Talen Energy Corp 10-K

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA TALEN ENERGY CORPORATION AND SUBSIDIARIES ITEM 8. TABLE OF CONTENTS Page Report of Independent Registered Public Audit Firm (PCAOB ID 238 ) 49 Consolidated Statements of Operations 52 Consolidated Statements of Comprehensive Income (Loss) 53 Consolidated Balance Sheets 54 Consolidated Statements of Cash Flows 55 Consolidated Statements of Equity 57 Notes to the Annual Financial Statements 58 1. Organization and Operations 58 2. Basis of Presentation and Summary of Significant Accounting Policies 58 3 . Talen Emergence from Restructuring 65 4 . F resh Start Accounting 66 5 . Risk Management, Derivative Instruments and Hedging Activities 74 6 . Revenue 76 7 . Income Taxes 77 8 . Inventory 80 9 . Nuclear Decommissioning Trust Funds 81 10. Property, Plant and Equipment 82 11 . Asset Retirement Obligations and Accrued Environmental Costs 84 1 2 . Commitments and Contingencies 86 1 3 . Long-Term Debt and Other Credit Facilities 91 1 4 . Fair Value 94 1 5 . Postretirement Benefit Obligations 95 1 6 . Stock-Based Com pensation 101 1 7 . Earnings Per Share 103 1 8 . Stockholders' Equity 104 1 9 . Supplemental Cash Flow Information 106 2 0 . Acquisitions and Divestitures 107 2 1 . Segments 107 48 Item 8. Table of Contents REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM To the Board of Directors and Stockholders of Talen Energy Corporation Opinion on the Financial Statements We have audited the accompanying consolidated balance sheets of Talen Energy Corporation and its subsidiaries (Successor) (the "Company") as of December 31, 2024 and 2023, and the related consolidated statements of operations, comprehensive income (loss), equity and cash flows for the year then ended December 31, 2024 and for the period from May 18, 2023 through December 31, 2023, including the related notes and financial statement schedule listed in the accompanying index (collectively referred to as the "consolidated financial statements"). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2024 and 2023, and the results of its operations and its cash flows for the year ended December 31, 2024 and for the period from May 18, 2023 through December 31, 2023 in conformity with accounting principles generally accepted in the United States of America. Basis of Accounting As discussed in Note 3 to the consolidated financial statements, the United States Bankruptcy Court for Southern District of Texas confirmed the Company's Plan of Reorganization (the "plan") in December 2022. Confirmation of the plan resulted in the discharge of all claims against the Company that arose before May 9, 2022 and substantially alters rights and interests of equity security holders as provided for in the plan. The plan was substantially consummated on May 17, 2023 and the Company emerged from bankruptcy. In connection with its emergence from bankruptcy, the Company adopted fresh start accounting as of May 17, 2023. Basis for Opinion These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s consolidated financial statements based on our audit. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB. We conducted our audit of these consolidated financial statements in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud. Our audit included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audit also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. We believe that our audit provides a reasonable basis for our opinion. Critical Audit Matters The critical audit matter communicated below is a matter arising from the current period audit of the consolidated financial statements that was communicated or required to be communicated to the audit committee and that (i) relates to accounts or disclosures that are material to the consolidated financial statements and (ii) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates. Commodity Derivatives Valuation As described in Notes 2, 5 and 14 to the consolidated financial statements, the Company had a fair value net derivative asset position of $71 million and a fair value net derivative liability position of $7 million, as of December 31, 2024. As disclosed by management, the Company utilizes exchange-traded and over the-counter traded derivative instruments to economically hedge the commodity price risk of the forecasted future sales and purchases of commodities associated with their generation portfolio. Commodity derivative contracts are valued using inputs and assumptions such as contractual volumes, delivery location, forward commodity prices, commodity price volatility, discount rates, and credit worthiness of counterparties. The principal considerations for our determination that performing procedures relating to commodity derivative valuation is a critical audit matter are (i) the significant judgment by management when developing the valuation of commodity derivatives; (ii) a high degree of auditor judgment and effort in performing procedures and evaluating management’s significant assumptions related to the forward commodity prices and commodity price volatility; and (iii) the audit effort involved the use of professionals with specialized skill and knowledge. 49 Item 8. Table of Contents Addressing the matter involved performing procedures and evaluating audit evidence in connection with forming our overall opinion on the consolidated financial statements. These procedures included, among others, (i) testing management’s process for developing the valuation of commodity derivatives; (ii) evaluating the appropriateness of management’s model; (iii) testing, on a sample basis, the completeness and accuracy of the underlying contract terms and the accounting treatment conclusions; and (iv) evaluating, on a sample basis, the reasonableness of the significant assumptions used by management related to forward commodity prices and commodity price volatility. Professionals with specialized skill and knowledge were used to assist in evaluating the reasonableness of forward commodity prices and commodity price volatility assumptions. /s/ PricewaterhouseCoopers LLP Houston, Texas February 27, 2025 We have served as the Company’s auditor since 2017. 50 Item 8. Table of Contents REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM To the Board of Managers and Members of Talen Energy Supply, LLC Opinion on the Financial Statements We have audited the consolidated statements of operations, comprehensive income (loss), equity and cash flows of Talen Energy Supply, LLC and its subsidiaries (Predecessor) (the “Company”) for the period from January 1, 2023 through May 17, 2023 and for the year then ended December 31, 2022, including the related notes (collectively referred to as the “consolidated financial statements”). In our opinion, the consolidated financial statements present fairly, in all material respects, the results of operations and cash flows of the Company for the period from January 1, 2023 through May 17, 2023 and for the year then ended December 31, 2022 in conformity with accounting principles generally accepted in the United States of America. Basis of Accounting As discussed in Note 3 to the consolidated financial statements, the Company filed a petition on May 9, 2022 with the United States Bankruptcy Court for the Southern District of Texas for reorganization under the provisions of Chapter 11 of the Bankruptcy Code. The Company’s Plan of Reorganization was substantially consummated on May 17, 2023 and the Company emerged from bankruptcy. In connection with its emergence from bankruptcy, the Company adopted fresh start accounting. Basis for Opinion These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s consolidated financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB. We conducted our audits of these consolidated financial statements in accordance with the standards of the PCAOB and in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. We believe that our audits provide a reasonable basis for our opinion. /s/ PricewaterhouseCoopers LLP Houston, Texas March 14, 2024 We have served as the Company’s auditor since 2017. 51 Item 8. Table of Contents TALEN ENERGY CORPORATION AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF OPERATIONS Successor Predecessor (Millions of Dollars, except share data) Year Ended December 31, 2024 May 18 through December 31, 2023 January 1 through May 17, 2023 Year Ended December 31, 2022 Capacity revenues $ 192 $ 133 $ 108 $ 377 Energy and other revenues 1,881 1,156 1,042 2,035 Unrealized gain (loss) on derivative instruments (Note 5) 42 55 60 677 Operating Revenues (Note 6) 2,115 1,344 1,210 3,089 Fuel and energy purchases ( 694 ) ( 424 ) ( 176 ) ( 938 ) Nuclear fuel amortization ( 123 ) ( 108 ) ( 33 ) ( 94 ) Unrealized gain (loss) on derivative instruments (Note 5) 20 ( 3 ) ( 123 ) ( 52 ) Energy Expenses ( 797 ) ( 535 ) ( 332 ) ( 1,084 ) Operating Expenses Operation, maintenance and development ( 592 ) ( 358 ) ( 285 ) ( 610 ) General and administrative ( 163 ) ( 93 ) ( 51 ) ( 106 ) Depreciation, amortization and accretion (Note 10) ( 298 ) ( 165 ) ( 200 ) ( 520 ) Impairments (Note 10) ( 1 ) ( 3 ) ( 381 ) — Operational restructuring — — — ( 488 ) Other operating income (expense), net ( 38 ) ( 30 ) ( 37 ) ( 40 ) Operating Income (Loss) 226 160 ( 76 ) 241 Nuclear decommissioning trust funds gain (loss), net (Note 9) 178 108 57 ( 184 ) Interest expense and other finance charges (Note 13) ( 238 ) ( 176 ) ( 163 ) ( 359 ) Reorganization income (expense), net (Note 4) — — 799 ( 812 ) Consolidation of subsidiary gain (loss) (Note 2) — — — ( 170 ) Gain (loss) on sale of assets, net (Note 20) 884 7 50 — Other non-operating income (expense), net 61 95 10 ( 44 ) Income (Loss) Before Income Taxes 1,111 194 677 ( 1,328 ) Income tax benefit (expense) (Note 7) ( 98 ) ( 51 ) ( 212 ) 35 Net Income (Loss) 1,013 143 465 ( 1,293 ) Less: Net income (loss) attributable to noncontrolling interest 15 9 ( 14 ) ( 4 ) Net Income (Loss) Attributable to Stockholders (Successor) / Member (Predecessor) $ 998 $ 134 $ 479 $ ( 1,289 ) Per Common Share (Successor) Net Income (Loss) Attributable to Stockholders - Basic $ 18.40 $ 2.27 N/A N/A Net Income (Loss) Attributable to Stockholders - Diluted $ 17.67 $ 2.26 N/A N/A Weighted-Average Number of Common Shares Outstanding - Basic (in thousands) 54,254 59,029 N/A N/A Weighted-Average Number of Common Shares Outstanding - Diluted (in thousands) 56,486 59,399 N/A N/A The accompanying Notes to the Annual Financial Statements are an integral part of the financial statements. 52 Item 8. Table of Contents TALEN ENERGY CORPORATION AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) Successor Predecessor (Millions of Dollars) Year Ended December 31, 2024 May 18 through December 31, 2023 January 1 through May 17, 2023 Year Ended December 31, 2022 Net Income (Loss) $ 1,013 $ 143 $ 465 $ ( 1,293 ) Other Comprehensive Income (Loss) Available-for-sale securities unrealized gain (loss), net (Note 9) ( 14 ) 2 6 ( 69 ) Postretirement benefit actuarial (gain) loss, net (Note 15) 5 ( 38 ) — ( 15 ) Postretirement benefit prior service (credits) costs, net (Note 15) 21 — — — Income tax benefit (expense) 5 8 ( 2 ) 31 Gains (losses) arising during the period, net of tax 17 ( 28 ) 4 ( 53 ) Available-for-sale securities unrealized (gain) loss, net (Note 9) 1 7 4 33 Qualifying derivatives unrealized (gain) loss, net — — ( 1 ) ( 2 ) Postretirement benefit prior service (credits) costs, net (Note 15) ( 1 ) — — 1 Postretirement benefit actuarial (gain) loss, net (Note 15) — — 2 27 Income tax (benefit) expense ( 6 ) ( 2 ) ( 3 ) ( 21 ) Reclassifications from AOCI, net of tax ( 6 ) 5 2 38 Total Other Comprehensive Income (Loss) 11 ( 23 ) 6 ( 15 ) Comprehensive Income (Loss) 1,024 120 471 ( 1,308 ) Less: Comprehensive income (loss) attributable to noncontrolling interest 15 9 ( 14 ) ( 4 ) Comprehensive Income (Loss) Attributable to Stockholders (Successor) / Member (Predecessor) $ 1,009 $ 111 $ 485 $ ( 1,304 ) The accompanying Notes to the Annual Financial Statements are an integral part of the financial statements. 53 Item 8. Table of Contents TALEN ENERGY CORPORATION AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS Successor (Millions of Dollars, except share data) December 31, 2024 December 31, 2023 Assets Cash and cash equivalents $ 328 $ 400 Restricted cash and cash equivalents (Note 19) 37 501 Accounts receivable (Note 6) 123 137 Inventory, net (Note 8) 302 375 Derivative instruments (Notes 5 and 14) 66 89 Other current assets 184 52 Total current assets 1,040 1,554 Property, plant and equipment, net (Note 10) 3,154 3,839 Nuclear decommissioning trust funds (Notes 9 and 14) 1,724 1,575 Derivative instruments (Notes 5 and 14) 5 6 Other noncurrent assets 183 147 Total Assets $ 6,106 $ 7,121 Liabilities and Equity Long-term debt, due within one year (Notes 13 and 14) $ 17 $ 9 Accrued interest 18 32 Accounts payable and other accrued liabilities 266 344 Derivative instruments (Notes 5 and 14) — 32 Other current liabilities 154 69 Total current liabilities 455 486 Long-term debt (Notes 13 and 14) 2,987 2,811 Derivative instruments (Notes 5 and 14) 7 11 Postretirement benefit obligations (Note 15) 305 368 Asset retirement obligations and accrued environmental costs (Note 11) 468 469 Deferred income taxes (Note 7) 362 407 Other noncurrent liabilities 135 35 Total Liabilities $ 4,719 $ 4,587 Commitments and Contingencies (Note 12) Stockholders' Equity (Note 18) Common stock ($ 0.001 par value, 350,000,000 shares authorized) (a) $ — $ — Additional paid-in capital 1,725 2,346 Accumulated retained earnings (deficit) ( 326 ) 134 Accumulated other comprehensive income (loss) ( 12 ) ( 23 ) Total Stockholders' Equity 1,387 2,457 Noncontrolling interests — 77 Total Equity 1,387 2,534 Total Liabilities and Equity $ 6,106 $ 7,121 __________________ (a) 45,961,910 and 59,028,843 shares issued and outstanding as of December 31, 2024 (Successor) and December 31, 2023 (Successor), respectively. The accompanying Notes to the Annual Financial Statements are an integral part of the financial statements. 54 Item 8. Table of Contents TALEN ENERGY CORPORATION AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS Successor Predecessor (Millions of Dollars) Year Ended December 31, 2024 May 18 through December 31, 2023 January 1 through May 17, 2023 Year Ended December 31, 2022 Operating Activities Net income (loss) $ 1,013 $ 143 $ 465 $ ( 1,293 ) Non-cash reconciliation adjustments: (Gain) loss on AWS Data Campus Sale and ERCOT Sale (Note 20) ( 886 ) — — — Depreciation, amortization and accretion (Note 19) 285 157 208 549 NDT funds (gain) loss, net (excluding interest and fees) (Note 9) ( 130 ) ( 78 ) ( 43 ) 227 Nuclear fuel amortization (Note 10) 123 108 33 94 Unrealized (gains) losses on derivative instruments (Note 5) ( 69 ) ( 40 ) 65 ( 647 ) Deferred income taxes ( 46 ) 55 195 ( 48 ) Impairments (Note 10) 1 3 381 — (Gain) loss on sales of assets, net — ( 7 ) ( 50 ) — Reorganization (income) expense, net (Note 4) — — ( 933 ) 99 Operational restructuring — — — 488 Consolidation of subsidiary (gain) loss (Note 2) — — — 170 Other (Note 19) ( 26 ) 7 7 200 Changes in assets and liabilities: Inventory, net 67 ( 68 ) 10 ( 55 ) Accounts receivable 14 8 261 ( 298 ) Other assets ( 61 ) 147 98 ( 46 ) Accounts payable and accrued liabilities ( 69 ) ( 49 ) ( 69 ) 187 Accrued interest ( 15 ) 28 ( 124 ) 250 Other liabilities 55 ( 12 ) ( 42 ) 310 Net cash provided by (used in) operating activities 256 402 462 187 Investing Activities NDT funds investment purchases (Note 9) ( 2,295 ) ( 1,290 ) ( 959 ) ( 2,271 ) NDT funds investment sale proceeds (Note 9) 2,263 1,265 949 2,243 Proceeds from AWS Data Campus Sale and ERCOT Sale (Note 20) 1,398 — — — Nuclear fuel expenditures (Note 10) ( 104 ) ( 45 ) ( 49 ) ( 80 ) Property, plant and equipment expenditures (Note 10) ( 85 ) ( 116 ) ( 138 ) ( 232 ) Equity investments in affiliates ( 10 ) ( 5 ) ( 8 ) ( 162 ) Proceeds from the sale of assets 2 8 46 — Increase (decrease) in cash and restricted cash due to consolidation of subsidiaries — — — 123 Other investing activities 2 12 2 11 Net cash provided by (used in) investing activities 1,171 ( 171 ) ( 157 ) ( 368 ) 55 Item 8. Table of Contents TALEN ENERGY CORPORATION AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS Successor Predecessor (Millions of Dollars) Year Ended December 31, 2024 May 18 through December 31, 2023 January 1 through May 17, 2023 Year Ended December 31, 2022 Financing Activities Share repurchases (Note 18) ( 1,958 ) — — — TES debt issuance (Note 13) 849 — — — TES debt repayments (Note 13) ( 479 ) — — — Cumulus Digital TLF repayment (Note 13) ( 182 ) ( 15 ) — — Repurchase of noncontrolling interest (Note 18) ( 125 ) ( 19 ) — — Cash settlement of restricted stock units ( 32 ) — — — Exercise or repurchase of warrants (Note 18) ( 16 ) ( 40 ) — — Deferred financing costs ( 13 ) ( 7 ) ( 74 ) ( 59 ) LMBE-MC TLB payments — ( 294 ) ( 7 ) ( 52 ) TLB-1 proceeds, net — 288 — — Repayment of prepetition secured indebtedness (Note 4) — — ( 3,898 ) — Financing proceeds at Emergence, net of discount (Note 4) — — 2,219 — Contributions from member — — 1,393 — Payment of make-whole premiums on prepetition secured indebtedness — — ( 152 ) — Derivatives with financing elements — — ( 20 ) ( 104 ) Debtor-in-possession credit facilities proceeds, net — — — 987 Prepetition deferred capacity obligations repayments — — — ( 176 ) Prepetition inventory repurchase obligations, net increase (decrease) — — — ( 165 ) Prepetition senior secured revolving credit facility proceeds — — — 62 Prepetition senior secured revolving credit facility repayments — — — ( 62 ) Other ( 7 ) 3 — ( 5 ) Net cash provided by (used in) financing activities ( 1,963 ) ( 84 ) ( 539 ) 426 Net Increase (Decrease) in Cash and Cash Equivalents and Restricted Cash and Cash Equivalents ( 536 ) 147 ( 234 ) 245 Beginning of period cash and cash equivalents and restricted cash and cash equivalents 901 754 988 743 End of period cash and cash equivalents and restricted cash and cash equivalents $ 365 $ 901 $ 754 $ 988 See Note 19 for supplemental cash flow information. The accompanying Notes to the Annual Financial Statements are an integral part of the financial statements. 56 Item 8. Table of Contents TALEN ENERGY CORPORATION AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF EQUITY (Millions of Dollars, except share data) Common stock shares (a) Additional paid-in capital Accumulated earnings (deficit) AOCI Treasury stock Member's Equity Non controlling Interest Total Equity December 31, 2021 (Predecessor) — $ — $ — $ — $ — $ 733 $ — $ 733 Net income (loss) — — — — — ( 1,289 ) ( 4 ) ( 1,293 ) Other comprehensive income (loss) — — — — — ( 15 ) — ( 15 ) Non-cash consolidation of affiliate subsidiary — — — — — — 71 71 Non-cash distribution to member — — — — — ( 2 ) — ( 2 ) Non-cash contribution from member — — — — — — 17 17 Cash contribution — — — — — — 7 7 December 31, 2022 (Predecessor) — $ — $ — $ — $ — $ ( 573 ) $ 91 $ ( 482 ) Net income (loss) — — — — — 479 ( 14 ) 465 Other comprehensive income (loss) — — — — — 6 — 6 Cancellation of member’s equity (b) — — — — — 88 — 88 Issuance of member’s equity (b) — — — — — 2,313 — 2,313 Issuance of warrants (b) — — — — — 8 — 8 Common equity from member’s equity exchange 59,029 2,321 — — — ( 2,321 ) — — Non-cash contributions (c) — — — — — — 38 38 Non-cash distributions (d) — — — — — — ( 5 ) ( 5 ) May 17, 2023 (Predecessor) 59,029 $ 2,321 $ — $ — $ — $ — $ 110 $ 2,431 May 18, 2023 (Successor) 59,029 $ 2,321 $ — $ — $ — $ — $ 110 $ 2,431 Net income (loss) — — 134 — — — 9 143 Other comprehensive income (loss) — — — ( 23 ) — — — ( 23 ) Purchase of noncontrolling interest (e) — 5 — — — — ( 24 ) ( 19 ) Cash contribution — — — — — — 1 1 Non-cash distributions (d) — — — — — — ( 20 ) ( 20 ) Stock-based compensation expense — 19 — — — — — 19 Other — 1 — — — — 1 2 December 31, 2023 (Successor) 59,029 $ 2,346 $ 134 $ ( 23 ) $ — $ — $ 77 $ 2,534 Net income (loss) — — 998 — — — 15 1,013 Other comprehensive income (loss) — — — 11 — — — 11 Share repurchases ( 13,227 ) — — — ( 1,977 ) — — ( 1,977 ) Retirement of treasury stock — ( 519 ) ( 1,458 ) — 1,977 — — — Purchase of noncontrolling interest (e) — ( 87 ) — — — — ( 38 ) ( 125 ) Cash settlement of restricted stock units — ( 32 ) — — — — — ( 32 ) Exercise of warrants 160 ( 16 ) — — — — — ( 16 ) Cash distributions (f) — — — — — — ( 2 ) ( 2 ) Non-cash distributions (g) — — — — — — ( 52 ) ( 52 ) Stock-based compensation expense — 33 — — — — — 33 December 31, 2024 (Successor) 45,962 $ 1,725 $ ( 326 ) $ ( 12 ) $ — $ — $ — $ 1,387 __________________ (a) Shares in thousands. (b) Pursuant to the Plan of Reorganization: (i) existing equity interests were canceled; and (ii) new equity interests and equity-classified warrants were issued. (c) Related to contributions of cryptocurrency miners by TeraWulf to Nautilus. (d) Related primarily to distributions of Bitcoin to TeraWulf. (e) TES acquisition of remaining noncontrolling interests in Cumulus Digital and Nautilus. See Note 18 for additional information. (f) Distributions to noncontrolling interest owners of Cumulus Digital and Nautilus. (g) Related primarily to distribution of Bitcoin and cryptocurrency miners to TeraWulf. The accompanying Notes to the Annual Financial Statements are an integral part of the financial statements. 57 Item 8. Table of Contents TALEN ENERGY CORPORATION AND SUBSIDIARIES NOTES TO THE ANNUAL FINANCIAL STATEMENTS Capitalized terms and abbreviations appearing in these Notes to the Annual Financial Statements Financial Statements are defined in the glossary. Dollars are in millions, unless otherwise noted. “TEC” refers to Talen Energy Corporation. “TES” refers to Talen Energy Supply, LLC. For periods after May 17, 2023, the terms “Talen,” “Successor,” the “Company,” “we,” “us,” and “our” refer to TEC and its consolidated subsidiaries (including TES), unless the context clearly indicates otherwise. For periods on or before May 17, 2023, the terms “Talen,” “Predecessor,” the “Company,” “we,” “us,” and “our” refer to TES and its consolidated subsidiaries, unless the context clearly indicates otherwise. See Note 2 for additional information. This presentation has been applied where identification of subsidiaries is not material to the matter being disclosed, and to conform narrative disclosures to the presentation of financial information on a consolidated basis. When identification of a subsidiary is considered important to understanding the matter being disclosed, the specific entity’s name is used. Each disclosure referring to a subsidiary also applies to TEC insofar as such subsidiary’s financial information is included in TEC’s consolidated financial information. TEC and each of its subsidiaries and affiliates are separate legal entities and, except by operation of law, are not liable for the debts or obligations of one another absent an express contractual undertaking to the contrary. 1. Organization and Operations Talen is a leading independent power producer and energy infrastructure company dedicated to powering the future. We own and operate approximately 10.7 gigawatts of power infrastructure in the United States, including 2.2 gigawatts of nuclear power and a significant dispatchable generation fleet. We produce and sell electricity, capacity, and ancillary services into wholesale U.S. power markets, with our generation fleet principally located in the Mid-Atlantic and Montana. Talen is headquartered in Houston, Texas. 2. Basis of Presentation and Summary of Significant Accounting Policies Basis of Presentation and Principles of Consolidation These Annual Financial Statements, which are prepared in accordance with GAAP, include: (i) the accounts of all controlled subsidiaries; (ii) elimination adjustments for intercompany transactions between controlled subsidiaries; (iii) any undivided interests in jointly owned facilities consolidated on a proportionate basis; and (iv) all adjustments considered necessary for a fair presentation of the information set forth. All adjustments are of a normal recurring nature except as otherwise disclosed. Emergence from Restructuring, Fresh Start Accounting, and Reverse Acquisition. In May 2022, TES and 71 of its subsidiaries voluntarily commenced the Restructuring under Chapter 11 of the U.S. Bankruptcy Code. TEC joined the Restructuring in December 2022. The Plan of Reorganization was approved by the requisite parties and confirmed by the bankruptcy court in late 2022, and was consummated and became effective in May 2023, when TEC, TES, and the other debtors emerged from the Restructuring. Upon commencement of the Restructuring, TES was deconsolidated from TEC for financial reporting purposes because TEC no longer controlled TES. TEC regained control of TES at Emergence, which resulted in TEC’s reconsolidation of TES. The combination was accounted for as a reverse acquisition in which TEC was the legal acquirer and TES was the accounting acquirer. Accordingly, these Annual Financial Statements are issued under the name of TEC, the legal parent of TES and accounting acquiree, but represent the continuation of the financial statements of TES, the accounting acquirer. After Emergence, TES applied fresh start accounting, which resulted in a new basis of accounting, as the Company became a new financial reporting entity. As a result of the application of fresh start accounting and the implementation of the Plan of Reorganization, our financial position and results of operations beginning after Emergence are not comparable to our financial position or results of operations prior to that date. The financial results are presented for: (i) the Predecessor periods from January 1 through May 17, 2023 (Predecessor) and the year ended December 31, 2022 (Predecessor); and (ii) the Successor periods from May 18 through December 31, 2023 (Successor) and the year ended December 31, 2024 (Successor). These Annual Financial Statements and notes hereto have been presented with a black line division to delineate the lack of comparability between the Predecessor and Successor . See Note 3 for additional information on the Restructuring and Note 4 for additional information on fresh start accounting. Consolidation of an Affiliate’s Subsidiary. In September 2022, as part of a settlement of certain matters in the Restructuring, TES exchanged preferred units in subsidiaries of Cumulus Digital for common units in Cumulus Digital. Following the consummation of the exchange and other related transactions, TES became the primary beneficiary of Cumulus Digital, a variable interest entity, due to its ability to control the activities that most significantly impacted Cumulus Digital. Accordingly, Cumulus Digital and its subsidiaries were consolidated by TES as of September 30, 2022. The difference between (i) the fair value of Cumulus Digital and its subsidiaries; and (ii) the carrying value of the preferred units immediately before the exchange resulted in a loss of $ 170 million presented as “Consolidation of subsidiary gain (loss)” on the Consolidated Statements of Operations for the year ended December 31, 2022 (Predecessor). 58 Item 8. Table of Contents Summary of Significant Accounting Policies Reclassifications. Certain amounts in the prior period financial statements were reclassified to conform to the current period’s presentation. The reclassifications did not affect operating income, net income, total assets, total liabilities, net equity, or cash flows. Use of Estimates. The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. Restructuring Effects. Income, expenses, gains, or losses that were incurred or realized as a direct result of the Restructuring since entering bankruptcy proceedings are presented as “Reorganization income (expense), net” on the Consolidated Statements of Operations. See Notes 3 and 4 for additional information on the Restructuring and fresh start accounting. Fair Value of Financial Instruments and Derivatives. We carry a portion of our assets and liabilities at fair value that are measured at a reporting date using an exit price (i.e., the price that would be received to sell an asset or paid to transfer a liability). An exit price may be developed under a market approach utilizing market transactions, an income approach utilizing present value techniques, or a replacement cost approach. The exit prices are disclosed according to the quality of valuation inputs under a three-tiered hierarchy comprised of: (i) Level 1 inputs that are quoted prices (unadjusted) in active markets for identical assets or liabilities; (ii) Level 2 inputs that are other than quoted prices that are directly or indirectly observable; and (iii) Level 3 inputs are unobservable inputs for assets or liabilities. The classification of an asset or liability is based on the lowest level of input significant to its fair value. Those initially classified as Level 3 are subsequently reported as Level 2 when the fair value derived from unobservable inputs is inconsequential to the overall fair value, or if corroborated market data becomes available. Those initially classified as Level 2 are subsequently reported as Level 3 if corroborated market data is no longer available. Transfers occur at the end of the reporting period. See Notes 5, 10, 14, and 15 for fair value disclosures. Operating Revenues and Revenue Recognition. Operating revenues on the Consolidated Statements of Operations are primarily comprised of items presented as: (i) “Capacity revenues;” (ii) “Energy and other revenues;” and (iii) “Unrealized gain (loss) on derivative instruments” for certain electricity contracts. Capacity revenues. Includes amounts earned from auctions in ISOs and RTOs and under bilateral contracts to provide available generation capacity that is needed to satisfy system reliability and integrity requirements. Capacity revenues are recognized ratably over the PJM Capacity Year by Talen-owned generation facilities that participate in the auctions and stand ready to deliver generated power. Capacity revenues are based on invoiced amounts corresponding directly to the value provided over a specific time interval. Energy and other revenues. Energy revenues primarily include: (i) amounts earned from sales to ISOs and RTOs for electric generation and ancillary services products that support transmission and grid operations; (ii) amounts earned for wholesale electricity sales to bilateral counterparties; and (iii) realized gains and losses on commodity derivative instruments. Sales of each electric generation and ancillary services to ISOs and RTOs represent performance obligations recognized over time based on volumes delivered or services performed at contractually agreed upon day-ahead or real-time market prices. Sales of wholesale electricity to bilateral counterparties represent performance obligations recognized over a contractually agreed period of time based on volumes delivered at the contractually agreed price. Sales of electric generation, ancillary services, and wholesale electricity to bilateral counterparties are recognized based on invoiced amounts which corresponds directly with the value provided over a specific time interval. Certain contracts constitute bundled agreements to sell energy, capacity, and (or) ancillary services. In such cases, all performance obligations are deemed to be delivered and (or) performed at the same time. Accordingly, as the timing of revenue recognition for all performance obligations is the same and occurs over a contractually agreed period of time, it is unnecessary to allocate transaction price to multiple performance obligations. 59 Item 8. Table of Contents Realized gains and losses on commodity derivative instruments include the settlements of financial and physical power transactions utilized for the Company’s commercial risk management objectives. Realized settlements of these derivative instruments are recognized and presented net within “Energy and other revenues” on the Consolidated Statements of Operations based on the delivery period of the underlying contract at contractually agreed prices. See “Energy Expenses” below for additional information on realized gains and losses of derivative instruments presented as “Fuel and energy purchases” on the Consolidated Statements of Operations. Other revenues primarily include: (i) Nuclear PTC revenues; and (ii) Nautilus revenues from Bitcoin mining. The Nuclear PTC program provides qualified nuclear power generation facilities with transferable credits for electricity produced and sold to an unrelated party during each tax year. These credits, which are accounted for by analogy to income-based grants under international accounting standards for government grants and disclosure of government assistance, are recognized when there is reasonable assurance that the Company will comply with the applicable conditions and that the credit will be received, which is generally over the period of production. As the credits that are generated each tax year are based on annual gross receipts and production volumes, the measurement of the credit value is estimated at each period until the final value can be determined at the end of the year, which may be different than the estimated amount. The credit value includes a five -times multiplier (up to $ 15 per MWh) for meeting prevailing wage requirements. Accordingly, Nuclear PTCs are recognized based on production volumes generated during the period and measured at the credit value for the tax year. See Note 6 for amounts recognized, which are presented as “Energy and other revenues” on the Consolidated Statements of Operations and “Other current assets” on the Consolidated Balance Sheets. Credits that are utilized to reduce federal income taxes payable are presented as a reduction of “Other current liabilities” on the Consolidated Balance Sheets. There have been no transfers of Nuclear PTCs to third parties during the year ended December 31, 2024 (Successor). Additional guidance expected to be issued from the U.S. Treasury and IRS may impact the credit value recognized. The primary output of Nautilus’s ordinary business activities is providing hash calculation services to solve complex cryptographic algorithms in support of blockchain mining. Nautilus is party to a mining pool arrangement to provide an unspecified amount of its available hash calculations to an unaffiliated mining pool operator. Nautilus is entitled to an enforceable right to compensation from the mining pool operator only for the duration of time over which Nautilus provides its hash calculations. In exchange for providing hash calculation services to the mining pool operator, Nautilus is entitled to consideration, whether or not the mining pool operator successfully solves a block, based on a ‘full-pay-per-share’ payout methodology. Nautilus’s only performance obligation is to provide hash calculations to the mining pool operator. If Nautilus does not provide hash calculations to the mining pool operator, no consideration is earned by Nautilus nor does Nautilus incur any penalties from the mining pool operator. The Bitcoin earned by Nautilus is all variable noncash consideration. Accordingly, Nautilus recognizes revenue that is measured at fair value using the quoted price for Bitcoin in Nautilus’s principal market at the beginning of each day (Coordinated Universal Time). Nautilus operations were suspended in October 2024. Unrealized gain (loss) on derivative instruments. Includes unrealized gains and losses resulting from changes in the fair value of certain power contracts that qualify as derivative instruments. See “Derivative Instruments” below for the recognition criteria of unrealized gains and losses on commodity derivative instruments. See “Energy Expenses” below for additional information on unrealized gains and losses of derivative instruments presented as “Energy Expenses” on the Consolidated Statements of Operations. See Note 6 for additional information on revenue. Energy Expenses. Energy expenses on the Consolidated Statements of Operations are primarily comprised of items presented as: (i) “Fuel and energy purchases;” (ii) “Nuclear fuel amortization;” and (iii) “Unrealized gain (loss) on derivative instruments” for certain commodity purchase contracts. Fuel and energy purchases. Primarily includes: (i) fuel costs; (ii) environmental product costs; and (iii) realized gain (loss) on commodity derivative instruments. Fuel costs include the costs incurred by Talen-owned generation facilities for the conversion of natural gas, coal, and (or) oil products to electricity. Fuel for electric generation from natural gas purchases are recognized at the agreed price for natural gas delivered to the applicable generation facility over a contractually agreed period of time. Fuel for electric generation from coal and oil product inventories are recognized at the applicable weighted average inventory cost of volumes consumed. Environmental product costs primarily include RGGIs and other emission product compliance costs that are mandated by certain states. The estimated cost of compliance is accrued at the time an obligation under the applicable terms of each state's environmental compliance program arises. Realized gains and losses on commodity derivative instruments primarily include the settlements of financial and physical fuel contracts utilized for the Company’s commercial risk management objectives. Realized settlements of these derivative instruments are recognized and presented net within “Fuel and energy purchases” on the Consolidated Statements of Operations based on the delivery period of the underlying contract at contractually agreed prices. See “Operating Revenues and Revenue Recognition” above for additional information on realized gains and losses on derivative instruments presented as “Energy and other revenues” on the Consolidated Statements of Operations. 60 Item 8. Table of Contents Nuclear fuel amortization. Nuclear fuel-related costs, including procurement of uranium, conversion, enrichment, fabrication and assemblies, are capitalized and presented as “Property, plant and equipment, net” on the Consolidated Balance Sheets and presented as a cash outflow within the investing activities section on the Consolidated Statements of Cash Flows. Such costs are amortized as the fuel is consumed using the units-of-production method and presented as “Nuclear fuel amortization” on the Consolidated Statements of Operations. Unrealized gain (loss) on derivative instruments. Includes unrealized gains and losses resulting from changes in the fair value of certain fuel contracts and environmental product contracts that qualify as derivative instruments. See “Derivative Instruments” below for the recognition criteria of unrealized gains and losses on commodity derivative instruments. See “Operating Revenues and Revenue Recognition” above for additional information on unrealized gains and losses of derivative instruments presented as “Operating Revenues” on the Consolidated Statements of Operations. Derivative Instruments. The fair value of derivative contracts required to be measured at fair value are presented as “Derivative instruments” within assets or liabilities on the Consolidated Balance Sheets. The primary type of derivative instruments utilized are commodity derivatives. Commodity derivative contracts are valued using inputs and assumptions such as contractual volumes, delivery location, forward commodity prices, commodity price volatility, discount rates, and credit worthiness of counterparties. For derivatives that trade in liquid markets, such as generic forwards, swaps, and options, the inputs and assumptions are generally observable. Such instruments are categorized in Level 2. In most instances, master netting agreements govern derivative transactions between parties and contain certain provisions for setoff rights. The fair value of derivative instruments is presented net of setoff rights and cash collateral deposits. The fair value of commercial contracts that are not subject to netting and (or) collateral provisions is presented gross. Prior to Emergence, the fair value of derivative instruments presented on the Consolidated Balance Sheets was presented gross of setoff rights and cash collateral deposits exchanged between parties under such arrangements. Unrealized gains or losses associated with a derivative instrument that economically hedges certain risks but where qualified cash flow hedge accounting is not elected or not met are presented on the Consolidated Statements of Operations in the period when such gains or losses arise. As there are no derivatives where qualified hedge accounting has been elected, changes in the fair value of commodity derivatives are presented as “Unrealized gain (loss) on derivative instruments,” as a component of either “Operating Revenues” or “Energy Expenses” on the Consolidated Statements of Operations in a manner consistent with the presentation of net realized gains and losses. See “Operating Revenues” and “Energy Expenses” above for a discussion of net realized gains and losses on commodity derivatives. The cumulative net gains or losses for interest rate contracts are presented as “Interest expense and other finance charge s ” on the Consolidated Statements of Operations. See Notes 5 and 14 for additional information on the presentation of derivative contracts and fair value measurements. Operation, Maintenance and Development. The costs of removal, repairs, maintenance, and other operating costs, pre-commercial development activities, and salaries and benefits for operations personnel that each do not meet capitalization criteria are recognized as an expense when incurred. Materials and supplies inventories are recognized as an expense at the weighted average cost of materials consumed as they are used for repairs and maintenance. Costs for pre-commercial development stages of certain projects that are not capitalized as “Property, plant and equipment, net” on the Consolidated Balance Sheets and recurring operational and maintenance activities are each presented as “Operation, maintenance and development” on the Consolidated Statements of Operations. Development expenses incurred are primarily for pre-commercial activities at Nautilus and hyperscale construction activities at Cumulus Digital. Stock-Based Compensation. TEC grants performance stock units (“PSUs”) and restricted stock units (“RSUs”) to certain employees and non-employee directors. The fair value of PSUs is estimated on the grant date utilizing a Monte Carlo Valuation Model, which contains significant unobservable inputs that are believed to be consistent with those used by principal market participants. The fair value of RSUs is derived from the closing price of TEC common stock at the grant date. Forfeitures are recognized as they occur. Unvested PSUs and RSUs are entitled to dividends or dividend equivalents, which are accrued and distributed to award recipients at the time such awards vest. Dividends and dividend equivalents are subject to the same vesting and forfeiture provisions as the underlying awards. Stock-based compensation expense is recognized for both graded and cliff vesting awards on a straight-line basis over the requisite service period for the entire award. Stock-based compensation expense is presented as “General and administrative” on the Consolidated Statements of Operations. See Note 16 for additional information on stock-based compensation. Income Taxes. TEC and its subsidiaries file a consolidated U.S. federal income tax return. Income taxes are accounted for under the asset and liability method. Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying values of existing assets and liabilities and their respective tax basis, tax credits and NOL carryforwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities due to a change in tax rates is recognized as income in the period that includes the enactment date. Valuation allowances are recognized to reduce deferred tax assets to the extent necessary to result in an amount that is more likely than not to be realized. Disproportionate income tax effects are removed from AOCI when the circumstance upon which they are premised ceases to exist. 61 Item 8. Table of Contents The financial statement effect of a tax position is recognized when it is more-likely-than-not, based on the technical merits, that the position will be sustained upon examination. A tax position that meets the more-likely-than-not recognition threshold is measured as the largest amount of tax benefit that is greater than 50% likely of being realized upon ultimate settlement with a taxing authority. A previously recognized tax position is reversed in the first period in which it is no longer more-likely-than-not that the tax position would be sustained upon examination. Interest and penalties from tax uncertainties are presented as “Income tax benefit (expense)” on the Consolidated Statements of Operations. See Note 7 for additional information on income taxes. Loss Contingencies. Potential losses are accrued when: (i) information is available that indicates it is probable (i.e., likely to occur) that a loss has been incurred, given the likelihood of the uncertain future events; and (ii) the amount of the loss can be reasonably estimated. We continuously assess potential loss contingencies for environmental remediation, litigation claims, regulatory penalties and other events. Loss contingencies are discounted when appropriate. Legal costs are expensed as incurred. See Note 12 for additional information. Concentrations of Credit Risk. Concentrations of credit risk exist primarily within cash and cash equivalents, receivables, and commodity derivative assets. Cash and cash equivalents are generally held in accounts where the amounts deposited exceed the maximum deposit insurance provided by the Federal Deposit Insurance Corporation. Cash and cash equivalents and restricted cash balances are primarily deposited in accounts with major financial institutions with investment grade credit ratings. In certain instances, funds are invested in highly liquid U.S. Treasury securities or other obligations with original maturities of less than 90 days that are issued by or guaranteed by the U.S. Government. Concentrations of credit risk for receivables are primarily attributable to entities that reimburse Talen for certain capital expenditures and operating costs associated with jointly owned facilities. Concentrations of credit risk for commodity derivative assets are primarily attributable to unaffiliated investment grade counterparties which engage in energy marketing activities with Talen Energy Marketing. See Note 5 for additional information on concentrations of credit risk. Cash and Cash Equivalents. Bank deposits, liquid investments, and other similar assets with original maturities of three months or less. Bank deposits, commodity exchange deposits, liquid investments, and other similar assets with original maturities of three months or less that are restricted by agreement are presented as “Restricted cash and cash equivalents” on the Consolidated Balance Sheets. See Note 19 for additional information. Accounts Receivable. Receivables primarily consist of amounts due from customers or other contract counterparties, net of any collection allowances. Uncollected receivables greater than 30 days past due are assessed for collectability based on a variety of factors that include, but are not limited to, customer credit worthiness, duration receivables are outstanding, and (or) historical collection experience. Management continuously assesses and considers current economic trends that might impact the amount of future credit losses. Additionally, if it becomes known that a specific customer may have the inability to settle its obligation that is not yet past due, such receivables are assessed for collectability. If these assessments indicate a receivable collection is remote, its carrying value is reduced through an allowance for doubtful accounts measured at management’s best estimate, and a charge is presented on the Consolidated Statements of Operations. If any portion of the original carrying value of the receivable is recovered, the allowance and the associated charge are reversed in the period of collection. Inventory. Inventory consists of fuel for generation (primarily coal and fuel oil), materials and supplies, and environmental products each of which are valued at the lower of weighted average cost or net realizable value. See Note 8 for additional information on inventory. Variable Interest Entities. The primary beneficiary (a controlling financial interest) of a VIE is required to consolidate the VIE when it has both: (i) the power to direct the activities that most significantly impact the entity’s economic performance; and (ii) the obligation to absorb losses or receive benefits from the entity that could potentially be significant to the VIE. Talen consolidates a VIE when it is determined that it is the primary beneficiary of the VIE. Investments in entities in which Talen has the ability to exercise significant influence but does not have a controlling financial interest are accounted for under the equity method. Investments in Debt and Equity Securities. The NDT holds investments in available-for-sale debt securities and equity securities, which are carried at fair value and presented as “Nuclear decommissioning trust funds” on the Consolidated Balance Sheets. Unrealized gains and losses, net of income tax, on available-for-sale debt securities are presented as “Other Comprehensive Income (Loss)” on the Consolidated Statements of Comprehensive Income in the period when such gains and losses arise. Realized gains and losses on available-for-sale debt securities are transferred from AOCI to “Nuclear decommissioning trust funds gain (loss), net” on the Consolidated Statements of Operations in the period when the sale of the security occurs. The specific identification method is used to calculate realized gains and losses on debt and equity securities. If an available-for-sale debt security's fair value declines below cost and the decline is determined to be other-than-temporary, the unrealized loss is recognized on the Consolidated Statements of Comprehensive Income in the period when such determination arises. Unrealized gains and losses and realized gains and losses on equity securities are presented as “Nuclear decommissioning trust funds gain (loss), net” on the Consolidated Statements of Operations in the period when such gains or losses arise. See Notes 9 and 14 for additional information on investments in debt and equity securities. 62 Item 8. Table of Contents Property, Plant and Equipment. Expenditures for land, the construction of facilities, the addition or refurbishment of major equipment, and commercially viable new development projects are capitalized at cost. Such capitalized amounts include interest costs, where appropriate. Facilities, land, and other equipment acquired in a business combination is recognized at fair value. In each case, such amounts are presented as “Property, plant and equipment, net” on the Consolidated Balance Sheets. Reductions in the carrying value of PP&E are accumulated over the estimated useful life of each depreciable unit using straight-line or group depreciation methods, where appropriate. Such periodic reduction is presented as a charge to “Depreciation, amortization and accretion” on the Consolidated Statements of Operations. Generally, upon normal retirement of PP&E under the group depreciation method, the costs of such assets are retired against accumulated depreciation in the period of the retirement and no gain or loss is recognized. Any remaining carrying value of PP&E at its retirement date that depreciated under the straight-line depreciation method is presented as a loss within “Other operating income (expense), net” on the Consolidated Statements of Operations. Any remaining carrying value of PP&E at its sale date and any proceeds from the disposition are presented as a gain or loss net on the Consolidated Statements of Operations. Expenditures for intangible assets such as contractual rights, software and licenses are capitalized at cost and are presented as “Property, plant and equipment, net” on the Consolidated Balance Sheets. Reductions in the carrying value of intangible assets with finite useful lives are accumulated over the estimated useful life of each intangible asset using an amortization pattern which reflects the economic benefits of the intangible asset. Such periodic reduction is presented as a charge to “Depreciation, amortization and accretion” on the Consolidated Statements of Operations. See “Impairments” below for additional information regarding impairments on the carrying values of PP&E. See Note 10 for additional information on PP&E. Impairments. PP&E used in operations are assessed for impairment whenever changes in facts and circumstances indicate the carrying value of the asset group may not be recoverable. Indicators of impairment may include changes in the economic environment, negative financial trends, physical damage to assets or decisions of management regarding strategic initiatives. Where applicable, individual assets are grouped for impairment purposes at the lowest level for which there are identifiable cash flows that are largely independent of the cash flows of other assets and liabilities. If there is an indication the carrying value of an asset group may not be recovered, management reviews the expected future cash flows of the asset group. If the sum of the undiscounted pre-tax cash flows is less than the carrying value of the asset group, the asset group is written down to its estimated fair value. Impairment charges are presented as “Impairments” on the Consolidated Statements of Operations in the period in which the impairment condition arises. If facts and circumstances indicate that the carrying value of an asset under construction will have no future economic benefit, such amounts are presented on the Consolidated Statements of Operations in the period in which such projects are abandoned, canceled, or management otherwise determines the costs to be unrecoverable. Fair value may be determined by a variety of valuation methods including third-party appraisals, market prices of similar assets, and present value techniques. However, as there is generally a lack of quoted market prices for long-lived assets, the fair value of impaired assets is typically determined based on the present values of expected future cash flows using discount rates that are believed to be consistent with those used by principal market participants. The estimated cash flows and related fair value computations consider all available evidence at the date of the review, such as estimated future generation volumes, forward capacity and commodity prices, energy prices, operating costs, capital expenditures, and environmental costs. See Note 10 for information on impairments. Asset Retirement Obligations. A liability for an ARO or conditional ARO exists when a legal obligation arises from laws, regulations or other contractual requirements for the retirement of tangible long-lived assets. When an ARO liability is incurred, which is typically at asset construction or through assumption of the liability in connection with a business combination, it is initially recognized at fair value. Fair value measurements are estimated under a present value technique and are discounted using a credit-adjusted risk-free rate. Additionally, given the inherent uncertainty in estimating the amount of cash flows to settle an ARO liability or its settlement date, fair value estimates include a market risk premium and a range of possible cash flow outcomes, where applicable. At the initial recognition, the effects on the Consolidated Balance Sheets include: (i) an increase to “Asset retirement obligations and accrued environmental costs” for the portion of ARO to be settled after one year and (or) “Other current liabilities” for the portion of the ARO to be settled within one year; and (ii) an offsetting increase to “Property, plant and equipment, net” for the asset retirement capitalized cost. Estimated future ARO cash expenditures and settlement dates are reviewed periodically to identify any required amendments to the carrying value of each ARO liability. ARO liabilities increase over a period of time through the recognition of accretion expense to recognize changes in the obligation due to the passage of time. The asset retirement capitalized cost is depreciated at a rate consistent with the useful life of the associated long-lived asset. The depreciation of the asset retirement capitalized cost and the accretion of the ARO liability are each presented as “Depreciation, amortization and accretion” on the Consolidated Statements of Operations. An ARO liability amendment associated with a long-lived asset that is not fully impaired or depreciated is recognized through an adjustment to the ARO liability and the asset retirement capitalized cost. Any revision to the asset retirement capitalized cost is generally depreciated over the remaining life of the associated long-lived asset. An ARO liability amendment associated with a fully impaired or depreciated asset is presented as “Other operating income (expense), net” on the Consolidated Statements of Operations. At settlement, a gain or loss will arise if the cash expenditures to settle the ARO liabilities are different than the carrying values. Such gains or losses are presented as “Other operating income (expense), net” on the Consolidated Statements of Operations. 63 Item 8. Table of Contents A conditional ARO refers to an entity’s legal obligation to perform an asset retirement activity in which the timing or method of settlement is conditional on a future event that may or may not be within the entity’s control, including legal or regulatory requirements. There may also be instances when there is no available information regarding the ultimate ARO settlement timing or the fair value of the obligation may not be reasonably estimable. If sufficient information becomes available to reasonably estimate the fair value of the liability for an ARO or a conditional ARO, a liability is recognized in the period in which it is determined. See Note 11 for additional information on AROs. Contingencies. Management continuously assesses potential loss contingencies for environmental remediation, litigation claims, regulatory penalties and other events. Potential losses are accrued when: (i) information is available that indicates it is probable (i.e., likely to occur) that a loss has been incurred, given the likelihood of the uncertain future events; and (ii) the amount of the loss can be reasonably estimated. Loss contingencies are recognized at management's best estimate, which may be discounted, where appropriate. Loss contingencies exclude estimates for any legal fees, which are recognized as incurred when the legal services are performed. See Note 12 for additional information on loss contingencies. Business interruption insurance proceeds are considered gain contingencies and not recognized until realized. Debt. Proceeds received on the issuance of new term loans, secured notes, unsecured notes, bonds, and similar indebtedness are presented as “Long-term debt” or “Long-term debt, due within one year” on the Consolidated Balance Sheets. Interest incurred as paid-in-kind, whether accrued or capitalized as additional principal are presented as “Long-term debt” with the associated outstanding amounts of indebtedness. Costs incurred to issue new indebtedness and any original issuance discounts or premiums are deferred at issuance on the Consolidated Balance Sheets and presented together with the associated outstanding principal amounts of indebtedness. Interest accrues on outstanding principal amounts of indebtedness based on contractually determined rates during each period. Costs incurred for the issuance of indebtedness and any original issuance discounts or premiums are subsequently amortized through the expected maturity date of the associated indebtedness under the effective interest rate method and are presented as “Interest expense and other finance charges” on the Consolidated Statements of Operations. Gains and losses on the: (i) early redemption of indebtedness; or (ii) early termination and (or) reduction of revolving credit facility committed capacity are presented as a gain or loss on the Consolidated Statements of Operations. Such amounts include the proportional derecognition of any deferred financing costs, fees, discounts, and (or) premiums associated with the indebtedness. Direct cash borrowings under secured lines of credit, revolving credit facilities, and similar indebtedness are presented as a current liability on the Consolidated Balance Sheets. Costs incurred to issue new arrangements are deferred and presented as “Other current assets” or “Other noncurrent assets” on the Consolidated Balance Sheets. Interest accrues on direct cash borrowings and LCs based on contractually determined rates during each period. Costs incurred to issue new arrangements are subsequently amortized through the expected expiration of the associated arrangement under the straight-line method. Commitment fees on available but unused credit facility capacity are expensed as incurred. Such costs are presented as “Interest expense and other finance charges” on the Consolidated Statements of Operations. See Note 13 for additional information on debt. Postretirement Benefit Obligations. Certain Talen subsidiaries sponsor various defined benefit pension plans and other postretirement benefit plans. Gains and losses, net of income tax, that arise and are not a component of net periodic defined benefit costs are presented as “Other Comprehensive Income (Loss)” on the Consolidated Statements of Comprehensive Income. Following Emergence, actuarial gains and losses in excess of the greater of 10% of the plan's projected benefit obligation or the market-related value of plan assets are amortized over (i) the expected average remaining service period of active plan participants for active plans; or (ii) the average future remaining lifetime of the plan participants of frozen plans. Prior to Emergence, Talen used an accelerated amortization method for the recognition of gains and losses for defined benefit pension plans: (i) actuarial gains and losses in excess of 30% of the plan's projected benefit obligation are amortized on a straight-line basis over one-half of the expected average remaining service of active plan participants; and (ii) actuarial gains and losses in excess of 10% of the greater of the plan's projected benefit obligation or the market-related value of plan assets and less than 30% of the plan's projected benefit obligation are amortized on a straight-line basis over the expected average remaining service period of active plan participants. Following Emergence, a spot rate curve that represents a portfolio of high-quality corporate bonds is used to develop the discount rate utilized to measure the projected benefit obligations and service costs for benefit plans. Prior to Emergence, a bond matching methodology was utilized, based on a specific portfolio of bonds that closely match the overall cash flow timing and duration of the benefit plans. 64 Item 8. Table of Contents Talen is obligated to provide health care benefits under the Coal Act and pneumoconiosis (black lung) benefits under the Black Lung Act for retired miners and eligible beneficiaries. Benefits are funded from a Voluntary Employees’ Benefit Association (“VEBA”) trust and a trust maintained under certain federal and state black lung legislation. Shortfalls in funded status of the plans are assessed as contingent liabilities. As such, Talen recognizes funding shortfalls on its balance sheet, where applicable, if benefit obligations of either plan exceed the fair value of available trust assets. See Note 15 for additional information on the plans and the accounting for defined benefits. Treasury Stock and Retirement of Treasury Shares. Share repurchases are accounted for under the cost method, which recognizes the entire cost of the acquired stock, including transaction costs and excise tax, as a reduction in additional paid-in-capital and are presented as “Treasury stock” on the Consolidated Balance Sheets. Share repurchases are recognized on a trade date basis when we are contractually obligated to purchase the shares. Treasury shares are retired on the settlement date of the transaction. At retirement, the common stock balance is reduced for the par value of the shares. The excess of the acquisition cost of repurchased shares over the par value is recognized in additional paid-in capital (up to the amount credited to additional paid-in capital upon original issuance of the shares), with any remaining cost deducted from retained earnings. Recently Adopted Accounting Pronouncements ASU 2023-07 . In November 2023, the Financial Accounting Standards Board (the “FASB”) issued ASU 2023-07, Segment Reporting (Topic 280): Improvements to Reportable Segment Disclosures. This ASU requires enhanced disclosures about significant segment expenses. The ASU is effective for fiscal years beginning after December 15, 2023, and interim periods within fiscal years beginning after December 15, 2024. Early adoption is permitted. The Company adopted the fiscal year disclosure requirements for this ASU beginning January 1, 2024, and will adopt interim period disclosure requirements beginning January 1, 2025. Recent Accounting Pronouncements Not Yet Adopted ASU 2023-09. In December 2023, the FASB issued ASU 2023-09 Income Taxes (Topic 740): Improvements to Income Tax Disclosures. This ASU requires annual disclosures for specific categories in the rate reconciliation and additional information for reconciling items that meet a quantitative threshold. The ASU is effective for fiscal years beginning after December 15, 2024. Early adoption is permitted for annual financial statements that have not yet been issued. The Company is evaluating the disclosure impact of this ASU and expects to adopt it in the required period. ASU 2024-03. In November 2024, the FASB issued ASU 2024-03, Expense Disaggregation Disclosures (Subtopic 220-40): Disaggregation of Income Statement Expenses. This ASU requires public companies to disclose, in the notes to financial statements, specified information about certain costs and expenses at each interim and annual reporting period. This ASU is effective for annual reporting periods beginning after December 15, 2026. Early adoption is permitted. The Company is evaluating the disclosure impact of this ASU and expects to adopt it in the required period. 3. Emergence from Restructuring Voluntary Reorganization Under Chapter 11 of the U.S. Bankruptcy Code In May 2022, TES and 71 of its subsidiaries voluntarily commenced the Restructuring under Chapter 11 of the U.S. Bankruptcy Code. TEC joined the Restructuring in December 2022. The Plan of Reorganization was approved by the requisite parties and confirmed by the bankruptcy court in late 2022, and was consummated and became effective in May 2023, when TEC, TES, and the other debtors emerged from the Restructuring. Prior to and during the Restructuring, TES and its debtor subsidiaries reached a number of settlements with various stakeholders (including certain holders of claims under TES’s prepetition indebtedness, certain affiliates Riverstone Holdings, LLC (“Riverstone”) (which then held all of the equity in TEC), TEC, and the Official Committee of Unsecured Creditors), the terms of which were incorporated into the Plan of Reorganization. Under the settlements, the Company agreed to conduct a common equity rights offering, which certain holders of prepetition unsecured notes agreed to backstop in exchange for subscription rights to purchase 30 % of the new equity issued plus a backstop premium payment in the form of cash and (or) new equity. Restructuring Transactions and Emergence The Restructuring transactions were completed, and the Company emerged from the Restructuring, on May 17, 2023. Pursuant to the Plan of Reorganization, among other things: • Claims against TEC were paid in full in cash or reinstated. All existing equity interests in TEC were extinguished, and new equity interests in TEC were issued as follows: • Holders of unsecured claims under TES’s prepetition indebtedness (including the backstopping holders) received: (i) TEC equity; and (ii) subscription rights to purchase additional TEC equity in the equity rights offering. 65 Item 8. Table of Contents • The equity rights offering was consummated, resulting in $ 1.4 billion in net cash proceeds to the Company. The backstopping holders (i) fully exercised their subscription rights; (ii) were required to purchase additional unsubscribed-for TEC equity; and (iii) were paid the remaining portion of the backstop premium in the form of TEC equity. • Riverstone received: (i) 1 % of the equity in TEC; (ii) a contingent right to receive additional TEC equity or cash upon certain conditions following Emergence; and (iii) warrants to purchase additional TEC equity. In the third quarter 2023, Riverstone surrendered the warrants and waived its contingent right to additional TEC equity or cash in exchange for $ 40 million in cash. • The existing intercompany ownership structure of the debtors remained in place and intercompany claims were extinguished. • The Company consummated its exit financings, comprised of the RCF, TLB-1, TLC, TLC LCF, Bilateral LCF, and Secured Notes. The PEDFA 2009B and 2009C Bonds remained outstanding following the Restructuring. • The proceeds of the equity rights offering and the exit financings, together with cash on hand, were used to fully repay the Company’s debtor-in-possession credit facilities and to pay $ 3.1 billion relating to other secured claims. • Holders of other unsecured claims received interests in a designated $ 26 million pool of cash, to which Talen Montana subsequently contributed an additional $ 11 million from proceeds of the PPL/Talen Montana settlement . See Note 12 for additional information on the PPL/Talen Montana settlement. 4. Fresh Start Accounting At Emergence, TES adopted fresh start accounting as: (i) the holders of existing voting shares before the consummation of the Plan of Reorganization received less than 50 % of the voting shares of the Successor; and (ii) the reorganization value of TES’s assets immediately prior to confirmation of the Plan of Reorganization of $ 7.8 billion was less than the total of post-petition liabilities and allowed claims of $ 9.8 billion. Accordingly, TES allocated its reorganization value to its individual assets based on their estimated fair values. Reorganization Value Reorganization value is derived from an estimate of enterprise value, or the fair value of the Company’s interest-bearing debt and member’s equity. As negotiated in the Plan of Reorganization and related disclosure statement approved by the Bankruptcy Court, the enterprise value as of Emergence was $ 4.5 billion. Management engaged third-party valuation advisors to assist in estimating the enterprise value and allocating the enterprise value to the assets and liabilities for financial reporting purposes as of Emergence. Enterprise value assumptions incorporated: (i) economic and industry information relevant to the business; (ii) internal financial information and operating data; (iii) historical financial information; and (iv) financial projections and other applicable assumptions. The valuation techniques used to estimate the enterprise value as of Emergence included the income approach, market approach, and cost approach, with consideration of the exit market and nature of the applicable asset or liability subject to valuation. The Company’s principal assets are generation facilities whose values were determined by a discounted cash flow analysis based on management’s latest outlook of the business through the end of their expected useful lives. The forward-looking projections considered: (i) company-specific factors, such as unit characteristics, plant dispatch, operating expenses, capital expenditures and estimated economic useful lives; and (ii) macroeconomic factors, such as capacity prices, energy prices, fuel prices, market supply and demand factors, inflation factors, and environmental regulations. Commodity prices used to estimate future cash flows in observable periods were primarily based on adjusted exchange prices, prices provided by brokers, or prices provided by price service companies that are corroborated by market data. Commodity prices for future unobservable periods used third party pricing services that incorporate industry standard methodologies that may consider the historical relationships among various commodities, modeled market prices, inflation assumptions, and other relevant economic measures. Future estimates for capital expenditures and operating expenses, such as major maintenance and employee compensation were estimated considering unit operating experience, recent historical financial information, and expected operating performance. The expected useful lives of the generation facilities were estimated through 2050 and incorporated expectations regarding the economic prospects of each unit, permitting and licensing, regulatory requirements, and (or) other considerations. The cash flow estimates incorporated a federal effective tax rate of 21% and the applicable state tax rate based on the location of each generation facility. The present value of expected future cash flows utilized a weighted average cost of capital discount rate that ranged from 8.5 % to 46.5 %. The discount rate utilized for nuclear generation was 8.5 % and certain natural gas generation facilities were estimated near the low end of the range. Certain coal and natural gas generation units were estimated near the high end of the range. Discount rates for each generation facility considered, among other things, unit characteristics, fuel type, and market location. 66 Item 8. Table of Contents The assumptions used to estimate the reorganization value considered all available evidence as of Emergence and are believed to be consistent with those used by the principal market participants and outlook for each generation facility and represent management’s best estimate of reorganization value. However, such assumptions are inherently uncertain and require judgment. Accordingly, changes to sensitive assumptions, which primarily include commodity prices and discount rates, would have a reasonable possibility of significantly affecting the measurement of the reorganization value. See below under “Fresh Start Adjustments” for additional information regarding assumptions used in the measurement of the Company’s various other significant assets and liabilities. Upon the application of fresh start accounting, the Company preliminarily allocated the reorganization value to its individual assets based on their estimated fair values. The following table reconciles the Company’s enterprise value to the estimated reorganization value at Emergence: May 17, 2023 Enterprise value (a) $ 4,500 Plus: Cash and cash equivalents and Restricted cash and cash equivalents (b) 701 Plus: Current liabilities excluding long-term debt due within one year 514 Plus: Non-current liabilities excluding long-term debt and liability-classified warrants 1,234 Plus: Fair value of noncontrolling interest 110 Reorganization value to be allocated $ 7,059 __________________ (a) Excludes any value associated with noncontrolling interest. (b) Excludes $ 52 million for payment of professional fees. The following table reconciles TES’s enterprise value to the estimated fair value at Emergence: May 17, 2023 Enterprise value (a) $ 4,500 Plus: Cash and cash equivalents and Restricted cash and cash equivalents (b) 701 Less: Fair value of debt ( 2,845 ) Less: Liability-classified warrants ( 35 ) Fair value of member’s equity (c) 2,321 Plus: Fair value of noncontrolling interest 110 Fair value of equity $ 2,431 __________________ (a) Excludes any value associated with noncontrolling interest. (b) Excludes $ 52 million for payment of professional fees. (c) Issued in accordance with the Plan of Reorganization. Includes 59,028,843 shares of TEC common stock and $ 8 million of equity-classified warrants. 67 Item 8. Table of Contents Consolidated Balance Sheet The “Reorganization Adjustments” on the fresh start Consolidated Balance Sheet as of Emergence present the aggregate effect of the transactions contemplated by the Plan of Reorganization. The “Fresh Start Adjustments” present the preliminary fair value and other required adjustments as a result of applying fresh start accounting. The explanatory notes provide additional information related to the adjustments, the methods used to determine fair values, and significant assumptions. May 17, 2023 Assets Predecessor Reorganization Adjustments (a) Fresh Start Adjustments Successor Cash and cash equivalents $ 1,302 $ ( 1,133 ) (b) $ — $ 169 Restricted cash and cash equivalents 240 426 (c) ( 81 ) (q) 585 Accounts receivable, net 148 ( 3 ) (d) — 145 Inventory, net 448 — ( 141 ) (r) 307 Derivative instruments 818 — ( 632 ) (q) 186 Other current assets 135 — ( 5 ) (s) 130 Total current assets 3,091 ( 710 ) ( 859 ) 1,522 Property, plant and equipment, net 4,322 — ( 458 ) (t) 3,864 Nuclear decommissioning trust funds 1,465 — — 1,465 Derivative instruments 37 — ( 37 ) (q) — Other noncurrent assets 146 ( 12 ) (e) 74 (u) 208 Total Assets $ 9,061 $ ( 722 ) $ ( 1,280 ) $ 7,059 Liabilities and Equity Revolving credit facilities $ 848 $ ( 848 ) (f) $ — $ — Long-term debt, due within one year 1,005 ( 1,000 ) (g) — 5 Accrued interest 288 ( 284 ) (h) — 4 Accounts payable and other accrued liabilities 382 3 (i) — 385 Derivative instruments 711 — ( 654 ) (q) 57 Other current liabilities 414 ( 349 ) (j) 3 (v) 68 Total current liabilities 3,648 ( 2,478 ) ( 651 ) 519 Long-term debt 2,504 281 (k) 55 (w) 2,840 Liabilities subject to compromise 2,788 ( 2,788 ) (l) — — Derivative instruments 135 — ( 93 ) (q) 42 Postretirement benefit obligations ( 1 ) 302 (m) 34 (x) 335 Asset retirement obligations and accrued environmental costs 580 202 (m) ( 340 ) (y) 442 Deferred income taxes 82 283 (n) ( 8 ) (z) 357 Other noncurrent liabilities 19 60 (o) 14 (aa) 93 Total Liabilities 9,755 ( 4,138 ) ( 989 ) 4,628 Member’s equity ( 818 ) 3,416 (p) ( 277 ) (bb) 2,321 Noncontrolling interests 124 — ( 14 ) (cc) 110 Total Equity ( 694 ) 3,416 ( 291 ) 2,431 Total Liabilities and Equity $ 9,061 $ ( 722 ) $ ( 1,280 ) $ 7,059 Reorganization Adjustments The reorganization adjustments required in connection with the application of fresh start accounting and the allocation of the enterprise value were: (a) Emergence adjustments for the implementation of the Plan of Reorganization. Such adjustments include: (i) settlement of prepetition liabilities subject to compromise; (ii) payment of certain prepetition indebtedness; (iii) issuances of member’s equity; (iv) recognition of new indebtedness and related restricted cash; and (v) other items. 68 Item 8. Table of Contents (b) The uses of “Cash and cash equivalents” at Emergence resulting from the implementation of the Plan of Reorganization were: Proceeds from rights offering $ 1,400 Proceeds from TLB-1 and TLC 1,019 Proceeds from Secured Notes 1,200 Release of restricted cash 89 Payment of claims under prepetition senior secured revolving credit facility ( 1,029 ) Payment of claims under other prepetition secured indebtedness ( 2,136 ) Payment of debtor-in-possession term loan ( 1,012 ) Restriction of cash relating to TLC LCF ( 470 ) Payment of debt issuance costs on exit financing (TLB-1, TLC, and Secured Notes) ( 54 ) Funding of professional fees escrow account ( 52 ) Payment of hedge rejections ( 42 ) Payment to general unsecured creditors trust ( 26 ) Payment of professional fees ( 22 ) Other (a) 2 Total uses of Cash and cash equivalents $ ( 1,133 ) __________________ (a) Includes $ 1 million of proceeds from Riverstone for payment to general unsecured creditors trust. (c) “Restricted cash and cash equivalents” net change: Restriction of cash relating to TLC LCF $ 470 Funding of professional fees escrow account 52 Release of restricted cash ( 89 ) Payment of professional fees ( 7 ) Net change in Restricted cash and cash equivalents $ 426 (d) “Accounts receivable, net” net change related to settlement of affiliate receivables. (e) “Other noncurrent assets” net change: Write-off of debt issuance costs associated with prepetition senior secured revolving credit facility $ ( 22 ) Reclassification of previously capitalized debt issuance costs to Long-term debt ( 14 ) Capitalization of debt issuance costs 24 Net change in Other noncurrent assets $ ( 12 ) (f) Payment of principal amounts owed under prepetition senior secured revolving credit facility. (g) Repayment of debtor-in-possession credit facilities. (h) “Accrued interest” net change: Payment of accrued interest on prepetition senior secured revolving credit facility $ ( 183 ) Payment of accrued interest on other prepetition secured indebtedness ( 89 ) Payment of accrued interest on debtor-in-possession credit facilities ( 12 ) Net change in Accrued interest $ ( 284 ) (i) “Accounts payable and other accrued liabilities” net change: Payment of hedge contract rejections $ ( 42 ) Payment of professional fees ( 6 ) Reinstatement of liabilities subject to compromise 38 Accrual for professional fees incurred at Emergence 13 Net change in Accounts payable and other accrued liabilities $ 3 69 Item 8. Table of Contents (j) “Other current liabilities” net change: Issuance of equity for backstop premium $ ( 380 ) Reinstatement of liabilities subject to compromise 31 Net change in Other current liabilities $ ( 349 ) (k) “Long-term debt” net change: Payment of claims under prepetition secured indebtedness $ ( 2,048 ) Borrowings of $ 1.2 billion under the Secured Notes (a) 1,179 Borrowings of $ 580 million under TLB-1 (b) 548 Borrowings of $ 470 million under TLC (c) 446 Reinstatement of PEDFA 2009B Bonds and PEDFA 2009C Bonds (d) 130 Write-off of prepetition secured indebtedness issuance costs 26 Net change in Long-term debt $ 281 ______________ (a) Net of an aggregate initial purchaser discount and debt issuance costs of $ 21 million. (b) Net of an aggregate original issue discount and debt issuance costs of $ 32 million. (c) Net of an aggregate original issue discount and debt issuance costs of $ 24 million. (d) Includes recognition of $ 4 million of interest expense. (l) “Liabilities subject to compromise” settled or reinstated at Emergence in accordance with the Plan of Reorganization : Liabilities subject to compromise prior to Emergence Debt $ 1,555 Termination of retail contracts 447 Postretirement benefit obligations 305 Asset retirement obligations and accrued environmental costs 220 Other liabilities 92 Deferred tax liabilities 77 Accounts payable and accrued liabilities 51 Accrued interest 41 Total 2,788 Reinstatement and settlements of certain Liabilities subject to compromise Reinstatement of liabilities subject to compromise (a) ( 801 ) Excess fair value ascribed to lenders participating in rights offering ( 315 ) Issuance of member’s equity to holders of claims under prepetition unsecured notes and PEDFA 2009A Bonds ( 186 ) Payment to general unsecured creditors trust ( 24 ) Total ( 1,326 ) Gain on derecognition of certain Liabilities subject to compromise (b) $ 1,462 ______________ (a) Primarily includes postretirement benefit obligations, AROs, and deferred income taxes. (b) Represents liabilities subject to compromise that were discharged in accordance with the Plan of Reorganization. (m) Reinstatement of “Liabilities subject to compromise.” (n) “Deferred income taxes” net change: Increase in deferred tax liabilities primarily due to estimated tax attribute reduction from the recognition of cancellation of debt income, partially offset by change in valuation allowance $ 206 Reinstatement of liabilities subject to compromise 77 Net change in Deferred income taxes $ 283 70 Item 8. Table of Contents (o) “Other noncurrent liabilities” net change: Issuance of liability-classified warrants $ 35 Reinstatement of liabilities subject to compromise 25 Net change in Other noncurrent liabilities $ 60 The estimated fair value of liability-classified warrants was determined using a Black-Scholes Option Pricing Model with the following assumptions at Emergence: Expected volatility 30 % Expected term (years) 5 Expected dividend yield — % Risk-free interest rate 3.6 % Strike price per share $ 52.92 Fair value per share $ 11.29 (p) “Member’s equity” net change: Gain on settlement of liabilities subject to compromise $ 1,462 Other losses attributable to gain on debt discharge ( 3 ) Gain on debt discharge 1,459 Write-off of deferred financing cost ( 46 ) Professional fees expensed at Emergence ( 27 ) Restructuring-related compensation expense ( 8 ) Total reorganization items from reorganization adjustments 1,378 Interest expense incurred at Emergence ( 4 ) Income from reorganization adjustments before income taxes 1,374 Income tax expense ( 206 ) Net income from reorganization adjustments 1,168 Issuance of member’s equity in connection with rights offering 1,715 Issuance of member’s equity for backstop premium 380 Issuance of member’s equity to holders of claims under prepetition unsecured notes and PEDFA 2009A Bonds 186 Issuance of equity-classified warrants 8 Issuance of liability-classified warrants ( 35 ) Other (a) ( 6 ) Net change in Member’s equity $ 3,416 ______________ (a) Includes $ 1 million of proceeds from Riverstone for payment to general unsecured creditors trust. Fresh Start Adjustments (q) Net presentation of derivatives on the Consolidated Balance Sheets. See Note 2 for additional information on the related accounting policy. (r) “Inventory, net” fair value adjustments: Coal $ ( 33 ) Oil products 11 Materials and supplies ( 133 ) Environmental products 14 Total adjustment to Inventory, net $ ( 141 ) The fair values for oil, coal and environmental products were estimated using current market prices. The fair values of materials and supplies were estimated using an indirect cost approach. The cost approach estimates fair value by considering the amount required to construct or purchase a new asset of equal utility at current prices, with adjustments for asset function, age, physical deterioration, and obsolescence. (s) “Other current assets” primarily represents miscellaneous fair value adjustments. 71 Item 8. Table of Contents (t) “Property, plant and equipment, net” fair value adjustments: Electric generation $ ( 350 ) Other property and equipment ( 80 ) Intangible assets ( 65 ) Capitalized software ( 3 ) Construction work in progress 40 Total adjustment to Property, plant and equipment, net $ ( 458 ) The fair value of “Property, plant and equipment, net” was estimated using the income approach, market approach and cost approach, as applicable. The fair value of land was estimated utilizing the market approach, which considered comparable market-based transactions within a defined area based on size, use and utility. (u) “Other noncurrent assets” fair value adjustments: Favorable supply contracts (a) $ 109 Fair value adjustment to equity method investments 3 Eliminate debt issuance costs associated with debtor-in-possession credit facilities ( 29 ) Fair value reduction to other miscellaneous assets ( 9 ) Total adjustment to Other noncurrent assets $ 74 __________________ (a) The fair value of supply contracts was determined utilizing the present value of the after-tax difference between the pricing of actual contracts in place and a current market benchmark. (v) “Other current liabilities” fair value adjustments, primarily related to short-term AROs. (w) “Long-term debt” fair value adjustments: Eliminate debt issuance costs associated with prepetition secured notes, prepetition TLB and LMBE-MC TLB $ 48 Fair value adjustment to Cumulus Digital TLF 11 Fair value adjustment to LMBE-MC TLB ( 4 ) Total adjustment to Long-term debt $ 55 Fair value adjustments to “Long-term debt” were determined using a lattice model, given that the debt can be prepaid by the borrower prior to the maturity date. (x) Change in accounting policy for discount rates used to estimate postretirement obligations from a bond-matching model to yield curve approach. See Note 2 for additional information. (y) Adjustment to present at fair value AROs using assumptions as of Emergence, including an inflation factor of 2 %- 3 % and an estimated 5 - to 20 -year credit-adjusted risk-free rate of 8 %- 12 %based on timing of cash flows for each underlying obligation. (z) Adjustment to “Deferred income taxes” for the change in financial reporting basis of assets and liabilities as a result of the adoption of fresh start accounting. (aa) Fair value adjustments primarily related to unfavorable supply contracts of $ 13 million and the recognition of unfavorable lease liabilities. The fair value of supply contracts was determined utilizing the present value of the after-tax difference between the pricing of actual contracts in place and current market benchmarks. (bb) Cumulative impact of fresh start accounting adjustments presented herein. (cc) “Noncontrolling interests” fair value adjustments for certain subsidiaries . 72 Item 8. Table of Contents Liabilities Subject to Compromise As of December 31, 2022 (Predecessor), prepetition liabilities and obligations whose treatment and satisfaction were dependent on the outcome of the Restructuring were presented as “Liabilities subject to compromise” on the Consolidated Balance Sheets. The carrying value of prepetition liabilities that were subject to compromise are presented at the best estimate of the claim amount permitted by the Bankruptcy Court. Such amounts presented as “Liabilities subject to compromise” on the Consolidated Balance Sheets were subject to adjustments depending on bankruptcy court actions, developments with respect to disputed claims, determination of secured status of certain claims, the determination as to the value of any collateral securing claims, proof of claims and (or) other events. Predecessor December 31, 2022 Debt (a) $ 1,558 Termination of retail power and other contracts 447 Postretirement benefit obligations (a) 309 Asset retirement obligations and accrued environmental costs (a) 219 Other liabilities (a) 114 Deferred tax liabilities 83 Accounts payable and accrued liabilities 53 Accrued interest 41 Derivatives (a) 1 Liabilities Subject to Compromise $ 2,825 __________________ (a) Includes both current and noncurrent amounts. Reorganization Income (Expense), net “Reorganization income (expense), net” for the relevant periods were: Predecessor January 1 through May 17, 2023 Year Ended December 31, 2022 Backstop premium $ ( 70 ) $ ( 310 ) Gain (loss) on debt discharge 1,459 — Gain (loss) on revaluation adjustments ( 460 ) — Professional fees ( 56 ) ( 210 ) Make-whole premiums and accrued interest on certain indebtedness ( 21 ) ( 183 ) Professional fees incurred to obtain the debtor-in-possession credit facilities — ( 70 ) Write-off of deferred financing cost and original issue discount ( 46 ) ( 30 ) Other ( 7 ) ( 9 ) Reorganization Income (Expense), net $ 799 $ ( 812 ) In the preceding table, make-whole premiums and accrued interest on certain indebtedness primarily represents charges recognized by the debtors for estimates related to make-whole premiums and accrued interest, where applicable, on the prepetition senior secured revolving credit facility and certain other prepetition secured indebtedness. As of the bankruptcy petition date, the debtors ceased recognizing interest expense on certain outstanding unsecured or under-secured prepetition indebtedness. Contractual interest expense represented amounts due under the terms of outstanding prepetition indebtedness. The charges are presented as “Reorganization income (expense), net” on the Consolidated Statements of Operations and included in “Accrued interest” on the Consolidated Balance Sheets. Cash paid for certain reorganization expenses was $ 308 million for the period from January 1 through May 17, 2023 (Predecessor). Cash paid for the year ended December 31, 2022 (Predecessor) for debtor-in-possession credit facilities financing fees is presented as “Financing Activities” on the Consolidated Statements of Cash Flows. 73 Item 8. Table of Contents 5. Risk Management, Derivative Instruments and Hedging Activities Risk Management Objectives We are exposed to risks arising from our business, including but not limited to market and commodity price risk, credit and liquidity risk, and interest rate risk. The hedging strategies deployed by our commercial organization manage and (or) balance these risks within a structured risk management program in order to minimize near-term future cash flow volatility. Our risk management committee, comprised of certain senior management members across the organization, oversees the management of these risks in accordance with our risk policy. In turn, the risk management committee is overseen by the risk committee of the Board of Directors. The Board of Directors, including the risk committee, and management have established procedures to monitor, measure, and manage hedging activities and credit risk in accordance with the risk policy. Key risk control activities, which are designed to ensure compliance with the risk policy, include, among other activities, credit review and approval, validation of transactions and market prices, verification of risk and transaction limits, portfolio stress tests, analysis and monitoring of margin at risk, and daily portfolio reporting. Market and Commodity Price Risk. Volatility in the wholesale power markets provides uncertainty in the future earnings and cash flows of the business. The price risk Talen is exposed to includes the price variability associated with future sales and (or) purchases of power, natural gas, coal, uranium, oil products, environmental products, and other energy commodities in competitive wholesale markets. Several factors influence price volatility, including: (i) seasonal changes in demand; (ii) weather conditions; (iii) available regional load-serving supply; (iv) regional transportation and (or) transmission availability; (v) market liquidity; and (vi) federal, regional, and state regulations. Within the parameters of our risk policy, we generally utilize exchange-traded and over-the-counter traded derivative instruments and, in certain instances, structured products, to economically hedge the commodity price risk of the forecasted future sales and purchases of commodities associated with our generation portfolio. Open commodity purchase (sales) derivatives range in maturity through 2026. The net notional volumes of open commodity derivatives were: Successor December 31, 2024 (a) December 31, 2023 (a) Power (MWh) ( 38,615,192 ) ( 27,557,871 ) Natural gas (MMBtu) 32,405,460 8,314,060 Emission allowances (tons) 100,000 500,000 __________________ (a) The volumes may be less than the contractual volumes, as the probability that option contracts will be exercised is considered in the volumes displayed. Interest Rate Risk. Talen is exposed to interest rate risk from the possibility that changes in interest rates will affect future cash flows associated with existing floating rate debt issuances. To reduce interest rate risk, derivative instruments are utilized to economically hedge the interest rates for a predetermined contractual notional amount, which results in a cash settlement between counterparties. To the extent possible, first lien interest rate fixed-for-floating swaps are utilized to hedge this risk. Open interest rate derivatives are related to the TLB-1 indebtedness and mature in 2026. The net notional volumes of open interest rate derivatives were: Successor December 31, 2024 December 31, 2023 Interest rate (in millions) $ 290 $ 290 Credit Risk. Credit risk, which is the risk of financial loss if a customer, counterparty, or financial institution is unable to perform or pay amounts due, is applicable to cash and cash equivalents, restricted cash and cash equivalents, derivative instruments, and accounts receivable. The maximum amount of credit exposure associated with financial assets is equal to the carrying value of such assets. Credit risk, which cannot be completely eliminated, is managed through a number of practices such as ongoing reviews of counterparty creditworthiness, prepayment, inclusion of termination rights in contracts which are triggered by certain events of default, and executing master netting arrangements that permit amounts between parties to be offset. Additionally, credit enhancements such as cash deposits, LCs, and credit insurance may be employed to mitigate credit risk. 74 Item 8. Table of Contents Cash and cash equivalents are placed in depository accounts or high-quality, short-term investments with major international banks and financial institutions. Individual counterparty exposure from over-the-counter derivative instruments is managed within predetermined credit limits and includes the use of master netting arrangements and cash-call margins, when appropriate, to reduce credit risk. Exchange-traded commodity contracts, which are executed through futures commission merchants, have minimal credit risk because they are subject to mandatory margin requirements and are cleared with an exchange. However, Talen is exposed to the credit risk of the futures commission merchants arising from daily variation margin cash calls. Restricted cash and cash equivalents deposited to meet initial margin requirements are held by futures commission merchants in segregated accounts for the benefit of Talen. Outstanding accounts receivable include those from sales of capacity, generated electricity, and ancillary services through contracts directly with ISOs and RTOs and realized settlements of physical and financial derivative instruments with commodity marketers. Additionally, Talen carries accounts receivable due from joint owners for their portion of operating and capital costs for certain jointly owned facilities that are operated by the Company. The majority of outstanding receivables, which are continually monitored, have customary payment terms. The allowance for doubtful accounts was a non-material amount as of December 31, 2024 (Successor) and December 31, 2023 (Successor). As of December 31, 2024 (Successor), Talen’s aggregate credit exposure, which excludes the effects of netting arrangements, cash collateral, LCs, and any allowances for doubtful collections, was $ 350 million and its credit exposure including such net effects was $ 91 million. Excluding ISO and RTO counterparties, whose accounts receivable settlements are subject to applicable market controls, the ten largest single net credit exposures account for 71 % of Talen’s total net credit exposure, which are primarily with entities assigned investment grade credit ratings. Certain derivative instruments contain credit risk-related contingent features, which may require us to provide cash collateral, LCs, or guarantees from a creditworthy entity if the fair value of a liability eclipses a certain threshold or upon a decline in Talen’s credit rating. The fair values of derivative instruments in a net liability position, and that contain credit risk-related contingent features, were non-material as of December 31, 2024 (Successor) and December 31, 2023 (Successor). Derivative Instrument Presentation Balance Sheets Presentation. The fair value of derivative instruments presented within assets and liabilities on the Consolidated Balance Sheets were: Successor December 31, 2024 December 31, 2023 Assets Liabilities Assets Liabilities Commodity contracts $ 65 $ — $ 88 $ 32 Interest rate contracts 1 — 1 — Total current derivative instruments 66 — 89 32 Commodity contracts 4 7 6 5 Interest rate contracts 1 — — 6 Total non-current derivative instruments $ 5 $ 7 $ 6 $ 11 All commodity and interest rate derivatives are economic hedges where the changes in fair value are presented immediately in income as unrealized gains and losses. Changes in the fair value and realized settlements on commodity derivative instruments are presented as separate components of “Energy and other revenues” and “Fuel and energy purchases” on the Consolidated Statements of Operations. See Note 2 for additional information on derivative instruments and Note 14 for additional information on fair value. Effect of Netting. Generally, the right of setoff within master netting arrangements permits the fair value of derivative assets to be offset with derivative liabilities. As an election, derivative assets and derivative liabilities are presented on the Consolidated Balance Sheets with the effect of such permitted netting as of December 31, 2024 (Successor) and December 31, 2023 (Successor). 75 Item 8. Table of Contents The net amounts of “Derivative instruments” presented as assets and liabilities on the Consolidated Balance Sheets considering the effect of permitted netting and where cash collateral is pledged in accordance with the underlying agreement were: Gross Derivative Instruments Eligible for Offset Net Derivative Instruments Collateral (Posted) Received Net Amounts December 31, 2024 (Successor) Assets $ 227 $ ( 154 ) $ 73 $ ( 2 ) $ 71 Liabilities 173 ( 154 ) 19 ( 12 ) 7 December 31, 2023 (Successor) Assets $ 295 $ ( 198 ) $ 97 $ ( 2 ) $ 95 Liabilities 300 ( 198 ) 102 ( 59 ) 43 Statements of Operations Presentation. The location and pre-tax effect of “Derivative instruments” presented on the Consolidated Statements of Operations for the periods were: Successor Predecessor Year Ended December 31, 2024 May 18 through December 31, 2023 January 1 through May 17, 2023 Year Ended December 31, 2022 Realized gain (loss) on commodity contracts Energy revenues (a) $ 317 $ 360 $ 644 $ ( 613 ) Fuel and energy purchases (a) ( 35 ) ( 91 ) ( 34 ) 127 Unrealized gain (loss) on commodity contracts Operating revenues (b) 42 55 60 677 Energy expenses (b) 20 ( 3 ) ( 123 ) ( 52 ) Realized and unrealized gain (loss) on interest rate contracts Interest expense and other finance charges 9 ( 4 ) — 30 __________________ (a) Does not include those derivative instruments that settle through physical delivery. (b) Presented as “Unrealized gain (loss) on derivative instruments” on the Consolidated Statements of Operations. Contract Terminations Commodity Hedge Terminations. In March and April 2022, Talen Energy Marketing and a counterparty terminated certain derivative contracts in a net liability position with a carrying value and fair value of $ 124 million prior to the agreements’ scheduled maturity dates. As the parties agreed to a monthly settlement through January 2023, repayments are presented as “Derivatives with financing elements” on the Consolidated Statements of Cash Flows. In May 2022, certain commodity counterparties of Talen Energy Marketing terminated derivative contracts in a net liability position with a carrying value and fair value of $ 33 million prior to the agreements’ scheduled maturity dates. During 2022, Talen Energy Marketing received $ 7 million in net settlements from counterparties and, at Emergence, settled the remaining $ 40 million. 6. Revenue The components of operating revenues for the periods were: Successor Predecessor Year Ended December 31, 2024 May 18 through December 31, 2023 January 1 through May 17, 2023 Year Ended December 31, 2022 Capacity revenues $ 192 $ 133 $ 108 $ 377 Electricity sales and ancillary services, ISO/RTO 1,144 880 281 2,534 Physical electricity sales, bilateral contracts, other 147 71 62 298 Other revenue from customers 91 81 27 — Total revenue from contracts with customers 1,574 1,165 478 3,209 Realized and unrealized gain (loss) on derivative instruments 307 179 732 ( 120 ) Nuclear PTC (a) 220 — — — Other revenue 14 — — — Operating revenues $ 2,115 $ 1,344 $ 1,210 $ 3,089 __________________ (a) During the year ended December 31, 2024 (Successor), $ 70 million of estimated Nuclear PTCs were utilized as a credit against our federal income tax payable. See Note 7 for additional information on the tax impact of the Nuclear PTC . 76 Item 8. Table of Contents Accounts Receivable “Accounts receivable” presented on the Consolidated Balance Sheets were: Successor December 31, 2024 December 31, 2023 Customer accounts receivable $ 66 $ 52 Other accounts receivable 57 85 Accounts receivable $ 123 $ 137 During the year ended December 31, 2024 (Successor), the period from May 18 through December 31, 2023 (Successor), and the period from January 1 through May 17, 2023 (Predecessor), there were no significant changes in accounts receivable other than normal receivable recognition and collection transactions. See Note 5 for additional information on Talen’s credit risk on the carrying value of its receivables and for additional information on a Talen Energy Marketing receivables sales arrangement that was terminated in May 2022. Future Performance Obligations In the normal course of business, Talen has future performance obligations for capacity sales awarded through market-based capacity auctions and (or) for capacity sales under bilateral contractual arrangements. The PJM Base Residual Auction for the 2025/2026 PJM Capacity Year was held in July 2024. 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. The PJM BRAs for any years thereafter have not yet been held, and the PJM BRA for delivery year 2026/2027 has been postponed to July 2025. See Note 12 for additional information on the PJM BRAs. As of December 31, 2024 (Successor), the expected future period capacity revenues subject to unsatisfied or partially unsatisfied performance obligations were: 2025 2026 (a) 2027 2028 2029 Expected capacity revenues $ 478 $ 281 $ 3 $ 1 $ — __________________ (a) Estimated through May 31, 2026. The PJM BRA for the 2026/2027 PJM Capacity Year has been delayed to July 2025. 7. Income Taxes The components of “Income tax benefit (expense)” for the periods were: Successor Predecessor Year Ended December 31, 2024 May 18 through December 31, 2023 January 1 through May 17, 2023 Year Ended December 31, 2022 Federal $ ( 113 ) $ 3 $ ( 15 ) $ ( 9 ) State ( 31 ) 1 ( 2 ) ( 4 ) Current income taxes ( 144 ) 4 ( 17 ) ( 13 ) Federal 47 ( 55 ) ( 184 ) 68 State ( 1 ) — ( 11 ) ( 21 ) Deferred income taxes 46 ( 55 ) ( 195 ) 47 Investment tax credit — — — 1 Income tax benefit (expense) $ ( 98 ) $ ( 51 ) $ ( 212 ) $ 35 77 Item 8. Table of Contents Effective Tax Rate Reconciliations The reconciliations of the effective tax rate for the periods were: Successor Predecessor Year Ended December 31, 2024 May 18 through December 31, 2023 January 1 through May 17, 2023 Year Ended December 31, 2022 Income (loss) before income taxes $ 1,111 $ 194 $ 677 $ ( 1,328 ) Income tax benefit (expense) ( 98 ) ( 51 ) ( 212 ) 35 Effective tax rate 8.8 % 26.3 % 31.3 % 2.6 % Federal income tax statutory tax rate 21 % 21 % 21 % 21 % Income tax benefit (expense) computed at the federal income tax statutory tax rate $ ( 234 ) $ ( 41 ) $ ( 143 ) $ 279 Income tax increase (decrease) due to: Change in valuation allowance 128 ( 43 ) 129 ( 198 ) Nuclear PTC 46 — — — Reorganization adjustments 23 26 ( 138 ) — Return to provision 11 — — — Other permanent differences 3 22 ( 16 ) ( 94 ) Nuclear decommissioning trust taxes ( 27 ) ( 16 ) ( 9 ) 28 State income taxes, net of federal benefit ( 48 ) 1 ( 34 ) 19 Other — — ( 1 ) 1 Income tax benefit (expense) $ ( 98 ) $ ( 51 ) $ ( 212 ) $ 35 Deferred Taxes The components of deferred tax liabilities and deferred tax assets were: Successor December 31, 2024 December 31, 2023 Nuclear decommissioning trust $ 502 $ 443 Property, plant and equipment, net 465 560 Unrealized gain on qualifying derivatives 32 12 Investment in subsidiaries — 14 Deferred tax liabilities 999 1,029 Less: Interest limitation carryforward 340 336 Federal net operating loss carryforwards 164 273 Accrued pension costs 80 78 Accrued liabilities 30 26 State net operating loss carryforwards 15 26 Other 8 10 Deferred tax assets 637 749 Valuation allowance — ( 128 ) Deferred tax liabilities, net $ 362 $ 408 78 Item 8. Table of Contents Net Operating Losses The components of NOL carryforwards were: Successor December 31, 2024 December 31, 2023 Federal, expirations 2036 - 2037 $ — $ 43 Federal, indefinite expiration, limited to annual utilization of 80% 783 1,258 State, expirations 2025 - 2043 310 555 See “Emergence from Restructuring” below for information on limitations on our NOLs. Unrecognized Tax Benefits Unrecognized tax benefits as of December 31, 2024 (Successor) and December 31, 2023 (Successor) were a non-material amount and it is not expected the total amount of unrecognized tax benefit will change significantly within one year. All tax returns filed for years December 31, 2021 and forward are open to examination by the relevant taxing authorities. Emergence from Restructuring The Company evaluated, including the change in control resulting from its Emergence from bankruptcy, the tax impact of its Restructuring as described in Note 3. As part of the Restructuring, a substantial portion of the Company’s prepetition debt was extinguished, resulting in cancellation of debt income (“CODI”). A taxpayer emerging from bankruptcy may exclude CODI from taxable income but must first reduce its tax attributes by the amount of CODI realized. The Company realized CODI of $ 1.2 billion, which resulted in a partial reduction in tax basis in PP&E assets. Upon Emergence, the Company experienced an ownership change under Section 382 of the Internal Revenue Code. The Internal Revenue Code Sections 382 and 383 impose limitations on the ability of a company to utilize tax attributes after experiencing an ownership change. States generally have similar tax attribute limitation rules following an ownership change. The Company also applied fresh start accounting. As a result, deferred tax assets and liabilities were adjusted based on the Successor GAAP financial statements. See Note 4 for additional information on fresh start accounting. Valuation Allowance The Company’s most significant deferred tax assets are its net operating losses and interest limitation carryforward. Management assesses the available positive and negative evidence to estimate whether it is more likely than not that sufficient future taxable income will be generated to permit the use of existing deferred tax assets. Such assessment includes the evaluation of historical earnings after adjusting for certain nonrecurring items for the purpose of projecting future taxable income. Negative evidence in the form of cumulative losses are no longer present as the Company has returned to profitability. The existence of objective positive evidence allows for consideration of other subjective evidence, including (but not limited to) Talen’s projections for future income which would allow for utilization of all net operating losses and interest limitation carryforwards. At each period, management will continue to assess the available positive and negative evidence to determine the need for a valuation allowance. As a result of the assessment, it was determined that it is more likely than not that federal and state deferred tax assets will be fully utilized by future taxable income. As of December 31, 2024 (Successor), the entire federal and state valuation allowances were released, resulting in a $ 128 million tax benefit. For the period from May 18 through December 31, 2023 (Successor), a $ 43 million tax expense was recognized for the increase in federal and state valuation allowances based on the realizability of deferred tax assets. For the period from January 1 through May 17, 2023 (Predecessor), a $ 129 million benefit was recognized for the reduction in federal and state valuation allowances. The change in valuation allowance estimates was the result of tax attribute reduction from the cancellation of debt income that was realized upon Emergence. For the year ended December 31, 2022 (Predecessor) a $ 198 million tax expense was recognized for the increase in federal and state valuation allowances based on realizability of deferred tax assets. 79 Item 8. Table of Contents Inflation Reduction Act of 2022 The Inflation Reduction Act was signed into law in August 2022. Among the Act’s provisions are amendments to the Internal Revenue Code to create a nuclear production tax credit program. The Nuclear PTC program provides qualified nuclear power generation facilities with a $ 3 per MWh transferable credit for electricity produced and sold to an unrelated party during each tax year. Electricity produced and sold by Susquehanna to third parties after December 31, 2023 through December 31, 2032 qualifies 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 (which we expect to meet), 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 17 million MWh sold to third parties in calendar year 2024. 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, the terms of which are not yet fully 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. Accordingly, 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 6 for additional information on Nuclear PTC revenue recognized. Current Taxes Payable Current tax liabilities presented as “Other current liabilities” on the Consolidated Balance Sheets were $ 53 million as of December 31, 2024 (Successor) and $ 2 million as of December 31, 2023 (Successor). 8. Inventory Successor December 31, 2024 December 31, 2023 Coal $ 92 $ 152 Oil products 65 75 Fuel inventory for electric generation 157 227 Materials and supplies, net 88 72 Environmental products 57 76 Inventory, net $ 302 $ 375 Inventory net realizable value and obsolescence charges on coal and fuel oil inventories are presented as “Other operating income (expense), net” on the Consolidated Statements of Operations. Such non-cash charges were non-material for the year ended December 31, 2024 (Successor), non-material for the period from May 18 through December 31, 2023 (Successor), $ 37 million for the period from January 1 through May 17, 2023 (Predecessor) , and non-material for the year ended December 31, 2022 (Predecessor). During the period from January 1 through May 17, 2023 (Predecessor), $ 24 million of adjustments were related to Brandon Shores coal and materials and supplies inventories. See Note 10 for additional information on the Brandon Shores recoverability assessment. 80 Item 8. Table of Contents 9. Nuclear Decommissioning Trust Funds Successor December 31, 2024 December 31, 2023 Amortized Cost Unrealized Gains Unrealized Losses Fair Value Amortized Cost Unrealized Gains Unrealized Losses Fair Value Cash equivalents $ 3 $ — $ — $ 3 $ 9 $ — $ — $ 9 Equity securities 509 651 55 1,105 491 575 53 1,013 Debt securities 615 3 7 611 570 10 1 579 Receivables (payables), net 5 — — 5 ( 26 ) — — ( 26 ) NDT funds $ 1,132 $ 654 $ 62 $ 1,724 $ 1,044 $ 585 $ 54 $ 1,575 See Note 14 for additional information on the NDT fair value. There were no available-for-sale debt securities with credit losses as of December 31, 2024 (Successor) and December 31, 2023 (Successor). As of December 31, 2024 (Successor), there was no intent to sell available-for-sale debt securities with unrealized losses, and it is not more likely than not that each of these investments will be required to be sold before the recovery of its amortized cost. The aggregate related fair value of available-for-sale debt securities with unrealized losses as of December 31, 2024 (Successor) were: Fair Value Unrealized Losses Corporate debt securities $ 71 $ ( 2 ) Municipal debt securities 60 ( 1 ) U.S. Government debt securities 226 ( 4 ) Debt securities in unrealized loss position $ 357 $ ( 7 ) As of December 31, 2024 (Successor), the aggregate fair value of debt securities in a loss position for a duration of one year or longer were $ 15 million and the unrealized losses were non-material. The contractual maturities for available-for-sale debt securities presented on the Consolidated Balance Sheets were: Successor December 31, 2024 December 31, 2023 Maturities within one year $ 82 $ 105 Maturities within two to five years 220 194 Maturities thereafter 309 280 Debt securities, fair value $ 611 $ 579 The sales proceeds, gains, and losses for available-for-sale debt securities for the periods were: Successor Predecessor Year Ended December 31, 2024 May 18 through December 31, 2023 January 1 through May 17, 2023 Year Ended December 31, 2022 Sales proceeds of NDT funds investments (a) $ 2,132 $ 1,259 $ 839 $ 2,081 Gross realized gains 12 5 7 10 Gross realized losses ( 13 ) ( 11 ) ( 12 ) ( 43 ) __________________ (a) Sales proceeds are used to pay income taxes and trust management fees. Remaining proceeds are reinvested in the NDT. 81 Item 8. Table of Contents 10. Property, Plant and Equipment Successor December 31, 2024 December 31, 2023 Estimated Useful Life (years) Gross Value Accumulated Depreciation Carrying Value Gross Value Accumulated Depreciation Carrying Value Electric generation 3 - 27 $ 3,030 $ ( 292 ) $ 2,738 $ 3,178 $ ( 109 ) $ 3,069 Nuclear fuel 1 - 6 322 ( 152 ) 170 228 ( 55 ) 173 Other property and equipment 1 - 26 90 ( 18 ) 72 358 ( 21 ) 337 Capitalized software 1 - 5 8 ( 3 ) 5 6 ( 1 ) 5 Construction work in progress 169 — 169 255 — 255 Property, plant and equipment, net $ 3,619 $ ( 465 ) $ 3,154 $ 4,025 $ ( 186 ) $ 3,839 The components of “Depreciation, amortization and accretion ” presented on the Consolidated Statements of Operations for the periods were: Successor Predecessor Year Ended December 31, 2024 May 18 through December 31, 2023 January 1 through May 17, 2023 Year Ended December 31, 2022 Depreciation expense (a) $ 225 $ 133 $ 173 $ 432 Amortization expense (b) 16 1 4 12 Accretion expense (c) 57 31 24 78 Other — — ( 1 ) ( 2 ) Depreciation, amortization and accretion $ 298 $ 165 $ 200 $ 520 __________________ (a) Electric generation and other property and equipment. (b) Intangible assets and capitalized software. (c) ARO and accrued environmental cost accretion. See Note 11 for additional information. The cost of nuclear fuel and the amortization of nuclear fuel intangible assets are presented as “Nuclear fuel amortization” on the Consolidated Statements of Operations. Amortization expense related to nuclear fuel intangible assets was $ 33 million for the year ended December 31, 2024 (Successor) and $ 53 million for the period from May 18 through December 31, 2023 (Successor). Estimated intangible assets amortization expense for the next four years is: 2025 2026 2027 2028 (a) Estimated amortization expense $ 14 $ 5 $ 3 $ 1 __________________ (a) Supply contracts underlying the nuclear fuel intangible assets expire in 2028. The carrying value of nuclear fuel intangible assets presented as “Other noncurrent assets” on the Consolidated Balance Sheets was $ 23 million as of December 31, 2024 (Successor) and $ 56 million as of December 31, 2023 (Successor). Jointly Owned Facilities Certain of Talen's subsidiaries own undivided interests in jointly owned electric generation facilities and related assets. These generation facilities and other assets are maintained and operated pursuant to their joint ownership participation and operating agreements. Under such arrangements, each participant is responsible for funding its proportional share of costs and is entitled to its proportionate share of electric generation and (or) other attributes of the relevant jointly owned facilities. Talen's proportional share of gross margin and other operating costs for its undivided interests is presented within the Consolidated Statements of Operations. Talen owns undivided interest of 90 % in Susquehanna, 22.22 % in Conemaugh, and 12.34 % in Keystone. See below for information regarding the ownership of Colstrip in Montana. The carrying value of Colstrip, Conemaugh, and Keystone were non-material as of December 31, 2024 (Successor) and December 31, 2023 (Successor). 82 Item 8. Table of Contents The proportionate share of “Property, plant and equipment, net” related to Susquehanna presented on the Consolidated Balance Sheets was: Successor December 31, 2024 December 31, 2023 Ownership interest 90 % 90 % Electric generation $ 2,206 $ 2,187 Nuclear fuel 322 228 Other property and equipment 25 19 Capitalized software 2 2 Construction work in progress 109 95 Proportionate property, plant and equipment, cost 2,664 2,531 Less: accumulated depreciation and amortization 326 121 Proportionate property, plant and equipment, net $ 2,338 $ 2,410 Talen Montana. Talen Montana owns 30 % of Colstrip Unit 3 and does not own any portion of Colstrip Unit 4. However, it is a participant in a joint-owner sharing agreement which governs each party’s responsibilities and rights whereby Talen Montana is responsible for 15 % of the total operating costs and expenditures of Colstrip Unit 3 and 15 % of Colstrip Unit 4. Accordingly, it is entitled to 15 % of the available generation from each of these units. In January 2020, Talen Montana and the other co-owner of Colstrip Units 1 and 2 permanently retired the units. Talen Montana is responsible for 50 % of the decommissioning and other related costs of Colstrip Units 1 and 2. Reliability Impact Assessments Brandon Shores and H.A Wagner RMR Arrangements. In 2023, we notified PJM of our intent to deactivate electric generation at both our Brandon Shores and H.A. Wagner facilities on June 1, 2025. However, PJM subsequently notified us that both Brandon Shores and H.A Wagner are needed past their previously planned retirement dates to maintain reliability in PJM. In January 2025, we reached a settlement (which remains subject to FERC approval) with key stakeholders on the terms of an RMR arrangement and filed with FERC the resulting Joint Offers of Settlement regarding both facilities’ RMR Continuing Operations Rates Schedules (the “CORS”). If approved, the proposed RMR arrangements will extend the operating life of these plants through May 31, 2029, or until such time as the necessary transmission upgrades are placed into service. Beginning June 1, 2025, the CORS will provide a monthly fixed-cost payment of $ 12,083,333 ($ 312 /MW-day) for Brandon Shores and $ 2,916,667 ($ 137 /MW-day) for H.A Wagner, which includes a performance “hold back” of $ 416,667 per month for Brandon Shores and $ 208,333 per month for H.A Wagner, each to be paid out based on unit performance. We will also receive separate reimbursement for variable costs and approved project investments. 2023 Impairment Brandon Shores Asset Group. Brandon Shores is required by contract and permit to cease coal combustion by December 31, 2025. In the first quarter 2023, Talen canceled its plan to convert Brandon Shores to an oil combustion facility due to an increase in expected conversion costs. This decision triggered a recoverability assessment of the carrying value of the Brandon Shores asset group. Brandon Shores notified PJM that it will deactivate electric generation on June 1, 2025. See above for additional information. The recoverability analysis indicated that the Brandon Shores asset group carrying value exceeded its future estimated undiscounted cash flows, which required an impairment charge to amend the asset group’s carrying value of its PP&E to its estimated fair value. The estimated fair value of the asset group was determined by a discounted cash flow technique that utilized significant unobservable inputs including an 11 % discount rate. We believe that the utilized discount rate and other discounted cash flow assumptions are consistent with those used by principal market participants. Such assumptions consider available evidence regarding the prospects of future cash flows for the Brandon Shores asset group, including but not limited to estimated available future generation volumes and useful lives, capacity prices, energy prices, operating costs, capital expenditures, and environmental costs. Accordingly, for the period from January 1 through May 17, 2023 (Predecessor), a $ 361 million non-cash pre-tax impairment charge on the asset group’s undepreciated PP&E is presented as “Impairments” on the Consolidated Statements of Operations. 83 Item 8. Table of Contents Equity Method Investments Talen holds equity interests in Conemaugh Fuels and Keystone Fuels equal to its respective undivided ownership interests in Conemaugh and Keystone. Conemaugh Fuels and Keystone Fuels were formed to purchase coal and sell it to Conemaugh and Keystone. Additionally, they may sell coal to any entity that manufactures or produces synthetic fuel from coal for resale to Conemaugh and Keystone. The aggregate affiliated fuel purchases by Talen from Conemaugh Fuels and Keystone Fuels is presented as “Fuel and energy purchases” on the Consolidated Statements of Operations. Talen’s aggregate fuel purchases for Conemaugh and Keystone Fuels were $ 35 million for the year ended December 31, 2024 (Successor), $ 23 million for the period from May 18 through December 31, 2023 (Successor) and $ 14 million for the period from January 1 through May 17, 2023 (Predecessor). For the year ended December 31, 2022 (Predecessor), Talen’s aggregate fuel purchases were $ 63 million. 11. Asset Retirement Obligations and Accrued Environmental Costs Successor December 31, 2024 December 31, 2023 Asset retirement obligations $ 498 $ 464 Accrued environmental costs 21 23 Total asset retirement obligations and accrued environmental costs 519 487 Less: asset retirement obligations and accrued environmental costs due within one year (a) 51 18 Asset retirement obligations and accrued environmental costs due after one year $ 468 $ 469 __________________ (a) Presented as “ Other current liabilities ” on the Consolidated Balance Sheets. Asset Retirement Obligations Certain subsidiaries of the Company have legal retirement obligations for the decommissioning and environmental remediation costs associated with our current and former generation, which include activities such as structure removal and remediation of coal piles, wastewater basins, and ash impoundments. Most of these obligations, except remediation of some ash impoundments, are not expected to be paid until several years, or decades, in the future. The most significant obligations are associated with the decommissioning of Susquehanna (for which the NDT is expected to fund) and coal ash disposal units associated with legacy coal-fired generation facilities (for which the Company has posted surety bonds and letters of credit for certain facilities). The carrying value of these obligations include assumptions of estimated future ARO cash expenditures, cost escalation rates, probabilistic cash flow models and discount rates. The ARO carrying value of AROs associated with legacy coal-fired generation facilities may be impacted by current or future EPA rulemaking. Additionally, as of December 31, 2024 (Successor), the fair values of certain AROs as a result of the EPA CCR Rule cannot be determined. See Note 12 for additional information on the EPA CCR Rule and the regulatory timeline that is expected to determine the associated scope of work. Additionally, certain subsidiaries of the Company have legal retirement obligations associated with the removal, disposal, and (or) monitoring of asbestos-containing material at certain generation facilities. Given that the ultimate volume of asbestos-containing material is not yet known, the fair value of these obligations cannot be reasonably estimated. These obligations will be recognized upon a change in economic events or other circumstances which enables the fair value to be estimable. 84 Item 8. Table of Contents The changes of the ARO carrying value during the periods were: ARO Rollforward Carrying value, December 31, 2022 (Predecessor) $ 751 Obligations settled ( 11 ) Changes in estimates and (or) settlement dates 3 Accretion expense 23 Carrying value, May 17, 2023 (Predecessor) $ 766 Carrying value, May 18, 2023 (Successor) $ 766 Fair value adjustment at Emergence ( 321 ) Obligations settled ( 11 ) Accretion expense 30 Carrying value, December 31, 2023 (Successor) $ 464 Obligations settled ( 13 ) Changes in estimates and (or) settlement dates ( 17 ) Accretion expense 55 Obligations incurred 9 Carrying value, December 31, 2024 (Successor) $ 498 Supplemental information for the ARO: Successor December 31, 2024 December 31, 2023 Supplemental Information Nuclear (a) $ 242 $ 214 Non-Nuclear (b) 256 250 Carrying value $ 498 $ 464 __________________ (a) Obligations are expected to be settled with available funds in the NDT at the time of decommissioning. See Note 14 for additional information on the NDT. (b) Certain obligations are: (i) partially supported by surety bonds, some of which have been collateralized with cash and (or) LCs; or (ii) partially prefunded under phased installment agreements. Susquehanna. Each joint owner of Susquehanna is obligated to fund their proportional share of Susquehanna's ARO. Talen’s proportionate share of decommissioning activities will be funded from the NDT when decommissioning commences in connection with the expiration of Susquehanna’s licenses. The licenses for Susquehanna Unit 1 and Unit 2 expire in 2042 and 2044, respectively, and can be extended subject to NRC approval. The NRC has jurisdiction over the decommissioning of nuclear power generation facilities and requires minimum decommissioning funding based upon a formula. Under the most recent calculation in 2022, the NDT exceeds the NRC's minimum funding requirements. Each joint owner of Susquehanna is obligated to fund their proportional decommissioning costs if their respective nuclear decommissioning trusts do not contain sufficient funds. We believe the NDT will be adequate to fund the Company’s proportionate share of decommissioning costs. As of December 31, 2024 (Successor), the fair value of the NDT was $ 1.7 billion and the carrying value the Company’s proportionate share of the Susquehanna ARO, which is discounted under a present value technique, was $ 242 million. See Note 2 for additional information on the measurement of AROs. Talen Montana. Talen Montana has significant decommissioning and environmental remediation liabilities primarily consisting of its proportionate share of remediation, closure and decommissioning costs for coal ash impoundments at Colstrip. Due to the expected timing and scope of anticipated remediation activities, actual cash expenditures associated with these obligations are expected to materially increase over the next five years and will continue at a reduced spending level for several decades. Talen Montana, along with the other co-owners of Colstrip, are working with the Montana Department of Environmental Quality (the “MDEQ”) to define the scope of required remediation, the scope of closure and decommissioning activities, and an estimate of the costs, including the amount of necessary financial assurance necessary to backstop these obligations. Talen Montana's decommissioning and environmental remediation is expected to be paid by funds available to Talen Montana at the time of decommissioning. Talen Montana's estimate of its proportionate share of the AROs, discounted using a credit adjusted risk-free rate, was $ 98 million at December 31, 2024 (Successor) and $ 107 million at December 31, 2023 (Successor). 85 Item 8. Table of Contents As a result of environmental regulations issued by the EPA or other regulatory entities, the Company may be required to revise and (or) recognize new AROs. Future adjustments may be required to the Talen Montana ARO estimates due to the ongoing remediation requirements under MDEQ obligations and the EPA CCR Rule. If the assumptions underlying Talen Montana's estimates do not materialize as expected, actual cash expenditures and costs could be materially different than currently estimated. Moreover, regulatory changes and (or) changes resulting from required scope revisions on remediation activities could affect these obligations. See Note 12 for information on Talen Montana’s requirement to provide financial assurance for certain environmental decommissioning and remediation liabilities related to Colstrip. Accrued Environmental Costs Under the Pennsylvania Clean Streams Law, a Talen subsidiary is obligated to remediate acid mine drainage at a former mine site and may be required to take additional steps to prevent acid mine drainage at this site. Liabilities related to the remediation were $ 21 million and $ 23 million as of December 31, 2024 (Successor) and December 31, 2023 (Successor), respectively, and were presented as “Other current liabilities” and “Asset retirement obligations and accrued environmental costs” on the Consolidated Balance Sheets. Such liabilities were discounted based on a credit adjusted risk-free rate that was in existence at the time of initial liability recognition of 8.41 %. The undiscounted amount of the liabilities was $ 32 million and $ 34 million as of December 31, 2024 (Successor) and December 31, 2023 (Successor). 12. Commitments and Contingencies Legal, Regulatory, and Environmental Matters We are regularly subject to various legal, regulatory, and environmental matters in connection with our business. While we believe we have meritorious positions and will continue to vigorously defend our positions in these matters, we may not be successful in our efforts, and we cannot predict the effect of an adverse outcome of any such matter. If an unfavorable outcome is probable and can be reasonably estimated, a liability is recognized. In the event of an unfavorable outcome, the liability may be in excess of amounts currently accrued. Because of the inherently unpredictable nature of legal, regulatory, and environmental matters and the wide range of potential outcomes for any such matter, no estimate of the possible losses in excess of amounts accrued, if any, can be made at this time regarding any matter specifically described below. As a result, additional losses actually incurred in excess of amounts accrued could be substantial. Unless otherwise disclosed below, we are unable to predict the outcome of any matter discussed below or reasonably estimate the amount of any associated costs and (or) potential liabilities. Additionally, it is possible that the outcome of any such matter, including market modifications, could materially impact our business, financial condition, results of operations, cash flows, and (or) liquidity. Legal Matters We are involved in various legal and administrative proceedings, investigations, claims, and litigation from time to time in the course of our business. Such matters may include, but are not limited to, those relating to employment and benefits, commercial disputes, personal injury, property damage, regulatory matters, environmental matters, and various other claims for injuries and (or) damages. While we believe we have meritorious positions and will continue to appropriately respond to all legal matters, because of the inherently unpredictable nature of legal proceedings, there is a wide range of potential outcomes for any such matter. ERCOT Weather Event (Winter Storm Uri) Lawsuits. In connection with the ERCOT Sale (see Note 20 for additional information), the Company retained certain potential liabilities relating to claims filed from 2021 onward against its former Texas subsidiaries seeking unspecified damages for alleged losses caused by the defendants’ failure to provide sufficient power to the grid during Winter Storm Uri. The claims also allege similar liability against numerous other ERCOT power market participants. In December 2023, five multi-district litigation (“MDL”) bellwether lawsuits, which were selected by the MDL court as representative of all 58 cases filed in the Uri litigation, were dismissed by the MDL court, a ruling subsequently upheld by the Texas First Court of Appeals. On January 31 and February 3, 2025, the plaintiffs (in two groups) filed for mandamus relief in the Texas Supreme Court, seeking to overturn the lower courts. If affirmed by the Texas Supreme Court, Talen expects the dismissal ruling to apply broadly to all Uri cases against Talen’s former subsidiaries. Pursuant to the Plan of Reorganization, Talen’s maximum potential damages on prepetition Uri claims are expressly limited to payments from Talen’s insurers. However, claims filed after the Restructuring by plaintiffs who did not receive effective notice of the Restructuring, if any, may not be subject to the limitations in the Plan of Reorganization. Spent Nuclear Fuel Litigation. Federal law requires the U.S. government to provide for the permanent disposal of commercial SNF, but the government has not yet done so. Until May 2014, the Department of Energy required nuclear generation facility operators to contribute to a fund intended to pay for the transportation and disposal of SNF, and Talen cannot predict if or when the government will reinstate any such fee in the future. In May 2023, an existing settlement agreement between Susquehanna and the U.S. government was extended through the end of 2025. The settlement agreement requires the government to reimburse Susquehanna for certain SNF storage costs through 2025 and requires Susquehanna to waive certain claims against the government relating to temporary SNF storage. As of December 31, 2024 (Successor), the Company has an accrued receivable of $ 14 million related to such reimbursements. During the period from May 18 through December 31, 2023 (Successor) and the year ended December 31, 2022 (Predecessor), Susquehanna received reimbursements of $ 24 million and $ 7 million for such costs. No assurance can be provided that this arrangement will be extended beyond 2025. 86 Item 8. Table of Contents Regulatory Matters We are subject to regulation by federal and state agencies and other bodies that exercise regulatory authority in the various regions where we conduct business, including but not limited to FERC; the Department of Energy; the NRC; NERC; the Federal Communications Commission; and state public utility commissions. In addition, the RTOs and ISOs in the regions in which we conduct business inherently have complex rules that are intended to balance the interests of market stakeholders. Proposed market structure modifications may lead to disputes among stakeholders that might not be resolved for a period of time as a result of regulatory and (or) legal proceedings. Accordingly, we are subject to uncertainty with respect to: (i) new or amended regulations issued by regulatory agencies; and (ii) changes in market design, tariff structure, capacity auctions, and (or) pricing rules. PJM Capacity Market Reform. In June 2023, FERC accepted a request by PJM to delay certain PJM Base Residual Auctions in order for PJM to propose market reforms. PJM filed its market reform proposals with FERC in October 2023. In early 2024, FERC accepted portions of PJM’s proposed market changes. PJM held the PJM BRA for the 2025/2026 PJM Capacity Year in July 2024 which incorporated the FERC accepted changes. The PJM BRAs for the 2026/2027, 2027/2028, and 2028/2029 PJM Capacity Years were previously scheduled for December 2024, June 2025 (later changed to July 2025), and December 2025, respectively; however in September 2024, the Sierra Club and other organizations filed a complaint at FERC challenging PJM’s rules establishing must-offer exceptions for PJM BRA participation by RMR resources and seeking to delay the 2026/2027 PJM BRA pending resolution of its complaint. In October 2024, PJM announced it had concerns about FERC considering the Sierra Club’s complaints about RMR resources in isolation and therefore intended to file a Section 205 proceeding under the Federal Power Act seeking FERC’s approval of to-be-determined market reforms, including but not limited to potential revisions to the treatment of RMR resources. As a result, in October 2024 PJM formally requested that FERC approve six-month delays in the PJM BRAs for the 2026/2027, 2027/2028, 2028/2029, and 2029/2030 PJM Capacity Years and in November 2024, FERC approved the auction delays. The planning parameters for the 2026/2027 PJM BRA are expected in March 2025. Talen can provide no assurance that the four scheduled auctions will be held as scheduled or at all. A series of filings aimed at reforming the PJM capacity market were filed at FERC. In November 2024, the Joint Consumer Advocates, comprised of consumer advocacy groups and government entities from Illinois, Maryland, New Jersey, Ohio, and the District of Columbia filed a complaint against PJM asking FERC to find that PJM’s existing capacity market rules are unjust and unreasonable and issue an order requiring certain short-term and longer-term changes to PJM’s capacity market rules. In response, PJM made two FERC filings in December 2024 to address what they perceive as capacity market design issues (the “PJM Capacity Market 205 proceeding”). PJM proposed to retain the dual fuel combustion turbine as the reference resource and to implement a uniform non-performance charge throughout the RTO for the 2026/2027 and 2027/2028 delivery years, and to administratively include RMR units that meet certain criteria as price takers in the capacity auctions for the next two delivery years and will not assess penalties or pay bonuses to these RMR units. If approved, under PJM’s proposal, Talen’s Brandon Shores and H.A. Wagner plants may meet the criteria for RMR inclusion in the capacity auctions. PJM’s filing also clarifies that being excused from being required to offer into the capacity market is no defense to exercising market power by electing not to offer. Further, PJM proposed to make changes to the capacity market mitigation rules. This proposal will eliminate the must-offer exception for intermittent and limited duration resources that are eligible to participate in the capacity market and will allow market sellers to incorporate a risk component in their capacity market offers. Following the above filings, in December 2024, the Pennsylvania Governor filed a complaint against PJM at FERC to address alleged elevated costs to consumers from the PJM capacity market in the 2026/2027 and 2027/2028 delivery years. Among other things, the Governor’s complaint proposed to lower the capacity price cap and reopen the closed interconnection queue to get new projects online. In January 2025, the Governor filed a motion to consolidate his complaint with the Joint Consumer Advocates complaint and two PJM filings referenced above. On January 28, 2025, the Governor and PJM announced they had reached an agreement to resolve the Governor’s complaint. That agreement would impose a collar on the capacity prices in the 2026/2027 and 2027/2028 BRAs, with a minimum capacity price of $ 175 /Megawatt-day (“MWd”) and a maximum price of $ 325 /MWd. On February 14, 2025, FERC accepted PJM’s proposals in the PJM Capacity Market 205 proceeding and as a result, the changes to the BRA parameters described above as part of that proceeding will be adopted for the 2026/2027 and 2027/2028 delivery years. Also on February 14, 2025, as a result of the agreement with PJM to collar the BRA results for the next two auction the Governor withdrew his complaints from FERC. On February 20, 2025, PJM initiated a new Section 205 proceeding seeking FERC’s approval of a settlement that will revise the relevant auction parameters and impose the capacity price collar agreed to with the Governor. The filing seeks expedited treatment intended to maintain the current auction schedule. At this time, it is unknown whether the collar arrangement will be approved by FERC or whether the auction schedule will remain unchanged. Talen filed comments in support of this proposal on February 24, 2025. On February 20, 2025, FERC initiated a technical conference docket to consider broad resource adequacy issues across all RTOs, with the initial proceedings to take place on June 4 and 5, 2025. The Company intends to intervene in the new technical conference docket and participate in those proceedings. 87 Item 8. Table of Contents Environmental Matters Extensive federal, state, and local environmental laws and regulations are applicable to our business, including those related to air emissions, water discharges, and hazardous substances and solid waste management. From time to time, in the ordinary course of our business, Talen may be: (i) subject to environmental remediation work at its facilities; (ii) involved in other environmental matters; or (iii) become subject to other, new or revised environmental statutes, regulations, or requirements. It may be necessary for us to modify, curtail, replace, or cease operation of certain facilities or performance of certain operations to comply with statutes, regulations, and other requirements imposed by regulatory bodies, courts, or environmental groups. We may incur significant costs to comply with these requirements, including increased capital expenditures or operation and maintenance expenses, monetary fines, remediation costs, penalties, or other restrictions. Legal challenges to environmental rules or permits add to the uncertainty of estimating future compliance costs. In addition, in January 2025, President Trump issued executive orders directing the heads of all federal agencies to identify and begin the processes to suspend, revise, or rescind all agency actions, including existing regulations, that are unduly burdensome on the identification, development, or use of domestic energy resources. Consequently, future implementation and enforcement of these rules remains uncertain at this time. Further, costs may increase significantly if the requirements or scope of environmental laws or regulations, or similar rules, are expanded or changed. EPA CSAPR and Nitrogen Oxides (“NOx”) Requirements. Coal-fired generation facilities, including those in which Talen has ownership, have been the subject of EPA regulations and efforts by certain states and other parties to strengthen applicable NOx emission limits under the Clean Air Act. In 2015, the EPA’s 2015 revision to the 8-hour ozone National Ambient Air Quality Standards for ground-level ozone to 70 parts per billion (the “EPA 2015 Ozone Standard”) was issued, which triggered updates to state-specific compliance requirements as well as provisions that are intended to limit cross-state emissions. In June 2023, the EPA published a rule in connection with the EPA 2015 Ozone Standard updating the EPA CSAPR ozone season NOx allowance trading program for 2023 and beyond (“Good Neighbor Plan”). Talen’s facilities in Maryland, Pennsylvania, and New Jersey are subject to the new rule; however, the entire rule has been challenged by multiple parties. The Good Neighbor Plan was stayed in its entirety by the U.S. Supreme Court in June 2024 pending a complete review of the rule by the D.C. Circuit Court of Appeals. In November 2024, the EPA issued an interim final rule indicating it plans to provide NOx allocations and budgets from the previously applicable and less restrictive Revised CSAPR Update rule until the Good Neighbor Plan matter is resolved. In February 2025, the D.C. Circuit Court of Appeals denied the EPA’s motion requesting the Good Neighbor Plan litigation be held in abeyance for 60 days and ordered the parties to complete supplemental briefing in March 2025. As a result, future implementation and enforcement of the Good Neighbor Plan remains uncertain at this time. EPA MATS Rule. In May 2024, the EPA published a rule that requires coal-fired generation facilities to reduce particulate matter emissions by the middle of 2027 (or 2028, if an extension is approved). Colstrip is not expected to meet the new particulate matter standard without substantial upgrades to its control equipment. As a result, Talen Montana and the other Colstrip co-owners face the decision either to invest in new cost-prohibitive control equipment or retire the Colstrip facility. Such decision must be evaluated in conjunction with compliance requirements under the May 2024 EPA GHG Rule due to timing and costs. Challenges to the EPA MATS Rule have been filed in the D.C. Circuit Court of Appeals, including by Talen and 23 states. After motions to stay the EPA MATS Rule during the pendency of the litigation were denied by the D.C. Circuit Court of Appeals, Talen and other parties filed emergency stay request applications with the U.S. Supreme Court in September 2024, which were denied in October 2024. The appeal on the merits of the new rule remains pending in the D.C. Circuit Court of Appeals. In February 2025, the D.C. Circuit Court of Appeals granted the EPA’s unopposed motion to hold the MATS litigation in abeyance for 90 days. No assurance can be provided as to when the challenges to the EPA MATS Rule will be resolved or whether such challenges will be resolved in the Company’s favor. As the timeline for compliance with the new standards is accelerated and must be considered in tandem with the new EPA GHG Rule, which is also subject to ongoing legal challenges, it is possible the Company will need to make operating decisions about the future of Colstrip before the Company has clarity about the outcome of the litigation. EPA GHG Rule. In May 2024, the EPA published a rule that establishes carbon dioxide limits for new electric generating units (“EGUs”) and GHG guidelines for certain existing EGUs. Under the guidelines, if existing coal-fired EGUs operate beyond 2031, GHG reductions, such as those achieved by the addition of carbon capture and sequestration (“CCS”), are required to be implemented by the end of 2031. Colstrip is not expected to meet the new rules without substantial technology upgrades and pipeline infrastructure build-out. As a result, Talen Montana and the other Colstrip co-owners face the decision either to invest in new cost-prohibitive controls (e.g., CCS technology) or retire the Colstrip facility by the end of 2031. Such decision must be evaluated in conjunction with compliance requirements under the May 2024 EPA MATS Rule. Petitions have been filed in the D.C. Circuit Court of Appeals, including by coalitions representing 27 states and an ad hoc coalition of power producers of which Talen is a member, requesting a review of the EPA GHG Rule. Stay motions were denied by the D.C. Circuit Court of Appeals in July 2024 and the U.S. Supreme Court in October 2024. Appeals of the EPA GHG Rule remain pending in the D.C. Circuit Court of Appeals. In February 2025, the D.C. Circuit Court of Appeals granted the EPA’s unopposed motion to hold the litigation in abeyance for 60 days. No assurance can be provided as to when the challenges to the EPA GHG Rule will be resolved or whether such challenges will be resolved in the Company’s favor. The EPA has also stated its intent to develop GHG regulations for existing natural gas combustion turbines; however, no rule has been proposed. As the timeline for compliance with the new standards is accelerated and must be considered in tandem with the new EPA MATS Rule, which is also subject to ongoing legal challenges, it is possible the Company will need to make operating decisions about the future of Colstrip before the Company has clarity about the outcome of the litigation. 88 Item 8. Table of Contents Pennsylvania RGGI. In October 2019, the then-Governor of Pennsylvania signed an Executive Order directing the Pennsylvania Department of Environmental Protection (the “PDEP”) to draft regulations establishing a cap-and-trade program with the intent of enabling Pennsylvania to join the RGGI, a multi-state regional cap-and-trade program comprised of several Eastern U.S. states. In April 2022, Pennsylvania entered the RGGI program, with compliance set to begin on July 1, 2022. However, in November 2023, the Commonwealth Court of Pennsylvania ruled RGGI was an invalid tax and voided the rulemaking. The PDEP appealed this decision to the Pennsylvania Supreme Court and filed notice with the court that the RGGI program would not be implemented while the appeal is pending. In July 2024, the Pennsylvania Supreme Court permitted certain non-profit environmental groups to intervene in the litigation. EPA ELG Rule. In November 2015, the EPA revised the effluent limitation guidelines for certain power generation facilities, which imposed more stringent standards for wastewater streams as facility discharge permits are renewed. In 2020, the EPA issued changes that would exempt coal generation facility operators from meeting certain wastewater standards if the facility would commit to cease coal-fired generation by the end of 2028, which Talen elected for its wholly owned coal operations. In May 2024, the EPA published revisions to the EPA ELG Rule, which imposed additional requirements for legacy wastewater and combustion residual leachate. Such EPA ELG Rule revisions impact Talen’s active generation facilities that have both CCR units and hold National Pollutant Discharge Elimination System (“NPDES”) discharge permits. These sites include Brandon Shores, Brunner Island, Montour, and potentially Martins Creek. Talen is evaluating what: (i) potential discharge limits may apply; (ii) treatment may be required; and (iii) the implementation timeline may be. Obligations for installing any new wastewater treatment equipment, if necessary, will not be known until each applicable state where the active generation facilities operate makes their own determination with respect to NPDES permit renewals with new limits and associated timing. As a result of the future permit conditions, additional capital expenditures and (or) AROs may be required, which may have a material impact on our results of operations and (or) financial condition. Multiple challenges, including stay requests, to the EPA ELG Rule have been filed in various U.S. Courts of Appeal by parties that include 15 states, environmental groups, and industry groups, including the Utility Water Act Group, of which Talen is a member. The appeals have been consolidated in the U.S. Court of Appeals for the Eighth Circuit, and in October 2024, stay requests were denie d. In February 2025, the EPA filed a motion in the U.S. Court of Appeals for the Eight Circuit re questing that the litigation be held in abeyance for a period of 60 days with a motion to govern due at the end of that period. No assurance can be provided as to when the challenges to the EPA ELG Rule merits will be resolved or whether such challenges will be resolved in the Company’s favor. EPA CCR Rule. In April 2015, the EPA established regulations under the Resource Conservation and Recovery Act (“RCRA”) to identify CCRs as nonhazardous solid waste and provided CCR management and siting requirements. The 2015 rule was modified in 2020 after a 2018 D.C. Circuit Court of Appeals ruling found that, among other things, the EPA did not adequately regulate unlined impoundments. In its 2020 rulemaking, the EPA specified procedures for owners to extend the operating timeline of certain unlined impoundments. Talen submitted an extension request under this process for an unlined impoundment at Montour, which was withdrawn in December 2024, following the end of basin operations and the initiation of basin closure. The 2018 D.C. Circuit Court of Appeals ruling also found that the EPA did not properly address legacy surface impoundments in the 2015 CCR rule. As a result of the finding, in May 2024, the EPA finalized additional federal CCR regulations effective in November 2024, which provided new requirements for legacy CCR surface impoundments and new requirements for other CCR disposal and management areas at active power plants (“CCR Management Units” or “CCRMUs”). This rule has been challenged in the D.C. Circuit Court of Appeals by multiple parties, including two industry groups of which Talen is a member. In December 2024, the U.S. Supreme Court denied a requested stay of the legacy EPA CCR Rule. In February 2025, the D.C Circuit Court of Appeals granted EPA’s unopposed motion to hold the litigation in abeyance for 120 days. Additionally, the EPA is being challenged by other industry parties on new regulatory interpretations that could be consequential to CCR unit closure practices and costs. No assurance can be provided at this time as to when the legal challenges to the EPA CCR Rule and interpretations will be resolved or whether such challenges will be decided in the Company’s favor. Talen continues to review the new EPA CCR Rule provisions that went into effect in 2024, perform the required applicability assessments, and await additional information and guidance from the EPA concerning the rule’s requirements. Pursuant to the regulations, initial facility evaluation reports to identify CCR areas which may become regulated and subject to the rule’s requirements are due in February 2026. Following that, site investigation may be required to further investigate applicability, and a subsequent facility report is due in February 2027. The Company has initiated reviews under the facility evaluation report requirements at locations with ash impoundments that have long since ceased coal operations as well as at locations with current coal operations. No assurance can be provided as to whether any specific ash impoundments owned by the Company may or may not be within scope of the updated EPA CCR Rule until the Company completes its assessments within the regulatory timeframe. As of December 31, 2024 (Successor), the Company has recognized required cost estimates in order to comply with the EPA CCR Rule’s initial compliance requirements and deadlines, including the initial groundwater monitoring requirements. The Company does not yet have sufficient information available to estimate costs for the future compliance obligations under the rule. As the Company continues its applicability evaluations and site assessments to determine the scope of work on its properties imposed by the new rule, additional new AROs and (or) revisions could be required. It is expected estimates will be available, under the timeline provided for by the regulations, as described above, at the completion of the initial facility evaluation reports or at the completion of a subsequent site investigation. Such AROs or ARO changes could be material and, as a result, may have a material impact on our results of operations and (or) financial condition. 89 Item 8. Table of Contents Certain Resolved Matters Pension Litigation. In July 2024, a U.S. District Court in Pennsylvania approved the settlement of a class action lawsuit brought by former Talen employees alleging they were owed enhanced benefits under the TERP. Pursuant to the settlement, Talen agreed to pay: (i) $ 6 million for settlement administrative costs and plaintiff attorneys fees, which were partially offset by insurance recoveries; and (ii) $ 14 million to class members from the TERP. Both payment obligations were substantially completed during the year ended December 31, 2024 (Successor). PPL/Talen Montana Litigation. In December 2023, a settlement was reached in (i) a 2018 class action lawsuit filed by the Talen Montana Retirement Plan against PPL and its affiliates claiming that an improper $ 733 million distribution to PPL left Talen Montana insolvent; and (ii) a related 2018 lawsuit filed by PPL against Talen and affiliates seeking various substantive and procedural relief in the first case. Under the terms of the settlement, PPL paid Talen Montana $ 115 million in exchange for a full release of claims, with $ 11 million of that amount remitted to the general unsecured creditors trust established under the Plan of Reorganization. As a result, a $ 104 million net gain is presented as “Other non-operating income (expense), net” on the Consolidated Statements of Operations for the year ended December 31, 2023 (Successor) . Winter Storm Elliott . During December 2022, as a result of Winter Storm Elliott, PJM experienced conditions that resulted in PJM declaring a Capacity Performance event. In April 202 3, we and certain other market participants filed FERC complaints against PJM disputing a portion of the penalties charged by PJM to generators (including us) for failing to meet PJM’s Capacity Performance requirements. In December 2023, FERC approved a market-wide settlement resolving all Winter Storm Elliot complaints, including ours, which reduced our net aggregate penalties to an estimated $ 28 million. Utilizing the best available information of PJM’s assessments: (i) an initial penalty of $ 33 million was recognized for the year ended December 31, 2022 (Predecessor) ; (ii) an increase of $ 13 million for the period from January 1 through May 17, 2023 (Predecessor) ; and (iii) an increase of $ 2 million for the period from May 18 through December 31, 2023 (Successor) . At the time of FERC’s approval, aggregate net penalty payments of $ 29 million had been remitted to PJM. Accordingly, in December 2023 as a result of FERC’s approval, the remaining $ 19 million estimated liability was derecognized. Guarantees and Other Assurances In the normal course of business, the Company enters into agreements to provide financial performance assurance to third parties on behalf of certain subsidiaries. These agreements primarily support or enhance the stand-alone creditworthiness attributed to a subsidiary or facilitate the commercial activities in which these subsidiaries engage. Such agreements may include guarantees, stand-by LCs, and (or) surety bonds. Additionally, they may include customary indemnifications to third parties related to asset sales and other transactions. The probability of expected material payment and (or) performance for these assurance agreements is believed to be remote. Surety Bonds. Surety bonds provide financial performance assurance to third parties on behalf of certain Company subsidiaries for obligations including but not limited to environmental obligations and AROs. In the event of nonperformance by the applicable subsidiary, the beneficiary would make a claim to the surety, and the Company would be required to reimburse any payment by the surety. Talen’s liability with respect to any particular surety bond is released once the obligations secured by the surety bond are performed. Surety bond providers generally have the right to request additional collateral or request that such bonds be replaced by alternate surety providers. As of December 31, 2024 (Successor) and December 31, 2023 (Successor), the aggregate amount of surety bonds outstanding was $ 234 million and $ 240 million, respectively, including surety bonds posted on behalf of Talen Montana as discussed below. Talen Montana Financial Assurance. Pursuant to the Colstrip Administrative Order on Consent (the “Colstrip AOC”), Talen Montana, in its capacity as the Colstrip operator, is obligated to close and remediate coal ash disposal impoundments at Colstrip. The Colstrip AOC specifies an evaluation process between Talen Montana and the MDEQ on the scope of remediation and closure activities, requires the MDEQ to approve such scope, and requires financial assurance to be provided to the MDEQ on approved plans. Each of the co-owners of Colstrip has provided its proportionate share of financial assurance to the MDEQ for estimates of coal ash disposal impoundments remediation and closure activities approved by the MDEQ. The aggregate amount of surety bonds posted to the MDEQ on behalf of Talen Montana’s proportionate share of such activities wa s $ 125 million and $ 115 million as of December 31, 2024 (Successor) and December 31, 2023 (Successor), respectively. Talen Montana’s surety bond requirements may increase due to scope changes, cost revisions, and (or) other factors when the MDEQ conducts annual reviews of approved remediation and closure plans as required under the Colstrip AOC. The surety bond requirements are expected to decrease as Colstrip’s coal ash impoundments remediation and closure activities are completed. See Note 11 for additional information on Colstrip AROs. Other Commitments and Contingencies Nuclear Insurance. The Price-Anderson Act is a federal law that governs liability-related issues and ensures the availability of funds for public liability claims arising from a nuclear incident at any U.S. licensed nuclear facility. It also seeks to limit the liability of nuclear reactor owners for such claims from any single incident. As of December 31, 2024 (Successor), the liability limit per incident is $ 16.3 billion for such claims, which is funded by insurance coverage from American Nuclear Insurers ($ 500 million in coverage), with the remainder covered by an industry retrospective assessment program. 90 Item 8. Table of Contents As of December 31, 2024 (Successor), under the industry retrospective assessment program, in the event of a nuclear incident at any of the reactors covered by the Price-Anderson Act, Susquehanna could be assessed deferred premiums of up to $ 332 million per incident, payable at a maximum of $ 49 million per year. Additionally, Susquehanna purchases property insurance programs from Nuclear Electric Insurance Limited (“NEIL”), an industry mutual insurance company of which Susquehanna is a member. As of December 31, 2024 (Successor), facilities at Susquehanna are insured against nuclear property damage losses up to $ 2 billion and non-nuclear property damage losses up to $ 1 billion. Susquehanna also purchases an insurance program that provides coverage for the cost of replacement power during prolonged outages of nuclear units caused by certain specified conditions. Under the NEIL property and replacement power insurance programs, Susquehanna could be assessed retrospective premiums in the event of the insurers’ adverse loss experience. The maximum assessment for this premium is $ 48 million as of December 31, 2024 (Successor). Talen has additional coverage that, under certain conditions, may reduce this exposure. Talen Montana Fuel Supply. Talen Montana purchases coal from a mine owned by Westmoreland Rosebud Mining, LLC (the “Rosebud Mine”) for its interest in Colstrip Units 3 and 4 under a full requirements contract with the mine operator. Two lawsuits have been brought against the Rosebud Mine challenging permits issued to it by the State of Montana. Talen Montana is not party to either lawsuit, but is monitoring the progress of each to assess the impact to its operations. In the first lawsuit, the Montana Supreme Court affirmed a lower court’s ruling to vacate a mining permit and require the Montana Board of Environmental Review to perform an additional review of the permit. In the second lawsuit, the Montana Federal District Court ordered a branch of the U.S. Department of the Interior to complete an updated Environmental Impact Statement (“EIS”). In December 2024, the Montana Federal District Court granted an extension to the EIS completion date to October 7, 2025. At this time, Talen cannot predict the effect that an adverse outcome of these lawsuits to Rosebud Mine would have on: (i) Talen Montana’s ability to source fuel for its share of Colstrip operations; or (ii) Talen Montana’s operations, results of operations, or liquidity. 13. Long-term Debt and Other Credit Facilities TES is the borrower/issuer under all the Company’s debt and credit facilities. As of December 31, 2024 (Successor), TES was not in default under any of its debt or credit agreements. Long-Term Debt Successor Interest Rate (a) December 31, 2024 December 31, 2023 TLB-1 7.02 % $ 857 $ 866 TLB-2 7.02 % 850 — TLC (b) N/A — 470 Secured Notes 8.63 % 1,200 1,200 PEDFA 2009B Bonds 5.25 % 50 50 PEDFA 2009C Bonds 5.25 % 81 81 Cumulus Digital TLF (b) N/A — 182 Total principal 3,038 2,849 Unamortized deferred financing costs and original issuance discounts ( 34 ) ( 29 ) Total carrying value 3,004 2,820 Less: long-term debt, due within one year 17 9 Long-term debt $ 2,987 $ 2,811 __________________ (a) Computed interest rate as of December 31, 2024 (Successor). (b) See “Recent Transactions” below for additional information on extinguishments of indebtedness. Long-term debt maturities as of December 31, 2024 (Successor) were: 2025 2026 2027 2028 2029 Thereafter Total Principal debt maturities $ 17 $ 17 $ 17 $ 17 $ 17 $ 2,952 $ 3,038 91 Item 8. Table of Contents Revolving Credit and Other Facilities Successor December 31, 2024 Maturity Committed Capacity (a) Direct Cash Borrowings LCs Issued Unused Capacity RCF December 2029 $ 700 $ — $ — $ 700 LCF December 2026 900 — 374 526 Total $ 1,600 $ — $ 374 $ 1,226 __________________ (a) RCF committed capacity can be used for direct cash borrowings and (or) LCs. In December 2024, the TLC LCF and Bilateral LCF were terminated. However, as certain LCs remained outstanding under these facilities pending their transition to the LCF, corresponding backstop LCs were issued under the LCF. As of December 31, 2024 (Successor), the amount of such backstop LCs issued under the LCF were $ 297 million. As of December 31, 2023 (Successor): (i) the aggregate LCs issued under the TLC LCF and Bilateral LCF were $ 478 million; and (ii) LCs issued under TLC LCF were collateralized by $ 472 million of cash presented as “Restricted cash and cash equivalents” on the Consolidated Balance Sheets. The restricted cash was released in connection with the TLC LCF termination. See “Recent Transactions–Credit Facilities” below for additional information on LC facility terminations. Long-Term Debt, Revolving Credit, and Other Facilities Certain key terms of our indebtedness include: Secured Notes TLB-1 TLB-2 RCF LCF PEDFA Bonds Maturity: June 2030 May 2030 December 2031 December 2029 December 2026 2009B: December 2038 2009C: December 2037 Index: None Term SOFR Term SOFR Term SOFR None None Rate, Applicable Margin, and Amortization: 8.625 % per annum fixed rate No applicable margin No amortization 2.50 % per annum applicable margin; leverage-based step-downs to 2.25 % and 2.00 % Amortization 1.00 % per annum; paid quarterly Same as TLB-1 Cash borrowings: 2.00 % per annum applicable margin; leverage-based step-downs to 1.75 % and 1.50 % LCs: LC fee equal to applicable margin above + fronting fee of 0.125 % Unused commitments: 0.375 %; leverage-based step-down to 0.25 % No amortization LCs: Same as RCF Unused commitments: Same as RCF 5.25 % per annum fixed rate No applicable margin No amortization Prepayment Penalty: Prior to June 1, 2026: Redeemable at par plus a customary “make-whole” premium. 40 % redeemable from the proceeds of certain equity offerings at 108.625 %. 10 % redeemable at 103 % from June 1, 2025 – May 31, 2026 On or after June 1 of the following years: 2026: 104.313 %; 2027: 102.156 %; 2028 and after: 100 % 1.00 % to the extent prepaid prior to June 20, 2025 in connection with a repricing transaction 1.00 % to the extent prepaid prior to June 13, 2025 in connection with a repricing transaction None None Prior to June 1, 2026: Par plus a customary “make-whole” premium On or after June 1, 2026: Par Credit Agreement . The Credit Agreement governs the RCF, TLB-1, TLB-2, and LCF. The Credit Agreement contains customary negative covenants including but not limited to limitations on incurrence of liens and additional indebtedness, making investments, payment of dividends, and asset sales. The Credit Agreement also contains customary affirmative covenants. Solely with respect to the RCF and LCF, and solely during a compliance period (i.e., when RCF cash borrowings exceed 50 % of revolving commitments), the Credit Agreement requires TES’s consolidated first lien net leverage ratio not to exceed 4.25 x. This financial covenant does not apply to the TLB-1 or TLB-2. The Credit Agreement also contains customary representations and warranties, events of default, and remedies (including acceleration of amounts due and (or) termination of commitments). 92 Item 8. Table of Contents Secured Notes. Interest on the Secured Notes is payable semi-annually on June 1 and December 1 of each year and at maturity. The Secured Notes are subject to customary negative covenants, including but not limited to certain limitations on incurrence of liens and additional indebtedness, making investments, payment of dividends, and transactions involving the Susquehanna assets, but do not contain any financial covenants. The Secured Notes also contain customary affirmative covenants, events of default, and remedies (including acceleration). PEDFA Bonds. The PEDFA 2009B and 2009C Bonds were issued by the PEDFA on behalf of TES, and TES then received the proceeds under corresponding back-to-back exempt facilities loan agreements with the PEDFA. Corresponding TES unsecured promissory notes for each series contain the applicable principal, interest, and prepayment provisions. The PEDFA Bonds bear interest at a fixed rate until the end of the current term rate period on June 1, 2027, at which time they are subject to mandatory remarketing during which TES may elect a different interest rate mode. Aside from principal amount and final maturity, the terms of the PEDFA 2009B Bonds and 2009C Bonds are substantially identical. The PEDFA Bonds are subject to customary affirmative and negative covenants appropriate for such tax-exempt facilities, including but not limited to limitations on incurrence of liens (but not unsecured indebtedness), and asset sales. The PEDFA Bonds are also subject customary events of default and remedies (including acceleration). Secured ISDAs. Talen Energy Marketing is party to certain Secured ISDAs, under which TES and the Subsidiary Guarantors provide the applicable counterparties with a first priority lien on and security interest (which ranks pari passu with the liens securing the Credit Facilities and the Secured Notes) in certain assets in lieu of posting collateral in the form of cash equivalents or LCs. The secured obligations under the Secured ISDAs were $ 17 million as of December 31, 2024 (Successor). Security Interests, Guarantees, and Cross-Defaults Secured Obligations. The obligations under the Credit Facilities, Secured Notes, and Secured ISDAs are secured by a first-priority lien on and security interest in substantially all of the assets of TES and the Subsidiary Guarantors. The Subsidiary Guarantors guarantee TES’s obligations under the Credit Facilities and the Secured Notes. TES and the Subsidiary Guarantors guarantee Talen Energy Marketing’s obligations under the Secured ISDAs. The amount for which TES and the Subsidiary Guarantors may be liable is equal to the amount of obligations outstanding under such agreements and may also include unpaid interest, premiums, penalties, and (or) other fees and expenses. An event of default under the Credit Facilities, Secured Notes, or Secured ISDAs, if not cured or waived, may result in a cross acceleration of amounts due and (or) cross termination across all these agreements. Unsecured Obligations. The PEDFA Bonds are senior unsecured obligations of TES that are effectively subordinated to TES’s secured obligations, including the Credit Facilities, Secured Notes, and Secured ISDAs, to the extent of the value of the assets securing those obligations. Certain of the Subsidiary Guarantors also guarantee TES’s obligations under the PEDFA Bonds. These guarantees are the general unsecured obligations of such Subsidiary Guarantors, rank equally with all of their other senior unsecured indebtedness, and are effectively subordinated to their secured obligations, including guarantees under the Credit Facilities, Secured Notes, and Secured ISDAs, to the extent of the value of the assets securing those obligations. Recent Transactions Secured Notes. In January 2025, the indenture governing the Secured Notes was amended to, among other things: (i) modify certain provisions, including certain covenants and related definitions, in order to substantially conform to the corresponding amendments to the Credit Agreement obtained in the December 2024 transactions discussed below; and (ii) waive TES’s right to optionally redeem up to 10 % of the Secured Notes at a price of 103 % of par prior to June 1, 2025. Credit Facilities. In December 2024, TES completed several refinancing transactions: • TLB-2: Issued a new $ 850 million TLB-2, the proceeds of which were used, together with cash on hand, to repurchase shares of our outstanding common stock from Rubric. See Note 18 for additional information on repurchases of common stock. • TLB-1: Repriced the existing $ 857 million TLB-1 to reduce the current interest rate margin by 100 basis points (to SOFR plus 250 basis points, with further leverage-based step downs available) to align pricing with the new TLB-2. • RCF: Repriced the existing $ 700 million RCF to reduce the current interest rate margin by 100 basis points (to SOFR plus 200 basis points, with further leverage-based step downs available), increased revolving LC capacity from $ 475 million to $ 700 million, and extended the maturity from May 2028 to December 2029. • LCF: Issued a new $ 900 million standalone secured LCF to transition LCs from the TLC LCF and Bilateral LCF. LCs issued under the LCF are subject to an LC fee of 2.00 % per annum (with leverage-based step downs available) plus a fronting fee of 0.125 % per annum. • TLC/TLC LCF: Repaid in full the $ 470 million TLC utilizing the restricted cash collateralizing the TLC LCF, and terminated the TLC and associated $ 470 million TLC LCF. 93 Item 8. Table of Contents • Bilateral LCF: Terminated the $ 75 million Bilateral LCF. In connection with these transactions, the requisite lenders under the Credit Agreement also consented to certain amendments, among other things, increasing the Company’s flexibility for restricted payments, investments, and dispositions under the Credit Facilities. As a result of these transactions, the Company derecognized the carrying value of the extinguished TLC and presents the carrying value of the newly issued TLB-2 on the Consolidated Balance Sheet. In May 2024, TES repriced the TLB-1 and TLC, and the lenders, as part of these debt modifications, agreed to waive mandatory prepayment obligations related to the ERCOT Sale. See Note 20 for additional information on the ERCOT Sale. Additionally, the lenders under the TLB-1, TLC, and RCF consented to certain other covenant improvements. PEDFA Bonds. In June 2024, TES completed the remarketing of its outstanding $ 50 million in PEDFA 2009B Bonds and $ 81 million in PEDFA 2009C Bonds. As part of the remarketing, (i) the PEDFA Bonds were transitioned from a variable daily interest rate to a fixed term rate of 5.25 % until June 1, 2027, at which time they are subject to mandatory remarketing during which TES may elect a different interest rate mode; (ii) $ 133 million of TES LCs that had previously supported the PEDFA Bonds were terminated; (iii) mandatory repurchase and optional redemption provisions were modified; and (iv) certain covenants relating to changes of control, incurrence of liens, and asset sales were amended and became operative. The remarketing transaction is excluded from the Consolidated Statements of Cash Flows as a non-cash item. Cumulus Digital TLF Repayment. In connection with the AWS Data Campus Sale, the Cumulus Digital TLF was paid in full in March 2024, together with all accrued interest and other outstanding amounts, and related liens, guarantees, and LCs were released and terminated. See Note 20 for additional information on the AWS Data Campus Sale. 14. Fair Value Recurring Fair Value Measurements Financial assets and liabilities reported at fair value on a recurring basis primarily include energy commodity derivatives, interest rate derivatives, and investments held within the NDT. The classifications of recurring fair value measurements within the fair value hierarchy were: Successor December 31, 2024 December 31, 2023 Level 1 Level 2 NAV Netting (a) Total Level 1 Level 2 NAV Netting (a) Total Assets Cash equivalents $ — $ — $ 3 $ — $ 3 $ — $ — $ 9 $ — $ 9 Equity securities (b) 758 — 347 — 1,105 629 — 384 — 1,013 U.S. Government debt securities 353 — — — 353 337 — — — 337 Municipal debt securities — 85 — — 85 — 86 — — 86 Corporate debt securities — 173 — — 173 — 156 — — 156 Receivables (payables), net (c) — — — — 5 — — — — ( 26 ) NDT funds 1,111 258 350 — 1,724 966 242 393 — 1,575 Commodity derivatives 134 91 — ( 156 ) 69 98 196 — ( 200 ) 94 Interest rate derivatives — 2 — — 2 — 1 — — 1 Total assets $ 1,245 $ 351 $ 350 $ ( 156 ) $ 1,795 $ 1,064 $ 439 $ 393 $ ( 200 ) $ 1,670 Liabilities Commodity derivatives $ 145 $ 29 $ — $ ( 167 ) $ 7 $ 155 $ 139 $ — $ ( 257 ) $ 37 Interest rate derivatives — — — — — — 6 — — 6 Total liabilities $ 145 $ 29 $ — $ ( 167 ) $ 7 $ 155 $ 145 $ — $ ( 257 ) $ 43 __________________ (a) Amounts represent netting pursuant to master netting arrangements and cash collateral held or placed with the same counterparty. (b) Includes commingled equity and fixed income funds and real estate investment trusts. (c) Represents: (i) interest and dividends earned but not received; and (ii) net sold or purchased investments, but not settled. There were no recurring fair value measurements classified as Level 3 as of December 31, 2024 (Successor) and December 31, 2023 (Successor). 94 Item 8. Table of Contents Nonrecurring Fair Value Measurements There were no nonrecurring fair value measurements related to impairments of long-lived assets during the year ended December 31, 2024 (Successor) and for the period from May 18 through December 31, 2023 (Successor). See Note 4 for information on the nonrecurring fair value measurements resulting in the application of fresh start accounting and Note 10 for information on the nonrecurring fair value measurement of Brandon Shores during the period from January 1 through May 17, 2023 (Predecessor). Reported Fair Value The carrying value of certain financial assets and liabilities on the Consolidated Balance Sheets, including “Cash and cash equivalents , ” “Restricted cash and cash equivalents , ” “Accounts receivable , ” and “Accounts payable and other accrued liabilities” approximate fair value. The fair value measurements of indebtedness are classified as Level 2 within the fair value hierarchy. The fair value of fixed rate debt was estimated primarily by utilizing an income approach whereby the future cash flows of the obligations are discounted at the estimated current cost of funding rates, which incorporates the credit risk associated with the obligations. The carrying value of variable rate indebtedness approximates fair value. The carrying value and fair value of indebtedness presented on the Consolidated Balance Sheets were: Successor December 31, 2024 December 31, 2023 Carrying Value Fair Value Carrying Value Fair Value Long-term debt (a) $ 3,004 $ 3,120 $ 2,820 $ 2,934 Other short-term indebtedness (b) — — 6 6 __________________ (a) Aggregate value of “Long-term debt” and “Long-term debt, due within one year” presented on the Consolidated Balance Sheets. (b) Presented as “Other current liabilities” on the Consolidated Balance Sheets. 15. Postretirement Benefit Obligations TES and certain subsidiaries sponsor postemployment benefits which include defined benefit pension plans, health and welfare postretirement plans (other postretirement benefit plans), and a defined contribution plan. Pension and Other Postretirement Defined Benefit Plans Obligations under the defined benefit pension and other postretirement plans are generally based on factors, among others, such as age of the participants, years of service, and compensation. The pension and other postretirement plans are closed to new participants. Effective December 31, 2018, all participants ceased accruing additional benefits in the TERP, the Company’s largest defined benefit pension plan. Funded Status. The net fair value of underfunded defined benefit pension and other postretirement plans are presented as “Postretirement benefit obligations” on the Consolidated Balance Sheets. Certain other postretirement plans were overfunded by $ 36 million and $ 33 million as of December 31, 2024 (Successor) and 2023 (Successor), respectively, and are presented as “Other noncurrent assets” on the Consolidated Balance Sheets. The current portion of certain unfunded postretirement obligations were non-material. 95 Item 8. Table of Contents The aggregate funded status and the weighted average assumptions for the periods were: Pension Benefits Successor Predecessor Year Ended December 31, 2024 May 18 through December 31, 2023 January 1 through May 17, 2023 Change in benefit obligation Benefit obligation beginning balance $ 1,308 $ 1,300 $ 1,273 Service cost 2 2 1 Interest cost 63 40 25 Actuarial (gain) loss ( 81 ) 20 6 Actual benefits paid ( 105 ) ( 55 ) ( 34 ) Resolved litigation settlement and other charges 15 1 — Benefit obligation ending balance $ 1,202 $ 1,308 $ 1,271 Change in plan assets Plan assets fair value beginning balance 975 997 994 Actual return on plan assets ( 13 ) 24 35 Employer contributions 54 9 2 Actual benefits paid ( 105 ) ( 55 ) ( 34 ) Plan assets fair value ending balance $ 911 $ 975 $ 997 Funded status $ ( 291 ) $ ( 333 ) $ ( 274 ) Accumulated benefit obligation $ 1,202 $ 1,308 $ 1,271 Aggregate amounts of underfunded plans Benefit obligation/Accumulated benefit obligation 1,202 1,308 1,271 Fair value of plan assets 911 975 997 Amounts recognized in accumulated other comprehensive income Net (gain) loss 34 37 238 Total accumulated other comprehensive income $ 34 $ 37 $ 238 Assumptions Discount rate 5.65 % 5.00 % 5.37 % Interest crediting rate 6.00 % 6.00 % 6.00 % Rate of compensation increase 3.45 % 3.45 % 3.45 % 96 Item 8. Table of Contents Other Postretirement Benefits Successor Predecessor Year Ended December 31, 2024 May 18 through December 31, 2023 January 1 through May 17, 2023 Change in benefit obligation Benefit obligation beginning balance $ 79 $ 78 $ 77 Service cost 1 1 — Interest cost 3 2 1 Plan amendments ( 21 ) — — Actuarial (gain) loss ( 3 ) 1 1 Plan participant contributions 2 2 1 Actual benefits paid ( 9 ) ( 5 ) ( 4 ) Benefit obligation ending balance $ 52 $ 79 $ 76 Change in plan assets Plan assets fair value beginning balance 75 74 75 Actual return on plan assets 3 4 2 Plan participant contributions 2 2 1 Actual benefits paid ( 9 ) ( 5 ) ( 4 ) Plan assets fair value ending balance $ 71 $ 75 $ 74 Funded status $ 19 $ ( 4 ) $ ( 2 ) Aggregate amounts of underfunded plans Benefit obligation / Accumulated benefit obligation $ 52 $ 78 $ 76 Fair value of plan assets 71 75 74 Amounts recognized in accumulated other comprehensive income Net (gain) loss ( 2 ) ( 1 ) 4 Prior service cost (credit) ( 20 ) — ( 4 ) Total accumulated other comprehensive income $ ( 22 ) $ ( 1 ) $ — Assumptions Discount rate 5.63 % 5.01 % 5.36 % Rate of compensation increase 2.31 % 2.31 % 2.31 % During the year ended December 31, 2024 (Successor), the decrease in postretirement benefit obligations was primarily attributable to increasing interest rates, offset by actual returns being less than expected returns on plan assets. In March 2024, $ 10 million of excess assets from the PA Mines United Mine Workers of America (“UMWA”) Plan VEBA were transferred to a separate VEBA, which provides benefits for participants in Talen’s health and welfare “wrap plan.” As such assets were not presented on the Consolidated Balance Sheets prior to the transfer of the assets from the VEBA, a transfer gain of $ 10 million was recognized for the year ended December 31, 2024 (Successor) and presented as “Other non-operating income (expense), net” on the Consolidated Statements of Operations. Net Periodic Benefit Cost and Amounts Recognized in OCI. Service cost is presented as “Postretirement benefits service (credit) costs, net,” while the other components of net periodic defined benefit cost (credit) for pension and other postretirement plans are presented as “Operation, maintenance and development” on the Consolidated Statements of Operations. The portion of net periodic benefit cost capitalized during the year ended December 31, 2024 (Successor) and during the periods from May 18 through December 31, 2023 (Successor), and during the periods from January 1 through May 17, 2023 (Predecessor) was not material. 97 Item 8. Table of Contents The components of net periodic benefit cost (credit), the amounts recognized in OCI and the associated weighted average assumptions for pension and other postretirement plans for the periods were: Pension Benefits Successor Predecessor Year Ended December 31, 2024 May 18 through December 31, 2023 January 1 through May 17, 2023 Year Ended December 31, 2022 Net periodic benefit costs (credits): Service cost $ 2 $ 2 $ 1 $ 4 Interest cost 63 40 25 50 Expected return on plan assets ( 66 ) ( 41 ) ( 30 ) ( 68 ) Amortization of net (gain) loss — — 2 27 Resolved litigation settlement and other charges 15 1 — — Net periodic defined benefit cost (credit) 14 2 ( 2 ) 13 Net actuarial (gain) loss ( 3 ) 38 2 19 Reclassifications due to settlement and (or) curtailment: Amortization of net (gain) loss — — — ( 27 ) Total recognized in OCI $ ( 3 ) $ 38 $ 2 $ ( 8 ) Total recognized in net periodic costs and OCI $ 11 $ 40 $ — $ 5 Assumptions Discount rate 5.00 % 5.12 % 5.41 % 2.97 % Rate of compensation increase 3.45 % 3.45 % 3.45 % 3.45 % Expected return on plan assets 7.25 % 7.25 % 7.50 % 5.75 % Other Postretirement Benefits Successor Predecessor Year Ended December 31, 2024 May 18 through December 31, 2023 January 1 through May 17, 2023 Year Ended December 31, 2022 Net periodic benefit costs (credits): Service cost $ 1 $ 1 $ 1 $ 1 Interest cost 3 2 1 3 Expected return on plan assets ( 4 ) ( 2 ) ( 2 ) ( 4 ) Amortization of prior service cost (credit) ( 1 ) — — ( 1 ) Net periodic defined benefit cost (credit) ( 1 ) 1 — ( 1 ) Net actuarial (gain) loss ( 2 ) ( 1 ) — ( 3 ) Prior service credit ( 21 ) — — — Reclassifications due to settlement and (or) curtailment: Amortization of prior service cost (credit) 1 — — 1 Amortization of net (gain) loss — — — ( 1 ) Total recognized in OCI $ ( 22 ) $ ( 1 ) $ — $ ( 3 ) Total recognized in net periodic costs and OCI $ ( 23 ) $ — $ — $ ( 4 ) Assumptions Discount rate 5.01 % 5.13 % 5.41 % 2.94 % Rate of compensation increase 2.31 % 2.31 % 2.31 % 2.31 % Expected return on plan assets 5.49 % 5.49 % 5.74 % 3.89 % Health care grading trend rates (a) 7.10 % to 4.40 % 6.50 % to 4.50 % 6.50 % to 4.50 % 4.50 % __________________ (a) Trend rates grading to 2027. In September 2024, the Company approved a plan amendment for certain other postretirement benefit plans, resulting in the recognition of prior service credits of $ 21 million and presented as “Postretirement benefit prior service (credits) costs, net” on the Consolidated Statements of Comprehensive Income (Loss). See Note 12 for additional information on recently resolved litigation regarding certain of our defined benefit pension obligations. 98 Item 8. Table of Contents The expected long-term rates of return for pension and other postretirement plans are based on management's projections using a best-estimate of expected returns, volatilities, and correlations for each asset class. Each plan’s specific current and expected asset allocations are also considered in developing a reasonable return assumption. Contributions and Payments . TES contributed $ 43 million and $ 5 million to the TES sponsored pension plan during the year ended December 31, 2024 (Successor) and the period from May 18 through December 31, 2023 (Successor), respectively. There were no contributions for the pension plans during the period from January 1 through May 17, 2023 (Predecessor). Talen Montana contributed $ 10 million, $ 4 million, and $ 2 million of discretionary contributions to the Talen Montana sponsored pension plan during the year ended December 31, 2024 (Successor) and for the periods from May 18 through December 31, 2023 (Successor), and January 1 through May 17, 2023 (Predecessor), respectively, to the Talen Montana pension plan. TES expects to contribute $ 65 million to the TES sponsored pension plan in 2025. Talen Montana expects to contribute $ 8 million of discretionary contributions to the Talen Montana sponsored pension plan in 2025, of which $ 4 million is expected to be collected by Talen Montana from the other joint owners of Colstrip. The aggregate benefits paid to pension and other postretirement plan participants was $ 114 million for year ended December 31, 2024 (Successor), $ 60 million during the period from May 18 through December 31, 2023 (Successor), and $ 38 million during the period from January 1 through May 17, 2023 (Predecessor). The forecasted undiscounted benefit payments to plan participants as of December 31, 2024 (Successor) were: 2025 2026 2027 2028 2029 2030-2034 Pension plans $ 97 $ 94 $ 94 $ 93 $ 93 $ 452 Other postretirement plans 6 6 5 5 4 18 Pension plan assets. Pension plan assets are held in external trusts, including a master trust, which includes a 401(h) account that is restricted for certain other postretirement benefit obligations of Talen Energy Supply. The plans’ investment policies outline investment objectives. The risk management framework categorizes the plan assets within three sub-portfolios: growth, immunizing, and liquidity. The trust investments within these portfolios are routinely monitored to seek a risk-adjusted return on a mix of assets that, in combination with our funding policy, will provide sufficient assets to provide long-term growth and liquidity for benefit payments, match asset duration with the expected liability duration, and mitigate concentrations of risk with asset diversification. The weighted-average target asset allocations for the pension plan assets as of December 31, 2024 (Successor) were: December 31, 2024 Equity securities 32 % Debt securities 10 % Other 7 % Growth portfolio 48 % Debt securities 35 % Other 12 % Immunizing portfolio 47 % Liquidity portfolio 4 % Total 100 % 99 Item 8. Table of Contents The classifications of pension plan asset fair value measurements within the fair value hierarchy were: Successor December 31, 2024 December 31, 2023 Level 1 NAV Total Level 1 NAV Total Cash equivalents $ — $ 100 $ 100 $ — $ 169 $ 169 Commingled equity securities — 274 274 — 288 288 Commingled debt securities — 286 286 — 301 301 Alternative and other investments ( 15 ) 231 216 52 191 243 Receivables (payables), net (a) — — 35 — — ( 25 ) Total trust funds ( 15 ) 891 911 52 949 976 Restricted 401(h) assets (b) — — — — ( 1 ) Total plan assets $ ( 15 ) $ 891 $ 911 $ 52 $ 949 $ 975 __________________ (a) Represents: (i) interest and dividends earned but not received; and (ii) net sold or purchased investments, but not settled. (b) Other postretirement 401(h) benefits assets are a component of the pension plan master trust. Accordingly, these are excluded from pension plan assets. Level 1 investments consist of exchange-traded futures contracts, which are valued using unadjusted prices available from the underlying market. Certain investments in cash equivalent funds, commingled equity securities, commingled debt securities, and alternative investments are not classified within the fair value hierarchy. The fair value measurement of these funds is based on firm quotes of NAV per share, as a practical expedient for valuation, which are not obtained from a quoted price in an active market. Investments in cash equivalent funds consist of short-term investment funds and commingled cash equivalent funds. Investments in equity funds consist of large and small cap U.S. and international funds that can be redeemed daily. Investments in commingled debt funds consist of funds that invest in investment-grade intermediate and long-duration corporate and government fixed-income securities. These investments can be redeemed daily. Alternative and other investments consist of investments in funds that invest in a portfolio of exchange-traded futures and forward contracts, hedge funds of funds that employ investment strategies including long/short equity, market neutral, distressed debt, and relative value, private equity partnerships, with limited lives ranging from ten to fifteen years , and real estate investment partnerships. Investments in real estate partnerships have redemption limitations based on available funding and investments in private equity partnerships that cannot be redeemed with the partnership prior to the end of the partnerships’ lives; however, the interest may be sold to other parties. Redemptions of hedge funds, private equity, and real estate partnerships are also subject to the respective general partner's approval. Other postretirement benefit plan assets. The investment strategy with respect to most of the other postretirement benefit obligations is to fund VEBA or similar trusts with voluntary contributions, when appropriate, and to invest in a tax efficient manner. Other postretirement benefit plans are invested in a mix of assets for long-term growth with an objective of earning returns that provide liquidity as required for benefit payments. These plans benefit from diversification of asset types, investment fund strategies and investment fund managers, and therefore, have no significant concentration of risk. Equity securities include investments in domestic large-cap commingled funds. Ownership interests in commingled funds that invest entirely in debt securities are classified as equity securities but treated as debt securities for asset allocation and target allocation purposes. Ownership interests in money market funds are treated as cash and cash equivalents for asset allocation and target allocation purposes. The target asset allocations for other postretirement benefit assets as of December 31, 2024 (Successor) were: 2024 Cash and cash equivalents 4 % Equity securities 11 % Debt securities 84 % Total 100 % 100 Item 8. Table of Contents The classifications of other postretirement benefit plan asset fair value measurements within the fair value hierarchy were: Successor December 31, 2024 December 31, 2023 Level 1 Level 2 NAV Total Level 1 Level 2 NAV Total Cash equivalents $ — $ — $ 4 $ 4 $ — $ — $ 7 $ 7 Commingled equity securities — — 10 10 — — 9 9 U.S. Government debt securities 7 — — 7 8 — — 8 Corporate debt securities — 18 — 18 — 16 — 16 Commingled debt securities — — 32 32 — — 34 34 Total trust funds 7 18 46 71 8 16 50 74 Restricted 401(h) assets (a) — — — — — — — 1 Total plan assets $ 7 $ 18 $ 46 $ 71 $ 8 $ 16 $ 50 $ 75 __________________ (a) Other postretirement 401(h) benefits assets are a component of the pension plan master trust. Accordingly, these are reported as postretirement assets. Level 1 investments consist of U.S. Treasury and (or) U.S. government debt securities, which are valued using unadjusted prices available from the underlying market. Level 2 investments consist of corporate debt securities, which are valued using observable inputs such as benchmark yields, relevant trade data, broker/dealer bid/ask prices, benchmark securities, and credit valuation adjustments. Certain investments in money market funds, commingled equity securities, and commingled debt securities are not classified within the fair value hierarchy. The fair value measurements of these funds are based on firm quotes of NAV per share, as a practical expedient for valuation, which are not obtained from a quoted price in an active market. Investments in equity securities consist of investments in a passively managed equity index fund that invests in securities and a combination of other collective funds. Investments in debt securities represent investments in funds that invest in a diversified portfolio of investment grade fixed income securities. Defined Contribution Plan Substantially all Company employees are eligible to participate in the Company’s 401(k) deferred savings plans. Employer contributions to the plans were $ 25 million, $ 9 million, and $ 10 million during the year ended December 31, 2024 (Successor), for the period from May 18 through December 31, 2023 (Successor), and from the period January 1 through May 17, 2023 (Predecessor). Coal Industry Retiree Benefit Plans Talen is obligated under the Coal Act and the Black Lung Act to pay for certain health care and black lung benefits of retired miners and allowable beneficiaries. These obligations are funded from medical VEBAs and a black lung trust. The funded status of each plan as of December 31, 2024 (Successor) was: Trust Asset Fair Value Obligation Fair Value Overfunded Status Benefit Plan for UMWA Represented Retirees of Pennsylvania Mines, LLC $ 21 $ 16 $ 5 Coal Worker's Pneumoconiosis (Black Lung) Benefit Plan 9 5 4 Shortfalls in funded status of the plans are assessed as contingent liabilities. As the fair value of VEBA and black lung trust assets exceed the plan obligations, both VEBA and black lung trust assets and the plan obligations are not reported on the Talen Consolidated Balance Sheets. See in Note 2 for our accounting policy related to postretirement benefits. 16. Stock-Based Compensation In June 2023, TEC began granting PSUs and RSUs to certain employees and non-employee directors under the 2023 Equity Incentive Plan. The aggregate number of shares authorized for issuance under the 2023 Talen Equity Plan is 7,083,461 shares. 101 Item 8. Table of Contents Stock-based Compensation Expense Stock-based compensation expense presented as “General and administrative” on the Consolidated Statement of Operations for the periods was: Successor Year Ended December 31, 2024 May 18 through December 31, 2023 Stock-based compensation expense $ 33 $ 19 Income tax benefit ( 8 ) ( 2 ) After-tax stock-based compensation expense $ 25 $ 17 Performance Stock Units PSUs vest three years after Emergence or a consummation of a change in control event based on the satisfaction of a continued employment condition and the achievement of certain market conditions over a performance period. Participants will be awarded additional PSUs if market conditions exceed targets at the time of vesting. If the Company declares any cash dividends while the PSUs are outstanding, participants will be credited a dividend, payable at the time of vesting, based on the number of shares of common stock underlying the PSUs. The following table summarizes the Company’s non-vested PSUs and changes during the year: Successor Units Weighted-Average Grant Date Fair Value per Unit Non-vested as of December 31, 2023 (Successor) 968,793 $ 54.35 Granted 4,945 96.00 Forfeited ( 17,391 ) 72.75 Non-vested as of December 31, 2024 (Successor) 956,347 $ 54.23 As of December 31, 2024, $ 24 million of unrecognized compensation cost related to unvested PSUs granted are expected to be recognized over a weighted average period of approximately 1.5 years. The fair value of the PSUs was determined using a Monte Carlo valuation methodology based on the fair value of the underlying stock price at the grant date and the significant inputs and assumptions summarized below: Successor Year Ended December 31, 2024 May 18 through December 31, 2023 Volatility (a) 25 % 25 % Expected term (in years) 2.4 3 Risk-free rate (b) 4.29 % 4.35 % - 4.59 % __________________ (a) Derived from an option pricing method based on the average asset volatility of peer companies and the Company’s leverage ratio. (b) Based on the U.S. constant maturity treasury rate with a term matching the expected time to the end of the performance measurement period. 102 Item 8. Table of Contents Restricted Stock Units RSUs have three-year ratable vesting schedules beginning on the grant date, with restrictions on transferring settled shares prior to the final scheduled vesting date for each award. The fair value of the RSUs granted is derived from the closing price of TEC common stock on the grant date. The following table summarizes the Company’s non-vested RSUs and changes during the year: Successor Units Weighted-Average Grant Date Fair Value per Unit Non-vested as of December 31, 2023 (Successor) 845,269 $ 48.46 Granted 56,346 121.89 Forfeited ( 56,594 ) 55.01 Vested ( 295,616 ) 48.90 Non-vested as of December 31, 2024 (Successor) 549,405 $ 55.07 RSUs vested during the year ended December 31, 2024 (Successor) were settled in cash for $ 32 million. As of December 31, 2024, $ 22 million of unrecognized compensation cost related to unvested RSUs granted are expected to be recognized over a weighted average period of approximately 1.5 years. 17. Earnings Per Share Basic EPS is computed by dividing net income (loss) by the weighted average number of shares of common stock outstanding during the applicable period. Diluted EPS is computed by dividing income by the weighted-average number of shares of common stock outstanding, increased by incremental shares that would be outstanding if potentially dilutive non-participating securities were converted to common stock as calculated using the treasury stock method. EPS for the periods were: Successor Predecessor Year Ended December 31, 2024 May 18 through December 31, 2023 January 1 through May 17, 2023 Year Ended December 31, 2022 Numerator: (Millions of Dollars) Net Income (Loss) $ 1,013 $ 143 $ 465 $ ( 1,293 ) Less: Net income (loss) attributable to noncontrolling interest 15 9 ( 14 ) ( 4 ) Net Income (Loss) Attributable to Stockholders (Successor) / Member (Predecessor) $ 998 $ 134 $ 479 $ ( 1,289 ) Denominator: (Thousands) Weighted-Average Number of Common Shares Outstanding - Basic 54,254 59,029 — — Warrants — 84 — — Restricted stock units 354 166 — — Performance stock units 1,878 120 — — Weighted-Average Number of Common Shares Outstanding - Diluted 56,486 59,399 — — Earnings per Share - Basic $ 18.40 $ 2.27 N/A N/A Earnings per Share - Diluted 17.67 2.26 N/A N/A For the period from January 1 through May 17, 2023 (Predecessor) and year ended December 31, 2022 (Predecessor), there were no outstanding shares of common stock. There were no shares excluded from diluted EPS for the year ended December 31, 2024 (Successor). 134,798 PSUs were excluded from diluted EPS for the period from May 18 through December 31, 2023 (Successor) due to their anti-dilutive nature. These awards are excluded from the calculation of EPS because the performance conditions have not been met during the reporting period. 103 Item 8. Table of Contents 18. Stockholders’ Equity Common Stock Transactions Share Repurchases and Retirements. Summary of activity under the SRP and direct repurchases: Successor Year Ended December 31, 2024 Number of Shares (a) (b) Share Price (c) Total Amount Share repurchases 13,227,222 $ 149.50 $ 1,977 Share retirements ( 13,227,222 ) 149.50 ( 1,977 ) __________________ (a) Includes 7,307,300 shares repurchased from affiliates of Rubric in July 2024 and December 2024 at a weighted average price of $ 177.16 per share. Of the total shares repurchased by the Company, $ 850 million purchased from affiliates of Rubric were not under the SRP. (b) Includes 5,275,862 shares repurchased as result of a tender offer in June 2024 at a weighted average price of $ 117.16 per share. (c) Weighted average price per share, including transaction costs and excise taxes. As of December 31, 2024 (Successor), all repurchased shares have been retired. See Note 2 for the accounting policy related to treasury stock and retirement of treasury shares. As of February 27, 2025, TEC had 45,961,910 shares of common stock outstanding. Exercise of Warrants. 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. Share Repurchases In May 2024, the Board of Directors approved an increase of the SRP from $ 300 million to a remaining capacity of $ 1 billion. In September 2024, the Board of Directors approved an increase of the remaining capacity to $ 1.25 billion through December 31, 2026. As of December 31, 2024 (Successor), the Company had repurchased approximately 22 % of its outstanding shares of common stock for a total of $ 1.95 billion, exclusive of transaction costs and excise taxes. The Board of Directors approved a portion of the share repurchases executed with Rubric in December 2024 outside of the existing authorization in the SRP. The remaining capacity of the SRP as of December 31, 2024 (Successor) is $ 1.1 billion. Employee Stock Purchase Plan In November 2024, the Board of Directors approved the Company’s 2025 Employee Stock Purchase Plan (“ESPP”), which is subject to approval by shareholders. Effective January 1, 2025, eligible employees can withhold between 1 % and 10 % of their eligible compensation to purchase TEC common stock at the lesser of 85 % of its market value on the offering date or 85 % of the market value on the exercise date. Offering dates will occur each January 1 and July 1 and exercise dates each June 30 and December 31. Initially, 500,000 shares may be issued pursuant to the ESPP, with automatic increases in the number of shares authorized for issuance beginning on January 1, 2026 and ending on January 1, 2034. The maximum number of shares that may be issued under the ESPP is 5,000,000 shares. Acquisition of Noncontrolling Interests Purchase of Equity in Nautilus. In October 2024, the Company acquired TeraWulf’s 25 % equity interest in Nautilus in exchange for $ 85 million and the distribution by Nautilus of its Bitcoin mining equipment to TeraWulf. As a result of the transaction, the Company owns 100 % of the equity of Nautilus. In conjunction with the transaction, we suspended Bitcoin mining operations at the facility. Purchase of Equity in Cumulus Digital. In March 2024, TES acquired all of the equity of Cumulus Digital held by affiliates of Orion Energy Partners and two former members of Talen senior management in exchange for an aggregate of $ 39 million. Following these transactions, TES owns 100 % of the equity of Cumulus Digital. 104 Item 8. Table of Contents Accumulated Other Comprehensive Income Changes in AOCI for the periods were: Successor Predecessor Year Ended December 31, 2024 May 18 through December 31, 2023 January 1 through May 17, 2023 Year Ended December 31, 2022 Beginning balance $ ( 23 ) $ — $ ( 167 ) $ ( 152 ) Gains (losses) arising during the period (a) 12 ( 36 ) 6 ( 84 ) Reclassifications to Consolidated Statements of Operations (b) — 7 5 59 Income tax benefit (expense) ( 1 ) 6 ( 5 ) 10 Other comprehensive income (loss) 11 ( 23 ) 6 ( 15 ) Cancellation of equity at Emergence — — 161 — Accumulated other comprehensive income (loss) $ ( 12 ) $ ( 23 ) $ — $ ( 167 ) __________________ (a) Primarily related to “Postretirement benefit actuarial (gain) loss, net” for the period from May 18 through December 31, 2023 (Successor) and “Available-for-sale securities unrealized gain (loss), net” and “Postretirement benefit actuarial (gain) loss, net” for the year ended December 31, 2022 (Predecessor). (b) Primarily related to “Available-for-sale securities unrealized gain (loss), net” and “Postretirement benefit actuarial (gain) loss, net” for the year ended December 31, 2022 (Predecessor). The components of AOCI, net of tax, were: Successor December 31, 2024 December 31, 2023 Available-for-sale securities unrealized gain (loss), net $ ( 3 ) $ 5 Postretirement benefit prior service credits (costs), net 14 — Postretirement benefit actuarial gain (loss), net ( 23 ) ( 28 ) Accumulated other comprehensive income (loss) $ ( 12 ) $ ( 23 ) The locations of pre-tax gains (losses) reclassified from AOCI and included on the Consolidated Statements of Operations for the periods were: Successor Predecessor Year Ended December 31, 2024 May 18 through December 31, 2023 January 1 through May 17, 2023 Year Ended December 31, 2022 Nuclear decommissioning trust funds gain (loss), net (a) $ ( 1 ) $ ( 7 ) $ ( 4 ) $ ( 33 ) Depreciation, amortization and accretion (b) — — 1 2 Operation, maintenance and development (c) 1 — — ( 1 ) Other non-operating income (expense), net (d) — — ( 2 ) ( 27 ) Total $ — $ ( 7 ) $ ( 5 ) $ ( 59 ) __________________ (a) Available-for-sale securities unrealized gain (loss), net. (b) Qualifying derivatives unrealized gain (loss). (c) Postretirement benefit prior service credits (costs), net. (d) Postretirement benefit actuarial gain (loss), net. The postretirement obligations components of AOCI are not presented in their entirety on the Consolidated Statements of Operations during the periods; rather, they are included in the computation of net periodic defined benefit costs (credits). See Note 15 for additional information. 105 Item 8. Table of Contents 19. Supplemental Cash Flow Information Supplemental information for the Consolidated Statements of Cash Flows for the periods was: Successor Predecessor Year Ended December 31, 2024 May 18 through December 31, 2023 January 1 through May 17, 2023 Year Ended December 31, 2022 Cash paid during the period Interest and other finance charges, net of capitalized interest (a) $ 255 $ 133 $ 283 $ 277 Income taxes, net 20 12 7 14 Unrealized (gain) loss on derivative instruments included on the Statements of Cash Flows Commodity contracts $ ( 62 ) $ ( 52 ) $ 63 $ ( 625 ) Interest rate swap contracts (interest expense) ( 7 ) 12 2 ( 23 ) Unrealized (gain) loss on derivative instruments $ ( 69 ) $ ( 40 ) $ 65 $ ( 648 ) Depreciation, amortization and accretion included on the Statements of Cash Flows Depreciation, amortization and accretion $ 298 $ 165 $ 200 $ 520 Other ( 13 ) ( 8 ) 8 29 Depreciation, amortization and accretion $ 285 $ 157 $ 208 $ 549 Reconciliation of other non-cash operating activities Bitcoin revenue $ ( 91 ) $ ( 81 ) $ ( 27 ) $ — Stock-based compensation 33 19 — — Fair value adjustment on distribution of miners 14 — — — Derivative option premium amortization 11 52 29 67 Derivatives with financing elements — — — 104 Non-cash environmental liability revisions — — — 13 Other 7 17 5 16 Total $ ( 26 ) $ 7 $ 7 $ 200 Non-cash investing activities Capital expenditure accrual increase (decrease) $ 6 $ 7 $ ( 28 ) 2 Accounts receivable contributed to equity method investment — — — 2 Non-cash financing activities Non-cash increase to PP&E and decrease to other current assets for contribution of Bitcoin miners to Nautilus (b) $ — $ — $ 14 $ 30 Non-cash decrease to PP&E and decrease to noncontrolling interest for distribution of Bitcoin miners to TeraWulf (c) 43 — 3 — Non-cash increase to PP&E and increase to noncontrolling interest for contribution of Bitcoin miners by TeraWulf (b) — — 38 14 __________________ (a) Capitalized interest totaled $ 5 million for the year ended December 31, 2024 (Successor); $ 10 million for the period from May 18 through December 31, 2023 (Successor); and $ 12 million for the period from January 1 through May 17, 2023 (Predecessor), and $ 12 million for the year ended December 31, 2022 (Predecessor). (b) In 2023, each of the joint venture partners of Nautilus made non-cash contributions to Nautilus of Bitcoin miners that increased PP&E. (c) In 2024, Nautilus distributed Bitcoin miners to TeraWulf as part of the buyout of TeraWulf’s noncontrolling interest. 106 Item 8. Table of Contents Cash and Restricted Cash The following provides a reconciliation of “Cash and cash equivalents” and “Restricted cash and cash equivalents” presented on the Consolidated Statements of Cash Flows to line items within the Consolidated Balance Sheets: Successor December 31, 2024 December 31, 2023 Cash and cash equivalents $ 328 $ 400 Restricted cash and cash equivalents: TES TLC debt restricted deposits — 472 Nautilus project restricted deposits — 10 Commodity exchange margin deposits 37 — Cumulus Digital restricted deposits — 19 Restricted cash and cash equivalents 37 501 Total $ 365 $ 901 20. Acquisitions and Divestitures 2024 Activities ERCOT Sale. In May 2024, we sold our 1,710 MW Texas generation portfolio to CPS Energy for $ 785 million, subject to customary net working capital adjustments. A gain on sale of $ 564 million is presented as “Gain (loss) on sale of assets, net” on the Consolidated Statements of Operations for the year ended December 31, 2024 (Successor). AWS Data Campus Sale. In March 2024, AWS purchased substantially all the assets related to the AWS Data Campus and certain other assets for gross proceeds of $ 650 million, of which $ 350 million were received at closing with the remaining $ 300 million held in escrow until August 2024. For the year ended December 31, 2024 (Successor), a $ 324 million gain on sale is presented as “Gain (loss) on sale of assets, net” on the Consolidated Statements of Operations. In connection with the AWS Data Campus Sale, the Company entered into the AWS PPA. 2023 Activities Western Gas Book Divestiture. In April 2023, Talen sold certain contracts relating to the transportation of natural gas in the southwestern United States for $ 15 million. For the period from January 1 through May 17, 2023 (Predecessor), a $ 15 million gain was presented as “Gain (loss) on sale of assets, net” on the Consolidated Statements of Operations. Pennsylvania Minerals Divestiture. In March 2023, Talen sold certain mineral interests located in Pennsylvania for $ 29 million, while preserving the right to certain royalty payments from existing and future producing natural gas wells. For the period from January 1 through May 17, 2023 (Predecessor), a $ 29 million gain was presented as “Gain (loss) on sale of assets, net” on the Consolidated Statements of Operations. 21. Segments Talen’s operating segments are based on the market areas in which our generation facilities operate and reflect the manner in which our Chief Executive Officer, who is the chief operating decision maker, reviews results and allocate resources. Adjusted EBITDA is the key profit metric used to measure financial performance of each segment. Total assets or other asset metrics are not considered a key metric or reviewed by the chief operating decision maker. “PJM” is engaged in electricity generation, marketing activities, commodity risk and fuel management within the PJM RTO or ISO markets and is comprised of Susquehanna and Talen’s natural gas and coal generation facilities. “Other” represents an operating segment that includes the operating and marketing activities of Talen Montana’s proportionate share of Colstrip in the WECC market and other non-material operating and development activities. “Other” also includes the operating activities of Nautilus until Bitcoin mining operations were suspended in October 2024 and the operating activities of our Texas power generation facilities in the ERCOT market prior to their disposal in May 2024. We have determined it appropriate to aggregate results of Talen’s remaining non-reportable segments and other operating activities. “Corporate and Eliminations” represents a non-reportable segment that includes: (i) general and administrative expenses incurred by our corporate function; (ii) interest expense and other corporate activities not allocated to our operating segments; and (iii) intercompany eliminations. This grouping is presented to reconcile the reportable segments to our consolidated results. 107 Item 8. Table of Contents Financial results for the segments and reconciliation to consolidated results: PJM Other Corporate and Eliminations Total Year Ended December 31, 2024 (Successor) Operating revenues $ 1,866 $ 367 $ ( 118 ) $ 2,115 Operation, maintenance and development expenses (a) 518 74 — 592 Interest expense and other finance charges — — 238 238 Other segment items (b) 573 Adjusted EBITDA 775 Capital expenditures 164 24 1 189 May 18 through December 31, 2023 (Successor) Operating revenues $ 1,120 $ 397 $ ( 173 ) $ 1,344 Operation, maintenance and development expenses (a) 294 78 ( 14 ) 358 Interest expense and other finance charges — — 176 176 Other segment items (b) 449 Adjusted EBITDA 377 Capital expenditures 110 45 6 161 January 1 through May 17, 2023 (Predecessor) Operating revenues $ 1,052 $ 195 $ ( 37 ) $ 1,210 Operation, maintenance and development expenses (a) 245 47 ( 7 ) 285 Interest expense and other finance charges — — 163 163 Other segment items (b) 119 Adjusted EBITDA 688 Capital expenditures 132 53 2 187 Year ended December 31, 2022 (Predecessor) Operating revenues $ 2,902 $ 194 $ ( 7 ) $ 3,089 Operation, maintenance and development expenses (a) 519 97 ( 6 ) 610 Interest expense and other finance charges — — 359 359 Other segment items (b) 1,402 Adjusted EBITDA 981 Capital expenditures 237 69 6 312 __________________ (a) This significant segment expense category aligns with the segment-level information that is regularly provided to the CODM. (b) Other segment items are primarily comprised of fuel and energy purchases. 108 Item 8. Table of Contents Reconciliation of segment Adjusted EBITDA to Net Income (Loss): Successor Predecessor Year Ended December 31, 2024 May 18 through December 31, 2023 January 1 through May 17, 2023 Year Ended December 31, 2022 Adjusted EBITDA: PJM $ 775 $ 377 $ 688 $ 981 Total Segment Adjusted EBITDA $ 775 $ 377 $ 688 $ 981 Reconciling Items: Interest expense and other finance charges $ ( 238 ) $ ( 176 ) $ ( 163 ) $ ( 359 ) Income tax benefit (expense) ( 98 ) ( 51 ) ( 212 ) 35 Depreciation, amortization and accretion ( 298 ) ( 165 ) ( 200 ) ( 520 ) Nuclear fuel amortization ( 123 ) ( 108 ) ( 33 ) ( 94 ) Reorganization (gain) loss, net — — 799 ( 812 ) Unrealized (gain) loss on commodity derivative contracts 62 52 ( 63 ) 625 Nuclear decommissioning trust funds gain (loss), net 178 108 57 ( 184 ) Stock-based compensation expense ( 33 ) ( 19 ) — — Long-term incentive compensation expense ( 21 ) ( 2 ) — — Gain (loss) on asset sales, net 884 7 50 — Non-cash impairments ( 1 ) ( 3 ) ( 381 ) — Legal settlements and litigation costs 10 84 ( 1 ) ( 20 ) Unusual market events 1 19 ( 14 ) ( 29 ) Net periodic defined benefit cost ( 14 ) ( 2 ) 3 ( 12 ) Operational and other restructuring activities ( 76 ) ( 48 ) ( 17 ) ( 570 ) Hedge termination losses, net — — — ( 158 ) Development expenses ( 1 ) ( 7 ) ( 10 ) ( 17 ) Non-cash inventory net realizable value, obsolescence, and other charges ( 20 ) ( 4 ) ( 56 ) ( 3 ) Consolidation of subsidiary gain (loss), net — — — ( 170 ) "Other" operating segment 71 113 37 103 Noncontrolling interest 21 42 14 ( 3 ) Corporate and Eliminations ( 76 ) ( 64 ) ( 30 ) ( 69 ) Other items 10 ( 10 ) ( 3 ) ( 17 ) Net Income (Loss) $ 1,013 $ 143 $ 465 $ ( 1,293 ) 109 Form 10- K Table of Contents ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE None.