TALOS ENERGY INC. 10-K

Item 9A. Controls and Procedures Evaluation of Disclosure Controls and Procedures Our management, with the participation of our chief executive officer and chief financial officer, has evaluated the effectiveness of our disclosure controls and procedures (as defined in Rules 13a- 15(e) and 15d- 15(e) under the Exchange Act) as of the end of the period covered by this Annual Report. Based on such evaluation, our chief executive officer and chief financial officer have concluded that as of December 31, 2025, our disclosure controls and procedures were effective at a reasonable assurance level. Our disclosure controls and procedures are designed at a reasonable assurance level to ensure that information we are required to disclose in reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the rules and forms of SEC, and that such information is accumulated and communicated to our management, including our chief executive officer and chief financial officer, as appropriate, to allow timely decisions regarding required disclosures. Management’s Annual Report on Internal Control over Financial Reporting Our management is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Rule 13a-15(f) under the Exchange Act. Management conducted an assessment of the effectiveness of our internal control over financial reporting based on the criteria set forth in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework). Based on the assessment, management has concluded that its internal control over financial reporting was effective as of December 31, 2025 to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements in accordance with GAAP. Our independent registered public accounting firm, Ernst & Young LLP, has issued an audit report with respect to our internal control over financial reporting, which is included in this Annual Report. 65 Table of Contents Changes in Internal Control over Financial Reporting There were no changes in our internal controls over financial reporting identified in management's evaluation pursuant to Rules 13a-15(d) or 15d-15(d) of the Exchange Act during the fourth quarter of 2025 that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting. Item 9B. Other Information During the three months ended December 31, 2025 , no director or officer of the Company adopted or terminated a “Rule 10b5-1 trading arrangement” or “non-Rule 10b5-1 trading arrangement,” as each term is defined in Item 408(a) of Regulation S-K. Item 9C. Disclosure Regarding Foreign Jurisdictions that Prevent Inspection Not applicable. 66 Table of Contents PART III Item 10. Directors, Executive Officers and Corporate Governance The information required by this item is incorporated by reference to our Proxy Statement for the 2026 Annual Meeting of Stockholders to be filed with the SEC within 120 days of the fiscal year ended December 31, 2025. Our Board of Directors has adopted a Code of Conduct applicable to all officers, directors and employees, which is available on our website ( www.talosenergy.com ) under “Governance Documents” section within the “Governance” tab. We intend to satisfy the disclosure requirement under Item 5.05 of Form 8-K regarding amendment to, or waiver from, a provision of our Code of Conduct by posting such information on the website address and location specified above. The Company has an Insider Trading Policy governing the purchase, sale and other dispositions of the Company's securities that applies to the Company and its directors, officers and employees. The Company believes that its Insider Trading Policy is reasonably designed to promote compliance with insider trading laws, rules and regulations, and listing standards applicable to the Company. A copy of the Company's Insider Trading Policy is included as Exhibit 19.1 to this Annual Report. Item 11. Executive Compensation The information required by this item is incorporated by reference to our Proxy Statement for the 2026 Annual Meeting of Stockholders to be filed with the SEC within 120 days of the fiscal year ended December 31, 2025. Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters. The information required by this item is incorporated by reference to our Proxy Statement for the 2026 Annual Meeting of Stockholders to be filed with the SEC within 120 days of the fiscal year ended December 31, 2025. Item 13. Certain Relationships and Related Transactions, and Director Independence The information required by this item is incorporated by reference to our Proxy Statement for the 2026 Annual Meeting of Stockholders to be filed with the SEC within 120 days of the fiscal year ended December 31, 2025. Item 14. Principal Accountant Fees and Services The information required by this item is incorporated by reference to our Proxy Statement for the 2026 Annual Meeting of Stockholders to be filed with the SEC within 120 days of the fiscal year ended December 31, 2025. 67 Table of Contents PART IV Item 15. Exhibits and Financial Statement Schedules (a) The following documents are filed as part of this Annual Report: (1) Financial Statements: Refer to the Index to Consolidated Financial Statements on page F-1 for a list of all financial statements filed as part of this Annual Report on Form 10-K. (2) Financial Statement Schedules: Other than as stated on the Index to Consolidated Financial Statements on page F-1 with respect to Schedule I, financial statement schedules have been omitted because they are either not material, not required, not applicable or the information required to be presented is included in our Consolidated Financial Statements and related notes. (3) Exhibits: Exhibit Number Description 2.1# Agreement and Plan of Merger, dated as of September 21, 2022, by and among Talos Energy Inc., Talos Production Inc., Tide Merger Sub I Inc., Tide Merger Sub II LLC, Tide Merger Sub III LLC, BCC EnVen Investments, L.P. and EnVen Energy Corporation (incorporated by reference to Exhibit 2.1 to Talos Energy Inc.’s Form 8-K (File No. 001-38497) filed with the SEC on September 22, 2022). 2.2# Agreement and Plan of Merger, dated as of January 13, 2024, by and among Talos Energy Inc., QuarterNorth Energy Inc., Compass Star Merger Sub Inc. and the Equityholder Representatives named therein (incorporated by reference to Exhibit 2.1 to Talos Energy Inc.’s Form 8-K (File No. 001-38497) filed with the SEC on January 16, 2024). 3.1 Second Amended and Restated Certificate of Incorporation of Talos Energy Inc. (incorporated by reference to Exhibit 3.1 to Talos Energy Inc.’s Form 8-K (File No. 001-38497) filed with the SEC on February 14, 2023). 3.2 Certificate of Amendment of the Second Amended and Restated Certificate of Incorporation of Talos Energy Inc. (incorporated by reference to Exhibit 3.1 to Talos Energy Inc.’s Form 8-K (File No. 001-38497) filed with the SEC on May 23, 2024). 3.3 Certificate of Designations of Series A Junior Participating Preferred Stock of Talos Energy Inc. (incorporated by reference to Exhibit 3.1 to Talos Energy Inc.’s Form 8-K (File No. 001-38497) filed with the SEC on October 1, 2024). 3.4 Certificate of Elimination of Certificate of Designations of Series A Junior Participating Preferred Stock of Talos Energy Inc. (incorporated by reference to Exhibit 3.1 to Talos Energy Inc.’s Form 8-K (File No. 001-38497) filed with the SEC on December 17, 2024). 3.5 Second Amended and Restated Bylaws of Talos Energy Inc. (incorporated by reference to Exhibit 3.2 to Talos Energy Inc.’s Form 8-K (File No. 001-38497) filed with the SEC on February 14, 2023). 4.1 Description of Registrant’s Securities Registered Pursuant to Section 12 of the Securities Exchange Act of 1934 (incorporated by reference to Exhibit 4.10 to Talos Energy Inc.’s Form 10-K (File No. 001-38497) filed with the SEC on March 1, 2023). 4.2 Form of Stock Certificate for Common Stock of Talos Energy Inc. (incorporated by reference to Exhibit 4.2 to Talos Energy Inc.’s Amendment No. 1 to the Registration Statement on Form S-4 (File No. 333-222341) filed with the SEC on February 9, 2018) . 4.3 Indenture, dated as of February 7, 2024, by and among Talos Production Inc., the Guarantors named therein and Wilmington Trust, National Association, as trustee (9.000% Senior Notes). (incorporated by reference to Exhibit 4.1 to Talos Energy Inc.’s Form 8-K (File No. 001-38497) filed with the SEC on February 7, 2024). 4.4 First Supplemental Indenture, dated as of March 4, 2024, by and among Talos Production Inc., each of the guarantors party thereto and Wilmington Trust, National Association, as trustee and as collateral agent (9.000% Senior Notes) (incorporated by reference to Exhibit 4.2 to Talos Energy Inc.’s Form 8-K (File No. 001-38497) filed with the SEC on March 5, 2024). 68 Table of Contents 4.5 Indenture, dated as of February 7, 2024, by and among Talos Production Inc., the Guarantors named therein and Wilmington Trust, National Association, (9.375% Senior Notes) (incorporated by reference to Exhibit 4.3 to Talos Energy Inc.’s Form 8-K (File No. 001-38497) filed with the SEC on February 7, 2024). 4.6 First Supplemental Indenture, dated as of March 4, 2024, by and among Talos Production Inc., each of the guarantors party thereto and Wilmington Trust, National Association, as trustee and as collateral agent (9.375% Senior Notes) (incorporated by reference to Exhibit 4.3 to Talos Energy Inc.’s Form 8-K (File No. 001-38497) filed with the SEC on March 5, 2024). 4.7 Form of 9.000% Second-Priority Senior Secured Note due 2029 (included as Exhibit A to Exhibit 4.5 hereto) (incorporated by reference to Exhibit 4.2 to Talos Energy Inc.’s Form 8-K (File No. 001-38497) filed with the SEC on February 7, 2024). 4.8 Form of 9.375% Second-Priority Senior Secured Note due 2031 (included as Exhibit A to Exhibit 4.6 hereto) (incorporated by reference to Exhibit 4.4 to Talos Energy Inc.’s Form 8-K (File No. 001-38497) filed with the SEC on February 7, 2024). 4.9 Amended and Restated Credit Agreement, dated as of January 20, 2026, by and among Talos Production LLC, as borrower, Talos Energy Inc., as holdings, JPMorgan Chase Bank, N.A., as administrative agent, and the lenders named therein (incorporated by reference to Exhibit 10.1 to Talos Energy Inc.’s Form 8-K12 (File No. 001-38497) filed with the SEC on January 22, 2026). 10.1 Intercreditor Agreement, dated as of May 10, 2018, between JPMorgan Chase Bank, N.A., as First Lien Agent, and Wilmington Trust, National Association, as Second Lien Agent (incorporated by reference to Exhibit 10.3 to Talos Energy Inc.’s Form 8-K12B (File No. 001-38497) filed with the SEC on May 16, 2018). 10.2† Employment Agreement, dated as of February 3, 2012, by and between Talos Energy Operating Company LLC and Timothy S. Duncan (incorporated by reference to Exhibit 10.10 to Talos Energy Inc.’s Amendment No. 3 to the Registration Statement on Form S-4 (File No. 333-222341) filed with the SEC on March 30, 2018) . 10.3† Employment Agreement, dated as of August 30, 2013, by and between Talos Energy Operating Company LLC and William S. Moss, III (incorporated by reference to Exhibit 10.14 to Talos Energy Inc.’s Amendment No. 3 to the Registration Statement on Form S-4 (File No. 333-222341) filed with the SEC on March 30, 2018) . 10.4† Separation and Release Agreement by and between the Company and Robert D. Abendschein, effective December 26, 2023 (incorporated by reference to Exhibit 10.1 to Talos Energy Inc.’s Form 8-K (File No. 001-38497) filed with the SEC on December 29, 2023). 10.5† Talos Energy Inc. Long Term Incentive Plan (incorporated by reference to Exhibit 10.4 to Talos Energy Inc.’s Form 8-K12B (File No. 001-38497) filed with the SEC on May 16, 2018). 10.6† Amended and Restated Talos Energy Inc. 2021 Long Term Incentive Plan (incorporated by reference to Exhibit 10.1 to Talos Energy Inc.’s Form 8-K (File No. 001-38497) filed with the SEC on May 23, 2024). 10.7 Contract for the Exploration and Extraction of Hydrocarbons under Production Sharing Modality (Contract Area 7), dated as of September 4, 2015, by and among the National Hydrocarbons Commission, Sierra O&G Exploración y Producción, S. de R.L. de C.V., Talos Energy Offshore México 7, S. de R.L. de C.V. and Premier Oil Exploration and Production Mexico, S.A. de C.V. (incorporated by reference to Exhibit 10.9 to Talos Energy Inc.’s Amendment No. 4 to the Registration Statement on Form S-4 (File No. 333-222341) filed with the SEC on April 4, 2018) . 10.8† Form of Indemnification Agreement (Directors and Officers) (incorporated by reference to Exhibit 10.12 to Talos Energy Inc.’s Form 10-K (File No. 001-38497) filed with the SEC on February 29, 2024). 10.9† Form of Restricted Stock Unit Grant Notice and Restricted Stock Agreement (Directors) (incorporated by reference to Exhibit 10.20 to Talos Energy Inc.’s Form 10-Q (File No. 001-38497) filed with the SEC on August 9, 2018). 10.10† Form of Talos Energy Inc. Long Term Incentive Plan Restricted Stock Unit Grant Notice and Restricted Stock Unit Agreement (Directors) (incorporated by reference to Exhibit 10.1 to Talos Energy Inc.’s Form 10-Q (File No. 001-38497) filed with the SEC on May 6, 2021). 10.11† Form of Talos Energy Inc. 2021 Long Term Incentive Plan Restricted Stock Unit Grant Notice and Restricted Stock Unit Agreement (Directors) (incorporated by reference to Exhibit 10.1 to Talos Energy Inc.’s Form 10-Q (File No. 001-38497) filed with the SEC on November 3, 2021). 69 Table of Contents 10.12† Form of Talos Energy Inc. 2021 Long Term Incentive Plan Restricted Stock Unit Grant Notice and Restricted Stock Unit Agreement (Executives) (incorporated by reference to Exhibit 10.1 to Talos Energy Inc.’s Form 10-Q (File No. 001-38497) filed with the SEC on May 5, 2022). 10.13† Form of Talos Energy Inc. 2021 Long Term Incentive Plan Performance Share Unit Grant Notice and Performance Share Unit Agreement (Executives) (incorporated by reference to Exhibit 10.2 to Talos Energy Inc.’s Form 10-Q (File No. 001-38497) filed with the SEC on May 5, 2022). 10.14† Talos Energy Operating Company LLC Amended and Restated Executive Severance Plan (incorporated by reference to Exhibit 10.1 to Talos Energy Inc.’s Form 8-K (File No. 001-38497) filed with the SEC on March 2, 2020). 10.15† Form of Participation Agreement pursuant to Talos Energy Operating Company LLC Amended and Restated Executive Severance Plan (incorporated by reference to Exhibit 10.2 to Talos Energy Inc.’s Form 8-K (File No. 001-38497) filed with the SEC on October 26, 2020). 10.16† Talos Energy Inc. 2021 Long Term Incentive Plan Restricted Stock Unit Grant Notice and Restricted Stock Unit Agreement (Directors) (incorporated by reference to Exhibit 10.5 to Talos Energy Inc.’s Form 10-Q (File No. 001-38497) filed with the SEC on May 9, 2023). 10.17† Form of Separation and Release Agreement (incorporated by reference to Exhibit 10.4 to Talos Energy Inc.’s Form 10-Q (File No. 001-38497) filed with the SEC on May 7, 2024). 10.18† Separation and Release Agreement by and between Talos Energy Inc. and Timothy S. Duncan, effective November 1, 2024 (incorporated by reference to Exhibit 10.3 to Talos Energy Inc.’s Form 8-K (File No. 001-38497) filed with the SEC on November 4, 2024). 10.19† Performance Share Unit Grant Notice and Performance Share Unit Agreement by and between Talos Energy Inc. and Timothy S. Duncan, effective November 1, 2024 (incorporated by reference to Exhibit 10.4 to Talos Energy Inc.’s Form 8-K (File No. 001-38497) filed with the SEC on November 4, 2024). 10.20 Cooperation Agreement, dated December 16, 2024, by and between Talos Energy Inc. and Control Empresarial de Capitales, S.A. de C.V. (incorporated by reference to Exhibit 10.1 to Talos Energy Inc.’s Form 8-K (File No. 001-38497) filed with the SEC on December 17, 2024). 10.21 Amendment to Cooperation Agreement effective as of December 8, 2025, by and between Talos Energy, Inc. and Control Empresarial de Capitales, S.A. de C.V. (incorporated by reference to Exhibit 10.1 to Talos Energy Inc.’s Form 8-K (File No. 001-38497) filed with the SEC on December 11, 2025). 10.22† Equity Interest Purchase Agreement, dated December 16, 2024, by and between Talos Production Inc. and Zamajal, S.A. de C.V. (incorporated by reference to Exhibit 10.2 to Talos Energy Inc.’s Form 8-K (File No. 001-38497) filed with the SEC on December 17, 2024). 10.23† Offer Letter Agreement, dated February 2, 2025, by and between Talos Energy Inc. and Paul Goodfellow, effective February 2, 2025 (incorporated by reference to Exhibit 10.1 to Talos Energy Inc.’s Form 8-K (File No. 001-38497) filed with the SEC on February 3, 2025). 10.24† Participation Agreement pursuant to Talos Energy Operating Company LLC Amended and Restated Executive Severance Plan (incorporated by reference to Exhibit 10.2 to Talos Energy Inc.’s Form 8-K (File No. 001-38497) filed with the SEC on February 3, 2025). 10.25† Form of Amended and Restated Talos Energy Inc. 2021 Long Term Incentive Plan Restricted Stock Unit Grant Notice and Restricted Stock Unit Agreement (Executives) (2024) (incorporated by reference to Exhibit 10.1 to Talos Energy Inc.’s Form 10-Q (File No. 001-38497) filed with the SEC on November 12, 2024). 10.26† Form of Amended and Restated Talos Energy Inc. 2021 Long Term Incentive Plan Performance Share Unit Grant Notice and Performance Share Unit Agreement (Executives) (2024) (incorporated by reference to Exhibit 10.2 to Talos Energy Inc.’s Form 10-Q (File No. 001-38497) filed with the SEC on November 12, 2024). 10.27† Form of Amended and Restated Talos Energy Inc. 2021 Long Term Incentive Plan Restricted Stock Unit Grant Notice and Restricted Stock Unit Agreement (Executives Retention) (2024) (incorporated by reference to Exhibit 10.3 to Talos Energy Inc.’s Form 10-Q (File No. 001-38497) filed with the SEC on November 12, 2024). 10.28† Form of Amended and Restated Talos Energy Inc. 2021 Long Term Incentive Plan Performance Share Unit Grant Notice and Performance Share Unit Agreement (Stock Price Hurdle) (incorporated by reference to Exhibit 10.1 to Talos Energy Inc.’s Form 10-Q (File No. 001-38497) filed with the SEC on May 6, 2025). 70 Table of Contents 10.29* First Amendment to the Equity Interest Purchase Agreement, dated June 24 2025, by and between Talos Energy LLC, Talos Production Inc., and Zamajal, S.A. de C.V. 10.30* Second Amendment to the Equity Interest Purchase Agreement, dated December 11, 2025, by and between Talos Energy LLC, Talos Production Inc., and Zamajal, S.A. de C.V. 19.1 Talos Energy Inc. Insider Trading Policy (incorporated by reference to Exhibit 19.1 to Talos Energy Inc.’s Form 10-K (File No. 001-38497) filed with the SEC on February 27, 2025). 21.1* List of Subsidiaries of Talos Energy Inc. 23.1* Consent of Ernst & Young LLP. 23.2* Consent of Netherland, Sewell & Associates, Inc. 24.1* Powers of Attorney (included on signature pages of this Part IV). 31.1* Certification of Chief Executive Officer of Talos Energy Inc. pursuant to Rule 13a-14(a)/15d-14(a) of the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. 31.2* Certification of Chief Financial Officer of Talos Energy Inc. pursuant to Rule 13a-14(a)/15d-14(a) of the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. 32.1** Certification of Chief Executive Officer and Chief Financial Officer of Talos Energy Inc. pursuant to 18 U.S.C. § 1350, as adopted pursuant to the Sarbanes-Oxley Act of 2002. 97.1 Talos Energy Inc. Executive Compensation Clawback Policy, effective November 15, 2023 (incorporated by reference to Exhibit 97.1 to Talos Energy Inc.’s Form 10-K (File No. 001-38497) filed with the SEC on February 29, 2024). 99.1* Netherland, Sewell & Associates, Inc. reserve report for Talos Energy Inc. as of December 31, 2025. 101.INS* Inline XBRL Instance. 101.SCH* Inline XBRL Taxonomy Extension Schema With Embedded Linkbase Documents. 104* Cover Page Interactive Data File (Embedded within the Inline XBRL document and included in Exhibit 101) . * Filed herewith. ** Furnished herewith. † Identifies management contracts and compensatory plans or arrangements. # Certain schedules, annexes or exhibits have been omitted pursuant to Item 601(a)(5) of Regulation S-K, but will be furnished supplementally to the SEC upon request. Item 16. Form 10-K Summary None. 71 Table of Contents SIGNATURES Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized. TALOS ENERGY INC. Date: February 24, 2026 By: /s/ Zachary B. Dailey Zachary B. Dailey Executive Vice President and Chief Financial Officer POWER OF ATTORNEY KNOW ALL PERSONS BY THESE PRESENTS, that each person whose signature appears below constitutes and appoints William S. Moss, III and Zachary B. Dailey, and each of them, as his or her true and lawful attorneys-in-fact and agents, with full power of substitution and resubstitution, for him or her and in his or her name, place and stead, in any and all capacities, to sign any and all amendments to this report, and to file the same, with all exhibits thereto, and other documents in connection therewith, with the Securities and Exchange Commission, granting unto said attorneys-in-fact and agents, and each of them, full power and authority to do and perform each and every act and thing requisite and necessary to be done in connection therewith, as fully to all intents and purposes as he or she might or could do in person, hereby ratifying and confirming that all said attorneys-in-fact and agents, or any of them or their or his or her substitute or substitutes, may lawfully do or cause to be done by virtue hereof. Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the dates indicated. Signature Title Date /s/ Paul Goodfellow Chief Executive Officer February 24, 2026 Paul Goodfellow (Principal Executive Officer) /s/ Zachary B. Dailey Chief Financial Officer February 24, 2026 Zachary B. Dailey (Principal Financial Officer, Authorized Signatory) /s/ Gregory Babcock Chief Accounting Officer February 24, 2026 Gregory Babcock (Principal Accounting Officer, Authorized Signatory) /s/ Paula R. Glover Director February 24, 2026 Paula R. Glover /s/ Neal P. Goldman Director February 24, 2026 Neal P. Goldman /s/ John “Brad” Juneau Director February 24, 2026 John “Brad” Juneau /s/ Richard Sherrill Director February 24, 2026 Richard Sherrill /s/ Charles M. Sledge Director February 24, 2026 Charles M. Sledge /s/ Shandell Szabo Director February 24, 2026 Shandell Szabo 72 Table of Contents Index to Consolidated Financial Statement s Reports of Independent Registered Public Accounting Firm (PCAOB ID 42 ) F- 2 Consolidated Balance Sheets as of December 31, 2025 and 2024 F- 5 Consolidated Statements of Operations for the years ended December 31, 2025, 2024 and 2023 F- 6 Consolidated Statements of Changes in Stockholders’ Equity for the years ended December 31, 2025, 2024 and 2023 F- 7 Consolidated Statements of Cash Flows for the years ended December 31, 2025, 2024 and 2023 F- 8 Notes to Consolidated Financial Statements F- 9 Note 1 — Organization, Nature of Business and Basis of Presentation F- 9 Note 2 — Summary of Significant Accounting Policies F- 10 Note 3 — Acquisitions and Divestitures F- 15 Note 4 — Property, Plant and Equipment F- 19 Note 5 — Leases F- 20 Note 6 — Financial Instruments F- 21 Note 7 — Equity Method Investments F- 23 Note 8 — Debt F- 24 Note 9 — Asset Retirement Obligations F- 28 Note 10 — Stockholders’ Equity F- 28 Note 11 — Employee Benefit Plans and Share-Based Compensation F- 28 Note 12 — Income Taxes F- 31 Note 13 — Income (Loss) Per Share F- 33 Note 14 — Related Party Transactions F- 34 Note 15 — Commitments and Contingencies F- 34 Note 16 — Segment Information F- 36 Note 17 — Supplemental Oil and Gas Disclosures (Unaudited) F- 39 Note 18 — Subsequent Events F- 42 Schedule to Consolidated Financial Statements F- 43 Schedule I — Condensed Financial Information of Registrant F- 43 F- 1 Table of Contents Report of Independent Regist ered Public Accounting Firm To the Stockholders and the Board of Directors of Talos Energy Inc. Opinion on the Financial Statements We have audited the accompanying consolidated balance sheets of Talos Energy Inc. (the Company) as of December 31, 2025 and 2024, the related consolidated statements of operations, changes in stockholders' equity and cash flows for each of the three years in the period ended December 31, 2025, and the related notes and financial statement schedule listed in the Index at Item 15(a) (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 at December 31, 2025 and 2024, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2025, in conformity with U.S. generally accepted accounting principles. We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the Company's internal control over financial reporting as of December 31, 2025, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework), and our report dated February 24, 2026 expressed an unqualified opinion thereon. Basis for Opinion These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on the Company’s financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB. We conducted our audits 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 financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the 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 financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion. Critical Audit Matters The critical audit matters communicated below are matters arising from the current period audit of the financial statements that were communicated or required to be communicated to the audit committee and that: (1) relate to accounts or disclosures that are material to the financial statements and (2) 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. Depreciation, depletion and amortization of oil and natural gas properties and full cost ceiling impairment Description of the Matter At December 31, 2025, the net book value of the Company’s proved oil and natural gas properties was $3,949 million, and depreciation, depletion and amortization (DD&A) and the full cost ceiling impairment of oil and natural gas properties were $1,054 million and $454 million, respectively for the year then ended. As described in Note 2 to the consolidated financial statements, the Company follows the full cost method of accounting for its oil and gas properties. Depreciation, depletion and amortization (DD&A) of the cost of proved oil and gas properties is calculated using the unit-of-production method based on proved oil and natural gas reserves, as estimated by independent petroleum engineers. The Company’s capitalized costs are limited to a ceiling based on the present value of future net revenues from proved oil and natural gas reserves, discounted at 10%. Proved oil and gas reserves are prepared using standard geological and engineering methods generally recognized in the petroleum industry based on evaluations of estimated in-place hydrocarbon volumes using financial and non-financial inputs. Judgment is required by the independent and internal petroleum engineers (“engineers”) in estimating proved oil and natural gas reserves. Estimating reserves also requires the selection and evaluation of inputs, including historical production, oil and natural gas price assumptions, operating and capital costs assumptions, among others. Because of the complexity involved in estimating oil and natural gas reserves, management engaged independent petroleum engineers to prepare the proved oil and natural gas reserve estimates for all properties as of December 31, 2025. F- 2 Table of Contents Auditing the Company’s DD&A expense and full cost ceiling impairment calculations is complex because of the use of the work of engineers and the evaluation of management’s determination of the inputs described above used by the engineers in estimating proved oil and natural gas reserves. How We Addressed the Matter in Our Audit We obtained an understanding, evaluated the design, and tested the operating effectiveness of the Company’s controls that address the risks of material misstatement relating to the DD&A expense and the full cost ceiling impairment calculations for oil and natural gas properties, including management’s controls over the completeness and accuracy of the financial data and inputs used by the engineers for use in estimating proved oil and natural gas reserves. Our audit procedures included, among others, evaluating the professional qualifications and objectivity of the engineers responsible for the preparation of the reserve estimates. We tested the completeness and accuracy of the financial data and inputs used by the engineers in the estimation of proved oil and natural gas reserves by agreeing significant inputs to source documentation, and assessing the inputs for reasonableness based on review of corroborative evidence and consideration of any contrary evidence. Additionally, we performed analytic and lookback procedures on select inputs to the proved oil and natural gas reserve estimate. We also tested the DD&A expense and full cost ceiling impairment calculations for oil and natural gas properties to assess whether they are based on the appropriate proved oil and natural gas reserve volumes as estimated by the engineers. Asset retirement obligations Description of the Matter At December 31, 2025, asset retirement obligations total $1,332 million. As described in Note 2 and 9 of the consolidated financial statements, the Company records a liability for the asset retirement obligation at fair value in the period in which it is incurred. The retirement obligations are periodically adjusted to reflect changes in the expected cash flows resulting from revisions to the estimates of either the timing or amount of the retirement costs. Due to the complexity involved in estimating the expected cash outflows, management used decommissioning engineers to estimate the expected cash outflows for the Company’s asset retirement obligation as of December 31, 2025. Auditing management’s accounting for retirement obligations was especially challenging as significant judgment is required by the Company in determining the obligations. The significant judgment was primarily related to the inherent estimation uncertainty relating to the expected cash outflows, extent of future asset retirement activities and the timing of asset retirement activities. How We Addressed the Matter in Our Audit We obtained an understanding, evaluated the design, and tested the operating effectiveness of the controls over the Company’s accounting for asset retirement obligations, including the controls over management’s review of the significant assumptions described above. To test the asset retirement obligations, among other procedures, we evaluated the methodology, tested the significant assumptions described above and tested the completeness and accuracy of the underlying data used by the Company in estimating the expected cashflows. To assess the estimates of asset retirement activities and cash flows, we evaluated significant changes from the prior estimate, analyzed consistency between the timing of asset retirement activities and projected productive life of the properties, compared cost rates against third-party information or internal cost records and recalculated management’s estimate. We involved our asset retirement specialists to assist in our evaluation of the expected cash outflows for asset retirement obligation. /s/ Ernst & Young LLP We have served as the Company’s auditor since 2010. Houston, Texas February 24, 2026 F- 3 Table of Contents Report of Independent Registered Public Accounting Firm To the Stockholders and the Board of Directors of Talos Energy Inc. Opinion on Internal Control Over Financial Reporting We have audited Talos Energy Inc.’s internal control over financial reporting as of December 31, 2025, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) (the COSO criteria). In our opinion, Talos Energy Inc. (the Company) maintained, in all material respects, effective internal control over financial reporting as of December 31, 2025, based on the COSO criteria. We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated balance sheets of the Company as of December 31, 2025 and 2024, the related consolidated statements of operations, changes in stockholders’ equity and cash flows for each of the three years in the period ended December 31, 2025, and the related notes and financial statement schedule listed in the Index at Item 15(a) and our report dated February 24, 2026 expressed an unqualified opinion thereon. Basis for Opinion The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Management’s Annual Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the 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 in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion. 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 (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) 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 (3) 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. /s/ Ernst & Young LLP Houston, Texas February 24, 2026 F- 4 Table of Contents TALOS ENERGY INC. CONSOLIDATED B ALANCE SHEETS (In thousands, except share amounts) Year Ended December 31, 2025 2024 ASSETS Current assets: Cash and cash equivalents $ 362,809 $ 108,172 Accounts receivable, net 323,058 404,258 Assets from price risk management activities 54,420 33,486 Prepaid assets 83,080 77,487 Other current assets 17,939 35,980 Total current assets 841,306 659,383 Property and equipment: Proved properties 10,621,012 9,784,832 Unproved properties, not subject to amortization 480,555 587,238 Other property and equipment 22,643 35,069 Total property and equipment 11,124,210 10,407,139 Accumulated depreciation, depletion and amortization ( 6,686,575 ) ( 5,191,865 ) Total property and equipment, net 4,437,635 5,215,274 Other long-term assets: Restricted cash 76,181 106,260 Assets from price risk management activities — 253 Equity method investments 112,382 111,269 Other well equipment 49,307 58,306 Notes receivable, net 19,636 17,748 Operating lease assets 9,214 11,294 Other assets 6,396 12,008 Total assets $ 5,552,057 $ 6,191,795 LIABILITIES AND EQUITY Current liabilities: Accounts payable $ 92,979 $ 117,055 Accrued liabilities 290,223 326,913 Accrued royalties 59,768 77,672 Current portion of asset retirement obligations 112,489 97,166 Liabilities from price risk management activities 6,708 6,474 Accrued interest payable 48,972 49,084 Current portion of operating lease liabilities 3,657 3,837 Other current liabilities 29,925 44,854 Total current liabilities 644,721 723,055 Long-term liabilities: Long-term debt 1,226,189 1,221,399 Asset retirement obligations 1,219,639 1,052,569 Liabilities from price risk management activities — 3,537 Operating lease liabilities 11,956 15,489 Other long-term liabilities 281,429 416,041 Total liabilities 3,383,934 3,432,090 Commitments and contingencies (Note 15) Equity: Talos Energy Inc. stockholdersʼ equity: Preferred stock; $ 0.01 par value; 30,000,000 shares authorized and zero shares issued or outstanding as of December 31, 2025 and 2024, respectively — — Common stock; $ 0.01 par value; 270,000,000 shares authorized; 188,530,052 and 187,434,908 shares issued as of December 31, 2025 and 2024, respectively 1,885 1,874 Additional paid-in capital 3,296,643 3,274,626 Accumulated deficit ( 918,400 ) ( 424,110 ) Treasury stock, at cost; 20,015,369 and 7,417,385 shares as of December 31, 2025 and 2024, respectively ( 212,144 ) ( 92,685 ) Total Talos Energy Inc. stockholders' equity 2,167,984 2,759,705 Noncontrolling interest 139 — Total equity 2,168,123 2,759,705 Total liabilities and equity $ 5,552,057 $ 6,191,795 See accompanying notes. F- 5 Table of Contents TALOS ENERGY INC. CONSOLIDATED S TATEMENTS OF OPERATIONS (In thousands, except per share amounts) Year Ended December 31, 2025 2024 2023 Revenues: Oil 1,560,401 $ 1,806,148 $ 1,357,732 Natural gas 169,445 105,528 68,034 NGL 50,224 61,892 32,120 Total revenues 1,780,070 1,973,568 1,457,886 Operating expenses: Lease operating expense 546,716 566,041 389,621 Production taxes 418 1,377 2,451 Depreciation, depletion and amortization 1,056,281 1,023,558 663,534 Impairment of oil and natural gas properties 454,482 — — Accretion expense 125,296 117,604 86,152 General and administrative expense 155,368 201,517 158,493 Other operating (income) expense 1,789 ( 109,454 ) ( 52,155 ) Total operating expenses 2,340,350 1,800,643 1,248,096 Operating income (expense) ( 560,280 ) 172,925 209,790 Interest expense ( 163,381 ) ( 187,638 ) ( 173,145 ) Price risk management activities income (expense) 105,455 ( 1,458 ) 80,928 Equity method investment income (expense) ( 1,807 ) ( 10,289 ) ( 3,209 ) Other income (expense) 15,520 ( 44,930 ) 12,371 Net income (loss) before income taxes ( 604,493 ) ( 71,390 ) 126,735 Income tax benefit (expense) 109,169 ( 5,003 ) 60,597 Net income (loss) $ ( 495,324 ) $ ( 76,393 ) $ 187,332 Net income (loss) attributable to noncontrolling interest ( 1,034 ) — — Net income (loss) attributable to Talos Energy Inc. $ ( 494,290 ) $ ( 76,393 ) $ 187,332 Net income (loss) per share attributable to common stockholders: Basic $ ( 2.82 ) $ ( 0.44 ) $ 1.56 Diluted $ ( 2.82 ) $ ( 0.44 ) $ 1.55 Weighted average common shares outstanding: Basic 175,136 175,605 119,894 Diluted 175,136 175,605 120,752 See accompanying notes. F- 6 Table of Contents TALOS ENERGY INC. CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS’ EQUITY (In thousands, except share amounts) Talos Energy Inc. Stockholders' Equity Common Stock Additional Paid-In Capital Accumulated Deficit Common Stock Held in Treasury Total Stockholders' Equity Noncontrolling Interest Total Equity Balance at December 31, 2022 $ 826 $ 1,699,799 $ ( 535,049 ) $ — $ 1,165,576 $ — $ 1,165,576 Equity-based compensation — 25,008 — — 25,008 — 25,008 Equity-based compensation tax withholdings — ( 7,459 ) — — ( 7,459 ) — ( 7,459 ) Equity-based compensation stock issuances 11 ( 11 ) — — — — — Issuance of common stock for acquisition (Note 3) 438 831,760 — — 832,198 — 832,198 Purchase of treasury stock — — — ( 47,504 ) ( 47,504 ) — ( 47,504 ) Net income (loss) — — 187,332 — 187,332 — 187,332 Balance at December 31, 2023 1,275 2,549,097 ( 347,717 ) ( 47,504 ) 2,155,151 — 2,155,151 Equity-based compensation — 21,987 — — 21,987 — 21,987 Equity-based compensation tax withholdings — ( 6,206 ) — — ( 6,206 ) — ( 6,206 ) Equity-based compensation stock issuances 11 ( 11 ) — — — — — Issuance of common stock for acquisition (Note 3) 243 322,387 — — 322,630 — 322,630 Issuance of common stock (Note 10) 345 387,372 387,717 — 387,717 Purchase of treasury stock — — — ( 45,181 ) ( 45,181 ) — ( 45,181 ) Net income (loss) — — ( 76,393 ) — ( 76,393 ) — ( 76,393 ) Balance at December 31, 2024 1,874 3,274,626 ( 424,110 ) ( 92,685 ) 2,759,705 — 2,759,705 Equity-based compensation — 25,616 — — 25,616 — 25,616 Equity-based compensation tax withholdings — ( 3,588 ) — — ( 3,588 ) — ( 3,588 ) Equity-based compensation stock issuances 11 ( 11 ) — — — — — Issuance of common stock for acquisition (Note 3) — — — — — — — Issuance of common stock (Note 10) — — — — — — — Initial consolidation of subsidiary — — — — — 1,173 1,173 Purchase of treasury stock — — — ( 119,459 ) ( 119,459 ) — ( 119,459 ) Net income (loss) — — ( 494,290 ) — ( 494,290 ) ( 1,034 ) ( 495,324 ) Balance at December 31, 2025 $ 1,885 $ 3,296,643 $ ( 918,400 ) $ ( 212,144 ) $ 2,167,984 $ 139 $ 2,168,123 Common Stock Share Activity Issued Held in Treasury Outstanding Balance at December 31, 2022 82,570,328 — 82,570,328 Equity-based compensation stock issuances 1,110,143 — 1,110,143 Issuance of common stock for acquisitions 43,799,890 — 43,799,890 Purchase of treasury stock — ( 3,400,000 ) ( 3,400,000 ) Balance at December 31, 2023 127,480,361 ( 3,400,000 ) 124,080,361 Equity-based compensation stock issuances 1,105,095 — 1,105,095 Issuance of common stock for acquisitions 24,349,452 — 24,349,452 Issuance of common stock 34,500,000 — 34,500,000 Purchase of treasury stock — ( 4,017,385 ) ( 4,017,385 ) Balance at December 31, 2024 187,434,908 ( 7,417,385 ) 180,017,523 Equity-based compensation stock issuances 1,095,144 — 1,095,144 Purchase of treasury stock — ( 12,597,984 ) ( 12,597,984 ) Balance at December 31, 2025 188,530,052 ( 20,015,369 ) 168,514,683 See accompanying notes. F- 7 Table of Contents TALOS ENERGY INC. CONSOLIDATED STATEM ENTS OF CASH FLOWS (In thousands) Year Ended December 31, 2025 2024 2023 Cash flows from operating activities: Net income (loss) $ ( 495,324 ) $ ( 76,393 ) $ 187,332 Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities Depreciation, depletion, amortization and accretion expense 1,181,577 1,141,162 749,686 Impairment of oil and natural gas properties 454,482 — — Amortization of deferred financing costs and original issue discount 8,359 9,303 15,039 Equity-based compensation expense 18,418 14,462 12,953 Price risk management activities (income) expense ( 105,455 ) 1,458 ( 80,928 ) Net cash received (paid) on settled derivative instruments 81,471 4,710 ( 9,457 ) Equity method investment (income) expense 1,807 10,289 3,209 Loss (gain) on extinguishment of debt — 60,256 — Settlement of asset retirement obligations ( 117,847 ) ( 108,789 ) ( 86,615 ) Loss (gain) on sale of assets 381 38 ( 66,115 ) Loss (gain) on sale of business — ( 100,482 ) — Changes in operating assets and liabilities: Accounts receivable 85,459 8,576 20,352 Other current assets 15,895 ( 6,964 ) 7,066 Accounts payable ( 22,833 ) ( 3,831 ) ( 60,401 ) Other current liabilities ( 66,563 ) 1,290 ( 96,960 ) Other non-current assets and liabilities, net ( 104,001 ) 7,508 ( 76,092 ) Net cash provided by (used in) operating activities 935,826 962,593 519,069 Cash flows from investing activities: Exploration, development and other capital expenditures ( 481,905 ) ( 508,914 ) ( 561,434 ) Cash acquired in excess of payments for acquisitions 1,690 — 17,617 Payments for acquisitions, net of cash acquired ( 49,978 ) ( 936,214 ) — Proceeds from (cash paid for) sale of property and equipment, net 1,716 1,161 73,004 Contributions to equity method investees ( 4,559 ) ( 22,988 ) ( 29,447 ) Investment in intangible assets — — ( 12,366 ) Proceeds from sales of business — 146,676 — Other ( 13,710 ) — — Net cash provided by (used in) investing activities ( 546,746 ) ( 1,320,279 ) ( 512,626 ) Cash flows from financing activities: Issuance of common stock — 387,717 — Issuance of senior notes — 1,250,000 — Redemption of senior notes — ( 897,116 ) ( 30,000 ) Proceeds from Bank Credit Facility — 880,000 825,000 Repayment of Bank Credit Facility — ( 1,080,000 ) ( 625,000 ) Deferred financing costs — ( 32,872 ) ( 11,775 ) Other deferred payments ( 20,539 ) ( 2,389 ) ( 1,545 ) Payments of finance lease ( 19,589 ) ( 17,834 ) ( 16,306 ) Purchase of treasury stock ( 119,459 ) ( 45,181 ) ( 47,504 ) Employee stock awards tax withholdings ( 3,588 ) ( 6,206 ) ( 7,459 ) Distribution to noncontrolling interest ( 1,347 ) — — Net cash provided by (used in) financing activities ( 164,522 ) 436,119 85,411 Net increase (decrease) in cash, cash equivalents and restricted cash 224,558 78,433 91,854 Cash, cash equivalents and restricted cash: Balance, beginning of period 214,432 135,999 44,145 Balance, end of period $ 438,990 $ 214,432 $ 135,999 Supplemental non-cash transactions: Capital expenditures included in accounts payable and accrued liabilities $ 84,721 $ 85,550 $ 114,972 Supplemental cash flow information: Interest paid, net of amounts capitalized $ 118,037 $ 130,841 $ 130,313 See accompanying notes. F- 8 Table of Contents TALOS ENERGY INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS December 31, 2025 Note 1 — Organization, Nature of Business and Basis of Presentation Organization and Nature of Business Talos Energy Inc. (the “Parent Company”) is a Delaware corporation originally incorporated on November 14, 2017 . The Parent Company conducts all business operations through its operating subsidiaries, owns no operating assets and has no material operations, cash flows or liabilities independent of its subsidiaries. The Parent Company’s common stock is traded on The New York Stock Exchange under the ticker symbol “TALO.” The Parent Company (including its subsidiaries, collectively “Talos” or the “Company”) is a technically driven, innovative, independent energy company focused on maximizing long-term value through our oil and gas exploration and production (“Upstream”) business in the United States (“U.S.”) Gulf of America and offshore Mexico. The Company’s activities are primarily concentrated in the Deepwater (i.e., water depths of more than 600 feet) area of the U.S. Gulf of America. The Company leverages decades of technical and offshore operational expertise to acquire, explore, and produce assets in key geological trends while maintaining a focus on safe and efficient operations, environmental responsibility and community impact. Basis of Presentation and Consolidation The Consolidated Financial Statements have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”) and include the accounts of the Parent Company and entities in which the Parent Company holds a controlling financial interest including any variable interest entity in which the Parent Company is the primary beneficiary. All intercompany transactions have been eliminated. All adjustments are of a normal, recurring nature and are necessary to fairly present the financial position, results of operations and cash flows for the periods reflected herein. The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities as of the date of the financial statements, the reported amounts of revenues and expenses during the reporting periods and the reported amounts of proved oil and natural gas reserves. Actual results could differ from those estimates. Segments From January 1, 2024 through March 18, 2024, the Company had two operating segments: (i) exploration and production of oil, natural gas and NGLs (“Upstream Segment”) and (ii) CCS (“CCS Segment”). Both segments are reportable based on the Company’s measure of segment profit or loss. The legal entities included in the CCS Segment were designated as unrestricted, non-guarantor subsidiaries of the Company for purposes of the Bank Credit Facility (as defined in Note 2 — Summary of Significant Accounting Policies ) and indenture governing the senior notes. See additional information in Note 16 — Segment Information. Recently Adopted Accounting Standards Tax Disclosures — In December 2023, the FASB issued an update intended to improve income tax disclosures primarily through expanded disclosure of income tax rate reconciliation items and disaggregation of income taxes paid by jurisdiction. The tabular rate reconciliation requires both percentages and dollars to be presented. This disclosure guidance became effective for annual reporting periods beginning after December 15, 2024. The Company adopted this guidance retrospectively in this Annual Report on Form 10-K for the year ended December 31, 2025, and the adoption of such guidance did not have a material impact on the Company’s consolidated financial statements. See additional information in Note 12 — Income Taxes . Recently Issued Accounting Standards Not Yet Adopted Disaggregation of Income Statement Expenses — In November 2024, the FASB issued an update requiring the disaggregated disclosure of income statement expenses. The guidance does not change the expense captions an entity presents on the face of the income statement; rather, it requires disaggregation of certain expense captions into specified categories in disclosures within the footnotes to the financial statements. Such disclosures must be made on an annual and interim basis in a tabular format in the footnotes to the financial statements. Entities will be required to disaggregate any relevant expense caption presented on the face of the income statement within continuing operations into the following required natural expense categories, as applicable: (1) purchases of inventory, (2) employee compensation, (3) depreciation, (4) intangible asset amortization, and (5) depreciation, depletion, and amortization recognized as part of oil- and gas-producing activities or other depletion expenses. The update is effective for fiscal years beginning after December 15, 2026, and interim periods within fiscal years beginning after December 15, 2027 on a prospective retrospective basis. Early adoption and retrospective application are permitted. The Company is currently evaluating the effect of this update on the Company’s disclosures. F- 9 Table of Contents Note 2 — Summary of Significant Accounting Policies Overview of Significant Accounting Policies Cash and Cash Equivalents — The Company presents cash as “Cash and cash equivalents” on the Company’s Consolidated Balance Sheets. The Company considers all cash, money market funds and highly liquid investments with an original maturity of three months or less as cash and cash equivalents. Accounts Receivable and Allowance for Expected Credit Losses — Accounts receivable are stated at the historical carrying amount net of an allowance for expected credit losses. At each reporting period, the recoverability of material receivables is assessed using historical data, current market conditions and reasonable and supported forecasts of future economic conditions to determine their expected collectability. A loss-rate methodology is used to estimate the allowance for expected credit losses to be accrued on material receivables to reflect the net amount to be collected. As of December 31, 2025 and 2024 , the Company had allowances of $ 17.7 million and $ 25.5 million, respectively, presented in “Accounts receivable, net” on the Consolidated Balance Sheets. Price Risk Management Activities — The Company uses commodity price derivatives to manage fluctuating oil and natural gas market risks. The Company periodically enters into commodity derivative contracts, which may require payments to (or receipts from) counterparties based on the differential between a fixed price and a variable price for a fixed quantity of oil or natural gas without the exchange of underlying volumes. Commodity derivatives are recorded on the Consolidated Balance Sheets at fair value with settlements of such contracts and changes in the unrealized fair value recorded in earnings each period. Realized gains and losses on the settlement of commodity derivatives and changes in their unrealized gains and losses are reported in “Price risk management activities income (expense)” on the Consolidated Statements of Operations. The Company classifies cash flows related to derivative contracts based on the nature and purpose of the derivative. As the cash flows from derivatives are considered an integral part of the Company’s oil and natural gas operations, they are classified as cash flows from operating activities. The Company does not enter into derivative agreements for trading or other speculative purposes. The commodity derivative’s fair value reflects the Company’s best estimate with priority based upon exchange or over-the-counter quotations. Quoted valuations may not be available due to location differences or terms that extend beyond the period for which quotations are available. Where quotes are not available, the Company utilizes other valuation techniques or models to estimate market values. These modeling techniques require the Company to make estimations of future prices, price correlation, market volatility and liquidity. The Company’s actual results may differ from its estimates, and these differences can be favorable or unfavorable. Prepaid Assets — Prepaid assets primarily represent prepaid insurance, advance payments to operators, progress payments for well equipment and deposits with the Office of Natural Resources Revenue (“ONRR”) . The progress payments made for well equipment relate to long lead time items which the Company has not taken title to as of period end. The deposits with ONRR represent the Company’s estimated federal royalties payable within thirty days of the production date. On a monthly basis, the Company adjusts the deposit based on actual royalty payments remitted to the ONRR. Accounting for Oil and Natural Gas Activities — The Company follows the full cost method of accounting for oil and natural gas exploration and development activities. Under the full cost method, substantially all costs incurred in connection with the acquisition, development and exploration of oil and natural gas reserves are capitalized. These capitalized amounts include the internal and external costs directly related to the acquisition of assets, development and exploration activities, asset retirement costs and capitalized interest. Under the full cost method, dry hole costs and geological and geophysical costs are capitalized into the full cost pool, which is subject to amortization and assessed for impairment on a quarterly basis through a ceiling test calculation as discussed below. Capitalized costs associated with proved reserves are amortized on a country-by-country basis over the life of the total proved reserves using the unit of production method, computed quarterly. Conversely, capitalized costs associated with unproved properties and related geological and geophysical costs, exploration wells currently drilling and capitalized interest are initially excluded from the amortizable base. The Company transfers unproved property costs into the amortizable base when properties are determined to have proved reserves or when the Company has completed an unproved properties evaluation resulting in an impairment. The Company evaluates each of these unproved properties individually for impairment at least annually. Additionally, the amortizable base includes future development costs, asset retirement costs, net of estimated salvage values, and geological and geophysical costs incurred that cannot be associated with specific unproved properties or prospects in which the Company owns a direct interest. The Company capitalizes overhead costs that are directly related to exploration, acquisition and development activities. F- 10 Table of Contents The Company’s capitalized costs are limited to a ceiling based on the present value of future net revenues from proved reserves, computed using a discount factor of 10 %, plus the lower of cost or estimated fair value of unproved oil and natural gas properties not being amortized less the related tax effects. Generally, any costs in excess of the ceiling are recognized as a non-cash “Impairment of oil and natural gas properties” on the Consolidated Statements of Operations and an increase to “Accumulated depreciation, depletion and amortization” on the Company’s Consolidated Balance Sheets. The expense may not be reversed in future periods, even though higher oil, natural gas and NGL prices may subsequently increase the ceiling. The Company performs this ceiling test calculation each quarter. In accordance with the SEC rules and regulations, the Company utilizes SEC Pricing when performing the ceiling test. The Company also holds prices and costs constant over the life of the reserves, even though actual prices and costs of oil and natural gas are often volatile and may change from period to period. Under the full cost method of accounting for oil and natural gas operations, assets whose costs are currently being depreciated, depleted or amortized are assets in use in the earnings activities of the enterprise and do not qualify for capitalization of interest cost. Investments in unproved properties for which exploration and development activities are in progress and other major development projects that are not being currently depreciated, depleted or amortized are assets qualifying for capitalization of interest costs. When the Company sells or conveys interests in oil and natural gas properties, the Company reduces its oil and natural gas reserves for the amount attributable to the sold or conveyed interest. The Company treats sales proceeds on non-significant sales as reductions to the cost of the Company’s oil and natural gas properties. The Company does not recognize a gain or loss on sales of oil and natural gas properties, unless those sales would significantly alter the relationship between capitalized costs and proved reserves. Other Property and Equipment — Other property and equipment is recorded at cost and consists primarily of leasehold improvements, office furniture and fixtures and computer hardware. Acquisitions and betterments are capitalized; maintenance and repairs are expensed as incurred. Depreciation is provided using the straight-line method over estimated useful lives of three to ten years . Restricted Cash — Any cash that is legally restricted from use is classified as restricted cash. If the purpose of restricted cash relates to acquiring a long-term asset, liquidating a long-term liability, or is otherwise unavailable for a period longer than one year from the balance sheet date, the restricted cash is included in other long-term assets. Otherwise, restricted cash is included in other current assets in the Consolidated Balance Sheets. The Company acquired funds held in escrow to be used for future plugging and abandonment (“P&A”) obligations assumed through the EnVen Acquisition (as defined in Note 3 — Acquisitions and Divestitures ). These escrow accounts were fully funded by EnVen (as defined in Note 3 — Acquisitions and Divestitures ) prior to the consummation of the acquisition. This is reflected as “Restricted Cash” within “Other long-term assets” on the Consolidated Balance Sheets. Equity Method Investments — The Company generally accounts for investments under the equity method of accounting when it exercises significant influence over the entity’s operating and financial policies, but does not hold a controlling financial interest in the entity. The voting percentage that is presumed to provide an investor with the required level of influence necessary to apply the equity method of accounting varies depending on the nature of the investee. For investments in common stock, in-substance common stock, a limited liability company or partnership that does not maintain specific ownership accounts for each investor, a voting percentage of 20 % or more is generally presumed to demonstrate significant influence. In applying the equity method of accounting, the investments are initially recognized at cost and subsequently adjusted for the Company’s proportionate share of earnings, losses, contributions and distributions. Investments accounted for using the equity method are reflected as “Equity method investments” on the Consolidated Balance Sheets. The equity in earnings of an investee is reflected in “Equity method investment income (expense)” on the Consolidated Statements of Operations. The gain or loss from the full or partial sale of an equity method investment is presented in the same line item in which the Company reports the equity in earnings of the investee. The Company assesses equity method investments for impairment whenever changes in the facts and circumstances indicate a loss in value has occurred if the loss is deemed to be other-than-temporary. When the loss is deemed to be other-than-temporary, the carrying value of the equity method investment is written down to fair value. The impairment charge is included as a component of the Company’s share of the earning or losses of the investee. No impairment charges have been recorded during the years ended December 31, 2025, 2024 and 2023 . Other Well Equipment — Other well equipment primarily represents the cost of equipment to be used in the Company’s oil and natural gas drilling and development activities such as drilling pipe, tubulars and certain wellhead equipment. When well equipment is supplied to wells, the cost is capitalized in oil and gas properties, and if such property is jointly owned, the proportionate costs will be reimbursed by third party participants. F- 11 Table of Contents Notes Receivable, net — The Company holds two notes receivable with an aggregate face value of $ 66.2 million acquired by the Company as part of the EnVen Acquisition, which consist of commitments from the sellers of oil and natural gas properties related to the costs associated with P&A obligations (the “P&A Notes Receivable”). The P&A Notes Receivable are recorded at a discounted value, being accreted to their principal amounts and presented as such, net of related cumulative estimated credit losses, on the accompanying Consolidated Balance Sheets. The Company estimates the current expected credit losses related to its P&A Notes Receivable using the probability of default method based on the long-term credit ratings of the counterparties of the notes, which are currently considered “investment grade.” Leases — At inception, contracts are reviewed to determine whether the agreement contains a lease. To the extent an arrangement is determined to include a lease, it is classified as either an operating or a finance lease, which dictates the pattern of expense recognition in the income statement. Operating leases are reflected as “Operating lease assets,” “Current portion of operating lease liabilities” and “Operating lease liabilities” on the Consolidated Balance Sheets. Finance leases are included in “Property and equipment,” “Other current liabilities” and “Other long-term liabilities” on the Consolidated Balance Sheets. A right-of-use (“ROU”) asset representing our right to use an underlying asset for the lease term and a lease liability representing our obligation to make lease payments arising from the lease are recognized on the Consolidated Balance Sheets for all leases, regardless of classification. The ROU asset is initially measured as the present value of the lease liability adjusted for any payments made prior to lease commencement, including any initial direct costs incurred and incentives received. Lease liabilities are initially measured at the present value of future minimum lease payments, excluding variable lease payments, over the lease term. As most of our leases do not provide an implicit rate, the Company generally uses an incremental borrowing rate based on the estimated rate of interest for collateralized borrowing over a similar term of the lease payments at commencement date. Certain of the Company’s leases include one or more options to renew the lease, with renewal terms that can extend the lease term for additional years. When determining if renewals should be included in the lease term to be recognized, the Company utilizes the reasonably certain threshold, therefore, certain of the leases included in the calculation of its ROU assets and lease liabilities could include optional renewal periods for which it is not contractually obligated, but for which the Company currently expects to exercise such options. The Company has elected to account for lease and non-lease components in its contracts as a single lease component for all asset classes except for our leased floating production vessel class. Our lease terms may include options to extend or terminate the lease when it is reasonably certain that the Company will exercise that option. The Company has elected, as an accounting policy, not to record leases with terms of twelve months or less (i.e., short-term) on the Consolidated Balance Sheets. See Note 5 — Leases for additional information. Debt Issuance Costs — The Company presents debt issuance costs associated with revolving line-of-credit arrangements as a reduction of the carrying value of long-term debt when there is a balance outstanding and in “Other assets” on the Consolidated Balance Sheets when no such balance is outstanding. Asset Retirement Obligations — The Company has obligations associated with the retirement of its oil and natural gas wells and related infrastructure. The Company has obligations to plug wells and remove or appropriately abandon all production facilities, structures and pipelines following cessation of operations. The Company accrues a liability with respect to these obligations based on its estimate of the timing and amount to plug, remove or abandon the associated assets. In estimating the liability associated with its asset retirement obligations, the Company utilizes several assumptions, including a credit-adjusted risk-free interest rate, estimated costs of decommissioning services, estimated timing of when the work will be performed and a projected inflation rate. Changes in estimate represent changes to the expected amount and timing of payments to settle its asset retirement obligations. Typically, these changes result from obtaining new information about the timing of its obligations to plug and abandon oil and natural gas wells and the costs to do so. After initial recording, the liability is increased for the passage of time, with the increase being reflected as “Accretion expense” on the Company’s Consolidated Statements of Operations. If the Company incurs an amount different from the amount accrued for asset retirement obligations, the Company recognizes the difference as an adjustment to proved properties. Decommissioning Obligations — Certain counterparties in divestiture transactions or third parties in existing leases that have filed for bankruptcy protection or undergone associated reorganizations may not be able to perform required abandonment obligations. The Company may be held jointly and severally liable for the decommissioning of various facilities and related wells. The Company accrues losses associated with decommissioning obligations when such losses are probable and reasonably estimable. When there is a range of possible outcomes, the amount accrued is the most likely outcome within the range. If no single outcome within the range is more likely than the others, the minimum amount in the range is accrued. These accruals may be adjusted as additional information becomes available. In addition, when decommissioning obligations are reasonably possible, the Company discloses an estimate for a possible loss or range of loss (or a statement that such an estimate cannot be reasonably made). See Note 15 — Commitments & Contingencies for additional information. Share-Based Compensation — Certain of the Company’s employees participate in its equity-based compensation plan. The Company measures all employee equity-based compensation awards at fair value on the date awards are granted to its employees . F- 12 Table of Contents The fair value of the stock-based awards is determined at the date of grant and is not remeasured for awards classified as equity unless the award is modified. Liability classified awards are remeasured at each reporting period. The Company records share-based compensation, net of actual forfeitures, for the restricted stock units (“RSUs”) and performance share units (“PSUs”) in “General and administrative expense” on the Consolidated Statements of Operations, net of amounts capitalized to oil and gas properties. See Note 11 — Employee Benefits Plans and Share-Based Compensation for additional information. RSUs — Share-based compensation is based on the market price of the Company’s common stock on the grant date and recognized over the requisite service period using the straight-line method. PSUs with Market Based Conditions — Share-based compensation is based on the grant date fair value determined using a Monte Carlo valuation model for awards with a market condition and recognized over the requisite service period using the straight-line method. Estimates used in the Monte Carlo valuation model are considered highly-complex and subjective. The number of shares of common stock issuable ranges from zero to 200 % of the number of PSUs granted based on the Company’s total shareholder return (“TSR”). Share-based compensation related to PSUs with a market condition are recognized as the requisite service period is fulfilled, even if the market condition is not achieved. PSUs with Performance Based Conditions — Share-based compensation is based on the market price of the Company’s common stock on the grant date and recognized over the requisite service period using the straight-line method for awards with a performance condition. The Company recognizes compensation cost for awards with performance conditions if and when the Company concludes that it is probable that the performance condition will be achieved. The Company reassesses the probability of vesting at each reporting period for awards with performance conditions and adjusts compensation cost based on its probability assessment. The Company recognizes a cumulative catch-up adjustment for such changes in its probability assessment in subsequent reporting periods, using the grant date fair value of the award whose terms reflect the updated probable performance condition (which could be either a reversal or increase in expense). The number of shares of common stock issuable ranges from zero to 200 % of the number of PSUs granted based on a metric associated with the Company’s own operations or activities. Revenue Recognition — Revenues are recorded based from the sale of oil, natural gas and NGL quantities sold to purchasers. The Company records revenues from the sale of oil, natural gas and NGLs based on quantities of production sold to purchasers under short-term contracts (less than twelve months) at market prices when delivery to the customer has occurred, title has transferred, prices are fixed and determinable and collection is reasonably assured. This occurs when production has been delivered to a pipeline or when a barge lifting has occurred. The Company recognizes transportation costs as a component of lease operating expense when it is the shipper of the product. Each unit of product typically represents a separate performance obligation, therefore, future volumes are wholly unsatisfied and disclosure of the transaction price allocated to remaining performance obligations is not required. Production Handling Fees — The Company presents certain reimbursements for costs from certain third parties as a reduction of “Lease operating expense” on the Consolidated Statements of Operations. Income Taxes — The Company records current income taxes based on estimates of current taxable income and provides for deferred income taxes to reflect estimated future income tax payments and receipts. The impact to changes in tax laws are recorded in the period the change is enacted. Deferred taxes represent the tax impacts of differences between the financial statement and tax bases of assets and liabilities and carryovers at each year end. The Company classifies all deferred tax assets and liabilities, along with any related valuation allowance, as long-term on the Consolidated Balance Sheets. The realization of deferred tax assets depends on recognition of sufficient future taxable income during periods in which those temporary differences are deductible. The Company reduces deferred tax assets by a valuation allowance when, based on estimates, it is more likely than not that a portion of those assets will not be realized in a future period. The deferred tax asset estimates are subject to revision, either up or down, in future periods based on new facts or circumstances. In evaluating the Company’s valuation allowances, the Company considers cumulative book losses, the reversal of existing temporary differences, the existence of taxable income in carryback years, tax planning strategies and future taxable income for each of its taxable jurisdictions, the latter two of which involve the exercise of significant judgment. Changes to the Company’s valuation allowances could materially impact its results of operations. The Company’s policy is to classify interest and penalties associated with underpayment of income taxes as “Interest expense” and “General and administrative expense” on the Consolidated Statements of Operations, respectively. Income (Loss) Per Share — Basic net income per common share (“EPS”) is computed by dividing net income (loss) by the weighted average number of shares of common stock outstanding during the period. Except when the effect would be antidilutive, diluted EPS includes the impact of RSUs and PSUs. See Note 13 — Income (Loss) Per Share for additional information. Fair Value Measure of Financial Instruments — Financial instruments generally consist of cash and cash equivalents, accounts receivable, commodity derivatives, accounts payable and debt. The carrying amount of cash and cash equivalents, accounts receivable and accounts payable approximates fair value due to the highly liquid nature of these instruments. F- 13 Table of Contents Current fair value accounting standards define fair value, establish a consistent framework for measuring fair value and stipulate the related disclosure requirements for each major asset and liability category measured at fair value on either a recurring or nonrecurring basis. These standards also clarify fair value is an exit price, presenting the amount that would be received to sell an asset or paid to transfer a liability, in an orderly transaction between market participants. The Company follows a three-level hierarchy, prioritizing and defining the types of inputs used to measure fair value depending on the degree to which they are observable as follows: • Level 1 – Inputs to the valuation methodology are quoted prices (unadjusted) for identical assets or liabilities in active markets. • Level 2 – Inputs to the valuation methodology include quoted prices for similar assets and liabilities in active markets, and inputs that are observable for the asset or liability, either directly or indirectly, for substantially the full term of the financial statement. • Level 3 – Inputs to the valuation methodology are unobservable (little or no market data), which require the reporting entity to develop its own assumptions and are significant to the fair value measurement. Assets and liabilities measured at fair value are based on one or more of three valuation techniques. The valuation techniques are as follows: • Market Approach – Prices and other relevant information generated by market transactions involving identical or comparable assets or liabilities. • Cost Approach – Amount that would be required to replace the service capacity of an asset (replacement cost). • Income Approach – Techniques to convert expected future cash flows to a single present value amount based on market expectations (including present value techniques, option-pricing and excess earnings models). Authoritative guidance on financial instruments requires certain fair value disclosures to be presented. The estimated fair value amounts have been determined using available market information and valuation methodologies. Considerable judgment is required in interpreting market data to develop the estimates of fair value. The use of different assumptions or valuation methodologies may have a material effect on the estimated fair value amounts. Variable Interest Entities — Upon inception of a contractual agreement, the Parent Company performs an assessment to determine whether the arrangement contains a variable interest in a legal entity and whether that legal entity is a variable interest Entity (“VIE”). The Parent Company assesses all aspects of its interests in an entity and uses judgment when determining if it is the primary beneficiary. The primary beneficiary has both the power to direct the activities of the VIE that most significantly impact the entity’s economic performance and the obligation to absorb losses or the right to receive benefits from the VIE that could potentially be significant to the VIE. Other qualitative factors that are considered include decision-making responsibilities, the VIE capital structure, risk and rewards sharing, contractual agreements with the VIE, voting rights and level of involvement of other parties. A reassessment of the primary beneficiary conclusion is conducted when there are changes in the facts and circumstances related to a VIE. See Note 7 — Equity Method Investments for additional information. Concentration of Credit Risk Consisting principally of cash and cash equivalents, accounts receivable and commodity derivatives, the Company is subject to concentrated financial instruments credit risk. Cash and cash equivalents balances are maintained in financial institutions, which at times, exceed federally insured limits. The Company monitors the financial condition of these institutions and has not experienced losses on these accounts. Commodity derivatives are entered into with registered swap dealers, all of which participate in the Company’s senior reserve-based revolving credit facility (the “Bank Credit Facility”). The Company monitors the financial condition of these institutions and has not experienced losses due to counterparty default on these instruments. The Company markets the majority of its oil and natural gas production, and all of its revenues are attributable to the U.S. The majority of the Company’s oil, natural gas and NGL production is sold to customers under short-term (less than 12 months) contracts at market-based prices. The Company’s customers consist primarily of major oil and natural gas companies, well-established oil and gas pipeline companies and independent oil and gas producers and suppliers. The Company performs ongoing credit evaluations of its customers and provide allowances for probable credit losses when necessary. F- 14 Table of Contents The percent of consolidated revenue of major customers, those whose total represented 10% or more of the Company’s oil, natural gas and NGL revenues, was as follows: Year Ended December 31, 2025 2024 2023 Shell Trading (US) Company 35 % 48 % 54 % Exxon Mobil Corporation 23 % 17 % ** Valero Energy Corporation ** ** 21 % Chevron Corporation 12 % ** ** ** Less than 10 % The loss of a major customer could have material adverse effect on the Company in the short term. However, the Company believes it would be able to obtain other customers to market its oil, natural gas and NGL production. Cash, Cash Equivalents and Restricted Cash The following table provides a reconciliation of the amount of cash, cash equivalents and restricted cash reported within the Consolidated Balance Sheets to the total of the same such amounts shown in the Consolidated Statements of Cash Flows (in thousands): Year Ended December 31, 2025 2024 Cash and cash equivalents $ 362,809 $ 108,172 Restricted cash included in Other long-term assets 76,181 106,260 Total cash, cash equivalent and restricted cash $ 438,990 $ 214,432 The decrease in restricted cash is a result of amounts being released from the escrow account upon the completion of certain P&A work. Accounts Receivable The following table provides the components of “Accounts receivable, net” as presented on the Consolidated Balance Sheets (in thousands): Year Ended December 31, 2025 2024 Trade $ 166,793 $ 236,694 Joint interest 132,527 133,562 Other 23,738 34,002 Total accounts receivable, net $ 323,058 $ 404,258 Note 3 — Acquisitions and Divestitures Acquisitions — Business Combinations Acquisitions qualifying as business combinations are accounted for under the acquisition method of accounting, which requires, among other items, that assets acquired and liabilities assumed be recognized on the Consolidated Balance Sheets at their fair values as of the acquisition date. QuarterNorth Acquisition — On March 4, 2024 , the Company completed the acquisition of QuarterNorth Energy Inc. (“QuarterNorth”), a privately-held U.S. Gulf of America exploration and production company (the “QuarterNorth Acquisition,” and the merger agreement related thereto, the “QuarterNorth Merger Agreement”) for consideration consisting of (i) $ 1,247.4 million in cash and (ii) 24.3 million shares of the Company’s common stock valued at $ 322.6 million. The cash payment was partially funded with a January 2024 underwritten public offering of 34.5 million shares of the Company’s common stock (See Note 10 — Stockholders’ Equity ), borrowings under the Bank Credit Facility and the Senior Notes (as defined in Note 8 — Debt ). F- 15 Table of Contents The following table summarizes the purchase price (in thousands, except share and per share data): Shares of Talos common stock 24,349,452 Talos common stock price (1) $ 13.25 Common stock value $ 322,630 Cash consideration $ 1,247,419 Total purchase price (2) $ 1,570,049 (1) Represents the closing price of the Company’s common stock on March 4, 2024, the date of the closing of the QuarterNorth Acquisition. (2) Total purchase price net of $ 331.4 million cash and cash equivalents acquired at closing is $ 1,238.7 million. The following table presents the final allocation of the purchase price to the assets acquired and liabilities assumed, based on their fair values on March 4, 2024 (in thousands): Cash and cash equivalents $ 331,374 Other current assets (1) 165,696 Property and equipment 1,622,414 Other long-term assets 20,781 Current liabilities: Current portion of asset retirement obligations ( 6,748 ) Other current liabilities ( 199,704 ) Long-term liabilities: Asset retirement obligations ( 192,771 ) Deferred tax liabilities ( 168,102 ) Other long-term liabilities ( 2,891 ) Allocated purchase price $ 1,570,049 (1) Included in current assets is acquired receivables in the amount of $ 136.3 million excluding receivables with credit deterioration, which represents the contractual value net of allowances of approximately $ 15.5 million. The fair values determined for accounts receivable, accounts payable and other current assets and most current liabilities were generally equivalent to the carrying value due to their short-term nature. The fair value of proved oil and natural gas properties as of the acquisition date is based on estimated proved oil, natural gas and NGL reserves and related discounted future net cash flows incorporating market participant assumptions. Significant inputs to the valuation include estimates of future production volumes, future operating, development and plugging and abandonment costs, future commodity prices, and a weighted average cost of capital discount rate. When estimating the fair value of proved and unproved properties, additional risk adjustments were applied to proved developed non-producing, proved undeveloped and probable reserves to reflect the relative uncertainty of each reserve class. These inputs are classified as Level 3 unobservable inputs, including the underlying commodity price assumptions which are based on NYMEX forward strip prices, escalated for inflation, and adjusted for price differentials. The fair value of asset retirement obligations is determined by calculating the present value of estimated future cash flows related to the liabilities. The Company utilizes several assumptions, including a credit-adjusted risk-free interest rate, estimated costs of decommissioning services, estimated timing of when the work will be performed and a projected inflation rate. The fair values of derivative instruments were estimated using a third-party industry standard pricing model which considers various inputs such as quoted forward commodity prices, discount rates, volatility factors and current market and contractual prices for the underlying instruments, as well as other relevant data. The Company incurred approximately $ 21.6 million of acquisition-related costs in connection with the QuarterNorth Acquisition exclusive of severance expense, of which $ 18.6 million was recognized during the year ended December 31, 2024 and $ 3.0 million was recognized for the year ended December 31, 2023. These costs were reflected in “General and administrative expense” on the Consolidated Statements of Operations except for $ 4.9 million of fees associated with an unutilized bridge loan that was included in “Interest expense” on the Consolidated Statements of Operations during the year ended December 31, 2024. Additionally, the Company incurred $ 22.2 million in severance expense in connection with the QuarterNorth Acquisition for the year ended December 31, 2024. See Note 11 — Employee Benefits Plans and Share-Based Compensation for additional discussion. F- 16 Table of Contents The following table presents revenue and net income attributable to the QuarterNorth Acquisition for the period from March 4, 2024 to December 31, 2024: Revenue $ 503,397 Net income (loss) $ 89,209 Pro Forma Financial Information (Unaudited) — The following supplemental pro forma financial information (in thousands, except per common share amounts), presents the consolidated results of operations for the years ended December 31, 2024 and 2023 as if the QuarterNorth Acquisition had occurred on January 1, 2023. The unaudited pro forma information was derived from historical statements of operations of the Company and QuarterNorth adjusted to include (i) depletion expense applied to the adjusted basis of the oil and natural gas properties acquired, (ii) interest expense to reflect borrowings under the Bank Credit Facility and Senior Notes, (iii) general and administrative expense adjusted for transaction related costs incurred (including severance), (iv) weighted average basic and diluted shares of common stock outstanding from the issuance of 24.3 million shares of common stock as partial consideration for the QuarterNorth Acquisition and (v) weighted average basic and diluted shares of common stock outstanding from the issuance of 34.5 million shares of common stock from the underwritten public offering in January 2024 that partially funded the cash portion of the QuarterNorth Acquisition. Supplemental pro forma earnings for the year ended December 31, 2023 were adjusted to include $ 31.7 million of general and administrative expenses and supplemental pro forma earnings for the year ended December 31, 2024 were adjusted to exclude these expenses. This information does not purport to be indicative of results of operations that would have occurred had the QuarterNorth Acquisition occurred on January 1, 2023, nor is such information indicative of any expected future results of operations (in thousands, except for the per share data). Year Ended December 31, 2024 2023 Revenue $ 2,100,837 $ 2,141,579 Net income (loss) $ ( 69,131 ) $ 245,720 Basic net income (loss) per common share $ ( 0.38 ) $ 1.37 Diluted net income (loss) per common share $ ( 0.38 ) $ 1.37 EnVen Acquisition — On September 21, 2022 , the Company executed a merger agreement to acquire EnVen Energy Corporation (“EnVen”), a private operator in the Deepwater U.S. Gulf of America (the “EnVen Acquisition,” and such agreement, the “EnVen Merger Agreement”). On February 13, 2023 , the Company completed the EnVen Acquisition for consideration consisting of (i) $ 207.3 million in cash, (ii) 43.8 million shares of the Company’s common stock valued at $ 832.2 million and (iii) the effective settlement of an accounts receivable balance of $ 8.4 million . No gain or loss was recognized on settlement as the payable was effectively settled at the recorded amount. The cash payment was partially funded with borrowings under the Bank Credit Facility. The following table summarizes the purchase price (in thousands, except share and per share data): Talos common stock 43,799,890 Talos common stock price per share (1) $ 19.00 Common stock value $ 832,198 Cash consideration $ 207,313 Settlement of preexisting relationship $ 8,388 Total purchase price $ 1,047,899 (1) Represents the closing price of the Company’s common stock on February 13, 2023, the date of the closing of the EnVen Acquisition. The Company incurred approximately $ 21.8 million of acquisition-related costs in connection with the EnVen Acquisition exclusive of severance expense, of which $ 12.8 million was recognized during the year ended December 31, 2023 and reflected in general and administrative expense on the Consolidated Statements of Operations. Additionally, the Company incurred $ 25.3 million in severance expense in connection with the EnVen Acquisition for the year ended December 31, 2023. See Note 11 — Employee Benefit Plans and Share-Based Compensation for additional discussion. The following table presents revenue and net income (loss) attributable to the EnVen Acquisition for the period from February 13, 2023 to December 31, 2023 (in thousands): Revenue $ 423,624 Net income (loss) $ 85,622 F- 17 Table of Contents Pro Forma Financial Information (Unaudited) — The following supplemental pro forma financial information (in thousands, except per common share amounts), presents the consolidated results of operations for the year ended December 31, 2023 as if the EnVen Acquisition had occurred on January 1, 2022. The unaudited pro forma information was derived from historical statements of operations of the Company and EnVen adjusted to include (i) depletion expense applied to the adjusted basis of the oil and natural gas properties acquired, (ii) interest expense to reflect borrowings under the Bank Credit Facility and to adjust the amortization of the premium of the 11.75 % Notes (as defined in Note 8 — Debt ), (iii) general and administrative expense adjusted for transaction related costs incurred (including severance), (iv) other income (expense) to adjust the accretion of the discount on the P&A Notes Receivable and (v) weighted average basic and diluted shares of common stock outstanding from the issuance of 43.8 million shares of common stock to EnVen. Supplemental pro forma earnings for the year ended December 31, 2023 were adjusted to exclude $ 65.1 million of general and administrative expenses. This information does not purport to be indicative of results of operations that would have occurred had the EnVen Acquisition occurred on January 1, 2022, nor is such information indicative of any expected future results of operations (in thousands, except for the per share data). Year Ended December 31, 2023 Revenue $ 1,509,929 Net income (loss) $ 217,537 Basic net income (loss) per common share $ 1.74 Diluted net income (loss) per common share $ 1.73 Asset Acquisitions Acquisitions accounted for as asset acquisitions require, among other items, the cost of the acquisition to be allocated to the assets acquired and liabilities assumed based on relative fair value basis. Acquisition of Working Interests in Monument Oil Discovery — The Company executed two separate definitive agreements to acquire a collective 21.4 % non-operated working interest in the Monument oil discovery (“Monument Project”) in the Deepwater U.S. Gulf of America located on certain Walker Ridge lease blocks. Cash consideration totaling $ 20.2 million, after customary closing adjustments, was paid on the closing dates of July 31, 2024 and August 2, 2024 with $ 24.4 million of additional cash consideration paid periodically in installments beginning January 1, 2025 through April 1, 2026. The Company allocated $ 42.6 million to proved properties. The carrying amount for the deferred cash consideration of $ 4.0 million is included in “Other current liabilities” on the Consolidated Balance Sheets at December 31, 2025. Acquisition of Incremental Working Interest in Monument Oil Discovery — On March 7, 2025 , the Company completed the acquisition of an additional 8.3 % non-operated working interest in the Monument Project for $ 14.8 million, substantially all of which was allocated to its proved properties. An additional aggregate $ 6.3 million of contingent payments will be recognized upon the achievement of certain milestones defined in the agreement. Acquisition of Incremental Working Interest in Mississippi Canyon Blocks — On July 22, 2025, the Company completed the acquisition of an additional 75.2 % and 50.0 % working interest in U.S. Gulf of America Mississippi Canyon blocks 108 and 110, respectively (the “Amberjack Acquisition”), in the Deepwater area. Prior to the Amberjack Acquisition, the Company owned an interest in and operated these developed and producing blocks. The Company also acquired a controlling financial interest in SP 49 Pipeline LLC (“SP 49”) as part of the Amberjack Acquisition. The one-third equity interest in SP 49 not held by the Company is presented as “Noncontrolling interest” in the Company’s Consolidated Financial Statements. The $ 38.6 million cost of the Amberjack Acquisition, including $ 33.7 million of cash at closing, was primarily allocated to the Company’s proved properties. Divestitures Talos Low Carbon Solutions Divestiture — On March 18, 2024 , the Company entered into a definitive agreement relating to and subsequently completed the sale of its wholly owned subsidiary, Talos Low Carbon Solutions LLC to TotalEnergies E&P USA, Inc. for a purchase price of $ 125.0 million plus customary reimbursements and adjustments, combined totaling approximately $ 142.0 million (the “TLCS Divestiture”). The TLCS Divestiture included the Company’s entire CCS business including its equity investments in three projects along the U.S. Gulf Coast: Bayou Bend CCS LLC, Harvest Bend CCS LLC, and Coastal Bend CCS LLC. The TLCS Divestiture also entitled Talos to certain contingent payments, of which $ 4.7 million was received during the year ended December 31, 2024 . A gain of $ 100.4 million was recognized related to TLCS Divestiture during the year ended December 31, 2024. The gain on the TLCS Divestiture is presented as “Other operating income (expense)” on the Consolidated Statements of Operations and the contingent payments are included in “Other current assets” on the Consolidated Balance Sheets at December 31, 2025 . A deferred payment of $ 12.5 million due in October 2025 has not been received and the Company determined there was significant doubt surrounding the collectability of such deferred payment. Accordingly, the Company derecognized the deferred payment, of which $ 8.9 million is reflected as an expense in “Other operating income (expense)” and $ 3.6 million is reflected as the reversal of imputed interest income in “Other income (expense)” on the Consolidated Statements of Operations for the year ended December 31, 2025. F- 18 Table of Contents The Company incurred approximately $ 6.1 million of costs in connection with the TLCS Divestiture exclusive of severance expense, of which $ 5.5 million was recognized during the year ended December 31, 2024 and reflected in “General and administrative expense” on the Consolidated Statements of Operations. Additionally, the Company incurred $ 3.7 million in severance expense in connection with the TLCS Divestiture for the year ended December 31, 2024. See Note 11 — Employee Benefits Plans and Share-Based Compensation for additional discussion. Mexico Divestiture — On September 27, 2023, the Company closed the sale of a 49.9 % equity interest in its subsidiary, Talos Energy Mexico 7, S. de R.L. de C.V. (“Talos Mexico”) to Zamajal, S.A. de C.V. (“Zamajal”), a subsidiary of Grupo Carso, S.A.B. de C.V. (“Carso”) for $ 74.9 million in cash consideration with an additional $ 49.9 million contingent on first oil production from the Zama Field (the “2023 Mexico Divestiture”). The contingent consideration will be recognized when regular commercial production from the Zama Field becomes probable. Talos Mexico, through its wholly owned subsidiary, currently holds a 17.4 % unitized interest in the Zama Field. The fair value of the Company’s retained equity method investment in Talos Mexico was $ 107.6 million upon the closing of the 2023 Mexico Divestiture. Fair value was determined using the implied value of Talos Mexico, based on the transaction price from the 2023 Mexico Divestiture, an orderly market transaction. A gain of $ 66.2 million was recognized on the 2023 Mexico Divestiture during the year ended December 31, 2023 which is included in “Other operating (income) expense” on the Consolidated Statements of Operations. On December 16, 2024, the Company entered into an agreement to sell an additional equity interest in Talos Mexico to Zamajal. See Note 7 — Equity Method Investments for additional information. Note 4 — Property, Plant and Equipment Proved Properties The Company’s interests in oil and natural gas proved properties are located in the United States, primarily in the Gulf of America deep and shallow waters. The Company’s ceiling test computations resulted in an impairment of its U.S. oil and natural gas properties during the year ended December 31, 2025 of $ 454.5 million . No impairment charges were recorded during the years ended December 31, 2024 and 2023. At December 31, 2025, its ceiling test computation was based on SEC pricing of $ 65.37 per Bbl of oil, $ 3.61 per Mcf of natural gas and $ 19.22 per Bbl of NGLs. Further ceiling test impairments could be recorded in the near term should the 12-month average trailing commodity prices decline as compared to the commodity prices used in prior quarters. Unproved Properties Unproved capitalized costs of oil and natural gas properties excluded from amortization relate to unevaluated properties associated with acquisitions, leases awarded in the U.S. Gulf of America federal lease sales, certain geological and geophysical costs, expenditures associated with certain exploratory wells in progress and capitalized interest. The following table sets forth a summary of the Company’s oil and natural gas property costs not being amortized at December 31, 2025, by the year in which such costs were incurred (in thousands): Year Ended December 31, Total 2025 2024 2023 2022 and Prior Acquisition United States $ 400,677 $ — $ 263,783 $ 136,894 $ — Exploration United States 79,878 41,576 26,314 9,585 2,403 Total unproved properties, not subject to amortization $ 480,555 $ 41,576 $ 290,097 $ 146,479 $ 2,403 The excluded costs will be included in the amortization base as properties are evaluated and proved reserves are established or impairment is determined. The unproved costs will be excluded from the amortization base until the Company has made a determination as to the existence of proved reserves. The Company currently estimates the majority of these costs to be transferred to the amortization base within six years of December 31, 2025. F- 19 Table of Contents Note 5 — Leases The Company has operating leases principally for office space, drilling rigs, compressors and other equipment necessary to support the Company’s operations. Costs associated with the Company’s leases are either expensed or capitalized depending on how the underlying asset is utilized. Additionally, the Company has a finance lease related to the use of the Helix Producer I (the “HP-I”), a dynamically positioned floating production facility that interconnects with the Phoenix Field through a production buoy. The HP-I is utilized in the Company’s oil and natural gas development activities and the ROU asset was capitalized and included in proved property and depleted as part of the full cost pool. Once items are included in the full cost pool, they are indistinguishable from other proved properties. The capitalized costs within the full cost pool are amortized over the life of the total proved reserves using the unit-of-production method, computed quarterly. The lease costs described below are presented on a gross basis and do not represent the Company’s net proportionate share of such amounts. A portion of these costs have been or may be billed to other working interest owners. The Company’s share of these costs is included in property and equipment, lease operating expense or general and administrative expense, as applicable. The components of lease costs were as follows (in thousands): Year Ended December 31, 2025 2024 2023 Finance lease costs - interest on lease liabilities $ 11,193 $ 12,948 $ 14,476 Operating lease costs, excluding short-term leases (1) 4,192 4,207 4,883 Short-term lease costs (2) 151,379 100,895 117,132 Variable lease costs (3) 2,668 2,464 2,888 Variable and fixed sublease income ( 1,586 ) ( 1,436 ) ( 482 ) Total lease costs $ 167,846 $ 119,078 $ 138,897 (1) Operating lease costs reflect a single lease cost, calculated so that the cost of the lease is allocated over the lease term on a straight-line basis. (2) Short-term lease costs are reported at gross amounts and primarily represent costs incurred for drilling rigs and well intervention vessels, most of which are short-term contracts not recognized as a ROU asset and lease liability on the Consolidated Balance Sheets. The short-term operating lease costs incurred during the periods presented are not necessarily indicative of the Company’s future short-term lease costs and obligations, as it routinely executes short-term contracts for the use of drilling rigs to support its drilling activities. Short-term lease costs for drilling rigs can vary significantly based on the timing of the drilling program. Market conditions can also contribute to the volatility and variability of short-term drilling rig lease costs. (3) Variable lease costs primarily represent differences between minimum payment obligations and actual operating charges incurred by the Company related to its long-term leases. The present value of the fixed lease payments recorded as the Company’s ROU asset and liability, adjusted for initial direct costs and incentives were as follows (in thousands): December 31, 2025 December 31, 2024 Operating leases: Operating lease assets $ 9,214 $ 11,294 Current portion of operating lease liabilities $ 3,657 $ 3,837 Operating lease liabilities 11,956 15,489 Total operating lease liabilities $ 15,613 $ 19,326 Finance leases: Proved properties $ 166,261 $ 166,261 Other current liabilities $ 21,473 $ 19,589 Other long-term liabilities 90,169 111,641 Total finance lease liabilities $ 111,642 $ 131,230 F- 20 Table of Contents The table below presents the lease maturity by year as of December 31, 2025 (in thousands). Such commitments are reflected at undiscounted values and are reconciled to the discounted present value recognized on the Consolidated Balance Sheets. Operating Leases Finance Leases 2026 $ 5,072 $ 30,782 2027 4,753 30,782 2028 4,610 30,782 2029 3,226 30,782 2030 1,223 12,826 Thereafter 135 — Total lease payments $ 19,019 $ 135,954 Imputed interest ( 3,406 ) ( 24,312 ) Total lease liabilities $ 15,613 $ 111,642 The table below presents the weighted average remaining lease term and discount rate related to leases: Year Ended December 31, 2025 2024 2023 Weighted average remaining lease term: Operating leases 3.9 years 4.8 years 5.9 years Finance leases 4.4 years 5.4 years 6.4 years Weighted average discount rate: Operating leases 10.8 % 10.7 % 10.8 % Finance leases 9.2 % 9.2 % 9.2 % The table below presents the supplemental cash flow information related to leases (in thousands): Year Ended December 31, 2025 2024 2023 Operating cash outflow from finance leases $ 11,193 $ 12,948 $ 14,476 Operating cash outflow from operating leases $ 5,830 $ 5,634 $ 6,318 ROU assets obtained in exchange for new operating lease liabilities (1) $ — $ 1,909 $ 12,971 Remeasurement of lease liability arising from modification of ROU asset (2) $ — $ — $ ( 5,124 ) (1) See QuarterNorth Acquisition and EnVen Acquisition each in Note 3 — Acquisitions and Divestitures . (2) Lease termination accounted for as a lease modification based on the modified lease term. The termination did not take effect contemporaneously with the effective date of the modification. Note 6 — Financial Instruments As of December 31, 2025 and 2024, the carrying amounts of cash and cash equivalents, restricted cash, accounts receivable and accounts payable approximate their fair values because they are highly liquid or due to the short-term nature of these instruments. Debt Instruments The following table presents the carrying amounts, net of discount and deferred financing costs, and estimated fair values of the Company’s debt instruments (in thousands): December 31, 2025 December 31, 2024 Carrying Amount Fair Value Carrying Amount Fair Value 9.000 % Second-Priority Senior Secured Notes $ 614,058 $ 649,425 $ 611,135 $ 640,619 9.375 % Second-Priority Senior Secured Notes $ 612,131 $ 656,250 $ 610,264 $ 635,750 The carrying value of the senior notes are adjusted for discount, premium and deferred financing costs. Fair value is estimated (representing a Level 1 fair value measurement) using quoted secondary market trading prices and, where such prices are not available, other observable (Level 2) inputs are used such as quoted prices for similar liabilities in the active markets. See Note 8 — Debt for the maturity dates of the Company’s Senior Notes. F- 21 Table of Contents The fair value of the Bank Credit Facility is estimated based on the outstanding borrowings under the Bank Credit Facility since it is secured by the Company’s reserves and the interest rates are variable and reflective of market rates (representing a Level 2 fair value measurement). Oil and Natural Gas Derivatives The Company attempts to mitigate a portion of its commodity price risk and stabilize cash flows associated with sales of oil and natural gas production. The Company is currently utilizing oil and natural gas swaps and costless collars. Swaps are contracts where the Company either receives or pays depending on whether the oil or natural gas floating market price is above or below the contracted fixed price. Costless collars consist of a purchased put option and a sold call option with no net premiums paid to or received from counterparties. Typical collar contracts require payments by the Company if the NYMEX average closing price is above the ceiling price or payments to the Company if the NYMEX average closing price is below the floor price. The following table presents the impact that derivatives, not designated as hedging instruments, had on its Consolidated Statements of Operations (in thousands): Year Ended December 31, 2025 2024 2023 Net cash received (paid) on settled derivative instruments $ 81,471 $ 4,710 $ ( 9,457 ) Unrealized gain (loss) 23,984 ( 6,168 ) 90,385 Price risk management activities income (expense) $ 105,455 $ ( 1,458 ) $ 80,928 The following tables reflect the contracted average daily volumes and weighted average prices under the terms of the Company's derivative contracts as of December 31, 2025: Swap Contracts Production Period Settlement Index Volumes Swap Price Crude oil: (Bbls) (per Bbl) January 2026 – December 2026 NYMEX WTI CMA 8,197 $ 65.51 Natural gas: (MMBtu) (per MMBtu) January 2026 – December 2026 NYMEX Henry Hub 28,671 $ 3.85 Two-Way Collar Contracts Production Period Settlement Index Volumes Floor Price Ceiling Price Crude oil: (Bbls) (per Bbl) (per Bbl) January 2026 – December 2026 NYMEX WTI CMA 11,997 $ 60.00 $ 68.25 The following tables provide additional information related to financial instruments measured at fair value on a recurring basis (in thousands): December 31, 2025 Level 1 Level 2 Level 3 Total Assets: Oil and natural gas derivatives $ — $ 54,420 $ — $ 54,420 Liabilities: Oil and natural gas derivatives — ( 6,708 ) — ( 6,708 ) Total net asset (liability) $ — $ 47,712 $ — $ 47,712 December 31, 2024 Level 1 Level 2 Level 3 Total Assets: Oil and natural gas derivatives $ — $ 33,739 $ — $ 33,739 Liabilities: Oil and natural gas derivatives — ( 10,011 ) — ( 10,011 ) Total net asset (liability) $ — $ 23,728 $ — $ 23,728 F- 22 Table of Contents Financial Statement Presentation Derivatives are classified as either current or non-current assets or liabilities based on their anticipated settlement dates. Although the Company has master netting arrangements with its counterparties, the Company presents its derivative financial instruments on a gross basis in its Consolidated Balance Sheets. The following table presents the fair value of derivative financial instruments as well as the potential effect of netting arrangements on the Company's recognized derivative asset and liability amounts (in thousands): December 31, 2025 December 31, 2024 Assets Liabilities Assets Liabilities Oil and natural gas derivatives: Current $ 54,420 $ 6,708 $ 33,486 $ 6,474 Non-current — — 253 3,537 Total gross amounts presented on balance sheet 54,420 6,708 33,739 10,011 Less: Gross amounts not offset on the balance sheet 6,708 6,708 10,011 10,011 Net amounts $ 47,712 $ — $ 23,728 $ — Credit Risk The Company is subject to the risk of loss on its financial instruments as a result of nonperformance by counterparties pursuant to the terms of their contractual obligations. The Company has entered into International Swaps and Derivative Association agreements with counterparties to mitigate this risk. The Company also maintains credit policies with regard to its counterparties to minimize overall credit risk. These policies require (i) the evaluation of potential counterparties’ financial condition to determine their credit worthiness; (ii) the regular monitoring of counterparties’ credit exposures; (iii) the use of contract language that affords the Company netting or set off opportunities to mitigate exposure risk; and (iv) potentially requiring counterparties to post cash collateral, parent guarantees, or letters of credit to minimize credit risk. The Company’s assets and liabilities from commodity price risk management activities at December 31, 2025 represent derivative instruments from eight counterparties; all of which are registered swap dealers that have an “investment grade” (minimum Standard & Poor’s rating of BBB- or better) credit rating and are parties under the Company’s Bank Credit Facility. The Company enters into derivatives directly with these counterparties and, subject to the terms of the Company’s Bank Credit Facility, is not required to post collateral or other securities for credit risk in relation to the derivative activities. Had the Company’s counterparties failed to perform under existing commodity derivative contracts the maximum loss at December 31, 2025 would have been $ 47.7 million. Note 7 — Equity Method Investments Talos Mexico See Note 3 – Acquisitions and Divestitures for additional information on the deconsolidation of Talos Mexico. On December 16, 2024, the Company entered into an agreement to sell an additional 30.1 % equity interest in Talos Mexico to Zamajal, a subsidiary of Carso, for $ 49.7 million in cash consideration with an additional $ 33.1 million contingent on first oil production from the Zama Field (the “Incremental Mexico Equity Sale”). The Incremental Mexico Equity Sale is expected to close no later than May of 2026 upon the satisfaction of customary closing conditions and the receipt of all regulatory approvals. As of December 31, 2025, Talos Mexico, which currently holds a 17.4 % interest in the Zama Field, is owned 50.1 % by the Company and 49.9 % by Zamajal. See Note 14 — Related Party Transactions for additional information on Carso. The carrying amount of the Company’s investment in Talos Mexico was $ 112.4 million and $ 111.3 million as of December 31, 2025 and 2024, respectively. The carrying amount of the investment includes a $ 66.0 million positive basis difference, which will be amortized using the units-of-production method upon commencement of regular commercial production from the Zama Field. Bayou Bend CCS LLC In March 2024, the Company sold its entire CCS business inclusive of Bayou Bend CCS LLC (“Bayou Bend”). S ee Note 3 – Acquisitions and Divestitures for additional information on the TLCS Divestiture. During the year ended December 31, 2023, Chevron U.S.A. Inc. (“Chevron”) made $ 8.6 million of contributions to Bayou Bend on the Company’s behalf in accordance with an agreement executed in 2022. The Bayou Bend investment was increased with an offsetting gain as the capital carry was funded by Chevron. The Company recognized an $ 8.6 million gain during the year ended December 31, 2023 on the funding of the capital carry of its investment in Bayou Bend. This gain is included in “Equity method investment income (expense)” on the Consolidated Statements of Operations. VIE Disclosures VIE and Primary Beneficiary Determination — Talos Mexico was determined to be a VIE. Talos Mexico did not have sufficient equity at risk to finance activities without additional subordinated financial support. The Company is not the primary beneficiary of Talos Mexico due to the governance structure of this entity. The most significant activities of Talos Mexico are jointly controlled by the owners. F- 23 Table of Contents Financings — Talos Mexico has historically been funded through equity contributions from owners. Maximum Exposure — The Company’s maximum exposure to loss as result of its involvement with Talos Mexico is the carrying amount of its investment. Nature of Risks — Talos Mexico holds a working interest in the unitized Zama Field. Developing oil fields with partners involves certain operational risks - namely, disagreements over project management, reliance on the operator’s capabilities, and high capital expenditures. An Integrated Project Team (“IPT”) reporting to the Zama Unit Operating Committee, was formed in March 2023 to pool the talents and competencies of all companies participating in the development of the Zama Field. Even though an IPT exists, teamwork could remain a challenge. The Zama Unit Development Plan (“UDP”) was approved by CNH in June 2023. Final Investment Decision (“FID”) is expected following completion and final review of the front-end engineering and design (“FEED”), project financing and final approvals. Achieving FID is a crucial stage and marks the beginning of the engineering and construction stage. Availability of equipment and unexpected construction hurdles could delay the start of oil and gas production. There is also a risk that the project will not be completed within the budget and timeline, which ultimately could have an adverse impact on the net present value of the project. On December 31, 2025, operatorship of the Zama Unit was transferred from Petróleos Mexicanos to Harbour Energy. Note 8 — Debt A summary of the detail comprising the Company’s debt and the related book values for the respective periods presented is as follows (in thousands): Maturity Date December 31, 2025 December 31, 2024 9.000 % Second-Priority Senior Secured Notes February 1, 2029 $ 625,000 $ 625,000 9.375 % Second-Priority Senior Secured Notes February 1, 2031 625,000 625,000 Bank Credit Facility March 31, 2027 — — Total debt, before discount and deferred financing cost 1,250,000 1,250,000 Unamortized discount and deferred financing cost, net ( 23,811 ) ( 28,601 ) Total debt $ 1,226,189 $ 1,221,399 9.000% Second-Priority Senior Secured Notes—due February 2029 The 9.000% Second-Priority Senior Secured Notes due 2029 (the “ 9.000 % Notes”) were issued pursuant to an indenture dated February 7, 2024, by and among the Company, Talos Production Inc. (the “Issuer”), the subsidiary guarantors party thereto (together with the Company, the “Guarantors”) and Wilmington Trust, National Association, as trustee and collateral agent. The 9.000% Notes are secured on a second-priority senior secured basis by liens on substantially the same collateral as the collateral securing the Issuer’s existing first-priority obligations under its Bank Credit Facility. The 9.000 % Notes rank equally in right of payment with all of the Issuer’s and the Guarantors’ existing and future senior obligations, are senior in right of payment to any obligations of the Issuer and the Guarantors future debt that is, by its term, expressly subordinated in right of payment to the 9.000% Notes and, to the extent of the value of the collateral, are effectively senior to all existing and future unsecured obligations of the Issuer and the Guarantors (other than the Company) and any future obligations of the Issuer and the Guarantors that are secured by the collateral on a junior-priority basis. The 9.000 % Notes are effectively pari passu with all of the Issuer’s and the Guarantors’ existing and future obligations that are secured by the collateral on a second-priority basis including the 9.375% Notes (as defined below) and are effectively junior to any existing and future obligations of the Issuer and the Guarantors that are secured by the collateral on a senior-priority basis to the 9.000% Notes including indebtedness under the Bank Credit Facility. The 9.000 % Notes mature on February 1, 2029 and have interest payable semi-annually each February 1 and August 1 , commencing August 1, 2024. At any time prior to February 1, 2026, the Company may redeem up to 40 % of the principal amount of the 9.000% Notes at a redemption rate of 109.00 % of the principal amount plus accrued and unpaid interest. At any time prior to February 1, 2026, the Company may also redeem some or all of the 9.000% Notes, plus a “make-whole premium,” together with accrued and unpaid interest, if any, to, but excluding, the date of redemption. Thereafter, the Company may redeem all or a portion of the 9.000% Notes in whole at any time or in part from time to time at the following redemption prices (expressed as percentages of the principal amount) plus accrued and unpaid interest if redeemed during the period commencing on February 1 of the years set forth below : Period Redemption Price 2026 104.500 % 2027 102.250 % 2028 and thereafter 100.000 % As of December 31, 2024, the Company has incurred debt issuance costs of $ 16.3 million related to the 9.000% Notes issued as part of the debt offering that partially funded the cash portion of the QuarterNorth Acquisition. The debt issue costs reduced the proceeds from the debt issued. See Note 3 — Acquisitions and Divestitures for further discussion on the QuarterNorth Acquisition. F- 24 Table of Contents 9.375% Second-Priority Senior Secured Notes—due February 2031 The 9.375% Second-Priority Senior Secured Notes due 2031 (the “ 9.375 % Notes” and, together with the 9.000% Notes, the “Senior Notes”) were issued pursuant to an indenture dated February 7, 2024, by and among the Company, the Issuer, the Guarantors party thereto and Wilmington Trust, National Association, as trustee and collateral agent. The 9.375% Notes are secured on a second-priority senior secured basis by liens on substantially the same collateral as the collateral securing the Issuer’s existing first-priority obligations under its Bank Credit Facility. The 9.375 % Notes rank equally in right of payment with all of the Issuer’s and the Guarantors’ existing and future senior obligations, are senior in right of payment to any obligations of the Issuer and the Guarantors future debt that is, by its term, expressly subordinated in right of payment to the 9.375% Notes and, to the extent of the value of the collateral, are effectively senior to all existing and future unsecured obligations of the Issuer and the Guarantors (other than the Company) and any future obligations of the Issuer and the Guarantors that are secured by the collateral on a junior-priority basis. The 9.375 % Notes are effectively pari passu with all of the Issuer’s and the Guarantors’ existing and future obligations that are secured by the collateral on a second-priority basis including the 9.000% Notes and are effectively junior to any existing and future obligations of the Issuer and the Guarantors that are secured by the collateral on a senior-priority basis to the 9.375% Notes including indebtedness under the Bank Credit Facility. The 9.375 % Notes mature on February 1, 2031 and have interest payable semi-annually each February 1 and August 1 , commencing August 1, 2024. At any time prior to February 1, 2027, the Company may redeem up to 40 % of the principal amount of the 9.375% Notes at a redemption rate of 109.375 % of the principal amount plus accrued and unpaid interest. At any time prior to February 1, 2027, the Company may also redeem some or all of the 9.375% Notes, plus a “make-whole premium,” together with accrued and unpaid interest, if any, to, but excluding, the date of redemption. Thereafter, the Company may redeem all or a portion of the 9.375% Notes in whole at any time or in part from time to time at the following redemption prices (expressed as percentages of the principal amount) plus accrued and unpaid interest if redeemed during the period commencing on February 1 of the years set forth below : Period Redemption Price 2027 104.688 % 2028 102.344 % 2029 and thereafter 100.000 % As of December 31, 2024, the Company has incurred debt issuance costs of $ 16.3 million related to the 9.375% Notes issued as part of the debt offering that partially funded the cash portion of the QuarterNorth Acquisition. The debt issue costs reduced the proceeds from the debt issued. Debt Covenants for 9.000% Notes and 9.375% Notes Each of the indentures that govern the 9.000% Notes and the 9.375% Notes contain covenants that, among other things, limit the Issuer’s ability and the ability of its restricted subsidiaries to: (i) incur, assume or guarantee additional indebtedness or issue certain convertible or redeemable equity securities; (ii) create liens to secure indebtedness; (iii) pay distributions or dividends on equity interests, redeem or repurchase equity securities or redeem junior lien, unsecured or subordinated indebtedness; (iv) make investments; (v) restrict distributions, loans or other asset transfers from the Issuer’s restricted subsidiaries; (vi) consolidate with or merge with or into, or sell substantially all of the Issuer’s properties to, another person; (vii) sell or otherwise dispose of assets, including equity interests in subsidiaries; and (viii) enter into transactions with affiliates. These covenants are subject to certain exceptions and qualifications. The Company was in compliance with all debt covenants at December 31, 2025 . 12.00% Second-Priority Senior Secured Notes On February 7, 2024 , the Company redeemed $ 638.5 million aggregate principal amount of the 12.00 % Second-Priority Senior Secured Notes due 2026 (the “12.00% Notes”) at 103.000 % plus accrued and unpaid interest using the proceeds from the issuance of the Senior Notes. The debt redemption resulted in a loss on extinguishment of debt of $ 54.9 million, which is presented as “Other income (expense)” on the Consolidated Statements of Operations. 11.75% Senior Secured Second Lien Notes On February 7, 2024, the Company redeemed $ 227.5 million aggregate principal amount of the 11.75 % Senior Secured Second Lien Notes due 2026 (the “11.75% Notes”) at 102.938 % plus accrued and unpaid interest using the proceeds from the issuance of the Senior Notes. The debt redemption resulted in a loss on extinguishment of debt of $ 5.4 million, which is presented as “Other income (expense)” on the Consolidated Statements of Operations. Bank Credit Facility The Company maintains the Bank Credit Facility with a syndicate of financial institutions. The borrowing base is redetermined by the lenders at least semi-annually during the second quarter and fourth quarter of each year based on a proved reserves report that the Company delivers to the administrative agent of its Bank Credit Facility. F- 25 Table of Contents On August 4, 2025, the Company entered into the Borrowing Base Redetermination Agreement and Twelfth Amendment to Credit Agreement (the “Twelfth Amendment”). The Twelfth Amendment, among other things, (i) decreased both the borrowing base and commitments to $ 700.0 million and (ii) removed the $ 50.0 million cap on the amount of unrestricted cash that may be deducted in the calculation of consolidated total debt (used to calculate the Consolidated Total Debt to EDITDAX ratio under the Bank Credit Facility) if, as of the applicable date of determination, each lender’s total exposure is $ 0 . Interest under the Bank Credit Facility accrues at the Company’s option either at an alternate base rate (“ABR”) plus the applicable margin (“ABR Loans”), an adjusted term secured overnight financing rate (“SOFR”) plus the applicable margin (“Term Benchmark Loans”) or adjusted daily simple SOFR plus the applicable margin (“RFR Loans”). The ABR is based on the greater of (a) the prime rate, (b) a federal funds rate plus 0.5 % or (c) the adjusted term SOFR for a one-month interest period plus 1.00 %. The adjusted term SOFR is equal to the term SOFR for each applicable tenor (e.g., one-month, three-months, six-months, and twelve-months) calculated and published by the CME Group Inc. plus 0.10 %. The adjusted daily simple SOFR is equal to the overnight SOFR calculated and published by the Federal Reserve Bank of New York plus 0.10 %. In addition, the Company is obligated to pay a commitment fee on the unutilized portion of the commitments. The pricing grid below shows the applicable margin for Term Benchmark Loans, RFR Loans and ABR Loans as well as the commitment fee rate, in each case based upon the applicable borrowing base utilization percentage: Borrowing Base Utilization Percentage Utilization Term Benchmark Loans and RFR Loans ABR Loans Commitment Fee Rate Level 1 < 25 % 2.75 % 1.75 % 0.38 % Level 2 ≥ 25 % < 50 % 3.00 % 2.00 % 0.38 % Level 3 ≥ 50 % < 75 % 3.25 % 2.25 % 0.50 % Level 4 ≥ 75 % < 90 % 3.50 % 2.50 % 0.50 % Level 5 ≥ 90 % 3.75 % 2.75 % 0.50 % The Bank Credit Facility has certain debt covenants, the most restrictive of which is that the Company must maintain a Consolidated Total Debt to EBITDAX Ratio (as defined in the Bank Credit Facility) of no greater than 3.00 to 1.00 calculated each quarter utilizing the most recent twelve months to determine EBITDAX. The Company must also maintain a current ratio no less than 1.00 to 1.00 each quarter. Under the Bank Credit Facility, unutilized commitments are included in current assets in the current ratio calculation. The Bank Credit Facility is secured by, among other things, mortgages covering at least 85.0 % of the oil and natural gas assets of the Company. The Bank Credit Facility is fully and unconditionally guaranteed by the Company and certain of its wholly-owned subsidiaries. As of December 31, 2025, the Company's borrowing base was $ 700.0 million with total commitments of $ 700.0 million . Additionally, no more than $ 250.0 million of the Company’s borrowing base can be used as letters of credit with current commitments at $ 250.0 million. The amount the Company is able to borrow with respect to the borrowing base is subject to compliance with the financial covenants and other provisions of the Bank Credit Facility. The Company was in compliance with all debt covenants at December 31, 2025. See Note 15 — Commitments and Contingencies for the amount of letters of credit issued under the Bank Credit Facility as of December 31, 2025. Subsequent Event — On January 20, 2026, Talos Energy Inc., Talos Production Inc., a Delaware corporation and wholly owned subsidiary of the Company (“Talos Production”), and certain other direct and indirect subsidiaries of the Company and Talos Production entered into the Amended and Restated Credit Agreement (the “A&R Credit Agreement”) among the Company, Talos Production, as Borrower, JPMorgan Chase Bank, N.A., as administrative agent (the “Administrative Agent”), the issuing banks, the lenders party thereto, and the other persons from time to time party thereto. The A&R Credit Agreement amends and restates in its entirety the credit agreement, dated as of May 10, 2018 (as amended from time to time, the “Existing Credit Agreement”), by and among the Company, Talos Production, as Borrower, JPMorgan Chase Bank, N.A., as administrative agent, the issuing banks, the lenders party thereto, and the other persons party thereto. This credit facility has an initial borrowing base and total commitments of $ 700.0 million (with a letter of credit facility with a $ 250 million sublimit), subject to redetermination by the lenders at least semi-annually during the second quarter and fourth quarter of each year. The maturity date of the A&R Credit Agreement is the earlier of (i) January 20, 2030 and (ii) November 2, 2028 (the 91st day prior to the earliest stated maturity date of the 9.000 % Notes, (or any Permitted Refinancing Indebtedness with respect thereto)), if such notes (or such Permitted Refinancing Indebtedness) have not been refinanced, redeemed, or repaid in full on prior to such 91st day. Interest accrues at Talos Production’s option either at an alternate base rate (“ABR”) plus the applicable margin (“ABR Loans”), an adjusted term secured overnight financing rate (“SOFR”) plus the applicable margin (“Term Benchmark Loans”) or adjusted daily simple SOFR plus the applicable margin (“RFR Loans”). ABR is based on the greater of (a) the prime rate, (b) a federal funds rate plus 0.5 % or (c) the adjusted term SOFR for a one-month interest period plus 1.00 %. The adjusted term SOFR is equal to the term SOFR for each applicable tenor (e.g., one-month, three-months and six-months) calculated and published by the CME Group Inc. The adjusted daily simple SOFR is equal to the overnight SOFR calculated and published by the Federal Reserve Bank of New York. In addition, Talos Production is obligated to pay a commitment fee on the unutilized portion of the commitments. The applicable margin and the commitment fee rate are calculated based upon the utilization levels as a percentage of unused lender commitments then in effect. F- 26 Table of Contents The A&R Credit Agreement includes certain conditions to borrowings, representations and warranties and events of default customary for financings of its type and size. The A&R Credit Agreement also limits the Company’s, Talos Production’s and their respective subsidiaries’ ability to, among other things, incur additional indebtedness, grant liens on any assets, pay dividends or make certain restricted payments, make certain investments, consummate certain asset sales, make certain payments on indebtedness, and merge, consolidate or engage in other fundamental changes. The A&R Credit Agreement has certain customary affirmative and negative covenants, including that Talos Production must maintain a Consolidated Total Debt to EBITDAX Ratio (as defined in the A&R Credit Agreement) of no greater than to 3.00 to 1.00 calculated each quarter utilizing the most recent twelve months to determine EBITDAX. Talos Production must also maintain a current ratio no less than 1.00 to 1.00 each quarter. Under the A&R Credit Agreement, unutilized commitments are included in current assets in the current ratio calculation. This credit facility is secured by, among other things, mortgages covering at least 85.0 % of the proved oil and natural gas assets of the Company and is fully and unconditionally guaranteed by the Company and certain of its wholly-owned subsidiaries. Limitation on Restricted Payments Including Dividends The Company has not historically declared or paid any cash dividends on its capital stock. However, to the extent the Company determines in the future that it may be appropriate to pay a special dividend or initiate a quarterly dividend program, the Company’s ability to pay any such dividends to its stockholders may be limited to the extent its consolidated subsidiaries are limited in their ability to make distributions to the Parent Company, including the significant restrictions that the agreements governing the Company’s debt impose on the ability of its consolidated subsidiaries to make distributions and other payments to the Parent Company. With respect to entities accounted for under the equity method, the Company’s equity method investee as of December 31, 2025 did not have any undistributed earnings. The Bank Credit Facility contains restrictions on the ability of Talos Production Inc. to transfer funds to the Parent Company in the form of cash dividends, loans or advances. The Bank Credit Facility restricts distributions and other payments to the Parent Company, subject to certain baskets and other exceptions described therein including the payment of operating expense incurred in the ordinary course of business and for income taxes attributable to its ownership in Talos Production Inc. Under the Bank Credit Facility, general distributions and other restricted payments may be made to the Company so long as after giving pro forma effect to the making of any such restricted payment (i) no default or event of default has occurred and is continuing; (ii) available commitments exceed 25 % of the then effective loan limit; (iii) the pro forma current ratio of 1.0 to 1.0 is satisfied; and (iv) either (A) the Consolidated Total Debt to EBITDAX Ratio (as defined in the Bank Credit Facility) is not greater than 1.75 to 1.00 and the aggregate amount of such restricted payments does not exceed the Available Free Cash Flow Amount (as defined in the Bank Credit Facility) at the time made or (B) the Consolidated Total Debt to EBITDAX Ratio is not greater than 1.00 to 1.00. In addition, each of the indentures governing the Senior Notes restrict the Issuer and its restricted subsidiaries from, directly or indirectly, among other things, declaring or paying any dividend on account of their equity securities, subject to certain limited exceptions described in the indentures. Such exceptions include, among other things, if (i) no default has occurred or would occur as a result thereof, (ii) immediately after giving effect to such transaction on a pro forma basis, the Issuer could incur $ 1.00 of additional indebtedness in compliance with a fixed charge coverage ratio of at least 2.25 to 1.00, (iii) immediately after giving effect to such transaction on a pro forma basis, the consolidated leverage ratio is not greater than 3.00 to 1.00, and (iii) if payments pursuant to such transaction, together with the aggregate amount of certain other restricted payments, is less than the cumulative credit permitted under the indenture. At December 31, 2025 , restricted net assets of the Company’s consolidated subsidiaries exceeded 25 %. F- 27 Table of Contents Note 9 — Asset Retirement Obligations The asset retirement obligations included in the Consolidated Balance Sheets in current and non-current liabilities, and the changes in that liability were as follows (in thousands): Year Ended December 31, 2025 2024 Balance, beginning of period $ 1,149,735 $ 897,226 Obligations assumed (1) 10,868 199,519 Obligations incurred 14,146 107 Obligations settled ( 117,847 ) ( 108,789 ) Obligations divested ( 3,150 ) — Accretion expense 125,296 117,604 Changes in estimate (2) 153,080 44,068 Balance, end of period $ 1,332,128 $ 1,149,735 Less: Current portion 112,489 97,166 Long-term portion $ 1,219,639 $ 1,052,569 (1) Obligations assumed during the year ended December 31, 2024 were in connection with the QuarterNorth Acquisition. See further discussion in Note 3 — Acquisitions and Divestitures . (2) Changes in estimate were primarily due to changes in expected timing and cost estimates to satisfy certain future abandonment obligations. At December 31, 2025, the Company has (1) restricted cash of $ 76.2 million inclusive of interest earned to date, held in escrow and (2) the P&A Notes Receivable with an aggregate face value of $ 66.2 million to settle future asset retirement obligations. These assets are discussed in Note 2 — Summary of Significant Accounting Policies . Note 10 — Stockholders’ Equity Underwritten Equity Offering On January 22, 2024, we closed an underwritten public offering of 34.5 million shares of our common stock, which generated net proceeds of $ 387.7 million after deducting underwriting discounts of $ 15.1 million and offering expenses of $ 0.8 million. The net proceeds from this equity offering partially funded the cash portion of the QuarterNorth Acquisition. See Note 3 – Acquisitions and Divestitures for additional information on the QuarterNorth Acquisition. Note 11 — Employee Benefits Plans and Share-Based Compensation Severance During the years ended December 31, 2024 and 2023, the Company accrued severance costs of $ 26.0 million and $ 25.3 million, respectively, in connection with the EnVen Acquisition, QuarterNorth Acquisition and TLCS Divestiture. See Note 3 — Acquisitions and Divestitures for additional information. The involuntary termination benefits were provided pursuant to (i) a one-time benefit arrangement that was recognized over the future service period through the termination date and (ii) contractual termination benefits required by the terms of existing employment agreements. Severance costs are reflected in “General and administrative expense” on the Consolidated Statements of Operations. The severance accrual had been reduced to an immaterial amount by December 31, 2024. In connection with the departure of the Company’s former President and Chief Executive Officer on August 29, 2024, the Company incurred $ 5.0 million of severance, all of which is reflected in “General and administrative expense” on the Consolidated Statements of Operations. Long Term Incentive Plan The Amended and Restated Talos Energy Inc. 2021 Long Term Incentive Plan (the “A&R LTIP”) became effective on May 23, 2024 and authorizes the Company to grant awards of up to 12,439,415 shares of the Company’s common stock, subject to the share recycling and adjustment provisions of the A&R LTIP. The A&R LTIP also extends the term of the plan to May 23, 2034. The A&R LTIP provides for potential grants of: (i) incentive stock options qualified as such under U.S. federal income tax laws (“ISOs”), (ii) stock options that do not qualify as ISOs (together with ISOs, “Options”), (iii) stock appreciation rights, (iv) restricted stock awards, (v) RSUs, (vi) awards of vested stock, (vii) dividend equivalents, (viii) other share-based or cash awards and (ix) substitute awards. Employees, non-employee directors and other service providers of the Company and its affiliates are eligible to receive awards under the A&R LTIP. Award of Vested Stock — On November 1, 2024, the Company entered into a separation and release agreement with its former President and Chief Executive Officer and granted, pursuant to the A&R LTIP, a stock award of 28,519 fully vested shares of the Company’s common stock. This grant represented the pro rata portion of the Company’s 2024 LTIP award to which the former executive was entitled. F- 28 Table of Contents Restricted Stock Units – Employees — RSUs granted to employees under the A&R LTIP primarily vest ratably over an approximate three-year period subject to such employee’s continued service through each vesting date. Upon vesting, each RSU represents a contingent right to receive one share of common stock. The total unrecognized share-based compensation expense related to these RSUs at December 31, 2025 was approximately $ 31.5 million, which is expected to be recognized over a weighted average period of 1.8 years. On September 9, 2024, there were 157,071 RSUs issued as retention awards to executive officers that were required to report their beneficial ownership of the Company's equity securities and any transactions in such securities. These retention RSUs will vest ratably on each of September 9, 2025, September 9, 2026, and September 9, 2027. On November 1, 2024, the Company’s former Interim Chief Executive Officer and President was granted 43,630 RSUs, all of which vested on December 31, 2024. The Company’s former Interim Chief Executive Officer and President also agreed to forfeit 4,273 RSUs that he was granted in 2024 for his service as a non-employee member of the Board. Restricted Stock Units – Non-employee Directors — RSUs granted to non-employee directors under the A&R LTIP vest approximately one year following the date of grant, subject to such non-employee director’s continued service through the vesting date. Each non-employee director is provided the opportunity to defer the settlement of their RSUs until a later date, as timely selected pursuant to a deferral election form. Following the vesting date, or such later date as elected by the director pursuant to the deferral election, these RSUs are settled 60 % in shares of our common stock and 40 % in cash, unless the director timely elects for the awards to be settled 100 % in shares of our common stock. The following table summarizes RSU activity: Restricted Stock Units Weighted Average Grant Date Fair Value Unvested RSUs at December 31, 2022 3,215,504 $ 12.79 Granted 1,154,541 $ 16.24 Vested ( 1,730,959 ) $ 11.97 Forfeited ( 332,725 ) $ 14.52 Unvested RSUs at December 31, 2023 2,306,361 $ 14.89 Granted 3,155,776 $ 11.97 Vested ( 1,534,798 ) $ 13.72 Forfeited ( 384,904 ) $ 14.65 Unvested RSUs at December 31, 2024 3,542,435 $ 12.83 Granted 3,017,967 $ 8.80 Vested ( 1,484,838 ) $ 13.46 Forfeited ( 479,809 ) $ 10.25 Unvested RSUs at December 31, 2025 4,595,755 $ 10.25 Performance Share Units – Employees — PSUs granted to employees under the A&R LTIP represent the contingent right to receive one share of common stock. However, the number of shares of common stock issuable ranges from zero to 200 % of the target number of PSUs granted. The total unrecognized share-based compensation expense related to these PSUs at December 31, 2025 was approximately $ 6.9 million, which is expected to be recognized over a weighted average period of 1.8 years. F- 29 Table of Contents The following table summarizes PSU activity: Performance Share Units Weighted Average Grant Date Fair Value Unvested PSUs at December 31, 2022 638,601 $ 23.66 Granted (1) 595,394 $ 18.76 Forfeited ( 217,346 ) $ 21.28 Unvested PSUs at December 31, 2023 1,016,649 $ 21.30 Granted (2) 299,472 $ 11.36 Forfeited (3) ( 666,455 ) $ 22.71 Unvested PSUs at December 31, 2024 649,666 $ 15.27 Granted (4) 1,014,647 $ 9.87 Forfeited (5) ( 550,014 ) $ 15.94 Unvested PSUs at December 31, 2025 1,114,299 $ 10.02 (1) There were 297,697 PSUs granted that are eligible to vest based on continued employment and the Company’s annualized absolute TSR over a three-year performance period. An additional 297,697 PSUs were granted and are eligible to vest based on continued employment and the Company’s return on the wells included in the 2023 drill program over a three-year performance period. (2) Eligible to vest based on continued employment and the relative annualized TSR of the Company as compared to a peer group over a three-year performance period, as modified by the Company’s absolute annualized TSR over the same performance period. Additionally, on November 1, 2024, the Company entered into a separation and release agreement with its former President and Chief Executive Officer and granted, pursuant to the A&R LTIP, an award of 38,844 PSUs. This grant represented the pro rata portion of the Company’s 2024 LTIP award to which the former executive was entitled. (3) The performance period for 475,604 PSUs ended on December 31, 2024. The payout on these awards was 0 % based on actual performance over the performance period as certified by the Compensation Committee of the Company’s Board of Directors in early 2025. Since these awards were legally forfeited they were added back to the plan reserve for future grants under the recycling provisions of the A&R LTIP. (4) There were 837,066 PSUs granted that are eligible to vest based on continued employment and the relative annualized TSR of the Company as compared to a peer group over a three-year performance period, as modified by the Company’s absolute annualized TSR over the same performance period. The remaining PSUs granted are eligible to vest based on continued employment and the achievement of certain stock-price hurdles over a three-year performance period. (5) The performance period for 317,494 PSUs ended on December 31, 2025. The payout on these awards was 0 % based on actual performance over the performance period as certified by the Compensation Committee of the Company’s Board of Directors in early 2026. Since these awards were legally forfeited, they were added back to the plan reserve for future grants under the recycling provisions of the A&R LTIP. The following table summarizes the assumptions used in the Monte Carlo simulations to calculate the fair value of the relative or absolute TSR PSUs granted during the periods indicated: Year Ended December 31, 2025 2024 2023 Expected term (in years) 2.3 - 2.8 2.2 - 2.3 2.1 - 2.8 Expected volatility 45.6 - 52.4 % 49.5 - 54.4 % 61.9 - 73.1 % Risk-free interest rate 3.5 - 3.8 % 3.6 - 4.1 % 4.4 - 4.6 % Dividend yield — % — % — % Share-based Compensation Costs Share-based compensation costs associated with RSUs, PSUs and other awards are reflected as “General and administrative expense” on the Consolidated Statements of Operations, net amounts capitalized to “Proved Properties” on the Consolidated Balance Sheets. Because of the non-cash nature of share-based compensation, the expensed portion of share-based compensation is added back to net income in arriving at “Net cash provided by (used in) operating activities” on the Consolidated Statements of Cash Flows. The following table presents the amount of costs expensed and capitalized (in thousands): Year Ended December 31, 2025 2024 2023 Share-based compensation costs $ 25,967 $ 22,088 $ 25,236 Less: Amounts capitalized to oil and gas properties 7,549 7,626 12,283 Total share-based compensation expense $ 18,418 $ 14,462 $ 12,953 F- 30 Table of Contents N ote 12 — Income Taxes Income Tax Expense (Benefit) The components of income tax expense (benefit) were as follows (in thousands): Year Ended December 31, 2025 2024 2023 Current income tax expense (benefit): Federal $ ( 140 ) $ ( 2,180 ) $ 18 State 739 103 58 Mexico 73 309 31 Total current income tax expense (benefit) $ 672 $ ( 1,768 ) $ 107 Deferred income tax expense (benefit): Federal $ ( 94,409 ) $ ( 10,874 ) $ ( 61,182 ) State ( 15,432 ) 17,645 478 Mexico — — — Total deferred income tax expense (benefit) $ ( 109,841 ) $ 6,771 $ ( 60,704 ) Total income tax expense (benefit) $ ( 109,169 ) $ 5,003 $ ( 60,597 ) A reconciliation of income tax expense (benefit) computed at the U.S. federal statutory tax rate to the Company’s income tax expense (benefit) is as follows (in thousands, except percentages): Year Ended December 31, 2025 2024 2023 Income tax expense (benefit) at the federal statutory tax rate $ ( 126,944 ) 21.0 % $ ( 14,992 ) 21.0 % $ 26,614 21.0 % State and local income taxes, net of federal benefit (1) ( 14,849 ) 2.5 % 17,726 ( 24.8 )% 524 0.4 % Foreign tax effects Mexico Statutory tax rate difference between Mexico and U.S. 169 ( 0.0 )% 295 ( 0.4 )% 436 0.4 % Other ( 565 ) 0.1 % ( 671 ) 0.9 % ( 1,452 ) ( 1.1 )% Change in valuation allowance 28,800 ( 4.8 )% — — % ( 93,726 ) ( 74.0 )% Nontaxable or nondeductible items 2,848 ( 0.5 )% 4,925 ( 6.9 )% 4,419 3.5 % Effect of cross-border tax laws 395 ( 0.1 )% 620 ( 0.9 )% 1,016 0.8 % Change in unrecognized tax benefits 73 ( 0.0 )% 65 ( 0.1 )% 31 0.0 % Other adjustments 904 ( 0.1 )% ( 2,965 ) 4.2 % 1,541 1.2 % Total income tax expense (benefit) $ ( 109,169 ) 18.1 % $ 5,003 ( 7.0 )% $ ( 60,597 ) ( 47.8 )% Effective tax rate 18.1 % ( 7.0 )% ( 47.8 )% (1) State and local taxes in Louisiana made up the majority (greater than 50%) of the tax effect in this category. The Company’s effective tax rate for the year ended December 31, 2025 differed from the federal statutory rate of 21.0 % primarily due to recording an income tax expense of $ 28.8 million related to recording a valuation allowance on its U.S. federal deferred tax assets offset with a state income tax benefit of $ 14.8 million. The Company’s effective tax rate for the year ended December 31, 2024 differed from the federal statutory rate of 21.0 % primarily due to state income tax expense of $ 17.7 million and income tax expense of $ 4.9 million related to nontaxable or nondeductible items. The Company’s effective tax rate for the year ended December 31, 2023 differed from the federal statutory rate of 21.0 % primarily due to a non-cash tax benefit of $ 93.7 million related to the release of the valuation allowance for its federal deferred tax assets offset with income tax expense of $ 4.4 million related to nontaxable or nondeductible items. F- 31 Table of Contents Deferred Tax Assets and Liabilities Net deferred tax assets and liabilities reflect the net tax effects of temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for income tax purposes. Net deferred tax assets and liabilities is included in “Other liabilities” on the Consolidated Balance Sheets as of December 31, 2025. Significant components of deferred tax assets and liabilities were as follows (in thousands): Year Ended December 31, 2025 2024 Deferred tax assets: Federal net operating loss $ 139,330 $ 108,717 Foreign tax loss carryforward 544 452 State net operating loss 16,359 12,426 Interest expense carryforward 40,177 74,957 Asset retirement obligations 302,222 262,773 Finance lease liability 25,389 29,926 Other 19,286 25,347 Total deferred tax assets 543,307 514,598 Valuation allowance ( 32,735 ) ( 3,325 ) Total deferred tax assets, net $ 510,572 $ 511,273 Deferred tax liabilities: Oil and gas properties $ 656,457 $ 772,439 Derivatives 10,851 5,411 Total deferred tax liabilities 667,308 777,850 Net deferred tax liability $ ( 156,736 ) $ ( 266,577 ) Net Operating Loss The table below presents the details of the Company’s net operating loss carryovers as of December 31, 2025 (in thousands): Amount Expiration Year Federal net operating losses $ 263,501 2036 - 2037 Federal net operating losses $ 399,976 Unlimited Foreign tax loss carryforward $ 1,812 2026 - 2035 State net operating losses $ 373,383 Unlimited As of December 31, 2025, the Company had U.S. federal net operating loss carryforwards (“NOLs”) of approximately $ 663.5 million , $ 569.8 million of which are subject to limitations under Section 382 of the Internal Revenue Code of 1986, as amended (the “Code”). Section 382 of the Code provides an annual limitation with respect to the ability of a corporation to utilize its tax attributes, against future U.S. taxable income in the event of a change in o wnership. If not utilized, such carryforwards would begin to expire at the end of 2036 . Valuation Allowance The Company recorded a valuation allowance of $ 32.7 million and $ 3.3 million as of December 31, 2025 and 2024, respectively. Deferred income tax assets and liabilities are recorded related to NOLs and temporary differences between the book and tax basis of assets and liabilities expected to produce tax deductions and income in the future. The realization of these assets depends on recognition of sufficient future taxable income in specific tax jurisdictions in which those NOLs or temporary differences relate. At December 31, 2025, the Company’s valuation allowance primarily related to the temporary differences related to the Company’s asset retirement obligations. At December 31, 2024, the company’s valuation allowance related to state operating loss carryforwards. In assessing the need for a valuation allowance, the Company considers whether it is more likely than not that some portion or all of the deferred tax assets will not be realized using available positive and negative evidence, including future reversals of temporary differences, tax-planning strategies and future taxable income, to estimate whether sufficient future taxable income will be generated to permit use of deferred tax assets. A significant piece of objective negative evidence evaluated is the cumulative loss incurred over recent years. Such objective negative evidence limits the Company’s ability to consider other subjective positive evidence. F- 32 Table of Contents Uncertain Tax Positions The table below sets forth the beginning and ending balance of the total amount of unrecognized tax benefits. Balances in the uncertain tax positions are as follows (in thousands): Year Ended December 31, 2025 2024 2023 Total unrecognized tax benefits, beginning balance $ 1,592 $ 989 $ 835 Increases in unrecognized tax benefits as a result of: Tax positions taken during a prior period 277 ( 120 ) 154 Tax positions taken during the current period — 723 — Total unrecognized tax benefits, ending balance $ 1,869 $ 1,592 $ 989 The Company recognizes interest and penalties related to uncertain tax positions as “Interest Expense” and “General and administrative expense” on the Consolidated Statements of Operations, respectively. Income Taxes Paid The components of income taxes paid (net of refunds) were as follows (in thousands): Year Ended December 31, 2025 2024 2023 Income taxes paid (net of refunds) Federal (U.S.) $ 179 $ 5,215 $ ( 18 ) Louisiana 418 1 — Other 34 ( 297 ) 12 Total income taxes paid (net of refunds) $ 631 $ 4,919 $ ( 6 ) Years Open to Examination The 2022 through 2025 tax years remain open to examination by the tax jurisdictions in which the Company is subject to tax. The statute of limitations with respect to the U.S. federal income tax returns of the Company for years ending on or before December 31, 2020 are closed, except to the extent of any NOL carryover balance. Not e 13 — Income (Loss) Per Share Basic earnings per common share is computed by dividing net income (loss) attributable to common stockholders by the weighted average number of shares of common stock outstanding during the period. Except when the effect would be antidilutive, diluted earnings per common share includes the impact of RSUs and PSUs. The following table presents the computation of the Company’s basic and diluted income (loss) per share attributable to common stockholders (in thousands, except for the per share amounts): Year Ended December 31, 2025 2024 2023 Net income (loss) attributable to Talos Energy Inc. $ ( 494,290 ) $ ( 76,393 ) $ 187,332 Weighted average common shares outstanding — basic 175,136 175,605 119,894 Dilutive effect of securities — — 858 Weighted average common shares outstanding — diluted 175,136 175,605 120,752 Net income (loss) per share attributable to common stockholders: Basic $ ( 2.82 ) $ ( 0.44 ) $ 1.56 Diluted $ ( 2.82 ) $ ( 0.44 ) $ 1.55 Anti-dilutive potentially issuable securities excluded from diluted common shares 3,581 2,084 1,353 F- 33 Table of Contents Note 14 — Related Party Transactions Slim Family and Affiliates Carlos Slim Helú, Carlos Slim Domit, Marco Antonio Slim Domit, Patrick Slim Domit, María Soumaya Slim Domit, Vanessa Paola Slim Domit and Johanna Monique Slim Domit (collectively, the “Slim Family”) are beneficiaries of a Mexican trust which in turn owns all of the outstanding voting securities of Control Empresarial de Capitales S.A. de C.V. (“Control Empresarial” together with the Slim Family, the “Slim Family Office”). Control Empresarial, a sociedad anónima de capital variable organized under the laws of the United Mexican States, is a holding company with portfolio investments in various companies. Control Empresarial and the Slim Family became related parties on November 7, 2023 when they accumulated greater than ten percent of the Company’s outstanding shares of common stock. In connection with the Company’s underwritten public equity offering in January 2024 as further described in Note 10 — Stockholders’ Equity , Control Empresarial further increased its holding of the Company’s outstanding stock and thereafter continued to purchase shares from time to time in the open market. On December 16, 2024, the Company entered into a cooperation agreement (“Cooperation Agreement”) with Control Empresarial. Pursuant to the Cooperation Agreement, Control Empresarial agreed during the term of the Cooperation Agreement that it will not acquire, agree or seek to acquire or make any proposal or offer to acquire, or announce any intention to acquire, directly or indirectly, beneficially or otherwise, any voting securities of the Company (other than in connection with a stock split, stock dividend or similar corporate action initiated by the Company) if, immediately after such acquisition, Control Empresarial and the other members of its investor group, collectively, would, in the aggregate, beneficially own in aggregate more than 25.0 % of the outstanding shares of any class of voting securities of the Company. However, pursuant to the Cooperation Agreement, Control Empresarial and the investor group are not required to sell any voting securities they own if the aggregate ownership exceeds 25.0 % solely because the Company repurchases shares or takes another similar action that reduces the number of outstanding voting securities. On December 8, 2025, the Company entered into an amendment to the Cooperation Agreement with Control Empresarial to extend the period of the Cooperation Agreement for an additional year, to December 16, 2026, but the agreement is subject to early termination upon the occurrence of certain events described in the Cooperation Agreement. Control Empresarial held approximately 25.8 % of the Company’s outstanding shares of common stock as of December 31, 2025 based on SEC beneficial ownership reports filed by Control Empresarial and the Company’s total outstanding shares of common stock as of that date. The Slim Family own a majority stake in Carso. Carso is a public stock company incorporated in Mexico, which holds the shares of a group of companies that primarily operate in the commercial, industrial, infrastructure and construction and energy sectors. Carso, through its Zamajal subsidiary, has an ownership interest in Talos Mexico. See Note 7 – Equity Method Investments for additional information on Talos Mexico. As of December 31, 2025 , Carso owes the Company $ 2.8 million related to advisory services the Company provided in connection with the Lakach Deepwater natural gas field off Mexico’s southeastern coast near Veracruz. Grupo Financiero Inbursa, S.A.B. de C.V. (“GFI”) is a Mexico-based holding company engaged, through its subsidiaries, in the financial sector. The company’s main activities are structured in four business lines: commercial banking, asset management, insurance and investment banking. The Slim Family own a majority stake in GFI. Banco Inbursa, S.A., Institución de Banca Múltiple, Grupo Financiero Inbursa (“Banco Inbursa”) is a wholly owned banking subsidiary of GFI. In connection with the debt offering in February 2024, the Company consummated a firm commitment debt offering consisting of $ 1,250.0 million in aggregate principal amount of second-priority senior secured notes in a private offering to eligible purchasers that was exempt from registration under the Securities Act. In connection with the debt offering, and after expressing a non-binding indication of interest after commencement of the offering, entities and/or persons related to the Slim Family Office purchased an aggregate principal amount of $ 312.5 million of such notes from the initial purchasers of such offering. In connection with such transaction, the Company paid Banco Inbursa, an advisory fee of approximately $ 2.7 million. See Note 8 – Debt for additional information regarding the issuance of the second-priority senior secured notes. Equity Method Investments The Company had a $ 0.7 million and $ 0.7 million related party receivable from various equity method investments as of December 31, 2025 and 2024, respectively. These amounts are reflected in “Accounts Receivable, net” on the Consolidated Balance Sheets. See Note 7 – Equity Method Investments for additional information on the Company’s equity method investments. Note 15 — Commitments and Contingencies Legal Proceedings and Other Contingencies From time to time, the Company is involved in litigation, regulatory examinations and administrative proceedings primarily arising in the ordinary course of business in jurisdictions in which the Company does business. Although the outcome of these matters cannot be predicted with certainty, the Company’s management believes none of these matters, either individually or in the aggregate, would have a material effect upon the Company’s financial position; however, an unfavorable outcome could have a material adverse effect on the Company’s results from operations for a specific interim period or year. F- 34 Table of Contents During the year ended December 31, 2024, the Company settled long-standing litigation initiated in June 2019 involving the former President of EnVen, which was assumed as part of the EnVen Acquisition. The Company paid $ 14.4 million to satisfy the judgment, inclusive of legal fees and interest. By virtue of the Company’s acquisition of QuarterNorth, Talos is defending a lawsuit brought by a contractor concerning amounts allegedly owed for drilling operations at several locations in the Gulf of America. The lawsuit alleges that the contractor is entitled to certain statutory liens under Louisiana law. Talos disputes the contractor’s lien and damages claims and is defending the suit aggressively. A trial date has not been set for this case. It is reasonably possible that a loss may be realized, with the range of loss between zero and approximately $ 22 million. By virtue of the Company’s acquisition of QuarterNorth, Talos is defending a lawsuit brought by plaintiffs (“Warrant Holders”) that held warrants issued by QuarterNorth pursuant and subject to warrant agreements. Warrant Holders allege that the QuarterNorth board improperly reduced the value of the warrants, which diluted their ownership interest in QuarterNorth prior to its acquisition by Talos. Trial is scheduled for May 2026, in the Court of Chancery of the State of Delaware. It is reasonably possible that a loss may be realized, with the range of loss between zero and approximately $ 21 million. Firm Transportation Commitments The Company has firm transportation agreements in place with pipeline carriers for future transportation of oil and gas production. The Company is obligated to transport a minimum monthly oil and gas volumes or pay for any deficiencies for years 2026 through 2030. Our production is currently expected to exceed the minimum monthly volume in the periods provided in the agreements. The table below summarizes the future minimum transportation fees under the Company’s commitment as of December 31, 2025 (in thousands): 2026 $ 7,356 2027 11,760 2028 14,191 2029 7,468 2030 3,173 Total $ 43,948 Performance Obligations Regulations with respect to the Company's operations govern, among other things, engineering and construction specifications for production facilities, safety procedures, plugging and abandonment of wells, and removal of facilities in the U.S. Gulf of America. As of December 31, 2025, the Company had secured performance bonds from third party sureties totaling $ 1.5 billion . The cost of securing these bonds is reflected as “Interest expense” on the Consolidated Statements of Operations. Additionally, as of December 31, 2025, the Company had secured letters of credit issued under its Bank Credit Facility totaling $ 97.4 million . Letters of credit that are outstanding reduce the available revolving credit commitments. See Note 8 — Debt for further information on the Bank Credit Facility. On November 3, 2025, the Company entered into arrangements with its surety providers to establish limits on the amount of aggregate collateral that such surety providers can require the Company to post, with annual collateral funding commitments set forth in the table below. The arrangements also require the Company to spend a minimum amount on plugging and abandonment activities each year. For the three years commencing January 1, 2026 and for the subsequent two years commencing January 1, 2029, the Company is required to spend $ 90.0 million and $ 45.0 million on these activities on an annual basis, respectively. The table below outlines the estimated collateral funding commitments under the arrangements as of December 31, 2025 (in thousands): Period Collateral Funding Commitments 2026 $ 41,704 2027 42,694 2028 43,199 2029 42,134 2030 35,240 Thereafter 46,776 Total $ 251,747 F- 35 Table of Contents The collateral funding commitments may be secured by cash or letters of credit which will reduce the Company’s liquidity. For the year ended December 31, 2025 , we posted collateral of $ 40.1 million secured by letters of credit. Collateral funded with cash will be reflected as “Restricted cash” within the Consolidated Balance Sheets. The collateral funding commitments, and ultimately any posted cash collateral, will be reduced as plugging and abandonment activities are completed and underlying surety bonds are released. Decommissioning Obligations The Company, as a co-lessee or predecessor-in-interest in oil and natural gas leases located in the U.S. Gulf of America, is in the chain of title with unrelated third parties either directly or by virtue of divestiture of certain oil and natural gas assets previously owned and assigned by our subsidiaries. Certain counterparties in these divestiture transactions or third parties in existing leases have filed for bankruptcy protection or undergone associated reorganizations and may not be able to perform required abandonment obligations. Regulations or federal laws could require the Company to assume such obligations. The Company reflects such costs as “Other operating (income) expense” on the Consolidated Statements of Operations. The decommissioning obligations included are in the Consolidated Balance Sheets as “Other current liabilities” and “Other long-term liabilities”, and the changes in that liability were as follows (in thousands): Year Ended December 31, 2025 2024 2023 Balance, beginning of period $ 20,002 $ 15,564 $ 54,269 Additions 1,769 6,168 266 Obligations assumed — 1,326 — Changes in estimate 1,476 2,391 11,613 Settlements ( 1,102 ) ( 5,447 ) ( 50,584 ) Balance, end of period $ 22,145 $ 20,002 $ 15,564 Less: Current portion 470 5,453 3,280 Long-term portion $ 21,675 $ 14,549 $ 12,284 Although it is reasonably possible that the Company could receive state or federal decommissioning orders in the future or be notified of defaulting third parties in existing leases, the Company cannot predict with certainty, if, how or when such orders or notices will be resolved or estimate a possible loss or range of loss that may result from such orders. However, the Company could incur judgments, enter into settlements or revise its opinion regarding the outcome of certain notices or matters, and such developments could have a material adverse effect on its results of operations in the period in which the amounts are accrued and its cash flows in the period in which the amounts are paid. Not e 16 — Segment Information The Company’s operations were managed through two operating segments through March 18, 2024: (i) the Upstream Segment and (ii) the CCS Segment, both of which were reportable for the year ended December 31, 2024. The CCS Segment was divested in March 2024. Prior to the divestment of the CCS Segment, corporate general and administrative expense included certain shared costs such as finance, accounting, tax, human resources, information technology and legal costs that were not directly attributable to each operating segment. These shared expenses were fully allocated to each operating segment. Segment accounting policies are the same as those described in Note 2 – Summary of Significant Accounting Policies The chief operating decision maker (“CODM”) is currently the President and Chief Executive Officer and Chief Financial Officer . The profit or loss metric used to evaluate segment performance is net income as reported in the Company’s Consolidated Statements of Operations. Net income is used by the CODM to measure segment profit or loss, assess performance and make strategic capital resource allocations. The Company’s CODM does not review assets by segment as part of the financial information provided and therefore, no asset information is provided in the tables below. F- 36 Table of Contents The following tables present selected segment information for the periods indicated (in thousands): Year Ended December 31, 2025 Upstream Total Revenues from external customers $ 1,780,070 $ 1,780,070 Significant expenses: Direct operating and maintenance (1) ( 526,839 ) ( 526,839 ) Workover (1) ( 19,877 ) ( 19,877 ) Adjusted general and administrative expense (2) ( 133,986 ) ( 133,986 ) Net cash received (paid) on settled derivative instruments 81,471 81,471 Interest expense ( 163,381 ) ( 163,381 ) Other segment items: Other (3) 10,349 10,349 Depreciation, depletion and amortization ( 1,056,281 ) ( 1,056,281 ) Impairment of oil and natural gas properties ( 454,482 ) ( 454,482 ) Accretion expense ( 125,296 ) ( 125,296 ) Mark-to-market derivative fair value gain (loss) 23,984 23,984 Equity-based compensation expense ( 18,418 ) ( 18,418 ) Equity method investment income (loss) ( 1,807 ) ( 1,807 ) Income tax benefit (expense) 109,169 109,169 Net income (loss) ( 495,324 ) $ ( 495,324 ) Segment Expenditures $ 617,575 $ 617,575 (1) Component of lease operating expense. (2) Includes general and administrative expense less transaction expenses and equity-based compensation. (3) Primarily includes interest income and other miscellaneous operating income offset by the derecognition of a deferred payment that was deemed uncollectible. Year Ended December 31, 2024 Upstream CCS (1) Total Revenues from external customers $ 1,973,568 $ — $ 1,973,568 Significant expenses: Direct operating and maintenance (2) ( 492,123 ) — ( 492,123 ) Workover (2) ( 73,918 ) — ( 73,918 ) Adjusted general and administrative expense (3) ( 130,695 ) ( 1,919 ) ( 132,614 ) Net cash received (paid) on settled derivative instruments 4,710 — 4,710 Interest expense ( 187,432 ) ( 206 ) ( 187,638 ) Other segment items: Other (4) ( 23,048 ) ( 8,472 ) ( 31,520 ) Depreciation, depletion and amortization ( 1,023,512 ) ( 46 ) ( 1,023,558 ) Accretion expense ( 117,604 ) — ( 117,604 ) Mark-to-market derivative fair value gain (loss) ( 6,168 ) — ( 6,168 ) Equity-based compensation expense ( 14,415 ) ( 47 ) ( 14,462 ) Gain on TLCS Divestiture (5) — 100,482 100,482 Equity method investment income (loss) ( 2,319 ) ( 7,970 ) ( 10,289 ) Gain (loss) on extinguishment of debt ( 60,256 ) — ( 60,256 ) Income tax benefit (expense) 12,188 ( 17,191 ) ( 5,003 ) Net income (loss) $ ( 141,024 ) $ 64,631 $ ( 76,393 ) Segment Expenditures $ 603,765 $ 17,519 $ 621,284 (1) The CCS Segment was an emerging business in the start-up phase of operations and the business did no t generate any revenues. (2) Component of lease operating expense. (3) Includes general and administrative expense less transaction expenses and equity-based compensation. Corporate overhead allocated to the Upstream Segment and CCS Segment was $ 78.5 million and $ 0.4 million, respectively. (4) Primarily includes transaction expenses offset by interest income for the Upstream Segment and transaction expenses for the CCS Segment. Transaction expenses include severance expense, costs related to the QuarterNorth Acquisition and costs related to the TLCS Divestiture. See further discussion in Note 3 — Acquisition and Divestitures and Note 11 — Employee Benefits Plans and Share-Based Compensation . (5) See further discussion in Note 3 — Acquisitions and Divestitures for additional information. F- 37 Table of Contents Year Ended December 31, 2023 Upstream CCS (1) Total Revenues from external customers $ 1,457,886 $ — $ 1,457,886 Significant expenses: Direct operating and maintenance (2) ( 374,481 ) — ( 374,481 ) Workover (2) ( 15,140 ) — ( 15,140 ) Adjusted general and administrative expense (3) ( 88,333 ) ( 10,423 ) ( 98,756 ) Net cash received (paid) on settled derivative instruments ( 9,457 ) — ( 9,457 ) Interest expense ( 172,060 ) ( 1,085 ) ( 173,145 ) Other segment items: Other (4) ( 55,048 ) 4,159 ( 50,889 ) Depreciation, depletion and amortization ( 661,904 ) ( 1,630 ) ( 663,534 ) Accretion expense ( 86,152 ) — ( 86,152 ) Mark-to-market derivative fair value gain (loss) 90,385 — 90,385 Equity-based compensation expense ( 11,454 ) ( 1,499 ) ( 12,953 ) Gain on the 2023 Mexico Divestiture (5) 66,180 — 66,180 Equity method investment income (loss) 120 ( 12,229 ) ( 12,109 ) Gain (loss) on partial sale of equity investment (6) — 8,900 8,900 Income tax benefit (expense) 57,719 2,878 60,597 Net income (loss) $ 198,261 $ ( 10,929 ) $ 187,332 Segment Expenditures $ 733,669 $ 40,961 $ 774,630 (1) The CCS Segment was an emerging business in the start-up phase of operations and the business did no t generate any revenues. (2) Component of lease operating expense. (3) Includes general and administrative expense less transaction expenses and equity-based compensation. Corporate overhead allocated to the Upstream Segment and CCS Segment was $ 49.3 million and $ 1.7 million, respectively. (4) Primarily includes transaction expenses and decommissioning obligations for the Upstream Segment. Transaction expenses include costs related to the EnVen Acquisition, inclusive of severance expense. See further discussion in Note 3 — Acquisition and Divestitures , Note 11 — Employee Benefits Plans and Share-Based Compensation and Note 15 — Commitments and Contingencies . (5) See further discussion in Note 3 — Acquisitions and Divestitures for additional information. (6) Includes a gain on the funding of the capital carry of the Company’s investment in Bayou Bend by Chevron of $ 8.6 million. See further discussion in Note 7 — Equity Method Investments. The following table presents the reconciliation of Segment Expenditures to the Company’s consolidated totals (in thousands): Year Ended December 31, 2025 2024 2023 Segment Expenditures: Total reportable segments $ 617,575 $ 621,284 $ 774,630 Change in capital expenditures included in accounts payable and accrued liabilities 829 29,423 ( 9,199 ) Plugging & abandonment ( 117,847 ) ( 108,789 ) ( 86,615 ) Decommissioning obligations settled ( 1,102 ) ( 5,447 ) ( 50,584 ) Investment in Talos Mexico ( 4,559 ) ( 5,469 ) — Investment in CCS intangibles and equity method investees — ( 17,519 ) ( 40,946 ) Other deferred payments ( 2,104 ) ( 2,389 ) ( 1,545 ) Non-cash well equipment transfers ( 15,837 ) ( 3,412 ) ( 27,731 ) Other 4,950 1,232 3,424 Exploration, development and other capital expenditures $ 481,905 $ 508,914 $ 561,434 F- 38 Table of Contents Note 17 — Suppl emental Oil and Gas Disclosures (Unaudited) Capitalized Costs Aggregate amounts of capitalized costs relating to oil, natural gas and NGL activities and the aggregate amount of related accumulated depreciation, depletion and amortization (“DD&A”) as of the dates indicated are presented below (in thousands): Year Ended December 31, 2025 2024 2023 Consolidated Entities: Proved properties $ 10,621,012 $ 9,784,832 $ 7,906,295 Unproved oil and gas properties, not subject to amortization 480,555 587,238 268,315 Total oil and gas properties 11,101,567 10,372,070 8,174,610 Less: Accumulated DD&A 6,672,024 5,163,844 4,143,491 Net capitalized costs $ 4,429,543 $ 5,208,226 $ 4,031,119 DD&A rate (Per Boe) $ 30.51 $ 30.11 $ 27.23 Company's Share of Equity Investees: Unproved oil and gas properties, not subject to amortization $ 62,528 $ 58,723 $ 56,579 Included in the depletable basis of proved oil and gas properties is the estimate of the Company’s proportionate share of asset retirement costs relating to these properties which are also reflected as “Asset retirement obligations” on the accompanying Consolidated Balance Sheets. See Note 9 — Asset Retirement Obligations for additional information. Costs Incurred for Property Acquisition, Exploration and Development Activities The following table reflects the costs incurred in oil, natural gas and NGL property acquisition, exploration and development activities during the years indicated (in thousands). Costs incurred also include new asset retirement obligations established in the current year, as well as increases or decreases to the asset retirement obligations resulting from changes to estimates during the year. Year Ended December 31, 2025 2024 2023 Consolidated Entities: Property acquisition costs: Proved properties $ 62,689 $ 1,085,324 $ 951,703 Unproved properties, not subject to amortization — 380,129 249,688 Total property acquisition costs 62,689 1,465,453 1,201,391 Exploration costs 54,647 129,400 161,296 Development costs 618,441 602,607 805,148 Total costs incurred $ 735,777 $ 2,197,460 $ 2,167,835 Company's Share of Equity Investees: Exploration costs $ 3,805 $ 2,144 $ 290 Estimated Quantities of Proved Oil, Natural Gas and NGL Reserves The Company employs full-time experienced reserve engineers and geologists who are responsible for determining proved reserves in compliance with SEC guidelines. There are numerous uncertainties inherent in estimating quantities of proved reserves and projecting future rates of production and timing of development expenditures. The reserve data in the following tables only represent estimates and should not be construed as being exact. Engineering reserve estimates were prepared based upon interpretation of production performance data and subsurface information obtained from the drilling of existing wells. All of the Company’s proved oil, natural gas and NGL reserves are located in the U.S. Gulf of America. At December 31, 2025 and 2024 all proved reserves were estimated by Netherland, Sewell & Associates, Inc (“NSAI”), independent petroleum engineers and geologists. At December 31, 2023, 100 % of proved oil, natural gas and NGL reserves attributable to all of the Company’s oil and natural gas properties were estimated and compiled for reporting purposes by the Company’s reservoir engineers and audited by NSAI. F- 39 Table of Contents The following table presents the Company’s estimated proved reserves at its net ownership interest: Oil (MBbls) Gas (MMcf) NGLs (MBbls) Oil Equivalent (MBoe) Consolidated Entities: Total proved reserves at December 31, 2022 91,059 219,551 12,928 140,579 Revision of previous estimates ( 6,308 ) ( 62,946 ) ( 1,283 ) ( 18,082 ) Production ( 18,062 ) ( 26,194 ) ( 1,767 ) ( 24,195 ) Acquisition of reserves 41,871 36,690 1,116 49,102 Extensions and discoveries 2,255 12,770 979 5,362 Total proved reserves at December 31, 2023 110,815 179,871 11,973 152,766 Revision of previous estimates ( 599 ) ( 30,186 ) 698 ( 4,932 ) Production ( 24,078 ) ( 41,078 ) ( 2,969 ) ( 33,893 ) Acquisition of reserves 51,376 99,683 4,834 72,824 Extensions and discoveries 5,534 9,684 329 7,477 Total proved reserves at December 31, 2024 143,048 217,974 14,865 194,242 Revision of previous estimates 3,944 15,826 ( 686 ) 5,896 Production ( 24,065 ) ( 46,122 ) ( 2,782 ) ( 34,534 ) Acquisition of reserves 7,232 2,573 10 7,670 Extensions and discoveries 467 4,349 227 1,419 Total proved reserves at December 31, 2025 130,626 194,600 11,634 174,693 Total Proved Developed Reserves as of: December 31, 2023 98,225 141,823 9,957 131,819 December 31, 2024 108,479 175,139 12,733 150,402 December 31, 2025 101,031 156,420 9,644 136,745 Total Proved Undeveloped Reserves as of: December 31, 2023 12,590 38,048 2,016 20,947 December 31, 2024 34,569 42,835 2,132 43,840 December 31, 2025 29,595 38,180 1,990 37,948 During 2025, proved reserves decreased by 19.5 MMBoe primarily due to 34.5 MMBoe of production. This decrease was partially offset by the acquisition of reserves of 7.7 MMBoe in connection with the incremental working interests in the Monument Project and certain Mississippi Canyon blocks as discussed in Note 3 — Acquisitions and Divestitures as well as an increase of 5.9 MMBoe from revisions of previous estimates. The revisions were due to certain upward revisions for positive well performance primarily in the Katmai Field combined with the Lobster Field, and from the Venice and Lime Rock wells, which tie back to our Ram Powell facility. These upward revisions were partially offset by the derecognition of approximately 2.0 MMBoe of PUD reserves associated with our South Timbalier 308 Field in the Shelf (i.e., w ater depths up to 600 feet) area, resulting from a reassessment of the drilling and development plan following successful drilling at the Katmai Field. During 2024, proved reserves increased by 41.5 MMBoe primarily due to the acquisition of reserves of 72.8 MMBoe in connection with the QuarterNorth Acquisition and the Monument Project as well as 7.5 MMBoe of estimated proved reserves from extensions and discoveries primarily from evaluations of the Brutus Field, Ewing Bank 953 Field, Sunspear Field and Pompano Field in the Deepwater area. This increase was partially offset by 33.9 MMBoe of production and a decrease of 4.9 MMBoe from revisions of previous estimates. The revisions were primarily due to a 11.3 MMBoe of downward revisions primarily related to derecognizing proved developed non-producing and PUD cases in the Phoenix Field, Brutus Field and Prince Field, all located in the Deepwater area. Additionally, due to the Deepwater assets acquired via the QuarterNorth Acquisition and the Monument Project, the Company reassessed its drilling and development plan resulting in the derecognition of 4.2 MMBoe of PUD reserves primarily associated non-operated fields located in the Shelf & Gulf Coast area. These downward revisions were offset by upward revisions 15.3 MMBoe due to the successful drilling of the Katmai West #2 development well in addition to positive well performance primarily in the Katmai Field and Big Bend Field located in the Deepwater area. During 2023, proved reserves increased by 12.2 MMBoe primarily due to acquisition of reserves of 49.1 MMBoe in connection with the EnVen Acquisition and 5.4 MMBoe of estimated proved reserves from extensions and discoveries primarily from evaluations of the Brutus Field in the Deepwater area. This increase was partially offset by 24.2 MMBoe of production and a decrease of 18.1 MMBoe from revisions of previous estimates. The revisions were primarily due to a 13.5 MMBoe decrease in reserve volumes due to the decrease in SEC Pricing of $ 17.47 per Bbl of oil and $ 4.05 per Mcf of natural gas and an additional decrease in the Phoenix Field in the Deepwater area due to well performance. F- 40 Table of Contents Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil, Natural Gas and NGL Reserves The following table reflects the standardized measure of discounted future net cash flows relating to the Company’s interest in proved oil, natural gas and NGL reserves (in thousands): Year Ended December 31, 2025 2024 2023 Consolidated Entities: Future cash inflows $ 9,465,575 $ 11,660,546 $ 9,425,055 Future costs: Production ( 2,954,861 ) ( 3,436,232 ) ( 3,090,491 ) Development and abandonment ( 2,901,567 ) ( 3,301,619 ) ( 2,358,368 ) Future net cash flows before income taxes 3,609,147 4,922,695 3,976,196 Future income tax expense ( 519,461 ) ( 845,894 ) ( 589,413 ) Future net cash flows after income taxes 3,089,686 4,076,801 3,386,783 Discount at 10% annual rate ( 284,829 ) ( 512,597 ) ( 343,295 ) Standardized measure of discounted future net cash flows $ 2,804,857 $ 3,564,204 $ 3,043,488 Future cash inflows are computed by applying SEC Pricing to year-end quantities of proved reserves. The discounted future cash flow estimates do not include the effects of derivative instruments. See the following table for SEC Pricing used in determining the standardized measure: Year Ended December 31, 2025 2024 2023 Oil price per Bbl $ 65.37 $ 75.51 $ 78.56 Natural gas price per Mcf $ 3.61 $ 2.45 $ 2.75 NGL price per Bbl $ 19.22 $ 21.91 $ 18.77 Future net cash flows are discounted at the prescribed rate of 10 %. Actual future net cash flows may vary considerably from these estimates. Although the Company’s estimates of total proved reserves, development and abandonment costs and production rates were based on the best information available, the development and production of oil and gas reserves may not occur in the periods assumed. All estimated costs to settle asset retirement obligations associated with the Company’s proved reserves have been included in their calculation of development and abandonment of the standardized measure of discounted future net cash flows for each period presented. Actual prices realized, costs incurred and production quantities may vary significantly from those used. Therefore, such estimated future net cash flow computations should not be considered to represent the Company’s estimate of the expected revenues or the current value of existing proved reserves. Changes in Standardized Measure of Discounted Future Net Cash Flows Principal changes in the standardized measure of discounted future net cash flows attributable to the Company’s proved oil, natural gas and NGL reserves are as follows (in thousands): Year Ended December 31, 2025 2024 2023 Consolidated Entities: Standardized measure, beginning of year $ 3,564,204 $ 3,043,488 $ 4,368,448 Sales and transfers of oil, net gas and NGLs produced during the period ( 1,232,936 ) ( 1,406,150 ) ( 1,065,814 ) Net change in prices and production costs ( 946,617 ) ( 123,537 ) ( 2,835,125 ) Changes in estimated future development and abandonment costs 72,525 193,810 ( 19,877 ) Previously estimated development and abandonment costs incurred 183,066 47,016 202,503 Accretion of discount 420,072 485,409 518,110 Net change in income taxes 252,340 ( 181,190 ) 357,321 Purchases of reserves 143,040 1,638,000 2,033,852 Extensions and discoveries 7,250 74,126 90,244 Net change due to revision in quantity estimates 403,358 ( 162,041 ) ( 484,423 ) Changes in production rates (timing) and other ( 61,445 ) ( 44,727 ) ( 121,751 ) Standardized measure, end of year $ 2,804,857 $ 3,564,204 $ 3,043,488 F- 41 Table of Contents No te 18 — Subsequent Events Amended and Restated Credit Agreement For additional information, see Note 8 — Debt . F- 42 Table of Contents Schedule I. Condensed Financial Information of Registrant TALOS ENERGY INC. (PARENT ONLY) BALANCE SHEETS (In thousands, except share amounts) Year Ended December 31, 2025 2024 ASSETS Current assets: Prepaid assets $ — $ 203 Other current assets 179 19 Total current assets 179 222 Other long-term assets: Investments in subsidiaries 2,321,449 3,006,909 Total assets $ 2,321,628 $ 3,007,131 LIABILITIES AND STOCKHOLDERSʼ EQUITY Current liabilities: Accounts payable $ 40 $ 333 Accrued liabilities 567 544 Other current liabilities 1,058 162 Total current liabilities 1,665 1,039 Long-term liabilities: Other long-term liabilities 151,979 246,387 Total liabilities 153,644 247,426 Commitments and contingencies (Note 15) Stockholdersʼ equity: Preferred stock; $ 0.01 par value; 30,000,000 shares authorized and zero shares issued or outstanding as of December 31, 2025 and 2024, respectively — — Common stock; $ 0.01 par value; 270,000,000 shares authorized; 188,530,052 and 187,434,908 shares issued as of December 31, 2025 and 2024, respectively 1,885 1,874 Additional paid-in capital 3,296,643 3,274,626 Accumulated deficit ( 918,400 ) ( 424,110 ) Treasury stock, at cost; 20,015,369 and 7,417,385 shares as of December 31, 2025 and 2024, respectively ( 212,144 ) ( 92,685 ) Total stockholdersʼ equity 2,167,984 2,759,705 Total liabilities and stockholdersʼ equity $ 2,321,628 $ 3,007,131 See accompanying notes. F- 43 Table of Contents TALOS ENERGY INC. (PARENT ONLY) STATEMENTS OF OPERATIONS (In thousands) Year Ended December 31, 2025 2024 2023 Operating expenses: General and administrative expense $ 3,605 $ 3,234 $ 2,708 Total operating expenses 3,605 3,234 2,708 Operating income (expense) ( 3,605 ) ( 3,234 ) ( 2,708 ) Other income (expense) ( 1 ) ( 1 ) ( 1 ) Equity earnings (loss) from subsidiaries ( 585,315 ) ( 83,986 ) 128,888 Net income (loss) before income taxes ( 588,921 ) ( 87,221 ) 126,179 Income tax benefit (expense) 94,631 10,828 61,153 Net income (loss) $ ( 494,290 ) $ ( 76,393 ) $ 187,332 See accompanying notes. F- 44 Table of Contents TALOS ENERGY INC. (PARENT ONLY) STATEMENTS OF CASH FLOWS (In thousands) Year Ended December 31, 2025 2024 2023 Cash flows from operating activities: Net cash provided by (used in) operating activities $ ( 1,399 ) $ ( 1,403 ) $ ( 1,836 ) Cash flows from investing activities: Investments in subsidiaries — ( 389,138 ) — Distributions from subsidiaries 120,858 48,005 49,340 Net cash provided by (used in) investing activities 120,858 ( 341,133 ) 49,340 Cash flows from financing activities: Issuance of common stock — 387,717 — Purchase of treasury stock ( 119,459 ) ( 45,181 ) ( 47,504 ) Net cash provided (used in) by financing activities ( 119,459 ) 342,536 ( 47,504 ) Net increase (decrease) in cash and cash equivalents — — — Cash and cash equivalents: Balance, beginning of period — — — Balance, end of period $ — $ — $ — See accompanying notes. F- 45 Table of Contents TALOS ENERGY INC. (PARENT ONLY) NOTES TO CONDENSED FINANCIAL STATEMENTS December 31, 2025 Note 1 — Basis of Presentation Pursuant to the rules and regulations of the SEC, the parent only condensed financial information of Talos Energy, Inc. do not reflect all of the information and notes normally included with financial statements prepared in accordance with GAAP. Therefore, these condensed financial statements should be read in conjunction with the consolidated financial statements and related notes included under Part IV, Item 15. Exhibits and Financial Statement Schedules in this Annual Report. F- 46