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 June 30, 2024 (Successor), our generation capacity was 10,665 MW (summer rating). Talen is headquartered in Houston, Texas. Recent Developments Common Stock Transactions In the six months ended June 30, 2024 (Successor), the company repurchased a total of 5,773,889 shares of the Company’s common stock under the share repurchase program for an aggregate purchase price of $661 million, inclusive of transaction costs and excise taxes, at a weighted average per share price of $114.48. Of the total shares repurchased, 5,275,862 shares were the result of the tender offer executed in June 2024. In June 2024, the Company retired 5,768,862 shares of treasury stock repurchased during the six months ended June 30, 2024 (Successor). In July 2024, the Company repurchased 2,413,793 shares from affiliates of Rubric Capital Management LP at a purchase price of $116.00 per share for an aggregate purchase price of $280 million and retired the shares. There were de minimis transaction costs associated with this repurchase. 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 tax impacts, the Company issued 160,289 shares of the Company’s common stock. As of August 13, 2024, the Company has 51,001,450 shares of common stock outstanding. See Note 15 in Notes to the Interim Financial Statements for more information related to share repurchases and the retirement of treasury stock. PJM 2025/2026 Base Residual Auction In July 2024, PJM reported the results of the PJM Base Residual Auction for the 2025/2026 planning 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. 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 1, 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. 38 Term Loan Repricing In May 2024, the Company completed a repricing transaction with respect to the TLB and TLC. The new rate applicable to the TLB and TLC is SOFR plus 350 basis points, which reduces the interest rate margin by 100 basis points. The applicable SOFR floor was reduced from 50 to 0 basis points. Additionally, in connection with the repricing, the lenders under the TLB and TLC agreed to: (i) waive any mandatory prepayment obligations in connection with the ERCOT Sale; and (ii) certain other amendments permitting Talen additional capacity for dispositions, restricted payments and investments under the Credit Agreement. ERCOT Sale In March 2024, the Company and CPS Energy entered into an agreement for CPS Energy to acquire the Company’s 1,710 MW Texas generation portfolio located within the ERCOT market for $785 million, subject to customary net working capital adjustments. The sale closed in May 2024. A net gain of $563 million is presented as “Gain (loss) on sale of assets, net” on the Consolidated Statements of Operations. 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 Reliability Impact 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 transmission 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 transmission reliability. Each generation facility has filed a cost-of-servicer 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 approved 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 additional information on the Brandon Shores impairment. Commodity Markets The following tables summarize average on-peak power prices and natural gas prices for the PJM market for the three months ended June 30, 2024 (Successor) and 2023 (Predecessor). During the second quarter of 2024, natural gas prices for Texas Eastern M-3 settled below its ten-year average resulting from storage levels above the five-year range 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 average settled market prices for the three months ended June 30 were: 2024 2023 PJM West Hub Day Ahead Peak - $/MWh $ 37.67 $ 35.40 PJM PPL Zone Day Ahead Peak - $/MWh 28.34 25.97 PJM BGE Zone Day Ahead Peak - $/MWh 45.10 42.70 Texas Eastern M-3 - $/MMBtu 1.53 1.50 39 The PJM West Hub Day Ahead Peak 2024 quarter average settled prices increased approximately 6% compared to the prior year. The weighted average forward market prices for the periods from July 1 through December 31 as of June 30: 2024 2023 PJM West Hub ATC - $/MWh $ 43.64 $ 37.48 Texas Eastern M-3 - $/MMBtu 2.14 2.19 PJM West Hub ATC Spark Spreads (a) 28.64 22.13 __________________ (a) Spark spreads are computed based on day-ahead West Hub ATC prices, TETCO M-3 gas prices, and a heat rate of 7 MMBtu/MWh. Capacity Markets Our generation capacity is located in markets with capacity products, which are intended to ensure long-term grid reliability for customers by securing sufficient power supply resources to meet predicted future demand. Capacity prices are affected by supply and demand fundamentals, such as generation facility additions and retirements, capacity imports from and exports to adjacent markets, generation facility retrofit costs, non-performance risk premium penalties, demand response products, ISO demand forecasts, reserve margin targets and adjustments to PJM MSOC as determined by the PJM IMM. PJM Capacity Auctions. Under the RPM, PJM conducts a series of capacity auctions. Most capacity is procured in the auctions conducted each May for the delivery of generation capacity for the PJM Capacity Year, which is three years from the date of the auction. Capacity auctions have recently been delayed, resulting in the auctions being held with less than 3 years between the auctions and the PJM Capacity Year, with the most recent auction held in July 2024. The capacity market construct provides generation owners the opportunity for some revenue visibility on a multiyear basis. The results of each of these auctions impacts Talen's capacity revenues in the specific PJM Capacity Year. See “Capacity Prices” below for additional information on capacity prices and see Note 10 in Notes to the Interim Financial Statements for additional information on the PJM RPM and other PJM matters. Capacity Prices. The following table displays the PJM Base Residual Auction’s cleared capacity prices for the markets and zones in which we primarily operate: 2025/2026 (b) 2024/2025 2023/2024 2022/2023 PJM Capacity Performance ($/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. (b) 2025/2026 prices were released on July 30, 2024. 40 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 will qualify 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. 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, 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. 41 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 June 30, 2024, the six months ended June 30, 2024, and for the period May 18 through June 30, 2023 are referred to as the “Successor” periods. Our financial results for the period April 1 through May 17, 2023 and for the period from January 1 through May 17, 2023 are referred to as the “Predecessor” periods. The operating results for the three and six months ended June 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 derivatives instruments resulting from changes in fair value during the period and 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. 42 Results for the Three Months Ended June 30, 2024 (Successor), May 18 through June 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, except share data) Three Months Ended June 30, 2024 May 18 through June 30, 2023 April 1 through May 17, 2023 Capacity revenues $ 46 $ 26 $ 42 Energy and other revenues 367 188 180 Unrealized gain (loss) on derivative instruments 76 87 (85) Operating Revenues 489 301 137 Fuel and energy purchases (163) (57) (69) Nuclear fuel amortization (28) (25) (9) Unrealized gain (loss) on derivative instruments 15 (46) (9) Energy Expenses (176) (128) (87) Operating Expenses Operation, maintenance and development (164) (69) (108) General and administrative (40) (18) (22) Depreciation, amortization and accretion (75) (28) (68) Impairments — — (16) Operational restructuring (1) — — Other operating income (expense), net (6) (3) (28) Operating Income (Loss) 27 55 (192) Nuclear decommissioning trust funds gain (loss), net 27 39 11 Interest expense and other finance charges (62) (33) (59) Reorganization income (expense), net — — 838 Gain (loss) on sale of assets, net 561 — 15 Other non-operating income (expense), net 17 (11) 4 Income (Loss) Before Income Taxes 570 50 617 Income tax benefit (expense) (112) (19) (198) Net Income (Loss) 458 31 419 Less: Net income (loss) attributable to noncontrolling interest 4 2 (12) Net Income (Loss) Attributable to Stockholders (Successor) / Member (Predecessor) $ 454 $ 29 $ 431 43 Successor Period — Three Months Ended June 30, 2024 Net Income (Loss) Attributable to Stockholders totaled $454 million for the three months ended June 30, 2024 (Successor). Results were driven by: • Capacity Revenues totaled $46 million. This primarily included earned capacity awards based on resource clearing prices received from the PJM Base Residual Auction for the 2024/2025 and 2023/2024 delivery periods. • Energy and Other Revenues, net of Fuel and Energy Purchases totaled $204 million. This primarily consisted of: (i) $271 million in third-party wholesale electricity sales and ancillary revenues; (ii) $72 million in other revenue primarily related to Nautilus operations and Nuclear PTC; and (iii) $17 million in net realized gains from hedging activities. Such amounts were partially offset by $(155) million in fuel and purchased power costs. • Unrealized Gain (Loss) on Derivative Instruments totaled $91 million gain, net. This consisted of: (i) 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. • Nuclear Fuel Amortization totaled $(28) million. This consisted of the periodic expense of nuclear fuel costs capitalized as property, plant and equipment. Activity also included $8 million of amortization on certain nuclear fuel contracts that were recognized at fair value at Emergence. • Operation, Maintenance, and Development totaled $(164) 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 costs. • Depreciation, Amortization and Accretion totaled $(75) 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 $27 million. 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 $(62) million. This primarily consisted of interest expense incurred on the Secured Notes and Term Loans. • Gain (loss) on Sale of Assets, net totaled $561 million This is primarily related to the ERCOT Sale that closed in May 2024. See Note 17 in Notes to the Interim Financial Statements for additional information. • Other Non-operating Income (Expense) , net totaled $17 million. This is primarily related to interest income. • Income Tax Benefit (Expense) totaled $(112) million. This primarily consisted of federal and state income taxes, effects of permanent nondeductible items, trust tax on the nuclear decommissioning trust income, and changes in the valuation allowance. Successor Period — May 18 through June 30, 2023 See “Successor Period - May 18 through June 30, 2023” within “Results for the Six Months Ended June 30, 2024 (Successor)” below for a discussion of the results of operations for the above period. 44 Predecessor Period — April 1 through May 17, 2023 Net Income (Loss) Attributable to Member totaled $431 million for the period April 1 through May 17, 2023. Results were driven by: • Capacity Revenues totaled $42 million for the period and were primarily based on resource clearing prices received from the PJM Base Residual Auction for the 2022/2023 delivery period. • Energy and Other Revenues, net of Fuel and Energy Purchases, totaled $111 million. This consisted of: (i) $98 million in third-party wholesale electricity sales and ancillary revenues; (ii) $52 million in net realized gains from hedging activities; and (iii) $18 million in other revenue primarily related to Nautilus operations. Such amounts were partially offset by $(57) million in fuel and purchased power costs. • Unrealized Gain (Loss) on Derivative Instruments totaled $(94) million. This consisted of: (i) unrealized losses incurred as a result of increases in forward power prices; coupled with (ii) unrealized losses from the reversal of positions previously recognized as mark-to-market assets which settled during the period. • Nuclear Fuel Amortization totaled $(9) million. This consisted of the periodic expense of nuclear fuel costs capitalized as property, plant and equipment. • Operation, Maintenance, and Development totaled $(108) 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 costs. • Depreciation, Amortization and Accretion totaled $(68) 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 $11 million. This consisted of realized gains on debt and equity securities, unrealized losses 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. • Other Operating Income (Expense), net, totaled $(28) million, primarily due to fuel inventory net realizable value adjustment expense. See Note 6 in Notes to the Interim Financial Statements for additional information. • Reorganization Income (Expense), net, totaled $838 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. See Note 2 in Notes to the Interim Financial Statements for additional information. • Interest Expense and Other Finance Charges totaled $(59) million. This primarily consisted of interest expense incurred on prepetition debt and certain LC fees. • Gain (loss) on Sale of Assets, net, totaled $15 million. This is 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 $(198) million. This primarily consisted of federal and state income taxes, changes in the valuation allowance, and reorganization adjustments. 45 Results for the Six Months Ended June 30, 2024 (Successor), May 18 through June 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, except share data) Six Months Ended June 30, 2024 May 18 through June 30, 2023 January 1 through May 17, 2023 Capacity revenues $ 91 $ 26 $ 108 Energy and other revenues 939 188 1,042 Unrealized gain (loss) on derivative instruments (32) 87 60 Operating Revenues 998 301 1,210 Fuel and energy purchases (313) (57) (176) Nuclear fuel amortization (63) (25) (33) Unrealized gain (loss) on derivative instruments (12) (46) (123) Energy Expenses (388) (128) (332) Operating Expenses Operation, maintenance and development (318) (69) (285) General and administrative (83) (18) (51) Depreciation, amortization and accretion (150) (28) (200) Impairments — — (381) Operational restructuring (1) — — Other operating income (expense), net (6) (3) (37) Operating Income (Loss) 52 55 (76) Nuclear decommissioning trust funds gain (loss), net 102 39 57 Interest expense and other finance charges (121) (33) (163) Reorganization income (expense), net — — 799 Gain (loss) on sale of assets, net 885 — 50 Other non-operating income (expense), net 40 (11) 10 Income (Loss) Before Income Taxes 958 50 677 Income tax benefit (expense) (181) (19) (212) Net Income (Loss) 777 31 465 Less: Net income (loss) attributable to noncontrolling interest 29 2 (14) Net Income (Loss) Attributable to Stockholders (Successor) / Member (Predecessor) $ 748 $ 29 $ 479 46 Successor Period — Six Months Ended June 30, 2024 Net Income (Loss) Attributable to Stockholders totaled $748 million for the six months ended June 30, 2024. Results were driven by: • Capacity Revenues totaled $91 million. This primarily included earned capacity awards based on resource clearing prices received from the PJM Base Residual Auction for the 2023/2024 and 2024/2025 delivery period. • Energy and Other Revenues, net of Fuel and Energy Purchases, totaled $626 million. This consisted of: (i) $600 million in third-party wholesale electricity sales and ancillary revenues; (ii) $150 million in other revenue primarily related to Nautilus operations and Nuclear PTC; and (iii) $182 million in net realized gains from hedging activities. Such amounts were partially offset by $(306) million in fuel and purchased power costs. • Unrealized Gain (Loss) on Derivative Instruments totaled $(44) 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 $(63) million. This consisted of the periodic expense of nuclear fuel costs capitalized as property, plant and equipment. Activity also included $19 million of amortization on certain nuclear fuel contracts that were recognized at fair value at Emergence. • Operation, Maintenance, and Development totaled $(318) 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. • Depreciation, Amortization and Accretion totaled $(150) 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 $102 million. 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 $(121) 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 $563 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 $40 million. This is primarily due to interest income. 47 Successor Period — May 18 through June 30, 2023 Net Income (Loss) Attributable to Stockholders totaled $29 million for the period from May 18 through June 30, 2023. Results were driven by: • Capacity Revenues totaled $26 million and were primarily based on resource clearing prices received from the PJM Base Residual Auction for the 2023/2024 and 2022/2023 delivery periods. • Energy and Other Revenues, net of Fuel and Energy Purchases, totaled $131 million. This consisted of: (i) $136 million in third-party wholesale electricity sales and ancillary revenues; (ii) $16 million in net realized gains from hedging activities; and (iii) $15 million in other revenue primarily related to Nautilus operations. Such amounts were partially offset by $(36) million in fuel and purchased power costs. • Unrealized Gain (Loss) on Derivative Instruments totaled $41 million gain, net. This consisted of unrealized gains incurred as a result of decreases in forward power prices. • Nuclear Fuel Amortization totaled $(25) million. This consisted of the periodic expense of nuclear fuel costs capitalized as property, plant and equipment. Activity also included $(14) million of amortization on certain nuclear fuel contracts that were recognized at fair value at Emergence. • Operation, Maintenance, and Development totaled $(69) 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 costs. • Depreciation, Amortization and Accretion totaled $(28) 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 $39 million. This consisted of realized 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 $(33) million. This primarily consisted of interest expense incurred on prepetition debt and certain LC fees. • Other Non-operating Income (Expense), net, totaled $(11) million, primarily due to mark-to-market adjustments for warrants issued in 2023. • Income Tax Benefit (Expense) totaled $(19) million. This primarily consisted of federal and state income taxes and trust tax on nuclear decommissioning trust income. 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 Base Residual Auction for the 2022/2023 delivery period. Capacity revenues were negatively impacted by $(13) million of net PJM capacity penalties related to Winter Storm Elliot. • 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 operations in February 2023. 48 • 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, reflecting fuel inventory net realizable value adjustment expense. 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, 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. 49 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. 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. 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. In June 2024, using available cash deposits, the Company completed a tender offer which resulted in the purchase of 5,275,862 shares of its common stock for $612 million, exclusive of transaction costs. In July 2024, the Company repurchased $2,413,793 shares from affiliates of Rubric Capital Management LP for an aggregate purchase price of $280 million. There were de minimis transaction costs associated with this repurchase. See Notes 3, 9 and 16 in Notes to the Interim Financial Statements for additional information regarding various liquidity topics discussed below. Talen Liquidity Successor June 30, 2024 December 31, 2023 Cash and cash equivalents, unrestricted $ 632 $ 400 RCF 640 638 Available liquidity $ 1,272 $ 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. 50 Financial Performance Assurances Successor June 30, 2024 December 31, 2023 Outstanding surety bonds $ 235 $ 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 lower the interest charges by 100 basis points and waive the prepayment obligation 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. Cash Flow Activities The net cash provided by (used in) operating, investing and financing activities for the six months ended June 30 were: Successor Predecessor Six Months Ended June 30, 2024 May 18 through June 30, 2023 January 1 through May 17, 2023 Operating activities $ 150 $ (1) $ 462 Investing activities 979 (38) (157) Financing activities (915) — (539) Successor Period — Six Months Ended June 30, 2024 • Operating Cash Flows. Cash provided by (used in) operating activities totaled $150 million. This primarily consisted of cash provided from operations of the Company. • Investing Cash Flows. Cash provided by (used in) investing activities totaled $979 million. Talen received $339 million of initial net proceeds from the Cumulus Data Campus Sale in the first quarter of 2024 and $754 million of initial net proceeds from the ERCOT Sale in the second quarter of 2024. Partially offsetting these inflows were capital expenditures of $(90) million that primarily consisted of $(45) million for nuclear fuel expenditures. See Note 17 in Notes to the Interim Financial Statements for additional information on the Cumulus Data Campus Sale and the ERCOT Sale. 51 • Financing Cash Flows. Cash provided by (used in) financing activities totaled $(915) million. This primarily consisted of $(182) million for the repayment of the Cumulus Digital TLF in the first quarter of 2024 using a portion of the proceeds from the Cumulus Data Campus Sale; $(39) million in the first quarter of 2024 for the repurchase of noncontrolling interests held by affiliates of Orion and two former members of Talen senior management; and $(654) million in the six months ended June 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 $(28) million occurred to cash settle restricted stock units upon vesting. Successor Period — May 18 through June 30, 2023 • Investing Cash Flows. Cash provided by (used in) investing activities totaled $(38) million and primarily consisted of capital expenditures. Capital expenditures outflows, including those for nuclear fuel, totaled $(34) million and consisted of: $(20) million for fuel conversion projects and Cumulus Data Campus project; and $(14) million related to nuclear fuel expenditures. Predecessor Period — January 1 through May 17, 2023 • Operating Cash Flows. Cash provided by (used in) operating activities totaled $462 million and consisted of cash provided from the operations of the Company, including declines in accounts receivable, partially offset by payments made for accrued interest and other claims at Emergence. • Investing Cash Flows. Cash provided by (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 current projects including the Montour gas conversion project, the Cumulus Data Campus and Nautilus crypto mining projects and projects at Susquehanna; and $(49) million related to nuclear fuel expenditures. • Financing Cash Flows. Cash provided by (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. 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. 52 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 contributes to Adjusted EBITDA beginning in the first quarter 2024, following termination of the Cumulus Digital credit facility 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. 53 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: Successor Predecessor Successor Predecessor Three Months Ended June 30, 2024 May 18 through June 30, 2023 April 1 through May 17, 2023 Six Months Ended June 30, 2024 May 18 through June 30, 2023 January 1 through May 17, 2023 Net Income (Loss) $ 458 $ 31 $ 419 $ 777 $ 31 $ 465 Adjustments Interest expense and other finance charges 62 33 59 121 33 163 Income tax (benefit) expense 112 19 198 181 19 212 Depreciation, amortization and accretion 75 28 68 150 28 200 Nuclear fuel amortization 28 25 9 63 25 33 Reorganization (gain) loss, net (a) — — (838) — — (799) Unrealized (gain) loss on commodity derivative contracts (91) (41) 94 44 (41) 63 Nuclear decommissioning trust funds (gain) loss, net (27) (39) (11) (102) (39) (57) Stock-based compensation expense 8 16 — 16 16 — Long-term incentive compensation expense 6 — — 16 — — (Gain) loss on asset sales, net (b) (561) — (15) (885) — (50) Non-cash impairments (c) — — 16 — — 381 Operational and other restructuring activities 19 12 9 21 12 17 Development expenses — 2 3 — 2 10 Non-cash inventory net realizable value, obsolescence, and other charges (d) 2 3 32 3 3 56 Noncontrolling interest (7) (8) (9) (18) (8) (14) Other 3 (2) 1 (11) (2) 15 Total Adjusted EBITDA $ 87 $ 79 $ 35 $ 376 $ 79 $ 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. 54 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.