TALOS ENERGY INC., 10-K filed on 2/25/2026
Annual Report
v3.25.4
Document and Entity Information - USD ($)
 12 Months Ended
Dec. 31, 2025
Feb. 17, 2026
Jun. 30, 2025
Cover [Abstract]      
Document Type 10-K    
Amendment Flag false    
Document Period End Date Dec. 31, 2025    
Document Fiscal Year Focus 2025    
Document Fiscal Period Focus FY    
Trading Symbol TALO    
Title of 12(b) Security Common Stock    
Security Exchange Name NYSE    
Entity Registrant Name Talos Energy Inc.    
Document Annual Report true    
Document Transition Report false    
Entity Small Business false    
Entity Emerging Growth Company false    
ICFR Auditor Attestation Flag true    
Auditor Name Ernst & Young LLP    
Auditor Location Houston, Texas    
Auditor Firm ID 42    
Entity Current Reporting Status Yes    
Entity Interactive Data Current Yes    
Entity Shell Company false    
Entity Incorporation, State or Country Code DE    
Entity File Number 001-38497    
Entity Tax Identification Number 82-3532642    
Entity Address, Address Line One 333 Clay Street    
Entity Address, Address Line Two Suite 3300    
Entity Address, City or Town Houston    
Entity Address, State or Province TX    
Entity Address, Postal Zip Code 77002    
City Area Code 713    
Local Phone Number 328-3000    
Entity Central Index Key 0001724965    
Current Fiscal Year End Date --12-31    
Entity Filer Category Large Accelerated Filer    
Entity Common Stock, Shares Outstanding   168,514,683  
Entity Well-known Seasoned Issuer Yes    
Entity Voluntary Filers No    
Entity Public Float     $ 1,106,796,185
Documents Incorporated by Reference

Portions of the registrant’s definitive proxy statement relating to the 2026 Annual Meeting of Stockholders are incorporated by reference into Part III of this report.

    
Document Financial Statement Error Correction Flag false    
Auditor Opinion [Text Block]

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.

    
v3.25.4
CONSOLIDATED BALANCE SHEETS - USD ($)
$ in Thousands
Dec. 31, 2025
Dec. 31, 2024
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 0 253
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
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 0 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)
Stockholders' 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 0 0
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 0
Total equity 2,168,123 2,759,705
Total liabilities and stockholdersʼ equity $ 5,552,057 $ 6,191,795
v3.25.4
CONSOLIDATED BALANCE SHEETS (Parenthetical) - $ / shares
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
Dec. 31, 2022
Statement of Financial Position [Abstract]        
Preferred stock, par value $ 0.01 $ 0.01    
Preferred stock, shares authorized 30,000,000 30,000,000    
Preferred stock, shares issued 0 0    
Preferred stock, shares outstanding 0 0    
Common stock, par value $ 0.01 $ 0.01    
Common stock, shares authorized 270,000,000 270,000,000    
Common stock, shares issued 188,530,052 187,434,908 127,480,361 82,570,328
Treasury stock, common, shares 20,015,369 7,417,385 3,400,000  
v3.25.4
CONSOLIDATED STATEMENTS OF OPERATIONS - USD ($)
shares in Thousands, $ in Thousands
 12 Months Ended
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
Revenues:      
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 0 0
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) 0 0
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
Oil      
Revenues:      
Revenues $ 1,560,401 $ 1,806,148 $ 1,357,732
Natural Gas      
Revenues:      
Revenues 169,445 105,528 68,034
NGL      
Revenues:      
Revenues $ 50,224 $ 61,892 $ 32,120
v3.25.4
CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS' EQUITY - USD ($)
$ in Thousands
Total
Common Stock
Additional Paid-in Capital
Accumulated Deficit
Treasury Stock
Noncontrolling Interest
Parent
Balance at Dec. 31, 2022 $ 1,165,576 $ 826 $ 1,699,799 $ (535,049)     $ 1,165,576
Beginning balance, issued shares at Dec. 31, 2022 82,570,328            
Beginning balance, outstanding shares at Dec. 31, 2022   82,570,328          
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)        
Equity-based compensation stock issuances, Shares 1,110,143 1,110,143          
Issuance of common stock for acquisitions $ 832,198 $ 438 831,760       832,198
Issuance of common stock for acquisitions, Shares 43,799,890 43,799,890          
Purchase of treasury stock $ (47,504)       $ (47,504)   47,504
Purchase of treasury stock, Shares (3,400,000)       (3,400,000)    
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest $ 187,332     187,332     187,332
Balance at Dec. 31, 2023 $ 2,155,151 $ 1,275 2,549,097 (347,717) $ (47,504)   2,155,151
Ending balance, issued shares at Dec. 31, 2023 127,480,361            
Ending balance, outstanding shares at Dec. 31, 2023   124,080,361          
Ending balance, treasury stock, common, shares at Dec. 31, 2023 (3,400,000)            
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)        
Equity-based compensation stock issuances, Shares 1,105,095 1,105,095          
Issuance of common stock for acquisitions $ 322,630 $ 243 322,387       322,630
Issuance of common stock for acquisitions, Shares 24,349,452 24,349,452          
Issuance of common stock $ 387,717 $ 345 387,372       387,717
Issuance of common stock, Shares 34,500,000 34,500,000          
Purchase of treasury stock $ (45,181)       $ (45,181)   45,181
Purchase of treasury stock, Shares (4,017,385)       (4,017,385)    
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest $ (76,393)     (76,393)     (76,393)
Balance at Dec. 31, 2024 2,759,705 $ 1,874 3,274,626 (424,110) $ (92,685)   2,759,705
Balance at Dec. 31, 2024 $ 2,759,705            
Ending balance, issued shares at Dec. 31, 2024 187,434,908            
Ending balance, outstanding shares at Dec. 31, 2024   180,017,523          
Ending balance, treasury stock, common, shares at Dec. 31, 2024 (7,417,385)            
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)        
Equity-based compensation stock issuances, Shares 1,095,144 1,095,144          
Initial consolidation of subsidiary $ 1,173         $ 1,173  
Purchase of treasury stock $ (119,459)       $ (119,459)   119,459
Purchase of treasury stock, Shares (12,597,984)       (12,597,984)    
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest $ (495,324)     (494,290)   (1,034) (494,290)
Balance at Dec. 31, 2025 2,167,984 $ 1,885 $ 3,296,643 $ (918,400) $ (212,144)   $ 2,167,984
Balance at Dec. 31, 2025 $ 2,168,123         $ 139  
Ending balance, issued shares at Dec. 31, 2025 188,530,052            
Ending balance, outstanding shares at Dec. 31, 2025   168,514,683          
Ending balance, treasury stock, common, shares at Dec. 31, 2025 (20,015,369)            
v3.25.4
CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 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 0 0
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 0 60,256 0
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 0 (100,482) 0
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 0 17,617
Payments for acquisitions, net of cash acquired (49,978) (936,214) 0
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 0 0 (12,366)
Proceeds from sale of business 0 146,676 0
Other (13,710) 0 0
Net cash provided by (used in) investing activities (546,746) (1,320,279) (512,626)
Cash flows from financing activities:      
Issuance of common stock 0 387,717 0
Issuance of senior notes 0 1,250,000 0
Redemption of senior notes 0 (897,116) (30,000)
Proceeds from Bank Credit Facility 0 880,000 825,000
Repayment of Bank Credit Facility 0 (1,080,000) (625,000)
Deferred financing costs 0 (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) 0 0
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
v3.25.4
Pay vs Performance Disclosure - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
Pay vs Performance Disclosure      
Net Income (Loss) $ (494,290) $ (76,393) $ 187,332
v3.25.4
Insider Trading Arrangements
 3 Months Ended
Dec. 31, 2025
Trading Arrangements, by Individual  
Rule 10b5-1 Arrangement Adopted false
Non-Rule 10b5-1 Arrangement Adopted false
Rule 10b5-1 Arrangement Terminated false
Non-Rule 10b5-1 Arrangement Terminated false
v3.25.4
Insider Trading Policies and Procedures
 12 Months Ended
Dec. 31, 2025
Insider Trading Policies and Procedures [Line Items]  
Insider Trading Policies and Procedures Adopted true
v3.25.4
Cybersecurity Risk Management, Strategy and Governance
 12 Months Ended
Dec. 31, 2025
Cybersecurity Risk Management, Strategy, and Governance [Line Items]  
Cybersecurity Risk Management Processes for Assessing, Identifying, and Managing Threats [Text Block]

Item 1C. Cybersecurity

Assessing, Identifying and Managing Cybersecurity Risks — We rely extensively on information technology (“IT”) and operational technology (“OT”) systems to support exploration, drilling, production, and administrative functions across our offshore and corporate operations. These systems include process control systems on production platforms, remote monitoring systems, and enterprise IT applications for finance, human resources, and supply chain management. Our cybersecurity program is designed to protect these systems from unauthorized access, data breaches, ransomware, and other cyber threats. We aim to implement industry-standard security measures including network segmentation, firewalls, intrusion detection, endpoint protection, multi-factor authentication, incident response plans, security awareness training, and regular security audits. In addition, we maintain policies and procedures designed to assess, identify and manage cybersecurity threats and incidents and strive to align our cybersecurity operating model with the National Institute of Standards and Technology Cybersecurity Framework (“NIST CSF”). We do not represent that our practices conform to any specific technical standards or requirements; rather, we utilize the NIST CSF as a framework that informs how we design our approach to identify, evaluate, and address cybersecurity risks in our operations. In November 2025, we appointed a Vice President - Chief Information Officer (“CIO”) to oversee our cybersecurity team, which actively works with third-party service providers to assess, identify and manage risks in our information systems in order to protect the confidentiality, integrity and availability of our digital infrastructure. The cybersecurity team meets regularly to evaluate potential threats, discuss best practices and identify new solutions to help mitigate cyber risks.

Our third-party service providers provide extended coverage of our information technology and operational technology environments and conduct regular evaluations of our cybersecurity controls, including testing the design and operational effectiveness of our cybersecurity controls. We also share and receive threat intelligence with other companies in the energy sector, government agencies, information sharing and analysis centers and cybersecurity associations in order to monitor and address developments in the cybersecurity environment.

To serve as an additional protection from outside threats, we also seek to prepare our employees and contractors about cybersecurity risks through cybersecurity training, simulated phishing exercises and awareness campaigns. We routinely conduct employee training, and point-in-time training for any phishing failures. We have implemented software and processes and currently use a managed service to help identify and evaluate risks from cybersecurity threats associated with third-party service vendors. In the event of a cybersecurity incident deemed to have a moderate or higher business impact, we have an incident response plan to notify senior leadership and to address how to contain the incident, mitigate the impact, and restore normal operations efficiently.

Cybersecurity Risk Assessment — We have integrated cybersecurity risk management into our broader Enterprise Risk Management (“ERM”) framework to promote a company-wide culture of cybersecurity risk management. Our ERM framework is designed to identify and prioritize company-wide risks, including cybersecurity threats, and integrate mitigation measures into our business, operational and capital structure planning activities. The purpose of the ERM framework is to enable the Board and executive leadership to (1) align risk management with strategic objectives, (2) identify risks, including cybersecurity risks, throughout the organization, (3) assess and prioritize risks that could impact the Company’s operational and strategic objectives, (4) develop and monitor risk mitigation initiatives, and (5) report and assess material risks, mitigation strategies and progress to the Board and/or its applicable committees. Cybersecurity risk is reviewed by a cross-functional, management-level ERM Steering Committee as part of the Company’s overall enterprise risk management program .

Board of Directors’ Oversight of Risks from Cybersecurity Threats — The Audit Committee has been delegated responsibility by the Board for overseeing the Company’s overall enterprise risk management program, including cybersecurity risk. The Audit Committee oversees our cybersecurity policies, procedures, risk exposures and the steps taken by management to monitor and mitigate cybersecurity risks. Our cybersecurity team regularly updates and reports to the Audit Committee regarding cybersecurity risk exposure and our cybersecurity risk management strategy. The Audit Committee Chair is responsible for reporting key cybersecurity issues regarding current and potential material cybersecurity threats and our risk mitigation response strategies to the Board. To further inform our Board and management on emerging cybersecurity issues, we periodically engage third-party cybersecurity experts to report to the Audit Committee, other directors, and management, as applicable, on topics that may include, among other things, the latest cybersecurity trends, new technologies, evolving threats in the marketplace, proposed initiatives, legislation, and reporting standards.

Management’s Role in Assessing and Managing Cybersecurity Threats — Our CIO is responsible for assessing, identifying and managing cybersecurity risks and is supported by the cybersecurity team. Top cybersecurity risks are also integrated into our overall ERM framework and overseen at the management level by the ERM Steering Committee. The CIO, who reports directly to the CFO and is a member of the ERM Steering Committee, is responsible for our efforts to comply with applicable cybersecurity standards, establish cybersecurity protocols and protect the integrity, confidentiality and availability of our information technology infrastructure. Technology and cybersecurity policy decisions are made by our CIO in consultation with our CFO. In addition, our CIO has a direct line of communication with the Chief Executive Officer and General Counsel, as needed. Our CIO has over 30 years of experience in information technology and cybersecurity, holds a Bachelor of Science from Royal Holloway, University of London and has performed the role of CIO for over 7 years within a leading upstream E&P Company including the responsibility and accountability to the Audit Committee for cybersecurity.

Impact of Risks from Cybersecurity Threats — The energy sector’s growing reliance on information and operational technology to manage critical business functions has significantly increased the exposure to cybersecurity threats. The rising frequency and sophistication of cyber incidents, whether resulting from deliberate attacks or accidental breaches, pose substantial risks to the energy industry. For example, a cyber-attack on a production control system could result in significant environmental and safety risks, such as a well incident, shut-in or spill that could cause business interruption, reputational damage, regulatory fines and penalties, costs of compliance and remediation or insurance limitations. Other examples of cybersecurity threats we face include incidents common to most companies in the energy industry, such as phishing, business email compromise, ransomware and denial-of-service, as well as attacks from more advanced sources, including nation state actors, that target companies in the energy industry. Our customers, suppliers, subcontractors and joint venture partners face similar cybersecurity threats. As these threats continue to evolve, effectively preventing, detecting, mitigating, and responding to cyber incidents has become an ongoing and increasingly complex challenge. Regulatory compliance adds another layer of complexity, particularly as cybersecurity reporting and disclosure requirements continue to evolve. These regulations require prompt and detailed disclosures of material cyber incidents, demanding significant resources and well-structured internal processes to maintain compliance. Failure to meet these obligations could lead to legal penalties, heightened regulatory oversight, and reputational harm. Additionally, the constantly shifting regulatory landscape may introduce overlapping or conflicting requirements, further complicating compliance efforts. To minimize potential risks, it is essential to closely monitor these developments and incorporate them into our cybersecurity and regulatory compliance strategies.

As of the date of this Annual Report, we are not aware of any cybersecurity incidents that have materially affected or are reasonably likely to materially affect the Company, although the Company periodically experiences cybersecurity incidents that are not deemed material to our business. A significant cybersecurity incident impacting us or third parties with whom we do business could materially and adversely disrupt our operations and affect our business strategy and performance, financial condition and results of operations. Although we believe we have implemented comprehensive cybersecurity measures, no security program is infallible. For additional information about cybersecurity risks, please see Part I, Item 1A. Risk Factors — Risks Related to our Business and the Oil and Natural Gas Industry — Technology and cybersecurity threats could disrupt our operations and cause reputational and financial harm to our business.
Cybersecurity Risk Management Processes Integrated [Flag] true
Cybersecurity Risk Management Processes Integrated [Text Block]

Cybersecurity Risk Assessment — We have integrated cybersecurity risk management into our broader Enterprise Risk Management (“ERM”) framework to promote a company-wide culture of cybersecurity risk management. Our ERM framework is designed to identify and prioritize company-wide risks, including cybersecurity threats, and integrate mitigation measures into our business, operational and capital structure planning activities. The purpose of the ERM framework is to enable the Board and executive leadership to (1) align risk management with strategic objectives, (2) identify risks, including cybersecurity risks, throughout the organization, (3) assess and prioritize risks that could impact the Company’s operational and strategic objectives, (4) develop and monitor risk mitigation initiatives, and (5) report and assess material risks, mitigation strategies and progress to the Board and/or its applicable committees. Cybersecurity risk is reviewed by a cross-functional, management-level ERM Steering Committee as part of the Company’s overall enterprise risk management program .
Cybersecurity Risk Management Third Party Engaged [Flag] true
Cybersecurity Risk Third Party Oversight and Identification Processes [Flag] true
Cybersecurity Risk Materially Affected or Reasonably Likely to Materially Affect Registrant [Flag] false
Cybersecurity Risk Board of Directors Oversight [Text Block]

Board of Directors’ Oversight of Risks from Cybersecurity Threats — The Audit Committee has been delegated responsibility by the Board for overseeing the Company’s overall enterprise risk management program, including cybersecurity risk. The Audit Committee oversees our cybersecurity policies, procedures, risk exposures and the steps taken by management to monitor and mitigate cybersecurity risks. Our cybersecurity team regularly updates and reports to the Audit Committee regarding cybersecurity risk exposure and our cybersecurity risk management strategy. The Audit Committee Chair is responsible for reporting key cybersecurity issues regarding current and potential material cybersecurity threats and our risk mitigation response strategies to the Board. To further inform our Board and management on emerging cybersecurity issues, we periodically engage third-party cybersecurity experts to report to the Audit Committee, other directors, and management, as applicable, on topics that may include, among other things, the latest cybersecurity trends, new technologies, evolving threats in the marketplace, proposed initiatives, legislation, and reporting standards.

Cybersecurity Risk Board Committee or Subcommittee Responsible for Oversight [Text Block] The Audit Committee has been delegated responsibility by the Board for overseeing the Company’s overall enterprise risk management program, including cybersecurity risk.To further inform our Board and management on emerging cybersecurity issues, we periodically engage third-party cybersecurity experts to report to the Audit Committee, other directors, and management, as applicable, on topics that may include, among other things, the latest cybersecurity trends, new technologies, evolving threats in the marketplace, proposed initiatives, legislation, and reporting standards.
Cybersecurity Risk Process for Informing Board Committee or Subcommittee Responsible for Oversight [Text Block] The Audit Committee oversees our cybersecurity policies, procedures, risk exposures and the steps taken by management to monitor and mitigate cybersecurity risks. Our cybersecurity team regularly updates and reports to the Audit Committee regarding cybersecurity risk exposure and our cybersecurity risk management strategy. The Audit Committee Chair is responsible for reporting key cybersecurity issues regarding current and potential material cybersecurity threats and our risk mitigation response strategies to the Board
Cybersecurity Risk Role of Management [Text Block]

Management’s Role in Assessing and Managing Cybersecurity Threats — Our CIO is responsible for assessing, identifying and managing cybersecurity risks and is supported by the cybersecurity team. Top cybersecurity risks are also integrated into our overall ERM framework and overseen at the management level by the ERM Steering Committee. The CIO, who reports directly to the CFO and is a member of the ERM Steering Committee, is responsible for our efforts to comply with applicable cybersecurity standards, establish cybersecurity protocols and protect the integrity, confidentiality and availability of our information technology infrastructure. Technology and cybersecurity policy decisions are made by our CIO in consultation with our CFO. In addition, our CIO has a direct line of communication with the Chief Executive Officer and General Counsel, as needed. Our CIO has over 30 years of experience in information technology and cybersecurity, holds a Bachelor of Science from Royal Holloway, University of London and has performed the role of CIO for over 7 years within a leading upstream E&P Company including the responsibility and accountability to the Audit Committee for cybersecurity.
Cybersecurity Risk Management Positions or Committees Responsible [Flag] true
Cybersecurity Risk Management Positions or Committees Responsible [Text Block] Technology and cybersecurity policy decisions are made by our CIO in consultation with our CFO. In addition, our CIO has a direct line of communication with the Chief Executive Officer and General Counsel, as needed.
Cybersecurity Risk Management Expertise of Management Responsible [Text Block] Our CIO has over 30 years of experience in information technology and cybersecurity, holds a Bachelor of Science from Royal Holloway, University of London and has performed the role of CIO for over 7 years within a leading upstream E&P Company including the responsibility and accountability to the Audit Committee for cybersecurity.
Cybersecurity Risk Process for Informing Management or Committees Responsible [Text Block] Technology and cybersecurity policy decisions are made by our CIO in consultation with our CFO. In addition, our CIO has a direct line of communication with the Chief Executive Officer and General Counsel, as needed.
Cybersecurity Risk Management Positions or Committees Responsible Report to Board [Flag] true
v3.25.4
Organization, Nature of Business and Basis of Presentation
 12 Months Ended
Dec. 31, 2025
Organization, Consolidation and Presentation of Financial Statements [Abstract]  
Organization, Nature of Business and Basis of Presentation

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.
v3.25.4
Summary of Significant Accounting Policies
 12 Months Ended
Dec. 31, 2025
Organization, Consolidation and Presentation of Financial Statements [Abstract]  
Summary of Significant Accounting Policies

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.

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.

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.

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.

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.

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

 
v3.25.4
Acquisitions and Divestitures
 12 Months Ended
Dec. 31, 2025
Business Combination [Abstract]  
Acquisitions and Divestitures

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).

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.

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

 

 

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.

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.

v3.25.4
Property, Plant and Equipment
 12 Months Ended
Dec. 31, 2025
Oil and Gas, Joint Interest Billing, Receivable [Abstract]  
Property, Plant and Equipment

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.
v3.25.4
Leases
 12 Months Ended
Dec. 31, 2025
Leases [Abstract]  
Leases

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

 

 

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.
v3.25.4
Financial Instruments
 12 Months Ended
Dec. 31, 2025
Financial Instruments [Abstract]  
Financial Instruments

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.

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

 

 

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.
v3.25.4
Equity Method Investments
 12 Months Ended
Dec. 31, 2025
Equity Method Investments and Joint Ventures [Abstract]  
Equity Method Investments

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”). See 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.

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.
v3.25.4
Debt
 12 Months Ended
Dec. 31, 2025
Debt Disclosure [Abstract]  
Debt

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.

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.

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.

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%.
v3.25.4
Asset Retirement Obligations
 12 Months Ended
Dec. 31, 2025
Asset Retirement Obligation Disclosure [Abstract]  
Asset Retirement Obligations

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.

v3.25.4
Stockholders' Equity
 12 Months Ended
Dec. 31, 2025
Equity [Abstract]  
Stockholders' Equity

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.
v3.25.4
Employee Benefits Plans and Share-Based Compensation
 12 Months Ended
Dec. 31, 2025
Share-Based Payment Arrangement [Abstract]  
Employee Benefits Plans and Share-Based Compensation

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.

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.

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

 
v3.25.4
Income Taxes
 12 Months Ended
Dec. 31, 2025
Income Tax Disclosure [Abstract]  
Income Taxes

Note 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.

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 ownership. 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.

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.
v3.25.4
Income (Loss) Per Share
 12 Months Ended
Dec. 31, 2025
Earnings Per Share [Abstract]  
Income (Loss) Per Share

Note 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

 
v3.25.4
Related Party Transactions
 12 Months Ended
Dec. 31, 2025
Related Party Transactions [Abstract]  
Related Party Transactions

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.
v3.25.4
Commitments and Contingencies
 12 Months Ended
Dec. 31, 2025
Commitments and Contingencies Disclosure [Abstract]  
Commitments and Contingencies

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.

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

 

 

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.
v3.25.4
Segment Information
 12 Months Ended
Dec. 31, 2025
Segment Reporting [Abstract]  
Segment Information

Note 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.

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 not 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.

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 not 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

 
v3.25.4
Supplemental Oil and Gas Disclosures (Unaudited)
 12 Months Ended
Dec. 31, 2025
Extractive Industries [Abstract]  
Supplemental Oil and Gas Disclosures (Unaudited)

Note 17 — Supplemental 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.

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., water 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.

 

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

 
v3.25.4
Subsequent Events
 12 Months Ended
Dec. 31, 2025
Subsequent Events [Abstract]  
Subsequent Events

Note 18 — Subsequent Events

Amended and Restated Credit Agreement

For additional information, see Note 8 — Debt.
v3.25.4
Schedule I - Condensed Financial Information of Registrant (Parent Only)
 12 Months Ended
Dec. 31, 2025
Condensed Financial Information Disclosure [Abstract]  
Schedule I - Condensed Financial Information of Registrant (Parent Only)

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

 

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

 

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

$

—

 

$

—

 

$

—

 
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.

v3.25.4
Summary of Significant Accounting Policies (Policies)
 12 Months Ended
Dec. 31, 2025
Summary Of Significant Accounting Policies [Line Items]  
Organization, Nature of Business, Basis of Presentation and Consolidation

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

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

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

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.
Cash and Cash Equivalents 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 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

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 — 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

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.

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 — 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 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

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.
Notes Receivable, net

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

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

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

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.
Share-Based Compensation

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.

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

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.
Income Taxes

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

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

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.

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

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

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.

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

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

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

 
Production Handling Fees [Member]  
Summary Of Significant Accounting Policies [Line Items]  
Industry Specific Policies

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.
Other Well Equipment [Member]  
Summary Of Significant Accounting Policies [Line Items]  
Industry Specific Policies 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.
Decommissioning Obligations [Member]  
Summary Of Significant Accounting Policies [Line Items]  
Industry Specific Policies

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.
v3.25.4
Summary of Significant Accounting Policies (Tables)
 12 Months Ended
Dec. 31, 2025
Accounting Policies [Abstract]  
Schedule of Percent of Consolidated Revenue of Major Customers, Those Whose Total Represented 10% or More of Oil, Natural Gas and NGL Revenues

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%
Schedule of Cash and Cash Equivalents

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

 
Schedule of Accounts Receivable, Net

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

 
Schedule of Allowance for Credit Losses 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.
v3.25.4
Acquisitions and Divestitures (Tables)
 12 Months Ended
Dec. 31, 2025
EnVen Energy Corporation  
Business Acquisition [Line Items]  
Summary of Purchase Price

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.
Summary Of Revenues And Net Income Attributable To Acquisition

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

 

 
Supplemental Proforma Information 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

 
QuarterNorth  
Business Acquisition [Line Items]  
Summary of Purchase Price

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.
Summary of Allocation of Purchase Price to Assets Acquired and Liabilities Assumed

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.
Summary Of Revenues And Net Income Attributable To Acquisition

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

 
Supplemental Proforma Information 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

 
v3.25.4
Property, Plant and Equipment (Tables)
 12 Months Ended
Dec. 31, 2025
Oil and Gas, Joint Interest Billing, Receivable [Abstract]  
Summary of Oil and Natural Gas Property Costs Not Being Amortized

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

 
v3.25.4
Leases (Tables)
 12 Months Ended
Dec. 31, 2025
Leases [Abstract]  
Components of Lease Costs 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.
Schedule of ROU Asset and Lease Liability, Adjusted for Initial Direct Costs and Incentives

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

 

 
Schedule of Lease Maturity

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

 

 
Schedule of Weighted Average Remaining Lease Term and Discount Rate

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

%

 
Supplemental Cash Flow Information Related to Leases

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.
v3.25.4
Financial Instruments (Tables)
 12 Months Ended
Dec. 31, 2025
Financial Instruments [Abstract]  
Schedule of Carrying Amounts and Estimated Fair Values of Financial 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

 
Schedule of Impact that Derivatives not Qualifying as Hedging Instruments in Condensed Consolidated Statements of Operations

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

 

 
Schedule of Contracted Volumes and Weighted Average Prices and will Receive Under the Terms of Derivative Contracts

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

 

 
Summary of Additional Information Related to Financial Instruments Measured at Fair Value on Recurring Basis

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

 

 
Schedule of Fair Value of Derivative Financial Instruments 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

 

$

—

 

 
v3.25.4
Debt (Tables)
 12 Months Ended
Dec. 31, 2025
Debt Disclosure [Abstract]  
Summary of Detail Comprising Debt and Related Book Values

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

 
Summary of Redemption Prices of 9.000% and 9.375% Notes 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

%
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

%
Schedule of Pricing Grid for Borrowing Base Utilization Percentage 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%

 
v3.25.4
Asset Retirement Obligations (Tables)
 12 Months Ended
Dec. 31, 2025
Asset Retirement Obligation Disclosure [Abstract]  
Schedule of 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.
v3.25.4
Employee Benefits Plans and Share-Based Compensation (Tables)
 12 Months Ended
Dec. 31, 2025
Share-Based Payment Arrangement [Abstract]  
Summary of Restricted Stock Units Activity

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

 
Summary of Performance Share Units Activity

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.
Summary of Assumptions Used to Calculate the Grant Date Fair Value of TSR PSUs Granted

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

— %

— %

— %

 
Schedule of Recognized Share Based Compensation Expense, Net

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

 
v3.25.4
Income Taxes (Tables)
 12 Months Ended
Dec. 31, 2025
Income Tax Disclosure [Abstract]  
Components of 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

)
Summary of Reconciliation of Income Taxes Computed at U.S. Federal Statutory Tax Rate to Income Tax Expense (Benefit)

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.
Summary of Significant Components of 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

)

 
Summary of Net Operating Loss Carryovers

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

 
Summary of Balances In Uncertain Tax Positions

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

 

 
Components of Income Taxes Paid Net of Refunds

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

)
v3.25.4
Income (Loss) Per Share (Tables)
 12 Months Ended
Dec. 31, 2025
Earnings Per Share [Abstract]  
Summary of Computation of Basic and Diluted Income (Loss) Per Share Attributable to Common Stockholders

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

 
v3.25.4
Commitments and Contingencies (Tables)
 12 Months Ended
Dec. 31, 2025
Commitments and Contingencies Disclosure [Abstract]  
Summary of Future Minimum Transportation Fees

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

 

 
Summary of Estimated Collateral Funding Commitments

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

 

 
Summary of Decommissioning Obligations Included in Consolidated Balance Sheets

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

 
v3.25.4
Segment Information (Tables)
 12 Months Ended
Dec. 31, 2025
Segment Reporting [Abstract]  
Summary of Information by Business Segment

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 not 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.

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 not 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.
Reconciliation of Reportable Segment Expenditures

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

 
v3.25.4
Supplemental Oil and Gas Disclosures (Unaudited) (Tables)
 12 Months Ended
Dec. 31, 2025
Extractive Industries [Abstract]  
Schedule of Capitalized Costs Related to Oil, Natural Gas and NGL Activities and Related Accumulated Depreciation, Depletion and Amortization

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

 
Schedule of Costs Incurred in Oil, Natural Gas and NGL 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

 
Schedule of Estimated Proved Reserves at Net Ownership Interest

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

 
Schedule of Standardized Measure of Discounted Future Net Cash Flows Related to Interest in 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

 

 
Schedule of Base Prices Used in Determining Standardized Measure

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

 
Schedule of Principal 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

 
v3.25.4
Organization, Nature of Business and Basis of Presentation - Additional Information (Details) - Segment
 3 Months Ended 12 Months Ended
Mar. 18, 2024
Dec. 31, 2025
Dec. 31, 2024
Basis Of Presentation And Schedule Of Accounting Policy [Line Items]      
Date of incorporation   Nov. 14, 2017  
Number of operating segments 2   2
v3.25.4
Summary of Significant Accounting Policies - Additional Information (Details) - USD ($)
 12 Months Ended
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
Summary Of Significant Accounting Policies [Line Items]      
Allowance for expected credit losses $ 17,700,000 $ 25,500,000  
Impairment charges 0 $ 0 $ 0
Future plugging and abanonment obligations      
Summary Of Significant Accounting Policies [Line Items]      
Receivable with imputed interest, face amount 66,200,000    
EnVen Energy Corporation      
Summary Of Significant Accounting Policies [Line Items]      
Receivable with imputed interest, face amount $ 66,200,000    
Minimum      
Summary Of Significant Accounting Policies [Line Items]      
Other property and equipment, estimated useful lives 3 years    
Minimum | Performance Share Unit | Performance Based Conditions      
Summary Of Significant Accounting Policies [Line Items]      
Number of common stock issuable upon vesting, percentage range of PSUs granted 0.00%    
Minimum | Performance Shares      
Summary Of Significant Accounting Policies [Line Items]      
Number of common stock issuable upon vesting, percentage range of PSUs granted 0.00%    
Minimum | Performance Shares | Market Based Conditions      
Summary Of Significant Accounting Policies [Line Items]      
Number of common stock issuable upon vesting, percentage range of PSUs granted 0.00%    
Maximum      
Summary Of Significant Accounting Policies [Line Items]      
Other property and equipment, estimated useful lives 10 years    
Maximum | Performance Share Unit | Performance Based Conditions      
Summary Of Significant Accounting Policies [Line Items]      
Number of common stock issuable upon vesting, percentage range of PSUs granted 200.00%    
Maximum | Performance Shares      
Summary Of Significant Accounting Policies [Line Items]      
Number of common stock issuable upon vesting, percentage range of PSUs granted 200.00%    
Maximum | Performance Shares | Market Based Conditions      
Summary Of Significant Accounting Policies [Line Items]      
Number of common stock issuable upon vesting, percentage range of PSUs granted 200.00%    
Measurement Input Discount Rate      
Summary Of Significant Accounting Policies [Line Items]      
Present value of future net revenues from proved reserves, discount rate 10.00%    
Limited Partnership or Limited Liability Company Type Investment | Minimum | Common Stock      
Summary Of Significant Accounting Policies [Line Items]      
Equity method investment, ownership percentage 20.00%    
v3.25.4
Summary of Significant Accounting Policies - Schedule of Percent of Consolidated Revenue of Major Customers, Those Whose Total Represented 10% or More of Oil, Natural Gas and NGL Revenues (Details) - Sales Revenue - Customer Concentration Risk
 12 Months Ended
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
Shell Trading (US) Company      
Concentration Risk Line Items      
Concentration risk, percentage 35.00% 48.00% 54.00%
Exxon Mobil Corporation      
Concentration Risk Line Items      
Concentration risk, percentage 23.00% 17.00%  
Valero energy corporation      
Concentration Risk Line Items      
Concentration risk, percentage     21.00%
Chevron Corporation      
Concentration Risk Line Items      
Concentration risk, percentage 12.00%    
v3.25.4
Summary of Significant Accounting Policies - Schedule of Percent of Consolidated Revenue of Major Customers, Those Whose Total Represented 10% or More of Oil, Natural Gas and NGL Revenues (Parenthetical) (Details) - Sales Revenue - Customer Concentration Risk
 12 Months Ended
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
Exxon Mobil Corporation      
Concentration Risk Line Items      
Concentration risk, percentage 23.00% 17.00%  
Exxon Mobil Corporation | Maximum      
Concentration Risk Line Items      
Concentration risk, percentage     10.00%
Valero energy corporation      
Concentration Risk Line Items      
Concentration risk, percentage     21.00%
Valero energy corporation | Maximum      
Concentration Risk Line Items      
Concentration risk, percentage 10.00% 10.00%  
Chevron Corporation      
Concentration Risk Line Items      
Concentration risk, percentage 12.00%    
Chevron Corporation | Maximum      
Concentration Risk Line Items      
Concentration risk, percentage   10.00% 10.00%
v3.25.4
Summary of Significant Accounting Policies - Schedule of Cash and Cash Equivalents (Details) - USD ($)
$ in Thousands
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
Dec. 31, 2022
Summary Of Significant Accounting Policies [Abstract]        
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 $ 135,999 $ 44,145
v3.25.4
Summary of Significant Accounting Policies - Schedule of Accounts Receivable, Net (Details) - USD ($)
$ in Thousands
Dec. 31, 2025
Dec. 31, 2024
Summary Of Significant Accounting Policies [Abstract]    
Trade $ 166,793 $ 236,694
Joint interest 132,527 133,562
Other 23,738 34,002
Total accounts receivable, net $ 323,058 $ 404,258
v3.25.4
Acquisitions and Divestitures - Acquisitions - Business Combination - Additional Information (Details) - USD ($)
$ in Thousands
 12 Months Ended 15 Months Ended
Jul. 22, 2025
Mar. 07, 2025
Aug. 02, 2024
Mar. 04, 2024
Feb. 13, 2023
Sep. 21, 2022
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
Apr. 01, 2026
Business Acquisition [Line Items]                    
Issuance of common stock, Shares               34,500,000    
Proved properties             $ 10,621,012 $ 9,784,832    
Other current liabilities             29,925 44,854    
Monument Project                    
Business Acquisition [Line Items]                    
Asset acquisition, date of acquisition agreement   Mar. 07, 2025                
Proved properties     $ 42,600              
Percentage of non-operated working interest acquired   8.30% 21.40%              
Cash consideration   $ 14,800 $ 20,200              
Monument Project | Notes Payable, Other Payables [Member]                    
Business Acquisition [Line Items]                    
Other current liabilities             $ 4,000      
Monument Project | Milestone Payment                    
Business Acquisition [Line Items]                    
Cash consideration   $ 6,300                
Monument Project | Pro Forma                    
Business Acquisition [Line Items]                    
Cash consideration                   $ 24,400
Mississippi Canyon blocks 108                    
Business Acquisition [Line Items]                    
Percentage of working interest acquired 75.20%                  
Mississippi Canyon Blocks 110                    
Business Acquisition [Line Items]                    
Percentage of working interest acquired 50.00%                  
Mississippi Canyon Blocks                    
Business Acquisition [Line Items]                    
Cash consideration $ 33,700                  
Asset acquisition, consideration transferred $ 38,600                  
EnVen Energy Corporation                    
Business Acquisition [Line Items]                    
Business acquisition, effective date         Feb. 13, 2023          
Pro forma financial information             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.      
Cumulative transaction related costs                 $ 21,800  
Cash consideration         $ 207,313          
Business acquisition, date of acquisition agreement           Sep. 21, 2022        
Common stock value         832,198          
Settlement of preexisting relationship         8,388          
Supplemental pro forma earnings                 $ 217,537  
EnVen Energy Corporation | 11.75% notes                    
Business Acquisition [Line Items]                    
Debt instrument interest rate                 11.75%  
EnVen Energy Corporation | Employee Severance                    
Business Acquisition [Line Items]                    
Aquisition severance cost                 $ 25,300  
EnVen Energy Corporation | Settlements Of Preexisting Relationship                    
Business Acquisition [Line Items]                    
Gain or loss recognized on settlement         $ 0          
EnVen Energy Corporation | Common Stock                    
Business Acquisition [Line Items]                    
Aggregate shares issued         43,800,000          
EnVen Energy Corporation | Common Stock | Pro Forma                    
Business Acquisition [Line Items]                    
Aggregate shares issued                 43,800,000  
EnVen Energy Corporation | General and Administrative Expense                    
Business Acquisition [Line Items]                    
Acquisition, transaction related cost                 $ 12,800  
EnVen Energy Corporation | General and Administrative Expense | Nonrecurring Adjustments                    
Business Acquisition [Line Items]                    
Supplemental pro forma earnings                 (65,100)  
QuarterNorth | General and Administrative Expense | Nonrecurring Adjustments                    
Business Acquisition [Line Items]                    
Supplemental pro forma earnings                 31,700  
QuarterNorth Acquisition                    
Business Acquisition [Line Items]                    
Pro forma financial information             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.      
Cumulative transaction related costs               21,600    
Cash consideration       $ 1,247,419            
Business acquisition, date of acquisition agreement       Mar. 04, 2024            
Common stock value       $ 322,630            
Supplemental pro forma earnings               (69,131) 245,720  
QuarterNorth Acquisition | Employee Severance                    
Business Acquisition [Line Items]                    
Aquisition severance cost               $ 22,200    
QuarterNorth Acquisition | Common Stock                    
Business Acquisition [Line Items]                    
Aggregate shares issued       24,300,000            
QuarterNorth Acquisition | Common Stock | Pro Forma                    
Business Acquisition [Line Items]                    
Aggregate shares issued               24,300,000    
QuarterNorth Acquisition | General and Administrative Expense                    
Business Acquisition [Line Items]                    
Acquisition, transaction related cost               $ 18,600 $ 3,000  
QuarterNorth Acquisition | Interest Expense                    
Business Acquisition [Line Items]                    
Acquisition, transaction related cost               $ 4,900    
QuarterNorth Acquisition | January 2024 equity offering | Common Stock | Pro Forma                    
Business Acquisition [Line Items]                    
Aggregate shares issued               34,500,000    
v3.25.4
Acquisitions and Divestitures - Acquisitions - Business Combination - Summary of Purchase Price (Details) - USD ($)
$ / shares in Units, $ in Thousands
Mar. 04, 2024
Feb. 13, 2023
EnVen Energy Corporation    
Business Acquisition [Line Items]    
Talos common stock price per share [1]   $ 19
Common stock value   $ 832,198
Cash consideration   207,313
Settlement of preexisting relationship   8,388
Total purchase price   $ 1,047,899
EnVen Energy Corporation | Common Stock    
Business Acquisition [Line Items]    
Shares of Talos common stock   43,799,890
QuarterNorth Acquisition    
Business Acquisition [Line Items]    
Talos common stock price per share [2] $ 13.25  
Common stock value $ 322,630  
Cash consideration 1,247,419  
Total purchase price [3] $ 1,570,049  
QuarterNorth Acquisition | Common Stock    
Business Acquisition [Line Items]    
Shares of Talos common stock 24,349,452  
[1] Represents the closing price of the Company’s common stock on February 13, 2023, the date of the closing of the EnVen Acquisition.
[2] Represents the closing price of the Company’s common stock on March 4, 2024, the date of the closing of the QuarterNorth Acquisition.
[3] Total purchase price net of $331.4 million cash and cash equivalents acquired at closing is $1,238.7 million.
v3.25.4
Acquisitions and Divestitures - Acquisition - Business Combinations - Summary of Purchase Price (Parenthetical) (Details) - QuarterNorth Acquisition
$ in Thousands
Mar. 04, 2024
USD ($)
Business Combination [Line Items]  
Cash and cash equivalents $ 331,374
Purchase price net of cash and cash equivalents $ 1,238,700
v3.25.4
Acquisitions and Divestitures - Acquisitions - Business Combinations - Summary of Allocation of Purchase Price to Assets Acquired and Liabilities Assumed (Details) - QuarterNorth Acquisition
$ in Thousands
Mar. 04, 2024
USD ($)
Business Acquisition [Line Items]  
Cash and cash equivalents $ 331,374
Other current assets 165,696 [1]
Property and equipment 1,622,414
Other long-term assets 20,781
Current portion of asset retirement obligations (6,748)
Other current liabilities (199,704)
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.
v3.25.4
Acquisitions and Divestitures - Acquisitions - Business Combinations - Summary of Allocation of Purchase Price to Assets Acquired and Liabilities Assumed (Parenthetical) (Details) - QuarterNorth Acquisition
$ in Millions
Mar. 04, 2024
USD ($)
Business Combination [Line Items]  
Acquired receivables $ 136.3
Financing Receivable, Purchased with Credit Deterioration, Allowance for Credit Loss at Acquisition Date $ 15.5
v3.25.4
Acquisitions and Divestitures - Acquisitions - Business Combination - Summary of Revenue and Net Income Attributable to Acquisition (Details) - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2024
Dec. 31, 2023
EnVen Energy Corporation    
Business Acquisition [Line Items]    
Revenue   $ 423,624
Net income (loss)   $ 85,622
QuarterNorth Acquisition    
Business Acquisition [Line Items]    
Revenue $ 503,397  
Net income (loss) $ 89,209  
v3.25.4
Acquisitions and Divestitures - Acquisitions - Business Combination - Summary of Supplemental Proforma Information (Details) - USD ($)
$ / shares in Units, $ in Thousands
 12 Months Ended
Dec. 31, 2024
Dec. 31, 2023
EnVen Energy Corporation    
Business Acquisition [Line Items]    
Business Acquisition, Pro Forma 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
QuarterNorth Acquisition    
Business Acquisition [Line Items]    
Business Acquisition, Pro Forma 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
v3.25.4
Acquisitions and Divestitures - Divestitures - Additional Information (Details) - USD ($)
$ in Thousands
 12 Months Ended
Mar. 18, 2024
Sep. 27, 2023
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]          
Proceeds from Divestiture of Businesses     $ 0 $ 146,676 $ 0
Other current assets     17,939 35,980  
Proceeds from (cash paid for) sale of property and equipment, net     1,716 1,161 $ 73,004
Unproved oil and gas properties, not subject to amortization     480,555 587,238  
TLCS          
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]          
Divestiture expense excludes severance cost       6,100  
Severance expense       3,700  
General and Administrative Expense | TLCS          
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]          
Business exit costs       5,500  
Talos Mexico          
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]          
Percentage of equity interests sold   49.90%      
Proceeds from (cash paid for) sale of property and equipment, net   $ 74,900      
Fair value of Company's retained equity method investment   107,600      
Talos Mexico | Earnout          
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]          
Proceeds from (cash paid for) sale of property and equipment, net   $ 49,900      
Talos Mexico | Disposal Group, Held-for-Sale or Disposed of by Sale, Not Discontinued Operations          
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]          
Disposal Group, Not Discontinued Operation, Gain (Loss) on Disposal, Statement of Income or Comprehensive Income [Extensible Enumeration]         Other Operating Income (Expense), Net
Disposal Group, Not Discontinued Operation, Gain (Loss) on Disposal         $ 66,200
Talos Low Carbon Solutions          
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]          
Business disposal date Mar. 18, 2024        
Proceeds from Divestiture of Businesses $ 142,000        
Talos Low Carbon Solutions | Uncollectible Receivables          
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]          
Receivable with imputed interest, face amount     12,500    
Talos Low Carbon Solutions | Other Operating (Income) Expense          
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]          
Derecognized deferred payment     8,900    
Talos Low Carbon Solutions | Other Income          
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]          
Derecognized deferred payment     $ 3,600    
Talos Low Carbon Solutions | Disposal Group, Held-for-Sale or Disposed of by Sale, Not Discontinued Operations          
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]          
Disposal Group, Not Discontinued Operation, Gain (Loss) on Disposal       100,400  
Talos Low Carbon Solutions | Disposal Group, Held-for-Sale or Disposed of by Sale, Not Discontinued Operations | Earnout          
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]          
Proceeds from Divestiture of Businesses       $ 4,700  
TotalEnergies E&P USA, Inc          
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]          
Base purchase price before adjustments $ 125,000        
Zama Field | Talos Mexico          
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]          
Oil and gas ownership working interest     17.40%    
v3.25.4
Property, Plant and Equipment - Additional Information (Details)
$ in Thousands
 12 Months Ended
Dec. 31, 2025
USD ($)
$ / bbl
$ / Mcf
Dec. 31, 2024
USD ($)
$ / bbl
$ / Mcf
Dec. 31, 2023
USD ($)
$ / bbl
$ / Mcf
Property, Plant and Equipment [Line Items]      
Impairment of oil and natural gas properties | $ $ 454,482 $ 0 $ 0
Anticipated timing of inclusion of costs in amortization calculation 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.    
Oil (MBbls)      
Property, Plant and Equipment [Line Items]      
SEC pricing 65.37 75.51 78.56
Gas (MMcf)      
Property, Plant and Equipment [Line Items]      
SEC pricing | $ / Mcf 3.61 2.45 2.75
NGL (MBbls)      
Property, Plant and Equipment [Line Items]      
SEC pricing 19.22 21.91 18.77
U.S      
Property, Plant and Equipment [Line Items]      
Impairment of oil and natural gas properties | $ $ 454,500 $ 0 $ 0
U.S | Oil (MBbls)      
Property, Plant and Equipment [Line Items]      
SEC pricing 65.37    
U.S | Gas (MMcf)      
Property, Plant and Equipment [Line Items]      
SEC pricing | $ / Mcf 3.61    
U.S | NGL (MBbls)      
Property, Plant and Equipment [Line Items]      
SEC pricing 19.22    
v3.25.4
Property, Plant and Equipment - Summary of Oil and Natural Gas Property Costs Not Being Amortized (Details) - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
Dec. 31, 2022
Capitalized Costs Of Unproved Properties Excluded From Amortization [Line Items]        
Total unproved properties, not subject to amortization $ 480,555 $ 587,238    
United States        
Capitalized Costs Of Unproved Properties Excluded From Amortization [Line Items]        
Acquisition 400,677      
Exploration 79,878      
2025        
Capitalized Costs Of Unproved Properties Excluded From Amortization [Line Items]        
Total unproved properties, not subject to amortization 41,576      
2025 | United States        
Capitalized Costs Of Unproved Properties Excluded From Amortization [Line Items]        
Acquisition 0      
Exploration $ 41,576      
2024        
Capitalized Costs Of Unproved Properties Excluded From Amortization [Line Items]        
Total unproved properties, not subject to amortization   290,097    
2024 | United States        
Capitalized Costs Of Unproved Properties Excluded From Amortization [Line Items]        
Acquisition   263,783    
Exploration   $ 26,314    
2023        
Capitalized Costs Of Unproved Properties Excluded From Amortization [Line Items]        
Total unproved properties, not subject to amortization     $ 146,479  
2023 | United States        
Capitalized Costs Of Unproved Properties Excluded From Amortization [Line Items]        
Acquisition     136,894  
Exploration     $ 9,585  
2022 and Prior        
Capitalized Costs Of Unproved Properties Excluded From Amortization [Line Items]        
Total unproved properties, not subject to amortization       $ 2,403
2022 and Prior | United States        
Capitalized Costs Of Unproved Properties Excluded From Amortization [Line Items]        
Acquisition       0
Exploration       $ 2,403
v3.25.4
Leases - Components of Lease Costs (Details) - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
Lease, Cost [Abstract]      
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.
v3.25.4
Leases - Schedule of ROU Asset and Lease Liability, Adjusted for Initial Direct Costs and Incentives (Details) - USD ($)
$ in Thousands
Dec. 31, 2025
Dec. 31, 2024
Assets and Liabilities, Lessee [Abstract]    
Operating lease assets $ 9,214 $ 11,294
Current portion of operating lease liabilities $ 3,657 $ 3,837
Operating Lease, Liability, Current, Statement of Financial Position [Extensible List] Current portion of operating lease liabilities Current portion of operating lease liabilities
Operating lease liabilities $ 11,956 $ 15,489
Total operating lease liabilities 15,613 19,326
Proved properties 166,261 166,261
Other current liabilities $ 21,473 $ 19,589
Finance Lease, Liability, Current, Statement of Financial Position [Extensible List] Other current liabilities Other current liabilities
Other long-term liabilities $ 90,169 $ 111,641
Finance Lease, Liability, Noncurrent, Statement of Financial Position [Extensible List] Other long-term liabilities Other long-term liabilities
Total finance lease liabilities $ 111,642 $ 131,230
v3.25.4
Leases - Schedule of Lease Maturity (Details) - USD ($)
$ in Thousands
Dec. 31, 2025
Dec. 31, 2024
Leases [Abstract]    
Operating Leases, 2026 $ 5,072  
Operating Leases, 2027 4,753  
Operating Leases, 2028 4,610  
Operating Leases, 2029 3,226  
Operating Leases, 2030 1,223  
Operating Leases, Thereafter 135  
Operating Leases, Total lease payments 19,019  
Operating Leases, Imputed interest (3,406)  
Total operating lease liabilities 15,613 $ 19,326
Finance Leases, 2026 30,782  
Finance Leases, 2027 30,782  
Finance Leases, 2028 30,782  
Finance Leases, 2029 30,782  
Finance Leases, 2030 12,826  
Finance Leases, Thereafter 0  
Finance Leases, Total lease payments 135,954  
Finance Leases, Imputed interest (24,312)  
Total finance lease liabilities $ 111,642 $ 131,230
v3.25.4
Leases - Schedule of Weighted Average Remaining Lease Term and Discount Rate (Details)
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
Weighted average remaining lease term:      
Operating leases 3 years 10 months 24 days 4 years 9 months 18 days 5 years 10 months 24 days
Finance leases 4 years 4 months 24 days 5 years 4 months 24 days 6 years 4 months 24 days
Weighted average discount rate:      
Operating leases 10.80% 10.70% 10.80%
Finance leases 9.20% 9.20% 9.20%
v3.25.4
Leases - Supplemental Cash Flow Information Related to Leases (Details) - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
Cash Flow, Operating Activities, Lessee [Abstract]      
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] 0 1,909 12,971
Remeasurement of lease liability arising from modification of ROU asset [2] $ 0 $ 0 $ (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.
v3.25.4
Financial Instruments - Schedule of Carrying Amounts and Estimated Fair Values of Financial Instruments (Details) - USD ($)
$ in Thousands
Dec. 31, 2025
Dec. 31, 2024
Debt Instrument [Line Items]    
Carrying Amount $ 1,226,189 $ 1,221,399
9.000% Second-Priority Senior Secured Notes - due February 2029    
Debt Instrument [Line Items]    
Carrying Amount 614,058 611,135
Fair Value 649,425 640,619
9.375% Second-Priority Senior Secured Notes - due February 2031    
Debt Instrument [Line Items]    
Carrying Amount 612,131 610,264
Fair Value $ 656,250 $ 635,750
v3.25.4
Financial Instruments - Schedule of Carrying Amounts and Estimated Fair Values of Financial Instruments (Parenthetical) (Details)
Dec. 31, 2025
Dec. 31, 2024
9.000% Second-Priority Senior Secured Notes - due February 2029    
Debt Instrument [Line Items]    
Debt instrument interest rate 9.00% 9.00%
9.375% Second-Priority Senior Secured Notes - due February 2031    
Debt Instrument [Line Items]    
Debt instrument interest rate 9.375% 9.375%
v3.25.4
Financial Instruments - Additional Information (Details)
$ in Millions
 12 Months Ended
Dec. 31, 2025
USD ($)
Concentration Risk [Line Items]  
Credit risk, financial instruments 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.
Maximum loss on commodity contracts $ 47.7
Counterparty Risk Investment Grade  
Concentration Risk [Line Items]  
Number of counterparties description all of which
v3.25.4
Financial Instruments - Schedule of Impact that Derivatives not Qualifying as Hedging Instruments in Condensed Consolidated Statements of Operations (Details) - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
Derivative Instruments and Hedging Activities Disclosures [Line Items]      
Derivative fair value gain (loss) $ 105,455 $ (1,458) $ 80,928
Gain Loss on Derivative Instruments Unrealized Component      
Derivative Instruments and Hedging Activities Disclosures [Line Items]      
Derivative fair value gain (loss) 23,984 (6,168) 90,385
Commodity Contract      
Derivative Instruments and Hedging Activities Disclosures [Line Items]      
Derivative fair value gain (loss) 105,455 (1,458) 80,928
Commodity Contract | Gain Loss on Derivative Instruments Realized Component      
Derivative Instruments and Hedging Activities Disclosures [Line Items]      
Derivative fair value gain (loss) $ 81,471 $ 4,710 $ (9,457)
v3.25.4
Financial Instruments - Schedule of Contracted Volumes and Weighted Average Prices and will Receive Under the Terms of Derivative Contracts (Details) - January 2026 - December 2026
 12 Months Ended
Dec. 31, 2025
MMBTU
$ / bbl
$ / MMBTU
bbl
Crude Oil | Swap  
Derivative [Line Items]  
Settlement Index NYMEX WTI CMA
Volumes | bbl 8,197
Swap Price 65.51
Crude Oil | Collar  
Derivative [Line Items]  
Settlement Index NYMEX WTI CMA
Volumes | bbl 11,997
Floor Price 60
Ceiling Price 68.25
Natural Gas | Swap  
Derivative [Line Items]  
Settlement Index NYMEX Henry Hub
Average Daily Volumes | MMBTU 28,671
Swap Price | $ / MMBTU 3.85
v3.25.4
Financial Instruments - Summary of Additional Information Related to Financial Instruments Measured at Fair Value on Recurring Basis (Details) - USD ($)
$ in Thousands
Dec. 31, 2025
Dec. 31, 2024
Oil and Natural Gas Derivatives    
Assets:    
Oil and natural gas derivatives $ 47,712 $ 23,728
Liabilities:    
Oil and natural gas derivatives 0 0
Fair Value on Recurring Basis    
Liabilities:    
Total net asset (liability) 47,712 23,728
Fair Value on Recurring Basis | Oil and Natural Gas Derivatives    
Assets:    
Oil and natural gas derivatives $ 54,420 $ 33,739
Derivative Asset, Statement of Financial Position [Extensible Enumeration] Assets Assets
Liabilities:    
Oil and natural gas derivatives $ (6,708) $ (10,011)
Derivative Liability, Statement of Financial Position [Extensible Enumeration] Liabilities Liabilities
Fair Value on Recurring Basis | Level 1    
Liabilities:    
Total net asset (liability) $ 0 $ 0
Fair Value on Recurring Basis | Level 1 | Oil and Natural Gas Derivatives    
Assets:    
Oil and natural gas derivatives $ 0 $ 0
Derivative Asset, Statement of Financial Position [Extensible Enumeration] Assets Assets
Liabilities:    
Oil and natural gas derivatives $ 0 $ 0
Derivative Liability, Statement of Financial Position [Extensible Enumeration] Liabilities Liabilities
Fair Value on Recurring Basis | Level 2    
Liabilities:    
Total net asset (liability) $ 47,712 $ 23,728
Fair Value on Recurring Basis | Level 2 | Oil and Natural Gas Derivatives    
Assets:    
Oil and natural gas derivatives $ 54,420 $ 33,739
Derivative Asset, Statement of Financial Position [Extensible Enumeration] Assets Assets
Liabilities:    
Oil and natural gas derivatives $ (6,708) $ (10,011)
Derivative Liability, Statement of Financial Position [Extensible Enumeration] Liabilities Liabilities
Fair Value on Recurring Basis | Level 3    
Liabilities:    
Total net asset (liability) $ 0 $ 0
Fair Value on Recurring Basis | Level 3 | Oil and Natural Gas Derivatives    
Assets:    
Oil and natural gas derivatives $ 0 $ 0
Derivative Asset, Statement of Financial Position [Extensible Enumeration] Assets Assets
Liabilities:    
Oil and natural gas derivatives $ 0 $ 0
Derivative Liability, Statement of Financial Position [Extensible Enumeration] Liabilities Liabilities
v3.25.4
Financial Instruments - Schedule of Fair Value of Derivative Financial Instruments (Details) - USD ($)
$ in Thousands
Dec. 31, 2025
Dec. 31, 2024
Price Risk Derivatives [Line Items]    
Derivative Asset, Current $ 54,420 $ 33,486
Derivative Asset, Noncurrent 0 253
Derivative Liability, Current 6,708 6,474
Derivative Liability, Noncurrent 0 3,537
Oil and Natural Gas Derivatives    
Price Risk Derivatives [Line Items]    
Derivative Asset, Current 54,420 33,486
Derivative Asset, Noncurrent 0 253
Total gross amounts presented on balance sheet, Assets 54,420 33,739
Gross amounts not offset on the balance sheet 6,708 10,011
Net Amounts 47,712 23,728
Derivative Liability, Current 6,708 6,474
Derivative Liability, Noncurrent 0 3,537
Total gross amounts presented on balance sheet, Liabilities 6,708 10,011
Gross amounts not offset on the balance sheet 6,708 10,011
Net Amounts $ 0 $ 0
v3.25.4
Equity Method Investments - Additional Information (Details) - USD ($)
$ in Thousands
 12 Months Ended
Dec. 16, 2024
Dec. 31, 2025
Dec. 31, 2023
Dec. 31, 2024
Schedule of Equity Method Investments [Line Items]        
Equity method investments   $ 112,382   $ 111,269
Talos Mexico        
Schedule of Equity Method Investments [Line Items]        
Equity method investments   $ 112,400   $ 111,300
Talos Mexico | Variable Interest Entity, Not Primary Beneficiary | Zama Field        
Schedule of Equity Method Investments [Line Items]        
Equity method investment, ownership interest   50.10%    
Talos Mexico | Equity Method Investee | Variable Interest Entity, Not Primary Beneficiary        
Schedule of Equity Method Investments [Line Items]        
Equity method investment, basis difference   $ 66,000    
Talos Mexico | Equity Method Investee | Variable Interest Entity, Not Primary Beneficiary | Zama Field        
Schedule of Equity Method Investments [Line Items]        
Oil And GasOwnership Working Interest   17.40%    
Talos Mexico | Equity Method Investee | Variable Interest Entity, Not Primary Beneficiary | Earnout        
Schedule of Equity Method Investments [Line Items]        
Proceeds from sale of equity method investment $ 33,100      
Talos Mexico | Pro Forma | Equity Method Investee | Variable Interest Entity, Not Primary Beneficiary        
Schedule of Equity Method Investments [Line Items]        
Percentage of equity interests sold 30.10%      
Proceeds from sale of equity method investment $ 49,700      
Talos Mexico | Pro Forma | Zamajal [Member] | Variable Interest Entity, Not Primary Beneficiary        
Schedule of Equity Method Investments [Line Items]        
Percentage of equity interests sold   49.90%    
Bayou Bend CCS LLC | Equity Method Investment Income | Capital Carry        
Schedule of Equity Method Investments [Line Items]        
Gain on partial disposal of investment     $ 8,600  
Bayou Bend CCS LLC | Chevron U.S.A Inc        
Schedule of Equity Method Investments [Line Items]        
Capital carry contribution funded     $ 8,600  
v3.25.4
Debt - Summary of Detail Comprising Debt and Related Book Values (Details) - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2025
Dec. 31, 2024
Debt Instrument [Line Items]    
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
Senior Notes | 9.000% Second-Priority Senior Secured Notes Matured on February 1, 2029    
Debt Instrument [Line Items]    
Senior Notes, Maturity Date Feb. 01, 2029 Feb. 01, 2029
Total debt, before discount and deferred financing cost $ 625,000 $ 625,000
Senior Notes | 9.375% Second-Priority Senior Secured Notes Matured on February 1, 2031    
Debt Instrument [Line Items]    
Senior Notes, Maturity Date Feb. 01, 2031 Feb. 01, 2031
Total debt, before discount and deferred financing cost $ 625,000 $ 625,000
Line of Credit | Bank Credit Facility Matured on March 31, 2027    
Debt Instrument [Line Items]    
Bank credit facility, Maturity Date Mar. 31, 2027 Mar. 31, 2027
Total debt, before discount and deferred financing cost $ 0 $ 0
v3.25.4
Debt - Summary of Detail Comprising Debt and Related Book Values (Parenthetical) (Details) - Senior Notes
Dec. 31, 2025
Dec. 31, 2024
9.000% Second-Priority Senior Secured Notes Matured on February 1, 2029    
Debt Instrument [Line Items]    
Debt instrument interest rate 9.00% 9.00%
9.375% Second-Priority Senior Secured Notes Matured on February 1, 2031    
Debt Instrument [Line Items]    
Debt instrument interest rate 9.375% 9.375%
v3.25.4
Debt - Additional information (Details)
$ / shares in Units, $ in Thousands
 12 Months Ended
Jan. 31, 2027
Jan. 31, 2026
Jan. 20, 2026
USD ($)
Feb. 07, 2024
USD ($)
Dec. 31, 2025
USD ($)
$ / shares
Dec. 31, 2024
USD ($)
Dec. 31, 2023
USD ($)
Aug. 04, 2025
USD ($)
Debt Instrument [Line Items]                
Loss on extinguishment of debt         $ (0) $ (60,256) $ 0  
Debt instrument covenant description         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.      
Limitation on Restricted Payments Including Dividends, Description         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%.      
A&R Credit Agreement                
Debt Instrument [Line Items]                
Letter of credit facility borrowing, description         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.      
Revolving Credit Facility                
Debt Instrument [Line Items]                
Line of credit facility, Dividend restrictions         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.      
Minimum                
Debt Instrument [Line Items]                
Restricted net assets, subsidiaries exceeded         25.00%      
Subsequent Event | A&R Credit Agreement                
Debt Instrument [Line Items]                
Borrowing base and commitments     $ 700,000          
Credit facility, maximum borrowing capacity     $ 700,000          
Percentage of mortgage covering oil and natural gas assets     85.00%          
Line of Credit Facility, Commitments     $ 700,000          
Maturity date earlier     Nov. 02, 2028          
Maturity date latest     Jan. 20, 2030          
Subsequent Event | Minimum | A&R Credit Agreement                
Debt Instrument [Line Items]                
Debt instrument covenant current ratio.     1          
Subsequent Event | Maximum | A&R Credit Agreement                
Debt Instrument [Line Items]                
Consolidated total debt to EBITDAX ratio     3          
Subsequent Event | Maximum | Letter of Credit                
Debt Instrument [Line Items]                
Line of Credit Facility, Commitments     $ 250,000          
Base Rate Federal Funds [Member] | Subsequent Event | A&R Credit Agreement                
Debt Instrument [Line Items]                
Debt Instrument, Basis Spread on Variable Rate     0.50%          
One Month Adjusted Term Secured Overnight Financing Rate [Member] | Subsequent Event | A&R Credit Agreement                
Debt Instrument [Line Items]                
Debt Instrument, Basis Spread on Variable Rate     1.00%          
9.000% Second-Priority Senior Secured Notes - due February 2029                
Debt Instrument [Line Items]                
Debt issuance costs           16,300    
Debt instrument covenant description         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.      
9.000% Second-Priority Senior Secured Notes - due February 2029 | Senior Notes                
Debt Instrument [Line Items]                
Debt instrument interest rate       9.00%        
Debt Instrument, Frequency of Periodic Payment         semi-annually      
Debt instrument payment terms         semi-annually each February 1 and August 1      
Debt instrument maturity date         Feb. 01, 2029      
Debt instrument redemption, description         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      
9.000% Second-Priority Senior Secured Notes - due February 2029 | Senior Notes | Forecast                
Debt Instrument [Line Items]                
Debt instrument, redemption price, percentage   109.00%            
Percentage of principal amount redeemed   40.00%            
9.000% Second-Priority Senior Secured Notes - due February 2029 | Subsequent Event | A&R Credit Agreement                
Debt Instrument [Line Items]                
Debt instrument interest rate     9.00%          
9.375% Second-Priority Senior Secured Notes - due February 2031                
Debt Instrument [Line Items]                
Debt issuance costs           $ 16,300    
Debt instrument covenant description         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.      
9.375% Second-Priority Senior Secured Notes - due February 2031 | Senior Notes                
Debt Instrument [Line Items]                
Debt instrument interest rate       9.375%        
Debt Instrument, Frequency of Periodic Payment         semi-annually      
Debt instrument payment terms         semi-annually each February 1 and August 1      
Debt instrument maturity date         Feb. 01, 2031      
Debt instrument redemption, description         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      
9.375% Second-Priority Senior Secured Notes - due February 2031 | Senior Notes | Forecast                
Debt Instrument [Line Items]                
Debt instrument, redemption price, percentage 109.375%              
Percentage of principal amount redeemed 40.00%              
12.00% Second-Priority Senior Secured Notes - due January 2026                
Debt Instrument [Line Items]                
Debt instrument, repurchase date       Feb. 07, 2024        
12.00% Second-Priority Senior Secured Notes - due January 2026 | Senior Notes                
Debt Instrument [Line Items]                
Debt instrument, redemption price, percentage       103.00%        
Debt instrument interest rate       12.00%        
Debt instrument, repurchase amount       $ 638,500        
11.75% Senior Secured Second Lien Notes | Senior Notes                
Debt Instrument [Line Items]                
Debt instrument, redemption price, percentage       102.938%        
Debt instrument interest rate       11.75%        
Debt instrument, repurchase amount       $ 227,500        
Bank Credit Facility - matures March 2027                
Debt Instrument [Line Items]                
Borrowing base and commitments         $ 700,000      
Credit facility, maximum borrowing capacity         $ 700,000      
Bank credit facility, description         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. 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.      
Percentage of mortgage covering oil and natural gas assets         85.00%      
Line of Credit Facility, Commitments         $ 700,000      
Bank Credit Facility - matures March 2027 | Letter of Credit                
Debt Instrument [Line Items]                
Line of Credit Facility, Commitments         $ 250,000      
Bank Credit Facility - matures March 2027 | Minimum                
Debt Instrument [Line Items]                
Debt instrument covenant current ratio.         1      
Bank Credit Facility - matures March 2027 | Maximum                
Debt Instrument [Line Items]                
Consolidated total debt to EBITDAX ratio         3      
Bank Credit Facility - matures March 2027 | Maximum | Letter of Credit                
Debt Instrument [Line Items]                
Line of Credit Facility, Commitments         $ 250,000      
Bank Credit Facility - matures March 2027 | Adjusted Daily Simple Secured Overnight Financing Rate [Member]                
Debt Instrument [Line Items]                
Debt Instrument, Basis Spread on Variable Rate         0.10%      
Bank Credit Facility - matures March 2027 | Base Rate Federal Funds [Member]                
Debt Instrument [Line Items]                
Debt Instrument, Basis Spread on Variable Rate         0.50%      
Bank Credit Facility - matures March 2027 | One Month Adjusted Term Secured Overnight Financing Rate [Member]                
Debt Instrument [Line Items]                
Debt Instrument, Basis Spread on Variable Rate         1.00%      
Bank Credit Facility - matures March 2027 | Adjusted Term Secured Overnight Financing Rate [Member]                
Debt Instrument [Line Items]                
Debt Instrument, Basis Spread on Variable Rate         0.10%      
Bank Credit Facility                
Debt Instrument [Line Items]                
Borrowing base and commitments               $ 700,000
Credit facility, maximum borrowing capacity               700,000
Line of Credit Facility, Commitments               700,000
Bank Credit Facility | Covenant Calculation                
Debt Instrument [Line Items]                
Debt instrument unrestricted cash deducted from debt               50,000
Line of credit facility lender commitment amount               $ 0
Restrictions which limit the payment of dividends | Revolving Credit Facility                
Debt Instrument [Line Items]                
Percentage of commitments exceeding the effective loan limit         25.00%      
Restrictions which limit the payment of dividends | Senior Notes                
Debt Instrument [Line Items]                
Fixed Charge Coverage Ratio Satisfied With Incurrence Of Additional Indebtedness Amount | $ / shares         $ 1      
Restrictions which limit the payment of dividends | Minimum | Revolving Credit Facility                
Debt Instrument [Line Items]                
Pro Forma Current Ratio         1      
Restrictions which limit the payment of dividends | Maximum | Revolving Credit Facility                
Debt Instrument [Line Items]                
Consolidated total debt to EBITDAX ratio         1      
Restrictions which limit the payment of dividends | Maximum | Restricted payments does not exceed the available free cash flow amount | Revolving Credit Facility                
Debt Instrument [Line Items]                
Consolidated total debt to EBITDAX ratio         1.75      
Restrictions which limit the payment of dividends | Maximum | Senior Notes                
Debt Instrument [Line Items]                
Consolidated total debt to EBITDAX ratio         3      
Debt instrument fixed charge coverage ratio         2.25      
Other Income (Expense) | 12.00% Second-Priority Senior Secured Notes - due January 2026 | Senior Notes                
Debt Instrument [Line Items]                
Loss on extinguishment of debt       (54,900)        
Other Income (Expense) | 11.75% Senior Secured Second Lien Notes | Senior Notes                
Debt Instrument [Line Items]                
Loss on extinguishment of debt       $ (5,400)        
v3.25.4
Debt - Summary of Redemption Prices of 9.000% and 9.375% Notes (Details)
 12 Months Ended
Dec. 31, 2025
9.000% Second-Priority Senior Secured Notes - due February 2029 | Debt Instrument, Redemption, Period One  
Debt Instrument, Redemption [Line Items]  
Debt Instrument, Redemption Price, Percentage 104.50%
9.000% Second-Priority Senior Secured Notes - due February 2029 | Debt Instrument, Redemption, Period Two  
Debt Instrument, Redemption [Line Items]  
Debt Instrument, Redemption Price, Percentage 102.25%
9.000% Second-Priority Senior Secured Notes - due February 2029 | Debt Instrument, Redemption, Period After Two  
Debt Instrument, Redemption [Line Items]  
Debt Instrument, Redemption Price, Percentage 100.00%
9.375% Second-Priority Senior Secured Notes - due February 2031 | Debt Instrument, Redemption, Period One  
Debt Instrument, Redemption [Line Items]  
Debt Instrument, Redemption Price, Percentage 104.688%
9.375% Second-Priority Senior Secured Notes - due February 2031 | Debt Instrument, Redemption, Period Two  
Debt Instrument, Redemption [Line Items]  
Debt Instrument, Redemption Price, Percentage 102.344%
9.375% Second-Priority Senior Secured Notes - due February 2031 | Debt Instrument, Redemption, Period After Two  
Debt Instrument, Redemption [Line Items]  
Debt Instrument, Redemption Price, Percentage 100.00%
v3.25.4
Debt - Schedule of Pricing Grid for Borrowing Base Utilization Percentage (Details)
 12 Months Ended
Dec. 31, 2025
Level 1  
Debt Instrument [Line Items]  
Commitment fee percentage 0.38%
Level 1 | Term Benchmark Loans and RFR Loan  
Debt Instrument [Line Items]  
Basis Spread on Variable Rate 2.75%
Level 1 | Alternate Base Rate  
Debt Instrument [Line Items]  
Basis Spread on Variable Rate 1.75%
Level 2  
Debt Instrument [Line Items]  
Commitment fee percentage 0.38%
Level 2 | Term Benchmark Loans and RFR Loan  
Debt Instrument [Line Items]  
Basis Spread on Variable Rate 3.00%
Level 2 | Alternate Base Rate  
Debt Instrument [Line Items]  
Basis Spread on Variable Rate 2.00%
Level 3  
Debt Instrument [Line Items]  
Commitment fee percentage 0.50%
Level 3 | Term Benchmark Loans and RFR Loan  
Debt Instrument [Line Items]  
Basis Spread on Variable Rate 3.25%
Level 3 | Alternate Base Rate  
Debt Instrument [Line Items]  
Basis Spread on Variable Rate 2.25%
Level 4  
Debt Instrument [Line Items]  
Commitment fee percentage 0.50%
Level 4 | Term Benchmark Loans and RFR Loan  
Debt Instrument [Line Items]  
Basis Spread on Variable Rate 3.50%
Level 4 | Alternate Base Rate  
Debt Instrument [Line Items]  
Basis Spread on Variable Rate 2.50%
Level 5  
Debt Instrument [Line Items]  
Commitment fee percentage 0.50%
Level 5 | Term Benchmark Loans and RFR Loan  
Debt Instrument [Line Items]  
Basis Spread on Variable Rate 3.75%
Level 5 | Alternate Base Rate  
Debt Instrument [Line Items]  
Basis Spread on Variable Rate 2.75%
Maximum [Member] | Level 1  
Debt Instrument [Line Items]  
Utilization 25.00%
Maximum [Member] | Level 2  
Debt Instrument [Line Items]  
Utilization 50.00%
Maximum [Member] | Level 3  
Debt Instrument [Line Items]  
Utilization 75.00%
Maximum [Member] | Level 4  
Debt Instrument [Line Items]  
Utilization 90.00%
Minimum [Member] | Level 2  
Debt Instrument [Line Items]  
Utilization 25.00%
Minimum [Member] | Level 3  
Debt Instrument [Line Items]  
Utilization 50.00%
Minimum [Member] | Level 4  
Debt Instrument [Line Items]  
Utilization 75.00%
Minimum [Member] | Level 5  
Debt Instrument [Line Items]  
Utilization 90.00%
v3.25.4
Asset Retirement Obligations - Schedule of Asset Retirement Obligations (Details) - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
Asset Retirement Obligation Disclosure [Abstract]      
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) 0  
Accretion expense 125,296 117,604 $ 86,152
Changes in estimate [2] 153,080 44,068  
Balance, end of period 1,332,128 1,149,735 $ 897,226
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.
v3.25.4
Asset Retirement Obligations - Additional Information (Details) - Future plugging and abanonment obligations
$ in Millions
Dec. 31, 2025
USD ($)
Asset Retirement Obligation [Line Items]  
Restricted Cash $ 76.2
Receivable with imputed interest, face amount $ 66.2
v3.25.4
Stockholders' Equity - Additional Information (Details) - USD ($)
$ in Thousands
 12 Months Ended
Jan. 22, 2024
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
Stockholders Equity Note Related to Business Acquisition [Line Items]        
Issuance of common stock, Shares     34,500,000  
Issuance of common stock   $ 0 $ 387,717 $ 0
Common Stock        
Stockholders Equity Note Related to Business Acquisition [Line Items]        
Issuance of common stock, Shares     34,500,000  
Underwriter Discount Fee        
Stockholders Equity Note Related to Business Acquisition [Line Items]        
Payments of stock issuance costs $ 15,100      
Offering Expenses        
Stockholders Equity Note Related to Business Acquisition [Line Items]        
Payments of stock issuance costs $ 800      
Underwritten Public Offering        
Stockholders Equity Note Related to Business Acquisition [Line Items]        
Issuance of common stock, Shares 34,500,000      
Underwritten Public Offering | Common Stock        
Stockholders Equity Note Related to Business Acquisition [Line Items]        
Issuance of common stock $ 387,700      
v3.25.4
Employee Benefits Plans and Share-Based Compensation - Additional Information (Details) - USD ($)
$ in Millions
 12 Months Ended
Nov. 01, 2024
Sep. 09, 2024
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
May 23, 2024
Share Based Compensation Arrangement By Share Based Payment Award Line Items            
Accrued severance cost       $ 26.0 $ 25.3  
Restricted Stock Units            
Share Based Compensation Arrangement By Share Based Payment Award Line Items            
Share-Based Compensation vested shares, grant     1,484,838 1,534,798 1,730,959  
Share - Based Compensation Arrangement, granted     3,017,967 3,155,776 1,154,541  
Forfeited     479,809 384,904 332,725  
Performance Shares            
Share Based Compensation Arrangement By Share Based Payment Award Line Items            
Contingent Right Upon Vesting to Receive Common Stock     1      
Share-Based Payment Arrangement, Nonvested Award, Cost Not yet Recognized, Period for Recognition     1 year 9 months 18 days      
Share-based compensation expense unrecognized     $ 6.9      
Share - Based Compensation Arrangement, granted     1,014,647 [1] 299,472 [2] 595,394 [3]  
Forfeited     550,014 [4] 666,455 [5] 217,346  
Performance Shares | Minimum            
Share Based Compensation Arrangement By Share Based Payment Award Line Items            
Share-Based Compensation Arrangement by Share-Based Payment Award, Award Vesting Rights, Percentage     0.00%      
Performance Shares | Maximum            
Share Based Compensation Arrangement By Share Based Payment Award Line Items            
Share-Based Compensation Arrangement by Share-Based Payment Award, Award Vesting Rights, Percentage     200.00%      
Share-Based Payment Arrangement | Common Stock            
Share Based Compensation Arrangement By Share Based Payment Award Line Items            
Share-Based Compensation vested shares, grant 28,519          
Executive Officer | Restricted Stock Units            
Share Based Compensation Arrangement By Share Based Payment Award Line Items            
Share-Based Compensation vested shares, grant       43,630    
Share - Based Compensation Arrangement, granted 43,630 157,071        
Director | Restricted Stock Units            
Share Based Compensation Arrangement By Share Based Payment Award Line Items            
Forfeited 4,273          
2021 Long Term Incentive Plan            
Share Based Compensation Arrangement By Share Based Payment Award Line Items            
Share-Based Compensation authorized to grant           12,439,415
2021 Long Term Incentive Plan | Performance Shares            
Share Based Compensation Arrangement By Share Based Payment Award Line Items            
Description of method used to calculate fair value     Monte Carlo simulations      
2021 Long Term Incentive Plan | Employees | Restricted Stock Units            
Share Based Compensation Arrangement By Share Based Payment Award Line Items            
Share-Based Compensation Arrangement by Share-Based Payment Award, Award Vesting Period     3 years      
Contingent Right Upon Vesting to Receive Common Stock     1      
Share-Based Payment Arrangement, Nonvested Award, Cost Not yet Recognized, Period for Recognition     1 year 9 months 18 days      
Share-based compensation expense unrecognized     $ 31.5      
2021 Long Term Incentive Plan | Director | Restricted Stock Units            
Share Based Compensation Arrangement By Share Based Payment Award Line Items            
Share-Based Compensation Arrangement by Share-Based Payment Award, Award Vesting Period     1 year      
Contingent Right Upon Vesting to Receive Common Stock Percentage     60.00%      
Contingent Right Upon Vesting to Receive Cash Percentage     40.00%      
2021 Long Term Incentive Plan | Director | Restricted Stock Units | Maximum            
Share Based Compensation Arrangement By Share Based Payment Award Line Items            
Contingent Right Upon Vesting to Receive Common Stock Percentage     100.00%      
General and Administrative Expense | Executive Officer            
Share Based Compensation Arrangement By Share Based Payment Award Line Items            
Severance expense     $ 5.0      
[1] 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.
[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] 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.
[4] 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.
[5] 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.
v3.25.4
Employee Benefits Plans and Share-Based Compensation - Schedule of Restricted Stock and Performance Share Units Activity (Details) - $ / shares
 12 Months Ended
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
Restricted Stock Units      
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]      
Unvested beginning of the period 3,542,435 2,306,361 3,215,504
Granted 3,017,967 3,155,776 1,154,541
Vested (1,484,838) (1,534,798) (1,730,959)
Forfeited (479,809) (384,904) (332,725)
Unvested end of the period 4,595,755 3,542,435 2,306,361
Unvested weighted average grant date fair value, beginning of the period $ 12.83 $ 14.89 $ 12.79
Unvested weighted average grant date fair value, granted 8.8 11.97 16.24
Unvested weighted average grant date fair value, vested 13.46 13.72 11.97
Unvested weighted average grant date fair value, forfeited 10.25 14.65 14.52
Unvested weighted average grant date fair value, end of the period $ 10.25 $ 12.83 $ 14.89
Performance Shares      
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]      
Unvested beginning of the period 649,666 1,016,649 638,601
Granted 1,014,647 [1] 299,472 [2] 595,394 [3]
Forfeited (550,014) [4] (666,455) [5] (217,346)
Unvested end of the period 1,114,299 649,666 1,016,649
Unvested weighted average grant date fair value, beginning of the period $ 15.27 $ 21.3 $ 23.66
Unvested weighted average grant date fair value, granted 9.87 [1] 11.36 [2] 18.76 [3]
Unvested weighted average grant date fair value, forfeited 15.94 [4] 22.71 [5] 21.28
Unvested weighted average grant date fair value, end of the period $ 10.02 $ 15.27 $ 21.3
[1] 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.
[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] 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.
[4] 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.
[5] 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.
v3.25.4
Employee Benefits Plans and Share-Based Compensation - Schedule of Restricted Stock and Performance Share Units Activity (Parenthetical) (Details) - shares
 12 Months Ended
Nov. 01, 2024
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
Dec. 31, 2022
Restricted Stock Units          
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]          
Granted   3,017,967 3,155,776 1,154,541  
Forfeited   479,809 384,904 332,725  
Unvested   4,595,755 3,542,435 2,306,361 3,215,504
Performance Shares          
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]          
Granted   1,014,647 [1] 299,472 [2] 595,394 [3]  
Forfeited   550,014 [4] 666,455 [5] 217,346  
Unvested   1,114,299 649,666 1,016,649 638,601
Share based payment payout percentage     0.00%    
Absolute Total Shareholder Return Award | Performance Shares          
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]          
Granted   837,066   297,697  
Share-Based Compensation Arrangement by Share-Based Payment Award, Award Vesting Period       3 years 3 years
Return On Drilling Program Award          
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]          
Share-Based Compensation Arrangement by Share-Based Payment Award, Award Vesting Period       3 years  
Return On Drilling Program Award | Performance Shares          
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]          
Granted       297,697  
Relative Total Shareholder Return Award | Performance Shares          
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]          
Share based payment payout percentage   0.00%      
Total Shareholder Return Award | Performance Shares          
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]          
Share-Based Compensation Arrangement by Share-Based Payment Award, Award Vesting Period     3 years    
Former Executive Officer | Total Shareholder Return Award | Performance Shares          
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]          
Granted 38,844        
2022 Grant | Performance Shares | 2025 Long Term Incentive Plan          
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]          
Forfeited     475,604    
2023 Grant | Performance Shares | 2025 Long Term Incentive Plan          
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]          
Forfeited   317,494      
[1] 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.
[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] 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.
[4] 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.
[5] 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.
v3.25.4
Employee Benefits Plans and Share-Based Compensation - Summary of Assumptions Used to Calculate the Grant Date Fair Value (Details) - Performance Shares
 12 Months Ended
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
Granted During December 31, 2025      
Share Based Compensation Arrangement By Share Based Payment Award Line Items      
Dividend yield 0.00%    
Granted During December 31, 2025 | Maximum      
Share Based Compensation Arrangement By Share Based Payment Award Line Items      
Expected term (in years) 2 years 9 months 18 days    
Expected volatility 52.40%    
Risk-free interest rate 3.80%    
Granted During December 31, 2025 | Minimum      
Share Based Compensation Arrangement By Share Based Payment Award Line Items      
Expected term (in years) 2 years 3 months 18 days    
Expected volatility 45.60%    
Risk-free interest rate 3.50%    
Granted During December 31, 2024      
Share Based Compensation Arrangement By Share Based Payment Award Line Items      
Dividend yield   0.00%  
Granted During December 31, 2024 | Maximum      
Share Based Compensation Arrangement By Share Based Payment Award Line Items      
Expected term (in years)   2 years 3 months 18 days  
Expected volatility   54.40%  
Risk-free interest rate   4.10%  
Granted During December 31, 2024 | Minimum      
Share Based Compensation Arrangement By Share Based Payment Award Line Items      
Expected term (in years)   2 years 2 months 12 days  
Expected volatility   49.50%  
Risk-free interest rate   3.60%  
Granted During December 31, 2023      
Share Based Compensation Arrangement By Share Based Payment Award Line Items      
Dividend yield     0.00%
Granted During December 31, 2023 | Maximum      
Share Based Compensation Arrangement By Share Based Payment Award Line Items      
Expected term (in years)     2 years 9 months 18 days
Expected volatility     73.10%
Risk-free interest rate     4.60%
Granted During December 31, 2023 | Minimum      
Share Based Compensation Arrangement By Share Based Payment Award Line Items      
Expected term (in years)     2 years 1 month 6 days
Expected volatility     61.90%
Risk-free interest rate     4.40%
v3.25.4
Employee Benefits Plans and Share-Based Compensation - Schedule of Recognized Share Based Compensation Expense, Net (Details) - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
Share-Based Payment Arrangement [Abstract]      
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
v3.25.4
Income Taxes - Components of Income Tax Expense (Benefit) (Details) - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 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 0 0 0
Total deferred income tax expense (benefit) (109,841) 6,771 (60,704)
Total income tax expense (benefit) $ (109,169) $ 5,003 $ (60,597)
v3.25.4
Income Taxes - Summary of Reconciliation of Income Taxes Computed U.S.Federal Statutory Tax Rate To Income Tax Expense (Benefit) (Details) - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
Effective Income Tax Rate Reconciliation [Line Items]      
Income tax expense (benefit) at the federal statutory tax rate $ (126,944) $ (14,992) $ 26,614
State and local income taxes, net of federal benefit [1] (14,849) 17,726 524
Other 904 (2,965) 1,541
Change in valuation allowance 28,800 0 (93,726)
Nontaxable or nondeductible items 2,848 4,925 4,419
Effect of cross-border tax laws 395 620 1,016
Change in unrecognized tax benefits 73 65 31
Total income tax expense (benefit) $ (109,169) $ 5,003 $ (60,597)
Effective Income Tax Rate Reconciliation, Percent [Abstract]      
Income tax expense (benefit) at the federal statutory tax rate 21.00% 21.00% 21.00%
State and local income taxes, net of federal benefit [1] 2.50% (24.80%) 0.40%
Other (0.10%) 4.20% 1.20%
Change in valuation allowance (4.80%) 0.00% (74.00%)
Nontaxable or nondeductible items (0.50%) (6.90%) 3.50%
Effect of cross-border tax laws (0.10%) (0.90%) 0.80%
Change in unrecognized tax benefits (0.00%) (0.10%) 0.00%
Total income tax expense (benefit) 18.10% (7.00%) (47.80%)
Foreign | MEXICO      
Effective Income Tax Rate Reconciliation [Line Items]      
Statutory tax rate difference between Mexico and U.S. $ 169 $ 295 $ 436
Other $ (565) $ (671) $ (1,452)
Effective Income Tax Rate Reconciliation, Percent [Abstract]      
Statutory tax rate difference between Mexico and U.S. (0.00%) (0.40%) 0.40%
Other 0.10% 0.90% (1.10%)
[1] State and local taxes in Louisiana made up the majority (greater than 50%) of the tax effect in this category.
v3.25.4
Income Taxes - Summary of Reconciliation of Income Taxes Computed U.S.Federal Statutory Tax Rate To Income Tax Expense (Benefit) (Parenthetical) (Details)
 12 Months Ended
Dec. 31, 2025
Effective Income Tax Rate Reconciliation [Line Items]  
Effective Income Tax Rate Reconciliation, State and Local Jurisdiction, Contribution Greater than 50 Percent, Tax Effect [Extensible Enumeration] State and Local Jurisdiction [Member]
v3.25.4
Income Taxes - Additional Information (Details) - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
Income Tax Disclosure [Line Items]      
Federal statutory rate 21.00% 21.00% 21.00%
State income tax benefit [1] $ (14,849) $ 17,726 $ 524
Nontaxable or nondeductible items $ 2,848 4,925 4,419
Operating loss carryforwards limitation on use 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 ownership. If not utilized, such carryforwards would begin to expire at the end of 2036.    
Valuation allowance $ 32,735 $ 3,325  
Income tax examination, Year 2022 2023 2024 2025    
Valuation allowance, commentary 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.    
Federal      
Income Tax Disclosure [Line Items]      
Valuation allowance, deferred tax asset, increase (decrease), amount $ 28,800   $ (93,700)
Operating loss carryforwards 663,500    
State      
Income Tax Disclosure [Line Items]      
State income tax benefit (14,800)    
Internal Revenue Code      
Income Tax Disclosure [Line Items]      
Operating loss carryforwards $ 569,800    
Internal Revenue Code | Federal | Capital loss carryforward      
Income Tax Disclosure [Line Items]      
Operating loss carryforwards expiration year 2036    
[1] State and local taxes in Louisiana made up the majority (greater than 50%) of the tax effect in this category.
v3.25.4
Income Taxes - Summary of Significant Components of Deferred Tax Assets and Liabilities (Details) - USD ($)
$ in Thousands
Dec. 31, 2025
Dec. 31, 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)
v3.25.4
Income Taxes - Summary of Net Operating Loss Carryovers (Details)
$ in Thousands
 12 Months Ended
Dec. 31, 2025
USD ($)
Operating Loss Carryforwards [Line Items]  
Operating loss carryforwards limitation on use 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 ownership. If not utilized, such carryforwards would begin to expire at the end of 2036.
Federal  
Operating Loss Carryforwards [Line Items]  
Net operating losses carryforward, Amount $ 663,500
Federal | Minimum  
Operating Loss Carryforwards [Line Items]  
Net operating losses, Expiration year 2036
Federal | Maximum  
Operating Loss Carryforwards [Line Items]  
Net operating losses, Expiration year 2037
Federal | 2036 - 2037  
Operating Loss Carryforwards [Line Items]  
Net operating losses carryforward, Amount $ 263,501
Federal | Unlimited Expiration Year  
Operating Loss Carryforwards [Line Items]  
Net operating losses carryforward, Amount $ 399,976
Operating loss carryforwards limitation on use Unlimited
Foreign | Minimum  
Operating Loss Carryforwards [Line Items]  
Net operating losses, Expiration year 2026
Foreign | Maximum  
Operating Loss Carryforwards [Line Items]  
Net operating losses, Expiration year 2035
Foreign | 2026 - 2033  
Operating Loss Carryforwards [Line Items]  
Net operating losses carryforward, Amount $ 1,812
State | Unlimited Expiration Year  
Operating Loss Carryforwards [Line Items]  
Net operating losses carryforward, Amount $ 373,383
Operating loss carryforwards limitation on use Unlimited
v3.25.4
Income Taxes - Summary of Balances In Uncertain Tax Positions (Details) - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
Income Tax Uncertainties [Abstract]      
Total unrecognized tax benefits, beginning balance $ 1,592 $ 989 $ 835
Unrecognized Tax Benefits, Increase Resulting from Prior Period Tax Positions 277   154
Unrecognized Tax Benefits, Decrease Resulting from Prior Period Tax Positions   120  
Tax positions taken during the current period 0 723 0
Total unrecognized tax benefits, ending balance $ 1,869 $ 1,592 $ 989
v3.25.4
Income Taxes - Components of Income Taxes Paid Net of Refunds (Details) - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
Income Tax Paid, by Individual Jurisdiction [Line Items]      
Total income taxes paid (net of refunds) $ 631 $ 4,919 $ (6)
U.S      
Income Tax Paid, by Individual Jurisdiction [Line Items]      
Federal (U.S.) 179 5,215 (18)
Louisiana      
Income Tax Paid, by Individual Jurisdiction [Line Items]      
Income Taxes Paid, State and Local 418 1 0
Other      
Income Tax Paid, by Individual Jurisdiction [Line Items]      
Income Taxes Paid, State and Local $ 34 $ (297) $ 12
v3.25.4
Income (Loss) Per Share - Summary of Computation of Basic and Diluted Income (Loss) Per Share Attributable to Common Stockholders (Details) - USD ($)
$ / shares in Units, shares in Thousands, $ in Thousands
 12 Months Ended
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
Earnings Per Share [Abstract]      
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 0 0 858
Weighted average common shares outstanding — diluted 175,136 175,605 120,752
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
v3.25.4
Related Party Transactions - Additional Information (Details) - USD ($)
$ in Millions
Dec. 31, 2025
Dec. 31, 2024
Dec. 16, 2024
Feb. 07, 2024
Investment, Identifier [Axis]: Slim Family Office        
Related Party Transaction [Line Items]        
Debt Instrument, Face Amount       $ 312.5
Second Priority Senior Secured Notes        
Related Party Transaction [Line Items]        
Debt Instrument, Face Amount       $ 1,250.0
Beneficial Owner | Slim Family        
Related Party Transaction [Line Items]        
Stock ownership percentage 25.80%      
Beneficial Owner | Maximum | Control Empresarial        
Related Party Transaction [Line Items]        
Stock ownership percentage     25.00%  
Beneficial Owner | Maximum | Slim Family        
Related Party Transaction [Line Items]        
Stock ownership percentage     25.00%  
Equity Method Investee        
Related Party Transaction [Line Items]        
Related party receivable $ 0.7 $ 0.7    
Related Party | Banco Inbursa [Member]        
Related Party Transaction [Line Items]        
Debt Issuance Costs, Gross   $ 2.7    
Carso | Lakach Deepwater Natural Gas Field | Related Party        
Related Party Transaction [Line Items]        
Related party receivable $ 2.8      
v3.25.4
Commitments and Contingencies - Additional Information (Details) - USD ($)
$ in Millions
 12 Months Ended
Dec. 31, 2024
Dec. 31, 2025
Nov. 03, 2025
Loss Contingencies [Line Items]      
Payments for Legal Settlements $ 14.4    
Bank Credit Facility | Letter of Credit      
Loss Contingencies [Line Items]      
Letters of credit outstanding amount   $ 97.4  
Surety Arrangement Plugging And Abandonment Activity Spend Amount [Member]      
Loss Contingencies [Line Items]      
Collateral funding commitments for years 2026, 2027 and 2028     $ 90.0
Collateral funding commitments for years 2029 and 2030     $ 45.0
Surety Bond Collateral      
Loss Contingencies [Line Items]      
Letters of credit outstanding amount   40.1  
Maximum [Member]      
Loss Contingencies [Line Items]      
Reasonably possible that a loss may be realized   22.0  
Minimum [Member]      
Loss Contingencies [Line Items]      
Reasonably possible that a loss may be realized   0.0  
Warrant [Member] | Maximum [Member] | QuarterNorth Acquisition      
Loss Contingencies [Line Items]      
Reasonably possible that a loss may be realized   21.0  
Warrant [Member] | Minimum [Member] | QuarterNorth Acquisition      
Loss Contingencies [Line Items]      
Reasonably possible that a loss may be realized   0.0  
Surety Bond      
Loss Contingencies [Line Items]      
Surety performance bonds outstanding   $ 1,500.0  
v3.25.4
Commitments and Contingencies - Summary of Future Minimum Transportation Fees (Details) - Firm Transportation
$ in Thousands
Dec. 31, 2025
USD ($)
Contractual Obligation [Line Items]  
2026 $ 7,356
2027 11,760
2028 14,191
2029 7,468
2030 3,173
Total $ 43,948
v3.25.4
Commitments and Contingencies - Summary of Estimated Collateral Funding Commitments (Details) - Surety Bond Collateral
$ in Thousands
Dec. 31, 2025
USD ($)
Other Commitments [Line Items]  
2026 $ 41,704
2027 42,694
2028 43,199
2029 42,134
2030 35,240
Thereafter 46,776
Total $ 251,747
v3.25.4
Commitments and Contingencies - Summary of Decommissioning Obligations Included in Consolidated Balance Sheets (Details) - Decommissioning Abandonment Obligations - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
Loss Contingencies [Line Items]      
Balance, beginning of period $ 20,002 $ 15,564 $ 54,269
Additions 1,769 6,168 266
Obligations assumed 0 1,326 0
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
Other Current Liabilities      
Loss Contingencies [Line Items]      
Less: Current portion 470 5,453 3,280
Other Noncurrent Liabilities      
Loss Contingencies [Line Items]      
Loss Contingency, Accrual, Noncurrent, Total $ 21,675 $ 14,549 $ 12,284
v3.25.4
Segment Information - Additional Information (Details) - Segment
 3 Months Ended 12 Months Ended
Mar. 18, 2024
Dec. 31, 2025
Dec. 31, 2024
Segment Reporting [Abstract]      
Number of operating segments 2   2
Number of Reportable Segments   1  
Segment Reporting, CODM, Individual Title and Position or Group Name [Extensible Enumeration]   srt:ChiefExecutiveOfficerMember, srt:ChiefFinancialOfficerMember, srt:PresidentMember  
Segment Reporting, CODM, Profit (Loss) Measure, How Used, Description   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.  
Segment reporting, no asset information [true false]   true  
v3.25.4
Segment Information - Summary of Information by Business Segment (Details) - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
Segment Reporting Information [Line Items]      
Revenues from external customers $ 1,780,070 $ 1,973,568 $ 1,457,886
Lease operating expense:      
Lease operating expense (546,716) (566,041) (389,621)
Derivative instrument on fair value gain (loss) 105,455 (1,458) 80,928
Interest expense (163,381) (187,638) (173,145)
Segment Reporting Information, Additional Information [Abstract]      
Depreciation, depletion and amortization (1,056,281) (1,023,558) (663,534)
Impairment of oil and natural gas properties (454,482) 0 0
Equity-based compensation expense (18,418) (14,462) (12,953)
Gain on Divestiture 0 100,482 0
Equity method investment income (loss) (1,807) (10,289) (3,209)
Gain (loss) on extinguishment of debt (0) (60,256) 0
Income tax benefit (expense) 109,169 (5,003) 60,597
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest (495,324) (76,393) 187,332
CCS Segment      
Segment Reporting Information [Line Items]      
Revenues from external customers   0 0
Operating Segments      
Segment Reporting Information [Line Items]      
Revenues from external customers 1,780,070 1,973,568 1,457,886
Lease operating expense:      
Adjusted general and administrative expense (133,986) [1] (132,614) [2] (98,756) [3]
Interest expense (163,381) (187,638) (173,145)
Segment Reporting Information, Additional Information [Abstract]      
Other 10,349 [4] (31,520) [5] (50,889) [6]
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)
Equity-based compensation expense (18,418) (14,462) (12,953)
Gain on Divestiture [7]   100,482  
Gain on Divestiture [8]     66,180
Equity method investment income (loss) (1,807) (10,289) (12,109)
Gain (loss) on partial sale of equity investment [9]     8,900
Gain (loss) on extinguishment of debt   (60,256)  
Income tax benefit (expense) 109,169 (5,003) 60,597
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest (495,324) (76,393) 187,332
Segment Expenditures 617,575 621,284 774,630
Operating Segments | Upstream      
Segment Reporting Information [Line Items]      
Revenues from external customers 1,780,070 1,973,568 1,457,886
Lease operating expense:      
Adjusted general and administrative expense (133,986) [1] (130,695) [2] (88,333) [3]
Interest expense (163,381) (187,432) (172,060)
Segment Reporting Information, Additional Information [Abstract]      
Other 10,349 [4] (23,048) [5] (55,048) [6]
Depreciation, depletion and amortization (1,056,281) (1,023,512) (661,904)
Impairment of oil and natural gas properties (454,482)    
Accretion expense (125,296) (117,604) (86,152)
Equity-based compensation expense (18,418) (14,415) (11,454)
Gain on Divestiture [7]   0  
Gain on Divestiture [8]     66,180
Equity method investment income (loss) (1,807) (2,319) 120
Gain (loss) on partial sale of equity investment [9]     0
Gain (loss) on extinguishment of debt   (60,256)  
Income tax benefit (expense) 109,169 12,188 57,719
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest (495,324) (141,024) 198,261
Segment Expenditures 617,575 603,765 733,669
Operating Segments | CCS Segment      
Segment Reporting Information [Line Items]      
Revenues from external customers   0 [10] 0 [11]
Lease operating expense:      
Adjusted general and administrative expense   (1,919) [2],[10] (10,423) [3],[11]
Interest expense   (206) [10] (1,085) [11]
Segment Reporting Information, Additional Information [Abstract]      
Other   (8,472) [5],[10] 4,159 [6],[11]
Depreciation, depletion and amortization   (46) [10] (1,630) [11]
Accretion expense   0 [10] 0 [11]
Equity-based compensation expense   (47) [10] (1,499) [11]
Gain on Divestiture [7],[10]   100,482  
Gain on Divestiture [8],[11]     0
Equity method investment income (loss)   (7,970) [10] (12,229) [11]
Gain (loss) on partial sale of equity investment [9],[11]     8,900
Gain (loss) on extinguishment of debt [10]   0  
Income tax benefit (expense)   (17,191) [10] 2,878 [11]
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest   64,631 [10] (10,929) [11]
Segment Expenditures   17,519 [10] 40,961 [11]
Operating Segments | Direct operating and maintenance      
Lease operating expense:      
Lease operating expense (526,839) [12] (492,123) [13] (374,481) [14]
Operating Segments | Direct operating and maintenance | Upstream      
Lease operating expense:      
Lease operating expense (526,839) [12] (492,123) [13] (374,481) [14]
Operating Segments | Direct operating and maintenance | CCS Segment      
Lease operating expense:      
Lease operating expense   0 [10],[13] 0 [11],[14]
Operating Segments | Workover      
Lease operating expense:      
Lease operating expense (19,877) [12] (73,918) [13] (15,140) [14]
Operating Segments | Workover | Upstream      
Lease operating expense:      
Lease operating expense (19,877) [12] (73,918) [13] (15,140) [14]
Operating Segments | Workover | CCS Segment      
Lease operating expense:      
Lease operating expense   0 [10],[13] 0 [11],[14]
Operating Segments | Derivative realized gain loss      
Lease operating expense:      
Derivative instrument on fair value gain (loss) (81,471) 4,710 (9,457)
Operating Segments | Derivative realized gain loss | Upstream      
Lease operating expense:      
Derivative instrument on fair value gain (loss) (81,471) 4,710 (9,457)
Operating Segments | Derivative realized gain loss | CCS Segment      
Lease operating expense:      
Derivative instrument on fair value gain (loss)   0 [10] 0 [11]
Operating Segments | Derivative mark to market gain (loss)      
Lease operating expense:      
Derivative instrument on fair value gain (loss) 23,984 (6,168) 90,385
Operating Segments | Derivative mark to market gain (loss) | Upstream      
Lease operating expense:      
Derivative instrument on fair value gain (loss) $ 23,984 (6,168) 90,385
Operating Segments | Derivative mark to market gain (loss) | CCS Segment      
Lease operating expense:      
Derivative instrument on fair value gain (loss)   $ 0 [10] $ 0 [11]
[1] Includes general and administrative expense less transaction expenses and equity-based compensation.
[2] 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.
[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 interest income and other miscellaneous operating income offset by the derecognition of a deferred payment that was deemed uncollectible.
[5] 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.
[6] 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.
[7] See further discussion in Note 3 — Acquisitions and Divestitures for additional information.
[8] See further discussion in Note 3 — Acquisitions and Divestitures for additional information.
[9] Includes a gain on the funding of the capital carry of the Company’s investment in Bayou Bend by Chevron of $8.6 million. See further discussion in Note 7 — Equity Method Investments.
[10] The CCS Segment was an emerging business in the start-up phase of operations and the business did not generate any revenues.
[11] The CCS Segment was an emerging business in the start-up phase of operations and the business did not generate any revenues.
[12] Component of lease operating expense.
[13] Component of lease operating expense.
[14] Component of lease operating expense.
v3.25.4
Segment Information - Summary of Information by Business Segment (Details) (Parenthetical) - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
Segment Reporting Information [Line Items]      
Revenues from external customers $ 1,780,070 $ 1,973,568 $ 1,457,886
Segment reporting other item composition description Primarily includes interest income and other miscellaneous operating income offset by the derecognition of a deferred payment that was deemed uncollectible. 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 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.
Operating Segments      
Segment Reporting Information [Line Items]      
Revenues from external customers $ 1,780,070 $ 1,973,568 $ 1,457,886
Gain on partial disposal of investment [1]     8,900
Operating Segments | Capital Carry | Bayou Bend CCS LLC      
Segment Reporting Information [Line Items]      
Gain on partial disposal of investment     8,600
Upstream      
Segment Reporting Information [Line Items]      
Corporate overhead   78,500 49,300
Upstream | Operating Segments      
Segment Reporting Information [Line Items]      
Revenues from external customers $ 1,780,070 1,973,568 1,457,886
Gain on partial disposal of investment [1]     0
CCS Segment      
Segment Reporting Information [Line Items]      
Revenues from external customers   0 0
Corporate overhead   400 1,700
CCS Segment | Operating Segments      
Segment Reporting Information [Line Items]      
Revenues from external customers   $ 0 [2] 0 [3]
Gain on partial disposal of investment [1],[3]     $ 8,900
[1] Includes a gain on the funding of the capital carry of the Company’s investment in Bayou Bend by Chevron of $8.6 million. See further discussion in Note 7 — Equity Method Investments.
[2] The CCS Segment was an emerging business in the start-up phase of operations and the business did not generate any revenues.
[3] The CCS Segment was an emerging business in the start-up phase of operations and the business did not generate any revenues.
v3.25.4
Segment Information - Reconciliation of Reportable Segment Expenditures (Details) - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
Segment Reporting Information [Line Items]      
Plugging & abandonment $ 117,847 $ 108,789 $ 86,615
Contributions to equity method investees (4,559) (22,988) (29,447)
Other deferred payments (20,539) (2,389) (1,545)
Exploration, development and other capital expenditures 481,905 508,914 561,434
Operating Segments | Reportable segment      
Segment Reporting Information [Line Items]      
Segment Expenditures 617,575 621,284 774,630
Segment Reconciling Items      
Segment Reporting Information [Line Items]      
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 CCS intangibles and equity method investees (0) (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
Segment Reconciling Items | Talos Energy Mexico      
Segment Reporting Information [Line Items]      
Contributions to equity method investees $ (4,559) $ (5,469) $ 0
v3.25.4
Supplemental Oil and Gas Disclosures (Unaudited) - Schedule of Capitalized Costs Related to Oil, Natural Gas and NGL Activities and Related Accumulated Depreciation, Depletion and Amortization (Details)
$ in Thousands
Dec. 31, 2025
USD ($)
$ / Boe
Dec. 31, 2024
USD ($)
$ / Boe
Dec. 31, 2023
USD ($)
$ / Boe
Reserve Quantities [Line Items]      
Proved properties $ 10,621,012 $ 9,784,832  
Unproved oil and gas properties, not subject to amortization 480,555 587,238  
Consolidated Entities [Member]      
Reserve Quantities [Line Items]      
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) | $ / Boe 30.51 30.11 27.23
Equity Method Investee [Member]      
Reserve Quantities [Line Items]      
Unproved oil and gas properties, not subject to amortization $ 62,528 $ 58,723 $ 56,579
v3.25.4
Supplemental Oil and Gas Disclosures (Unaudited) - Schedule of Costs Incurred in Oil, Natural Gas and NGL Property Acquisition, Exploration and Development Activities (Details) - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
Equity Method Investee [Member]      
Property acquisition costs:      
Exploration costs $ 3,805 $ 2,144 $ 290
Consolidated Entities [Member]      
Property acquisition costs:      
Proved properties 62,689 1,085,324 951,703
Unproved properties, not subject to amortization 0 380,129 249,688
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
v3.25.4
Supplemental Oil and Gas Disclosures (Unaudited) - Additional Information (Details)
 12 Months Ended
Dec. 31, 2025
MMBoe
$ / bbl
$ / Mcf
Dec. 31, 2024
MMBoe
$ / Mcf
$ / bbl
Dec. 31, 2023
MMBoe
$ / bbl
$ / Mcf
Reserve Quantities [Line Items]      
Audited percentage of proved oil, natural gas and NGL reserves attributable to all of oil and natural gas properties     100.00%
Proved Developed and Undeveloped Reserve, Net (Energy), Period Increase (Decrease) (19.5) 41.5 12.2
Acquisition of reserves 7.7    
Significant changes in reserves, description 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., water 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.
Production 34.5 33.9 24.2
Revision to previous estimates 5.9 4.9 (18.1)
Estimated proved reserves from extensions and discoveries   7.5 5.4
Purchases of estimated proved reserves 7.7    
Prescribed rate of discounted future net cash flows 10.00%    
Oil (MBbls)      
Reserve Quantities [Line Items]      
SEC pricing | $ / bbl 65.37 75.51 78.56
Gas (MMcf)      
Reserve Quantities [Line Items]      
SEC pricing | $ / Mcf 3.61 2.45 2.75
EnVen Energy Corporation      
Reserve Quantities [Line Items]      
Acquisition of reserve     49.1
Quarter North And Monument Acquisitions [Member]      
Reserve Quantities [Line Items]      
Acquisition of reserves   72.8  
Purchases of estimated proved reserves   72.8  
Pricing and Well Performance [Member]      
Reserve Quantities [Line Items]      
Revision to previous estimates   11.3 (13.5)
SEC Pricing [Member] | Oil (MBbls)      
Reserve Quantities [Line Items]      
SEC pricing | $ / bbl     (17.47)
SEC Pricing [Member] | Gas (MMcf)      
Reserve Quantities [Line Items]      
SEC pricing | $ / Mcf     (4.05)
Reassessed Drilling And Development Plan, Undeveloped Reserves [Member] | South Timbalier 308 Field [Member]      
Reserve Quantities [Line Items]      
Revision to previous estimates   2  
Reassessed Drilling And Development Plan, Undeveloped Reserves [Member] | Shelf and Gulf Coast [Member]      
Reserve Quantities [Line Items]      
Revision to previous estimates 4.2    
Successful Drilling Katmai West And Positive Well Performance Katmai And Big Bend Fields [Member] | Deep Water [Member]      
Reserve Quantities [Line Items]      
Estimated proved reserves from extensions and discoveries   15.3  
v3.25.4
Supplemental Oil and Gas Disclosures (Unaudited) - Schedule of Estimated Proved Reserves at Net Ownership Interest (Details)
 12 Months Ended
Dec. 31, 2025
MBoe
MMBoe
MMcf
MMBbls
Dec. 31, 2024
MBoe
MMBoe
MMBbls
MMcf
Dec. 31, 2023
MBoe
MMBoe
MMBbls
MMcf
Reserve Quantities [Line Items]      
Revision to previous estimates | MMBoe 5.9 4.9 (18.1)
Production | MMBoe (34.5) (33.9) (24.2)
Acquisition of reserves | MMBoe 7.7    
Extensions and discoveries | MMBoe   7.5 5.4
Oil (MBbls)      
Reserve Quantities [Line Items]      
Total proved reserves, beginning balance 143,048 110,815 91,059
Revision of previous estimates 3,944 (599) (6,308)
Production (24,065) (24,078) (18,062)
Acquisition of reserves 7,232 51,376 41,871
Extensions and discoveries 467 5,534 2,255
Total proved reserves, ending balance 130,626 143,048 110,815
Total proved developed reserves 101,031 108,479 98,225
Total proved undeveloped reserves 29,595 34,569 12,590
Gas (MMcf)      
Reserve Quantities [Line Items]      
Total proved reserves, beginning balance | MMcf 217,974 179,871 219,551
Revision of previous estimates | MMcf 15,826 (30,186) (62,946)
Production | MMcf (46,122) (41,078) (26,194)
Acquisition of reserves 2,573 99,683 36,690
Extensions and discoveries | MMcf 4,349 9,684 12,770
Total proved reserves, ending balance | MMcf 194,600 217,974 179,871
Total proved developed reserves 156,420 175,139 141,823
Total proved undeveloped reserves | MMcf 38,180 42,835 38,048
NGL (MBbls)      
Reserve Quantities [Line Items]      
Total proved reserves, beginning balance 14,865 11,973 12,928
Revision of previous estimates (686) 698 (1,283)
Production (2,782) (2,969) (1,767)
Acquisition of reserves 10 4,834 1,116
Extensions and discoveries 227 329 979
Total proved reserves, ending balance 11,634 14,865 11,973
Total proved developed reserves 9,644 12,733 9,957
Total proved undeveloped reserves 1,990 2,132 2,016
Oil Equivalent (MBoe)      
Reserve Quantities [Line Items]      
Total proved reserves, beginning balance | MBoe 194,242 152,766 140,579
Revision to previous estimates | MBoe 5,896 (4,932) (18,082)
Production | MBoe (34,534) (33,893) (24,195)
Acquisition of reserves | MBoe 7,670 72,824 49,102
Extensions and discoveries | MBoe 1,419 7,477 5,362
Total proved reserves, ending balance | MBoe 174,693 194,242 152,766
Total proved developed reserves | MBoe 136,745 150,402 131,819
Total proved undeveloped reserves | MBoe 37,948 43,840 20,947
v3.25.4
Supplemental Oil and Gas Disclosures (Unaudited) - Schedule of Standardized Measure of Discounted Future Net Cash Flows Related to Interest in Proved Oil, Natural Gas and NGL Reserves (Details) - USD ($)
$ in Thousands
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
Dec. 31, 2022
Extractive Industries [Abstract]        
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 $ 4,368,448
v3.25.4
Supplemental Oil and Gas Disclosures (Unaudited) - Schedule of Base Prices Used in Determining Standardized Measure (Details)
 12 Months Ended
Dec. 31, 2025
$ / Mcf
$ / bbl
Dec. 31, 2024
$ / bbl
$ / Mcf
Dec. 31, 2023
$ / bbl
$ / Mcf
Oil      
Discounted Future Net Cash Flows Relating To Proved Oil And Gas Reserves [Line Items]      
SEC pricing 65.37 75.51 78.56
Natural Gas      
Discounted Future Net Cash Flows Relating To Proved Oil And Gas Reserves [Line Items]      
SEC pricing | $ / Mcf 3.61 2.45 2.75
NGL      
Discounted Future Net Cash Flows Relating To Proved Oil And Gas Reserves [Line Items]      
SEC pricing 19.22 21.91 18.77
v3.25.4
Supplemental Oil and Gas Disclosures (Unaudited) - Schedule of Principal Changes in Standardized Measure of Discounted Future Net Cash Flows (Details) - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
Extractive Industries [Abstract]      
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
v3.25.4
Schedule I - Balance Sheets (Details) - USD ($)
$ in Thousands
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
Dec. 31, 2022
Accounts receivable:        
Other, net $ 23,738 $ 34,002    
Prepaid assets 83,080 77,487    
Other current assets 17,939 35,980    
Total current assets 841,306 659,383    
Other long-term assets:        
Investments in subsidiaries 112,382 111,269    
Total assets 5,552,057 6,191,795    
Current liabilities:        
Accounts payable 92,979 117,055    
Accrued liabilities 290,223 326,913    
Other current liabilities 29,925 44,854    
Total current liabilities 644,721 723,055    
Long-term liabilities:        
Other long-term liabilities 281,429 416,041    
Total liabilities 3,383,934 3,432,090    
Commitments and contingencies (Note 15)    
Stockholders' 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 0 0    
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 $ 2,155,151 $ 1,165,576
Total liabilities and stockholdersʼ equity 5,552,057 6,191,795    
Parent        
Accounts receivable:        
Prepaid assets 0 203    
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    
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)    
Stockholders' 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 0 0    
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    
Total liabilities and stockholdersʼ equity $ 2,321,628 $ 3,007,131    
v3.25.4
Schedule I - Balance Sheets (Details) (Paranthetical) - $ / shares
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
Dec. 31, 2022
Condensed Balance Sheet Statements, Captions [Line Items]        
Preferred Stock, Par or Stated Value Per Share $ 0.01 $ 0.01    
Preferred Stock, Shares Authorized 30,000,000 30,000,000    
Preferred Stock, Shares Issued 0 0    
Preferred Stock, Shares Outstanding 0 0    
Common Stock, Par or Stated Value Per Share $ 0.01 $ 0.01    
Common Stock, Shares Authorized 270,000,000 270,000,000    
Common Stock, Shares, Issued 188,530,052 187,434,908 127,480,361 82,570,328
Treasury stock, common, shares 20,015,369 7,417,385 3,400,000  
Parent Company [Member]        
Condensed Balance Sheet Statements, Captions [Line Items]        
Preferred Stock, Par or Stated Value Per Share $ 0.01 $ 0.01    
Preferred Stock, Shares Authorized 30,000,000 30,000,000    
Preferred Stock, Shares Issued 0 0    
Preferred Stock, Shares Outstanding 0 0    
Common Stock, Par or Stated Value Per Share $ 0.01 $ 0.01    
Common Stock, Shares Authorized 270,000,000 270,000,000    
Common Stock, Shares, Issued 188,530,052 187,434,908    
Treasury stock, common, shares 20,015,369 7,417,385    
v3.25.4
Schedule I - Statements of Operations (Details) - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
Operating expenses:      
General and administrative expense $ 155,368 $ 201,517 $ 158,493
Total operating expenses (2,340,350) (1,800,643) (1,248,096)
Operating income (expense) (560,280) 172,925 209,790
Other income (expense) 15,520 (44,930) 12,371
Income tax benefit (expense) 109,169 (5,003) 60,597
Net income (loss) attributable to Talos Energy Inc. (494,290) (76,393) 187,332
Parent      
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) attributable to Talos Energy Inc. $ (494,290) $ (76,393) $ 187,332
v3.25.4
Schedule I - Statements of Cash Flows (Details) - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
Cash flows from operating activities:      
Net cash provided by (used in) operating activities $ 935,826 $ 962,593 $ 519,069
Cash flows from investing activities:      
Net cash provided by (used in) investing activities (546,746) (1,320,279) (512,626)
Cash flows from financing activities:      
Issuance of common stock 0 387,717 0
Purchase of treasury stock (119,459) (45,181) (47,504)
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
Parent      
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 0 (389,138) 0
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 0 387,717 0
Purchase of treasury stock (119,459) (45,181) (47,504)
Net cash provided by (used in) financing activities (119,459) 342,536 (47,504)
Net increase (decrease) in cash, cash equivalents and restricted cash 0 0 0
Cash, cash equivalents and restricted cash:      
Balance, beginning of period 0 0 0
Balance, end of period $ 0 $ 0 $ 0