorded at fair value. See Note 15 — Derivative Financial Instruments for additional information.
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Retirement Benefits
We sponsor defined benefit pension and OPEB plans as described in Note 14 — Retirement Benefits. The plan obligations and costs of providing benefits under these plans are remeasured annually as of year end. The measurements involve various factors, assumptions, and accounting policy elections. The impact of assumption changes or experiences different from that assumed on pension and OPEB obligations are recognized over time, not immediately in the Consolidated Statements of Operations and Comprehensive Income. For defined benefit pension plans, gains or losses exceeding the greater of 10% of the PBO or the MRV of plan assets are amortized over the expected average remaining service period of plan participants. For OPEB plans, gains or losses exceeding the greater of 10% of the APBO or the MRV of plan assets are amortized over the average future remaining lifetime of the current inactive population.
We separately report the pension and OPEB service cost and non-service cost (credit) components of net periodic benefit costs (credits) for all plans in our Consolidated Statements of Operations and Comprehensive Income. The service cost component remains in Operating and maintenance expense and Property, plant, and equipment, net (where criteria for capitalization of direct labor has been met) while the non-service cost (credit) components are included in Other, net, in accordance with single-employer plan accounting.
Renewable Energy Certificates/Credits
RECs are included in Renewable energy credits in the Consolidated Balance Sheets. Purchased RECs are recorded at cost when delivered and internally generated RECs are recognized at a zero-cost basis when generated. The cost of RECs purchased on a stand-alone basis is based on the transaction price, while the cost of RECs acquired through PPAs represents the relative fair value at contract inception. Generally, revenue for RECs that are sold to a counterparty under a contract that specifically identifies a power plant is recognized at a point in time when the power is produced. This includes both bundled and unbundled REC sales. Otherwise, the revenue is recognized upon physical transfer of the REC to the customer.

2. Mergers, Acquisitions, and Dispositions
Acquisition of Calpine Corporation
On January 7, 2026, we acquired all the outstanding equity interest of Calpine in a cash and stock transaction for a purchase price of approximately $ 22 billion. The merger consideration consisted of an aggregate of 50 million newly issued shares of our common stock, no par value, and approximately $ 4.5 billion in cash. In connection with the merger, the newly issued shares will be subject to a lock-up period which expires on June 30, 2026 for 50 % of the shares and on June 30, 2027 for the remaining 50 %. For information on the debt assumed as part of the transaction, see Note 16 — Debt and Credit Agreements.
Calpine owns and operates a generation fleet of natural gas, geothermal, battery storage, and solar assets with approximately 23 GWs of generation capacity, after considering divestitures required by certain regulatory approvals for the transaction, including the DOJ resolution. This resolution was the final regulatory clearance to complete the merger of Calpine and Constellation. The DOJ resolution requires that we divest five generating assets located in PJM, one in ERCOT, and Calpine's minority interest in the Gregory Power Plant, also in ERCOT. Four of these assets were already subject to FERC divestiture requirements. The DOJ resolution requires us to enter into definitive agreement(s) to divest these assets within 240 days of closing the Calpine acquisition, i.e., by September 4, 2026. In January 2026, Calpine completed the divestiture of its minority ownership interest in the Gregory Power Plant as required under the terms of the DOJ resolution. We are taking steps to divest the remaining six power plants. In addition to operating a large generation fleet, Calpine also operates a competitive retail electric supplier platform serving approximately 62 TWhs of load annually.
The transaction will be accounted for as a business combination using the acquisition method of accounting and we will record the fair value of the assets acquired and liabilities assumed as of the acquisition date. We expect that the consideration transferred is greater than the fair value of the net assets acquired, and therefore we anticipate recording goodwill on the opening balance sheet. Due to the recency of the acquisition date, the preliminary acquisition valuation for the business combination is incomplete at this time. Disclosures related to the acquisition date fair value of the assets acquired and liabilities assumed, among other acquisition-related disclosures, will be included in our March 31, 2026 Form 10-Q.
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Note 2 — Mergers, Acquisitions, and Dispositions

Fees incurred as part of the acquisition were not material to the Consolidated Statements of Operations and Comprehensive Income for the twelve months ended December 31, 2025.
Acquisition of Joint Ownership in South Texas Project
In November 2023, we completed the acquisition of NRG South Texas LP (renamed and converted as Constellation South Texas, LLC), which owns a 44 % undivided ownership interest in the jointly-owned STP, a 2,645 MW, dual-unit nuclear plant located in Bay City, Texas. The consideration transferred was $ 1.66  billion. Other owners include City Public Service Board of San Antonio (CPS, 40 %) and the City of Austin, Texas (Austin, 16 %). This acquisition is complementary to and aligned strategically with our existing clean energy business operations.
The operating revenues and results of operations for STP have been included in the Consolidated Statements of Operations and Comprehensive Income from the date of acquisition and were not material for the year ended December 31, 2023. The pro forma effects of this acquisition were not significant to our reported results for the period of acquisition. Accordingly, no pro forma financial information has been presented herein.
In May 2024, we executed a settlement agreement with all parties (CPS/City of San Antonio, Austin, and NRG Energy, Inc.), resolving all litigation involving our purchase of the ownership interest in STP. The terms of the settlement include us selling a 2 % ownership interest in STP to CPS at the same price and terms that we paid NRG Energy Inc. for our 44 % interest. We are working towards closing the transaction which has already received regulatory approvals (including the NRC and PUCT). The terms of settlement are not expected to have a material impact on our results of operations and financial condition.

3.   Regulatory Matters
The following matters below discuss the status of our material regulatory and legislative proceedings.
New England Regulatory Matters
Mystic Units 8 and 9 Cost of Service Agreement. In December 2018, FERC issued an order accepting a cost of service agreement for Mystic Units 8 and 9 for the period between June 1, 2022 to May 31, 2024. The agreement preserved the two gas-fired electric generating units for the period while allowing the Mystic units to recover their costs of operating, including a substantial portion of the costs associated with the adjacent EMT. Upon the expiration of the agreement on May 31, 2024, the two generating units retired.
The Mystic COS required an annual process whereby we identified and supported our projected costs under the agreement and/or true-up previous projections to the actual costs incurred. Interested parties then had the opportunity to challenge our filings. All proceedings related to the annual files or outstanding matters related to the Mystic COS have been settled and approved by FERC. The settlements did not have a material financial impact on our consolidated financial statements.
Federal Regulatory Matters
One Big Beautiful Bill Act of 2025. In July 2025, the OBBBA was signed into law, which, among other things, permanently extends key provisions of the 2017 Tax Cuts and Jobs Act, including full bonus depreciation and immediate deduction of research and development expenses. In addition, the OBBBA preserves transferability and certain federal tax credits from the IRA, specifically, 45U for existing nuclear plants through 2032 and 45Y for new nuclear projects, including uprates, restarts, and new reactors, through 2035, while enhancing the credit to allow advanced nuclear facilities to qualify for the energy communities bonus adder, subject to eligibility requirements. As it relates to both 45U and 45Y, certain foreign entity of concern rules must be met to qualify for the respective credits. Overall, the OBBBA reinforces the long-term economic viability of our nuclear generation assets. While the provisions of the OBBBA resulted in acceleration of cash benefits of approximately $ 200 million, the impact of these provisions recognized in the year ended December 31, 2025 was not material to our results of operations.
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Note 3 — Regulatory Matters

Operating License Renewals
Conowingo Hydroelectric Project. In 2012, we submitted an application to FERC for a new license for the Conowingo Hydroelectric Project (Conowingo). In connection with our efforts to obtain a water quality certification pursuant to Section 401 of the Clean Water Act (401 Certification) from MDE for Conowingo, we had been working with MDE and other stakeholders to resolve water quality licensing issues, including: (1) water quality, (2) fish habitat, and (3) sediment.
In 2019, we and MDE filed with FERC a Joint Offer of Settlement (Offer of Settlement) that would resolve all outstanding issues relating to the 401 Certification. FERC subsequently issued a new 50-year license for Conowingo, effective March 1, 2021. Several environmental groups appealed FERC’s ruling to the U.S. Court of Appeals for the D.C. Circuit. The court of appeals issued a decision vacating FERC’s decision to grant Conowingo its license renewal and sending the matter back to FERC for further proceedings. Upon issuance of the mandate from the U.S. Court of Appeals for the D.C. Circuit, we began operating under an annual license, which renews automatically, containing the same terms as the license that was in effect prior to the 2021 FERC order. MDE informed us that as a result of the U.S. Court of Appeals decision, MDE would be resuming its administrative reconsideration of the 401 Certification.
In September 2025, we reached a settlement agreement with MDE and the other parties to the MDE reconsideration proceeding, Lower Susquehanna Riverkeeper Association, and Waterkeepers Chesapeake, which resolves all outstanding issues relating to the 401 Certification. As a result, MDE issued a Revised Water Quality Certification, which is needed for FERC to move forward with the issuance of a new 50-year license. The Revised Water Quality Certification and accompanying settlement agreement provide for a modified operational flow regime, funding for water quality and resiliency projects, commitments for trash and debris removal, fish and eel passage improvements, funding for freshwater mussel restoration and control of invasive species like snakeheads and blue catfish, and funds to support additional studies on dredging and related activities. Our commitments under the various provisions of this settlement are not effective unless and until FERC approves and issues the new license. The terms of this settlement have no impact on the prior settlement agreement with the DOI.
The financial impact of this settlement and other commitments related to this renewal are estimated to be $ 15 million to $ 20 million per year, on average, recognized over the term of the 50-year renewal, inclusive of capital and operating costs. The actual timing and amount of the majority of these costs are not currently fixed and will vary from year to year throughout the life of the new license. We cannot currently predict when FERC will issue the new license. Depreciation provisions continue to assume operation through 2071 given our expectation that a 50-year license will be issued.
Peach Bottom Units 2 and 3. In March 2020, the NRC approved a second 20-year license renewal for Peach Bottom Units 2 and 3. As a result, Peach Bottom Units 2 and 3 were granted the authority to operate through 2053 and 2054, respectively.
Notwithstanding its 2020 approval, in February 2022, the NRC took action to modify Peach Bottom's subsequently renewed licenses in response to a request for hearing that the NRC had not previously adjudicated. In its February 2022 decision, the NRC reversed itself and concluded that the previous environmental review required by the National Environmental Policy Act (NEPA) for the Peach Bottom subsequently renewed licenses was incomplete because it did not adequately address environmental impacts resulting from renewing the units’ licenses for an additional 20 years. As a result, the NRC undertook a rulemaking to modify its regulations and guidance to specifically address environmental impacts during the period of subsequent license renewal. In addition, the NRC modified the expiration dates for the Peach Bottom licenses from 2053 and 2054 to 2033 and 2034, respectively, pending the completion of the updated NEPA analysis.
In September 2025, the NRC completed its environmental impact review of Peach Bottom Units 2 and 3, restoring the expiration dates of the respective operating licenses to 2053 and 2054, consistent with current accounting estimates utilized for both depreciation and ARO assumed retirement dates.
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Note 4 — Revenue from Contracts with Customers

4. Revenue from Contracts with Customers
We recognize revenue from contracts with customers to depict the transfer of goods or services to customers at an amount that we expect to be entitled to in exchange for those goods or services. Our primary sources of revenue include competitive sales of power, natural gas, and other energy-related products and sustainable solutions. The performance obligations, revenue recognition, and payment terms associated with these sources of revenue are further discussed in the table below. There are no significant financing components for these sources of revenue.
Unless otherwise noted, for each of the significant revenue categories and related performance obligations described below, we have the right to consideration from the customer in an amount that corresponds directly with the value transferred to the customer for the performance completed to date. Therefore, we generally recognize revenue in the amount for which we have the right to invoice the customer. As a result, there are generally no significant judgments used in determining or allocating the transaction price.

Revenue Source Description Performance Obligation Timing of Revenue Recognition Payment Terms
Power Sales
Sales of power and other energy-related products to wholesale and retail customers through our customer-facing business Various, including the delivery of power (generally delivered over time) and other energy-related products such as capacity (generally delivered over time), CMCs, ZECs, RECs or other ancillary services (generally delivered at a point in time) Concurrently as power is generated for bundled power sale contracts (a)
Generally within the month following delivery to the customer

Natural Gas Sales
Sales of natural gas to wholesale and retail customers through our customer-facing business
Various, including the delivery of natural gas (generally delivered overtime) and sustainable natural gas attributes (generally delivered at a point in time)
Over time as the natural gas is delivered to the customer
Generally within the month following delivery to the customer

Other Products and Services
Sales of other energy-related products and sustainable solutions, such as long-term construction and installation of energy efficiency assets and new power generating facilities, primarily to C&I customers
Construction and/or installation of the asset for the customer
Revenues and associated costs are recognized throughout the contract term using an input method to measure progress towards completion (b)
Generally within 30 or 45 days from the invoice date

__________
(a) Certain contracts may contain limits on the total amount of revenue we are able to collect over the entire term of the contract. In such cases, we estimate the total consideration expected to be received over the term of the contract net of the constraint and allocate the expected consideration to the performance obligations in the contract such that revenue is recognized ratably over the term of the entire contract as the performance obligations are satisfied.
(b) The method recognizes revenue based on the various inputs used to satisfy the performance obligation, such as costs incurred and total labor hours expended. The total amount of revenue that will be recognized is based on the agreed upon contractually-stated amount. The average contract term for these projects is approximately 18 months.
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We incur incremental costs in order to execute certain retail power and gas sales contracts. These costs, which primarily relate to retail broker fees and sales commissions, are capitalized when incurred as contract acquisition costs and generally amortized over the corresponding term of the contract. These capitalized costs and related amortization were not material as of and for the years ended December 31, 2025 and 2024.
Transaction Price Allocated to Remaining Performance Obligations
The following table shows the amounts of future revenues expected to be recorded in each year for performance obligations that are unsatisfied or partially unsatisfied as of December 31, 2025. This disclosure only includes contracts for which the total consideration is fixed and determinable at contract inception. The average contract term varies by customer type and commodity but ranges from one month to several years. This disclosure excludes mark-to-market derivatives and certain power and gas sales contracts which contain variable volumes and/or variable pricing.

2026 2027 2028 2029 2030 2031 and thereafter Total
Remaining performance obligations $ 386   $ 269   $ 135   $ 117   $ 61   $ 79   $ 1,047  

Transaction Price Allocated to Previously Satisfied Performance Obligations
Our Clinton and Quad Cities units contract with certain utilities in Illinois which require delivery of all ZECs produced during each planning year (June through May), with total compensation limited by an annual cap for each planning year designed to limit the cost of ZECs to each utility's customers. ZECs delivered that, if paid, would result in the annual cap being exceeded may be paid in subsequent years at the vintage year price as long as the payments would not exceed the annual cap in the year paid. The program commenced June 2017 and continues through May 2027. In various planning years since the program began, we delivered ZECs to the utilities in excess of the annual compensation cap.
The ZEC price and annual compensation cap effective for each planning year are administratively determined by the IPA. For the June 2025 through May 2026 planning year, the ZEC price has been established at $1.17 per ZEC, subject to an annual cap of $224 million. ZECs generated and delivered during this planning year will not exceed the annual cap and, as a result, we recognized $ 201 million of revenue during the second quarter of 2025 as a receivable for ZECs delivered in prior planning years, with payment expected in the third quarter of 2026. As of December 31, 2025, this receivable is included within Accounts receivable, net in the Consolidated Balance Sheets.
For the June 2024 through May 2025 planning year, the ZEC price was established at $9.38 per ZEC, subject to an annual cap of $222 million. ZECs generated and delivered during this planning year did not exceed the annual cap, however the revenue recognized during the second quarter of 2024 for ZECs delivered in prior planning years was not material.
For the June 2023 through May 2024 planning year, the ZEC price was established at $0.30 per ZEC, subject to an annual cap of $224 million. ZECs generated and delivered during the planning year did not exceed the annual cap, and as a result we recognized $ 218 million of revenue during the second quarter of 2023, with payment received in the third quarter of 2024.
Revenue Disaggregation
We disaggregate the revenue recognized from contracts with customers into categories that depict how the nature, amount, timing, and uncertainty of revenue and cash flows are affected by economic factors. See Note 5 — Segment Information for the presentation of revenue disaggregation.
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Note 5 — Segment Information

5. Segment Information
Operating segments are determined based on information used by the CODM in deciding how to evaluate performance and allocate resources. We have five reportable segments consisting of the Mid-Atlantic, Midwest, New York, ERCOT, and all other power regions referred to collectively as “Other Power Regions.”
The basis for our reportable segments is the integrated management of our electricity business that is located in different geographic regions, and largely representative of the footprints of ISO/RTO and/or NERC regions, which utilize multiple supply sources to provide electricity through various distribution channels (wholesale and retail). Our hedging strategies and risk metrics are also aligned to these same geographic regions. Descriptions of each of our five reportable segments are as follows:
• Mid-Atlantic represents operations in the eastern half of PJM, which includes New Jersey, Maryland, Virginia, West Virginia, Delaware, the District of Columbia, and parts of Pennsylvania and North Carolina.
• Midwest represents operations in the western half of PJM and the United States footprint of MISO, excluding MISO’s Southern Region.
• New York represents operations within NYISO.
• ERCOT represents operations within Electric Reliability Council of Texas that covers a majority of the state of Texas.
• Other Power Regions:
• New England represents operations within ISO-NE.
• South represents operations in FRCC, MISO’s Southern Region, and the remaining portions of SERC not included within MISO or PJM.
• West represents operations in WECC, which includes CAISO.
• Canada represents operations across the entire country of Canada and includes AESO, OIESO, and the Canadian portion of MISO.
Constellation's CEO is considered the CODM and evaluates the performance of our electric business activities and allocates resources based on segment RNF, primarily through review of budget-to-actual variance analyses. RNF is Operating revenues net of Purchased power and fuel expenses. We believe this is a useful measurement of operational performance, although it is not a presentation defined under GAAP and may not be comparable to other companies’ presentations or deemed more useful than the GAAP information provided elsewhere in this report. In our evaluation of operating segments, we noted the CODM reviews a variety of performance and profitability measures at a consolidated level with a primary focus on RNF reporting at the regional level. Our operating revenues include all sales to third parties as well as government assistance. Purchased power and fuel expenses are considered the significant segment expense. Purchased power costs include all costs associated with the procurement and supply of electricity including capacity, energy, and ancillary services. Fuel expense includes the fuel costs for our owned generation and fuel costs associated with tolling agreements. The results of our other business activities are not regularly reviewed by the CODM and are therefore not classified as operating segments or included in the regional reportable segment amounts. These activities include wholesale and retail sales of natural gas, energy-related sales in the United Kingdom, as well as sales of other energy-related products and sustainable solutions that are not significant to our overall results of operations. Further, our unrealized gains and losses on economic hedging activities and our amortization of certain intangible assets and liabilities relating to commodity contracts recorded at fair value from mergers and acquisitions are also excluded from the regional reportable segment amounts. The CODM does not use a measure of total assets in making decisions regarding allocating resources to or assessing the performance of these reportable segments.
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Note 5 — Segment Information

The following tables disaggregate the revenue recognized from contracts with customers into categories that depict how the nature, amount, timing, and uncertainty of revenue and cash flows are affected by economic factors. The disaggregation of revenues reflects our power sales by geographic region.
The following tables, which relate directly to our Consolidated Statements of Operations and Comprehensive Income, provide the reconciliation of operating revenues, purchased power and fuel expenses, and RNF for our reportable segments for the years ended December 31, 2025, 2024, and 2023.

2025 Revenues from contracts with customers
Other revenues (a)
Total Operating revenues
Total Purchased power and fuel expenses
Total RNF

Mid-Atlantic $ 6,461   $ 26   $ 6,487   $ ( 3,076 ) $ 3,411  
Midwest 5,288   516   5,804   ( 2,102 ) 3,702  
New York 2,389   ( 199 ) 2,190   ( 590 ) 1,600  
ERCOT 1,296   608   1,904   ( 767 ) 1,137  

Other Power Regions  4,865   718   5,583   ( 4,764 ) 819  
Total Reportable Segments
20,299   1,669   21,968   ( 11,299 ) 10,669  
Other (b)
2,364   1,201   3,565   ( 3,382 ) 183  
Total Consolidated Results
$ 22,663   $ 2,870   $ 25,533   $ ( 14,681 ) $ 10,852  

2024
Mid-Atlantic $ 5,429   $ 93   $ 5,522   $ ( 2,442 ) $ 3,080  
Midwest 3,848   957   4,805   ( 1,603 ) 3,202  
New York 1,937   113   2,050   ( 597 ) 1,453  
ERCOT 1,053   497   1,550   ( 503 ) 1,047  

Other Power Regions 4,749   757   5,506   ( 4,238 ) 1,268  
Total Reportable Segments
17,016   2,417   19,433   ( 9,383 ) 10,050  
Other (b)
1,948   2,187   4,135   ( 2,036 ) 2,099  
Total Consolidated Results
$ 18,964   $ 4,604   $ 23,568   $ ( 11,419 ) $ 12,149  

2023
Mid-Atlantic $ 5,453   $ ( 315 ) $ 5,138   $ ( 2,214 ) $ 2,924  
Midwest 4,846   ( 188 ) 4,658   ( 1,403 ) 3,255  
New York 1,910   111   2,021   ( 770 ) 1,251  
ERCOT 1,232   114   1,346   ( 764 ) 582  

Other Power Regions 4,956   895   5,851   ( 4,611 ) 1,240  
Total Reportable Segments
18,397   617   19,014   ( 9,762 ) 9,252  
Other (b)
2,444   3,460   5,904   ( 6,239 ) ( 335 )
Total Consolidated Results
$ 20,841   $ 4,077   $ 24,918   $ ( 16,001 ) $ 8,917  

__________
(a) Includes revenues from nuclear PTCs beginning in 2024 as well as derivatives and leases. Intersegment activity in all periods presented is not material.
(b) Represents revenue activities not allocated to a region. See text above for a description of included activities. Other includes unrealized losses of ($ 805 ) million, and unrealized gains of $ 316 million and $ 1,399 million, and natural gas revenues from contracts with customers of $ 1,758 million, $ 1,429 million, and $ 1,859 million, for the years ended December 31, 2025, 2024, and 2023, respectively.
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Combined Notes to Consolidated Financial Statements
(Dollars in millions, unless otherwise noted)

Note 6 — Government Assistance

6. Government Assistance
Beginning in 2024, our nuclear units are eligible for a PTC extending through 2032. The nuclear PTC provides a transferable credit up to $15 per MWh (a base credit of $3 per MWh with a five times multiplier provided certain prevailing wage requirements are met) and is subject to phase-out when annual gross receipts are between $25.00 per MWh and $43.75 per MWh and $26.00 per MWh and $44.75 per MWh for 2024 and 2025, respectively. We evaluated and expect to meet the annual prevailing wage requirements at all of our nuclear units and are eligible for the five times multiplier. Both the amount of the PTC and the gross receipts thresholds adjust for inflation annually through the duration of the program based on the GDP price deflator for the preceding calendar year. The benefits of the PTC may be realized through a credit against our federal income taxes or transferred via sale to an unrelated party. In July 2025, Congress passed the OBBBA which affirmed the provisions of the nuclear PTC with no material changes.
For the years ended December 31, 2025 and 2024, our Consolidated Statements of Operations and Comprehensive Income included an estimated nuclear PTC benefit in Operating revenues of approximately $ 320 million and $ 2,080 million, respectively. Our estimates require the exercise of judgment in determining the amount of nuclear PTC expected for each of our nuclear units. The nuclear PTC continues to be the subject of additional guidance, from the U.S. Treasury and IRS, and may materially impact the total amount of the benefits we receive.
Nuclear PTCs are initially recorded within Other deferred debits and other assets within the Consolidated Balance Sheets and reclassified as a reduction to Accounts payable and accrued expenses when used to reduce our federal income tax payable, or an increase in Cash and cash equivalents or Other current assets when sold, depending on the specific payment terms of each contract.
There were no sales agreements for nuclear PTCs in 2025. In 2024, we executed agreements for the sale of $ 1,750 million of nuclear PTCs to unaffiliated third parties at a nominal discount, with approximately $ 1,570 million of cash proceeds received upon sale that were included within Cash flows from operating activities in our Consolidated Statements of Cash Flows. Cash received in 2025 on sale agreements executed in 2024 was approximately $ 95 million. Our Consolidated Balance Sheets reflected estimated nuclear PTCs of approximately $ 120 million within Other deferred debits and other assets as of December 31, 2025, and $ 185 million and $ 95 million within Other deferred debits and other assets, and within Other current assets , respectively, as of December 31, 2024. Additionally, during the years ended December 31, 2025 and 2024, we recognized a reduction to Accounts payable and accrued expenses of $ 375 million and $ 150 million, respectively, for estimated nuclear PTCs that we have utilized as a credit against our current federal income taxes payable.
Many of the state-sponsored programs providing compensation for the emissions-free attributes of generation from certain of our nuclear units include contractual or other provisions that require us to refund that compensation up to the amount of the nuclear PTC received or pass through the entirety of the nuclear PTC received. As of December 31, 2025 and 2024, we have recognized approximately $ 1,190 million and $ 1,030 million, respectively, of estimated payables within Other deferred credits and other liabilities , Accounts payable and accrued expenses or as offsets to Accounts receivable, net in our Consolidated Balance Sheets associated with programs requiring refunds or pass through of the nuclear PTC. In general, we expect to remit refunds or pass-throughs of state-sponsored program compensation related to nuclear PTCs in the year following the filing of the related tax return. We recognized a reduction to net operating revenue of approximately $ 125 million and $ 50 million, respectively, associated with these programs in our Consolidated Statements of Operations and Comprehensive Income for the years ended December 31, 2025 and 2024. As with the actual amount of the nuclear PTC earned, any change resulting from additional guidance received may materially impact amounts due under state-sponsored programs.
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Combined Notes to Consolidated Financial Statements
(Dollars in millions, unless otherwise noted)

Note 7 — Accounts Receivable

7. Accounts Receivable
The following table provides additional information on the disaggregation of customer and other accounts receivable:

Accounts receivable, net
December 31, 2025 CEG Parent Constellation
Customer accounts receivable (net of allowance for credit losses of $ 158 for CEG Parent and Constellation)
$ 3,577   $ 3,577  
Other accounts receivable (net of allowance for credit losses of $ 9 for CEG Parent and Constellation)
689   674  
Total $ 4,266   $ 4,251  

December 31, 2024
Customer accounts receivable (net of allowance for credit losses of $ 190 for CEG Parent and Constellation)
$ 3,116   $ 3,116  
Other accounts receivable (net of allowance for credit losses of $ 6 for CEG Parent and Constellation)
602   587  
Total $ 3,718   $ 3,703  

Allowance for Credit Losses on Accounts Receivable
The following table presents the rollforward of allowance for credit losses on customer accounts receivable from January 1, 2024 to December 31, 2025:

2025 2024
Balance as of January 1 $ 190   $ 56  
Current period provision for expected credit losses 47   17  
Write-offs, net of recoveries (a)
( 79 ) ( 21 )
Facility amendment impact (b)
—   138  
Balance as of December 31 $ 158   $ 190  

__________
(a) Recoveries were not material.
(b) Impact as a result of the December 2024 amendment of our revolving accounts receivable financing arrangement. See below for details.
The allowance for credit losses on other accounts receivable was not material as of the balance sheet dates, therefore, a rollforward is not presented.
Unbilled Customer Revenue
We recorded $ 1,305 million and $ 1,109  million of unbilled customer revenues in Accounts receivable, net in the Consolidated Balance Sheets as of December 31, 2025 and 2024, respectively.
Sales of Customer Accounts Receivable
In 2020, NER, a bankruptcy remote, special purpose entity, which is wholly owned by us, entered a revolving accounts receivable financing arrangement with a number of financial institutions and a commercial paper conduit (Purchasers) to sell certain customer accounts receivables (Facility). On December 31, 2024, we amended the Facility. We will no longer sell receivables to the Purchasers and all outstanding receivables were assigned back to us. Under the Facility's prior terms, NER sold eligible short-term customer accounts receivable to the Purchasers in exchange for cash and subordinated interest. The transfers were reported as sales of receivables in the consolidated financial statements. The subordinated interest in collections upon the receivables sold to the Purchasers is referred to as the DPP. As a result of the receivables being assigned back to NER under the amended Facility, NER forgave any and all remaining DPP owed by the Purchasers. The reassignment of receivables resulted in the recognition of $ 1,529 million of Accounts receivable, net as of December 31, 2024. See Note 16 — Debt and Credit Agreements for terms of the amended Facility.
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(Dollars in millions, unless otherwise noted)

Note 7 — Accounts Receivable

The following table summarizes our cash proceeds associated with the Facility prior to the amendment:

For the Years Ended December 31,
2024 2023
Proceeds from new transfers (a)
$ 1,688   $ 3,649  
Cash collections received on DPP (b)
10,517   8,140  
Cash collections reinvested in the Facility $ 12,205   $ 11,789  

_________
(a) Customer accounts receivable sold into the Facility were $ 12,262 million and $ 11,746 million for the years ended December 31, 2024, and 2023, respectively.
(b) Does not include the $ 300  million and $ 800  million net cash payments to the Purchasers in 2024 and 2023, respectively, in order to reduce the outstanding borrowing amount under the Facility.
We previously recognized the cash proceeds received upon sale in Cash flows from operating activities within the Changes in Other assets and liabilities line in the Consolidated Statements of Cash Flows, which were ($ 10,574 ) million and ($ 8,097 ) million for the years ended December 31, 2024, and 2023, respectively. The collection and reinvestment of DPP was recognized in Cash flows from investing activities in the Collection of DPP, net line in the Consolidated Statements of Cash Flows, which was $ 10,217 million, and $ 7,340 million for the years ended December 31, 2024, and 2023, respectively.
See Note 21 — Variable Interest Entities for additional information on NER.
Other Sales of Customer Accounts Receivables
We are required, under supplier tariffs, to sell customer receivables to certain utility companies at a nominal discount. The total gross receivables sold were $ 4,204 million, $ 280 million, and $ 356 million for the years ended December 31, 2025, 2024, and 2023, respectively. Prior to the Facility amendment discussed in the preceding paragraphs, certain accounts receivable subject to these supplier tariffs were sold to the Purchasers under the Facility.

8. Property, Plant, and Equipment
The following table presents a summary of property, plant, and equipment by asset category as of December 31, 2025 and 2024:

Asset Category December 31, 2025 December 31, 2024
Electric $ 33,253   $ 32,156  
Nuclear fuel (a)
6,298   5,894  
CWIP
1,995   1,273  

Total property, plant, and equipment 41,546   39,323  
Less: accumulated depreciation (b)
19,072   18,088  
Property, plant, and equipment, net $ 22,474   $ 21,235  
__________
(a) Includes nuclear fuel that is in the fabrication and installation phase of $ 1,674  million and $ 1,485  million as of December 31, 2025 and 2024, respectively.
(b) Includes accumulated amortization of nuclear fuel in the reactor core of $ 2,622  million and $ 2,447  million as of December 31, 2025 and 2024, respectively.
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(Dollars in millions, unless otherwise noted)

Note 8 — Property, Plant, and Equipment

The estimated useful lives of our generating facilities are based on a combination of depreciation studies, historical retirements, site licenses and management estimates of operating costs and expected energy market conditions. The estimated useful lives of our nuclear stations generally include expectations for an additional 20-year term beyond current license expiration, except for Calvert Cliffs, FitzPatrick, Limerick, NMP Unit 2, and STP where depreciation provisions correspond with the expiration of the current NRC operating license. The estimated useful lives of our hydroelectric facilities also generally align with their FERC operating licenses. Conowingo depreciation provisions are based on an estimated useful life through 2071, in anticipation that a 50 -year license will be issued. Generally, our oil and gas plants have estimated useful lives of 40 to 45 years with wind and solar generating facilities having estimated useful lives of 25 and 35 years, respectively. See Note 3 — Regulatory Matters for additional information regarding license renewals for Peach Bottom and Conowingo.
Annual depreciation rates for electric generation were 2.91 %, 3.43 %, and 3.26 % for the years ended December 31, 2025, 2024, and 2023, respectively. Nuclear fuel amortization is charged to fuel expense using the unit-of-production method based on the expected consumption period of the fuel, generally ranging from 1 to 8 years, and is excluded from the annual depreciation rates. See Note 22 — Supplemental Financial Information for additional information on nuclear fuel amortization.

9. Jointly-Owned Electric Plants
Our material undivided ownership interests in jointly-owned plants as of December 31, 2025 and 2024 were as follows:

NMP Unit 2 Quad Cities Peach Bottom
STP (a)
Salem
Operator Constellation Constellation Constellation STPNOC PSEG Nuclear
Ownership interest 82.00   % 75.00   % 50.00   % 44.00   % 42.59   %
Our share as of December 31, 2025

Plant in service $ 1,119   $ 1,324   $ 1,590   $ 1,064   $ 842  
Accumulated depreciation 363   852   752   98   402  
CWIP
53   29   25   23   101  
Our share as of December 31, 2024

Plant in service $ 1,122   $ 1,294   $ 1,570   $ 1,040   $ 791  
Accumulated depreciation 327   840   721   52   387  
CWIP
27   13   15   25   68  

__________
(a) Within the 44 % undivided ownership interest in STP, 2 % interest was recorded as held for sale as of December 31, 2025 and 2024. See Note 2 — Mergers, Acquisitions, and Dispositions for additional information.
Our undivided ownership interests are financed with our funds and all operations are proportionately consolidated consistent with our ownership interest in the Consolidated Statements of Operations and Comprehensive Income.

10. Asset Retirement Obligations
Nuclear Decommissioning Asset Retirement Obligations
We have a legal obligation to decommission our nuclear power plants following the permanent cessation of operations. To estimate our nuclear decommissioning obligations we use 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. We update our AROs annually, unless circumstances warrant more frequent updates, based on our review of updated cost studies and our annual evaluation of cost escalation factors and probabilities assigned to various scenarios.
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(Dollars in millions, unless otherwise noted)

Note 10 — Asset Retirement Obligations

The financial statement impact for changes in an ARO, on an individual unit basis, due to the changes in and timing of estimated cash flows generally result in a corresponding change in the unit’s ARC in Property, plant, and equipment in the Consolidated Balance Sheets. If an ARO decreases for a Non-Regulatory Agreement Unit without any remaining ARC, the corresponding change is recorded as a decrease in Operating and maintenance expense in the Consolidated Statements of Operations and Comprehensive Income, whereas the corresponding decrease for Regulatory Agreement Units without any remaining ARC results in an increase to the Payables related to Regulatory Agreement Units in the Consolidated Balance Sheets.
The following table provides a rollforward of the nuclear decommissioning AROs reflected in the Consolidated Balance Sheets from January 1, 2024 to December 31, 2025:

2025 2024
Beginning balance as of January 1
$ 12,186   $ 13,891  
Net increase (decrease) due to changes in, and timing of, estimated future cash flows
108   ( 2,299 )
Accretion expense 630   640  
Costs incurred related to decommissioning plants
( 16 ) ( 24 )
Reclassification to liabilities held for sale (a)
—   ( 22 )
Ending balance as of December 31
$ 12,908   $ 12,186  

__________
(a) Reflects amounts transferred to Liabilities held for sale for the sale of 2 % interest to CPS in connection with the 2023 acquisition of interest in STP. See Note 2 — Mergers, Acquisitions, and Dispositions for additional information.
The net $ 108  million increase in the AROs during 2025 for the changes in, and timing of, estimated future cash flows was driven primarily by higher escalation rates partially offset by higher discount rates and revised cost studies for our Braidwood, Byron, Clinton, and LaSalle nuclear plants .
The net $ 2,299  million decrease in the AROs during 2024 for changes in the amounts and timing of estimated decommissioning cash flows was driven by multiple adjustments, including the following:
• Net decrease of $ 3,036 million due to changes in assumed retirement dates for various plants, including Braidwood, Byron, Calvert Cliffs, FitzPatrick, LaSalle, Limerick, NMP Unit 2, Quad Cities, Salem and Crane
• A decrease of $ 154 million related to a change in assumed timing of DOE acceptance of SNF and a revised cost study for Salem
• An increase of $ 891 million due to an increase in cost escalation rates and lower discount rates
NDT Funds
NDT funds have been established for each of our nuclear units to satisfy our nuclear decommissioning obligations, as required by the NRC, and withdrawals from these funds for reasons other than to pay for decommissioning are restricted pursuant to NRC requirements until all decommissioning activities have been completed. Generally, NDT funds established for a particular unit may not be used to fund the decommissioning obligations of any other unit.
The NDT funds associated with our nuclear units have been funded with amounts collected from the previous owners and their respective utility customers. PECO is authorized to collect funds, in revenues, through regulated rates for decommissioning the former PECO nuclear plants, and these collections are scheduled through the operating lives of these former PECO plants. The amounts collected from PECO customers are remitted to us and deposited into the NDT funds for the unit for which funds are collected. Every five years, PECO files a rate adjustment with the PAPUC that reflects PECO’s calculations of the estimated amount needed to decommission each of the former PECO units based on updated fund balances and estimated decommissioning costs. The rate adjustment is used to determine the amount collectible from PECO customers. In March 2022, PECO filed its Nuclear Decommissioning Cost Adjustment with the PAPUC proposing an annual recovery from customers of approximately $ 4  million. In August 2022, the PAPUC approved the filing, and the new rates became effective January 1, 2023.
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(Dollars in millions, unless otherwise noted)

Note 10 — Asset Retirement Obligations

Additionally, for the STP units, we maintain decommissioning trust funds for those units proportionate to our ownership. We also retain the authority through the PUCT to obtain additional decommissioning funding through AEP Texas and CenterPoint. Every five years, owners of each Texas jurisdictional nuclear generation unit are required to file an update of decommissioning costs with the PUCT in support of appropriate utility rates for decommissioning trust funding. In July 2023, the decommissioning cost update for our share of the STP decommissioning obligation was filed, proposing annual funding amounts from AEP Texas and CenterPoint totaling approximately $ 1  million. In March 2024, the PUCT approved the filing, and AEP Texas and CenterPoint tariffs were adjusted accordingly in May and August 2024, respectively.
Any shortfall of funds necessary for decommissioning, determined for each generating station unit, are generally required to be funded by us, with the exception of STP and the former PECO units. We have recourse to collect additional amounts from the respective utility customers through the utility commissions for the former PECO units and STP in the event of a shortfall of NDT funds. Collection of additional amounts for the former PECO units are subject to certain limitations and thresholds, as prescribed by an order from the PAPUC that limits collection of amounts associated with the first $ 50  million of any shortfall of trust funds compared to decommissioning costs, as well as 5 % of any additional shortfalls, on an aggregate basis for all former PECO units. The initial $ 50  million and up to 5 % of any additional shortfalls would be borne by us. No such limitations exist for the STP units, however PUCT regulatio ns require that any funds remaining in the trust after completion of decommissioning to be refunded to utility customers in a manner determined by the commission. Aside from the former PECO units and STP, no recourse exists to collect additional amounts from utility customers for any of our other nuclear units.
With respect to the Regulatory Agreement Units, any funds remaining in the NDTs after all decommissioning has been completed are required to be refunded to the respective utility customers, subject to certain limitations that allow sharing of excess funds with us related to the former PECO units. With respect to our other nuclear units, we retain any funds remaining after decommissioning. However, in connection with CENG's acquisition of the NMP and Ginna plants and settlements with certain regulatory agencies, certain conditions pertaining to NDT funds apply that, if met, could possibly result in obligations to make payments to certain third parties (clawbacks). For NMP and Ginna, the clawback provisions are triggered only in the event that the required decommissioning activities are discontinued or not started or completed in a timely manner. In the event that the clawback provisions are triggered for NMP, then, depending upon the triggering event, an amount equal to 50 % of the total amount withdrawn from the funds for non-decommissioning activities as defined in the agreement or 50 % of any excess funds in the trust funds above the amounts required for decommissioning (including SNF management and site restoration) is to be paid to the NMP sellers. In the event that the clawback provisions are triggered for Ginna, then an amount equal to any estimated cost savings realized by not completing any of the required decommissioning activities is to be paid to the Ginna sellers. We expect to comply with applicable regulations and timely commence and complete all required decommissioning activities.
We had NDT funds totali ng $ 19,396  million and $ 17,321  million as of December 31, 2025 and 2024, respectively. The current portions of the NDT funds, which are included in Other current assets in our Consolidated Balance Sheets, were not material as of December 31, 2025 and 2024. See Note 22 — Supplemental Financial Information for additional information on activities of the NDT funds.
Accounting Implications of the Regulatory Agreement Units
See Note 1 — Basis of Presentation for additional information on the accounting policy for Regulatory Agreement Units. 
For the former PECO units and STP, given the symmetric settlement provisions that allow for continued recovery of decommissioning costs from the respective utility customers in the event of a shortfall and the obligation for us to ultimately return excess funds to the respective utility customers (on an aggregate basis for all seven former PECO units and on the underlying utility customer basis for STP) decommissioning-related activities are generally offset in the Consolidated Statements of Operations and Comprehensive Income, regardless of whether the NDT funds are expected to exceed or fall short of the total estimated decommissioning obligation. The offset of decommissioning-related activities in the Consolidated Statements of Operations and Comprehensive Income results in an equal adjustment to noncurrent payables or noncurrent receivables. Any changes to the existing PECO or STP regulatory agreements could impact our ability to offset decommissioning-related activities in the Consolidated Statements of Operations and Comprehensive Income, and the potential impact to our consolidated financial statements could be material.
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Combined Notes to Consolidated Financial Statements
(Dollars in millions, unless otherwise noted)

Note 10 — Asset Retirement Obligations

For the former ComEd units, given no further recovery from ComEd customers is permitted and we retain an obligation to ultimately return any unused NDTs to ComEd customers (on a unit-by-unit basis), to the extent the related NDT investment balances are expected to exceed the total estimated decommissioning obligation for each unit, decommissioning-related activities are offset in the Consolidated Statements of Operations and Comprehensive Income which results in us recognizing a noncurrent payable. However, given the asymmetric settlement provision that does not allow for continued recovery from ComEd customers in the event of a shortfall, recognition of a receivable related to former ComEd Units is not permissible and accounting for decommissioning-related activities for that unit would not be offset, and the impact to the Consolidated Statements of Operations and Comprehensive Income could be material during such periods.
The following table presents our noncurrent payables to ComEd, PECO, CenterPoint, and AEP Texas reflected as Payables related to Regulatory Agreement Units in the Consolidated Balance Sheets as of December 31, 2025 and 2024:

As of December 31,
2025 2024
ComEd $ 4,313   $ 3,780  
PECO 442   247  
CenterPoint
430   365  
AEP Texas
149   126  
Payables related to Regulatory Agreement Units $ 5,334   $ 4,518  

As of December 31, 2025, decommissioning-related activities for all of the former ComEd units, except for Zion (see Zion Station Decommissioning below), are currently offset in the Consolidated Statements of Operations and Comprehensive Income.
The decommissioning-related activities for the Non-Regulatory Agreement Units are reflected in the Consolidated Statements of Operations and Comprehensive Income within Operating and maintenance expense, Depreciation and amortization expense, and Other, net.
Zion Station Decommissioning
In 2010, we completed an asset sale agreement under which ZionSolutions assumed responsibility for decommissioning Zion Station and we transferred to ZionSolutions substantially all the Zion Station’s assets, including the related NDT funds. In November 2023, ZionSolutions completed its contractual obligations and transferred the NRC license back to us. We will store the SNF at Zion Station until it is transferred to the DOE for ultimate disposal and complete all remaining decommissioning activities associated with the SNF dry storage facility.
Any shortage of f unds necessary to maintain the SNF and decommission the SNF storage facility is ultimately required to be funded by us. As of December 31, 2025 and 2024, the ARO associated with Zion's SNF storage facility is $ 170 million and $ 163  million, respectively, and the NDT funds available to fund this obligation are $ 67 million and $ 63  million, respectively.
NRC Minimum Funding Requirements
NRC regulations require that licensees of nuclear generating facilities demonstrate reasonable assurance that funds will be available in specified minimum amounts for radiological decommissioning of the facility at the end of its life. The estimated decommissioning obligations are calculated using an NRC methodology that is different from the AROs recorded in the Consolidated Balance Sheets primarily due to differences in the type of costs included in the estimates, the basis for estimating such costs, and assumptions regarding the decommissioning alternatives to be used, potential license renewals, decommissioning cost escalation, and the growth rate in the NDT funds. Under NRC regulations, if the minimum funding requirements for radiological decommissioning calculated under the NRC methodology are greater than the future value of the NDT funds, also calculated under the NRC methodology, then the NRC requires resolution of the shortfalls which could include further funding or other financial guarantees.
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(Dollars in millions, unless otherwise noted)

Note 10 — Asset Retirement Obligations

Key assumptions used in the minimum funding calculation for radiological decommissioning costs using the NRC methodology at December 31, 2025 include: (1) consideration of costs only for the removal of radiological contamination at each unit; (2) the option on a unit-by-unit basis to use generic, non-site specific cost estimates; (3) consideration of only one decommissioning scenario for each unit; (4) the plants cease operation at the end of their current license lives (with no assumed license renewals for those units that have not already received renewals); (5) the assumption of current nominal dollar cost estimates that are neither escalated through the anticipated period of decommissioning, nor discounted using the CARFR; and (6) assumed annual after-tax returns on the NDT funds o f 2 % ( 3 % f or the former PECO units, as specified by the PAPUC).
In contrast, the key criteria and assumptions used by us to determine the AROs and to forecast the target growth in the NDT funds as of December 31, 2025 include: (1) the use of site specific cost estimates that are updated at least once every five years; (2) the inclusion in the ARO estimate of all legally unavoidable costs required to decommission the unit (e.g., radiological decommissioning and full site restoration for certain units, on-site SNF maintenance and storage subsequent to ceasing operations and until DOE acceptance, and disposal of certain LLRW); (3) as applicable, the consideration of multiple scenarios where decommissioning and site restoration activities, as applicable, are completed under possible scenarios ranging from 10 to 70 years after the cessation of plant operations or the end of the current licensed operating life; (4) the consideration of multiple end of life scenarios; (5) the measurement of the obligation at the present value of the future estimated costs and an annual accretion of the ARO; and (6) an estimated targeted annual pre-tax return on the N DT fun ds of 6.2 % to 7.1 % (as compared to a historical 5-year annual average pre-tax return of approximatel y 6.8 %).
We are required to provide to the NRC a biennial report by unit (annually for units that have been retired or are within five years of license expiration), based on values as of December 31, addressing our ability to meet the NRC minimum funding levels. Depending on the value of the trust funds, we may be required to take steps, such as providing financial guarantees through surety bonds, 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 NRC minimum funding requirements are met. As a result, our cash flows and financial position may be significantly adversely affected.
We filed our biennial decommissioning funding status report with the NRC in March 2025 for all units, including our shutdown units, except for STP units which were included in a separate report submitted to the NRC submitted by STPNOC. The status reports demonstrated adequate decommissioning funding assurance based on trust fund values as of December 31, 2024 for all units except for Peach Bottom Unit 1. Financial assurance for decommissioning Peach Bottom Unit 1 is provided by collections from PECO customers. See NDT Funds section above for additional information.
We will file the next decommissioning funding status report with the NRC in M arch 2026. This report will reflect the status of decommissioning funding as of December 31, 2025 for shutdown units and any units within 5 years of license expiration. We expect the funding status report to demonstrate adequate funding assurance based on the value of trust funds as of December 31, 2025 for all units.
As the future values of trust funds change due to market conditions, the NRC minimum funding status of our units will change. In addition, if changes occur to the regulatory agreements with the PAPUC or the PUCT that currently allow amounts to be collected from utility customers for decommissioning the former PECO and STP units, the NRC minimum funding status of those plants could change at subsequent NRC filing dates.
Non-Nuclear Asset Retirement Obligations
We have AROs for plant closure costs associated with our natural gas, oil, and renewable generating facilities, including asbestos abatement, removal of certain storage tanks, restoring leased land to the condition it was in prior to construction of renewable generating stations, disposal of hazardous materials, and other decommissioning-related activities. See Note 1 — Basis of Presentation for additional information on the accounting policy for AROs. 
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(Dollars in millions, unless otherwise noted)

Note 10 — Asset Retirement Obligations

The following table provides a rollforward of the non-nuclear AROs reflected in the Consolidated Balance Sheets from January 1, 2024 to December 31, 2025:

2025 2024
Beginning balance as of January 1
$ 288   $ 257  
Net increase due to changes in, and timing of, estimated future cash flows
12   19  
Accretion expense 17   15  

Costs incurred related to decommissioning plants
—   ( 3 )

Ending balance as of December 31
$ 317   $ 288  

11. Leases
Lessee
We have operating leases for which we are the lessee. The significant types of operating leases are contracted generation and real estate. The following table outlines other terms and conditions of the lease agreements as of December 31, 2025. We did not have material finance leases in 2025, 2024, or 2023.

In Years
Remaining lease terms 1 - 30

Options to extend the term 2 - 30

Options to terminate within 2

The components of operating lease costs were as follows:

For the Years Ended December 31,
2025 2024 2023
Operating lease costs $ 104   $ 105   $ 96  
Variable lease costs 109   145   146  

Total lease costs (a)
$ 213   $ 250   $ 242  

__________
(a) Excludes $ 50  million of sublease income recorded for each of the years ended December 31, 2025, 2024, and 2023.
The following table provides additional information regarding the presentation of operating lease ROU assets and lease liabilities in the Consolidated Balance Sheets:

As of December 31,
2025 2024
Operating lease ROU assets (a)

Other deferred debits and other assets $ 371   $ 436  

Operating lease liabilities (a)

Other current liabilities 72   72  
Other deferred credits and other liabilities 433   511  
Total operating lease liabilities $ 505   $ 583  

__________
(a) The operating ROU assets and lease liabilities include $ 141  million and $ 241  million, respectively, related to contracted generation as of December 31, 2025, and $ 176  million and $ 289  million, respectively, as of December 31, 2024.

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Combined Notes to Consolidated Financial Statements
(Dollars in millions, unless otherwise noted)

Note 11 — Leases

The weighted average remaining lease terms, in years, and the weighted average discount rates for operating leases were as follows:

As of December 31,
2025 2024 2023
Weighted average remaining lease term 6.7 7.4 8.4
Weighted average discount rate 5.1   % 5.0   % 5.0   %

The following table reconciles the undiscounted cash flows for our operating leases to the operating lease liabilities recorded on our consolidated balance sheet as of December 31, 2025:

2026 $ 104  
2027 104  
2028 105  
2029 103  
2030 63  
2031 and thereafter 159  
Total lease payments 638  
Less: Imputed interest 133  
Operating lease liabilities $ 505  

Supplemental cash flow information related to operating leases was as follows:

For the Years Ended December 31,
2025 2024 2023
Cash paid for amounts included in the measurement of operating lease liabilities $ 90   $ 87   $ 102  
ROU assets obtained in exchange for operating lease obligations 2   6   13  

Lessor
We have operating leases for which we are the lessor. The significant types of operating leases are contracted generation and real estate. The following table outlines other terms and conditions of the lease agreements as of December 31, 2025.

In Years
Remaining lease terms 1 - 15

Options to extend the term 5 - 20

The components of lease income were as follows:

For the Years Ended December 31,
2025 2024 2023
Operating lease income $ 51   $ 51   $ 51  
Variable lease income 231   244   248  

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(Dollars in millions, unless otherwise noted)

Note 11 — Leases

The following table presents the lease payments we expect to receive over the remaining terms as of December 31, 2025:

2026 $ 50  
2027 50  
2028 50  
2029 48  
2030 9  
2031 and thereafter 29  
Total $ 236  

12. Intangible Assets
Goodwill
See Note 1 — Basis of Presentation for our policy regarding goodwill. Our operating segments are also considered reporting units for goodwill impairment assessment purposes.
The following table provides a rollforward of the carrying amount of goodwill from January 1, 2024 to December 31, 2025. There were no impairment losses for the years ended December 31, 2025, 2024, and 2023 .

2025 2024

Beginning balance as of January 1
$ 420   $ 425  
Goodwill allocated to assets held for sale
—   ( 5 )
Ending balance as of December 31
$ 420   $ 420  

Other Intangible Assets and Liabilities
Our other intangible assets and liabilities included in Other current assets, Other deferred debits and other assets, Other current liabilities, and Other deferred credits and other liabilities in the Consolidated Balance Sheets, consisted of the following as of December 31, 2025 and 2024. The customer relationships are generally amortized on a straight line basis, while UECs are amortized in accordance with the expected realization of the underlying cash flows:

December 31, 2025 December 31, 2024
Gross Accumulated Amortization Net Gross Accumulated Amortization Net
UECs
$ 1,850   $ ( 1,686 ) $ 164   $ 1,850   $ ( 1,669 ) $ 181  
Customer Relationships 174   ( 137 ) 37   244   ( 189 ) 55  

Total $ 2,024   $ ( 1,823 ) $ 201   $ 2,094   $ ( 1,858 ) $ 236  

The following table summarizes the amortization expense related to our other intangible assets and liabilities for the years ended December 31, 2025, 2024, and 2023:

For the Years Ended December 31,
2025 2024 2023
Amortization expense (a)
$ 35   $ 60   $ 58  

__________
(a) See Note 22 — Supplemental Financial Information for additional information on amortization expense.
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(Dollars in millions, unless otherwise noted)

Note 12 — Intangible Assets

The following table summarizes the estimated future amortization expense related to our other intangible assets and liabilities as of December 31, 2025:

For the Years Ending December 31, Estimated Future Amortization Expense
2026 $ 41  
2027 33  
2028 28  
2029 20  
2030 16  
2031 and thereafter 63  
Total
$ 201  

13. Income Taxes
Income (Loss) Before Income Taxes
Income (loss) before income taxes is comprised of the following components:

For the Years Ended December 31,
2025 2024 2023
Domestic $ 3,458   $ 4,433   $ 2,137  
Foreign 53   83   310  
Total Income (loss) before income taxes $ 3,511   $ 4,516   $ 2,447  

Components of Income Tax Expense or Benefit
Income taxes are comprised of the following components:

For the Years Ended December 31,
2025 2024 2023
Federal
Current $ 764   $ 451   $ 392  
Deferred 238   229   302  
ITC amortization ( 15 ) ( 14 ) ( 15 )
State
Current 136   127   142  
Deferred 50   ( 39 ) ( 34 )
Foreign
Current 14   ( 25 ) 72  
Deferred —   45   —  
Total Income tax (benefit) expense $ 1,187   $ 774   $ 859  

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(Dollars in millions, unless otherwise noted)

Note 13 — Income Taxes

Income Taxes Paid
Income taxes (net of refunds) paid during the year was comprised of the following components:

For the Years Ended December 31,
2025 2024 2023
Federal $ 341   $ 242   $ 315  
State
Illinois 16   24   19  
Maryland 11   24   7  
Other state 91   141   41  
Foreign
United Kingdom ( 20 ) —   61  
Other foreign 7   5   23  
Total income taxes paid (net of refunds) $ 446   $ 436   $ 466  

Rate Reconciliation
The effective income tax rate varies from the U.S. federal statutory rate principally due to the following:

For the Years Ended December 31,
2025 2024 2023
U.S. federal statutory income tax 21.0   % $ 737   21.0   % $ 948   21.0   % $ 514  
(Decrease) increase due to:
State income taxes, net of federal income tax benefit (a)(b)
4.2   147   1.5   69   3.5   86  
Foreign tax effects
0.1   2   0.1   3   0.5   12  
Tax credits

PTC ( 2.1 ) ( 74 ) ( 9.4 ) ( 425 ) —   —  
Amortization of ITC, including deferred taxes on basis differences ( 0.3 ) ( 12 ) ( 0.2 ) ( 11 ) ( 0.5 ) ( 12 )
Other ( 0.3 ) ( 8 ) ( 0.4 ) ( 16 ) ( 0.6 ) ( 15 )
Nontaxable or nondeductible items

Share-based payment awards ( 1.2 ) ( 44 ) ( 0.4 ) ( 17 ) ( 0.3 ) ( 7 )
Excess officers compensation 1.5   51   0.7   34   0.8   20  
Other 1.0   38   0.2   10   0.4   9  
Other adjustments

Qualified NDT fund income and losses 9.9   350   4.0   179   10.3   252  
Effective income tax (c)(d)
33.8   % $ 1,187   17.1   % $ 774   35.1   % $ 859  

_________
(a) Includes $ 21 million, ($ 42 ) million and ($ 4 ) million related to state rate changes and certain state tax positions in 2025, 2024, and 2023, respectively.
(b) In 2025, state taxes in Massachusetts, New York, Pennsylvania, and New Jersey made up the majority (greater than 50%) of the tax effect in this category. In 2024, state taxes in Maryland, Illinois, Massachusetts, California, New Jersey, New York, Pennsylvania, and Connecticut made up the majority (greater than 50%) of the tax effect in this category. In 2023, state taxes in Maryland, Pennsylvania, New Jersey, and California made up the majority (greater than 50%) of the tax effect in this category.
(c) The change in effective tax rate in 2025 is primarily due to the inclusion of nuclear PTCs, which are not taxable, and higher income from Qualified NDT funds.
(d) Amounts may not recalculate due to rounding.
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(Dollars in millions, unless otherwise noted)

Note 13 — Income Taxes

Tax Differences and Carryforwards
The tax effects of temporary differences and carryforwards, which give rise to significant portions of the deferred tax assets (liabilities), as of December 31, 2025 and 2024 are presented below:

December 31, 2025 December 31, 2024
Plant basis differences $ ( 3,321 ) $ ( 3,138 )
Accrual-based contracts
( 35 ) ( 30 )
Derivatives and other financial instruments 1,090   700  
Deferred pension and postretirement obligation ( 359 ) ( 336 )
Nuclear decommissioning activities ( 187 ) ( 256 )
Tax loss carryforward
23   19  
Tax loss carryforward valuation allowances
( 3 ) ( 3 )
Investment in partnerships ( 283 ) ( 204 )
Other, net ( 160 ) 242  
Deferred income tax liabilities (net) ( 3,235 ) ( 3,006 )
Unamortized ITCs ( 309 ) ( 325 )
Total deferred income tax liabilities (net) and
unamortized ITCs $ ( 3,544 ) $ ( 3,331 )

The following table provides our carryforwards, of which the state-related items are presented on a post-apportioned basis, and any corresponding valuation allowances as of December 31, 2025:

December 31, 2025
Federal

Federal general business credits carryforwards and other carryforwards $ —  

State
State net operating losses (NOL) and other carryforwards
393  
Deferred taxes on state tax attributes (net) 17  
Valuation allowance on state tax attributes ( 3 )
Foreign
Foreign NOL and other carryforwards
20  
Deferred taxes on foreign tax attributes (net) 5  

As of December 31, 2025, NOL carryforwards consisted primarily of NOL in ten states, totaling $ 17 M in deferred tax assets with the majority to expire between 2030 and 2032. A portion of state NOLs is offset with a valuation allowance to address potential limitation on NOL usage prior to expiration.
Unrecognized Tax Benefits
Our unrecognized tax benefits were not material as of and for the years ended December 31 , 2025, 2024, and 2023, and if recognized, would not significantly impact our effective tax rate. Further, these amounts are not expected to significantly increase or decrease within the next twelve months.
Total amounts of interest and penalties recognized
Interest and penalty expenses are recorded in Interest expense, net and Other, net, respectively, in the Consolidated Statements of Operations and Comprehensive Income. There was no material interest and penalty expense related to our tax positions for the years ended December 31 , 2025, 2024, and 2023.
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(Dollars in millions, unless otherwise noted)

Note 13 — Income Taxes

Description of tax years open to assessment by major jurisdiction

Major Jurisdiction Open Years (a)

Federal consolidated income tax returns 2010-2024

Illinois unitary corporate income tax returns 2012-2024

Texas combined corporate income tax returns
2021-2024

New Jersey combined corporate income tax returns 2021-2024

Maryland separate corporate income tax returns
2022-2024

Massachusetts combined corporate income tax returns
2022-2024

New York combined corporate income tax returns 2022-2024

Pennsylvania separate corporate income tax returns 2022-2024

California combined corporate income tax returns
2010-2024

__________
(a) Tax years open to assessment include years when we were consolidated by Exelon. See discussion below under the Tax Matters Agreement for responsibility of taxes of these open years.
Constellation participates in the IRS Compliance Assurance Process which provides the opportunity to resolve complex tax matters with the IRS prior to filing its federal income tax returns with a goal to achieve certainty with respect to tax matters. Constellation entered the program for the 2024 tax year.
Other Tax Matters
One Big Beautiful Bill Act
In July 2025, Congress passed the OBBBA which, among other things, included certain changes in tax law. See Note 3 — Regulatory Matters for additional information.
Tax Matters Agreement
In connection with the separation, we entered a TMA with Exelon. The TMA governs the respective rights, responsibilities, and obligations between us and Exelon after the separation with respect to tax liabilities and benefits, tax attributes, tax returns, tax contests and other tax sharing regarding U.S. federal, state, local and foreign income taxes, other tax matters and related tax returns.
Responsibility and Indemnification for Taxes . As a former subsidiary of Exelon, we have joint and several liability with Exelon to the IRS and certain state jurisdictions relating to the taxable periods that we were included in federal and state filings. However, the TMA specifies the portion of this tax liability for which we will bear contractual responsibility, and we and Exelon agreed to indemnify each other against any amounts for which such indemnified party is not responsible. Specifically, we will be liable for taxes due and payable in connection with tax returns that we are required to file. We will also be liable for our share of certain taxes required to be paid by Exelon with respect to taxable years or periods (or portions thereof) ending on or prior to the separation to the extent that we would have been responsible for such taxes under the Exelon tax sharing agreement then existing. As of December 31, 2025 and 2024, respectively, our Consolidated Balance Sheets reflect $ 43 million and $ 39 million in Other deferred credits and other liabilities, respectively, for tax liabilities where we maintain contractual responsibility to Exelon.
Tax Refunds and Attributes . The TMA provides for the allocation of certain pre-closing tax attributes between us and Exelon. Tax attributes will be allocated in accordance with the principles set forth in the existing Exelon tax sharing agreement, unless otherwise required by law. Under the TMA, we will be entitled to refunds for taxes for which we are responsible. In addition, it is expected that Exelon will have tax attributes that may be used to offset Exelon’s future tax liabilities. A significant portion of such attributes were generated by our business. In February 2024, we executed an amendment to the TMA that modified the timing of Exelon's payment of amounts due to us. During 2025 and 2024, we received payments for tax attributes utilized by Exelon related to the 2024 and 2023 tax years of $ 145 million and $ 174 million, respectively. As of December 31, 2025 and 2024, respectively, we had $ 175 million and $ 138 million in Accounts receivable, net and $ 21 million and $ 201 million in Other deferred debits and other assets for the reclassified tax attributes expected to be utilized by Exelon after separation in accordance with the terms of the TMA.
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(Dollars in millions, unless otherwise noted)

Note 13 — Income Taxes

IRS Notice 2026. In February 2026, the IRS issued Notice 2026‑7 (the “Notice”), which provides guidance on the implementation of the corporate alternative minimum tax (CAMT). The Notice permits taxpayers to deduct repair and maintenance costs under tax law principles in determining adjusted financial statement income and applies retroactively to previously filed tax returns. As a result of this Notice, Exelon amended its 2023 and 2024 tax returns to reflect less CAMT and thus lower utilization of previously refunded tax attributes.
We received a demand letter from Exelon on February 19, 2026, and expect to remit to Exelon $ 235  million under the TMA related to prior periods. This payment is due within 45 days of our receipt of the demand letter. We will increase our receivable for the $ 235  million in the first quarter of 2026 as we expect Exelon to pay us as it utilizes these tax attributes in future periods.

14. Retirement Benefits
Defined Benefit Pension and OPEB
Approximately half of current employees participate in the defined benefit pension and OPEB plans that we sponsor. As the plan sponsor, our Consolidated Balance Sheets reflect underfunded pension and OPEB liabilities equal to an excess of either the PBO or APBO over the fair value of the plan assets, consistent with a single employer benefit plan. Newly hired employees are generally not eligible for either pension or OPEB benefits; instead, these employees are eligible to receive an enhanced non-discretionary fixed employer contribution under our sponsored defined contribution savings plan.
Benefit Obligations, Plan Assets, and Funded Status
We use a December 31 measurement date for our pension and OPEB obligations and the related plan assets. The actuarial losses experienced upon remeasurement as of December 31, 2025 were offset against AOCI, net of deferred taxes. See the table below for changes associated with the pension valuation.
The following tables provide a rollforward of the changes in the benefit obligations and plan assets for the years ended December 31, 2025 and 2024 for all plans combined:

Pension Benefits OPEB
2025 2024 2025 2024
Change in benefit obligation:
Benefit obligation as of the beginning of the year $ 7,397   $ 7,770   $ 1,422   $ 1,443  
Service cost 84   90   18   17  
Interest cost 408   391   78   72  
Plan participants' contributions —   —   30   24  
Actuarial loss (gain), net
289   ( 269 ) 120   12  
Reclassification to liabilities held for sale
—   ( 9 ) —   ( 1 )
Settlements ( 3 ) ( 13 ) —   —  
Gross benefits paid ( 582 ) ( 563 ) ( 147 ) ( 145 )
Benefit obligation as of the end of year $ 7,593   $ 7,397   $ 1,521   $ 1,422  

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(Dollars in millions, unless otherwise noted)

Note 14 — Retirement Benefits

Pension Benefits OPEB
2025 2024 2025 2024
Change in plan assets:
Plan assets as of the beginning of year
$ 6,317   $ 6,687   $ 598   $ 692  
Employer contributions 174   177   —   —  
Plan participants' contributions —   —   24   18  
Actual return (loss) on plan assets
593   37   45   22  
Reclassification to assets held for sale
—   ( 8 ) —   —  
Settlements ( 3 ) ( 13 ) —   —  
Gross benefits paid ( 582 ) ( 563 ) ( 103 ) ( 134 )
Fair value of plan assets as of the end of year
$ 6,499   $ 6,317   $ 564   $ 598  

Over (under) funded status (Plan assets less benefit obligations)
$ ( 1,094 ) $ ( 1,080 ) $ ( 957 ) $ ( 824 )

We present our benefit obligations net of plan assets in our Consolidated Balance Sheets within the following line items:

Pension Benefits OPEB
2025 2024 2025 2024

Other current liabilities $ ( 22 ) $ ( 9 ) $ ( 52 ) $ ( 20 )
Pension and non-pension benefit obligations
( 1,072 ) ( 1,071 ) ( 905 ) ( 804 )

The following table provides the ABO and fair value of plan assets for all pension plans with an ABO in excess of plan assets.

ABO in Excess of Plan Assets December 31, 2025 December 31, 2024
ABO $ ( 7,436 ) $ ( 7,225 )
Fair value of plan assets
6,499   6,317  

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(Dollars in millions, unless otherwise noted)

Note 14 — Retirement Benefits

Components of Net Periodic Benefit (Credit) Cost
See Note 1 — Basis of Presentation for additional information on where we report the service cost and other non-service cost (credit) components for all plans.
The following table presents the components of our net periodic benefit (credit) cost for the years ended December 31, 2025, 2024, and 2023. The amounts below are shown prior to capitalization and co-owner allocations, the effects of which were not material for any of the periods presented.

Pension Benefits OPEB Total Pension Benefits and OPEB
2025 2024 2023 2025 2024 2023 2025 2024 2023
Components of net periodic benefit (credit) cost:

Service cost $ 84   $ 90   $ 89   $ 18   $ 17   $ 16   $ 102   $ 107   $ 105  
Non-service components of pension benefits & OPEB (credit) cost:

Interest cost 408 391   404   78   72   76   486   463   480  
Expected return on assets ( 489 ) ( 506 ) ( 520 ) ( 33 ) ( 42 ) ( 45 ) ( 522 ) ( 548 ) ( 565 )
Amortization of:
Prior service (credit) cost
1 1   1   ( 6 ) ( 6 ) ( 10 ) ( 5 ) ( 5 ) ( 9 )
Actuarial (gain) loss
103 102   48   ( 8 ) ( 9 ) ( 12 ) 95   93   36  
Settlement charges 1   6   —   — —   —   1   6   —  

Non-service components of pension benefits & OPEB credit (cost)
24   ( 6 ) ( 67 ) 31   15   9   55   9   ( 58 )
Net periodic benefit (credit) cost
$ 108   $ 84   $ 22   $ 49   $ 32   $ 25   $ 157   $ 116   $ 47  

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(Dollars in millions, unless otherwise noted)

Note 14 — Retirement Benefits

Components of AOCI
We recognize the overfunded or underfunded status of defined benefit pension and OPEB plans as an asset or liability on our balance sheet, with offsetting entries to AOCI. The following tables provide the pre-tax components of AOCI for the years ended December 31, 2025 and 2024, for all plans combined:

Pension Benefits OPEB
2025 2024 2025 2024
Changes in plan assets and benefit obligations recognized in AOCI:
Current year actuarial (gain) loss $ 186   $ 202   $ 109   $ 33  
Amortization of actuarial (loss) gain ( 103 ) ( 102 ) 8   9  

Amortization of prior service (cost) credit ( 1 ) ( 1 ) 6   6  
Settlements ( 1 ) ( 6 ) —   —  
Total recognized in AOCI $ 81   $ 93   $ 123   $ 48  

The following table provides the components of gross accumulated other comprehensive income (loss) that have not been recognized as components of periodic benefit cost as of December 31, 2025 and 2024, for all plans combined:

Pension Benefits OPEB
2025 2024 2025 2024
Prior service (credit) cost
$ 8   $ 8   $ ( 11 ) $ ( 18 )
Actuarial (gain) loss
3,162   3,080   73   ( 43 )
Total $ 3,170   $ 3,088   $ 62   $ ( 61 )

Average Remaining Service Period
For pension benefits, we amortize the unrecognized prior service (credits) costs and certain actuarial gains and losses reflected in AOCI, as applicable, based on participants’ average remaining service periods.
For OPEB, we amortize the unrecognized prior service (credits) costs reflected in AOCI over participants’ average remaining service period to benefit eligibility age, and amortize certain actuarial gains and losses reflected in AOCI over participants’ average remaining service period to expected retirement.
The resulting average remaining service periods (in years) for pension and OPEB as of December 31, 2025 and 2024 were as follows:

December 31, 2025 December 31, 2024
Pension plans 10 11
OPEB plans:
Benefit Eligibility Age 8 8
Expected Retirement 9 9

Assumptions
The measurement of the plan obligations and costs of providing benefits under our defined benefit pension and OPEB plans involves various factors, including the development of valuation assumptions and inputs and accounting policy elections. The measurement of benefit obligations and costs is impacted by several assumptions and inputs, as shown below, among other factors. When developing the required assumptions, we consider historical information as well as future expectations.
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Note 14 — Retirement Benefits

Discount Rate. The discount rates are determined by developing a spot rate curve based on the yield to maturity of high-quality corporate bonds with similar maturities to the 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.
Expected Rate of Return. To determine the EROA, we use third-party expectations for future long-term capital market performance, weighted by our target asset class allocations.
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. Upon remeasurement as of December 31, 2025 and December 31, 2024, we utilized the mortality tables and projection scales released by the SOA.
The following assumptions were used to determine the benefit obligations for the plans as of December 31, 2025 and December 31, 2024. Assumptions used to determine year-end benefit obligations are the assumptions used to estimate the subsequent year’s net periodic benefit costs.

Pension Benefits OPEB
December 31, 2025 December 31, 2024 December 31, 2025 December 31, 2024
Discount rate (a)
5.38   % 5.66   % 5.30   % 5.63   %
Investment crediting rate (b)
5.93   % 5.72   % N/A N/A
Rate of compensation increase (c)
4.25   % 4.25   % 4.25   % 4.25   %
Mortality table Pri-2012 table with MP-2021 improvement scale (adjusted) Pri-2012 table with MP-2021 improvement scale (adjusted) Pri-2012 table with MP-2021 improvement scale (adjusted) Pri-2012 table with MP-2021 improvement scale (adjusted)
Healthcare cost trend on covered charges N/A N/A 9.00 % initial, 5.00 % ultimate
7.00 % initial, 5.00 % ultimate

__________
(a) The discount rates above represent the blended rates used to calculate the majority of Constellation's pension and OPEB costs.
(b) The investment crediting rate above represents a weighted average rate.
(c) Includes 4.25 % average for the three-year period (2026-2028) and 3.75 % average thereafter.
The following assumptions were used to determine the net periodic benefit cost for the plans for the years ended December 31, 2025 and 2024.

Pension Benefits OPEB
2025 2024 2025 2024
Discount rate (a)
5.66   % 5.17   % 5.63   % 5.15   %
Investment crediting rate (b)
5.72   % 5.07   % N/A N/A
Expected return on plan assets (c)
6.50   % 6.50   % 6.00   % 6.50   %
Rate of compensation increase (d)
4.25   % 4.25   % 4.25   % 4.25   %
Mortality table Pri-2012 table with MP-2021 improvement scale (adjusted) Pri-2012 table with MP-2021 improvement scale (adjusted) Pri-2012 table with MP-2021 improvement scale (adjusted) Pri-2012 table with MP-2021 improvement scale (adjusted)
Healthcare cost trend on covered charges N/A N/A 7.00 % initial, 5.00 % ultimate
Initial and ultimate rate of 5.00 %

__________
(a) The discount rates above represent the blended rates used to calculate the majority of Constellation's pension and OPEB costs.
(b) The investment crediting rate above represents a weighted average rate.
(c) Applicable to our pension and OPEB plans with plan assets, with the OPEB rate representing a weighted average.
(d) Includes 4.25 % average for the four-year period (2025-2028) and 3.75 % average thereafter.
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(Dollars in millions, unless otherwise noted)

Note 14 — Retirement Benefits

Contributions
We consider various factors when making qualified pension funding decisions, including actuarially determined minimum contribution requirements under ERISA, contributions required to avoid benefit restrictions and at-risk status as defined by the Pension Protection Act, and management of the pension obligation. The Pension Protection Act requires the attainment of certain funding levels to avoid benefit restrictions (such as an inability to pay lump sums or to accrue benefits prospectively), and at-risk status (which triggers higher minimum contribution requirements and participant notification). The projected contributions below reflect a funding strategy to make annual contributions to offset some of the growth of the liability (e.g., from service cost). Qualified pension contributions made in February 2026 reflect our funding strategy and market conditions as of year-end.
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 some of our plans. For our funded OPEB plans, we consider several factors in determining the level of our contributions, including liabilities management and levels of benefit claims paid. Annually, we evaluate whether additional funding for those plans is needed, and the OPEB values below reflect both plan contributions (if applicable) and benefit payments for unfunded plans.
The following table provides our contributions paid to our qualified pension plans, non-qualified pension plans, and OPEB plans for the years ended December 31, 2025, 2024, and 2023:

2025 2024 2023
Pension contributions (a)
$ 174   $ 177   $ 26  
OPEB contributions
37   7   28  
Total contributions
$ 211   $ 184   $ 54  

__________
(a) Our annual qualified pension contributions were $ 161 million in 2025 and 2024. The benefit payments to the non-qualified pension plans in 2025 and 2024 were not material.

The following table provides our planned contributions to our qualified pension plans, non-qualified pension plans, and OPEB plans in 2026 (including our benefit payments related to unfunded plans):

Qualified Pension Plans Non-Qualified Pension Plans OPEB Total

Planned contributions $ 162   $ 22   $ 64   $ 248  

Estimated Future Benefit Payments
Estimated future benefit payments to participants over the next ten years in all pension and OPEB plans as of December 31, 2025 are as follows:

Pension Benefits OPEB
2026 $ 595   $ 125  
2027 580   127  
2028 598   127  
2029 590   127  
2030 590   126  
2031 through 2035 2,848   608  
Total estimated future benefits payments through 2035
$ 5,801   $ 1,240  

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Note 14 — Retirement Benefits

Plan Assets
On a regular basis, we evaluate our investment strategy to ensure that plan assets will be sufficient to pay plan benefits when due. We have developed and implemented a liability hedging investment strategy for the majority of our qualified pension plans which has reduced the volatility of these pension assets relative to the associated pension obligations. We are likely to continue to gradually increase the liability hedging portfolios as the funded statuses of the plans improve. The overall objective is to achieve attractive risk-adjusted returns that will satisfy the liquidity requirements of the plans’ liabilities while striving to minimize the risk of significant losses. Trust assets for our OPEB plans are managed in a diversified investment strategy that prioritizes maximizing liquidity and returns while minimizing asset volatility.
Actual asset returns have an impact on the costs reported for the pension and OPEB plans. The actual asset returns across our pension and OPEB plans for the year ended December 31, 2025 were 10.10 % and 10.10 %, respectively, compared to an expected long-term return assumption of 6.50 % and 6.00 %, respectively. We used an EROA of 6.50 % and 6.00 % to estimate our 2026 pension and OPEB costs, respectively.
Our pension and OPEB plan target asset allocations as of December 31, 2025 and 2024 were as follows:

December 31, 2025 December 31, 2024
Asset Category Pension Benefits OPEB Pension Benefits OPEB
Equity securities 21   % 24   % 21   % 20   %
Fixed income securities 54   % 59   % 54   % 66   %
Alternative investments (a)
25   % 17   % 25   % 14   %
Total 100   % 100   % 100   % 100   %

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(a) Alternative investments include private equity, hedge funds, real assets, and private credit.
We evaluated our pension and OPEB plans’ asset portfolios for the existence of significant concentrations of credit risk as of December 31, 2025. Types of concentrations that were evaluated include, but are not limited to, investment concentrations in a single entity, type of industry, foreign country, and individual fund. As of December 31, 2025, our pension and OPEB plans held no credit risk concentrations surpassing 10% of plan assets.
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Table of Contents
Combined Notes to Consolidated Financial Statements
(Dollars in millions, unless otherwise noted)

Note 14 — Retirement Benefits

Fair Value Measurements
The following table presents pension and OPEB plan assets measured and recorded at fair value as a net component of Pension and non-pension postretirement benefit obligations in our Consolidated Balance Sheets on a recurring basis and their level within the fair value hierarchy as of December 31, 2025 and 2024. There were no plan assets classified as Level 3 as of December 31, 2025 and 2024.

December 31, 2025 December 31, 2024
Level 1 Level 2 Total Level 1 Level 2 Total
Pension plan assets (a)

Cash equivalents $ 195   $ —   $ 195   $ 170   $ —   $ 170  
Equities (b)
1,053   —   1,053   1,041   —   1,041  
Fixed income 847   1,862   2,709   675   1,795   2,470  

Total assets measured at fair value 2,095   1,862   3,957   1,886   1,795   3,681  
Assets measured at NAV —  —  2,934   —  —  2,869  
Pension plan assets subtotal 2,095   1,862   6,891   1,886   1,795   6,550  

OPEB plan assets (a)

Cash equivalents 24   —   24   18   —   18  
Equities 71   —   71   96   —   96  

Fixed income 71   22   93   132   39   171