Talen Energy Corp (TLN) FY 2024 MD&A

ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following Management’s Discussion and Analysis of Financial Condition and Results of Operations should be read in conjunction with the Annual Financial Statements and the accompanying notes. The discussion contains forward-looking statements as well as estimates regarding market and industry data, which involve risks, uncertainties, and assumptions. See “Cautionary Note Regarding Forward-Looking Information” and “Market and Industry Data” for additional information. Dollars are in millions, unless otherwise noted.

Recent Developments

Common Stock Transactions

Share Repurchases. During the year ended December 31, 2024 (Successor), we repurchased and retired a total of 13,227,222 shares, or approximately 22%, of TEC’s outstanding common stock through a combination of the SRP and direct repurchases from affiliates of Rubric Capital Management LP (collectively, “Rubric”). A total of: (i) 7,307,300 shares were purchased from Rubric; (ii) 5,275,862 shares through a tender offer; and (iii) 644,060 shares in the open market. The aggregate purchase price after transaction fees and excise tax was approximately $2.0 billion at a weighted average price of $149.50 per share. As of December 31, 2024 (Successor), the remaining capacity under the SRP is approximately $1.1 billion through 2026.

See Note 18 to the Annual Financial Statements for additional information on the SRP, other share repurchases, and other common stock transactions.

Financing Transactions

Secured Notes Consent. In January 2025, we received consents from noteholders representing a majority in principal amount of the Secured Notes to adopt certain amendments to the Indenture to, among other things: (i) modify certain provisions, including certain covenants and related definitions, in order to substantially conform to the corresponding amendments to the Credit Agreement obtained in the December 2024 transactions discussed below; and (ii) waive TES’s right to optionally redeem up to 10% of the Secured Notes at a price of 103% of par prior to June 1, 2025.

December 2024 Financing Activities. In December 2024, we completed several financing transactions that resulted in the: (i) issuance of $380 million in net additional long-term indebtedness through full repayment of the TLC utilizing restricted cash collateralizing the TLC and issuance of the TLB-2 (at an initial rate of SOFR + 2.5%); (ii) issuance of the new $900 million LCF and termination of the TLC LCF and Bilateral LCF, which had the combined effect of increasing our LC capacity by $355 million; and (iii) favorable repricing and covenant improvements on the existing TLB-1 and RCF (repriced to initial rates of SOFR + 2.5% and SOFR + 2.0%, respectively) as well an extension of the RCF maturity. The proceeds of the TLB-2 issuance were used, together with cash on hand, to repurchase shares of our outstanding common stock held by Rubric.

See Note 13 to the Annual Financial Statements for additional information on long-term debt, other credit facilities, and recent financing activities.

Power Transactions

AWS PPA. In connection with the AWS Data Campus Sale in 2024, we and AWS entered into the AWS PPA, pursuant to which we agreed to supply long-term, carbon-free power from Susquehanna to the AWS Data Campus through fixed-price power commitments. Under the AWS PPA, AWS has minimum contractual power commitments that increase in 120 MW increments annually (or earlier, at AWS’s option), with a one-time option to either cap commitments at 480 MW or otherwise purchase, in continuing annual steps, up to 960 MW. Each step up in capacity commitment has a fixed price for an initial 10-year term, after which AWS has the option to renew each step at a price that includes a fixed margin above then-applicable PJM energy and capacity prices. The initial term of the AWS PPA is 18 years, with two 10-year extensions at AWS’s option. Under a separate agreement, we will receive additional revenue from AWS related to the sales of carbon-free energy to the grid. We expect to begin receiving initial revenues from power sales in 2025. See Note 20 to the Annual Financial Statements for additional information on the AWS Data Campus Sale.

Susquehanna ISA Amendment. In November 2024, FERC issued an order denying the Susquehanna ISA Amendment between PJM, PPL Corporation, and Susquehanna that would permit Susquehanna to decrease the amount of power supply it would otherwise provide to the power grid. Such order does not have an impact on the existing ISA permitting 300 MW of co-located load at Susquehanna to supply power for the first phases of the AWS Data Campus. In December 2024, FERC issued an order stating that it would address our request for rehearing in a future order, which FERC has not yet issued. Due to FERC’s decision not to address the merits of our motion for rehearing, we have filed an appeal in the U.S. Court of Appeals for the Fifth Circuit. Delivery “behind-the-meter” of more than 300 MW of power under the AWS PPA requires that FERC approve an amended ISA between Susquehanna, PPL, and PJM. Without an amendment we will be unable to deliver the full amount of contract volume under the AWS PPA on a behind-the-meter basis, which may require a contract renegotiation to deliver the additional power “in-front-of-the-meter.” See “Item 3. Legal Proceedings” and “Item 1A. Risk Factors—Regulatory, Environmental, and Legal Risks—Our business is subject to extensive energy-related regulation and oversight.” for additional information on the Susquehanna ISA Amendment.

32

Form 10-K Table of Contents

Brandon Shores and H.A Wagner RMR Arrangements. In 2023, we notified PJM of our intent to deactivate electric generation at both our Brandon Shores and H.A. Wagner facilities on June 1, 2025. However, PJM subsequently notified us that both Brandon Shores and H.A Wagner are needed past their previously planned retirement dates to maintain reliability in PJM. In January 2025, we reached a settlement (which remains subject to FERC approval) with key stakeholders on the terms of an RMR arrangement and filed with FERC the resulting Joint Offers of Settlement regarding both facilities’ RMR Continuing Operations Rates Schedules. If approved, the proposed RMR arrangements will extend the operating life of these plants through May 31, 2029, or until such time as the necessary transmission upgrades are placed into service. See Note 10 to the Annual Financial Statements for additional information on the RMR proceedings and settlement and the related impairment of the Brandon Shores asset group.

Factors Affecting Our Financial Condition and Results of Operations

Earnings in future periods are subject to various uncertainties and risks. See “Cautionary Note Regarding Forward-Looking Information,” “Item 1A. Risk Factors,” and Notes 5 and 12 to the Annual Financial Statements for additional information on our risks.

Commodity Markets

During 2024, natural gas prices for Texas Eastern M-3 settled below their ten-year average as a result of natural gas storage levels above the five-year average and abundant natural gas supplies. In PJM, periodic below average temperatures during the winter and above average temperatures during the summer contributed to increased load demand that resulted in higher annual settled on-peak power prices compared with the prior year.

The weighted average settled on-peak power prices and natural gas prices for the PJM market for the years ended December 31, 2024 (Successor), December 31, 2023 (Successor), and December 31, 2022 (Predecessor) were:

As of December 31, 2024 (Successor), the weighted average forward market prices for the following years were:

__________________

(a)Spark spreads are computed based on day-ahead West Hub ATC prices, TETCO M-3 natural gas prices, and a heat rate of 7 MMBtu/MWh.

As of December 31, 2023 (Successor), the weighted average forward market prices for the following years were:

__________________

(a)Spark spreads are computed based on day-ahead West Hub ATC prices, TETCO M-3 natural gas prices, and a heat rate of 7 MMBtu/MWh.

(b)Represents forward prices for 2024 as of December 31, 2023 (Successor). See weighted average settled prices table above for 2024 realized prices.

Capacity Markets

Our generation capacity is located primarily in markets with capacity products, which are intended to ensure long-term grid reliability for customers by securing sufficient power supply resources to meet predicted future demand. Capacity prices are affected by supply and demand fundamentals, such as generation facility additions and retirements, capacity imports from and exports to adjacent markets, generation facility retrofit costs, non-performance risk premium penalties, demand response products, RTO/ISO demand forecasts, reserve margin targets, and (in PJM) adjustments to the PJM Market Seller Offer Cap as determined by the PJM Independent Market Monitor.

33

Form 10-K Table of Contents

PJM Capacity Auctions. Under the PJM Reliability Pricing Model, when held on schedule, the PJM Base Residual Auction is required to be conducted in the month of May three years prior to the start of the applicable PJM Capacity Year in order for PJM to secure commitments from capacity resources. The results of each PJM BRA impact our capacity revenues for the specific PJM Capacity Year. However, PJM has delayed its recent BRAs, which has resulted in less than 3 years between each auction and the start of the relevant PJM Capacity Year. The BRA for the 2025/2026 Capacity Year, which was the most recent auction, was held in July 2024. The BRA for the 2026/2027 Capacity Year is currently delayed until July 2025. The capacity market construct provides generation owners some opportunity for revenue visibility on a multiyear basis and is intended to provide a price signal for new generation to be built in the future. See Note 12 to the Annual Financial Statements for additional information on the PJM capacity market, systemic risks, BRA delays, and related legal actions.

Capacity Prices. The following table displays the cleared capacity prices for completed PJM BRAs for the markets and zones in which we primarily operate:

__________________

(a)Displayed prices are from the applicable market publications.

For the 2025/2026 Capacity Year, we cleared a total of 6,820 MW at a clearing price of $269.92 per MW-day for the MAAC, PPL, and PSEG locational deliverability areas.

Capacity Performance Event. As a result of Winter Storm Elliott in December 2022, PJM experienced extreme cold weather conditions that resulted in PJM’s declaration of a Capacity Performance event requiring generators to operate at their maximum output capacity. Certain of our generation facilities failed to meet PJM’s Capacity Performance requirements while others met or exceeded their obligations. As a result, we incurred final aggregate net Capacity Performance penalties of $29 million, which were remitted during the period from May 18 through December 31, 2023 (Successor) and the period from January 1 through May 17, 2023 (Predecessor). See Note 12 to the Annual Financial Statements for additional information.

Nuclear Production Tax Credit

The Inflation Reduction Act was signed into law in August 2022. Among the Act’s provisions are amendments to the Internal Revenue Code to create a nuclear production tax credit program. The Nuclear PTC program provides qualified nuclear power generation facilities with a transferable tax credit for electricity produced and sold to an unrelated party during each tax year. The credit provides support beginning when annual gross receipts decline below an equivalent $43.75/MWh, increases ratably up to $3/MWh when annual gross receipts are equivalent to $25/MWh, and is subject to potential adjustments including inflation escalators and a five-times increase in value (up to $15/MWh) for meeting prevailing wage requirements (which we expect to meet). Electricity produced and sold by Susquehanna to third parties from December 31, 2023 through December 31, 2032 will be eligible for the credit. See Notes 6 and 7 to the Annual Financial Statements for additional information on Nuclear PTC revenue recognized and the Inflation Reduction Act.

Seasonality/Scheduled Maintenance

The demand for and market prices of electricity and natural gas are affected considerably by weather and, as a result, our operating results may fluctuate significantly on a seasonal basis. In general, below-average temperatures in the winter and above-average temperatures in the summer tend to increase electricity demand, energy prices, and revenues. Alternatively, moderate temperatures tend to decrease electricity demand and may adversely affect resulting energy margins, particularly in PJM. In addition, our operating expenses typically fluctuate geographically on a seasonal basis, with peak power generation and expenses during the winter in the Mid-Atlantic. We ordinarily perform planned facility maintenance during milder non-peak demand periods in the spring and fall to ensure reliability during peak periods. The pattern of fluctuations in our operating results varies depending on the type and location of the facilities being serviced, the capacity markets served, the maintenance requirements of our facilities, and the terms of bilateral contracts to purchase or sell electricity. Our largest recurring maintenance project is the annual spring refueling outage at Susquehanna. We serve our fossil generation fleet through a combination of self-service and contracted maintenance activity (including long-term service agreements at certain facilities). See also “Item 1A. Risk Factors—Industry and Market Risks—Our business is subject to physical, market, economic, and regulatory risks relating to weather conditions and extreme weather events.”

34

Form 10-K Table of Contents

Results of Operations

The results of operations presented below should be reviewed in conjunction with the Annual Financial Statements and the related notes. Our financial results for the year ended December 31, 2024 (Successor) and for the period from May 18 through December 31, 2023 (Successor) are referred to as the “Successor” periods. Our financial results for the period from January 1 through May 17, 2023 (Predecessor) and the year ended December 31, 2022 (Predecessor) are referred to as the “Predecessor” periods. The operating results for the Successor Periods are not comparable with the operating results for the Predecessor Periods due to the application of fresh start accounting after Emergence in May 2023. See Notes 2, 3, and 4 to the Annual Financial Statements for additional information regarding the Restructuring and related accounting. Our results of operations as reported in the Annual Financial Statements are prepared in accordance with GAAP.

In the explanations below, “Energy and other revenues” and “Fuel and energy purchases” are evaluated collectively because the price for power is generally determined by the variable operating cost of the next marginal generator dispatched to meet demand. “Energy and other revenues” relate to sales to an RTO or ISO, sales under wholesale bilateral contracts, realized hedging activity, Bitcoin revenue, and Nuclear PTC revenue. “Fuel and energy purchases” includes costs for fuel to generate electricity and settlements of financial and physical transactions related to fuel and energy purchases.

In addition, unrealized gains (losses) on derivative instruments resulting from changes in fair value during the periods are presented separately as revenues within “Operating Revenues” and expenses within “Energy Expenses” in the Annual Financial Statements. We evaluate them collectively because they represent the changes in fair value of our economic hedging activities.

Results for the Year Ended December 31, 2024 (Successor), the Period from May 18 through December 31, 2023 (Successor), the Period from January 1 through May 17, 2023 (Predecessor), and the Year Ended December 31, 2022 (Predecessor)

The following table and subsequent sections display the results of operations for the Successor and Predecessor periods:

35

Form 10-K Table of Contents

Successor Period — Year Ended December 31, 2024

Net Income (Loss) Attributable to Stockholders totaled $998 million for the year ended December 31, 2024 (Successor). Results were driven by:

•Capacity Revenues totaled $192 million. This primarily included earned capacity awards based on resource clearing prices received from the PJM BRAs for the 2023/2024 and 2024/2025 PJM Capacity Years.

•Energy and Other Revenues, net of Fuel and Energy Purchases totaled $1.2 billion. This consisted of: (i) $1.3 billion in third-party wholesale electricity sales and ancillary revenues; (ii) $325 million in other revenue primarily related to Nuclear PTC and Bitcoin revenue; and (iii) $230 million in net realized gains from hedging activities. Such amounts were partially offset by $(659) million in fuel and purchased power costs.

•Unrealized Gain (Loss) on Derivative Instruments totaled $62 million gain, net. This consisted of: (i) unrealized gains from the reversal of positions previously recognized as mark-to-market liabilities which settled during the period; and (ii) unrealized gains incurred as a result of decreases in forward power prices.

•Nuclear Fuel Amortization totaled $(123) million. This consisted of the periodic expense of nuclear fuel costs capitalized as PP&E and $33 million of amortization on certain nuclear fuel contracts that were recognized at fair value at Emergence. See Note 4 to the Annual Financial Statements for additional information.

•Operation, Maintenance and Development totaled $(592) million. This consisted of generation facility operating costs, including employee wages and benefits, the costs of removal, repairs, and maintenance that are not capitalized, contractor costs, and certain materials and supplies.

•Depreciation, Amortization and Accretion totaled $(298) million. This consisted of depreciation of long-lived PP&E, intangibles, and ARO accretion.

•Nuclear Decommissioning Trust Funds Gain (Loss), net totaled $178 million. This consisted of realized and unrealized gains and losses on debt and equity securities, dividends, and interest income associated with NDT investments. See Notes 9 and 14 to the Annual Financial Statements for additional information.

•Interest Expense and Other Finance Charges totaled $(238) million. This primarily consisted of interest expense incurred on the Secured Notes, TLB-1, and TLB-2.

•Gain (Loss) on Sale of Assets, net totaled $884 million. This primarily consisted of the $564 million gain from the ERCOT Sale that closed in May 2024 and the $324 million gain from the AWS Data Campus Sale that closed in March 2024. See Note 20 to the Annual Financial Statements for additional information.

•Other Non-Operating Income (Expense), net totaled $61 million. This primarily consisted of interest income on cash deposits.

•Income Tax Benefit (Expense) totaled $(98) million. This primarily related to federal and state tax expense on pre-tax income, the release of the federal and state valuation allowance, and the exclusion of Nuclear PTC income as a permanent item.

Successor Period — May 18 through December 31, 2023

Net Income (Loss) Attributable to Stockholders totaled $134 million for the period from May 18 through December 31, 2023 (Successor). Results were driven by:

•Capacity Revenues totaled $133 million. This primarily consisted of earned capacity awards based on resource clearing prices received from the PJM BRA for the 2023/2024 PJM Capacity Year. Capacity revenues were positively impacted by $19 million as a result of the FERC-approved settlement agreement for net PJM Capacity Performance penalties assessed related to Winter Storm Elliot. See Note 12 to the Annual Financial Statements for additional information on PJM Capacity Performance penalties.

•Energy and Other Revenues, net of Fuel and Energy Purchases totaled $732 million. This consisted of: (i) $950 million in third-party wholesale electricity sales and ancillary revenues; (ii) $81 million in Bitcoin revenue; and (iii) $33 million in net realized gains from hedging activities. Such amounts were partially offset by $(332) million in fuel and purchased power costs.

•Unrealized Gain (Loss) on Derivative Instruments totaled $52 million gain, net. This consisted of unrealized gains incurred as a result of decreases in forward power prices; and (ii) unrealized gains from the reversal of positions previously recognized as mark-to-market liabilities which settled during the period.

36

Form 10-K Table of Contents

•Nuclear Fuel Amortization totaled $(108) million. This consisted of the periodic expense of nuclear fuel costs capitalized as PP&E and $53 million of amortization on certain nuclear fuel contracts that were recognized at fair value at Emergence. See Note 4 to the Annual Financial Statements for additional information.

•Operation, Maintenance and Development totaled $(358) million. This consisted of generation facility operating costs, including employee wages and benefits, the costs of removal, repairs, and maintenance that are not capitalized, contractor costs, and certain materials and supplies.

•Depreciation, Amortization and Accretion totaled $(165) million. This consisted of depreciation of long-lived PP&E, intangibles, and ARO accretion.

•Nuclear Decommissioning Trust Funds Gain (Loss), net totaled $108 million. This consisted of realized and unrealized gains and losses on debt and equity securities, dividends, and interest income associated with NDT investments. See Notes 9 and 14 to the Annual Financial Statements for additional information.

•Interest Expense and Other Finance Charges totaled $(176) million. This primarily consisted of interest expense incurred on the Secured Notes and TLB-1.

•Other Non-Operating Income (Expense), net totaled $95 million. This primarily consisted of the gain on the PPL/Talen Montana litigation settlement. See Note 12 to the Annual Financial Statements for additional information.

•Income Tax Benefit (Expense) totaled $(51) million. This primarily related to federal and state tax expense on pre-tax income and changes in the valuation allowance. See Note 7 to the Annual Financial Statements for additional information.

Predecessor Period — January 1 through May 17, 2023

Net Income (Loss) Attributable to Member totaled $479 million for the period from January 1 through May 17, 2023 (Predecessor). Results were driven by:

•Capacity Revenues totaled $108 million. This primarily consisted of earned capacity awards based on resource clearing prices received from the PJM BRA for the 2022/2023 PJM Capacity Year. Capacity revenues were negatively impacted by $(13) million of net PJM Capacity Performance penalties related to Winter Storm Elliott. See Note 12 to the Annual Financial Statements for additional information on PJM Capacity Performance penalties.

•Energy and Other Revenues, net of Fuel and Energy Purchases totaled $866 million. This consisted of: (i) $637 million in net realized gains from hedging activities; (ii) $343 million in third-party wholesale electricity sales and ancillary revenues; and (iii) $27 million in Bitcoin revenue. Such amounts were partially offset by $(141) million in fuel and purchased power costs.

•Unrealized Gain (Loss) on Derivative Instruments totaled $(63) million loss, net. This consisted of unrealized losses from the reversal of positions previously recognized as mark-to-market assets which settled during the period, partially offset by unrealized gains incurred as a result of decreases in forward power prices.

•Nuclear Fuel Amortization totaled $(33) million. This consisted of the periodic expense of nuclear fuel costs capitalized as PP&E.

•Operation, Maintenance and Development totaled $(285) million. This consisted of generation facility operating costs, including employee wages and benefits, the costs of removal, repairs, and maintenance that are not capitalized, contractor costs, and certain materials and supplies.

•Depreciation, Amortization and Accretion totaled $(200) million. This consisted of depreciation of long-lived PP&E, intangibles, and ARO accretion.

•Impairments totaled $(381) million. This consisted of the assessment of Brandon Shores asset group recoverability associated with a decision to deactivate Brandon Shores on June 1, 2025. See Note 10 to the Annual Financial Statements for additional information.

•Other Operating Income (Expense), net totaled $(37) million. This primarily consisted of non-cash charges for fuel inventory net realizable value adjustments. See Note 8 to the Annual Financial Statements for additional information.

•Nuclear Decommissioning Trust Funds Gain (Loss), net totaled $57 million. This consisted of realized and unrealized gains and losses on debt and equity securities, dividends, and interest income associated with NDT investments. See Notes 9 and 14 to the Annual Financial Statements for additional information.

•Interest Expense and Other Finance Charges totaled $(163) million. This primarily consisted of interest expense incurred on prepetition indebtedness of TES and the LMBE-MC TLB and certain LC fees.

37

Form 10-K Table of Contents

•Reorganization Income (Expense), net totaled $799 million. This primarily consisted of: (i) a $1.5 billion gain on debt discharge recognized upon Emergence, partially offset by a $(460) million loss on revaluation adjustments; (ii) $(70) million in backstop commitment letters; (iii) $(84) million in professional fees; (iv) and $(46) million for the write-off of the carrying value of prepetition debt issuance costs. See Note 2 to the Annual Financial Statements for additional information.

•Gain (loss) on Sale of Assets, net totaled $50 million. This primarily consisted of gains due to non-recurring sales during the period. See Note 20 to the Annual Financial Statements for additional information.

•Income Tax Benefit (Expense) totaled $(212) million. This primarily related to federal and state tax expense on pre-tax income, reorganization adjustments, and changes in the valuation allowance. See Note 7 to the Annual Financial Statements for additional information.

Predecessor Period — Year Ended December 31, 2022

Net Income (Loss) Attributable to Member totaled $(1.3) billion for the year ended December 31, 2022 (Predecessor). Results were driven by:

•Capacity Revenues totaled $377 million. This primarily consisted of earned capacity awards based on resource clearing prices received from the PJM BRAs for the 2021/2022 and 2022/2023 PJM Capacity Years. Capacity revenues were negatively impacted by $33 million of net PJM Capacity Performance penalties related to Winter Storm Elliott. See Note 12 to the Annual Financial Statements for additional information on PJM Capacity Performance penalties.

•Energy and Other Revenues, net of Fuel and Energy Purchases totaled $1.1 billion. This consisted of: (i) $2.8 billion in third-party wholesale electricity sales and ancillary revenues; (ii) $(513) million in net realized losses from hedging activities; and (iii) $(157) million in losses incurred on early terminated commodity contracts. Such amounts were partially offset by $(1.1) billion in fuel and purchased power costs.

•Unrealized Gain (Loss) on Derivative Instruments totaled $625 million gain, net. This consisted of unrealized gains from the reversal of positions previously recognized as mark-to-market liabilities which settled during the period, coupled with unrealized gains incurred as a result of decreases in forward power prices.

•Nuclear Fuel Amortization totaled $(94) million. This consisted of the periodic expense of nuclear fuel costs capitalized as PP&E.

•Operation, Maintenance and Development totaled $(610) million. This consisted of generation facility operating costs, including employee wages and benefits, the costs of removal, repairs, and maintenance that are not capitalized, contractor costs, and certain materials and supplies.

•Depreciation, Amortization and Accretion totaled $(520) million. This consisted of depreciation of long-lived PP&E, intangibles, and ARO accretion.

•Operational Restructuring totaled $(488) million. This consisted of: (i) a $(453) million loss resulting from charges related to retail power contracts in the PJM market that were rejected in connection with the Reorganization; and (ii) a $(35) million loss primarily due to charges related to long-term service agreements in the ERCOT market that were rejected in connection with the Reorganization.

•Other Operating Income (Expense), net totaled $(40) million. This primarily consisted of: (i) $(17) million of expenses related to environmental liability revisions in the PJM market; and (ii) $(18) million for the estimated costs of a legal settlement.

•Nuclear Decommissioning Trust Funds Gain (Loss), net totaled $(184) million. This consisted of realized and unrealized gains and losses on debt and equity securities, dividends, and interest income associated with NDT investments. See Notes 9 and 14 to the Annual Financial Statements for additional information.

•Interest Expense and Other Finance Charges totaled $(359) million. This primarily consisted of interest expense incurred on prepetition indebtedness of TES and the LMBE-MC TLB and certain LC fees.

•Reorganization Income (Expense), net totaled $(812) million. This consisted of (i) $(310) million in backstop commitment letter premium; (ii) $(210) million for professional fees related to the Restructuring; (iii) $(183) million for make-whole premiums and accrued interest on certain indebtedness; (iv) $(70) million for professional fees incurred to obtain the debtor-in-possession credit agreements; and (v) $(30) million for the write-off of the carrying value of prepetition debt issuance costs.

•Consolidation of Subsidiary Gain (Loss) totaled $(170) million. This consisted of losses recognized from the consolidation of Cumulus Digital due to a change of control.

38

Form 10-K Table of Contents

•Other Non-Operating Income (Expense), net totaled $(44) million. This primarily consisted of non-recurring corporate professional fees associated with liability and other management initiatives.

•Income Tax Benefit (Expense) totaled $35 million. This primarily related to federal and state tax benefit on pre-tax loss, changes in the valuation allowance, and non-deductible transaction costs.

Liquidity and Capital Resources

Our liquidity and capital requirements are generally a function of: (i) debt service requirements; (ii) capital expenditures; (iii) maintenance activities; (iv) liquidity requirements for our hedging activities including cash collateral and other forms of credit support; (v) legacy environmental obligations; (vi) other working capital requirements; and (or) (vii) discretionary expenditures, including share repurchase activities.

Our primary sources of liquidity and capital include available cash deposits, cash flows from operations, amounts available under our debt and credit facilities, and potential incremental financing proceeds. Generating sufficient cash flows for our business is primarily dependent on capacity revenue, the production and sale of power at margins sufficient to cover fixed and variable expenses, hedging strategies to manage price risk exposure, and the ability to access a wide range of capital market financing options.

Our hedging strategy is focused on maintaining appropriate risk tolerances with an emphasis on protecting cash flows across our generation fleet. Our strong balance sheet provides ample capacity and counterparty appetite for lien-based hedging, which limits the use of margin posting requirements. Specifically, our hedging strategy prioritizes a first lien-based hedging program, in which hedging counterparties are granted a lien in the same collateral securing our first-lien debt obligations, while minimizing exchange-based hedging and the associated margin requirements. Additionally, we now have lower overall hedging needs given the cash-flow stability afforded by the Nuclear PTC (which provides a built-in hedging apparatus through the tax credit) and significantly reduced debt service requirements following the Restructuring and subsequent refinancing transactions.

We are partially exposed to financial risks arising from natural business exposures including commodity price and interest rate volatility. Within the bounds of our risk management program and policies, we use a variety of derivative instruments to enhance the stability of future cash flows to maintain sufficient financial resources for working capital, debt service, capital expenditures, debt covenant compliance, and (or) other needs.

See the following Notes to the Annual Financial Statements for additional information on liquidity topics discussed below: Note 5 for derivatives and hedging, Note 11 for AROs and environmental obligations, Note 13 for long-term debt and credit facilities, and Note 19 for supplemental cash flow information.

Liquidity and Letter of Credit Capacity

__________________

(a)As of December 31, 2024 (Successor), all RCF committed capacity can be used for direct cash borrowings and (or) LCs. As of December 31, 2023 (Successor). All RCF committed capacity could be used for direct cash borrowings and up to $475 million of such capacity could be used for LCs.

(b)Excludes LC capacity available under the RCF. Includes (i) LC capacity under the LCF as of December 31, 2024 (Successor); and (ii) aggregate LC capacity under the TLC LCF and Bilateral LCF as of December 31, 2023 (Successor).

Based on current and anticipated levels of operations, industry conditions, and market environments in which we transact, we believe available liquidity from financing activities, cash on hand, and cash flows from operations (including changes in working capital) will be adequate to meet working capital, debt service, capital expenditures, and (or) other future requirements for the next twelve months and beyond. See Note 13 to the Annual Financial Statements for additional information on the RCF and the issuance of the LCF and termination of the TLC LCF and Bilateral LCF in December 2024.

39

Form 10-K Table of Contents

Guarantees and Other Assurances

Guarantees of Subsidiary Obligations. TES guarantees certain agreements and obligations for its subsidiaries. Certain agreements may contingently require payments to a guaranteed or indemnified party. See Note 12 to the Annual Financial Statements for additional information on guarantees.

Financial Performance Assurances. TES has provided financial performance assurances in the form of surety bonds to third parties on behalf of certain subsidiaries for obligations including but not limited to environmental obligations and AROs. Surety bond providers generally have the right to request additional collateral to backstop surety bonds.

Forecasted Uses of Cash

Capital Expenditures. Capital expenditure plans are revised periodically for changes in operational needs, market conditions, regulatory requirements, and cost projections. Accordingly, the expected cash requirements for capital expenditures are subject to revision.

__________________

(a)Expected capitalized interest on capital expenditures is a non-material amount in 2025 and 2026.

Projected ARO and Accrued Environmental Liability Cash Flows. Certain of our subsidiaries have legal obligations to perform significant decommissioning and remediation activities associated with current operations and (or) at former generation facility sites. Our projected undiscounted spending on AROs and environmental liabilities is presented in the table below. The majority of the estimated non-nuclear spend is related to ash impoundments at Colstrip and Brunner Island. Beginning in 2025, we expect to increase our remediation spend associated with our obligations at Colstrip. The carrying value of these obligations includes certain assumptions, including a rate of inflation of 2.50%. Projections are subject to revision based on changes in estimated inflation rates, changes in the estimated timing of settling AROs, and escalating retirement costs. Susquehanna’s AROs are expected to be settled with funds available from the NDT at the time of decommissioning. See Note 11 to the Annual Financial Statements for additional information.

As of December 31, 2024 (Successor), the expected undiscounted payments are estimated to be:

__________________

(a)Certain obligations are: (i) partially supported by surety bonds, some of which have been collateralized with cash and (or) LCs; or (ii) partially prefunded under phased installment agreements.

Indebtedness. See Note 13 to the Annual Financial Statements and “—Recent Developments—Financing Transactions” above for additional information on our indebtedness.

Cash Flow Activities

The net cash provided by (used in) operating, investing, and financing activities for the periods were:

40

Form 10-K Table of Contents

Successor Period — Year Ended December 31, 2024

•Operating Cash Flows. Cash provided by operating activities totaled $256 million.

•Investing Cash Flows. Cash provided by investing activities totaled $1.2 billion. This primarily consisted of $635 million of proceeds from the AWS Data Campus Sale and $763 million of proceeds from the ERCOT Sale. Such amounts were partially offset by: (i) net NDT fund investments of $(32) million; and (ii) capital expenditures of $(189) million, which primarily consisted of $(104) million for nuclear fuel and $(85) million for PP&E. See Note 20 to the Annual Financial Statements for additional information on the AWS Data Campus Sale and the ERCOT Sale.

•Financing Cash Flows. Cash used in financing activities totaled $(2.0) billion. This primarily consisted of: (i) $(2.0) billion for share repurchases; (ii) $(479) million to repay the TLC; (iii) $(182) million for the repayment of the Cumulus Digital TLF; (iv) $(125) million for the repurchases of noncontrolling interests (a) in Cumulus Digital from affiliates of Orion Energy Partners and two former members of Talen senior management, and (b) in Nautilus from TeraWulf; and (v) $(32) million to settle vested restricted stock units in cash. Such amounts were partially offset by $849 million in proceeds from the issuance of new debt. See Notes 13 and 18 to the Annual Financial Statements and “—Recent Developments” above for additional information on debt transactions and share repurchases.

Successor Period — May 18 through December 31, 2023

•Operating Cash Flows. Cash provided by operating activities totaled $402 million. This primarily consisted of: (i) cash provided from operations; and (ii) the net receipt of $104 million related to the settlement of the PPL/Talen Montana litigation. See Note 12 to the Annual Financial Statements for additional information on the PPL/Talen Montana settlement.

•Investing Cash Flows. Cash used in investing activities totaled $(171) million. This primarily consisted of capital expenditures totaling $(161) million, which consisted of: (i) $(116) million for then-current projects, including the Montour gas conversion project and the AWS Data Campus; and (ii) $(45) million related to nuclear fuel expenditures, as we purchased uranium for needs in future periods.

•Financing Cash Flows. Cash used by financing activities totaled $(84) million. This primarily consisted of $(59) million for payments to former affiliates to settle warrants and to repurchase affiliates’ noncontrolling interests in Cumulus Digital.

Predecessor Period — January 1 through May 17, 2023

•Operating Cash Flows. Cash provided by operating activities totaled $462 million.

•Investing Cash Flows. Cash used in investing activities totaled $(157) million. This primarily consisted of capital expenditures totaling $(187) million, which consisted of: (i) $(138) million for then-current projects, including the Montour gas conversion project, the AWS Data Campus, the Nautilus cryptocurrency project, and projects at Susquehanna; and (ii) $(49) million related to nuclear fuel expenditures. Such amounts were offset by $46 million in proceeds from the sale of assets.

•Financing Cash Flows. Cash used in financing activities totaled $(539) million. This primarily consisted of the net effect of issuances and repayments of prepetition debt and make-whole premiums of about $(1.9) billion net cash outflow, partially offset by $1.4 billion cash inflow for a contribution from member.

Predecessor Period — Year Ended December 31, 2022

•Operating Cash Flows. Cash provided by operating activities totaled $187 million.

•Investing Cash Flows. Cash used in investing activities totaled $(368) million. This primarily consisted of: (i) capital expenditures totaling $(312) million, which consisted of: (a) $(232) million for then-current projects, including the Montour gas conversion project and projects at Susquehanna, and (b) $(80) million related to nuclear fuel expenditures; and (ii) $(162) million in equity investments in affiliates. Such amounts were offset by a $123 million increase to cash due to the consolidation of Cumulus Digital.

•Financing Cash Flows. Cash used in financing activities totaled $426 million. This primarily consisted of net proceeds from debtor-in-possession credit facilities of $987 million, after discount and debt issuance costs, partially offset by: (i) repayments on prepetition deferred capacity obligations and inventory repurchase obligations of $(341) million; (ii) $(104) million related to terminations of certain derivative contracts; (iii) $(59) million of deferred financing costs; and (iv) $(52) million related payments of the LMBE-MC TLB.

41

Form 10-K Table of Contents

Non-GAAP Financial Measure

Adjusted EBITDA, which we use as a measure of our performance, is not a financial measure prepared under GAAP. Non-GAAP financial measures do not have definitions under GAAP and may be defined and calculated differently by, and not be comparable to, similarly titled measures used by other companies. Non-GAAP measures are not intended to replace the most comparable GAAP measures as indicators of performance. Generally, a non-GAAP financial measure is a numerical measure of financial performance, financial position, or cash flows that excludes (or includes) amounts that are included in (or excluded from) the most directly comparable measure calculated and presented in accordance with GAAP. Management cautions readers not to place undue reliance on the following non-GAAP financial measure, but to also consider it along with its most directly comparable GAAP financial measure. Non-GAAP measures have limitations as analytical tools and should not be considered in isolation or as a substitute for analyzing our results as reported under GAAP.

Adjusted EBITDA

We use Adjusted EBITDA to: (i) assist in comparing operating performance and readily view operating trends on a consistent basis from period to period without certain items that may distort financial results; (ii) plan and forecast overall expectations and evaluate actual results against such expectations; (iii) communicate with our Board of Directors, shareholders, creditors, analysts, and the broader financial community concerning our financial performance; (iv) set performance metrics for our annual short-term incentive compensation; and (v) assess compliance with our indebtedness.

Adjusted EBITDA is computed as net income (loss) adjusted, among other things, for certain: (i) nonrecurring charges; (ii) non-recurring gains; (iii) non-cash and other items; (iv) unusual market events; (v) any depreciation, amortization, or accretion; (vi) mark-to-market gains or losses; (vii) gains and losses on the NDT; (viii) gains and losses on asset sales, dispositions, and asset retirement; (ix) impairments, obsolescence, and net realizable value charges; (x) interest expense; (xi) income taxes; (xii) legal settlements, liquidated damages, and contractual terminations; (xiii) development expenses; (xiv) noncontrolling interests, except where otherwise noted; and (xv) other adjustments. Such adjustments are computed consistently with the provisions of our indebtedness to the extent that they can be derived from the financial records of the business. Pursuant to TES’s debt agreements, Cumulus Digital contributes to Adjusted EBITDA beginning in the first quarter 2024, following termination of the Cumulus Digital TLF and associated cash flow sweep.

Additionally, we believe investors commonly adjust net income (loss) information to eliminate the effect of nonrecurring restructuring expenses and other non-cash charges, which can vary widely from company to company and from period to period and impair comparability. We believe Adjusted EBITDA is useful to investors and other users of our financial statements to evaluate our operating performance because it provides an additional tool to compare business performance across companies and between periods. Adjusted EBITDA is widely used by investors to measure a company’s operating performance without regard to such items described above. These adjustments can vary substantially from company to company and period to period depending upon accounting policies, book value of assets, capital structure, and the method by which assets were acquired.

42

Form 10-K Table of Contents

The following table presents a reconciliation of the GAAP financial measure of “Net Income (Loss)” presented on the Consolidated Statements of Operations to the non-GAAP financial measure of Adjusted EBITDA:

__________________

(a)See Note 4 to the Annual Financial Statements for additional information.

(b)See Note 20 to the Annual Financial Statements for additional information.

(c)See Note 10 to the Annual Financial Statements for additional information.

(d)See Note 12 to the Annual Financial Statements for additional information.

(e)The year ended December 31, 2024 (Successor) primarily includes the effects of nonrecurring ERCOT hedge settlements that occurred after the ERCOT Sale and severance payments associated with cost reduction initiatives.

(f)The periods from May 18 through December 31, 2023 (Successor) and from January 1 through May 17, 2023 (Predecessor) include the effects of nonrecurring costs associated with exit from the Restructuring, severance costs associated with cost reduction initiatives, and nonrecurring post-Restructuring strategic initiative costs.

(g)The year ended December 31, 2022 (Predecessor) includes non-cash charges for retail contracts terminated in connection with the Restructuring. See Note 4 to the Annual Financial Statements for additional information.

(h)See Note 8 to the Annual Financial Statements for additional information.

Critical Accounting Policies and Estimates

Financial statements prepared in conformity with GAAP require the application of appropriate accounting policies to form the basis of estimates utilizing methods, judgments, and (or) assumptions that materially affect: (i) the measurement and carrying values of assets and liabilities as of the date of the financial statements; (ii) the revenues recognized and expenses incurred during the presented reporting periods; and (iii) financial statement disclosures of commitments, contingencies, and other significant matters. Such judgments and assumptions may include significant subjectivity due to the inherent uncertainties of future events which exist to such an extent that there is a reasonable likelihood that materially different amounts would have been reported under different conditions or if different assumptions had been used. We believe the following areas contain the most significant accounting judgments, the highest levels of subjectivity, or relate to uncertain matters that are susceptible to material changes in estimates that are critical to understanding the Company’s financial results. Due to such inherent uncertainties, actual results may differ substantially from estimates and (or) estimates may change materially in periods where new information becomes known. Management develops these estimates based on best available information, historical experience, and subject matter experts. See Note 2 to the Annual Financial Statements for additional information on accounting policies for each of the following topics.

43

Form 10-K Table of Contents

Derivative Instruments

Derivative instruments, which are deployed by our commercial organization to manage and (or) mitigate market and commodity price risk, are presented on the Consolidated Balance Sheets at fair value and are comprised primarily of power and natural gas commodity contracts. Derivative identification is challenging. While a conventional financially settled contract, such as a swap or option, generally contains standard terms that facilitate its identification as a derivative instrument, judgment is required to determine whether contracts to buy or sell commodities with physical delivery requirements or contracts that contain certain embedded settlement or fluctuating price features meet the definition of a derivative instrument. This judgment typically includes, among other things, an evaluation of the contract, its expected cash flows, and the activity levels of its principal market. Additionally, judgment is required to determine if a commodity contract intended for physical delivery meets an allowable exemption prior to accounting for its income effects under the accrual accounting method rather than at fair value. This typically includes assumptions regarding the probability of physical delivery and the quantities used in normal business activities.

As our derivative contracts generally settle within future time periods supportable by commodity exchange markets and the frequent occurrence of commercial transactions, the majority of our derivative contracts utilize quoted prices in active markets or other observable market inputs to determine fair value. However, such prices are subject to volatility between periods based on weather, local market events, macroeconomic trends, and (or) other events and factors. Accordingly, changes in fair value for contracts identified as derivatives may result in material changes to unrealized gains or losses presented on the Consolidated Statements of Operations between periods. Changes in fair value of commodity derivatives are presented as “Unrealized gain (loss) on derivative instruments” as a component of either “Operating Revenues” or “Fuel and energy purchases” on the Consolidated Statements of Operations, in a consistent manner with the presentation of its realized net gains or losses.

See Note 5 to the Annual Financial Statements for additional information on derivative instruments.

Nuclear Decommissioning Asset Retirement Obligations

We have significant legal obligations associated with Susquehanna’s decommissioning. Susquehanna’s Unit 1 and Unit 2 licenses, if not renewed, will expire in 2042 and 2044, respectively, at or before which time the units will shut down.

Judgment is required to make reasonable ARO assumptions regarding the range of likely outcomes for cost estimates, as these obligations are not expected to be paid until years or decades in the future, and potentially many years after shutdown. Inflation rates and discount rates may be subject to revision until the ARO settlement date. As such, changes in assumptions to the range of likely outcomes could result in different cash outlay for AROs at the settlement date than the current carrying value of the ARO presented on the Consolidated Balance Sheets. Susquehanna periodically assesses its ARO through third-party engineering studies in order to determine expected scope, costs, and timing of decommissioning activities. Generally, its decommissioning cost study is updated approximately every seven years. As part of the cost study update process, we and the third-party engineering firm evaluate cost projections based on the latest engineering techniques and the latest information which incorporates nuclear plant retirements in the industry. We incorporate the results of the study as well as our experience, knowledge, and professional judgment to the specific characteristics of Susquehanna’s decommissioning plan to update the carrying value of the ARO.

AROs are recognized at fair value at the time of installation and as an increase to PP&E. The income effect of AROs is generally presented as “Depreciation, amortization and accretion” on the Consolidated Statements of Operations through the expected ARO settlement date. However, for an asset that has a fully depreciated PP&E carrying value, revisions in ARO estimates have an immediate effect in earnings. Revisions to the estimated ARO are presented as “Other operating income (expense), net” on the Consolidated Statements of Operations.

See Note 11 to the Annual Financial Statements for additional information on AROs.

Recoverability of Long-Lived Assets

PP&E used in operations are assessed for impairment whenever changes in facts and circumstances indicate the carrying amount of the asset group may not be recoverable. Judgment is required to identify these events. In certain instances, the events could be external to us and may include, among other events, changes in the economic environment, such as a decrease in the market price of an asset, significant changes to market rules and regulations in the power markets in which we operate, and changes in federal or state environmental regulations that would materially affect the cash flows of our generation fleet. In other instances, the events result from negative financial trends, physical damage to assets, or decisions of management regarding strategic initiatives, such as sales of assets, generation facility retirements, or significant changes in planned capital expenditures or operating costs.

44

Form 10-K Table of Contents

Individual assets are grouped for impairment 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. There is significant judgment in identifying the lowest level of independent cash flows in the merchant power market, given that certain groups of our generation facilities participate in the same market. In determining the appropriate level of aggregation, we consider the manner in which we make economic decisions regarding the revenue and commercial activities of the generation facilities and the manner in which we make operational and maintenance decisions. Accordingly, we generally aggregate assets for impairment at the reporting unit level, unless there are additional facts and circumstances present which indicate that an asset should be tested for recoverability on a standalone basis. Periodically, we evaluate whether events such as changes in market conditions, regulatory changes, or other events require a change in aggregation.

If there is an indication that the carrying value of an asset group may not be recovered, we review 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 asset group is written down to its estimated fair value. Fair value for PP&E 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 as of the date of the review, such as estimated future generation volumes, capacity prices, energy prices, operating costs, and capital expenditures.

Impairment charges are presented on the Consolidated Statements of Operations in the period in which the impairment determination is made.

See Note 10 to the Annual Financial Statements for additional information on recognized impairments.

Postretirement Benefit Obligations

Certain of our subsidiaries sponsor postemployment benefits that include defined benefit pension plans. Accounting for defined benefit pensions involves significant estimates to determine projected benefit obligations and company contribution requirements, which inherently require assumptions be made regarding many uncertainties. Such uncertainties include discount rates, expected return on assets, expected wages for participants at retirement, estimated retirement dates, and mortality rates. Over a period of time, we are required to fund all vested benefits for postretirement defined benefit pension plans through plan assets, investment returns, or contributions to the plans.

Actuarial assumptions required under GAAP to determine the projected benefit obligations and actuarial assumptions required under ERISA to determine contribution assumptions differ in their objectives. Actuarial assumptions regarding projected benefit obligations under GAAP affect the net periodic defined benefit cost presented within our Consolidated Statements of Operations. Actuarial assumptions used in the computation to estimate required contributions to the defined benefit plans affect funding requirements over a period of time.

We are responsible for the estimates regarding our postemployment benefits. However, we engage actuarial firms, who apply professional standards in the determination of the judgmental assumptions for plan contributions, to estimate both the contribution requirements for postemployment benefits and the associated projected benefit obligations under GAAP.

Projected benefit obligations are particularly sensitive to expected return on plan assets and the discount rate. The expected return on plan assets is the estimated long-term rates of return on plan assets that will be earned over the life of each plan. These projected returns reduce the net periodic defined benefit costs. The discount rate is used to compute the present value of benefits, which is based on projections of benefit payments to be made in the future. The objective in selecting the discount rate is to measure the single amount that, if invested at the measurement date in a portfolio of high-quality debt instruments, would provide the necessary future cash flows to pay the accumulated benefits when due. Please see Note 15 to the Annual Financial Statements for the weighted-average assumptions used for the discount rate and expected return on plan assets for all plans.

A variance in the discount rate or expected return on plan assets could have a significant impact on postretirement benefit obligations and annual net periodic pension costs. The following table displays the estimated increase (decrease) for defined benefit pension plans of a 1% increase and a 1% decrease in the discount rate and expected return on plan assets on the postretirement benefit obligation and net periodic pension cost as of December 31, 2024 (Successor).

45

Form 10-K Table of Contents

Income Taxes

Significant management estimates and judgments are involved to determine the provision for income taxes, deferred tax assets and liabilities, and valuation allowances.

An assessment is performed on a quarterly basis to determine the likelihood of realizing deferred tax assets. We assess the probability of realizing deferred tax assets by evaluating historical income after adjusting for certain nonrecurring items for purposes of projecting future income, our intent and ability to implement tax planning strategies, and performing scheduling of the reversal of temporary differences. We also evaluate negative evidence, such as the expiration of historical operating loss or tax credit carryforwards, that could indicate an inability to realize deferred tax assets. Based on the combined assessment, we recognize valuation allowances for deferred tax assets when it is more likely than not such benefit will not be realized in future periods.

Actual income taxes could vary from estimated amounts due to the future impacts of various items, including changes in income tax laws, forecasted financial conditions, and results of operations in future periods, as well as results of audits and examinations of filed tax returns by taxing authorities. See Note 7 to the Annual Financial Statements for additional information on income taxes.

Recent Accounting Pronouncements

See Note 2 to the Annual Financial Statements for a description of recently adopted accounting pronouncements and recently issued accounting pronouncements not yet adopted.