Talen Energy Corp (TLN)

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.

Item 7. Combined Management's Discussion and Analysis of Financial Condition and Results of Operations

This "Item 7. Combined Management's Discussion and Analysis of Financial Condition and Results of Operations" is separately filed by Talen Energy Corporation and Talen Energy Supply. Any information contained herein relating to an individual registrant is filed by such registrant solely on its own behalf, and neither registrant makes any representation as to information relating to the other registrant except that information relating to Talen Energy Supply and its subsidiaries is also attributed to Talen Energy Corporation and information relating to the subsidiaries of Talen Energy Supply is also attributed to Talen Energy Supply. As Talen Energy Corporation is substantially comprised of Talen Energy Supply and its subsidiaries, most disclosures refer to Talen Energy and are intended to be applicable to both registrants.  When identification of a particular registrant or subsidiary is considered important to understanding the matter being disclosed, the specific entity's name is used, in particular, for those few disclosures that apply only to Talen Energy Corporation. Each disclosure referring to a subsidiary applies to both Talen Energy Corporation and Talen Energy Supply and each disclosure referring to Talen Energy Supply applies to Talen Energy Corporation through consolidation.

Talen Energy Corporation's obligation to report under the Securities and Exchange Act of 1934, as amended, commenced on May 1, 2015, the date Talen Energy Corporation's Registration Statement on Form S-1 relating to the spinoff transaction was declared effective by the SEC. Talen Energy Supply is a separate registrant and considered the predecessor of Talen Energy Corporation, and therefore, the financial information prior to June 1, 2015 presented in this Annual Report on Form 10-K for both registrants includes only legacy Talen Energy Supply information. From June 1, 2015, upon completion of the spinoff and acquisition, Talen Energy Corporation's and Talen Energy Supply's consolidated financial information also includes RJS. As such, Talen Energy Corporation's and Talen Energy Supply's consolidated financial information presented in this Annual Report on Form 10-K for 2015 represents twelve months of legacy Talen Energy Supply information consolidated with seven months of RJS information from June 1, 2015, while 2014 and 2013 represent only legacy Talen Energy Supply information.

The following should be read in conjunction with the registrants' Consolidated Financial Statements and accompanying Notes.  Capitalized terms and abbreviations are defined in the glossary.  Dollars are in millions, except per share data, unless otherwise noted.

"Management's Discussion and Analysis of Financial Condition and Results of Operations" includes the following information:

Overview

Talen Energy is a North American competitive power generation and marketing company headquartered in Allentown, Pennsylvania. Talen Energy produces and sells electricity, capacity and ancillary services from its fleet of power plants totaling approximately 17,400 MW at December 31, 2015, principally located in the Northeast, Mid-Atlantic and Southwest regions of the U.S. See "Item 2. Properties" for additional information on Talen Energy's power plants. For a more detailed description of Talen Energy's business, see "Item 1. Business."

32

Table of Contents

Business Strategy

Talen Energy seeks to optimize the value from its competitive power generation assets and marketing portfolio while mitigating near-term volatility in both cash flow and earnings metrics. Talen Energy endeavors to accomplish this by matching projected output from its generation assets with forward power sales in the wholesale and retail markets while effectively managing exposure to fuel price volatility, counterparty credit risk and operational risk. Talen Energy is focused on safe, reliable, and resilient operations, disciplined capital investment, portfolio optimization, cost management and the pursuit of value enhancing growth opportunities.

To manage financing costs and access to credit markets, and to fund capital expenditures and growth opportunities, a key objective of Talen Energy is to maintain adequate liquidity capacity. In addition, Talen Energy has a financial risk management policy and operational procedures that, among other things, are designed to monitor and manage exposure to earnings and cash flow volatility related to, as applicable, changes in energy and fuel prices, interest rates, counterparty credit quality and the operating performance of generating units. To manage these risks, Talen Energy generally uses contracts such as forwards, options, swaps and insurance contracts primarily focused on mitigating cash flow volatility within the next 12 month period.

Key Performance Measures

In addition to operating income (loss), Talen Energy utilizes Adjusted EBITDA and Margins, both non-GAAP financial measures, as indicators of performance for its business, with Adjusted EBITDA as the primary financial performance measure used by management to evaluate its business and monitor results of operations. Results for the years ended December 31 were as follows.

See "Results of Operations" for a detailed analysis of Talen Energy's results, the definitions of Margins and Adjusted EBITDA and a reconciliation of these non-GAAP measures to related GAAP measures.

Executive Summary

The increase in Margins, a primary driver to changes in the other three earnings measures reflected above, was primarily due to a $237 million increase related to the RJS and MACH Gen generating facilities acquired in 2015.

The declines in operating income (loss) and net income (loss) were substantially due to non-cash goodwill and other asset impairment charges recorded in 2015. Net income (loss) was also negatively impacted by an $80 million after-tax charge related to a debt extinguishment in 2015, and net income (loss) in 2014 benefited from a $206 million after-tax gain on the sale of the hydroelectric generating facilities in Montana. See Note 6 to the Financial Statements for additional information on the sale of the hydroelectric generating facilities.

Several of the key financial and operational developments that impacted results for the year ended December 31, 2015 were as follows:

33

Table of Contents

In addition to the impairment assessments that resulted in these charges, management also tested its coal-fired generation facilities located primarily within the PJM market for impairment and concluded that the plants were not impaired at December 31, 2015. The recoverability assessment is very sensitive to forward energy and capacity price assumptions as well as forecasted operation and maintenance and capital spending and further declines could negatively impact future testing results. The carrying value of these coal-fired generation facilities was more than $3 billion as of December 31, 2015. See Notes 14 and 16 to the Financial Statements for additional information on the impairment testing that occurred and the charges recorded in 2015.

Key Competitive Power Business Dynamics

Electricity, natural gas and capacity prices are significant contributors to the profitability of Talen Energy's portfolio. A discussion of the general factors and current market conditions affecting these commodities and Talen Energy's operations follows.

34

Table of Contents

Electricity Prices

Electricity prices impact Talen Energy's operations. The price for electricity varies by region and can be influenced by a host of supply and demand factors including, but not limited to, generator availability, market design, fuel prices for power generators, transmission congestion, demand growth and seasonality. In 2015, delivered prices for electricity fell, relative to 2014 delivered prices, across the competitive power markets in which Talen Energy operates, primarily driven by unusual market and weather volatility in the first quarter of 2014 and a continued decline in natural gas prices, which are discussed below.

The table below reflects the average around-the-clock day ahead electricity prices at various pricing points located near Talen Energy's power plants for the years ended December 31.

If a decline in electricity prices driven by declining gas prices persists, Talen Energy will likely experience lower energy Margins at its coal-fired and nuclear generation facilities as higher priced hedges expire. To mitigate the impact of the declining Margins on coal-fired and nuclear generation facilities, as described above, Talen Energy is pursuing opportunities to modify certain of its coal-fired generation facilities to be capable of operating on both coal and natural gas, as well as evaluating cost reduction measures at these facilities.

In November 2015, the FERC issued an order on "Price Formation" in the energy and ancillary service markets. These changes and future changes signaled by the FERC in that order may eventually improve pricing and thus compensation for generators in the energy and ancillary services markets, but no assurances can be given that will occur.

In December 2015, the FERC accepted a previously submitted PJM proposal that permits cost-based offers to exceed $2,000/MWh in certain circumstances but limits cost-based offers to $2,000/MWh for the purpose of setting locational marginal prices. Under the proposal, market-based offers are permitted to rise along with cost-based offers but are not permitted to exceed $2,000/MWh or the corresponding cost-based offers. Moreover, electricity providers will be permitted to recover actual costs above $2,000MWh through make-whole payments. In addition, electricity prices will be permitted to rise to $3,700/MWh during certain shortage pricing events. The changes became effective in December 2015.

However, in January 2016, as a part of the Price Formation efforts, the FERC issued a Notice of Proposed Rulemaking (NOPR) for comment which requires each RTO, including PJM, to cap each resource's incremental electricity offer to the higher of $1,000/MWh or that resource's verified cost-based incremental electricity offer. Under this proposal, verified cost-based incremental electricity offers above $1,000/MWh would be used for purposes of calculating Locational Marginal Prices. Comments on this NOPR are due within 60 days and final FERC action on this proposed ruling could modify the above December 2015 acceptance of the PJM proposal.

Capacity Prices

Capacity prices are another key source of revenue for Talen Energy’s operations. Currently, about 80% of Talen Energy's generation capacity is located in markets with a capacity product, including assets in PJM, NYISO and ISO-NE. Similar to electricity, capacity prices are affected by supply and demand fundamentals such as power plant additions and retirements, imports/exports of capacity from/to adjacent markets, costs associated with plant retrofits, risk premiums associated with penalties for non-performance, demand response products, ISO demand forecasts and reserve margin targets. Over the past three auction cycles, capacity prices have increased in PJM and ISO-NE, primarily attributable to incentive-based changes in the capacity market structures designed to improve operational availability during periods of peak demand.

35

Table of Contents

The table below reflects the cleared capacity prices for the zones in which the majority of Talen Energy's plants are located for the three most recent strip auctions.

As a result of unusual market and weather volatility in the first quarter of 2014, PJM determined that changes were necessary to ensure system reliability. In December 2014, PJM proposed to add an enhanced Capacity Performance (CP) product to the capacity market structure to permit additional compensation for generation owners/operators to make the necessary investments to maintain system reliability in exchange for stronger performance requirements, with higher penalties for non-performers. In June 2105, the FERC issued an order approving the PJM CP proposal largely as it was filed and the CP product is being phased in through the 2020/2021 auction based on a percentage of capacity to meet reliability requirements. The phase in percentage was set at 60% for 2016/2017, 70% for 2017/2018 and 80% for both 2018/2019 and 2019/2020. 2020/2021 will be the first auction to procure 100% of the CP product. In August 2015, PJM completed the first base residual auction inclusive of a CP product for the planning year 2018/2019 and subsequently, in late August and September 2015, PJM completed the two CP transitional auctions for planning years 2016/2017 and 2017/2018. The first CP product implementation will begin on June 1, 2016 for the portion procured in the 2016/2017 transitional auction.

In December 2015, PJM altered its process for forecasting load beginning with the most recent 2016 "Load Processing Report" to reflect a shorter period for historical weather data, updated end usage data, and the inclusion of distributed solar generation. The revised process lowered the load forecast. This reduction in load is expected to put downward pressure on PJM capacity prices.

In January 2016, the U.S. Supreme Court reversed the ruling of the U.S. Court of Appeals for the D.C. Circuit Court and upheld the FERC's jurisdiction over rules regarding DR in organized markets. Therefore, DR will be permitted to continue to participate in future PJM energy and capacity auctions.

Natural Gas Prices

Natural gas prices are a key aspect of the current competitive power environment. The extensive development of major shale formations in the U.S. over the past few years has caused natural gas prices to decline. Power prices have also declined substantially due to the high degree of correlation with natural gas prices, weak general economic conditions and other factors. As a result, Talen Energy has experienced a shift in the dispatching of its generation fleet from coal-fired to gas-fired generation.

Environmental Regulations

Talen Energy is subject to extensive federal, state and local environmental laws, rules and regulations, including those pertaining to CCRs, GHG, effluent limitation guidelines and MATS.  In 2015, the EPA published the final rules related to GHG regulations for new and existing power plants that could have a significant industry-wide impact. Talen Energy is in the process of evaluating these rules. See "Financial Condition - Environmental Matters" below for additional information on these requirements.  In 2015, Talen Energy recorded increases to existing AROs of $41 million as a result of a review of the 2015 CCR rule. Further changes to AROs may be required as estimates are refined and compliance with the rule continues.

36

Table of Contents

Other Regulatory Matters

There have been attempts in Ohio by certain companies to have their utilities be permitted to subsidize several uneconomic merchant generation assets owned by non-utility affiliates. Those attempts are being opposed by many generator and consumer interests both in Ohio and at the FERC. Additional efforts to oppose on grounds of federal preemption may also be made in Federal Court. If approved and not reversed, out of market subsidies could be disruptive to the market signals for competitive generation and threaten the long-term viability of PJM's markets. It is too early to predict the outcome of these efforts to subsidize uneconomic generators in Ohio.

Talen Energy cannot predict the impact that future economic and market conditions and regulatory requirements may have on its financial condition or results of operations.

Results of Operations

As a result of the RJS Power acquisition on June 1, 2015, results for RJS (since the date of acquisition) are included in Talen Energy's 2015 results with no comparable amounts in 2014 and 2013. When discussing Talen Energy's results of operations for 2015 compared with 2014, the results of RJS are isolated for purposes of comparability (if significant). At acquisition, the Sapphire operations were classified as discontinued operations. However, in November 2015, when the FERC approved the third mitigation package excluding the Sapphire portfolio, the assets and liabilities and operating results were reclassified to held and used and to continuing operations, as it is no longer probable that the Sapphire portfolio will be sold.

As a result of the MACH Gen acquisition on November 2, 2015, results for MACH Gen (since the date of acquisition) are included in Talen Energy's 2015 results with no comparable amounts in 2014 and 2013. When discussing Talen Energy's results of operations for 2015 compared with 2014, the results of MACH Gen are isolated for purposes of comparability (if significant).

Talen Energy is organized in two segments: East and West, based on geographic location. The East segment includes the generating, marketing and trading activities in PJM, NYISO and ISO-NE. The West segment includes the generating, marketing and trading activities located in ERCOT and WECC. See Note 2 to the Financial Statements for additional information on Talen Energy's segments and the segment reevaluation.

The discussion within "Statement of Income Analysis" addresses significant changes in principal line items on the Statements of Income comparing 2015 with 2014 and 2014 with 2013 on a GAAP basis. The "Margins" discussion, presented by segment, includes a reconciliation of that non-GAAP financial measure to operating income(loss). The "EBITDA and Adjusted EBITDA" discussion, also presented by segment, includes a reconciliation of those non-GAAP financial measures to operating income (loss) and consolidated net income (loss).

Earnings in future periods are subject to various risks and uncertainties. See "Forward-Looking Information," "Item 1. Business," "Item 1A. Risk Factors," the rest of this "Item 7. Combined Management's Discussion and Analysis of Financial Condition and Results of Operations" and Note 11 to the Financial Statements for a discussion of the risks, uncertainties and factors that may impact future earnings.

37

Table of Contents

Statement of Income Analysis, Margins, EBITDA and Adjusted EBITDA

Statement of Income Analysis --

See below for a discussion of the components of the changes to Net Income (Loss) for the periods. The changes in Net Income (Loss) and Operating Income (Loss) from period to period were, in part, attributable to the acquisition of RJS Power, MACH Gen and several items that management believes are not indicative of ongoing operations. See "EBITDA and Adjusted EBITDA" below for information on the items management does not believe are indicative of ongoing operations.

Energy-Related Businesses

Net contributions to the East segment's operating income (loss) from energy-related businesses decreased by $4 million in 2015 compared with 2014. Net contributions to the East segment's operating income (loss) increased by $13 million in 2014 compared with 2013. During 2014, Talen Energy recorded a $17 million increase to "Energy-related businesses" revenues on the 2014 Statements of Income related to prior periods and the timing of revenue recognition for a mechanical contracting and engineering subsidiary. See Note 1 to the Financial Statements for additional information. Excluding the impact of the 2014 adjustment, the change in 2015 compared with 2014 was an increase of $13 million due to higher margins on existing construction projects at the mechanical contracting and engineering subsidiaries. The change in 2014 compared with 2013 was primarily due to the $17 million revenue adjustment.

38

Table of Contents

Operation and Maintenance

The increase (decrease) in operation and maintenance was due to:

Loss on Lease Termination

A $697 million charge was recorded in 2013 for the termination of the Colstrip operating lease to facilitate the sale of the Montana hydroelectric generating facilities. See Note 6 to the Financial Statements for additional information.

Impairments

Impairments in 2015 primarily include a $465 million goodwill impairment, a $175 million impairment of the Sapphire plants and a $14 million impairment of the C.P. Crane plant (all included in the East segment). 2013 includes a $65 million impairment of the Corette plant (included in the West segment). These impairments exclude those recorded to "Income (Loss) from Discontinued Operations (net of income taxes)" on the 2014 Statement of Income. See Note 16 to the Financial Statements for additional information.

39

Table of Contents

Depreciation

Depreciation increased by $59 million in 2015 compared with 2014, primarily due to increases in the East and West segments of $31 million and $25 million, primarily related to the acquisitions of RJS Power and MACH Gen. There are no comparable amounts in 2014 and 2013 for RJS or MACH Gen as their acquisition occurred in 2015.

Depreciation decreased by $2 million in 2014 compared with 2013, primarily due to an $8 million increase in the East segment and a $10 million decrease in the West segment. The increase in the East segment was partially due to $13 million from PP&E additions in part due to the completed Holtwood expansion project in 2013. The decrease in the West segment was primarily due to decreases from the impairment of the Corette plant and the write off of leasehold improvement assets in conjunction with the termination of the operating lease at the Colstrip facility, both of which occurred in 2013. See Note 14 to the Financial Statements for additional information on the Corette impairment and Note 6 to the Financial Statements for information on the Colstrip operating lease termination.

Taxes, Other Than Income

Taxes, other than income increased by $8 million for 2015 compared with 2014. This increase was primarily due to $11 million related to RJS, $7 million impacting the East segment and $4 million impacting the West segment. Taxes other than income increased by $4 million in 2014 compared with 2013, within the East segment. There are no comparable amounts in 2014 and 2013 for RJS as the acquisition occurred in 2015.

Other Income (Expense) - net

Other income (expense) - net decreased by $148 million in 2015 compared with 2014 and decreased by $2 million in 2014 compared with 2013. The decrease in 2015 compared with 2014 was primarily due to the recording of a $134 million charge for a termination payment to a remarketing dealer related to an October 2015 debt extinguishment and a $9 million decrease in 2015 in net earnings on the NDT funds. See Note 5 for additional information on the debt extinguishment. The decrease in 2014 compared with 2013 resulted from 2013 including a gain of $8 million related to adjustments to liabilities for a former mining subsidiary partially offset by a $5 million increase in 2014 in net earnings on the NDT funds.

Interest Expense

The increase (decrease) in interest expense was due to:

40

Table of Contents

Income Taxes

The increase (decrease) in income taxes was due to:

See Note 4 to the Financial Statements for additional information.

Income (Loss) from Discontinued Operations (net of income taxes)

Income (Loss) from Discontinued Operations (net of income taxes) for 2014 and 2013 includes the Montana hydroelectric generating facilities which were sold in November 2014.  See Note 6 to the Financial Statements for additional information.

Margins

Management utilizes "Margins," a non-GAAP financial measure, as an indicator of performance for its business.

"Margins" is defined as energy revenues offset by the cost of fuel, energy purchases, certain operation and maintenance expenses, primarily ancillary charges, and gross receipts tax, recorded in "Taxes, other than income." This performance measure is relevant due to the volatility in the individual revenue and expense lines on the Statements of Income that comprise "Margins." This volatility stems from a number of factors, including the required netting of certain transactions with ISOs, RTOs and significant fluctuations in unrealized gains and losses. Such factors could result in gains or losses being recorded in either "Wholesale energy," "Retail energy" or "Energy purchases" on the Statements of Income. This performance measure includes PLR revenues from energy sales to PPL Electric by Talen Energy Marketing, which prior to June 1, 2015, are reflected in "Wholesale energy to affiliate" in the reconciliation table below. "Margins" excludes unrealized (gains) losses on: energy related economic activity, which includes the changes in fair value of positions used to economically hedge a portion of the economic value of the competitive generation assets, full-requirement sales contracts and retail activities; and trading activities. These derivatives are subject to changes in fair value due to market price volatility of the input and output commodities (e.g., fuel and power) prior to the delivery period that was hedged or when realized. Energy related economic activity includes premium amortization associated with options. Unrealized gains and losses related to derivatives and premium amortization associated with options are deferred and included in "Margins" over the delivery period of the item that was hedged or upon realization.

This measure is not intended to replace "Operating Income (Loss)," which is determined in accordance with GAAP, as an indicator of overall operating performance. Other companies may use different measures to analyze and report their results of operations. Management believes this measure provides additional useful criteria to make investment decisions. This

41

Table of Contents

performance measure is used, in conjunction with other information, by senior management to manage Talen Energy's operations and analyze actual results compared with budget.

Reconciliation of Margins

The following tables contain the components from the Statements of Income that are included in Margins and a reconciliation to "Operating Income (Loss)" for the years ended December 31.

42

Table of Contents

million. See Note 1 to the Financial Statements for additional information on the revenue adjustment. 2015, 2014 and 2013 includes OCI amortization on non-active derivative positions of $(11) million, $(11) million and $(13) million.

Changes in Margins

The following table shows Margins by segment for the years ended December 31, as well as the change between periods. Margins do not include operations related to those assets classified as discontinued operations. The factors that gave rise to the changes are described following the table.

East Segment

East segment Margins increased $162 million in 2015 from the Raven and Sapphire portfolios. There are no comparable amounts in the 2014 or 2013 periods as the acquisition of Raven and Sapphire occurred during 2015.

Excluding the impact of the Raven, Sapphire and MACH Gen acquisitions, East segment Margins increased in 2015 compared with 2014 by $22 million primarily due to higher realized energy prices of $68 million, improved spark spreads of $59 million, higher nuclear availability of $51 million and lower average fuel prices of $24 million, substantially offset by lower capacity prices of $55 million, gains realized in 2014 on certain commodity positions of $46 million, the net effect of unusual market and weather volatility in the first quarter of 2014 as discussed below of $38 million, lower volumes on full-requirement sales contracts of $25 million and retail electric activity of $12 million.

East segment Margins decreased in 2014 compared with 2013 primarily due to lower realized energy prices of $354 million and lower capacity prices of $34 million, partially offset by favorable asset performance of $70 million, gains realized in 2014 on certain commodity positions of $46 million, unusual market and weather volatility in 2014 as discussed below of $38 million and gas optimization of $26 million.

During the first quarter of 2014, the PJM region experienced unusually cold weather conditions, higher demand and congestion patterns, causing rising natural gas and electricity prices in spot and near-term forward markets. Due to these market dynamics, Talen Energy captured opportunities on unhedged generation, which were offset primarily by losses incurred by under-hedged full-requirement sales contracts and retail electric portfolios, which were not fully hedged or able to be fully hedged given the higher load conditions and lack of market liquidity.

West Segment

West segment Margins increased $68 million in 2015 compared with 2014 from the Jade portfolio. There are no comparable amounts in the 2014 and 2013 periods as the acquisition of Jade occurred during 2015.

EBITDA and Adjusted EBITDA

In addition to operating income (loss), EBITDA and Adjusted EBITDA, non-GAAP financial measures are other indicators of performance for Talen Energy's business, with Adjusted EBITDA as the primary financial performance measure used by management to evaluate its business and monitor results of operations.

EBITDA represents net income (loss) before interest expense, income taxes, depreciation and certain amortization. Adjusted EBITDA represents EBITDA further adjusted for certain non-cash and other items that management believes are not indicative of ongoing operations including, but not limited to, unrealized gains and losses on derivative contracts, stock-based compensation expense, asset retirement obligation accretion, impairments, gains and losses on securities in the NDT funds, gains or losses on sales, dispositions or retirements of assets, debt extinguishments and transition, transaction and restructuring costs.

EBITDA and Adjusted EBITDA are not intended to represent cash flows from operations, operating income (loss) or net income (loss) as defined by U.S. GAAP as indicators of operating performance and are not necessarily comparable to similarly-

43

Table of Contents

titled measures reported by other companies. Management cautions investors that amounts presented in accordance with Talen Energy's definitions of EBITDA and Adjusted EBITDA may not be comparable to similar measures disclosed by other companies because not all companies calculate EBITDA and Adjusted EBITDA in the same manner. Talen Energy believes EBITDA and Adjusted EBITDA are useful to investors and other users of these financial statements in evaluating Talen Energy's operating performance because they provide additional tools to compare business performance across companies and across periods. Talen Energy believes that EBITDA is widely used by investors to measure a company's operating performance without regard to such items as interest expense, income taxes, depreciation and amortization, which can vary substantially from company to company depending upon accounting methods and book value of assets, capital structure and the method by which assets were acquired. Additionally, Talen Energy believes that investors commonly adjust EBITDA information to eliminate the effect of restructuring and other expenses, which vary widely from company to company and impair comparability. Talen Energy adjusts for these and other items, as management believes that these items would distort their ability to efficiently view and assess the company's core operating trends. In summary, management primarily uses Adjusted EBITDA as a measure of operating performance to assist in comparing performance from period to period on a consistent basis and to readily view operating trends, as a measure for planning and forecasting overall expectations and for evaluating actual results against such expectations, as a measure of certain corporate financial goals used to determine variable compensation and in communications with the Talen Energy Corporation Board of Directors, senior management, shareholders, creditors, analysts and investors concerning Talen Energy's financial performance.

Reconciliations of EBITDA and Adjusted EBITDA

The tables below provide reconciliations of EBITDA and Adjusted EBITDA to operating income (loss) on a segment basis and to net income (loss) on a consolidated basis for the years ended December 31.