10-K – 2026-02-24 – ceg-20251231.htm

Total assets measured at fair value 166   22   188   246   39   285  
Assets measured at NAV —  —  374   —  —  309  
OPEB plan assets subtotal 166   22   562   246   39   594  
Total pension and OPEB plan assets (c)
$ 2,261   $ 1,884   $ 7,453   $ 2,132   $ 1,834   $ 7,144  
__________
(a) See Note 17 — Fair Value of Financial Assets and Liabilities for a description of levels within the fair value hierarchy.
(b) Includes total derivative assets and liabilities that are not material, which have total notional amounts of $ 2,509 million and $ 2,635 million as of December 31, 2025 and 2024, respectively. The notional principal amounts for these instruments provide one measure of the transaction volume outstanding as of the fiscal years ended and do not represent the amount of the company’s exposure to credit or market loss.
(c) Excludes net liabilities of $ 390 million and $ 229 million as of December 31, 2025 and 2024, respectively. These items are required to reconcile to the fair value of net plan assets and consist primarily of receivables or payables related to pending securities sales and purchases, and interest and dividends receivable.
Valuation Techniques Used to Determine Fair Value
The techniques used to determine the fair value of the pension and OPEB assets invested in cash equivalents, equities, fixed income, derivatives, private equity, real assets, and private credit investments are the same as the valuation techniques for these types of investments in the NDT funds. See Cash Equivalents and NDT Fund Investments in Note 17 — Fair Value of Financial Assets and Liabilities for further information.
Pension and OPEB assets also include investments in hedge funds. Hedge fund investments include those that employ a broad range of strategies to enhance returns and provide additional diversification. The fair value of hedge funds is determined using NAV or its equivalent as a practical expedient, and therefore, hedge funds are not classified within the fair value hierarchy. We have the ability to redeem these investments at NAV or its equivalent subject to certain restrictions, which may include a lock-up period or a gate.
Defined Contribution Savings Plan
We sponsor the Constellation Employee Savings Plan, a 401(k) defined contribution savings plan. The plan allows employees to contribute a portion of their pre-tax and/or after-tax income in accordance with specified guidelines. We match a percentage of the employee contributions up to certain limits. In addition, certain employees are eligible for a fixed non-discretionary employer contribution in lieu of a pension benefit. The employer contributions to the savings plan were $ 126  million, $ 117 million, and $ 106 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 15 — Derivative Financial Instruments

15. Derivative Financial Instruments
We use derivative instruments to manage commodity price risk, interest rate risk, and foreign exchange risk related to ongoing business operations.
Authoritative guidance requires that derivative instruments be recognized as either assets or liabilities at fair value, with changes in fair value of the derivative recognized in earnings immediately. Other accounting treatments, including NPNS, are available through special election and designation, provided they meet specific, restrictive criteria both at the time of designation and on an ongoing basis. All derivative instruments, excluding NPNS, are recorded at fair value through earnings. For all NPNS derivative instruments, accounts receivable or accounts payable are recorded when derivatives settle and revenue or expense is recognized in earnings as the underlying physical commodity is delivered.
Authoritative guidance for the offsetting of assets and liabilities requires the fair value of derivative instruments to be shown in the Combined Notes to Consolidated Financial Statements on a gross basis, even when the derivative instruments are subject to legally enforceable master netting agreements and qualify for net presentation in the Consolidated Balance Sheets. A master netting agreement is an agreement between two counterparties that may have derivative and non-derivative contracts with each other providing for the net settlement of all referenced contracts via one payment stream, which takes place as the contracts deliver, when collateral is requested or in the event of default. In the tables below, which present fair value balances, our commodity economic hedges are shown gross. The impact of the netting of fair value balances with the same counterparty that are subject to legally enforceable master netting agreements, as well as netting of cash collateral, including margin on exchange positions, is aggregated in the collateral and netting columns.
Our use of cash collateral is generally unrestricted unless we were downgraded below investment grade. As our senior unsecured debt rating is currently rated at BBB+ and Baa1 by S&P and Moody's, respectively, it would take a three-notch downgrade by S&P or Moody's for our rating to go below investment grade.
Commodity Price Risk
We employ established policies and procedures to manage our risks associated with market fluctuations in commodity prices by entering into physical and financial derivative contracts, including swaps, futures, forwards, options, and short-term and long-term commitments to purchase and sell energy and energy-related products. We believe these instruments, which are either determined to be non-derivative or classified as economic hedges, mitigate exposure to fluctuations in commodity prices.
To the extent the amount of energy we produce or procure differs from the amount of energy we have contracted to sell, we are exposed to market fluctuations in the prices of electricity, natural gas, and other commodities. We use a variety of derivative and non-derivative instruments to manage the commodity price risk of our electric generation facilities, including power and gas sales, fuel and power purchases, natural gas transportation and pipeline capacity agreements, and other energy-related products marketed and purchased. To manage these risks, we may enter into fixed-price derivative or non-derivative contracts to hedge the variability in future cash flows from expected sales of power and gas and purchases of power and fuel. The objectives for executing such hedges include fixing the price for a portion of anticipated future electricity sales at a level that provides an acceptable return. We are also exposed to differences between the locational settlement prices of certain economic hedges and the hedged generating units. This price difference is actively managed through other instruments which include derivative congestion products, whose changes in fair value are recognized in earnings each period, and auction revenue rights, which are accounted for on an accrual basis.
In general, increases and decreases in forward market prices have a positive and negative impact, respectively, on owned and contracted generation positions that have not been hedged. Beginning in 2024, our existing nuclear fleet is eligible for a nuclear PTC, an important tool in managing commodity price risk for each nuclear unit not already receiving state support. The nuclear PTC provides increasing levels of support as unit revenues decline below levels established in the IRA and is further adjusted for inflation annually through the duration of the program based on the GDP price deflator for the preceding calendar year. See Note 6 — Government Assistance for additional information.
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Combined Notes to Consolidated Financial Statements
(Dollars in millions, unless otherwise noted)

Note 15 — Derivative Financial Instruments

In locations and periods where our load serving activities do not naturally offset existing generation portfolio risk, remaining commodity price exposure is managed through portfolio hedging activities. Portfolio hedging activities are generally concentrated in the prompt three years, when customer demand and market liquidity enable effective price risk mitigation. During this prompt three-year period, we seek to mitigate the price risk associated with our load serving contracts, non-nuclear generation, and any residual price risk for our nuclear generation that the nuclear PTC and state programs may not fully mitigate. We also enter transactions that further optimize the economic benefits of our overall portfolio.
The following tables provide a summary of the commodity derivative fair value balances recorded as of December 31, 2025 and 2024:

December 31, 2025 Economic Hedges
Collateral (a)
Netting (a)
Total
Derivative assets (current)
$ 7,349   $ 375   $ ( 6,791 ) $ 933  
Derivative assets (noncurrent)
5,030   272   ( 4,853 ) 449  
Total derivative assets
12,379   647   ( 11,644 ) 1,382  
Derivative liabilities (current)
( 7,642 ) 386   6,791   ( 465 )
Derivative liabilities (noncurrent)
( 5,585 ) 319   4,853   ( 413 )
Total derivative liabilities
( 13,227 ) 705   11,644   ( 878 )
Total derivative net assets (liabilities)
$ ( 848 ) $ 1,352   $ —   $ 504  

December 31, 2024
Derivative assets (current)
$ 5,518   $ 152   $ ( 4,860 ) $ 810  
Derivative assets (noncurrent)
3,672   120   ( 3,421 ) 371  
Total derivative assets
9,190   272   ( 8,281 ) 1,181  
Derivative liabilities (current)
( 5,498 ) 173   4,860   ( 465 )
Derivative liabilities (noncurrent)
( 3,961 ) 141   3,421   ( 399 )
Total derivative liabilities
( 9,459 ) 314   8,281   ( 864 )
Total derivative net assets (liabilities)
$ ( 269 ) $ 586   $ —   $ 317  

_________
(a) We net all available amounts allowed in our Consolidated Balance Sheets in accordance with authoritative guidance for derivatives. These amounts include unrealized derivative transactions with the same counterparty under legally enforceable master netting agreements and cash collateral.
The following table summarizes the net buy/(sell) notional position of commodity derivative transactions, excluding our NPNS derivatives that are not recorded at fair value, as of December 31, 2025 and 2024:

(In millions)
As of December 31,
Commodity Type
2025 2024 Unit of Measure

Electricity
( 260 ) ( 130 ) MWh

Natural Gas
33 33 MMBtu

Emissions
( 35 ) ( 18 ) Short Ton

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

Note 15 — Derivative Financial Instruments

Economic Hedges (Commodity Price Risk)
For the years ended December 31, 2025, 2024, and 2023, we recognized the following net pre-tax commodity unrealized gains (losses), which are also included in the Net fair value changes related to derivatives line in the Consolidated Statements of Cash Flows.

For the Years Ended December 31,
Income Statement Location 2025 2024 2023
Operating revenues $ ( 804 ) $ 313   $ 1,402  
Purchased power and fuel 183   963   ( 2,368 )
Total $ ( 621 ) $ 1,276   $ ( 966 )

Interest Rate and Foreign Exchange Risk
We utilize interest rate swaps to manage our interest rate exposure and foreign currency derivatives to manage foreign exchange rate exposure associated with international commodity sales and purchases in currencies other than U.S. dollars, both of which are treated as economic hedges. The notional amounts were $ 1,439 million and $ 592 million as of December 31, 2025 and 2024, respectively.
The derivative assets and liabilities for the years ended December 31, 2025 and 2024 and the unrealized gains and losses associated with management of interest rate and foreign currency risk for the years ended December 31, 2025, 2024, and 2023 were not material. The unrealized gains and losses associated with management of interest rate and foreign currency exchange rate risk are also included in the Net fair value changes related to derivatives line in the Consolidated Statements of Cash Flows.
Credit Risk
We would be exposed to credit-related losses in the event of non-performance by counterparties on executed derivative instruments. The credit exposure of derivative contracts, before collateral, is represented by the fair value of contracts as of the reporting date.
For commodity derivatives, we enter into enabling agreements that allow for payment netting with our counterparties, which reduces our exposure to counterparty risk by providing for the offset of amounts payable to the counterparty against amounts receivable from the counterparty. Typically, each enabling agreement is for a specific commodity and, with respect to each individual counterparty, netting is limited to t ransactions involving that specific commodity product, except where master netting agreements exist with a counterparty that allows for cross product netting. In addition to right of offset language in the enabling agreement, our credit department establishes credit limits, margining thresholds and collateral requirements for each counterparty, which are defined in the derivative contracts. Counterparty credit limits are based on an internal credit review process that considers a variety of factors, including the results of a scoring model, leverage, liquidity, profitability, credit ratings by credit rating agencies, and other risk management criteria. To the extent that a counterparty’s margining thresholds are exceeded, the counterparty is required to post collateral with us, as specified in each enabling agreement. Our credit department monitors current and forward credit exposure to counterparties and their affiliates, both on an individual and an aggregate basis.
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Combined Notes to Consolidated Financial Statements
(Dollars in millions, unless otherwise noted)

Note 15 — Derivative Financial Instruments

The following tables provide information on the credit exposure for derivative instruments, inclusive of payables and receivables, net of collateral and instruments that are subject to master netting agreements, as of December 31, 2025. The amounts in the tables below exclude credit risk exposure from individual retail counterparties, NPNS contracts, forward values on non-derivative contracts and exposure through RTOs, ISOs, as well as commodity exchanges. The tables further delineate that exposure by credit rating of the counterparties and provide guidance on the concentration of credit risk to individual counterparties.

Rating as of December 31, 2025 Total Exposure Before Credit Collateral
Credit Collateral (a)
Net Exposure
Number of Counterparties Greater than 10% of Net Exposure
Net Exposure of Counterparties Greater than 10% of Net Exposure

Investment grade $ 966   $ 10   $ 956   1   $ 152  
Non-investment grade 10   1   9   —   —  
No external ratings
Internally rated — investment grade 172   6   166   —   —  
Internally rated — non-investment grade 156   23   133   —   —  
Total $ 1,304   $ 40   $ 1,264   1   $ 152  
__________
(a) As of December 31, 2025, credit collateral held from counterparties was entirely in the form of letters of credit.

Net Credit Exposure by Type of Counterparty As of December 31, 2025
Investor-owned utilities, marketers, power producers $ 1,052  
Energy cooperatives and municipalities 89  
Financial Institutions 48  
Other 75  
Total $ 1,264  

Credit-Risk-Related Contingent Features
As part of the normal course of business, we routinely enter into physically and financially settled contracts for the purchase and sale of capacity, electricity, fuels, emissions allowances, and other energy-related products. Certain of our derivative instruments contain provisions that require us to post collateral. We also enter into commodity transactions on exchanges where the exchanges act as the counterparty to each trade. Transactions on the exchanges must adhere to comprehensive collateral and margining requirements. This collateral may be posted in the form of cash or credit support with thresholds contingent upon our credit ratings from S&P and Moody's. The collateral and credit support requirements vary by contract and by counterparty. These credit-risk-related contingent features stipulate that if we were to be downgraded or lose our investment grade credit ratings (based on our senior unsecured debt rating), we would be required to provide additional collateral. This incremental collateral requirement allows for the offsetting of derivative instruments that are assets with the same counterparty, where the contractual right of offset exists under applicable master netting agreements. In the absence of expressly agreed-to provisions that specify the collateral that must be provided, collateral requested will be a function of the facts and circumstances of the situation at the time of the demand. In such cases, we believe an amount of several months of future payments (e.g., capacity payments) rather than a calculation of fair value is a reasonable estimate for the contingent collateral obligation, which has been factored into the disclosure below.
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Combined Notes to Consolidated Financial Statements
(Dollars in millions, unless otherwise noted)

Note 15 — Derivative Financial Instruments

The aggregate fair value of all derivative instruments with credit-risk-related contingent features in a liability position that are not fully collateralized (excluding transactions on the exchanges that are fully collateralized) is detailed in the table below:

As of December 31,
Credit-Risk-Related Contingent Features 2025 2024
Gross fair value of derivative contracts containing this feature
$ ( 1,307 ) $ ( 1,346 )
Offsetting fair value of contracts under master netting arrangements
554   602  
Net fair value of derivative contracts containing this feature $ ( 753 ) $ ( 744 )

As of December 31, 2025 and 2024, we posted or held the following amounts of cash collateral and letters of credit on derivative contracts with external counterparties, after giving consideration to offsetting derivative and non-derivative positions under master netting agreements.

As of December 31,
2025 2024
Cash collateral posted
$ 1,399   $ 635  
Letters of credit posted
718   890  
Cash collateral held
47   49  
Letters of credit held
115   91  
Additional collateral required in the event of a credit downgrade below investment grade (at BB+/Ba1) (a)(b)(c)
2,670   1,949  
_________
(a) Certain of our contracts contain provisions that allow a counterparty to request additional collateral when there has been a subjective determination that our credit quality has deteriorated, generally termed “adequate assurance”. Due to the subjective nature of these provisions, we estimate the amount of collateral that we may ultimately be required to post in relation to the maximum exposure with the counterparty.
(b) The downgrade collateral is inclusive of all contracts in a liability position regardless of accounting treatment and excludes any contracts with individual retail counterparties.
(c) A loss of investment grade credit rating would require a three-notch downgrade from current levels of BBB+ and Baa1 at S&P and Moody's, respectively.
We routinely enter into supply forward contracts with certain utilities with one-sided collateral postings only from us. If market prices fall below the benchmark price levels in these contracts, the utilities are not required to post collateral. However, when market prices rise above the benchmark price levels, we are required to post collateral once certain unsecured credit limits are exceeded.
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Combined Notes to Consolidated Financial Statements
(Dollars in millions, unless otherwise noted)

Note 16 — Debt and Credit Agreements

16. Debt and Credit Agreements
Short-Term Borrowings
We meet our short-term liquidity requirements primarily through the issuance of commercial paper. We may use our credit facility for general corporate purposes, including meeting short-term funding requirements and the issuance of letters of credit.
Credit Agreements
In September 2025, we amended our existing RCF to increase the available aggregate commitment from $ 4.5  billion to $ 7.0  billion, which included incremental revolving credit commitments of $ 2.5  billion and extension of the maturity date to September 2030. The incremental commitments became available upon closing of the Calpine acquisition in January 2026. The RCF may be drawn down in the form of loans and/or to support commercial paper and letters of credit issuances.
The RCF fixed facility fee rate is 0.175 % and borrowings under the RCF bear interest at a rate based upon either the Daily Simple SOFR rate or a Term SOFR rate, plus an adder based upon our credit ratings. The adders for the Daily Simple SOFR-based borrowings and Term SOFR borrowings are 0.075 % and 1.075 %, respectively. The letters of credit bear interest at a rate of 1.075 %.
If we were to lose our investment grade credit rating, the maximum adders for Daily Simple SOFR rate borrowings and Term SOFR rate borrowings would be 1.00 % and 2.00 %, respectively. The credit agreements also require us to pay facility fees based upon the aggregate commitments. The fees vary depending upon our credit rating.
Accounts Receivable Facility
In December 2024, we amended the Facility to provide NER access to revolving loans from a number of financial institutions ("Lenders") secured by certain customer accounts receivable. As part of the amendment, the maximum funding limit of the of the Facility was increased from $ 1.1  billion to $ 1.5  billion and the maturity date was extended to December 2027. Under previous terms of the Facility, certain customer accounts receivable were sold to the Purchasers. Immediately following the amendment, all receivables previously sold were assigned back to us and receivables will no longer be sold to the Purchasers under the amendment. Subsequent to the amendment, draws and repayments related to the Facility will be reflected as Proceeds from short-term borrowings and Repayments of short-term borrowings, respectively, in the Consolidated Statements of Cash Flows. Draws on the facility bear interest at a commercial paper rate or a Daily One Month Term SOFR or Term SOFR rate, plus an adder of 0.10 % per annum. Interest is payable monthly. There were no draws on the Facility as of December 31, 2025. In February 2026, we drew on the Facility in the amount of $ 600  million which was still outstanding as of the date of this filing.
The amended Facility requires the balance of eligible receivables to be maintained at or above the balance of cash proceeds received from the Lenders. To the extent the eligible receivables decrease below such balance, we are required to repay cash to the Lenders. When eligible receivables exceed cash proceeds, we have the ability to increase the cash proceeds received up to the maximum funding limit.
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Combined Notes to Consolidated Financial Statements
(Dollars in millions, unless otherwise noted)

Note 16 — Debt and Credit Agreements

As of December 31, 2025 and 2024, we had the following aggregate bank commitments, credit facility borrowings and available capacity under our respective credit facilities:

December 31, 2025
Facility Type Aggregate Bank Commitment
Facility Draws Outstanding Letters of Credit (a)
Outstanding Commercial Paper (b)
Total Available Capacity

Revolving Credit Facility $ 4,500   $ —   $ 40   $ —   $ 4,460  
Bilaterals (c)
2,350   —   1,276   —   1,074  
Accounts Receivable Facility 1,500   —   —   —   1,500  
Liquidity Facility 971   —   647   —   312   (d)

Project Finance 137   —   122   —   15  
Total $ 9,458   $ —   $ 2,085   $ —   $ 7,361  

December 31, 2024
Revolving Credit Facility $ 4,500   $ —   $ 51   $ —   $ 4,449  
Bilaterals
1,850   —   1,095   —   755  
Accounts Receivable Facility
1,500   —   —   —   1,500  
Liquidity Facility 971   —   907   —   21   (d)

Project Finance 137   —   120   —   17  
Total $ 8,958   $ —   $ 2,173   $ —   $ 6,742  

__________
(a) Excludes an additional outstanding letter of credit which was not issued under these facilities of $ 15 million as of December 31, 2025 and 2024. See Note 18 — Commitments and Contingencies for additional information.
(b) Our commercial paper program is supported by the revolving credit agreement. In order to maintain our commercial paper program in the amounts indicated above, we must have a credit facility in place, at least equal to the amount of our commercial paper program. As of December 31, 2025 and 2024, the maximum program size of our commercial paper program was $ 4.5  billion. We do not issue commercial paper in an aggregate amount exceeding the then available capacity under our credit facility. There were no commercial paper borrowings outstanding as of December 31, 2025 and 2024.
(c) Refer to table below for additional information on our bilateral credit agreements.
(d) The maximum amount of the bank commitment is not to exceed $ 971 million. The aggregate available capacity of the facility is subject to market fluctuations based on the value of U.S Treasury Securities which determines the amount of collateral held in the trust. We may post additional collateral to borrow up to the maximum bank commitment. As of December 31, 2025 and 2024, without posting additional collateral, the actual availability of facility, prior to outstanding letters of credit was $ 959  million and $ 928  million, respectively.
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Combined Notes to Consolidated Financial Statements
(Dollars in millions, unless otherwise noted)

Note 16 — Debt and Credit Agreements

Bilateral Credit Agreements
The following table reflects the bilateral credit agreements at December 31, 2025:

Date Initiated (a)
Latest Amendment Date Maturity Date (b)
Amount
January 2016 April 2023 April 2026 $ 150  
October 2019 N/A N/A 200
November 2019 N/A N/A 300
November 2019 N/A N/A 100
November 2019 June 2024 June 2026 100
May 2020 (c)
March 2023 N/A 300
August 2022 N/A N/A 50
March 2023 March 2025 March 2027 100
December 2023 N/A N/A 200
March 2024 (c)
N/A N/A 200
May 2024 N/A N/A 150
January 2025 (c)
N/A N/A 200
March 2025 N/A March 2026 300
$ 2,350  

__________
(a) Bilateral credit agreements solely support the issuance of letters of credit and do not back our commercial paper program.
(b) Credit facilities that do not contain a maturity date are specific to the agreements set within each contract. In some instances, credit facilities are automatically renewed based on the contingency standards set within the specific agreement.
(c) In February 2026, we increased the capacity to issue letters of credit by an additional $ 100 million each for three existing uncommitted bilateral facilities.
Short-Term Loan Agreements
We had short-term loan agreements outstanding as of December 31, 2025 as reflected in the table below. There were no short-term loan agreements outstanding as of December 31, 2024.

Month Initiated
Interest Rate
Maturity
Weighted Average Interest Rate
Outstanding Amount as of December 31, 2025

May 2025 1-month SOFR + 0.90 %
May 2026 5.09   % $ 900  
September 2025 1-month SOFR + 0.90 %
September 2026 4.93   % 750  

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

Note 16 — Debt and Credit Agreements

Long-Term Debt 
The following table presents the outstanding long-term debt as of December 31, 2025 and 2024:

December 31,
Rates Maturity Date
2025 2024
Long-term debt
Senior unsecured notes 5.60 % - 6.50 %
2028 - 2054 $ 5,688   $ 6,588  
Tax-exempt notes
4.10 % - 4.45 %
2029 - 2053 (a)
412   435  
Notes payable and other 1.71 % - 6.10 %
2026 - 2035 53   51  
Nonrecourse debt:
Fixed rates 2.29 % - 6.00 %
2031 - 2037 653   720  
Variable rates 5.82 % - 6.76 %
2027 597   680  
Total long-term debt 7,403   8,474  
Unamortized debt discount and premium, net ( 1 ) ( 4 )
Unamortized debt issuance costs ( 60 ) ( 58 )
Long-term debt due within one year ( 92 ) ( 1,028 )
Long-term debt $ 7,250   $ 7,384  
________
(a) The Tax-exempt notes have a maturity date of June 2029 to April 2053, and a mandatory purchase date that ranges from April 2028 to June 2029.
Long-term debt maturities in the periods 2026 through 2031 and thereafter are as follows:

2026 $ 92  
2027 666  
2028 828  
2029 157  
2030 99  
2031 and thereafter
5,561  
Total $ 7,403  

DOE Loan Guarantee
In November 2025, the DOE Office of Energy Dominance Financing issued a guarantee for up to $ 1.0 billion for an unsecured loan from the Federal Financing Bank to support the restart of the Crane Clean Energy Center. The loan will mature in November 2055. Interest rates on the loan will be fixed upon each advance at a spread of 0.375 % above U.S. Treasuries of comparable maturity. There have been no borrowings on this loan as of the date of this filing.
Calpine Acquisition
Upon completion of the acquisition of Calpine in January 2026, we assumed approximately $ 12.6  billion of debt inclusive of approximately $ 7.6  billion of corporate long-term debt, including senior unsecured and secured notes and corporate term loans in addition to approximately $ 5  billion of various project financing arrangements. Pursuant to the Exchange Offers discussed below, we issued new notes in January 2026 effectively replacing $ 2.3  billion of Calpine's senior unsecured and secured notes with Constellation senior unsecured notes. Using the proceeds from our January 2026 bond issuance, as discussed below, along with cash on hand and short-term debt, we repaid $ 2.5  billion of Calpine corporate term loans immediately after the acquisition closing and repaid $ 1.25  billion of Calpine senior secured first lien notes in February 2026. Following the debt exchange and redemptions discussed, $ 6.5  billion of Calpine debt remains outstanding.
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Combined Notes to Consolidated Financial Statements
(Dollars in millions, unless otherwise noted)

Note 16 — Debt and Credit Agreements

Debt Exchange Offering
In December 2025, we announced that, in connection with the planned acquisition of Calpine by CEG Parent, we commenced private exchange offers and related consent solicitations with respect to certain outstanding debt of Calpine. Under the Exchange Offers, we solicited consents to holders of certain Calpine debt to amend the notes and the related indentures under which they were issued to eliminate substantially all of the restrictive covenants, restrictive provisions and events of default, other than payment-related and bankruptcy-related events of default. In January 2026, we completed the exchange offering, effectively replacing $ 2.3 billion of Calpine senior secured and unsecured notes with Constellation senior unsecured notes.
The terms of the debt issuance under the exchange are as follows:

Note Interest Rate Maturity Issued Amount
2029 Senior Notes 4.625 % February 2029 $ 647  
2031 Senior Notes 5.000 % February 2031 848  
2031 Senior Notes 3.750 % March 2031 795  
Total $ 2,290  

Senior Note Issuance
In January 2026, we issued senior unsecured notes totaling $ 2.75 billion, the proceeds from which were used to pay down Calpine debt assumed. The terms of the debt issuance are as follows:

Note
Interest Rate
Maturity Issued Amount

2028 Floating Rate Senior Notes
SOFR + 0.600 %
January 2028 $ 300  
2028 Senior Notes
3.900 % January 2028 900  
2031 Senior Notes
4.400 % January 2031 750  
2066 Senior Notes
5.875 % January 2066 800  
Total
$ 2,750  

Debt Covenants
As of December 31, 2025, we are in compliance with all debt covenants.
Nonrecourse Debt 
We have also issued nonrecourse debt, for which approximately $ 1.9 billion and $ 2 billion of generating assets have been pledged as collateral as of December 31, 2025 and 2024, respectively. Borrowings under these agreements are secured by the assets and equity of each respective project. The lenders do not have recourse against us in the event of a default. If a specific project financing entity does not maintain compliance with its specific nonrecourse debt covenants, there could be a requirement to accelerate repayment of the associated debt or other borrowings earlier than the stated maturity dates. In these instances, if such repayment was not satisfied, the lenders or security holders would generally have rights to foreclose against the project-specific assets and related collateral. The potential requirement to satisfy the associated debt or other borrowings earlier than otherwise anticipated could lead to impairments due to a higher likelihood of disposing of the respective project-specific assets significantly before the end of their useful lives.
Antelope Valley Solar Ranch One. In December 2011, the DOE Loan Programs Office issued a guarantee for up to $ 646 million for a nonrecourse loan from the Federal Financing Bank to support the financing of the construction of the Antelope Valley facility. The project became fully operational in 2014. The loan will mature in January 2037. Interest rates on the loan were fixed upon each advance at a spread of 37.5 basis points above U.S. Treasuries of comparable maturity. The advances were completed in December 2015 and the outstanding loan balance bears interest at an average blended interest rate of 2.82 %. As of December 31, 2025 and 2024, approximately $ 335 million and $ 365 million were outstanding, respectively. In addition, we have issued letters of credit to support the equity investment in the project, with $ 36 million outstanding as of December 31, 2025 and 2024. In December 2017, our interests in Antelope Valley were contributed to and are pledged as collateral for the CR financing structures referenced below.
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(Dollars in millions, unless otherwise noted)

Note 16 — Debt and Credit Agreements

Continental Wind, LLC. In September 2013, Continental Wind, our indirect subsidiary, completed the issuance and sale of $ 613 million senior secured notes. Continental Wind owns and operates a portfolio of wind farms in Idaho, Kansas, Michigan, Oregon, New Mexico and Texas with a total net capacity of 667 MWs. The net proceeds were distributed to us for general business purposes. The notes are scheduled to mature in February 2033. The notes bear interest at a fixed rate of 6.00 % with interest payable semi-annually. As of December 31, 2025 and 2024, approximately $ 260 million and $ 290 million were outstanding, respectively.
In addition, Continental Wind has a $ 128 million letter of credit facility and $ 4 million working capital revolver facility. Continental Wind has issued letters of credit to satisfy certain of its credit support and security obligations. As of December 31, 2025 and 2024, the Continental Wind letter of credit facility had $ 122 million and $ 119 million in letters of credit outstanding related to the project, respectively.
In 2017, our interests in Continental Wind were contributed to CRP, whose assets were contributed to and are pledged as collateral for the CR financing structure referenced below.
Renewable Power Generation. In March 2016, RPG, our indirect subsidiary, issued $ 150 million aggregate principal amount of nonrecourse senior secured notes. The net proceeds were distributed to us for paydown of long-term debt obligations at Sacramento PV Energy and Constellation Solar Horizons and for general business purposes. The loan is scheduled to mature in March 2035. The term loan bears interest at a fixed rate of 4.11 % payable semi-annually. As of December 31, 2025 and 2024, approximately $ 55 million and $ 60 million were outstanding, respectively. In 2017, our interests in RPG were contributed to CRP, whose assets were contributed to and are pledged as collateral for the CR financing structure referenced below.
Constellation Renewables. In December 2020, CR entered into a financing agreement for a $ 750 million nonrecourse senior secured term loan credit facility, scheduled to mature in December 2027. Beginning in October 2025, the term loan bears interest at a variable rate equal to 3-month SOFR plus 2.00 %, subject to a 1 % SOFR floor with interest payable quarterly. Redemptions prior to October 2025 were based on 3-month SOFR plus 2.25 %. Redemptions from June 2023 through June 2024 were based on 3-month SOFR plus 2.76 %, and LIBOR plus 2.50 % prior to that date.
In addition to the financing, CR entered interest rate swaps to manage a portion of the interest rate exposure in connection with the financing. The swap had an initial notional amount of $ 516 million and fixed the 3-month LIBOR at 1.05 %. Beginning in June 2023, the swap fixed the 3-month SOFR at 0.8295 %. The swap expired in December 2024. In January 2024, CR entered an additional interest rate swap to manage a portion of the interest rate exposure in connection with the financing. The swap had a notional amount of $ 120 M and fixed the 3-month SOFR to 3.98 %.
Our interests in CRP and Antelope Valley are contributed to and pledged as collateral for this financing. As of December 31, 2025 and 2024, $ 600 million and $ 630  million was outstanding, respectively. See Note 21 — Variable Interest Entities for additional information on CRP and Note 15 — Derivative Financial Instruments for additional information on interest rate swaps.
West Medway II, LLC. In May 2021, West Medway II, LLC (West Medway II) entered into a $ 150  million nonrecourse senior secured term loan maturing in March 2026. Our interests in West Medway II were pledged as collateral. Net proceeds were used for general corporate purposes. Beginning in May 2025, the loan bore interest at 1-month SOFR plus 3.350 %. Redemptions from May 2023 to May 2025 were based on 1-month SOFR plus the variable interest rate of 2.975 % - 3.225 % and LIBOR plus 2.875 % prior to that date. West Medway II also entered into interest rate swaps with a $ 113  million initial notional amount that fixed LIBOR at 0.61 % and, beginning in May 2023, fixed SOFR at 0.5365 %. The swaps were terminated in August and October 2025. As of December 31, 2024, approximately $ 50  million was outstanding and the term loan was fully repaid in October 2025.
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Note 17 — Fair Value of Financial Assets and Liabilities

17. Fair Value of Financial Assets and Liabilities
We measure and classify fair value measurements in accordance with the hierarchy as defined by GAAP. The hierarchy prioritizes the inputs to valuation techniques used to measure fair value into three levels as follows:
• Level 1 — quoted prices (unadjusted) in active markets for identical assets or liabilities that we have the ability to liquidate as of the reporting date
• Level 2 — inputs other than quoted prices included within Level 1 that are directly observable for the asset or liability or indirectly observable through corroboration with observable market data
• Level 3 — unobservable inputs, such as internally developed pricing models or third-party valuations for the asset or liability due to little or no market activity for the asset or liability
Fair Value of Financial Liabilities Recorded at Amortized Cost
The following table presents the carrying amounts and fair values of our long-term debt and the SNF obligation as of December 31, 2025 and 2024. We have no financial liabilities classified as Level 1. The carrying amounts of the short-term liabilities as presented in the Consolidated Balance Sheets are representative of their fair value (Level 2) because of the short-term nature of these instruments.

December 31, 2025 December 31, 2024
Carrying Amount Fair Value Carrying Amount Fair Value
Level 2 Level 3 Total Level 2 Level 3 Total
Long-Term Debt, including amounts due within one year $ 7,342   $ 6,995   $ 666   $ 7,661   $ 8,412   $ 7,805   $ 716   $ 8,521  
SNF Obligation (a)
1,426   1,406   —   1,406   1,366   1,278   —   1,278  

__________
(a) SNF Obligation is included in Other deferred credits and other liabilities in the Consolidated Balance Sheets.
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We use the following methods and assumptions to estimate fair value of our financial liabilities recorded at carrying cost:

Type Level Valuation
Long-Term Debt, including amounts due within one year

Taxable Debt Securities
2 The fair value is determined by a valuation model that is based on a conventional discounted cash flow methodology and utilizes assumptions of current market pricing curves. We obtain credit spreads based on trades of our existing debt securities as well as other issuers in the utility sector with similar credit ratings. The yields are then converted into discount rates of various tenors that are used for discounting the respective cash flows of the same tenor for each bond or note.
Variable Rate Financing Debt 2 Debt rates are reset on a regular basis and the carrying value approximates fair value.
Government-Backed Fixed Rate Project Financing Debt
3 The fair value is similar to the process for taxable debt securities. Due to the lack of market trading data on similar debt, the discount rates are derived based on the original loan interest rate spread to the applicable U.S. Treasury rate as well as a current market curve derived from government-backed securities.
Non-Government-Backed Fixed Rate Nonrecourse Debt
3 Fair value is based on market and quoted prices for its own and other nonrecourse debt with similar risk profiles. Given the low trading volume in the nonrecourse debt market, the price quotes used to determine fair value will reflect certain qualitative factors, such as market conditions, investor demand, new developments that might significantly impact the project cash flows or off-taker credit, and other circumstances related to the project.
SNF Obligation
SNF Obligation 2 The carrying amount is derived from a contract with the DOE to provide for disposal of SNF from certain of our nuclear generating stations. See Note 18 — Commitments and Contingencies for further details. When determining the fair value of the obligation, the future carrying amount of the SNF obligation is calculated by compounding the current book value of the SNF obligation at the 13-week U.S. Treasury rate. The compounded obligation amount is discounted back to present value using our discount rate, which is calculated using the same methodology as described above for the taxable debt securities, and an estimated maturity date of 2040 for the years ended December 31, 2025 and 2024.

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Note 17 — Fair Value of Financial Assets and Liabilities

Recurring Fair Value Measurements
The following tables present assets and liabilities measured and recorded at fair value in the Consolidated Balance Sheets on a recurring basis and their level within the fair value hierarchy as of December 31, 2025 and 2024:

As of December 31, 2025 As of December 31, 2024
Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total
Assets
Cash equivalents (a)
$ 42   $ —   $ —   $ 42   $ 120   $ —   $ —   $ 120  
NDT fund investments
Cash equivalents (b)
72   165   —   237   187   163   —   350  
Equities 6,245   1,426   —   7,671   5,230   1,897   —   7,127  

Fixed income 2,201   1,566   395   4,162   2,089   1,462   368   3,919  
Private credit —   —   132   132   —   —   134   134  
Assets measured at NAV —  —  —  7,194   —  —  —  5,791  

NDT fund investments subtotal (c)
8,518   3,157   527   19,396   7,506   3,522   502   17,321  
Rabbi trust investments 66   45   1   112   58   41   1   100  

Investments in equities 87   —   —   87   389   —   —   389  
Derivative assets

Economic hedges 1,114   7,449   3,830   12,393   1,278   5,306   2,641   9,225  

Effect of netting and allocation of collateral
( 889 ) ( 6,853 ) ( 3,256 ) ( 10,998 ) ( 1,097 ) ( 4,790 ) ( 2,123 ) ( 8,010 )
Derivative assets subtotal
225   596   574   1,395   181   516   518   1,215  

Total assets measured at fair value 8,938   3,798   1,102   21,032   8,254   4,079   1,021   19,145  

Liabilities
Derivative liabilities

Economic hedges ( 1,148 ) ( 8,021 ) ( 4,062 ) ( 13,231 ) ( 1,222 ) ( 5,462 ) ( 2,778 ) ( 9,462 )

Effect of netting and allocation of collateral
1,065   7,657   3,628   12,350   1,180   5,157   2,259   8,596  
Derivative liabilities subtotal
( 83 ) ( 364 ) ( 434 ) ( 881 ) ( 42 ) ( 305 ) ( 519 ) ( 866 )
Deferred compensation obligation —   ( 124 ) —   ( 124 ) —   ( 93 ) —   ( 93 )
Total liabilities measured at fair value ( 83 ) ( 488 ) ( 434 ) ( 1,005 ) ( 42 ) ( 398 ) ( 519 ) ( 959 )
Total net assets $ 8,855   $ 3,310   $ 668   $ 20,027   $ 8,212   $ 3,681   $ 502   $ 18,186  
__________
(a) CEG Parent has $ 70 million and $ 130 million of Level 1 cash equivalents as of December 31, 2025 and 2024, respectively. We exclude cash of $ 3,621 million and $ 2,924 million, and restricted cash of $ 57 million and $ 71 million, as of December 31, 2025 and 2024, respectively. CEG Parent has no additional cash exclusions as of December 31, 2025, and an additional $ 4 million of cash excluded as of December 31, 2024.
(b) Includes net liabilities of $ 166 million and $ 148 million as of December 31, 2025 and 2024, respectively, which consist of receivables related to pending securities sales, interest and dividend receivables, repurchase agreement obligations, and payables related to pending securities purchases. The repurchase agreements are generally short-term in nature with durations generally of 30 days or less.
(c) Includes total NDT derivative assets and liabilities that are not material, which have total notional amounts of $ 810 million and $ 1,119 million as of December 31, 2025 and 2024, respectively. The notional principal amounts provide one measure of the transaction volume outstanding as of the periods ended and do not represent the amount of our exposure to credit or market loss.
As of December 31, 2025, our NDTs have outstanding commitments to invest in private credit, private equity, and real assets of $ 505 million, $ 487 million, and $ 576 million, respectively. These commitments will be funded by our existing NDT funds.
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Note 17 — Fair Value of Financial Assets and Liabilities

Equity Security Investments without Readily Determinable Fair Values. We hold investments without readily determinable fair values with carrying amounts of $ 109 million and $ 150 million as of December 31, 2025 and 2024, respectively. Changes in fair value, cumulative adjustments, and impairments were not material for the years ended December 31, 2025 and 2024.
Reconciliation of Level 3 Assets and Liabilities
The following tables present the fair value reconciliation of Level 3 assets and liabilities measured at fair value on a recurring basis during the years ended December 31, 2025 and 2024:

For the Year Ended December 31, 2025
NDT Fund Investments Derivatives
Rabbi Trust Investments
Total
Balance as of January 1, 2025 $ 502   $ ( 1 ) $ 1   $ 502  
Total realized / unrealized gains (losses)
Included in net income (loss) 9   ( 326 ) (a)
—   ( 317 )
Included in Payables related to Regulatory Agreement Units
19   —   —   19  
Change in collateral —   236   —   236  
Purchases —   84   —   84  
Sales —   ( 5 ) —   ( 5 )
Settlements ( 4 ) 51  

—   47  
Transfers into Level 3 1   ( 47 ) (b)
—   ( 46 )
Transfers out of Level 3 —   148   (b)
—   148  
Balance as of December 31, 2025 $ 527   $ 140   $ 1   $ 668  
The amount of total gains (losses) included in income attributed to the change in unrealized gains (losses) related to assets and liabilities as of December 31, 2025
$ 9   $ ( 56 ) $ —   $ ( 47 )

For the Year Ended December 31, 2024
NDT Fund Investments Derivatives
Rabbi Trust Investments
Total
Balance as of January 1, 2024 $ 429   $ 869   $ 1   $ 1,299  
Total realized / unrealized gains (losses)
Included in net income (loss) 5   ( 861 ) (a)
—   ( 856 )
Included in Payables related to Regulatory Agreement Units 16   —   —   16  
Change in collateral —   ( 325 ) —   ( 325 )
Purchases 66   61   —   127  
Sales —   ( 83 ) —   ( 83 )
Settlements ( 15 ) 29   —   14  
Transfers into Level 3 1   44   (b)
—   45  
Transfers out of Level 3 —   265   (b)
—   265  
Balance as of December 31, 2024 $ 502   $ ( 1 ) $ 1   $ 502  
The amount of total gains (losses) included in income attributed to the change in unrealized gains (losses) related to assets and liabilities as of December 31, 2024
$ 5   $ ( 126 ) $ —   $ ( 121 )

__________
(a) Includes a reduction of ($ 219 ) million and ($ 706 ) million for realized gains due to the settlement of derivative contracts for the years ended December 31, 2025 and 2024, respectively.
(b) Transfers into and out of Level 3 generally occur when the contract tenor becomes less and more observable, respectively, primarily due to changes in market liquidity or assumptions for certain commodity contracts.
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Note 17 — Fair Value of Financial Assets and Liabilities

The following table presents the income statement classification of the total realized and unrealized gains (losses) included in income for Level 3 assets and liabilities measured at fair value on a recurring basis during the years ended December 31, 2025, 2024, and 2023:

Operating Revenues
Purchased Power and Fuel
Other, net
2025 2024 2023 2025 2024 2023 2025 2024 2023
Total gains (losses) included in net income
$ ( 340 ) $ ( 539 ) $ 706   $ 65   $ ( 293 ) $ ( 503 ) $ 9   $ 5   $ 2  
Total unrealized gains (losses)
( 172 ) 207   1,673   116   ( 333 ) ( 479 ) 9   5   2  

Valuation Techniques Used to Determine Fair Value
Cash Equivalents. Investments with original maturities of three months or less when purchased, including mutual and money market funds, are considered cash equivalents. The fair values are based on observable market prices and, therefore, are included in the recurring fair value measurements hierarchy as Level 1.
NDT Fund Investments. The trust fund investments have been established to satisfy our nuclear decommissioning obligations as required by the NRC. The NDT funds hold debt and equity securities directly and indirectly through commingled funds and mutual funds, which are included in equities and fixed income. Our NDT fund investments policies outline investment guidelines for the trusts and limit the trust funds’ exposures to investments in highly illiquid markets and other alternative investments, including private credit, private equity, and real assets. Investments with maturities of three months or less when purchased, including certain short-term fixed income securities are considered cash equivalents and included in the recurring fair value measurements hierarchy as Level 1 or Level 2.
Equities. These investments consist of individually held equity securities, equity mutual funds, and equity commingled funds in domestic and foreign markets. With respect to individually held equity securities, the trustees obtain prices from pricing services, whose prices are generally obtained from direct feeds from market exchanges, which we are able to independently corroborate. Equity securities held individually, including real estate investment trusts, rights, and warrants, are primarily traded on exchanges that contain only actively traded securities due to the volume trading requirements imposed by these exchanges. The equity securities that are held directly by the trust funds are valued based on quoted prices in active markets and categorized as Level 1. Certain equity securities have been categorized as Level 2 because they are based on evaluated prices that reflect observable market information, such as actual trade information or similar securities. Certain private placement equity securities are categorized as Level 3 because they are not publicly traded and are priced using significant unobservable inputs.
Equity commingled funds and mutual funds are maintained by investment companies, and fund investments are held in accordance with a stated set of fund objectives. The values of some of these funds are publicly quoted. For mutual funds which are publicly quoted, the funds are valued based on quoted prices in active markets and have been categorized as Level 1. For equity commingled funds and mutual funds which are not publicly quoted, the fund administrators value the funds using the NAV per fund share, derived from the quoted prices in active markets on the underlying securities and are not classified within the fair value hierarchy. These investments can typically be redeemed monthly or more frequently, with 30 or less days of notice and without further restrictions.
Fixed income. For fixed income securities, which consist primarily of corporate debt securities, U.S. government securities, foreign government securities, municipal bonds, asset and mortgage-backed securities, commingled funds, mutual funds, and derivative instruments, the trustees obtain multiple prices from pricing vendors whenever possible, which enables cross-provider validations in addition to checks for unusual daily movements. A primary price source is identified based on asset type, class, or issue for each security. With respect to individually held fixed income securities, the trustees monitor prices supplied by pricing services and may use a supplemental price source or change the primary price source of a given security if the portfolio managers challenge an assigned price and the trustees determine that another price source is preferable. We have obtained an understanding of how these prices are derived, including the nature and observability of the inputs used in deriving such prices. Additionally, we selectively corroborate the fair values of securities by comparison to other market-based price sources. Investments in U.S. Treasury securities have been categorized as Level 1 because they trade in highly-liquid and transparent markets. Certain private placement fixed income securities
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have been categorized as Level 3 because they are priced using certain significant unobservable inputs and are typically illiquid. The remaining fixed income securities, including certain other fixed income investments, are based on evaluated prices that reflect observable market information, such as actual trade information of similar securities, adjusted for observable differences and are categorized as Level 2. This includes equity investments sold short during the period, which represent liabilities.
Other fixed income investments primarily consist of fixed income commingled funds and mutual funds, which are maintained by investment companies and hold fund investments in accordance with a stated set of fund objectives. The values of some of these funds are publicly quoted. For mutual funds which are publicly quoted, the funds are valued based on quoted prices in active markets and have been categorized as Level 1. For fixed income commingled funds and mutual funds which are not publicly quoted, the fund administrators value the funds using the NAV per fund share, derived from the quoted prices in active markets of the underlying securities and are not classified within the fair value hierarchy. These investments typically can be redeemed monthly or more frequently, with 30 or less days of notice and without further restrictions.
Derivative instruments. These instruments, consisting primarily of futures and swaps to manage risk, are recorded at fair value. Over-the-counter derivatives are valued daily, based on quoted prices in active markets and trade in open markets, and have been categorized as Level 1. Derivative instruments other than over-the-counter derivatives are valued based on external price data of comparable securities and have been categorized as Level 2.
Private credit. Private credit investments primarily consist of investments in private debt strategies. These investments are generally less liquid assets, typically with an underlying term of 3 to 5 years, and are usually intended to be held to maturity. The fair value of these investments is determined by the fund manager or administrator using a combination of valuation models including cost models, market models, and income models and typically cannot be redeemed until maturity of the term loan. Private credit investments held directly by us are categorized as Level 3 because they are based largely on inputs that are unobservable and utilize complex valuation models. For certain private credit funds, the fair value is determined using a combination of valuation models including cost models, market models, and income models and typically cannot be redeemed until maturity of the term loan. These investments are not classified within the fair value hierarchy because their fair value is determined using NAV or its equivalent as a practical expedient.
Private equity. These investments include those in limited partnerships that invest in operating companies that are not publicly traded on a stock exchange such as leveraged buyouts, growth capital, venture capital, distressed investments, and investments in natural resources. These investments typically cannot be redeemed and are generally liquidated over a period of 8 to 10 years from the initial investment date, which is based on our understanding of the investment funds. Private equity valuations are reported by the fund manager and are based on the valuation of the underlying investments, which include unobservable inputs such as cost, operating results, discounted future cash flows, and market-based comparable data. These valuation inputs are unobservable. The fair value of private equity investments is determined using NAV or its equivalent as a practical expedient, and therefore, these investments are not classified within the fair value hierarchy.
Real assets. These investments are funds with a direct investment in pools of real estate properties or infrastructure assets. These funds are reported by the fund manager and are generally based on independent appraisals of the underlying investments from sources with professional qualifications, typically using a combination of market-based comparable data and discounted cash flows. These valuation inputs are unobservable. Certain real asset investments cannot be redeemed and are generally liquidated over a period of 8 to 25 years from the initial investment date, which is based on our understanding of the investment funds. The remaining liquid real asset investments are generally redeemable from the investment vehicle quarterly, with 30 to 90 days of notice. The fair value of real asset investments is determined using NAV or its equivalent as a practical expedient, and therefore, these investments are not classified within the fair value hierarchy.
We evaluated our NDT 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, there were no significant concentrations (generally defined as greater than 10%) of risk in the NDT assets.
See Note 10 — Asset Retirement Obligations for additional information on the NDT fund investments.
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Note 17 — Fair Value of Financial Assets and Liabilities

Rabbi Trust Investments. The Rabbi trusts were established to hold assets related to deferred compensation plans existing for certain active and retired members of executive management and directors. The Rabbi trusts' assets are included in investments in the Consolidated Balance Sheets and consist primarily of money market funds, mutual funds, and life insurance policies. Money market funds and mutual funds are publicly quoted and have been categorized as Level 1 given the clear observability of the prices. The life insurance policies are valued using the cash surrender value of the policies, net of loans against those policies, which is provided by a third-party. Certain life insurance policies, which consist primarily of mutual funds that are priced based on observable market data, have been categorized as Level 2 because the life insurance policies can be liquidated at the reporting date for the value of the underlying assets.
Deferred Compensation Obligations. Our deferred compensation plans allow participants to defer certain cash compensation into a notional investment account. We include such plans in other current and noncurrent liabilities in the Consolidated Balance Sheets. The value of our deferred compensation obligations is based on the market value of the participants’ notional investment accounts. The underlying notional investments are comprised primarily of equities, mutual funds, commingled funds, and fixed income securities which are based on directly and indirectly observable market prices. Since the deferred compensation obligations themselves are not exchanged in an active market, they are categorized as Level 2 in the fair value hierarchy.
The value of certain employment agreement obligations (which are included with the Deferred compensation obligation in the table above) are based on a known and certain stream of payments to be made over time and are categorized as Level 2 within the fair value hierarchy.
Investments in Equities. We hold certain investments in equity securities with readily determinable fair values in addition to those held within the NDT funds. These equity securities are valued based on quoted prices in active markets and are categorized as Level 1.
Derivatives. Derivative contracts are traded in both exchange-based and non-exchange-based markets. Exchange-based derivatives that are valued using unadjusted quoted prices in active markets are categorized in Level 1 in the fair value hierarchy. Certain derivatives’ pricing is verified using indicative price quotations available through brokers, over-the-counter, or exchanges and are categorized in Level 2. These price quotations reflect the average of the bid-ask, mid-point prices and are obtained from sources that we believe provide the most liquid market for the commodity. The price quotations are reviewed and corroborated to ensure the prices are observable and representative of an orderly transaction between market participants. This includes consideration of actual transaction volumes, market delivery points, bid-ask spreads, and contract duration. The remainder of derivative contracts are valued using the Black model, an industry standard option valuation model. The Black model considers inputs such as contract terms, including maturity, and market parameters, including assumptions of the future prices of energy, interest rates, volatility, credit worthiness, and credit spread. For derivatives that trade in liquid markets, such as generic forwards, swaps, and options, model inputs are generally observable. Such instruments are categorized in Level 2. Our derivatives are predominantly at liquid trading points. For derivatives that trade in less liquid markets with limited pricing information, model inputs generally would include both observable and unobservable inputs. These valuations may include an estimated basis adjustment from an illiquid trading point to a liquid trading point for which active price quotations are available. Such instruments are categorized in Level 3.
For valuations that include both observable and unobservable inputs, if the unobservable input is determined to be significant to the overall inputs, the entire valuation is categorized in Level 3. This includes derivatives valued using indicative price quotations whose contract tenure extends into unobservable periods. In instances where observable data is unavailable, consideration is given to the assumptions that market participants would use in valuing the asset or liability. This includes assumptions about market risks such as liquidity, volatility, and contract duration. Such instruments are categorized in Level 3 as the model inputs generally are not observable. We consider credit and non-performance risk in the valuation of derivative contracts categorized in Level 2 and 3, including both historical and current market data, in our assessment of credit and non-performance risk by counterparty. Due to master netting agreements and collateral posting requirements, the impacts of credit and non-performance risk were not material to the consolidated financial statements.
Disclosed below is detail surrounding our significant Level 3 valuations. The calculated fair value includes marketability discounts for margining provisions and other attributes. The Level 3 balance generally consists of forward sales and purchases of power and natural gas and certain transmission congestion contracts. We utilize various inputs and factors including market data and assumptions that market participants would use in pricing
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assets or liabilities as well as assumptions about the risks inherent in the inputs to the valuation technique. The inputs and factors include forward commodity prices, commodity price volatility, contractual volumes, delivery location, interest rates, credit quality of counterparties, and credit enhancements.
For commodity derivatives, the primary input to the valuation models is the forward commodity price curve for each instrument. All locations are reviewed and verified by risk management considering published exchange transaction prices, executed bilateral transactions, broker quotes, and other observable or public data sources. The relevant forward commodity curve used to value each of the derivatives depends on a number of factors, including commodity type, delivery location, and delivery period. Price volatility varies by commodity and location. When appropriate, we discount future cash flows using risk-free interest rates with adjustments to reflect the credit quality of each counterparty for assets and our own credit quality for liabilities. The level of observability of a forward commodity price varies generally due to the delivery location and delivery period. Certain delivery locations including PJM West Hub (for power) and Henry Hub (for natural gas) are more liquid and prices are observable for up to three years in the future. The observability period of volatility is generally shorter than the underlying power curve used in option valuations. The forward curve for a less liquid location is estimated by using the forward curve from the liquid location and applying a spread to represent the cost to transport the commodity to the delivery location. This spread does not typically represent a majority of the instrument’s market price. As a result, the change in fair value is closely tied to liquid market movements and not a change in the applied spread. The change in fair value associated with a change in the spread is generally immaterial. An average spread calculated across all Level 3 power and gas delivery locations is approximately $ 52.17 and $ 3.52 for power and natural gas, respectively as of December 31, 2025. Many of the commodity derivatives are short term in nature and thus a majority of the fair value may be based on observable inputs even though the contract as a whole must be classified as Level 3.
See Note 15 — Derivative Financial Instruments for additional information on derivatives.
The following table presents the significant inputs to the forward curve used to value these positions:

Type of trade Fair Value as of December 31, 2025 Fair Value as of December 31, 2024 Valuation Technique
Unobservable Input
2025 Range & Arithmetic Average
2024 Range & Arithmetic Average

Level 3 Derivatives—Economic hedges (a)(b)
$ ( 232 ) $ ( 137 ) Discounted Cash Flow Forward power price $ 1.89 - $ 154
$ 52 $ 2.57 - $ 140
$ 49
Forward gas price $( 0.46 ) - $ 15
$ 3.52 $ 2.09 - $ 15
$ 3.68
Option Model Volatility percentage 14 % - 197 %
59 % 23 % - 141 %
57 %

__________
(a) The valuation techniques, unobservable inputs, ranges, and arithmetic averages are the same for the asset and liability positions.
(b) The fair values do not include cash collateral posted (received) on Level 3 positions of $ 372 million and $ 136 million as of December 31, 2025 and 2024, respectively.
The inputs listed above, which are as of the balance sheet date, would have a direct impact on the fair values of the above instruments if they were adjusted. The significant unobservable inputs used in the fair value measurement of our commodity derivatives are forward commodity prices and for options is price volatility. Increases (decreases) in the forward commodity price in isolation would result in significantly higher (lower) fair values for long positions (contracts that give us the obligation or option to purchase a commodity), with offsetting impacts to short positions (contracts that give us the obligation or right to sell a commodity). Increases (decreases) in volatility would increase (decrease) the value for the holder of the option (writer of the option). Generally, a change in the estimate of forward commodity prices is unrelated to a change in the estimate of volatility of prices. An increase to the heat rate or renewable factors would increase the fair value accordingly. Generally, interrelationships exist between market prices of natural gas and power. As such, an increase in natural gas pricing would potentially have a similar impact on forward power markets.
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Note 18 — Commitments and Contingencies

18. Commitments and Contingencies
Commercial Commitments. Commercial commitments as of December 31, 2025, representing commitments potentially triggered by future events, were as follows:

Expiration within
2026 2027 2028 2029 2030 2031 and beyond Total
Letters of credit $ 1,784   $ 190   $ 122   $ —   $ 1   $ 3   $ 2,100  
Surety bonds (a)
603   —   214   —   —   —   817  
Total commercial commitments $ 2,387   $ 190   $ 336   $ —   $ 1   $ 3   $ 2,917  

__________
(a) Surety bonds — Guarantees issued related to contract and commercial agreements, excluding bid bonds.
Nuclear Insurance
We are subject to liability, property damage and other risks associated with major incidents at any of our nuclear stations. Our financial exposure to these risks is mitigated through insurance and other industry risk-sharing provisions.
The Price-Anderson Act was enacted to ensure the availability of funds for public liability claims arising from an incident at any of the U.S. licensed nuclear facilities and to limit the liability of nuclear reactor owners for such claims from any single incident. As of December 31, 2025, the current liability limit per incident is $ 16.3 billion and is subject to change to account for the effects of inflation and changes in the number of licensed reactors at least once every five years with the last adjustment effective January 1, 2024. In accordance with the Price-Anderson Act, we maintain financial protection at levels equal to the amount of liability insurance available from private sources through the purchase of private nuclear energy liability insurance for public liability claims that could arise in the event of an incident. Effective January 1, 2024, the required amount of nuclear energy liability insurance purchased is $ 500 million for each operating site. Claims exceeding that amount are covered through mandatory participation in a financial protection pool, as required by the Price Anderson-Act, which could provide up to approximately an additional $ 15.8 billion per incident at any U.S. nuclear power reactor in funds available for public liability claims. Participation in this secondary financial protection pool requires the operator of each reactor to fund its proportionate share of costs for any single incident at any U.S. nuclear power reactor that exceeds the primary layer of financial protection. Our share of this secondary layer would be approximately $ 3.5 billion, based on our ownership interest in the insured nuclear reactors, however, any amounts payable under this secondary layer would be capped at $ 520  million per incident within one calendar year.
In addition, the U.S. Congress could impose revenue-raising measures on the nuclear industry to pay public liability claims exceeding the $ 16.3 billion limit for a single incident.
We are required by the NRC to maintain minimal levels of property insurance that demonstrates to the satisfaction of the NRC that we possess an equivalent amount of protection covering the licensee's obligation, in the event of an accident at the licensee's reactor, to stabilize and decontaminate the reactor and the reactor station site at which the reactor experiencing the accident is located. The insurance maintained for each facility is currently provided through insurance policies purchased from NEIL, an industry mutual insurance company of which we are a member. Currently, the NRC requires that we maintain a minimum coverage limit for each reactor site of $ 1.06  billion, and we currently have coverage of $ 1.5  billion for each site.
NEIL may declare distributions to its members as a result of favorable operating experience. In recent years, NEIL has made distributions to its members. Our portion of the annual distribution declared by NEIL is estimated to be $ 114  million for 2025, and was $ 44  million and $ 59  million for 2024 and 2023, respectively. The distributions were recorded as a reduction to Operating and maintenance expense in the Consolidated Statements of Operations and Comprehensive Income.
Premiums paid to NEIL by its members are also subject to a potential assessment for adverse loss experience in the form of a retrospective premium obligation. NEIL has never assessed this retrospective premium since its formation in 1973, and we cannot predict the level of future assessments, if any. The current maximum aggregate annual retrospective premium obligation for our interests is approximately $ 297 million. NEIL requires its
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members to maintain an investment grade credit rating or to ensure collectability of their annual retrospective premium obligation by providing a financial guarantee, letter of credit, deposit premium, or some other means of assurance.
NEIL provides “all risk” property damage, decontamination, and premature decommissioning insurance for each station for losses resulting from damage to its nuclear plants, either due to accidents or acts of terrorism. If the decision is made to decommission the facility, a portion of the insurance proceeds will be allocated to a fund, which we are required by the NRC to maintain, to provide for decommissioning the facility. In the event of an insured loss, we are unable to predict the timing of the availability of insurance proceeds to us and the amount of such proceeds that would be available. In the event that one or more acts of terrorism cause accidental property damage within a twelve-month period from the first accidental property damage under one or more policies for all insured plants, the maximum recovery by us will be an aggregate of $ 3.2 billion plus such additional amounts as the insurer may recover for all such losses from reinsurance, indemnity and any other source, applicable to such losses.
For our insured losses, we are self-insured to the extent that losses are within the policy deductible or exceed the amount of insurance maintained. Uninsured losses and other expenses, to the extent not recoverable from insurers or the nuclear industry, could also be borne by us. Any such losses could have a material adverse effect on our consolidated financial statements.
Spent Nuclear Fuel Obligation
Under the Nuclear Waste Policy Act of 1982 (NWPA), the DOE is responsible for the development of a geologic repository for and the disposal of SNF and high-level radioactive waste. As required by the NWPA, we are a party to contracts with the DOE (Standard Contracts) to provide for disposal of SNF from our nuclear generating stations. In accordance with the NWPA and the Standard Contracts, we had previously paid the DOE one mill ($0.001) per kWh of net nuclear generation for the cost of SNF disposal. The DOE reduced the SNF disposal fee to zero in May 2014. Until a new fee structure is in effect, we will not accrue any further costs related to SNF disposal fees. This fee may be adjusted prospectively to ensure full cost recovery.
We currently assume the DOE will begin accepting SNF in 2040 and use that date for purposes of estimating the nuclear decommissioning AROs. The SNF acceptance date assumption is based on management’s estimate of the amount of time required for DOE to select a site location and develop the necessary infrastructure for long-term SNF storage.
The NWPA and the Standard Contracts required the DOE to begin taking possession of SNF generated by nuclear generating units no later than January 31, 1998. The DOE, however, failed to meet that deadline and its performance has been, and is expected to remain, delayed. In August 2004, we and the DOJ, in close consultation with the DOE, reached a settlement under which the government agreed to reimburse us, subject to certain damage limitations based on the extent of the government’s breach, for costs associated with storage of SNF at our nuclear stations pending the DOE’s fulfillment of its obligations. That settlement agreement does not expire until all SNF has been collected from the sites that it covers. Calvert Cliffs, Ginna, NMP, Fitzpatrick, and STP each have separate settlement agreements in place with the DOE which were extended during 2023 to provide for the reimbursement of SNF storage costs through December 31, 2025, and we are currently seeking a further extension. We and the DOE have the option to extend those settlements every three years upon mutual consent.
Under the settlement agreements, we received total cumulative cash reimbursements of $ 2,238  million through December 31, 2025 for costs incurred. After considering the amounts due to co-owners of certain nuclear stations and to the current owner of Oyster Creek Nuclear Generating Station, we received net cumulative cash reimbursements of $ 1,955  million. As of December 31, 2025 and 2024, the amount of SNF storage costs for
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which reimbursement has been or will be requested from the DOE under the DOE settlement agreements is as follows:

December 31, 2025 December 31, 2024
DOE receivable - current (a)
$ 117   $ 124  
DOE receivable - noncurrent (b)
28   42  
Amounts owed to co-owners (c)
( 20 ) ( 40 )

__________
(a) Recorded in Accounts receivable, net.
(b) Recorded in Other deferred debits and other assets.
(c) Recorde d primarily in Accounts payable and accrued expenses and Accounts receivable, net. Represents amounts owed to the co-owners of Peach Bottom, Quad Cities, and NMP Unit 2 generating facilitie s .
The Standard Contracts with the DOE also required the payment to the DOE of a one-time fee applicable to nuclear plants that generated SNF prior to April 7, 1983. The below table outlines the SNF liability, which is recorded within Other deferred credits and other liabilities, as of December 31, 2025 and 2024:

December 31, 2025 December 31, 2024
Former ComEd units (a)
$ 1,271   $ 1,219  
Fitzpatrick (b)
155   147  
Total SNF Obligation $ 1,426   $ 1,366  

__________
(a) ComEd previously elected to defer payment of the one-time fee of $ 277  million for its units that began operations before April 7, 1983, with interest to the date of payment, until just prior to the first delivery of SNF to the DOE. The unfunded liabilities for SNF disposal costs, including the one-time fee, were transferred to us as part of Exelon’s 2001 corporate restructuring. See Note 10 — Asset Retirement Obligations for additional detail on Zion Station’s SNF obligation which is included in the table above.
(b) A prior owner of FitzPatrick elected to defer payment of the one-time fee of $ 34  million, with interest to the date of payment, for the FitzPatrick unit. As part of the FitzPatrick acquisition on March 31, 2017, we assumed a SNF liability for the DOE one-time fee obligation with interest related to FitzPatrick along with an offsetting asset, included in Other deferred debits and other assets, for the contractual right to reimbursement from NYPA, a prior owner of FitzPatrick, for amounts paid for the FitzPatrick DOE one-time fee obligation.
Interest for our SNF liabilities accrues at the 13-week Treasury Rate. The 13-week Treasury Rate in effect for calculation of the interest accrual at December 31, 2025 and 2024 was 3.906 % and 4.553 %, respectively for the deferred amount transferred from ComEd, and 3.953 % and 4.615 %, respectively, for the deferred FitzPatrick amount.
The following table summarizes sites for which we do not have an outstanding SNF Obligation:

Description Sites
Fees have been paid or began operations after April 7, 1983 Former PECO units, Braidwood, Byron, Calvert Cliffs, Clinton, LaSalle Unit 2, NMP Unit 2, and STP

Outstanding SNF Obligation remains with former owners NMP Unit 1, Ginna, and Crane

Environmental Remediation Matters
General. Our operations have in the past, and may in the future, require substantial expenditures to comply with environmental laws. Additionally, under Federal and state environmental laws, we are generally liable for the costs of remediating environmental contamination of property now or formerly owned by us and of property contaminated by hazardous substances generated by us. We own or lease several real estate parcels, including parcels on which our operations or the operations of others may have resulted in contamination by substances that are considered hazardous under environmental laws. In addition, we are currently involved in proceedings relating to sites where hazardous substances have been deposited and may be subject to additional proceedings in the future. Unless otherwise disclosed, we cannot reasonably estimate whether we will incur significant liabilities for additional investigation and remediation costs at these or additional sites identified by us,
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environmental agencies or others. Additional costs could have a material, unfavorable impact on our consolidated financial statements.
As of December 31, 2025 and 2024, we had accrued undiscounted amounts for environmental liabilities of $ 9 million and $ 60 million, respectively, in Accounts payable and accrued expenses and $ 169 million for both periods in Other deferred credits and other liabilities in the Consolidated Balance Sheets.
Cotter Corporation. The EPA has advised Cotter Corporation (N.S.L.) (Cotter), a former ComEd subsidiary, that it is potentially liable in connection with radiological contamination at two sites in Missouri. In 2000, ComEd sold Cotter to an unaffiliated third-party. As part of the sale, ComEd agreed to indemnify Cotter for any liability arising from these two Missouri superfund sites, West Lake Landfill and Latty Avenue. In connection with Exelon’s 2001 corporate restructuring, this responsibility to indemnify Cotter was transferred to us, and ultimately retained by us per the terms of our separation from Exelon. Refer to Note 1 — Basis of Presentation for additional information on the separation.
West Lake Landfill. Including Cotter, there are three PRPs currently participating in the West Lake Landfill remediation proceeding.
West Lake Landfill; Operable Unit 1 (OU1); Landfill Remediation. In September 2018, the EPA issued its Record of Decision Amendment (RODA) for the selection of a final remedy that requires partial excavation of the radiological materials and capping the landfill. The EPA and the PRPs have entered into a Consent Agreement to perform the Remedial Design, which is now expected to be completed in 2026. In March 2019, the PRPs received Special Notice Letters from the EPA to perform the Remedial Action work. The total estimated cost of the design, remedy, and operation and maintenance, considering the current EPA technical requirements, is approximately $ 560 million, including cost escalation on an undiscounted basis.
West Lake Landfill; Operable Unit 3 (OU3); Groundwater Study. In September 2018, the three identified PRPs, including Cotter, signed an Administrative Settlement Agreement and Order on Consent for the performance by the PRPs of the groundwater Remedial Investigation Feasibility Study (RI/FS). The purpose of this RI/FS is to define the nature and extent of any groundwater contamination from the West Lake Landfill site and evaluate remedial alternatives. We estimate the undiscounted cost for the groundwater RI/FS to be approximately $ 60 million. At this time we cannot predict the likelihood, or the extent to which remediation activities, if any, may be required and therefore cannot estimate a reasonably possible range of loss for response costs beyond those associated with the RI/FS component.
We determined a loss associated with the EPA's partial excavation and landfill cover remedy and the groundwater RI/FS is probable and have recorded a liability for each, both of which are included in the total amount as discussed above, that reflects management’s best estimate of Cotter’s allocable share of the cost among the PRPs. Given the joint and several nature of these two liabilities, the amount of our ultimate liability will depend on the actual costs incurred to implement the required remedy at OU1 and the required study at OU3, as well as on the nature and terms of any cost-sharing arrangements with the final group of PRPs. It is reasonably possible that the ultimate cost and Cotter's associated allocable share could differ significantly once these uncertainties are resolved, which could have a material impact on our results of operations and financial condition.
Latty Avenue and Vicinity Properties . In August 2011, Cotter was notified by the DOJ that Cotter is considered a PRP with respect to the government’s clean-up costs for contamination attributable to low-level radioactive residues at a former storage and reprocessing facility named Latty Avenue near St. Louis, Missouri.
Latty Avenue was investigated and remediated by the United States Army Corps of Engineers pursuant to funding under the Formerly Utilized Sites Remedial Action Program. The PRPs reached a settlement of this matter and the government filed a motion for entry of a Consent Decree, which was entered by the Court on January 24, 2025. Payment of $ 50  million plus statutory interest was made on January 30, 2025. The consent decree settles past and future responses costs incurred by the United States Army Corp of Engineers and DOE for their response actions conducted in connection with the release or threatened release of hazardous substances, including radioactive substances at Latty Avenue and certain additional adjacent properties.
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Litigation
We are involved in various litigation matters that are being defended and handled in the ordinary course of business. The assessment of whether a loss is probable or reasonably possible, and whether the loss or a range of loss is estimable, often involves a series of complex judgments about future events. We maintain accruals for such losses that are probable of being incurred and subject to reasonable estimation. Management is sometimes unable to estimate an amount or range of reasonably possible loss, particularly where (1) the damages sought are indeterminate, (2) the proceedings are in the early stages, or (3) the matters involve novel or unsettled legal theories. In such cases, there is considerable uncertainty regarding the timing or ultimate resolution of such matters, including a possible eventual loss.
Impacts of the February 2021 Extreme Cold Weather Event and Texas-based Generating Assets Outages. Beginning on February 15, 2021, our Texas-based generating assets within the ERCOT market, specifically Colorado Bend II, Wolf Hollow II, and Handley, experienced outages as a result of extreme cold weather conditions.
Various lawsuits have been filed against us since the February 2021 event and outages. In March 2021, we, along with more than 150 power generators and transmission and distribution companies, were sued by approximately 160 individually named plaintiffs, purportedly on behalf of all Texans who allegedly suffered loss of life or sustained personal injury, property damage, or other losses as a result of the weather events. The plaintiffs alleged that the defendants failed to properly prepare for the cold weather and failed to properly conduct their operations, seeking compensatory as well as punitive damages. Thereafter, numerous other plaintiffs filed multiple lawsuits against more than 300 defendants, including us, involving similar allegations of liability and claims of personal injury and property damage all arising out of the February weather events. These additional lawsuits allege wrongful death, property damage, or other losses. Co-defendants in these lawsuits include ERCOT, transmission and distribution utilities and other generators.
In December 2021, approximately 130 insurance companies which insured Texas homeowners and businesses filed a subrogation lawsuit against multiple defendants alleging that defendants were at fault for the energy failure that resulted from the winter storm, causing significant property damage to the insureds. Subsequently, several hundred other insurance companies filed similar claims. All of these cases were combined in a Multi-District-Litigation (MDL) pending in Texas state court, which established a bellwether process to consider initial motions to dismiss by the different industry groups of defendants. Defendants filed motions to dismiss the amended complaints in five bellwether cases in July 2022. In February 2023, the court granted the motions to dismiss pertaining to us in part and denied them in part, leaving the plaintiffs' negligence and nuisance claims to proceed. Since the motions to dismiss were partially denied, thousands of new claimants, many in multiple mass tort actions, filed lawsuits in various Texas state courts naming us, among hundreds of other defendants. The majority of these cases were transferred to the MDL. The MDL involves over 200 cases brought by approximately 30,000 plaintiffs, including more than 1,300 insurance companies, and we are defendants in the majority of them. We had also been named in an alleged class action that sought to assert claims on behalf of over 4.1 million Texans within ERCOT who lost power during Winter Storm Uri. The court subsequently denied certification of the class, and plaintiffs have not presently pursued on appeal.
In December 2023, the Court of Appeals for the First District of Texas granted the power generator defendants' Petition for a Writ of Mandamus in the five bellwether cases and ordered the MDL court to dismiss the remaining claims against the power generator defendants, including our entities. The motions to dismiss in the five bellwether cases are expected to be applied to all the claims against the power generator defendants in the MDL. In January 2024, plaintiffs filed motions for en banc reconsideration of the order with the full court of appeals in all five bellwether cases. In November 2024, the court denied plaintiffs' motions. In January 2025, plaintiffs petitioned the Supreme Court of Texas for mandamus review, requesting that the court reinstate the MDL court's denial of the generator defendants' motions to dismiss and thereby permit plaintiffs' claims to proceed. In June 2025, the court requested consolidated briefing on the merits in each of the five bellwether cases. The briefing concluded in February 2026, and the parties now await a decision from the court.
In addition to the cases pending in the MDL in Texas state court, in January 2025, the Attorney General of the State of Oklahoma filed a lawsuit in state court against us, along with 10 other defendants, alleging antitrust and consumer protection act violations as well as unjust enrichment in connection with the sale, transport and marketing of natural gas to state agencies, municipalities and the people of the state of Oklahoma during the extreme cold weather event. The Attorney General seeks compensatory and punitive damages. In March 2025,
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defendants filed multiple motions to dismiss the lawsuit, which were denied by the court in August 2025. The parties are now engaged in discovery with trial likely to be scheduled in 2027.
We dispute liability and deny that we are responsible for any of plaintiffs’ alleged claims and are vigorously contesting them. No loss contingencies have been reflected in the consolidated financial statements with respect to these matters, nor can we currently estimate a range of loss. It is reasonably possible, however, that resolution of these matters could have a material, unfavorable impact on our consolidated financial statements.
Asbestos Personal Injury Claims. We maintain a reserve for claims associated with asbestos-related personal injury actions at certain facilities that are currently owned by us or were previously owned by ComEd, PECO, or BGE. The estimated liabilities are recorded on an undiscounted basis and exclude the estimated legal costs associated with handling these matters, which could be material.
At December 31, 2025 and 2024, we recorded estimated liabilities of approximately $ 120 million and $ 125  million, respectively, in total for asbestos-related bodily injury claims. These amounts are primarily included in Other deferred credits and other liabilities in the Consolidated Balance Sheets. Current amounts included in Accounts payable and accrued expenses are not material in either of the periods presented. As of December 31, 2025, approximately $ 17 million of this amount related to 251 open claims presented to us, while the remaining $ 103 million is for estimated future asbestos-related bodily injury claims anticipated to arise through 2055, based on actuarial assumptions and analyses, which are updated on an annual basis. On a quarterly basis, we monitor actual experience against the number of forecasted claims to be received and expected claim payments and evaluate whether adjustments to the estimated liabilities are necessary.

19. Shareholders' Equity
Share Repurchase Program (CEG Parent)
Since 2023, our Board of Directors authorized the repurchase of up to $ 3  billion of the Company's outstanding common stock. Share repurchases may be made through a variety of methods, which may include open market transactions, privately negotiated transactions, or purchases pursuant to a Rule 10b5-1 trading plan, provided that the amounts spent do not exceed what is authorized. Any repurchased shares are constructively retired and cancelled. The program does not obligate us to acquire a minimum number of shares during any period and our repurchase of the Company's common stock may be limited, suspended, or discontinued at any time at our discretion and without prior notice. No other repurchase plans or programs have been authorized. As of December 31, 2025, there was approximately $ 593 million of remaining authority to repurchase shares of the Company's outstanding common stock.
During 2025, there were no open market repurchases. During 2024, we repurchased from the open market approximately 1.2 million shares of our common stock for a total cost, inclusive of taxes and transaction costs, of $ 150 million.
In 2024 and 2025, we entered into ASR agreements with financial institutions to initiate share repurchases of our common stock. Under the ASR agreements, we paid a specified amount to the financial institutions and received an initial delivery of shares of common stock, which resulted in an immediate reduction in the number of our shares outstanding. Based on the terms of the ASR agreements, we received an initial share delivery based on 80 % of each ASR agreements' cost. Upon settlement of the ASR agreements, the financial institution delivers additional incremental shares. The total number of shares ultimately delivered, and therefore the average price paid per share, is determined at the end of the applicable purchase period of each ASR agreement based on the average of the daily-volume weighted average share price, less a discount.
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Note 19 — Shareholders' Equity

The following table summarizes each ASR agreement for the years ended December 31, 2025 and December 31, 2024:

(in millions, except average price paid per share)
ASR Agreement Initiation Total Cost Initial Shares Received ASR Agreement Settlement Additional Shares Received
Total Number of Shares Purchased Average Price Paid per Share
March 2024 $ 354   1.7   May 2024 0.2   1.9   $ 182.65  
May 2024 $ 505   1.8   July 2024 0.6   2.4   $ 211.40  
June 2025 $ 404   1.1   August 2025 0.2   1.3   $ 311.84  

Capped Call Options. During 2025, we entered into two structured share repurchase agreements. Under these agreements, we made up-front cash payments in exchange for the right to receive a predetermined amount of shares of our common stock or cash at expiration. Neither option was exercised during 2025, therefore we did not receive any shares at expiration. As a result, we received our initial up-front cash payments of $ 150 million plus a nominal cash premium. The cash received restored the remaining authority available for repurchases.
Changes in Accumulated Other Comprehensive Income (Loss) (All Registrants)
The following tables present changes in AOCI, net of tax, by component:

Gains (losses) on Cash Flow Hedges
Pension and OPEB Items (a)
Foreign Currency Items Total
Balance at December 31, 2022 $ ( 9 ) $ ( 1,725 ) $ ( 26 ) $ ( 1,760 )
OCI before reclassifications ( 2 ) ( 453 ) 2   ( 453 )
Amounts reclassified from AOCI 1   21   —   22  
Net current-period OCI ( 1 ) ( 432 ) 2   ( 431 )
Balance at December 31, 2023 $ ( 10 ) $ ( 2,157 ) $ ( 24 ) $ ( 2,191 )
OCI before reclassifications —   ( 176 ) ( 10 ) ( 186 )
Amounts reclassified from AOCI 4   71   —   75  
Net current-period OCI 4   ( 105 ) ( 10 ) ( 111 )
Balance at December 31, 2024 $ ( 6 ) $ ( 2,262 ) $ ( 34 ) $ ( 2,302 )
OCI before reclassifications —   ( 219 ) 21   ( 198 )
Amounts reclassified from AOCI 7   68   —   75  
Net current-period OCI 7   ( 151 ) 21   ( 123 )
Balance at December 31, 2025 $ 1   $ ( 2,413 ) $ ( 13 ) $ ( 2,425 )
__________
(a) AOCI amounts are included in the computation of net periodic pension and OPEB cost. See Note 14 — Retirement Benefits for additional information. See our Consolidated Statements of Operations and Comprehensive Income for individual components of AOCI.
The following table presents income tax (expense) benefit allocated to each component of our other comprehensive income (loss):

Year Ended December 31,
2025 2024 2023
Pension and OPEB plans:

Actuarial loss reclassified to periodic benefit cost $ ( 24 ) $ ( 24 ) $ ( 10 )
Pension and OPEB plans valuation adjustment
74   59   151  

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Note 20 — Stock-Based Compensation Plans

20. Stock-Based Compensation Plans
Our LTIP grants cash and stock-based awards that primarily include performance share awards and restricted stock units. Our LTIP authorized 20,000,000 shares of common stock for these awards.
The following table presents the stock-based compensation expense included in the Consolidated Statements of Operations and Comprehensive Income:

For the Years Ended December 31,

2025 2024 2023
Total stock-based compensation expense included in Operating and maintenance expense
$ 385   $ 332   $ 178  
Income tax benefit ( 99 ) ( 85 ) ( 45 )
Total after-tax stock-based compensation expense $ 286   $ 247   $ 133  

We receive a tax deduction based on the intrinsic value of the award on the distribution date for performance share awards and restricted stock units. The tax deduction related to performance share awards and restricted stock units was not material for the years ended December 31, 2025, 2024, and 2023. For each award, throughout the requisite service period, we recognize the tax benefit related to compensation costs. For performance share awards and restricted stock units, our realized tax benefit when distributed was not material for the years ended December 31, 2025, 2024, and 2023.
Performance Share Awards
Performance share awards are granted under the LTIP. The performance share awards are typically settled 50 % in common stock and 50 % in cash at the end of the three-year performance period, subject to certain ownership thresholds that, if met, may result in cash settlement of the entire award.
The common stock portion of the performance share awards is considered an equity award and is valued based on our stock price on the grant date. The cash portion of the performance share awards is considered a liability award which is remeasured each reporting period based on the current stock price. As the value of the common stock and cash portions of the awards are based on the stock price during the performance period, coupled with changes in the total expected payout of the award, the compensation costs are subject to volatility until payment is made.
For nonretirement-eligible employees, performance share awards are recognized over the vesting period of three years using the straight-line method. For performance share awards granted to retirement-eligible employees, the value of the performance shares is recognized ratably over the vesting period, which is the year of grant. We process forfeitures as they occur for employees who do not complete the requisite service period.
The following table summarizes our unvested performance share awards activity:

Shares Weighted Average Grant Date Fair Value (per share)
Unvested at December 31, 2024
535,626   $ 99.06  
Granted 120,057   321.83  
Change in performance 96,623   313.60  

Forfeited ( 3,812 ) 195.73  
Undistributed vested awards (a)
( 469,066 ) 332.97  
Unvested at December 31, 2025
279,428   $ 198.49  
__________
(a) Represents performance share awards that vested but were not distributed to retirement-eligible employees during 2025 and 2024.

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The following table summarizes the weighted average grant date fair value and the total fair value of performance share awards vested:

December 31, 2025 (a)
December 31, 2024 (a)

Weighted average grant date fair value (per share) $ 321.83   $ 127.03  
Total fair value of performance shares vested 156   138  

__________
(a) As of December 31, 2025 and 2024, total unrecognized compensation costs related to unvested performance shares of $ 41  million and $ 50  million, respectively, are expected to be recognized over the remaining weighted average period of 1.5 years.
Restricted Stock Units
Restricted stock units are granted under the LTIP with the majority being settled in a specific number of shares of common stock after the service condition has been met. The corresponding cost is measured based on the grant date fair value of the restricted stock unit issued.
The value of the restricted stock units is expensed over the requisite service period using the straight-line method. The requisite service period for restricted stock units is generally three to five years . However, certain restricted stock unit awards become fully vested upon the employee reaching retirement eligibility. The value of the restricted stock units granted to retirement-eligible employees is recognized ratably over the vesting period, which is the year of grant. We process forfeitures as they occur for employees who do not complete the requisite service period.
The following table summarizes our unvested restricted stock unit activity:

Shares Weighted Average Grant Date Fair Value (per share)
Unvested at December 31, 2024
809,093   $ 96.53  
Granted 265,512   312.97  
Vested ( 437,388 ) 82.45  
Forfeited ( 11,067 ) 197.23  
Undistributed vested awards (a)
( 76,272 ) 271.03  
Unvested at December 31, 2025
549,878   $ 181.54  

__________
(a) Represents restricted stock units that vested but were not distributed to retirement-eligible employees during 2025 and 2024.
The following table summarizes the weighted average grant date fair value and the total fair value of restricted stock units vested:

December 31, 2025 (a)
December 31, 2024 (a)

Weighted average grant date fair value (per share) $ 312.97   $ 134.18  
Total fair value of restricted stock units vested
57   42  

__________
(a) As of December 31, 2025 and 2024, total unrecognized compensation costs related to unvested restricted stock units of $ 57  million and $ 41  million, respectively, are expected to be recognized over the remaining weighted average period of 1.9 years and 1.8 years, respectively.
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Note 21 — Variable Interest Entities

21. Variable Interest Entities
As of December 31, 2025 and 2024, we consolidated several VIEs or VIE groups for which we are the primary beneficiary (see Consolidated VIEs below) and had significant interests in several other VIEs for which we do not have the power to direct the entities’ activities and, accordingly, we were not the primary beneficiary (see Unconsolidated VIEs below). Consolidated and unconsolidated VIEs are aggregated to the extent that the entities have similar risk profiles.
Consolidated VIEs
The table below shows the carrying amounts and classification of the consolidated VIEs’ assets and liabilities included in the consolidated financial statements as of December 31, 2025 and 2024. The assets, except as noted in the footnotes to the table below, can only be used to settle obligations of the VIEs. The liabilities, except as noted in the footnotes to the table below, are such that creditors, or beneficiaries, do not have recourse to our general credit.

December 31, 2025 December 31, 2024
Cash and cash equivalents $ 52   $ 59  
Restricted cash and cash equivalents 48   50  
Accounts receivable, net
2,477   2,146  
Inventories, net 13   13
Other current assets 29   38  
Total current assets 2,619   2,306  
Property, plant and equipment, net 1,942   2,025  
Other deferred debits and other assets
123   142  
Total assets (a)
$ 4,684   $ 4,473  

Long-term debt due within one year $ 66   $ 64  
Accounts payable and accrued expenses
34   54  
Other current liabilities 3   —  
Total current liabilities 103   118  
Long-term debt 578   642  
Asset retirement obligations 231   206  
Other deferred credits and other liabilities
2   2  
Total deferred credits and other liabilities
233   208  
Total liabilities
$ 914   $ 968  

__________
(a) Our balances include unrestricted assets f or current UEC assets of $ 17  million and $ 22  million, disclosed within other current assets in the table above and noncurrent UEC assets of $ 116  million and $ 133  million, disclosed within other noncurrent assets in the table above as of December 31, 2025 and 2024, respectively.

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

Note 21 — Variable Interest Entities

As of December 31, 2025 and 2024, our consolidated VIEs included the following:

Consolidated VIE or VIE groups: Reason entity is a VIE: Reason we are the primary beneficiary:
CRP - A collection of wind and solar project entities. We have a 51 % equity ownership in CRP. See additional discussion below.
Similar structure to a limited partnership and the limited partners do not have kick-out rights with respect to the general partner.
We conduct the operational activities.
Bluestem Wind Energy Holdings, LLC - A Tax Equity structure which is consolidated by CRP. Similar structure to a limited partnership and the limited partners do not have kick-out rights with respect to the general partner.
We conduct the operational activities.
Antelope Valley - A solar generating facility, which is 100 % owned by us. Antelope Valley sells all of its output to PG&E through a PPA.
The PPA contract absorbs variability through a performance guarantee. We conduct all activities.
NER - A bankruptcy remote, special purpose entity which is 100 % owned by us, which purchases certain of our customer accounts receivable arising from the sale of retail electricity.

NER’s assets will be available first and foremost to satisfy the claims of the creditors of NER. Refer to Note 7 —Accounts Receivable for additional information on the sale of receivables.
Equity capitalization is insufficient to support its operations. We conduct all activities.

CRP - CRP is a collection of wind and solar project entities and some of these project entities are VIEs that are consolidated by CRP. While we or CRP own 100 % of the solar entities and 100 % of the majority of the wind entities, it has been determined that the wholly owned solar and wind entities are VIEs because the entities' customers absorb price variability from the entities through fixed price power and/or REC purchase agreements. Additionally, for the wind entities that have minority interests, it has been determined that these entities are VIEs because the governance rights of some investors are not proportional to their financial rights. We are the primary beneficiary of these solar and wind entities that qualify as VIEs because we control operations and direct all activities of the facilities. There is limited recourse to us related to certain solar and wind entities.
In 2017, our interests in CRP were contributed to and are pledged for the CR nonrecourse debt project financing structure. Refer to Note 16 — Debt and Credit Agreements for additional information.
Unconsolidated VIEs
Our variable interests in unconsolidated VIEs generally include energy purchase and sale contracts. The carrying amount of assets and liabilities in the Consolidated Balance Sheets that relate to our involvement with the VIEs are predominantly related to working capital accounts and generally represent the amounts owed by, or owed to us for the deliveries associated with the current billing cycles under the commercial agreements.
As of December 31, 2025 and 2024, we had unconsolidated variable interests in several VIEs for which we were not the primary beneficiary.
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Combined Notes to Consolidated Financial Statements
(Dollars in millions, unless otherwise noted)

Note 21 — Variable Interest Entities

The following table presents summary information about our unconsolidated VIE entities:

Commercial Agreement VIEs
December 31, 2025 December 31, 2024
Total assets (a)
$ 711   $ 617  
Total liabilities (a)
95   42  

Other ownership interests in VIE (a)
616   575  

__________
(a) These items represent amounts on the unconsolidated VIE balance sheets, not in the Consolidated Balance Sheets. These items are included to provide information regarding the relative size of the unconsolidated VIEs. We do not have any exposure to loss as we do not have a carrying amount in the equity investment VIEs as o f December 31, 2025 and 2024.
As of December 31, 2025 and 2024, the unconsolidated VIEs consist of:

Unconsolidated VIE groups: Reason entity is a VIE: Reason we are not the primary beneficiary:
Energy Purchase and Sale agreements - We have several energy purchase and sale agreements with generating facilities. PPA contracts that absorb variability through fixed pricing. We do not conduct the operational activities.

22. Supplemental Financial Information
Supplemental Consolidated Statements of Operations and Comprehensive Income Information
The following tables provide additional information about material items recorded in the Consolidated Statements of Operations and Comprehensive Income.

For the Years Ended December 31,
Taxes other than income taxes 2025 2024 2023
Property $ 289   $ 285   $ 253  
Gross receipts (a)
163   134 139
Payroll 161   152 142
Other
9   15 19
Total
$ 622   $ 586   $ 553  

__________
(a) Represent gross receipts taxes related to our retail operations. The offsetting collection of gross receipts taxes from customers is recorded in Operating revenues in the Consolidated Statements of Operations and Comprehensive Income.

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

Note 22 — Supplemental Financial Information

For the Years Ended December 31,
Other, net
2025 2024 2023
Decommissioning-related activities:
Net realized income on NDT funds (a)

Regulatory Agreement Units $ 672   $ 553   $ 657  
Non-Regulatory Agreement Units 322   266   335  
Net unrealized gains (losses) on NDT funds

Regulatory Agreement Units 764   184   397  
Non-Regulatory Agreement Units 506   156   259  
Regulatory offset to NDT fund-related activities (b)
( 1,152 ) ( 592 ) ( 845 )
Total Decommissioning-related activities
1,112   567   803  
Net unrealized gains (losses) from equity investments (c)
( 304 ) 11   307  

Other
128   92   158  
Total Other, net $ 936   $ 670   $ 1,268  

__________
(a) Realized income includes interest, dividends and realized gains and losses on sales of NDT fund investments.
(b) Includes the elimination of decommissioning-related activities and the elimination of income taxes related to all NDT fund activity for the Regulatory Agreement Units.
(c) Includes unrealized gains (losses) resulting from an equity investment in a publicly traded company. We record the fair value of this investment in Other deferred debits and other assets in the Consolidated Balance Sheets based on quoted market price of the stock.
Supplemental Cash Flow Information
The following tables provide additional information about material items recorded in the Consolidated Statements of Cash Flows.

For the Years Ended December 31,
Depreciation, amortization and accretion
Income statement location
2025 2024 2023
PP&E
Depreciation and amortization
$ 967   $ 1,101   $ 1,073  
Nuclear fuel
Purchased power and fuel
952   884 787
ARO accretion
Operating and maintenance 647   655 596
Amortization of intangible assets, net (a)
Depreciation and amortization 18   22 23
Amortization of UECs Operating revenues or Purchased power and fuel
17   38 35
Total depreciation, amortization, and accretion $ 2,601   $ 2,700   $ 2,514  

__________
(a) Primarily related to the amortization of customer relationships and trade names. Excludes UEC amortization, which is shown separately in the table.

For the Years Ended December 31,
Cash paid during the year 2025 2024 2023
Interest (net of amount capitalized) $ 412   $ 375   $ 264  

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

Note 22 — Supplemental Financial Information

CEG Parent Constellation
For the Years Ended December 31, For the Years Ended December 31,
Other non-cash operating activities 2025 2024 2023 2025 2024 2023
Other decommissioning-related activity (a)
$ ( 463 ) $ ( 485 ) $ ( 534 ) $ ( 463 ) $ ( 485 ) $ ( 534 )
Energy-related options (b)
( 103 ) 32   183   ( 103 ) 32   183  
Pension and non-pension postretirement benefit costs 152   107   47   152   107   47  

Other
191   174   322   110   128   260  
Total other non-cash operating activities
$ ( 223 ) $ ( 172 ) $ 18   $ ( 304 ) $ ( 218 ) $ ( 44 )
__________
(a) Includes the elimination of decommissioning-related activities for the Regulatory Agreement Units, including the elimination of operating revenues, ARO accretion, ARC amortization, investment income, and income taxes related to all NDT fund activity for these units.
(b) Includes option premiums reclassified to realized at the settlement of the underlying contracts and recorded to results of operations.
The following table provides a reconciliation of cash, restricted cash, and cash equivalents reported in the Consolidated Balance Sheets that sum to the total of the same amounts in the Consolidated Statements of Cash Flows.

December 31, 2025 CEG Parent Constellation
Cash and cash equivalents $ 3,641   $ 3,641  
Restricted cash and cash equivalents 107   79  

Total cash, restricted cash, and cash equivalents $ 3,748   $ 3,720  

December 31, 2024
Cash and cash equivalents $ 3,022   $ 3,018  
Restricted cash and cash equivalents 107   97  
Total cash, restricted cash, and cash equivalents $ 3,129   $ 3,115  

December 31, 2023
Cash and cash equivalents $ 368   $ 366  
Restricted cash and cash equivalents 86 74

Total cash, restricted cash, and cash equivalents $ 454   $ 440  

For additional information on restricted cash, see Note 1 — Basis of Presentation.
Supplemental Balance Sheet Information
The following tables provide additional information about material items recorded in the Consolidated Balance Sheets.

Inventories, net December 31, 2025 December 31, 2024
Materials and supplies $ 1,485   $ 1,357  
Natural gas, oil, and emission allowances 251   243  
Total $ 1,736   $ 1,600  

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

Note 22 — Supplemental Financial Information

Accounts payable and accrued expenses

December 31, 2025 CEG Parent Constellation
Accounts payable $ 2,813   $ 2,801  
Compensation-related accruals (a)
920   672  
Taxes accrued (b)
246   245  
Other accrued expenses
315   315  
Total
$ 4,294   $ 4,033  

December 31, 2024
Accounts payable
$ 2,369   $ 2,348  
Compensation-related accruals (a)
907   689  
Taxes accrued (b)
232   223  
Other accrued expenses
435   436  
Total
$ 3,943   $ 3,696  

__________
(a) Primarily includes accrued payroll, bonuses and other incentives, vacation, and benefits.
(b) Net of $ 375 million and $ 150 million as of December 31, 2025 and 2024, respectively, related to nuclear PTC that was used to offset the current tax liability. See Note 6 — Government Assistance for additional information on the nuclear PTC.
The following table provides additional information about investments included in Other deferred debits and other assets in the Consolidated Balance Sheets.

Investments December 31, 2025 December 31, 2024
Equity method investments
$ 3   $ 2  
Other investments:
Employee benefit trusts and investments (a)
112   100  
Equity investments with readily determinable fair values (b)
82   387
Equity investments without readily determinable fair values 109   150
Other available for sale debt security investments 1   1
Total
$ 307   $ 640  

__________
(a) Debt and equity security investments are recorded at fair market value.
(b) Does not include the equity investments with readily determinable fair values that are recorded in Other current assets in the Consolidated Balance Sheets. See Note 17 — Fair Value of Financial Assets and Liabilities for additional information on investments in equities.

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ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None.

ITEM 9A. CONTROLS AND PROCEDURES

Disclosure Controls and Procedures
During the fourth quarter of 2025, our principal executive officer and principal financial officer, evaluated the effectiveness of our disclosure controls and procedures related to the recording, processing, summarizing, and reporting of information in periodic reports that we file or submit with the SEC. These disclosure controls and procedures have been designed to ensure that (a) information relating to our consolidated subsidiaries, is accumulated and made known to our management, including our principal executive officer and principal financial officer, by other employees as appropriate to allow timely decisions regarding required disclosure, and (b) this information is recorded, processed, summarized, and reported, as applicable, within the time periods specified in the SEC’s rules and forms. Due to the inherent limitations of control systems, not all misstatements may be detected. These inherent limitations include the realities that judgments in decision-making can be faulty and that breakdowns can occur because of simple error or mistake. Additionally, controls could be circumvented by the individual acts of some persons or by collusion of two or more people.
Accordingly, as of December 31, 2025, our principal executive officer and principal financial officer concluded that our disclosure controls and procedures were effective to accomplish their objectives.
Changes in Internal Control Over Financial Reporting
We continually strive to improve our disclosure controls and procedures to enhance the quality of our financial reporting and to maintain dynamic systems that change as conditions warrant. There have been no changes in internal control over financial reporting that occurred during the fourth quarter of 2025 that have materially affected, or are reasonably likely to materially affect, any of our internal control over financial reporting.
Internal Control Over Financial Reporting
Management is required to assess and report on the effectiveness of its internal control over financial reporting as of December 31, 2025. As a result of that assessment, management determined that there were no material weaknesses as of December 31, 2025 and, therefore, concluded that our internal control over financial reporting was effective. Management’s Report on Internal Control Over Financial Reporting is included in ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.

ITEM 9B. OTHER INFORMATION
Rule 10b5-1 Trading Plans
During the three months ended December 31, 2025, none of our directors or executive officers (as defined in Rule 16a-1 under the Exchange Act) adopted or terminated any contract, instruction or written plan for the purchase or sale of our securities that was intended to satisfy the affirmative defense conditions of Rule 10b5-1(c) or any “non-Rule 10b5-1 trading arrangement” (as defined in Item 408 under Regulation S-K of the Exchange Act).

ITEM 9C. DISCLOSURE REGARDING FOREIGN JURISDICTIONS THAT PREVENT INSPECTIONS
Not Applicable.

PART III  
Constellation Energy Generation, LLC meets the conditions set forth in General Instruction I(1)(a) and (b) of Form 10-K for a reduced disclosure format. Accordingly, all items in this section relating to Constellation are not presented.
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ITEM 10. DIRECTORS, EXECUTIVE OFFICERS, AND CORPORATE GOVERNANCE
Information about our Executive Officers as of February 24, 2026

Name Age Position Period
Dominguez, Joseph 63 President and Chief Executive Officer 2022 – Present
President and Chief Executive Officer, Exelon Generation Company, LLC 2021 – 2022
Chief Executive Officer, ComEd 2018 – 2021

Smith, Shane 46 Executive Vice President and Chief Financial Officer 2026 – Present
Senior Vice President, Treasury and Credit and Treasurer 2022 – 2026
Vice President, Constellation Finance, Exelon 2020 – 2022

Eggers, Daniel 50 Senior Executive Vice President, Finance and Data Economy 2026 – Present
Executive Vice President and Chief Financial Officer 2022 – 2026
Executive Vice President and Chief Financial Officer, Exelon Generation Company, LLC 2021 – 2022
Senior Vice President of Corporate Finance, Exelon 2018 – 2021

Novotny, Andrew 49 Senior Executive Vice President, Constellation Power Operations and President and CEO, Calpine 2026 – Present
President and CEO, Calpine 2024 – 2026
President and Chief Operating Officer, Calpine 2023 – 2024
Chief Operating Officer, Calpine 2021 – 2023
Executive Vice President, Commercial Operations, Calpine 2018 – 2021

Dardis, David 53 Senior Executive Vice President and Chief External Affairs and Growth Officer 2026 – Present
Executive Vice President and Chief Legal and Policy Officer 2022 – 2026
Executive Vice President and General Counsel 2022 – 2024
Executive Vice President and General Counsel, Exelon Generation Company, LLC 2021 – 2022
Senior Vice President and General Counsel, Exelon Generation Company, LLC 2020 – 2021

Hanson, Bryan C. 60 Senior Executive Vice President and Chief Generation Officer 2026 – Present
Executive Vice President and Chief Generation Officer 2022 – 2026
Executive Vice President and Chief Generation Officer, Exelon Generation Company, LLC 2020 – 2022

McHugh, James 54 Senior Executive Vice President and Chief Commercial Officer 2026 – Present
Executive Vice President and Chief Commercial Officer 2022 – 2026
Executive Vice President and Chief Commercial Officer, Exelon Generation Company, LLC 2021 – 2022
Executive Vice President, Exelon; Chief Executive Officer, competitive retail and commodities business, Exelon 2018 – 2021

Koehler, Michael R. 59 Executive Vice President and Chief Administration Officer 2022 – Present
Executive Vice President and Chief Administration Officer, Exelon Generation Company, LLC 2021 – 2022
Senior Vice President and Chief Information and Chief Digital Officer, Exelon 2016 – 2021

Bauer, Matthew 49 Senior Vice President and Controller 2022 – Present
Vice President and Controller, Exelon Generation Company, LLC 2016 – 2022

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Directors, Director Nomination Process and Audit Committee
The information required under ITEM 10 concerning directors and nominees for election as directors at the annual meeting of shareholders (Item 401 of Regulation S-K), the director nomination process (Item 407(c)(3)), the audit committee (Item 407(d)(4) and (d)(5)), and the beneficial reporting compliance (Sec. 16(a)) is incorporated herein by reference to information to be contained in our definitive 2026 proxy statement (2026 Constellation Proxy Statement) to be filed with the SEC on or before April 30, 2026 pursuant to Regulation 14A or 14C, as applicable, under the Securities Exchange Act of 1934.
Code of Conduct and Ethics
In connection with the completion of the separation from Exelon, our Board of Directors adopted a code of conduct and ethics (Code of Ethics), effective February 1, 2022, that applies to all of our directors, officers and employees, including our principal executive officer, principal financial officer, principal accounting officer and persons performing similar functions. The Code of Ethics was updated in July 2024, as approved by the Board of Directors, and in February 2026 and is available upon written request to our corporate secretary or on our website at www.ConstellationEnergy.com. If we amend provisions of our Code of Ethics that apply to, or grant a waiver from a provision of our Code of Ethics for, an executive officer, we will publicly disclose such amendment or waiver on our website and as required by applicable law or listing rules. The information contained on, or accessible from, our website is not part of this annual report by reference or otherwise.
Insider Trading Policy
The Company has adopted an insider trading policy that governs the purchase, sale, and/or other transactions of our securities by our directors, officers and employees. A copy of our insider trading policy is filed as Exhibit 19-1 to this Annual Report on Form 10-K. In addition, with regard to the Company’s trading in its own securities, it is the Company’s policy to comply with the federal securities laws and the applicable exchange listing requirements.

ITEM 11. EXECUTIVE COMPENSATION
The information required by this item will be set forth under “Executive Compensation Data” and “Report of the Compensation Committee” in the Constellation Proxy Statement for the 2026 Annual Meeting of Shareholders which is incorporated herein by reference.
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ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

The information required by this item will be set forth under “Ownership of Constellation Stock” in the Constellation Proxy Statement for the 2026 Annual Meeting of Shareholders which is incorporated herein by reference.
Securities Authorized for Issuance under Constellation Equity Compensation Plans

[A] [B] [C]
Number of securities to be issued upon exercise of outstanding Options, warrants and rights (Note 1) Weighted-average price of outstanding Options, warrants and rights Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column [A]) (Note 2)
Equity compensation plans approved by security holders 1,743,951 N/A 33,200,578

__________
(1) Balance includes outstanding performance shares and restricted stock units that were granted under the Constellation LTIP (including shares awarded under those plans and deferred into the stock deferral plan) and deferred stock units granted to directors as part of their compensation. Unvested performance shares are subject to performance metrics and to a credit rating modifier. In addition, pursuant to the terms of the Constellation LTIP plan, 50% of final payouts are made in the form of shares of common stock and 50% is made in form of in cash, or if the participant has exceeded 200% of their stock ownership requirement, 100% of the final payout is made in cash. For performance shares, the total includes the maximum number of shares that could be issued assuming all participants receive 50% of payouts in shares and assuming the performance and credit rating modifier metrics were both at maximum, representing best case performance, for a total of 742,646 shares. If the performance and total shareholder return modifier metrics were at “target”, the number of securities to be issued for such awards would be 371,323. The balance also includes 203,456 shares to be issued upon the conversion of deferred stock units awarded to members of the Constellation Board of Directors. Conversion of the deferred stock units to shares of common stock occurs after a director terminates service on the Constellation board.
(2) Includes 16,615,296 shares remaining available for issuance from the employee stock purchase plan and 16,585,282 shares remaining available for issuance to former Constellation employees with outstanding awards made under the Constellation LTIP.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR INDEPENDENCE
The additional information required by this item will be set forth under “Related Persons Transactions” and “Director Independence” in the Constellation Proxy Statement for the 2026 Annual Meeting of Shareholders which is incorporated herein by reference.

ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES
The information required by this item will be set forth under “The Ratification of PricewaterhouseCoopers LLP as Constellation's Independent Registered Public Accounting Firm for 2026” in the Constellation Proxy Statement for the 2026 Annual Meeting of Shareholders which is incorporated herein by reference.
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PART IV

ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES

(a) The following documents are filed as a part of this report:

(1) Constellation Energy Corporation and Subsidiary Companies

(i) Financial Statements (Item 8):

Report of Independent Registered Public Accounting Firm dated February 24, 2026 of PricewaterhouseCoopers LLP (PCAOB ID 238)

Consolidated Statements of Operations and Comprehensive Income for the Years Ended December 31, 2025, 2024, and 2023

Consolidated Statements of Cash Flows for the Years Ended December 31, 2025, 2024, and 2023

Consolidated Balance Sheets at December 31, 2025 and 2024

Consolidated Statements of Changes in Equity for the Years Ended December 31, 2025, 2024, and 2023

Combined Notes to Consolidated Financial Statements

(ii) Financial Statement Schedule:

Schedule II—Valuation and Qualifying Accounts for the Years Ended December 31, 2025, 2024, and 2023

Schedules not included are omitted because of the absence of conditions under which they are required or because the required information is provided in the consolidated financial statements, including the notes thereto

Constellation Energy Corporation and Subsidiary Companies
Constellation Energy Generation, LLC and Subsidiary Companies
Schedule II – Valuation and Qualifying Accounts

Additions and adjustments
Description Balance at Beginning of Period
Charged to Costs and Expenses
Charged to Other Accounts
Deductions Balance at End of Period

(In millions)
For the year ended December 31, 2025
Allowance for credit losses $ 196   $ 49   $ 1   $ ( 79 ) (a)
$ 167  
Deferred tax valuation allowance 3   —   —     —   3  
Reserve for obsolete materials 238   —   ( 1 ) ( 22 ) 215  
For the year ended December 31, 2024
Allowance for credit losses $ 61   $ 18   $ 138   $ ( 21 ) (a)
$ 196  
Deferred tax valuation allowance 10   ( 7 ) —   —   3  
Reserve for obsolete materials 246   ( 4 ) ( 4 ) —   238  
For the year ended December 31, 2023
Allowance for credit losses $ 51   $ 25   $ —   $ ( 15 ) (a)
$ 61  
Deferred tax valuation allowance 11   —   ( 1 ) —   10  
Reserve for obsolete materials 238   8   9   ( 9 ) 246  

__________
(a) Write-offs, net of recoveries of individual accounts receivable.
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(2) Constellation Energy Generation, LLC and Subsidiary Companies

(i) Financial Statements (Item 8):

Report of Independent Registered Public Accounting Firm dated February 24, 2026 of PricewaterhouseCoopers LLP (PCAOB ID 238 )

Consolidated Statements of Operations and Comprehensive Income for the Years Ended December 31, 2025, 2024, and 2023

Consolidated Statements of Cash Flows for the Years Ended December 31, 2025, 2024, and 2023

Consolidated Balance Sheets at December 31, 2025 and 2024

Consolidated Statements of Changes in Equity for the Years Ended December 31, 2025, 2024, and 2023

Combined Notes to Consolidated Financial Statements

(ii) Financial Statement Schedule:

Schedule II—Valuation and Qualifying Accounts for the Years Ended December 31, 2025, 2024, and 2023 (a)

Schedules not included are omitted because of the absence of conditions under which they are required or because the required information is provided in the consolidated financial statements, including the notes thereto

__________
(a) The Constellation Energy Generation, LLC Schedule II - Valuation and Qualifying Accounts for Years ended December 31, 2025, 2024, and 2023 is the same as the Constellation Energy Corporation Schedule II.
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Exhibits required by Item 601 of Regulation S-K:
Certain of the following exhibits are incorporated herein by reference under Rule 12b-32 of the Exchange Act.

Exhibit No. Description
(2) Plans of acquisition, reorganization, arrangement, liquidation, or succession

2.1
Separation Agreement, dated January 31, 2022, between Exelon and Constellation (File No. 001-41137, Form 8-K dated February 2, 2022, Exhibit 2.1)

2.2
Agreement and Plan of Merger, dated as of January 10, 2025, by and among Calpine Corporation, CPN CS Holdco Corp., CPN CKS Corp., Constellation Energy Corporation, Cascade Transco Inc., Cascade Transco – 1, LLC and Volt Energy Holdings GP, LLC, solely in its capacity as the representative of the stockholders of Calpine Corporation (File No. 001-41137, Form 8-K dated January 13, 2025, Exhibit 2.1)

(3) Articles of Incorporation and Bylaws

3.1
Amended and Restated Articles of Incorporation of Constellation Energy Corporation, effective January 31, 2022 (File No. 001-41137, Form 8-K dated February 2, 2022, Exhibit 3.1)

3.2
Second Amended and Restated Bylaws of Constellation Energy Corporation, effective July 26, 2022 (File No. 001-41137, Form 8-K dated July 29, 2022, Exhibit 3.1)

3.3
Amended and Restated Certificate of Organization, as amended, of Constellation (File No. 001-41137, Form 10-K dated February 25, 2022, Exhibit 3.3)

3.4
Amended and Restated Operating Agreement of Constellation (File No. 001-41137, Form 10-K dated February 25, 2022, Exhibit 3.4)

(4) Instruments Defining the Rights of Securities Holders, Including Indentures

4.1
Form of 5.60% Senior Note due 2042 issued by Constellation (File No. 333-85496, Form 8-K dated June 18, 2012, Exhibit 4.2)

4.2
Form of 6.000% Senior Notes due 2033 issued by Constellation (File No. 333-85496, Form 8-K dated September 30, 2013, Exhibit No. 4.1)

4.3
Indenture dated as of September 28, 2007 from Constellation to U.S. Bank National Association, as trustee (File No. 333-85496, Form 8-K dated September 28, 2007, Exhibit 4.1)

4.4
Form of 6.25% Constellation Senior Note due 2039 (File No. 333-85496, Form 8-K dated September 23, 2009, Exhibit 4.2)

4.5
Form of 5.75% Constellation Senior Note due 2041 (File No. 333-85496, Form 8-K dated September 30, 2010, Exhibit 4.2)

4.6
Indenture, dated as of September 30, 2013, among Continental Wind, LLC, the guarantors party thereto and Wilmington Trust, National Association, as trustee (File No. 333-85496, Form 8-K dated September 30, 2013, Exhibit 4.1)

4.7
Form of Constellation 3.250% Senior Notes due 2025 (File No. 333-85496, Form 8-K dated May 15, 2020, Exhibit 4.1)

4.8
Indenture, dated as of February 9, 2022, between Constellation and Deutsche Bank Trust Company Americas, as trustee (File No. 001-41137, Form 10-K dated February 25, 2022, Exhibit 4.11)

4.9
First Supplemental Indenture, dated as of February 9, 2022, between Constellation and Deutsche Bank Trust Company Americas, as trustee (File No. 001-41137, Form 10-K dated February 25, 2022, Exhibit 4.12)

4.10
Form of Constellation 3.046% Senior Notes due 2027 (incorporated by reference to Exhibit 4.9 filed herein)

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4.11
Facility Agreement, dated as of February 9, 2022, among Constellation, Fells Point Funding Trust and Deutsche Bank Trust Company Americas, as trustee (File No. 001-41137, Form 10-K dated February 25, 2022, Exhibit 4.14)

4.12
Letter of Credit Facility Agreement, dated February 9, 2022, among Constellation, Deutsche Bank Trust Company Americas, as administrative and collateral agent, and the various financial institutions from time to time parties thereto (File No. 001-41137, Form 10-K dated February 25, 2022, Exhibit 4.15)

4.13
Amended and Restated Declaration of Trust of Fells Point Funding Trust, dated as of February 9, 2022 (File No. 001-41137, Form 10-K dated February 25, 2022, Exhibit 4.16)

4.14
Pledge and Control Agreement, dated as of February 9, 2022, among Fells Point Funding Trust, Constellation, Deutsche Bank Company Americas, as collateral agent and securities intermediary (File No. 001-41137, Form 10-K dated February 25, 2022, Exhibit 4.17)

4.15
Form of Constellation Energy Generation, LLC 5.600% Senior Notes due 2028 (File No. 333-85496, Form 8-K dated February 24, 2023, Exhibit 4.1)

4.16
Form of Constellation Energy Generation, LLC 5.800% Senior Notes due 2033 (File No. 333-85496, Form 8-K dated February 24, 2023, Exhibit 4.2)

4.17
Form of Constellation Energy Generation, LLC 6.125% Senior Notes due January 15, 2034 (File No. 333-85496, Form 8-K dated September 29, 2023, Exhibit 4.1)

4.18
Form of Constellation Energy Generation, LLC 6.500% Senior Notes due October 1, 2053 (File No. 333-85496, Form 8-K dated September 29, 2023, Exhibit 4.2)

4.19
Form of Constellation Energy Generation, LLC 5.750% Green Senior Note due March 15, 2054 (File No. 001-41137, Form 8-K dated March 15, 2024, Exhibit 4.1)

4.20
Indenture, dated December 27, 2019, between Calpine Corporation and Wilmington Trust, National Association, as trustee (including Form of 5.125% Senior Note due 2028) (File No. 001-41137, Form 8-K dated January 7, 2026, Exhibit 4.1)

4.21
Indenture, dated August 10, 2020, between Calpine Corporation and Wilmington Trust, National Association, as trustee (including Form of 4.625% Senior Note due 2029) (File No. 001-41137, Form 8-K dated January 7, 2026, Exhibit 4.2)

4.22
Indenture, dated August 10, 2020, between Calpine Corporation and Wilmington Trust, National Association, as trustee (including Form of 5.000% Senior Note due 2031) (File No. 001-41137, Form 8-K dated January 7, 2026, Exhibit 4.3)

4.23
Indenture, dated December 20, 2019, among Calpine Corporation, the guarantors party thereto from time to time and Wilmington Trust, National Association, as trustee (including Form of 4.500% Senior Secured Notes due 2028) (File No. 001-41137, Form 8-K dated January 7, 2026, Exhibit 4.4)

4.24
First Supplemental Indenture, dated August 20, 2025, among Calpine Corporation, the guarantors party thereto and Wilmington Trust, National Association, as trustee (File No. 001-41137, Form 8-K dated January 7, 2026, Exhibit 4.5)

4.25
Indenture, dated December 16, 2020, among Calpine Corporation, the guarantors party thereto from time to time and Wilmington Trust, National Association, as trustee (including Form of 3.750% Senior Secured Notes due 2031) (File No. 001-41137, Form 8-K dated January 7, 2026, Exhibit 4.6)

4.26
First Supplemental Indenture, dated August 20, 2025, among Calpine Corporation, the guarantors party thereto and Wilmington Trust, National Association, as trustee (File No. 001-41137, Form 8-K dated January 7, 2026, Exhibit 4.7)

4.27
Form of Constellation Energy Generation, LLC Floating Rate Senior Notes due January 8, 2028 (File No. 333-85496, Form 8-K dated January 8, 2026, Exhibit 4.1)

4.28
Form of Constellation Energy Generation, LLC 3.900% Senior Notes due January 8, 2028 (File No. 333-85496, Form 8-K dated January 8, 2026, Exhibit 4.2)

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4.29
Form of Constellation Energy Generation, LLC 4.400% Senior Notes due January 15, 2031 (File No. 333-85496, Form 8-K dated January 8, 2026, Exhibit 4.3)

4.30
Form of Constellation Energy Generation, LLC 5.875% Senior Notes due January 15, 2066 (File No. 333-85496, Form 8-K dated January 8, 2026, Exhibit 4.4)

4. 31
First Supplemental Indenture, dated as of January 15, 2026, among Calpine Corporation and Wilmington Trust, National Association, as trustee (File No. 001-41137, Form 8-K dated January 15 , 2026, Exhibit 4. 1 )

4.3 2
First Supplemental Indenture, dated as of January 15, 2026, among Calpine Corporation and Wilmington Trust, National Association, as trustee (File No. 001-41137, Form 8-K dated January 15 , 2026, Exhibit 4. 2 )

4.3 3
Second Supplemental Indenture, dated as of January 15, 2026, among Calpine Corporation, the guarantors party thereto and Wilmington Trust, National Association, as trustee (File No. 001-41137, Form 8-K dated January 15 , 2026, Exhibit 4. 3 )

4.3 4
Form of New 2029 Senior Note (File No. 001-41137, Form 8-K dated January 15 , 2026, Exhibit 4. 4 )

4.3 5
Form of New February 2031 Senior Note (File No. 001-41137, Form 8-K dated January 15 , 2026, Exhibit 4. 5 )

4.3 6
Form of New March 2031 Senior Note (File No. 001-41137, Form 8-K dated January 15 , 2026, Exhibit 4. 6 )

(10) Material Contracts

10.1
Transition Services Agreement, dated January 31, 2022, between Exelon and Constellation (File No. 001-41137, Form 8-K dated February 2, 2022, Exhibit 10.1)

10.2
Tax Matters Agreement, dated January 31, 2022, between Exelon and Constellation (File No. 001-41137, Form 8-K dated February 2, 2022, Exhibit 10.2)

10.3*
Employee Matters Agreement, dated January 31, 2022, between Exelon and Constellation (File No. 001-41137, Form 8-K dated February 2, 2022, Exhibit 10.3)

10.4
Credit Agreement, dated as of November 28, 2017, as thereafter amended and conformed among Constellation Renewables, LLC, Constellation Renewables Holding, LLC, Morgan Stanley Senior Funding, Inc. as administrative agent, Wilmington Trust, National Association, as depository bank and collateral agent, and the lenders and other agents party thereto. (Certain portions of this exhibit have been omitted by redacting a portion of text, as indicated by asterisks in the text. This exhibit has been filed separately with the U.S. Securities and Exchange Commission pursuant to a request for confidential treatment.) (File No. 001-16169, Form 10-K dated February 9, 2018, Exhibit 10.94)

10.5
Receivables Purchase Agreement, dated as of April 8, 2020, among Constellation NewEnergy, Inc. as servicer, and NewEnergy Receivables LLC, as seller, MUFG Bank, LTD., as Agent, the Conduits party thereto, the Financial Institutions party thereto and the Purchaser Agents party thereto (File No. 001-16169, Form 8-K dated April 9, 2020, Exhibit 10.1)

10.6
Credit Agreement, among Constellation Renewables, LLC, the lenders party thereto, Jefferies Finance LLC, as administrative agent, and Wilmington Trust, National Association, as depositary bank and collateral agent, dated December 15, 2020 (File No. 333-85496, Form 8-K dated December 15, 2020, Exhibit 1.1)

10.7
Amendment No. 2 to Receivables Purchase Agreement, dated as of March 29, 2021, among Constellation NewEnergy, Inc., as servicer, and NewEnergy Receivables LLC, as seller, MUFG Bank, LTD., as agent, the Conduits party thereto, the Financial Institutions party thereto and the Purchaser Agents party thereto (File No. 001-16169, Form 8-K, dated March 31, 2021, Exhibit 10.1)

10.8
Settlement Agreement, dated August 6, 2021, between Constellation and EDF Inc. (File No. 333-85496, Form 10-Q dated November 3, 2021, Exhibit 10.1)

10.9
364-Day Term Loan Credit Agreement, dated August 6, 2021, between Generation and Barclays Bank PLC (File No. 333-85496, Form 10-Q dated November 3, 2021, Exhibit 10.2)

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10.10
$3,500,000,000 Credit Agreement dated as of February 1, 2022, among Constellation Energy Generation, JPMorgan Chase Bank, N.A., as Administrative Agent, and various financial institutions, as lenders (File No. 001-41137, Form 10-K dated February 25, 2022, Exhibit 10.10)

10.11
Constellation Energy Corporation Non-Employee Deferred Stock Unit Plan (File No. 001-41137, Form 10-K dated February 25, 2022, Exhibit 10.11)

10.12
Constellation Energy Corporation Unfunded Deferred Compensation Plan for Directors (File No. 001-41137, Form 10-K dated February 25, 2022, Exhibit 10.12)

10.13
Constellation Energy Group Deferred Compensation Plan for Non-Employee Directors (File No. 001-41137, Form 10-K dated February 25, 2022, Exhibit 10.13)

10.14*
Constellation Energy Corporation Senior Management Severance Plan (File No. 001-41137, Form 10-K dated February 25, 2022, Exhibit 10.14)

10.15*
Constellation Energy Corporation Deferred Compensation Plan (File No. 001-41137, Form 10-K dated February 25, 2022, Exhibit 10.15)

10.16*
Constellation Energy Corporation Supplemental Management Retirement Plan (File No. 001-41137, Form 10-K dated February 25, 2022, Exhibit 10.16)

10.17
Constellation Energy Corporation PECO Supplemental Pension Benefit Plan (File No. 001-41137, Form 10-K dated February 25, 2022, Exhibit 10.17)

10.18*
Constellation Energy Group Nonqualified Deferred Compensation Plan (File No. 001-41137, Form 10-K dated February 25, 2022, Exhibit 10.18)

10.19
Constellation Energy Group Benefits Restoration Plan (File No. 001-41137, Form 10-K dated February 25, 2022, Exhibit 10.19)

10.20
Constellation Energy Corporation Supplemental Pension Plan (File No. 001-41137, Form 10-K dated February 25, 2022, Exhibit 10.20)

10.21*
Constellation Energy Corporation Long-Term Incentive Plan (File No. 001-41137, Form 10-K dated February 25, 2022, Exhibit 10.21)

10.22
Constellation Energy Corporation Employee Stock Purchase Plan (File No. 001-41137, Form 10-K dated February 25, 2022, Exhibit 10.22)

10.23*
Form of Restricted Stock Unit Retention Award under the Constellation Energy Corporation Long-Term Incentive Plan (File No. 001-41137, Form 10-K dated February 25, 2022, Exhibit 10.23)

10.24*
Form of Restricted Stock Unit Award under the Constellation Energy Corporation Long-Term Incentive Plan (File No. 001-41137, Form 10-K dated February 25, 2022, Exhibit 10.24)

10.25*
Form of Performance Share Award under the Constellation Energy Corporation Long-Term Incentive Plan (File No. 001-41137, Form 10-K dated February 25, 2022, Exhibit 10.25)

10.26*
Form of Separation Agreement under the Constellation Energy Corporation Senior Management Severance Plan (File No. 001-41137, Form 10-K dated February 25, 2022, Exhibit 10.26)

10.27
Amendment No. 3 to Receivables Purchase Agreement, dated as of August 16, 2022, among Constellation NewEnergy, Inc., as servicer, and NewEnergy Receivables LLC, as seller, MUFG Bank, LTD., as agent, the Conduits party thereto, the Financial Institutions party thereto and the Purchaser Agents party thereto (File No. 001-41137, Form 8-K, dated August 18, 2022, Exhibit 10.1)

10.28
Amended and Restated Credit Agreement dated as of June 14, 2024, among Constellation Energy Generation, JPMorgan Chase Bank, N.A., as Administrative Agent, and the various financial institutions signatory thereto (File No. 001-41137, Form 8-K dated June 14, 2024, Exhibit 1.1)

10.29
Receivables Financing Agreement, dated as of December 31, 2024, by and among NewEnergy Receivables, LLC, the various financial institutions party thereto, MUFG Bank, Ltd., as Agent, and Constellation NewEnergy, Inc (File No. 001-41137, Form 10-K, dated February 18, 2025, Exhibit 10.29)

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10. 30
Loan Guarantee Agreement, dated as of November 17, 2025, by and between Constellation Energy Generation, LLC and the U.S. Department of Energy, in its capacity as guarantor and as loan servicer (File No. 001-41137, Form 8-K dated November 18, 2025, Exhibit 10.1)

10. 31
FFB Note Purchase Agreement, dated as of November 17, 2025, by and among Constellation Energy Generation, LLC, the U.S. Department of Energy and the Federal Financing Bank (File No. 001-41137, Form 8-K dated November 18, 2025, Exhibit 10.2)

10. 32
Future Advance Promissory Note dated as of November 17, 2025, issued by Constellation Energy Generation, LLC in favor of the Federal Financing Bank (File No. 001-41137, Form 8-K dated November 18, 2025, Exhibit 10.3)

10. 33
Registration Rights Agreement, dated January 7, 2026, by and among Constellation Energy Corporation and the parties thereto from time to time (File No. 001-41137, Form 8-K, dated January 7, 2026, Exhibit 10.1)

10. 34
Credit Agreement, dated December 15, 2017, among Calpine Construction Finance Company, L.P., as borrower, the lenders party thereto from time to time, and Credit Suisse AG, Cayman Islands Branch, as administrative agent and collateral agent (File No. 001-41137, Form 8-K, dated January 7, 2026, Exhibit 10.2 )

10. 35
Amendment No. 3 to Credit Agreement, dated August 2, 2023, among Calpine Construction Finance Company, L.P., as borrower, the lenders party thereto, and Credit Suisse AG, Cayman Islands Branch, as administrative agent and collateral agent (File No. 001-41137, Form 8-K, dated January 7, 2026, Exhibit 10.3)

10. 36
Amendment No. 4 to Credit Agreement, dated June 6, 2024, among Calpine Construction Finance Company, L.P., as borrower, the lenders party thereto, and Citibank, N.A., as administrative agent and collateral agent (File No. 001-41137, Form 8-K, dated January 7, 2026, Exhibit 10.4)

10. 37
2024 Incremental Term Loan Commitment Supplement, dated September 16, 2024, among Calpine Construction Finance Company, L.P., as borrower, the lenders party thereto, and Citibank, N.A., as administrative agent and collateral agent (File No. 001-41137, Form 8-K, dated January 7, 2026, Exhibit 10.5)

10. 38
Amendment No. 5 to Credit Agreement, dated November 18, 2025, among Calpine Construction Finance Company, L.P., as borrower, the lenders party thereto, and Citibank, N.A., as administrative agent and collateral agent (File No. 001-41137, Form 8-K, dated January 7, 2026, Exhibit 10.6)

10. 39
Credit Agreement, dated June 9, 2020, among Geysers Power Company, LLC, the guarantors party thereto, MUFG Bank, Ltd, as administrative agent, MUFG Union Bank, N.A., as first lien collateral agent, and the lenders and issuing banks parties thereto (File No. 001-41137, Form 8-K, dated January 7, 2026, Exhibit 10.7)

10. 40
Omnibus Amendment Agreement, dated November 9, 2021, among Geysers Power Company, LLC, the guarantors party thereto, MUFG Bank, Ltd, as administrative agent, MUFG Union Bank, N.A., as first lien collateral agent, and the lenders and issuing banks parties thereto (File No. 001-41137, Form 8-K, dated January 7, 2026, Exhibit 10.8)

10. 4 1
Second Omnibus Amendment Agreement, dated May 31, 2022, among Geysers Power Company, LLC, the guarantors party thereto, MUFG Bank, Ltd, as administrative agent, MUFG Union Bank, N.A., as first lien collateral agent, and the lenders and issuing banks parties thereto (File No. 001-41137, Form 8-K, dated January 7, 2026, Exhibit 10.9)

10.42**
Description of the Registrant's Securities Registered Pursuant to Section 12 of the Securities Exchange Act of 1934

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(19) Insider trading policies and procedures

19.1
Insider Trading Policy (File No. 001-41137, Form 10-K dated February 27, 2024, Exhibit 19.1)

(21) Subsidiaries

21.1
Constellation Energy Corporation

21.2
Constellation Energy Generation, LLC

(23) Consent of Independent Registered Public Accountants

23.1
Constellation Energy Corporation

23.2
Constellation Energy Generation, LLC

(24) Power of Attorney (Constellation Energy Corporation)

24.1
Yves C. de Balmann

24.2
Bradley Halverson

24.3
Charles Harrington

24.4
Julie Holzrichter

24.5
Ashish Khandpur

24.6
Robert Lawless

24.7
John Richardson

24.8
Nneka Rimmer

24.9
Dhiaa Jamil

24.10
Eileen Paterson

24.11
Alan Armstrong

(97) Policy Relating to Recovery of Erroneously Awarded Compensation

97.1
Compensation Clawback Policy for Executive Officers (File No. 001-41137, Form 10-K dated February 27, 2024, Exhibit 97.1)

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Certifications Pursuant to Rule 13a-14(a) and 15d-14(a) of the Securities and Exchange Act of 1934 as to the Annual Report on Form 10-K for the year ended December 31, 2025 filed by the following officers for the following registrants:

Exhibit No. Description
31.1
Filed by Joseph Dominguez for Constellation Energy Corporation

31.2
Filed by Shane P. Smith for Constellation Energy Corporation

31.3
Filed by Joseph Dominguez for Constellation Energy Generation, LLC

31.4
Filed by Shane P. Smith for Constellation Energy Generation, LLC

Certifications Pursuant to Section 1350 of Chapter 63 of Title 18 United States Code as to the Annual Report on Form 10-K for the year ended December 31, 2025 filed by the following officers for the following registrants:

Exhibit No. Description
32.1
Filed by Joseph Dominguez for Constellation Energy Corporation

32.2
Filed by Shane P. Smith for Constellation Energy Corporation

32.3
Filed by Joseph Dominguez for Constellation Energy Generation, LLC

32.4
Filed by Shane P. Smith for Constellation Energy Generation, LLC

101.INS
Inline XBRL Instance Document - the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document.

101.SCH Inline XBRL Taxonomy Extension Schema Document.

101.CAL Inline XBRL Taxonomy Extension Calculation Linkbase Document.

101.DEF Inline XBRL Taxonomy Extension Definition Linkbase Document.

101.LAB Inline XBRL Taxonomy Extension Label Linkbase Document.

101.PRE Inline XBRL Taxonomy Extension Presentation Linkbase Document.

104 Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101)

__________
* Management contract or compensatory plan or arrangement.
** Filed herewith.

ITEM 16. FORM 10-K SUMMARY

None.
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SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Exchange Act, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized, on the 24th day of February, 2026.

CONSTELLATION ENERGY CORPORATION

By: /s/ JOSEPH DOMINGUEZ
Name: Joseph Dominguez
Title: President and Chief Executive Officer

Pursuant to the requirements of the Exchange Act, this report has been signed by the following persons on behalf of the Registrant and in the capacities indicated on the 24th day of February, 2026.

Signature Title

/s/ JOSEPH DOMINGUEZ President and Chief Executive Officer (Principal Executive Officer)
Joseph Dominguez

/s/ SHANE P. SMITH
Executive Vice President and Chief Financial Officer (Principal Financial Officer)
Shane P. Smith

/s/ MATTHEW N. BAUER Senior Vice President and Controller (Principal Accounting Officer)
Matthew N. Bauer

This annual report has also been signed below by David Dardis, Attorney-in-Fact, on behalf of the following Directors on the date indicated:

Yves C. de Balmann John Richardson
Bradley Halverson Nneka Rimmer
Charles Harrington Dhiaa Jamil

Julie Holzrichter Eileen Paterson

Ashish Khandpur Alan Armstrong
Robert Lawless

By: /s/ DAVID DARDIS February 24, 2026
Name: David Dardis

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SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Exchange Act, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized, on the 24th day of February, 2026.

CONSTELLATION ENERGY GENERATION, LLC

By: /s/ JOSEPH DOMINGUEZ
Name: Joseph Dominguez
Title: President and Chief Executive Officer

Pursuant to the requirements of the Exchange Act, this report has been signed by the following persons on behalf of the Registrant and in the capacities indicated on the 24th day of February, 2026.

Signature Title

/s/ JOSEPH DOMINGUEZ President and Chief Executive Officer (Principal Executive Officer)
Joseph Dominguez

/s/ SHANE P. SMITH
Executive Vice President and Chief Financial Officer (Principal Financial Officer)
Shane P. Smith

/s/ MATTHEW N. BAUER Senior Vice President and Controller (Principal Accounting Officer)
Matthew N. Bauer

179