Talos Energy (TALO) 10-K 28 Feb 24 2023 FY Annual report Financial data

Document and Entity Information

Document and Entity Information - USD ($)	12 Months Ended
	Dec. 31, 2023	Feb. 21, 2024	Jun. 30, 2023
Cover [Abstract]
Document Type	10-K
Amendment Flag	false
Document Period End Date	Dec. 31, 2023
Document Fiscal Year Focus	2023
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		158,632,597
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Public Float			$ 1,493,763,437
Documents Incorporated by Reference	Portions of the registrant’s definitive proxy statement relating to the 2024 Annual Meeting of Stockholders are incorporated by reference into Part III of this report.
Document Financial Statement Error Correction Flag	false

CONSOLIDATED BALANCE SHEETS

CONSOLIDATED BALANCE SHEETS - USD ($) $ in Thousands	Dec. 31, 2023	Dec. 31, 2022
Current assets:
Cash and cash equivalents	$ 33,637	$ 44,145
Accounts receivable
Trade, net	178,977	150,598
Joint interest, net	79,337	54,697
Other, net	19,296	6,684
Assets from price risk management activities	36,152	25,029
Prepaid assets	64,387	84,759
Other current assets	10,389	1,917
Total current assets	422,175	367,829
Property and equipment:
Proved properties	7,906,295	5,964,340
Unproved properties, not subject to amortization	268,315	154,783
Other property and equipment	34,027	30,691
Total property and equipment	8,208,637	6,149,814
Accumulated depreciation, depletion and amortization	(4,168,328)	(3,506,539)
Total property and equipment, net	4,040,309	2,643,275
Other long-term assets:
Restricted cash	102,362	0
Assets from price risk management activities	17,551	7,854
Equity method investments	146,049	1,745
Other well equipment	54,277	25,541
Notes receivable, net	16,207	0
Operating lease assets	11,418	5,903
Other assets	5,961	6,479
Total assets	4,816,309	3,058,626
Current liabilities:
Accounts payable	84,193	128,174
Accrued liabilities	227,690	219,769
Accrued royalties	55,051	52,215
Current portion of long-term debt	33,060	0
Current portion of asset retirement obligations	77,581	39,888
Liabilities from price risk management activities	7,305	68,370
Accrued interest payable	42,300	36,340
Current portion of operating lease liabilities	2,666	1,943
Other current liabilities	48,769	60,359
Total current liabilities	578,615	607,058
Long-term liabilities:
Long-term debt	992,614	585,340
Asset retirement obligations	819,645	501,773
Liabilities from price risk management activities	795	7,872
Operating lease liabilities	18,211	14,855
Other long-term liabilities	251,278	176,152
Total liabilities	2,661,158	1,893,050
Commitments and contingencies
Stockholdersʼ Equity:
Preferred stock; $0.01 par value; 30,000,000 shares authorized and zero shares issued or outstanding as of December 31, 2023 and 2022, respectively	0	0
Common stock; $0.01 par value; 270,000,000 shares authorized; 127,480,361 and 82,570,328 shares issued as of December 31, 2023 and 2022, respectively	1,275	826
Additional paid-in capital	2,549,097	1,699,799
Accumulated deficit	(347,717)	(535,049)
Treasury stock, at cost; 3,400,000 and zero shares as of December 31, 2023 and 2022, respectively	(47,504)	0
Total stockholdersʼ equity	2,155,151	1,165,576
Total liabilities and stockholdersʼ equity	$ 4,816,309	$ 3,058,626

CONSOLIDATED BALANCE SHEETS (Pa

CONSOLIDATED BALANCE SHEETS (Parenthetical) - $ / shares	Dec. 31, 2023	Dec. 31, 2022
Statement of Financial Position [Abstract]
Preferred stock, par value	$ 0.01	$ 0.01
Preferred stock, shares authorized	30,000,000	30,000,000
Preferred stock, shares issued	0	0
Preferred stock, shares outstanding	0	0
Common stock, par value	$ 0.01	$ 0.01
Common stock, shares authorized	270,000,000	270,000,000
Common stock, shares issued	127,480,361	82,570,328
Treasury stock, common, shares	3,400,000	0

CONSOLIDATED STATEMENTS OF OPER

CONSOLIDATED STATEMENTS OF OPERATIONS - USD ($) shares in Thousands, $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Revenues:
Total revenues	$ 1,457,886	$ 1,651,980	$ 1,244,540
Operating expenses:
Lease operating expense	389,621	308,092	283,601
Production taxes	2,451	3,488	3,363
Depreciation, depletion and amortization	663,534	414,630	395,994
Write-down of oil and natural gas properties	0	0	18,123
Accretion expense	86,152	55,995	58,129
General and administrative expense	158,493	99,754	78,677
Other operating (income) expense	(52,155)	33,902	32,037
Total operating expenses	1,248,096	915,861	869,924
Operating income (expense)	209,790	736,119	374,616
Interest expense	(173,145)	(125,498)	(133,138)
Price risk management activities income (expense)	80,928	(272,191)	(419,077)
Equity method investment income (expense)	(3,209)	14,222	0
Other income (expense)	12,371	31,800	(6,988)
Net income (loss) before income taxes	126,735	384,452	(184,587)
Income tax benefit (expense)	60,597	(2,537)	1,635
Net income (loss)	$ 187,332	$ 381,915	$ (182,952)
Net income (loss) per common share:
Basic	$ 1.56	$ 4.63	$ (2.24)
Diluted	$ 1.55	$ 4.56	$ (2.24)
Weighted average common shares outstanding:
Basic	119,894	82,454	81,769
Diluted	120,752	83,683	81,769
Oil
Revenues:
Revenues	$ 1,357,732	$ 1,365,148	$ 1,064,161
Natural Gas
Revenues:
Revenues	68,034	227,306	130,616
NGL
Revenues:
Revenues	$ 32,120	$ 59,526	$ 49,763

CONSOLIDATED STATEMENTS OF CHAN

CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS' EQUITY - USD ($) $ in Thousands	Total	Common Stock	Additional Paid-in Capital	Accumulated Deficit	Treasury Stock [Member]
Balance at Dec. 31, 2020	$ 926,601	$ 813	$ 1,659,800	$ (734,012)
Balance, Shares at Dec. 31, 2020		81,279,989
Equity based compensation	20,165		20,165
Equity-based compensation tax withholdings	(3,161)		(3,161)
Equity-based compensation stock issuances		$ 6	(6)
Equity-based compensation stock issuances, shares		601,488
Net Income (Loss)	(182,952)			(182,952)
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	82,570,328
Treasury stock, common, shares	0
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, Shares					3,400,000
Purchase of treasury stock	(47,504)				$ (47,504)
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

CONSOLIDATED STATEMENTS OF CASH

CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Cash flows from operating activities:
Net income (loss)	$ 187,332	$ 381,915	$ (182,952)
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities
Depreciation, depletion, amortization and accretion expense	749,686	470,625	454,123
Write-down of oil and natural gas properties and other well equipment	0	0	23,729
Amortization of discount, premium and deferred financing costs	15,039	14,379	13,382
Equity-based compensation expense	12,953	15,953	10,992
Price risk management activities (income) expense	(80,928)	272,191	419,077
Net cash received (paid) on settled derivative instruments	(9,457)	(425,559)	(290,164)
Equity method investment (income) expense	3,209	(14,222)	0
Loss (gain) on extinguishment of debt	0	1,569	13,225
Settlement of asset retirement obligations	(86,615)	(69,596)	(67,988)
Gain (loss) on sale of assets	(66,115)	303	(687)
Changes in operating assets and liabilities:
Accounts receivable	20,352	14,927	(35,396)
Other current assets	7,066	(36,545)	(18,901)
Accounts payable	(60,401)	24,258	(6,261)
Other current liabilities	(96,960)	73,531	64,800
Other non-current assets and liabilities, net	(76,092)	(13,990)	14,409
Net cash provided by (used in) operating activities	519,069	709,739	411,388
Cash flows from investing activities:
Exploration, development and other capital expenditures	(561,434)	(323,164)	(293,331)
Proceeds from (cash paid for) acquisitions, net of cash acquired	17,617
Proceeds from (cash paid for) acquisitions, net of cash acquired		(3,500)	(5,399)
Proceeds from (cash paid for) sale of property and equipment, net	73,004	1,937	4,983
Contributions to equity method investees	(29,447)	(2,250)	0
Investment in intangible assets	(12,366)	0	0
Proceeds from sale of equity method investment	0	15,000	0
Net cash provided by (used in) investing activities	(512,626)	(311,977)	(293,747)
Cash flows from financing activities:
Issuance of senior notes	0	0	600,500
Redemption of senior notes	(30,000)	(18,184)	(356,803)
Proceeds from Bank Credit Facility	825,000	85,000	100,000
Repayment of Bank Credit Facility	(625,000)	(460,000)	(365,000)
Deferred financing costs	(11,775)	(189)	(27,833)
Other deferred payments	(1,545)	0	(7,921)
Payments of finance lease	(16,306)	(25,493)	(21,804)
Purchase of treasury stock	(47,504)	0	0
Employee stock awards tax withholdings	(7,459)	(4,603)	(3,161)
Net cash provided by (used in) financing activities	85,411	(423,469)	(82,022)
Net increase (decrease) in cash, cash equivalents and restricted cash	91,854	(25,707)	35,619
Cash, cash equivalents and restricted cash:
Balance, beginning of period	44,145	69,852	34,233
Balance, end of period	135,999	44,145	69,852
Supplemental non-cash transactions:
Capital expenditures included in accounts payable and accrued liabilities	114,972	105,773	45,761
Supplemental cash flow information:
Interest paid, net of amounts capitalized	$ 130,313	$ 91,809	$ 68,891

Pay vs Performance Disclosure

Pay vs Performance Disclosure - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Pay vs Performance Disclosure
Net Income (Loss)	$ 187,332	$ 381,915	$ (182,952)

Insider Trading Arrangements

Insider Trading Arrangements	3 Months Ended
	Dec. 31, 2023
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

Organization, Nature of Busines

Organization, Nature of Business and Basis of Presentation	12 Months Ended
	Dec. 31, 2023
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 independent exploration and production company focused on safely and efficiently maximizing long-term value through its operations, currently in the United States (“U.S.”) and offshore Mexico both through upstream oil and gas exploration and production and the development of low carbon solutions opportunities. The Company leverages decades of technical and offshore operational expertise in the acquisition, exploration and development of assets in key geological trends that are present in many offshore basins around the world. The Company is also utilizing its expertise to develop CCS projects to help reduce industrial emissions along the coast of the U.S. Gulf of Mexico. Basis of Presentation and Consolidation The Consolidated Financial Statements have been prepared in accordance with GAAP and include the accounts of the Parent Company and entities in which the Parent Company holds a controlling financial interest. Both majority-owned subsidiaries and any variable interest entity in which the Parent Company is the primary beneficiary are consolidated. 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 The Company has two operating segments: (i) exploration and production of oil, natural gas and NGLs (“Upstream Segment”) and (ii) CCS (“CCS Segment”). The Upstream Segment is the Company’s only reportable segment. The legal entities included in the CCS Segment have been 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 15 — Segment Information. Recently Issued Accounting Standards Segment Reporting — In November 2023, the Financial Accounting Standards Board (“FASB”) issued an update to the required disclosures for segment reporting. The update is intended to improve reportable segment disclosures, primarily through enhanced disclosures about significant segment expenses. The update will require public entities to disclose significant segment expenses that are regularly provided to the chief operating decision maker and included within segment profit and loss. The update is effective for fiscal years beginning after December 15, 2023, and interim periods within fiscal years beginning after December 15, 2024 on a retrospective basis. Early adoption is permitted. The Company is currently evaluating the effect of this update on the Company’s disclosures. 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 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 is currently evaluating the effect of this update on the Company’s disclosures.

Summary of Significant Accounti

Summary of Significant Accounting Policies	12 Months Ended
	Dec. 31, 2023
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. Cash and cash equivalents are carried at cost, which approximates fair value. 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, 2023 and 2022 , the Company had allowances of $ 8.8 million and $ 10.7 million, respectively, presented net in accounts receivable on the Consolidated Balance Sheets. Price Risk Management Activities — The Company uses commodity price derivatives to manage fluctuating oil and natural gas market risks. The Company periodically enters into commodity derivative contracts, which may require payments to (or receipts from) counterparties based on the differential between a fixed price and a variable price for a fixed quantity of oil or natural gas without the exchange of underlying volumes. Commodity derivatives are recorded on the Consolidated Balance Sheets at fair value with settlements of such contracts and changes in the unrealized fair value recorded in earnings each period. Realized gains and losses on the settlement of commodity derivatives and changes in their unrealized gains and losses are reported in “Price risk management activities income (expense)” on the Consolidated Statements of Operations. The Company classifies cash flows related to derivative contracts based on the nature and purpose of the derivative. As the derivative cash flows 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 then 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, 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 costs directly related to acquisition, 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. For investments in a limited partnership or unincorporated joint venture and a limited liability company or partnership that maintains a specific ownership account for each investor, a voting percentage of 3 - 5 % or more is generally presumed to demonstrate significant influence. Equity method accounting for interests in limited partnerships is generally appropriate unless the interest is so minor that the investor has virtually no influence (less than 3 %). 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, 2023, 2022 and 2021 . 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 (as defined herein), 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. 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. 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 when production on those wells is exhausted, when the Company no longer plans to use them or when the Company abandons them. The Company accrues a liability with respect to these obligations based on its estimate of the timing and amount to replace, remove or retire 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 14 — 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 10 — 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 upon vesting 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 upon vesting 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. ONRR Federal Royalty Refund — Included within “Other operating (income) expense” on the Consolidated Statements of Operations is income from the Company’s multi-year federal royalty refund claim from the ONRR. The Company records income when a refund is filed and its collection is reasonably assured. 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, PSUs and outstanding warrants. See Note 12 — 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 substantially 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 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, 2023 2022 2021 Shell Trading (US) Company 54 % 44 % 45 % Valero Energy Corporation 21 % 23 % ** Chevron Products Company ** 11 % 29 % ** 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, 2023 2022 Cash and cash equivalents $ 33,637 $ 44,145 Restricted cash included in Other long-term assets 102,362 — Total cash, cash equivalent and restricted cash $ 135,999 $ 44,145

Acquisitions and Divestitures

Acquisitions and Divestitures	12 Months Ended
	Dec. 31, 2023
Business Combinations [Abstract]
Acquisitions and Divestitures	Note 3 — Acquisitions and Divestitures 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. 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 Mexico (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 the five-year NYMEX forward strip prices, escalated for inflation thereafter, 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 10 — 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): Year Ended December 31, 2023 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. Supplemental pro forma earnings for the year ended December 31, 2023 were adjusted to exclude $ 65.1 million of general and administrative expenses. This information does not purport to be indicative of results of operations that would have occurred had the EnVen Acquisition occurred on January 1, 2022, nor is such information indicative of any expected future results of operations (in thousands, except for the per share data). Year Ended December 31, 2023 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 Subsequent Event QuarterNorth Acquisition — On January 13, 2024 , the Company executed a merger agreement to acquire QuarterNorth Energy Inc. (“QuarterNorth,” and such acquisition, the “QuarterNorth Acquisition”), a privately-held U.S. Gulf of Mexico exploration and production company. The QuarterNorth Acquisition is expected to close during the first quarter of 2024. Consideration for the QuarterNorth Acquisition primarily consists of (i) approximately $ 964.9 million in cash, (ii) the amount of net unrestricted cash of QuarterNorth as of December 31, 2023 and (iii) 24.8 million shares of the Company’s common stock. Divestiture 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., a wholly owned subsidiary of Grupo Carso, for $ 74.9 million in cash consideration with an additional $ 49.9 million contingent on first oil production from the Zama Field (the “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, holds a 17.4 % unitized interest in the Zama Field. As a result of the 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 Mexico Divestiture, which was an orderly transaction between market participants. A gain of $ 66.2 million was recognized on the Mexico Divestiture during the year ended December 31, 2023 which is included in “Other operating (income) expense” on the Consolidated Statements of Operations.

Property, Plant and Equipment

Property, Plant and Equipment	12 Months Ended
	Dec. 31, 2023
Oil and Gas Property [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 Mexico deep and shallow waters. During 2023, 2022 and 2021 , the Company’s ceiling test computations did no t result in a write-down of its U.S. oil and natural gas properties. At December 31, 2023, its ceiling test computation was based on SEC pricing of $ 78.56 per Bbl of oil, $ 2.75 per Mcf of natural gas and $ 18.77 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 Mexico federal lease sales, certain geological and geophysical costs, expenditures associated with certain exploratory wells in progress and capitalized interest. During the year ended December 31, 2023 , the Company derecognized $ 112.3 million of unproved properties associated with the exploration and appraisal activities in Block 7 located in the shallow waters off the coast of Mexico’s Tabasco state. See Note 3 — Acquisitions and Divestitures for additional discussion. During the year ended December 31, 2021, the Company’s evaluation of unproved property located offshore Mexico resulted in a non-cash impairment of $ 18.1 million presented as “Write-down of oil and natural gas properties” on the Consolidated Statements of Operations. The non-cash impairment was primarily attributable to the Company’s operations in offshore Mexico in Block 31 associated with the Company’s non-consent of the proposed appraisal plan during the fourth quarter of 2021. The following table sets forth a summary of the Company’s oil and natural gas property costs not being amortized at December 31, 2023, by the year in which such costs were incurred (in thousands): Year Ended December 31, Total 2023 2022 2021 2020 and Prior Acquisition United States $ 249,799 $ 229,216 $ — $ — $ 20,583 Exploration United States 18,516 10,108 1,299 2,295 4,814 Total unproved properties, not subject to amortization $ 268,315 $ 239,324 $ 1,299 $ 2,295 $ 25,397 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 eight years.

Leases

Leases	12 Months Ended
	Dec. 31, 2023
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. 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. Costs associated with the Company’s leases are either expensed or capitalized depending on how the underlying asset is utilized. In November 2022, the Company exercised its option to extend the lease of the HP-I through June 1, 2024. The extension resulted in a remeasurement of the lease liability to $ 166.3 million and corresponding adjustment to proved property. 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, 2023 2022 2021 Finance lease cost - interest on lease liabilities $ 14,476 $ 7,558 $ 11,453 Operating lease cost, excluding short-term leases (1) 4,883 2,281 2,706 Short-term lease cost (2) 117,132 55,072 38,472 Variable lease cost (3) 2,888 1,450 1,356 Variable and fixed sublease income ( 482 ) — — Total lease cost $ 138,897 $ 66,361 $ 53,987 (1) Operating lease cost 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, 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, 2023 2022 Operating leases: Operating lease assets $ 11,418 $ 5,903 Current portion of operating lease liabilities $ 2,666 $ 1,943 Operating lease liabilities 18,211 14,855 Total operating lease liabilities $ 20,877 $ 16,798 Finance leases: Proved properties $ 166,261 $ 166,261 Other current liabilities $ 17,834 $ 16,306 Other long-term liabilities 131,230 149,064 Total finance lease liabilities $ 149,064 $ 165,370 The table below presents the lease maturity by year as of December 31, 2023 (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 2024 $ 4,748 $ 30,782 2025 4,716 30,782 2026 4,803 30,782 2027 4,708 30,782 2028 4,610 30,782 Thereafter 4,584 43,608 Total lease payments $ 28,169 $ 197,518 Imputed interest ( 7,292 ) ( 48,454 ) Total lease liabilities $ 20,877 $ 149,064 The table below presents the weighted average remaining lease term and discount rate related to leases: Year Ended December 31, 2023 2022 2021 Weighted average remaining lease term: Operating leases 5.9 years 6.4 years 7.4 years Finance leases 6.4 years 7.4 years 1.4 years Weighted average discount rate: Operating leases 10.8 % 11.8 % 11.9 % Finance leases 9.2 % 9.2 % 21.9 % The table below presents the supplemental cash flow information related to leases (in thousands): Year Ended December 31, 2023 2022 2021 Operating cash outflow from finance leases $ 14,476 $ 7,181 $ 11,453 Operating cash outflow from operating leases $ 6,318 $ 3,722 $ 3,864 ROU assets obtained in exchange for new finance lease liabilities $ — $ 166,261 $ — ROU assets obtained in exchange for new operating lease liabilities (1) $ 12,971 $ 474 $ 1,020 Remeasurement of lease liability arising from modification of ROU asset (2) $ ( 5,124 ) $ — $ — (1) See EnVen Acquisition 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.

Financial Instruments

Financial Instruments	12 Months Ended
	Dec. 31, 2023
Financial Instruments [Abstract]
Financial Instruments	Note 6 — Financial Instruments As of December 31, 2023 and 2022, 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, 2023 December 31, 2022 Carrying Fair Carrying Fair 12.00 % Second-Priority Senior Secured Notes – due January 2026 $ 601,353 $ 655,130 $ 590,132 $ 674,542 11.75 % Senior Secured Second Lien Notes – due April 2026 $ 234,221 $ 233,410 $ — $ — Bank Credit Facility – matures March 2027 $ 190,100 $ 200,000 $ ( 4,792 ) $ — 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 carrying amount of the Company’s bank credit facility, as amended and restated (the “Bank Credit Facility”), is presented net of deferred financing costs. 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. In connection with the EnVen Acquisition, the Company assumed oil and natural gas collar contracts that combine a two-way collar with a short put that holds an exercise price below the floor price (“three-way collar”). In these contracts, when the NYMEX average closing price is below the floor price, the Company receives the difference between the NYMEX average closing price and the floor price, capped at the difference between the floor price and the short put 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, 2023 2022 2021 Net cash received (paid) on settled derivative instruments $ ( 9,457 ) $ ( 425,559 ) $ ( 290,164 ) Unrealized gain (loss) (1) 90,385 153,368 ( 128,913 ) Price risk management activities income (expense) $ 80,928 $ ( 272,191 ) $ ( 419,077 ) (1) Includes $ 1.4 million gain from the unrealized derivative instruments acquired from the EnVen Acquisition for the year ended December 31, 2023 . 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, 2023: Swap Contracts Production Period Settlement Index Volumes Swap Price Crude oil: (Bbls) (per Bbl) January 2024 – December 2024 NYMEX WTI CMA 16,859 $ 74.30 January 2025 – December 2025 NYMEX WTI CMA 7,734 $ 73.80 Natural gas: (MMBtu) (per MMBtu) January 2024 – December 2024 NYMEX Henry Hub 18,716 $ 3.41 January 2025 – December 2025 NYMEX Henry Hub 13,712 $ 3.92 Two-Way Collar Contracts Production Period Settlement Index Volumes Floor Price Ceiling Price Crude oil: (Bbls) (per Bbl) (per Bbl) January 2024 – December 2024 NYMEX WTI CMA 1,497 $ 70.00 $ 79.32 Natural gas: (MMBtu) (per MMBtu) (per MMBtu) January 2024 – December 2024 NYMEX Henry Hub 10,000 $ 4.00 $ 6.90 Three-Way Collar Contracts Production Period Settlement Index Volumes Short Put Price Floor Price Ceiling Price Crude oil: (Bbls) (per Bbl) (per Bbl) (per Bbl) January 2024 – March 2024 NYMEX WTI CMA 3,200 $ 57.27 $ 70.00 $ 98.01 The following tables provide additional information related to financial instruments measured at fair value on a recurring basis (in thousands): 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 December 31, 2022 Level 1 Level 2 Level 3 Total Assets: Oil and natural gas derivatives $ — $ 32,883 $ — $ 32,883 Liabilities: Oil and natural gas derivatives — ( 76,242 ) — ( 76,242 ) Total net asset (liability) $ — $ ( 43,359 ) $ — $ ( 43,359 ) 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, 2023 December 31, 2022 Assets Liabilities Assets Liabilities Oil and natural gas derivatives: Current $ 36,152 $ 7,305 $ 25,029 $ 68,370 Non-current 17,551 795 7,854 7,872 Total gross amounts presented on balance sheet 53,703 8,100 32,883 76,242 Less: Gross amounts not offset on the balance sheet 8,100 8,100 32,883 32,883 Net amounts $ 45,603 $ — $ — $ 43,359 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, 2023 represent derivative instruments from nine 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 eight of which 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, 2023 would have been $ 45.6 million.

Equity Method Investments

Equity Method Investments	12 Months Ended
	Dec. 31, 2023
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, 2023 2023 2022 Upstream: Talos Energy Mexico 7, S. de R.L. de C.V 50.1 % $ 107,259 $ — SP 49 Pipeline LLC 33.3 % 861 374 CCS: Bayou Bend CCS LLC 25.0 % 28,183 1,371 Harvest Bend CCS LLC 65.0 % 9,746 — Coastal Bend CCS LLC 50.0 % — — Total Equity Method Investments $ 146,049 $ 1,745 Talos Energy Mexico 7, S. de R.L. de C.V. S ee 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. 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”). Bayou Bend has a CCS site that is in the early stages of development located offshore Jefferson County, Texas, near the Beaumont and Port Arthur, Texas industrial corridor. 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. Effective March 1, 2023, Chevron became the operator of Bayou Bend. During March 2023, Bayou Bend expanded its storage footprint through the acquisition of onshore acreage in Chambers and Jefferson Counties, Texas located within the Houston Ship Channel, Beaumont and Port Arthur region. VIE Disclosures VIE and Primary Beneficiary Determination — Talos Mexico, Bayou Bend, Harvest Bend CCS LLC (“Harvest Bend”), and Coastal Bend CCS LLC (“Coastal Bend”) were each determined to be a VIE. Neither Talos Mexico, Bayou Bend, Harvest Bend, nor Coastal Bend had sufficient equity at risk to finance their respective activities without additional subordinated financial support. The Company is not the primary beneficiary of these VIE’s due to the governance structure of these entities. The most significant activities of these entities are jointly controlled by the owners. The level of the Company’s economic interest in Harvest Bend is not indicative of the amount of power held. Financings — All of the Company’s VIE’s have historically been funded through equity contributions from owners. Maximum Exposure — The Company’s maximum exposure to loss as result of its involvement with VIE’s is the carrying amount of each 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. The successful development of our CCS projects is dependent on various economic, regulatory, operational and technical factors. The failure to satisfy, wholly or in a significant measure, any of such factors could have a material adverse impact on the Company’s business, results of operations and financial condition. For example, successful development of CCS projects in the United States requires compliance with stringent and varied regulatory schemes including obtaining Class VI well permits that are applicable to subsurface injection of CO 2 for geologic sequestration. Locating a suitable source of anthropogenic CO 2 and reaching suitable agreements to capture that CO 2 is crucial. Infrastructure to transport CO 2 between the source and CCS project sites is also required. In project areas with existing CO 2 transportation pipelines, reaching an agreement on CO 2 transportation with operators of such pipelines will be necessary. Inability to reach a suitable agreement may render a project uneconomic or impracticable. Separately, if no CO 2 pipelines exist in proposed project areas, or if existing pipelines do not extend to one or more of the Company’s project sites, conversion of existing pipelines or construction of new pipelines or lateral connections will be required, which may render one or more projects uneconomic. Given the capital-intensive nature of CCS projects, project finance plays a critical role in accelerating the development of the Company’s projects. If the Company is unable to obtain acceptable financing for its CCS projects, then it could result in significant delays in the development and construction of such projects. Lastly, the development of CCS projects is incentivized by tax credits provided under Section 45Q of the Internal Revenue Code of 1986, as amended. The Company’s inability to benefit from such tax credits could prevent the development of the Company’s projects.

Debt

Debt	12 Months Ended
	Dec. 31, 2023
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): Year Ended December 31, 2023 2022 12.00 % Second-Priority Senior Secured Notes – due January 2026 $ 638,541 $ 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 1,066,041 638,541 Unamortized discount, premium and deferred financing cost, net ( 40,367 ) ( 53,201 ) Total debt 1,025,674 585,340 Less: Current portion of long-term debt 33,060 — Long-term debt $ 992,614 $ 585,340 12.00% Second-Priority Senior Secured Notes The 12.00% Second-Priority Senior Secured Notes due 2026 (the “ 12.00 % Notes”) were issued pursuant to an indenture dated January 4, 2021 and the first supplemental indenture dated January 14, 2021 between the Parent Company (the “Parent Guarantor”), Talos Production Inc. (the “Issuer”), and certain of the Issuer's subsidiaries (the “Subsidiary Guarantors” and, together with the Parent Guarantor, the “Guarantors”) and Wilmington Trust, National Association, as trustee and collateral agent. The 12.00 % Notes rank pari passu in right of payment and constitute a single class of securities for all purposes under the indentures. The 12.00% Notes are fully and unconditionally guaranteed, jointly and severally, on a senior unsecured basis by the Parent Guarantor and on a second-priority senior secured basis by each of the Subsidiary Guarantors and will be unconditionally guaranteed on the same basis by certain of the Issuer’s future subsidiaries. The 12.00% Notes are secured on a second-priority 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 12.00 % Notes mature January 15, 2026 and have interest payable semi-annually each January 15 and July 15 . The Company may redeem all or a portion of the 12.00% Notes in whole at any time or in part from time to time at the following redemption prices (expressed as percentages of principal amount) plus accrued and unpaid interest if redeemed during the period commencing on January 15 of the years set forth below : Period Redemption Price 2023 106.000 % 2024 103.000 % 2025 and thereafter 100.000 % The indenture governing the 12.00% Notes applies certain limitations on the Company’s ability and the ability of its subsidiaries to, among other things, (i) incur, assume or guarantee additional indebtedness or issue certain convertible or redeemable equity securities; (ii) create liens to secure indebtedness; (iii) pay distributions on equity interests, repurchase equity securities or redeem junior lien, unsecured or subordinated indebtedness; (iv) make investments; (v) restrict distributions, loans or other asset transfers from Talos Production Inc.’s restricted subsidiaries; (vi) consolidate with or merge with or into, or sell substantially all of Talos Production Inc.’s properties to, another person; (vii) sell or otherwise dispose of assets, including equity interests in subsidiaries; and (viii) enter into transactions with affiliates. The 12.00 % Notes contain customary quarterly and annual reporting, financial and administrative covenants. The Company was in compliance with all debt covenants at December 31, 2023. The Issuer initiated a notes consent solicitation on October 21, 2022, to obtain the requisite holders’ consent to certain amendments to the indenture governing the Issuer’s 12.00 % Notes to permit the incurrence of indebtedness in respect of the 11.75 % Senior Secured Second Lien Notes due 2026 of EnVen (the “Notes Consent Solicitation”). The Notes Consent Solicitation expired on October 27, 2022, with holders of 95.8 % of the aggregate principal amount of the 12.00% Notes outstanding consenting. As a result, the Issuer entered into a second supplemental indenture to the base indenture on October 27, 2022 , which became effective upon its execution. The Issuer offered holders of the 12.00% Notes consideration equal to 50 basis points times the principal amount of the 12.00% Notes held by such consenting holder (“Consent Fee”). On February 13, 2023, the Issuer paid the Consent Fee of approximately $ 3.1 million in the aggregate in connection with the EnVen Acquisition. 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. Subsequent Event — On January 23, 2024, the Company issued a conditional notice to redeem in full the 12.00 % Notes at a redemption price of 103.00 % of the principal amount thereof, plus accrued and unpaid interest to, but excluding, the redemption date, in accordance with the 12.00% Notes indenture. The 12.00% Notes were redeemed on February 7, 2024 for $ 662.4 million utilizing the net proceeds from the Debt Offering (as defined below). 11.75% Senior Secured Second Lien Notes On February 13, 2023 , in conjunction with the closing of the EnVen Acquisition, the Company assumed EnVen’s 11.75 % Senior Secured Second Lien Notes due 2026 (the “11.75% Notes”) with a principal amount of $ 257.5 million. The 11.75% Notes mature on April 15, 2026 and interest accrues and is to be paid semi-annually in cash in arrears on April 15th and October 15th of each year. The indenture governing the 11.75% Notes requires the redemption of $ 15.0 million of the principal amount outstanding at par value on April 15th and October 15th of each year. The Company may redeem all or a portion of the 11.75% Notes in whole at any time or in part from time to time at the following redemption prices (expressed as percentages of principal amount) plus accrued and unpaid interest if redeemed during the period commencing on February 15 of the years set forth below: Period Redemption Price 2023 105.875 % 2024 102.938 % 2025 and thereafter 100.000 % The 11.75% Notes are governed by an indenture by and among Energy Ventures GoM LLC, EnVen Finance Corporation as co-issuers, the guarantors party thereto and Wilmington Trust, National Association as trustee and collateral agent, dated as of April 15, 2021 (“11.75% Notes Indenture”). Talos Production Inc. and certain of its subsidiaries entered into a supplemental indenture to the 11.75% Notes Indenture which, inter alia, provides for the assumption of the indebtedness in respect of the 11.75% Notes by Talos Production Inc., as well as guarantees of such indebtedness by certain subsidiaries of Talos Production Inc., as contemplated by the terms of the 11.75% Notes Indenture. The 11.75% Notes Indenture contains certain covenants, which are customary with respect to non-investment grade debt securities, including limitations on the Company’s ability to incur and guarantee additional indebtedness, repay, redeem, or repurchase certain debt and capital stock, issue certain preferred stock or similar equity securities, pay dividends or make other distributions on capital stock, enter into certain types of transactions with affiliates, make loans or investments, and make other restricted payments. Additionally, certain covenants restrict Talos Production Inc. subsidiaries’ ability to pay dividends, create liens, and sell certain assets. Subsequent Event — On January 26, 2024, the Company issued a conditional notice to redeem in full the 11.75 % Notes at a redemption price of 102.938 % of the principal amount thereof, plus accrued and unpaid interest to, but excluding, the redemption date, in accordance with the 11.75% Notes Indenture. The Company irrevocably deposited funds with the trustee sufficient to satisfy and discharge the 11.75% Notes Indenture and the 11.75% Notes until redeemed on April 15, 2024 with the funds deposited with the trustee and elected to satisfy and discharge the 11.75% Notes Indenture in accordance with its terms and the 11.75% Notes trustee acknowledged such discharge and satisfaction. The Company deposited $ 247.5 million with the trustee on February 7, 2024 utilizing the net proceeds from the Debt Offering. 11.00% Second-Priority Senior Secured Notes On January 13, 2021, the Company redeemed $ 347.3 million aggregate principal amount of the 11.00 % Second-Priority Senior Secured Notes due 2022 (the “11.00% Notes”) at 102.75 % plus accrued and unpaid interest using the proceeds from the issuance of the 12.00% Notes. The debt redemption resulted in a loss on extinguishment of debt of $ 13.2 million for the year ended December 31, 2021, which is included in “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 a Bank Credit Facility with a syndicate of financial institutions. The Bank Credit Facility provides for the determination of the borrowing base based on the Company’s proved producing reserves and a portion of the Company's proved undeveloped reserves. The borrowing base is redetermined by the lenders at least semi-annually during the second quarter and fourth quarter of each year. On December 23, 2022, the Company entered into the Incremental Agreement and Ninth Amendment to Credit Agreement (the “Ninth Amendment”). The Ninth Amendment, among other things, (i) extended the maturity date of the Bank Credit Facility from November 12, 2024 to March 31, 2027 , (ii) increased the borrowing base from $ 1.1 billion to $ 1.5 billion and (iii) increased commitments from $ 806.3 million to $ 965.0 million, in each case went into effect upon the closing of the EnVen Acquisition and the occurrence of certain events related thereto. On June 9, 2023, the borrowing base decreased from $ 1.5 billion to $ 1.1 billion and commitments were reaffirmed at $ 965.0 million as part of the biannual determination. The Bank Credit Facility no longer bears interest at the applicable London InterBank Offered Rate plus the applicable margin. 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 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, 2023, the Company's borrowing base was $ 1,075.0 million with total commitments of $ 965.0 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, 2023. As of December 31, 2023 , the Company had outstanding borrowings at a weighted average interest rate of 8.26 %. See Note 14 — Commitments and Contingencies for the amount of letters of credit issued under the Bank Credit Facility as of December 31, 2023. Subsequent Event — On January 13, 2024, the Company entered into the Tenth Amendment to Credit Agreement (the “Tenth Amendment”). The Tenth Amendment, among other things, (i) permits the incurrence of additional indebtedness in order to fund the QuarterNorth Acquisition, with such indebtedness excluded from any reduction of the borrowing base that would otherwise result from such incurrence, and (ii) reaffirms the borrowing base at $ 1.1 billion effective upon closing of the QuarterNorth Acquisition. 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, 2023 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, the indenture governing the 12.00% Notes restricts the Company’s consolidated 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 indenture. 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 2.25 to 1.00, (iii) the ratio of the issuer’s total debt to EBITDA 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. The indenture governing the 11.75% Notes contains a similar restriction on the Company and its consolidated subsidiaries’ ability to declare or pay dividends, subject to exceptions which include, among other things, (i) subject to no default or event of default having occurred or continuing, dividends in an aggregate amount not to exceed the greater of $ 25 million and 2.5 % of Adjusted Consolidated Net Tangible Assets, (ii) dividends or distributions to any parent company to make payments, in lieu of issuing fractional shares in connection with share dividends, share splits, reverse share splits, mergers, consolidations, amalgamations or other business combinations and in connection with the exercise of warrants, options or other securities convertible into or exchangeable for equity interests of the Company. At December 31, 2023 , restricted net assets of the Company’s consolidated subsidiaries exceeded 25 %. Subsequent Event — Debt Offering On February 7, 2024, the Company closed an upsized offering (the “Debt Offering”) for the sale of $ 1,250.0 million in aggregate principal amount of second-priority senior secured notes, consisting of $ 625.0 million aggregate principal amount of second-priority senior secured notes due 2029 and $ 625.0 million aggregate principal amount of second-priority senior secured notes due 2031 (collectively, the “New Senior Notes”), in a private offering to eligible purchasers that is exempt from registration under the Securities Act. The net proceeds from the Debt Offering (i) are expected to fund a portion of the cash consideration for the pending QuarterNorth Acquisition, (ii) funded the redemption of all of the outstanding 12.00% Notes and all of the outstanding 11.75% Notes discussed above (the “Redemptions”), and (iii) paid premiums, fees and expenses related to the Redemptions and the issuance of the New Senior Notes. The Company intends to use any remaining net proceeds for general corporate purposes, which may include the repayment of a portion of the outstanding borrowings under the Bank Credit Facility. An aggregate of $ 340.0 million principal amount of the New Senior Notes will be subject to a “special mandatory redemption” in the event that the transactions contemplated by the QuarterNorth Merger Agreement are not consummated on or before May 31, 2024 (or up to September 30, 2024 solely in the event the parties require additional time to satisfy certain requirements under the Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended, pursuant to the terms of the QuarterNorth Merger Agreement), or if we notify the trustee of the New Senior Notes that we will not pursue the consummation of the QuarterNorth Acquisition.

Asset Retirement Obligations

Asset Retirement Obligations	12 Months Ended
	Dec. 31, 2023
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, 2023 2022 Balance, beginning of period $ 541,661 $ 434,006 Obligations assumed (1) 258,858 — Obligations incurred 14,199 1,140 Obligations settled ( 86,615 ) ( 69,596 ) Obligations divested ( 19,448 ) ( 1,572 ) Accretion expense 86,152 55,995 Changes in estimate (2) 102,419 121,688 Balance, end of period $ 897,226 $ 541,661 Less: Current portion 77,581 39,888 Long-term portion $ 819,645 $ 501,773 (1) Assumed in connection with the EnVen Acquisition. See further discussion in Note 3 — Acquisitions and Divestitures . (2) Changes in estimate were primarily due to an increase in estimated service costs. Additionally, increases for the year ended December 31, 2023 due to the acceleration of estimated settlement date. At December 31, 2023, the Company has (1) restricted cash of $ 102.4 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 .

Employee Benefits Plans and Sha

Employee Benefits Plans and Share-Based Compensation	12 Months Ended
	Dec. 31, 2023
Share-Based Payment Arrangement [Abstract]
Employee Benefits Plans and Share-Based Compensation	Note 10 — Employee Benefits Plans and Share-Based Compensation EnVen Acquisition Severance The following table summarizes severance accrual activity in connection with the EnVen Acquisition included in “Other current liabilities” and “Other long-term liabilities” on the Consolidated Balance Sheets as of December 31, 2023 (in thousands): Severance accrual at December 31, 2022 $ — Accrual additions 25,348 Benefit payments ( 19,054 ) Severance accrual at December 31, 2023 6,294 Less: Current portion at December 31, 2023 6,190 Long-term portion at December 31, 2023 $ 104 The above table includes involuntary termination benefits that are being provided pursuant to a one-time benefit arrangement that is being spread 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 employee agreements. Pursuant to the EnVen Merger Agreement, a rabbi trust was established and funded with $ 14.5 million at closing to pay a portion of future severance benefits associated with the contractual termination benefits. As of December 31, 2023 , the rabbi trust held $ 3.7 million in assets of which $ 3.3 million and $ 0.4 million are included in “Other current assets” and “Other assets,” respectively, on the Consolidated Balance Sheets and both of which are included in the severance accrual at December 31, 2023 listed above. The assets of the rabbi trust are available to satisfy the claims of our creditors in the event of bankruptcy or insolvency. Severance costs are reflected in “General and administrative expense” on the Consolidated Statement of Operations. Long Term Incentive Plans On May 11, 2021, the Company’s stockholders approved the Talos Energy Inc. 2021 Long Term Incentive Plan (the “2021 LTIP”), which had previously been approved by the board of directors of the Company. No further awards will be granted under the Talos Energy Inc. Long Term Incentive Plan (the “2018 LTIP”) (together with the 2021 LTIP, the “LTIP Plans”). The 2021 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 consultants of the Company and its affiliates are eligible to receive awards under the 2021 LTIP. The 2021 LTIP authorizes the Company to grant awards of up to 8,639,415 shares of the Company’s common stock, subject to the share counting and share recycling provisions of the 2021 LTIP. Restricted Stock Units – Employees — RSUs granted to employees under the LTIP Plans 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, 2023 was approximately $ 19.0 million, which is expected to be recognized over a weighted average period of 1.7 years. Restricted Stock Units – Non-employee Directors — RSUs granted to non-employee directors under the LTIP Plans vested approximately one year following the date of grant, subject to such non-employee director’s continued service through the vesting date. Upon vesting, these RSUs represent a contingent right to receive one share of common stock for each RSU for 60 %, and cash for the remaining 40 %. The total unrecognized share-based compensation expense related to these RSUs at December 31, 2023 was approximately $ 0.1 million, which is expected to be recognized over a weighted average period of 0.2 years. Of the unrecognized share-based compensation expense, $ 0.1 million relates to liability awards and will be subsequently remeasured at each reporting period. The following table summarizes RSU activity: Restricted Weighted Average Unvested RSUs at December 31, 2020 1,652,988 $ 13.73 Granted 1,102,038 $ 13.11 Vested ( 669,832 ) $ 15.01 Forfeited ( 101,995 ) $ 12.46 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 (1) 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 (1) As of December 31, 2023 and 2022 , 26,975 and 25,257 , respectively, of the unvested RSUs were accounted for as liability awards in “Accrued liabilities” on the Consolidated Balance Sheet. The Company considers its intent and ability to settle awards in cash or shares in determining whether to classify the awards as equity or as a liability. Certain awards granted during the year ended December 31, 2021 were originally classified as liability awards; however, these awards became equity-classified awards upon stockholder approval of the 2021 LTIP. The aggregate amount of compensation cost related to these awards is determined by the fair value of the award on the modification date. Performance Share Units – Employees — PSUs granted to employees under the LTIP Plans represent the contingent right to receive one share of common stock. However, the number of shares of common stock issuable upon vesting 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, 2023 was approximately $ 8.7 million, which is expected to be recognized over a weighted average period of 1.7 years. The following table summarizes PSU activity: Performance Weighted Average Unvested PSUs at December 31, 2020 834,172 $ 25.46 Granted 586,995 $ 18.96 Vested ( 391,308 ) $ 39.43 Forfeited ( 14,400 ) $ 18.48 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 (1) There were 314,833 PSUs granted that are eligible to vest based on continued employment and the Company’s annualized absolute total shareholder return (“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 will again be available for new awards under the recycling provisions of the 2021 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. Certain awards granted during the year ended December 31, 2021 were originally classified as liability awards; however, these awards became equity-classified awards upon stockholder approval of the 2021 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 and modified at the date indicated: 2023 2022 2021 Grant Grant Grant Grant Grant Modification Grant December 1 July 1 March 5 September 20 March 5 May 11 March 8 Expected term (in years) 2.1 2.5 2.8 2.3 2.8 2.6 2.8 Expected volatility 61.9 % 66.2 % 73.1 % 74.3 % 82.2 % 80.9 % 78.3 % Risk-free interest rate 4.4 % 4.6 % 4.5 % 3.9 % 1.6 % 0.3 % 0.3 % Dividend yield — % — % — % — % — % — % — % Fair value (in thousands) $ 12 $ 173 $ 6,165 $ 621 $ 8,668 $ 9,715 $ 11,129 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 will vest 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 are accounted for as a modification. The incremental cost of $ 9.7 million will be recognized prospectively over the modified requisite service period. Additionally, the remaining unrecognized grant or modification date fair value of the original PSUs will be 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, 2023 2022 2021 Share-based compensation costs $ 25,236 $ 28,280 $ 20,560 Less: Amounts capitalized to oil and gas properties 12,283 12,327 9,568 Total share-based compensation expense $ 12,953 $ 15,953 $ 10,992

Income Taxes

Income Taxes	12 Months Ended
	Dec. 31, 2023
Income Tax Disclosure [Abstract]
Income Taxes	Note 11 — Income Taxes Income Tax Expense (Benefit) The components of income tax expense (benefit) were as follows (in thousands): Year Ended December 31, 2023 2022 2021 Current income tax expense (benefit): United States $ 76 $ 1,375 $ ( 5 ) Mexico 31 432 ( 993 ) Total current income tax expense (benefit) $ 107 $ 1,807 $ ( 998 ) Deferred income tax expense (benefit): United States $ ( 60,704 ) $ 659 $ ( 1,067 ) Mexico — 71 430 Total deferred income tax expense (benefit) $ ( 60,704 ) $ 730 $ ( 637 ) Total income tax expense (benefit) $ ( 60,597 ) $ 2,537 $ ( 1,635 ) 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, 2023 2022 2021 Income tax expense (benefit) at the federal statutory tax rate $ 26,614 $ 80,735 $ ( 38,763 ) State income taxes 1,748 1,591 ( 674 ) Impact of foreign operations 13,539 15,657 ( 11,920 ) Effect of change in state rate — — 2,008 Prior year taxes 1,184 ( 2,920 ) 486 Change in valuation allowance ( 106,815 ) ( 96,537 ) 45,547 Other permanent differences 3,133 4,011 1,681 Total income tax expense (benefit) $ ( 60,597 ) $ 2,537 $ ( 1,635 ) Effective tax rate ( 47.81 )% 0.66 % 0.89 % The Company’s effective tax rate for the year ended December 31, 2023 differed from the federal statutory rate of 21.0 % primarily due to a non-cash tax benefit of $ 106.8 million related to the release of the valuation allowance for its 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 and 2021 differed from the federal statutory rate of 21.0 % primarily due t o recording a full valuation allowance against its federal, state and foreign deferred tax assets. Deferred Tax Assets and Liabilities Net deferred tax assets (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. Significant components of deferred tax assets and liabilities were as follows (in thousands): Year Ended December 31, 2023 2022 Deferred tax assets: Federal net operating loss $ 147,252 $ 159,257 Foreign tax loss carryforward 509 44,462 State net operating loss 24,840 24,787 Tax credits 107 107 Interest expense carryforward 46,414 23,262 Asset retirement obligations 190,248 115,848 Derivatives — 9,273 Other well equipment 1,317 1,891 Accrued bonus 5,050 5,863 Share-based compensation 5,172 5,296 Operating lease liabilities 4,427 3,669 Finance lease liabilities 31,607 32,559 Other 3,383 7,142 Total deferred tax assets 460,326 433,416 Valuation allowance ( 23,697 ) ( 129,105 ) Total deferred tax assets, net $ 436,629 $ 304,311 Deferred tax liabilities: Oil and gas properties $ 512,918 $ 302,602 Operating lease assets 2,421 1,323 Derivatives 9,670 — Prepaid 3,847 2,530 Total deferred tax liabilities 528,856 306,455 Net deferred tax liability $ ( 92,227 ) $ ( 2,144 ) Net Operating Loss The table below presents the details of the Company’s net operating loss carryovers as of December 31, 2023 (in thousands): Amount Expiration Year Federal net operating losses $ 452,393 2035 - 2037 Federal net operating losses $ 248,807 Unlimited Foreign tax loss carryforward $ 1,696 2025 - 2032 State net operating losses $ 125,958 2025 - 2037 State net operating losses $ 277,930 Unlimited As of December 31, 2023, the Company had U.S. federal net operating loss carryforwards (“NOLs”) of approximately $ 701.2 million , all of which are subject to limitation under Section 382 of the IRC. IRC Section 382 provides an annual limitation with respect to the ability of a corporation to utilize its tax attributes, against future U.S. taxable income in the event of a change in o wnership. If not utilized, such carryforwards would begin to expire at the end of 2035 . Valuation Allowance The Company recorded a valuation allowance of $ 23.7 million and $ 129.1 million as of December 31, 2023 and 2022, 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 temporary differences or NOLs 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 is 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. 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, 2023 2022 2021 Total unrecognized tax benefits, beginning balance $ 835 $ 696 $ 648 Increases in unrecognized tax benefits as a result of: Tax positions taken during a prior period 154 100 21 Tax positions taken during the current period — 39 27 Total unrecognized tax benefits, ending balance $ 989 $ 835 $ 696 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 2020 through 2023 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, 2019 are closed, except to the extent of any NOL carryover balance. EnVen Acquisition On February 13, 2023, the Company completed the EnVen Acquisition, which is further discussed in Note 3 — Acquisitions and Divestitures . The Company recognized a net deferred tax liability of $ 150.3 million in its purchase price allocation as of the acquisition date to reflect differences between tax basis and the fair value of EnVen’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.

Income (Loss) Per Share

Income (Loss) Per Share	12 Months Ended
	Dec. 31, 2023
Earnings Per Share [Abstract]
Income (Loss) Per Share	Note 12 — 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, PSUs and outstanding warrants. The warrants expired unexercised on February 28, 2021. 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, 2023 2022 2021 Net income (loss) $ 187,332 $ 381,915 $ ( 182,952 ) Weighted average common shares outstanding — basic 119,894 82,454 81,769 Dilutive effect of securities 858 1,229 — Weighted average common shares outstanding — diluted 120,752 83,683 81,769 Net income (loss) per common share: Basic $ 1.56 $ 4.63 $ ( 2.24 ) Diluted $ 1.55 $ 4.56 $ ( 2.24 ) Anti-dilutive potentially issuable securities excluded from diluted common shares 1,353 865 1,709

Related Party Transactions

Related Party Transactions	12 Months Ended
	Dec. 31, 2023
Related Party Transactions [Abstract]
Related Party Transactions	Note 13 — Related Party Transactions Apollo Funds and Riverstone Funds On February 3, 2012, Talos Energy LLC completed a transaction with funds and other alternative investment vehicles managed by Apollo Management VII, L.P. and Apollo Commodities Management, L.P., with respect to Series I (“Apollo Funds”), and entities controlled by or affiliated with Riverstone Energy Partners V, L.P. (“Riverstone Funds”) and members of management pursuant to which the Talos Energy LLC received a private equity capital commitment. On January 3, 2022, the Apollo Funds ceased being a beneficial owner of more than five percent of the Company’s common stock. On July 5, 2023, the Riverstone Funds ceased being a beneficial owner of more than five percent of the Company’s common stock. Whistler Acquisition Settlement On August 31, 2018 , the Company acquired Whistler Energy II, LLC from Whistler Energy II Holdco, LLC, an affiliate of the Apollo Funds. A settlement agreement related to a dispute regarding the decommissioning obligation of a Deepwater well was executed in September 2021. For the year ended December 31, 2021, the Company recognized a $ 4.4 million gain resulting from the settlement which is reflected in “Other income (expense)” on the Company’s Consolidated Statements of Operations. Registration Rights Agreements 2018 Registration Rights Agreement — On May 10, 2018, the Company entered into a registration rights agreement (the “2018 Registration Rights Agreement”) with certain of the Apollo Funds and the Riverstone Funds, certain funds controlled by Franklin Advisers, Inc. (“Franklin”) and certain clients of MacKay Shields LLC (“MacKay Shields”), relating to the registered resale of the Company’s common stock owned by such parties on such date. Subsequently, the 2018 Registration Rights Agreement was amended to add additional affiliates of the Riverstone Funds as parties to the agreement and provide such parties with customary registration rights with respect to the Company’s Series A Convertible Preferred Stock issued to these parties at the closing of an acquisition on February 28, 2020. The 2018 Registration Rights Agreement provided that registration rights would terminate with respect to Franklin and MacKay Shields in the event that either Franklin or MacKay Shields ceased to beneficially own 5 % or more of the then outstanding shares of the Company’s common stock. Additionally, the 2018 Registration Rights Agreement provided that registration rights would otherwise terminate at such time as there were no registrable securities outstanding. The 2018 Registration Rights Agreement terminated on July 5, 2023 as there were no registrable securities outstanding. The Company agreed to bear all of the expenses incurred in connection with any offer and sale, while the selling stockholders will be responsible for paying underwriting fees, discounts and selling commissions. The Company incurred fees of nil , nil , and $ 0.7 million for the fiscal years ended December 31, 2023, 2022 and 2021, respectively. 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. Adage and Bain held approximately 2.3 % and 12.2 %, respectively, of the Company’s outstanding shares of common stock as of December 31, 2023 based on SEC beneficial ownership reports filed by each of Adage and Bain. 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. The Company did no t incur any fees for the fiscal year ended December 31, 2023. Amended and Restated Stockholders’ Agreement and Related Agreements On May 10, 2018 , the Company entered into a Stockholders’ Agreement (the “Stockholders’ Agreement”) by and among the Company and the other parties thereto. On February 24, 2020 , the Company and the other parties thereto amended the Stockholders’ Agreement to, among other things, add additional affiliates of the Riverstone Funds (or one or more of its designated affiliates) as parties to the Stockholders’ Agreement and provided ownership of the Series A Convertible Preferred Stock would, prior to the conversion thereof on March 20, 2020, count towards certain stock ownership requirements on an as converted basis to retain the Riverstone Funds rights to nominate directors to the board of directors. On March 29, 2022 , the Company and other parties thereto, entered into the Amended and Restated Stockholders’ Agreement, in connection with the termination of the Apollo Funds’ rights thereunder and the resignation of certain members of the Company's Board of Directors (the “Amended and Restated Stockholders’ Agreement”). The Amended and Restated Stockholders’ Agreement, among other things, (i) terminated the rights of the Apollo Funds under the Stockholders’ Agreement and (ii) eliminated the requirement that the board of directors consist of ten members. In connection with the closing of the EnVen Acquisition, the Company and the Riverstone Funds terminated the Amended and Restated Stockholders’ Agreement and Mr. Robert M. Tichio resigned from the Company’s Board of Directors pursuant to a shareholder support agreement dated as of September 21, 2022 requiring the Riverstone Funds to, among other things, approve the EnVen Merger Agreement and the proposed business combination. In connection with the termination of the Amended and Restated Stockholders’ Agreement , the Company and the Riverstone Funds entered into a letter agreement, dated February 13, 2023 , pursuant to which the parties thereto agreed to execute and deliver such additional documents and take all such further action as may be reasonably necessary to cause the Amended and Restated Stockholders’ Agreement to be terminated without any further force and effect. Legal Fees The Company has engaged the law firm Vinson & Elkins L.L.P. (“V&E”) to provide legal services. An immediate family member of William S. Moss III, the Company’s Executive Vice President and General Counsel and one of its executive officers, is a partner at V&E. For the years ended December 31, 2023, 2022 and 2021 , the Company incurred fees of approximately $ 3.3 million, $ 4.8 million, and $ 3.1 million, respectively, of which $ 0.8 million, $ 1.3 million, and $ 0.2 million were payable at each respective balance sheet date for legal services performed by V&E. Slim Family 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. Control Empresarial held approximately 12.2 % of the Company’s outstanding shares of common stock as of December 31, 2023 based on SEC beneficial ownership reports filed by Control Empresarial. The Slim Family own a majority stake in Grupo Carso, which indirectly has an ownership interest in Talos Mexico. See Note 3 – Acquisitions and Divestitures for additional information. The Company had no related party receivable from affiliates of the Slim Family as of December 31, 2023. Subsequent Event — In connection with the January Equity Offering (defined below), Control Empresarial increased their holding to approximately 21.9 % of the Company’s outstanding shares of common stock as of the closing of the January Equity Offering based on SEC beneficial ownership reports filed by Control Empresarial. See Note 17 – Subsequent Events for additional information. 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 expects to pay Inbursa, a banking institution controlled by the Slim Family Office an advisory fee of approximately $ 2.7 million. See Note 8 – Debt for additional information regarding the Debt Offering. Equity Method Investments The Company had a $ 5.5 million related party receivable from various equity method investments as of December 31, 2023. This is 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.

Commitments and Contingencies

Commitments and Contingencies	12 Months Ended
	Dec. 31, 2023
Commitments and Contingencies Disclosure [Abstract]
Commitments and Contingencies	Note 14 — 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. As Of December 31, 2023 , the Company has recorded $ 14.3 million as “Other current liabilities” on the Consolidated Balance Sheets related to the litigation. 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 Mexico and certain obligations under the production sharing contracts with Mexico. As of December 31, 2023, the Company had secured performance bonds from third party sureties totaling $ 1.4 billion . The cost of securing these bonds is reflected as “Interest expense” on the Consolidated Statements of Operations. Additionally, as of December 31, 2023, the Company had secured letters of credit issued under its Bank Credit Facility totaling $ 10.8 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, 2023 (in thousands): 2024 2025 2026 2027 Thereafter Total Vessel Commitments (1) $ 13,216 $ — $ — $ — $ — $ 13,216 Committed purchase orders (2) 3,083 — — — — 3,083 Other commitments (3) 3,991 327 — — — 4,318 Total $ 20,290 $ 327 $ — $ — $ — $ 20,617 (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. (3) Includes commitments associated with the Company’s CCS Segment relating to an equity funding obligation and payments required under a sequestration agreement. 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 Mexico, 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, 2023 2022 2021 Balance, beginning of period $ 54,269 $ 24,336 $ — Additions 266 8,900 21,056 Changes in estimate 11,613 22,658 — Reimbursements due from third parties — — 3,280 Settlements ( 50,584 ) ( 1,625 ) — Balance, end of period $ 15,564 $ 54,269 $ 24,336 Less: Current portion 3,280 42,069 3,756 Long-term portion $ 12,284 $ 12,200 $ 20,580 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.

Segment Information

Segment Information	12 Months Ended
	Dec. 31, 2023
Segment Reporting [Abstract]
Segment Information	Note 15 — Segment Information The Company’s operations are managed through two operating segments: (i) Upstream Segment and (ii) CCS Segment. The Upstream Segment is the Company’s only reportable segment. The Company’s chief operating decision-maker (“CODM”) is the President and Chief Executive Officer, who reviews operating results to make decisions about allocating resources and assessing performance for the entire company. A reportable segment is an operating segment that meets materiality thresholds. The 10% test, as prescribed by the segment reporting accounting guidance, are based on the reported measures of revenue, profit, and assets that are used by the CODM to assess performance and allocate resources. The CCS Segment currently does not meet any of the reportable segment quantitative thresholds. The profit or loss metric used to evaluate segment performance is Adjusted EBITDA, which is defined by the Company as net income (loss) plus interest expense; income tax expense (benefit); depreciation, depletion, and amortization; accretion expense; non-cash write-down of oil and natural gas properties; transaction and other (income) expenses; decommissioning obligations; the net change in the fair value of derivatives (mark to market effect, net of cash settlements and premiums related to these derivatives); (gain) loss on debt extinguishment; non-cash write-down of other well equipment; and non-cash equity-based compensation expense. Corporate general and administrative expense include certain shared costs such as finance, accounting, tax, human resources, information technology and legal costs that are not directly attributable to each of operating segment. A portion of these expenses are allocated based on the percentage of employees dedicated to each operating segment. The remaining expenses are included in the reconciliation of reportable segment Adjusted EBITDA to consolidated pre-tax net income (loss) as an unallocated corporate general and administrative expense. The accounting policies of the segments 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): Upstream All Other (1) Total Revenues from External Customers: Year Ended December 31, 2023 $ 1,457,886 $ — $ 1,457,886 Year Ended December 31, 2022 1,651,980 — 1,651,980 Year Ended December 31, 2021 1,244,540 — 1,244,540 Equity in the Net Income (Loss) of Investees Accounted for by the Equity Method: Year Ended December 31, 2023 $ 120 $ ( 12,228 ) $ ( 12,108 ) Year Ended December 31, 2022 101 ( 1,166 ) ( 1,065 ) Year Ended December 31, 2021 — — — Adjusted EBITDA: Year Ended December 31, 2023 $ 979,729 $ ( 22,883 ) $ 956,846 Year Ended December 31, 2022 $ 859,840 $ ( 12,786 ) 847,054 Year Ended December 31, 2021 615,798 ( 4,782 ) 611,016 Segment Expenditures: Year Ended December 31, 2023 $ 733,669 $ 40,961 $ 774,630 Year Ended December 31, 2022 452,674 2,778 455,452 Year Ended December 31, 2021 338,822 — 338,822 (1) The CCS Segment is included in the “All Other” category. The CCS Segment is an emerging business in the start-up phase of operations and the business that does not currently generate any revenues. The CCS Segment’s business activities are conducted through both wholly owned subsidiaries and equity method investments with industry partners. Equity method investments is a business strategy that enables us to achieve favorable economies of scale relative to the level of investment and business risk assumed. Reconciliations The following table presents the reconciliations of Adjusted EBITDA to the Company’s consolidated totals (in thousands): Year Ended December 31, 2023 2022 2021 Adjusted EBITDA: Total for reportable segments $ 979,729 $ 859,840 $ 615,798 All other ( 22,883 ) ( 12,786 ) ( 4,782 ) Unallocated corporate general and administrative expense ( 6,128 ) ( 5,280 ) ( 4,542 ) Interest expense ( 173,145 ) ( 125,498 ) ( 133,138 ) Depreciation, depletion and amortization ( 663,534 ) ( 414,630 ) ( 395,994 ) Accretion expense ( 86,152 ) ( 55,995 ) ( 58,129 ) Write-down of oil and natural gas properties — — ( 18,123 ) Transaction and other (income) expenses (1) 33,295 34,513 ( 5,886 ) Decommissioning obligations (2) ( 11,879 ) ( 31,558 ) ( 21,055 ) Derivative fair value gain (loss) (3) 80,928 ( 272,191 ) ( 419,077 ) Net cash (received) paid on settled derivative instruments (3) 9,457 425,559 290,164 Gain (loss) on extinguishment of debt — ( 1,569 ) ( 13,225 ) Non-cash write-down of other well equipment — — ( 5,606 ) Non-cash equity-based compensation expense ( 12,953 ) ( 15,953 ) ( 10,992 ) Income (loss) before income taxes $ 126,735 $ 384,452 $ ( 184,587 ) (1) Transaction expenses includes $ 40.4 million and $ 9.0 million in costs related to the EnVen Acquisition, inclusive of $ 25.3 million and nil in severance expense for the years ended December 31, 2023 and 2022, respectively. See further discussion in Note 3 — Acquisition and Divestitures and Note 10 — Employee Benefits Plans and Share-Based Compensation . Other income (expense) includes other miscellaneous income and expenses that the Company does not view as a meaningful indicator of its operating performance. For the year ended December 31, 2023, the amount includes a $ 66.2 million gain on the Mexico Divestiture. See further discussion in Note 3 — Acquisitions and Divestitures . The amount includes a gain on the funding of the capital carry of the Company’s investment in Bayou Bend by Chevron of $ 8.6 million and $ 1.4 million for the year ended December 31, 2023 and 2022, respectively. Additionally, it includes a $ 13.9 million gain on the partial sale of its investment in Bayou Bend to Chevron for the year ended December 31, 2022. See further discussion in Note 7 — Equity Method Investments . For the year ended December 31, 2022, the amount 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 14 — Commitments and Contingencies. (2) Estimated decommissioning obligations were a result of working interest partners or counterparties of divestiture transactions that were unable to perform the required abandonment obligations due to bankruptcy or insolvency. See Note 14 — Commitments and Contingencies for additional information on decommissioning obligations. (3) The adjustments for the derivative fair value (gains) losses and net cash receipts (payments) on settled commodity derivative instruments have the effect of adjusting net loss for changes in the fair value of derivative instruments, which are recognized at the end of each accounting period because the Company does not designate commodity derivative instruments as accounting hedges. This results in reflecting commodity derivative gains and losses within Adjusted EBITDA on an unrealized basis during the period the derivatives settled. The following table presents the reconciliation of Segment Expenditures to the Company’s consolidated totals (in thousands): Year Ended December 31, 2023 2022 2021 Segment Expenditures: Total reportable segments $ 733,669 $ 452,674 $ 338,822 All other 40,961 2,778 — Change in capital expenditures included in accounts payable and accrued liabilities ( 9,199 ) ( 60,011 ) 28,258 Plugging & abandonment ( 86,615 ) ( 69,596 ) ( 67,988 ) Decommissioning obligations settled ( 50,584 ) ( 1,625 ) — Investment in CCS intangibles and equity method investees ( 40,946 ) ( 2,778 ) — Other deferred payments ( 1,545 ) — ( 7,921 ) Insurance recovery proceeds 2,802 — — Non-cash well equipment transfers ( 27,731 ) ( 6 ) 1,086 Other 622 1,728 1,074 Exploration, development and other capital expenditures $ 561,434 $ 323,164 $ 293,331

Supplemental Oil and Gas Disclo

Supplemental Oil and Gas Disclosures (Unaudited)	12 Months Ended
	Dec. 31, 2023
Extractive Industries [Abstract]
Supplemental Oil and Gas Disclosures (Unaudited)	Note 16 — Suppl emental Oil and Gas Disclosures (Unaudited) Capitalized Costs Aggregate amounts of capitalized costs relating to oil, natural gas and NGL activities and the aggregate amount of related accumulated depletion and amortization as of the dates indicated are presented below (in thousands): Year Ended December 31, 2023 2022 2021 Consolidated Entities: Proved properties $ 7,906,295 $ 5,964,340 $ 5,232,480 Unproved oil and gas properties, not subject to amortization (1) 268,315 154,783 219,055 Total oil and gas properties 8,174,610 6,119,123 5,451,535 Less: Accumulated depletion 4,143,491 3,484,590 3,072,907 Net capitalized costs $ 4,031,119 $ 2,634,533 $ 2,378,628 Depletion and amortization rate (Per Boe) $ 27.23 $ 18.95 $ 16.71 Company's Share of Equity Investees: Unproved oil and gas properties, not subject to amortization $ 56,579 $ — $ — (1) Amount includes $ 111.4 million and $ 110.3 million of unproved properties, not subject to amortization, related to the Company’s operations in offshore Mexico for the years ended December 31, 2022 and 2021, respectively. 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, 2023 2022 2021 Consolidated Entities: Property acquisition costs: Proved properties $ 951,703 $ — $ 210 Unproved properties, not subject to amortization 249,688 2,221 — Total property acquisition costs 1,201,391 2,221 210 Exploration costs (1) 161,296 125,889 23,844 Development costs 805,148 541,512 245,058 Total costs incurred $ 2,167,835 $ 669,622 $ 269,112 Company's Share of Equity Investees: Exploration costs $ 290 $ — $ — (1) Amount includes nil , $ 1.2 million and $ 6.6 million of exploration costs related to the Company’s operations in offshore Mexico for the years ended December 31, 2023, 2022 and 2021 , respectively. 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. The Company’s Director of Reserves, internal reservoir engineers and geologists analyzed and prepared reserve estimates on all oil and natural gas fields. All of the Company’s proved oil, natural gas and NGL reserves are located in the U.S. Gulf of Mexico. At December 31, 2023, 2022 and 2021 , 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 Netherland, Sewell & Associates, Inc. (“NSAI”), independent petroleum engineers and geologists. The following table presents the Company’s estimated proved reserves at its net ownership interest: Oil (MBbls) Gas (MMcf) NGL (MBbls) Oil Equivalent Consolidated Entities: Total proved reserves at December 31, 2020 109,307 257,208 10,858 163,033 Revision of previous estimates 13,619 8,979 5,137 20,252 Production ( 16,159 ) ( 32,795 ) ( 1,875 ) ( 23,500 ) Extensions and discoveries 997 2,961 315 1,806 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 ) Purchases 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 Total Proved Developed Reserves as of: December 31, 2021 93,420 186,442 11,792 136,286 December 31, 2022 80,285 161,727 9,315 116,555 December 31, 2023 98,225 141,823 9,957 131,819 Total Proved Undeveloped Reserves as of: December 31, 2021 14,344 49,911 2,643 25,305 December 31, 2022 10,774 57,824 3,613 24,024 December 31, 2023 12,590 38,048 2,016 20,947 During 2023, proved reserves increased by 12.2 MMBoe primarily due to a purchases 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 Green Canyon core 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 Green Canyon core 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 Green Canyon core 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 Mississippi Canyon core area. During 2021 , proved reserves decreased by 1.4 MMBoe primarily due to a decrease of 23.5 MMBoe of production. The decrease was partially offset by revision to previous estimates of 20.3 MMBoe due to increase in commodity prices as well as 1.8 MMBoe of estimated proved reserves from extensions and discoveries primarily from an evaluation of Crown and Anchor Field located in the Mississippi Canyon core 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, 2023 2022 2021 Consolidated Entities: Future cash inflows $ 9,425,055 $ 10,674,896 $ 8,496,005 Future costs: Production ( 3,090,491 ) ( 1,906,752 ) ( 1,868,818 ) Development and abandonment ( 2,358,368 ) ( 1,873,453 ) ( 1,422,507 ) Future net cash flows before income taxes 3,976,196 6,894,691 5,204,680 Future income tax expense ( 589,413 ) ( 1,114,409 ) ( 676,778 ) Future net cash flows after income taxes 3,386,783 5,780,282 4,527,902 Discount at 10% annual rate ( 343,295 ) ( 1,411,834 ) ( 1,087,291 ) Standardized measure of discounted future net cash flows $ 3,043,488 $ 4,368,448 $ 3,440,611 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, 2023 2022 2021 Oil price per Bbl $ 78.56 $ 96.03 $ 67.14 Natural gas price per Mcf $ 2.75 $ 6.80 $ 3.71 NGL price per Bbl $ 18.77 $ 33.89 $ 26.62 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, 2023 2022 2021 Consolidated Entities: Standardized measure, beginning of year $ 4,368,448 $ 3,440,611 $ 1,904,934 Sales and transfers of oil, net gas and NGLs produced during the period ( 1,065,814 ) ( 1,340,400 ) ( 957,576 ) Net change in prices and production costs ( 2,835,125 ) 2,388,442 2,049,980 Changes in estimated future development and abandonment costs ( 19,877 ) ( 84,391 ) ( 57,876 ) Previously estimated development and abandonment costs incurred 202,503 20,107 69,125 Accretion of discount 518,110 392,600 199,849 Net change in income taxes 357,321 ( 327,265 ) ( 391,834 ) Purchases of reserves 2,033,852 — — Sales of reserves — ( 5,218 ) — Extensions and discoveries 90,244 202,239 45,485 Net change due to revision in quantity estimates ( 484,423 ) ( 255,743 ) 426,357 Changes in production rates (timing) and other ( 121,751 ) ( 62,534 ) 152,167 Standardized measure, end of year $ 3,043,488 $ 4,368,448 $ 3,440,611

Subsequent Events

Subsequent Events	12 Months Ended
	Dec. 31, 2023
Subsequent Events [Abstract]
Subsequent Events	Note 17 — Subsequent Events QuarterNorth Acquisition For additional Information, see the following: • Note 3 — Acquisitions and Divestitures • Note 8 — Debt • Note 13 — Related Party Transactions Equity Offering On January 22, 2024, the Company closed an upsized underwritten public offering (the “January Equity Offering”) of 34.5 million shares of the Company’s common stock, resulting in net proceeds to the Company of approximately $ 388.5 million, after deducting underwriting discounts and commissions and before estimated offering expenses. The Company intends to use the net proceeds from the January Equity Offering to fund a portion of the cash consideration for the QuarterNorth Acquisition. However, the QuarterNorth Acquisition remains subject to certain conditions to closing. Pending the use of the proceeds of the January Equity Offering as described above, the Company may temporarily use all or a portion of such proceeds to reduce the borrowings outstanding under the Company’s Bank Credit Facility. In the event that the QuarterNorth Acquisition is not completed, the proceeds from the January Equity Offering will be used for general corporate purposes.

Schedule I - Condensed Financia

Schedule I - Condensed Financial Information of Registrant (Parent Only)	12 Months Ended
	Dec. 31, 2023
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, 2023 2022 ASSETS Current assets: Accounts receivable: Other, net $ 100 $ — Prepaid assets 221 169 Other current assets 19 36 Total current assets 340 205 Other long-term assets: Investments in subsidiaries 2,246,908 1,168,053 Total assets $ 2,247,248 $ 1,168,258 LIABILITIES AND STOCKHOLDERSʼ EQUITY Current liabilities: Accounts payable $ 316 $ 249 Accrued liabilities 705 728 Other current liabilities 124 62 Total current liabilities 1,145 1,039 Long-term liabilities: Other long-term liabilities 90,952 1,643 Total liabilities 92,097 2,682 Commitments and contingencies Stockholdersʼ equity: Preferred stock; $ 0.01 par value; 30,000,000 shares authorized and zero shares issued or outstanding as of December 31, 2023 and 2022, respectively — — Common stock; $ 0.01 par value; 270,000,000 shares authorized; 127,480,361 and 82,570,328 shares issued as of December 31, 2023 and 2022, respectively 1,275 826 Additional paid-in capital 2,549,097 1,699,799 Accumulated deficit ( 347,717 ) ( 535,049 ) Treasury stock, at cost; 3,400,000 and zero shares as of December 31, 2023 and 2022, respectively ( 47,504 ) — Total stockholdersʼ equity 2,155,151 1,165,576 Total liabilities and stockholdersʼ equity $ 2,247,248 $ 1,168,258 TALOS ENERGY INC. (PARENT ONLY) STATEMENTS OF OPERATIONS (In thousands) Year Ended December 31, 2023 2022 2021 Revenues: Oil $ — $ — $ — Natural gas — — — NGL — — — Total revenues — — — Operating expenses: Lease operating expense — — — Production taxes — — — Depreciation, depletion and amortization — — — Accretion expense — — — General and administrative expense $ 2,708 $ 2,145 $ 1,322 Other operating (income) expense — — — Total operating expenses 2,708 2,145 1,322 Operating income (expense) ( 2,708 ) ( 2,145 ) ( 1,322 ) Interest expense — — ( 5 ) Price risk management activities income (expense) — — — Equity method investment income (expense) — — — Other income (expense) ( 1 ) ( 1 ) ( 2 ) Equity earnings (loss) from subsidiaries 128,888 385,968 ( 180,548 ) Net income (loss) before income taxes 126,179 383,822 ( 181,877 ) Income tax benefit (expense) 61,153 ( 1,907 ) ( 1,075 ) Net income (loss) $ 187,332 $ 381,915 $ ( 182,952 ) TALOS ENERGY INC. (PARENT ONLY) STATEMENTS OF CASH FLOWS (In thousands) Year Ended December 31, 2023 2022 2021 Cash flows from operating activities: Net cash provided by (used in) operating activities $ ( 1,836 ) $ ( 809 ) $ ( 876 ) Cash flows from investing activities: Distributions from subsidiaries 49,340 809 879 Contributions to subsidiaries — — ( 3 ) Net cash provided by (used in) investing activities 49,340 809 876 Cash flows from financing activities: Purchase of treasury stock ( 47,504 ) — — Net cash provided (used in) by financing activities ( 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, 2023 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.

Summary of Significant Accoun_2

Summary of Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2023
Organization, Consolidation and Presentation of Financial Statements [Abstract]
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 independent exploration and production company focused on safely and efficiently maximizing long-term value through its operations, currently in the United States (“U.S.”) and offshore Mexico both through upstream oil and gas exploration and production and the development of low carbon solutions opportunities. The Company leverages decades of technical and offshore operational expertise in the acquisition, exploration and development of assets in key geological trends that are present in many offshore basins around the world. The Company is also utilizing its expertise to develop CCS projects to help reduce industrial emissions along the coast of the U.S. Gulf of Mexico. Basis of Presentation and Consolidation The Consolidated Financial Statements have been prepared in accordance with GAAP and include the accounts of the Parent Company and entities in which the Parent Company holds a controlling financial interest. Both majority-owned subsidiaries and any variable interest entity in which the Parent Company is the primary beneficiary are consolidated. 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 The Company has two operating segments: (i) exploration and production of oil, natural gas and NGLs (“Upstream Segment”) and (ii) CCS (“CCS Segment”). The Upstream Segment is the Company’s only reportable segment. The legal entities included in the CCS Segment have been 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 15 — Segment Information.
Recently Issued Accounting Standards	Recently Issued Accounting Standards Segment Reporting — In November 2023, the Financial Accounting Standards Board (“FASB”) issued an update to the required disclosures for segment reporting. The update is intended to improve reportable segment disclosures, primarily through enhanced disclosures about significant segment expenses. The update will require public entities to disclose significant segment expenses that are regularly provided to the chief operating decision maker and included within segment profit and loss. The update is effective for fiscal years beginning after December 15, 2023, and interim periods within fiscal years beginning after December 15, 2024 on a retrospective basis. Early adoption is permitted. The Company is currently evaluating the effect of this update on the Company’s disclosures. 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 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 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. Cash and cash equivalents are carried at cost, which approximates fair value.
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, 2023 and 2022 , the Company had allowances of $ 8.8 million and $ 10.7 million, respectively, presented net in accounts receivable on the Consolidated Balance Sheets.
Price Risk Management Activities	Price Risk Management Activities — The Company uses commodity price derivatives to manage fluctuating oil and natural gas market risks. The Company periodically enters into commodity derivative contracts, which may require payments to (or receipts from) counterparties based on the differential between a fixed price and a variable price for a fixed quantity of oil or natural gas without the exchange of underlying volumes. Commodity derivatives are recorded on the Consolidated Balance Sheets at fair value with settlements of such contracts and changes in the unrealized fair value recorded in earnings each period. Realized gains and losses on the settlement of commodity derivatives and changes in their unrealized gains and losses are reported in “Price risk management activities income (expense)” on the Consolidated Statements of Operations. The Company classifies cash flows related to derivative contracts based on the nature and purpose of the derivative. As the derivative cash flows 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 then 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, 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 costs directly related to acquisition, 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. For investments in a limited partnership or unincorporated joint venture and a limited liability company or partnership that maintains a specific ownership account for each investor, a voting percentage of 3 - 5 % or more is generally presumed to demonstrate significant influence. Equity method accounting for interests in limited partnerships is generally appropriate unless the interest is so minor that the investor has virtually no influence (less than 3 %). 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, 2023, 2022 and 2021 .
Other Well Equipment	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	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 (as defined herein), 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. 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.
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 when production on those wells is exhausted, when the Company no longer plans to use them or when the Company abandons them. The Company accrues a liability with respect to these obligations based on its estimate of the timing and amount to replace, remove or retire 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	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 14 — Commitments & Contingencies for additional information.
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 10 — 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 upon vesting 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 upon vesting 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.
Production Handling Fees	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.
ONRR Federal Royalty Refund	ONRR Federal Royalty Refund — Included within “Other operating (income) expense” on the Consolidated Statements of Operations is income from the Company’s multi-year federal royalty refund claim from the ONRR. The Company records income when a refund is filed and its collection is reasonably assured.
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, PSUs and outstanding warrants. See Note 12 — 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 substantially 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 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, 2023 2022 2021 Shell Trading (US) Company 54 % 44 % 45 % Valero Energy Corporation 21 % 23 % ** Chevron Products Company ** 11 % 29 % ** 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, 2023 2022 Cash and cash equivalents $ 33,637 $ 44,145 Restricted cash included in Other long-term assets 102,362 — Total cash, cash equivalent and restricted cash $ 135,999 $ 44,145

Summary of Significant Accoun_3

Summary of Significant Accounting Policies (Tables)	12 Months Ended
	Dec. 31, 2023
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, 2023 2022 2021 Shell Trading (US) Company 54 % 44 % 45 % Valero Energy Corporation 21 % 23 % ** Chevron Products Company ** 11 % 29 % ** 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, 2023 2022 Cash and cash equivalents $ 33,637 $ 44,145 Restricted cash included in Other long-term assets 102,362 — Total cash, cash equivalent and restricted cash $ 135,999 $ 44,145

Acquisitions and Divestitures (

Acquisitions and Divestitures (Tables) - EnVen Energy Corporation	12 Months Ended
	Dec. 31, 2023
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): Year Ended December 31, 2023 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

Property, Plant and Equipment (

Property, Plant and Equipment (Tables)	12 Months Ended
	Dec. 31, 2023
Oil and Gas Property [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, 2023, by the year in which such costs were incurred (in thousands): Year Ended December 31, Total 2023 2022 2021 2020 and Prior Acquisition United States $ 249,799 $ 229,216 $ — $ — $ 20,583 Exploration United States 18,516 10,108 1,299 2,295 4,814 Total unproved properties, not subject to amortization $ 268,315 $ 239,324 $ 1,299 $ 2,295 $ 25,397

Leases (Tables)

Leases (Tables)	12 Months Ended
	Dec. 31, 2023
Leases [Abstract]
Components of Lease Costs	The components of lease costs were as follows (in thousands): Year Ended December 31, 2023 2022 2021 Finance lease cost - interest on lease liabilities $ 14,476 $ 7,558 $ 11,453 Operating lease cost, excluding short-term leases (1) 4,883 2,281 2,706 Short-term lease cost (2) 117,132 55,072 38,472 Variable lease cost (3) 2,888 1,450 1,356 Variable and fixed sublease income ( 482 ) — — Total lease cost $ 138,897 $ 66,361 $ 53,987 (1) Operating lease cost 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, 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 ROU Asset and 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, 2023 2022 Operating leases: Operating lease assets $ 11,418 $ 5,903 Current portion of operating lease liabilities $ 2,666 $ 1,943 Operating lease liabilities 18,211 14,855 Total operating lease liabilities $ 20,877 $ 16,798 Finance leases: Proved properties $ 166,261 $ 166,261 Other current liabilities $ 17,834 $ 16,306 Other long-term liabilities 131,230 149,064 Total finance lease liabilities $ 149,064 $ 165,370
Schedule of Lease Maturity	The table below presents the lease maturity by year as of December 31, 2023 (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 2024 $ 4,748 $ 30,782 2025 4,716 30,782 2026 4,803 30,782 2027 4,708 30,782 2028 4,610 30,782 Thereafter 4,584 43,608 Total lease payments $ 28,169 $ 197,518 Imputed interest ( 7,292 ) ( 48,454 ) Total lease liabilities $ 20,877 $ 149,064
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, 2023 2022 2021 Weighted average remaining lease term: Operating leases 5.9 years 6.4 years 7.4 years Finance leases 6.4 years 7.4 years 1.4 years Weighted average discount rate: Operating leases 10.8 % 11.8 % 11.9 % Finance leases 9.2 % 9.2 % 21.9 %
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, 2023 2022 2021 Operating cash outflow from finance leases $ 14,476 $ 7,181 $ 11,453 Operating cash outflow from operating leases $ 6,318 $ 3,722 $ 3,864 ROU assets obtained in exchange for new finance lease liabilities $ — $ 166,261 $ — ROU assets obtained in exchange for new operating lease liabilities (1) $ 12,971 $ 474 $ 1,020 Remeasurement of lease liability arising from modification of ROU asset (2) $ ( 5,124 ) $ — $ — (1) See EnVen Acquisition 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.

Financial Instruments (Tables)

Financial Instruments (Tables)	12 Months Ended
	Dec. 31, 2023
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, 2023 December 31, 2022 Carrying Fair Carrying Fair 12.00 % Second-Priority Senior Secured Notes – due January 2026 $ 601,353 $ 655,130 $ 590,132 $ 674,542 11.75 % Senior Secured Second Lien Notes – due April 2026 $ 234,221 $ 233,410 $ — $ — Bank Credit Facility – matures March 2027 $ 190,100 $ 200,000 $ ( 4,792 ) $ —
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, 2023 2022 2021 Net cash received (paid) on settled derivative instruments $ ( 9,457 ) $ ( 425,559 ) $ ( 290,164 ) Unrealized gain (loss) (1) 90,385 153,368 ( 128,913 ) Price risk management activities income (expense) $ 80,928 $ ( 272,191 ) $ ( 419,077 ) (1) Includes $ 1.4 million gain from the unrealized derivative instruments acquired from the EnVen Acquisition for the year ended December 31, 2023 .
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, 2023: Swap Contracts Production Period Settlement Index Volumes Swap Price Crude oil: (Bbls) (per Bbl) January 2024 – December 2024 NYMEX WTI CMA 16,859 $ 74.30 January 2025 – December 2025 NYMEX WTI CMA 7,734 $ 73.80 Natural gas: (MMBtu) (per MMBtu) January 2024 – December 2024 NYMEX Henry Hub 18,716 $ 3.41 January 2025 – December 2025 NYMEX Henry Hub 13,712 $ 3.92 Two-Way Collar Contracts Production Period Settlement Index Volumes Floor Price Ceiling Price Crude oil: (Bbls) (per Bbl) (per Bbl) January 2024 – December 2024 NYMEX WTI CMA 1,497 $ 70.00 $ 79.32 Natural gas: (MMBtu) (per MMBtu) (per MMBtu) January 2024 – December 2024 NYMEX Henry Hub 10,000 $ 4.00 $ 6.90 Three-Way Collar Contracts Production Period Settlement Index Volumes Short Put Price Floor Price Ceiling Price Crude oil: (Bbls) (per Bbl) (per Bbl) (per Bbl) January 2024 – March 2024 NYMEX WTI CMA 3,200 $ 57.27 $ 70.00 $ 98.01
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, 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 December 31, 2022 Level 1 Level 2 Level 3 Total Assets: Oil and natural gas derivatives $ — $ 32,883 $ — $ 32,883 Liabilities: Oil and natural gas derivatives — ( 76,242 ) — ( 76,242 ) Total net asset (liability) $ — $ ( 43,359 ) $ — $ ( 43,359 )
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, 2023 December 31, 2022 Assets Liabilities Assets Liabilities Oil and natural gas derivatives: Current $ 36,152 $ 7,305 $ 25,029 $ 68,370 Non-current 17,551 795 7,854 7,872 Total gross amounts presented on balance sheet 53,703 8,100 32,883 76,242 Less: Gross amounts not offset on the balance sheet 8,100 8,100 32,883 32,883 Net amounts $ 45,603 $ — $ — $ 43,359

Equity Method Investments (Tabl

Equity Method Investments (Tables)	12 Months Ended
	Dec. 31, 2023
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, 2023 2023 2022 Upstream: Talos Energy Mexico 7, S. de R.L. de C.V 50.1 % $ 107,259 $ — SP 49 Pipeline LLC 33.3 % 861 374 CCS: Bayou Bend CCS LLC 25.0 % 28,183 1,371 Harvest Bend CCS LLC 65.0 % 9,746 — Coastal Bend CCS LLC 50.0 % — — Total Equity Method Investments $ 146,049 $ 1,745

Debt (Tables)

Debt (Tables)	12 Months Ended
	Dec. 31, 2023
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): Year Ended December 31, 2023 2022 12.00 % Second-Priority Senior Secured Notes – due January 2026 $ 638,541 $ 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 1,066,041 638,541 Unamortized discount, premium and deferred financing cost, net ( 40,367 ) ( 53,201 ) Total debt 1,025,674 585,340 Less: Current portion of long-term debt 33,060 — Long-term debt $ 992,614 $ 585,340
Summary of Redemption Prices of 12.% and 11.75% Notes	The Company may redeem all or a portion of the 12.00% Notes in whole at any time or in part from time to time at the following redemption prices (expressed as percentages of principal amount) plus accrued and unpaid interest if redeemed during the period commencing on January 15 of the years set forth below : Period Redemption Price 2023 106.000 % 2024 103.000 % 2025 and thereafter 100.000 % The Company may redeem all or a portion of the 11.75% Notes in whole at any time or in part from time to time at the following redemption prices (expressed as percentages of principal amount) plus accrued and unpaid interest if redeemed during the period commencing on February 15 of the years set forth below: Period Redemption Price 2023 105.875 % 2024 102.938 % 2025 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 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 %

Asset Retirement Obligations (T

Asset Retirement Obligations (Tables)	12 Months Ended
	Dec. 31, 2023
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, 2023 2022 Balance, beginning of period $ 541,661 $ 434,006 Obligations assumed (1) 258,858 — Obligations incurred 14,199 1,140 Obligations settled ( 86,615 ) ( 69,596 ) Obligations divested ( 19,448 ) ( 1,572 ) Accretion expense 86,152 55,995 Changes in estimate (2) 102,419 121,688 Balance, end of period $ 897,226 $ 541,661 Less: Current portion 77,581 39,888 Long-term portion $ 819,645 $ 501,773 (1) Assumed in connection with the EnVen Acquisition. See further discussion in Note 3 — Acquisitions and Divestitures . (2) Changes in estimate were primarily due to an increase in estimated service costs. Additionally, increases for the year ended December 31, 2023 due to the acceleration of estimated settlement date.

Employee Benefits Plans and S_2

Employee Benefits Plans and Share-Based Compensation (Tables)	12 Months Ended
	Dec. 31, 2023
Share-Based Payment Arrangement [Abstract]
Schedule Of Acquisition Severance Costs	The following table summarizes severance accrual activity in connection with the EnVen Acquisition included in “Other current liabilities” and “Other long-term liabilities” on the Consolidated Balance Sheets as of December 31, 2023 (in thousands): Severance accrual at December 31, 2022 $ — Accrual additions 25,348 Benefit payments ( 19,054 ) Severance accrual at December 31, 2023 6,294 Less: Current portion at December 31, 2023 6,190 Long-term portion at December 31, 2023 $ 104
Summary of Restricted Stock Units Activity	The following table summarizes RSU activity: Restricted Weighted Average Unvested RSUs at December 31, 2020 1,652,988 $ 13.73 Granted 1,102,038 $ 13.11 Vested ( 669,832 ) $ 15.01 Forfeited ( 101,995 ) $ 12.46 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 (1) 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 As of December 31, 2023 and 2022 , 26,975 and 25,257 , 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 Weighted Average Unvested PSUs at December 31, 2020 834,172 $ 25.46 Granted 586,995 $ 18.96 Vested ( 391,308 ) $ 39.43 Forfeited ( 14,400 ) $ 18.48 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 (1) There were 314,833 PSUs granted that are eligible to vest based on continued employment and the Company’s annualized absolute total shareholder return (“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 will again be available for new awards under the recycling provisions of the 2021 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.
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 and modified at the date indicated: 2023 2022 2021 Grant Grant Grant Grant Grant Modification Grant December 1 July 1 March 5 September 20 March 5 May 11 March 8 Expected term (in years) 2.1 2.5 2.8 2.3 2.8 2.6 2.8 Expected volatility 61.9 % 66.2 % 73.1 % 74.3 % 82.2 % 80.9 % 78.3 % Risk-free interest rate 4.4 % 4.6 % 4.5 % 3.9 % 1.6 % 0.3 % 0.3 % Dividend yield — % — % — % — % — % — % — % Fair value (in thousands) $ 12 $ 173 $ 6,165 $ 621 $ 8,668 $ 9,715 $ 11,129
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, 2023 2022 2021 Share-based compensation costs $ 25,236 $ 28,280 $ 20,560 Less: Amounts capitalized to oil and gas properties 12,283 12,327 9,568 Total share-based compensation expense $ 12,953 $ 15,953 $ 10,992

Income Taxes (Tables)

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2023
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, 2023 2022 2021 Current income tax expense (benefit): United States $ 76 $ 1,375 $ ( 5 ) Mexico 31 432 ( 993 ) Total current income tax expense (benefit) $ 107 $ 1,807 $ ( 998 ) Deferred income tax expense (benefit): United States $ ( 60,704 ) $ 659 $ ( 1,067 ) Mexico — 71 430 Total deferred income tax expense (benefit) $ ( 60,704 ) $ 730 $ ( 637 ) Total income tax expense (benefit) $ ( 60,597 ) $ 2,537 $ ( 1,635 )
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, 2023 2022 2021 Income tax expense (benefit) at the federal statutory tax rate $ 26,614 $ 80,735 $ ( 38,763 ) State income taxes 1,748 1,591 ( 674 ) Impact of foreign operations 13,539 15,657 ( 11,920 ) Effect of change in state rate — — 2,008 Prior year taxes 1,184 ( 2,920 ) 486 Change in valuation allowance ( 106,815 ) ( 96,537 ) 45,547 Other permanent differences 3,133 4,011 1,681 Total income tax expense (benefit) $ ( 60,597 ) $ 2,537 $ ( 1,635 ) Effective tax rate ( 47.81 )% 0.66 % 0.89 %
Summary of Significant Components of Deferred Tax Assets and Liabilities	Net deferred tax assets (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. Significant components of deferred tax assets and liabilities were as follows (in thousands): Year Ended December 31, 2023 2022 Deferred tax assets: Federal net operating loss $ 147,252 $ 159,257 Foreign tax loss carryforward 509 44,462 State net operating loss 24,840 24,787 Tax credits 107 107 Interest expense carryforward 46,414 23,262 Asset retirement obligations 190,248 115,848 Derivatives — 9,273 Other well equipment 1,317 1,891 Accrued bonus 5,050 5,863 Share-based compensation 5,172 5,296 Operating lease liabilities 4,427 3,669 Finance lease liabilities 31,607 32,559 Other 3,383 7,142 Total deferred tax assets 460,326 433,416 Valuation allowance ( 23,697 ) ( 129,105 ) Total deferred tax assets, net $ 436,629 $ 304,311 Deferred tax liabilities: Oil and gas properties $ 512,918 $ 302,602 Operating lease assets 2,421 1,323 Derivatives 9,670 — Prepaid 3,847 2,530 Total deferred tax liabilities 528,856 306,455 Net deferred tax liability $ ( 92,227 ) $ ( 2,144 )
Summary of Net Operating Loss Carryovers	The table below presents the details of the Company’s net operating loss carryovers as of December 31, 2023 (in thousands): Amount Expiration Year Federal net operating losses $ 452,393 2035 - 2037 Federal net operating losses $ 248,807 Unlimited Foreign tax loss carryforward $ 1,696 2025 - 2032 State net operating losses $ 125,958 2025 - 2037 State net operating losses $ 277,930 Unlimited
Summary of Balances In Uncertain Tax Positions	Balances in the uncertain tax positions are as follows (in thousands): Year Ended December 31, 2023 2022 2021 Total unrecognized tax benefits, beginning balance $ 835 $ 696 $ 648 Increases in unrecognized tax benefits as a result of: Tax positions taken during a prior period 154 100 21 Tax positions taken during the current period — 39 27 Total unrecognized tax benefits, ending balance $ 989 $ 835 $ 696

Income (Loss) Per Share (Tables

Income (Loss) Per Share (Tables)	12 Months Ended
	Dec. 31, 2023
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, 2023 2022 2021 Net income (loss) $ 187,332 $ 381,915 $ ( 182,952 ) Weighted average common shares outstanding — basic 119,894 82,454 81,769 Dilutive effect of securities 858 1,229 — Weighted average common shares outstanding — diluted 120,752 83,683 81,769 Net income (loss) per common share: Basic $ 1.56 $ 4.63 $ ( 2.24 ) Diluted $ 1.55 $ 4.56 $ ( 2.24 ) Anti-dilutive potentially issuable securities excluded from diluted common shares 1,353 865 1,709

Commitments and Contingencies (

Commitments and Contingencies (Tables)	12 Months Ended
	Dec. 31, 2023
Commitments and Contingencies Disclosure [Abstract]
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, 2023 (in thousands): 2024 2025 2026 2027 Thereafter Total Vessel Commitments (1) $ 13,216 $ — $ — $ — $ — $ 13,216 Committed purchase orders (2) 3,083 — — — — 3,083 Other commitments (3) 3,991 327 — — — 4,318 Total $ 20,290 $ 327 $ — $ — $ — $ 20,617 (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. (3) Includes commitments associated with the Company’s CCS Segment relating to an equity funding obligation and payments required under a sequestration agreement.
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, 2023 2022 2021 Balance, beginning of period $ 54,269 $ 24,336 $ — Additions 266 8,900 21,056 Changes in estimate 11,613 22,658 — Reimbursements due from third parties — — 3,280 Settlements ( 50,584 ) ( 1,625 ) — Balance, end of period $ 15,564 $ 54,269 $ 24,336 Less: Current portion 3,280 42,069 3,756 Long-term portion $ 12,284 $ 12,200 $ 20,580

Segment Information (Tables)

Segment Information (Tables)	12 Months Ended
	Dec. 31, 2023
Segment Reporting [Abstract]
Summary of Information by Business Segment	The following table presents selected segment information for the periods indicated (in thousands): Upstream All Other (1) Total Revenues from External Customers: Year Ended December 31, 2023 $ 1,457,886 $ — $ 1,457,886 Year Ended December 31, 2022 1,651,980 — 1,651,980 Year Ended December 31, 2021 1,244,540 — 1,244,540 Equity in the Net Income (Loss) of Investees Accounted for by the Equity Method: Year Ended December 31, 2023 $ 120 $ ( 12,228 ) $ ( 12,108 ) Year Ended December 31, 2022 101 ( 1,166 ) ( 1,065 ) Year Ended December 31, 2021 — — — Adjusted EBITDA: Year Ended December 31, 2023 $ 979,729 $ ( 22,883 ) $ 956,846 Year Ended December 31, 2022 $ 859,840 $ ( 12,786 ) 847,054 Year Ended December 31, 2021 615,798 ( 4,782 ) 611,016 Segment Expenditures: Year Ended December 31, 2023 $ 733,669 $ 40,961 $ 774,630 Year Ended December 31, 2022 452,674 2,778 455,452 Year Ended December 31, 2021 338,822 — 338,822 (1) The CCS Segment is included in the “All Other” category. The CCS Segment is an emerging business in the start-up phase of operations and the business that does not currently generate any revenues. The CCS Segment’s business activities are conducted through both wholly owned subsidiaries and equity method investments with industry partners. Equity method investments is a business strategy that enables us to achieve favorable economies of scale relative to the level of investment and business risk assumed.
Schedule of Reconciliation of Reportable Segment Information to the Company's Consolidated Totals	The following table presents the reconciliations of Adjusted EBITDA to the Company’s consolidated totals (in thousands): Year Ended December 31, 2023 2022 2021 Adjusted EBITDA: Total for reportable segments $ 979,729 $ 859,840 $ 615,798 All other ( 22,883 ) ( 12,786 ) ( 4,782 ) Unallocated corporate general and administrative expense ( 6,128 ) ( 5,280 ) ( 4,542 ) Interest expense ( 173,145 ) ( 125,498 ) ( 133,138 ) Depreciation, depletion and amortization ( 663,534 ) ( 414,630 ) ( 395,994 ) Accretion expense ( 86,152 ) ( 55,995 ) ( 58,129 ) Write-down of oil and natural gas properties — — ( 18,123 ) Transaction and other (income) expenses (1) 33,295 34,513 ( 5,886 ) Decommissioning obligations (2) ( 11,879 ) ( 31,558 ) ( 21,055 ) Derivative fair value gain (loss) (3) 80,928 ( 272,191 ) ( 419,077 ) Net cash (received) paid on settled derivative instruments (3) 9,457 425,559 290,164 Gain (loss) on extinguishment of debt — ( 1,569 ) ( 13,225 ) Non-cash write-down of other well equipment — — ( 5,606 ) Non-cash equity-based compensation expense ( 12,953 ) ( 15,953 ) ( 10,992 ) Income (loss) before income taxes $ 126,735 $ 384,452 $ ( 184,587 ) (1) Transaction expenses includes $ 40.4 million and $ 9.0 million in costs related to the EnVen Acquisition, inclusive of $ 25.3 million and nil in severance expense for the years ended December 31, 2023 and 2022, respectively. See further discussion in Note 3 — Acquisition and Divestitures and Note 10 — Employee Benefits Plans and Share-Based Compensation . Other income (expense) includes other miscellaneous income and expenses that the Company does not view as a meaningful indicator of its operating performance. For the year ended December 31, 2023, the amount includes a $ 66.2 million gain on the Mexico Divestiture. See further discussion in Note 3 — Acquisitions and Divestitures . The amount includes a gain on the funding of the capital carry of the Company’s investment in Bayou Bend by Chevron of $ 8.6 million and $ 1.4 million for the year ended December 31, 2023 and 2022, respectively. Additionally, it includes a $ 13.9 million gain on the partial sale of its investment in Bayou Bend to Chevron for the year ended December 31, 2022. See further discussion in Note 7 — Equity Method Investments . For the year ended December 31, 2022, the amount 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 14 — Commitments and Contingencies. (2) Estimated decommissioning obligations were a result of working interest partners or counterparties of divestiture transactions that were unable to perform the required abandonment obligations due to bankruptcy or insolvency. See Note 14 — Commitments and Contingencies for additional information on decommissioning obligations. (3) The adjustments for the derivative fair value (gains) losses and net cash receipts (payments) on settled commodity derivative instruments have the effect of adjusting net loss for changes in the fair value of derivative instruments, which are recognized at the end of each accounting period because the Company does not designate commodity derivative instruments as accounting hedges. This results in reflecting commodity derivative gains and losses within Adjusted EBITDA on an unrealized basis during the period the derivatives settled.
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, 2023 2022 2021 Segment Expenditures: Total reportable segments $ 733,669 $ 452,674 $ 338,822 All other 40,961 2,778 — Change in capital expenditures included in accounts payable and accrued liabilities ( 9,199 ) ( 60,011 ) 28,258 Plugging & abandonment ( 86,615 ) ( 69,596 ) ( 67,988 ) Decommissioning obligations settled ( 50,584 ) ( 1,625 ) — Investment in CCS intangibles and equity method investees ( 40,946 ) ( 2,778 ) — Other deferred payments ( 1,545 ) — ( 7,921 ) Insurance recovery proceeds 2,802 — — Non-cash well equipment transfers ( 27,731 ) ( 6 ) 1,086 Other 622 1,728 1,074 Exploration, development and other capital expenditures $ 561,434 $ 323,164 $ 293,331

Supplemental Oil and Gas Disc_2

Supplemental Oil and Gas Disclosures (Unaudited) (Tables)	12 Months Ended
	Dec. 31, 2023
Extractive Industries [Abstract]
Schedule of Capitalized Costs Related to Oil, Natural Gas and NGL Activities and Related Accumulated Depletion and Amortization	Aggregate amounts of capitalized costs relating to oil, natural gas and NGL activities and the aggregate amount of related accumulated depletion and amortization as of the dates indicated are presented below (in thousands): Year Ended December 31, 2023 2022 2021 Consolidated Entities: Proved properties $ 7,906,295 $ 5,964,340 $ 5,232,480 Unproved oil and gas properties, not subject to amortization (1) 268,315 154,783 219,055 Total oil and gas properties 8,174,610 6,119,123 5,451,535 Less: Accumulated depletion 4,143,491 3,484,590 3,072,907 Net capitalized costs $ 4,031,119 $ 2,634,533 $ 2,378,628 Depletion and amortization rate (Per Boe) $ 27.23 $ 18.95 $ 16.71 Company's Share of Equity Investees: Unproved oil and gas properties, not subject to amortization $ 56,579 $ — $ — (1) Amount includes $ 111.4 million and $ 110.3 million of unproved properties, not subject to amortization, related to the Company’s operations in offshore Mexico for the years ended December 31, 2022 and 2021, respectively.
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, 2023 2022 2021 Consolidated Entities: Property acquisition costs: Proved properties $ 951,703 $ — $ 210 Unproved properties, not subject to amortization 249,688 2,221 — Total property acquisition costs 1,201,391 2,221 210 Exploration costs (1) 161,296 125,889 23,844 Development costs 805,148 541,512 245,058 Total costs incurred $ 2,167,835 $ 669,622 $ 269,112 Company's Share of Equity Investees: Exploration costs $ 290 $ — $ — (1) Amount includes nil , $ 1.2 million and $ 6.6 million of exploration costs related to the Company’s operations in offshore Mexico for the years ended December 31, 2023, 2022 and 2021 , respectively.
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) NGL (MBbls) Oil Equivalent Consolidated Entities: Total proved reserves at December 31, 2020 109,307 257,208 10,858 163,033 Revision of previous estimates 13,619 8,979 5,137 20,252 Production ( 16,159 ) ( 32,795 ) ( 1,875 ) ( 23,500 ) Extensions and discoveries 997 2,961 315 1,806 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 ) Purchases 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 Total Proved Developed Reserves as of: December 31, 2021 93,420 186,442 11,792 136,286 December 31, 2022 80,285 161,727 9,315 116,555 December 31, 2023 98,225 141,823 9,957 131,819 Total Proved Undeveloped Reserves as of: December 31, 2021 14,344 49,911 2,643 25,305 December 31, 2022 10,774 57,824 3,613 24,024 December 31, 2023 12,590 38,048 2,016 20,947
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, 2023 2022 2021 Consolidated Entities: Future cash inflows $ 9,425,055 $ 10,674,896 $ 8,496,005 Future costs: Production ( 3,090,491 ) ( 1,906,752 ) ( 1,868,818 ) Development and abandonment ( 2,358,368 ) ( 1,873,453 ) ( 1,422,507 ) Future net cash flows before income taxes 3,976,196 6,894,691 5,204,680 Future income tax expense ( 589,413 ) ( 1,114,409 ) ( 676,778 ) Future net cash flows after income taxes 3,386,783 5,780,282 4,527,902 Discount at 10% annual rate ( 343,295 ) ( 1,411,834 ) ( 1,087,291 ) Standardized measure of discounted future net cash flows $ 3,043,488 $ 4,368,448 $ 3,440,611
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, 2023 2022 2021 Oil price per Bbl $ 78.56 $ 96.03 $ 67.14 Natural gas price per Mcf $ 2.75 $ 6.80 $ 3.71 NGL price per Bbl $ 18.77 $ 33.89 $ 26.62
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, 2023 2022 2021 Consolidated Entities: Standardized measure, beginning of year $ 4,368,448 $ 3,440,611 $ 1,904,934 Sales and transfers of oil, net gas and NGLs produced during the period ( 1,065,814 ) ( 1,340,400 ) ( 957,576 ) Net change in prices and production costs ( 2,835,125 ) 2,388,442 2,049,980 Changes in estimated future development and abandonment costs ( 19,877 ) ( 84,391 ) ( 57,876 ) Previously estimated development and abandonment costs incurred 202,503 20,107 69,125 Accretion of discount 518,110 392,600 199,849 Net change in income taxes 357,321 ( 327,265 ) ( 391,834 ) Purchases of reserves 2,033,852 — — Sales of reserves — ( 5,218 ) — Extensions and discoveries 90,244 202,239 45,485 Net change due to revision in quantity estimates ( 484,423 ) ( 255,743 ) 426,357 Changes in production rates (timing) and other ( 121,751 ) ( 62,534 ) 152,167 Standardized measure, end of year $ 3,043,488 $ 4,368,448 $ 3,440,611

Organization, Nature of Busin_2

Organization, Nature of Business and Basis of Presentation - Additional Information (Details)	12 Months Ended
	Dec. 31, 2023 Segment
Basis Of Presentation And Schedule Of Accounting Policy [Line Items]
Date of incorporation	Nov. 14, 2017
Number of Operating Segments	2

Summary of Significant Accoun_4

Summary of Significant Accounting Policies - Additional Information (Details) - USD ($)	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Summary Of Significant Accounting Policies [Line Items]
Allowance for expected credit losses	$ 8,800,000	$ 10,700,000
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
Summary Of Significant Accounting Policies [Line Items]
Number of common stock issuable upon vesting, percentage range of PSUs granted	0%
Minimum | Performance Shares
Summary Of Significant Accounting Policies [Line Items]
Number of common stock issuable upon vesting, percentage range of PSUs granted	0%
Maximum
Summary Of Significant Accounting Policies [Line Items]
Other property and equipment, estimated useful lives	10 years
Maximum | Performance Share Unit
Summary Of Significant Accounting Policies [Line Items]
Number of common stock issuable upon vesting, percentage range of PSUs granted	200%
Maximum | Performance Shares
Summary Of Significant Accounting Policies [Line Items]
Number of common stock issuable upon vesting, percentage range of PSUs granted	200%
Measurement Input Discount Rate
Summary Of Significant Accounting Policies [Line Items]
Present value of future net revenues from proved reserves, discount rate	10%
Limited Partnership or Limited Liability Company Type Investment | Minimum
Summary Of Significant Accounting Policies [Line Items]
Equity method investment, ownership percentage	3%
Limited Partnership or Limited Liability Company Type Investment | Minimum | Common Stock
Summary Of Significant Accounting Policies [Line Items]
Equity method investment, ownership percentage	20%
Limited Partnership or Limited Liability Company Type Investment | Maximum
Summary Of Significant Accounting Policies [Line Items]
Equity method investment, ownership percentage	5%
Equity method investment, maximum required ownership percentage	3%

Summary of Significant Accoun_5

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, 2023	Dec. 31, 2022	Dec. 31, 2021
Shell Trading (US) Company
Concentration Risk Line Items
Concentration risk, percentage	54%	44%	45%
Valero energy corporation
Concentration Risk Line Items
Concentration risk, percentage	21%	23%
Chevron Products Company
Concentration Risk Line Items
Concentration risk, percentage		11%	29%

Summary of Significant Accoun_6

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, 2023	Dec. 31, 2022	Dec. 31, 2021
Valero energy corporation
Concentration Risk Line Items
Concentration risk, percentage	21%	23%
Valero energy corporation | Maximum
Concentration Risk Line Items
Concentration risk, percentage			10%
Chevron Products Company
Concentration Risk Line Items
Concentration risk, percentage		11%	29%
Chevron Products Company | Maximum
Concentration Risk Line Items
Concentration risk, percentage	10%

Summary of Significant Accoun_7

Summary of Significant Accounting Policies - Schedule of Cash and Cash Equivalents (Details) - USD ($) $ in Thousands	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Summary Of Significant Accounting Policies [Abstract]
Cash and cash equivalents	$ 33,637	$ 44,145
Restricted cash included in Other long-term assets	102,362	0
Total cash, cash equivalent and restricted cash	$ 135,999	$ 44,145	$ 69,852	$ 34,233

Acquisitions and Divestitures -

Acquisitions and Divestitures - Business Combination - Additional Information (Details) - USD ($) $ in Thousands				12 Months Ended
	Jan. 13, 2024	Feb. 13, 2023	Sep. 21, 2022	Dec. 31, 2023	Dec. 31, 2022
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. Supplemental pro forma earnings for the year ended December 31, 2023 were adjusted to exclude $65.1 million of general and administrative 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 | 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)	$ 65,100
EnVen Energy Corporation | Common Stock
Business Acquisition [Line Items]
Aggregate shares issued		43,799,890
EnVen Energy Corporation | Common Stock | Pro Forma
Business Acquisition [Line Items]
Aggregate shares issued					43,800,000
QuarterNorth Energy, Inc. | Subsequent Event
Business Acquisition [Line Items]
Cash consideration	$ 964,900
Business Acquisition, Date of Acquisition Agreement	Jan. 13, 2024
QuarterNorth Energy, Inc. | Common Stock | Subsequent Event
Business Acquisition [Line Items]
Aggregate shares issued	24,800,000

Acquisitions and Divestitures_2

Acquisitions and Divestitures - Business Combination - Summary of Purchase Price (Details) - EnVen Energy Corporation $ / shares in Units, $ in Thousands	Feb. 13, 2023 USD ($) $ / shares shares
Business Acquisition [Line Items]
Talos common stock price per share | $ / shares	$ 19	[1]
Common stock value	$ 832,198
Cash consideration	207,313
Settlement of preexisting relationship	8,388
Total purchase price	$ 1,047,899
Common Stock
Business Acquisition [Line Items]
Talos common stock | shares	43,799,890
[1] Represents the closing price of the Company’s common stock on February 13, 2023, the date of the closing of the EnVen Acquisition.

Acquisitions and Divestitures_3

Acquisitions and Divestitures - Business Combination - Summary of Allocation of Purchase Price to Assets Acquired and Liabilities Assumed (Details) - EnVen Energy Corporation $ in Thousands	Feb. 13, 2023 USD ($)
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

Acquisitions and Divestitures_4

Acquisitions and Divestitures - Business Combination - Summary of Revenue and Net Income Attributable to Acquisition (Details) - EnVen Energy Corporation $ in Thousands	12 Months Ended
	Dec. 31, 2023 USD ($)
Business Acquisition [Line Items]
Revenue	$ 423,624
Net income (loss)	$ 85,622

Acquisitions and Divestitures_5

Acquisitions and Divestitures - Business Combination - Summary of Supplemental Proforma Information (Details) - EnVen Energy Corporation - USD ($) $ / shares in Units, $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022
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

Acquisitions and Divestitures_6

Acquisitions and Divestitures - Divestiture - Additional Information (Details) - USD ($) $ in Thousands		12 Months Ended
	Sep. 27, 2023	Dec. 31, 2023	Dec. 31, 2022
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Unproved oil and gas properties, not subject to amortization		$ 268,315	$ 154,783
Disposal Group, Not Discontinued Operation, Gain (Loss) on Disposal, Statement of Income or Comprehensive Income [Extensible Enumeration]		Other Operating Income (Expense), Net
Talos Mexico
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Percentage of equity interests sold	49.90%
Sale of stock, consideration received on transaction	$ 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]
Sale of stock, consideration received on transaction	$ 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
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%

Property, Plant and Equipment -

Property, Plant and Equipment - Additional Information (Details)	12 Months Ended
	Dec. 31, 2023 USD ($) $ / bbl $ / Mcf	Dec. 31, 2022 USD ($) $ / Mcf $ / bbl	Dec. 31, 2021 USD ($) $ / Mcf $ / bbl	Sep. 27, 2023 USD ($)
Property, Plant and Equipment [Line Items]
Write-down of oil and natural gas properties	$ 0	$ 0	$ 18,123,000
Total unproved properties, not subject to amortization	$ 268,315,000	$ 154,783,000
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 eight years.
Oil (MBbls)
Property, Plant and Equipment [Line Items]
SEC pricing | $ / bbl	78.56	96.03	67.14
Gas (MMcf)
Property, Plant and Equipment [Line Items]
SEC pricing | $ / Mcf	2.75	6.80	3.71
NGL (MBbls)
Property, Plant and Equipment [Line Items]
SEC pricing | $ / bbl	18.77	33.89	26.62
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 | $ / bbl	78.56
US | Gas (MMcf)
Property, Plant and Equipment [Line Items]
SEC pricing | $ / Mcf	2.75
US | NGL (MBbls)
Property, Plant and Equipment [Line Items]
SEC pricing | $ / bbl	18.77
Mexico
Property, Plant and Equipment [Line Items]
Write-down of oil and natural gas properties			18,100,000
Total unproved properties, not subject to amortization		$ 111,400,000	$ 110,300,000
Disposal Group, Disposed of by Sale, Not Discontinued Operations [Member] | Mexico | Zama prospect
Property, Plant and Equipment [Line Items]
Total unproved properties, not subject to amortization				$ 112,300

Property, Plant and Equipment_2

Property, Plant and Equipment - Summary of Oil and Natural Gas Property Costs Not Being Amortized (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Capitalized Costs Of Unproved Properties Excluded From Amortization [Line Items]
Total unproved properties, not subject to amortization	$ 268,315	$ 154,783
United States
Capitalized Costs Of Unproved Properties Excluded From Amortization [Line Items]
Acquisition	249,799
Exploration	18,516
Mexico
Capitalized Costs Of Unproved Properties Excluded From Amortization [Line Items]
Total unproved properties, not subject to amortization		111,400	$ 110,300
2023
Capitalized Costs Of Unproved Properties Excluded From Amortization [Line Items]
Total unproved properties, not subject to amortization	239,324
2023 | United States
Capitalized Costs Of Unproved Properties Excluded From Amortization [Line Items]
Acquisition	229,216
Exploration	$ 10,108
2022
Capitalized Costs Of Unproved Properties Excluded From Amortization [Line Items]
Total unproved properties, not subject to amortization		1,299
2022 | United States
Capitalized Costs Of Unproved Properties Excluded From Amortization [Line Items]
Acquisition		0
Exploration		$ 1,299
2021
Capitalized Costs Of Unproved Properties Excluded From Amortization [Line Items]
Total unproved properties, not subject to amortization			2,295
2021 | United States
Capitalized Costs Of Unproved Properties Excluded From Amortization [Line Items]
Acquisition			0
Exploration			$ 2,295
2020 and Prior
Capitalized Costs Of Unproved Properties Excluded From Amortization [Line Items]
Total unproved properties, not subject to amortization				$ 25,397
2020 and Prior | United States
Capitalized Costs Of Unproved Properties Excluded From Amortization [Line Items]
Acquisition				20,583
Exploration				$ 4,814

Leases - Additional Information

Leases - Additional Information (Details) - USD ($) $ in Thousands	Dec. 31, 2023	Dec. 31, 2022	Nov. 30, 2022
Lease, Cost [Abstract]
Finance Lease, Liability, Statement of Financial Position [Extensible Enumeration]			Liabilities
Lease liability	$ 149,064	$ 165,370	$ 166,300

Leases - Components of Lease Co

Leases - Components of Lease Costs (Details) - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Lease, Cost [Abstract]
Finance lease cost - interest on lease liabilities		$ 14,476	$ 7,558	$ 11,453
Operating lease cost, excluding short-term leases	[1]	4,883	2,281	2,706
Short-term lease cost	[2]	117,132	55,072	38,472
Variable lease cost	[3]	2,888	1,450	1,356
Variable and fixed sublease income		(482)	0	0
Total lease cost		$ 138,897	$ 66,361	$ 53,987
[1] Operating lease cost reflect a single lease cost, calculated so that the cost of the lease is allocated over the lease term on a straight-line basis. Short-term lease costs are reported at gross amounts and primarily represent costs incurred for drilling rigs, 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.

Leases - Schedule of Right-of-U

Leases - Schedule of Right-of-Use Asset and Liability, Adjusted for Initial Direct Costs and Incentives (Details) - USD ($) $ in Thousands	Dec. 31, 2023	Dec. 31, 2022	Nov. 30, 2022
Operating leases:
Operating lease assets	$ 11,418	$ 5,903
Current portion of operating lease liabilities	$ 2,666	$ 1,943
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	$ 18,211	$ 14,855
Total operating lease liabilities	20,877	16,798
Finance leases:
Proved property	$ 166,261	$ 166,261
Finance Lease, Right-of-Use Asset, Statement of Financial Position [Extensible Enumeration]	Proved properties	Proved properties
Other current liabilities	$ 17,834	$ 16,306
Finance Lease, Liability, Current, Statement of Financial Position [Extensible List]	Other current liabilities	Other current liabilities
Other long-term liabilities	$ 131,230	$ 149,064
Finance Lease, Liability, Noncurrent, Statement of Financial Position [Extensible List]	Other long-term liabilities	Other long-term liabilities
Total finance lease liabilities	$ 149,064	$ 165,370	$ 166,300

Leases - Schedule of Lease Matu

Leases - Schedule of Lease Maturity (Details) - USD ($) $ in Thousands	Dec. 31, 2023	Dec. 31, 2022	Nov. 30, 2022
Leases [Abstract]
Operating Leases, 2024	$ 4,748
Operating Leases, 2025	4,716
Operating Leases, 2026	4,803
Operating Leases, 2027	4,708
Operating Leases, 2028	4,610
Operating Leases, Thereafter	4,584
Operating Leases, Total lease payments	28,169
Operating Leases, Imputed interest	(7,292)
Total operating lease liabilities	20,877	$ 16,798
Finance Leases, 2024	30,782
Finance Leases, 2025	30,782
Finance Leases, 2026	30,782
Finance Leases, 2027	30,782
Finance Leases, 2028	30,782
Finance Leases, Thereafter	43,608
Finance Leases, Total lease payments	197,518
Finance Leases, Imputed interest	(48,454)
Total finance lease liabilities	$ 149,064	$ 165,370	$ 166,300

Leases - Schedule of Weighted A

Leases - Schedule of Weighted Average Remaining Lease Term and Discount Rate (Details)	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Weighted average remaining lease term:
Operating leases	5 years 10 months 24 days	6 years 4 months 24 days	7 years 4 months 24 days
Finance leases	6 years 4 months 24 days	7 years 4 months 24 days	1 year 4 months 24 days
Weighted average discount rate:
Operating leases	10.80%	11.80%	11.90%
Finance leases	9.20%	9.20%	21.90%

Leases - Supplemental Cash Flow

Leases - Supplemental Cash Flow Information Related to Leases (Details) - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Lessee Cash Flow Information [Abstract]
Operating cash outflow from finance leases		$ 14,476	$ 7,181	$ 11,453
Operating cash outflow from operating leases		6,318	3,722	3,864
ROU assets obtained in exchange for new finance lease liabilities		0	166,261	0
ROU assets obtained in exchange for new operating lease liabilities	[1]	12,971	474	1,020
Remeasurement of lease liability arising from modification of ROU asset	[2]	$ 5,124	$ 0	$ 0
[1] See EnVen Acquisition in Note 3 — Acquisitions and Divestitures 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.

Financial Instruments - Schedul

Financial Instruments - Schedule of Carrying Amounts and Estimated Fair Values of Financial Instruments (Details) - USD ($) $ in Thousands	Dec. 31, 2023	Dec. 31, 2022
Debt Instrument [Line Items]
Carrying Amount	$ 1,025,674	$ 585,340
12.00% Second-Priority Senior Secured Notes - due January 2026
Debt Instrument [Line Items]
Carrying Amount	601,353	590,132
Fair Value	655,130	674,542
11.75% Senior Secured Second Lien Notes - due April 2026
Debt Instrument [Line Items]
Carrying Amount	234,221	0
Fair Value	233,410	0
Bank Credit Facility - matures March 2027
Debt Instrument [Line Items]
Carrying Amount	190,100
Fair Value	$ 200,000	0
Carrying Amount		$ (4,792)

Financial Instruments - Sched_2

Financial Instruments - Schedule of Carrying Amounts and Estimated Fair Values of Financial Instruments (Parenthetical) (Details)	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022
12.00% Second-Priority Senior Secured Notes - due January 2026
Debt Instrument [Line Items]
Debt instrument interest rate	12%	12%
Senior notes, maturity date	Jan. 15, 2026	Jan. 15, 2026
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

Financial Instruments - Additio

Financial Instruments - Additional Information (Details) $ in Millions	12 Months Ended
	Dec. 31, 2023 USD ($) Counterparty
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, 2023 represent derivative instruments from nine 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 eight of which 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, 2023 would have been $45.6 million.
Maximum loss on commodity contracts | $	$ 45.6
Counterparty Risk Investment Grade
Concentration Risk [Line Items]
Number of counterparties description	all of which
Counterparty Risk Diversification
Concentration Risk [Line Items]
Number of counterparties | Counterparty	9

Financial Instruments - Sched_3

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, 2023	Dec. 31, 2022	Dec. 31, 2021
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative fair value gain (loss)		$ 80,928	$ (272,191)	$ (419,077)
Gain Loss on Derivative Instruments Unrealized Component
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative fair value gain (loss)	[1]	90,385	153,368	(128,913)
Commodity Contract
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative fair value gain (loss)		80,928	(272,191)	(419,077)
Commodity Contract | Gain Loss on Derivative Instruments Realized Component
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative fair value gain (loss)		$ (9,457)	$ (425,559)	$ (290,164)
[1] Includes $ 1.4 million gain from the unrealized derivative instruments acquired from the EnVen Acquisition for the year ended December 31, 2023 .

Financial Instruments - Sched_4

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, 2023	Dec. 31, 2022	Dec. 31, 2021
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative fair value gain (loss)		$ 80,928	$ (272,191)	$ (419,077)
Gain Loss on Derivative Instruments Unrealized Component
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative fair value gain (loss)	[1]	90,385	$ 153,368	$ (128,913)
Gain Loss on Derivative Instruments Unrealized Component | EnVen Energy Corporation [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative fair value gain (loss)		$ 1,400
[1] Includes $ 1.4 million gain from the unrealized derivative instruments acquired from the EnVen Acquisition for the year ended December 31, 2023 .

Financial Instruments - Sched_5

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, 2023 MMBTU $ / MMBTU $ / bbl Bcf bbl
Crude Oil | January 2024 - December 2024 | Swaps
Derivative [Line Items]
Settlement Index	NYMEX WTI CMA
Average Daily Volumes | bbl	16,859
Weighted Average Swap Price	74.30
Crude Oil | January 2024 - December 2024 | Collars
Derivative [Line Items]
Settlement Index	NYMEX WTI CMA
Average Daily Volumes | bbl	1,497
Weighted average put price	70
Weighted average call price	79.32
Crude Oil | January 2024 - March 2024 | Three Way Collar Contracts
Derivative [Line Items]
Settlement Index	NYMEX WTI CMA
Average Daily Volumes | Bcf	3,200
Weighted average put price | $ / MMBTU	70
Weighted average call price	98.01
Crude Oil | January 2024 - March 2024 | Three Way Collar Contracts | Short
Derivative [Line Items]
Short Put Price	57.27
Crude Oil | January 2025 - December 2025 | Swaps
Derivative [Line Items]
Settlement Index	NYMEX WTI CMA
Average Daily Volumes | bbl	7,734
Weighted Average Swap Price	73.80
Natural Gas | January 2024 - December 2024 | Swaps
Derivative [Line Items]
Settlement Index	NYMEX Henry Hub
Weighted Average Swap Price | $ / MMBTU	3.41
Average Daily Volumes | MMBTU	18,716
Natural Gas | January 2024 - December 2024 | Collars
Derivative [Line Items]
Settlement Index	NYMEX Henry Hub
Average Daily Volumes | MMBTU	10,000
Weighted average put price | $ / MMBTU	4
Weighted average call price | $ / MMBTU	6.9
Natural Gas | January 2025 - December 2025 | Swaps
Derivative [Line Items]
Settlement Index	NYMEX Henry Hub
Weighted Average Swap Price | $ / MMBTU	3.92
Average Daily Volumes | MMBTU	13,712

Financial Instruments - Summary

Financial Instruments - Summary of Additional Information Related to Financial Instruments Measured at Fair Value on Recurring Basis (Details) - USD ($) $ in Thousands	Dec. 31, 2023	Dec. 31, 2022
Oil and Natural Gas Derivatives
Assets:
Oil and natural gas derivatives	$ 45,603	$ 0
Liabilities:
Oil and natural gas derivatives	0	(43,359)
Fair Value on Recurring Basis
Liabilities:
Total net asset (liability)	45,603	(43,359)
Fair Value on Recurring Basis | Oil and Natural Gas Derivatives
Assets:
Oil and natural gas derivatives	$ 53,703	$ 32,883
Derivative Asset, Statement of Financial Position [Extensible Enumeration]	Assets	Assets
Liabilities:
Oil and natural gas derivatives	$ (8,100)	$ (76,242)
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)	$ 45,603	$ (43,359)
Fair Value on Recurring Basis | Level 2 | Oil and Natural Gas Derivatives
Assets:
Oil and natural gas derivatives	$ 53,703	$ 32,883
Derivative Asset, Statement of Financial Position [Extensible Enumeration]	Assets	Assets
Liabilities:
Oil and natural gas derivatives	$ (8,100)	$ (76,242)
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

Financial Instruments - Sched_6

Financial Instruments - Schedule of Fair Value of Derivative Financial Instruments (Details) - USD ($) $ in Thousands	Dec. 31, 2023	Dec. 31, 2022
Price Risk Derivatives [Line Items]
Derivative Asset, Current	$ 36,152	$ 25,029
Derivative Asset, Noncurrent	17,551	7,854
Derivative Liability, Current	7,305	68,370
Derivative Liability, Noncurrent	795	7,872
Oil and Natural Gas Derivatives
Price Risk Derivatives [Line Items]
Derivative Asset, Current	36,152	25,029
Derivative Asset, Noncurrent	17,551	7,854
Total gross amounts presented on balance sheet, Assets	53,703	32,883
Gross amounts not offset on the balance sheet	8,100	32,883
Net Amounts	45,603	0
Derivative Liability, Current	7,305	68,370
Derivative Liability, Noncurrent	795	7,872
Total gross amounts presented on balance sheet, Liabilities	8,100	76,242
Gross amounts not offset on the balance sheet	8,100	32,883
Net Amounts	$ 0	$ 43,359

Equity Method Investments - Sch

Equity Method Investments - Schedule of Equity Method Investments (Details) - USD ($) $ in Thousands	Dec. 31, 2023	Dec. 31, 2022
Schedule of Equity Method Investments [Line Items]
Total equity method investments	$ 146,049	$ 1,745
Talos Energy Mexico 7, S. de R.L. de C.V | Upstream
Schedule of Equity Method Investments [Line Items]
Total equity method investments	$ 107,259	0
Equity method investment, ownership interest	50.10%
SP 49 Pipeline LLC | Upstream
Schedule of Equity Method Investments [Line Items]
Total equity method investments	$ 861	374
Equity method investment, ownership interest	33.30%
Bayou Bend CCS LLC | CCS
Schedule of Equity Method Investments [Line Items]
Total equity method investments	$ 28,183	1,371
Equity method investment, ownership interest	25%
Harvest Bend CCS LLC | CCS
Schedule of Equity Method Investments [Line Items]
Total equity method investments	$ 9,746	0
Equity method investment, ownership interest	65%
Coastal Bend CCS LLC | CCS
Schedule of Equity Method Investments [Line Items]
Total equity method investments	$ 0	$ 0
Equity method investment, ownership interest	50%

Equity Method Investments - Add

Equity Method Investments - Additional Information (Details) - USD ($) $ in Thousands			1 Months Ended	12 Months Ended
	May 24, 2022	Mar. 08, 2022	May 31, 2022	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Schedule of Equity Method Investments [Line Items]
Equity method investment payment				$ 29,447	$ 2,250	$ 0
Proceeds from sale of equity method investment				0	15,000	$ 0
Equity Method Investee
Schedule of Equity Method Investments [Line Items]
Related party receivable				5,500
Talos Enrgy Mexico 7, S. de R.L. de C.V | Equity Method Investee | Variable Interest Entity, Not Primary Beneficiary
Schedule of Equity Method Investments [Line Items]
Equity method investment, basis difference				66,000
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%
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%
Equity method investment payment		$ 2,300

Debt - Summary of Detail Compri

Debt - Summary of Detail Comprising Debt and Related Book Values (Details) - USD ($) $ in Thousands	Dec. 31, 2023	Dec. 31, 2022
Debt Instrument [Line Items]
Total debt, before discount, premium and deferred financing cost	$ 1,066,041	$ 638,541
Unamortized discount, premium and deferred financing cost, net	(40,367)	(53,201)
Total debt	1,025,674	585,340
Less: current portion of long-term debt	33,060	0
Long-Term Debt	992,614	585,340
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	638,541	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	227,500	0
Bank Credit Facility | Bank Credit Facility - matures March 2027
Debt Instrument [Line Items]
Total debt, before discount, premium and deferred financing cost	$ 200,000	$ 0

Debt - Summary of Detail Comp_2

Debt - Summary of Detail Comprising Debt and Related Book Values (Parenthetical) (Details)	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Feb. 13, 2023	Jan. 14, 2021
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
Senior Notes | 12.00% Second-Priority Senior Secured Notes - due January 2026
Debt Instrument [Line Items]
Debt instrument interest rate	12%	12%		12%
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%	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

Debt - Additional information (

Debt - Additional information (Details) - USD ($)							12 Months Ended
	Feb. 13, 2023	Dec. 23, 2022	Oct. 27, 2022	Oct. 21, 2022	May 31, 2022	Jan. 13, 2021	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021	Jun. 09, 2023	Jan. 14, 2021
Debt Instrument [Line Items]
Gain (loss) on extinguishment of debt							$ 0	$ (1,569,000)	$ (13,225,000)
Debt instrument, face amount							$ 1,066,041,000	$ 638,541,000
DebtInstrument 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, 2023 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, the indenture governing the 12.00% Notes restricts the Company’s consolidated 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 indenture. 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 2.25 to 1.00, (iii) the ratio of the issuer’s total debt to EBITDA 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.The indenture governing the 11.75% Notes contains a similar restriction on the Company and its consolidated subsidiaries’ ability to declare or pay dividends, subject to exceptions which include, among other things, (i) subject to no default or event of default having occurred or continuing, dividends in an aggregate amount not to exceed the greater of $25 million and 2.5% of Adjusted Consolidated Net Tangible Assets, (ii) dividends or distributions to any parent company to make payments, in lieu of issuing fractional shares in connection with share dividends, share splits, reverse share splits, mergers, consolidations, amalgamations or other business combinations and in connection with the exercise of warrants, options or other securities convertible into or exchangeable for equity interests of the Company. At December 31, 2023, restricted net assets of the Company’s consolidated subsidiaries exceeded 25%.Subsequent Event — Debt OfferingOn February 7, 2024, the Company closed an upsized offering (the “Debt Offering”) for the sale of $1,250.0 million in aggregate principal amount of second-priority senior secured notes, consisting of $625.0 million aggregate principal amount of second-priority senior secured notes due 2029 and $625.0 million aggregate principal amount of second-priority senior secured notes due 2031 (collectively, the “New Senior Notes”), in a private offering to eligible purchasers that is exempt from registration under the Securities Act. The net proceeds from the Debt Offering (i) are expected to fund a portion of the cash consideration for the pending QuarterNorth Acquisition, (ii) funded the redemption of all of the outstanding 12.00% Notes and all of the outstanding 11.75% Notes discussed above (the “Redemptions”), and (iii) paid premiums, fees and expenses related to the Redemptions and the issuance of the New Senior Notes. The Company intends to use any remaining net proceeds for general corporate purposes, which may include the repayment of a portion of the outstanding borrowings under the Bank Credit Facility.An aggregate of $340.0 million principal amount of the New Senior Notes will be subject to a “special mandatory redemption” in the event that the transactions contemplated by the QuarterNorth Merger Agreement are not consummated on or before May 31, 2024 (or up to September 30, 2024 solely in the event the parties require additional time to satisfy certain requirements under the Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended, pursuant to the terms of the QuarterNorth Merger Agreement), or if we notify the trustee of the New Senior Notes that we will not pursue the consummation of the QuarterNorth Acquisition.
EnVen Energy Corporation
Debt Instrument [Line Items]
Business Acquisition, Effective Date of Acquisition	Feb. 13, 2023
Minimum
Debt Instrument [Line Items]
Restricted net assets, subsidiaries exceeded							25%
11.00% Second-Priority Senior Secured Notes - due April 2022
Debt Instrument [Line Items]
Debt instrument, redemption price, percentage						102.75%
11.75% Senior Secured Second Lien Notes - due April 2026
Debt Instrument [Line Items]
Debt instrument maturity date							Apr. 15, 2026	Apr. 15, 2026
Debt instrument, interest rate, stated percentage							11.75%	11.75%
11.75% Senior Secured Second Lien Notes - due April 2026 | Maximum | Restrictions which limit the payment of dividends
Debt Instrument [Line Items]
Dividends							$ 25,000,000
Percentage of adjusted consolidated net tangible assets							2.50%
7.50% Senior Notes – due May 2022
Debt Instrument [Line Items]
Debt instrument maturity date					May 31, 2022
Debt instrument, interest rate, stated percentage					7.50%
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					$ 6,100,000
12.00% Second-Priority Senior Secured Notes - due January 2026
Debt Instrument [Line Items]
Fixed Charge Coverage Ratio Satisfied With Incurrence Of Additional Indebtedness Amount							$ 1
Date of Second Supplemental Indenture			Oct. 27, 2022
12.00% Second-Priority Senior Secured Notes - due January 2026 | Maximum | Restrictions which limit the payment of dividends
Debt Instrument [Line Items]
Consolidated total debt to EBITDAX ratio							3
Debt instrument fixed charge coverage ratio							2.25
Bank Credit Facility - matures March 2027
Debt Instrument [Line Items]
Credit facility, maximum borrowing capacity							$ 1,075,000,000
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. On December 23, 2022, the Company entered into the Incremental Agreement and Ninth Amendment to Credit Agreement (the “Ninth Amendment”). The Ninth Amendment, among other things, (i) extended the maturity date of the Bank Credit Facility from November 12, 2024 to March 31, 2027, (ii) increased the borrowing base from $1.1 billion to $1.5 billion and (iii) increased commitments from $806.3 million to $965.0 million, in each case went into effect upon the closing of the EnVen Acquisition and the occurrence of certain events related thereto. On June 9, 2023, the borrowing base decreased from $1.5 billion to $1.1 billion and commitments were reaffirmed at $965.0 million as part of the biannual determination.
Percentage of mortgage covering oil and natural gas assets							85%
Line of Credit Facility, Commitments							$ 965,000,000
Bank Credit Facility - matures March 2027 | Letter of Credit
Debt Instrument [Line Items]
Line of Credit Facility, Commitments							$ 150,000,000
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%
Bank Credit Facility - matures March 2027 | Adjusted Term Secured Overnight Financing Rate [Member]
Debt Instrument [Line Items]
Debt Instrument, Basis Spread on Variable Rate							0.10%
Bank Credit Facility - 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							$ 250,000,000
Bank 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.
Line of Credit Facility, Commitments										$ 965,000,000
Bank Credit Facility | Restrictions which limit the payment of dividends
Debt Instrument [Line Items]
Percentage of commitments exceeding the effective loan limit							25%
Bank Credit Facility | Pro Forma
Debt Instrument [Line Items]
Debt instrument maturity date		Mar. 31, 2027
Bank Credit Facility | Minimum
Debt Instrument [Line Items]
Credit facility, maximum borrowing capacity										1,100,000,000
Bank Credit Facility | Minimum | Restrictions which limit the payment of dividends
Debt Instrument [Line Items]
Pro Forma Current Ratio							1
Bank Credit Facility | Minimum | Pro Forma
Debt Instrument [Line Items]
Credit facility, maximum borrowing capacity		$ 1,100,000,000
Line of Credit Facility, Commitments		806,300,000
Bank Credit Facility | Maximum
Debt Instrument [Line Items]
Credit facility, maximum borrowing capacity										$ 1,500,000,000
Bank Credit Facility | Maximum | Restrictions which limit the payment of dividends
Debt Instrument [Line Items]
Consolidated total debt to EBITDAX ratio							1
Bank Credit Facility | Maximum | Pro Forma
Debt Instrument [Line Items]
Credit facility, maximum borrowing capacity		1,500,000,000
Line of Credit Facility, Commitments		$ 965,000,000
Bank Credit Facility | Maximum | Restricted payments does not exceed the available free cash flow amount | Restrictions which limit the payment of dividends
Debt Instrument [Line Items]
Consolidated total debt to EBITDAX ratio							1.75
Enven Second Lien Notes
Debt Instrument [Line Items]
Debt instrument maturity date	Apr. 15, 2026
Enven Second Lien Notes | EnVen Energy Corporation
Debt Instrument [Line Items]
Debt instrument, face amount	$ 257,500,000
Level 1 | Term Benchmark Loans and RFR Loan
Debt Instrument [Line Items]
Debt Instrument, Basis Spread on Variable Rate							2.75%
Level 1 | Alternate Base Rate
Debt Instrument [Line Items]
Debt Instrument, Basis Spread on Variable Rate							1.75%
Level 2 | Term Benchmark Loans and RFR Loan
Debt Instrument [Line Items]
Debt Instrument, Basis Spread on Variable Rate							3%
Level 2 | Alternate Base Rate
Debt Instrument [Line Items]
Debt Instrument, Basis Spread on Variable Rate							2%
Senior Notes | 11.00% Second-Priority Senior Secured Notes - due April 2022
Debt Instrument [Line Items]
Debt instrument, interest rate, stated percentage						11%
Debt instrument, repurchase amount						$ 347,300,000
Senior Notes | 11.00% Second-Priority Senior Secured Notes - due April 2022 | Other Income (Expense)
Debt Instrument [Line Items]
Gain (loss) on extinguishment of debt									$ (13,200,000)
Senior Notes | 11.75% Senior Secured Second Lien Notes - due April 2026
Debt Instrument [Line Items]
Debt instrument maturity date							Apr. 15, 2026	Apr. 15, 2026
Debt instrument frequency of periodic payment	The indenture governing the 11.75% Notes requires the redemption of $15.0 million of the principal amount outstanding at par value on April 15th and October 15th of each year.
Debt instrument, interest rate, stated percentage	11.75%						11.75%	11.75%
Debt instrument redemption, description							The Company may redeem all or a portion of the 11.75% Notes in whole at any time or in part from time to time at the following redemption prices (expressed as percentages of principal amount) plus accrued and unpaid interest if redeemed during the period commencing on February 15 of the years set forth below:
Debt instrument, face amount							$ 227,500,000	$ 0
Senior Notes | 12.00% Second-Priority Senior Secured Notes - due January 2026
Debt Instrument [Line Items]
Debt instrument, redemption price, percentage				12%
Debt instrument maturity date							Jan. 15, 2026	Jan. 15, 2026
Debt instrument frequency of periodic payment							semi-annually
Debt instrument payment terms							semi-annually each January 15 and July 15
Debt instrument, interest rate, stated percentage							12%	12%			12%
Debt instrument redemption, description							The Company may redeem all or a portion of the 12.00% Notes in whole at any time or in part from time to time at the following redemption prices (expressed as percentages of principal amount) plus accrued and unpaid interest if redeemed during the period commencing on January 15 of the years set forth below
Debt instrument, face amount							$ 638,541,000	$ 638,541,000
Notes Solicitation Consents Fee Consideration	$ 3,100,000
Debt instrument, repurchase amount								11,500,000
Senior Notes | 12.00% Second-Priority Senior Secured Notes - due January 2026 | Other Income (Expense)
Debt Instrument [Line Items]
Gain (loss) on extinguishment of debt								(1,600,000)
Senior Notes | Enven Second Lien Notes
Debt Instrument [Line Items]
Debt instrument, periodic payment, principal	$ 15,000,000
Line of Credit [Member]
Debt Instrument [Line Items]
Line of Credit Facility, Borrowing Capacity, Description							The Bank Credit Facility provides for the determination of the borrowing base based on the Company’s proved producing reserves and a portion of the Company's proved undeveloped reserves.
Line of Credit [Member] | Bank Credit Facility - matures March 2027
Debt Instrument [Line Items]
Weighted average interest rate							8.26%
Debt instrument, face amount							$ 200,000,000	$ 0
Notes Solicitation Consent [Member] | 12.00% Second-Priority Senior Secured Notes - due January 2026
Debt Instrument [Line Items]
Amount of notes consents received from notes consent solicitation			95.80%
Notes Solicitation Consents Fee Consideration, Basis Points			0.50%
Notes Solicitation Consent Permit Enven Senior Notes Indebtedness | Enven Second Lien Notes | EnVen Energy Corporation
Debt Instrument [Line Items]
Debt instrument, interest rate, stated percentage				11.75%

Debt - Subsequent Event (Detail

Debt - Subsequent Event (Details) - USD ($) $ in Millions						12 Months Ended
	Feb. 07, 2024	Jan. 26, 2024	Jan. 23, 2024	Jan. 13, 2024	Oct. 21, 2022	Dec. 31, 2023	Feb. 13, 2023	Dec. 31, 2022	Jan. 14, 2021
12.00% Second-Priority Senior Secured Notes - due January 2026 | Senior Notes
Debt Instrument [Line Items]
Debt instrument redemption, description						The Company may redeem all or a portion of the 12.00% Notes in whole at any time or in part from time to time at the following redemption prices (expressed as percentages of principal amount) plus accrued and unpaid interest if redeemed during the period commencing on January 15 of the years set forth below
Debt instrument, interest rate, stated percentage						12%		12%	12%
Debt instrument, redemption price, percentage					12%
12.00% Second-Priority Senior Secured Notes - due January 2026 | Subsequent Event
Debt Instrument [Line Items]
Debt instrument redemption, description			On January 23, 2024, the Company issued a conditional notice to redeem in full the 12.00% Notes at a redemption price of 103.00% of the principal amount thereof, plus accrued and unpaid interest to, but excluding, the redemption date, in accordance with the 12.00% Notes indenture. The 12.00% Notes were redeemed on February 7, 2024 for $662.4 million utilizing the net proceeds from the Debt Offering (as defined below).
Debt instrument, redemption price, percentage			103%
12.00% Second-Priority Senior Secured Notes - due January 2026 | Subsequent Event | Senior Notes
Debt Instrument [Line Items]
Debt instrument, interest rate, stated percentage			12%
12.00% Second-Priority Senior Secured Notes - due February 2023 | Subsequent Event
Debt Instrument [Line Items]
Redemption of Senior secured notes	$ 662.4
Eleven Point Seven Five Percent Senior Secured Second Lien Notes Due April Two Thousand Twenty Six [Member]
Debt Instrument [Line Items]
Debt instrument, interest rate, stated percentage						11.75%		11.75%
Eleven Point Seven Five Percent Senior Secured Second Lien Notes Due April Two Thousand Twenty Six [Member] | Senior Notes
Debt Instrument [Line Items]
Debt instrument redemption, description						The Company may redeem all or a portion of the 11.75% Notes in whole at any time or in part from time to time at the following redemption prices (expressed as percentages of principal amount) plus accrued and unpaid interest if redeemed during the period commencing on February 15 of the years set forth below:
Debt instrument, interest rate, stated percentage						11.75%	11.75%	11.75%
Eleven Point Seven Five Percent Senior Secured Second Lien Notes Due April Two Thousand Twenty Six [Member] | Subsequent Event
Debt Instrument [Line Items]
Debt instrument redemption, description		On January 26, 2024, the Company issued a conditional notice to redeem in full the 11.75% Notes at a redemption price of 102.938% of the principal amount thereof, plus accrued and unpaid interest to, but excluding, the redemption date, in accordance with the 11.75% Notes Indenture. The Company irrevocably deposited funds with the trustee sufficient to satisfy and discharge the 11.75% Notes Indenture and the 11.75% Notes until redeemed on April 15, 2024 with the funds deposited with the trustee and elected to satisfy and discharge the 11.75% Notes Indenture in accordance with its terms and the 11.75% Notes trustee acknowledged such discharge and satisfaction. The Company deposited $247.5 million with the trustee on February 7, 2024 utilizing the net proceeds from the Debt Offering.
Debt instrument, redemption price, percentage		102.938%
Funds deposited with trustee	247.5
Eleven Point Seven Five Percent Senior Secured Second Lien Notes Due April Two Thousand Twenty Six [Member] | Subsequent Event | Senior Notes
Debt Instrument [Line Items]
Debt instrument, interest rate, stated percentage		11.75%
Bank Credit Facility - matures March 2027
Debt Instrument [Line Items]
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. On December 23, 2022, the Company entered into the Incremental Agreement and Ninth Amendment to Credit Agreement (the “Ninth Amendment”). The Ninth Amendment, among other things, (i) extended the maturity date of the Bank Credit Facility from November 12, 2024 to March 31, 2027, (ii) increased the borrowing base from $1.1 billion to $1.5 billion and (iii) increased commitments from $806.3 million to $965.0 million, in each case went into effect upon the closing of the EnVen Acquisition and the occurrence of certain events related thereto. On June 9, 2023, the borrowing base decreased from $1.5 billion to $1.1 billion and commitments were reaffirmed at $965.0 million as part of the biannual determination.
Credit facility, maximum borrowing capacity						$ 1,075
Bank Credit Facility - matures March 2027 | Subsequent Event
Debt Instrument [Line Items]
Bank credit facility, description				On January 13, 2024, the Company entered into the Tenth Amendment to Credit Agreement (the “Tenth Amendment”). The Tenth Amendment, among other things, (i) permits the incurrence of additional indebtedness in order to fund the QuarterNorth Acquisition, with such indebtedness excluded from any reduction of the borrowing base that would otherwise result from such incurrence, and (ii) reaffirms the borrowing base at $1.1 billion effective upon closing of the QuarterNorth Acquisition.
Bank Credit Facility - matures March 2027 | Subsequent Event | Pro Forma
Debt Instrument [Line Items]
Credit facility, maximum borrowing capacity				$ 1,100
Second Priority Senior Secured Notes | Subsequent Event
Debt Instrument [Line Items]
Debt instrument, face amount	1,250
Second-Priority Senior Secured Notes Due 2029 | Subsequent Event
Debt Instrument [Line Items]
Debt instrument, face amount	625
Second-Priority Senior Secured Notes Due 2031 | Subsequent Event
Debt Instrument [Line Items]
Debt instrument, face amount	625
New Senior Notes | Subsequent Event | Debentures Subject to Mandatory Redemption
Debt Instrument [Line Items]
Debt instrument, face amount	$ 340

Debt - Summary of Redemption Pr

Debt - Summary of Redemption Prices of 12.00% and 11.75% Notes (Details)			12 Months Ended
	Jan. 26, 2024	Jan. 23, 2024	Dec. 31, 2023
12.00% Second-Priority Senior Secured Notes - due January 2026 | Debt Instrument, Redemption, Period Three
Debt Instrument, Redemption [Line Items]
Debt instrument, redemption price, percentage			106%
12.00% Second-Priority Senior Secured Notes - due January 2026 | Debt Instrument, Redemption, Period Four
Debt Instrument, Redemption [Line Items]
Debt instrument, redemption price, percentage			103%
12.00% Second-Priority Senior Secured Notes - due January 2026 | Debt Instrument, Redemption, Period After Five
Debt Instrument, Redemption [Line Items]
Debt instrument, redemption price, percentage			100%
12.00% Second-Priority Senior Secured Notes - due January 2026 | Subsequent Event
Debt Instrument, Redemption [Line Items]
Debt instrument, redemption price, percentage		103%
11.75% Senior Secured Second Lien Notes - due April 2026 | Debt Instrument, Redemption, Period Three
Debt Instrument, Redemption [Line Items]
Debt instrument, redemption price, percentage			105.875%
11.75% Senior Secured Second Lien Notes - due April 2026 | Debt Instrument, Redemption, Period Four
Debt Instrument, Redemption [Line Items]
Debt instrument, redemption price, percentage			102.938%
11.75% Senior Secured Second Lien Notes - due April 2026 | Debt Instrument, Redemption, Period After Five
Debt Instrument, Redemption [Line Items]
Debt instrument, redemption price, percentage			100%
11.75% Senior Secured Second Lien Notes - due April 2026 | Subsequent Event
Debt Instrument, Redemption [Line Items]
Debt instrument, redemption price, percentage	102.938%

Debt - Schedule of Pricing Grid

Debt - Schedule of Pricing Grid for Borrowing Base Utilization Percentage (Details)	12 Months Ended
	Dec. 31, 2023
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%
Level 2 | Alternate Base Rate
Debt Instrument [Line Items]
Basis Spread on Variable Rate	2%
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%
Maximum [Member] | Level 2
Debt Instrument [Line Items]
Utilization	50%
Maximum [Member] | Level 3
Debt Instrument [Line Items]
Utilization	75%
Maximum [Member] | Level 4
Debt Instrument [Line Items]
Utilization	90%
Minimum [Member] | Level 2
Debt Instrument [Line Items]
Utilization	25%
Minimum [Member] | Level 3
Debt Instrument [Line Items]
Utilization	50%
Minimum [Member] | Level 4
Debt Instrument [Line Items]
Utilization	75%
Minimum [Member] | Level 5
Debt Instrument [Line Items]
Utilization	90%

Asset Retirement Obligations -

Asset Retirement Obligations - Schedule of Asset Retirement Obligations (Details) - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Asset Retirement Obligation Disclosure [Abstract]
Balance, beginning of period		$ 541,661	$ 434,006
Obligations assumed	[1]	258,858	0
Obligations incurred		14,199	1,140
Obligations settled		(86,615)	(69,596)
Obligations divested		(19,448)	(1,572)
Accretion expense		86,152	55,995	$ 58,129
Changes in estimate	[2]	102,419	121,688
Balance, end of period		897,226	541,661	$ 434,006
Less: Current portion		77,581	39,888
Long-term portion		$ 819,645	$ 501,773
[1] Assumed in connection with the EnVen Acquisition. See further discussion in Note 3 — Acquisitions and Divestitures . Changes in estimate were primarily due to an increase in estimated service costs. Additionally, increases for the year ended December 31, 2023 due to the acceleration of estimated settlement date.

Asset Retirement Obligations (A

Asset Retirement Obligations (Additional Information) (Details) - USD ($) $ in Thousands	Dec. 31, 2023	Dec. 31, 2022
Restricted cash	$ 102,362	$ 0
EnVen Energy Corporation
Receivable with imputed interest, face amount	66,200
Future Plugging and Abanonment Obligations
Restricted cash	$ 102,400

Employee Benefits Plans and S_3

Employee Benefits Plans and Share-Based Compensation - Additional Information (Details) - USD ($) $ in Millions	1 Months Ended	12 Months Ended
	Mar. 31, 2022	Dec. 31, 2023		Dec. 31, 2022		Dec. 31, 2021	Feb. 13, 2023
Employee Severance [Member] | TALOEnven Energy Corporation [Member]
Share Based Compensation Arrangement By Share Based Payment Award Line Items
Asset, Held-in-Trust		$ 3.7					$ 14.5
Asset, Held-in-Trust, Current		3.3
Asset, Held-in-Trust, Noncurrent		$ 0.4
Restricted Stock Units
Share Based Compensation Arrangement By Share Based Payment Award Line Items
Unvested restricted stock units and award, granted		1,154,541		2,297,465		1,102,038
Share-Based Payment Arrangement, Plan Modification, Incremental Cost		$ 9.7
Performance Shares
Share Based Compensation Arrangement By Share Based Payment Award Line Items
Contingent Right Upon Vesting to Receive Common Stock		1
Share-based compensation expense recognized period		1 year 8 months 12 days
Share-based compensation expense unrecognized		$ 8.7
Unvested restricted stock units and award, granted		595,394	[1]	629,666	[2]	586,995
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%
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%
Executive Officer | Restricted Stock Units
Share Based Compensation Arrangement By Share Based Payment Award Line Items
Unvested restricted stock units and award, granted	1,147,352
Long Term Incentive Plan
Share Based Compensation Arrangement By Share Based Payment Award Line Items
Share-Based Compensation authorized to grant		8,639,415
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
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		1 year 8 months 12 days
Share-based compensation expense unrecognized		$ 19
Long Term Incentive Plan | Non-employee Directors | 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
Share-based compensation expense recognized period		2 months 12 days
Contingent Right Upon Vesting to Receive Common Stock Percentage		60%
Contingent Right Upon Vesting to Receive Cash Percentage		40%
Share-based compensation expense liabilities		$ 0.1
Share-based compensation expense unrecognized		$ 0.1
[1] There were 297,697 PSUs granted that are eligible to vest based on continued employment and the Company’s annualized absolute TSR over a three-year performance period. An additional 297,697 PSUs were granted and are eligible to vest based on continued employment and the Company’s return on the wells included in the 2023 drill program over a three-year performance period. There were 314,833 PSUs granted that are eligible to vest based on continued employment and the Company’s annualized absolute total shareholder return (“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.

Employee Benefits Plans and S_4

Employee Benefits Plans and Share-Based Compensation - Schedule Of Acquisition Severance Costs (Details) - Taloenven Energy Corporation Member - Employee Severance $ in Thousands	12 Months Ended
	Dec. 31, 2023 USD ($)
Acquisition Severance Costs Line Items
Severance accrual at December 31, 2022	$ 0
Accrual additions	25,348
Benefit payments	(19,054)
Severance accrual at December 31, 2023	6,294
Less: Current portion at December 31, 2023	6,190
Long-term portion at December 31, 2023	$ 104

Employee Benefits Plans and S_5

Employee Benefits Plans and Share-Based Compensation - Schedule of Restricted Stock and Performance Share Units Activity (Details) - $ / shares	12 Months Ended
	Dec. 31, 2023		Dec. 31, 2022		Dec. 31, 2021
Restricted Stock Units
Share Based Compensation Arrangement By Share Based Payment Award Line Items
Unvested beginning of the period	3,215,504	[1]	1,983,199		1,652,988
Granted	1,154,541		2,297,465		1,102,038
Vested	(1,730,959)		(967,269)		(669,832)
Forfeited	(332,725)		(97,891)		(101,995)
Unvested end of the period	2,306,361	[1]	3,215,504	[1]	1,983,199
Unvested weighted average grant date fair value, beginning of the period	$ 12.79	[1]	$ 13.02		$ 13.73
Unvested weighted average grant date fair value, granted	16.24		13.23		13.11
Unvested weighted average grant date fair value, vested	11.97		14.14		15.01
Unvested weighted average grant date fair value, forfeited	14.52		14.34		12.46
Unvested weighted average grant date fair value, end of the period	$ 14.89	[1]	$ 12.79	[1]	$ 13.02
Performance Shares
Share Based Compensation Arrangement By Share Based Payment Award Line Items
Unvested beginning of the period	638,601		1,015,459		834,172
Granted	595,394	[2]	629,666	[3]	586,995
Vested			(14,474)	[4]	(391,308)
Forfeited	(217,346)		(16,486)		(14,400)
Cancelled			(975,564)
Unvested end of the period	1,016,649		638,601		1,015,459
Unvested weighted average grant date fair value, beginning of the period	$ 23.66		$ 16.41		$ 25.46
Unvested weighted average grant date fair value, granted	18.76	[2]	23.73	[3]	18.96
Unvested weighted average grant date fair value, vested			13.05	[4]	39.43
Unvested weighted average grant date fair value, forfeited	21.28		17.48		18.48
Unvested weighted average grant date fair value, Cancelled			16.42
Unvested weighted average grant date fair value, end of the period	$ 21.3		$ 23.66		$ 16.41
[1] As of December 31, 2023 and 2022 , 26,975 and 25,257 , respectively, of the unvested RSUs were accounted for as liability awards in “Accrued liabilities” on the Consolidated Balance Sheet. 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. There were 314,833 PSUs granted that are eligible to vest based on continued employment and the Company’s annualized absolute total shareholder return (“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. 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 will again be available for new awards under the recycling provisions of the 2021 LTIP.

Employee Benefits Plans and S_6

Employee Benefits Plans and Share-Based Compensation - Schedule of Restricted Stock and Performance Share Units Activity (Parenthetical) (Details) - shares	12 Months Ended
	Dec. 31, 2023		Dec. 31, 2022		Dec. 31, 2021	Dec. 31, 2020
Restricted Stock Units
Share Based Compensation Arrangement By Share Based Payment Award Line Items
Granted	1,154,541		2,297,465		1,102,038
Unvested RSUs	2,306,361	[1]	3,215,504	[1]	1,983,199	1,652,988
Performance Shares
Share Based Compensation Arrangement By Share Based Payment Award Line Items
Granted	595,394	[2]	629,666	[3]	586,995
Unvested RSUs	1,016,649		638,601		1,015,459	834,172
Maximum | Performance Shares
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%
Minimum | Performance Shares
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%
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%
Accrued Liabilities | Restricted Stock Units
Share Based Compensation Arrangement By Share Based Payment Award Line Items
Unvested RSUs	26,975		25,257
[1] As of December 31, 2023 and 2022 , 26,975 and 25,257 , respectively, of the unvested RSUs were accounted for as liability awards in “Accrued liabilities” on the Consolidated Balance Sheet. 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. There were 314,833 PSUs granted that are eligible to vest based on continued employment and the Company’s annualized absolute total shareholder return (“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.

Employee Benefits Plans and S_7

Employee Benefits Plans and Share-Based Compensation - Summary of Assumptions Used to Calculate the Grant Date Fair Value (Details) - Performance Shares - USD ($) $ in Thousands	Dec. 01, 2023	Jul. 01, 2023	Mar. 05, 2023	Sep. 20, 2022	Mar. 05, 2022	May 11, 2021	Mar. 08, 2021
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%
Fair value (in thousands)	$ 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%
Fair value (in thousands)		$ 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%
Fair value (in thousands)			$ 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%
Fair value (in thousands)				$ 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%
Fair value (in thousands)					$ 8,668
Grant Date May 11, 2021
Share Based Compensation Arrangement By Share Based Payment Award Line Items
Expected term (in years)						2 years 7 months 6 days
Expected volatility						80.90%
Risk-free interest rate						0.30%
Dividend yield						0%
Fair value (in thousands)						$ 9,715
Grant Date March 8, 2021
Share Based Compensation Arrangement By Share Based Payment Award Line Items
Expected term (in years)							2 years 9 months 18 days
Expected volatility							78.30%
Risk-free interest rate							0.30%
Dividend yield							0%
Fair value (in thousands)							$ 11,129

Employee Benefits Plans and S_8

Employee Benefits Plans and Share-Based Compensation - Schedule of Recognized Share Based Compensation Expense, Net (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Share-Based Payment Arrangement [Abstract]
Share-based compensation costs	$ 25,236	$ 28,280	$ 20,560
Less: Amounts capitalized to oil and gas properties	12,283	12,327	9,568
Share-Based Payment Arrangement, Expense	$ 12,953	$ 15,953	$ 10,992

Income Taxes - Components of In

Income Taxes - Components of Income Tax Expense (Benefit) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Current income tax expense (benefit)
United States	$ 76	$ 1,375	$ (5)
Mexico	31	432	(993)
Total current income tax expense (benefit)	107	1,807	(998)
Deferred income tax expense (benefit)
United States	(60,704)	659	(1,067)
Mexico	0	71	430
Total deferred income tax expense (benefit)	(60,704)	730	(637)
Total income tax expense (benefit)	$ (60,597)	$ 2,537	$ (1,635)

Income Taxes - Summary of Recon

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, 2023	Dec. 31, 2022	Dec. 31, 2021
Income Tax Disclosure [Abstract]
Income tax expense (benefit) at the federal statutory tax rate	$ 26,614	$ 80,735	$ (38,763)
State income taxes	1,748	1,591	(674)
Impact of foreign operations	13,539	15,657	(11,920)
Effect of change in state rate	0	0	2,008
Prior year taxes	1,184	(2,920)	486
Change in valuation allowance	(106,815)	(96,537)	45,547
Other permanent differences	3,133	4,011	1,681
Total income tax expense (benefit)	$ (60,597)	$ 2,537	$ (1,635)
Effective tax rate	(47.81%)	0.66%	0.89%

Income Taxes - Additional Infor

Income Taxes - Additional Information (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021	Feb. 13, 2023
Income Tax Disclosure [Line Items]
Federal statutory rate	21%	21%	21%
Income tax benefit (expense)	$ 60,597	$ (2,537)	$ 1,635
Operating loss carryforwards limitation on use	As of December 31, 2023, the Company had U.S. federal net operating loss carryforwards (“NOLs”) of approximately $701.2 million, all of which are subject to limitation under Section 382 of the IRC. IRC Section 382 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 2035.
Valuation allowance	$ 23,697	$ 129,105
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.
EnVen Energy Corporation
Income Tax Disclosure [Line Items]
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Deferred Tax Liabilities				$ 150,264
Earliest Tax Year
Income Tax Disclosure [Line Items]
Income tax examination, Year	2020
Latest Tax Year
Income Tax Disclosure [Line Items]
Income tax examination, Year	2023
Federal
Income Tax Disclosure [Line Items]
Operating loss carryforwards	$ 701,200
State
Income Tax Disclosure [Line Items]
Deferred tax assets, valuation allowance expense (benefit)	$ (106,800)
Internal Revenue Code | Federal | Capital loss carryforward
Income Tax Disclosure [Line Items]
Operating loss carryforwards expiration year	2035

Income Taxes - Summary of Signi

Income Taxes - Summary of Significant Components of Deferred Tax Assets and Liabilities (Details) - USD ($) $ in Thousands	Dec. 31, 2023	Dec. 31, 2022
Deferred tax assets:
Federal net operating loss	$ 147,252	$ 159,257
Foreign tax loss carryforward	509	44,462
State net operating loss	24,840	24,787
Tax credits	107	107
Interest expense carryforward	46,414	23,262
Asset retirement obligations	190,248	115,848
Derivatives	0	9,273
Other well equipment	1,317	1,891
Accrued bonus	5,050	5,863
Share-based compensation	5,172	5,296
Operating lease liabilities	4,427	3,669
Finance lease liabilities	31,607	32,559
Other	3,383	7,142
Total deferred tax assets	460,326	433,416
Valuation allowance	(23,697)	(129,105)
Total deferred tax assets, net	436,629	304,311
Deferred tax liabilities:
Oil and gas properties	512,918	302,602
Operating lease assets	2,421	1,323
Derivatives	9,670	0
Prepaid	3,847	2,530
Total deferred tax liabilities	528,856	306,455
Net deferred tax liability	$ (92,227)	$ (2,144)

Income Taxes - Summary of Net O

Income Taxes - Summary of Net Operating Loss Carryovers (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2023 USD ($)
Operating Loss Carryforwards [Line Items]
Operating loss carryforwards limitation on use	As of December 31, 2023, the Company had U.S. federal net operating loss carryforwards (“NOLs”) of approximately $701.2 million, all of which are subject to limitation under Section 382 of the IRC. IRC Section 382 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 2035.
Federal
Operating Loss Carryforwards [Line Items]
Net operating losses carryforward, Amount	$ 701,200
Federal | Minimum
Operating Loss Carryforwards [Line Items]
Net operating losses, Expiration year	2035
Federal | Maximum
Operating Loss Carryforwards [Line Items]
Net operating losses, Expiration year	2037
Federal | 2035 - 2037
Operating Loss Carryforwards [Line Items]
Net operating losses carryforward, Amount	$ 452,393
Federal | Unlimited Expiration Year
Operating Loss Carryforwards [Line Items]
Net operating losses carryforward, Amount	$ 248,807
Operating loss carryforwards limitation on use	Unlimited
Foreign | Minimum
Operating Loss Carryforwards [Line Items]
Net operating losses, Expiration year	2025
Foreign | Maximum
Operating Loss Carryforwards [Line Items]
Net operating losses, Expiration year	2032
Foreign | 2025 - 2032
Operating Loss Carryforwards [Line Items]
Net operating losses carryforward, Amount	$ 1,696
State | Minimum
Operating Loss Carryforwards [Line Items]
Net operating losses, Expiration year	2025
State | Maximum
Operating Loss Carryforwards [Line Items]
Net operating losses, Expiration year	2037
State | Unlimited Expiration Year
Operating Loss Carryforwards [Line Items]
Net operating losses carryforward, Amount	$ 277,930
Operating loss carryforwards limitation on use	Unlimited
State | 2025 - 2037
Operating Loss Carryforwards [Line Items]
Net operating losses carryforward, Amount	$ 125,958

Income Taxes - Summary of Balan

Income Taxes - Summary of Balances In Uncertain Tax Positions (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Income Tax Uncertainties [Abstract]
Total unrecognized tax benefits, beginning balance	$ 835	$ 696	$ 648
Tax positions taken during a prior period	154	100	21
Tax positions taken during the current period	0	39	27
Total unrecognized tax benefits, ending balance	$ 989	$ 835	$ 696

Income (Loss) Per Share - Summa

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, 2023	Dec. 31, 2022	Dec. 31, 2021
Earnings Per Share [Abstract]
Net Income (Loss)	$ 187,332	$ 381,915	$ (182,952)
Weighted average common shares outstanding — basic	119,894	82,454	81,769
Dilutive effect of securities	858	1,229	0
Weighted average common shares outstanding — diluted	120,752	83,683	81,769
Basic	$ 1.56	$ 4.63	$ (2.24)
Diluted	$ 1.55	$ 4.56	$ (2.24)
Anti-dilutive potentially issuable securities excluded from diluted common shares	1,353	865	1,709

Related Party Transactions - Ad

Related Party Transactions - Additional Information (Details) - USD ($) $ in Thousands				1 Months Ended	12 Months Ended
	Feb. 07, 2024	Feb. 13, 2023	Sep. 21, 2022	Aug. 31, 2018	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021	Jan. 22, 2024
Related Party Transaction [Line Items]
General and administrative expense					$ 158,493	$ 99,754	$ 78,677
Stockholders agreement date					May 10, 2018
Stockholders agreement amendment date					Feb. 24, 2020
Amended restated stockholders agreement termination date		Feb. 13, 2023
Amended restated stockholders agreement date					Mar. 29, 2022
Second Priority Senior Secured Notes | Subsequent Event
Related Party Transaction [Line Items]
Debt Instrument, Face Amount	$ 1,250,000
Franklin or MacKay Shields | Scenario Plan
Related Party Transaction [Line Items]
Registration rights cease, beneficial ownership less than 5%						5%
Slim Family
Related Party Transaction [Line Items]
Related party receivable					$ 0
Investment, Identifier [Axis]: Slim Family Office
Related Party Transaction [Line Items]
Debt Instrument, Face Amount	312,500
Secondary Offering Expenses
Related Party Transaction [Line Items]
General and administrative expense					0	$ 0	700
2022 Registration Rights Agreement | Secondary Offering Expenses
Related Party Transaction [Line Items]
General and administrative expense					0
EnVen Energy Corporation
Related Party Transaction [Line Items]
Business Acquisition, Date of Acquisition Agreement			Sep. 21, 2022
Vinson & Elkins L.L.P.
Related Party Transaction [Line Items]
General and administrative expense					3,300	4,800	3,100
Legal fees payable					$ 800	$ 1,300	200
Beneficial Owner | Adage
Related Party Transaction [Line Items]
Stock ownership percentage					2.30%
Beneficial Owner | BainCapitalLpMember
Related Party Transaction [Line Items]
Stock ownership percentage					12.20%
Beneficial Owner | Slim Family
Related Party Transaction [Line Items]
Stock ownership percentage					12.20%
Beneficial Owner | Slim Family | Subsequent Event
Related Party Transaction [Line Items]
Stock ownership percentage								21.90%
Equity Method Investee
Related Party Transaction [Line Items]
Related party receivable					$ 5,500
Nonrelated Party [Member] | Banco Inbursa [Member] | Subsequent Event
Related Party Transaction [Line Items]
advisory fee	$ 2,700
Whistler Energy II Holdco LLC [Member] | Apollo Funds | Whistler Energy II, LLC
Related Party Transaction [Line Items]
Business Acquisition, Date of Acquisition Agreement				Aug. 31, 2018
Whistler Energy II Holdco LLC [Member] | Apollo Funds | Whistler Energy II, LLC | Other Operating (Income) Expense
Related Party Transaction [Line Items]
Gain (Loss) related to decommissioning obligation settlement							$ 4,400

Commitments and Contingencies -

Commitments and Contingencies - Additional Information (Details) - USD ($) $ in Millions		12 Months Ended
	Mar. 23, 2022	Dec. 31, 2023
Loss Contingencies [Line Items]
Gain (Loss) Related to Litigation Settlement, Total	$ 27.5
EnVen Energy Corporation | Dunwoody [Member] | Other Current Liabilities | Judicial ruling
Loss Contingencies [Line Items]
Litigation settlement, amount awarded to other party		$ 14.3
Surety Bond
Loss Contingencies [Line Items]
Surety performance bonds outstanding		1,400
Bank Credit Facility | Letter of Credit
Loss Contingencies [Line Items]
Letters of credit outstanding amount		$ 10.8

Commitments and Contingencies_2

Commitments and Contingencies - Summary of Total Minimum Commitments (Details) $ in Thousands	Dec. 31, 2023 USD ($)
Contractual Obligation [Line Items]
2024	$ 20,290
2025	327
2026	0
2027	0
Thereafter	0
Total	20,617
Vessel Commitments
Contractual Obligation [Line Items]
2024	13,216	[1]
2025	0	[1]
2026	0	[1]
2027	0	[1]
Thereafter	0	[1]
Total	13,216	[1]
Committed Purchase Orders
Contractual Obligation [Line Items]
2024	3,083	[2]
2025	0	[2]
2026	0	[2]
2027	0	[2]
Thereafter	0	[2]
Total	3,083	[2]
Other Commitments
Contractual Obligation [Line Items]
2024	3,991	[3]
2025	327	[3]
2026	0	[3]
2027	0	[3]
Thereafter	0	[3]
Total	$ 4,318	[3]
[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. 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. Includes commitments associated with the Company’s CCS Segment relating to an equity funding obligation and payments required under a sequestration agreement.

Commitments and Contingencies_3

Commitments and Contingencies - Summary of Decommissioning Obligations Included in Consolidated Balance Sheets (Details) - Decommissioning Abandonment Obligations - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Loss Contingencies [Line Items]
Balance, beginning of period	$ 54,269	$ 24,336	$ 0
Additions	266	8,900	21,056
Changes in estimate	11,613	22,658	0
Reimbursements due from third parties	0	0	3,280
Settlements	(50,584)	(1,625)	0
Balance, end of period	15,564	54,269	24,336
Other Current Liabilities
Loss Contingencies [Line Items]
Less: Current portion	3,280	42,069	3,756
Other Noncurrent Liabilities
Loss Contingencies [Line Items]
Long-term portion	$ 12,284	$ 12,200	$ 20,580

Segment Information - Additiona

Segment Information - Additional Information (Details)	12 Months Ended
	Dec. 31, 2023 Segment
Segment Reporting [Abstract]
Number of operating segments	2
Segment reporting, no asset information [true false]	true

Segment Information- Summary of

Segment Information- Summary of information by Business Segment (Details) - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2023	Dec. 31, 2022		Dec. 31, 2021
Segment Reporting Information Line Items
Revenues from External Customers		$ 1,457,886	$ 1,651,980		$ 1,244,540
Equity in the Net Income (Loss) of Investees Accounted for by the Equity Method		(3,209)	14,222		0
Operating Segments [Member]
Segment Reporting Information Line Items
Revenues from External Customers		1,457,886	1,651,980		1,244,540
Equity in the Net Income (Loss) of Investees Accounted for by the Equity Method		(12,108)	(1,065)		0
Adjusted EBITDA		956,846	847,054		611,016
Segment Expenditures		774,630	455,452		338,822
Operating Segments [Member] | Upstream
Segment Reporting Information Line Items
Revenues from External Customers		1,457,886	1,651,980		1,244,540
Equity in the Net Income (Loss) of Investees Accounted for by the Equity Method		120	101		0
Adjusted EBITDA		979,729	859,840		615,798
Segment Expenditures		733,669	452,674		338,822
Operating Segments [Member] | All Other
Segment Reporting Information Line Items
Revenues from External Customers	[1]	0	0		0
Equity in the Net Income (Loss) of Investees Accounted for by the Equity Method		(12,228)	(1,166)	[1]	0	[1]
Adjusted EBITDA		(22,883)	(12,786)	[1]	(4,782)	[1]
Segment Expenditures	[1]	$ 40,961	$ 2,778		$ 0
[1] The CCS Segment is included in the “All Other” category. The CCS Segment is an emerging business in the start-up phase of operations and the business that does not currently generate any revenues. The CCS Segment’s business activities are conducted through both wholly owned subsidiaries and equity method investments with industry partners. Equity method investments is a business strategy that enables us to achieve favorable economies of scale relative to the level of investment and business risk assumed.

Segment Information - Schedule

Segment Information - Schedule of Reconciliation of Reportable Segment Information to the Company's Consolidated Totals (Details) - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2023	Dec. 31, 2022		Dec. 31, 2021
Segment Reporting Information Line Items
General and Administrative Expense		$ 158,493	$ 99,754		$ 78,677
Interest expense		(173,145)	(125,498)		(133,138)
Depreciation, depletion and amortization		(663,534)	(414,630)		(395,994)
Write-down of oil and natural gas properties		0	0		18,123
Derivative fair value gain (loss)		80,928	(272,191)		(419,077)
Gain (loss) on extinguishment of debt		0	(1,569)		(13,225)
Non-cash equity-based compensation expense		12,953	15,953		10,992
Income (loss) before income taxes		126,735	384,452		(184,587)
Operating Segments
Segment Reporting Information Line Items
Adjusted EBITDA		956,846	847,054		611,016
Segment Reconciling Items
Segment Reporting Information Line Items
Interest expense		(173,145)	(125,498)		(133,138)
Depreciation, depletion and amortization		(663,534)	(414,630)		(395,994)
Accretion expense		(86,152)	(55,995)		(58,129)
Write-down of oil and natural gas properties		0	0		(18,123)
Transaction and other (income) expenses	[1]	33,295	34,513		(5,886)
Decommissioning Obligations	[2]	(11,879)	(31,558)		(21,055)
Derivative fair value gain (loss)	[3]	80,928	(272,191)		(419,077)
Net cash (received) paid on settled derivative instruments	[3]	9,457	425,559		290,164
Gain (loss) on extinguishment of debt		0	(1,569)		(13,225)
Non-cash write-down of other well equipment		0	0		(5,606)
Non-cash equity-based compensation expense		(12,953)	(15,953)		(10,992)
Corporate Non Segment
Segment Reporting Information Line Items
General and Administrative Expense		(6,128)	(5,280)		(4,542)
Reportable segment | Operating Segments
Segment Reporting Information Line Items
Adjusted EBITDA		979,729	859,840		615,798
All Other | Operating Segments
Segment Reporting Information Line Items
Adjusted EBITDA		$ (22,883)	$ (12,786)	[4]	$ (4,782)	[4]
[1] Transaction expenses includes $ 40.4 million and $ 9.0 million in costs related to the EnVen Acquisition, inclusive of $ 25.3 million and nil in severance expense for the years ended December 31, 2023 and 2022, respectively. See further discussion in Note 3 — Acquisition and Divestitures and Note 10 — Employee Benefits Plans and Share-Based Compensation . Other income (expense) includes other miscellaneous income and expenses that the Company does not view as a meaningful indicator of its operating performance. For the year ended December 31, 2023, the amount includes a $ 66.2 million gain on the Mexico Divestiture. See further discussion in Note 3 — Acquisitions and Divestitures . The amount includes a gain on the funding of the capital carry of the Company’s investment in Bayou Bend by Chevron of $ 8.6 million and $ 1.4 million for the year ended December 31, 2023 and 2022, respectively. Additionally, it includes a $ 13.9 million gain on the partial sale of its investment in Bayou Bend to Chevron for the year ended December 31, 2022. See further discussion in Note 7 — Equity Method Investments . For the year ended December 31, 2022, the amount 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 14 — Commitments and Contingencies. Estimated decommissioning obligations were a result of working interest partners or counterparties of divestiture transactions that were unable to perform the required abandonment obligations due to bankruptcy or insolvency. See Note 14 — Commitments and Contingencies for additional information on decommissioning obligations. The adjustments for the derivative fair value (gains) losses and net cash receipts (payments) on settled commodity derivative instruments have the effect of adjusting net loss for changes in the fair value of derivative instruments, which are recognized at the end of each accounting period because the Company does not designate commodity derivative instruments as accounting hedges. This results in reflecting commodity derivative gains and losses within Adjusted EBITDA on an unrealized basis during the period the derivatives settled. The CCS Segment is included in the “All Other” category. The CCS Segment is an emerging business in the start-up phase of operations and the business that does not currently generate any revenues. The CCS Segment’s business activities are conducted through both wholly owned subsidiaries and equity method investments with industry partners. Equity method investments is a business strategy that enables us to achieve favorable economies of scale relative to the level of investment and business risk assumed.

Segment Information - Schedul_2

Segment Information - Schedule of Reconciliation of Reportable Segment Information to the Company's Consolidated Totals (Details) (Parenthetical) - USD ($) $ in Millions		12 Months Ended
	Mar. 23, 2022	Dec. 31, 2023	Dec. 31, 2022
Segment Reporting Information Line Items
Gain (Loss) Related to Litigation Settlement, Total	$ 27.5
Employee Severance | EnVen Energy Corporation
Segment Reporting Information Line Items
Aquisition severance cost		$ 25.3
Operating Segments
Segment Reporting Information Line Items
Gain (Loss) Related to Litigation Settlement, Total			$ 27.5
Operating Segments | Bayou Bend
Segment Reporting Information Line Items
Gain on partial disposal of investment			13.9
Operating Segments | Capital Carry | Bayou Bend
Segment Reporting Information Line Items
Gain on partial disposal of investment		8.6	1.4
Operating Segments | Talos Mexico
Segment Reporting Information Line Items
Disposal group, not discontinued operation, gain (loss) on disposal		66.2
Operating Segments | EnVen Energy Corporation
Segment Reporting Information Line Items
Transaction and other income (expenses)		40.4	9
Operating Segments | Employee Severance | EnVen Energy Corporation
Segment Reporting Information Line Items
Aquisition severance cost		$ 25.3	$ 0

Segment Information - Reconcili

Segment Information - Reconciliation of Reportable Segment Expenditures (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Segment Reporting Information Line Items
Plugging & abandonment	$ 86,615	$ 69,596	$ 67,988
Other deferred payments	(1,545)	0	(7,921)
Exploration, development and other capital expenditures	561,434	323,164	293,331
Operating Segments | Reportable segment
Segment Reporting Information Line Items
Segment Expenditures	733,669	452,674	338,822
Operating Segments | All Other
Segment Reporting Information Line Items
Segment Expenditures	40,961	2,778	0
Segment Reconciling Items
Segment Reporting Information Line Items
Change in capital expenditures included in accounts payable and accrued liabilities	(9,199)	(60,011)	28,258
Plugging & abandonment	(86,615)	(69,596)	(67,988)
Decommissioning obligations settled	(50,584)	(1,625)	0
Investment in CCS intangibles and equity method investees	(40,946)	(2,778)	0
Other deferred payments	(1,545)	0	(7,921)
Insurance recovery proceeds	2,802	0	0
Non-cash well equipment transfers	(27,731)	(6)	1,086
Other	$ 622	$ 1,728	$ 1,074

Supplemental Oil and Gas Disc_3

Supplemental Oil and Gas Disclosures (Unaudited) - Schedule of Capitalized Costs Related to Oil, Natural Gas and NGL Activities and Related Accumulated Depletion and Amortization (Details) $ in Thousands	Dec. 31, 2023 USD ($) $ / Boe	Dec. 31, 2022 USD ($) $ / Boe	Dec. 31, 2021 USD ($) $ / Boe
Reserve Quantities [Line Items]
Proved properties	$ 7,906,295	$ 5,964,340
Unproved oil and gas properties, not subject to amortization	268,315	154,783
Consolidated Entities [Member]
Reserve Quantities [Line Items]
Proved properties	7,906,295	5,964,340	$ 5,232,480
Unproved oil and gas properties, not subject to amortization	268,315	154,783	219,055
Total oil and gas properties	8,174,610	6,119,123	5,451,535
Less: Accumulated depletion	4,143,491	3,484,590	3,072,907
Net capitalized costs	$ 4,031,119	$ 2,634,533	$ 2,378,628
Depletion and amortization rate (Per Boe) | $ / Boe	27.23	18.95	16.71
Equity Method Investee [Member]
Reserve Quantities [Line Items]
Unproved oil and gas properties, not subject to amortization	$ 56,579	$ 0	$ 0

Supplemental Oil and Gas Disc_4

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, 2023	Dec. 31, 2022	Dec. 31, 2021
Capitalized Costs Relating To Oil And Gas Producing Activities By Geographic Area [Line Items]
Unproved properties, not subject to amortization	$ 268,315	$ 154,783
Mexico
Capitalized Costs Relating To Oil And Gas Producing Activities By Geographic Area [Line Items]
Unproved properties, not subject to amortization		$ 111,400	$ 110,300

Supplemental Oil and Gas Disc_5

Supplemental Oil and Gas Disclosures (Unaudited) - Additional Information (Details)	12 Months Ended
	Dec. 31, 2023 MMBoe $ / Mcf $ / bbl	Dec. 31, 2022 MMBoe $ / Mcf $ / bbl	Dec. 31, 2021 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%	100%	100%
Proved Developed and Undeveloped Reserve, Net (Energy), Period Increase (Decrease)	12.2	(21)	(1.4)
Sales of reserves		1.4
Decrease of production	24.2	21.7	23.5
Revision to previous estimates	(18.1)	(9)	20.3
Estimated proved reserves from extensions and discoveries	5.4	11.2	1.8
Prescribed rate of discounted future net cash flows	10%
Oil (MBbls)
Reserve Quantities [Line Items]
SEC pricing | $ / bbl	78.56	96.03	67.14
Gas (MMcf)
Reserve Quantities [Line Items]
SEC pricing | $ / Mcf	2.75	6.80	3.71
EnVen Energy Corporation
Reserve Quantities [Line Items]
Purchase of reserve	49.1
Pricing and Well Performance [Member]
Reserve Quantities [Line Items]
Revision to previous estimates	(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)

Supplemental Oil and Gas Disc_6

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, 2023	Dec. 31, 2022	Dec. 31, 2021
Equity Method Investee [Member]
Property acquisition costs:
Exploration costs	$ 290	$ 0	$ 0
Consolidated Entities [Member]
Property acquisition costs:
Proved properties	951,703	0	210
Unproved properties, not subject to amortization	249,688	2,221	0
Total property acquisition costs	1,201,391	2,221	210
Exploration costs	161,296	125,889	23,844
Development costs	805,148	541,512	245,058
Total costs incurred	$ 2,167,835	$ 669,622	$ 269,112

Supplemental Oil and Gas Disc_7

Supplemental Oil and Gas Disclosures (Unaudited) - Schedule of Costs Incurred in Oil, Natural Gas and NGL Property Acquisition, Exploration and Development Activities (Parenthetical) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Mexico
Costs Incurred Oil And Gas Property Acquisition Exploration And Development Activities [Line Items]
Exploration costs	$ 0	$ 1.2	$ 6.6

Supplemental Oil and Gas Disc_8

Supplemental Oil and Gas Disclosures (Unaudited) - Schedule of Estimated Proved Reserves at Net Ownership Interest (Details)	12 Months Ended
	Dec. 31, 2023 MBoe MMBoe MMBbls MMcf	Dec. 31, 2022 MBoe MMBoe MMBbls MMcf	Dec. 31, 2021 MBoe MMBoe MMBbls MMcf
Reserve Quantities [Line Items]
Revision to previous estimates | MMBoe	(18.1)	(9)	20.3
Production | MMBoe	(24.2)	(21.7)	(23.5)
Sales of reserves | MMBoe		(1.4)
Extensions and discoveries | MMBoe	5.4	11.2	1.8
Oil (MBbls)
Reserve Quantities [Line Items]
Total proved reserves, beginning balance	91,059	107,764	109,307
Revision of previous estimates	(6,308)	(5,625)	13,619
Production	(18,062)	(14,561)	(16,159)
Sales of reserves		(158)
Purchases of reserves	41,871
Extensions and discoveries	2,255	3,639	997
Total proved reserves, ending balance	110,815	91,059	107,764
Total proved developed reserves	98,225	80,285	93,420
Total proved undeveloped reserves	12,590	10,774	14,344
Gas (MMcf)
Reserve Quantities [Line Items]
Total proved reserves, beginning balance | MMcf	219,551	236,353	257,208
Revision of previous estimates | MMcf	(62,946)	(8,302)	8,979
Production | MMcf	(26,194)	(32,215)	(32,795)
Sales of reserves | MMcf		(7,625)
Purchases of reserves	36,690
Extensions and discoveries | MMcf	12,770	31,340	2,961
Total proved reserves, ending balance | MMcf	179,871	219,551	236,353
Total proved developed reserves | MMcf	141,823	161,727	186,442
Total proved undeveloped reserves | MMcf	38,048	57,824	49,911
NGL (MBbls)
Reserve Quantities [Line Items]
Total proved reserves, beginning balance	12,928	14,435	10,858
Revision of previous estimates	(1,283)	(2,002)	5,137
Production	(1,767)	(1,793)	(1,875)
Sales of reserves		0
Purchases of reserves	1,116
Extensions and discoveries	979	2,288	315
Total proved reserves, ending balance	11,973	12,928	14,435
Total proved developed reserves	9,957	9,315	11,792
Total proved undeveloped reserves	2,016	3,613	2,643
Oil Equivalent (MBoe)
Reserve Quantities [Line Items]
Purchases of reserves	49,102
Total proved reserves, beginning balance | MBoe	140,579	161,591	163,033
Revision to previous estimates | MBoe	(18,082)	(9,010)	20,252
Production | MBoe	(24,195)	(21,723)	(23,500)
Sales of reserves | MBoe		(1,429)
Extensions and discoveries | MBoe	5,362	11,150	1,806
Total proved reserves, ending balance | MBoe	152,766	140,579	161,591
Total proved developed reserves | MBoe	131,819	116,555	136,286
Total proved undeveloped reserves | MBoe	20,947	24,024	25,305

Supplemental Oil and Gas Disc_9

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, 2023	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Extractive Industries [Abstract]
Future cash inflows	$ 9,425,055	$ 10,674,896	$ 8,496,005
Future costs:
Production	(3,090,491)	(1,906,752)	(1,868,818)
Development and abandonment	(2,358,368)	(1,873,453)	(1,422,507)
Future net cash flows before income taxes	3,976,196	6,894,691	5,204,680
Future income tax expense	(589,413)	(1,114,409)	(676,778)
Future net cash flows after income taxes	3,386,783	5,780,282	4,527,902
Discount at 10% annual rate	(343,295)	(1,411,834)	(1,087,291)
Standardized measure of discounted future net cash flows	$ 3,043,488	$ 4,368,448	$ 3,440,611	$ 1,904,934

Supplemental Oil and Gas Dis_10

Supplemental Oil and Gas Disclosures (Unaudited) - Schedule of Base Prices Used in Determining Standardized Measure (Details)	12 Months Ended
	Dec. 31, 2023 $ / bbl $ / Mcf	Dec. 31, 2022 $ / Mcf $ / bbl	Dec. 31, 2021 $ / Mcf $ / bbl
Oil
Discounted Future Net Cash Flows Relating To Proved Oil And Gas Reserves [Line Items]
SEC pricing	78.56	96.03	67.14
Natural Gas
Discounted Future Net Cash Flows Relating To Proved Oil And Gas Reserves [Line Items]
SEC pricing | $ / Mcf	2.75	6.80	3.71
NGL
Discounted Future Net Cash Flows Relating To Proved Oil And Gas Reserves [Line Items]
SEC pricing	18.77	33.89	26.62

Supplemental Oil and Gas Dis_11

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, 2023	Dec. 31, 2022	Dec. 31, 2021
Extractive Industries [Abstract]
Standardized measure, beginning of year	$ 4,368,448	$ 3,440,611	$ 1,904,934
Sales and transfers of oil, net gas and NGLs produced during the period	(1,065,814)	(1,340,400)	(957,576)
Net change in prices and production costs	(2,835,125)	2,388,442	2,049,980
Changes in estimated future development and abandonment costs	(19,877)	(84,391)	(57,876)
Previously estimated development and abandonment costs incurred	202,503	20,107	69,125
Accretion of discount	518,110	392,600	199,849
Net change in income taxes	357,321	(327,265)	(391,834)
Purchases of reserves	2,033,852	0	0
Sales of reserves	0	(5,218)	0
Extensions and discoveries	90,244	202,239	45,485
Net change due to revision in quantity estimates	(484,423)	(255,743)	426,357
Changes in production rates (timing) and other	(121,751)	(62,534)	152,167
Standardized measure, end of year	$ 3,043,488	$ 4,368,448	$ 3,440,611

Subsequent Events (Details)

Subsequent Events (Details) - Subsequent Event [Member] - QuarterNorth Energy, Inc. [Member] - Underwritten Public Offering [Member] $ in Millions	Jan. 22, 2024 USD ($) shares
Subsequent Event [Line Items]
Share of common stock | shares	34,500,000
Net proceeds after deducting underwriting discounts and commissions | $	$ 388.5

Schedule I - Balance Sheets (De

Schedule I - Balance Sheets (Details) - USD ($) $ in Thousands	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Accounts receivable
Other, net	$ 19,296	$ 6,684
Prepaid assets	64,387	84,759
Other current assets	10,389	1,917
Total current assets	422,175	367,829
Other long-term assets:
Investments in subsidiaries	146,049	1,745
Total assets	4,816,309	3,058,626
Current liabilities:
Accounts payable	84,193	128,174
Accrued liabilities	227,690	219,769
Other current liabilities	48,769	60,359
Total current liabilities	578,615	607,058
Long-term liabilities:
Other long-term liabilities	251,278	176,152
Total liabilities	2,661,158	1,893,050
Commitments and contingencies
Stockholdersʼ Equity:
Preferred stock; $0.01 par value; 30,000,000 shares authorized and zero shares issued or outstanding as of December 31, 2023 and 2022, respectively	0	0
Common stock; $0.01 par value; 270,000,000 shares authorized; 127,480,361 and 82,570,328 shares issued as of December 31, 2023 and 2022, respectively	1,275	826
Additional paid-in capital	2,549,097	1,699,799
Accumulated deficit	(347,717)	(535,049)
Treasury stock, at cost; 3,400,000 and zero shares as of December 31, 2023 and 2022, respectively	(47,504)	0
Total stockholdersʼ equity	2,155,151	1,165,576	$ 760,653	$ 926,601
Total liabilities and stockholdersʼ equity	4,816,309	3,058,626
Parent
Accounts receivable
Other, net	100	0
Prepaid assets	221	169
Other current assets	19	36
Total current assets	340	205
Other long-term assets:
Investments in subsidiaries	2,246,908	1,168,053
Total assets	2,247,248	1,168,258
Current liabilities:
Accounts payable	316	249
Accrued liabilities	705	728
Other current liabilities	124	62
Total current liabilities	1,145	1,039
Long-term liabilities:
Other long-term liabilities	90,952	1,643
Total liabilities	92,097	2,682
Commitments and contingencies
Stockholdersʼ Equity:
Preferred stock; $0.01 par value; 30,000,000 shares authorized and zero shares issued or outstanding as of December 31, 2023 and 2022, respectively	0	0
Common stock; $0.01 par value; 270,000,000 shares authorized; 127,480,361 and 82,570,328 shares issued as of December 31, 2023 and 2022, respectively	1,275	826
Additional paid-in capital	2,549,097	1,699,799
Accumulated deficit	(347,717)	(535,049)
Treasury stock, at cost; 3,400,000 and zero shares as of December 31, 2023 and 2022, respectively	(47,504)	0
Total stockholdersʼ equity	2,155,151	1,165,576
Total liabilities and stockholdersʼ equity	$ 2,247,248	$ 1,168,258

Schedule I - Balance Sheets (_2

Schedule I - Balance Sheets (Details) (Paranthetical) - $ / shares	Dec. 31, 2023	Dec. 31, 2022
Condensed Balance Sheet Statements, Captions [Line Items]
Preferred Stock, Par or Stated Value Per Share	$ 0.01	$ 0.01
Preferred Stock, Shares Authorized	30,000,000	30,000,000
Preferred Stock, Shares Issued	0	0
Preferred Stock, Shares Outstanding	0	0
Common Stock, Par or Stated Value Per Share	$ 0.01	$ 0.01
Common Stock, Shares Authorized	270,000,000	270,000,000
Common Stock, Shares, Issued	127,480,361	82,570,328
Treasury stock, common, shares	3,400,000	0
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	127,480,361	82,570,328
Treasury stock, common, shares	3,400,000	0

Schedule I - Statements of Oper

Schedule I - Statements of Operations (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Revenues [Abstract]
Total revenues	$ 1,457,886	$ 1,651,980	$ 1,244,540
Operating Expenses [Abstract]
Lease operating expense	389,621	308,092	283,601
Production taxes	2,451	3,488	3,363
Depreciation, depletion and amortization	663,534	414,630	395,994
Accretion expense	86,152	55,995	58,129
General and administrative expense	158,493	99,754	78,677
Other operating (income) expense	52,155	(33,902)	(32,037)
Total operating expenses	(1,248,096)	(915,861)	(869,924)
Operating income (expense)	209,790	736,119	374,616
Interest expense	(173,145)	(125,498)	(133,138)
Price risk management activities income (expense)	80,928	(272,191)	(419,077)
Equity method investment income (expense)	(3,209)	14,222	0
Other income (expense)	12,371	31,800	(6,988)
Net income (loss) before income taxes	126,735	384,452	(184,587)
Income tax benefit (expense)	60,597	(2,537)	1,635
Net income (loss)	187,332	381,915	(182,952)
Parent
Revenues [Abstract]
Total revenues	0	0	0
Operating Expenses [Abstract]
Lease operating expense	0	0	0
Production taxes	0	0	0
Depreciation, depletion and amortization	0	0	0
Accretion expense	0	0	0
General and administrative expense	2,708	2,145	1,322
Other operating (income) expense	0	0	0
Total operating expenses	2,708	2,145	1,322
Operating income (expense)	(2,708)	(2,145)	(1,322)
Interest expense	0	0	(5)
Price risk management activities income (expense)	0	0	0
Equity method investment income (expense)	0	0	0
Other income (expense)	(1)	(1)	(2)
Equity earnings (loss) from subsidiaries	128,888	385,968	(180,548)
Net income (loss) before income taxes	126,179	383,822	(181,877)
Income tax benefit (expense)	61,153	(1,907)	(1,075)
Net income (loss)	187,332	381,915	(182,952)
Oil
Revenues [Abstract]
Revenues	1,357,732	1,365,148	1,064,161
Oil | Parent
Revenues [Abstract]
Revenues	0	0	0
Natural Gas
Revenues [Abstract]
Revenues	68,034	227,306	130,616
Natural Gas | Parent
Revenues [Abstract]
Revenues	0	0	0
NGL
Revenues [Abstract]
Revenues	32,120	59,526	49,763
NGL | Parent
Revenues [Abstract]
Revenues	$ 0	$ 0	$ 0

Schedule I - Statements of Cash

Schedule I - Statements of Cash Flows (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Cash flows from operating activities:
Net cash provided used in operating activities	$ 519,069	$ 709,739	$ 411,388
Cash flows from investing activities:
Net cash provided by (used in) investing activities	(512,626)	(311,977)	(293,747)
Cash flows from financing activities:
Purchase of treasury stock	(47,504)	0	0
Net cash provided by (used in) financing activities	85,411	(423,469)	(82,022)
Net increase (decrease) in cash, cash equivalents and restricted cash	91,854	(25,707)	35,619
Cash, cash equivalents and restricted cash:
Balance, beginning of period	44,145	69,852	34,233
Balance, end of period	135,999	44,145	69,852
Parent
Cash flows from operating activities:
Net cash provided used in operating activities	(1,836)	(809)	(876)
Cash flows from investing activities:
Distributions from subsidiaries	49,340	809	879
Contributions to Subsidiaries	0	0	(3)
Net cash provided by (used in) investing activities	49,340	809	876
Cash flows from financing activities:
Purchase of treasury stock	(47,504)	0	0
Net cash provided by (used in) financing activities	(47,504)	0	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