Talen Energy Corp 10-Q

ITEM 2. 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 Interim Financial Statements, the Annual Financial Statements, and their accompanying notes. In addition, the following discussion contains forward-looking statements, which involve risks and uncertainties. See “Cautionary Note Regarding Forward-Looking Information” for additional information on forward-looking statements. Capitalized terms and abbreviations are defined in the glossary. Dollars are in millions, unless otherwise noted. Overview Talen owns and operates power infrastructure in the United States. We produce and sell electricity, capacity, and ancillary services into wholesale power markets in the United States, primarily in PJM and WECC, with our generation fleet principally located in the Mid-Atlantic region of the United States and Montana. The majority of our generation is produced at our zero-carbon nuclear and lower-carbon gas-fired facilities. As of September 30, 2024 (Successor), our generation capacity was 10,676 MW (summer rating). Talen is headquartered in Houston, Texas. Recent Developments Susquehanna ISA Amendment On November 1, 2024, FERC issued an order denying the amended interconnection service agreement between PJM, PPL, and Susquehanna that would permit Susquehanna to decrease the amount of power supply that would otherwise be provided to the power grid. Such order does not have an impact on the existing interconnection service agreement permitting 300 MW of co-located load at Susquehanna to supply power for the first phases of the AWS data center campus. See Note 10 in Notes to the Interim Financial Statements for additional information on the Susquehanna ISA Amendment. Purchase of TeraWulf’s Minority Interest in Nautilus In October 2024, the Company: (i) increased its ownership in Nautilus to 100% by completing the strategic acquisition of TeraWulf’s 25% interest in Nautilus in exchange for $85 million in cash; (ii) caused Nautilus to distribute all of the Bitcoin miners that were used in the operations of Nautilus to TeraWulf; and (iii) suspended operational activities at Nautilus as the Company continues to advance its strategic alternatives for the asset. Subsequent to the acquisition, Nautilus continues to be party to both the ground lease agreement and the submetered power arrangement with AWS. See our Registration Statement for additional information on the Nautilus ground lease and submetered power arrangements. Additional Increase of Share Repurchase Program Capacity In September 2024, the Board of Directors approved an increase of the Company’s share repurchase program to a remaining capacity of $1.25 billion through December 31, 2026. As of September 30, 2024 (Successor), the company had repurchased approximately 14% of its outstanding shares of common stock for a total of $952 million, exclusive of transaction cost and excise tax. See Note 15 in Notes to the Interim Financial Statements for additional information. Common Stock Transactions In the three months ended September 30, 2024 (Successor), the Company repurchased a total of 2,559,826 shares of the Company’s common stock under its share repurchase program for an aggregate purchase price of $304 million, inclusive of transaction costs and excise taxes, at a weighted average per share price of $118.82. Of the total shares repurchased during the period, 2,413,793 shares were purchased from affiliates of Rubric Capital Management LP in July 2024. In the three months ended September 30, 2024 (Successor), the Company retired 2,564,853 shares repurchased and settled during the period. In July 2024, a former executive exercised equity-classified warrants to 457,142 shares of the Company’s common stock in a non-cash transaction. After giving effect to the non-cash exercise and related tax withholding, the Company issued 160,289 shares of the Company’s common stock. As of November 14, 2024, the Company has 50,855,417 shares of common stock outstanding. See Note 15 in Notes to the Interim Financial Statements for additional information related to share repurchases and the retirement of treasury stock. Receipt of Cumulus Data Campus Sale Funds Previously Held in Escrow In August 2024, as the result of achieving development milestones under its agreement with AWS governing the Cumulus Data Campus Sale, the Company received the remaining $300 million of sales proceeds that were held in escrow. See Note 17 to the Interim Financial Statements for additional information on the Cumulus Data Campus Sale. 31 PJM 2025/2026 Base Residual Auction In July 2024, PJM reported the results of the PJM BRA for the 2025/2026 PJM Capacity Year. Talen 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. 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” and Notes 3 and 10 in Notes to the Interim Financial Statements for additional information on our risks. Generation Facility Updates PJM RMR Assessments. In the first quarter 2023, the project to convert Brandon Shores’ fuel source from coal to fuel oil was canceled for economic reasons, which resulted in non-cash impairment charges related to property, plant, and equipment and inventories. In April 2023, Brandon Shores notified PJM that it will deactivate electric generation on June 1, 2025. In June 2023, PJM notified Brandon Shores that its generation Units 1 and 2 are needed for reliability. In October 2023, for economic reasons, the Company provided a notice to PJM that it intends to deactivate H.A. Wagner on June 1, 2025. In January 2024, PJM notified H.A Wagner that its generation Units 3 and 4 are needed for reliability. Each generation facility has filed a cost-of-service rate schedule at FERC, which was accepted in June 2024, subject to refund. Additionally, an administrative settlement judge was appointed in June 2024 and settlement proceedings have commenced. No assurance can be provided as to when, if at all, a final rate schedule will be accepted by FERC or how the rate schedule and resulting revenues may be modified in the course of settlement judge procedures, or, should they be necessary, in the course of any subsequent evidential hearing. See Note 8 in Notes to the Interim Financial Statements for additional information on the reliability assessments and related impairment of the Brandon Shores asset group. Commodity Markets The following tables summarize average on-peak power prices and natural gas prices for the PJM market for the three months ended September 30, 2024 (Successor) and 2023 (Successor). During the third quarter 2024, natural gas prices for Texas Eastern M-3 settled below their ten-year average resulting from storage levels above the five-year average and ample supply. In PJM, higher than normal temperatures during the quarter contributed to increased power load resulting in higher settled on-peak power prices compared to the same period in the prior year. PJM . The weighted average settled market prices for the three months ended September 30 were: 2024 2023 PJM West Hub Day Ahead Peak - $/MWh $ 50.03 $ 42.93 PJM PPL Zone Day Ahead Peak - $/MWh 37.54 29.46 PJM BGE Zone Day Ahead Peak - $/MWh 69.60 53.27 Texas Eastern M-3 - $/MMBtu 1.50 1.39 The PJM West Hub Day Ahead Peak 2024 quarter weighted average settled prices increased approximately 17% compared to the prior year. The weighted average forward market prices for the periods from October 1 through December 31 as of September 30: 2024 2023 PJM West Hub ATC - $/MWh $ 42.67 $ 41.32 Texas Eastern M-3 - $/MMBtu 2.47 2.68 PJM West Hub ATC Spark Spreads (a) 25.34 22.53 __________________ (a) Spark spreads are computed based on day-ahead West Hub ATC prices, TETCO M-3 gas prices, and a heat rate of 7 MMBtu/MWh. Capacity Markets Our generation capacity is located 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, ISO demand forecasts, reserve margin targets, and adjustments to PJM Market Seller Offer Cap as determined by the PJM Independent Market Monitor. PJM Capacity Auctions. Under its reliability pricing model, PJM conducts a series of capacity auctions. Most capacity is procured in the auctions conducted each May for the delivery of generation capacity for the PJM Capacity Year, which is three 32 years from the date of the auction. Capacity auctions have recently been delayed, resulting in the auctions being held with less than 3 years between the auctions and the PJM Capacity Year, with the most recent auction held in July 2024. The capacity market construct provides generation owners the opportunity for some revenue visibility on a multiyear basis. The results of each of these auctions impacts Talen's capacity revenues in the specific PJM Capacity Year. See “Capacity Prices” below for additional information on capacity prices and see Note 10 in Notes to the Interim Financial Statements for additional information on PJM matters, including recent developments related to potential delays in future PJM BRAs. Capacity Prices. The following table displays the cleared capacity prices for completed PJM BRAs for the markets and zones in which we primarily operate: 2025/2026 2024/2025 2023/2024 2022/2023 PJM Capacity Performance ($/MW-day) (a) MAAC $ 269.92 $ 49.49 $ 49.49 $ 95.79 PPL 269.92 49.49 49.49 95.79 __________________ (a) Displayed prices are from the applicable market publications. Nuclear Production Tax Credit The Inflation Reduction Act of 2022 was signed into law in August 2022. Among the Act’s provisions are amendments to the Internal Revenue Code of 1986 to create a Nuclear PTC program. The Nuclear PTC program provides qualified nuclear power generation facilities with a $3 per MWh transferable credit for electricity produced and sold to an unrelated party during each tax year. Electricity produced and sold by Susquehanna after December 31, 2023 through December 31, 2032 may be eligible for the credit, which is subject to potential adjustments. Such adjustments include inflation escalators, a five-times increase in tax credit value (to $15 per MWh) if the qualifying generation facility meets prevailing wage requirements, and a pro-rata decrease in tax credit value once the annual gross receipts of a qualifying generation facility exceeds $25 per MWh. As the credit is eliminated when the annual gross receipts are equivalent to $43.75 per MWh (adjusted for inflation), the Nuclear PTC program is expected to create a minimum price Susquehanna is expected to receive for its generation. Susquehanna generated approximately 18 million MWh in each of the calendar years 2023, 2022, and 2021. The credit would be: Annual Gross Receipts Credit Amount $25 per MWh or less $15 per MWh Greater than $25 per MWh Ratably reduced until gross receipts equal $43.75 per MWh, $0 after that threshold The Inflation Reduction Act’s provisions are subject to implementation regulations, whose terms are not yet known. No assurance can be provided as to the magnitude of the benefit to Susquehanna as the Inflation Reduction Act’s provisions, including the computations of the Nuclear PTC, are subject to implementation regulations that could impact the credit value recognized to date and credit value available in future periods. As such, Talen cannot fully predict the realization of any minimum price for Susquehanna’s generation and (or) impacts to Talen’s liquidity or results of operations. See Note 4 in Notes to the Interim Financial Statements for additional information on Nuclear PTC revenue recognized. Seasonality/Scheduled Maintenance The demand for and market prices of electricity and natural gas are affected by weather. As a result, our operating results in the future may fluctuate substantially on a seasonal basis. For example, a lack of sustained cold weather in the Mid-Atlantic region may suppress regional natural gas prices and reduce our future capacity and energy revenues. Alternatively, above-average temperatures in the summer tend to increase summer cooling electricity demand, energy prices, and revenues, and below-average temperatures in the winter tend to increase winter heating electricity demand, energy prices, and revenues. Inversely, the milder weather during spring and fall tend to decrease the need for both cooling electricity demand and heating electricity demand. In addition, our operating expenses typically fluctuate on a seasonal basis, with peak power generation during the winter in the Mid-Atlantic region. We ordinarily perform facility maintenance during lower or non-peak demand periods to ensure reliability during periods of peak usage. The pattern of the fluctuations in our operating results varies depending on the type and location of the power generation facilities being serviced, the capacity markets served, the maintenance requirements of our facilities, and the terms of bilateral contracts to purchase or sell electricity. The largest recurring maintenance project is the annual spring refueling outage at Susquehanna. The outages normally occur during late March and into April each year. Susquehanna Unit 1 entered its spring refueling outage on March 25, 2024 and successfully completed the outage on April 25, 2024. 33 Results of Operations The results of operations presented below should be reviewed in conjunction with the Interim Financial Statements, the Annual Financial Statements, and their respective notes. Our financial results for the three months ended September 30, 2024, the nine months ended September 30, 2024, and for the period May 18 through September 30, 2023 are referred to as the “Successor” periods. Our financial results for the period from January 1 through May 17, 2023 are referred to as the “Predecessor” period. The operating results for the nine months ended September 30, 2024 cannot be adequately compared with any of the previous periods reported in the Interim Financial Statements or Annual Financial Statements. Our results of operations as reported in the Interim 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 revenues relate to sales to an ISO or RTO, sales under wholesale bilateral contracts or 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 period are presented separately as revenues within “Operating Revenues” and expenses within “Total Energy Expenses” in the Interim Financial Statements. We evaluate them collectively because they represent the changes in fair value of Talen’s economic hedging activities. Results for the Three Months Ended September 30, 2024 (Successor) and the Three Months Ended September 30, 2023 (Successor) The following table and subsequent section display the results of operations: Successor (Millions of Dollars) Three Months Ended September 30, 2024 Three Months Ended September 30, 2023 Favorable (Unfavorable) Variance Capacity revenues $ 50 $ 44 $ 6 Energy and other revenues 505 600 (95) Unrealized gain (loss) on derivative instruments (Note 3) 95 (128) 223 Operating Revenues (Note 4) 650 516 134 Fuel and energy purchases (222) (253) 31 Nuclear fuel amortization (30) (47) 17 Unrealized gain (loss) on derivative instruments (Note 3) 7 44 (37) Energy Expenses (245) (256) 11 Operating Expenses Operation, maintenance and development (127) (140) 13 General and administrative (38) (37) (1) Depreciation, amortization and accretion (Note 8) (75) (66) (9) Impairments (Note 8) — (2) 2 Other operating income (expense), net (7) (8) 1 Operating Income (Loss) 158 7 151 Nuclear decommissioning trust funds gain (loss), net 67 (24) 91 Interest expense and other finance charges (Note 11) (66) (68) 2 Other non-operating income (expense), net 20 (7) 27 Income (Loss) Before Income Taxes 179 (92) 271 Income tax benefit (expense) (Note 5) (11) 16 (27) Net Income (Loss) 168 (76) 244 Less: Net income (loss) attributable to noncontrolling interest — 1 (1) Net Income (Loss) Attributable to Stockholders (Successor) $ 168 $ (77) $ 245 34 Successor Periods — Three Months Ended September 30, 2024 Compared to Three Months Ended September 30, 2023 Net Income (Loss) Attributable to Stockholders increased by $245 million, primarily driven by the factors discussed below. • Operating Revenues, net of Energy Expenses. $145 million favorable increase due to the following: Energy and Other Revenues, net of Fuel and Energy Purchases. $(64) million unfavorable decrease. This is primarily driven by (i) $(198) million decrease in realized energy margin from electric generation and ancillary revenue due to the ERCOT Sale in April 2024 and lower generation at Susquehanna, partially offset by higher realized prices at Susquehanna and PJM fossil plants; (ii) $73 million favorable increase in hedge results; and (iii) $71 million favorable increase in Nuclear PTC revenue. Unrealized Gain (Loss) on Derivative Instruments, net. $186 million favorable increase. This is primarily driven by (i) $130 million of favorable increase in positions existing in both the third quarters 2024 and 2023 resulting from lower forward power prices; (ii) $35 million favorable increase due to lower unrealized losses on new trades executed in the third quarter 2024 as compared to trades executed in the third quarter 2023; and (iii) $32 million unrealized gain from the reversal of positions previously recognized as mark-to-market liabilities which settled during the period. • Nuclear Decommissioning Trust Funds Gain (Loss), net. $91 million favorable increase. This is primarily driven by an increase in unrealized gains on equity securities in 2024 as a result of investment returns and a decline in interest rates during the third quarter 2024. Investment return volatility resulted in losses in the comparative 2023 period. See Notes 7 and 12 in Notes to the Interim Financial Statements for additional information. • Other Non-operating Income (Expense), net. $27 million favorable increase. This is primarily related to a decrease in pension litigation settlement charges recognized in 2023 and an increase in interest income in 2024. See Note 10 in Notes to the Interim Financial Statements for additional information on the pension litigation settlement. • Income Tax Benefit (Expense). $(27) million unfavorable increase. This is driven by an increase to federal and state tax expense due to change in pre-tax book income, increase in unfavorable permanent differences, increase in production tax credits benefit, increase in NDT net tax expense, and decrease to valuation allowance expense. 35 Results for the Nine Months Ended September 30, 2024 (Successor), May 18 through September 30, 2023 (Successor), and January 1 through May 17, 2023 (Predecessor) The following table and subsequent sections display the results of operations for the Successor and Predecessor periods: Successor Predecessor (Millions of Dollars) Nine Months Ended September 30, 2024 May 18 through September 30, 2023 January 1 through May 17, 2023 Capacity revenues $ 141 $ 70 $ 108 Energy and other revenues 1,444 788 1,042 Unrealized gain (loss) on derivative instruments (Note 3) 63 (41) 60 Operating Revenues (Note 4) 1,648 817 1,210 Fuel and energy purchases (535) (310) (176) Nuclear fuel amortization (93) (72) (33) Unrealized gain (loss) on derivative instruments (Note 3) (5) (2) (123) Energy Expenses (633) (384) (332) Operating Expenses Operation, maintenance and development (445) (209) (285) General and administrative (121) (55) (51) Depreciation, amortization and accretion (Note 8) (225) (94) (200) Impairments (Note 8) — (2) (381) Operational restructuring — — — Other operating income (expense), net (14) (11) (37) Operating Income (Loss) 210 62 (76) Nuclear decommissioning trust funds gain (loss), net 169 15 57 Interest expense and other finance charges (187) (101) (163) Reorganization income (expense), net — — 799 Gain (loss) on sale of assets, net 885 — 50 Other non-operating income (expense), net 60 (18) 10 Income (Loss) Before Income Taxes 1,137 (42) 677 Income tax benefit (expense) (Note 5) (192) (3) (212) Net Income (Loss) 945 (45) 465 Less: Net income (loss) attributable to noncontrolling interest 29 3 (14) Net Income (Loss) Attributable to Stockholders (Successor) / Member (Predecessor) $ 916 $ (48) $ 479 Successor Period — Nine Months Ended September 30, 2024 Net Income (Loss) Attributable to Stockholders totaled $916 million for the nine months ended September 30, 2024. Results were driven by: • Capacity Revenues totaled $141 million. This primarily included earned capacity awards based on resource clearing prices received from the PJM BRA for the 2023/2024 and 2024/2025 delivery periods. • Energy and Other Revenues, net of Fuel and Energy Purchases totaled $909 million. This consisted of: (i) $989 million in third-party wholesale electricity sales and ancillary revenues; (ii) $242 million in other revenue primarily related to Nuclear PTC and Bitcoin revenue; and (iii) $182 million in net realized gains from hedging activities. Such amounts were partially offset by $(504) million in fuel and purchased power costs. • Unrealized Gain (Loss) on Derivative Instruments totaled $58 million gain, net. This consisted of: (i) unrealized gains incurred as a result of decreases in forward power prices; partially offset by (ii) unrealized losses from the reversal of positions previously recognized as mark-to-market assets which settled during the period. • Nuclear Fuel Amortization totaled $(93) million. This consisted of the periodic expense of nuclear fuel costs capitalized as property, plant and equipment. Activity also included $27 million of amortization on certain nuclear fuel contracts that were recognized at fair value at Emergence. • Operation, Maintenance, and Development totaled $(445) million. This consisted of generation facility operating costs, including wages and benefits for employees, the costs of removal, repairs and maintenance that are not capitalized, contractor costs, and certain materials and supplies. 36 • Depreciation, Amortization and Accretion totaled $(225) million This consisted of the periodic expense of long-lived property, plant and equipment and ARO accretion. • Nuclear Decommissioning Trust Funds Gain (Loss), net , totaled $169 million. This consisted of unrealized gains on equity securities, realized gains and losses on debt and equity securities, dividends, and interest income on investments in the NDT. See Notes 7 and 12 in Notes to the Interim Financial Statements for additional information. • Interest Expense and Other Finance Charges totaled $(187) million. This primarily consisted of interest expense incurred on the Secured Notes and Term Loans. • Gain (Loss) on Sale of Assets, net totaled $885 million. This is primarily comprised of the $564 million gain from the ERCOT Sale that closed in May 2024 and the $324 million gain from the Cumulus Data Campus Sale that closed in March 2024. See Note 17 in Notes to the Interim Financial Statements for additional information. • Other Non-operating Income (Expense), net, totaled $60 million. This is primarily due to interest income. • Income Tax Benefit (Expense) totaled $(192) million. This primarily consists of federal and state income taxes, effects of permanent items, trust tax on income from the NDT, changes in valuation allowance, and excluded production tax credit income. Successor Period — May 18 through September 30, 2023 Net Income (Loss) totaled $(48) million for the period of May 18 through September 30, 2023 (Successor). Results were driven by: • Capacity Revenues totaled $70 million for the period, which were primarily based on resource clearing prices received from the PJM BRA for the 2023/2024 delivery period. • Energy and Other Revenues, net of Fuel and Energy Purchases, totaled $478 million for the period and consisted of $729 million in third-party wholesale electricity sales and ancillary revenues, coupled with $44 million in other revenue; partially offset by $(240) million in fuel and purchased power costs and $(55) million in net realized losses from hedging activities. Other revenues relate to operations of Nautilus that commenced in February 2023. • Unrealized Gain (Loss) on Derivative Instruments totaled $(43) million of net losses for the period, which was comprised of unrealized losses incurred as a result of increases in forward power prices, partially offset by unrealized losses from the reversal of positions previously recognized as mark-to-market assets which settled during the period. • Nuclear Fuel Amortization totaled $(72) million for the period and was related to the amortization of nuclear fuel costs that were previously capitalized to property, plant and equipment. Activity in this period included $38 million of additional amortization related to certain nuclear contracts as a result of fair value adjustments. • Operation, Maintenance, and Development totaled $(209) million for the period. This consists of generation facility operating costs, including salary and benefit costs for generation-facility employees, the costs of removal, repairs and maintenance that are not capitalized, contractor costs, and certain materials and supplies. • Depreciation, Amortization and Accretion totaled $(94) million for the period. This consists of depreciation of long-lived property, plant and equipment and accretion related to AROs. The period includes the effect of fair value adjustments made to property, plant and equipment and AROs upon Emergence. • Interest Expense and Other Finance Charges totaled $(101) million for the period and primarily consisted of interest expense incurred on the Secured Notes, Term Loans, Cumulus Digital TLF, and LMBE-MC TLB. 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. Results were driven by: • Capacity Revenues totaled $108 million for the period and were primarily based on resource clearing prices received from the PJM BRA for the 2022/2023 delivery period. Capacity revenues were negatively impacted by $(13) million of net PJM capacity penalties related to Winter Storm Elliott. 37 • Energy and Other Revenues, net of Fuel and Energy Purchases, totaled $866 million for the period and consisted of $637 million in net realized gains from hedging activities, coupled with $343 million in third-party wholesale electricity sales and ancillary revenues and $27 million in other revenue, partially offset by $(141) million in fuel and purchased power costs. Other revenues relate to operations of Nautilus that commenced in February 2023. • Unrealized Gain (Loss) on Derivative Instruments totaled $(63) million loss, net. This consisted of (i) unrealized losses from the reversal of positions previously recognized as mark-to-market assets which settled during the period; partially offset by (ii) 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 property, plant and equipment. • Operation, Maintenance, and Development totaled $(285) million for the period. This consisted of generation facility operating costs, including salary and benefit costs, 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 for the period and consisted of depreciation of long-lived property, plant and equipment, intangibles, and accretion related to AROs. The period was impacted by new depreciation rates related to a change in useful lives for the generation facilities. • Impairments totaled $(381) million in the period and primarily consisted of the assessment of Brandon Shores asset group recoverability associated with a decision to deactivate Brandon Shores on June 1, 2025. See Note 8 in Notes to the Interim Financial Statements for additional information. • Other Operating Income (Expense), net, totaled $37 million for the period, primarily consisting of non-cash charges for fuel inventory net realizable value adjustments. See Note 6 in Notes to the Interim Financial Statements for additional information. • Nuclear Decommissioning Trust Funds Gain (Loss), net , was $57 million for the period. This consisted of realized gains and losses on debt and equity securities, unrealized gains on equity securities, dividends and interest income on investments in the NDT. See Notes 7 and 12 in Notes to the Interim Financial Statements for additional information. • Interest Expense and Other Finance Charges totaled $(163) million for the period and primarily consisted of interest expense incurred on the Prepetition Secured Notes, Prepetition RCF, Prepetition TLB, and LMBE-MC TLB and certain LC fees. • Reorganization Income (Expense), net, totaled $799 million for the period, primarily due to the $1,459 million gain on debt discharge recognized upon Emergence partially offset by a $460 million loss on revaluation adjustments, $70 million in backstop commitment letters, and $57 million in professional fees. See Note 2 in Notes to the Interim Financial Statements for additional information. • Gain (loss) on Sale of Assets, net, totaled $50 million, primarily due to non-recurring sales during the period. See Note 17 in Notes to the Interim Financial Statements for additional information. • Income Tax Benefit (Expense) totaled $(212) million for the period and was primarily related to federal/state income taxes, reorganization adjustments, and changes in the valuation allowance. See Note 5 in Notes to the Interim Financial Statements for additional information. 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 commercial and hedging activities, including cash collateral and other forms of credit support; (v) legacy environmental obligations; and (vi) other working capital requirements and (or) the Company’s discretionary expenditures. Our primary sources of liquidity and capital include available cash deposits, cash flows from operations, amounts available under our debt 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 establishing 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 does not require cash collateral posting. 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. This strategy limits the use of exchange-based hedging and the associated margin requirements, which helps minimize collateral posting requirements. Additionally, there are lower overall hedging needs given the cash-flow stability afforded by the Nuclear PTC and significantly reduced debt service requirements. 38 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 Interim Financial Statements for additional information regarding various liquidity topics discussed below: Note 3 for derivatives and hedging, Note 9 for AROs and environmental obligations, Note 11 for long-term debt and credit facilities, and Note 16 for supplemental cash flow information. Talen Liquidity Successor September 30, 2024 December 31, 2023 Cash and cash equivalents, unrestricted $ 648 $ 400 RCF 700 638 Available liquidity $ 1,348 $ 1,038 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. Financial Performance Assurances Successor September 30, 2024 December 31, 2023 Outstanding surety bonds $ 234 $ 240 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 See Management’s Discussion and Analysis of Financial Condition and Results of Operations in the Annual Financial Statements attached to the Registration Statement for information regarding forecasted uses of cash related to capital expenditures and forecasted spending on AROs and accrued environmental liabilities. Indebtedness Long-Term Debt Repricing. In May 2024, the Company completed a repricing of the TLB and TLC. The lenders agreed to, among other things, reduce the SOFR interest rate margin by 100 basis points and waive any prepayment obligations in connection with the ERCOT Sale. Remarketing of PEDFA Bonds. In June 2024, the Company completed the remarketing of $50 million in aggregate principal amount of its PEDFA 2009B and $81 million in aggregate principal amount of its PEDFA 2009C Bonds. The bonds will bear interest at 5.25% until the end of the new term rate period on June 2027. In connection with the remarketing, $133 million of LCs issued under the TLC LCF that had previously supported the bonds were terminated, providing the Company with increased LC capacity under the TLC LCF. See Note 11 in Notes to the Interim Financial Statements for additional information on the repricing and Talen’s indebtedness. 39 Cash Flow Activities The net cash provided by (used in) operating, investing and financing activities for the nine months ended September 30 were: Successor Predecessor Nine Months Ended September 30, 2024 May 18 through September 30, 2023 January 1 through May 17, 2023 Operating activities $ 246 $ 180 $ 462 Investing activities 1,225 (108) (157) Financing activities (1,240) (62) (539) Successor Period — Nine Months Ended September 30, 2024 • Operating Cash Flows . Cash provided by operating activities totaled $246 million. • Investing Cash Flows. Cash provided by investing activities totaled $1,225 million. Talen received $635 million of proceeds from the Cumulus Data Campus Sale in the nine months ended September 30, 2024 (Successor), including $300 million of deferred proceeds that were received in the third quarter 2024, and $763 million of proceeds from the ERCOT Sale in the second quarter 2024, including $8 million of deferred proceeds that were received in the third quarter 2024. Partially offsetting these inflows were NDT fund investments, net of $(24) million and capital expenditures of $(147) million that primarily consisted of $(89) million for nuclear fuel expenditures and $(58) million for property, plant, and equipment. See Note 17 in Notes to the Interim Financial Statements for additional information on the Cumulus Data Campus Sale and the ERCOT Sale. • Financing Cash Flows. Cash used in financing activities totaled $(1,240) million. This primarily consisted of $(182) million for the repayment of the Cumulus Digital TLF in the first quarter 2024 using a portion of the proceeds from the Cumulus Data Campus Sale; $(39) million in the first quarter 2024 for the repurchase of noncontrolling interests held by affiliates of Orion and two former members of Talen senior management; and $(956) million in the nine months ended September 30, 2024 (Successor) to repurchase common stock shares. See “Recent Developments - Shares Repurchases” above for additional information on share repurchases. In addition, an outflow of $(31) million occurred to settle vested restricted stock units in cash. Successor Period — May 18 through September 30, 2023 • Operating Cash Flows. Cash provided by operating activities totaled $180 million. • Investing Cash Flows . Cash used in investing activities totaled $(108) million and primarily consisted of capital expenditures. Capital expenditures, including those for nuclear fuel, totaled $(103) million and consisted of $(60) million across the Company for then-current projects including the Montour gas conversion project and the Cumulus Data Campus; and $(43) million related to nuclear-fuel expenditures as Talen purchased uranium needs for future periods. • Financing Cash Flows. Cash used by financing activities totaled $(62) million and primarily consisted of $(59) million for payments to former affiliates to settle warrants and to repurchase affiliates’ noncontrolling interests in Cumulus Digital Holdings. 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 and consisted of capital expenditures offset by $46 million in proceeds from the sale of assets. Capital expenditures, including those for nuclear fuel, totaled $(187) million and consisted of $(138) million across the Company for then-current projects including the Montour gas conversion project, the Cumulus Data Campus, the Nautilus crypto mining project, and projects at Susquehanna; and $(49) million related to nuclear fuel expenditures. • Financing Cash Flows. Cash used in financing activities totaled $(539) million and 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. 40 Contractual Obligations and Commitments 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 10 in Notes to the Interim Financial Statements for additional information regarding guarantees. Non-GAAP Financial Measure We include Adjusted EBITDA, which the Company uses as a measure of its performance and is not a financial measure prepared under GAAP, in these Interim Financial Statements. 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, non-GAAP financial measures are numerical measures of financial performance, financial position, or cash flows that exclude (or include) amounts that are included in (or excluded from) the most directly comparable measure calculated and presented in accordance with GAAP. Management cautions readers of this financial information not to place undue reliance on this non-GAAP financial measure, but to also consider them along with their most directly comparable GAAP financial measure. Non-GAAP measures have limitations as an analytical tool 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 the Company’s 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; 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 Holdings 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 the 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. 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: 41 Successor Predecessor (Millions of Dollars) Three Months Ended September 30, 2024 Three Months Ended September 30, 2023 Nine Months Ended September 30, 2024 May 18 through September 30, 2023 January 1 through May 17, 2023 Net Income (Loss) $ 168 $ (76) $ 945 $ (45) $ 465 Adjustments Interest expense and other finance charges 66 68 187 101 163 Income tax (benefit) expense 11 (16) 192 3 212 Depreciation, amortization and accretion 75 66 225 94 200 Nuclear fuel amortization 30 47 93 72 33 Reorganization (gain) loss, net (a) — — — — (799) Unrealized (gain) loss on commodity derivative contracts (102) 84 (58) 43 63 Nuclear decommissioning trust funds (gain) loss, net (67) 24 (169) (15) (57) Stock-based compensation expense 8 9 24 11 — Long-term incentive compensation expense 3 — 19 — — (Gain) loss on asset sales, net (b) — — (885) — (50) Non-cash impairments (c) — 2 — 2 381 Operational and other restructuring activities 40 4 61 30 17 Development expenses 1 5 1 7 10 Non-cash inventory net realizable value, obsolescence, and other charges (d) 2 (2) 5 1 56 Noncontrolling interest (3) (14) (21) (22) (14) Other (2) 23 (13) 21 15 Total Adjusted EBITDA $ 230 $ 224 $ 606 $ 303 $ 695 _______ (a) See Note 2 in Notes to the Interim Financial Statements for additional information. (b) See Note 17 in Notes to the Interim Financial Statements for additional information. (c) See Note 8 in Notes to the Interim Financial Statements for additional information. (d) See Note 6 in Notes to the Interim Financial Statements for additional information. Critical Accounting Policies and Estimates The Company’s financial statements are prepared in conformity with GAAP, which 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 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. See the Annual Financial Statements attached to the Registration Statement for a description of our critical accounting policies and estimates. 42 ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK See Note 3 in Notes to the Interim Financial Statements for a description of our market risk.