TALOS ENERGY INC., 10-K filed on 2/27/2025
Annual Report
v3.25.0.1
Document and Entity Information - USD ($)
 12 Months Ended
Dec. 31, 2024
Feb. 19, 2025
Jun. 28, 2024
Cover [Abstract]      
Document Type 10-K    
Amendment Flag false    
Document Period End Date Dec. 31, 2024    
Document Fiscal Year Focus 2024    
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   180,059,531  
Entity Well-known Seasoned Issuer Yes    
Entity Voluntary Filers No    
Entity Public Float     $ 1,529,482,022
Documents Incorporated by Reference

Portions of the registrant’s definitive proxy statement relating to the 2025 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, 2024 and 2023, 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, 2024, 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, 2024 and 2023, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2024, 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, 2024, 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 26, 2025 expressed an unqualified opinion thereon.

    
v3.25.0.1
CONSOLIDATED BALANCE SHEETS - USD ($)
$ in Thousands
Dec. 31, 2024
Dec. 31, 2023
Current assets:    
Cash and cash equivalents $ 108,172 $ 33,637
Accounts receivable:    
Trade, net 236,694 178,977
Joint interest, net 133,562 79,337
Other, net 34,002 19,296
Assets from price risk management activities 33,486 36,152
Prepaid assets 77,487 64,387
Other current assets 35,980 10,389
Total current assets 659,383 422,175
Property and equipment:    
Proved properties 9,784,832 7,906,295
Unproved properties, not subject to amortization 587,238 268,315
Other property and equipment 35,069 34,027
Total property and equipment 10,407,139 8,208,637
Accumulated depreciation, depletion and amortization (5,191,865) (4,168,328)
Total property and equipment, net 5,215,274 4,040,309
Other long-term assets:    
Restricted cash 106,260 102,362
Assets from price risk management activities 253 17,551
Equity method investments 111,269 146,049
Other well equipment 58,306 54,277
Notes receivable, net 17,748 16,207
Operating lease assets 11,294 11,418
Other assets 12,008 5,961
Total assets 6,191,795 4,816,309
Current liabilities:    
Accounts payable 117,055 84,193
Accrued liabilities 326,913 227,690
Accrued royalties 77,672 55,051
Current portion of long-term debt 0 33,060
Current portion of asset retirement obligations 97,166 77,581
Liabilities from price risk management activities 6,474 7,305
Accrued interest payable 49,084 42,300
Current portion of operating lease liabilities 3,837 2,666
Other current liabilities 44,854 48,769
Total current liabilities 723,055 578,615
Long-term liabilities:    
Long-term debt 1,221,399 992,614
Asset retirement obligations 1,052,569 819,645
Liabilities from price risk management activities 3,537 795
Operating lease liabilities 15,489 18,211
Other long-term liabilities 416,041 251,278
Total liabilities 3,432,090 2,661,158
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, 2024 and 2023, respectively 0 0
Common stock; $0.01 par value; 270,000,000 shares authorized; 187,434,908 and 127,480,361 shares issued as of December 31, 2024 and 2023, respectively 1,874 1,275
Additional paid-in capital 3,274,626 2,549,097
Accumulated deficit (424,110) (347,717)
Treasury stock, at cost; 7,417,385 and 3,400,000 shares as of December 31, 2024 and 2023, respectively (92,685) (47,504)
Total stockholdersʼ equity 2,759,705 2,155,151
Total liabilities and stockholdersʼ equity $ 6,191,795 $ 4,816,309
v3.25.0.1
CONSOLIDATED BALANCE SHEETS (Parenthetical) - $ / shares
Dec. 31, 2024
Dec. 31, 2023
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 187,434,908 127,480,361
Treasury stock, common, shares 7,417,385 3,400,000
v3.25.0.1
CONSOLIDATED STATEMENTS OF OPERATIONS - USD ($)
shares in Thousands, $ in Thousands
 12 Months Ended
Dec. 31, 2024
Dec. 31, 2023
Dec. 31, 2022
Revenues:      
Total revenues $ 1,973,568 $ 1,457,886 $ 1,651,980
Operating expenses:      
Lease operating expense 566,041 389,621 308,092
Production taxes 1,377 2,451 3,488
Depreciation, depletion and amortization 1,023,558 663,534 414,630
Accretion expense 117,604 86,152 55,995
General and administrative expense 201,517 158,493 99,754
Other operating (income) expense (109,454) (52,155) 33,902
Total operating expenses 1,800,643 1,248,096 915,861
Operating income (expense) 172,925 209,790 736,119
Interest expense (187,638) (173,145) (125,498)
Price risk management activities income (expense) (1,458) 80,928 (272,191)
Equity method investment income (expense) (10,289) (3,209) 14,222
Other income (expense) (44,930) 12,371 31,800
Net income (loss) before income taxes (71,390) 126,735 384,452
Income tax benefit (expense) (5,003) 60,597 (2,537)
Net income (loss) $ (76,393) $ 187,332 $ 381,915
Net income (loss) per common share:      
Basic $ (0.44) $ 1.56 $ 4.63
Diluted $ (0.44) $ 1.55 $ 4.56
Weighted average common shares outstanding:      
Basic 175,605 119,894 82,454
Diluted 175,605 120,752 83,683
Oil      
Revenues:      
Revenues $ 1,806,148 $ 1,357,732 $ 1,365,148
Natural Gas      
Revenues:      
Revenues 105,528 68,034 227,306
NGL      
Revenues:      
Revenues $ 61,892 $ 32,120 $ 59,526
v3.25.0.1
CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS' EQUITY - USD ($)
$ in Thousands
Total
Common Stock
Additional Paid-in Capital
Accumulated Deficit
Treasury Stock
Balance at Dec. 31, 2021 $ 760,653 $ 819 $ 1,676,798 $ (916,964)  
Balance, Shares at Dec. 31, 2021   81,881,477      
Equity based compensation 27,611   27,611    
Equity-based compensation tax withholdings (4,603)   (4,603)    
Equity-based compensation stock issuances   $ 7 (7)    
Equity-based compensation stock issuances, shares   688,851      
Net Income (Loss) 381,915     381,915  
Balance at Dec. 31, 2022 1,165,576 $ 826 1,699,799 (535,049)  
Balance, Shares at Dec. 31, 2022   82,570,328      
Equity based compensation 25,008   25,008    
Equity-based compensation tax withholdings (7,459)   (7,459)    
Equity-based compensation stock issuances   $ 11 (11)    
Equity-based compensation stock issuances, shares   1,110,143      
Issuance of common stock for acquisitions 832,198 $ 438 831,760    
Issuance of common stock for acquisitions, Shares   43,799,890      
Purchase of treasury stock (47,504)       $ (47,504)
Purchase of treasury stock, Shares         3,400,000
Net Income (Loss) 187,332     187,332  
Balance at Dec. 31, 2023 $ 2,155,151 $ 1,275 2,549,097 (347,717) $ (47,504)
Balance, Shares at Dec. 31, 2023 127,480,361 127,480,361      
Treasury stock, common, shares 3,400,000       3,400,000
Equity based compensation $ 21,987   21,987    
Equity-based compensation tax withholdings (6,206)   (6,206)    
Equity-based compensation stock issuances   $ 11 (11)    
Equity-based compensation stock issuances, shares   1,105,095      
Issuance of common stock for acquisitions 322,630 $ 243 322,387    
Issuance of common stock for acquisitions, Shares   24,349,452      
Issuance of common stock, Value $ 387,717 $ 345 387,372    
Issuance of common stock, Shares 34,500,000 34,500,000      
Purchase of treasury stock $ (45,181)       $ (45,181)
Purchase of treasury stock, Shares         4,017,385
Net Income (Loss) (76,393)     (76,393)  
Balance at Dec. 31, 2024 $ 2,759,705 $ 1,874 $ 3,274,626 $ (424,110) $ (92,685)
Balance, Shares at Dec. 31, 2024 187,434,908 187,434,908      
Treasury stock, common, shares 7,417,385       7,417,385
v3.25.0.1
CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2024
Dec. 31, 2023
Dec. 31, 2022
Cash flows from operating activities:      
Net income (loss) $ (76,393) $ 187,332 $ 381,915
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities      
Depreciation, depletion, amortization and accretion expense 1,141,162 749,686 470,625
Amortization of deferred financing costs and original issue discount 9,303 15,039 14,379
Equity-based compensation expense 14,462 12,953 15,953
Price risk management activities (income) expense 1,458 (80,928) 272,191
Net cash received (paid) on settled derivative instruments 4,710 (9,457) (425,559)
Equity method investment (income) expense 10,289 3,209 (14,222)
Loss (gain) on extinguishment of debt 60,256 0 1,569
Settlement of asset retirement obligations (108,789) (86,615) (69,596)
Loss (gain) on sale of assets 38 (66,115) 303
Loss (gain) on sale of business (100,482) 0 0
Changes in operating assets and liabilities:      
Accounts receivable 8,576 20,352 14,927
Other current assets (6,964) 7,066 (36,545)
Accounts payable (3,831) (60,401) 24,258
Other current liabilities 1,290 (96,960) 73,531
Other non-current assets and liabilities, net 7,508 (76,092) (13,990)
Net cash provided by (used in) operating activities 962,593 519,069 709,739
Cash flows from investing activities:      
Exploration, development and other capital expenditures (508,914) (561,434) (323,164)
Cash acquired in excess of payments for acquisitions 0 17,617 0
Payments for acquisitions, net of cash acquired (936,214) 0 (3,500)
Proceeds from (cash paid for) sale of property and equipment, net 1,161 73,004 1,937
Contributions to equity method investees (22,988) (29,447) (2,250)
Investment in intangible assets 0 (12,366) 0
Proceeds from sale of businesses 146,676 0 0
Proceeds from sale of equity method investment 0 0 15,000
Net cash provided by (used in) investing activities (1,320,279) (512,626) (311,977)
Cash flows from financing activities:      
Issuance of common stock 387,717 0 0
Issuance of senior notes 1,250,000 0 0
Redemption of senior notes (897,116) (30,000) (18,184)
Proceeds from Bank Credit Facility 880,000 825,000 85,000
Repayment of Bank Credit Facility (1,080,000) (625,000) (460,000)
Deferred financing costs (32,872) (11,775) (189)
Other deferred payments (2,389) (1,545) 0
Payments of finance lease (17,834) (16,306) (25,493)
Purchase of treasury stock (45,181) (47,504) 0
Employee stock awards tax withholdings (6,206) (7,459) (4,603)
Net cash provided by (used in) financing activities 436,119 85,411 (423,469)
Net increase (decrease) in cash, cash equivalents and restricted cash 78,433 91,854 (25,707)
Cash, cash equivalents and restricted cash:      
Balance, beginning of period 135,999 44,145 69,852
Balance, end of period 214,432 135,999 44,145
Supplemental non-cash transactions:      
Capital expenditures included in accounts payable and accrued liabilities 85,550 114,972 105,773
Supplemental cash flow information:      
Interest paid, net of amounts capitalized $ 130,841 $ 130,313 $ 91,809
v3.25.0.1
Pay vs Performance Disclosure - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2024
Dec. 31, 2023
Dec. 31, 2022
Pay vs Performance Disclosure      
Net Income (Loss) $ (76,393) $ 187,332 $ 381,915
v3.25.0.1
Insider Trading Arrangements
 3 Months Ended
Dec. 31, 2024
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
Insider Trading Policies and Procedures Adopted true
v3.25.0.1
Insider Trading Policies and Procedures
 3 Months Ended
Dec. 31, 2024
Insider Trading Policies and Procedures [Line Items]  
Insider Trading Policies and Procedures Adopted true
v3.25.0.1
Cybersecurity Risk Management, Strategy and Governance
 12 Months Ended
Dec. 31, 2024
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 strive to align our cybersecurity operating model with the National Institute of Standards and Technology (“NIST”) Cybersecurity Framework to enhance our ability to protect, detect, respond, and recover from potential cybersecurity threats. Our cybersecurity team actively works 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.

We engage third-party service providers to conduct evaluations of our cybersecurity controls through penetration testing, independent audits and consulting on best practices to address existing and new challenges. These evaluations include testing the design and operational effectiveness of our cybersecurity controls. Going forward, we are committed to conducting these evaluations at least annually. To further enhance the capabilities of our internal systems, we utilize third-party vendors to provide extended coverage of our information technology and operational technology environments. We also share and receive threat intelligence with 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 conduct employee training bi-annually, 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 Board of Directors is aware of the importance of managing risks associated with 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 receives reports at least quarterly from the Director of Information Technology regarding cybersecurity matters, which may include, among other things, the results of cybersecurity audits, cybersecurity maturity assessments, other information technology matters, risk mitigation strategies, data protection and progress on initiatives. 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 information technology team is responsible for assessing, identifying and managing cybersecurity risks. Top cybersecurity risks are also integrated into our overall ERM framework and overseen at the management level by the ERM Steering Committee. Our Director of Information Technology, who reports directly to the CFO and Executive Vice President (“EVP”) 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 Director of Information Technology in consultation with our CFO and EVP. In addition, our Director of Information Technology has a direct line of communication with the Office of the Interim Chief Executive Officer and General Counsel as needed. Our Director of Information Technology has over 20 years of experience in cybersecurity, holds a Master of Science in Cybersecurity from the University of Houston and is a Certified Information Systems Security Professional and a Boardroom Certified Qualified Technology Expert.

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. 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 previous cybersecurity incidents that have materially affected or are reasonably likely to materially affect the Company, although the Company regularly experiences cybersecurity incidents that are not deemed material to our operations. 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, and a cybersecurity incident impacting us or any of these entities could materially adversely disrupt our operations, including our drilling operations, and affect our performance 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 — Our business could be negatively affected by security threats, including cybersecurity threats, terrorist attacks and other disruptions.
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 Board of Directors is aware of the importance of managing risks associated with 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 receives reports at least quarterly from the Director of Information Technology regarding cybersecurity matters, which may include, among other things, the results of cybersecurity audits, cybersecurity maturity assessments, other information technology matters, risk mitigation strategies, data protection and progress on initiatives. 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 receives reports at least quarterly from the Director of Information Technology regarding cybersecurity matters, which may include, among other things, the results of cybersecurity audits, cybersecurity maturity assessments, other information technology matters, risk mitigation strategies, data protection and progress on initiatives.
Cybersecurity Risk Role of Management [Text Block] Management’s Role in Assessing and Managing Cybersecurity Threats — Our information technology team is responsible for assessing, identifying and managing cybersecurity risks. Top cybersecurity risks are also integrated into our overall ERM framework and overseen at the management level by the ERM Steering Committee. Our Director of Information Technology, who reports directly to the CFO and Executive Vice President (“EVP”) 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 Director of Information Technology in consultation with our CFO and EVP. In addition, our Director of Information Technology has a direct line of communication with the Office of the Interim Chief Executive Officer and General Counsel as needed. Our Director of Information Technology has over 20 years of experience in cybersecurity, holds a Master of Science in Cybersecurity from the University of Houston and is a Certified Information Systems Security Professional and a Boardroom Certified Qualified Technology Expert.
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 Director of Information Technology in consultation with our CFO and EVP. In addition, our Director of Information Technology has a direct line of communication with the Office of the Interim Chief Executive Officer and General Counsel as needed.
Cybersecurity Risk Management Expertise of Management Responsible [Text Block] Our Director of Information Technology has over 20 years of experience in cybersecurity, holds a Master of Science in Cybersecurity from the University of Houston and is a Certified Information Systems Security Professional and a Boardroom Certified Qualified Technology Expert.
Cybersecurity Risk Process for Informing Management or Committees Responsible [Text Block] Technology and cybersecurity policy decisions are made by our Director of Information Technology in consultation with our CFO and EVP. In addition, our Director of Information Technology has a direct line of communication with the Office of the Interim Chief Executive Officer and General Counsel as needed.
Cybersecurity Risk Management Positions or Committees Responsible Report to Board [Flag] true
v3.25.0.1
Organization, Nature of Business and Basis of Presentation
 12 Months Ended
Dec. 31, 2024
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 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

Segment Reporting — In November 2023, the Financial Accounting Standards Board (“FASB”) issued an update to the required disclosures for segment reporting to improve reportable segment disclosures, primarily through enhanced disclosures about significant segment expenses that are included within segment profit and loss are required to be disclosed. The disclosure guidance became effective in 2024 for annual periods only; will become effective for interim periods during 2025; and was adopted on a retrospective basis for all prior periods presented in the financial statements. The enhanced segment disclosures are included in Note 16 — Segment Information. As of December 31, 2024, the Company has a single reportable segment entity managed on a consolidated basis. Upon adoption of the new disclosure guidance and a change in the chief operating decision maker (“CODM”), the Company’s measure of segment profit or loss became net income (loss) because the segment reporting guidance requires disclosure of the measure used by the CODM that is closest to GAAP. Previously, the Company’s measure of segment profit or loss was Adjusted EBITDA.

Recently Issued Accounting Standards Not Yet Adopted

Tax Disclosures — In December 2023, the FASB issued an update which expands disclosures in an entity’s income tax rate reconciliation table and regarding cash taxes paid both in the U.S. and foreign jurisdictions. The tabular rate reconciliation will require both percentages and dollars. Currently, there is an option to present the table in either percentages or dollars. The update is effective for annual periods beginning after December 15, 2024 on a prospective basis. However, retrospective application in all periods presented is permitted. The Company continues to evaluate the impact of this new disclosure guidance.

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.
v3.25.0.1
Summary of Significant Accounting Policies
 12 Months Ended
Dec. 31, 2024
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, 2024 and 2023, the Company had allowances of $25.5 million and $8.8 million, respectively, presented net in “Accounts receivable” on the Consolidated Balance Sheets. See Note 3 — Acquisitions and Divestitures for further discussion on the allowances acquired as part of the QuarterNorth Acquisition.

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 subscriptions, 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, dismantlement, restoration and abandonment 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 “Write-down 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 required deposits of approximately $100.0 million, which was 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 Statement 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, 2024, 2023 and 2022.

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,

 

 

2024

 

2023

 

2022

 

Shell Trading (US) Company

 

48

%

 

54

%

 

44

%

Exxon Mobil Corporation

 

17

%

**

 

**

 

Valero Energy Corporation

**

 

 

21

%

 

23

%

Chevron Products Company

**

 

**

 

 

11

%

 

** 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 Statement of Cash Flows (in thousands):

 

Year Ended December 31,

 

 

2024

 

2023

 

Cash and cash equivalents

$

108,172

 

$

33,637

 

Restricted cash included in Other long-term assets

 

106,260

 

 

102,362

 

Total cash, cash equivalent and restricted cash

$

214,432

 

$

135,999

 
v3.25.0.1
Acquisitions and Divestitures
 12 Months Ended
Dec. 31, 2024
Business Combinations [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 following table presents the final allocation of the purchase price to the assets acquired and liabilities assumed based on their fair values on February 13, 2023 (in thousands):

Current assets

$

243,571

 

Property and equipment

 

1,455,347

 

Other long-term assets:

 

 

Restricted cash

 

100,753

 

Notes receivable, net

 

14,844

 

Other long-term assets

 

48,899

 

Current liabilities:

 

 

Current portion of long-term debt

 

(33,234

)

Current portion of asset retirement obligations

 

(7,079

)

Other current liabilities

 

(124,347

)

Long-term liabilities:

 

 

Long-term debt

 

(233,836

)

Asset retirement obligations

 

(251,779

)

Deferred tax liabilities

 

(150,264

)

Other long-term liabilities

 

(14,976

)

Allocated purchase price

$

1,047,899

 

 

The fair values determined for accounts receivable, accounts payable and other current assets and most current liabilities were equivalent to the carrying value due to their short-term nature. Assumed debt was valued based on observable market prices.

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 and development 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, probable and possible 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 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 $9.0 million was recognized during the year ended December 31, 2022 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 years ended December 31, 2023 and 2022 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, 2022 were adjusted to include $65.1 million of general and administrative expenses, of which $16.3 million were incurred during the year ended December 31, 2022, and supplemental pro forma earnings for the year ended December 31, 2023 were adjusted to exclude these 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

 

2022

 

Revenue

$

1,509,929

 

$

2,355,215

 

Net income (loss)

$

217,537

 

$

425,995

 

Basic net income (loss) per common share

$

1.74

 

$

3.37

 

Diluted net income (loss) per common share

$

1.73

 

$

3.34

 

 

Asset Acquisition

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. An additional aggregate $24.4 million will be paid periodically in installments beginning January 1, 2025 through April 1, 2026. The Company allocated $42.6 million to proved properties. Deferred payments have been included in “Other current liabilities” and “Other long-term liabilities” on the Consolidated Balance Sheets at December 31, 2024 based on timing of the scheduled payment. The Monument Project will initially be developed with two subsea wells tied back to a third-party floating production system.

Subsequent Event — On February 20, 2025, the Company executed a definitive agreement to acquire an additional 8.3% non-operated working interest in the Monument Project for $6.3 million, excluding customary effective date adjustments. An additional aggregate $6.3 million will be paid after certain milestones are achieved. The Company expects to close the transaction in March 2025.

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 an initial purchase price of $125.0 million plus customary reimbursements and adjustments, combined totaling approximately $142.0 million (the “TLCS Divestiture”). The TLCS Divestiture includes 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 entitles Talos to certain contingent payments, of which $4.7 million was received during the year ended December 31, 2024 and $12.5 million is expected to be received during the year ended December 31, 2025. 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, 2024 based on timing of the expected receipt.

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.

As a result of the 2023 Mexico Divestiture, Talos Mexico was deconsolidated on September 27, 2023 and is now accounted for as an equity method investment. Total assets derecognized included $112.3 million of unproved properties associated with exploration and appraisal activities in Block 7 located in the shallow waters off the coast of Mexico’s Tabasco state. The fair value of the Company’s retained equity method investment in Talos Mexico was $107.6 million. The determination of fair value was based on the implied fair value of Talos Mexico. The implied fair value of Talos Mexico was based on the transaction price of the 2023 Mexico Divestiture, which was an orderly transaction between market participants. 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.

v3.25.0.1
Property, Plant and Equipment
 12 Months Ended
Dec. 31, 2024
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. During 2024, 2023 and 2022, the Company’s ceiling test computations did not result in a write-down of its U.S. oil and natural gas properties. At December 31, 2024, its ceiling test computation was based on SEC pricing of $75.51 per Bbl of oil, $2.45 per Mcf of natural gas and $21.91 per Bbl of NGLs.

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, 2024, by the year in which such costs were incurred (in thousands):

 

 

 

Year Ended December 31,

 

 

Total

 

2024

 

2023

 

2022

 

2021 and Prior

 

Acquisition United States

$

540,735

 

$

347,661

 

$

185,437

 

$

—

 

$

7,637

 

Exploration United States

 

46,503

 

 

31,592

 

 

8,961

 

 

3,097

 

 

2,853

 

Total unproved properties, not subject to amortization

$

587,238

 

$

379,253

 

$

194,398

 

$

3,097

 

$

10,490

 

 

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 these costs will be transferred to the amortization base over seven years.
v3.25.0.1
Leases
 12 Months Ended
Dec. 31, 2024
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,

 

 

2024

 

2023

 

2022

 

Finance lease costs - interest on lease liabilities

$

12,948

 

$

14,476

 

$

7,558

 

Operating lease costs, excluding short-term leases(1)

 

4,207

 

 

4,883

 

 

2,281

 

Short-term lease costs(2)

 

100,895

 

 

117,132

 

 

55,072

 

Variable lease costs(3)

 

2,464

 

 

2,888

 

 

1,450

 

Variable and fixed sublease income

 

(1,436

)

 

(482

)

 

—

 

Total lease costs

$

119,078

 

$

138,897

 

$

66,361

 

 

(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.
(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):

 

Year Ended December 31,

 

 

2024

 

2023

 

Operating leases:

 

 

 

 

Operating lease assets

$

11,294

 

$

11,418

 

 

 

 

 

 

Current portion of operating lease liabilities

$

3,837

 

$

2,666

 

Operating lease liabilities

 

15,489

 

 

18,211

 

Total operating lease liabilities

$

19,326

 

$

20,877

 

 

 

 

 

 

Finance leases:

 

 

 

 

Proved properties

$

166,261

 

$

166,261

 

 

 

 

 

 

Other current liabilities

$

19,589

 

$

17,834

 

Other long-term liabilities

 

111,641

 

 

131,230

 

Total finance lease liabilities

$

131,230

 

$

149,064

 

 

The table below presents the lease maturity by year as of December 31, 2024 (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

 

2025

$

5,656

 

$

30,782

 

2026

 

4,983

 

 

30,782

 

2027

 

4,753

 

 

30,782

 

2028

 

4,610

 

 

30,782

 

2029

 

3,226

 

 

30,782

 

Thereafter

 

1,357

 

 

12,825

 

Total lease payments

$

24,585

 

$

166,735

 

Imputed interest

 

(5,259

)

 

(35,505

)

Total lease liabilities

$

19,326

 

$

131,230

 

 

The table below presents the weighted average remaining lease term and discount rate related to leases:

 

Year Ended December 31,

 

 

2024

 

2023

 

2022

 

Weighted average remaining lease term:

 

 

 

 

 

 

Operating leases

4.8 years

 

5.9 years

 

6.4 years

 

Finance leases

5.4 years

 

6.4 years

 

7.4 years

 

Weighted average discount rate:

 

 

 

 

 

 

Operating leases

 

10.7

%

 

10.8

%

 

11.8

%

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,

 

 

2024

 

2023

 

2022

 

Operating cash outflow from finance leases

$

12,948

 

$

14,476

 

$

7,181

 

Operating cash outflow from operating leases

$

5,634

 

$

6,318

 

$

3,722

 

 

 

 

 

 

 

 

ROU assets obtained in exchange for new finance lease liabilities

$

—

 

$

—

 

$

166,261

 

ROU assets obtained in exchange for new operating lease liabilities(1)

$

1,909

 

$

12,971

 

$

474

 

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.
v3.25.0.1
Financial Instruments
 12 Months Ended
Dec. 31, 2024
Financial Instruments [Abstract]  
Financial Instruments

Note 6 — Financial Instruments

As of December 31, 2024 and 2023, 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, 2024

 

December 31, 2023

 

 

Carrying
Amount

 

Fair
Value

 

Carrying
Amount

 

Fair
Value

 

9.000% Second-Priority Senior Secured Notes – due February 2029

$

611,135

 

$

640,619

 

$

—

 

$

—

 

9.375% Second-Priority Senior Secured Notes – due February 2031

$

610,264

 

$

635,750

 

$

—

 

$

—

 

12.00% Second-Priority Senior Secured Notes – due January 2026

$

—

 

$

—

 

$

601,353

 

$

655,130

 

11.75% Senior Secured Second Lien Notes – due April 2026

$

—

 

$

—

 

$

234,221

 

$

233,410

 

Bank Credit Facility – matures March 2027

$

—

 

$

—

 

$

190,100

 

$

200,000

 

 

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.

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,

 

 

2024

 

2023

 

2022

 

Net cash received (paid) on settled derivative instruments

$

4,710

 

$

(9,457

)

$

(425,559

)

Unrealized gain (loss)

 

(6,168

)

 

90,385

 

 

153,368

 

Price risk management activities income (expense)

$

(1,458

)

$

80,928

 

$

(272,191

)

 

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, 2024:

Swap Contracts

 

Production Period

Settlement Index

Volumes

 

Swap Price

 

Crude oil:

 

(Bbls)

 

(per Bbl)

 

January 2025 – December 2025

NYMEX WTI CMA

 

25,951

 

$

72.66

 

January 2026 – June 2026

NYMEX WTI CMA

 

10,497

 

$

65.98

 

Natural gas:

 

(MMBtu)

 

(per MMBtu)

 

January 2025 – December 2025

NYMEX Henry Hub

 

57,384

 

$

3.50

 

January 2026 – December 2026

NYMEX Henry Hub

 

20,000

 

$

3.65

 

 

Two-Way Collar Contracts

 

Production Period

Settlement Index

Volumes

 

Floor Price

 

Ceiling Price

 

Crude oil:

 

(Bbls)

 

(per Bbl)

 

(per Bbl)

 

January 2025 – March 2025

NYMEX WTI CMA

 

3,000

 

$

65.00

 

$

84.35

 

 

The following tables provide additional information related to financial instruments measured at fair value on a recurring basis (in thousands):

 

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

 

 

 

December 31, 2023

 

 

Level 1

 

Level 2

 

Level 3

 

Total

 

Assets:

 

 

 

 

 

 

 

 

Oil and natural gas derivatives

$

—

 

$

53,703

 

$

—

 

$

53,703

 

Liabilities:

 

 

 

 

 

 

 

 

Oil and natural gas derivatives

 

—

 

 

(8,100

)

 

—

 

 

(8,100

)

Total net asset (liability)

$

—

 

$

45,603

 

$

—

 

$

45,603

 

 

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, 2024

 

December 31, 2023

 

 

Assets

 

Liabilities

 

Assets

 

Liabilities

 

Oil and natural gas derivatives:

 

 

 

 

 

 

 

 

Current

$

33,486

 

$

6,474

 

$

36,152

 

$

7,305

 

Non-current

 

253

 

 

3,537

 

 

17,551

 

 

795

 

Total gross amounts presented on balance sheet

 

33,739

 

 

10,011

 

 

53,703

 

 

8,100

 

Less: Gross amounts not offset on the balance sheet

 

10,011

 

 

10,011

 

 

8,100

 

 

8,100

 

Net amounts

$

23,728

 

$

—

 

$

45,603

 

$

—

 

 

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, 2024 represent derivative instruments from seven 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, 2024 would have been $23.7 million.
v3.25.0.1
Equity Method Investments
 12 Months Ended
Dec. 31, 2024
Equity Method Investments and Joint Ventures [Abstract]  
Equity Method Investments

Note 7 — Equity Method Investments

The following table presents the Company’s investments in unconsolidated affiliates by segment for the periods indicated below. The Company accounts for these investments using the equity method of accounting.

 

Ownership Interest at

 

Year Ended December 31,

 

 

December 31, 2024

 

2024

 

2023

 

Upstream:

 

 

 

 

 

 

Talos Mexico

 

50.1

%

$

110,194

 

$

107,259

 

SP 49 Pipeline LLC

 

33.3

%

 

1,075

 

 

861

 

CCS(1):

 

 

 

 

 

 

Bayou Bend CCS LLC

 

—

 %

 

—

 

 

28,183

 

Harvest Bend CCS LLC

 

—

 %

 

—

 

 

9,746

 

Coastal Bend CCS LLC

 

—

 %

 

—

 

 

—

 

Total Equity Method Investments

 

 

$

111,269

 

$

146,049

 

 

(1)
See TLCS Divestiture discussion in Note 3 — Acquisitions and Divestitures.

Talos Mexico

See Note 3 – Acquisitions and Divestitures for additional information on the deconsolidation of Talos Mexico. There is $66.0 million positive basis difference related to this investment, which will be amortized on a units of production method once regular commercial production from the Zama Field commences.

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 during 2025 upon the satisfaction of customary closing conditions and the receipt of all regulatory approvals. After consummation of the Incremental Mexico Equity Sale, Talos Mexico, which currently holds a 17.4% interest in the Zama field, will be owned 20.0% by the Company and 80.0% by Zamajal. While the Company anticipates the Incremental Mexico Equity Sale will close in 2025, there can be no assurance that all of the conditions to closing, including obtaining necessary regulatory approvals, will be satisfied. See Note 14 — Related Party Transactions for additional information on Carso.

Bayou Bend CCS LLC

On March 8, 2022, the Company made a $2.3 million cash contribution for a 50% membership interest in Bayou Bend CCS LLC (“Bayou Bend”). In May 2022, the Company sold a 25% membership interest to Chevron U.S.A. Inc. (“Chevron”) for upfront cash consideration of $15.0 million. The Company recognized a $13.9 million gain on the partial sale of its investment in Bayou Bend during the year ended December 31, 2022, which is included in “Equity method investment income (expense)” on the Consolidated Statement of Operations. Chevron also agreed to fund up to $10.0 million of contributions to Bayou Bend on the Company’s behalf, which was fully funded by the first quarter of 2023. 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 and $1.4 million gain during the years ended December 31, 2023 and 2022, respectively, 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. In March 2024, the Company sold its entire CCS business inclusive of Bayou Bend. See Note 3 – Acquisitions and Divestitures for additional information on the TLCS Divestiture.

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. In March 2023, Petróleos Mexicanos submitted the Zama Unit Development Plan (“UDP”) to Mexico’s governmental agency for approval and the UDP received approved in June 2023. An Integrated Project Team (“IPT”) was formed in March 2023 to pool the talents and competencies of all companies participating in the development of the Zama Field. The IPT reports to the Zama Unit Operating Committee, which includes representatives from each of the participating companies. 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, where project contractors proceed with procuring material and beginning the construction. Availability of equipment and unexpected construction hurdles could delay the start of oil and gas production. Even though an IPT exists, teamwork could remain a challenge. 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.
v3.25.0.1
Debt
 12 Months Ended
Dec. 31, 2024
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):

 

December 31, 2024

 

December 31, 2023

 

9.000% Second-Priority Senior Secured Notes – due February 2029

$

625,000

 

$

—

 

9.375% Second-Priority Senior Secured Notes – due February 2031

 

625,000

 

 

—

 

12.00% Second-Priority Senior Secured Notes – due January 2026

 

—

 

 

638,541

 

11.75% Senior Secured Second Lien Notes – due April 2026

 

—

 

 

227,500

 

Bank Credit Facility – matures March 2027

 

—

 

 

200,000

 

Total debt, before discount, premium and deferred financing cost

 

1,250,000

 

 

1,066,041

 

Unamortized discount, premium and deferred financing cost, net

 

(28,601

)

 

(40,367

)

Total debt

 

1,221,399

 

 

1,025,674

 

Less: Current portion of long-term debt

 

—

 

 

33,060

 

Long-term debt

$

1,221,399

 

$

992,614

 

 

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, 2024.

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.

During the year ended December 31, 2022, the Company repurchased $11.5 million of the 12.00% Notes. The debt repurchases resulted in a loss on extinguishment of debt for the year ended December 31, 2022 of $1.6 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.

7.50% Senior Notes

The 7.50% Senior Notes due 2022 matured on May 31, 2022 and were redeemed at an aggregate principal of $6.1 million plus accrued and unpaid interest.

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 December 4, 2024, the Company entered into the Borrowing Base Redetermination Agreement and Eleventh Amendment to Credit Agreement (the “Eleventh Amendment”), in order to (i) decrease the borrowing base to $925.0 million and decrease the total commitments to $925.0 million and (ii) implement an availability cap such that, if the aggregate exposure of all lenders under the Bank Credit Facility would equal or exceed $800 million at any time after the date of the Eleventh Amendment, lenders holding at least two-thirds of the aggregate commitments shall approve the making of any addition loan or issuance of any additional letter of credit.

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, 2024, the Company's borrowing base was $925.0 million with total commitments of $925.0 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 $150.0 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, 2024. See Note 15 — Commitments and Contingencies for the amount of letters of credit issued under the Bank Credit Facility as of December 31, 2024.

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 primary equity method investee as of December 31, 2024 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, 2024, restricted net assets of the Company’s consolidated subsidiaries exceeded 25%.
v3.25.0.1
Asset Retirement Obligations
 12 Months Ended
Dec. 31, 2024
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,

 

 

2024

 

2023

 

Balance, beginning of period

$

897,226

 

$

541,661

 

Obligations assumed(1)

 

199,519

 

 

258,858

 

Obligations incurred

 

107

 

 

14,199

 

Obligations settled

 

(108,789

)

 

(86,615

)

Obligations divested

 

—

 

 

(19,448

)

Accretion expense

 

117,604

 

 

86,152

 

Changes in estimate(2)

 

44,068

 

 

102,419

 

Balance, end of period

$

1,149,735

 

$

897,226

 

Less: Current portion

 

97,166

 

 

77,581

 

Long-term portion

$

1,052,569

 

$

819,645

 

 

(1)
Assumed in connection with the QuarterNorth Acquisition and EnVen Acquisition. See further discussion in Note 3 — Acquisitions and Divestitures.
(2)
Changes in estimate were primarily due to changes in expected timing and increases in cost estimates to satisfy certain future abandonment obligations.

At December 31, 2024, the Company has (1) restricted cash of $106.3 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.

v3.25.0.1
Stockholders' Equity
 12 Months Ended
Dec. 31, 2024
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.

Stockholder Rights Agreement

On October 1, 2024, the Company entered into a Rights Agreement (the “Rights Agreement”) with Computershare Trust Company, N.A., as rights agent (the “Rights Agent”). In connection therewith, the Board of Directors of the Company (the “Board”) declared a dividend of one preferred share purchase right (“Right”) for each outstanding share of the Company’s common stock, par value $0.01 per share (the “Common Stock”). The dividend became payable on October 11, 2024 to stockholders of record as of the close of business on such date.

On December 17, 2024, the Company and the Rights Agent entered into the First Amendment to the Rights Agreement (the “Amendment”). The Amendment accelerated the expiration of the Rights from the close of business on October 1, 2025 to the close of business on December 17, 2024. Accordingly, the Rights issued under the Rights Agreement expired and are no longer outstanding. Because the Rights have expired as a result of the Amendment, no preferred shares will be issued pursuant to the Rights Agreement or the Rights.
v3.25.0.1
Employee Benefits Plans and Share-Based Compensation
 12 Months Ended
Dec. 31, 2024
Share-Based Payment Arrangement [Abstract]  
Employee Benefits Plans and Share-Based Compensation

Note 11 — Employee Benefits Plans and Share-Based Compensation

Severance

The following table summarizes severance accrual activity in connection with the EnVen Acquisition, QuarterNorth Acquisition and TLCS Divestiture included in “Other current liabilities” and “Other long-term liabilities” on the Consolidated Balance Sheets, and the changes in that liability were as follows (in thousands):

 

Year Ended December 31,

 

 

2024

 

2023

 

Balance, beginning of period

$

6,294

 

$

—

 

Accrual additions

 

25,991

 

 

25,348

 

Benefit payments

 

(31,451

)

 

(19,054

)

Balance, end of period

 

834

 

 

6,294

 

Less: Current portion

 

827

 

 

6,190

 

Long-term portion

$

7

 

$

104

 

The above table includes involuntary termination benefits that are being provided pursuant to a one-time benefit arrangement that is being recognized over the future service period through the termination date. Involuntary termination benefits are also being provided pursuant to 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.

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, 2024 was approximately $31.7 million, which is expected to be recognized over a weighted average period of 2.2 years.

On September 9, 2024, there were 157,071 RSUs issued as retention awards to executive officers that are 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, 2021

 

1,983,199

 

$

13.02

 

Granted

 

2,297,465

 

$

13.23

 

Vested

 

(967,269

)

$

14.14

 

Forfeited

 

(97,891

)

$

14.34

 

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(1)

 

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(1)

 

3,542,435

 

$

12.83

 

 

(1)
As of December 31, 2024 and 2023, 35,508 and 26,975, respectively, of the unvested RSUs were accounted for as liability awards in “Accrued liabilities” on the Consolidated Balance Sheet.

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, 2024 was approximately $3.4 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, 2021

 

1,015,459

 

$

16.41

 

Granted(1)

 

629,666

 

$

23.73

 

Vested(2)

 

(14,474

)

$

13.05

 

Forfeited

 

(16,486

)

$

17.48

 

Cancelled

 

(975,564

)

$

16.42

 

Unvested PSUs at December 31, 2022

 

638,601

 

$

23.66

 

Granted(3)

 

595,394

 

$

18.76

 

Forfeited

 

(217,346

)

$

21.28

 

Unvested PSUs at December 31, 2023

 

1,016,649

 

$

21.30

 

Granted(4)

 

299,472

 

$

11.36

 

Forfeited(5)

 

(666,455

)

$

22.71

 

Unvested PSUs at December 31, 2024

 

649,666

 

$

15.27

 

 

(1)
There were 314,833 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 314,833 PSUs were granted and are eligible to vest based on continued employment and the Company’s return on the wells included in the 2022 drill program over a three-year performance period.
(2)
The performance period for the relative TSR awards ended on December 31, 2022. 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 2023. 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.
(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)
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.
(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.

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 at the date indicated:

 

2024

 

2023

 

2022

 

 

Grant

 

Grant

 

Grant

 

Grant

 

Grant

 

Grant

 

Grant

 

 

November 1

 

September 9

 

December 1

 

July 1

 

March 5

 

September 20

 

March 5

 

Expected term (in years)

 

2.2

 

 

2.3

 

 

2.1

 

 

2.5

 

 

2.8

 

 

2.3

 

 

2.8

 

Expected volatility

 

49.5

 %

 

54.4

 %

 

61.9

 %

 

66.2

 %

 

73.1

 %

 

74.3

 %

 

82.2

 %

Risk-free interest rate

 

4.1

 %

 

3.6

 %

 

4.4

 %

 

4.6

 %

 

4.5

 %

 

3.9

 %

 

1.6

 %

Dividend yield

 

—

 %

 

—

 %

 

—

 %

 

—

 %

 

—

 %

 

—

 %

 

—

 %

Fair value (in thousands)

$

355

 

$

3,047

 

$

12

 

$

173

 

$

6,165

 

$

621

 

$

8,668

 

 

Modification — During March 2022, the outstanding PSUs held by certain executive officers that were awarded in 2020 and 2021 were cancelled and, in connection with this cancellation, 1,147,352 of RSUs were granted (the “Retention RSUs”). The Retention RSUs vested ratably each year over two years, generally contingent upon continued employment through each such date. The cancellation of the PSUs along with the concurrent grant of the Retention RSUs were accounted for as a modification. The incremental cost of $9.7 million was recognized prospectively over the modified requisite service period. Additionally, the remaining unrecognized grant or modification date fair value of the original PSUs was recognized over the original remaining requisite service period.

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 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,

 

 

2024

 

2023

 

2022

 

Share-based compensation costs

$

22,088

 

$

25,236

 

$

28,280

 

Less: Amounts capitalized to oil and gas properties

 

7,626

 

 

12,283

 

 

12,327

 

Total share-based compensation expense

$

14,462

 

$

12,953

 

$

15,953

 
v3.25.0.1
Income Taxes
 12 Months Ended
Dec. 31, 2024
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,

 

 

2024

 

2023

 

2022

 

Current income tax expense (benefit):

 

 

 

 

 

 

Federal

$

(2,180

)

$

18

 

$

1,334

 

State

 

103

 

 

58

 

 

41

 

Mexico

 

309

 

 

31

 

 

432

 

Total current income tax expense (benefit)

$

(1,768

)

$

107

 

$

1,807

 

 

 

 

 

 

 

 

Deferred income tax expense (benefit):

 

 

 

 

 

 

Federal

$

(10,874

)

$

(61,182

)

$

567

 

State

 

17,645

 

 

478

 

 

92

 

Mexico

 

—

 

 

—

 

 

71

 

Total deferred income tax expense (benefit)

$

6,771

 

$

(60,704

)

$

730

 

 

 

 

 

 

 

 

Total income tax expense (benefit)

$

5,003

 

$

(60,597

)

$

2,537

 

 

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,

 

 

2024

 

2023

 

2022

 

Income tax expense (benefit) at the federal statutory tax rate

$

(14,992

)

$

26,614

 

$

80,735

 

State income taxes

 

(200

)

 

1,748

 

 

1,591

 

Impact of foreign operations

 

852

 

 

13,539

 

 

15,657

 

Effect of change in state rate

 

38,199

 

 

—

 

 

—

 

Prior year taxes

 

(2,937

)

 

1,184

 

 

(2,920

)

Change in valuation allowance

 

(20,273

)

 

(106,815

)

 

(96,537

)

Other permanent differences

 

4,354

 

 

3,133

 

 

4,011

 

Total income tax expense (benefit)

$

5,003

 

$

(60,597

)

$

2,537

 

Effective tax rate

 

(7.01

)%

 

(47.81

)%

 

0.66

 %

 

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 a non-cash tax expense of $38.2 million related to the effect of a change in state tax rate and $4.3 million related to permanent differences, offset with a non-cash tax benefit of $20.3 million related to the partial release of the valuation allowance for certain of its state deferred tax assets.

The Company’s effective tax rate for the years ended December 31, 2023 differed from the federal statutory rate of 21.0% primarily due to a non-cash tax benefit of $106.8 million related to the release of the valuation allowance for its federal deferred tax assets offset with permanent differences and state income tax expense.

The Company’s effective tax rate for the years ended December 31, 2022 differed from the federal statutory rate of 21.0% primarily due to recording a full valuation allowance against its federal, state and foreign deferred tax assets.

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, 2024. Significant components of deferred tax assets and liabilities were as follows (in thousands):

 

Year Ended December 31,

 

 

2024

 

2023

 

Deferred tax assets:

 

 

 

 

Federal net operating loss

$

108,717

 

$

147,252

 

Foreign tax loss carryforward

 

452

 

 

509

 

State net operating loss

 

12,426

 

 

24,840

 

Tax credits

 

—

 

 

107

 

Interest expense carryforward

 

74,957

 

 

46,414

 

Asset retirement obligations

 

262,773

 

 

190,248

 

Other well equipment

 

9,796

 

 

1,317

 

Accrued bonus

 

9,040

 

 

5,050

 

Share-based compensation

 

5,343

 

 

5,172

 

Operating lease liabilities

 

4,340

 

 

4,427

 

Finance lease liabilities

 

29,926

 

 

31,607

 

Other

 

5,764

 

 

3,383

 

Total deferred tax assets

 

523,534

 

 

460,326

 

Valuation allowance

 

(3,325

)

 

(23,697

)

Total deferred tax assets, net

$

520,209

 

$

436,629

 

 

 

 

 

 

Deferred tax liabilities:

 

 

 

 

Oil and gas properties

$

772,439

 

$

512,918

 

Operating lease assets

 

2,508

 

 

2,421

 

Derivatives

 

5,411

 

 

9,670

 

Prepaid

 

6,428

 

 

3,847

 

Total deferred tax liabilities

 

786,786

 

 

528,856

 

Net deferred tax liability

$

(266,577

)

$

(92,227

)

 

Net Operating Loss

The table below presents the details of the Company’s net operating loss carryovers as of December 31, 2024 (in thousands):

 

Amount

 

Expiration Year

Federal net operating losses

$

222,354

 

2036 - 2037

Federal net operating losses

$

295,348

 

Unlimited

Foreign tax loss carryforward

$

1,505

 

2026 - 2033

State net operating losses

$

282,871

 

Unlimited

 

As of December 31, 2024, the Company had U.S. federal net operating loss carryforwards (“NOLs”) of approximately $517.7 million, all of which are subject to limitation 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 $3.3 million and $23.7 million as of December 31, 2024 and 2023, 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.

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.

At December 31, 2022, the Company maintained a valuation allowance related to federal, state and foreign deferred tax assets, as there was insufficient positive evidence to overcome the substantial negative evidence of being in a cumulative loss position. At December 31, 2023, the Company was no longer in a cumulative loss position and reached the conclusion that it is appropriate to release the valuation allowance against its federal deferred tax assets due to the sustained positive operating performance and the availability of expected future taxable income. As of December 31, 2024, the Company’s remaining valuation allowance primarily relates to various state operating loss carryforwards.

Uncertain Tax Positions

The table below sets forth the beginning and ending balance of the total amount of unrecognized tax benefits. None of the unrecognized benefits would impact the effective tax rate if recognized. While amounts could change during the next 12 months, the Company does not anticipate having a material impact on its financial statements.

Balances in the uncertain tax positions are as follows (in thousands):

 

Year Ended December 31,

 

 

2024

 

2023

 

2022

 

Total unrecognized tax benefits, beginning balance

$

989

 

$

835

 

$

696

 

Increases in unrecognized tax benefits as a result of:

 

 

 

 

 

 

Tax positions taken during a prior period

 

(120

)

 

154

 

 

100

 

Tax positions taken during the current period

 

723

 

 

—

 

 

39

 

Total unrecognized tax benefits, ending balance

$

1,592

 

$

989

 

$

835

 

 

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.

Years Open to Examination

The 2021 through 2024 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.

QuarterNorth Acquisition

On March 4, 2024, the Company completed the QuarterNorth Acquisition, which is further discussed in Note 3 —Acquisitions and Divestitures. The Company recognized a net deferred tax liability of $168.1 million in its purchase price allocation as of the acquisition date to reflect differences between tax basis and the fair value of QuarterNorth’s assets acquired and liabilities assumed. The deferred tax balance is based on preliminary calculations and on information available to management at the time such estimates were made. Further analysis will be performed upon filing QuarterNorth’s tax returns that may result in a change to the net deferred tax liability recognized.
v3.25.0.1
Income (Loss) Per Share
 12 Months Ended
Dec. 31, 2024
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 were as follows (in thousands, except for the per share amounts):

 

Year Ended December 31,

 

 

2024

 

2023

 

2022

 

Net income (loss)

$

(76,393

)

$

187,332

 

$

381,915

 

 

 

 

 

 

 

 

Weighted average common shares outstanding — basic

 

175,605

 

 

119,894

 

 

82,454

 

Dilutive effect of securities

 

—

 

 

858

 

 

1,229

 

Weighted average common shares outstanding — diluted

 

175,605

 

 

120,752

 

 

83,683

 

 

 

 

 

 

 

 

Net income (loss) per common share:

 

 

 

 

 

 

Basic

$

(0.44

)

$

1.56

 

$

4.63

 

Diluted

$

(0.44

)

$

1.55

 

$

4.56

 

Anti-dilutive potentially issuable securities excluded from diluted common shares

 

2,084

 

 

1,353

 

 

865

 
v3.25.0.1
Related Party Transactions
 12 Months Ended
Dec. 31, 2024
Related Party Transactions [Abstract]  
Related Party Transactions

Note 14 — Related Party Transactions

2022 Registration Rights Agreement

In connection with the Company’s entry into the EnVen Merger Agreement on September 21, 2022 to acquire EnVen, the Company entered into a registration rights agreement (the “2022 Registration Rights Agreement”) with Adage Capital Partners, L.P. (“Adage”) and affiliated entities of Bain Capital, LP (“Bain”). Pursuant to the 2022 Registration Rights Agreement, the Company grants to Adage and Bain certain demand, “piggy-back” and shelf registration rights with respect to the shares of the Company’s common stock to be received by such entities in the EnVen Acquisition, subject to certain customary thresholds and conditions. Bain held approximately 8.4% of the Company’s outstanding shares of common stock as of December 31, 2024 based on SEC beneficial ownership reports filed by Bain. Adage ceased being a beneficial owner of more than five percent of the Company’s common stock as of December 31, 2023 based on a SEC beneficial ownership report filed by Adage in February 2024.

Additionally, the Company agreed to pay certain expenses of the parties incurred in connection with the exercise of their rights under such agreement and to indemnify them for certain securities law matters in connection with any registration statement filed pursuant thereto.

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 offering during January 2024 as further described in Note 10 — Stockholders’ Equity, Control Empresarial further increased their holding of the Company’s outstanding stock. Control Empresarial held approximately 24.2% of the Company’s outstanding shares of common stock as of December 31, 2024 based on SEC beneficial ownership reports filed by Control Empresarial.

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 would 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 more than 25.0% of the outstanding shares of any class of voting securities of the Company. The Cooperation Agreement expires December 16, 2025, but is subject to early termination upon the occurrence of certain events described in the Cooperation Agreement.

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, 2024, Carso owes the Company $2.3 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 $5.5 million related party receivable from various equity method investments as of December 31, 2024 and 2023, respectively. These amounts are reflected as “Other, net” within “Accounts Receivable” on the Consolidated Balance Sheets. See Note 7 – Equity Method Investments for additional information on the Company’s equity method investments.
v3.25.0.1
Commitments and Contingencies
 12 Months Ended
Dec. 31, 2024
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.

On March 23, 2022, the Company entered into a settlement agreement to receive $27.5 million to resolve previously pending litigation, which was filed on October 23, 2017, against a third-party supplier related to quality issues. As part of the settlement agreement, the Company released all of its claims in the litigation. The settlement is reflected as “Other income (expense)” on the Consolidated Statements of Operations.

In June 2019, David M. Dunwoody, Jr., former President of EnVen, filed a lawsuit against EnVen in Texas District Court alleging that the circumstances of his resignation entitled him to the severance payments and benefits under his employment agreement dated as of November 6, 2015 as a resignation for “Good Reason.” In September 2021, the trial court entered a judgment in favor or Mr. Dunwoody, inclusive of Mr. Dunwoody’s legal fees and interest. EnVen filed a Notice of Appeal in December 2021. The litigation was assumed as part of the EnVen Acquisition. In April 2023, the appellate court affirmed the trial court’s judgment. The Company filed a petition for review with the Texas Supreme Court on August 2, 2023, which was denied on January 26, 2024. The Company paid the judgment of $14.4 million, inclusive of Mr. Dunwoody’s legal fees and interest, during the year ended December 31, 2024.

Firm Transportation Commitments

The Company has firm transportation agreements in place with transportation pipelines for future transportation of oil production. The Company is obligated to transport a minimum monthly oil volume or pay for any deficiencies for years 2025 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, 2024 (in thousands):

2025

$

5,439

 

2026

 

5,718

 

2027

 

9,249

 

2028

 

10,619

 

2029

 

4,465

 

Thereafter

 

1,453

 

Total

$

36,943

 

 

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, removal of facilities in the U.S. Gulf of America.

As of December 31, 2024, 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, 2024, the Company had secured letters of credit issued under its Bank Credit Facility totaling $42.4 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.

The table below summarizes the Company’s total minimum commitments associated with vessel commitments, purchase obligations and other miscellaneous commitments as of December 31, 2024 (in thousands):

 

2025

 

2026

 

2027

 

2028

 

2029

 

Thereafter

 

Total

 

Vessel Commitments(1)

$

99,069

 

$

—

 

$

—

 

$

—

 

$

—

 

$

—

 

$

99,069

 

Committed purchase orders(2)

 

40,668

 

 

—

 

 

—

 

 

—

 

 

—

 

 

—

 

 

40,668

 

Other commitments

 

19,082

 

 

16,493

 

 

9,249

 

 

10,619

 

 

4,465

 

 

1,453

 

 

61,361

 

Total

$

158,819

 

$

16,493

 

$

9,249

 

$

10,619

 

$

4,465

 

$

1,453

 

$

201,098

 

 

(1)
Includes vessel commitments the Company will utilize for certain Deepwater well intervention, drilling operations and decommissioning activities. These commitments represent gross contractual obligations and accordingly, other joint owners in the properties operated by the Company will be billed for their working interest share of such costs.
(2)
Includes committed purchase orders to execute planned future drilling activities. These commitments represent gross contractual obligations and accordingly, other joint owners in the properties operated by the Company will be billed for their working interest share of such costs.

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,

 

 

2024

 

2023

 

2022

 

Balance, beginning of period

$

15,564

 

$

54,269

 

$

24,336

 

Additions

 

6,168

 

 

266

 

 

8,900

 

Obligations assumed

 

1,326

 

 

—

 

 

—

 

Changes in estimate

 

2,391

 

 

11,613

 

 

22,658

 

Settlements

 

(5,447

)

 

(50,584

)

 

(1,625

)

Balance, end of period

$

20,002

 

$

15,564

 

$

54,269

 

Less: Current portion

 

5,453

 

 

3,280

 

 

42,069

 

Long-term portion

$

14,549

 

$

12,284

 

$

12,200

 

 

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.

QuarterNorth Registration Rights Agreement

In connection with the Company’s entry into the QuarterNorth Merger Agreement, on March 4, 2024, the Company entered into a registration rights agreement (the “QNE Registration Rights Agreement”) with certain stockholders of QuarterNorth (collectively, the “RRA Holders”). Pursuant to the QNE Registration Rights Agreement, the Company granted the RRA Holders certain demand, “piggy-back” and shelf registration rights with respect to the shares of the Company’s common stock received in connection with the QuarterNorth Acquisition, subject to certain customary thresholds and conditions. The Company is obligated to pay certain expenses of the RRA Holders incurred in connection with the exercise of their rights under the QNE Registration Rights Agreement and indemnify them for certain securities law matters in connection with any registration statement filed pursuant thereto.
v3.25.0.1
Segment Information
 12 Months Ended
Dec. 31, 2024
Segment Reporting [Abstract]  
Segment Information

Note 16 — Segment Information

The Company’s operations were managed through two operating segments through March 18, 2024: (i) Upstream Segment and (ii) CCS Segment both of which are reportable. The CCS Segment was divested in March 2024. A reportable segment is an operating segment that meets materiality thresholds. The 10% tests, as prescribed by the segment reporting accounting guidance, are based on the reported measures of revenue, profit, and assets that are used by the Company’s CODM to assess performance and allocate resources. The QuarterNorth Acquisition did not change the Company’s reportable segment determinations and is included in the Upstream Segment. The CODM currently is the executive management team comprised of the General Counsel, Chief Financial Officer, and Head of Operations, each of whom are serving as Co-President, managing the Office of Interim Chief Executive Officer (“Office of the Interim CEO”).

The profit or loss metric used to evaluate segment performance is net income as reported in the Company’s Consolidated Statement of Operations. Net income is used by the CODM to measure segment profit or loss, assess performance and make strategic capital resource allocations.

Prior to the divestment of the CCS Segment, corporate general and administrative expense include certain shared costs such as finance, accounting, tax, human resources, information technology and legal costs that were not directly attributable to each of operating segment. These expenses have been fully allocated to each operating segment. Segment accounting policies are the same as those described in the summary of significant accounting policies.

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 table below.

The following table presents selected segment information for the periods indicated (in thousands):

Year Ended December 31, 2024

Upstream

 

CCS(1)

 

Total

 

Revenues from external customers

$

1,973,568

 

$

—

 

$

1,973,568

 

Significant expenses:

 

 

 

 

 

 

Lease operating expense:

 

 

 

 

 

 

Direct operating and maintenance

 

(492,123

)

 

—

 

 

(492,123

)

Workover

 

(73,918

)

 

—

 

 

(73,918

)

Adjusted general and administrative expense(2)

 

(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(3)

 

(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(4)

 

—

 

 

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) 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) 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.

(4) 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:

 

 

 

 

 

 

Lease operating expense:

 

 

 

 

 

 

Direct operating and maintenance

 

(374,481

)

 

—

 

 

(374,481

)

Workover

 

(15,140

)

 

—

 

 

(15,140

)

Adjusted general and administrative expense(2)

 

(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(3)

 

(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(4)

 

66,180

 

 

—

 

 

66,180

 

Equity method investment income (loss)

 

120

 

 

(12,229

)

 

(12,109

)

Gain (loss) on partial sale of equity investment(5)

 

—

 

 

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) 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.

(3) 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.

(4) See further discussion in Note 3 — Acquisitions and Divestitures.

(5) 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.

Year Ended December 31, 2022

Upstream

 

CCS(1)

 

Total

 

Revenues from external customers

$

1,651,980

 

$

—

 

$

1,651,980

 

Significant expenses:

 

 

 

 

 

 

Lease operating expense:

 

 

 

 

 

 

Direct operating and maintenance

 

(289,120

)

 

—

 

 

(289,120

)

Workover

 

(18,972

)

 

—

 

 

(18,972

)

Adjusted general and administrative expense(2)

 

(63,689

)

 

(8,968

)

 

(72,657

)

Net cash received (paid) on settled derivative instruments

 

(425,559

)

 

—

 

 

(425,559

)

Interest expense

 

(124,936

)

 

(562

)

 

(125,498

)

Other segment items:

 

 

 

 

 

 

Other(3)

 

(42,510

)

 

(2,653

)

 

(45,163

)

Depreciation, depletion and amortization

 

(414,395

)

 

(235

)

 

(414,630

)

Accretion expense

 

(55,995

)

 

—

 

 

(55,995

)

Mark-to-market derivative fair value gain (loss)

 

153,368

 

 

—

 

 

153,368

 

Equity-based compensation expense

 

(14,681

)

 

(1,272

)

 

(15,953

)

Gain on settlements(4)

 

29,998

 

 

—

 

 

29,998

 

Equity method investment income (loss)

 

101

 

 

(1,166

)

 

(1,065

)

Gain (loss) on partial sale of equity investment(5)

 

—

 

 

15,287

 

 

15,287

 

Gain (loss) on extinguishment of debt

 

(1,569

)

 

—

 

 

(1,569

)

Income tax benefit (expense)

 

(2,425

)

 

(112

)

 

(2,537

)

Net income (loss)

$

381,596

 

$

319

 

$

381,915

 

 

 

 

 

 

 

 

Segment Expenditures

$

452,674

 

$

2,778

 

$

455,452

 

 

(1) The CCS Segment was an emerging business in the start-up phase of operations and the business did not generate any revenues.

(2) Includes general and administrative expense less transaction expenses and equity-based compensation. Corporate overhead allocated to the Upstream Segment and CCS Segment was $49.2 million and $1.6 million, respectively.

(3) Primarily includes decommissioning obligations and transaction expenses for the Upstream Segment. Transaction expenses include costs related to the EnVen Acquisition. See further discussion in Note 3 — Acquisition and Divestitures and Note 15 — Commitments and Contingencies.

(4) Includes $27.5 million gain as a result of the settlement agreement to resolve previously pending litigation that was filed in October 2017 that is further discussed in Note 15 — Commitments and Contingencies.

(5) Includes a gain on the funding of the capital carry of the Company’s investment in Bayou Bend by Chevron of $1.4 million and a $13.9 million gain on the partial sale of its investment in Bayou Bend to Chevron. 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,

 

 

2024

 

2023

 

2022

 

Segment Expenditures:

 

 

 

 

 

 

Total reportable segments

$

621,284

 

$

774,630

 

$

455,452

 

Change in capital expenditures included in accounts payable and accrued liabilities

 

29,423

 

 

(9,199

)

 

(60,011

)

Plugging & abandonment

 

(108,789

)

 

(86,615

)

 

(69,596

)

Decommissioning obligations settled

 

(5,447

)

 

(50,584

)

 

(1,625

)

Investment in CCS intangibles and equity method investees

 

(22,988

)

 

(40,946

)

 

(2,778

)

Other deferred payments

 

(2,389

)

 

(1,545

)

 

—

 

Non-cash well equipment transfers

 

(3,412

)

 

(27,731

)

 

(6

)

Other

 

1,232

 

 

3,424

 

 

1,728

 

Exploration, development and other capital expenditures

$

508,914

 

$

561,434

 

$

323,164

 
v3.25.0.1
Supplemental Oil and Gas Disclosures (Unaudited)
 12 Months Ended
Dec. 31, 2024
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,

 

 

2024

 

2023

 

2022

 

Consolidated Entities:

 

 

 

 

 

 

Proved properties

$

9,784,832

 

$

7,906,295

 

$

5,964,340

 

Unproved oil and gas properties, not subject to amortization(1)

 

587,238

 

 

268,315

 

 

154,783

 

Total oil and gas properties

 

10,372,070

 

 

8,174,610

 

 

6,119,123

 

Less: Accumulated DD&A

 

5,163,844

 

 

4,143,491

 

 

3,484,590

 

Net capitalized costs

$

5,208,226

 

$

4,031,119

 

$

2,634,533

 

DD&A rate (Per Boe)

$

30.11

 

$

27.23

 

$

18.95

 

 

 

 

 

 

 

 

Company's Share of Equity Investees:

 

 

 

 

 

 

Unproved oil and gas properties, not subject to amortization

$

58,723

 

$

56,579

 

$

—

 

 

(1)
Amount includes $111.4 million of unproved properties, not subject to amortization, related to the Company’s operations in offshore Mexico for the year ended December 31, 2022.

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,

 

 

2024

 

2023

 

2022

 

Consolidated Entities:

 

 

 

 

 

 

Property acquisition costs:

 

 

 

 

 

 

Proved properties

$

1,085,324

 

$

951,703

 

$

—

 

Unproved properties, not subject to amortization

 

380,129

 

 

249,688

 

 

2,221

 

Total property acquisition costs

 

1,465,453

 

 

1,201,391

 

 

2,221

 

Exploration costs(1)

 

129,400

 

 

161,296

 

 

125,889

 

Development costs

 

602,607

 

 

805,148

 

 

541,512

 

Total costs incurred

$

2,197,460

 

$

2,167,835

 

$

669,622

 

 

 

 

 

 

 

 

Company's Share of Equity Investees:

 

 

 

 

 

 

Exploration costs

$

2,144

 

$

290

 

$

—

 

 

(1)
Year ended December 31, 2022 amount includes $1.2 million of exploration costs related to the Company’s operations in offshore Mexico.

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, 2024 all proved reserves were estimated by Netherland, Sewell & Associates, Inc (“NSAI”), independent petroleum engineers and geologists. At December 31, 2023 and 2022, 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, 2021

 

107,764

 

 

236,353

 

 

14,435

 

 

161,591

 

Revision of previous estimates

 

(5,625

)

 

(8,302

)

 

(2,002

)

 

(9,010

)

Production

 

(14,561

)

 

(32,215

)

 

(1,793

)

 

(21,723

)

Sales of reserves

 

(158

)

 

(7,625

)

 

—

 

 

(1,429

)

Extensions and discoveries

 

3,639

 

 

31,340

 

 

2,288

 

 

11,150

 

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

 

Total Proved Developed Reserves as of:

 

 

 

 

 

 

 

 

December 31, 2022

 

80,285

 

 

161,727

 

 

9,315

 

 

116,555

 

December 31, 2023

 

98,225

 

 

141,823

 

 

9,957

 

 

131,819

 

December 31, 2024

 

108,479

 

 

175,139

 

 

12,733

 

 

150,402

 

Total Proved Undeveloped Reserves as of:

 

 

 

 

 

 

 

 

December 31, 2022

 

10,774

 

 

57,824

 

 

3,613

 

 

24,024

 

December 31, 2023

 

12,590

 

 

38,048

 

 

2,016

 

 

20,947

 

December 31, 2024

 

34,569

 

 

42,835

 

 

2,132

 

 

43,840

 

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 Monument Acquisition 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 a decrease of 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 a decrease of 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.

During 2022, proved reserves decreased by 21.0 MMBoe primarily due to a decrease of 21.7 MMBoe of production. Additionally, there was a decrease of 9.0 MMBoe primarily due to timing of development of certain PUD locations to move beyond five years at the Phoenix Field in the Deepwater area and sales of reserves of 1.4 MMBoe primarily related to the Brushy Creek Field in the Shelf and Gulf Coast area. The decrease was partially offset by 11.2 MMBoe of estimated proved reserves from extensions and discoveries primarily from evaluations of the Pompano Field and the Ram Powell Field located in the Deepwater area.

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,

 

 

2024

 

2023

 

2022

 

Consolidated Entities:

 

 

 

 

 

 

Future cash inflows

$

11,660,546

 

$

9,425,055

 

$

10,674,896

 

Future costs:

 

 

 

 

 

 

Production

 

(3,436,232

)

 

(3,090,491

)

 

(1,906,752

)

Development and abandonment

 

(3,301,619

)

 

(2,358,368

)

 

(1,873,453

)

Future net cash flows before income taxes

 

4,922,695

 

 

3,976,196

 

 

6,894,691

 

Future income tax expense

 

(845,894

)

 

(589,413

)

 

(1,114,409

)

Future net cash flows after income taxes

 

4,076,801

 

 

3,386,783

 

 

5,780,282

 

Discount at 10% annual rate

 

(512,597

)

 

(343,295

)

 

(1,411,834

)

Standardized measure of discounted future net cash flows

$

3,564,204

 

$

3,043,488

 

$

4,368,448

 

 

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,

 

 

2024

 

2023

 

2022

 

Oil price per Bbl

$

75.51

 

$

78.56

 

$

96.03

 

Natural gas price per Mcf

$

2.45

 

$

2.75

 

$

6.80

 

NGL price per Bbl

$

21.91

 

$

18.77

 

$

33.89

 

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,

 

 

2024

 

2023

 

2022

 

Consolidated Entities:

 

 

 

 

 

 

Standardized measure, beginning of year

$

3,043,488

 

$

4,368,448

 

$

3,440,611

 

Sales and transfers of oil, net gas and NGLs produced during the period

 

(1,406,150

)

 

(1,065,814

)

 

(1,340,400

)

Net change in prices and production costs

 

(123,537

)

 

(2,835,125

)

 

2,388,442

 

Changes in estimated future development and abandonment costs

 

193,810

 

 

(19,877

)

 

(84,391

)

Previously estimated development and abandonment costs incurred

 

47,016

 

 

202,503

 

 

20,107

 

Accretion of discount

 

485,409

 

 

518,110

 

 

392,600

 

Net change in income taxes

 

(181,190

)

 

357,321

 

 

(327,265

)

Purchases of reserves

 

1,638,000

 

 

2,033,852

 

 

—

 

Sales of reserves

 

—

 

 

—

 

 

(5,218

)

Extensions and discoveries

 

74,126

 

 

90,244

 

 

202,239

 

Net change due to revision in quantity estimates

 

(162,041

)

 

(484,423

)

 

(255,743

)

Changes in production rates (timing) and other

 

(44,727

)

 

(121,751

)

 

(62,534

)

Standardized measure, end of year

$

3,564,204

 

$

3,043,488

 

$

4,368,448

 
v3.25.0.1
Subsequent Events
 12 Months Ended
Dec. 31, 2024
Subsequent Events [Abstract]  
Subsequent Events

Note 18 — Subsequent Events

Monument Additional Working Interest Acquisition

For additional information, see Note 3 — Acquisitions and Divestitures.

 
v3.25.0.1
Schedule I - Condensed Financial Information of Registrant (Parent Only)
 12 Months Ended
Dec. 31, 2024
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,

 

 

2024

 

2023

 

ASSETS

 

 

 

 

Current assets:

 

 

 

 

Accounts receivable:

 

 

 

 

Other, net

$

—

 

$

100

 

Prepaid assets

 

203

 

 

221

 

Other current assets

 

19

 

 

19

 

Total current assets

 

222

 

 

340

 

Other long-term assets:

 

 

 

 

Investments in subsidiaries

 

3,006,909

 

 

2,246,908

 

Total assets

$

3,007,131

 

$

2,247,248

 

LIABILITIES AND STOCKHOLDERSʼ EQUITY

 

 

 

 

Current liabilities:

 

 

 

 

Accounts payable

$

333

 

$

316

 

Accrued liabilities

 

544

 

 

705

 

Other current liabilities

 

162

 

 

124

 

Total current liabilities

 

1,039

 

 

1,145

 

Long-term liabilities:

 

 

 

 

Other long-term liabilities

 

246,387

 

 

90,952

 

Total liabilities

 

247,426

 

 

92,097

 

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, 2024 and 2023, respectively

 

—

 

 

—

 

Common stock; $0.01 par value; 270,000,000 shares authorized; 187,434,908 and 127,480,361 shares issued as of December 31, 2024 and 2023, respectively

 

1,874

 

 

1,275

 

Additional paid-in capital

 

3,274,626

 

 

2,549,097

 

Accumulated deficit

 

(424,110

)

 

(347,717

)

Treasury stock, at cost; 7,417,385 and 3,400,000 shares as of December 31, 2024 and 2023, respectively

 

(92,685

)

 

(47,504

)

Total stockholdersʼ equity

 

2,759,705

 

 

2,155,151

 

Total liabilities and stockholdersʼ equity

$

3,007,131

 

$

2,247,248

 

TALOS ENERGY INC. (PARENT ONLY)

STATEMENTS OF OPERATIONS

(In thousands)

 

Year Ended December 31,

 

 

2024

 

2023

 

2022

 

Operating expenses:

 

 

 

 

 

 

General and administrative expense

$

3,234

 

$

2,708

 

$

2,145

 

Total operating expenses

 

3,234

 

 

2,708

 

 

2,145

 

Operating income (expense)

 

(3,234

)

 

(2,708

)

 

(2,145

)

Other income (expense)

 

(1

)

 

(1

)

 

(1

)

Equity earnings (loss) from subsidiaries

 

(83,986

)

 

128,888

 

 

385,968

 

Net income (loss) before income taxes

 

(87,221

)

 

126,179

 

 

383,822

 

Income tax benefit (expense)

 

10,828

 

 

61,153

 

 

(1,907

)

Net income (loss)

$

(76,393

)

$

187,332

 

$

381,915

 

TALOS ENERGY INC. (PARENT ONLY)

STATEMENTS OF CASH FLOWS

(In thousands)

 

Year Ended December 31,

 

2024

 

2023

 

2022

 

Cash flows from operating activities:

 

 

 

 

 

 

Net cash provided by (used in) operating activities

$

(1,403

)

$

(1,836

)

$

(809

)

Cash flows from investing activities:

 

 

 

 

 

 

Investments in subsidiaries

 

(389,138

)

 

—

 

 

—

 

Distributions from subsidiaries

 

48,005

 

 

49,340

 

 

809

 

Net cash provided by (used in) investing activities

 

(341,133

)

 

49,340

 

 

809

 

Cash flows from financing activities:

 

 

 

 

 

 

Issuance of common stock

 

387,717

 

 

—

 

 

—

 

Purchase of treasury stock

 

(45,181

)

 

(47,504

)

 

—

 

Net cash provided (used in) by financing activities

 

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, 2024

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.

v3.25.0.1
Summary of Significant Accounting Policies (Policies)
 12 Months Ended
Dec. 31, 2024
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 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

Segment Reporting — In November 2023, the Financial Accounting Standards Board (“FASB”) issued an update to the required disclosures for segment reporting to improve reportable segment disclosures, primarily through enhanced disclosures about significant segment expenses that are included within segment profit and loss are required to be disclosed. The disclosure guidance became effective in 2024 for annual periods only; will become effective for interim periods during 2025; and was adopted on a retrospective basis for all prior periods presented in the financial statements. The enhanced segment disclosures are included in Note 16 — Segment Information. As of December 31, 2024, the Company has a single reportable segment entity managed on a consolidated basis. Upon adoption of the new disclosure guidance and a change in the chief operating decision maker (“CODM”), the Company’s measure of segment profit or loss became net income (loss) because the segment reporting guidance requires disclosure of the measure used by the CODM that is closest to GAAP. Previously, the Company’s measure of segment profit or loss was Adjusted EBITDA.

Recently Issued Accounting Standards Not Yet Adopted

Recently Issued Accounting Standards Not Yet Adopted

Tax Disclosures — In December 2023, the FASB issued an update which expands disclosures in an entity’s income tax rate reconciliation table and regarding cash taxes paid both in the U.S. and foreign jurisdictions. The tabular rate reconciliation will require both percentages and dollars. Currently, there is an option to present the table in either percentages or dollars. The update is effective for annual periods beginning after December 15, 2024 on a prospective basis. However, retrospective application in all periods presented is permitted. The Company continues to evaluate the impact of this new disclosure guidance.

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, 2024 and 2023, the Company had allowances of $25.5 million and $8.8 million, respectively, presented net in “Accounts receivable” on the Consolidated Balance Sheets. See Note 3 — Acquisitions and Divestitures for further discussion on the allowances acquired as part of the QuarterNorth Acquisition.

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 subscriptions, 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, dismantlement, restoration and abandonment 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 “Write-down 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 required deposits of approximately $100.0 million, which was 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 Statement 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, 2024, 2023 and 2022.
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,

 

 

2024

 

2023

 

2022

 

Shell Trading (US) Company

 

48

%

 

54

%

 

44

%

Exxon Mobil Corporation

 

17

%

**

 

**

 

Valero Energy Corporation

**

 

 

21

%

 

23

%

Chevron Products Company

**

 

**

 

 

11

%

 

** 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 Statement of Cash Flows (in thousands):

 

Year Ended December 31,

 

 

2024

 

2023

 

Cash and cash equivalents

$

108,172

 

$

33,637

 

Restricted cash included in Other long-term assets

 

106,260

 

 

102,362

 

Total cash, cash equivalent and restricted cash

$

214,432

 

$

135,999

 
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.

v3.25.0.1
Summary of Significant Accounting Policies (Tables)
 12 Months Ended
Dec. 31, 2024
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,

 

 

2024

 

2023

 

2022

 

Shell Trading (US) Company

 

48

%

 

54

%

 

44

%

Exxon Mobil Corporation

 

17

%

**

 

**

 

Valero Energy Corporation

**

 

 

21

%

 

23

%

Chevron Products Company

**

 

**

 

 

11

%

 

** 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 Statement of Cash Flows (in thousands):

 

Year Ended December 31,

 

 

2024

 

2023

 

Cash and cash equivalents

$

108,172

 

$

33,637

 

Restricted cash included in Other long-term assets

 

106,260

 

 

102,362

 

Total cash, cash equivalent and restricted cash

$

214,432

 

$

135,999

 
Schedule of Allowance for Credit Losses As of December 31, 2024 and 2023, the Company had allowances of $25.5 million and $8.8 million, respectively, presented net in “Accounts receivable” on the Consolidated Balance Sheets. See Note 3 — Acquisitions and Divestitures for further discussion on the allowances acquired as part of the QuarterNorth Acquisition.
v3.25.0.1
Acquisitions and Divestitures (Tables)
 12 Months Ended
Dec. 31, 2024
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 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 February 13, 2023 (in thousands):

Current assets

$

243,571

 

Property and equipment

 

1,455,347

 

Other long-term assets:

 

 

Restricted cash

 

100,753

 

Notes receivable, net

 

14,844

 

Other long-term assets

 

48,899

 

Current liabilities:

 

 

Current portion of long-term debt

 

(33,234

)

Current portion of asset retirement obligations

 

(7,079

)

Other current liabilities

 

(124,347

)

Long-term liabilities:

 

 

Long-term debt

 

(233,836

)

Asset retirement obligations

 

(251,779

)

Deferred tax liabilities

 

(150,264

)

Other long-term liabilities

 

(14,976

)

Allocated purchase price

$

1,047,899

 

 
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

 

2022

 

Revenue

$

1,509,929

 

$

2,355,215

 

Net income (loss)

$

217,537

 

$

425,995

 

Basic net income (loss) per common share

$

1.74

 

$

3.37

 

Diluted net income (loss) per common share

$

1.73

 

$

3.34

 
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

 
v3.25.0.1
Property, Plant and Equipment (Tables)
 12 Months Ended
Dec. 31, 2024
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, 2024, by the year in which such costs were incurred (in thousands):

 

 

 

Year Ended December 31,

 

 

Total

 

2024

 

2023

 

2022

 

2021 and Prior

 

Acquisition United States

$

540,735

 

$

347,661

 

$

185,437

 

$

—

 

$

7,637

 

Exploration United States

 

46,503

 

 

31,592

 

 

8,961

 

 

3,097

 

 

2,853

 

Total unproved properties, not subject to amortization

$

587,238

 

$

379,253

 

$

194,398

 

$

3,097

 

$

10,490

 
v3.25.0.1
Leases (Tables)
 12 Months Ended
Dec. 31, 2024
Leases [Abstract]  
Components of Lease Costs The components of lease costs were as follows (in thousands):

 

Year Ended December 31,

 

 

2024

 

2023

 

2022

 

Finance lease costs - interest on lease liabilities

$

12,948

 

$

14,476

 

$

7,558

 

Operating lease costs, excluding short-term leases(1)

 

4,207

 

 

4,883

 

 

2,281

 

Short-term lease costs(2)

 

100,895

 

 

117,132

 

 

55,072

 

Variable lease costs(3)

 

2,464

 

 

2,888

 

 

1,450

 

Variable and fixed sublease income

 

(1,436

)

 

(482

)

 

—

 

Total lease costs

$

119,078

 

$

138,897

 

$

66,361

 

 

(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.
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 Right-of-Use ("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):

 

Year Ended December 31,

 

 

2024

 

2023

 

Operating leases:

 

 

 

 

Operating lease assets

$

11,294

 

$

11,418

 

 

 

 

 

 

Current portion of operating lease liabilities

$

3,837

 

$

2,666

 

Operating lease liabilities

 

15,489

 

 

18,211

 

Total operating lease liabilities

$

19,326

 

$

20,877

 

 

 

 

 

 

Finance leases:

 

 

 

 

Proved properties

$

166,261

 

$

166,261

 

 

 

 

 

 

Other current liabilities

$

19,589

 

$

17,834

 

Other long-term liabilities

 

111,641

 

 

131,230

 

Total finance lease liabilities

$

131,230

 

$

149,064

 

 
Schedule of Lease Maturity

The table below presents the lease maturity by year as of December 31, 2024 (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

 

2025

$

5,656

 

$

30,782

 

2026

 

4,983

 

 

30,782

 

2027

 

4,753

 

 

30,782

 

2028

 

4,610

 

 

30,782

 

2029

 

3,226

 

 

30,782

 

Thereafter

 

1,357

 

 

12,825

 

Total lease payments

$

24,585

 

$

166,735

 

Imputed interest

 

(5,259

)

 

(35,505

)

Total lease liabilities

$

19,326

 

$

131,230

 

 
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,

 

 

2024

 

2023

 

2022

 

Weighted average remaining lease term:

 

 

 

 

 

 

Operating leases

4.8 years

 

5.9 years

 

6.4 years

 

Finance leases

5.4 years

 

6.4 years

 

7.4 years

 

Weighted average discount rate:

 

 

 

 

 

 

Operating leases

 

10.7

%

 

10.8

%

 

11.8

%

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,

 

 

2024

 

2023

 

2022

 

Operating cash outflow from finance leases

$

12,948

 

$

14,476

 

$

7,181

 

Operating cash outflow from operating leases

$

5,634

 

$

6,318

 

$

3,722

 

 

 

 

 

 

 

 

ROU assets obtained in exchange for new finance lease liabilities

$

—

 

$

—

 

$

166,261

 

ROU assets obtained in exchange for new operating lease liabilities(1)

$

1,909

 

$

12,971

 

$

474

 

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.
v3.25.0.1
Financial Instruments (Tables)
 12 Months Ended
Dec. 31, 2024
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, 2024

 

December 31, 2023

 

 

Carrying
Amount

 

Fair
Value

 

Carrying
Amount

 

Fair
Value

 

9.000% Second-Priority Senior Secured Notes – due February 2029

$

611,135

 

$

640,619

 

$

—

 

$

—

 

9.375% Second-Priority Senior Secured Notes – due February 2031

$

610,264

 

$

635,750

 

$

—

 

$

—

 

12.00% Second-Priority Senior Secured Notes – due January 2026

$

—

 

$

—

 

$

601,353

 

$

655,130

 

11.75% Senior Secured Second Lien Notes – due April 2026

$

—

 

$

—

 

$

234,221

 

$

233,410

 

Bank Credit Facility – matures March 2027

$

—

 

$

—

 

$

190,100

 

$

200,000

 

 
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,

 

 

2024

 

2023

 

2022

 

Net cash received (paid) on settled derivative instruments

$

4,710

 

$

(9,457

)

$

(425,559

)

Unrealized gain (loss)

 

(6,168

)

 

90,385

 

 

153,368

 

Price risk management activities income (expense)

$

(1,458

)

$

80,928

 

$

(272,191

)

 
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, 2024:

Swap Contracts

 

Production Period

Settlement Index

Volumes

 

Swap Price

 

Crude oil:

 

(Bbls)

 

(per Bbl)

 

January 2025 – December 2025

NYMEX WTI CMA

 

25,951

 

$

72.66

 

January 2026 – June 2026

NYMEX WTI CMA

 

10,497

 

$

65.98

 

Natural gas:

 

(MMBtu)

 

(per MMBtu)

 

January 2025 – December 2025

NYMEX Henry Hub

 

57,384

 

$

3.50

 

January 2026 – December 2026

NYMEX Henry Hub

 

20,000

 

$

3.65

 

 

Two-Way Collar Contracts

 

Production Period

Settlement Index

Volumes

 

Floor Price

 

Ceiling Price

 

Crude oil:

 

(Bbls)

 

(per Bbl)

 

(per Bbl)

 

January 2025 – March 2025

NYMEX WTI CMA

 

3,000

 

$

65.00

 

$

84.35

 

 
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, 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

 

 

 

December 31, 2023

 

 

Level 1

 

Level 2

 

Level 3

 

Total

 

Assets:

 

 

 

 

 

 

 

 

Oil and natural gas derivatives

$

—

 

$

53,703

 

$

—

 

$

53,703

 

Liabilities:

 

 

 

 

 

 

 

 

Oil and natural gas derivatives

 

—

 

 

(8,100

)

 

—

 

 

(8,100

)

Total net asset (liability)

$

—

 

$

45,603

 

$

—

 

$

45,603

 

 
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, 2024

 

December 31, 2023

 

 

Assets

 

Liabilities

 

Assets

 

Liabilities

 

Oil and natural gas derivatives:

 

 

 

 

 

 

 

 

Current

$

33,486

 

$

6,474

 

$

36,152

 

$

7,305

 

Non-current

 

253

 

 

3,537

 

 

17,551

 

 

795

 

Total gross amounts presented on balance sheet

 

33,739

 

 

10,011

 

 

53,703

 

 

8,100

 

Less: Gross amounts not offset on the balance sheet

 

10,011

 

 

10,011

 

 

8,100

 

 

8,100

 

Net amounts

$

23,728

 

$

—

 

$

45,603

 

$

—

 

 
v3.25.0.1
Equity Method Investments (Tables)
 12 Months Ended
Dec. 31, 2024
Equity Method Investments and Joint Ventures [Abstract]  
Schedule of Equity Method Investments

The following table presents the Company’s investments in unconsolidated affiliates by segment for the periods indicated below. The Company accounts for these investments using the equity method of accounting.

 

Ownership Interest at

 

Year Ended December 31,

 

 

December 31, 2024

 

2024

 

2023

 

Upstream:

 

 

 

 

 

 

Talos Mexico

 

50.1

%

$

110,194

 

$

107,259

 

SP 49 Pipeline LLC

 

33.3

%

 

1,075

 

 

861

 

CCS(1):

 

 

 

 

 

 

Bayou Bend CCS LLC

 

—

 %

 

—

 

 

28,183

 

Harvest Bend CCS LLC

 

—

 %

 

—

 

 

9,746

 

Coastal Bend CCS LLC

 

—

 %

 

—

 

 

—

 

Total Equity Method Investments

 

 

$

111,269

 

$

146,049

 

 

(1)
See TLCS Divestiture discussion in Note 3 — Acquisitions and Divestitures.
v3.25.0.1
Debt (Tables)
 12 Months Ended
Dec. 31, 2024
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):

 

December 31, 2024

 

December 31, 2023

 

9.000% Second-Priority Senior Secured Notes – due February 2029

$

625,000

 

$

—

 

9.375% Second-Priority Senior Secured Notes – due February 2031

 

625,000

 

 

—

 

12.00% Second-Priority Senior Secured Notes – due January 2026

 

—

 

 

638,541

 

11.75% Senior Secured Second Lien Notes – due April 2026

 

—

 

 

227,500

 

Bank Credit Facility – matures March 2027

 

—

 

 

200,000

 

Total debt, before discount, premium and deferred financing cost

 

1,250,000

 

 

1,066,041

 

Unamortized discount, premium and deferred financing cost, net

 

(28,601

)

 

(40,367

)

Total debt

 

1,221,399

 

 

1,025,674

 

Less: Current portion of long-term debt

 

—

 

 

33,060

 

Long-term debt

$

1,221,399

 

$

992,614

 
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%

 
v3.25.0.1
Asset Retirement Obligations (Tables)
 12 Months Ended
Dec. 31, 2024
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,

 

 

2024

 

2023

 

Balance, beginning of period

$

897,226

 

$

541,661

 

Obligations assumed(1)

 

199,519

 

 

258,858

 

Obligations incurred

 

107

 

 

14,199

 

Obligations settled

 

(108,789

)

 

(86,615

)

Obligations divested

 

—

 

 

(19,448

)

Accretion expense

 

117,604

 

 

86,152

 

Changes in estimate(2)

 

44,068

 

 

102,419

 

Balance, end of period

$

1,149,735

 

$

897,226

 

Less: Current portion

 

97,166

 

 

77,581

 

Long-term portion

$

1,052,569

 

$

819,645

 

 

(1)
Assumed in connection with the QuarterNorth Acquisition and EnVen Acquisition. See further discussion in Note 3 — Acquisitions and Divestitures.
(2)
Changes in estimate were primarily due to changes in expected timing and increases in cost estimates to satisfy certain future abandonment obligations.
v3.25.0.1
Employee Benefits Plans and Share-Based Compensation (Tables)
 12 Months Ended
Dec. 31, 2024
Share-Based Payment Arrangement [Abstract]  
Schedule Of Acquisition Severance Costs

The following table summarizes severance accrual activity in connection with the EnVen Acquisition, QuarterNorth Acquisition and TLCS Divestiture included in “Other current liabilities” and “Other long-term liabilities” on the Consolidated Balance Sheets, and the changes in that liability were as follows (in thousands):

 

Year Ended December 31,

 

 

2024

 

2023

 

Balance, beginning of period

$

6,294

 

$

—

 

Accrual additions

 

25,991

 

 

25,348

 

Benefit payments

 

(31,451

)

 

(19,054

)

Balance, end of period

 

834

 

 

6,294

 

Less: Current portion

 

827

 

 

6,190

 

Long-term portion

$

7

 

$

104

 
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, 2021

 

1,983,199

 

$

13.02

 

Granted

 

2,297,465

 

$

13.23

 

Vested

 

(967,269

)

$

14.14

 

Forfeited

 

(97,891

)

$

14.34

 

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(1)

 

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(1)

 

3,542,435

 

$

12.83

 

 

As of December 31, 2024 and 2023, 35,508 and 26,975, respectively, of the unvested RSUs were accounted for as liability awards in “Accrued liabilities” on the Consolidated Balance Sheet.
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, 2021

 

1,015,459

 

$

16.41

 

Granted(1)

 

629,666

 

$

23.73

 

Vested(2)

 

(14,474

)

$

13.05

 

Forfeited

 

(16,486

)

$

17.48

 

Cancelled

 

(975,564

)

$

16.42

 

Unvested PSUs at December 31, 2022

 

638,601

 

$

23.66

 

Granted(3)

 

595,394

 

$

18.76

 

Forfeited

 

(217,346

)

$

21.28

 

Unvested PSUs at December 31, 2023

 

1,016,649

 

$

21.30

 

Granted(4)

 

299,472

 

$

11.36

 

Forfeited(5)

 

(666,455

)

$

22.71

 

Unvested PSUs at December 31, 2024

 

649,666

 

$

15.27

 

 

(1)
There were 314,833 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 314,833 PSUs were granted and are eligible to vest based on continued employment and the Company’s return on the wells included in the 2022 drill program over a three-year performance period.
(2)
The performance period for the relative TSR awards ended on December 31, 2022. 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 2023. 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.
(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)
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.
(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.
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 at the date indicated:

 

2024

 

2023

 

2022

 

 

Grant

 

Grant

 

Grant

 

Grant

 

Grant

 

Grant

 

Grant

 

 

November 1

 

September 9

 

December 1

 

July 1

 

March 5

 

September 20

 

March 5

 

Expected term (in years)

 

2.2

 

 

2.3

 

 

2.1

 

 

2.5

 

 

2.8

 

 

2.3

 

 

2.8

 

Expected volatility

 

49.5

 %

 

54.4

 %

 

61.9

 %

 

66.2

 %

 

73.1

 %

 

74.3

 %

 

82.2

 %

Risk-free interest rate

 

4.1

 %

 

3.6

 %

 

4.4

 %

 

4.6

 %

 

4.5

 %

 

3.9

 %

 

1.6

 %

Dividend yield

 

—

 %

 

—

 %

 

—

 %

 

—

 %

 

—

 %

 

—

 %

 

—

 %

Fair value (in thousands)

$

355

 

$

3,047

 

$

12

 

$

173

 

$

6,165

 

$

621

 

$

8,668

 

 
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,

 

 

2024

 

2023

 

2022

 

Share-based compensation costs

$

22,088

 

$

25,236

 

$

28,280

 

Less: Amounts capitalized to oil and gas properties

 

7,626

 

 

12,283

 

 

12,327

 

Total share-based compensation expense

$

14,462

 

$

12,953

 

$

15,953

 
v3.25.0.1
Income Taxes (Tables)
 12 Months Ended
Dec. 31, 2024
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,

 

 

2024

 

2023

 

2022

 

Current income tax expense (benefit):

 

 

 

 

 

 

Federal

$

(2,180

)

$

18

 

$

1,334

 

State

 

103

 

 

58

 

 

41

 

Mexico

 

309

 

 

31

 

 

432

 

Total current income tax expense (benefit)

$

(1,768

)

$

107

 

$

1,807

 

 

 

 

 

 

 

 

Deferred income tax expense (benefit):

 

 

 

 

 

 

Federal

$

(10,874

)

$

(61,182

)

$

567

 

State

 

17,645

 

 

478

 

 

92

 

Mexico

 

—

 

 

—

 

 

71

 

Total deferred income tax expense (benefit)

$

6,771

 

$

(60,704

)

$

730

 

 

 

 

 

 

 

 

Total income tax expense (benefit)

$

5,003

 

$

(60,597

)

$

2,537

 
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,

 

 

2024

 

2023

 

2022

 

Income tax expense (benefit) at the federal statutory tax rate

$

(14,992

)

$

26,614

 

$

80,735

 

State income taxes

 

(200

)

 

1,748

 

 

1,591

 

Impact of foreign operations

 

852

 

 

13,539

 

 

15,657

 

Effect of change in state rate

 

38,199

 

 

—

 

 

—

 

Prior year taxes

 

(2,937

)

 

1,184

 

 

(2,920

)

Change in valuation allowance

 

(20,273

)

 

(106,815

)

 

(96,537

)

Other permanent differences

 

4,354

 

 

3,133

 

 

4,011

 

Total income tax expense (benefit)

$

5,003

 

$

(60,597

)

$

2,537

 

Effective tax rate

 

(7.01

)%

 

(47.81

)%

 

0.66

 %
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, 2024. Significant components of deferred tax assets and liabilities were as follows (in thousands):

 

Year Ended December 31,

 

 

2024

 

2023

 

Deferred tax assets:

 

 

 

 

Federal net operating loss

$

108,717

 

$

147,252

 

Foreign tax loss carryforward

 

452

 

 

509

 

State net operating loss

 

12,426

 

 

24,840

 

Tax credits

 

—

 

 

107

 

Interest expense carryforward

 

74,957

 

 

46,414

 

Asset retirement obligations

 

262,773

 

 

190,248

 

Other well equipment

 

9,796

 

 

1,317

 

Accrued bonus

 

9,040

 

 

5,050

 

Share-based compensation

 

5,343

 

 

5,172

 

Operating lease liabilities

 

4,340

 

 

4,427

 

Finance lease liabilities

 

29,926

 

 

31,607

 

Other

 

5,764

 

 

3,383

 

Total deferred tax assets

 

523,534

 

 

460,326

 

Valuation allowance

 

(3,325

)

 

(23,697

)

Total deferred tax assets, net

$

520,209

 

$

436,629

 

 

 

 

 

 

Deferred tax liabilities:

 

 

 

 

Oil and gas properties

$

772,439

 

$

512,918

 

Operating lease assets

 

2,508

 

 

2,421

 

Derivatives

 

5,411

 

 

9,670

 

Prepaid

 

6,428

 

 

3,847

 

Total deferred tax liabilities

 

786,786

 

 

528,856

 

Net deferred tax liability

$

(266,577

)

$

(92,227

)

 
Summary of Net Operating Loss Carryovers

The table below presents the details of the Company’s net operating loss carryovers as of December 31, 2024 (in thousands):

 

Amount

 

Expiration Year

Federal net operating losses

$

222,354

 

2036 - 2037

Federal net operating losses

$

295,348

 

Unlimited

Foreign tax loss carryforward

$

1,505

 

2026 - 2033

State net operating losses

$

282,871

 

Unlimited

 
Summary of Balances In Uncertain Tax Positions

Balances in the uncertain tax positions are as follows (in thousands):

 

Year Ended December 31,

 

 

2024

 

2023

 

2022

 

Total unrecognized tax benefits, beginning balance

$

989

 

$

835

 

$

696

 

Increases in unrecognized tax benefits as a result of:

 

 

 

 

 

 

Tax positions taken during a prior period

 

(120

)

 

154

 

 

100

 

Tax positions taken during the current period

 

723

 

 

—

 

 

39

 

Total unrecognized tax benefits, ending balance

$

1,592

 

$

989

 

$

835

 

 
v3.25.0.1
Income (Loss) Per Share (Tables)
 12 Months Ended
Dec. 31, 2024
Earnings Per Share [Abstract]  
Summary of Computation of Basic and Diluted Income (Loss) Per Share

The following table presents the computation of the Company’s basic and diluted income (loss) per share were as follows (in thousands, except for the per share amounts):

 

Year Ended December 31,

 

 

2024

 

2023

 

2022

 

Net income (loss)

$

(76,393

)

$

187,332

 

$

381,915

 

 

 

 

 

 

 

 

Weighted average common shares outstanding — basic

 

175,605

 

 

119,894

 

 

82,454

 

Dilutive effect of securities

 

—

 

 

858

 

 

1,229

 

Weighted average common shares outstanding — diluted

 

175,605

 

 

120,752

 

 

83,683

 

 

 

 

 

 

 

 

Net income (loss) per common share:

 

 

 

 

 

 

Basic

$

(0.44

)

$

1.56

 

$

4.63

 

Diluted

$

(0.44

)

$

1.55

 

$

4.56

 

Anti-dilutive potentially issuable securities excluded from diluted common shares

 

2,084

 

 

1,353

 

 

865

 
v3.25.0.1
Commitments and Contingencies (Tables)
 12 Months Ended
Dec. 31, 2024
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, 2024 (in thousands):

2025

$

5,439

 

2026

 

5,718

 

2027

 

9,249

 

2028

 

10,619

 

2029

 

4,465

 

Thereafter

 

1,453

 

Total

$

36,943

 

 
Summary of Total Minimum Commitments

The table below summarizes the Company’s total minimum commitments associated with vessel commitments, purchase obligations and other miscellaneous commitments as of December 31, 2024 (in thousands):

 

2025

 

2026

 

2027

 

2028

 

2029

 

Thereafter

 

Total

 

Vessel Commitments(1)

$

99,069

 

$

—

 

$

—

 

$

—

 

$

—

 

$

—

 

$

99,069

 

Committed purchase orders(2)

 

40,668

 

 

—

 

 

—

 

 

—

 

 

—

 

 

—

 

 

40,668

 

Other commitments

 

19,082

 

 

16,493

 

 

9,249

 

 

10,619

 

 

4,465

 

 

1,453

 

 

61,361

 

Total

$

158,819

 

$

16,493

 

$

9,249

 

$

10,619

 

$

4,465

 

$

1,453

 

$

201,098

 

 

(1)
Includes vessel commitments the Company will utilize for certain Deepwater well intervention, drilling operations and decommissioning activities. These commitments represent gross contractual obligations and accordingly, other joint owners in the properties operated by the Company will be billed for their working interest share of such costs.
(2)
Includes committed purchase orders to execute planned future drilling activities. These commitments represent gross contractual obligations and accordingly, other joint owners in the properties operated by the Company will be billed for their working interest share of such costs.
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,

 

 

2024

 

2023

 

2022

 

Balance, beginning of period

$

15,564

 

$

54,269

 

$

24,336

 

Additions

 

6,168

 

 

266

 

 

8,900

 

Obligations assumed

 

1,326

 

 

—

 

 

—

 

Changes in estimate

 

2,391

 

 

11,613

 

 

22,658

 

Settlements

 

(5,447

)

 

(50,584

)

 

(1,625

)

Balance, end of period

$

20,002

 

$

15,564

 

$

54,269

 

Less: Current portion

 

5,453

 

 

3,280

 

 

42,069

 

Long-term portion

$

14,549

 

$

12,284

 

$

12,200

 
v3.25.0.1
Segment Information (Tables)
 12 Months Ended
Dec. 31, 2024
Segment Reporting [Abstract]  
Summary of Information by Business Segment

The following table presents selected segment information for the periods indicated (in thousands):

Year Ended December 31, 2024

Upstream

 

CCS(1)

 

Total

 

Revenues from external customers

$

1,973,568

 

$

—

 

$

1,973,568

 

Significant expenses:

 

 

 

 

 

 

Lease operating expense:

 

 

 

 

 

 

Direct operating and maintenance

 

(492,123

)

 

—

 

 

(492,123

)

Workover

 

(73,918

)

 

—

 

 

(73,918

)

Adjusted general and administrative expense(2)

 

(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(3)

 

(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(4)

 

—

 

 

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) 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) 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.

(4) 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:

 

 

 

 

 

 

Lease operating expense:

 

 

 

 

 

 

Direct operating and maintenance

 

(374,481

)

 

—

 

 

(374,481

)

Workover

 

(15,140

)

 

—

 

 

(15,140

)

Adjusted general and administrative expense(2)

 

(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(3)

 

(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(4)

 

66,180

 

 

—

 

 

66,180

 

Equity method investment income (loss)

 

120

 

 

(12,229

)

 

(12,109

)

Gain (loss) on partial sale of equity investment(5)

 

—

 

 

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) 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.

(3) 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.

(4) See further discussion in Note 3 — Acquisitions and Divestitures.

(5) 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.

Year Ended December 31, 2022

Upstream

 

CCS(1)

 

Total

 

Revenues from external customers

$

1,651,980

 

$

—

 

$

1,651,980

 

Significant expenses:

 

 

 

 

 

 

Lease operating expense:

 

 

 

 

 

 

Direct operating and maintenance

 

(289,120

)

 

—

 

 

(289,120

)

Workover

 

(18,972

)

 

—

 

 

(18,972

)

Adjusted general and administrative expense(2)

 

(63,689

)

 

(8,968

)

 

(72,657

)

Net cash received (paid) on settled derivative instruments

 

(425,559

)

 

—

 

 

(425,559

)

Interest expense

 

(124,936

)

 

(562

)

 

(125,498

)

Other segment items:

 

 

 

 

 

 

Other(3)

 

(42,510

)

 

(2,653

)

 

(45,163

)

Depreciation, depletion and amortization

 

(414,395

)

 

(235

)

 

(414,630

)

Accretion expense

 

(55,995

)

 

—

 

 

(55,995

)

Mark-to-market derivative fair value gain (loss)

 

153,368

 

 

—

 

 

153,368

 

Equity-based compensation expense

 

(14,681

)

 

(1,272

)

 

(15,953

)

Gain on settlements(4)

 

29,998

 

 

—

 

 

29,998

 

Equity method investment income (loss)

 

101

 

 

(1,166

)

 

(1,065

)

Gain (loss) on partial sale of equity investment(5)

 

—

 

 

15,287

 

 

15,287

 

Gain (loss) on extinguishment of debt

 

(1,569

)

 

—

 

 

(1,569

)

Income tax benefit (expense)

 

(2,425

)

 

(112

)

 

(2,537

)

Net income (loss)

$

381,596

 

$

319

 

$

381,915

 

 

 

 

 

 

 

 

Segment Expenditures

$

452,674

 

$

2,778

 

$

455,452

 

 

(1) The CCS Segment was an emerging business in the start-up phase of operations and the business did not generate any revenues.

(2) Includes general and administrative expense less transaction expenses and equity-based compensation. Corporate overhead allocated to the Upstream Segment and CCS Segment was $49.2 million and $1.6 million, respectively.

(3) Primarily includes decommissioning obligations and transaction expenses for the Upstream Segment. Transaction expenses include costs related to the EnVen Acquisition. See further discussion in Note 3 — Acquisition and Divestitures and Note 15 — Commitments and Contingencies.

(4) Includes $27.5 million gain as a result of the settlement agreement to resolve previously pending litigation that was filed in October 2017 that is further discussed in Note 15 — Commitments and Contingencies.

(5) Includes a gain on the funding of the capital carry of the Company’s investment in Bayou Bend by Chevron of $1.4 million and a $13.9 million gain on the partial sale of its investment in Bayou Bend to Chevron. 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,

 

 

2024

 

2023

 

2022

 

Segment Expenditures:

 

 

 

 

 

 

Total reportable segments

$

621,284

 

$

774,630

 

$

455,452

 

Change in capital expenditures included in accounts payable and accrued liabilities

 

29,423

 

 

(9,199

)

 

(60,011

)

Plugging & abandonment

 

(108,789

)

 

(86,615

)

 

(69,596

)

Decommissioning obligations settled

 

(5,447

)

 

(50,584

)

 

(1,625

)

Investment in CCS intangibles and equity method investees

 

(22,988

)

 

(40,946

)

 

(2,778

)

Other deferred payments

 

(2,389

)

 

(1,545

)

 

—

 

Non-cash well equipment transfers

 

(3,412

)

 

(27,731

)

 

(6

)

Other

 

1,232

 

 

3,424

 

 

1,728

 

Exploration, development and other capital expenditures

$

508,914

 

$

561,434

 

$

323,164

 
v3.25.0.1
Supplemental Oil and Gas Disclosures (Unaudited) (Tables)
 12 Months Ended
Dec. 31, 2024
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,

 

 

2024

 

2023

 

2022

 

Consolidated Entities:

 

 

 

 

 

 

Proved properties

$

9,784,832

 

$

7,906,295

 

$

5,964,340

 

Unproved oil and gas properties, not subject to amortization(1)

 

587,238

 

 

268,315

 

 

154,783

 

Total oil and gas properties

 

10,372,070

 

 

8,174,610

 

 

6,119,123

 

Less: Accumulated DD&A

 

5,163,844

 

 

4,143,491

 

 

3,484,590

 

Net capitalized costs

$

5,208,226

 

$

4,031,119

 

$

2,634,533

 

DD&A rate (Per Boe)

$

30.11

 

$

27.23

 

$

18.95

 

 

 

 

 

 

 

 

Company's Share of Equity Investees:

 

 

 

 

 

 

Unproved oil and gas properties, not subject to amortization

$

58,723

 

$

56,579

 

$

—

 

 

(1)
Amount includes $111.4 million of unproved properties, not subject to amortization, related to the Company’s operations in offshore Mexico for the year ended December 31, 2022.
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,

 

 

2024

 

2023

 

2022

 

Consolidated Entities:

 

 

 

 

 

 

Property acquisition costs:

 

 

 

 

 

 

Proved properties

$

1,085,324

 

$

951,703

 

$

—

 

Unproved properties, not subject to amortization

 

380,129

 

 

249,688

 

 

2,221

 

Total property acquisition costs

 

1,465,453

 

 

1,201,391

 

 

2,221

 

Exploration costs(1)

 

129,400

 

 

161,296

 

 

125,889

 

Development costs

 

602,607

 

 

805,148

 

 

541,512

 

Total costs incurred

$

2,197,460

 

$

2,167,835

 

$

669,622

 

 

 

 

 

 

 

 

Company's Share of Equity Investees:

 

 

 

 

 

 

Exploration costs

$

2,144

 

$

290

 

$

—

 

 

(1)
Year ended December 31, 2022 amount includes $1.2 million of exploration costs related to the Company’s operations in offshore Mexico.
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, 2021

 

107,764

 

 

236,353

 

 

14,435

 

 

161,591

 

Revision of previous estimates

 

(5,625

)

 

(8,302

)

 

(2,002

)

 

(9,010

)

Production

 

(14,561

)

 

(32,215

)

 

(1,793

)

 

(21,723

)

Sales of reserves

 

(158

)

 

(7,625

)

 

—

 

 

(1,429

)

Extensions and discoveries

 

3,639

 

 

31,340

 

 

2,288

 

 

11,150

 

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

 

Total Proved Developed Reserves as of:

 

 

 

 

 

 

 

 

December 31, 2022

 

80,285

 

 

161,727

 

 

9,315

 

 

116,555

 

December 31, 2023

 

98,225

 

 

141,823

 

 

9,957

 

 

131,819

 

December 31, 2024

 

108,479

 

 

175,139

 

 

12,733

 

 

150,402

 

Total Proved Undeveloped Reserves as of:

 

 

 

 

 

 

 

 

December 31, 2022

 

10,774

 

 

57,824

 

 

3,613

 

 

24,024

 

December 31, 2023

 

12,590

 

 

38,048

 

 

2,016

 

 

20,947

 

December 31, 2024

 

34,569

 

 

42,835

 

 

2,132

 

 

43,840

 
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,

 

 

2024

 

2023

 

2022

 

Consolidated Entities:

 

 

 

 

 

 

Future cash inflows

$

11,660,546

 

$

9,425,055

 

$

10,674,896

 

Future costs:

 

 

 

 

 

 

Production

 

(3,436,232

)

 

(3,090,491

)

 

(1,906,752

)

Development and abandonment

 

(3,301,619

)

 

(2,358,368

)

 

(1,873,453

)

Future net cash flows before income taxes

 

4,922,695

 

 

3,976,196

 

 

6,894,691

 

Future income tax expense

 

(845,894

)

 

(589,413

)

 

(1,114,409

)

Future net cash flows after income taxes

 

4,076,801

 

 

3,386,783

 

 

5,780,282

 

Discount at 10% annual rate

 

(512,597

)

 

(343,295

)

 

(1,411,834

)

Standardized measure of discounted future net cash flows

$

3,564,204

 

$

3,043,488

 

$

4,368,448

 

 
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,

 

 

2024

 

2023

 

2022

 

Oil price per Bbl

$

75.51

 

$

78.56

 

$

96.03

 

Natural gas price per Mcf

$

2.45

 

$

2.75

 

$

6.80

 

NGL price per Bbl

$

21.91

 

$

18.77

 

$

33.89

 
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,

 

 

2024

 

2023

 

2022

 

Consolidated Entities:

 

 

 

 

 

 

Standardized measure, beginning of year

$

3,043,488

 

$

4,368,448

 

$

3,440,611

 

Sales and transfers of oil, net gas and NGLs produced during the period

 

(1,406,150

)

 

(1,065,814

)

 

(1,340,400

)

Net change in prices and production costs

 

(123,537

)

 

(2,835,125

)

 

2,388,442

 

Changes in estimated future development and abandonment costs

 

193,810

 

 

(19,877

)

 

(84,391

)

Previously estimated development and abandonment costs incurred

 

47,016

 

 

202,503

 

 

20,107

 

Accretion of discount

 

485,409

 

 

518,110

 

 

392,600

 

Net change in income taxes

 

(181,190

)

 

357,321

 

 

(327,265

)

Purchases of reserves

 

1,638,000

 

 

2,033,852

 

 

—

 

Sales of reserves

 

—

 

 

—

 

 

(5,218

)

Extensions and discoveries

 

74,126

 

 

90,244

 

 

202,239

 

Net change due to revision in quantity estimates

 

(162,041

)

 

(484,423

)

 

(255,743

)

Changes in production rates (timing) and other

 

(44,727

)

 

(121,751

)

 

(62,534

)

Standardized measure, end of year

$

3,564,204

 

$

3,043,488

 

$

4,368,448

 
v3.25.0.1
Organization, Nature of Business and Basis of Presentation - Additional Information (Details) - Segment
 3 Months Ended 12 Months Ended
Mar. 18, 2024
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
v3.25.0.1
Summary of Significant Accounting Policies - Additional Information (Details) - USD ($)
 12 Months Ended
Dec. 31, 2024
Dec. 31, 2023
Dec. 31, 2022
Summary Of Significant Accounting Policies [Line Items]      
Allowance for expected credit losses $ 25,500,000 $ 8,800,000  
Impairment charges 0 $ 0 $ 0
EnVen Energy Corporation      
Summary Of Significant Accounting Policies [Line Items]      
Receivable with imputed interest, face amount 66,200,000    
EnVen Energy Corporation | Future plugging and abanonment obligations      
Summary Of Significant Accounting Policies [Line Items]      
Escrow Deposit $ 100,000,000    
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%    
v3.25.0.1
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, 2024
Dec. 31, 2023
Dec. 31, 2022
Shell Trading (US) Company      
Concentration Risk Line Items      
Concentration risk, percentage 48.00% 54.00% 44.00%
Exxon Mobil Corporation      
Concentration Risk Line Items      
Concentration risk, percentage 17.00%    
Valero energy corporation      
Concentration Risk Line Items      
Concentration risk, percentage   21.00% 23.00%
Chevron Products Company      
Concentration Risk Line Items      
Concentration risk, percentage     11.00%
v3.25.0.1
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, 2024
Dec. 31, 2023
Dec. 31, 2022
Exxon Mobil Corporation      
Concentration Risk Line Items      
Concentration risk, percentage 17.00%    
Exxon Mobil Corporation | Maximum      
Concentration Risk Line Items      
Concentration risk, percentage   10.00% 10.00%
Valero energy corporation      
Concentration Risk Line Items      
Concentration risk, percentage   21.00% 23.00%
Valero energy corporation | Maximum      
Concentration Risk Line Items      
Concentration risk, percentage 10.00%    
Chevron Products Company      
Concentration Risk Line Items      
Concentration risk, percentage     11.00%
Chevron Products Company | Maximum      
Concentration Risk Line Items      
Concentration risk, percentage 10.00% 10.00%  
v3.25.0.1
Summary of Significant Accounting Policies - Schedule of Cash and Cash Equivalents (Details) - USD ($)
$ in Thousands
Dec. 31, 2024
Dec. 31, 2023
Dec. 31, 2022
Dec. 31, 2021
Summary Of Significant Accounting Policies [Abstract]        
Cash and cash equivalents $ 108,172 $ 33,637    
Restricted cash included in Other long-term assets 106,260 102,362    
Total cash, cash equivalent and restricted cash $ 214,432 $ 135,999 $ 44,145 $ 69,852
v3.25.0.1
Acquisitions and Divestitures - Acquisitions - Business Combination - Additional Information (Details) - USD ($)
$ in Thousands, shares in Millions
 12 Months Ended 15 Months Ended
Feb. 20, 2025
Aug. 02, 2024
Mar. 04, 2024
Feb. 13, 2023
Sep. 21, 2022
Dec. 31, 2024
Dec. 31, 2023
Dec. 31, 2022
Apr. 01, 2026
Business Acquisition [Line Items]                  
Issuance of common stock, Shares           34.5      
Proved properties           $ 9,784,832 $ 7,906,295    
Employee Severance                  
Business Acquisition [Line Items]                  
Aquisition severance cost           25,991 25,348    
Monument Project                  
Business Acquisition [Line Items]                  
Proved properties           $ 42,600      
Percentage of non-operated working interest acquired   21.40%              
Cash consideration   $ 20,200              
Monument Project | Subsequent Event                  
Business Acquisition [Line Items]                  
Asset Acquisition, Date of Acquisition Agreement Feb. 20, 2025                
Percentage of non-operated working interest acquired 8.30%                
Cash consideration $ 6,300                
Monument Project | Subsequent Event | Milestone Payment                  
Business Acquisition [Line Items]                  
Cash consideration $ 6,300                
Monument Project | Pro Forma                  
Business Acquisition [Line Items]                  
Cash consideration                 $ 24,400
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 years ended December 31, 2023 and 2022 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, 2022 were adjusted to include $65.1 million of general and administrative expenses, of which $16.3 million were incurred during the year ended December 31, 2022, and supplemental pro forma earnings for the year ended December 31, 2023 were adjusted to exclude these expenses.      
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 $ 425,995  
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       43.8          
EnVen Energy Corporation | Common Stock | Pro Forma                  
Business Acquisition [Line Items]                  
Aggregate shares issued           43.8      
EnVen Energy Corporation | General and Administrative Expense                  
Business Acquisition [Line Items]                  
Cumulative transaction related costs             21,800    
Acquisition, transaction related cost             12,800 9,000  
EnVen Energy Corporation | General and Administrative Expense | Pro Forma                  
Business Acquisition [Line Items]                  
Acquisition, transaction related cost               16,300  
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.      
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     24.3            
QuarterNorth Acquisition | Common Stock | Pro Forma                  
Business Acquisition [Line Items]                  
Aggregate shares issued           24.3      
QuarterNorth Acquisition | General and Administrative Expense                  
Business Acquisition [Line Items]                  
Cumulative transaction related costs           $ 21,600      
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           34.5      
v3.25.0.1
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.
v3.25.0.1
Acquisitions and Divestitures - Acquisition - Business Combinations - Summary of Purchase Price (Parenthetical) (Details) - QuarterNorth Acquisition
$ in Thousands
Mar. 04, 2024
USD ($)
Business Acquisition [Line Items]  
Cash and cash equivalents $ 331,374
Purchase price net of cash and cash equivalents 1,238,700
Acquired receivables $ 136,300
v3.25.0.1
Acquisitions and Divestitures - Acquisitions - Business Combinations - Summary of Allocation of Purchase Price to Assets Acquired and Liabilities Assumed (Details) - USD ($)
$ in Thousands
Mar. 04, 2024
Feb. 13, 2023
EnVen Energy Corporation    
Business Acquisition [Line Items]    
Current assets   $ 243,571
Property and equipment   1,455,347
Restricted cash   100,753
Notes receivable, net   14,844
Other long-term assets   48,899
Current portion of long-term debt   (33,234)
Current portion of asset retirement obligations   (7,079)
Other current liabilities   (124,347)
Long-term debt   (233,836)
Asset retirement obligations   (251,779)
Deferred tax liabilities   (150,264)
Other long-term liabilities   (14,976)
Allocated purchase price   $ 1,047,899
QuarterNorth Acquisition    
Business Acquisition [Line Items]    
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 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.
v3.25.0.1
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 Acquisition [Line Items]  
Acquired receivables $ 136.3
Financing Receivable, Purchased with Credit Deterioration, Allowance for Credit Loss at Acquisition Date $ 15.5
v3.25.0.1
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  
v3.25.0.1
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
Dec. 31, 2022
EnVen Energy Corporation      
Business Acquisition [Line Items]      
Business Acquisition, Pro Forma Revenue   $ 1,509,929 $ 2,355,215
Net income (loss)   $ 217,537 $ 425,995
Basic net income (loss) per common share   $ 1.74 $ 3.37
Diluted net income (loss) per common share   $ 1.73 $ 3.34
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  
v3.25.0.1
Acquisitions and Divestitures - Divestitures - Additional Information (Details) - USD ($)
$ in Thousands
 12 Months Ended
Mar. 18, 2024
Sep. 27, 2023
Dec. 31, 2024
Dec. 31, 2023
Dec. 31, 2022
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]          
Proceeds from Divestiture of Businesses     $ 146,676 $ 0 $ 0
Other current assets     35,980 10,389  
Proceeds from sale     (1,161) (73,004) $ (1,937)
Unproved oil and gas properties, not subject to amortization     $ 587,238 $ 268,315  
Disposal Group, Not Discontinued Operation, Gain (Loss) on Disposal, Statement of Income or Comprehensive Income [Extensible Enumeration]     Other Operating Income (Expense), Net Other Operating Income (Expense), Net  
TLCS          
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]          
Severance expense     $ 3,700    
General and Administrative Expense | TLCS          
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]          
Divestiture expense excludes severance cost     6,100    
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 sale   $ 74,900      
Unproved oil and gas properties, not subject to amortization   112,300      
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 sale   $ 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       $ 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 | 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    
Other current assets     $ 12,500    
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%    
v3.25.0.1
Property, Plant and Equipment - Additional Information (Details)
 12 Months Ended
Dec. 31, 2024
USD ($)
$ / bbl
$ / Mcf
Dec. 31, 2023
USD ($)
$ / Mcf
$ / bbl
Dec. 31, 2022
USD ($)
$ / Mcf
$ / bbl
Property, Plant and Equipment [Line Items]      
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 these costs will be transferred to the amortization base over seven years.    
Oil (MBbls)      
Property, Plant and Equipment [Line Items]      
SEC pricing 75.51 78.56 96.03
Gas (MMcf)      
Property, Plant and Equipment [Line Items]      
SEC pricing | $ / Mcf 2.45 2.75 6.80
NGL (MBbls)      
Property, Plant and Equipment [Line Items]      
SEC pricing 21.91 18.77 33.89
US      
Property, Plant and Equipment [Line Items]      
Write-down of oil and natural gas properties | $ $ 0 $ 0 $ 0
US | Oil (MBbls)      
Property, Plant and Equipment [Line Items]      
SEC pricing 75.51    
US | Gas (MMcf)      
Property, Plant and Equipment [Line Items]      
SEC pricing | $ / Mcf 2.45    
US | NGL (MBbls)      
Property, Plant and Equipment [Line Items]      
SEC pricing 21.91    
v3.25.0.1
Property, Plant and Equipment - Summary of Oil and Natural Gas Property Costs Not Being Amortized (Details) - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2024
Dec. 31, 2023
Dec. 31, 2022
Dec. 31, 2021
Capitalized Costs Of Unproved Properties Excluded From Amortization [Line Items]        
Total unproved properties, not subject to amortization $ 587,238 $ 268,315    
United States        
Capitalized Costs Of Unproved Properties Excluded From Amortization [Line Items]        
Acquisition 540,735      
Exploration 46,503      
Mexico        
Capitalized Costs Of Unproved Properties Excluded From Amortization [Line Items]        
Total unproved properties, not subject to amortization     $ 111,400  
2024        
Capitalized Costs Of Unproved Properties Excluded From Amortization [Line Items]        
Total unproved properties, not subject to amortization 379,253      
2024 | United States        
Capitalized Costs Of Unproved Properties Excluded From Amortization [Line Items]        
Acquisition 347,661      
Exploration $ 31,592      
2023        
Capitalized Costs Of Unproved Properties Excluded From Amortization [Line Items]        
Total unproved properties, not subject to amortization   194,398    
2023 | United States        
Capitalized Costs Of Unproved Properties Excluded From Amortization [Line Items]        
Acquisition   185,437    
Exploration   $ 8,961    
2022        
Capitalized Costs Of Unproved Properties Excluded From Amortization [Line Items]        
Total unproved properties, not subject to amortization     3,097  
2022 | United States        
Capitalized Costs Of Unproved Properties Excluded From Amortization [Line Items]        
Acquisition     0  
Exploration     $ 3,097  
2021 and Prior        
Capitalized Costs Of Unproved Properties Excluded From Amortization [Line Items]        
Total unproved properties, not subject to amortization       $ 10,490
2021 and Prior | United States        
Capitalized Costs Of Unproved Properties Excluded From Amortization [Line Items]        
Acquisition       7,637
Exploration       $ 2,853
v3.25.0.1
Leases - Components of Lease Costs (Details) - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2024
Dec. 31, 2023
Dec. 31, 2022
Lease, Cost [Abstract]      
Finance lease costs - interest on lease liabilities $ 12,948 $ 14,476 $ 7,558
Operating lease costs, excluding short-term leases [1] 4,207 4,883 2,281
Short-term lease costs [2] 100,895 117,132 55,072
Variable lease costs [3] 2,464 2,888 1,450
Variable and fixed sublease income (1,436) (482) 0
Total lease costs $ 119,078 $ 138,897 $ 66,361
[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.
[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.
v3.25.0.1
Leases - Schedule of Right-of-Use Asset and Liability, Adjusted for Initial Direct Costs and Incentives (Details) - USD ($)
$ in Thousands
Dec. 31, 2024
Dec. 31, 2023
Assets and Liabilities, Lessee [Abstract]    
Operating lease assets $ 11,294 $ 11,418
Current portion of operating lease liabilities $ 3,837 $ 2,666
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 $ 15,489 $ 18,211
Total operating lease liabilities 19,326 20,877
Proved properties $ 166,261 $ 166,261
Finance Lease, Right-of-Use Asset, Statement of Financial Position [Extensible Enumeration] Proved properties Proved properties
Other current liabilities $ 19,589 $ 17,834
Finance Lease, Liability, Current, Statement of Financial Position [Extensible List] Other current liabilities Other current liabilities
Other long-term liabilities $ 111,641 $ 131,230
Finance Lease, Liability, Noncurrent, Statement of Financial Position [Extensible List] Other long-term liabilities Other long-term liabilities
Total finance lease liabilities $ 131,230 $ 149,064
v3.25.0.1
Leases - Schedule of Lease Maturity (Details) - USD ($)
$ in Thousands
Dec. 31, 2024
Dec. 31, 2023
Leases [Abstract]    
Operating Leases, 2025 $ 5,656  
Operating Leases, 2026 4,983  
Operating Leases, 2027 4,753  
Operating Leases, 2028 4,610  
Operating Leases, 2029 3,226  
Operating Leases, Thereafter 1,357  
Operating Leases, Total lease payments 24,585  
Operating Leases, Imputed interest (5,259)  
Total operating lease liabilities 19,326 $ 20,877
Finance Leases, 2025 30,782  
Finance Leases, 2026 30,782  
Finance Leases, 2027 30,782  
Finance Leases, 2028 30,782  
Finance Leases, 2029 30,782  
Finance Leases, Thereafter 12,825  
Finance Leases, Total lease payments 166,735  
Finance Leases, Imputed interest (35,505)  
Total finance lease liabilities $ 131,230 $ 149,064
v3.25.0.1
Leases - Schedule of Weighted Average Remaining Lease Term and Discount Rate (Details)
Dec. 31, 2024
Dec. 31, 2023
Dec. 31, 2022
Weighted average remaining lease term:      
Operating leases 4 years 9 months 18 days 5 years 10 months 24 days 6 years 4 months 24 days
Finance leases 5 years 4 months 24 days 6 years 4 months 24 days 7 years 4 months 24 days
Weighted average discount rate:      
Operating leases 10.70% 10.80% 11.80%
Finance leases 9.20% 9.20% 9.20%
v3.25.0.1
Leases - Supplemental Cash Flow Information Related to Leases (Details) - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2024
Dec. 31, 2023
Dec. 31, 2022
Cash Flow, Operating Activities, Lessee [Abstract]      
Operating cash outflow from finance leases $ 12,948 $ 14,476 $ 7,181
Operating cash outflow from operating leases 5,634 6,318 3,722
ROU assets obtained in exchange for new finance lease liabilities 0 0 166,261
ROU assets obtained in exchange for new operating lease liabilities [1] 1,909 12,971 474
Remeasurement of lease liability arising from modification of ROU asset [2] $ 0 $ (5,124) $ 0
[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.
v3.25.0.1
Financial Instruments - Schedule of Carrying Amounts and Estimated Fair Values of Financial Instruments (Details) - USD ($)
$ in Thousands
Dec. 31, 2024
Dec. 31, 2023
Debt Instrument [Line Items]    
Carrying Amount $ 1,221,399 $ 1,025,674
9.000% Second-Priority Senior Secured Notes - due February 2029    
Debt Instrument [Line Items]    
Carrying Amount 611,135 0
Fair Value 640,619 0
9.375% Second-Priority Senior Secured Notes - due February 2031    
Debt Instrument [Line Items]    
Carrying Amount 610,264 0
Fair Value 635,750 0
12.00% Second-Priority Senior Secured Notes - due January 2026    
Debt Instrument [Line Items]    
Carrying Amount 0 601,353
Fair Value 0 655,130
11.75% Senior Secured Second Lien Notes - due April 2026    
Debt Instrument [Line Items]    
Carrying Amount 0 234,221
Fair Value 0 233,410
Bank Credit Facility - matures March 2027    
Debt Instrument [Line Items]    
Carrying Amount 0 190,100
Fair Value $ 0 $ 200,000
v3.25.0.1
Financial Instruments - Schedule of Carrying Amounts and Estimated Fair Values of Financial Instruments (Parenthetical) (Details)
 12 Months Ended
Dec. 31, 2024
Dec. 31, 2023
9.000% Second-Priority Senior Secured Notes - due February 2029    
Debt Instrument [Line Items]    
Debt instrument interest rate 9.00%  
Senior notes, maturity date Feb. 01, 2029  
9.375% Second-Priority Senior Secured Notes - due February 2031    
Debt Instrument [Line Items]    
Debt instrument interest rate 9.375%  
Senior notes, maturity date Feb. 01, 2031  
12.00% Second-Priority Senior Secured Notes - due January 2026    
Debt Instrument [Line Items]    
Debt instrument interest rate   12.00%
Senior notes, maturity date   Jan. 15, 2026
11.75% Senior Secured Second Lien Notes - due April 2026    
Debt Instrument [Line Items]    
Debt instrument interest rate   11.75%
Senior notes, maturity date   Apr. 15, 2026
v3.25.0.1
Financial Instruments - Additional Information (Details)
$ in Millions
 12 Months Ended
Dec. 31, 2024
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, 2024 represent derivative instruments from seven 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, 2024 would have been $23.7 million.
Maximum loss on commodity contracts $ 23.7
Counterparty Risk Investment Grade  
Concentration Risk [Line Items]  
Number of counterparties description all of which
v3.25.0.1
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, 2024
Dec. 31, 2023
Dec. 31, 2022
Derivative Instruments and Hedging Activities Disclosures [Line Items]      
Derivative fair value gain (loss) $ (1,458) $ 80,928 $ (272,191)
Gain Loss on Derivative Instruments Unrealized Component      
Derivative Instruments and Hedging Activities Disclosures [Line Items]      
Derivative fair value gain (loss) (6,168) 90,385 153,368
Commodity Contract      
Derivative Instruments and Hedging Activities Disclosures [Line Items]      
Derivative fair value gain (loss) (1,458) 80,928 (272,191)
Commodity Contract | Gain Loss on Derivative Instruments Realized Component      
Derivative Instruments and Hedging Activities Disclosures [Line Items]      
Derivative fair value gain (loss) $ 4,710 $ (9,457) $ (425,559)
v3.25.0.1
Financial Instruments - Schedule of Impact that Derivatives not Qualifying as Hedging Instruments in Condensed consolidated Statements of Operations (Parenthetical) (Details) - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2024
Dec. 31, 2023
Dec. 31, 2022
Derivative Instruments and Hedging Activities Disclosures [Line Items]      
Derivative fair value gain (loss) $ (1,458) $ 80,928 $ (272,191)
Gain Loss on Derivative Instruments Unrealized Component      
Derivative Instruments and Hedging Activities Disclosures [Line Items]      
Derivative fair value gain (loss) $ (6,168) $ 90,385 $ 153,368
v3.25.0.1
Financial Instruments - Schedule of Contracted Volumes and Weighted Average Prices and will Receive Under the Terms of Derivative Contracts (Details)
 12 Months Ended
Dec. 31, 2024
MMBTU
$ / MMBTU
$ / bbl
bbl
Crude Oil | January 2025 - December 2025 | Swap  
Derivative [Line Items]  
Settlement Index NYMEX WTI CMA
Volumes | bbl 25,951
Swap Price 72.66
Crude Oil | January 2026 - June 2026 | Swap  
Derivative [Line Items]  
Settlement Index NYMEX WTI CMA
Volumes | bbl 10,497
Swap Price 65.98
Crude Oil | January 2025 - March 2025 | Collar  
Derivative [Line Items]  
Settlement Index NYMEX WTI CMA
Volumes | bbl 3,000
Floor Price 65
Ceiling Price 84.35
Natural Gas | January 2025 - December 2025 | Swap  
Derivative [Line Items]  
Settlement Index NYMEX Henry Hub
Average Daily Volumes | MMBTU 57,384
Swap Price | $ / MMBTU 3.50
Natural Gas | January 2026 - December 2026 | Swap  
Derivative [Line Items]  
Settlement Index NYMEX Henry Hub
Average Daily Volumes | MMBTU 20,000
Swap Price | $ / MMBTU 3.65
v3.25.0.1
Financial Instruments - Summary of Additional Information Related to Financial Instruments Measured at Fair Value on Recurring Basis (Details) - USD ($)
$ in Thousands
Dec. 31, 2024
Dec. 31, 2023
Oil and Natural Gas Derivatives    
Assets:    
Oil and natural gas derivatives $ 23,728 $ 45,603
Liabilities:    
Oil and natural gas derivatives 0 0
Fair Value on Recurring Basis    
Liabilities:    
Total net asset (liability) 23,728 45,603
Fair Value on Recurring Basis | Oil and Natural Gas Derivatives    
Assets:    
Oil and natural gas derivatives $ 33,739 $ 53,703
Derivative Asset, Statement of Financial Position [Extensible Enumeration] Assets Assets
Liabilities:    
Oil and natural gas derivatives $ (10,011) $ (8,100)
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) $ 23,728 $ 45,603
Fair Value on Recurring Basis | Level 2 | Oil and Natural Gas Derivatives    
Assets:    
Oil and natural gas derivatives $ 33,739 $ 53,703
Derivative Asset, Statement of Financial Position [Extensible Enumeration] Assets Assets
Liabilities:    
Oil and natural gas derivatives $ (10,011) $ (8,100)
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
v3.25.0.1
Financial Instruments - Schedule of Fair Value of Derivative Financial Instruments (Details) - USD ($)
$ in Thousands
Dec. 31, 2024
Dec. 31, 2023
Price Risk Derivatives [Line Items]    
Derivative Asset, Current $ 33,486 $ 36,152
Derivative Asset, Noncurrent 253 17,551
Derivative Liability, Current 6,474 7,305
Derivative Liability, Noncurrent 3,537 795
Oil and Natural Gas Derivatives    
Price Risk Derivatives [Line Items]    
Derivative Asset, Current 33,486 36,152
Derivative Asset, Noncurrent 253 17,551
Total gross amounts presented on balance sheet, Assets 33,739 53,703
Gross amounts not offset on the balance sheet 10,011 8,100
Net Amounts 23,728 45,603
Derivative Liability, Current 6,474 7,305
Derivative Liability, Noncurrent 3,537 795
Total gross amounts presented on balance sheet, Liabilities 10,011 8,100
Gross amounts not offset on the balance sheet 10,011 8,100
Net Amounts $ 0 $ 0
v3.25.0.1
Equity Method Investments - Schedule of Equity Method Investments (Details) - USD ($)
$ in Thousands
Dec. 31, 2024
Dec. 31, 2023
Schedule of Equity Method Investments [Line Items]    
Total equity method investments $ 111,269 $ 146,049
Talos Mexico | Upstream    
Schedule of Equity Method Investments [Line Items]    
Total equity method investments $ 110,194 107,259
Equity method investment, ownership interest 50.10%  
SP 49 Pipeline LLC | Upstream    
Schedule of Equity Method Investments [Line Items]    
Total equity method investments $ 1,075 861
Equity method investment, ownership interest 33.30%  
Bayou Bend CCS LLC | CCS    
Schedule of Equity Method Investments [Line Items]    
Total equity method investments $ 0 28,183
Equity method investment, ownership interest 0.00%  
Harvest Bend CCS LLC | CCS    
Schedule of Equity Method Investments [Line Items]    
Total equity method investments $ 0 9,746
Equity method investment, ownership interest 0.00%  
Coastal Bend CCS LLC | CCS    
Schedule of Equity Method Investments [Line Items]    
Total equity method investments $ 0 $ 0
Equity method investment, ownership interest 0.00%  
v3.25.0.1
Equity Method Investments - Additional Information (Details) - USD ($)
$ in Thousands
 1 Months Ended 12 Months Ended
Dec. 16, 2024
May 24, 2022
Mar. 08, 2022
May 31, 2022
Dec. 31, 2024
Dec. 31, 2023
Dec. 31, 2022
Schedule of Equity Method Investments [Line Items]              
Equity method investment payment         $ 22,988 $ 29,447 $ 2,250
Proceeds from sale of equity method investment         0 0 15,000
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    
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 | Variable Interest Entity, Not Primary Beneficiary | Zama Field              
Schedule of Equity Method Investments [Line Items]              
Equity method investment, ownership interest 20.00%            
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 80.00%            
Bayou Bend CCS LLC | Equity Method Investment Income              
Schedule of Equity Method Investments [Line Items]              
Gain on partial disposal of investment             13,900
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 $ 1,400
Bayou Bend CCS LLC | Chevron U.S.A Inc              
Schedule of Equity Method Investments [Line Items]              
Equity method investment ownership percentage sold       25.00%      
Proceeds from sale of equity method investment       $ 15,000      
Capital carry contribution funded   $ 10,000          
Bayou Bend CCS LLC | Equity Method Investee | Variable Interest Entity, Not Primary Beneficiary              
Schedule of Equity Method Investments [Line Items]              
Equity method investment, ownership interest     50.00%        
Equity method investment payment     $ 2,300        
v3.25.0.1
Debt - Summary of Detail Comprising Debt and Related Book Values (Details) - USD ($)
$ in Thousands
Dec. 31, 2024
Dec. 31, 2023
Debt Instrument [Line Items]    
Total debt, before discount, premium and deferred financing cost $ 1,250,000 $ 1,066,041
Unamortized discount, premium and deferred financing cost, net (28,601) (40,367)
Total debt 1,221,399 1,025,674
Less: current portion of long-term debt 0 33,060
Long-term debt 1,221,399 992,614
Senior Notes | 9.000% Second-Priority Senior Secured Notes - due February 2029    
Debt Instrument [Line Items]    
Total debt, before discount, premium and deferred financing cost 625,000 0
Senior Notes | 9.375% Second-Priority Senior Secured Notes - due February 2031    
Debt Instrument [Line Items]    
Total debt, before discount, premium and deferred financing cost 625,000 0
Senior Notes | 12.00% Second-Priority Senior Secured Notes - due January 2026    
Debt Instrument [Line Items]    
Total debt, before discount, premium and deferred financing cost 0 638,541
Senior Notes | 11.75% Senior Secured Second Lien Notes - due April 2026    
Debt Instrument [Line Items]    
Total debt, before discount, premium and deferred financing cost 0 227,500
Line of Credit | Bank Credit Facility - matures March 2027    
Debt Instrument [Line Items]    
Total debt, before discount, premium and deferred financing cost $ 0 $ 200,000
v3.25.0.1
Debt - Summary of Detail Comprising Debt and Related Book Values (Parenthetical) (Details)
 12 Months Ended
Dec. 31, 2024
Dec. 31, 2023
Feb. 07, 2024
Dec. 31, 2022
11.75% Senior Secured Second Lien Notes - due April 2026        
Debt Instrument [Line Items]        
Debt instrument interest rate   11.75%    
Senior notes, maturity date   Apr. 15, 2026    
Senior Notes | 9.000% Second-Priority Senior Secured Notes - due February 2029        
Debt Instrument [Line Items]        
Debt instrument interest rate 9.00%   9.00%  
Senior notes, maturity date Feb. 01, 2029      
Senior Notes | 9.375% Second-Priority Senior Secured Notes - due February 2031        
Debt Instrument [Line Items]        
Debt instrument interest rate 9.375%   9.375%  
Senior notes, maturity date Feb. 01, 2031      
Senior Notes | 12.00% Second-Priority Senior Secured Notes - due January 2026        
Debt Instrument [Line Items]        
Debt instrument interest rate   12.00% 12.00% 12.00%
Senior notes, maturity date Jan. 15, 2026 Jan. 15, 2026    
Senior Notes | 11.75% Senior Secured Second Lien Notes - due April 2026        
Debt Instrument [Line Items]        
Debt instrument interest rate   11.75% 11.75%  
Senior notes, maturity date Apr. 15, 2026 Apr. 15, 2026    
Bank Credit Facility | Bank Credit Facility - matures March 2027        
Debt Instrument [Line Items]        
Bank credit facility, maturity date Mar. 31, 2027 Mar. 31, 2027    
v3.25.0.1
Debt - Additional information (Details) - USD ($)
$ / shares in Units, $ in Thousands
 12 Months Ended
Jan. 31, 2027
Jan. 31, 2026
Feb. 07, 2024
May 31, 2022
Dec. 31, 2024
Dec. 31, 2023
Dec. 31, 2022
Dec. 04, 2024
Debt Instrument [Line Items]                
Loss on extinguishment of debt         $ (60,256) $ 0 $ (1,569)  
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 primary equity method investee as of December 31, 2024 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, 2024, restricted net assets of the Company’s consolidated subsidiaries exceeded 25%.      
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%      
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, 2024.      
9.000% Second-Priority Senior Secured Notes - due February 2029 | Senior Notes                
Debt Instrument [Line Items]                
Debt instrument interest rate     9.00%   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%            
9.375% 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, 2024.      
9.375% Second-Priority Senior Secured Notes - due February 2031 | Senior Notes                
Debt Instrument [Line Items]                
Debt instrument interest rate     9.375%   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%     12.00% 12.00%  
Debt instrument maturity date         Jan. 15, 2026 Jan. 15, 2026    
Debt instrument, repurchase amount     $ 638,500       $ 11,500  
11.75% Senior Secured Second Lien Notes                
Debt Instrument [Line Items]                
Debt instrument interest rate           11.75%    
Debt instrument maturity date           Apr. 15, 2026    
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%     11.75%    
Debt instrument maturity date         Apr. 15, 2026 Apr. 15, 2026    
Debt instrument, repurchase amount     $ 227,500          
Bank Credit Facility - matures March 2027                
Debt Instrument [Line Items]                
Credit facility, maximum borrowing capacity         $ 925,000      
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 December 4, 2024, the Company entered into the Borrowing Base Redetermination Agreement and Eleventh Amendment to Credit Agreement (the “Eleventh Amendment”), in order to (i) decrease the borrowing base to $925.0 million and decrease the total commitments to $925.0 million and (ii) implement an availability cap such that, if the aggregate exposure of all lenders under the Bank Credit Facility would equal or exceed $800 million at any time after the date of the Eleventh Amendment, lenders holding at least two-thirds of the aggregate commitments shall approve the making of any addition loan or issuance of any additional letter of credit.      
Percentage of mortgage covering oil and natural gas assets         85.00%      
Line of Credit Facility, Commitments         $ 925,000      
Bank Credit Facility - matures March 2027 | Letter of Credit                
Debt Instrument [Line Items]                
Line of Credit Facility, Commitments         $ 150,000      
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%      
7.50% Senior Notes – due May 2022                
Debt Instrument [Line Items]                
Debt instrument interest rate       7.50%        
Debt instrument maturity date       May 31, 2022        
Debt instrument redemption, description             The 7.50% Senior Notes due 2022 matured on May 31, 2022 and were redeemed at an aggregate principal of $6.1 million plus accrued and unpaid interest.  
Debt instrument, face amount       $ 6,100        
Bank Credit Facility                
Debt Instrument [Line Items]                
Credit facility, maximum borrowing capacity               $ 925,000
Line of Credit Facility, Commitments               925,000
Bank Credit Facility | Minimum | Availability Cap                
Debt Instrument [Line Items]                
Credit facility, maximum borrowing capacity               $ 800,000
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         $ 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)       $ (1,600)  
Other Income (Expense) | 11.75% Senior Secured Second Lien Notes | Senior Notes                
Debt Instrument [Line Items]                
Loss on extinguishment of debt     $ (5,400)          
v3.25.0.1
Debt - Summary of Redemption Prices of 9.000% and 9.375% Notes (Details)
 12 Months Ended
Dec. 31, 2024
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%
v3.25.0.1
Debt - Schedule of Pricing Grid for Borrowing Base Utilization Percentage (Details)
 12 Months Ended
Dec. 31, 2024
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%
v3.25.0.1
Asset Retirement Obligations - Schedule of Asset Retirement Obligations (Details) - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2024
Dec. 31, 2023
Dec. 31, 2022
Asset Retirement Obligation Disclosure [Abstract]      
Balance, beginning of period $ 897,226 $ 541,661  
Obligations assumed [1] 199,519 258,858  
Obligations incurred 107 14,199  
Obligations settled (108,789) (86,615)  
Obligations divested 0 (19,448)  
Accretion expense 117,604 86,152 $ 55,995
Changes in estimate [2] 44,068 102,419  
Balance, end of period 1,149,735 897,226 $ 541,661
Less: Current portion 97,166 77,581  
Long-term portion $ 1,052,569 $ 819,645  
[1] Assumed in connection with the QuarterNorth Acquisition and EnVen Acquisition. See further discussion in Note 3 — Acquisitions and Divestitures.
[2] Changes in estimate were primarily due to changes in expected timing and increases in cost estimates to satisfy certain future abandonment obligations.
v3.25.0.1
Asset Retirement Obligations (Additional Information) (Details) - USD ($)
$ in Thousands
Dec. 31, 2024
Dec. 31, 2023
Restricted cash $ 106,260 $ 102,362
EnVen energy corporation    
Receivable with imputed interest, face amount 66,200  
Future plugging and abanonment obligations    
Restricted cash $ 106,300  
v3.25.0.1
Stockholders' Equity - Additional Information (Details) - USD ($)
$ / shares in Units, $ in Thousands
 12 Months Ended
Dec. 17, 2024
Oct. 01, 2024
Jan. 22, 2024
Dec. 31, 2024
Dec. 31, 2023
Dec. 31, 2022
Share-Based Compensation Arrangement by Share-Based Payment Award [Line Items]            
Issuance of common stock, Shares       34,500,000    
Issuance of common stock       $ 387,717 $ 0 $ 0
Common stock, par value       $ 0.01 $ 0.01  
Rights agreement description The Amendment accelerated the expiration of the Rights from the close of business on October 1, 2025 to the close of business on December 17, 2024.          
Rights Agreement            
Share-Based Compensation Arrangement by Share-Based Payment Award [Line Items]            
Common stock, par value   $ 0.01        
Rights Agreement | O 2024 Q4 Dividends            
Share-Based Compensation Arrangement by Share-Based Payment Award [Line Items]            
Dividend payable record date   Oct. 11, 2024        
Common Stock            
Share-Based Compensation Arrangement by Share-Based Payment Award [Line Items]            
Issuance of common stock, Shares       34,500,000    
Underwriter Discount Fee            
Share-Based Compensation Arrangement by Share-Based Payment Award [Line Items]            
Payments of stock issuance costs     $ 15,100      
Offering Expenses            
Share-Based Compensation Arrangement by Share-Based Payment Award [Line Items]            
Payments of stock issuance costs     $ 800      
Underwritten Public Offering            
Share-Based Compensation Arrangement by Share-Based Payment Award [Line Items]            
Issuance of common stock, Shares     34,500,000      
Underwritten Public Offering | Common Stock            
Share-Based Compensation Arrangement by Share-Based Payment Award [Line Items]            
Issuance of common stock     $ 387,700      
v3.25.0.1
Employee Benefits Plans and Share-Based Compensation - Additional Information (Details) - USD ($)
$ in Millions
 1 Months Ended 12 Months Ended
Nov. 01, 2024
Sep. 09, 2024
Mar. 31, 2022
Dec. 31, 2024
Dec. 31, 2023
Dec. 31, 2022
May 23, 2024
Restricted Stock Units              
Share Based Compensation Arrangement By Share Based Payment Award Line Items              
Share-Based Compensation vested shares, grant       1,534,798 1,730,959 967,269  
Share - Based Compensation Arrangement, granted       3,155,776 1,154,541 2,297,465  
Forfeited       384,904 332,725 97,891  
Share-Based Payment Arrangement, Plan Modification, Incremental Cost           $ 9.7  
Performance Shares              
Share Based Compensation Arrangement By Share Based Payment Award Line Items              
Share-Based Compensation vested shares, grant [1]           14,474  
Contingent Right Upon Vesting to Receive Common Stock       1      
Share-based compensation expense recognized period       1 year 9 months 18 days      
Share-based compensation expense unrecognized       $ 3.4      
Share - Based Compensation Arrangement, granted       299,472 [2] 595,394 [3] 629,666 [4]  
Forfeited       666,455 [5] 217,346 16,486  
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 1,147,352        
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 compensation expense recognized period       2 years 2 months 12 days      
Share-based compensation expense unrecognized       $ 31.7      
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] The performance period for the relative TSR awards ended on December 31, 2022. 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 2023. 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.
[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] There were 314,833 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 314,833 PSUs were granted and are eligible to vest based on continued employment and the Company’s return on the wells included in the 2022 drill program over a three-year performance period.
[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.
v3.25.0.1
Employee Benefits Plans and Share-Based Compensation - Schedule Of Acquisition Severance Costs (Details) - Employee Severance - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2024
Dec. 31, 2023
Acquisition Severance Costs Line Items    
Balance, beginning of period $ 6,294 $ 0
Accrual additions 25,991 25,348
Benefit payments (31,451) (19,054)
Balance, end of period 834 6,294
Less: Current portion 827 6,190
Long-term portion $ 7 $ 104
v3.25.0.1
Employee Benefits Plans and Share-Based Compensation - Schedule of Restricted Stock and Performance Share Units Activity (Details) - $ / shares
 12 Months Ended
Dec. 31, 2024
Dec. 31, 2023
Dec. 31, 2022
Restricted Stock Units      
Share Based Compensation Arrangement By Share Based Payment Award Line Items      
Unvested beginning of the period 2,306,361 [1] 3,215,504 1,983,199
Granted 3,155,776 1,154,541 2,297,465
Vested (1,534,798) (1,730,959) (967,269)
Forfeited (384,904) (332,725) (97,891)
Unvested end of the period 3,542,435 [1] 2,306,361 [1] 3,215,504
Unvested weighted average grant date fair value, beginning of the period $ 14.89 [1] $ 12.79 $ 13.02
Unvested weighted average grant date fair value, granted 11.97 16.24 13.23
Unvested weighted average grant date fair value, vested 13.72 11.97 14.14
Unvested weighted average grant date fair value, forfeited 14.65 14.52 14.34
Unvested weighted average grant date fair value, end of the period $ 12.83 [1] $ 14.89 [1] $ 12.79
Performance Shares      
Share Based Compensation Arrangement By Share Based Payment Award Line Items      
Unvested beginning of the period 1,016,649 638,601 1,015,459
Granted 299,472 [2] 595,394 [3] 629,666 [4]
Vested [5]     (14,474)
Forfeited (666,455) [6] (217,346) (16,486)
Cancelled     (975,564)
Unvested end of the period 649,666 1,016,649 638,601
Unvested weighted average grant date fair value, beginning of the period $ 21.3 $ 23.66 $ 16.41
Unvested weighted average grant date fair value, granted 11.36 [2] 18.76 [3] 23.73 [4]
Unvested weighted average grant date fair value, vested [5]     13.05
Unvested weighted average grant date fair value, forfeited 22.71 [6] 21.28 17.48
Unvested weighted average grant date fair value, Cancelled     16.42
Unvested weighted average grant date fair value, end of the period $ 15.27 $ 21.3 $ 23.66
[1] As of December 31, 2024 and 2023, 35,508 and 26,975, respectively, of the unvested RSUs were accounted for as liability awards in “Accrued liabilities” on the Consolidated Balance Sheet.
[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] There were 314,833 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 314,833 PSUs were granted and are eligible to vest based on continued employment and the Company’s return on the wells included in the 2022 drill program over a three-year performance period.
[5] The performance period for the relative TSR awards ended on December 31, 2022. 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 2023. 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.
[6] 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.
v3.25.0.1
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, 2024
Dec. 31, 2023
Dec. 31, 2022
Dec. 31, 2021
Restricted Stock Units          
Share Based Compensation Arrangement By Share Based Payment Award Line Items          
Granted   3,155,776 1,154,541 2,297,465  
Forfeited   384,904 332,725 97,891  
Unvested   3,542,435 [1] 2,306,361 [1] 3,215,504 1,983,199
Performance Shares          
Share Based Compensation Arrangement By Share Based Payment Award Line Items          
Granted   299,472 [2] 595,394 [3] 629,666 [4]  
Forfeited   666,455 [5] 217,346 16,486  
Unvested   649,666 1,016,649 638,601 1,015,459
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     297,697 314,833  
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 3 years  
Return On Drilling Program Award | Performance Shares          
Share Based Compensation Arrangement By Share Based Payment Award Line Items          
Granted     297,697 314,833  
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      
Accrued Liabilities | Restricted Stock Units          
Share Based Compensation Arrangement By Share Based Payment Award Line Items          
Unvested   35,508 26,975    
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      
[1] As of December 31, 2024 and 2023, 35,508 and 26,975, respectively, of the unvested RSUs were accounted for as liability awards in “Accrued liabilities” on the Consolidated Balance Sheet.
[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] There were 314,833 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 314,833 PSUs were granted and are eligible to vest based on continued employment and the Company’s return on the wells included in the 2022 drill program over a three-year performance period.
[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.
v3.25.0.1
Employee Benefits Plans and Share-Based Compensation - Summary of Assumptions Used to Calculate the Grant Date Fair Value (Details) - Performance Shares - USD ($)
$ in Thousands
Nov. 01, 2024
Sep. 09, 2024
Dec. 01, 2023
Jul. 01, 2023
Mar. 05, 2023
Sep. 20, 2022
Mar. 05, 2022
Grant Date November 1, 2024              
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 4.10%            
Dividend yield 0.00%            
Fair value $ 355            
Grant Date September 9, 2024              
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   3.60%          
Dividend yield   0.00%          
Fair value   $ 3,047          
Grant Date December 1, 2023              
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%        
Dividend yield     0.00%        
Fair value     $ 12        
Grant Date July 1, 2023              
Share Based Compensation Arrangement By Share Based Payment Award Line Items              
Expected term (in years)       2 years 6 months      
Expected volatility       66.20%      
Risk-free interest rate       4.60%      
Dividend yield       0.00%      
Fair value       $ 173      
Grant Date March 5, 2023              
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         4.50%    
Dividend yield         0.00%    
Fair value         $ 6,165    
Grant Date September 20, 2022              
Share Based Compensation Arrangement By Share Based Payment Award Line Items              
Expected term (in years)           2 years 3 months 18 days  
Expected volatility           74.30%  
Risk-free interest rate           3.90%  
Dividend yield           0.00%  
Fair value           $ 621  
Grant Date March 5, 2022              
Share Based Compensation Arrangement By Share Based Payment Award Line Items              
Expected term (in years)             2 years 9 months 18 days
Expected volatility             82.20%
Risk-free interest rate             1.60%
Dividend yield             0.00%
Fair value             $ 8,668
v3.25.0.1
Employee Benefits Plans and Share-Based Compensation - Schedule of Recognized Share Based Compensation Expense, Net (Details) - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2024
Dec. 31, 2023
Dec. 31, 2022
Share-Based Payment Arrangement [Abstract]      
Share-based compensation costs $ 22,088 $ 25,236 $ 28,280
Less: Amounts capitalized to oil and gas properties 7,626 12,283 12,327
Total share-based compensation expense $ 14,462 $ 12,953 $ 15,953
v3.25.0.1
Income Taxes - Components of Income Tax Expense (Benefit) (Details) - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2024
Dec. 31, 2023
Dec. 31, 2022
Current income tax expense (benefit)      
Federal $ (2,180) $ 18 $ 1,334
State 103 58 41
Mexico 309 31 432
Total current income tax expense (benefit) (1,768) 107 1,807
Deferred income tax expense (benefit)      
Federal (10,874) (61,182) 567
State 17,645 478 92
Mexico 0 0 71
Total deferred income tax expense (benefit) 6,771 (60,704) 730
Total income tax expense (benefit) $ 5,003 $ (60,597) $ 2,537
v3.25.0.1
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, 2024
Dec. 31, 2023
Dec. 31, 2022
Income Tax Disclosure [Abstract]      
Income tax expense (benefit) at the federal statutory tax rate $ (14,992) $ 26,614 $ 80,735
State income taxes (200) 1,748 1,591
Impact of foreign operations 852 13,539 15,657
Effect of change in state rate 38,199 0 0
Prior year taxes (2,937) 1,184 (2,920)
Change in valuation allowance (20,273) (106,815) (96,537)
Other permanent differences 4,354 3,133 4,011
Total income tax expense (benefit) $ 5,003 $ (60,597) $ 2,537
Effective tax rate (7.01%) (47.81%) 0.66%
v3.25.0.1
Income Taxes - Additional Information (Details) - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2024
Dec. 31, 2023
Dec. 31, 2022
Mar. 04, 2024
Income Tax Disclosure [Line Items]        
Federal statutory rate 21.00% 21.00% 21.00%  
Effect of change in state rate $ 38,199 $ 0 $ 0  
Other permanent differences $ 4,354 3,133 $ 4,011  
Operating loss carryforwards limitation on use As of December 31, 2024, the Company had U.S. federal net operating loss carryforwards (“NOLs”) of approximately $517.7 million, all of which are subject to limitation 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 $ 3,325 23,697    
Income tax examination, Year 2021 2022 2023 2024      
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.      
Quarter North Energy        
Income Tax Disclosure [Line Items]        
Business combination, recognized identifiable assets acquired and liabilities assumed, deferred tax liabilities       $ 168,100
Federal        
Income Tax Disclosure [Line Items]        
Valuation allowance, deferred tax asset, increase (decrease), amount   $ (106,800)    
Other permanent differences $ 4,300      
Operating loss carryforwards 517,700      
State        
Income Tax Disclosure [Line Items]        
Effect of change in state rate 38,200      
State | State Valuation Allowance Deferred Tax        
Income Tax Disclosure [Line Items]        
Valuation allowance, deferred tax asset, increase (decrease), amount $ (20,300)      
Internal Revenue Code | Federal | Capital loss carryforward        
Income Tax Disclosure [Line Items]        
Operating loss carryforwards expiration year 2036      
v3.25.0.1
Income Taxes - Summary of Significant Components of Deferred Tax Assets and Liabilities (Details) - USD ($)
$ in Thousands
Dec. 31, 2024
Dec. 31, 2023
Deferred tax assets:    
Federal net operating loss $ 108,717 $ 147,252
Foreign tax loss carryforward 452 509
State net operating loss 12,426 24,840
Tax credits 0 107
Interest expense carryforward 74,957 46,414
Asset retirement obligations 262,773 190,248
Other well equipment 9,796 1,317
Accrued bonus 9,040 5,050
Share-based compensation 5,343 5,172
Operating lease liabilities 4,340 4,427
Finance lease liabilities 29,926 31,607
Other 5,764 3,383
Total deferred tax assets 523,534 460,326
Valuation allowance (3,325) (23,697)
Total deferred tax assets, net 520,209 436,629
Deferred tax liabilities:    
Oil and gas properties 772,439 512,918
Operating lease assets 2,508 2,421
Derivatives 5,411 9,670
Prepaid 6,428 3,847
Total deferred tax liabilities 786,786 528,856
Net deferred tax liability $ (266,577) $ (92,227)
v3.25.0.1
Income Taxes - Summary of Net Operating Loss Carryovers (Details)
$ in Thousands
 12 Months Ended
Dec. 31, 2024
USD ($)
Operating Loss Carryforwards [Line Items]  
Operating loss carryforwards limitation on use As of December 31, 2024, the Company had U.S. federal net operating loss carryforwards (“NOLs”) of approximately $517.7 million, all of which are subject to limitation 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 $ 517,700
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 $ 222,354
Federal | Unlimited Expiration Year  
Operating Loss Carryforwards [Line Items]  
Net operating losses carryforward, Amount $ 295,348
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 2033
Foreign | 2026 - 2033  
Operating Loss Carryforwards [Line Items]  
Net operating losses carryforward, Amount $ 1,505
State | Unlimited Expiration Year  
Operating Loss Carryforwards [Line Items]  
Net operating losses carryforward, Amount $ 282,871
Operating loss carryforwards limitation on use Unlimited
v3.25.0.1
Income Taxes - Summary of Balances In Uncertain Tax Positions (Details) - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2024
Dec. 31, 2023
Dec. 31, 2022
Income Tax Uncertainties [Abstract]      
Total unrecognized tax benefits, beginning balance $ 989 $ 835 $ 696
Tax positions taken during a prior period   154 100
Tax positions taken decrease during a prior period (120)    
Tax positions taken during the current period 723 0 39
Total unrecognized tax benefits, ending balance $ 1,592 $ 989 $ 835
v3.25.0.1
Income (Loss) Per Share - Summary of Computation of Basic and Diluted Income (Loss) Per Share (Details) - USD ($)
$ / shares in Units, shares in Thousands, $ in Thousands
 12 Months Ended
Dec. 31, 2024
Dec. 31, 2023
Dec. 31, 2022
Earnings Per Share [Abstract]      
Net Income (Loss) $ (76,393) $ 187,332 $ 381,915
Weighted average common shares outstanding — basic 175,605 119,894 82,454
Dilutive effect of securities 0 858 1,229
Weighted average common shares outstanding — diluted 175,605 120,752 83,683
Basic $ (0.44) $ 1.56 $ 4.63
Diluted $ (0.44) $ 1.55 $ 4.56
Anti-dilutive potentially issuable securities excluded from diluted common shares 2,084 1,353 865
v3.25.0.1
Related Party Transactions - Additional Information (Details) - USD ($)
$ in Millions
Dec. 31, 2024
Dec. 16, 2024
Feb. 07, 2024
Dec. 31, 2023
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 | BainCapitalLpMember        
Related Party Transaction [Line Items]        
Stock ownership percentage 8.40%      
Beneficial Owner | Slim Family        
Related Party Transaction [Line Items]        
Stock ownership percentage 24.20%      
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     $ 5.5
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 $ 2.3      
v3.25.0.1
Commitments and Contingencies - Additional Information (Details) - USD ($)
$ in Millions
 12 Months Ended
Mar. 23, 2022
Dec. 31, 2024
Loss Contingencies [Line Items]    
Gain (Loss) Related to Litigation Settlement, Total $ 27.5  
Payments for Legal Settlements   $ 14.4
Bank Credit Facility | Letter of Credit    
Loss Contingencies [Line Items]    
Letters of credit outstanding amount   42.4
Surety Bond    
Loss Contingencies [Line Items]    
Surety performance bonds outstanding   $ 1,500.0
v3.25.0.1
Commitments and Contingencies - Summary of Future Minimum Transportation Fees (Details)
$ in Thousands
Dec. 31, 2024
USD ($)
Contractual Obligation [Line Items]  
2025 $ 158,819
2026 16,493
2027 9,249
2028 10,619
2029 4,465
Thereafter 1,453
Total 201,098
Firm Transportation  
Contractual Obligation [Line Items]  
2025 5,439
2026 5,718
2027 9,249
2028 10,619
2029 4,465
Thereafter 1,453
Total $ 36,943
v3.25.0.1
Commitments and Contingencies - Summary of Total Minimum Commitments (Details)
$ in Thousands
Dec. 31, 2024
USD ($)
Contractual Obligation [Line Items]  
2025 $ 158,819
2026 16,493
2027 9,249
2028 10,619
2029 4,465
Thereafter 1,453
Total 201,098
Vessel Commitments  
Contractual Obligation [Line Items]  
2025 99,069 [1]
2026 0 [1]
2027 0 [1]
2028 0 [1]
2029 0 [1]
Thereafter 0 [1]
Total 99,069 [1]
Committed Purchase Orders  
Contractual Obligation [Line Items]  
2025 40,668 [2]
2026 0 [2]
2027 0 [2]
2028 0 [2]
2029 0 [2]
Thereafter 0 [2]
Total 40,668 [2]
Other Commitments  
Contractual Obligation [Line Items]  
2025 19,082
2026 16,493
2027 9,249
2028 10,619
2029 4,465
Thereafter 1,453
Total $ 61,361
[1] Includes vessel commitments the Company will utilize for certain Deepwater well intervention, drilling operations and decommissioning activities. These commitments represent gross contractual obligations and accordingly, other joint owners in the properties operated by the Company will be billed for their working interest share of such costs.
[2] Includes committed purchase orders to execute planned future drilling activities. These commitments represent gross contractual obligations and accordingly, other joint owners in the properties operated by the Company will be billed for their working interest share of such costs.
v3.25.0.1
Commitments and Contingencies - Summary of Decommissioning Obligations Included in Consolidated Balance Sheets (Details) - Decommissioning Abandonment Obligations - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2024
Dec. 31, 2023
Dec. 31, 2022
Loss Contingencies [Line Items]      
Balance, beginning of period $ 15,564 $ 54,269 $ 24,336
Additions 6,168 266 8,900
Obligations assumed 1,326 0 0
Changes in estimate 2,391 11,613 22,658
Settlements (5,447) (50,584) (1,625)
Balance, end of period 20,002 15,564 54,269
Other Current Liabilities      
Loss Contingencies [Line Items]      
Less: Current portion 5,453 3,280 42,069
Other Noncurrent Liabilities      
Loss Contingencies [Line Items]      
Loss Contingency, Accrual, Noncurrent, Total $ 14,549 $ 12,284 $ 12,200
v3.25.0.1
Segment Information - Additional Information (Details) - Segment
 3 Months Ended 12 Months Ended
Mar. 18, 2024
Dec. 31, 2024
Segment Reporting [Abstract]    
Number of operating segments 2 2
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 Statement 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
v3.25.0.1
Segment Information - Summary of Information by Business Segment (Details) - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2024
Dec. 31, 2023
Dec. 31, 2022
Segment Reporting Information [Line Items]      
Revenues from external customers $ 1,973,568 $ 1,457,886 $ 1,651,980
Lease operating expense:      
Lease operating expense (566,041) (389,621) (308,092)
Derivative instrument on fair value gain (loss) (1,458) 80,928 (272,191)
Interest expense (187,638) (173,145) (125,498)
Segment Reporting Information, Additional Information [Abstract]      
Depreciation, depletion and amortization (1,023,558) (663,534) (414,630)
Equity-based compensation expense (14,462) (12,953) (15,953)
Gain on Divestiture 100,482 0 0
Equity method investment income (loss) (10,289) (3,209) 14,222
Gain (loss) on extinguishment of debt (60,256) 0 (1,569)
Income tax benefit (expense) (5,003) 60,597 (2,537)
Net income (loss) (76,393) 187,332 381,915
CCS Segment      
Segment Reporting Information [Line Items]      
Revenues from external customers 0 0 0
Operating Segments      
Segment Reporting Information [Line Items]      
Revenues from external customers 1,973,568 1,457,886 1,651,980
Lease operating expense:      
Adjusted general and administrative expense (132,614) [1] (98,756) [2] (72,657) [3]
Interest expense (187,638) (173,145) (125,498)
Segment Reporting Information, Additional Information [Abstract]      
Other (31,520) [4] (50,889) [5] (45,163) [6]
Depreciation, depletion and amortization (1,023,558) (663,534) (414,630)
Accretion expense (117,604) (86,152) (55,995)
Equity-based compensation expense (14,462) (12,953) (15,953)
Gain on Divestiture [7] 100,482    
Gain on Divestiture [8]   66,180  
Gain On Settlements [9]     29,998
Equity method investment income (loss) (10,289) (12,109) (1,065)
Gain (loss) on partial sale of equity investment   8,900 [10] 15,287 [11]
Gain (loss) on extinguishment of debt (60,256)   (1,569)
Income tax benefit (expense) (5,003) 60,597 (2,537)
Net income (loss) (76,393) 187,332 381,915
Segment Expenditures 621,284 774,630 455,452
Operating Segments | Upstream      
Segment Reporting Information [Line Items]      
Revenues from external customers 1,973,568 1,457,886 1,651,980
Lease operating expense:      
Adjusted general and administrative expense (130,695) [1] (88,333) [2] (63,689) [3]
Interest expense (187,432) (172,060) (124,936)
Segment Reporting Information, Additional Information [Abstract]      
Other (23,048) [4] (55,048) [5] (42,510) [6]
Depreciation, depletion and amortization (1,023,512) (661,904) (414,395)
Accretion expense (117,604) (86,152) (55,995)
Equity-based compensation expense (14,415) (11,454) (14,681)
Gain on Divestiture [7] 0    
Gain on Divestiture [8]   66,180  
Gain On Settlements [9]     29,998
Equity method investment income (loss) (2,319) 120 101
Gain (loss) on partial sale of equity investment   0 [10] 0 [11]
Gain (loss) on extinguishment of debt (60,256)   (1,569)
Income tax benefit (expense) 12,188 57,719 (2,425)
Net income (loss) (141,024) 198,261 381,596
Segment Expenditures 603,765 733,669 452,674
Operating Segments | CCS Segment      
Segment Reporting Information [Line Items]      
Revenues from external customers 0 [12] 0 [13] 0 [14]
Lease operating expense:      
Adjusted general and administrative expense (1,919) [1],[12] (10,423) [2],[13] (8,968) [3],[14]
Interest expense (206) [12] (1,085) [13] (562) [14]
Segment Reporting Information, Additional Information [Abstract]      
Other (8,472) [4],[12] 4,159 [5],[13] (2,653) [6],[14]
Depreciation, depletion and amortization (46) [12] (1,630) [13] (235) [14]
Accretion expense 0 [12] 0 [13] 0 [14]
Equity-based compensation expense (47) [12] (1,499) [13] (1,272) [14]
Gain on Divestiture [7],[12] 100,482    
Gain on Divestiture [8],[13]   0  
Gain On Settlements [9],[14]     0
Equity method investment income (loss) (7,970) [12] (12,229) [13] (1,166) [14]
Gain (loss) on partial sale of equity investment   8,900 [10],[13] 15,287 [11],[14]
Gain (loss) on extinguishment of debt 0 [12]   0 [14]
Income tax benefit (expense) (17,191) [12] 2,878 [13] (112) [14]
Net income (loss) 64,631 [12] (10,929) [13] 319 [14]
Segment Expenditures 17,519 [12] 40,961 [13] 2,778 [14]
Operating Segments | Direct operating and maintenance      
Lease operating expense:      
Lease operating expense (492,123) (374,481) (289,120)
Operating Segments | Direct operating and maintenance | Upstream      
Lease operating expense:      
Lease operating expense (492,123) (374,481) (289,120)
Operating Segments | Direct operating and maintenance | CCS Segment      
Lease operating expense:      
Lease operating expense 0 [12] 0 [13] 0 [14]
Operating Segments | Workover      
Lease operating expense:      
Lease operating expense (73,918) (15,140) (18,972)
Operating Segments | Workover | Upstream      
Lease operating expense:      
Lease operating expense (73,918) (15,140) (18,972)
Operating Segments | Workover | CCS Segment      
Lease operating expense:      
Lease operating expense 0 [12] 0 [13] 0 [14]
Operating Segments | Derivative realized gain loss      
Lease operating expense:      
Derivative instrument on fair value gain (loss) 4,710 (9,457) (425,559)
Operating Segments | Derivative realized gain loss | Upstream      
Lease operating expense:      
Derivative instrument on fair value gain (loss) 4,710 (9,457) (425,559)
Operating Segments | Derivative realized gain loss | CCS Segment      
Lease operating expense:      
Derivative instrument on fair value gain (loss) 0 [12] 0 [13] 0 [14]
Operating Segments | Derivative mark to market gain (loss)      
Lease operating expense:      
Derivative instrument on fair value gain (loss) (6,168) 90,385 153,368
Operating Segments | Derivative mark to market gain (loss) | Upstream      
Lease operating expense:      
Derivative instrument on fair value gain (loss) (6,168) 90,385 153,368
Operating Segments | Derivative mark to market gain (loss) | CCS Segment      
Lease operating expense:      
Derivative instrument on fair value gain (loss) $ 0 [12] $ 0 [13] $ 0 [14]
[1] 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.
[2] 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.
[3] Includes general and administrative expense less transaction expenses and equity-based compensation. Corporate overhead allocated to the Upstream Segment and CCS Segment was $49.2 million and $1.6 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] 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.
[6] Primarily includes decommissioning obligations and transaction expenses for the Upstream Segment. Transaction expenses include costs related to the EnVen Acquisition. See further discussion in Note 3 — Acquisition and Divestitures 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.
[9] Includes $27.5 million gain as a result of the settlement agreement to resolve previously pending litigation that was filed in October 2017 that is further discussed in Note 15 — Commitments and Contingencies.
[10] 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.
[11] Includes a gain on the funding of the capital carry of the Company’s investment in Bayou Bend by Chevron of $1.4 million and a $13.9 million gain on the partial sale of its investment in Bayou Bend to Chevron. See further discussion in Note 7 — Equity Method Investments.
[12] The CCS Segment was an emerging business in the start-up phase of operations and the business did not generate any revenues.
[13] The CCS Segment was an emerging business in the start-up phase of operations and the business did not generate any revenues.
[14] The CCS Segment was an emerging business in the start-up phase of operations and the business did not generate any revenues.
v3.25.0.1
Segment Information - Summary of Information by Business Segment (Details) (Parenthetical) - USD ($)
$ in Thousands
 12 Months Ended
Mar. 23, 2022
Dec. 31, 2024
Dec. 31, 2023
Dec. 31, 2022
Segment Reporting Information [Line Items]        
Revenues from external customers   $ 1,973,568 $ 1,457,886 $ 1,651,980
Segment reporting other item composition description   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. Primarily includes decommissioning obligations and transaction expenses for the Upstream Segment. Transaction expenses include costs related to the EnVen Acquisition. See further discussion in Note 3 — Acquisition and Divestitures and Note 15 — Commitments and Contingencies.
Gain (Loss) Related to Litigation Settlement, Total $ 27,500      
Operating Segments        
Segment Reporting Information [Line Items]        
Revenues from external customers   $ 1,973,568 $ 1,457,886 $ 1,651,980
Gain on partial disposal of investment     8,900 [1] 15,287 [2]
Gain (Loss) Related to Litigation Settlement, Total       27,500
Operating Segments | Bayou Bend CCS LLC        
Segment Reporting Information [Line Items]        
Gain on partial disposal of investment       13,900
Operating Segments | Capital Carry | Bayou Bend CCS LLC        
Segment Reporting Information [Line Items]        
Gain on partial disposal of investment     8,600 1,400
Upstream        
Segment Reporting Information [Line Items]        
Corporate overhead   78,500 49,300 49,200
Upstream | Operating Segments        
Segment Reporting Information [Line Items]        
Revenues from external customers   1,973,568 1,457,886 1,651,980
Gain on partial disposal of investment     0 [1] 0 [2]
CCS Segment        
Segment Reporting Information [Line Items]        
Revenues from external customers   0 0 0
Corporate overhead   400 1,700 1,600
CCS Segment | Operating Segments        
Segment Reporting Information [Line Items]        
Revenues from external customers   $ 0 [3] 0 [4] 0 [5]
Gain on partial disposal of investment     $ 8,900 [1],[4] $ 15,287 [2],[5]
[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] Includes a gain on the funding of the capital carry of the Company’s investment in Bayou Bend by Chevron of $1.4 million and a $13.9 million gain on the partial sale of its investment in Bayou Bend to Chevron. See further discussion in Note 7 — Equity Method Investments.
[3] The CCS Segment was an emerging business in the start-up phase of operations and the business did not generate any revenues.
[4] The CCS Segment was an emerging business in the start-up phase of operations and the business did not generate any revenues.
[5] The CCS Segment was an emerging business in the start-up phase of operations and the business did not generate any revenues.
v3.25.0.1
Segment Information - Reconciliation of Reportable Segment Expenditures (Details) - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2024
Dec. 31, 2023
Dec. 31, 2022
Segment Reporting Information [Line Items]      
Plugging & abandonment $ 108,789 $ 86,615 $ 69,596
Other deferred payments (2,389) (1,545) 0
Exploration, development and other capital expenditures 508,914 561,434 323,164
Operating Segments | Reportable segment      
Segment Reporting Information [Line Items]      
Segment Expenditures 621,284 774,630 455,452
Segment Reconciling Items      
Segment Reporting Information [Line Items]      
Change in capital expenditures included in accounts payable and accrued liabilities 29,423 (9,199) (60,011)
Plugging & abandonment (108,789) (86,615) (69,596)
Decommissioning obligations settled (5,447) (50,584) (1,625)
Investment in CCS intangibles and equity method investees (22,988) (40,946) (2,778)
Other deferred payments (2,389) (1,545) 0
Non-cash well equipment transfers (3,412) (27,731) (6)
Other $ 1,232 $ 3,424 $ 1,728
v3.25.0.1
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, 2024
USD ($)
$ / Boe
Dec. 31, 2023
USD ($)
$ / Boe
Dec. 31, 2022
USD ($)
$ / Boe
Reserve Quantities [Line Items]      
Proved properties $ 9,784,832 $ 7,906,295  
Unproved oil and gas properties, not subject to amortization 587,238 268,315  
Consolidated Entities [Member]      
Reserve Quantities [Line Items]      
Proved properties 9,784,832 7,906,295 $ 5,964,340
Unproved oil and gas properties, not subject to amortization 587,238 268,315 154,783
Total oil and gas properties 10,372,070 8,174,610 6,119,123
Less: Accumulated DD&A 5,163,844 4,143,491 3,484,590
Net capitalized costs $ 5,208,226 $ 4,031,119 $ 2,634,533
DD&A rate (Per Boe) | $ / Boe 30.11 27.23 18.95
Equity Method Investee [Member]      
Reserve Quantities [Line Items]      
Unproved oil and gas properties, not subject to amortization $ 58,723 $ 56,579 $ 0
v3.25.0.1
Supplemental Oil and Gas Disclosures (Unaudited) - Schedule of Capitalized Costs Related to Oil, Natural Gas and NGL Activities and Related Accumulated Depletion and Amortization (Parenthetical) (Details) - USD ($)
$ in Thousands
Dec. 31, 2024
Dec. 31, 2023
Dec. 31, 2022
Capitalized Costs Relating To Oil And Gas Producing Activities By Geographic Area [Line Items]      
Unproved properties, not subject to amortization $ 587,238 $ 268,315  
Mexico      
Capitalized Costs Relating To Oil And Gas Producing Activities By Geographic Area [Line Items]      
Unproved properties, not subject to amortization     $ 111,400
v3.25.0.1
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, 2024
Dec. 31, 2023
Dec. 31, 2022
Equity Method Investee [Member]      
Property acquisition costs:      
Exploration costs $ 2,144 $ 290 $ 0
Consolidated Entities [Member]      
Property acquisition costs:      
Proved properties 1,085,324 951,703 0
Unproved properties, not subject to amortization 380,129 249,688 2,221
Total property acquisition costs 1,465,453 1,201,391 2,221
Exploration costs 129,400 161,296 125,889
Development costs 602,607 805,148 541,512
Total costs incurred $ 2,197,460 $ 2,167,835 $ 669,622
v3.25.0.1
Supplemental Oil and Gas Disclosures (Unaudited) - Schedule of Costs Incurred in Oil, Natural Gas and NGL Property Acquisition, Exploration and Development Activities (Parenthetical) (Details)
$ in Millions
 12 Months Ended
Dec. 31, 2022
USD ($)
Mexico  
Costs Incurred Oil And Gas Property Acquisition Exploration And Development Activities [Line Items]  
Exploration costs $ 1.2
v3.25.0.1
Supplemental Oil and Gas Disclosures (Unaudited) - Additional Information (Details)
 12 Months Ended
Dec. 31, 2024
MMBoe
$ / bbl
$ / Mcf
Dec. 31, 2023
MMBoe
$ / Mcf
$ / bbl
Dec. 31, 2022
MMBoe
$ / Mcf
$ / bbl
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% 100.00%
Proved Developed and Undeveloped Reserve, Net (Energy), Period Increase (Decrease) 41.5 12.2 (21)
Significant changes in reserves, description 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 Monument Acquisition 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 a decrease of 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 a decrease of 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. During 2022, proved reserves decreased by 21.0 MMBoe primarily due to a decrease of 21.7 MMBoe of production. Additionally, there was a decrease of 9.0 MMBoe primarily due to timing of development of certain PUD locations to move beyond five years at the Phoenix Field in the Deepwater area and sales of reserves of 1.4 MMBoe primarily related to the Brushy Creek Field in the Shelf and Gulf Coast area. The decrease was partially offset by 11.2 MMBoe of estimated proved reserves from extensions and discoveries primarily from evaluations of the Pompano Field and the Ram Powell Field located in the Deepwater area.
Sales of reserves     1.4
Decrease of production 33.9 24.2 21.7
Revision to previous estimates 4.9 (18.1) (9)
Estimated proved reserves from extensions and discoveries 7.5 5.4 11.2
Prescribed rate of discounted future net cash flows 10.00%    
Oil (MBbls)      
Reserve Quantities [Line Items]      
SEC pricing | $ / bbl 75.51 78.56 96.03
Gas (MMcf)      
Reserve Quantities [Line Items]      
SEC pricing | $ / Mcf 2.45 2.75 6.80
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] | 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    
v3.25.0.1
Supplemental Oil and Gas Disclosures (Unaudited) - Schedule of Estimated Proved Reserves at Net Ownership Interest (Details)
 12 Months Ended
Dec. 31, 2024
MBoe
MMBoe
MMcf
MMBbls
Dec. 31, 2023
MMBoe
MBoe
MMBbls
MMcf
Dec. 31, 2022
MBoe
MMBoe
MMcf
MMBbls
Reserve Quantities [Line Items]      
Revision to previous estimates | MMBoe 4.9 (18.1) (9)
Production | MMBoe (33.9) (24.2) (21.7)
Sales of reserves | MMBoe     (1.4)
Extensions and discoveries | MMBoe 7.5 5.4 11.2
Oil (MBbls)      
Reserve Quantities [Line Items]      
Total proved reserves, beginning balance 110,815 91,059 107,764
Revision of previous estimates (599) (6,308) (5,625)
Production (24,078) (18,062) (14,561)
Sales of reserves     (158)
Acquisition of reserves 51,376 41,871  
Extensions and discoveries 5,534 2,255 3,639
Total proved reserves, ending balance 143,048 110,815 91,059
Total proved developed reserves 108,479 98,225 80,285
Total proved undeveloped reserves 34,569 12,590 10,774
Gas (MMcf)      
Reserve Quantities [Line Items]      
Total proved reserves, beginning balance | MMcf 179,871 219,551 236,353
Revision of previous estimates | MMcf (30,186) (62,946) (8,302)
Production | MMcf (41,078) (26,194) (32,215)
Sales of reserves | MMcf     (7,625)
Acquisition of reserves 99,683 36,690  
Extensions and discoveries | MMcf 9,684 12,770 31,340
Total proved reserves, ending balance | MMcf 217,974 179,871 219,551
Total proved developed reserves | MMcf 175,139 141,823 161,727
Total proved undeveloped reserves | MMcf 42,835 38,048 57,824
NGL (MBbls)      
Reserve Quantities [Line Items]      
Total proved reserves, beginning balance 11,973 12,928 14,435
Revision of previous estimates 698 (1,283) (2,002)
Production (2,969) (1,767) (1,793)
Sales of reserves     0
Acquisition of reserves 4,834 1,116  
Extensions and discoveries 329 979 2,288
Total proved reserves, ending balance 14,865 11,973 12,928
Total proved developed reserves 12,733 9,957 9,315
Total proved undeveloped reserves 2,132 2,016 3,613
Oil Equivalent (MBoe)      
Reserve Quantities [Line Items]      
Total proved reserves, beginning balance | MBoe 152,766 140,579 161,591
Revision to previous estimates | MBoe (4,932) (18,082) (9,010)
Production | MBoe (33,893) (24,195) (21,723)
Acquisition of reserves | MBoe 72,824 49,102  
Sales of reserves | MBoe     (1,429)
Extensions and discoveries | MBoe 7,477 5,362 11,150
Total proved reserves, ending balance | MBoe 194,242 152,766 140,579
Total proved developed reserves | MBoe 150,402 131,819 116,555
Total proved undeveloped reserves | MBoe 43,840 20,947 24,024
v3.25.0.1
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, 2024
Dec. 31, 2023
Dec. 31, 2022
Dec. 31, 2021
Extractive Industries [Abstract]        
Future cash inflows $ 11,660,546 $ 9,425,055 $ 10,674,896  
Future costs:        
Production (3,436,232) (3,090,491) (1,906,752)  
Development and abandonment (3,301,619) (2,358,368) (1,873,453)  
Future net cash flows before income taxes 4,922,695 3,976,196 6,894,691  
Future income tax expense (845,894) (589,413) (1,114,409)  
Future net cash flows after income taxes 4,076,801 3,386,783 5,780,282  
Discount at 10% annual rate (512,597) (343,295) (1,411,834)  
Standardized measure of discounted future net cash flows $ 3,564,204 $ 3,043,488 $ 4,368,448 $ 3,440,611
v3.25.0.1
Supplemental Oil and Gas Disclosures (Unaudited) - Schedule of Base Prices Used in Determining Standardized Measure (Details)
 12 Months Ended
Dec. 31, 2024
$ / bbl
$ / Mcf
Dec. 31, 2023
$ / bbl
$ / Mcf
Dec. 31, 2022
$ / bbl
$ / Mcf
Oil      
Discounted Future Net Cash Flows Relating To Proved Oil And Gas Reserves [Line Items]      
SEC pricing 75.51 78.56 96.03
Natural Gas      
Discounted Future Net Cash Flows Relating To Proved Oil And Gas Reserves [Line Items]      
SEC pricing | $ / Mcf 2.45 2.75 6.80
NGL      
Discounted Future Net Cash Flows Relating To Proved Oil And Gas Reserves [Line Items]      
SEC pricing 21.91 18.77 33.89
v3.25.0.1
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, 2024
Dec. 31, 2023
Dec. 31, 2022
Extractive Industries [Abstract]      
Standardized measure, beginning of year $ 3,043,488 $ 4,368,448 $ 3,440,611
Sales and transfers of oil, net gas and NGLs produced during the period (1,406,150) (1,065,814) (1,340,400)
Net change in prices and production costs (123,537) (2,835,125) 2,388,442
Changes in estimated future development and abandonment costs 193,810 (19,877) (84,391)
Previously estimated development and abandonment costs incurred 47,016 202,503 20,107
Accretion of discount 485,409 518,110 392,600
Net change in income taxes (181,190) 357,321 (327,265)
Purchases of reserves 1,638,000 2,033,852 0
Sales of reserves 0 0 (5,218)
Extensions and discoveries 74,126 90,244 202,239
Net change due to revision in quantity estimates (162,041) (484,423) (255,743)
Changes in production rates (timing) and other (44,727) (121,751) (62,534)
Standardized measure, end of year $ 3,564,204 $ 3,043,488 $ 4,368,448
v3.25.0.1
Subsequent Events (Details) - USD ($)
$ in Thousands, shares in Millions
 12 Months Ended
Jan. 22, 2024
Dec. 31, 2024
Dec. 31, 2023
Dec. 31, 2022
Subsequent Event [Line Items]        
Share of common stock   34.5    
Net proceeds after deducting underwriting discounts and commissions   $ 387,717 $ 0 $ 0
Underwritten Public Offering [Member]        
Subsequent Event [Line Items]        
Share of common stock 34.5      
v3.25.0.1
Schedule I - Balance Sheets (Details) - USD ($)
$ in Thousands
Dec. 31, 2024
Dec. 31, 2023
Dec. 31, 2022
Dec. 31, 2021
Accounts receivable:        
Other, net $ 34,002 $ 19,296    
Prepaid assets 77,487 64,387    
Other current assets 35,980 10,389    
Total current assets 659,383 422,175    
Other long-term assets:        
Investments in subsidiaries 111,269 146,049    
Total assets 6,191,795 4,816,309    
Current liabilities:        
Accounts payable 117,055 84,193    
Accrued liabilities 326,913 227,690    
Other current liabilities 44,854 48,769    
Total current liabilities 723,055 578,615    
Long-term liabilities:        
Other long-term liabilities 416,041 251,278    
Total liabilities 3,432,090 2,661,158    
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, 2024 and 2023, respectively 0 0    
Common stock; $0.01 par value; 270,000,000 shares authorized; 187,434,908 and 127,480,361 shares issued as of December 31, 2024 and 2023, respectively 1,874 1,275    
Additional paid-in capital 3,274,626 2,549,097    
Accumulated deficit (424,110) (347,717)    
Treasury stock, at cost; 7,417,385 and 3,400,000 shares as of December 31, 2024 and 2023, respectively (92,685) (47,504)    
Total stockholdersʼ equity 2,759,705 2,155,151 $ 1,165,576 $ 760,653
Total liabilities and stockholdersʼ equity 6,191,795 4,816,309    
Parent        
Accounts receivable:        
Other, net 0 100    
Prepaid assets 203 221    
Other current assets 19 19    
Total current assets 222 340    
Other long-term assets:        
Investments in subsidiaries 3,006,909 2,246,908    
Total assets 3,007,131 2,247,248    
Current liabilities:        
Accounts payable 333 316    
Accrued liabilities 544 705    
Other current liabilities 162 124    
Total current liabilities 1,039 1,145    
Long-term liabilities:        
Other long-term liabilities 246,387 90,952    
Total liabilities 247,426 92,097    
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, 2024 and 2023, respectively 0 0    
Common stock; $0.01 par value; 270,000,000 shares authorized; 187,434,908 and 127,480,361 shares issued as of December 31, 2024 and 2023, respectively 1,874 1,275    
Additional paid-in capital 3,274,626 2,549,097    
Accumulated deficit (424,110) (347,717)    
Treasury stock, at cost; 7,417,385 and 3,400,000 shares as of December 31, 2024 and 2023, respectively (92,685) (47,504)    
Total stockholdersʼ equity 2,759,705 2,155,151    
Total liabilities and stockholdersʼ equity $ 3,007,131 $ 2,247,248    
v3.25.0.1
Schedule I - Balance Sheets (Details) (Paranthetical) - $ / shares
Dec. 31, 2024
Dec. 31, 2023
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 187,434,908 127,480,361
Treasury stock, common, shares 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 187,434,908 127,480,361
Treasury stock, common, shares 7,417,385 3,400,000
v3.25.0.1
Schedule I - Statements of Operations (Details) - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2024
Dec. 31, 2023
Dec. 31, 2022
Operating expenses:      
General and administrative expense $ 201,517 $ 158,493 $ 99,754
Total operating expenses (1,800,643) (1,248,096) (915,861)
Operating income (expense) 172,925 209,790 736,119
Other income (expense) (44,930) 12,371 31,800
Net income (loss) before income taxes (71,390) 126,735 384,452
Income tax benefit (expense) (5,003) 60,597 (2,537)
Net income (loss) (76,393) 187,332 381,915
Parent      
Operating expenses:      
General and administrative expense 3,234 2,708 2,145
Total operating expenses 3,234 2,708 2,145
Operating income (expense) (3,234) (2,708) (2,145)
Other income (expense) (1) (1) (1)
Equity earnings (loss) from subsidiaries (83,986) 128,888 385,968
Net income (loss) before income taxes (87,221) 126,179 383,822
Income tax benefit (expense) 10,828 61,153 (1,907)
Net income (loss) $ (76,393) $ 187,332 $ 381,915
v3.25.0.1
Schedule I - Statements of Cash Flows (Details) - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2024
Dec. 31, 2023
Dec. 31, 2022
Cash flows from operating activities:      
Net cash provided by (used in) operating activities $ 962,593 $ 519,069 $ 709,739
Cash flows from investing activities:      
Net cash provided by (used in) investing activities (1,320,279) (512,626) (311,977)
Cash flows from financing activities:      
Issuance of common stock 387,717 0 0
Purchase of treasury stock (45,181) (47,504) 0
Net cash provided by (used in) financing activities 436,119 85,411 (423,469)
Net increase (decrease) in cash, cash equivalents and restricted cash 78,433 91,854 (25,707)
Cash, cash equivalents and restricted cash:      
Balance, beginning of period 135,999 44,145 69,852
Balance, end of period 214,432 135,999 44,145
Parent      
Cash flows from operating activities:      
Net cash provided by (used in) operating activities (1,403) (1,836) (809)
Cash flows from investing activities:      
Investments in subsidiaries (389,138) 0 0
Distributions from subsidiaries 48,005 49,340 809
Net cash provided by (used in) investing activities (341,133) 49,340 809
Cash flows from financing activities:      
Issuance of common stock 387,717 0 0
Purchase of treasury stock (45,181) (47,504) 0
Net cash provided by (used in) financing activities 342,536 (47,504) 0
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