10-K – 2026-02-26 – tln-20251231.htm

Environmental product costs primarily include RGGIs and other emission product compliance costs that are mandated by certain states. The estimated cost of compliance is accrued at the time an obligation under the applicable terms of each state's environmental compliance program arises.
Realized gains and losses on commodity derivative instruments primarily include the settlements of financial and physical fuel contracts utilized for the Company’s commercial risk management objectives. Realized settlements of these derivative instruments are recognized and presented net within “Fuel and energy purchases” on the Consolidated Statements of Operations based on the delivery period of the underlying contract at contractually agreed prices. See “Operating Revenues and Revenue Recognition” above for additional information on realized gains and losses on derivative instruments presented as “Energy and other revenues” on the Consolidated Statements of Operations.
Nuclear fuel amortization. Nuclear fuel-related costs, including procurement of uranium, conversion, enrichment, fabrication and assemblies, are capitalized and presented as “Property, plant and equipment, net” on the Consolidated Balance Sheets and presented as a cash outflow within the investing activities section on the Consolidated Statements of Cash Flows. Such costs are amortized as the fuel is consumed using the units-of-production method and presented as “Nuclear fuel amortization” on the Consolidated Statements of Operations.
Unrealized gain (loss) on derivative instruments. Includes unrealized gains and losses resulting from changes in the fair value of certain fuel contracts and environmental product contracts that qualify as derivative instruments. See “Derivative Instruments” below for the recognition criteria of unrealized gains and losses on commodity derivative instruments. See “Operating Revenues and Revenue Recognition” above for additional information on unrealized gains and losses of derivative instruments presented as “Operating Revenues” on the Consolidated Statements of Operations.
Derivative Instruments. The fair value of derivative contracts required to be measured at fair value are presented as “Derivative instruments” within assets or liabilities on the Consolidated Balance Sheets. The primary type of derivative instruments utilized are commodity derivatives. Commodity derivative contracts are valued using inputs and assumptions such as contractual volumes, delivery location, forward commodity prices, commodity price volatility, discount rates, and credit worthiness of counterparties. For derivatives that trade in liquid markets, such as generic forwards, swaps, and options, the inputs and assumptions are generally observable.
In most instances, master netting agreements govern derivative transactions between parties and contain certain provisions for setoff rights. The fair value of derivative instruments is presented net of setoff rights and cash collateral deposits. The fair value of commercial contracts that are not subject to netting and (or) collateral provisions is presented gross. Prior to Emergence, the fair value of derivative instruments presented on the Consolidated Balance Sheets was presented gross of setoff rights and cash collateral deposits exchanged between parties under such arrangements.
Unrealized gains or losses associated with a derivative instrument that economically hedges certain risks but where qualified cash flow hedge accounting is not elected or not met are presented on the Consolidated Statements of Operations in the period when such gains or losses arise. As there are no derivatives where qualified hedge accounting has been elected, changes in the fair value of commodity derivatives are presented as “Unrealized gain (loss) on derivative instruments,” as a component of either “Operating Revenues” or “Energy Expenses” on the Consolidated Statements of Operations in a manner consistent with the presentation of net realized gains and losses. See “Operating Revenues” and “Energy Expenses” above for a discussion of net realized gains and losses on commodity derivatives. The cumulative net gains or losses for interest rate contracts are presented as “Interest expense and other finance charge s ” on the Consolidated Statements of Operations.
See Notes 2 and 11 for additional information on the presentation of derivative contracts and fair value measurements, respectively.
Operation, Maintenance and Development. The costs of removal, repairs, maintenance, and other operating costs, pre-commercial development activities, and salaries and benefits for operations personnel that each do not meet capitalization criteria are recognized as an expense when incurred. Materials and supplies inventories are recognized as an expense at the weighted average cost of materials consumed as they are used for repairs and maintenance. Costs for pre-commercial development stages of certain projects that are not capitalized as “Property, plant and equipment, net” on the Consolidated Balance Sheets and recurring operational and maintenance activities are each presented as “Operation, maintenance and development” on the Consolidated Statements of Operations. Development expenses incurred were primarily related to pre-commercial activities at Nautilus and hyperscale construction activities at Cumulus Digital.
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Stock-Based Compensation. TEC grants performance stock units (“PSUs”) and restricted stock units (“RSUs”) to certain employees and non-employee directors. The fair value of PSUs is estimated on the grant date utilizing a Monte Carlo Valuation Model, which contains significant unobservable inputs that are believed to be consistent with those used by principal market participants. The fair value of RSUs is derived from the closing price of TEC common stock at the grant date. Forfeitures are recognized as they occur. Unvested PSUs and RSUs are entitled to dividends or dividend equivalents, which are accrued and distributed to award recipients at the time such awards vest. Dividends and dividend equivalents are subject to the same vesting and forfeiture provisions as the underlying awards. Liability classified awards that settle in cash, or include an election to be settled in cash, are remeasured at fair value through settlement or maturity and presented as “Stock-based compensation liabilities” on the Consolidated Balance Sheets. Stock-based compensation expense is recognized for both graded and cliff vesting awards on a straight-line basis over the requisite service period for the entire award. Stock-based compensation expense is presented as “General and administrative” on the Consolidated Statements of Operations.
See Note 13 for additional information on stock-based compensation.
Income Taxes. TEC and its subsidiaries file a consolidated U.S. federal income tax return. Income taxes are accounted for under the asset and liability method. Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying values of existing assets and liabilities and their respective tax basis, tax credits and NOL carryforwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities due to a change in tax rates is recognized as income in the period that includes the enactment date. Valuation allowances are recognized to reduce deferred tax assets to the extent necessary to result in an amount that is more likely than not to be realized. Disproportionate income tax effects are removed from AOCI when the circumstance upon which they are premised ceases to exist.
The financial statement effect of a tax position is recognized when it is more-likely-than-not, based on the technical merits, that the position will be sustained upon examination. A tax position that meets the more-likely-than-not recognition threshold is measured as the largest amount of tax benefit that is greater than 50% likely of being realized upon ultimate settlement with a taxing authority. A previously recognized tax position is reversed in the first period in which it is no longer more-likely-than-not that the tax position would be sustained upon examination. Interest and penalties from tax uncertainties are presented as “Income tax benefit (expense)” on the Consolidated Statements of Operations.
See Note 4 for additional information on income taxes.
Concentrations of Credit Risk. Concentrations of credit risk exist primarily within cash and cash equivalents, receivables, and commodity derivative assets. Cash and cash equivalents are generally held in accounts where the amounts deposited exceed the maximum deposit insurance provided by the Federal Deposit Insurance Corporation. Cash and cash equivalents and restricted cash balances are primarily deposited in accounts with major financial institutions with investment grade credit ratings. In certain instances, funds are invested in highly liquid U.S. Treasury securities or other obligations with original maturities of less than 90 days that are issued by or guaranteed by the U.S. Government. Concentrations of credit risk for receivables are primarily attributable to entities that reimburse Talen for certain capital expenditures and operating costs associated with jointly owned facilities. Concentrations of credit risk for commodity derivative assets are primarily attributable to unaffiliated investment grade counterparties which engage in energy marketing activities with Talen Energy Marketing. See Note 2 for additional information on concentrations of credit risk.
Cash and Cash Equivalents. Bank deposits, liquid investments, and other similar assets with original maturities of three months or less. Cash and cash equivalents, including cash deposits supporting the Company’s commodity exchange activities, that are contractually restricted are presented as “Restricted cash and cash equivalents” on the Consolidated Balance Sheets.
See Note 16 for additional information.
Accounts Receivable. Receivables primarily consist of amounts due from customers or other contract counterparties, net of any collection allowances. Uncollected receivables greater than 30 days past due are assessed for collectability based on a variety of factors that include, but are not limited to, customer credit worthiness, duration receivables are outstanding, and (or) historical collection experience. Management continuously assesses and considers current economic trends that might impact the amount of future credit losses. If it becomes known that a specific customer may not have the ability to settle its obligation that is not yet past due, such receivables are assessed for collectability. If these assessments indicate a receivable collection is remote, its carrying value is reduced through an allowance for doubtful accounts measured at management’s best estimate, and a charge is presented on the Consolidated Statements of Operations. If any portion of the original carrying value of the receivable is recovered, the allowance and the associated charge are reversed in the period of collection.
Inventory. Inventory consists of fuel for generation (primarily coal and fuel oil), materials and supplies, and environmental products each of which are valued at the lower of weighted average cost or net realizable value. See Note 5 for additional information on inventory.
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Investments in Debt and Equity Securities. The NDT holds investments in available-for-sale debt securities and equity securities, which are carried at fair value and presented as “Nuclear decommissioning trust funds” on the Consolidated Balance Sheets.
Unrealized gains and losses, net of income tax, on available-for-sale debt securities are presented as “Other Comprehensive Income (Loss)” on the Consolidated Statements of Comprehensive Income in the period when such gains and losses arise. Realized gains and losses on available-for-sale debt securities are transferred from AOCI to “Nuclear decommissioning trust funds gain (loss), net” on the Consolidated Statements of Operations in the period when the sale of the security occurs. The specific identification method is used to calculate realized gains and losses on debt and equity securities. If an available-for-sale debt security's fair value declines below cost and the decline is determined to be other-than-temporary, the unrealized loss is recognized on the Consolidated Statements of Comprehensive Income in the period when such determination arises.
Unrealized gains and losses and realized gains and losses on equity securities are presented as “Nuclear decommissioning trust funds gain (loss), net” on the Consolidated Statements of Operations in the period when such gains or losses arise.
See Notes 6 and 11 for additional information on investments in debt and equity securities.
Property, Plant and Equipment. Expenditures for land, the construction of facilities, the addition or refurbishment of major equipment, and commercially viable new development projects are capitalized at cost. Such capitalized amounts include interest costs, where appropriate. Facilities, land, and other equipment acquired in a business combination are recognized at acquisition date fair value. In each case, such amounts are presented as “Property, plant and equipment, net” on the Consolidated Balance Sheets. Reductions in the carrying value of PP&E are accumulated over the estimated useful life of each depreciable unit using group or straight-line depreciation methods. Such periodic reduction is presented as a charge to “Depreciation, amortization and accretion” on the Consolidated Statements of Operations. Generally, upon normal retirement of PP&E under the group depreciation method, the costs of such assets are retired against accumulated depreciation in the period of the retirement and no gain or loss is recognized. Any remaining carrying value of PP&E at its retirement date that depreciated under the straight-line depreciation method is presented as a loss within “Other operating income (expense), net” on the Consolidated Statements of Operations. Any remaining carrying value of PP&E at its sale date and any proceeds from the disposition are presented as a gain or loss net on the Consolidated Statements of Operations.
See Note 17 for information on recent business combinations.
Expenditures for intangible assets such as contractual rights, software development costs, and long-term operating licenses are capitalized at cost and are presented as “Property, plant and equipment, net” on the Consolidated Balance Sheets. Reductions in the carrying value of intangible assets with finite useful lives are accumulated over the estimated useful life of each intangible asset using an amortization pattern which reflects the economic benefits of the intangible asset. Such periodic reduction is presented as a charge to “Depreciation, amortization and accretion” on the Consolidated Statements of Operations. See “Impairment” below for additional information regarding impairments of the carrying values of PP&E.
See Note 7 for additional information on PP&E.
Impairment. PP&E used in operations are assessed for impairment when changes in facts and circumstances indicate the carrying value of the asset group may not be recoverable. Indicators of impairment may include changes in the economic environment, negative financial trends, physical damage to assets or management’s decisions regarding strategic initiatives. Where applicable, individual assets are grouped for impairment analysis purposes at the lowest level for which there are identifiable cash flows that are largely independent of the cash flows of other assets and liabilities. If there is an indication the carrying value of an asset group may not be recoverable, management reviews the expected future cash flows of the asset group. If the sum of the undiscounted pre-tax cash flows is less than the carrying value of the asset group, the carrying value of the asset group is written down to its estimated fair value. Impairment charges are presented as “Impairments” on the Consolidated Statements of Operations in the period in which the impairment condition arises. If facts and circumstances indicate that the carrying value of an asset under construction will have no future economic benefit, such amounts are presented on the Consolidated Statements of Operations in the period in which such projects are abandoned, canceled, or management otherwise determines the costs to be unrecoverable.
Fair value may be determined by a variety of valuation methods including third-party appraisals, market prices of similar assets, and present value techniques. However, as there is generally a lack of quoted market prices for long-lived assets, the fair value of impaired assets is typically determined based on the present values of expected future cash flows using discount rates that are believed to be consistent with those used by principal market participants. The estimated cash flows and related fair value computations consider all available evidence at the date of the review, such as estimated future generation volumes, forward capacity and commodity prices, energy prices, operating costs, capital expenditures, and environmental costs.
See Note 7 for information on impairments.
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Asset Retirement Obligations. A liability for an ARO or conditional ARO exists when a legal obligation arises from laws, regulations or other contractual requirements for the retirement of tangible long-lived assets. When an ARO liability is incurred, which is typically at asset construction or through assumption of the liability in connection with a business combination, it is initially recognized at fair value. Fair value measurements are estimated under a present value technique and are discounted using a credit-adjusted risk-free rate. Additionally, given the inherent uncertainty in estimating the amount of cash flows to settle an ARO liability or its settlement date, fair value estimates include a market risk premium and a range of possible cash flow outcomes, where applicable. At the initial recognition, the effects on the Consolidated Balance Sheets include: (i) an increase to “Asset retirement obligations and accrued environmental costs” for the portion of ARO to be settled after one year and (or) “Other current liabilities” for the portion of the ARO to be settled within one year; and (ii) an offsetting increase to “Property, plant and equipment, net” for the asset retirement capitalized cost. Estimated future ARO cash expenditures and settlement dates are reviewed periodically to identify any required amendments to the carrying value of each ARO liability.
ARO liabilities increase through the recognition of accretion expense to recognize changes in the obligation due to the passage of time. The asset retirement capitalized cost is depreciated at a rate consistent with the useful life of the associated long-lived asset. The depreciation of the asset retirement capitalized cost and the accretion of the ARO liability are each presented as “Depreciation, amortization and accretion” on the Consolidated Statements of Operations. An ARO liability amendment associated with a long-lived asset that is not fully impaired or depreciated is recognized through an adjustment to the ARO liability and the asset retirement capitalized cost. Any revision to the asset retirement capitalized cost is generally depreciated over the remaining life of the associated long-lived asset. An ARO liability amendment associated with a fully impaired or depreciated asset is presented as “Other operating income (expense), net” on the Consolidated Statements of Operations. At settlement, a gain or loss will arise if the cash expenditures to settle the ARO liabilities are different than the carrying values. Such gains or losses are presented as “Other operating income (expense), net” on the Consolidated Statements of Operations.
A conditional ARO refers to an entity’s legal obligation to perform an asset retirement activity in which the timing or method of settlement is conditional on a future event that may or may not be within the entity’s control, including legal or regulatory requirements. There may also be instances when there is no available information regarding the ultimate ARO settlement timing or the fair value of the obligation may not be reasonably estimable. If sufficient information becomes available to reasonably estimate the fair value of the liability for an ARO or a conditional ARO, a liability is recognized in the period in which it is determined.
See Note 8 for additional information on AROs.
Contingencies. Potential loss contingencies may result from environmental remediation, litigation claims, regulatory penalties or other events. Potential losses are accrued when: (i) information is available that indicates it is probable (i.e., likely to occur) that a loss has been incurred, given the likelihood of the uncertain future events; and (ii) the amount of the loss can be reasonably estimated. Loss contingencies are recognized at management's best estimate, which may be discounted, where appropriate. Loss contingencies exclude estimates for any legal fees, which are recognized as incurred when the legal services are performed. Additionally, pursuant to federal and state legislation, the Company assesses the funding associated with certain legacy health care benefit plans for retired mine workers and recognizes expected funding shortfall, if any, as a contingent liability. See Note 9 for additional information on loss contingencies.
Business interruption insurance proceeds are considered gain contingencies and not recognized until realized.
Debt. Proceeds received on the issuance of new term loans, secured notes, unsecured notes, bonds, and similar indebtedness are presented as “Long-term debt” or “Long-term debt, due within one year” on the Consolidated Balance Sheets. Interest incurred as paid-in-kind, whether accrued or capitalized as additional principal are presented as “Long-term debt” with the associated outstanding amounts of indebtedness. Costs incurred to issue new indebtedness and any original issuance discounts or premiums are deferred at issuance on the Consolidated Balance Sheets and presented together with the associated outstanding principal amounts of indebtedness.
Interest accrues on outstanding principal amounts of indebtedness based on contractually determined rates during each period. Costs incurred for the issuance of indebtedness and any original issuance discounts or premiums are subsequently amortized through the expected maturity date of the associated indebtedness under the effective interest rate method and are presented as “Interest expense and other finance charges” on the Consolidated Statements of Operations.
Gains and losses on the: (i) early redemption of indebtedness; or (ii) early termination and (or) reduction of revolving credit facility committed capacity are presented as a gain or loss on the Consolidated Statements of Operations. Such amounts include the proportional derecognition of any deferred financing costs, fees, discounts, and (or) premiums associated with the indebtedness.
Direct cash borrowings under secured lines of credit, revolving credit facilities, and similar indebtedness are presented as a current liability on the Consolidated Balance Sheets. Costs incurred to issue new arrangements are deferred and presented as “Other current assets” or “Other noncurrent assets” on the Consolidated Balance Sheets. Interest accrues on direct cash borrowings and LCs based on contractually determined rates during each period.
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Costs incurred to issue new arrangements are subsequently amortized through the expected expiration of the associated arrangement under the straight-line method. Commitment fees on available but unused credit facility capacity are expensed as incurred. Such costs are presented as “Interest expense and other finance charges” on the Consolidated Statements of Operations.
See Note 10 for additional information on debt.
Postretirement Benefit Obligations. Certain Talen subsidiaries sponsor various defined benefit pension plans and other postretirement benefit plans. Gains and losses, net of income tax, that arise and are not a component of net periodic defined benefit costs are presented as “Other Comprehensive Income (Loss)” on the Consolidated Statements of Comprehensive Income. Service cost is presented as “Operation, maintenance and development” while the other components of net periodic defined benefit cost (credit) for pension and other postretirement plans are presented as “Other non-operating income (expense), net” on the Consolidated Statements of Operations.
Following Emergence, actuarial gains and losses in excess of the greater of 10% of the plan's projected benefit obligation or the market-related value of plan assets are amortized over (i) the expected average remaining service period of active plan participants for active plans; or (ii) the average future remaining lifetime of the plan participants of frozen plans. Prior to Emergence, Talen used an accelerated amortization method for the recognition of gains and losses for defined benefit pension plans: (i) actuarial gains and losses in excess of 30% of the plan's projected benefit obligation are amortized on a straight-line basis over one-half of the expected average remaining service of active plan participants; and (ii) actuarial gains and losses in excess of 10% of the greater of the plan's projected benefit obligation or the market-related value of plan assets and less than 30% of the plan's projected benefit obligation are amortized on a straight-line basis over the expected average remaining service period of active plan participants.
Following Emergence, a spot rate curve that represents a portfolio of high-quality corporate bonds is used to develop the discount rate utilized to measure the projected benefit obligations and service costs for benefit plans. Prior to Emergence, a bond matching methodology was utilized, based on a specific portfolio of bonds that closely match the overall cash flow timing and duration of the benefit plans.
See Note 12 for additional information on the plans and the accounting for defined benefits.
Treasury Stock and Retirement of Treasury Shares. Share repurchases are accounted for under the cost method, which recognizes the entire cost of the acquired stock, including transaction costs and excise tax, as a reduction in additional paid-in-capital and are presented as “Treasury stock” on the Consolidated Balance Sheets. Share repurchases are recognized on a trade date basis when we are contractually obligated to purchase the shares. Treasury shares are retired on the settlement date of the transaction. At retirement, the common stock balance is reduced for the par value of the shares. The excess of the acquisition cost of repurchased shares over the par value is recognized in additional paid-in capital (up to the amount credited to additional paid-in capital upon original issuance of the shares), with any remaining cost deducted from retained earnings.

Recently Adopted Accounting Pronouncements
There have been no recently adopted accounting pronouncements that had a material effect on the Company’s financials statements and (or) disclosures.

Recent Accounting Pronouncements Not Yet Adopted
ASU 2024-03. In November 2024, the FASB issued ASU 2024-03, Expense Disaggregation Disclosures (Subtopic 220-40): Disaggregation of Income Statement Expenses. This ASU requires public companies to disclose, in the notes to financial statements, specified information about certain costs and expenses at each interim and annual reporting period. This ASU is effective for annual reporting periods beginning after December 15, 2026. Early adoption is permitted. The Company is evaluating the disclosure impact of this ASU and expects to adopt it in the required period.
ASU 2025-11. In December 2025, the FASB issued ASU 2025-11, Interim Reporting (Topic 270): Narrow-Scope Improvements. This ASU provides clarification to certain elements of Topic 270, but does not change the fundamental nature of interim reporting or expand or reduce current interim disclosure requirements. This ASU is effective for annual periods beginning after December 15, 2027, and interim periods within those annual periods. Early adoption is permitted. The Company is evaluating the disclosure impact of this ASU and expects to adopt it in the required period.
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2. Risk Management, Derivative Instruments and Hedging Activities

Risk Management Objectives
We are exposed to risks arising from our business, including but not limited to market and commodity price risk, credit and liquidity risk, and interest rate risk. The hedging strategies deployed by our commercial and treasury organizations manage and (or) balance these risks within a structured risk management program in order to minimize near-term future cash flow volatility. Our risk management committee, comprised of certain senior management members across the organization, oversees the management of these risks in accordance with our risk policy. In turn, the risk management committee is overseen by the risk committee of the Board of Directors.
The Board of Directors, including the risk committee, and management have established procedures to monitor, measure, and manage hedging activities and credit risk in accordance with the risk policy.
Key risk control activities, which are designed to ensure compliance with the risk policy, include, among other activities, credit review and approval, validation of transactions and market prices, verification of risk and transaction limits, portfolio stress tests, analysis and monitoring of margin at risk, and daily portfolio reporting.
Market and Commodity Price Risk. Volatility in the wholesale power markets provides uncertainty in the future earnings and cash flows of the business. The price risk Talen is exposed to includes the price variability associated with future sales and (or) purchases of power, natural gas, coal, uranium, oil products, environmental products, and other energy commodities in competitive wholesale markets. Several factors influence price volatility, including: (i) seasonal changes in demand; (ii) weather conditions; (iii) available regional load-serving supply; (iv) regional transportation and (or) transmission availability; (v) market liquidity; and (vi) federal, regional, and state regulations.
Within the parameters of our risk policy, we generally utilize exchange-traded and over-the-counter traded derivative instruments and, in certain instances, structured products, to economically hedge the commodity price risk of the forecasted future sales and purchases of commodities associated with our generation portfolio.
Open commodity purchase (sales) derivatives range in maturity through 2027. The net notional volumes of commodity derivatives were:

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

Power (MWh) ( 59,634,723 ) ( 38,615,192 )
Natural gas (MMBtu) 169,209,022   32,405,460  
Emission allowances (tons) —   100,000  

__________________
(a) The volumes may be different than the contractual volumes, as the probability that option contracts will be exercised is considered in the volumes displayed.
Interest Rate Risk. Talen is exposed to interest rate risk from the possibility that changes in interest rates will affect future cash flows associated with existing floating rate debt issuances. To reduce interest rate risk, derivative instruments are utilized to economically hedge the interest rates for a predetermined contractual notional amount, which results in a cash settlement between counterparties. To the extent possible, first lien interest rate fixed-for-floating swaps are utilized to hedge this risk.
Open interest rate derivatives range in maturity through 2029. The net notional volumes of open interest rate derivatives were:

Successor
December 31,
2025 December 31,
2024
Interest rate (in millions)
$ 990   $ 290  

Credit Risk. Credit risk, which is the risk of financial loss if a customer, counterparty, or financial institution is unable to perform or pay amounts due, is applicable to cash and cash equivalents, restricted cash and cash equivalents, accounts receivable, and derivative instruments. The maximum amount of credit exposure associated with financial assets is equal to the carrying value of such assets. Credit risk, which cannot be completely eliminated, is managed through a number of practices such as ongoing reviews of counterparty creditworthiness, prepayment, inclusion of termination rights in contracts which are triggered by certain events of default, and executing master netting arrangements that permit amounts between parties to be offset. Additionally, credit enhancements such as cash deposits, LCs, and credit insurance may be employed to mitigate credit risk.
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Cash and cash equivalents are placed in depository accounts or high-quality, short-term investments with major international banks and financial institutions. Individual counterparty exposure from over-the-counter derivative instruments is managed within predetermined credit limits and includes the use of master netting arrangements and cash-call margins, when appropriate, to reduce credit risk. Exchange-traded commodity contracts, which are executed through futures commission merchants, have minimal credit risk because they are subject to mandatory margin requirements and are cleared with an exchange. However, Talen is exposed to the credit risk of the futures commission merchants arising from daily variation margin cash calls. Restricted cash and cash equivalents deposited to meet initial margin requirements are held by futures commission merchants in segregated accounts for the benefit of Talen.
Outstanding accounts receivable include those from sales of capacity, generated electricity, and ancillary services through contracts directly with ISOs and RTOs and realized settlements of physical and financial derivative instruments with commodity marketers. Additionally, Talen carries accounts receivable due from joint owners for their portion of operating and capital costs for certain jointly owned facilities that are operated by the Company. The majority of outstanding receivables, which are continually monitored, have customary payment terms. The allowance for doubtful accounts was a non-material amount as of December 31, 2025 (Successor) and 2024 (Successor).
As of December 31, 2025 (Successor), Talen’s aggregate credit exposure, which excludes the effects of netting arrangements, cash collateral, LCs, and any allowances for doubtful collections, was $ 652 million and its credit exposure including such netting effects was $ 47 million. Excluding ISO and RTO counterparties, whose accounts receivable settlements and congestion products are subject to applicable market controls, the ten largest single net credit exposures account for 83 % of Talen’s total net credit exposure, which are primarily with entities assigned investment grade credit ratings.
Certain derivative instruments contain credit risk-related contingent features, which may require us to provide cash collateral, LCs, or guarantees from a creditworthy entity if the fair value of a liability eclipses a certain threshold or upon a decline in Talen’s credit rating. The fair values of derivative instruments in a net liability position, and that contain credit risk-related contingent features, were non-material as of December 31, 2025 (Successor) and 2024 (Successor).

Derivative Instrument Presentation
Balance Sheets Presentation. The fair value of derivative instruments presented within assets and liabilities on the Consolidated Balance Sheets were:

Successor
December 31, 2025 December 31, 2024
Assets Liabilities Assets Liabilities
Commodity contracts $ 56   $ 97   $ 65   $ —  
Interest rate contracts —   4   1   —  

Total current derivative instruments 56   101   66   —  
Commodity contracts 4   59   4   7  
Interest rate contracts —   8   1   —  
Total non-current derivative instruments $ 4   $ 67   $ 5   $ 7  

All commodity and interest rate derivatives are economic hedges where the changes in fair value are presented immediately in income as unrealized gains and losses. Changes in the fair value and realized settlements on commodity derivative instruments are presented as separate components of “Energy and other revenues” and “Fuel and energy purchases” on the Consolidated Statements of Operations. Changes in the fair value and realized settlements on interest rate derivative instruments are presented as “Interest expense and other finance charges” on the Consolidated Statements of Operations. See Note 11 for additional information on fair value of commodity and interest rate derivatives.
Effect of Netting. Generally, the right of setoff within master netting arrangements permits the fair value of derivative assets to be offset with derivative liabilities. As an election, derivative assets and derivative liabilities are presented on the Consolidated Balance Sheets with the effect of such permitted netting as of December 31, 2025 (Successor) and 2024 (Successor).
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The net amounts of “Derivative instruments” presented as assets and liabilities on the Consolidated Balance Sheets considering the effect of permitted netting and where cash collateral is pledged in accordance with the underlying agreement were:

Gross Derivative Instruments Eligible for Offset Net Derivative Instruments Collateral (Posted) Received Net Amounts
December 31, 2025 (Successor)
Assets $ 456   $ ( 396 ) $ 60   $ —   $ 60  
Liabilities 608   ( 396 ) 212   ( 44 ) 168  
December 31, 2024 (Successor)
Assets $ 227   $ ( 154 ) $ 73   $ ( 2 ) $ 71  
Liabilities 173   ( 154 ) 19   ( 12 ) 7  

Statements of Operations Presentation. The location and pre-tax effect of “Derivative instruments” presented on the Consolidated Statements of Operations for the periods were:

Successor Predecessor
Year Ended December 31, 2025 Year Ended December 31, 2024 May 18 through December 31, 2023 January 1 through May 17, 2023
Realized gain (loss) on commodity contracts
Energy revenues (a)
$ 102   $ 317   $ 360   $ 644  
Fuel and energy purchases (a)
( 14 ) ( 35 ) ( 91 ) ( 34 )
Unrealized gain (loss) on commodity contracts
Operating revenues (b)
( 45 ) 42   55   60  
Energy expenses (b)
( 61 ) 20   ( 3 ) ( 123 )
Realized and unrealized gain (loss) on interest rate contracts
Interest expense and other finance charges ( 13 ) 9   ( 4 ) —  

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(a) Does not include those derivative instruments that settle through physical delivery.
(b) Presented as “Unrealized gain (loss) on derivative instruments” on the Consolidated Statements of Operations.

3. Revenue
The components of operating revenues for the periods were:

Successor Predecessor
Year Ended December 31, 2025 Year Ended December 31, 2024 May 18 through December 31, 2023 January 1 through May 17, 2023
Electricity sales and ancillary services, ISO/RTO $ 1,940   $ 1,144   $ 880   $ 281  
Capacity revenues 485   192   133   108  
Physical electricity sales, bilateral contracts, other 93   147   71   62  
Other revenue from customers —   91   81   27  
Total revenue from contracts with customers 2,518   1,574   1,165   478  
Realized and unrealized gain (loss) on derivative instruments 56   307   179   732  
Nuclear PTC —   220   —   —  
Other revenue 7   14   —   —  
Operating revenues $ 2,581   $ 2,115   $ 1,344   $ 1,210  

Accounts Receivable
“Accounts receivable” presented on the Consolidated Balance Sheets were:

Successor
December 31,
2025 December 31,
2024
Customer accounts receivable $ 160   $ 66  
Other accounts receivable 36   57  
Accounts receivable $ 196   $ 123  

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During the years ended December 31, 2025 (Successor), and 2024 (Successor), there were no significant changes in accounts receivable other than normal receivable recognition and collection transactions. See Note 2 for additional information on Talen’s credit risk on the carrying value of its receivables.

Future Performance Obligations
Talen’s estimated future fixed fee performance obligations primarily include capacity volumes awarded, net of capacity repurchases by the Company, through PJM BRAs and incremental PJM capacity auctions. See Note 9 for additional information on the PJM BRAs.
As of December 31, 2025 (Successor), future performance obligations that were unsatisfied or partially unsatisfied were:
2026 2027 2028 (a)
2029 (a)
2030 (a)

Future performance obligations $ 963   $ 1,053   $ 443   $ —   $ —  

__________________
(a) As PJM BRAs have not yet occurred for periods after the 2027/2028 PJM Capacity Year, there are no future performance obligations after May 31, 2028.

Brandon Shores and H.A. Wagner RMR Agreements
In May 2025, the FERC approved each of the Brandon Shores and H.A. Wagner RMR agreements, under which: (i) Talen will operate the generation facilities in accordance with such arrangements from June 1, 2025 through May 31, 2029, or until such time as the necessary third-party transmission upgrades are placed into service; (ii) Brandon Shores will earn annual fixed-cost payments of $ 145 million ($ 312 /MWd), inclusive of a $ 5 million per year unit performance “hold back;” (iii) H.A. Wagner will earn annual fixed-cost payments of $ 35 million ($ 137 /MWd), inclusive of a $ 2.5 million per year unit performance “hold back;” and (iv) each facility will receive separate reimbursement for variable costs and approved project investments. In August 2025, the Maryland Office of People’s Counsel filed an appeal of the FERC’s order approving the Brandon Shores and H.A. Wagner RMR agreements. Talen has intervened in that proceeding and plans to participate.
Additionally, H.A. Wagner Unit 4 is subject to certain emission restrictions associated with its air permits that limit the Unit’s annual runtime. In October 2025, the DOE granted PJM’s request, pursuant to Section 202(c) of the Federal Power Act, to renew the DOE’s July order, which allowed Unit 4 to exceed its air permit emission limits for the remainder of the calendar year when Unit 4 was needed to maintain grid reliability. Such order is subject to extension at the request of PJM and at the discretion of the DOE.

4. Income Taxes

The components of “Income tax benefit (expense)” for the periods were:

Successor Predecessor
Year Ended December 31, 2025 Year Ended December 31, 2024 May 18 through December 31, 2023 January 1 through May 17, 2023
Federal $ 54   $ ( 113 ) $ 3   $ ( 15 )
State 13   ( 31 ) 1   ( 2 )
Current income taxes 67   ( 144 ) 4   ( 17 )
Federal ( 135 ) 47   ( 55 ) ( 184 )
State 15   ( 1 ) —   ( 11 )
Deferred income taxes ( 120 ) 46   ( 55 ) ( 195 )

Income tax benefit (expense) $ ( 53 ) $ ( 98 ) $ ( 51 ) $ ( 212 )
Income (loss) before income taxes ( 166 ) 1,111   194   677  
Effective income tax rate ( 31.9 ) % 8.8   % 26.3   % 31.3   %

Current tax receivable presented as “Other current assets” on the Consolidated Balance Sheets were $ 35 million as of December 31, 2025 (Successor) and non-material as of December 31, 2024 (Successor). Current tax liabilities presented as “Other current liabilities” on the Consolidated Balance Sheets were non-material as of December 31, 2025 (Successor) and $ 53 million as of December 31, 2024 (Successor).
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Effective Tax Rate Reconciliations
The following table presents required disclosures pursuant to ASU 2023-09 and reconciles the U.S. federal statutory tax amount and rate to our effective tax amount and rate for the year ended December 31, 2025 (Successor):

Successor
Year Ended December 31, 2025
Federal income tax at statutory tax rate $ 35 21.0 %
State income taxes, net of federal benefit (a)
4 2.4 %
Nontaxable or nondeductible items:
Stock-based compensation ( 72 ) ( 43.2 )%
Nuclear PTC ( 2 ) ( 1.2 )%
Other permanent differences ( 1 ) ( 0.6 )%
Changes in valuation allowances ( 2 ) ( 1.2 )%
Other adjustments:
Return to provision 13 7.8 %
Tax on NDT ( 28 ) ( 16.9 )%
Income tax benefit (expense) $ ( 53 ) ( 31.9 )%

__________________
(a) Pennsylvania state income taxes comprised the majority of the tax effect in this category.
The following table presents the required disclosures prior to our adoption of ASU 2023-09 and reconciles the income tax benefit (expense) at our statutory rate to the income tax benefit (expense) at our effective rate for the following periods:

Successor Predecessor
Year Ended December 31, 2024 May 18 through December 31, 2023 January 1 through May 17, 2023
Income tax benefit (expense) computed at the federal income tax statutory tax rate of 21 %
$ ( 234 ) $ ( 41 ) $ ( 143 )
Income tax increase (decrease) due to:
Change in valuation allowance 128   ( 43 ) 129  
State income taxes, net of federal benefit ( 48 ) 1   ( 34 )
Nuclear PTC 46   —   —  
Nuclear decommissioning trust taxes ( 27 ) ( 16 ) ( 9 )
Reorganization adjustments 23   26   ( 138 )
Return to provision 11   —   —  
Permanent differences 3   22   ( 16 )

Other —   —   ( 1 )
Income tax benefit (expense) $ ( 98 ) $ ( 51 ) $ ( 212 )

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Deferred Taxes
The components of deferred tax liabilities and deferred tax assets were:

Successor
December 31,
2025 December 31,
2024

Property, plant and equipment, net $ 1,305 $ 465
Nuclear decommissioning trust 540 502
Unrealized gain on qualifying derivatives — 32

Other 3 —
Deferred tax liabilities 1,848 999
Less:
Federal net operating loss carryforwards 749 164
Interest limitation carryforward 331 340
Acquired fuel supply contract liabilities (a)
151 —
Accrued liabilities 53 30
Accrued pension costs 45 80
State net operating loss carryforwards 19 15

Unrealized loss on qualifying derivatives 16 —
Other — 8
Deferred tax assets 1,364 637
Valuation allowance ( 2 ) —
Deferred tax liabilities, net $ 486 $ 362

__________________
(a) See Note 17 for additional information on acquired fuel supply contract liabilities.

Net Operating Losses
The components of NOL carryforwards were:

Successor
December 31,
2025 December 31,
2024

Federal, indefinite expiration, limited to annual utilization of 80%
$ 3,566 $ 783
State, expirations 2026 - 2041 407 310

See “Emergence from Restructuring” below for information on limitations on our NOLs.

Income Taxes Paid Net of Refunds
The amounts of income taxes paid, net of refunds, were:

Successor
Year Ended December 31, 2025
US Federal - Corporate $ 26  
US Federal - NDT 15  
Total federal tax 41  

Pennsylvania 17  

Other states (a)
13  
Total state tax 30  
Total
$ 71  

__________________
(a) Consists primarily of New Jersey, Maryland, and Texas.

Unrecognized Tax Benefits
Unrecognized tax benefits as of December 31, 2025 (Successor) and 2024 (Successor) were a non-material amount. All tax returns filed for years December 31, 2022 and forward are open to examination by the relevant taxing authorities.
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Emergence from Restructuring
The Company evaluated, including the change in control resulting from its Emergence from bankruptcy, the tax impact of its Restructuring as described in Note 19. As part of the Restructuring, a substantial portion of the Company’s prepetition debt was extinguished, resulting in cancellation of debt income (“CODI”). A taxpayer emerging from bankruptcy may exclude CODI from taxable income but must first reduce its tax attributes by the amount of CODI realized. The Company realized CODI of $ 1.2 billion, which resulted in a partial reduction in tax basis in PP&E assets.
Upon Emergence, the Company experienced an ownership change under Section 382 of the Internal Revenue Code of 1986, as amended (the “Code”). The Code’s Sections 382 and 383 impose limitations on the ability of a company to utilize tax attributes after experiencing an ownership change. States generally have similar tax attribute limitation rules following an ownership change. The Company also applied fresh start accounting. As a result, deferred tax assets and liabilities were adjusted based on the Successor GAAP financial statements. See Note 20 for additional information on fresh start accounting.

Valuation Allowance
Management assesses the available positive and negative evidence to estimate whether it is more likely than not that sufficient future taxable income will be generated to permit the use of existing deferred tax assets. Negative evidence in the form of cumulative losses are no longer present as the Company has returned to profitability. The existence of objective positive evidence allows for consideration of other subjective evidence, including (but not limited to) Talen’s projections for future income which would allow for utilization of all net operating losses and interest limitation carryforwards.
As a result of the assessment, it was determined that it is more likely than not that all federal and most state deferred tax assets will be fully utilized by future taxable income. As of December 31, 2025 (Successor), the Company’s valuation allowance was non-material.
As of December 31, 2024 (Successor), it was more likely than not that federal and state deferred tax assets would be fully utilized by future taxable income. The entire federal and state valuation allowances were released, resulting in a $ 128 million tax benefit. For the period from May 18 through December 31, 2023 (Successor), a $ 43 million tax expense was recognized for the increase in federal and state valuation allowances based on the realizability of deferred tax assets. For the period from January 1 through May 17, 2023 (Predecessor), a $ 129 million benefit was recognized for the reduction in federal and state valuation allowances. The change in valuation allowance estimates was the result of tax attribute reduction from the cancellation of debt income that was realized upon Emergence.

Sale of Nuclear Production Tax Credits
In September 2025, Nuclear PTCs with an aggregate carrying value of $ 202 million were sold to an unaffiliated third party for cash consideration of $ 191 million. The $ 11 million difference between the carrying value and the sales price resulted in loss presented in “Other operating income (expense), net” on the Consolidated Statements of Operations. The Company’s Nuclear PTCs remaining after the sale were utilized in reducing federal income taxes payable.

One Big Beautiful Bill Act
In 2025, the One Big Beautiful Bill Act (the “OBBB”) was signed into law. The OBBB, among other things, makes key elements of the Tax Cuts and Jobs Act permanent, including 100% bonus depreciation, domestic research cost expensing, and the business interest expense limitation. The Company has included the known effects of the OBBB in its income tax provision .

5. Inventory

Successor
December 31,
2025 December 31,
2024
Coal $ 94   $ 92  
Oil products 57   65  
Fuel inventory for electric generation 151   157  
Materials and supplies, net 124   88  
Environmental products 3   57  
Inventory, net $ 278   $ 302  

Inventory net realizable value and obsolescence charges on coal and fuel oil inventories are presented as “Other operating income (expense), net” on the Consolidated Statements of Operations. Such non-cash charges were non-material for the year ended December 31, 2025 (Successor), the year ended December 31, 2024 (Successor), the period from May 18 through December 31, 2023 (Successor), and $ 37 million for the period from January 1 through May 17, 2023 (Predecessor).
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During the period from January 1 through May 17, 2023 (Predecessor), $ 24 million of adjustments were related to Brandon Shores coal and materials and supplies inventories. See Note 7 for additional information on the Brandon Shores recoverability assessment.

6. Nuclear Decommissioning Trust Funds

Successor
December 31, 2025 December 31, 2024
Amortized Cost Unrealized Gains Unrealized Losses Fair Value Amortized Cost Unrealized Gains Unrealized Losses Fair Value
Cash equivalents $ 16   $ —  $ —  $ 16   $ 3   $ —  $ —  $ 3  
Equity securities 385   739   ( 19 ) 1,105   509   651   ( 55 ) 1,105  
Debt securities 773   7   ( 3 ) 777   615   3   ( 7 ) 611  
Receivables (payables), net 2   —  —  2   5   —  —  5  
NDT Funds $ 1,176   $ 746   $ ( 22 ) $ 1,900   $ 1,132   $ 654   $ ( 62 ) $ 1,724  

See Note 11 for additional information on the NDT fair value. There were no available-for-sale debt securities with credit losses as of December 31, 2025 (Successor) and 2024 (Successor).
As of December 31, 2025 (Successor), there was no intent to sell available-for-sale debt securities with unrealized losses, and it is not more likely than not that each of these investments will be required to be sold before the recovery of its amortized cost. The aggregate fair value of available-for-sale debt securities with unrealized losses as of December 31, 2025 (Successor) was:

Fair Value Unrealized Losses
Corporate debt securities $ 76   $ ( 1 )
Municipal debt securities 50   ( 1 )
U.S. Government debt securities 113   ( 1 )
Debt securities in unrealized loss position $ 239   $ ( 3 )

As of December 31, 2025 (Successor), the aggregate fair value of debt securities in a loss position for a duration of one year or longer were $ 101 million and the unrealized losses were non-material.
The contractual maturities for available-for-sale debt securities presented on the Consolidated Balance Sheets were:

Successor
December 31,
2025 December 31,
2024
Maturities within one year $ 23   $ 82  
Maturities within two to five years 233   220  
Maturities thereafter 521   309  
Debt securities, fair value $ 777   $ 611  

The sales proceeds, gains, and losses for available-for-sale debt securities for the periods were:

Successor Predecessor
Year Ended December 31, 2025 Year Ended December 31, 2024 May 18 through December 31, 2023 January 1 through May 17, 2023
Sales proceeds of NDT funds investments (a)
$ 1,689   $ 2,132   $ 1,259   $ 839  
Gross realized gains 10   12   5   7  
Gross realized losses ( 6 ) ( 13 ) ( 11 ) ( 12 )

__________________
(a) Sales proceeds are used to pay income taxes and trust management fees. Remaining proceeds are reinvested in the NDT.
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The net unrealized gains and losses recognized associated with equity securities still held at the end of the reporting periods were:

Successor Predecessor
Year Ended December 31, 2025 Year Ended December 31, 2024 May 18 through December 31, 2023 January 1 through May 17, 2023
Equity securities, unrealized gains (losses) $ 123   $ 74   $ 83   $ 23  

7. Property, Plant and Equipment

Successor
December 31, 2025 December 31, 2024
Estimated Useful Life (years) Gross Value Accumulated Depreciation Carrying Value Gross Value Accumulated Depreciation Carrying Value
Electric generation 3 - 37
$ 7,522   $ ( 481 ) $ 7,041   $ 3,030   $ ( 292 ) $ 2,738  
Nuclear fuel 1 - 6
403   ( 213 ) 190   322   ( 152 ) 170  
Other property and equipment 3 - 24
63   ( 11 ) 52   90   ( 18 ) 72  

Capitalized software 1 - 5
10   ( 5 ) 5   8   ( 3 ) 5  
Construction work in progress 258   —  258   169   —  169  
Property, plant and equipment, net $ 8,256   $ ( 710 ) $ 7,546   $ 3,619   $ ( 465 ) $ 3,154  

The components of “Depreciation, amortization and accretion ” presented on the Consolidated Statements of Operations for the periods were: 

Successor Predecessor
Year Ended December 31, 2025 Year Ended December 31, 2024 May 18 through December 31, 2023 January 1 through May 17, 2023
Depreciation expense (a)
$ 211   $ 225   $ 133   $ 173  
Amortization expense (b)
10   16   1   4  
Accretion expense (c)
58   57   31   24  
Other —   —   —   ( 1 )
Depreciation, amortization and accretion $ 279   $ 298   $ 165   $ 200  

__________________
(a) Electric generation and other property and equipment.
(b) Intangible assets and capitalized software.
(c) ARO and accrued environmental cost accretion. See Note 8 for additional information.
The cost of nuclear fuel and the amortization of nuclear fuel intangible assets are presented as “Nuclear fuel amortization” on the Consolidated Statements of Operations.
Amortization expense related to nuclear fuel contract intangible assets was non-material for the year ended December 31, 2025 (Successor), $ 33 million for the year ended December 31, 2024 (Successor), and $ 53 million for the period from May 18 through December 31, 2023 (Successor). The carrying value of nuclear fuel contract intangible assets was non-material as of December 31, 2025 (Successor) and 2024 (Successor).

Jointly Owned Facilities
Certain of Talen's subsidiaries own undivided interests in jointly owned electric generation facilities and related assets. These generation facilities and other assets are maintained and operated pursuant to their joint ownership participation and operating agreements. Under such arrangements, each participant is responsible for funding its proportionate share of costs and is entitled to its proportionate share of electric generation and (or) other attributes of the relevant jointly owned facilities. Talen's proportionate share of revenues and expenses for its undivided interests is presented within the Consolidated Statements of Operations.
Talen owns undivided interest of 90 % in Susquehanna, 22.22 % in Conemaugh, and 12.34 % in Keystone. See below for information regarding the ownership of Colstrip in Montana. The carrying values of Colstrip, Conemaugh, and Keystone were non-material as of December 31, 2025 (Successor) and 2024 (Successor) .
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The proportionate share of “Property, plant and equipment, net” related to Susquehanna presented on the Consolidated Balance Sheets was:

Successor
December 31, 2025 December 31, 2024
Ownership interest 90 % 90 %

Electric generation $ 2,241   $ 2,206  
Nuclear fuel 403   322  
Other property and equipment 28   25  
Capitalized software 3   2  

Construction work in progress 114   109  
Proportionate property, plant and equipment, cost 2,789   2,664  
Less: accumulated depreciation and amortization 494   326  
Proportionate property, plant and equipment, net $ 2,295   $ 2,338  

Talen Montana. Talen Montana owns 30 % of Colstrip Unit 3 and does not own any portion of Colstrip Unit 4. However, it is a participant in a joint-owner sharing agreement which governs each party’s responsibilities and rights whereby Talen Montana is responsible for 15 % of the total operating costs and expenditures of Colstrip Unit 3 and 15 % of Colstrip Unit 4. Accordingly, it is entitled to 15 % of the available generation from each of these units. In January 2020, Talen Montana and the other co-owner of Colstrip Units 1 and 2 permanently retired the units. Talen Montana is responsible for 50 % of the decommissioning and other related costs of Colstrip Units 1 and 2.

Equity Method Investments
Talen holds equity interests in Conemaugh Fuels and Keystone Fuels equal to its respective undivided ownership interests in Conemaugh and Keystone. Conemaugh Fuels and Keystone Fuels were formed to purchase coal and sell it to Conemaugh and Keystone. Additionally, they may sell coal to any entity that manufactures or produces synthetic fuel from coal for resale to Conemaugh and Keystone. The aggregate affiliated fuel purchases by Talen from Conemaugh Fuels and Keystone Fuels is presented as “Fuel and energy purchases” on the Consolidated Statements of Operations. Talen’s aggregate fuel purchases for Conemaugh and Keystone Fuels were $ 48 million for the year ended December 31, 2025 (Successor), $ 35 million for the year ended December 31, 2024 (Successor), $ 23 million for the period from May 18 through December 31, 2023 (Successor) and $ 14 million for the period from January 1 through May 17, 2023 (Predecessor).

Nautilus Derecognition
In connection with the revisions to the AWS PPA (i) in June 2025, the Company agreed to cease use of the Nautilus facility, and (ii) in September 2025, the facility lease between the Company and AWS, and the related submetering and supply agreements, were terminated and AWS took possession of the existing facility structures. Accordingly, during the year ended December 31, 2025 (Successor), the Company derecognized approximately: (i) $ 15 million of structures and buildings presented as “Property, plant and equipment, net;” (ii) an aggregate $ 44 million of contract intangible assets and lease right-of-use assets presented as “Other noncurrent assets;” (iii) $ 10 million of lease liabilities presented as “Other current liabilities;” and (iv) an aggregate $ 57 million contractual obligations and lease obligations presented as “Other noncurrent liabilities.” The resulting net gain of $ 8 million is presented as “Other operating income (expense), net” on the Consolidated Statements of Operations.

Brandon Shores Impairment
Brandon Shores Asset Group. In the first quarter 2023, Talen canceled its plan to convert Brandon Shores to an oil combustion facility due to an increase in expected conversion costs. This decision triggered a recoverability assessment of the carrying value of the Brandon Shores asset group.
The recoverability analysis indicated that the Brandon Shores asset group carrying value exceeded its future estimated undiscounted cash flows, which required an impairment charge to amend the asset group’s carrying value of its PP&E to its estimated fair value. The estimated fair value of the asset group was determined by a discounted cash flow technique that utilized significant unobservable inputs including an 11 % discount rate. We believe that the utilized discount rate and other discounted cash flow assumptions are consistent with those used by principal market participants. Such assumptions consider available evidence regarding the prospects of future cash flows for the Brandon Shores asset group, including but not limited to estimated available future generation volumes and useful lives, capacity prices, energy prices, operating costs, capital expenditures, and environmental costs. Accordingly, for the period from January 1 through May 17, 2023 (Predecessor), a $ 361 million non-cash pre-tax impairment charge on the asset group’s undepreciated PP&E is presented as “Impairments” on the Consolidated Statements of Operations.
In May 2025, Brandon Shores and H.A. Wagner consummated RMR agreements which requires the facilities to operate until certain third-party transmission upgrades are placed into service. See Note 3 for additional information on the Brandon Shores and H.A. Wagner RMR agreements.
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8. Asset Retirement Obligations and Accrued Environmental Costs
Certain subsidiaries of the Company have legal retirement obligations for the decommissioning and environmental remediation costs associated with our current and former generation. Most of these obligations, except remediation of some ash impoundments, are not expected to be paid until several years, or decades, in the future. The Company’s most significant obligations are associated with the: (i) decommissioning of Susquehanna, which the NDT is expected to fund; and (ii) coal ash disposal units of legacy coal-fired generation facilities which, for certain obligations, the Company has posted surety bonds (some of which have been collateralized with LCs). The carrying value of these AROs include assumptions of estimated future retirement and remediation cash expenditures, cost escalation rates, probabilistic cash flow models, and discount rates.
The Company may be required to revise or recognize new AROs as a result of regulatory changes by the NRC, EPA, Montana Department of Environmental Quality (the “MDEQ”) or other regulatory entities. Additionally, revisions may result from scope of work amendments to remediation activities as well as changes to remediation costs and other assumptions. If the assumptions underlying any ARO estimates do not materialize as expected, actual cash expenditures and costs could be materially different than currently estimated.

Successor

December 31,
2025 December 31,
2024
Asset retirement obligations $ 514   $ 498  
Accrued environmental costs 20   21  
Total asset retirement obligations and accrued environmental costs 534   519  
Less: asset retirement obligations and accrued environmental costs due within one year (a)
40   51  

Asset retirement obligations and accrued environmental costs due after one year $ 494   $ 468  

__________________
(a) Presented as “Other current liabilities” on the Consolidated Balance Sheets.
The changes of the ARO carrying value during the period were:

Successor
2025 2024
Carrying value January 1, $ 498   $ 464  

Obligations settled ( 27 ) ( 13 )
Accretion expense 56   55  
Changes in estimates and (or) settlement dates ( 13 ) ( 17 )
Obligations incurred —   9  
Carrying value, December 31, $ 514   $ 498  

The disaggregation of ARO carrying values on the Consolidated Balance Sheets was:

Successor

December 31,
2025 December 31,
2024

Nuclear (a)
$ 272   $ 242  
Non-nuclear (b)
242   256  
Carrying value $ 514   $ 498  

__________________
(a) Obligations are expected to be settled with available funds in the NDT at the time of decommissioning. See Note 6 for additional information on the NDT.
(b) Certain obligations are: (i) partially supported by surety bonds, some of which have been collateralized with LCs; or (ii) partially prefunded under phased installment agreements.

Nuclear AROs
Each joint owner of Susquehanna is obligated to fund their proportionate share of Susquehanna's ARO. Talen’s proportionate share of decommissioning activities will be funded from the NDT when decommissioning commences in connection with the expiration of Susquehanna’s licenses. The licenses for Susquehanna Unit 1 and Unit 2 expire in 2042 and 2044, respectively, and can be extended subject to NRC approval. The NRC has jurisdiction over the decommissioning of nuclear power generation facilities and requires minimum decommissioning funding based upon a formula. Under the most recent calculation in 2024, the NDT exceeds the NRC's minimum funding requirements. Each joint owner of Susquehanna is obligated to fund their proportionate decommissioning costs if their respective nuclear decommissioning trusts do not contain sufficient funds. We believe the NDT will be adequate to fund the Company’s proportionate share of decommissioning costs. As of December 31, 2025 (Successor), the fair value of the NDT was $ 1.9 billion and the carrying value the Company’s proportionate share of the Susquehanna ARO, which is discounted under a present value technique, was $ 272 million. See Note 1 for additional information on the measurement of AROs.
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Non-nuclear AROs
Non-nuclear AROs are primarily comprised of remediation activities associated with legacy coal-fired generation facilities, particularly Colstrip, Brunner Island, and Montour and includes activities, among others, such as remediation of coal piles, wastewater basins, and ash impoundments and structure removal.
Talen Montana. Talen Montana’s has significant AROs associated with its proportionate share of remediation, closure and decommissioning costs for coal ash impoundments at Colstrip. Due to the expected timing and scope of anticipated remediation activities, actual cash expenditures associated with these obligations are expected to be material over the next several years and then at a reduced spending level for several decades. Talen Montana, along with the other co-owners of Colstrip, periodically work with the MDEQ to update the scope of required remediation, the scope of closure and decommissioning activities, and the associated estimate of the costs, including the amount of necessary financial assurance necessary to backstop these obligations. Talen Montana's decommissioning and environmental remediation is expected to be paid by funds available to Talen Montana at the time of decommissioning.
Future adjustments may be required to the Talen Montana ARO estimates due to the ongoing remediation requirements under MDEQ obligations and the EPA CCR Rule. See Note 9 for information on Talen Montana’s requirement to provide financial assurance for certain environmental decommissioning and remediation liabilities related to Colstrip. Talen Montana's estimate of its proportionate share of the AROs, discounted using a credit adjusted risk-free rate, was $ 90 million and $ 98 million as of December 31, 2025 (Successor) and 2024 (Successor), respectively.
Conditional AROs . As of December 31, 2025 (Successor), the fair values of certain AROs as a result of the EPA CCR Rule cannot be determined. See Note 9 for additional information on the EPA CCR Rule and the regulatory timeline that is expected to determine the associated scope of work.
Certain subsidiaries of the Company have legal retirement obligations associated with the removal, disposal, and (or) monitoring of asbestos-containing material at certain generation facilities. Given that the ultimate volume of asbestos-containing material is not yet known, the fair value of these obligations cannot be reasonably estimated. These obligations will be recognized upon a change in economic events or other circumstances which enables the fair value to be estimable.

Accrued Environmental Costs
Under the Pennsylvania Clean Streams Law, a Talen subsidiary is obligated to remediate acid mine drainage at a former mine site and may be required to take additional steps to prevent acid mine drainage at this site. Liabilities related to the remediation were $ 20 million and $ 21 million as of December 31, 2025 (Successor) and 2024 (Successor), respectively, and were presented as “ Other current liabilities ” and “Asset retirement obligations and accrued environmental costs” on the Consolidated Balance Sheets. Such liabilities were discounted based on a credit adjusted risk-free rate that was in existence at the time of initial liability recognition of 8.4 %. The undiscounted amount of the liabilities was $ 30 million and $ 32 million as of December 31, 2025 (Successor) and 2024 (Successor), respectively.

9. Commitments and Contingencies

Legal, Regulatory, and Environmental Matters
We are regularly subject to various legal, regulatory, and environmental matters in connection with our business. While we believe we have meritorious positions and will continue to vigorously defend our positions in these matters, we may not be successful in our efforts, and we cannot predict the effect of an adverse outcome of any such matter. If an unfavorable outcome is probable and can be reasonably estimated, a liability is recognized. In the event of an unfavorable outcome, the liability may be in excess of amounts currently accrued. Because of the inherently unpredictable nature of legal, regulatory, and environmental matters and the wide range of potential outcomes for any such matter, no estimate of the possible losses in excess of amounts accrued, if any, can be made at this time regarding any matter specifically described below. As a result, additional losses actually incurred in excess of amounts accrued could be substantial. Unless otherwise disclosed below, we are unable to predict the outcome of any matter discussed below or reasonably estimate the amount of any associated costs and (or) potential liabilities. Additionally, it is possible that the outcome of any such matter, including market modifications, could materially impact our business, financial condition, results of operations, cash flows, and (or) liquidity.

Legal Matters
We are involved in various legal and administrative proceedings, investigations, claims, and litigation from time to time in the course of our business. Such matters may include, but are not limited to, those relating to employment and benefits, commercial disputes, personal injury, property damage, regulatory matters, environmental matters, and various other claims for injuries and (or) damages. While we believe we have meritorious positions and will continue to appropriately respond to all legal matters, because of the inherently unpredictable nature of legal proceedings, there is a wide range of potential outcomes for any such matter.
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Brunner Island CCR Litigation. In April 2025, the Center for Biological Diversity (the “CBD”) filed a citizen suit in the U.S. District Court for the Middle District of Pennsylvania alleging that the Company and its subsidiary, Brunner Island, LLC, have failed to comply with groundwater monitoring and corrective action requirements at Brunner Island’s Ash Basin 5 and have therefore violated the RCRA and the EPA CCR Rule. The complaint seeks declaratory and injunctive relief. Talen believes the alleged claims are without merit and that the CBD’s factual and legal conclusions are incorrect. Talen filed a motion to dismiss the lawsuit which was followed by an amicus brief from the Utility Solid Waste Activities Group in support of Talen’s motion; briefing on the motion to dismiss was completed on June 30, 2025. No assurance can be provided as to the outcome of the litigation or its impacts on Talen’s operations.
ERCOT Weather Event (Winter Storm Uri) Lawsuits. In connection with the ERCOT Sale, the Company retained certain potential liabilities relating to claims filed from 2021 onward against its former Texas subsidiaries seeking unspecified damages for alleged losses caused by the defendants’ failure to provide sufficient power to the grid during Winter Storm Uri. The claims also allege similar liability against numerous other ERCOT power market participants. In December 2023, five multi-district litigation (“MDL”) bellwether lawsuits, which were selected by the MDL court as representative of all 58 cases filed in the Uri litigation, were dismissed by the MDL court, a ruling subsequently upheld by the Texas First Court of Appeals. In January and February 2025, the plaintiffs (in two groups) filed for relief in the Texas Supreme Court, seeking to overturn the lower courts. In July 2025, the Texas Supreme Court ordered merits briefing by the parties, which has since concluded. If the Court of Appeals decision is affirmed by the Texas Supreme Court, Talen expects the dismissal ruling to apply broadly to all Uri cases against Talen’s former subsidiaries. Pursuant to the Plan of Reorganization, Talen’s maximum potential damages on prepetition Uri claims are expressly limited to payments from Talen’s insurers. However, claims filed after Talen’s restructuring by plaintiffs who did not receive effective notice of the restructuring, if any, may not be subject to the limitations in the Plan of Reorganization. Talen cannot predict the effect of an adverse outcome for any such claims.
Spent Nuclear Fuel Litigation. Federal law requires the U.S. government to provide for the permanent disposal of commercial spent nuclear fuel (“SNF”), but the government has not yet done so. Until May 2014, the DOE required nuclear generation facility operators to contribute to a fund intended to pay for the transportation and disposal of SNF, and Talen cannot predict if or when the government will reinstate any such fee in the future. In May 2023, an existing settlement agreement between Susquehanna and the U.S. government was extended through the end of 2025. The settlement agreement requires the government to reimburse Susquehanna for certain SNF storage costs through 2025 and requires Susquehanna to waive certain claims against the government relating to temporary SNF storage. In July 2025, the Company reached an agreement with the DOE for a reimbursement of $ 14 million (reflecting Talen’s 90 % share) related to the 2023-2024 period and received the reimbursement in August 2025.

Regulatory Matters
We are subject to regulation by federal and state agencies and other bodies that exercise regulatory authority in the various regions where we conduct business, including but not limited to the FERC; the DOE; the NRC; NERC; the Federal Communications Commission; and state public utility commissions. In addition, the RTOs and ISOs in the regions in which we conduct business inherently have complex rules that are intended to balance the interests of market stakeholders. Proposed market structure modifications may lead to disputes among stakeholders that might not be resolved for a period of time as a result of regulatory and (or) legal proceedings. Accordingly, we are subject to uncertainty with respect to: (i) new or amended regulations issued by regulatory agencies; and (ii) changes in market design, tariff structure, capacity auctions, and (or) pricing rules.
PJM Capacity Market Reform. In June 2023, the FERC accepted a request by PJM to delay certain PJM Base Residual Auctions in order for PJM to propose market reforms. PJM filed its market reform proposals with the FERC in October 2023. In early 2024, the FERC accepted portions of PJM’s proposed market changes and PJM scheduled certain PJM BRAs on a delayed basis. In September 2024, the Sierra Club and other organizations filed a complaint at the FERC challenging PJM’s rules establishing must-offer exceptions for PJM BRA participation by RMR resources. In October 2024, PJM announced it had concerns about the FERC considering the Sierra Club’s complaints about RMR resources in isolation and therefore intended to file a Section 205 proceeding under the Federal Power Act seeking the FERC’s approval of to-be-determined market reforms, including but not limited to potential revisions to the treatm ent of RMR resources. As a result, in October 2024, PJM formally requested, which the FERC approved, six-month delays to the scheduled PJM BRAs for the 2028/2029, and 2029/2030 PJM Capacity Years to June 2026, and December 2026, respectively. Currently, the auction for the 2030/2031 PJM Capacity Year in May 2027 is scheduled on a non-delayed basis. Talen can provide no assurance that these or any scheduled PJM BRAs will be held on such dates or at all.
A series of filings aimed at reforming the PJM capacity market were filed at the FERC. In November 2024, the Joint Consumer Advocates, comprised of consumer advocacy groups and government entities from Illinois, Maryland, New Jersey, Ohio, and the District of Columbia filed a complaint against PJM asking the FERC to find that PJM’s existing capacity market rules are unjust and unreasonable and to issue an order requiring certain short-term and longer-term changes to PJM’s capacity market rules.
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In response, PJM made two FERC filings in December 2024 to address what they perceive as capacity market design issues (the “PJM Capacity Market 205 Proceeding”). PJM proposed to retain the dual fuel combustion turbine as the reference resource and to implement a uniform non-performance charge throughout the RTO for the 2026/2027 and 2027/2028 PJM Capacity Years, and to administratively include RMR units that meet certain criteria as price takers in the capacity auctions for the next two delivery years and will not assess penalties or pay bonuses to these RMR units. PJM’s filing also clarifies that being excused from being required to offer into the capacity market is no defense to exercising market power by electing not to offer. Further, PJM proposed to make changes to the capacity market mitigation rules. This proposal will eliminate the must-offer exception for intermittent and limited duration resources that are eligible to participate in the capacity market and will allow market sellers to incorporate a risk component in their capacity market offers. In February 2025, the FERC accepted PJM’s proposals in the PJM Capacity Market 205 Proceeding and as a result, the changes to the PJM BRA parameters described above as part of that proceeding were adopted for the 2026/2027 and 2027/2028 PJM Capacity Years.
In December 2024, the Pennsylvania Governor filed a complaint against PJM at the FERC to address alleged elevated costs to consumers from the PJM capacity market in the 2026/2027 and 2027/2028 PJM Capacity Years and proposed, among other things, a lower capacity price cap. As a result of a subsequent agreement between the State of Pennsylvania and PJM that resolved the Governor’s complaint, the Governor withdrew the complaint in February 2025. In April 2025, the FERC accepted PJM’s proposals reflecting its agreement with the Com monwealth of Pennsylvania. As a result, the PJM BRA imposed a price collar with an approximate minimum and maximum price of $ 175 /MWd and $ 325 /MWd, respectively, which was effective for the 2026/2027 PJM BRA in July 2025 and for the 2027/2028 PJM BRA in December 2025. It is uncertain whether price collars will be in effect for future PJM BRAs.
In February 2025, the FERC initiated a technical conference docket to consider broad resource adequacy issues across all RTOs, with the initial proceedings taking place in June 2025. The Company has intervened in the new technical conference docket and is closely monitoring those proceedings.
Interconnection of Large Loads. In October 2025, DOE directed the FERC to consider reforms to expedite and facilitate how large loads interconnect to the interstate transmission system. DOE stated that the Federal Power Act permits the FERC to exert jurisdiction over load interconnections even though it has not historically done so. DOE provided a draft advance notice of proposed rulemaking (“ANOPR”) and directed the FERC to initiate rulemaking procedures. In November 2025, the FERC requested public comment on the ANOPR, and the Company provided comments. DOE directed the FERC to take final action by the end of April 2026.
In August 2025, PJM began an accelerated process known as a Critical Issue Fast Path (“CIFP”) process with stakeholders to address how to integrate large load customers quickly and reliably. The CIFP stakeholders represented a wide range of views about resource allocations, costs, and how the addition of large loads like data centers to PJM should be managed in the context of the capacity market. The Company was an active participant in the CIFP process and submitted a joint proposal amongst itself, Constellation, Calpine, Amazon, Microsoft, and Google representing the group’s collective views on the best approach to large load additions. Neither the joint proposal nor any of the other proposals submitted received broad stakeholder support during voting. Nevertheless, PJM had planned to make a filing at the FERC in January 2026 containing PJM’s ultimate proposal to be in place for the 2028/2029 PJM BRA.
In December 2025, however, the FERC issued an order in a show cause proceeding on large loads co-located with generation. The FERC directed PJM to submit an informational report containing, among other items, all of the CIFP proposals. The FERC also found that the PJM tariff was unjust and unreasonable as to the interconnection of co-located loads. The FERC requested tariff revisions be submitted over the next 30-60 days and established a hearing schedule, which begins in February 2026, to establish rates, terms, and conditions of several new transmission services.
In January 2026, the National Energy Dominance Council (“NEDC”) and the Governors from each of the 13 states in PJM issued a “Statement of Principles” for PJM. Among other things, the statement calls for PJM to conduct a reliability backstop auction for new baseload capacity with 15-year contracts by September 2026. It also urges PJM to extend the existing price collar for the next two BRAs. Hours after the NEDC/Governors’ principles were released, the PJM Board of Managers issued a Board Decisional Letter — the final step in the Large Load Addition CIFP process. The Board’s Decisional Letter adopted specific elements of various proposals, including load forecasting improvements, voluntary bring your own generation paired with an expedited interconnection track, a holistic review in the coming year of investment incentives in PJM’s markets, and immediate initiation of a reliability backstop procurement. PJM also requested feedback on an extension of the price collar for the next two BRAs.
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Environmental Matters
Extensive federal, state, and local environmental laws and regulations are applicable to our business, including those related to air emissions, water discharges, hazardous substances, and solid waste management. From time to time, in the ordinary course of our business, Talen may be: (i) subject to environmental remediation work at its facilities; (ii) involved in other environmental matters; or (iii) become subject to other, new or revised environmental statutes, regulations, or requirements. It may be necessary for us to modify, curtail, replace, or cease operation of certain facilities or performance of certain operations to comply with statutes, regulations, and other requirements imposed by regulatory bodies, courts, or environmental groups. We may incur significant costs to comply with these requirements, including increased capital expenditures or operation and maintenance expenses, monetary fines, remediation costs, penalties, or other restrictions. Legal challenges to environmental rules or permits add to the uncertainty of estimating future compliance costs. In addition, in January 2025, President Trump issued executive orders directing the heads of all federal agencies to identify and begin the processes to suspend, revise, or rescind all agency actions, including existing regulations, that are unduly burdensome on the identification, development, or use of domestic energy resources. Consequently, in March 2025, the EPA announced that it will reconsider and potentially roll back 31 regulations and policies, many of which directly impact Talen, and various executive actions were taken in April 2025 to further encourage deregulation. The EPA’s reconsiderations for many of these regulations and policies remain ongoing, and certain executive orders have subsequently been challenged by states and individual plaintiffs. Future provisions, implementation, and enforcement of these executive actions and the environmental rules continue to be uncertain. Further, costs may increase significantly if the requirements or scope of environmental laws or regulations, or similar rules, are expanded or changed in other ways.
EPA CSAPR and Nitrogen Oxides (“NOx”) Requirements. Coal-fired generation facilities, including those in which Talen has ownership, have been the subject of EPA regulations and efforts by certain states and other parties to strengthen applicable NOx emission limits under the Clean Air Act. In 2015, the EPA revised the 8-hour ozone National Ambient Air Quality Standards for ground-level ozone to 70 parts per billion (the “EPA 2015 Ozone Standard”). This action triggered updates to state-specific compliance requirements as well as provisions that are intended to limit cross-state emissions. In June 2023, the EPA published a rule in connection with the EPA 2015 Ozone Standard updating the EPA CSAPR ozone season NOx allowance trading program for 2023 and beyond (the “Good Neighbor Plan”). Talen’s facilities in Maryland, Pennsylvania, and New Jersey were subject to the new rule; however, the entire rule was challenged by multiple parties, and subsequently the Good Neighbor Plan was stayed in its entirety by the U.S. Supreme Court in June 2024 pending a complete review of the rule by the D.C. Circuit Court of Appeals. In November 2024, the EPA issued an interim final rule indicating it plans to provide NOx allocations and budgets from the previously applicable and less restrictive Revised CSAPR Update Rule until the Good Neighbor Plan matter is resolved. After initially denying the EPA’s request in February 2025, the D.C. Circuit Court of Appeals in April 2025, granted the EPA’s motion requesting the Good Neighbor Plan litigation be held in abeyance pending the EPA’s review of the stayed rule and further orders by the court. As a result, future implementation and enforcement of the Good Neighbor Plan has continued to be uncertain.
In January 2026, the EPA proposed Phase 1 of its reconsideration of the Good Neighbor Plan. In its proposal, the EPA proposes to approve state implementation plan submissions governing interstate emissions from eight states (Alabama, Arizona, Kentucky, Minnesota, Mississippi, Nevada, New Mexico, and Tennessee). If finalized, these states would no longer be subject to Good Neighbor Plan requirements. Although Talen does not operate in any of the states identified in the proposed rule, EPA in its proposal states that it intends to undertake a separate action to address interstate transport obligations for the remaining states covered under the Good Neighbor Plan.

EPA MATS Rule. In May 2024, the EPA published a rule that requires coal-fired generation facilities to reduce particulate matter emissions by the middle of 2027 (or 2028, if an extension is approved) (the “2024 EPA MATS Rule”). In February 2026, however, the EPA issued a subsequent final rule repealing the lower particulate matter standards set in the 2024 amendments and reverting to particulate matter standards promulgated in the 2012 EPA MATS Rule (the “MATS Repeal Rule”). Challenges to the 2024 EPA MATS Rule were filed in the D.C. Circuit Court of Appeals, including by Talen and 23 states. The appeal on the merits of the 2024 rule remains pending in the D.C. Circuit Court of Appeals, but the litigation has been held in abeyance since February 2025, while the EPA reconsidered the rule. As a result of the EPA’s MATS Repeal Rule, the litigation over the 2024 EPA MATS Rule will likely be deemed moot. However, challenges to the MATS Repeal Rule are expected. No assurance can be provided as to whether the MATS Repeal Rule will survive judicial challenge and when such challenges will be resolved. Colstrip was not expected to meet the 2024 particulate matter standard without substantial upgrades to its control equipment. As a result, if the MATS Repeal Rule is vacated by a court or reconsidered by the EPA in the future, Talen Montana and the other Colstrip co-owners will face the decision either to invest in new cost-prohibitive control equipment or retire the Colstrip facility. Such a decision must be evaluated in conjunction with other compliance requirements.
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In March 2025, the EPA formally announced that it was reconsidering the 2024 EPA MATS Rule as part of its deregulation agenda. Concurrently, the Trump administration announced it was considering a two-year exemption from compliance obligations via Section 112(i)(4) of the Clean Air Act for affected power plants while the EPA reconsidered the rule. Talen applied for the exemption, which was granted in April 2025. This authorization affords more time for the Colstrip owners to consider the operational future of Colstrip. Environmental groups filed separate lawsuits in the D.C. Circuit Court of Appeals and the U.S. District Court for D.C., challenging the presidential exemptions issued to Colstrip and other fossil fuel-fired power plants. On August 5, 2025, the EPA filed a motion in each case requesting the courts hold the litigation in abeyance for six months pending the EPA’s efforts to repeal the 2024 EPA MATS Rule. Talen filed motions to intervene in both cases on August 8, 2025. On September 3, 2025, the U.S. District Court for D.C. granted the EPA’s motion to hold the case in abeyance for six months and also granted Talen’s motion to intervene. Plaintiffs filed a motion asking the court to reconsider its decision to hold the case in abeyance. The U.S. District Court for D.C. denied that motion in November 2025. The D.C. Circuit Court of Appeals granted the EPA’s motion for an abeyance and Talen’s motion to intervene in October 2025. The litigation may be deemed moot as a result of the EPA’s MATS Repeal Rule, but no assurance can be provided as to the outcome of this litigation at this time. The Company could be forced to make operating decisions about the future of Colstrip before clarity is obtained on legal challenges regarding the MATS Repeal Rule and the presidential exemption litigation.
EPA GHG Rule. In May 2024, the EPA published a rule that establishes carbon dioxide limits for new electric generating units (“EGUs”) and greenhouse gas (“GHG”) guidelines for certain existing EGUs. Under the guidelines, if existing coal-fired EGUs operate beyond 2031, GHG reductions, such as those achieved by the addition of carbon capture and sequestration (“CCS”), are required to be implemented by the end of 2031. Colstrip is not expected to meet the new rules without substantial technology upgrades and pipeline infrastructure build-out. As a result, Talen Montana and the other Colstrip co-owners face the decision either to invest in new cost-prohibitive controls (e.g., CCS technology) or retire the Colstrip facility by the end of 2031. Such a decision must be evaluated in conjunction with compliance requirements under the May 2024 EPA MATS Rule. Petitions have been filed in the D.C. Circuit Court of Appeals, including by coalitions representing 27 states and an ad hoc coalition of power producers of which Talen is a member, requesting a review of the EPA GHG Rule. Stay motions were denied by the D.C. Circuit Court of Appeals in July 2024 and the U.S. Supreme Court in October 2024. Appeals of the EPA GHG Rule remain pending in the D.C. Circuit Court of Appeals.
The D.C. Circuit Court of Appeals has held the litigation in abeyance since February 2025 to allow the EPA to reconsider the rule. No assurance can be provided as to when the challenges to the EPA GHG Rule will be resolved or whether such challenges will be resolved in the Company’s favor. In June 2025, the EPA released a proposed rule to repeal all GHG emission standards for fossil fuel-fired power plants. As an alternative, the EPA is proposing a narrow repeal of GHG standards, which would eliminate all emissions guidelines and standards for existing power plants and the Phase 2 GHG emissions standards that would apply to new combustion turbines beginning in 2032. Under the alternative proposal, Phase 1 GHG emissions standards applicable to new and reconstructed baseload fossil fuel-fired stationary combustion turbines would be retained. The public comment period on the proposal expired on August 7, 2025. No assurance can be provided as to whether the rule will be finalized and whether a final rule will survive judicial challenge. The EPA has also in the past stated its intent to develop GHG regulations for existing natural gas combustion turbines; however, no rule has been proposed, and no recent statements have been made. Operating decisions about the future of Colstrip are highly dependent on the fate of the EPA GHG Rule as well as the EPA MATS Rule. Given the legal and regulatory uncertainties with both rules, it is possible the Company will be required to make decisions about Colstrip’s future before it has clarity about the outcome of litigation and (or) the EPA’s regulations.
GHG Endangerment Finding. In February 2026, the EPA issued a final rule rescinding its 2009 finding that GHG emissions endanger public health and welfare and repealing all GHG emissions standards for light-, medium-, and heavy-duty vehicles and engines. The EPA made the 2009 endangerment finding in order to promulgate GHG emission standards for new motor vehicles under Section 202(a) of the Clean Air Act and has subsequently relied on this finding as a basis to regulate other sources of GHGs. In the final rule, EPA states it must rescind the endangerment finding because it lacks the statutory authority to regulate GHG emissions from vehicles in response to global climate changes concerns. The EPA does not explicitly state how the rescission impacts its authority to regulate GHG emissions from stationary sources. However, the final rule acknowledges that EPA has relied on the endangerment finding “to extend the GHG regulatory program to new and existing stationary source performance standards and guidelines for power plants under CAA section 111.” Citizen groups have challenged the final rule in the D.C. Circuit Court of Appeals. No assurance can be provided as to whether the rule will survive judicial challenge.

Pennsylvania RGGI. In October 2019, the then-Governor of Pennsylvania signed an executive order directing the Pennsylvania Department of Environmental Protection (the “PADEP”) to draft regulations establishing a cap-and-trade program with the intent of enabling Pennsylvania to join the RGGI, a multi-state regional cap-and-trade program comprised of several Eastern U.S. states. In April 2022, Pennsylvania entered the RGGI program, with compliance set to begin on July 1, 2022. However, in November 2023, the Commonwealth Court of Pennsylvania ruled RGGI was an invalid tax and voided the rulemaking. The PADEP appealed this decision to the Pennsylvania Supreme Court and filed notice with the court that the RGGI program would not be implemented while the appeal is pending. In July 2024, the Pennsylvania Supreme Court permitted certain non-profit environmental groups to intervene in the case. Oral argument in the case took place in May 2025. In November 2025, the Pennsylvania legislature passed a budget that included provisions requiring Pennsylvania to withdraw from RGGI. As a result, the PADEP filed an application to the Pennsylvania Supreme Court requesting to discontinue its appeal. The Pennsylvania Supreme Court granted the application and dismissed the case on January 6, 2026.
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EPA ELG Rule. In November 2015, the EPA revised the effluent limitation guidelines (“ELGs”) for certain power generation facilities, which imposed more stringent standards for wastewater streams as facility discharge permits are renewed. In 2020, the EPA issued changes that would exempt coal generation facility operators from meeting certain wastewater standards if the facility would commit to cease coal-fired generation by the end of 2028, which Talen elected for its wholly owned coal operations. In May 2024, the EPA published revisions to the EPA ELG Rule, which imposed additional requirements for legacy wastewater and combustion residual leachate. These revisions impact Talen’s active generation facilities that have both CCR units and hold National Pollutant Discharge Elimination System (“NPDES”) discharge permits. These sites include Brandon Shores, Brunner Island, Montour, and potentially Martins Creek. Talen is evaluating what: (i) potential discharge limits may apply; (ii) treatment may be required; and (iii) the implementation timeline may be. Obligations for installing any new wastewater treatment equipment, if necessary, will not be known until each applicable state where the active generation facilities operate makes its own determination with respect to NPDES permit renewals with new limits and associated timing. As a result of the future permit conditions, additional capital expenditures and (or) AROs may be required, which may have a material impact on Talen’s operations and (or) financial condition.
Multiple challenges, including stay requests, to the EPA ELG Rule have been filed in various U.S. Courts of Appeal by parties that include 15 states, environmental groups, and industry groups, including the Utility Water Act Group (“UWAG”), of which Talen is a member. The appeals have been consolidated in the U.S. Court of Appeals for the Eighth Circuit, which denied requests to stay the rule in October 2024 . At the EPA’s request, the Eighth Circuit has held the consolidated challenges in abeyance since February 2025 to allow the EPA to reconsider the rule. In March 2025, the EPA announced that it will revise the EPA ELG Rule as part of its deregulation agenda while considering immediate relief from some of the existing leachate requirements. In June 2025, the EPA announced that it will issue a proposal in 2025 to extend compliance deadlines under the 2024 EPA ELG Rule and seek information to potentially inform further rulemaking. In September 2025, the EPA issued a direct final rule extending a short-term deadline and a companion proposal extending many compliance deadlines for the 2024 EPA ELG Rule and providing some flexibility relating to some deadlines in the 2020 ELG Rule. In November 2025, the EPA issued a notice withdrawing the direct final rule due to the receipt of adverse comments. The EPA finalized its proposal in December 2025. Among other things, the final rule extends zero-discharge compliance deadlines established in the 2024 EPA ELG Rule by five years from December 31, 2029 to December 31, 2034. The extension rule has been legally challenged by environmental groups. These challenges have been consolidated in the U.S. Court of Appeals for the Second Circuit. UWAG has filed a motion to intervene in the consolidated litigation. In the final rule, the EPA also stated it is considering further rulemaking to revise the regulatory standards in the 2024 EPA ELG Rule. No assurance can be provided as to whether the EPA’s final rule will be challenged, when the challenges to the EPA ELG Rule merits will be resolved, or whether such changes and challenges will be resolved in the Company’s favor.
EPA CCR Rule. In April 2015, the EPA established regulations under the RCRA to identify CCRs as nonhazardous solid waste and provided CCR management and siting requirements. The 2015 rule was modified in 2020 after a 2018 D.C. Circuit Court of Appeals ruling found that, among other things, the EPA did not adequately regulate unlined impoundments. In its 2020 rulemaking, the EPA specified procedures for owners to extend the operating timeline of certain unlined impoundments. Talen submitted an extension request under this process for an unlined impoundment at Montour, which was withdrawn in December 2024, following the end of basin operations and the initiation of basin closure. The 2018 D.C. Circuit Court of Appeals ruling also found that the EPA did not properly address legacy surface impoundments in the 2015 CCR rule. As a result of the finding, in May 2024, the EPA finalized additional federal CCR regulations effective in November 2024 (the “Legacy CCR Rule”), which provided new requirements for legacy CCR surface impoundments and new requirements for other CCR disposal and management areas at active power plants (“CCR Management Units” or “CCRMUs”). This rule has been challenged in the D.C. Circuit Court of Appeals by multiple parties, including two industry groups of which Talen is a member. In December 2024, the U.S. Supreme Court denied a requested stay of the Legacy CCR Rule. At the EPA’s request, the D.C. Circuit Court of Appeals has held the case in abeyance since February 2025 to allow the EPA to reconsider the rule. Additionally, the EPA is being challenged by other industry parties on new regulatory interpretations that could be consequential to CCR unit closure practices and costs.
In March 2025, the EPA announced that it will prioritize the coal ash program by expediting state permit reviews. The EPA has also announced it will reform the federal CCR Rule and provided in the Legacy CCR Rule litigation proceeding that CCR Rule reforms will be completed in 2026. As an initial reform step, in February 2026, the EPA issued a final rule extending compliance deadlines for elements in the Legacy CCR Rule, including required applicability assessments, the initiation of new groundwater monitoring detection, and the initiation of unit closure. No assurance can be provided as to when and how federal CCR regulations will change further, when the legal challenges to the Legacy CCR Rule, how the EPA’s interpretations or further CCR Rule reforms will be resolved, or whether such challenges will be decided in the Company’s favor.
Talen continues to review the Legacy CCR Rule provisions that went into effect in 2024, perform the required applicability assessments, and await additional CCR Rule reforms. As a result of the EPA’s February 2026 CCRMU Extension Rule, initial facility evaluation reports to identify CCR areas which may become regulated and subject to the rule’s requirements are now due in February 2027. Following that, site investigation may be required to further investigate applicability, and a subsequent facility report is due in February 2028. The Company has initiated reviews under the facility evaluation report requirements at locations with ash impoundments that have long since ceased coal operations as well as at locations with current coal operations to meet these deadlines. No assurance can be provided as to whether any specific ash impoundments owned by the Company may or may not be within scope of the updated Legacy CCR Rule until the Company completes its assessments within the regulatory timeframe.
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As of December 31, 2025 (Successor), the Company has recognized cost estimates in complying with the Legacy CCR Rule’s initial compliance requirements and deadlines, including the initial groundwater monitoring requirements. The Company does not yet have sufficient information available to estimate costs for the future compliance obligations under the rule. As the Company continues its applicability evaluations and site assessments to determine the scope of work on its properties imposed by the new rule, additional new AROs and (or) revisions could be required. It is expected estimates will be available, under the timeline provided for by the regulations, as described above, at the completion of the initial facility evaluation reports or at the completion of a subsequent site investigation. Such AROs or ARO changes could be material and, as a result, may have a material impact on Talen’s operations and (or) financial condition.
In April 2025, a citizen suit was filed in the U.S. District Court for the Middle District of Pennsylvania alleging that the Company and its subsidiary, Brunner Island, LLC, are in violation of RCRA and the EPA CCR Rule. See the “Legal Matters” section above for additional information.

Certain Resolved Matters
PPL/Talen Montana Litigation. In December 2023, a settlement was reached in litigation between Talen and PPL regarding Talen’s claim that a $ 733 million distribution paid to PPL in 2014 left Talen Montana insolvent. Under the terms of the settlement, PPL paid Talen Montana $ 115 million in exchange for a full release of claims, with $ 11 million of that amount remitted to the general unsecured creditors trust established under the Plan of Reorganization. As a result, a $ 104 million net gain is presented as “Other non-operating income (expense), net” on the Consolidated Statements of Operations for the period May 18 through December 31, 2023 (Successor) .

Guarantees and Other Assurances
In the normal course of business, the Company enters into agreements to provide financial performance assurance to third parties on behalf of certain subsidiaries. These agreements primarily support or enhance the stand-alone creditworthiness attributed to a subsidiary or facilitate the commercial activities in which these subsidiaries engage. Such agreements may include guarantees, stand-by LCs, and (or) surety bonds. Additionally, they may include customary indemnifications to third parties related to asset sales and other transactions. The probability of expected material payment and (or) performance for these assurance agreements is believed to be remote.
Surety Bonds. Surety bonds provide financial performance assurance to third parties on behalf of certain Company subsidiaries for obligations including but not limited to environmental obligations and AROs. In the event of nonperformance by the applicable subsidiary, the beneficiary would make a claim to the surety, and the Company would be required to reimburse any payment by the surety. Talen’s liability with respect to any particular surety bond is released once the obligations secured by the surety bond are performed. Surety bond providers generally have the right to request additional collateral or request that such bonds be replaced by alternate surety providers. As of December 31, 2025 (Successor) and 2024 (Successor), the aggregate amount of surety bonds outstanding was $ 228 million and $ 234 million, respectively, including surety bonds posted on behalf of Talen Montana as discussed below.
Talen Montana Financial Assurance. Pursuant to the Colstrip Administrative Order on Consent (the “Colstrip AOC”), Talen Montana, in its capacity as the Colstrip operator, is obligated to close and remediate coal ash disposal impoundments at Colstrip. The Colstrip AOC specifies an evaluation process between Talen Montana and the Montana Department of Environmental Quality (the “MDEQ”) on the scope of remediation and closure activities, requires the MDEQ to approve such scope, and requires financial assurance to be provided to the MDEQ on approved plans. Each of the co-owners of Colstrip has provided its proportionate share of financial assurance to the MDEQ for estimates of coal ash disposal impoundments remediation and closure activities approved by the MDEQ.
The aggregate amount of surety bonds posted to the MDEQ on behalf of Talen Montana’s proportionate share of such activities wa s $ 114 million and $ 125 million as of December 31, 2025 (Successor) and 2024 (Successor), respectively. Talen Montana’s surety bond requirements may increase due to scope changes, cost revisions, and (or) other factors when the MDEQ conducts annual reviews of approved remediation and closure plans as required under the Colstrip AOC. The surety bond requirements are expected to decrease as Colstrip’s coal ash impoundments remediation and closure activities are completed. See Note 8 for additional information on Colstrip AROs.

Other Commitments and Contingencies
Nuclear Insurance. The Price-Anderson Act is a federal law that governs liability-related issues and ensures the availability of funds for public liability claims arising from a nuclear incident at any U.S. licensed nuclear facility. It also seeks to limit the liability of nuclear reactor owners for such claims from any single incident. As of December 31, 2025 (Successor), the liability limit per incident is $ 16.3 billion for such claims, which is funded by insurance coverage from American Nuclear Insurers ($ 500 million in coverage), with the remainder covered by an industry retrospective assessment program.
As of December 31, 2025 (Successor), under the industry retrospective assessment program, in the event of a nuclear incident at any of the reactors covered by the Price-Anderson Act, Susquehanna could be assessed deferred premiums of up to $ 332 million per incident, payable at a maximum of $ 49 million per year.
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Additionally, Susquehanna purchases property insurance programs from Nuclear Electric Insurance Limited (“NEIL”), an industry mutual insurance company of which Susquehanna is a member. As of December 31, 2025 (Successor), facilities at Susquehanna are insured against nuclear property damage losses up to $ 2 billion and non-nuclear property damage losses up to $ 1 billion. Susquehanna also purchases an insurance program that provides coverage for the cost of replacement power during prolonged outages of nuclear units caused by certain specified conditions.
Under the NEIL property and replacement power insurance programs, Susquehanna could be assessed retrospective premiums in the event of the insurers’ adverse loss experience. The maximum assessment for this premium is $ 50 million as of December 31, 2025 (Successor). Talen has additional coverage that, under certain conditions, may reduce this exposure.
Talen Montana Fuel Supply. Talen Montana purchases coal from a mine owned by Westmoreland Rosebud Mining, LLC (the “Rosebud Mine”) for its interest in Colstrip Units 3 and 4 under a full requirements contract with the mine operator. Several lawsuits have been brought against the Rosebud Mine challenging permits and approvals to expand its operations. Talen Montana is not party to these lawsuits but is monitoring the progress of each to assess the impact to its operations. In the first lawsuit, the Montana Supreme Court in 2023 affirmed a lower court’s ruling to vacate a mining permit and require the Montana Board of Environmental Review to perform an additional review of the permit. In the second lawsuit, the Montana Federal District Court ordered a branch of the U.S. Department of the Interior to complete an updated Environmental Impact Statement (“EIS”) for a separate expansion project. In August 2025, the U.S. Department of Interior issued a supplemental EIS and approved an expansion of operations to authorize the mining of federal coal through 2039. In the third lawsuit, plaintiffs challenged a water pollution permit authorizing a separate expansion to the mine in 2023. In September 2025, a Montana State District Court upheld the permit. Plaintiffs appealed that ruling to the Montana Supreme Court in November 2025. At this time, Talen cannot predict the effect that an adverse outcome of these lawsuits to Rosebud Mine would have on: (i) Talen Montana’s ability to source fuel for its share of Colstrip operations; or (ii) Talen Montana’s operations, results of operations, or liquidity.

10. Long-Term Debt and Other Credit Facilities
TES is the borrower/issuer under all the Company’s debt and credit facilities. As of December 31, 2025 (Successor), TES was not in default under any of its debt or credit agreements.

Long-Term Debt

Successor
Interest Rate (a)
December 31,
2025 December 31,
2024
TLB-1
6.35 % $ 848   $ 857  
TLB-2 6.35 % 842   850  

TLB-3 5.67 % 1,200   —  
Secured Notes 8.63 % 1,200   1,200  
2034 Unsecured Notes 6.25 % 1,400   —  
2036 Unsecured Notes 6.50 % 1,290   —  
PEDFA 2009B Bonds
5.25 % 50   50  
PEDFA 2009C Bonds
5.25 % 81   81  

Total principal 6,911   3,038  
Unamortized deferred financing costs and original issuance discounts ( 100 ) ( 34 )
Total carrying value 6,811   3,004  
Less: long-term debt, due within one year 29   17  
Long-term debt $ 6,782   $ 2,987  

__________________
(a) Computed interest rate as of December 31, 2025 (Successor).

Long-term debt maturities as of December 31, 2025 (Successor) were:

2026 2027 2028 2029 2030 Thereafter Total
Principal debt maturities $ 29   $ 29   $ 29   $ 29   $ 2,034   $ 4,761   $ 6,911  

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Revolving Credit and Other Facilities

Successor
December 31, 2025
Maturity Committed Capacity (a)
Direct Cash Borrowings LCs Issued Unused Capacity
RCF
December 2029 $ 900   $ —   $ —   $ 900  
LCF December 2027 1,100   —  448   652  

Total $ 2,000   $ —   $ 448   $ 1,552  

__________________
(a) RCF committed capacity can be used for direct cash borrowings and (or) LCs. Direct cash borrowings are not permitted under the LCF, which can only be used for LCs.

Long-Term Debt, Revolving Credit, and Other Facilities
Certain key terms of our indebtedness include:

Maturity: Index: Rate, Applicable Margin, and Amortization: Prepayment Penalty:
Secured Notes June 2030 None 8.625 % per annum fixed rate

No applicable margin

No amortization
Prior to June 1, 2026: Redeemable at par plus a customary “make-whole” premium. 40 % redeemable from the proceeds of certain equity offerings at 108.625 %. 10 % redeemable at 103 % through May 31, 2026

On or after June 1 of the following years: 2026: 104.313 %; 2027: 102.156 %; 2028 and after: par

2034 Unsecured Notes February 2034 None
6.250 % per annum fixed rate

No applicable margin

No amortization
Prior to October 15, 2028: Redeemable at par plus a customary “make-whole” premium. 40 % redeemable from the proceeds of certain equity offerings at 106.250 %

On or after October 15 of the following years: 2028: 103.125 %; 2029: 101.563 %; 2030 and after: par

2036 Unsecured Notes February 2036 None
6.500 % per annum fixed rate

No applicable margin

No amortization
Prior to October 15, 2030: Redeemable at par plus a customary “make-whole” premium. 40 % redeemable from the proceeds of certain equity offerings at 106.500 %

On or after October 15 of the following years: 2030: 103.250 %; 2031: 101.625 %; 2032 and after: par

TLB-1 May 2030 Term SOFR 2.50 % per annum applicable margin; leverage-based step-downs to 2.25 % and 2.00 %

Amortization 1.00 % per annum; paid quarterly
Currently none

TLB-2 December 2031 Term SOFR Same as TLB-1 Currently none

TLB-3 November 2032 Term SOFR
2.00 % per annum applicable margin; leverage-based step-downs to 1.75 % and 1.50 %

Amortization 1.00 % per annum; paid quarterly
1.00 % to the extent prepaid prior to May 25, 2026 in connection with a repricing transaction

RCF December 2029 Term SOFR Cash borrowings: 2.00 % per annum applicable margin; leverage-based step-downs to 1.75 % and 1.50 %
LCs: LC fee equal to applicable margin above + fronting fee of 0.125 %
Unused commitments: 0.375 %; leverage-based step-down to 0.25 %
No amortization
None
LCF December 2027 None LCs: Same as RCF
Unused commitments: Same as RCF
None
PEDFA
Bonds 2009B: December 2038

2009C: December 2037
None 5.25 % per annum fixed rate

No applicable margin

No amortization
Prior to June 1, 2026: Par plus a customary “make-whole” premium

On or after June 1, 2026: Par

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Credit Agreement . The Credit Agreement governs the RCF, TLB-1, TLB-2, TLB-3, and LCF. The Credit Agreement contains customary negative covenants including but not limited to limitations on incurrence of liens and additional indebtedness, making investments, payment of dividends, and asset sales. The Credit Agreement also contains customary affirmative covenants. Solely with respect to the RCF and LCF, and solely during a compliance period (i.e., when RCF cash borrowings exceed 50 % of revolving commitments on the last day of a fiscal quarter), the Credit Agreement requires TES’s consolidated first lien net leverage ratio not to exceed 4.25 x. This financial covenant does not apply to the TLB-1, TLB-2, or TLB-3. The Credit Agreement also contains customary representations and warranties, events of default, and remedies (including acceleration of amounts due and (or) termination of commitments).
Secured Notes. Interest on the Secured Notes is payable semi-annually on June 1 and December 1 of each year and at maturity. The Secured Notes are subject to customary negative covenants for secured notes, including but not limited to certain limitations on incurrence of liens and additional indebtedness, making investments, payment of dividends, and transactions involving the Susquehanna assets, but do not contain any financial covenants. The Secured Notes also contain customary affirmative covenants, events of default, and remedies (including acceleration).
Unsecured Notes. Interest on the Unsecured Notes is payable semi-annually on February 1 and August 1 of each year and at maturity. The Unsecured Notes are subject to customary negative covenants for unsecured notes, including but not limited to certain limitations on incurrence of liens and transactions involving the Susquehanna assets, but do not contain any financial covenants. The Unsecured Notes also contain customary affirmative covenants, events of default, and remedies (including acceleration).
PEDFA Bonds. The PEDFA 2009B and 2009C Bonds were issued by the PEDFA on behalf of TES, and TES then received the proceeds under corresponding back-to-back exempt facilities loan agreements with the PEDFA. Corresponding TES unsecured promissory notes for each series contain the applicable principal, interest, and prepayment provisions. The PEDFA Bonds bear interest at a fixed rate until the end of the current term rate period on June 1, 2027, at which time they are subject to mandatory remarketing during which TES may elect a different interest rate mode. Aside from principal amount and final maturity, the terms of the PEDFA 2009B Bonds and 2009C Bonds are substantially identical. The PEDFA Bonds are subject to customary affirmative and negative covenants appropriate for such tax-exempt facilities, including but not limited to limitations on incurrence of liens (but not unsecured indebtedness), and asset sales. The PEDFA Bonds are also subject customary events of default and remedies (including acceleration).
Secured ISDAs. Talen Energy Marketing is party to certain Secured ISDAs, under which TES and the Subsidiary Guarantors provide the applicable counterparties with a first priority lien on and security interest (which ranks pari passu with the liens securing the Credit Facilities and the Secured Notes) in certain assets in lieu of posting collateral in the form of cash equivalents or LCs. The secured obligations under the Secured ISDAs were $ 269 million as of December 31, 2025 (Successor).

Security Interests, Guarantees, Cross-Defaults, and Restrictions on Dividends
Secured Obligations. The obligations under the Credit Facilities, Secured Notes, and Secured ISDAs are secured by a first-priority lien on and security interest in substantially all of the assets of TES and the Subsidiary Guarantors. The Subsidiary Guarantors guarantee TES’s obligations under the Credit Facilities and the Secured Notes. TES and the Subsidiary Guarantors guarantee Talen Energy Marketing’s obligations under the Secured ISDAs. The amount for which TES and the Subsidiary Guarantors may be liable is equal to the amount of obligations outstanding under such agreements and may also include unpaid interest, premiums, penalties, and (or) other fees and expenses. An event of default under the Credit Facilities, Secured Notes, or Secured ISDAs, if not cured or waived, may result in a cross acceleration of amounts due and (or) cross termination across all these agreements.
Restrictions on Dividends. Agreements governing TES’s indebtedness restrict the ability of TES and the Subsidiary Guarantors to pay dividends or distributions or otherwise transfer assets to TEC, subject to certain exceptions. Notable exceptions include the ability to pay dividends or distributions: (1) in an amount not to exceed the gr eater of $ 420 million and 40 % of TES’s consolidated adjusted EBITDA, (2) in an unlimited amount so long as TES’s pro forma consolidated total net leverage ratio is less than or equal to 2.5 to 1.0, and (3) in an amount not to exceed the sum of: (a) the greater of $ 525 million and 50 % of TES’s consolidated adjusted EBITDA, (b) TES’s consolidated adjusted EBITDA minus 140 % of TES’s consolidated interest expense, in each case, for the period from June 1, 2023 through the most recent fiscal quarter (subject to compliance with either (x) a pro forma consolidated total net leverage ratio of less than or equal to 3.75 to 1.0 or (y) a fixed charge coverage ratio greater than or equal to 2.0 to 1.0), (c) equity contributions to TES, and (d) other customary “builder basket” components.
As of December 31, 2025 (Successor), substantially all net assets of TES and the Subsidiary Guarantors were subject to restrictions on dividends.
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Item 8. Table of Contents

Unsecured Obligations. The Unsecured Notes and the PEDFA Bonds are senior unsecured obligations of TES that are effectively subordinated to TES’s secured obligations, including the Credit Facilities, Secured Notes, and Secured ISDAs, to the extent of the value of the assets securing those obligations. The Subsidiary Guarantors guarantee TES’s obligations under the Unsecured Notes and certain of the Subsidiary Guarantors also guarantee TES’s obligations under the PEDFA Bonds. These guarantees are the general unsecured obligations of such Subsidiary Guarantors, rank equally with all of their other senior unsecured indebtedness, and are effectively subordinated to their secured obligations, including guarantees under the Credit Facilities, Secured Notes, and Secured ISDAs, to the extent of the value of the assets securing those obligations.

2025 Financing Transactions
Freedom and Guernsey Acquisitions Financing. In October and November 2025, TES completed several financing transactions and used the proceeds from the Unsecured Notes and the TLB-3 to finance the Freedom and Guernsey Acquisitions .
• Unsecured Notes . Issued: (i) $ 1.4 billion in aggregate principal amount of the 2034 Unsecured Notes and (ii) $ 1.3 billion in aggregate principal amount of the 2036 Unsecured Notes.
• TLB-3. Drew in full the $ 1.2 billion senior secured term loan B credit facility (the TLB-3), which constitutes a new tranche of term loans separate from TLB-1 and TLB-2.
• RCF. Increased its existing RCF (including its revolving LC capacity) from $ 700 million to $ 900 million.
• LCF. Increased its existing $ 900 million LCF to $ 1.1 billion and extended the maturity from December 2026 to December 2027.
Additionally, in November 2025, in connection with the closing of the Freedom and Guernsey Acquisitions, the Company entered into the Fifth Supplemental Indenture to the Secured Notes Indenture and First Supplemental Indentures to each of the Unsecured Notes Indentures to add certain entities as Subsidiary Guarantors of the Secured Notes and Unsecured Notes, respectively.
See Note 17 for additional information on the Freedom and Guernsey Acquisitions.

2024 Financing Transactions
Credit Facilities. In December 2024, TES completed several refinancing transactions:

• TLB-2. Issued a new $ 850 million TLB-2, the proceeds of which were used, together with cash on hand, to repurchase shares of our outstanding common stock from Rubric.
• TLB-1. Repriced the existing $ 857 million TLB-1 to reduce the current interest rate margin by 100 basis points (to SOFR plus 250 basis points, with further leverage-based step downs available) to align pricing with the new TLB-2.

• RCF. Repriced the existing $ 700 million RCF to reduce the current interest rate margin by 100 basis points (to SOFR plus 200 basis points, with further leverage-based step downs available), increased revolving LC capacity from $ 475 million to $ 700 million, and extended the maturity from May 2028 to December 2029.
• LCF. Issued a new $ 900 million standalone secured LCF to transition LCs from the TLC LCF and Bilateral LCF. LCs issued under the LCF are subject to an LC fee of 2.00 % per annum (with leverage-based step downs available) plus a fronting fee of 0.125 % per annum.

• TLC/TLC LCF. Repaid in full the $ 470 million TLC utilizing the restricted cash collateralizing the TLC LCF, and terminated the TLC and associated $ 470 million TLC LCF.
• Bilateral LCF. Terminated the $ 75 million Bilateral LCF.
In connection with these transactions, the requisite lenders under the Credit Agreement also consented to certain amendments, among other things, increasing the Company’s flexibility for restricted payments, investments, and dispositions under the Credit Facilities. As a result of these transactions, the Company derecognized the carrying value of the extinguished TLC and presents the carrying value of the newly issued TLB-2 on the Consolidated Balance Sheet.
In May 2024, TES repriced the TLB-1 and TLC, and the lenders, as part of these debt modifications, agreed to waive mandatory prepayment obligations related to the ERCOT Sale. See Note 17 for additional information on the ERCOT Sale. Additionally, the lenders under the TLB-1, TLC, and RCF consented to certain other covenant improvements.
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PEDFA Bonds. In June 2024, TES completed the remarketing of its outstanding $ 50 million in PEDFA 2009B Bonds and $ 81 million in PEDFA 2009C Bonds. As part of the remarketing, (i) the PEDFA Bonds were transitioned from a variable daily interest rate to a fixed term rate of 5.25 % until June 1, 2027, at which time they are subject to mandatory remarketing during which TES may elect a different interest rate mode; (ii) $ 133 million of TES LCs that had previously supported the PEDFA Bonds were terminated; (iii) mandatory repurchase and optional redemption provisions were modified; and (iv) certain covenants relating to changes of control, incurrence of liens, and asset sales were amended and became operative. The remarketing transaction is excluded from the Consolidated Statements of Cash Flows as a non-cash item.
Cumulus Digital TLF Repayment. In connection with the AWS Data Campus Sale, the Cumulus Digital TLF was paid in full in March 2024, together with all accrued interest and other outstanding amounts, and related liens, guarantees, and LCs were released and terminated. See Note 17 for additional information on the AWS Data Campus Sale.

11. Fair Value
Recurring Fair Value Measurements
Financial assets and liabilities reported at fair value on a recurring basis primarily include energy commodity derivatives, interest rate derivatives, and investments held within the NDT. See Note 1 for additional descriptions on fair value levels.
The classifications of recurring fair value measurements within the fair value hierarchy were:

Successor
December 31, 2025 December 31, 2024
Level 1 Level 2 NAV Netting (a)
Total Level 1 Level 2 NAV Netting (a)
Total
Assets
Cash equivalents $ —   $ —   $ 16   $ —  $ 16   $ —   $ —   $ 3   $ —  $ 3  
Equity securities (b)
871 —   234   —  1,105   758   —   347   —  1,105  
U.S. government debt securities 297 102   —   —  399   353   —   —   —  353  
Municipal debt securities —   101   —   —  101   —   85   —   —  85  
Corporate debt securities —   277   —   —  277   —   173   —   —  173  

Receivables (payables), net (c)
—  —  —  —  2   —  —  —  —  5  
NDT funds 1,168   480   250   —   1,900   1,111   258   350   —   1,724  

Commodity derivatives 361   95   —   ( 396 ) 60   134   91   —   ( 156 ) 69  
Interest rate derivatives —   —   —   —  —   —   2   —   —  2  
Total assets $ 1,529   $ 575   $ 250   $ ( 396 ) $ 1,960   $ 1,245   $ 351   $ 350   $ ( 156 ) $ 1,795  

Liabilities
Commodity derivatives
$ 407   $ 189   $ —   $ ( 440 ) $ 156   $ 145   $ 29   $ —   $ ( 167 ) $ 7  
Interest rate derivatives —   12   —   —  12   —   —   —   —  —  

Total liabilities $ 407   $ 201   $ —   $ ( 440 ) $ 168   $ 145   $ 29   $ —   $ ( 167 ) $ 7  
__________________
(a) Amounts represent netting pursuant to master netting arrangements and cash collateral held or placed with the same counterparty.
(b) Includes fixed income funds and real estate investment trusts.
(c) Represents: (i) interest and dividends earned but not received; and (ii) net sold or purchased investments, but not settled.
There were no recurring fair value measurements classified as Level 3 as of December 31, 2025 (Successor) and 2024 (Successor).
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Nonrecurring Fair Value Measurements
See Note 7 for nonrecurring fair value measurements during the year ended December 31, 2025 that are associated with the derecognition of certain Nautilus assets and liabilities. There were no material fair value measurements related to impairments of long-lived assets during the year ended December 31, 2024 (Successor), and for the period from May 18 through December 31, 2023 (Successor) See Note 7 for information on the nonrecurring fair value measurement of Brandon Shores and Note 20 for information on the nonrecurring fair value measurements resulting in the application of fresh start accounting during the period from January 1 through May 17, 2023 (Predecessor).

Reported Fair Value
The carrying value of certain financial assets and liabilities on the Consolidated Balance Sheets, including “Cash and cash equivalents , ” “Restricted cash and cash equivalents , ” “Accounts receivable , ” and “Accounts payable and other accrued liabilities” approximate fair value.
The carrying value and fair value of indebtedness presented on the Consolidated Balance Sheets were:

Successor
December 31, 2025 December 31, 2024
Carrying Value Fair Value Carrying Value Fair Value

Long-term debt (a)
$ 6,811   $ 7,069   $ 3,004   $ 3,120  

__________________
(a) Aggregate value of “Long-term debt” and “Long-term debt, due within one year” presented on the Consolidated Balance Sheets.

12. Postretirement Benefit Obligations
TES and certain subsidiaries sponsor postemployment benefits which include defined benefit pension plans, health and welfare postretirement plans (other postretirement benefit plans), and a defined contribution plan.

Pension and Other Postretirement Defined Benefit Plans
Obligations under the defined benefit pension and other postretirement plans are generally based on factors, among others, such as age of the participants, years of service, and compensation. The pension and other postretirement plans are closed to new participants. Effective December 31, 2018, all participants ceased accruing additional benefits in the TERP, the Company’s largest defined benefit pension plan.
Funded Status. The net fair value of underfunded defined benefit pension and other postretirement plans are presented as “Postretirement benefit obligations” on the Consolidated Balance Sheets. The Talen Montana sponsored defined benefit pension plan was overfunded by a non-material amount as of December 31, 2025 (Successor). Certain other postretirement plans were overfunded by $ 39 million and $ 36 million as of December 31, 2025 (Successor) and 2024 (Successor), respectively. Overfunded balances are presented as “Other noncurrent assets” on the Consolidated Balance Sheets. The current portion of certain unfunded postretirement obligations were non-material.
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Item 8. Table of Contents

The aggregate funded status and the weighted average assumptions for the periods were:

Pension Benefits
Successor
Year Ended December 31, 2025 Year Ended December 31, 2024

Change in benefit obligation
Benefit obligation beginning balance $ 1,202   $ 1,308  
Service cost 2   2  
Interest cost 65   63  
Actuarial (gain) loss 26   ( 81 )
Actual benefits paid ( 92 ) ( 105 )
Resolved litigation settlement and other charges —   15  
Benefit obligation ending balance $ 1,203   $ 1,202  
Change in plan assets
Plan assets fair value beginning balance 911   975  
Actual return on plan assets 102   ( 13 )
Employer contributions 70   54  
Actual benefits paid ( 92 ) ( 105 )
Plan assets fair value ending balance $ 991   $ 911  
Funded status $ ( 212 ) $ ( 291 )
Accumulated benefit obligation $ 1,203   $ 1,202  
Aggregate amounts of underfunded plans
Benefit obligation/Accumulated benefit obligation $ 1,203   $ 1,202  
Fair value of plan assets 991   911  
Amounts recognized in accumulated other comprehensive income
Net (gain) loss 28   34  
Total accumulated other comprehensive income $ 28   $ 34  
Assumptions
Discount rate 5.43   % 5.65   %
Interest crediting rate 6.00   % 6.00   %
Rate of compensation increase 3.45   % 3.45   %

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During the year ended December 31, 2025 (Successor) , the decrease in postretirement benefit obligations was primarily attributable to employer contributions and actual returns being higher than expected returns on plan assets.

Other Postretirement Benefits
Successor
Year Ended December 31, 2025 Year Ended December 31, 2024

Change in benefit obligation
Benefit obligation beginning balance $ 52   $ 79  
Service cost 1   1  
Interest cost 3   3  
Plan amendments ( 1 ) ( 21 )
Actuarial (gain) loss —   ( 3 )
Plan participant contributions 2   2  
Actual benefits paid ( 10 ) ( 9 )
Benefit obligation ending balance $ 47   $ 52  
Change in plan assets
Plan assets fair value beginning balance 71   75  
Actual return on plan assets 5   3  
Employer contributions 1   —  
Plan participant contributions 2   2  
Actual benefits paid ( 9 ) ( 9 )
Plan assets fair value ending balance $ 70   $ 71  
Funded status $ 23   $ 19  

Aggregate amounts of underfunded plans
Benefit obligation / Accumulated benefit obligation $ 47   $ 52  
Fair value of plan assets 70   71  
Amounts recognized in accumulated other comprehensive income
Net (gain) loss ( 3 ) ( 2 )
Prior service cost (credit) ( 16 ) ( 20 )
Total accumulated other comprehensive income $ ( 19 ) $ ( 22 )
Assumptions
Discount rate 5.42   % 5.63   %
Rate of compensation increase 4.19   % 2.31   %

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Net Periodic Benefit Cost and Amounts Recognized in OCI. The components of net periodic benefit cost (credit), the amounts recognized in OCI and the associated weighted average assumptions for pension and other postretirement plans for the periods were:

Pension Benefits
Successor Predecessor
Year Ended December 31, 2025 Year Ended December 31, 2024 May 18 through December 31, 2023 January 1 through May 17, 2023
Net periodic benefit costs (credits):
Service cost $ 2   $ 2   $ 2   $ 1  
Interest cost 65   63   40   25  
Expected return on plan assets ( 70 ) ( 66 ) ( 41 ) ( 30 )
Amortization of net (gain) loss —   —   —   2  
Resolved litigation settlement and other charges —   15   1   —  
Net periodic defined benefit cost (credit) ( 3 ) 14   2   ( 2 )
Net actuarial (gain) loss ( 7 ) ( 3 ) 38   2  
Reclassifications due to settlement and (or) curtailment:
Amortization of net (gain) loss —   —   —   —  
Total recognized in OCI $ ( 7 ) $ ( 3 ) $ 38   $ 2  
Total recognized in net periodic costs and OCI $ ( 10 ) $ 11   $ 40   $ —  
Assumptions
Discount rate 5.65   % 5.00   % 5.12   % 5.41   %
Rate of compensation increase 3.45   % 3.45   % 3.45   % 3.45   %
Expected return on plan assets 7.50   % 7.25   % 7.25   % 7.50   %

Other Postretirement Benefits
Successor Predecessor
Year Ended December 31, 2025 Year Ended December 31, 2024 May 18 through December 31, 2023 January 1 through May 17, 2023
Net periodic benefit costs (credits):
Service cost $ 1   $ 1   $ 1   $ 1  
Interest cost 3   3   2   1  
Expected return on plan assets ( 4 ) ( 4 ) ( 2 ) ( 2 )
Amortization of prior service cost (credit) ( 4 ) ( 1 ) —   —  
Amortization of net (gain) loss ( 1 ) —   —   —  
Net periodic defined benefit cost (credit) ( 5 ) ( 1 ) 1   —  
Net actuarial (gain) loss —   ( 2 ) ( 1 ) —  
Prior service credit ( 1 ) ( 21 ) —   —  
Reclassifications due to settlement and (or) curtailment:
Amortization of prior service cost (credit) 4   1   —   —  
Amortization of net (gain) loss 1   —   —   —  
Total recognized in OCI $ 4   $ ( 22 ) $ ( 1 ) $ —  
Total recognized in net periodic costs and OCI $ ( 1 ) $ ( 23 ) $ —   $ —  
Assumptions
Discount rate 5.63   % 5.01   % 5.13   % 5.41   %
Rate of compensation increase 4.19   % 2.31   % 2.31   % 2.31   %
Expected return on plan assets 6.07   % 5.49   % 5.49   % 5.74   %
Health care grading trend rates (a)
8.00 % to 4.40 %
7.10 % to 4.40 %
6.50 % to 4.50 %
6.50 % to 4.50 %

__________________
(a) Trend rates based on a 7 year grading period.
In September 2024, the Company approved a plan amendment for certain other postretirement benefit plans, resulting in the recognition of prior service credits of $ 21 million and presented as “Postretirement benefit prior service (credits) costs, net” on the Consolidated Statements of Comprehensive Income (Loss).
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The expected long-term rates of return for pension and other postretirement plans are based on management's projections using a best-estimate of expected returns, volatilities, and correlations for each asset class. Each plan’s specific current and expected asset allocations are also considered in developing a reasonable return assumption.
Contributions and Payments . TES contributed $ 62 million and $ 43 million to the TES sponsored pension plan during the years ended December 31, 2025 (Successor) and 2024 (Successor), respectively. Talen Montana contributed $ 8 million and $ 10 million of discretionary contributions to the Talen Montana sponsored pension plan during the years ended December 31, 2025 (Successor) and 2024 (Successor), respectively.
TES expects to contribute $ 26 million to the TES sponsored pension plan in 2026. Talen Montana expects to contribute a non material amount to the Talen Montana sponsored pension plan in 2026.
The aggregate benefits paid to pension and other postretirement plan participants was $ 102 million for year ended December 31, 2025 (Successor) and $ 114 million for the year ended December 31, 2024 (Successor).
The forecasted undiscounted benefit payments to plan participants as of December 31, 2025 (Successor) were:

2026 2027 2028 2029 2030 2031-2035
Pension plans $ 98   $ 94   $ 94   $ 93   $ 92   $ 447  
Other postretirement plans 5   5   5   4   3   16  

Pension plan assets. Pension plan assets are held in external trusts, including a master trust, which includes a 401(h) account that is restricted for certain other postretirement benefit obligations of Talen Energy Supply. The plans’ investment policies outline investment objectives.
The risk management framework categorizes the plan assets within three sub-portfolios: growth, immunizing, and liquidity. The trust investments within these portfolios are routinely monitored to seek a risk-adjusted return on a mix of assets that, in combination with our funding policy, will provide sufficient assets to provide long-term growth and liquidity for benefit payments, match asset duration with the expected liability duration, and mitigate concentrations of risk with asset diversification.
The weighted-average target asset allocations for the pension plan assets as of December 31, 2025 (Successor) were:

Equity securities 31   %
Debt securities 9   %
Other 7   %
Growth portfolio 47   %
Debt securities 37   %
Other 11   %
Immunizing portfolio 48   %
Liquidity portfolio 4   %
Total 100   %

See Note 1 for additional descriptions on fair value levels. The classifications of pension plan asset fair value measurements within the fair value hierarchy were:

Successor
December 31, 2025 December 31, 2024
Level 1 NAV Total Level 1 NAV Total
Cash equivalents $ —   $ 151   $ 151   $ —   $ 100   $ 100  
Commingled equity securities —   300   300   —   274   274  
Commingled debt securities —   336   336   —   286   286  
Alternative and other investments ( 3 ) 186   183   ( 15 ) 231   216  
Receivables (payables), net (a)
—  —  21   —   —   35  

Total plan assets $ ( 3 ) $ 973   $ 991   $ ( 15 ) $ 891   $ 911  

__________________
(a) Represents: (i) interest and dividends earned but not received; and (ii) net sold or purchased investments, but not settled.
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Other postretirement benefit plan assets. The investment strategy with respect to most of the other postretirement benefit obligations is to fund VEBA or similar trusts with voluntary contributions, when appropriate, and to invest in a tax efficient manner. Other postretirement benefit plans are invested in a mix of assets for long-term growth with an objective of earning returns that provide liquidity as required for benefit payments. These plans benefit from diversification of asset types, investment fund strategies and investment fund managers, and therefore, have no significant concentration of risk. Equity securities include investments in domestic large-cap commingled funds. Ownership interests in commingled funds that invest entirely in debt securities are classified as equity securities but treated as debt securities for asset allocation and target allocation purposes. Ownership interests in money market funds are treated as cash and cash equivalents for asset allocation and target allocation purposes.
The target asset allocations for other postretirement benefit assets were:

Successor

December 31, 2025
Cash and cash equivalents —   %
Equity securities 10   %
Debt securities 90   %
Total 100   %

See Note 1 for additional descriptions on fair value levels. The classifications of other postretirement benefit plan asset fair value measurements within the fair value hierarchy were:

Successor
December 31, 2025 December 31, 2024
Level 1 Level 2 NAV Total Level 1 Level 2 NAV Total
Cash equivalents $ —   $ —   $ 1   $ 1   $ —   $ —   $ 4   $ 4  
Commingled equity securities —   —   10   10   —   —   10   10  
U.S. Government debt securities 6   —   —   6   7   —   —   7  
Corporate debt securities —   18   —   18   —   18   —   18  
Commingled debt securities —  —  35   35   —  —  32   32  

Total plan assets $ 6   $ 18   $ 46   $ 70   $ 7   $ 18   $ 46   $ 71  

Defined Contribution Plan
Substantially all Company employees are eligible to participate in the Company’s 401(k) deferred savings plans. Employer contributions to the plans were $ 29 million for the year ended December 31, 2025 (Successor), $ 25 million for the year ended December 31, 2024 (Successor), $ 9 million for the period from May 18 through December 31, 2023 (Successor), and $ 10 million for the period from January 1 through May 17, 2023 (Predecessor).

13. Stock-Based Compensation
In June 2023, TEC began granting performance stock units (“PSUs”) and restricted stock units (“RSUs”) to certain employees and non-employee directors under the Company’s 2023 Equity Incentive Plan (the “Equity Plan”). The aggregate number of shares authorized for issuance under the Equity Plan is 7,083,461 shares of common stock.

Equity to Liability Modification
In December 2025, certain executive officers executed agreements providing for certain PSU and RSU awards that are scheduled to vest in 2026 to be partially settled in cash. Generally, the cash settlement amount will be equal up to 60 % of the net after-tax value on the vesting date of each such award. However, the cash settlement amount is subject to a cap. Additionally, all non-employee directors are expected to be offered the ability to net-settle (to account for income taxes) all of their PSUs and RSUs. Accordingly, the portion of each participant’s applicable awards that are expected to be settled in cash and all non-employee director awards were reclassified from equity to liability. As a result of the modification, a $ 501 million liability was recognized and presented as “Stock-based compensation liabilities” on the Consolidated Balance Sheets and was measured based on the closing share price of Talen’s common stock of $ 374.84 as of December 31, 2025 (Successor).
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Performance Stock Units
PSUs have three-year or two-year cliff vesting schedules or vest upon consummation of a change in control event based on the satisfaction of a continued employment condition and the achievement of certain market conditions over a performance period. Participants will be awarded additional PSUs if market conditions exceed targets at the time of vesting. If the Company declares any cash dividends while the PSUs are outstanding, participants will be credited a dividend, payable at the time of vesting, based on the number of shares of common stock underlying the PSUs.
Changes in non-vested PSUs during the year ended December 31, 2025 (Successor) were:

Liability-Classified PSUs Equity-Classified PSUs Total PSUs
Weighted-Average
Grant Date
Fair Value per Unit
Non-vested as of December 31, 2024 (Successor) —   956,347   956,347   $ 54.23  
Granted (a)
—   102,275   102,275   498.40  
Forfeited —   ( 288 ) ( 288 ) 645.03  

Equity to liability modification (b)
569,477   ( 569,477 ) —   53.69  
Non-vested as of December 31, 2025 (Successor) (c)
569,477   488,857   1,058,334   $ 147.45  

_____________
(a) The weighted-average grant date fair value per unit was $ 96.00 and $ 54.35 for the year ended December 31, 2024 (Successor) and for the period May 18 through December 31, 2023 (Successor), respectively.
(b) See description of December 2025 equity to liability modification above.
(c) Represents the target number of PSUs. Subject to the PSU award agreements, the actual amount of PSUs earned by participants at vesting can range from 0 % to 200 % of the target number of PSUs based on the Company’s stock price performance. In addition, certain of the PSUs are eligible to earn an additional amount of Talen shares based on the incremental Company stock price performance in excess of the PSU targets. Assuming all non-vested PSUs vested on December 31, 2025 (Successor) at the then current share price of the Company’s common stock the aggregate non-vested PSUs would be 1,268,275 .
The fair value of PSUs is determined using a Monte Carlo valuation methodology based on the fair value of the underlying stock price at the grant date. Significant inputs and assumptions used in the valuations of PSUs were:

Successor
Year Ended December 31, 2025 Year Ended December 31, 2024 May 18 through December 31, 2023
Volatility (a)
40 % - 50 %
25   % 25   %
Expected term (in years) 1.2 - 2
2.4 3
Risk-free rate (b)
3.52 % - 3.99 %
4.29   % 4.35 % - 4.59 %

__________________
(a)     Derived from an option pricing method based on the average asset volatility of peer companies and the Company’s leverage ratio.
(b)     Based on the U.S. constant maturity treasury rate with a term matching the expected time to the end of the performance measurement period.

Restricted Stock Units
RSUs have three-year ratable or two-year cliff vesting schedules beginning on the grant date, with restrictions on transferring settled shares prior to the final scheduled vesting date for the three-year awards. The fair value of RSUs granted is based on the closing price of TEC common stock on the grant date.
Changes in non-vested RSUs during the year ended December 31, 2025 (Successor) were:

Liability-Classified RSUs
Equity-Classified RSUs
Total RSUs
Weighted-Average
Grant Date
Fair Value per Unit
Non-vested as of December 31, 2024 (Successor) —   549,405   549,405   $ 55.07  
Granted (a)
—   53,096   53,096   209.82  
Forfeited —   ( 372 ) ( 372 ) 378.67  
Vested —   ( 261,476 ) ( 261,476 ) 48.71  
Equity to liability modification (b)
169,642   ( 169,642 ) —   61.08  
Non-vested as of December 31, 2025 (Successor)
169,642   171,011   340,653   $ 106.18  
_____________
(a) The weighted-average grant date fair value per unit was $ 121.89 and $ 48.46 for the year ended December 31, 2024 (Successor) and for the period May 18 through December 31, 2023 (Successor), respectively.
(b) See description of December 2025 equity to liability modification above.
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Stock-based Compensation Expense
Stock-based compensation expense presented as “General and administrative” on the Consolidated Statement of Operations was:

Successor
Year Ended December 31, 2025 Year Ended December 31, 2024 May 18 through December 31, 2023

Stock-based compensation expense, liability-classified awards $ 501   $ —   $ —  
Stock-based compensation expense, equity-classified awards 25   33   19  
Income tax benefit ( 132 ) ( 8 ) ( 5 )
After-tax stock-based compensation expense $ 395   $ 24   $ 14  

Unrecognized stock-based compensation expense and related periods of recognition as of December 31, 2025 (Successor) were:

PSUs
RSUs

Equity-Classified
Liability-Classified
Equity-Classified
Liability-Classified

Unrecognized stock-based compensation expense (a)
$ 33   $ 64   $ 9   $ 9  
Weighted-average period of recognition (in years) 0.5 0.4 0.6 0.4

__________________
(a)     Stock-based compensation expense related to liability-classified awards is subject to variability due to changes in their value through the settlement date.

14. Earnings Per Share
Basic EPS is computed by dividing net income (loss) by the weighted average number of shares of common stock outstanding during the applicable period. Diluted EPS is computed by dividing income by the weighted-average number of shares of common stock outstanding, increased by incremental shares that would be outstanding if potentially dilutive non-participating securities were converted to common stock as calculated using the treasury stock method. EPS for the periods were:

Successor Predecessor
Year Ended December 31, 2025 Year Ended December 31, 2024 May 18 through December 31, 2023 January 1 through May 17, 2023
Numerator: (Millions of Dollars)
Net Income (Loss) $ ( 219 ) $ 1,013   $ 143   $ 465  
Less:
Net income (loss) attributable to noncontrolling interest —   15   9   ( 14 )
Net Income (Loss) Attributable to Stockholders $ ( 219 ) $ 998   $ 134   $ 479  

Denominator: (Thousands)
Weighted-Average Number of Common Shares Outstanding - Basic 45,692   54,254   59,029   —  
Warrants —   —   84   —  
Restricted stock units —   354   166   —  
Performance stock units —   1,878   120   —  
Weighted-Average Number of Common Shares Outstanding - Diluted 45,692   56,486   59,399   —  

Earnings per Share - Basic $ ( 4.79 ) $ 18.40   $ 2.27   N/A
Earnings per Share - Diluted ( 4.79 ) 17.67   2.26   N/A

There were 151,505 RSUs and 1,631,614 PSUs excluded from dilutive EPS for the year ended December 31, 2025 (Successor) because the Company generated a net loss. No shares were excluded from diluted EPS for the year ended December 31, 2024 (Successor). 134,798 PSUs were excluded from diluted EPS for the period from May 18 through December 31, 2023 (Successor) due to their anti-dilutive nature. These awards are excluded from the calculation of EPS because the performance conditions have not been met during the reporting period.
For the period from January 1 through May 17, 2023 (Predecessor), there were no outstanding shares of common stock.
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15. Stockholders’ Equity

Share Repurchase Program
In September 2025, the Board of Directors approved an increase in the existing capacity of the Company’s SRP from $ 995 million to $ 2 billion and extended the expiration date from December 31, 2026 to December 31, 2028. These changes to the SRP became effective in November 2025 upon the completion of the Freedom and Guernsey Acquisitions. The remaining capacity under the SRP as of December 31, 2025 (Successor) was $ 2 billion.
As of December 31, 2025 (Successor), the Company had repurchased approximately 23 % of its outstanding shares of common stock for a total of approximately $ 2 billion, exclusive of transaction costs and excise taxes.
Summary of activity under the SRP:

Successor
Year Ended December 31, 2025 Year Ended December 31, 2024
Number of Shares Share Price (a)
Total Amount Number of Shares (b)(c)
Share Price (a)
Total Amount
Share repurchases 452,130   $ 186.24   $ 85   13,227,222   $ 149.50   $ 1,977  
Share retirements 452,130   186.24   85   13,227,222   149.50   1,977  
__________________
(a) Weighted average price per share, including transaction costs and excise taxes.
(b) Includes 7,307,300 shares repurchased from affiliates of Rubric in July 2024 and December 2024 at a weighted average price of $ 177.16 per share. Of the total shares repurchased by the Company, $ 850 million purchased from affiliates of Rubric were not under the SRP.
(c) Includes 5,275,862 shares repurchased as result of a tender offer in June 2024 at a weighted average price of $ 117.16 per share.
As of December 31, 2025 (Successor), all repurchased shares have been retired. See Note 1 for the accounting policy related to treasury stock and retirement of treasury stock.

Noncontrolling Interests
Purchase of Equity in Nautilus. In October 2024, the Company acquired TeraWulf’s 25 % equity interest in Nautilus in exchange for $ 85 million and the distribution by Nautilus of its Bitcoin mining equipment to TeraWulf. As a result of the transaction, the Company owns 100 % of the equity of Nautilus. In conjunction with the transaction, we suspended Bitcoin mining operations at the facility.
Purchase of Equity in Cumulus Digital. In March 2024, TES acquired all of the equity of Cumulus Digital held by affiliates of Orion Energy Partners and two former members of Talen senior management in exchange for an aggregate of $ 39 million in cash. Following these transactions, TES owns 100 % of the equity of Cumulus Digital.

Accumulated Other Comprehensive Income
Changes in AOCI for the periods were:

Successor Predecessor
Year Ended December 31, 2025 Year Ended December 31, 2024 May 18 through December 31, 2023 January 1 through May 17, 2023
Beginning balance $ ( 12 ) $ ( 23 ) $ —   $ ( 167 )
Gains (losses) arising during the period
21   12   ( 36 ) 6  
Reclassifications to Consolidated Statements of Operations
( 9 ) —   7   5  
Income tax benefit (expense) ( 4 ) ( 1 ) 6   ( 5 )
Other comprehensive income (loss) 8   11   ( 23 ) 6  
Cancellation of equity at Emergence —   —   —   161  
Accumulated other comprehensive income (loss) $ ( 4 ) $ ( 12 ) $ ( 23 ) $ —  

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The components of AOCI, net of tax, as of December 31, were:

Successor
2025 2024
Available-for-sale securities unrealized gain (loss), net $ 2   $ ( 3 )

Postretirement benefit prior service credits (costs), net 12   14  
Postretirement benefit actuarial gain (loss), net ( 18 ) ( 23 )
Accumulated other comprehensive income (loss) $ ( 4 ) $ ( 12 )

Reclassification adjustments from AOCI to the Consolidated Statements of Operations were non-material amounts for the years ended December 31, 2025 (Successor) and 2024 (Successor).
The postretirement obligations components of AOCI are not presented in their entirety on the Consolidated Statements of Operations during the periods; rather, they are included in the computation of net periodic defined benefit costs (credits). See Note 12 for additional information.

16. Supplemental Cash Flow Information
Supplemental information for the Consolidated Statements of Cash Flows for the periods was:

Successor Predecessor
Year Ended December 31, 2025 Year Ended December 31, 2024 May 18 through December 31, 2023 January 1 through May 17, 2023
Cash paid during the period
Interest and other finance charges, net of capitalized interest (a)
$ 233   $ 255   $ 133   $ 283  
Income taxes 71   20   12   7  

Unrealized (gain) loss on derivative instruments included on the Statements of Cash Flows
Commodity contracts $ 106   $ ( 62 ) $ ( 52 ) $ 63  
Interest rate swap contracts (interest expense) 15   ( 7 ) 12   2  
Unrealized (gain) loss on derivative instruments $ 121   $ ( 69 ) $ ( 40 ) $ 65  

Depreciation, amortization and accretion included on the Statements of Cash Flows
Depreciation, amortization and accretion $ 279   $ 298   $ 165   $ 200  

Other —   ( 13 ) ( 8 ) 8  
Depreciation, amortization and accretion $ 279   $ 285   $ 157   $ 208  

Reconciliation of other non-cash operating activities
Derivative option premium amortization $ 37   $ 11   $ 52   $ 29  

Bitcoin revenue —   ( 91 ) ( 81 ) ( 27 )

Fair value adjustment on distribution of miners —   14   —   —  

Other 14   7   17   5  
Total
$ 51   $ ( 59 ) $ ( 12 ) $ 7  

Non-cash investing activities
Accrued PP&E additions not paid at period end $ 23   $ 14   $ 13   $ 22  

Non-cash financing activities
Non-cash increase to PP&E and decrease to other current assets for contribution of Bitcoin miners to Nautilus $ —   $ —   $ —   $ 14  
Non-cash decrease to PP&E and decrease to noncontrolling interest for distribution of Bitcoin miners to TeraWulf —   43   —   3  
Non-cash increase to PP&E and increase to noncontrolling interest for contribution of Bitcoin miners by TeraWulf —   —   —   38  
__________________
(a) Capitalized interest was $ 4 million for the year ended December 31, 2025 (Successor), $ 5 million for the year ended December 31, 2024 (Successor), $ 10 for the period from May 18 through December 31, 2023 (Successor), and $ 12 for the period from January 1 through May 17, 2023 (Predecessor).
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Cash and Restricted Cash
The following table provides a reconciliation of “Cash and cash equivalents” and “Restricted cash and cash equivalents” presented on the Consolidated Balance Sheets to such amounts shown on the Consolidated Statements of Cash Flows:

Successor
December 31,
2025 December 31,
2024
Cash and cash equivalents $ 689   $ 328  
Restricted cash and cash equivalents (a)
63   37  
Total
$ 752   $ 365  

__________________
(a) Comprised of commodity exchange margin deposits.

17. Acquisitions and Divestitures

2026 Pending Acquisitions
Cornerstone Acquisition. On January 15, 2026, the Company entered into the Cornerstone Merger Agreement with affiliates of Energy Capital Partners to purchase (i) the Lawrenceburg Power Plant, a 1,120 MW natural gas fired combined cycle generation located in Lawrenceburg, Indiana, (ii) the Waterford Energy Center, a 875 MW natural gas fired combined cycle generation plant located in Waterford Township, Ohio; and (iii) the Darby Generating Station, a 456 MW natural gas combustion turbine plant located in Mount Sterling, Ohio, for a price of $ 3.45 billion, consisting of $ 2.55 billion in cash, subject to working capital and other customary adjustments, and 2,400,000 shares of Talen common stock, valued at approximately $ 900 million at the time of entry into the Cornerstone Merger Agreement. The Company expects the cash portion of the purchase price to be funded from the proceeds of new indebtedness. The acquisition will substantially expand Talen’s presence in the western PJM market and add additional efficient baseload generation assets to its fleet.
The transaction is expected to close early in the second half of 2026 and is subject to the satisfaction of customary closing conditions, including the expiration or termination of the waiting period pursuant to the Hart-Scott-Rodino Act of 1976, and regulatory approvals from the Federal Energy Regulatory Commission, Indiana Utility Regulatory Commission and other regulatory agencies.

2025 Acquisitions
Freedom and Guernsey Acquisitions. On November 25, 2025, the Company purchased all the ownership interests of Freedom and Guernsey, which increases the Company’s generating capacity by approximately 2.8 GW and provides efficient baseload generation and cash flow diversification. TES paid an aggregate purchase price of $ 3.8 billion in cash, paid transaction costs of $ 43 million presented as “Other operating income (expense), net” on the Consolidated Statements of Operations, and incurred deferred finance costs and original issuance discounts of $ 64 million presented as “Long-term debt” on the Consolidated Balance Sheets. See Note 10 for information on recent financing transactions related to the Freedom and Guernsey Acquisitions.

As the acquisition is a business combination, provisional fair value measurements were allocated to acquired assets and assumed liabilities with no resulting goodwill or bargain purchase adjustments. As such fair value measurements are provisional, revisions may occur up to one year from the date of acquisition as new information is obtained. The following table summarizes the provisional purchase price allocation for the identifiable assets acquired and liabilities assumed:

November 25,
2025
Cash and cash equivalents
$ 47  
Accounts receivable 29  
Other assets
10  
Property, plant, and equipment
4,509  
Fair value of assets acquired
$ 4,595  

Accounts payable and other accrued liabilities $ 28  
Derivative instruments
49  
Other liabilities
11  
Acquired fuel supply contract liabilities
667  
Fair value of liabilities assumed
$ 755  
Aggregate purchase price
$ 3,840  

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The fair values allocated to property, plant, and equipment were determined using the income approach valuation technique that discounted the projected future net cash flows expected to be generated by Freedom and Guernsey over their remaining economic lives utilizing market participant discount rates. Significant assumptions included the forecasted prices for capacity, wholesale power, and natural gas, volumetric assumptions, and discount rates.
Freedom and Guernsey are each party to long-term natural gas purchase agreements with third parties. Under the terms of the arrangements, the suppliers each provide a significant amount of the natural gas required to generate power at the facilities and expire in July 2028 for Freedom and February 2033 for Guernsey. The price paid for natural gas under each contract is variable based on changes to their respective market prices earned for electric generation. Accordingly, as the wholesale price of power at each facility increases or decreases, the prices paid for fuel under the long-term contracts result in corresponding changes. As the acquired fuel supply arrangements meet executory contract accounting requirements, their acquisition fair values were measured as of the acquisition date and presented as “Acquired fuel supply contract liabilities” on the Consolidated Balance Sheets. Such liabilities are expected to amortize as reductions to “Fuel and energy purchases” on the Consolidated Statement of Operations through expiry.
The fair values allocated to acquired fuel supply contracts were determined using the income approach valuation technique that discounted the projected future net cash flows expected to be paid under the long-term fuel contracts through their expiration dates utilizing market participant discount rates. Significant assumptions included the forecasted prices for wholesale power and natural gas, volumetric assumptions, and discount rates.

Impact of Freedom and Guernsey Acquisitions. The following table presents revenues and earnings included in the Consolidated Statements of Operations for Freedom and Guernsey since the acquisition date (November 25, 2025) through December 31, 2025 (Successor):

Year ended December 31, 2025
Operating Revenues $ 153  
Net Income (Loss) Attributable to Stockholders 62  

Pro Forma Financial Information. The following unaudited pro forma financial information for the years ended December 31, 2025 (Successor) and 2024 (Successor) assumes the Freedom and Guernsey Acquisitions occurred on January 1, 2024. The unaudited pro forma financial information is provided for information purposes only and is not necessarily indicative of the results of operations that would have occurred had the Freedom and Guernsey Acquisitions been completed on January 1, 2024, nor is the unaudited pro forma financial information indicative of future results of operations.

Year ended December 31, 2025 Year ended December 31, 2024
Operating Revenues $ 3,346   $ 2,704  
Net Income (Loss) Attributable to Stockholders ( 146 ) 902  

Amortization of Acquired Fuel Supply Contracts. The acquisition fair value of natural gas fuel supply contracts presented as “Acquired fuel supply contract liabilities” on the Consolidated Balance Sheets is subject to periodic amortization. Amortization associated with these contracts was $ 6 million for the year ended December 31, 2025 (Successor) and presented as a reduction to “Fuel and energy purchases.”
The estimated future amortization as of December 31, 2025 (Successor) is:

2026 2027 2028 2029 2030 Thereafter (a)
Total
Estimated amortization of acquired fuel supply contract liabilities
$ 93   $ 101   $ 102   $ 83   $ 84   $ 198   $ 661  

__________________
(a) Contracts expire in 2028 and 2033.

2025 Divestitures
Camden and Dartmouth Sales. In September 2025, we sold the Camden and Dartmouth generation facilities to an unaffiliated party for a combined as-adjusted purchase price of $ 25 million in cash, subject to further post-closing adjustments. A gain on sale of $ 22 million is presented as “Gain (loss) on sale of assets, net” on the Consolidated Statements of Operations for the year ended December 31, 2025 (Successor).
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2024 Divestitures
ERCOT Sale. In May 2024, we sold our 1,710 MW Texas generation portfolio to CPS Energy for $ 785 million, subject to customary net working capital adjustments. A gain on sale of $ 564 million is presented as “Gain (loss) on sale of assets, net” on the Consolidated Statements of Operations for the year ended December 31, 2024 (Successor).
AWS Data Campus Sale. In March 2024, AWS purchased substantially all the assets related to the AWS Data Campus and certain other assets for gross proceeds of $ 650 million, of which $ 350 million were received at closing with the remaining $ 300 million held in escrow until August 2024. For the year ended December 31, 2024 (Successor), a $ 324 million gain on sale is presented as “Gain (loss) on sale of assets, net” on the Consolidated Statements of Operations. In connection with the AWS Data Campus Sale, the Company entered into the initial AWS PPA. In June 2025, the Company and AWS entered into a revised AWS PPA, under which the Company is expected to provide AWS with up to 1,920 MW of “front-of-the-meter” power through 2042. The transition to the revised AWS PPA is expected to occur in Spring 2026.

2023 Divestitures
Western Gas Book Divestiture. In April 2023, Talen sold certain contracts relating to the transportation of natural gas in the southwestern United States for $ 15 million. For the period from January 1 through May 17, 2023 (Predecessor), a $ 15 million gain was presented as “Gain (loss) on sale of assets, net” on the Consolidated Statements of Operations.
Pennsylvania Minerals Divestiture. In March 2023, Talen sold certain mineral interests located in Pennsylvania for $ 29 million, while preserving the right to certain royalty payments from existing and future producing natural gas wells. For the period from January 1 through May 17, 2023 (Predecessor), a $ 29 million gain was presented as “Gain (loss) on sale of assets, net” on the Consolidated Statements of Operations.

18. Segments
Talen’s operating segments are based on the market areas in which our generation facilities operate and reflect the manner in which our Chief Executive Officer, who is the chief operating decision maker (the “CODM”), reviews results. Adjusted EBITDA is the key profit metric used by the CODM to review segment performance and allocate resources as it provides a clearer view of segment profitability by focusing on operational performance. Total assets or other asset metrics are not considered a key metric or reviewed by the chief operating decision maker.
“PJM” is engaged in electricity generation, marketing activities, and commodity risk and fuel management within the PJM market and is comprised of Susquehanna and Talen’s natural gas and coal generation facilities in PJM.
“Other” represents an operating segment that includes the operating and marketing activities of Talen Montana’s proportionate share of Colstrip in the WECC market and other non-material operating and development activities. “Other” also includes the operating activities of Nautilus until Bitcoin mining operations were suspended in October 2024 and the operating activities of our Texas power generation facilities in the ERCOT market prior to their disposition in May 2024. We have determined it appropriate to aggregate results of Talen’s remaining non-reportable segments and other operating activities.
“Corporate and Eliminations” represents a non-reportable segment that includes: (i) general and administrative expenses incurred by our corporate function; (ii) interest expense and other corporate activities not allocated to our operating segments; and (iii) intercompany eliminations. This grouping is presented to reconcile the reportable segments to our consolidated results.
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PJM Other Corporate and Eliminations Total
Year Ended December 31, 2025 (Successor)
Operating revenues $ 2,477   $ 161   $ ( 57 ) $ 2,581  
Operation, maintenance and development expenses (a)
586   34  
Interest expense and other finance charges —   —   302   302  
Other segment items (b)
817  
Adjusted EBITDA
1,074  
Capital expenditures 195   3   8   206  

Year Ended December 31, 2024 (Successor)
Operating revenues $ 1,866   $ 367   $ ( 118 ) $ 2,115  
Operation, maintenance and development expenses (a)
518   74  
Interest expense and other finance charges —   —   238   238  
Other segment items (b)
573  
Adjusted EBITDA
775  
Capital expenditures 164   24   1   189  

May 18 through December 31, 2023 (Successor)
Operating revenues $ 1,120   $ 397   $ ( 173 ) $ 1,344  
Operation, maintenance and development expenses (a)
294   78  
Interest expense and other finance charges —   —   176   176  
Other segment items (b)
449  
Adjusted EBITDA
377  
Capital expenditures 110   45   6   161  

January 1 through May 17, 2023 (Predecessor)
Operating revenues $ 1,052   $ 195   $ ( 37 ) $ 1,210  
Operation, maintenance and development expenses (a)
245   47  
Interest expense and other finance charges —   —   163   163  
Other segment items (b)
119  
Adjusted EBITDA
688  
Capital expenditures 132   53   2   187  

__________________
(a) This significant segment expense category aligns with the segment-level information that is regularly provided to the CODM.
(b) Other segment items are primarily comprised of fuel and energy purchases.
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Reconciliation of segment Adjusted EBITDA to Income (Loss) Before Income Taxes:

Successor Predecessor
Year Ended December 31, 2025 Year Ended December 31, 2024 May 18 through December 31, 2023 January 1 through May 17, 2023

PJM Segment Adjusted EBITDA $ 1,074   $ 775   $ 377   $ 688  

Reconciling Items:
Interest expense and other finance charges $ ( 302 ) $ ( 238 ) $ ( 176 ) $ ( 163 )
Depreciation, amortization and accretion (a)
( 266 ) ( 281 ) ( 157 ) ( 200 )
Nuclear fuel amortization (a)
( 97 ) ( 123 ) ( 108 ) ( 33 )
Reorganization income (expense), net (Note 20) (b)
—   —   —   799  
Unrealized gain (loss) on commodity derivative contracts ( 106 ) 62   52   ( 63 )
Nuclear decommissioning trust funds gain (loss), net 182   178   108   57  
Stock-based and other long-term incentive compensation expense (Note 13) (b)
( 535 ) ( 54 ) ( 21 ) —  

Gain (loss) on asset sales, net (Note 17) (b)
34   884   7   50  
Non-cash impairments and other charges (c)
( 11 ) ( 24 ) ( 15 ) ( 438 )
Legal settlements and litigation costs
( 6 ) ( 4 ) 84   ( 1 )
Acquisition and divestiture activities (d)
( 65 ) ( 62 ) —   —  

Operational and other restructuring activities (e)
( 21 ) ( 9 ) ( 30 ) ( 19 )

"Other" operating segment 32   71   113   37  
Noncontrolling interest —   21   42   14  
Corporate and Eliminations ( 71 ) ( 76 ) ( 64 ) ( 30 )
Other items ( 8 ) ( 9 ) ( 18 ) ( 21 )
Income (Loss) Before Income Taxes $ ( 166 ) $ 1,111   $ 194   $ 677  

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(a) Includes the periodic amortization of fair value adjustments associated with acquired executory contracts and intangible assets.
(b) See the corresponding Note to the Annual Financial Statements for additional information.
(c) Includes impairments, net realizable value adjustments and other write-offs. See Note 7 for additional information associated with the Brandon Shores impairment group recognized during the period of January 1 through May 17, 2023 (Predecessor).
(d) Includes the non-recurring: (i) advisory fees associated with completed acquisitions and divestitures; (ii) remaining settlements on contracts of divested assets; and (iii) non-recurring finance fees charged to the Consolidated Statement of Operations associated with acquisition financing fee arrangements.
(e) Non-recurring severance and retention costs and strategic initiative costs.

19. Emergence from Restructuring

Voluntary Reorganization Under Chapter 11 of the U.S. Bankruptcy Code
In May 2022, TES and 71 of its subsidiaries voluntarily commenced the Restructuring under Chapter 11 of the U.S. Bankruptcy Code. TEC joined the Restructuring in December 2022. The Plan of Reorganization was approved by the requisite parties and confirmed by the bankruptcy court in late 2022, and was consummated and became effective in May 2023, when TEC, TES, and the other debtors emerged from the Restructuring.
Prior to and during the Restructuring, TES and its debtor subsidiaries reached a number of settlements with various stakeholders (including certain holders of claims under TES’s prepetition indebtedness, certain affiliates Riverstone Holdings, LLC (“Riverstone”) (which then held all of the equity in TEC), TEC, and the Official Committee of Unsecured Creditors), the terms of which were incorporated into the Plan of Reorganization. Under the settlements, the Company agreed to conduct a common equity rights offering, which certain holders of prepetition unsecured notes agreed to backstop in exchange for subscription rights to purchase 30 % of the new equity issued plus a backstop premium payment in the form of cash and (or) new equity.

Restructuring Transactions and Emergence
The Restructuring transactions were completed, and the Company emerged from the Restructuring, on May 17, 2023. Pursuant to the Plan of Reorganization, among other things:
• Claims against TEC were paid in full in cash or reinstated. All existing equity interests in TEC were extinguished, and new equity interests in TEC were issued as follows:
• Holders of unsecured claims under TES’s prepetition indebtedness (including the backstopping holders) received: (i) TEC equity; and (ii) subscription rights to purchase additional TEC equity in the equity rights offering.
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Item 8. Table of Contents

• The equity rights offering was consummated, resulting in $ 1.4 billion in net cash proceeds to the Company. The backstopping holders (i) fully exercised their subscription rights; (ii) were required to purchase additional unsubscribed-for TEC equity; and (iii) were paid the remaining portion of the backstop premium in the form of TEC equity.
• Riverstone received: (i) 1 % of the equity in TEC; (ii) a contingent right to receive additional TEC equity or cash upon certain conditions following Emergence; and (iii) warrants to purchase additional TEC equity. In the third quarter 2023, Riverstone surrendered the warrants and waived its contingent right to additional TEC equity or cash in exchange for $ 40 million in cash.
• The existing intercompany ownership structure of the debtors remained in place and intercompany claims were extinguished.
• The Company consummated its exit financings, comprised of the RCF, TLB-1, TLC, TLC LCF, Bilateral LCF, and Secured Notes. The PEDFA 2009B and 2009C Bonds remained outstanding following the Restructuring.
• The proceeds of the equity rights offering and the exit financings, together with cash on hand, were used to fully repay the Company’s debtor-in-possession credit facilities and to pay $ 3.1 billion relating to other secured claims.
• Holders of other unsecured claims received interests in a designated $ 26 million pool of cash, to which Talen Montana subsequently contributed an additional $ 11 million from proceeds of the PPL/Talen Montana settlement . See Note 9 for additional information on the PPL/Talen Montana settlement.

20. Fresh Start Accounting
At Emergence, TES adopted fresh start accounting as: (i) the holders of existing voting shares before the consummation of the Plan of Reorganization received less than 50 % of the voting shares of the Successor; and (ii) the reorganization value of TES’s assets immediately prior to confirmation of the Plan of Reorganization of $ 7.8 billion was less than the total of post-petition liabilities and allowed claims of $ 9.8 billion. Accordingly, TES allocated its reorganization value to its individual assets based on their estimated fair values.