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Item 8. Financial Statements and Supplementary Data

2026-02-26 compared with 2025-02-28 · 1184 added, 1036 removed, 1357 unchanged (62% of the section changed)

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TALEN ENERGY CORPORATION AND SUBSIDIARIES

Report of Independent Registered Public Audit Firm (PCAOB ID 238 )

Report s of Independent Registered Public Audit Firm (PCAOB ID 238 )

Consolidated Statements of Operations

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Notes to the Annual Financial Statements

Organization and Operations

Basis of Presentation and Summary of Significant Accounting Policies

Talen Emergence from Restructuring

F resh Start Accounting

Business, Basis of Presentation, and Summary of Significant Accounting Policies

Risk Management, Derivative Instruments and Hedging Activities

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Postretirement Benefit Obligations

Stock-Based Com pensation

Stock-Based Compensation

Earnings Per Share

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Acquisitions and Divestitures

Talen Emergence from Restructuring

Fresh Start Accounting

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.

Opinions on the Financial Statements and Internal Control over Financial Reporting

We have audited the accompanying consolidated balance sheets of Talen Energy Corporation and its subsidiaries (Successor) (the "Company") as of December 31, 2025 and 2024, and the related consolidated statements of operations, of comprehensive income (loss), of equity and of cash flows for the years ended December 31, 2025 and 2024, and for the period from May 18, 2023 through December 31, 2023, including the related notes and financial statement schedule listed in the index appearing under Item 15(a)(2) (collectively referred to as the "consolidated financial statements").

We also have audited the Company's internal control over financial reporting as of December 31, 2025, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of the Company as of December 31, 2025 and 2024, and the results of its operations and its cash flows for the years ended December 31, 2025 and 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.

Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2025, based on criteria established in Internal Control - Integrated Framework (2013) issued by the COSO.

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.

As discussed in Note 19 to the consolidated financial statements, the bankruptcy court 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 2022 and substantially alters rights and interests of equity security holders as provided for in the plan.

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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.

Basis for Opinions

The Company's management is responsible for these consolidated financial statements, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting, included in Management’s Report on Internal Control Over Financial Reporting appearing under Item 9A.

Our responsibility is to express opinions on the Company’s consolidated financial statements and on the Company's internal control over financial reporting 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 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.

We conducted our audits in accordance with the standards of the PCAOB.

Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud, and whether effective internal control over financial reporting was maintained in all material respects.

Our audits of the consolidated financial statements 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.

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.

Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk.

Our audits also included performing such other procedures as we considered necessary in the circumstances.

We believe that our audits provide a reasonable basis for our opinions.

As described in Management’s Report on Internal Control Over Financial Reporting, management has excluded the Freedom and Guernsey entities from its assessment of internal control over financial reporting as of December 31, 2025, because they were acquired by the Company in a purchase business combination during 2025.

We have also excluded the Freedom and Guernsey entities from our audit of internal control over financial reporting.

The Freedom and Guernsey entities are wholly-owned subsidiaries whose total assets and total revenues excluded from management’s assessment and our audit of internal control over financial reporting collectively represent 20% and 6%, respectively, of the related consolidated financial statement amounts as of and for the year ended December 31, 2025.

Definition and Limitations of Internal Control over Financial Reporting

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.

A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company;

(ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company;

and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements.

Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

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.

The critical audit matters communicated below are matters arising from the current period audit of the consolidated financial statements that were communicated or required to be communicated to the audit committee and that (i) relate 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 matters below, providing separate opinions on the critical audit matters or on the accounts or disclosures to which they relate.

Acquisition of Freedom and Guernsey - Valuation of Plant and Equipment and Fuel Supply Contract Liabilities

As described in Note 17 to the consolidated financial statements, on November 25, 2025, the Company purchased all the ownership interests of Freedom and Guernsey for an aggregate purchase price of $3.8 billion in cash.

Of the acquired assets and liabilities assumed, $4,509 million related to property, plant and equipment, a majority of which relates to plant and equipment, and $667 million of fuel supply contract liabilities were recorded.

Fair value of plant and equipment was determined by management using the income approach and involved the use of significant assumptions including the forecasted prices for capacity, wholesale power, and natural gas, volumetric assumptions, and discount rates.

The fair values of fuel supply contract liabilities were estimated by management using the income approach and involved the use of significant assumptions including forecasted prices for wholesale power and natural gas, volumetric assumptions, and discount rates.

The principal considerations for our determination that performing procedures relating to the valuation of plant and equipment acquired and fuel supply contract liabilities assumed in the acquisition of Freedom and Guernsey is a critical audit matter are (i) the significant judgment by management when developing the fair value estimate of the plant and equipment acquired and the fuel supply contract liabilities assumed;

(ii) a high degree of auditor judgment, subjectivity, and effort in performing procedures and evaluating management’s significant assumptions related to (a) forecasted prices for capacity, wholesale power, and natural gas, volumetric assumptions, and discount rates for plant and equipment acquired and (b) forecasted prices for wholesale power and natural gas, volumetric assumptions, and discount rates for fuel supply contract liabilities assumed;

and (iii) the audit effort involved the use of professionals with specialized skill and knowledge.

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 testing the effectiveness of controls relating to the acquisition accounting, including controls over management’s valuation of the plant and equipment acquired and fuel supply contract liabilities assumed.

These procedures also included, among others (i) reading the purchase agreements and the fuel supply agreements;

(ii) testing management’s process for developing the fair value estimate of the plant and equipment acquired and the fuel supply contract liabilities assumed;

(iii) evaluating the appropriateness of the income approach used by management;

(iv) testing the completeness and accuracy of the underlying data used in the income approach;

and (v) evaluating the reasonableness of the significant assumptions used by management related to (a) forecasted prices for capacity, wholesale power, and natural gas, volumetric assumptions, and discount rates for plant and equipment acquired and (b) forecasted prices for wholesale power and natural gas, volumetric assumptions, and discount rates for fuel supply contract liabilities assumed.

Evaluating management’s assumptions related to (a) forecasted prices for capacity, wholesale power, and natural gas, and volumetric assumptions for plant and equipment and (b) forecasted prices for wholesale power and natural gas and volumetric assumptions for fuel supply contract liabilities involved considering (i) the current and past performance of Freedom and Guernsey;

(ii) the consistency with external market and industry data;

and (iii) whether the assumptions were consistent with evidence obtained in other areas of the audit.

Professionals with specialized skill and knowledge were used to assist in evaluating (i) the appropriateness of the income approach and (ii) the reasonableness of the discount rates assumption for plant and equipment acquired and fuel supply contract liabilities assumed.

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;

As described in Notes 1, 2, and 11 to the consolidated financial statements, the Company’s commodity derivatives had a fair value net derivative asset position of $60 million and a fair value net derivative liability position of $156 million as of December 31, 2025.

The Company utilizes 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 their generation portfolio.

As disclosed by management, commodity derivative contracts are valued using a market approach which utilizes 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 derivatives valuation is a critical audit matter are (i) the significant judgment by management when developing the estimated fair value 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;

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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;

These procedures included testing the effectiveness of controls relating to the commodity derivatives valuation, including controls over the development of significant assumptions.

These procedures also included, among others (i) testing management’s process for developing the estimated fair value of commodity derivatives;

(ii) evaluating the appropriateness of management’s market approach;

(iii) testing, on a sample basis, the completeness and accuracy of the underlying contract terms and the accounting treatment conclusions;

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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.

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, 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 in accordance 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.

As discussed in Note 19 to the consolidated financial statements, the Company filed a petition in May 2022 with the bankruptcy court 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.

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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

(Millions of Dollars, except share data) Year Ended December 31, 2025 Year Ended December 31, 2024 May 18 through December 31, 2023 January 1 through May 17, 2023

Energy and other revenues $ 2,141 $ 1,881 $ 1,156 $ 1,042

Capacity revenues 485 192 133 108

Unrealized gain (loss) on derivative instruments (Note 2) ( 45 ) 42 55 60

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Operation, maintenance and development ( 620 ) ( 592 ) ( 358 ) ( 285 )

General and administrative ( 163 ) ( 93 ) ( 51 ) ( 106 )

General and administrative (Includes stock-based compensation of $( 526 ), $( 33 ), $( 19 ), and $ 0 ) (Note 13)

( 624 ) ( 163 ) ( 93 ) ( 51 )

Depreciation, amortization and accretion (Note 7) ( 279 ) ( 298 ) ( 165 ) ( 200 )

Impairments (Note 7) — ( 1 ) ( 3 ) ( 381 )

Operational restructuring — — — ( 488 )

Other operating income (expense), net ( 82 ) ( 38 ) ( 30 ) ( 37 )

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Reorganization income (expense), net (Note 20) — — — 799

Consolidation of subsidiary gain (loss) (Note 2) — — — ( 170 )

Gain (loss) on sale of assets, net (Note 17) 34 884 7 50

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Net Income (Loss) Attributable to Stockholders (Successor) / Member (Predecessor) $ ( 219 ) $ 998 $ 134 $ 479

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

Per Common Share

Net Income (Loss) Attributable to Stockholders - Basic $ ( 4.79 ) $ 18.40 $ 2.27 N/A

Net Income (Loss) Attributable to Stockholders - Diluted $ ( 4.79 ) $ 17.67 $ 2.26 N/A

Weighted-Average Number of Common Shares Outstanding - Basic (in thousands) 45,692 54,254 59,029 N/A

Weighted-Average Number of Common Shares Outstanding - Diluted (in thousands) 45,692 56,486 59,399 N/A

The accompanying Notes to the Annual Financial Statements are an integral part of the financial statements.

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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

(Millions of Dollars) Year Ended December 31, 2025 Year Ended December 31, 2024 May 18 through December 31, 2023 January 1 through May 17, 2023

Net Income (Loss) $ ( 219 ) $ 1,013 $ 143 $ 465

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Derivative instruments (Notes 2 and 11) 101 —

Stock-based compensation liabilities (Note 13) 501 —

Other current liabilities 78 154

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Deferred income taxes (Note 4) 486 362

Acquired fuel supply contract liabilities (Note 17) 662 —

Other noncurrent liabilities 42 135

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Total Stockholders' Equity $ 1,093 $ 1,387

Noncontrolling interests — 77

Total Equity 1,387 2,534

Total Liabilities and Equity $ 6,106 $ 7,121

Total Liabilities and Stockholders' Equity $ 10,905 $ 6,106

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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

(Millions of Dollars) Year Ended December 31, 2025 Year Ended December 31, 2024 May 18 through December 31, 2023 January 1 through May 17, 2023

Operating Activities

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Non-cash reconciliation adjustments:

(Gain) loss on AWS Data Campus Sale and ERCOT Sale (Note 20) ( 886 ) — — —

Stock-based compensation (Note 13) 526 33 19 —

Depreciation, amortization and accretion (Note 16) 279 285 157 208

NDT funds (gain) loss, net (excluding interest and fees) (Note 9) ( 130 ) ( 78 ) ( 43 ) 227

Nuclear fuel amortization (Note 10) 123 108 33 94

Nuclear decommissioning trust funds (gain) loss, net (excluding interest and fees) (Note 6) ( 132 ) ( 130 ) ( 78 ) ( 43 )

Unrealized (gains) losses on derivative instruments (Note 2) 121 ( 69 ) ( 40 ) 65

Deferred income taxes 120 ( 46 ) 55 195

Impairments (Note 10) 1 3 381 —

(Gain) loss on sales of assets, net — ( 7 ) ( 50 ) —

Nuclear fuel amortization (Note 7) 97 123 108 33

(Gain) loss on sales of assets, net (Note 17) ( 36 ) — ( 7 ) ( 50 )

(Gain) loss on AWS Data Campus Sale and ERCOT Sale (Note 17) — ( 886 ) — —

Reorganization (income) expense, net (Note 20) — — — ( 933 )

Operational restructuring — — — 488

Consolidation of subsidiary (gain) loss (Note 2) — — — 170

Impairments (Note 7) — 1 3 381

Other (Note 16) 51 ( 59 ) ( 12 ) 7

Changes in assets and liabilities:

Inventory, net 67 ( 68 ) 10 ( 55 )

Accounts receivable ( 44 ) 14 8 261

Inventory, net 29 67 ( 68 ) 10

Other assets 182 ( 61 ) 147 98

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Accrued interest 42 ( 15 ) 28 ( 124 )

Collateral received (posted), net ( 33 ) 46 26 ( 83 )

Other liabilities ( 231 ) 9 ( 38 ) 41

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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 — — —

Freedom and Guernsey Acquisitions, net (Note 17) ( 3,793 ) — — —

Nuclear decommissioning trust funds investment purchases (Note 6) ( 1,962 ) ( 2,295 ) ( 1,290 ) ( 959 )

Nuclear decommissioning trust funds investment sale proceeds (Note 6) 1,927 2,263 1,265 949

Nuclear fuel expenditures (Note 7) ( 108 ) ( 104 ) ( 45 ) ( 49 )

Property, plant and equipment expenditures (Note 7) ( 98 ) ( 85 ) ( 116 ) ( 138 )

Equity investments in affiliates ( 10 ) ( 5 ) ( 8 ) ( 162 )

Proceeds from AWS Data Campus Sale and ERCOT Sale (Note 17) — 1,398 — —

Proceeds from the sale of assets 40 2 8 46

Increase (decrease) in cash and restricted cash due to consolidation of subsidiaries — — — 123

Other investing activities 2 12 2 11

Other ( 9 ) ( 8 ) 7 ( 6 )

Net cash provided by (used in) investing activities ( 4,003 ) 1,171 ( 171 ) ( 157 )

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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

(Millions of Dollars) Year Ended December 31, 2025 Year Ended December 31, 2024 May 18 through December 31, 2023 January 1 through May 17, 2023

Financing Activities

Debt issuances (Note 10) 3,890 849 — —

Share repurchases (Note 15) ( 103 ) ( 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 ( 89 ) ( 13 ) ( 7 ) ( 74 )

Revolving credit facility borrowings (Note 10) 75 — — —

Revolving credit facility repayments (Note 10) ( 75 ) — — —

Debt repayments (Note 10) ( 17 ) ( 479 ) — —

Cumulus Digital TLF repayment — ( 182 ) ( 15 ) —

Repurchase of noncontrolling interest — ( 125 ) ( 19 ) —

Cash settlement of restricted stock units — ( 32 ) — —

Exercise or repurchase of warrants — ( 16 ) ( 40 ) —

LMBE-MC TLB payments — — ( 294 ) ( 7 )

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 —

Repayment of prepetition secured indebtedness — — — ( 3,898 )

Financing proceeds at Emergence, net of discount — — — 2,219

Contributions from member — — — 1,393

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Derivatives with financing elements — — — ( 20 )

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 5 ( 7 ) 3 —

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Other comprehensive income (loss) — — — — — 6 — 6

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)

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— — — — — — ( 20 ) ( 20 )

Stock-based compensation expense — 19 — — — — — 19

Equity incentive plans — 19 — — — — — 19

Other — 1 — — — — 1 2

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— — — — — — ( 52 ) ( 52 )

Stock-based compensation expense — 33 — — — — — 33

Equity incentive plans — 33 — — — — — 33

December 31, 2024 (Successor) 45,962 $ 1,725 $ ( 326 ) $ ( 12 ) $ — $ — $ — $ 1,387

Net income (loss) — — ( 219 ) — — — — ( 219 )

Other comprehensive income (loss) — — — 8 — — — 8

Share repurchases ( 452 ) — — — ( 85 ) — — ( 85 )

Retirement of treasury stock — ( 18 ) ( 67 ) — 85 — — —

Equity incentive plans (h)

178 2 — — — — — 2

December 31, 2025 (Successor) 45,688 $ 1,709 $ ( 612 ) $ ( 4 ) $ — $ — $ — $ 1,093

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(a) Shares in thousands.

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(d) Related primarily to distributions of Bitcoin to TeraWulf.

(d) Related primarily to distribution 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.

(h) Includes cash payments for tax withholdings on vested stock-based awards of $ 26 million and impact of modification of certain awards from equity to liability.

The accompanying Notes to the Annual Financial Statements are an integral part of the financial statements.

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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.

Capitalized terms and abbreviations appearing in these notes to the Annual Financial Statements are defined in the glossary.

Dollars are in millions, unless otherwise noted.

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“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.

For periods after May 17, 2023, the terms “Talen,” the “Company,” “we,” “us,” and “our” refer to TEC and its consolidated subsidiaries (including TES), unless the context clearly indicates otherwise.

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.

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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.

Business, Basis of Presentation, and Summary of Significant Accounting Policies

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 own and operate approximately 13.1 GW of power infrastructure in the United States, including 2.2 GW of nuclear power and a significant dispatchable fossil 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.

power markets, with our generation fleet principally located in the Mid-Atlantic, Ohio, and Montana.

Talen is headquartered in Houston, Texas.

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:

These Annual Financial Statements, which are prepared in accordance with GAAP and pursuant to the rules and regulations of the U.S.

Securities and Exchange Commission (the “SEC”) for Annual Reports on Form 10-K, include:

(i) the accounts of all controlled subsidiaries;

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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).

(i) the Predecessor period from January 1 through May 17, 2023 (Predecessor);

and (ii) the Successor periods from May 18 through December 31, 2023 (Successor) and the years ended December 31, 2024 (Successor) and December 31, 2025 (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 19 for additional information on the Restructuring and Note 20 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).

Summary of Significant Accounting Policies

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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).

See Notes 19 and 20 for additional information on the Restructuring and fresh start accounting, respectively.

Business Combinations.

The purchase price paid by the Company to acquire a business is allocated to the identifiable assets acquired and liabilities assumed based on their estimated fair values as of the acquisition date.

If the initial accounting for a business combination is incomplete by the end of the reporting period in which the combination occurs, provisional amounts are reported.

Provisional amounts can be adjusted prospectively during a measurement period not to exceed one year from the acquisition date.

If the purchase price exceeds the net fair value of the acquired business, the difference is recognized as goodwill on the consolidated balance sheets.

Conversely, a bargain purchase gain is recognized on the consolidated statements of operations if the purchase price of an acquired business is below its net fair value.

See Note 17 for additional information on recent business combinations.

Fair Value of Financial Instruments and Hierarchy.

The portion of our assets and liabilities carried at fair value are measured as of 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.

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(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.

(iii) Level 3 inputs that 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.

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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.

Transfers occur at the end of a reporting period.

For qualifying investments without readily determinable fair values, NAV is elected as a practical expedient to determine the fair values based on firm quotes of NAV per share.

The following is a description of the Company’s fair value hierarchy associated with assets and liabilities presented on the Consolidated Balance Sheets as “Derivative instruments,” “Long-term Debt,” “Nuclear decommissioning trust funds,” and pension and other postretirement plan asset investments within “Postretirement benefit obligations” or “Other noncurrent assets.”

Fair Value Hierarchy Description

Level 1 Derivative instruments:

Commodity and interest rate futures and/or options.

Equity securities and U.S.

Government debt securities, which include U.S.

Treasury bills, notes and (or) bonds.

Pension plan asset investments:

Alternative and other investments, which include U.S.

Treasury futures contracts.

Other postretirement plan asset investments:

Government debt securities, which include U.S.

Treasury bills, notes, and/or bonds.

Level 2 Derivative instruments:

Over-the-counter swaps, options and forward purchase and sale contracts that are valued using adjusted exchange prices, prices provided by brokers, or pricing service companies that are all corroborated by market data.

government debt securities, municipal debt securities and corporate debt securities are valued using pricing provided by brokers or pricing service companies and corroborated by market data.

Long-term debt:

The reported fair value of fixed and variable rate debt is valued using prices provided by brokers or pricing service companies and corroborated by market data.

The carrying value of certain other short-term indebtedness approximates fair value.

Other postretirement plan asset investments:

Corporate debt securities are valued using pricing provided by brokers or pricing service companies and corroborated by market data.

Level 3 There are no material assets or liabilities valued utilizing such inputs.

Net Asset Value (NAV) NDT funds:

▪ Cash equivalents consist of short-term investment funds and commingled cash equivalent funds that can be redeemed daily.

▪ Equity securities consist of commingled fixed income funds that can be redeemed daily and real estate investment trusts that can be redeemed quarterly, subject to investment manager approval.

Pension plan asset investments:

▪ Cash equivalent funds consist of short-term investment funds and commingled cash equivalent funds that can be redeemed daily.

▪ Commingled equity securities consist of large and small cap U.S.

and international funds that can be redeemed daily.

▪ Commingled debt securities consist of funds that invest in investment-grade intermediate and long-duration corporate and government fixed-income securities that can be redeemed daily.

▪ Alternative and other investments primarily consist of fund investments in real estate, private equity, hedge funds, and infrastructure, which have redemption limitations subject to the respective general partner’s approval.

Other postretirement plan asset investments:

▪ Cash equivalent funds consist of short-term investment funds and commingled cash equivalent funds that can be redeemed daily.

▪ Commingled equity securities consist of investments in a passively-managed equity index fund that invests in securities and a combination of other collective funds that can be redeemed daily.

▪ Commingled debt securities consist of investments in funds that invest in a diversified portfolio of investment-grade fixed income securities that can be redeemed daily.

See Notes 2, 6, 11, and 12 for disclosures on fair value measurements and fair value levels.

Operating Revenues and Revenue Recognition.

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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.

Include 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.

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(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;

(ii) amounts earned for wholesale and retail electricity and other energy-related product sales to bilateral counterparties;

and (iii) realized gains and losses on commodity derivative instruments.

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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.

Such sales are recognized based on invoiced amounts, which correspond directly with the value provided over a specific time interval.

Accrued and unbilled revenues are estimated at the end of each reporting period.

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.

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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.

The Nuclear PTC 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.

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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.

Prior to its suspension of operations in October 2024, the primary output of Nautilus’s ordinary business activities was providing hash calculation services to solve complex cryptographic algorithms in support of blockchain mining.

Nautilus was party to a mining pool arrangement to provide an unspecified amount of its available hash calculations to an unaffiliated mining pool operator.

Nautilus was 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 was 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 was to provide hash calculations to the mining pool operator.

If Nautilus did not provide hash calculations to the mining pool operator, no consideration was earned by Nautilus nor did Nautilus incur any penalties from the mining pool operator.

The Bitcoin earned by Nautilus was all variable noncash consideration.

Accordingly, Nautilus recognized revenue that was 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 and no Bitcoin mining revenues have been generated since that time.

Unrealized gain (loss) on derivative instruments.

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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 costs include:

(i) the costs incurred by Talen-owned generation facilities for the conversion of natural gas, coal, and (or) oil products to electricity, and (ii) the periodic amortization (through contract expiry) of the acquisition date fair value of acquired executory fuel supply contracts.

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.

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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.

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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.

See Notes 2 and 11 for additional information on the presentation of derivative contracts and fair value measurements, respectively.

Operation, Maintenance and Development.

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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.

Development expenses incurred were primarily related to pre-commercial activities at Nautilus and hyperscale construction activities at Cumulus Digital.

Stock-Based Compensation.

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Dividends and dividend equivalents are subject to the same vesting and forfeiture provisions as the underlying awards.

Liability classified awards that settle in cash, or include an election to be settled in cash, are remeasured at fair value through settlement or maturity and presented as “Stock-based compensation liabilities” on the Consolidated Balance Sheets.

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.

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See Note 4 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.

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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.

Cash and cash equivalents, including cash deposits supporting the Company’s commodity exchange activities, that are contractually restricted are presented as “Restricted cash and cash equivalents” on the Consolidated Balance Sheets.

See Note 16 for additional information.

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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 it becomes known that a specific customer may not have the ability 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.

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See Note 5 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.

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Such capitalized amounts include interest costs, where appropriate.

Facilities, land, and other equipment acquired in a business combination is recognized at fair value.

Facilities, land, and other equipment acquired in a business combination are recognized at acquisition date 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.

Reductions in the carrying value of PP&E are accumulated over the estimated useful life of each depreciable unit using group or straight-line depreciation methods.

Such periodic reduction is presented as a charge to “Depreciation, amortization and accretion” on the Consolidated Statements of Operations.

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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.

See Note 17 for information on recent business combinations.

Expenditures for intangible assets such as contractual rights, software development costs, and long-term operating 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 “Impairment” below for additional information regarding impairments of the carrying values of PP&E.

See Note 7 for additional information on PP&E.

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.

PP&E used in operations are assessed for impairment when 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 management’s decisions regarding strategic initiatives.

Where applicable, individual assets are grouped for impairment analysis 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 recoverable, 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 carrying value of 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.

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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.

ARO liabilities increase 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.

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Contingencies.

Management continuously assesses potential loss contingencies for environmental remediation, litigation claims, regulatory penalties and other events.

Potential loss contingencies may result from environmental remediation, litigation claims, regulatory penalties or other events.

Potential losses are accrued when:

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Loss contingencies exclude estimates for any legal fees, which are recognized as incurred when the legal services are performed.

Additionally, pursuant to federal and state legislation, the Company assesses the funding associated with certain legacy health care benefit plans for retired mine workers and recognizes expected funding shortfall, if any, as a contingent liability.

See Note 9 for additional information on loss contingencies.

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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.

Service cost is presented as “Operation, maintenance and development” while the other components of net periodic defined benefit cost (credit) for pension and other postretirement plans are presented as “Other non-operating income (expense), net” on the Consolidated Statements of Operations.

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;

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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.

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 12 for additional information on the plans and the accounting for defined benefits.

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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.

There have been no recently adopted accounting pronouncements that had a material effect on the Company’s financials statements and (or) disclosures.

Recent Accounting Pronouncements Not Yet Adopted

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.

In November 2024, the FASB issued ASU 2024-03, Expense Disaggregation Disclosures (Subtopic 220-40):

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The Company is evaluating the disclosure impact of this ASU and expects to adopt it in the required period.

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.

• 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.

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.

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:

Enterprise value (a)

Cash and cash equivalents and Restricted cash and cash equivalents (b)

Current liabilities excluding long-term debt due within one year 514

Non-current liabilities excluding long-term debt and liability-classified warrants 1,234

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:

Enterprise value (a)

Cash and cash equivalents and Restricted cash and cash equivalents (b)

Fair value of debt ( 2,845 )

Liability-classified warrants ( 35 )

Fair value of member’s equity (c)

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.

Includes 59,028,843 shares of TEC common stock and $ 8 million of equity-classified warrants.

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.

Assets Predecessor Reorganization

Adjustments (a)

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.

(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 )

Total uses of Cash and cash equivalents $ ( 1,133 )

__________________

(a) Includes $ 1 million of proceeds from Riverstone for payment to general unsecured creditors trust.

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

(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)

Borrowings of $ 580 million under TLB-1 (b)

Borrowings of $ 470 million under TLC (c)

Reinstatement of PEDFA 2009B Bonds and PEDFA 2009C Bonds (d)

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.

(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

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

Reinstatement and settlements of certain Liabilities subject to compromise

Reinstatement of liabilities subject to compromise (a)

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)

______________

(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

(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 )

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.

(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)

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 .

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.

December 31, 2022

Termination of retail power and other contracts 447

Postretirement benefit obligations (a)

Asset retirement obligations and accrued environmental costs (a)

Other liabilities (a)

Deferred tax liabilities 83

Accounts payable and accrued liabilities 53

Accrued interest 41

Derivatives (a)

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:

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.

In December 2025, the FASB issued ASU 2025-11, Interim Reporting (Topic 270):

Narrow-Scope Improvements.

This ASU provides clarification to certain elements of Topic 270, but does not change the fundamental nature of interim reporting or expand or reduce current interim disclosure requirements.

This ASU is effective for annual periods beginning after December 15, 2027, and interim periods within those annual periods.

Early adoption is permitted.

The Company is evaluating the disclosure impact of this ASU and expects to adopt it in the required period.

Risk Management, Derivative Instruments and Hedging Activities

1 unchanged sentence

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.

The hedging strategies deployed by our commercial and treasury organizations 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.

14 unchanged sentences

Open commodity purchase (sales) derivatives range in maturity through 2027.

The net notional volumes of open commodity derivatives were:

December 31, 2024 (a)

December 31, 2023 (a)

The net notional volumes of commodity derivatives were:

Power (MWh) ( 59,634,723 ) ( 38,615,192 )

2 unchanged sentences

__________________

(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.

(a) The volumes may be different than the contractual volumes, as the probability that option contracts will be exercised is considered in the volumes displayed.

Interest Rate Risk.

2 unchanged sentences

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.

Open interest rate derivatives range in maturity through 2029.

The net notional volumes of open interest rate derivatives were:

December 31, 2024 December 31, 2023

2025 December 31,

Interest rate (in millions)

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.

9 unchanged sentences

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.

The allowance for doubtful accounts was a non-material amount as of December 31, 2025 (Successor) and 2024 (Successor).

As of December 31, 2025 (Successor), Talen’s aggregate credit exposure, which excludes the effects of netting arrangements, cash collateral, LCs, and any allowances for doubtful collections, was $ 652 million and its credit exposure including such netting effects was $ 47 million.

Excluding ISO and RTO counterparties, whose accounts receivable settlements and congestion products are subject to applicable market controls, the ten largest single net credit exposures account for 83 % 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).

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, 2025 (Successor) and 2024 (Successor).

Derivative Instrument Presentation

11 unchanged sentences

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.

Changes in the fair value and realized settlements on interest rate derivative instruments are presented as “Interest expense and other finance charges” on the Consolidated Statements of Operations.

See Note 11 for additional information on fair value of commodity and interest rate derivatives.

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).

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, 2025 (Successor) and 2024 (Successor).

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:

9 unchanged sentences

Successor Predecessor

Year Ended December 31, 2024 May 18 through December 31, 2023 January 1 through May 17, 2023 Year Ended December 31, 2022

Year Ended December 31, 2025 Year Ended December 31, 2024 May 18 through December 31, 2023 January 1 through May 17, 2023

Realized gain (loss) on commodity contracts

5 unchanged sentences

Operating revenues (b)

( 45 ) 42 55 60

Energy expenses (b)

5 unchanged sentences

(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.

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

Year Ended December 31, 2025 Year Ended December 31, 2024 May 18 through December 31, 2023 January 1 through May 17, 2023

Electricity sales and ancillary services, ISO/RTO $ 1,940 $ 1,144 $ 880 $ 281

Capacity revenues 485 192 133 108

Physical electricity sales, bilateral contracts, other 93 147 71 62

2 unchanged sentences

Realized and unrealized gain (loss) on derivative instruments 56 307 179 732

Nuclear PTC (a)

Nuclear PTC — 220 — —

Other revenue 7 14 — —

Operating revenues $ 2,581 $ 2,115 $ 1,344 $ 1,210

__________________

(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 .

Accounts Receivable

“Accounts receivable” presented on the Consolidated Balance Sheets were:

December 31, 2024 December 31, 2023

2025 December 31,

Customer accounts receivable $ 160 $ 66

1 unchanged sentence

Accounts receivable $ 196 $ 123

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.

During the years ended December 31, 2025 (Successor), and 2024 (Successor), there were no significant changes in accounts receivable other than normal receivable recognition and collection transactions.

See Note 2 for additional information on Talen’s credit risk on the carrying value of its receivables.

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.

Talen’s estimated future fixed fee performance obligations primarily include capacity volumes awarded, net of capacity repurchases by the Company, through PJM BRAs and incremental PJM capacity auctions.

See Note 9 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:

As of December 31, 2025 (Successor), future performance obligations that were unsatisfied or partially unsatisfied were:

2026 2027 2028 (a)

2027 2028 2029

Expected capacity revenues $ 478 $ 281 $ 3 $ 1 $ —

Future performance obligations $ 963 $ 1,053 $ 443 $ — $ —

__________________

(a) Estimated through May 31, 2026.

The PJM BRA for the 2026/2027 PJM Capacity Year has been delayed to July 2025.

(a) As PJM BRAs have not yet occurred for periods after the 2027/2028 PJM Capacity Year, there are no future performance obligations after May 31, 2028.

Brandon Shores and H.A.

Wagner RMR Agreements

In May 2025, the FERC approved each of the Brandon Shores and H.A.

Wagner RMR agreements, under which:

(i) Talen will operate the generation facilities in accordance with such arrangements from June 1, 2025 through May 31, 2029, or until such time as the necessary third-party transmission upgrades are placed into service;

(ii) Brandon Shores will earn annual fixed-cost payments of $ 145 million ($ 312 /MWd), inclusive of a $ 5 million per year unit performance “hold back;” (iii) H.A.

Wagner will earn annual fixed-cost payments of $ 35 million ($ 137 /MWd), inclusive of a $ 2.5 million per year unit performance “hold back;” and (iv) each facility will receive separate reimbursement for variable costs and approved project investments.

In August 2025, the Maryland Office of People’s Counsel filed an appeal of the FERC’s order approving the Brandon Shores and H.A.

Wagner RMR agreements.

Talen has intervened in that proceeding and plans to participate.

Additionally, H.A.

Wagner Unit 4 is subject to certain emission restrictions associated with its air permits that limit the Unit’s annual runtime.

In October 2025, the DOE granted PJM’s request, pursuant to Section 202(c) of the Federal Power Act, to renew the DOE’s July order, which allowed Unit 4 to exceed its air permit emission limits for the remainder of the calendar year when Unit 4 was needed to maintain grid reliability.

Such order is subject to extension at the request of PJM and at the discretion of the DOE.

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

Year Ended December 31, 2025 Year Ended December 31, 2024 May 18 through December 31, 2023 January 1 through May 17, 2023

Federal $ 54 $ ( 113 ) $ 3 $ ( 15 )

4 unchanged sentences

Deferred income taxes ( 120 ) 46 ( 55 ) ( 195 )

Investment tax credit — — — 1

Income tax benefit (expense) $ ( 53 ) $ ( 98 ) $ ( 51 ) $ ( 212 )

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 ( 166 ) 1,111 194 677

Effective income tax rate ( 31.9 ) % 8.8 % 26.3 % 31.3 %

Current tax receivable presented as “Other current assets” on the Consolidated Balance Sheets were $ 35 million as of December 31, 2025 (Successor) and non-material as of December 31, 2024 (Successor).

Current tax liabilities presented as “Other current liabilities” on the Consolidated Balance Sheets were non-material as of December 31, 2025 (Successor) and $ 53 million as of December 31, 2024 (Successor).

Effective Tax Rate Reconciliations

The following table presents required disclosures pursuant to ASU 2023-09 and reconciles the U.S.

federal statutory tax amount and rate to our effective tax amount and rate for the year ended December 31, 2025 (Successor):

Year Ended December 31, 2025

Federal income tax at statutory tax rate $ 35 21.0 %

State income taxes, net of federal benefit (a)

Nontaxable or nondeductible items:

Stock-based compensation ( 72 ) ( 43.2 )%

Nuclear PTC ( 2 ) ( 1.2 )%

Other permanent differences ( 1 ) ( 0.6 )%

Changes in valuation allowances ( 2 ) ( 1.2 )%

Other adjustments:

Return to provision 13 7.8 %

Tax on NDT ( 28 ) ( 16.9 )%

Income tax benefit (expense) $ ( 53 ) ( 31.9 )%

Effective tax rate

__________________

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

(a) Pennsylvania state income taxes comprised the majority of the tax effect in this category.

The following table presents the required disclosures prior to our adoption of ASU 2023-09 and reconciles the income tax benefit (expense) at our statutory rate to the income tax benefit (expense) at our effective rate for the following periods:

Successor Predecessor

Year Ended December 31, 2024 May 18 through December 31, 2023 January 1 through May 17, 2023

Income tax benefit (expense) computed at the federal income tax statutory tax rate of 21 %

$ ( 234 ) $ ( 41 ) $ ( 143 )

Income tax increase (decrease) due to:

Change in valuation allowance 128 ( 43 ) 129

State income taxes, net of federal benefit ( 48 ) 1 ( 34 )

Nuclear PTC 46 — —

Nuclear decommissioning trust taxes ( 27 ) ( 16 ) ( 9 )

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

Permanent differences 3 22 ( 16 )

Other — — ( 1 )

2 unchanged sentences

The components of deferred tax liabilities and deferred tax assets were:

December 31, 2024 December 31, 2023

Nuclear decommissioning trust $ 502 $ 443

2025 December 31,

Property, plant and equipment, net $ 1,305 $ 465

Nuclear decommissioning trust 540 502

Unrealized gain on qualifying derivatives — 32

Investment in subsidiaries — 14

Deferred tax liabilities 1,848 999

Interest limitation carryforward 340 336

Federal net operating loss carryforwards 749 164

Accrued pension costs 80 78

Interest limitation carryforward 331 340

Acquired fuel supply contract liabilities (a)

Accrued liabilities 53 30

Accrued pension costs 45 80

State net operating loss carryforwards 19 15

Unrealized loss on qualifying derivatives 16 —

Deferred tax assets 1,364 637

1 unchanged sentence

Deferred tax liabilities, net $ 486 $ 362

__________________

(a) See Note 17 for additional information on acquired fuel supply contract liabilities.

Net Operating Losses

The components of NOL carryforwards were:

December 31, 2024 December 31, 2023

Federal, expirations 2036 - 2037 $ — $ 43

2025 December 31,

Federal, indefinite expiration, limited to annual utilization of 80%

$ 3,566 $ 783

State, expirations 2026 - 2041 407 310

See “Emergence from Restructuring” below for information on limitations on our NOLs.

Income Taxes Paid Net of Refunds

The amounts of income taxes paid, net of refunds, were:

Year Ended December 31, 2025

US Federal - Corporate $ 26

US Federal - NDT 15

Total federal tax 41

Pennsylvania 17

Other states (a)

Total state tax 30

__________________

(a) Consists primarily of New Jersey, Maryland, and Texas.

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.

Unrecognized tax benefits as of December 31, 2025 (Successor) and 2024 (Successor) were a non-material amount.

All tax returns filed for years December 31, 2022 and forward are open to examination by the relevant taxing authorities.

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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.

Upon Emergence, the Company experienced an ownership change under Section 382 of the Internal Revenue Code of 1986, as amended (the “Code”).

The Code’s 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.

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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.

As a result of the assessment, it was determined that it is more likely than not that all federal and most state deferred tax assets will be fully utilized by future taxable income.

As of December 31, 2025 (Successor), the Company’s valuation allowance was non-material.

As of December 31, 2024 (Successor), it was more likely than not that federal and state deferred tax assets would be fully utilized by future taxable income.

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.

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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.

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

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).

December 31, 2024 December 31, 2023

Sale of Nuclear Production Tax Credits

In September 2025, Nuclear PTCs with an aggregate carrying value of $ 202 million were sold to an unaffiliated third party for cash consideration of $ 191 million.

The $ 11 million difference between the carrying value and the sales price resulted in loss presented in “Other operating income (expense), net” on the Consolidated Statements of Operations.

The Company’s Nuclear PTCs remaining after the sale were utilized in reducing federal income taxes payable.

One Big Beautiful Bill Act

In 2025, the One Big Beautiful Bill Act (the “OBBB”) was signed into law.

The OBBB, among other things, makes key elements of the Tax Cuts and Jobs Act permanent, including 100% bonus depreciation, domestic research cost expensing, and the business interest expense limitation.

The Company has included the known effects of the OBBB in its income tax provision .

2025 December 31,

Coal $ 94 $ 92

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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).

Such non-cash charges were non-material for the year ended December 31, 2025 (Successor), the year ended December 31, 2024 (Successor), the period from May 18 through December 31, 2023 (Successor), and $ 37 million for the period from January 1 through May 17, 2023 (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.

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See Note 11 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).

There were no available-for-sale debt securities with credit losses as of December 31, 2025 (Successor) and 2024 (Successor).

As of December 31, 2025 (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:

The aggregate fair value of available-for-sale debt securities with unrealized losses as of December 31, 2025 (Successor) was:

Fair Value Unrealized Losses

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The contractual maturities for available-for-sale debt securities presented on the Consolidated Balance Sheets were:

December 31, 2024 December 31, 2023

2025 December 31,

Maturities within one year $ 23 $ 82

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Successor Predecessor

Year Ended December 31, 2024 May 18 through December 31, 2023 January 1 through May 17, 2023 Year Ended December 31, 2022

Year Ended December 31, 2025 Year Ended December 31, 2024 May 18 through December 31, 2023 January 1 through May 17, 2023

Sales proceeds of NDT funds investments (a)

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Remaining proceeds are reinvested in the NDT.

The net unrealized gains and losses recognized associated with equity securities still held at the end of the reporting periods were:

Successor Predecessor

Year Ended December 31, 2025 Year Ended December 31, 2024 May 18 through December 31, 2023 January 1 through May 17, 2023

Equity securities, unrealized gains (losses) $ 123 $ 74 $ 83 $ 23

Property, Plant and Equipment

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Successor Predecessor

Year Ended December 31, 2024 May 18 through December 31, 2023 January 1 through May 17, 2023 Year Ended December 31, 2022

Year Ended December 31, 2025 Year Ended December 31, 2024 May 18 through December 31, 2023 January 1 through May 17, 2023

Depreciation expense (a)

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Accretion expense (c)

— — ( 1 ) ( 2 )

Other — — — ( 1 )

Depreciation, amortization and accretion $ 279 $ 298 $ 165 $ 200

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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).

Amortization expense related to nuclear fuel contract intangible assets was non-material for the year ended December 31, 2025 (Successor), $ 33 million for the year ended December 31, 2024 (Successor), and $ 53 million for the period from May 18 through December 31, 2023 (Successor).

The carrying value of nuclear fuel contract intangible assets was non-material as of December 31, 2025 (Successor) and 2024 (Successor).

Jointly Owned Facilities

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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.

Under such arrangements, each participant is responsible for funding its proportionate 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 proportionate share of revenues and expenses 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).

The carrying values of Colstrip, Conemaugh, and Keystone were non-material as of December 31, 2025 (Successor) and 2024 (Successor) .

The proportionate share of “Property, plant and equipment, net” related to Susquehanna presented on the Consolidated Balance Sheets was:

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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

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 $ 48 million for the year ended December 31, 2025 (Successor), $ 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).

Nautilus Derecognition

In connection with the revisions to the AWS PPA (i) in June 2025, the Company agreed to cease use of the Nautilus facility, and (ii) in September 2025, the facility lease between the Company and AWS, and the related submetering and supply agreements, were terminated and AWS took possession of the existing facility structures.

Accordingly, during the year ended December 31, 2025 (Successor), the Company derecognized approximately:

(i) $ 15 million of structures and buildings presented as “Property, plant and equipment, net;” (ii) an aggregate $ 44 million of contract intangible assets and lease right-of-use assets presented as “Other noncurrent assets;” (iii) $ 10 million of lease liabilities presented as “Other current liabilities;” and (iv) an aggregate $ 57 million contractual obligations and lease obligations presented as “Other noncurrent liabilities.” The resulting net gain of $ 8 million is presented as “Other operating income (expense), net” on the Consolidated Statements of Operations.

Brandon Shores 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.

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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.

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.

In May 2025, Brandon Shores and H.A.

Wagner consummated RMR agreements which requires the facilities to operate until certain third-party transmission upgrades are placed into service.

See Note 3 for additional information on the Brandon Shores and H.A.

Wagner RMR agreements.

Asset Retirement Obligations and Accrued Environmental Costs

December 31, 2024 December 31, 2023

Certain subsidiaries of the Company have legal retirement obligations for the decommissioning and environmental remediation costs associated with our current and former generation.

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 Company’s most significant obligations are associated with the:

(i) decommissioning of Susquehanna, which the NDT is expected to fund;

and (ii) coal ash disposal units of legacy coal-fired generation facilities which, for certain obligations, the Company has posted surety bonds (some of which have been collateralized with LCs).

The carrying value of these AROs include assumptions of estimated future retirement and remediation cash expenditures, cost escalation rates, probabilistic cash flow models, and discount rates.

The Company may be required to revise or recognize new AROs as a result of regulatory changes by the NRC, EPA, Montana Department of Environmental Quality (the “MDEQ”) or other regulatory entities.

Additionally, revisions may result from scope of work amendments to remediation activities as well as changes to remediation costs and other assumptions.

If the assumptions underlying any ARO estimates do not materialize as expected, actual cash expenditures and costs could be materially different than currently estimated.

2025 December 31,

Asset retirement obligations $ 514 $ 498

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(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.

The changes of the ARO carrying value during the periods were:

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 )

The changes of the ARO carrying value during the period were:

Carrying value January 1, $ 498 $ 464

Obligations settled ( 27 ) ( 13 )

Accretion expense 56 55

Carrying value, December 31, 2023 (Successor) $ 464

Obligations settled ( 13 )

Changes in estimates and (or) settlement dates ( 13 ) ( 17 )

Accretion expense 55

Obligations incurred — 9

Carrying value, December 31, 2024 (Successor) $ 498

Supplemental information for the ARO:

December 31, 2024 December 31, 2023

Supplemental Information

Carrying value, December 31, $ 514 $ 498

The disaggregation of ARO carrying values on the Consolidated Balance Sheets was:

2025 December 31,

Non-nuclear (b)

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(b) Certain obligations are:

(i) partially supported by surety bonds, some of which have been collateralized with cash and (or) LCs;

(i) partially supported by surety bonds, some of which have been collateralized with LCs;

or (ii) partially prefunded under phased installment agreements.

Each joint owner of Susquehanna is obligated to fund their proportional share of Susquehanna's ARO.

Each joint owner of Susquehanna is obligated to fund their proportionate 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.

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Under the most recent calculation in 2024, 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.

Each joint owner of Susquehanna is obligated to fund their proportionate 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.

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See Note 1 for additional information on the measurement of AROs.

Non-nuclear AROs

Non-nuclear AROs are primarily comprised of remediation activities associated with legacy coal-fired generation facilities, particularly Colstrip, Brunner Island, and Montour and includes activities, among others, such as remediation of coal piles, wastewater basins, and ash impoundments and structure removal.

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 has significant AROs associated with 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 be material over the next several years and then at a reduced spending level for several decades.

Talen Montana, along with the other co-owners of Colstrip, periodically work with the MDEQ to update the scope of required remediation, the scope of closure and decommissioning activities, and the associated 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).

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 9 for information on Talen Montana’s requirement to provide financial assurance for certain environmental decommissioning and remediation liabilities related to Colstrip.

Talen Montana's estimate of its proportionate share of the AROs, discounted using a credit adjusted risk-free rate, was $ 90 million and $ 98 million as of December 31, 2025 (Successor) and 2024 (Successor), respectively.

Conditional AROs .

As of December 31, 2025 (Successor), the fair values of certain AROs as a result of the EPA CCR Rule cannot be determined.

See Note 9 for additional information on the EPA CCR Rule and the regulatory timeline that is expected to determine the associated scope of work.

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.

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.

Liabilities related to the remediation were $ 20 million and $ 21 million as of December 31, 2025 (Successor) and 2024 (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 8.4 %.

The undiscounted amount of the liabilities was $ 32 million and $ 34 million as of December 31, 2024 (Successor) and December 31, 2023 (Successor).

The undiscounted amount of the liabilities was $ 30 million and $ 32 million as of December 31, 2025 (Successor) and 2024 (Successor), respectively.

Commitments and Contingencies

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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.

Brunner Island CCR Litigation.

In April 2025, the Center for Biological Diversity (the “CBD”) filed a citizen suit in the U.S.

District Court for the Middle District of Pennsylvania alleging that the Company and its subsidiary, Brunner Island, LLC, have failed to comply with groundwater monitoring and corrective action requirements at Brunner Island’s Ash Basin 5 and have therefore violated the RCRA and the EPA CCR Rule.

The complaint seeks declaratory and injunctive relief.

Talen believes the alleged claims are without merit and that the CBD’s factual and legal conclusions are incorrect.

Talen filed a motion to dismiss the lawsuit which was followed by an amicus brief from the Utility Solid Waste Activities Group in support of Talen’s motion;

briefing on the motion to dismiss was completed on June 30, 2025.

No assurance can be provided as to the outcome of the litigation or its impacts on Talen’s operations.

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.

In connection with the ERCOT Sale, 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.

In January and February 2025, the plaintiffs (in two groups) filed for relief in the Texas Supreme Court, seeking to overturn the lower courts.

In July 2025, the Texas Supreme Court ordered merits briefing by the parties, which has since concluded.

If the Court of Appeals decision is 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.

However, claims filed after Talen’s 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.

Talen cannot predict the effect of an adverse outcome for any such claims.

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.

government to provide for the permanent disposal of commercial spent nuclear fuel (“SNF”), but the government has not yet done so.

Until May 2014, the DOE 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.

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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.

In July 2025, the Company reached an agreement with the DOE for a reimbursement of $ 14 million (reflecting Talen’s 90 % share) related to the 2023-2024 period and received the reimbursement in August 2025.

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;

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 the FERC;

the Federal Communications Commission;

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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 June 2023, the 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 the FERC in October 2023.

In early 2024, the FERC accepted portions of PJM’s proposed market changes and PJM scheduled certain PJM BRAs on a delayed basis.

In September 2024, the Sierra Club and other organizations filed a complaint at the FERC challenging PJM’s rules establishing must-offer exceptions for PJM BRA participation by RMR resources.

In October 2024, PJM announced it had concerns about the 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 the FERC’s approval of to-be-determined market reforms, including but not limited to potential revisions to the treatm ent of RMR resources.

As a result, in October 2024, PJM formally requested, which the FERC approved, six-month delays to the scheduled PJM BRAs for the 2028/2029, and 2029/2030 PJM Capacity Years to June 2026, and December 2026, respectively.

Currently, the auction for the 2030/2031 PJM Capacity Year in May 2027 is scheduled on a non-delayed basis.

Talen can provide no assurance that these or any scheduled PJM BRAs will be held on such dates or at all.

A series of filings aimed at reforming the PJM capacity market were filed at the 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 the FERC to find that PJM’s existing capacity market rules are unjust and unreasonable and to 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 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 PJM Capacity 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.

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.

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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.

In February 2025, the FERC accepted PJM’s proposals in the PJM Capacity Market 205 Proceeding and as a result, the changes to the PJM BRA parameters described above as part of that proceeding were adopted for the 2026/2027 and 2027/2028 PJM Capacity Years.

In December 2024, the Pennsylvania Governor filed a complaint against PJM at the FERC to address alleged elevated costs to consumers from the PJM capacity market in the 2026/2027 and 2027/2028 PJM Capacity Years and proposed, among other things, a lower capacity price cap.

As a result of a subsequent agreement between the State of Pennsylvania and PJM that resolved the Governor’s complaint, the Governor withdrew the complaint in February 2025.

In April 2025, the FERC accepted PJM’s proposals reflecting its agreement with the Com monwealth of Pennsylvania.

As a result, the PJM BRA imposed a price collar with an approximate minimum and maximum price of $ 175 /MWd and $ 325 /MWd, respectively, which was effective for the 2026/2027 PJM BRA in July 2025 and for the 2027/2028 PJM BRA in December 2025.

It is uncertain whether price collars will be in effect for future PJM BRAs.

In February 2025, the FERC initiated a technical conference docket to consider broad resource adequacy issues across all RTOs, with the initial proceedings taking place in June 2025.

The Company has intervened in the new technical conference docket and is closely monitoring those proceedings.

Interconnection of Large Loads.

In October 2025, DOE directed the FERC to consider reforms to expedite and facilitate how large loads interconnect to the interstate transmission system.

DOE stated that the Federal Power Act permits the FERC to exert jurisdiction over load interconnections even though it has not historically done so.

DOE provided a draft advance notice of proposed rulemaking (“ANOPR”) and directed the FERC to initiate rulemaking procedures.

In November 2025, the FERC requested public comment on the ANOPR, and the Company provided comments.

DOE directed the FERC to take final action by the end of April 2026.

In August 2025, PJM began an accelerated process known as a Critical Issue Fast Path (“CIFP”) process with stakeholders to address how to integrate large load customers quickly and reliably.

The CIFP stakeholders represented a wide range of views about resource allocations, costs, and how the addition of large loads like data centers to PJM should be managed in the context of the capacity market.

The Company was an active participant in the CIFP process and submitted a joint proposal amongst itself, Constellation, Calpine, Amazon, Microsoft, and Google representing the group’s collective views on the best approach to large load additions.

Neither the joint proposal nor any of the other proposals submitted received broad stakeholder support during voting.

Nevertheless, PJM had planned to make a filing at the FERC in January 2026 containing PJM’s ultimate proposal to be in place for the 2028/2029 PJM BRA.

In December 2025, however, the FERC issued an order in a show cause proceeding on large loads co-located with generation.

The FERC directed PJM to submit an informational report containing, among other items, all of the CIFP proposals.

The FERC also found that the PJM tariff was unjust and unreasonable as to the interconnection of co-located loads.

The FERC requested tariff revisions be submitted over the next 30-60 days and established a hearing schedule, which begins in February 2026, to establish rates, terms, and conditions of several new transmission services.

In January 2026, the National Energy Dominance Council (“NEDC”) and the Governors from each of the 13 states in PJM issued a “Statement of Principles” for PJM.

Among other things, the statement calls for PJM to conduct a reliability backstop auction for new baseload capacity with 15-year contracts by September 2026.

It also urges PJM to extend the existing price collar for the next two BRAs.

Hours after the NEDC/Governors’ principles were released, the PJM Board of Managers issued a Board Decisional Letter — the final step in the Large Load Addition CIFP process.

The Board’s Decisional Letter adopted specific elements of various proposals, including load forecasting improvements, voluntary bring your own generation paired with an expedited interconnection track, a holistic review in the coming year of investment incentives in PJM’s markets, and immediate initiation of a reliability backstop procurement.

PJM also requested feedback on an extension of the price collar for the next two BRAs.

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.

Extensive federal, state, and local environmental laws and regulations are applicable to our business, including those related to air emissions, water discharges, hazardous substances, and solid waste management.

From time to time, in the ordinary course of our business, Talen may be:

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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.

Consequently, in March 2025, the EPA announced that it will reconsider and potentially roll back 31 regulations and policies, many of which directly impact Talen, and various executive actions were taken in April 2025 to further encourage deregulation.

The EPA’s reconsiderations for many of these regulations and policies remain ongoing, and certain executive orders have subsequently been challenged by states and individual plaintiffs.

Future provisions, implementation, and enforcement of these executive actions and the environmental rules continue to be uncertain.

Further, costs may increase significantly if the requirements or scope of environmental laws or regulations, or similar rules, are expanded or changed in other ways.

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.

In 2015, the EPA revised the 8-hour ozone National Ambient Air Quality Standards for ground-level ozone to 70 parts per billion (the “EPA 2015 Ozone Standard”).

This action 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 (the “Good Neighbor Plan”).

Talen’s facilities in Maryland, Pennsylvania, and New Jersey were subject to the new rule;

however, the entire rule was challenged by multiple parties, and subsequently 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.

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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.

After initially denying the EPA’s request in February 2025, the D.C.

Circuit Court of Appeals in April 2025, granted the EPA’s motion requesting the Good Neighbor Plan litigation be held in abeyance pending the EPA’s review of the stayed rule and further orders by the court.

As a result, future implementation and enforcement of the Good Neighbor Plan has continued to be uncertain.

In January 2026, the EPA proposed Phase 1 of its reconsideration of the Good Neighbor Plan.

In its proposal, the EPA proposes to approve state implementation plan submissions governing interstate emissions from eight states (Alabama, Arizona, Kentucky, Minnesota, Mississippi, Nevada, New Mexico, and Tennessee).

If finalized, these states would no longer be subject to Good Neighbor Plan requirements.

Although Talen does not operate in any of the states identified in the proposed rule, EPA in its proposal states that it intends to undertake a separate action to address interstate transport obligations for the remaining states covered under the Good Neighbor Plan.

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.

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) (the “2024 EPA MATS Rule”).

In February 2026, however, the EPA issued a subsequent final rule repealing the lower particulate matter standards set in the 2024 amendments and reverting to particulate matter standards promulgated in the 2012 EPA MATS Rule (the “MATS Repeal Rule”).

Challenges to the 2024 EPA MATS Rule were 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.

The appeal on the merits of the 2024 rule remains pending in the D.C.

Circuit Court of Appeals, but the litigation has been held in abeyance since February 2025, while the EPA reconsidered the rule.

As a result of the EPA’s MATS Repeal Rule, the litigation over the 2024 EPA MATS Rule will likely be deemed moot.

However, challenges to the MATS Repeal Rule are expected.

No assurance can be provided as to whether the MATS Repeal Rule will survive judicial challenge and when such challenges will be resolved.

Colstrip was not expected to meet the 2024 particulate matter standard without substantial upgrades to its control equipment.

As a result, if the MATS Repeal Rule is vacated by a court or reconsidered by the EPA in the future, Talen Montana and the other Colstrip co-owners will face the decision either to invest in new cost-prohibitive control equipment or retire the Colstrip facility.

Such a decision must be evaluated in conjunction with other compliance requirements.

In March 2025, the EPA formally announced that it was reconsidering the 2024 EPA MATS Rule as part of its deregulation agenda.

Concurrently, the Trump administration announced it was considering a two-year exemption from compliance obligations via Section 112(i)(4) of the Clean Air Act for affected power plants while the EPA reconsidered the rule.

Talen applied for the exemption, which was granted in April 2025.

This authorization affords more time for the Colstrip owners to consider the operational future of Colstrip.

Environmental groups filed separate lawsuits in the D.C.

Circuit Court of Appeals and the U.S.

District Court for D.C., challenging the presidential exemptions issued to Colstrip and other fossil fuel-fired power plants.

On August 5, 2025, the EPA filed a motion in each case requesting the courts hold the litigation in abeyance for six months pending the EPA’s efforts to repeal the 2024 EPA MATS Rule.

Talen filed motions to intervene in both cases on August 8, 2025.

On September 3, 2025, the U.S.

District Court for D.C.

granted the EPA’s motion to hold the case in abeyance for six months and also granted Talen’s motion to intervene.

Plaintiffs filed a motion asking the court to reconsider its decision to hold the case in abeyance.

District Court for D.C.

denied that motion in November 2025.

Circuit Court of Appeals granted the EPA’s motion for an abeyance and Talen’s motion to intervene in October 2025.

The litigation may be deemed moot as a result of the EPA’s MATS Repeal Rule, but no assurance can be provided as to the outcome of this litigation at this time.

The Company could be forced to make operating decisions about the future of Colstrip before clarity is obtained on legal challenges regarding the MATS Repeal Rule and the presidential exemption 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.

In May 2024, the EPA published a rule that establishes carbon dioxide limits for new electric generating units (“EGUs”) and greenhouse gas (“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.

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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.

Such a decision must be evaluated in conjunction with compliance requirements under the May 2024 EPA MATS Rule.

Petitions have been filed in the D.C.

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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.

Circuit Court of Appeals has held the litigation in abeyance since February 2025 to allow the EPA to reconsider the rule.

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.

In June 2025, the EPA released a proposed rule to repeal all GHG emission standards for fossil fuel-fired power plants.

As an alternative, the EPA is proposing a narrow repeal of GHG standards, which would eliminate all emissions guidelines and standards for existing power plants and the Phase 2 GHG emissions standards that would apply to new combustion turbines beginning in 2032.

Under the alternative proposal, Phase 1 GHG emissions standards applicable to new and reconstructed baseload fossil fuel-fired stationary combustion turbines would be retained.

The public comment period on the proposal expired on August 7, 2025.

No assurance can be provided as to whether the rule will be finalized and whether a final rule will survive judicial challenge.

The EPA has also in the past stated its intent to develop GHG regulations for existing natural gas combustion turbines;

however, no rule has been proposed, and no recent statements have been made.

Operating decisions about the future of Colstrip are highly dependent on the fate of the EPA GHG Rule as well as the EPA MATS Rule.

Given the legal and regulatory uncertainties with both rules, it is possible the Company will be required to make decisions about Colstrip’s future before it has clarity about the outcome of litigation and (or) the EPA’s regulations.

GHG Endangerment Finding.

In February 2026, the EPA issued a final rule rescinding its 2009 finding that GHG emissions endanger public health and welfare and repealing all GHG emissions standards for light-, medium-, and heavy-duty vehicles and engines.

The EPA made the 2009 endangerment finding in order to promulgate GHG emission standards for new motor vehicles under Section 202(a) of the Clean Air Act and has subsequently relied on this finding as a basis to regulate other sources of GHGs.

In the final rule, EPA states it must rescind the endangerment finding because it lacks the statutory authority to regulate GHG emissions from vehicles in response to global climate changes concerns.

The EPA does not explicitly state how the rescission impacts its authority to regulate GHG emissions from stationary sources.

However, the final rule acknowledges that EPA has relied on the endangerment finding “to extend the GHG regulatory program to new and existing stationary source performance standards and guidelines for power plants under CAA section 111.” Citizen groups have challenged the final rule in the D.C.

Circuit Court of Appeals.

No assurance can be provided as to whether the rule will survive judicial challenge.

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.

In October 2019, the then-Governor of Pennsylvania signed an executive order directing the Pennsylvania Department of Environmental Protection (the “PADEP”) 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.

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.

The PADEP 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 case.

Oral argument in the case took place in May 2025.

In November 2025, the Pennsylvania legislature passed a budget that included provisions requiring Pennsylvania to withdraw from RGGI.

As a result, the PADEP filed an application to the Pennsylvania Supreme Court requesting to discontinue its appeal.

The Pennsylvania Supreme Court granted the application and dismissed the case on January 6, 2026.

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 November 2015, the EPA revised the effluent limitation guidelines (“ELGs”) 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 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.

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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.

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 its 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 Talen’s 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.

Courts of Appeal by parties that include 15 states, environmental groups, and industry groups, including the Utility Water Act Group (“UWAG”), 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.

Court of Appeals for the Eighth Circuit, which denied requests to stay the rule in October 2024 .

At the EPA’s request, the Eighth Circuit has held the consolidated challenges in abeyance since February 2025 to allow the EPA to reconsider the rule.

In March 2025, the EPA announced that it will revise the EPA ELG Rule as part of its deregulation agenda while considering immediate relief from some of the existing leachate requirements.

In June 2025, the EPA announced that it will issue a proposal in 2025 to extend compliance deadlines under the 2024 EPA ELG Rule and seek information to potentially inform further rulemaking.

In September 2025, the EPA issued a direct final rule extending a short-term deadline and a companion proposal extending many compliance deadlines for the 2024 EPA ELG Rule and providing some flexibility relating to some deadlines in the 2020 ELG Rule.

In November 2025, the EPA issued a notice withdrawing the direct final rule due to the receipt of adverse comments.

The EPA finalized its proposal in December 2025.

Among other things, the final rule extends zero-discharge compliance deadlines established in the 2024 EPA ELG Rule by five years from December 31, 2029 to December 31, 2034.

The extension rule has been legally challenged by environmental groups.

These challenges have been consolidated in the U.S.

Court of Appeals for the Second Circuit.

UWAG has filed a motion to intervene in the consolidated litigation.

In the final rule, the EPA also stated it is considering further rulemaking to revise the regulatory standards in the 2024 EPA ELG Rule.

No assurance can be provided as to whether the EPA’s final rule will be challenged, when the challenges to the EPA ELG Rule merits will be resolved, or whether such changes and 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.

In April 2015, the EPA established regulations under the 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.

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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”).

As a result of the finding, in May 2024, the EPA finalized additional federal CCR regulations effective in November 2024 (the “Legacy CCR Rule”), 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.

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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.

Supreme Court denied a requested stay of the Legacy CCR Rule.

At the EPA’s request, the D.C.

Circuit Court of Appeals has held the case in abeyance since February 2025 to allow the EPA to reconsider the rule.

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.

In March 2025, the EPA announced that it will prioritize the coal ash program by expediting state permit reviews.

The EPA has also announced it will reform the federal CCR Rule and provided in the Legacy CCR Rule litigation proceeding that CCR Rule reforms will be completed in 2026.

As an initial reform step, in February 2026, the EPA issued a final rule extending compliance deadlines for elements in the Legacy CCR Rule, including required applicability assessments, the initiation of new groundwater monitoring detection, and the initiation of unit closure.

No assurance can be provided as to when and how federal CCR regulations will change further, when the legal challenges to the Legacy CCR Rule, how the EPA’s interpretations or further CCR Rule reforms will be resolved, or whether such challenges will be decided in the Company’s favor.

Talen continues to review the Legacy CCR Rule provisions that went into effect in 2024, perform the required applicability assessments, and await additional CCR Rule reforms.

As a result of the EPA’s February 2026 CCRMU Extension Rule, initial facility evaluation reports to identify CCR areas which may become regulated and subject to the rule’s requirements are now due in February 2027.

Following that, site investigation may be required to further investigate applicability, and a subsequent facility report is due in February 2028.

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.

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 Legacy CCR Rule until the Company completes its assessments within the regulatory timeframe.

As of December 31, 2025 (Successor), the Company has recognized cost estimates in complying with the Legacy 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.

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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.

Such AROs or ARO changes could be material and, as a result, may have a material impact on Talen’s operations and (or) financial condition.

In April 2025, a citizen suit was filed in the U.S.

District Court for the Middle District of Pennsylvania alleging that the Company and its subsidiary, Brunner Island, LLC, are in violation of RCRA and the EPA CCR Rule.

See the “Legal Matters” section above for additional information.

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.

In December 2023, a settlement was reached in litigation between Talen and PPL regarding Talen’s claim that a $ 733 million distribution paid to PPL in 2014 left Talen Montana insolvent.

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.

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 period May 18 through December 31, 2023 (Successor) .

Guarantees and Other Assurances

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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.

As of December 31, 2025 (Successor) and 2024 (Successor), the aggregate amount of surety bonds outstanding was $ 228 million and $ 234 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.

The Colstrip AOC specifies an evaluation process between Talen Montana and the Montana Department of Environmental Quality (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.

The aggregate amount of surety bonds posted to the MDEQ on behalf of Talen Montana’s proportionate share of such activities wa s $ 114 million and $ 125 million as of December 31, 2025 (Successor) and 2024 (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.

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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.

Several lawsuits have been brought against the Rosebud Mine challenging permits and approvals to expand its operations.

Talen Montana is not party to these lawsuits but is monitoring the progress of each to assess the impact to its operations.

In the first lawsuit, the Montana Supreme Court in 2023 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.

Department of the Interior to complete an updated Environmental Impact Statement (“EIS”) for a separate expansion project.

In August 2025, the U.S.

Department of Interior issued a supplemental EIS and approved an expansion of operations to authorize the mining of federal coal through 2039.

In the third lawsuit, plaintiffs challenged a water pollution permit authorizing a separate expansion to the mine in 2023.

In September 2025, a Montana State District Court upheld the permit.

Plaintiffs appealed that ruling to the Montana Supreme Court in November 2025.

At this time, Talen cannot predict the effect that an adverse outcome of these lawsuits to Rosebud Mine would have on:

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Interest Rate (a)

December 31, 2024 December 31, 2023

2025 December 31,

6.35 % $ 848 $ 857

TLB-2 6.35 % 842 850

TLB-3 5.67 % 1,200 —

Secured Notes 8.63 % 1,200 1,200

2034 Unsecured Notes 6.25 % 1,400 —

2036 Unsecured Notes 6.50 % 1,290 —

PEDFA 2009B Bonds

PEDFA 2009C Bonds

Cumulus Digital TLF (b)

Total principal 6,911 3,038

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(a) Computed interest rate as of December 31, 2025 (Successor).

(b) See “Recent Transactions” below for additional information on extinguishments of indebtedness.

Long-term debt maturities as of December 31, 2025 (Successor) were:

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(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.

Direct cash borrowings are not permitted under the LCF, which can only be used for LCs.

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

June 2030 May 2030 December 2031 December 2029 December 2026 2009B:

December 2038

December 2037

None Term SOFR Term SOFR Term SOFR None None

Rate, Applicable Margin, and Amortization:

Prepayment Penalty:

Secured Notes June 2030 None 8.625 % per annum fixed rate

No applicable margin

No amortization

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 % through May 31, 2026

On or after June 1 of the following years:

2028 and after:

2034 Unsecured Notes February 2034 None

6.250 % per annum fixed rate

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No amortization

Prior to October 15, 2028:

Redeemable at par plus a customary “make-whole” premium.

40 % redeemable from the proceeds of certain equity offerings at 106.250 %

On or after October 15 of the following years:

2030 and after:

2036 Unsecured Notes February 2036 None

6.500 % per annum fixed rate

No applicable margin

No amortization

Prior to October 15, 2030:

Redeemable at par plus a customary “make-whole” premium.

40 % redeemable from the proceeds of certain equity offerings at 106.500 %

On or after October 15 of the following years:

2032 and after:

TLB-1 May 2030 Term SOFR 2.50 % per annum applicable margin;

leverage-based step-downs to 2.25 % and 2.00 %

Amortization 1.00 % per annum;

paid quarterly

Currently none

TLB-2 December 2031 Term SOFR Same as TLB-1 Currently none

TLB-3 November 2032 Term SOFR

2.00 % per annum applicable margin;

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paid quarterly

Same as TLB-1 Cash borrowings:

1.00 % to the extent prepaid prior to May 25, 2026 in connection with a repricing transaction

RCF December 2029 Term SOFR Cash borrowings:

2.00 % per annum applicable margin;

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No amortization

LCF December 2027 None LCs:

Unused commitments:

5.25 % per annum fixed rate

December 2038

December 2037

None 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:

2028 and after:

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

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Credit Agreement .

The Credit Agreement governs the RCF, TLB-1, TLB-2, and LCF.

The Credit Agreement governs the RCF, TLB-1, TLB-2, TLB-3, 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.

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 on the last day of a fiscal quarter), 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, TLB-2, or TLB-3.

The Credit Agreement also contains customary representations and warranties, events of default, and remedies (including acceleration of amounts due and (or) termination of commitments).

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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 are subject to customary negative covenants for secured notes, 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).

Unsecured Notes.

Interest on the Unsecured Notes is payable semi-annually on February 1 and August 1 of each year and at maturity.

The Unsecured Notes are subject to customary negative covenants for unsecured notes, including but not limited to certain limitations on incurrence of liens and transactions involving the Susquehanna assets, but do not contain any financial covenants.

The Unsecured Notes also contain customary affirmative covenants, events of default, and remedies (including acceleration).

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.

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The secured obligations under the Secured ISDAs were $ 269 million as of December 31, 2025 (Successor).

Security Interests, Guarantees, and Cross-Defaults

Security Interests, Guarantees, Cross-Defaults, and Restrictions on Dividends

Secured Obligations.

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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.

Restrictions on Dividends.

Agreements governing TES’s indebtedness restrict the ability of TES and the Subsidiary Guarantors to pay dividends or distributions or otherwise transfer assets to TEC, subject to certain exceptions.

Notable exceptions include the ability to pay dividends or distributions:

(1) in an amount not to exceed the gr eater of $ 420 million and 40 % of TES’s consolidated adjusted EBITDA, (2) in an unlimited amount so long as TES’s pro forma consolidated total net leverage ratio is less than or equal to 2.5 to 1.0, and (3) in an amount not to exceed the sum of:

(a) the greater of $ 525 million and 50 % of TES’s consolidated adjusted EBITDA, (b) TES’s consolidated adjusted EBITDA minus 140 % of TES’s consolidated interest expense, in each case, for the period from June 1, 2023 through the most recent fiscal quarter (subject to compliance with either (x) a pro forma consolidated total net leverage ratio of less than or equal to 3.75 to 1.0 or (y) a fixed charge coverage ratio greater than or equal to 2.0 to 1.0), (c) equity contributions to TES, and (d) other customary “builder basket” components.

As of December 31, 2025 (Successor), substantially all net assets of TES and the Subsidiary Guarantors were subject to restrictions on dividends.

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.

The Unsecured Notes and 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.

The Subsidiary Guarantors guarantee TES’s obligations under the Unsecured Notes and 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.

2025 Financing Transactions

Freedom and Guernsey Acquisitions Financing.

In October and November 2025, TES completed several financing transactions and used the proceeds from the Unsecured Notes and the TLB-3 to finance the Freedom and Guernsey Acquisitions .

• Unsecured Notes .

(i) $ 1.4 billion in aggregate principal amount of the 2034 Unsecured Notes and (ii) $ 1.3 billion in aggregate principal amount of the 2036 Unsecured Notes.

Drew in full the $ 1.2 billion senior secured term loan B credit facility (the TLB-3), which constitutes a new tranche of term loans separate from TLB-1 and TLB-2.

Increased its existing RCF (including its revolving LC capacity) from $ 700 million to $ 900 million.

Increased its existing $ 900 million LCF to $ 1.1 billion and extended the maturity from December 2026 to December 2027.

Additionally, in November 2025, in connection with the closing of the Freedom and Guernsey Acquisitions, the Company entered into the Fifth Supplemental Indenture to the Secured Notes Indenture and First Supplemental Indentures to each of the Unsecured Notes Indentures to add certain entities as Subsidiary Guarantors of the Secured Notes and Unsecured Notes, respectively.

See Note 17 for additional information on the Freedom and Guernsey Acquisitions.

2024 Financing Transactions

Credit Facilities.

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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.

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.

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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.

See Note 1 for additional descriptions on fair value levels.

The classifications of recurring fair value measurements within the fair value hierarchy were:

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(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.

(b) Includes fixed income funds and real estate investment trusts.

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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).

There were no recurring fair value measurements classified as Level 3 as of December 31, 2025 (Successor) and 2024 (Successor).

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).

See Note 7 for nonrecurring fair value measurements during the year ended December 31, 2025 that are associated with the derecognition of certain Nautilus assets and liabilities.

There were no material 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 7 for information on the nonrecurring fair value measurement of Brandon Shores and Note 20 for information on the nonrecurring fair value measurements resulting in the application of fresh start accounting 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:

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$ 6,811 $ 7,069 $ 3,004 $ 3,120

Other short-term indebtedness (b)

__________________

(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.

Postretirement Benefit Obligations

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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 Talen Montana sponsored defined benefit pension plan was overfunded by a non-material amount as of December 31, 2025 (Successor).

Certain other postretirement plans were overfunded by $ 39 million and $ 36 million as of December 31, 2025 (Successor) and 2024 (Successor), respectively.

Overfunded balances are presented as “Other noncurrent assets” on the Consolidated Balance Sheets.

The current portion of certain unfunded postretirement obligations were non-material.

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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, 2025 Year Ended December 31, 2024

Change in benefit obligation

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Rate of compensation increase 3.45 % 3.45 %

During the year ended December 31, 2025 (Successor) , the decrease in postretirement benefit obligations was primarily attributable to employer contributions and actual returns being higher than expected returns on plan assets.

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, 2025 Year Ended December 31, 2024

Change in benefit obligation

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Actual return on plan assets 5 3

Employer contributions 1 —

Plan participant contributions 2 2

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Rate of compensation increase 4.19 % 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.

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:

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Successor Predecessor

Year Ended December 31, 2024 May 18 through December 31, 2023 January 1 through May 17, 2023 Year Ended December 31, 2022

Year Ended December 31, 2025 Year Ended December 31, 2024 May 18 through December 31, 2023 January 1 through May 17, 2023

Net periodic benefit costs (credits):

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Successor Predecessor

Year Ended December 31, 2024 May 18 through December 31, 2023 January 1 through May 17, 2023 Year Ended December 31, 2022

Year Ended December 31, 2025 Year Ended December 31, 2024 May 18 through December 31, 2023 January 1 through May 17, 2023

Net periodic benefit costs (credits):

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Amortization of prior service cost (credit) ( 4 ) ( 1 ) — —

Amortization of net (gain) loss ( 1 ) — — —

Net periodic defined benefit cost (credit) ( 5 ) ( 1 ) 1 —

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6.50 % to 4.50 %

__________________

(a) Trend rates grading to 2027.

(a) Trend rates based on a 7 year grading period.

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.

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.

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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 contributed $ 62 million and $ 43 million to the TES sponsored pension plan during the years ended December 31, 2025 (Successor) and 2024 (Successor), respectively.

Talen Montana contributed $ 8 million and $ 10 million of discretionary contributions to the Talen Montana sponsored pension plan during the years ended December 31, 2025 (Successor) and 2024 (Successor), respectively.

TES expects to contribute $ 26 million to the TES sponsored pension plan in 2026.

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).

Talen Montana expects to contribute a non material amount to the Talen Montana sponsored pension plan in 2026.

The aggregate benefits paid to pension and other postretirement plan participants was $ 102 million for year ended December 31, 2025 (Successor) and $ 114 million for the year ended December 31, 2024 (Successor).

The forecasted undiscounted benefit payments to plan participants as of December 31, 2025 (Successor) were:

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The weighted-average target asset allocations for the pension plan assets as of December 31, 2025 (Successor) were:

December 31, 2024

Equity securities 31 %

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Liquidity portfolio 4 %

See Note 1 for additional descriptions on fair value levels.

The classifications of pension plan asset fair value measurements within the fair value hierarchy were:

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— — 21 — — 35

Total trust funds ( 15 ) 891 911 52 949 976

Restricted 401(h) assets (b)

— — — — ( 1 )

Total plan assets $ ( 3 ) $ 973 $ 991 $ ( 15 ) $ 891 $ 911

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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.

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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:

The target asset allocations for other postretirement benefit assets were:

December 31, 2025

Cash and cash equivalents — %

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Debt securities 90 %

See Note 1 for additional descriptions on fair value levels.

The classifications of other postretirement benefit plan asset fair value measurements within the fair value hierarchy were:

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Commingled debt securities — — 35 35 — — 32 32

Total trust funds 7 18 46 71 8 16 50 74

Restricted 401(h) assets (a)

— — — — — — — 1

Total plan assets $ 6 $ 18 $ 46 $ 70 $ 7 $ 18 $ 46 $ 71

__________________

(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.

Employer contributions to the plans were $ 29 million for the year ended December 31, 2025 (Successor), $ 25 million for the year ended December 31, 2024 (Successor), $ 9 million for the period from May 18 through December 31, 2023 (Successor), and $ 10 million for the period from January 1 through May 17, 2023 (Predecessor).

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.

Stock-based Compensation Expense

Stock-based compensation expense presented as “General and administrative” on the Consolidated Statement of Operations for the periods was:

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

In June 2023, TEC began granting performance stock units (“PSUs”) and restricted stock units (“RSUs”) to certain employees and non-employee directors under the Company’s 2023 Equity Incentive Plan (the “Equity Plan”).

The aggregate number of shares authorized for issuance under the Equity Plan is 7,083,461 shares of common stock.

Equity to Liability Modification

In December 2025, certain executive officers executed agreements providing for certain PSU and RSU awards that are scheduled to vest in 2026 to be partially settled in cash.

Generally, the cash settlement amount will be equal up to 60 % of the net after-tax value on the vesting date of each such award.

However, the cash settlement amount is subject to a cap.

Additionally, all non-employee directors are expected to be offered the ability to net-settle (to account for income taxes) all of their PSUs and RSUs.

Accordingly, the portion of each participant’s applicable awards that are expected to be settled in cash and all non-employee director awards were reclassified from equity to liability.

As a result of the modification, a $ 501 million liability was recognized and presented as “Stock-based compensation liabilities” on the Consolidated Balance Sheets and was measured based on the closing share price of Talen’s common stock of $ 374.84 as of December 31, 2025 (Successor).

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.

PSUs have three-year or two-year cliff vesting schedules or vest upon 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:

Units Weighted-Average

Changes in non-vested PSUs during the year ended December 31, 2025 (Successor) were:

Liability-Classified PSUs Equity-Classified PSUs Total PSUs

Weighted-Average

Fair Value per Unit

Non-vested as of December 31, 2024 (Successor) — 956,347 956,347 $ 54.23

Granted 4,945 96.00

— 102,275 102,275 498.40

Forfeited — ( 288 ) ( 288 ) 645.03

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:

Year Ended December 31, 2024 May 18 through December 31, 2023

Equity to liability modification (b)

569,477 ( 569,477 ) — 53.69

Non-vested as of December 31, 2025 (Successor) (c)

569,477 488,857 1,058,334 $ 147.45

_____________

(a) The weighted-average grant date fair value per unit was $ 96.00 and $ 54.35 for the year ended December 31, 2024 (Successor) and for the period May 18 through December 31, 2023 (Successor), respectively.

(b) See description of December 2025 equity to liability modification above.

Subject to the PSU award agreements, the actual amount of PSUs earned by participants at vesting can range from 0 % to 200 % of the target number of PSUs based on the Company’s stock price performance.

In addition, certain of the PSUs are eligible to earn an additional amount of Talen shares based on the incremental Company stock price performance in excess of the PSU targets.

Assuming all non-vested PSUs vested on December 31, 2025 (Successor) at the then current share price of the Company’s common stock the aggregate non-vested PSUs would be 1,268,275 .

The fair value of PSUs is determined using a Monte Carlo valuation methodology based on the fair value of the underlying stock price at the grant date.

Significant inputs and assumptions used in the valuations of PSUs were:

Year Ended December 31, 2025 Year Ended December 31, 2024 May 18 through December 31, 2023

Volatility (a)

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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.

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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:

Units Weighted-Average

RSUs have three-year ratable or two-year cliff vesting schedules beginning on the grant date, with restrictions on transferring settled shares prior to the final scheduled vesting date for the three-year awards.

The fair value of RSUs granted is based on the closing price of TEC common stock on the grant date.

Changes in non-vested RSUs during the year ended December 31, 2025 (Successor) were:

Liability-Classified RSUs

Equity-Classified RSUs

Weighted-Average

Fair Value per Unit

Non-vested as of December 31, 2024 (Successor) — 549,405 549,405 $ 55.07

Granted 56,346 121.89

— 53,096 53,096 209.82

Forfeited — ( 372 ) ( 372 ) 378.67

Vested — ( 261,476 ) ( 261,476 ) 48.71

Equity to liability modification (b)

169,642 ( 169,642 ) — 61.08

Non-vested as of December 31, 2025 (Successor)

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.

169,642 171,011 340,653 $ 106.18

_____________

(a) The weighted-average grant date fair value per unit was $ 121.89 and $ 48.46 for the year ended December 31, 2024 (Successor) and for the period May 18 through December 31, 2023 (Successor), respectively.

(b) See description of December 2025 equity to liability modification above.

Stock-based Compensation Expense

Stock-based compensation expense presented as “General and administrative” on the Consolidated Statement of Operations was:

Year Ended December 31, 2025 Year Ended December 31, 2024 May 18 through December 31, 2023

Stock-based compensation expense, liability-classified awards $ 501 $ — $ —

Stock-based compensation expense, equity-classified awards 25 33 19

Income tax benefit ( 132 ) ( 8 ) ( 5 )

After-tax stock-based compensation expense $ 395 $ 24 $ 14

Unrecognized stock-based compensation expense and related periods of recognition as of December 31, 2025 (Successor) were:

Equity-Classified

Liability-Classified

Equity-Classified

Liability-Classified

Unrecognized stock-based compensation expense (a)

$ 33 $ 64 $ 9 $ 9

Weighted-average period of recognition (in years) 0.5 0.4 0.6 0.4

__________________

(a) Stock-based compensation expense related to liability-classified awards is subject to variability due to changes in their value through the settlement date.

Earnings Per Share

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Successor Predecessor

Year Ended December 31, 2024 May 18 through December 31, 2023 January 1 through May 17, 2023 Year Ended December 31, 2022

Year Ended December 31, 2025 Year Ended December 31, 2024 May 18 through December 31, 2023 January 1 through May 17, 2023

(Millions of Dollars)

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Net income (loss) attributable to noncontrolling interest — 15 9 ( 14 )

Net Income (Loss) Attributable to Stockholders (Successor) / Member (Predecessor) $ 998 $ 134 $ 479 $ ( 1,289 )

Net Income (Loss) Attributable to Stockholders $ ( 219 ) $ 998 $ 134 $ 479

Weighted-Average Number of Common Shares Outstanding - Basic 45,692 54,254 59,029 —

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Weighted-Average Number of Common Shares Outstanding - Diluted 45,692 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).

Earnings per Share - Basic $ ( 4.79 ) $ 18.40 $ 2.27 N/A

Earnings per Share - Diluted ( 4.79 ) 17.67 2.26 N/A

There were 151,505 RSUs and 1,631,614 PSUs excluded from dilutive EPS for the year ended December 31, 2025 (Successor) because the Company generated a net loss.

No shares were 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.

For the period from January 1 through May 17, 2023 (Predecessor), there were no outstanding shares of common stock.

Stockholders’ Equity

Common Stock Transactions

Share Repurchases and Retirements.

Summary of activity under the SRP and direct repurchases:

Year Ended December 31, 2024

Number of Shares (a) (b)

Share Price (c)

Share Repurchase Program

In September 2025, the Board of Directors approved an increase in the existing capacity of the Company’s SRP from $ 995 million to $ 2 billion and extended the expiration date from December 31, 2026 to December 31, 2028.

These changes to the SRP became effective in November 2025 upon the completion of the Freedom and Guernsey Acquisitions.

The remaining capacity under the SRP as of December 31, 2025 (Successor) was $ 2 billion.

As of December 31, 2025 (Successor), the Company had repurchased approximately 23 % of its outstanding shares of common stock for a total of approximately $ 2 billion, exclusive of transaction costs and excise taxes.

Summary of activity under the SRP:

Year Ended December 31, 2025 Year Ended December 31, 2024

Number of Shares Share Price (a)

Total Amount Number of Shares (b)(c)

Share Price (a)

Share repurchases 452,130 $ 186.24 $ 85 13,227,222 $ 149.50 $ 1,977

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__________________

(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.

(a) Weighted average price per share, including transaction costs and excise taxes.

(b) 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) 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.

As of December 31, 2025 (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

See Note 1 for the accounting policy related to treasury stock and retirement of treasury stock.

Noncontrolling Interests

Purchase of Equity in Nautilus.

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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.

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Successor Predecessor

Year Ended December 31, 2024 May 18 through December 31, 2023 January 1 through May 17, 2023 Year Ended December 31, 2022

Year Ended December 31, 2025 Year Ended December 31, 2024 May 18 through December 31, 2023 January 1 through May 17, 2023

Beginning balance $ ( 12 ) $ ( 23 ) $ — $ ( 167 )

Gains (losses) arising during the period (a)

Gains (losses) arising during the period

21 12 ( 36 ) 6

Reclassifications to Consolidated Statements of Operations (b)

Reclassifications to Consolidated Statements of Operations

Income tax benefit (expense) ( 4 ) ( 1 ) 6 ( 5 )

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Accumulated other comprehensive income (loss) $ ( 4 ) $ ( 12 ) $ ( 23 ) $ —

__________________

(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:

December 31, 2024 December 31, 2023

The components of AOCI, net of tax, as of December 31, were:

Available-for-sale securities unrealized gain (loss), net $ 2 $ ( 3 )

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Accumulated other comprehensive income (loss) $ ( 4 ) $ ( 12 )

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)

Operation, maintenance and development (c)

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).

(d) Postretirement benefit actuarial gain (loss), net.

Reclassification adjustments from AOCI to the Consolidated Statements of Operations were non-material amounts for the years ended December 31, 2025 (Successor) and 2024 (Successor).

The postretirement obligations components of AOCI are not presented in their entirety on the Consolidated Statements of Operations during the periods;

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Successor Predecessor

Year Ended December 31, 2024 May 18 through December 31, 2023 January 1 through May 17, 2023 Year Ended December 31, 2022

Year Ended December 31, 2025 Year Ended December 31, 2024 May 18 through December 31, 2023 January 1 through May 17, 2023

Cash paid during the period

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$ 233 $ 255 $ 133 $ 283

Income taxes, net 20 12 7 14

Income taxes 71 20 12 7

Unrealized (gain) loss on derivative instruments included on the Statements of Cash Flows

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Reconciliation of other non-cash operating activities

Derivative option premium amortization $ 37 $ 11 $ 52 $ 29

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 14 7 17 5

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Non-cash investing activities

Capital expenditure accrual increase (decrease) $ 6 $ 7 $ ( 28 ) 2

Accounts receivable contributed to equity method investment — — — 2

Accrued PP&E additions not paid at period end $ 23 $ 14 $ 13 $ 22

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)

Non-cash increase to PP&E and increase to noncontrolling interest for contribution of Bitcoin miners by TeraWulf (b)

Non-cash increase to PP&E and decrease to other current assets for contribution of Bitcoin miners to Nautilus $ — $ — $ — $ 14

Non-cash decrease to PP&E and decrease to noncontrolling interest for distribution of Bitcoin miners to TeraWulf — 43 — 3

Non-cash increase to PP&E and increase to noncontrolling interest for contribution of Bitcoin miners by TeraWulf — — — 38

__________________

(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.

(a) Capitalized interest was $ 4 million for the year ended December 31, 2025 (Successor), $ 5 million for the year ended December 31, 2024 (Successor), $ 10 for the period from May 18 through December 31, 2023 (Successor), and $ 12 for the period from January 1 through May 17, 2023 (Predecessor).

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:

December 31, 2024 December 31, 2023

The following table provides a reconciliation of “Cash and cash equivalents” and “Restricted cash and cash equivalents” presented on the Consolidated Balance Sheets to such amounts shown on the Consolidated Statements of Cash Flows:

2025 December 31,

Cash and cash equivalents $ 689 $ 328

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

Restricted cash and cash equivalents (a)

__________________

(a) Comprised of commodity exchange margin deposits.

Acquisitions and Divestitures

2024 Activities

2026 Pending Acquisitions

Cornerstone Acquisition.

On January 15, 2026, the Company entered into the Cornerstone Merger Agreement with affiliates of Energy Capital Partners to purchase (i) the Lawrenceburg Power Plant, a 1,120 MW natural gas fired combined cycle generation located in Lawrenceburg, Indiana, (ii) the Waterford Energy Center, a 875 MW natural gas fired combined cycle generation plant located in Waterford Township, Ohio;

and (iii) the Darby Generating Station, a 456 MW natural gas combustion turbine plant located in Mount Sterling, Ohio, for a price of $ 3.45 billion, consisting of $ 2.55 billion in cash, subject to working capital and other customary adjustments, and 2,400,000 shares of Talen common stock, valued at approximately $ 900 million at the time of entry into the Cornerstone Merger Agreement.

The Company expects the cash portion of the purchase price to be funded from the proceeds of new indebtedness.

The acquisition will substantially expand Talen’s presence in the western PJM market and add additional efficient baseload generation assets to its fleet.

The transaction is expected to close early in the second half of 2026 and is subject to the satisfaction of customary closing conditions, including the expiration or termination of the waiting period pursuant to the Hart-Scott-Rodino Act of 1976, and regulatory approvals from the Federal Energy Regulatory Commission, Indiana Utility Regulatory Commission and other regulatory agencies.

2025 Acquisitions

Freedom and Guernsey Acquisitions.

On November 25, 2025, the Company purchased all the ownership interests of Freedom and Guernsey, which increases the Company’s generating capacity by approximately 2.8 GW and provides efficient baseload generation and cash flow diversification.

TES paid an aggregate purchase price of $ 3.8 billion in cash, paid transaction costs of $ 43 million presented as “Other operating income (expense), net” on the Consolidated Statements of Operations, and incurred deferred finance costs and original issuance discounts of $ 64 million presented as “Long-term debt” on the Consolidated Balance Sheets.

See Note 10 for information on recent financing transactions related to the Freedom and Guernsey Acquisitions.

As the acquisition is a business combination, provisional fair value measurements were allocated to acquired assets and assumed liabilities with no resulting goodwill or bargain purchase adjustments.

As such fair value measurements are provisional, revisions may occur up to one year from the date of acquisition as new information is obtained.

The following table summarizes the provisional purchase price allocation for the identifiable assets acquired and liabilities assumed:

Cash and cash equivalents

Accounts receivable 29

Property, plant, and equipment

Fair value of assets acquired

Accounts payable and other accrued liabilities $ 28

Derivative instruments

Other liabilities

Acquired fuel supply contract liabilities

Fair value of liabilities assumed

Aggregate purchase price

The fair values allocated to property, plant, and equipment were determined using the income approach valuation technique that discounted the projected future net cash flows expected to be generated by Freedom and Guernsey over their remaining economic lives utilizing market participant discount rates.

Significant assumptions included the forecasted prices for capacity, wholesale power, and natural gas, volumetric assumptions, and discount rates.

Freedom and Guernsey are each party to long-term natural gas purchase agreements with third parties.

Under the terms of the arrangements, the suppliers each provide a significant amount of the natural gas required to generate power at the facilities and expire in July 2028 for Freedom and February 2033 for Guernsey.

The price paid for natural gas under each contract is variable based on changes to their respective market prices earned for electric generation.

Accordingly, as the wholesale price of power at each facility increases or decreases, the prices paid for fuel under the long-term contracts result in corresponding changes.

As the acquired fuel supply arrangements meet executory contract accounting requirements, their acquisition fair values were measured as of the acquisition date and presented as “Acquired fuel supply contract liabilities” on the Consolidated Balance Sheets.

Such liabilities are expected to amortize as reductions to “Fuel and energy purchases” on the Consolidated Statement of Operations through expiry.

The fair values allocated to acquired fuel supply contracts were determined using the income approach valuation technique that discounted the projected future net cash flows expected to be paid under the long-term fuel contracts through their expiration dates utilizing market participant discount rates.

Significant assumptions included the forecasted prices for wholesale power and natural gas, volumetric assumptions, and discount rates.

Impact of Freedom and Guernsey Acquisitions.

The following table presents revenues and earnings included in the Consolidated Statements of Operations for Freedom and Guernsey since the acquisition date (November 25, 2025) through December 31, 2025 (Successor):

Year ended December 31, 2025

Operating Revenues $ 153

Net Income (Loss) Attributable to Stockholders 62

Pro Forma Financial Information.

The following unaudited pro forma financial information for the years ended December 31, 2025 (Successor) and 2024 (Successor) assumes the Freedom and Guernsey Acquisitions occurred on January 1, 2024.

The unaudited pro forma financial information is provided for information purposes only and is not necessarily indicative of the results of operations that would have occurred had the Freedom and Guernsey Acquisitions been completed on January 1, 2024, nor is the unaudited pro forma financial information indicative of future results of operations.

Year ended December 31, 2025 Year ended December 31, 2024

Operating Revenues $ 3,346 $ 2,704

Net Income (Loss) Attributable to Stockholders ( 146 ) 902

Amortization of Acquired Fuel Supply Contracts.

The acquisition fair value of natural gas fuel supply contracts presented as “Acquired fuel supply contract liabilities” on the Consolidated Balance Sheets is subject to periodic amortization.

Amortization associated with these contracts was $ 6 million for the year ended December 31, 2025 (Successor) and presented as a reduction to “Fuel and energy purchases.”

The estimated future amortization as of December 31, 2025 (Successor) is:

2026 2027 2028 2029 2030 Thereafter (a)

Estimated amortization of acquired fuel supply contract liabilities

$ 93 $ 101 $ 102 $ 83 $ 84 $ 198 $ 661

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(a) Contracts expire in 2028 and 2033.

2025 Divestitures

Camden and Dartmouth Sales.

In September 2025, we sold the Camden and Dartmouth generation facilities to an unaffiliated party for a combined as-adjusted purchase price of $ 25 million in cash, subject to further post-closing adjustments.

A gain on sale of $ 22 million is presented as “Gain (loss) on sale of assets, net” on the Consolidated Statements of Operations for the year ended December 31, 2025 (Successor).

2024 Divestitures

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.

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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

In connection with the AWS Data Campus Sale, the Company entered into the initial AWS PPA.

In June 2025, the Company and AWS entered into a revised AWS PPA, under which the Company is expected to provide AWS with up to 1,920 MW of “front-of-the-meter” power through 2042.

The transition to the revised AWS PPA is expected to occur in Spring 2026.

2023 Divestitures

Western Gas Book Divestiture.

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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.

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.

Adjusted EBITDA is the key profit metric used by the CODM to review segment performance and allocate resources as it provides a clearer view of segment profitability by focusing on operational performance.

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.

“PJM” is engaged in electricity generation, marketing activities, and commodity risk and fuel management within the PJM market and is comprised of Susquehanna and Talen’s natural gas and coal generation facilities in PJM.

“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.

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This grouping is presented to reconcile the reportable segments to our consolidated results.

Financial results for the segments and reconciliation to consolidated results:

PJM Other Corporate and Eliminations Total

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Capital expenditures 195 3 8 206

May 18 through December 31, 2023 (Successor)

Year Ended December 31, 2024 (Successor)

Operating revenues $ 1,866 $ 367 $ ( 118 ) $ 2,115

Operation, maintenance and development expenses (a)

294 78 ( 14 ) 358

Interest expense and other finance charges — — 238 238

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Capital expenditures 164 24 1 189

January 1 through May 17, 2023 (Predecessor)

May 18 through December 31, 2023 (Successor)

Operating revenues $ 1,120 $ 397 $ ( 173 ) $ 1,344

Operation, maintenance and development expenses (a)

245 47 ( 7 ) 285

Interest expense and other finance charges — — 176 176

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Capital expenditures 110 45 6 161

Year ended December 31, 2022 (Predecessor)

January 1 through May 17, 2023 (Predecessor)

Operating revenues $ 1,052 $ 195 $ ( 37 ) $ 1,210

Operation, maintenance and development expenses (a)

519 97 ( 6 ) 610

Interest expense and other finance charges — — 163 163

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(b) Other segment items are primarily comprised of fuel and energy purchases.

Reconciliation of segment Adjusted EBITDA to Net Income (Loss):

Reconciliation of segment Adjusted EBITDA to Income (Loss) Before Income Taxes:

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

Year Ended December 31, 2025 Year Ended December 31, 2024 May 18 through December 31, 2023 January 1 through May 17, 2023

PJM Segment Adjusted EBITDA $ 1,074 $ 775 $ 377 $ 688

Reconciling Items:

Interest expense and other finance charges $ ( 302 ) $ ( 238 ) $ ( 176 ) $ ( 163 )

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 )

Depreciation, amortization and accretion (a)

( 266 ) ( 281 ) ( 157 ) ( 200 )

Nuclear fuel amortization (a)

( 97 ) ( 123 ) ( 108 ) ( 33 )

Reorganization income (expense), net (Note 20) (b)

Unrealized gain (loss) on commodity derivative contracts ( 106 ) 62 52 ( 63 )

Nuclear decommissioning trust funds gain (loss), net 182 178 108 57

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 ) —

Stock-based and other long-term incentive compensation expense (Note 13) (b)

( 535 ) ( 54 ) ( 21 ) —

Gain (loss) on asset sales, net (Note 17) (b)

Non-cash impairments and other charges (c)

( 11 ) ( 24 ) ( 15 ) ( 438 )

Legal settlements and litigation costs

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 )

( 6 ) ( 4 ) 84 ( 1 )

Acquisition and divestiture activities (d)

( 65 ) ( 62 ) — —

Operational and other restructuring activities (e)

( 21 ) ( 9 ) ( 30 ) ( 19 )

"Other" operating segment 32 71 113 37

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Other items ( 8 ) ( 9 ) ( 18 ) ( 21 )

Net Income (Loss) $ 1,013 $ 143 $ 465 $ ( 1,293 )

Form 10- K Table of Contents

Income (Loss) Before Income Taxes $ ( 166 ) $ 1,111 $ 194 $ 677

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(a) Includes the periodic amortization of fair value adjustments associated with acquired executory contracts and intangible assets.

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

See Note 7 for additional information associated with the Brandon Shores impairment group recognized during the period of January 1 through May 17, 2023 (Predecessor).

(d) Includes the non-recurring:

(i) advisory fees associated with completed acquisitions and divestitures;

(ii) remaining settlements on contracts of divested assets;

and (iii) non-recurring finance fees charged to the Consolidated Statement of Operations associated with acquisition financing fee arrangements.

(e) Non-recurring severance and retention costs and strategic initiative costs.

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.

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.

• 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.

See Note 9 for additional information on the PPL/Talen Montana settlement.