Talos Energy (TALO) 10-K 25 Feb 22 2021 FY Annual report Financial data

Document and Entity Information

Document and Entity Information - USD ($)	12 Months Ended
	Dec. 31, 2021	Feb. 17, 2022	Jun. 30, 2021
Cover [Abstract]
Document Type	10-K
Amendment Flag	false
Document Period End Date	Dec. 31, 2021
Document Fiscal Year Focus	2021
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		81,881,477
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Public Float			$ 703,193,887
Documents Incorporated by Reference	Portions of the registrant’s definitive proxy statement relating to the 2022 Annual Meeting of Stockholders are incorporated by reference into Part III of this report.

CONSOLIDATED BALANCE SHEETS

CONSOLIDATED BALANCE SHEETS - USD ($) $ in Thousands	Dec. 31, 2021	Dec. 31, 2020
Current assets:
Cash and cash equivalents	$ 69,852	$ 34,233
Accounts receivable
Trade, net	173,241	106,220
Joint interest, net	28,165	50,471
Other	18,062	18,448
Assets from price risk management activities	967	6,876
Prepaid assets	48,042	29,285
Other current assets	1,674	1,859
Total current assets	340,003	247,392
Property and equipment:
Proved properties	5,232,479	4,945,550
Unproved properties, not subject to amortization	219,055	254,994
Other property and equipment	29,091	32,853
Total property and equipment	5,480,625	5,233,397
Accumulated depreciation, depletion and amortization	(3,092,043)	(2,697,228)
Total property and equipment, net	2,388,582	2,536,169
Other long-term assets:
Assets from price risk management activities	2,770	945
Other well equipment inventory	17,449	18,927
Operating lease assets	5,714	6,855
Other assets	12,297	24,258
Total assets	2,766,815	2,834,546
Current liabilities:
Accounts payable	85,815	104,864
Accrued liabilities	130,459	163,379
Accrued royalties	59,037	27,903
Current portion of long-term debt	6,060	0
Current portion of asset retirement obligations	60,311	49,921
Liabilities from price risk management activities	186,526	66,010
Accrued interest payable	37,542	9,509
Current portion of operating lease liabilities	1,715	1,793
Other current liabilities	33,061	24,155
Total current liabilities	600,526	447,534
Long-term liabilities:
Long-term debt, net of discount and deferred financing costs	956,667	985,512
Asset retirement obligations	373,695	392,348
Liabilities from price risk management activities	13,938	9,625
Operating lease liabilities	16,330	18,554
Other long-term liabilities	45,006	54,372
Total liabilities	2,006,162	1,907,945
Commitments and contingencies (Note 12)
Stockholdersʼ Equity:
Preferred stock, $0.01 par value; 30,000,000 shares authorized and no shares issued or outstanding as of December 31, 2021 and 2020	0	0
Common stock $0.01 par value; 270,000,000 shares authorized; 81,881,477 and 81,279,989 shares issued and outstanding as of December 31, 2021 and 2020, respectively	819	813
Additional paid-in capital	1,676,798	1,659,800
Accumulated deficit	(916,964)	(734,012)
Total stockholdersʼ equity	760,653	926,601
Total liabilities and stockholdersʼ equity	$ 2,766,815	$ 2,834,546

CONSOLIDATED BALANCE SHEETS (Pa

CONSOLIDATED BALANCE SHEETS (Parenthetical) - $ / shares	Dec. 31, 2021	Dec. 31, 2020
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	81,881,477	81,279,989
Common stock, shares outstanding	81,881,477	81,279,989

CONSOLIDATED STATEMENTS OF OPER

CONSOLIDATED STATEMENTS OF OPERATIONS - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Revenues:
Total revenues	$ 1,244,540	$ 575,936	$ 908,064
Operating expenses:
Lease operating expense	283,601	246,564	243,427
Production taxes	3,363	1,054	1,349
Depreciation, depletion and amortization	395,994	364,346	345,931
Write-down of oil and natural gas properties	18,123	267,916	12,221
Accretion expense	58,129	49,741	34,389
General and administrative expense	78,677	79,175	77,209
Other operating (income) expense	32,037	(11,550)	(19,556)
Total operating expenses	869,924	997,246	694,970
Operating income (expense)	374,616	(421,310)	213,094
Interest expense	(133,138)	(99,415)	(97,847)
Net cash received (paid) on settled derivative instruments	(419,077)	87,685	(95,337)
Other income (expense)	(6,988)	3,018	2,678
Net income (loss) before income taxes	(184,587)	(430,022)	22,588
Income tax benefit (expense)	1,635	(35,583)	36,141
Net income (loss)	$ (182,952)	$ (465,605)	$ 58,729
Net income (loss) per common share:
Basic	$ (2.24)	$ (6.88)	$ 1.08
Diluted	$ (2.24)	$ (6.88)	$ 1.08
Weighted average common shares outstanding:
Basic	81,769	67,664	54,185
Diluted	81,769	67,664	54,413
Oil
Revenues:
Revenues	$ 1,064,161	$ 506,788	$ 833,118
Natural Gas
Revenues:
Revenues	130,616	53,714	55,278
NGL
Revenues:
Revenues	$ 49,763	$ 15,434	$ 19,668

CONSOLIDATED STATEMENTS OF CHAN

CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS' EQUITY (DEFICIT) - USD ($) $ in Thousands	Total	Common Stock	Preferred Stock	Additional Paid-in Capital	Accumulated Deficit
Balance at Dec. 31, 2018	$ 1,007,496	$ 542		$ 1,334,090	$ (327,136)
Balance, shares at Dec. 31, 2018		54,155,768
Equity based compensation	12,385			12,385
Equity based compensation, Shares		41,236
Equity-based compensation tax withholdings	(333)			(333)
Net income (loss)	58,729				58,729
Balance at Dec. 31, 2019	1,078,277	$ 542		1,346,142	(268,407)
Balance, shares at Dec. 31, 2019		54,197,004
Equity based compensation	16,462			16,462
Equity based compensation, Shares		180,525
Equity-based compensation tax withholdings	(827)			(827)
Shares Issued, Value, Share-based Payment Arrangement, after Forfeiture, Total		$ 1		(1)
Issuances of preferred shares	156,200		$ 1	156,199
Issuances of preferred shares, Shares			110,000
Conversion of preferred shares into common shares		$ 110	$ (1)	(109)
Conversion of preferred shares into common shares, Shares		11,000,000	(110,000)
Issuance of common stock	70,741	$ 83		70,658
Issuance of common stock, Shares		8,250,000
Issuance of common stock for acquisitions	35,393	$ 46		35,347
Issuance of common stock for acquisitions, Shares		4,602,460
Issuance of common stock for debt exchange	35,960	$ 31		35,929
Issuance of common stock for debt exchange, Shares		3,050,000
Net income (loss)	(465,605)				(465,605)
Balance at Dec. 31, 2020	$ 926,601	$ 813		1,659,800	(734,012)
Balance, shares at Dec. 31, 2020	81,279,989	81,279,989
Balance, shares at Dec. 31, 2020	0
Equity based compensation	$ 20,165			20,165
Equity based compensation, Shares		601,488
Equity-based compensation tax withholdings	(3,161)			(3,161)
Shares Issued, Value, Share-based Payment Arrangement, after Forfeiture, Total		$ 6		(6)
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	81,881,477
Balance, shares at Dec. 31, 2021	0

CONSOLIDATED STATEMENTS OF CASH

CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Cash flows from operating activities:
Net income (loss)	$ (182,952)	$ (465,605)	$ 58,729
Adjustments to reconcile net income (loss) to net cash provided by operating activities
Depreciation, depletion, amortization and accretion expense	454,123	414,087	380,320
Write-down of oil and natural gas properties and other well inventory	23,729	268,615	12,386
Amortization of deferred financing costs and original issue discount	13,382	6,804	5,207
Equity based compensation expense	10,992	8,669	6,964
Price risk management activities expense (income)	419,077	(87,685)	95,337
Net cash received (paid) on settled derivative instruments	(290,164)	143,905	(8,820)
Loss (gain) on extinguishment of debt	13,225	(1,662)	0
Settlement of asset retirement obligations	(67,988)	(43,933)	(75,331)
Gain on sale of assets	(687)	0	0
Changes in operating assets and liabilities:
Accounts receivable	(35,396)	(34,645)	5,788
Other current assets	(18,901)	35,934	(15,114)
Accounts payable	(6,261)	27,096	7,523
Other current liabilities	64,800	4,200	(35,459)
Other non-current assets and liabilities, net	14,409	26,143	(43,797)
Net cash provided by operating activities	411,388	301,923	393,733
Cash flows from investing activities:
Exploration, development and other capital expenditures	(293,331)	(362,942)	(463,409)
Cash paid for acquisitions, net of cash acquired	(5,399)	(315,962)	(37,916)
Proceeds from sale of property and equipment, net	4,983	0	5,369
Net cash used in investing activities	(293,747)	(678,904)	(495,956)
Cash flows from financing activities:
Proceeds from issuance of common stock	0	71,100	0
Issuance of senior notes	600,500	0	0
Redemption of senior notes and other long-term debt	(356,803)	(5,364)	(10,567)
Proceeds from Bank Credit Facility	100,000	350,000	110,000
Repayment of Bank Credit Facility	(365,000)	(60,000)	(25,000)
Deferred financing costs	(27,833)	(1,287)	(1,963)
Other Deferred Payments	(7,921)	(11,921)	(9,921)
Payments of finance lease	(21,804)	(17,509)	(14,133)
Employee stock awards tax withholdings	(3,161)	(827)	(333)
Net cash provided by (used in) financing activities	(82,022)	324,192	48,083
Net increase (decrease) in cash and cash equivalents	35,619	(52,789)	(54,140)
Cash, cash equivalents
Balance, beginning of period	34,233	87,022	141,162
Balance, end of period	69,852	34,233	87,022
Supplemental non-cash transactions:
Capital expenditures included in accounts payable and accrued liabilities	45,761	74,957	90,956
Debt exchanged for common stock	0	35,960	0
Supplemental cash flow information:
Interest paid, net of amounts capitalized	$ 68,891	$ 67,443	$ 62,571

Organization, Nature of Busines

Organization, Nature of Business and Basis of Presentation	12 Months Ended
	Dec. 31, 2021
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. On May 10, 2018, the Parent Company consummated a combination between Talos Energy LLC and Stone Energy Corporation (“Stone”) (such combination, “Stone Combination”). Talos Energy LLC, which was the acquirer of Stone for financial reporting and accounting purposes, was formed in 2011 and commenced commercial operations on February 6, 2013. 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.”) Gulf of Mexico and offshore Mexico both upstream through oil and gas exploration and production and downstream through the development of future carbon capture and storage 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. With a focus on environmental stewardship, the Company also utilizes its expertise to explore opportunities to reduce industrial emissions through our carbon capture and storage collaborative arrangements 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 each subsidiary from the date of inception. 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. Certain reclassifications have been made to the prior year presentation to conform to the current year presentation. Amounts previously included as income in “Other” within “Revenues and Other” on the Consolidated Statements of Operations are now reflected in “Other operating (income) expense” as a component of “Total operating expenses” on the Consolidated Statements of Operations. The Company has two operating segments: (i) exploration and production of oil, natural gas and NGLs (“E&P Segment”) and (ii) carbon capture and sequestration (“CCS Segment”). The E&P Segment is the Company’s only reportable segment. The CCS Segment did not meet any of the quantitative thresholds to be a separate reportable segment. It did no t generate any revenue and incurred $ 4.3 million of general and administrative expense during the year ended December 31, 2021. The CCS Segment did no t have any assets at December 31, 2021.

Summary of Significant Accounti

Summary of Significant Accounting Policies	12 Months Ended
	Dec. 31, 2021
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, 2021 and 2020 , the Company had allowances of $ 15.1 million and $ 9.2 million, respectively, presented net in accounts receivable on the Consolidated Balance Sheets. The Company presented $ 10.0 million and $ 19.1 million of long-term refund claims for value added taxes paid in Mexico in “Other assets” on the Consolidated Balance Sheets as of December 31, 2021 and 2020 , respectively. Current refund claims for value added taxes paid of $ 3.9 million and nil is presented net of an allowance in “Other” accounts receivable on the Consolidated Balance Sheets as of December 31, 2021 and 2020 , respectively. Prepaid Assets — Prepaid assets primarily represent deposits with the Office of Natural Resources Revenue (“ONRR”) . 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. 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. Gas Imbalances — Revenues are recorded based on the actual sales volumes sold to purchasers. An imbalance receivable or payable is recorded only to the extent the imbalance is in excess of its share of remaining proved developed reserves in an underlying property. Our imbalances are presented gross on our Consolidated Balance Sheets. At December 31, 2021 and 2020 , our imbalance receivable was approximately $ 1.7 million and $ 1.7 million, respectively, and imbalance payable was approximately $ 2.5 million and $ 3.6 million, respectively. 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. The refunds for the years ended December 31, 2021, 2020 and 2019 were nil , $ 8.9 million and $ 19.3 million, respectively. 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. 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 . Other Well Equipment Inventory — Other well equipment inventory 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. The Company’s well equipment is stated at the lower of cost or net realizable value. The Company recorded $ 5.6 million, $ 0.7 million, and $ 0.2 million of impairment to adjust inventory to net realizable value, which was expensed and reflected in “Other operating (income) expense” on the Consolidated Statements of Operations, during the years ended December 31, 2021, 2020 and 2019 , respectively. 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. 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. As of December 31, 2021 , the Company incurred $ 3.8 million and $ 20.6 million in obligations reflected as “Other current liabilities” and “Other long-term liabilities”, respectively, on the Consolidated Balance Sheets. 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 12 — Commitments & Contingencies for additional information. 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. 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. 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. 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 restricted stock units (“RSUs”), performance share units (“PSUs”) and outstanding warrants. See Note 10 — Income (Loss) Per Share 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 and recognizes compensation cost on a straight-line basis in the Company’s financial statements over the requisite service period of each grant . 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, but is remeasured at each reporting period for awards classified as a liability. The Company records share-based compensation, net of actual forfeitures, for the RSUs and PSUs in “General and administrative expense” on the Consolidated Statements of Operations, net of amounts capitalized to oil and gas properties. See Note 8 — 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 — Share-based compensation is based on the grant date fair value determined using a Monte Carlo valuation model 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”) relative to the TSR achieved by a specified industry peer group. Share-based compensation related to PSUs is recognized as the requisite service period is fulfilled, even if the market condition is not achieved. 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 substantially all 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, 2021 2020 2019 Shell Trading (US) Company 45 % 47 % 58 % Chevron Products Company 29 % 12 % ** Phillips 66 ** 22 % 28 % ** 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.

Acquisitions

Acquisitions	12 Months Ended
	Dec. 31, 2021
Business Combinations [Abstract]
Asset Acquisitions	Note 3 — Acquisitions Asset Acquisitions Acquisitions qualifying as an asset acquisition requires, among other items, that the cost of the assets acquired and liabilities assumed to be recognized on the Consolidated Balance Sheets by allocating the asset cost on a relative fair value basis. The fair value measurements of the oil and natural gas properties acquired and asset retirement obligations assumed were derived utilizing an income approach and based, in part, on significant inputs not observable in the market. These inputs represent Level 3 measurements in the fair value hierarchy and include, but are not limited to, estimates of reserves, future operating and development costs, future commodity prices, estimated future cash flows and appropriate discount rates. These inputs required significant judgments and estimates by the Company’s management at the time of the valuation. Transaction costs incurred on an asset acquisition are capitalized as a component of the assets acquired and any contingent consideration is recognized as the contingency is resolved. Acquisition of LLOG Properties — On November 16, 2020 , the Company completed the acquisition of select oil and natural gas assets from LLOG Exploration & Production Company, L.L.C. with an effective date of August 1, 2020 (the “LLOG Acquisition”). The oil and natural gas assets consist of interests in the Mississippi Canyon core area. The LLOG Acquisition was consummated pursuant to a Purchase and Sale Agreement executed on November 16, 2020 for $ 13.2 million in cash, inclusive of customary closing adjustments and $ 0.2 million of transaction related expenses. The following table presents the allocation of the purchase price to the assets acquired and liabilities assumed, based on their relative fair values, on November 16, 2020 (in thousands): Property and equipment $ 17,421 Asset retirement obligations ( 4,234 ) Allocated purchase price $ 13,187 Acquisition of Castex Energy 2005 — On August 5, 2020 , the Company completed the acquisition of select oil and natural gas assets from affiliates of Castex Energy 2005 Holdco, LLC with an effective date of April 1, 2020 (the “Castex Energy 2005 Acquisition”). The oil and natural gas assets consisted of 16 properties in the U.S. Gulf of Mexico shelf and Gulf Coast core area. The Castex Energy 2005 Acquisition was consummated pursuant to a Purchase and Sale Agreement dated June 19, 2020 for consideration consisting of (i) $ 6.5 million in cash, (ii) 4.6 million shares of the Company’s common stock and (iii) $ 1.4 million in transaction related expenses, inclusive of customary closing adjustments. The following table summarizes the purchase price, inclusive of customary closing adjustments (in thousands except share and per share data): Talos common stock 4,602,460 Talos common stock price per share (1) $ 7.69 Talos common stock value $ 35,393 Cash consideration $ 6,500 Transaction cost $ 1,413 Total purchase price $ 43,306 (1) Represents the closing price of the Company’s common stock on August 5, 2020, the closing date of the Castex Energy 2005 Acquisition. The following table presents the allocation of the purchase price to the assets acquired and liabilities assumed, based on their relative fair values, on August 5, 2020 (in thousands): Property and equipment $ 46,626 Asset retirement obligations ( 3,320 ) Allocated purchase price $ 43,306 Acquisition of Gunflint Field — On January 11, 2019, the Company completed the acquisition of an approximate 9.6 % non-operated working interest in the Gunflint Field located in the Mississippi Canyon area (the “Gunflint Acquisition”) from Samson Offshore Mapleleaf, LLC for $ 29.6 million ($ 27.9 million after customary purchase price adjustments).
Business Combination	Business Combination 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. The fair value measurements of the oil and natural gas properties acquired and asset retirement obligations assumed were derived utilizing an income approach and based, in part, on significant inputs not observable in the market. These inputs represent Level 3 measurements in the fair value hierarchy and include, but are not limited to, estimates of reserves, future operating and development costs, future commodity prices, estimated future cash flows and appropriate discount rates. These inputs required significant judgments and estimates at the time of the valuation. ILX and Castex Acquisition — On February 28, 2020 , the Company acquired the outstanding limited liability interests in certain wholly owned subsidiaries of ILX Holdings, LLC; ILX Holdings II, LLC; ILX Holdings III LLC and Castex Energy 2014, LLC, each a related party and an affiliate of the Riverstone Funds (as defined in Note 11 — Related Parties ) (the “Riverstone Sellers”), and Castex Energy 2016, LP (together with the Riverstone Sellers, the “Sellers”) with an effective date of July 1, 2019 (collectively, the “ILX and Castex Acquisition”). The ILX and Castex Acquisition was consummated pursuant to separate Purchase and Sale Agreements, dated December 10, 2019 (as amended from time to time, the “Purchase Agreements”) for aggregate consideration consisting of (i) $ 385.0 million in cash subject to customary closing adjustments and (ii) an aggregate 110,000 shares (the “Preferred Shares”) of a series of the Company’s preferred stock designated as “Series A Convertible Preferred Stock” which subsequently converted to 11.0 million shares of the Company’s common stock on March 30, 2020 (such common stock, the “Conversion Stock”). The cash consideration was funded with borrowings under the Bank Credit Facility. The following table summarizes the purchase price (in thousands except share and per share data): Talos Conversion Stock 11,000,000 Talos common stock price per share (1) $ 14.20 Conversion Stock value $ 156,200 Cash consideration $ 385,000 Customary closing and post-closing adjustments ( 81,878 ) Net cash consideration $ 303,122 Total purchase price $ 459,322 (1) Represents the closing price of the Company’s common stock on February 28, 2020, the closing date of the ILX and Castex Acquisition. The purchase price was based on the value of the Conversion Stock as the value approximates the value of the Preferred Shares as a result of the automatic conversion and dividend rights described in that certain Certificate of Designation, Preferences, Rights and Limitations. 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 28, 2020 (in thousands): Current assets (1) $ 11,060 Property and equipment 496,835 Other long-term assets 148 Current liabilities ( 16,520 ) Other long-term liabilities ( 32,201 ) Allocated purchase price $ 459,322 (1) Includes trade and other receivables of $ 8.2 million. The Company incurred $ 12.1 million of transaction related costs, of which $ 8.7 million and $ 3.4 million were recognized in the years ended December 31, 2020 and 2019, respectively. These costs are reflected in “General and administrative expense” on the Consolidated Statements of Operations. The following table presents revenue and net income attributable to the assets acquired in the ILX and Castex Acquisition: Year Ended December 31, 2020 Revenue $ 126,857 Net loss $ ( 6,011 ) 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, 2020 and 2019 as if the ILX and Castex Acquisition had occurred on January 1, 2019. The unaudited pro forma information was derived from historical statements of operations of the Company and the Sellers adjusted to (i) include depletion expense applied to the adjusted basis of the oil and natural gas properties acquired, (ii) include interest expense to reflect borrowings under the Bank Credit Facility, (iii) eliminate the write-down of oil and natural gas properties on the assets acquired to reflect the pro-forma ceiling test calculation and (iv) include weighted average basic and diluted shares of common stock outstanding, which was calculated assuming the 11.0 million shares of Conversion Stock were issued to the Sellers. This information does not purport to be indicative of results of operations that would have occurred had the ILX and Castex Acquisition occurred on January 1, 2019, nor is such information indicative of any expected future results of operations. Year Ended December 31, 2020 2019 Revenue $ 634,921 $ 1,246,391 Net income (loss) $ ( 449,988 ) $ 148,091 Basic net income (loss) per common share $ ( 6.48 ) $ 2.27 Diluted net income (loss) per common share $ ( 6.48 ) $ 2.26

Property, Plant and Equipment

Property, Plant and Equipment	12 Months Ended
	Dec. 31, 2021
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 2021, 2020 and 2019 , the Company’s ceiling test computations resulted in a write-down of its U.S. oil and natural gas properties of nil , $ 267.9 million and nil , respectively. At December 31, 2021, its ceiling test computation was based on SEC pricing of $ 67.14 per Bbl of oil, $ 3.71 per Mcf of natural gas and $ 26.62 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. Unproved properties also include expenditures associated with exploration and appraisal activities in Block 7 located in the shallow waters off the coast of Mexico’s Tabasco state. The following table sets forth a summary of the Company’s oil and natural gas property costs not being amortized at December 31, 2021, by the year in which such costs were incurred (in thousands): Year Ended December 31, Total 2021 2020 2019 2018 and Prior Acquisition United States $ 46,757 $ — $ 37,704 $ 3,216 $ 5,837 Exploration United States 62,038 16,242 11,195 31,111 3,490 Exploration Mexico 110,260 2,736 13,853 48,508 45,163 Total unproved properties, not subject $ 219,055 $ 18,978 $ 62,752 $ 82,835 $ 54,490 The excluded costs will be included in the amortization base as properties are evaluated and proved reserves are established or impairment is determined. The Company’s evaluation of unproved property located offshore Mexico resulted in a non-cash impairment of $ 18.1 million, $ 0.1 million and $ 12.2 million for the years ended December 31, 2021, 2020 and 2019, respectively, presented as “Write-down of oil and natural gas properties” on the Consolidated Statements of Operations. The non-cash impairment is attributable to the Company’s operations offshore Mexico in Block 2 and Block 31. The impairment of operations in Block 31 is attributable to the Company’s non-consent of the proposed appraisal plan during the fourth quarter of 2021. The impairment of operations in Block 2 is attributable to the Company’s assessment of future exploratory drilling opportunities and results from exploratory wells drilled during the second quarter of 2019. 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, 2021 2020 Balance, beginning of period $ 442,269 $ 369,478 Obligations acquired (1) 433 44,311 Obligations incurred 52 4,511 Obligations settled ( 67,988 ) ( 43,933 ) Obligations divested ( 340 ) ( 185 ) Accretion expense 58,129 49,741 Changes in estimate 1,451 18,346 Balance, end of period $ 434,006 $ 442,269 Less: Current portion 60,311 49,921 Long-term portion $ 373,695 $ 392,348 (1) Year ended December 31, 2020 includes $ 35.3 million, $ 3.3 million and $ 4.2 million of asset retirement obligations assumed in the ILX and Castex Acquisition, Castex Energy 2005 Acquisition and LLOG Acquisition, respectively.

Leases

Leases	12 Months Ended
	Dec. 31, 2021
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 right-of-use 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. 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, 2021 2020 2019 Finance lease cost - interest on lease liabilities $ 11,453 $ 15,748 $ 19,115 Operating lease cost, excluding short-term leases (1) 2,706 3,361 3,261 Short-term lease cost (2) 38,472 53,573 85,865 Variable lease cost (3) 1,356 543 11 Total lease cost $ 53,987 $ 73,225 $ 108,252 (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 right-of-use 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 right-of-use asset and liability, adjusted for initial direct costs and incentives were as follows (in thousands): Year Ended December 31, 2021 2020 Operating leases: Operating lease assets $ 5,714 $ 6,855 Current portion of operating lease liabilities $ 1,715 $ 1,793 Operating lease liabilities 16,330 18,554 Total operating lease liabilities $ 18,045 $ 20,347 Finance leases: Proved property $ 124,299 $ 124,299 Other current liabilities $ 27,083 $ 21,804 Other long-term liabilities 13,138 40,222 Total finance lease liabilities $ 40,221 $ 62,026 The table below presents the lease maturity by year as of December 31, 2021 (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 2022 $ 3,712 $ 33,257 2023 3,652 13,857 2024 3,454 — 2025 3,519 — 2026 3,584 — Thereafter 9,258 — Total lease payments $ 27,179 $ 47,114 Imputed interest ( 9,134 ) ( 6,893 ) Total lease liabilities $ 18,045 $ 40,221 The table below presents the weighted average remaining lease term and discount rate related to leases: Year Ended December 31, 2021 2020 2019 Weighted average remaining lease term: Operating leases 7.4 years 7.8 years 8.4 years Finance leases 1.4 years 2.4 years 3.4 years Weighted average discount rate: Operating leases 11.9 % 12.0 % 10.2 % Finance leases 21.9 % 21.9 % 21.9 % The table below presents the supplemental cash flow information related to leases (in thousands): Year Ended December 31, 2021 2020 2019 Operating cash outflow from finance leases $ 11,453 $ 15,748 $ 19,115 Operating cash outflow from operating leases $ 3,864 $ 2,648 $ 1,812 Right-of-use assets obtained in exchange for new $ 1,020 $ — $ 2,225

Financial Instruments

Financial Instruments	12 Months Ended
	Dec. 31, 2021
Financial Instruments [Abstract]
Financial Instruments	Note 6 — Financial Instruments As of December 31, 2021 and 2020, the carrying amounts of cash and cash equivalents, accounts receivable and accounts payable approximate their fair values because of 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, 2021 December 31, 2020 Carrying Fair Carrying Fair 12.00 % Second-Priority Senior Secured Notes – January 2026 $ 588,838 $ 685,945 $ — $ — 11.00 % Second-Priority Senior Secured Notes – April 2022 $ — $ — $ 343,579 $ 355,935 7.50 % Senior Notes – due May 2022 $ 6,060 $ 6,145 $ 6,060 $ 5,238 Bank Credit Facility – matures November 2024 $ 367,829 $ 375,000 $ 635,873 $ 640,000 The carrying value of the senior notes are presented net of the original issue discount and deferred financing costs. Fair value is estimated (representing a Level 1 fair value measurement) using quoted secondary market trading prices. The carrying amount of the Company’s 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 through the use of 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. Collar contracts typically require payments by the Company if the NYMEX average closing price is above the ceiling price or payments to the Company if the NYMEX average closing price is below the floor price. The Company has elected not to designate any of its derivative contracts for hedge accounting. Accordingly, 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 as “Price risk management activities income (expense)” on the Consolidated Statements of Operations in each period. 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, 2021 2020 2019 Net cash received (paid) on settled derivative instruments $ ( 290,164 ) $ 143,905 $ ( 8,820 ) Unrealized loss ( 128,913 ) ( 56,220 ) ( 86,517 ) Price risk management activities income (expense) $ ( 419,077 ) $ 87,685 $ ( 95,337 ) The following table reflects the contracted volumes and weighted average prices under the terms of the Company's derivative contracts as of December 31, 2021: Swap Contracts Production Period Settlement Index Average Weighted Crude oil: (Bbls) (per Bbl) January 2022 – December 2022 NYMEX WTI CMA 23,523 $ 52.42 January 2023 – December 2023 NYMEX WTI CMA 7,463 $ 63.13 Natural gas: (MMBtu) (per MMBtu) January 2022 – December 2022 NYMEX Henry Hub 43,392 $ 2.77 January 2023 – December 2023 NYMEX Henry Hub 16,408 $ 3.29 The following tables provide additional information related to financial instruments measured at fair value on a recurring basis (in thousands): December 31, 2021 Level 1 Level 2 Level 3 Total Assets: Oil and natural gas swaps $ — $ 3,737 $ — $ 3,737 Liabilities: Oil and natural gas swaps — ( 200,464 ) — ( 200,464 ) Total net liability $ — $ ( 196,727 ) $ — $ ( 196,727 ) December 31, 2020 Level 1 Level 2 Level 3 Total Assets: Oil and natural gas swaps and costless collars $ — $ 7,821 $ — $ 7,821 Liabilities: Oil and natural gas swaps and costless collars — ( 75,635 ) — ( 75,635 ) Total net liability $ — $ ( 67,814 ) $ — $ ( 67,814 ) 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. On derivative contracts recorded as assets in the table below, the Company is exposed to the risk the counterparties may not perform. 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, 2021 December 31, 2020 Assets Liabilities Assets Liabilities Oil and natural gas derivatives: Current $ 967 $ 186,526 $ 6,876 $ 66,010 Non-current 2,770 13,938 945 9,625 Total gross amounts presented on balance sheet 3,737 200,464 7,821 75,635 Less: Gross amounts not offset on the balance sheet 3,737 3,737 4,877 4,877 Net amounts $ — $ 196,727 $ 2,944 $ 70,758 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 creditworthiness; (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, 2021 represent derivative instruments from seven counterparties; all of which are registered swap dealers that have an “investment grade” (minimum Standard & Poor’s rating of BBB- or better) credit rating, and all 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.

Debt

Debt	12 Months Ended
	Dec. 31, 2021
Debt Disclosure [Abstract]
Debt	Note 7 — 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, 2021 2020 12.00 % Second-Priority Senior Secured Notes – due January 2026 $ 650,000 $ — 11.00 % Second-Priority Senior Secured Notes – due April 2022 — 347,254 7.50 % Senior Notes – due May 2022 6,060 6,060 Bank Credit Facility – matures November 2024 375,000 640,000 Total debt, before discount and deferred financing cost 1,031,060 993,314 Discount and deferred financing cost ( 68,333 ) ( 7,802 ) Total debt, net of discount and deferred financing costs 962,727 985,512 Less: Current portion of long-term debt 6,060 — Long-term debt, net of discount and deferred financing costs $ 956,667 $ 985,512 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 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 , commencing on July 15, 2021. At any time prior to January 15, 2023, the Company may redeem up to 40 % of the principal amount of the 12.00% Notes at a redemption rate of 112.00 % of the principal amount plus accrued and unpaid interest. At any time prior to January 15, 2023, the Company may also redeem some or all of the 1 2.00% Notes at a price equal to 100 % of the principal amount of the 1 2.00% Notes, plus a “make-whole premium,” together with accrued and unpaid interest, if any, to, but excluding, the date of redemption. Thereafter, the Company may redeem all or a portion of the 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 106.00 % 2024 103.00 % 2025 100.00 % 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, 2021. 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. On June 15, 2020, the Company entered into an exchange agreement pursuant to which the Company agreed to exchange $ 37.2 million aggregate principal amount of the 11.00 % Notes from certain holders in exchange for 3.1 million shares of the Company’s common stock plus cash in an amount equal to accrued interest up to the June 18, 2020 settlement date. Additionally, during the year ended December 31, 2020 , the Company repurchased $ 6.4 million of the 11.00 % Notes. The exchange agreement and debt repurchases resulted in a gain on extinguishment of debt for the year ended December 31, 2020 of $ 1.7 million, which is included in “Other income (expense)” on the Consolidated Statements of Operations. 7.50% Senior Notes The 7.50 % Senior Notes due May 2022 (the “7.50% Notes ” ) represent the remaining $ 6.1 million of debt assumed on May 10, 2018 in a business combination that was not exchanged for the 11.00 % Notes pursuant to an exchange offer and consent solicitation, and thus remain outstanding. As a result of the exchange offer and consent solicitation, substantially all of the restrictive covenants relating to the 7.50 % Notes have been removed and collateral securing the 7.50 % Notes has been released. The 7.50 % Notes mature May 31, 2022 and have interest payable semi-annually each May 31 and November 30 . The Company may redeem all or a portion of the 7.50 % Notes at redemption prices (expressed as percentages of the principal amount) equal to: (i) 105.625 % for the twelve-month period beginning on May 31, 2021 and (ii) 100 % beginning May 31, 2022, in each case, plus accrued and unpaid interest at the redemption date. Bank Credit Facility The Company maintains a Bank Credit Facility with a syndicate of financial institutions. The Bank Credit Facility provides for 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 each year. On June 22, 2021, the Company entered into a Borrowing Base Redetermination Agreement and Sixth Amendment to Credit Agreement (the “Sixth Amendment”). The Sixth Amendment, among other things, (i) extended the maturity date of the Bank Credit Facility from May 10, 2022 to November 12, 2024 , (ii) decreased the borrowing base from $ 960.0 million to $ 950.0 million and (iii) decreased the commitments to $ 655.0 million. On August 2, 2021 an additional lender was added to the syndicate, which increased commitments from $ 655.0 million to $ 730.0 million. On December 21, 2021, the Company entered into an Incremental Agreement, Borrowing Base Redetermination Agreement and Seventh Amendment to Credit Agreement (the “Seventh Amendment”). The Seventh Amendment, among other things, (i) reaffirmed the borrowing base at $ 950.0 million, (ii) increased the commitments from $ 730.0 million to $ 791.3 million, (iii) added an additional lender to the syndicate and (iv) added a provision to facilitate investments of up to $ 50.0 million in carbon capture and sequestration and other emerging energy transition opportunities in unrestricted subsidiaries. The Bank Credit Facility bears interest based on the borrowing base usage, at the applicable London InterBank Offered Rate (“LIBOR”) plus applicable margins, or an alternate base rate (“ABR”) plus applicable margins. The ABR is based on the greater of (a) the prime rate, (b) a federal funds rate plus 0.5 % or (c) the one-month Adjusted LIBOR Rate plus 1.0 %. 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 LIBOR loans and ABR loans as well as the commitment fee rate based upon the applicable borrowing base utilization percentage: Borrowing Base Utilization Percentage Utilization LIBOR Loans ABR Loans Commitment Level 1 < 25 % 3.00 % 2.00 % 0.50 % Level 2 ≥ 25 % < 50 % 3.25 % 2.25 % 0.50 % Level 3 ≥ 50 % < 75 % 3.50 % 2.50 % 0.50 % Level 4 ≥ 75 % < 90 % 3.75 % 2.75 % 0.50 % Level 5 ≥ 90 % 4.00 % 3.00 % 0.50 % The Bank Credit Facility has certain debt covenants, the most restrictive of which is that the Company must maintain a 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. According to the Bank Credit Facility, unutilized commitments are included in current assets in the current ratio calculation. The Bank Credit Facility is secured by substantially all 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, 2021, the Company's borrowing base was $ 950.0 million with total commitments of $ 791.3 million . Additionally, no more than $ 200.0 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, 2021. As of December 31, 2021 , the Company had outstanding borrowings at a weighted average interest rate of 3.50 %. See Note 12 — Commitments and Contingencies for the amount of letters of credit issued under the Bank Credit Facility as of December 31, 2021 .

Employee Benefits Plans and Sha

Employee Benefits Plans and Share-Based Compensation	12 Months Ended
	Dec. 31, 2021
Share-based Payment Arrangement [Abstract]
Employee Benefits Plans and Share-Based Compensation	Note 8 — Employee Benefits Plans and Share-Based Compensation 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 (collectively, the “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, 2021 was approximately $ 14.2 million, which is expected to be recognized over a weighted average period of 1.8 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, 2021 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 Stock Weighted Average Unvested RSUs at December 31, 2018 138,704 $ 33.85 Granted 732,771 $ 24.39 Vested ( 69,235 ) $ 33.72 Forfeited ( 68,463 ) $ 25.43 Unvested RSUs at December 31, 2019 733,777 $ 25.20 Granted 1,284,797 $ 10.02 Vested ( 273,787 ) $ 25.09 Forfeited ( 91,799 ) $ 19.65 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) 1,983,199 $ 13.02 (1) As of December 31, 2021 , 25,592 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 based on the TSR of the common stock relative to the TSR achieved by a specific industry peer group over an approximate three-year performance period, the last day of which is also the vesting date. The total unrecognized share-based compensation expense related to these PSUs at December 31, 2021 was approximately $ 8.8 million, which is expected to be recognized over a weighted average period of 1.8 years. The following table summarizes PSU activity: Performance Weighted Average Unvested PSUs at December 31, 2018 231,542 $ 44.47 Granted 218,060 $ 33.96 Forfeited ( 31,771 ) $ 40.27 Unvested PSUs at December 31, 2019 417,831 $ 39.31 Granted 441,642 $ 13.05 Forfeited ( 25,301 ) $ 37.67 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 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 PSUs granted and modified at the date indicated: 2021 2020 2019 Modification Grant Grant Grant May 11 March 8 March 5 March 5 May 16 Expected term (in years) 2.6 2.8 2.8 2.8 2.6 Expected volatility 80.9 % 78.3 % 48.8 % 46.9 % 44.8 % Risk-free interest rate 0.3 % 0.3 % 0.6 % 2.5 % 2.1 % Dividend yield — % — % — % — % — % Fair value (in thousands) $ 9,715 $ 11,129 $ 5,763 $ 6,195 $ 1,210 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 cost expensed and capitalized (in thousands): Year Ended December 31, 2021 2020 2019 Share-based compensation costs $ 20,560 $ 16,462 $ 12,924 Less: Amounts capitalized to oil and gas properties 9,568 7,793 5,960 Total share-based compensation expense $ 10,992 $ 8,669 $ 6,964

Income Taxes

Income Taxes	12 Months Ended
	Dec. 31, 2021
Income Tax Disclosure [Abstract]
Income Taxes	Note 9 — Income Taxes Income Tax Expense (Benefit) The components of income tax expense (benefit) were as follows (in thousands): Year Ended December 31, 2021 2020 2019 Current income tax expense (benefit): United States $ ( 5 ) $ ( 499 ) $ 437 Mexico ( 993 ) 185 1,183 Total current income tax expense (benefit) $ ( 998 ) $ ( 314 ) $ 1,620 Deferred income tax expense (benefit): United States $ ( 1,067 ) $ 35,923 $ ( 37,131 ) Mexico 430 ( 26 ) ( 630 ) Total deferred income tax expense (benefit) $ ( 637 ) $ 35,897 $ ( 37,761 ) Total income tax expense (benefit) $ ( 1,635 ) $ 35,583 $ ( 36,141 ) 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, 2021 2020 2019 Income tax expense (benefit) at the federal statutory tax rate $ ( 38,763 ) $ ( 90,304 ) $ 4,744 State income taxes ( 674 ) ( 14,215 ) 1,396 Impact of foreign operations ( 11,920 ) ( 1,030 ) ( 4,948 ) Effect of change in state rate 2,008 — — Prior year taxes 486 ( 4,237 ) ( 1,950 ) Other adjustments — — 137 Legal entity reorganization — ( 17,566 ) 39,336 Change in valuation allowance 45,547 162,213 ( 75,196 ) Other permanent differences 1,681 722 340 Total income tax expense (benefit) $ ( 1,635 ) $ 35,583 $ ( 36,141 ) Effective tax rate 0.89 % ( 8.27 )% ( 159.99 )% The Company’s effective tax rate for the year ending December 31, 2021 differed from the federal statutory rate of 21.0 % primarily due to recording a full valuation allowance against its federal, state and foreign deferred tax assets. The Company’s effective tax rate for the year ending December 31, 2020 differed from the federal statutory rate of 21.0 % primarily due to a non-cash tax expense of $ 162.2 million related to the recognition of a valuation allowance for its excess federal and state deferred tax assets. This expense was partially offset by a tax benefit of $ 17.6 million from adopting the final Treasury Regulations under Section 163(j) of the Internal Revenue Code (the “IRC”) for tax years ended December 31, 2018 and December 31, 2019. The adoption of the final Treasury Regulations reduced the non-cash tax expense recognized in the year ending December 31, 2019 from the legal entity conversion of a partnership to a corporation. The Company’s effective tax rate for the year ending December 31, 2019 differed from the federal statutory rate of 21.0 % primarily due to a non-cash tax benefit of $ 75.2 million related to the full release of the valuation allowance for its federal and a significant portion of its state deferred tax assets. The federal and state portion of the release equals $ 80.2 million, partially offset by a $ 5.0 million increase in valuation allowance recorded against foreign deferred tax assets. Additionally, the Company recorded a tax expense of $ 39.3 million related to the reorganization of our subsidiaries, of which $ 38.9 million represents the non-cash impact from the legal entity conversion of a partnership to a corporation. 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, 2021 2020 Deferred tax assets: Federal net operating loss $ 153,849 $ 133,804 Foreign tax loss carryforward 49,932 45,980 State net operating loss 24,265 25,740 Asset retirement obligations 92,823 106,604 Tax credits 303 522 Derivatives 42,075 16,346 Other well equipment inventory 5,680 9,470 Accrued bonus 5,087 3,069 Operating lease liabilities 4,081 4,904 Other 9,257 7,727 Total deferred tax assets 387,352 354,166 Valuation allowance ( 224,266 ) ( 178,998 ) Total deferred tax assets, net $ 163,086 $ 175,168 Deferred tax liabilities: Oil and gas properties $ 160,002 $ 170,596 Deferred financing — 1,765 Operating lease assets 1,423 1,652 Prepaid 3,075 3,216 Total deferred tax liabilities 164,500 177,229 Net deferred tax liability $ ( 1,414 ) $ ( 2,061 ) Net Operating Loss The table below presents the details of the Company’s net operating loss carryovers as of December 31, 2021 (in thousands): Amount Expiration Year Federal net operating losses $ 534,964 2035 - 2037 Federal net operating losses $ 197,651 Unlimited Foreign tax loss carryforward $ 166,440 2025 - 2031 State net operating losses $ 125,958 2025 - 2037 State net operating losses $ 268,221 Unlimited As of December 31, 2021, the Company had U.S. federal net operating loss carryforwards (“NOLs”) of approximately $ 732.6 million, of which $ 546.5 million is 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 in 2035 . Valuation Allowance The Company recorded a valuation allowance of $ 224.3 million and $ 179.0 million as of December 31, 2021 and 2020, 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. 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, 2021 2020 Total unrecognized tax benefits, beginning balance $ 648 $ 791 Increases in unrecognized tax benefits as a result of: Tax positions taken during a prior period 21 ( 208 ) Tax positions taken during the current period 27 65 Total unrecognized tax benefits, ending balance $ 696 $ 648 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 2018 through 2020 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, 2017 are closed, except to the extent of any NOL carryover balance.

Income (Loss) Per Share

Income (Loss) Per Share	12 Months Ended
	Dec. 31, 2021
Earnings Per Share [Abstract]
Income (Loss) Per Share	Note 10 — 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, 2021 2020 2019 Net income (loss) $ ( 182,952 ) $ ( 465,605 ) $ 58,729 Weighted average common shares outstanding — basic 81,769 67,664 54,185 Dilutive effect of securities — — 228 Weighted average common shares outstanding — diluted 81,769 67,664 54,413 Net income (loss) per common share: Basic $ ( 2.24 ) $ ( 6.88 ) $ 1.08 Diluted $ ( 2.24 ) $ ( 6.88 ) $ 1.08 Anti-dilutive potentially issuable securities excluded 1,709 5,019 4,220

Related Party Transactions

Related Party Transactions	12 Months Ended
	Dec. 31, 2021
Related Party Transactions [Abstract]
Related Party Transactions	Note 11 — Related Party Transactions 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, together with the Apollo Funds, the “Sponsors”) and members of management pursuant to which the Company received a private equity capital commitment. Collectively, the Sponsors held 36.4 % of the Company's common stock as of December 31, 2021. On January 3, 2022, the Apollo Funds ceased being a beneficial owner of more than five percent of the Company's common stock. ILX and Castex Acquisition On February 28, 2020 the Company acquired assets and liabilities at fair value from sellers that include, the Riverstone Sellers, affiliates of the Riverstone Funds. See additional details in Note 3 — Acquisitions. Whistler Acquisition On August 31, 2018 , the Company acquired Whistler Energy II, LLC from Whistler Energy II Holdco, LLC, an affiliate of the Apollo Funds. Included in “Other” accounts receivable on the Consolidated Balance Sheets is $ 1.1 million at December 31, 2020 due from an affiliate of the Apollo Funds to reimburse the Company for certain payments made post-closing. The receivable was collected during October 2021. Additionally, a settlement agreement was executed in September 2021 related to a dispute regarding a decommissioning obligation of a Deepwater well. 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. Equity Registration Rights Agreement On May 10, 2018, the Company entered into a Registration Rights Agreement (the “Original Equity 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 as of the closing of the Stone Combination (the “Original Registrable Securities”). The Company and the Riverstone Sellers (and their designated affiliates) agreed under the Purchase Agreements to enter into an amendment to the Original Equity Registration Rights Agreement (such amendment, the “Registration Rights Agreement Amendment,” and the Original Equity Registration Rights Agreement, as amended by the Registration Rights Agreement Amendment, the “Registration Rights Agreement”). The Registration Rights Agreement Amendment will add each of the Riverstone Sellers (or one or more of its designated affiliates) as parties to the Registration Rights Agreement and provide such parties with customary registration rights with respect to the Series A Convertible Preferred Stock (and Conversion Stock) (each as defined below) that the Riverstone Sellers received at the closing of the ILX and Castex Acquisition (the “New Registrable Securities” and together with the Original Registrable Securities, the “Registrable Securities”). Under the Registration Rights Agreement, the Company is required to file a shelf registration statement within 30 days of the Company’s receipt of written request by a holder of Registrable Securities (a “Holder”). Each Holder will be limited to two demand registrations in any twelve-month period. The Holders have the right to request that the Company initiate underwritten offerings of the Company’s common stock; provided, that the Apollo Funds and the Riverstone Funds will have the right to demand three underwritten offerings in any twelve-month period, and Franklin and MacKay Shields will only have the collective right to demand one underwritten offering. The Holders have customary piggyback rights with respect to any underwritten offering that the Company conducts for as long as the Holders and their respective affiliates own 5 % of the Registrable Securities. Each Holder will agree to a lock up with underwriters in the event of an underwritten offering, provided that the lock up will not apply to any Holder who does not have a right to participate in such underwritten offering. The Registration Rights Agreement have terminated with respect to Franklin and MacKay Shields. Additionally, the Apollo Funds no longer have piggyback rights effective January 3, 2022. The Registration Rights Agreement will otherwise terminate at such time as there are no Registrable Securities outstanding. In connection with the closing of the ILX and Castex Acquisition, and pursuant to the Purchase Agreements, as amended, the Company and ILX Holdings, LLC, ILX Holdings II, LLC, ILX Holdings III LLC and Riverstone V Castex 2014 Holdings, L.P., a Delaware limited partnership and designee of Castex Energy 2014, LLC, entered into the Registration Rights Agreement Amendment to the Registration Rights Agreement to, among other things, add each of the Riverstone Sellers (or one or more of its designated affiliates) as parties to the Registration Rights Agreement and provide such parties with customary registration rights with respect to the Company’s Series A Convertible Preferred Stock issued to the Riverstone Sellers at the closing of the ILX and Castex Acquisition The Company will bear all of the expenses incurred in connection with the offer and sale, while the Apollo Funds, the Riverstone Funds, Franklin and MacKay Shields will be responsible for paying underwriting fees, discounts and selling commissions. The Company incurred fees of $ 0.7 million, $ 0.2 million and $ 0.7 million for the fiscal years ended December 31, 2021, 2020 and 2019, respectively. In June and November of 2021, the Company entered into separate secondary underwriting agreements with certain stockholders affiliated with the Sponsors (the “Selling Stockholders”), pursuant to which the Selling Stockholders sold shares of common stock of the Company. Each secondary offering was made pursuant to a prospectus supplement filed with the SEC. The Selling Stockholders received all the proceeds from these offerings. Stockholders’ Agreement Amendment 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 (the “Stockholders’ Agreement Amendment”) to, among other things, add each of the Riverstone Sellers (or one or more of its designated affiliates) as parties to the Stockholders’ Agreement and provide that for purposes of determining whether the Riverstone Sellers and their affiliates continue to satisfy certain stock ownership requirements necessary to retain their rights to nominate directors to the board of directors, the Series A Convertible Preferred Stock owned by the Riverstone Sellers was, prior to the conversion thereof, counted towards such ownership requirements on an as converted basis at the closing of the ILX and Castex Acquisition. On March 30, 2020, all 110,000 shares of Series A Convertible Preferred Stock were converted into an aggregate 11.0 million shares of the Company’s common stock. 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, 2021, 2020 and 2019 , the Company incurred fees of approximately $ 3.1 million, $ 3.5 million and $ 4.2 million, respectively, of which $ 0.2 million, $ 0.7 million and $ 2.3 million were payable at each respective balance sheet date for legal services performed by V&E.

Commitments and Contingencies

Commitments and Contingencies	12 Months Ended
	Dec. 31, 2021
Commitments and Contingencies Disclosure [Abstract]
Commitments and Contingencies	Note 12 — 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 our results from operations for a specific interim period or year. 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 Mexico production sharing contracts. As of December 31, 2021, the Company had secured performance bonds from third party sureties and letters of credit issued under its Bank Credit Facility totaling approximately $ 724.4 million and $ 13.6 million , respectively. The table below summarizes the Company’s total minimum commitments associated with vessel commitments and purchase obligations as of December 31, 2021 (in thousands): 2022 2023 2024 2025 Thereafter Total Vessel Commitments (1) $ 29,710 $ — $ — $ — $ — $ 29,710 Committed purchase orders (2) 3,153 — — — — 3,153 Total $ 32,863 $ — $ — $ — $ — $ 32,863 (1) Includes vessel commitments the Company will utilize for certain Deepwater well intervention and decommissioning activities. These commitments represent gross contractual obligations and accordingly, other joint owners in the properties operated by the Company will be billed for their working interest share of such costs. (2) Includes committed purchase orders to execute planned future drilling activities. These commitments represent gross contractual obligations and accordingly, other joint owners in the properties operated by the Company will be billed for their working interest share of such costs. Decommissioning Obligations The Company has divested various leases, wells and facilities located in the U.S. Gulf of Mexico where the purchasers typically assume all abandonment obligations acquired. Certain of these 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. Under certain circumstances, regulations or federal laws could require the Company to assume such obligations. For the year ended December 31, 2021 , the Company recorded $ 21.1 million related to estimated decommissioning obligations reflected in “Other operating (income) expense” on the Consolidated Statements of Operations. 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 our opinion regarding the outcome of certain notices or matters, and such developments could have a material adverse effect on our results of operations in the period in which the amounts are accrued and our cash flows in the period in which the amounts are paid.

Supplemental Oil and Gas Disclo

Supplemental Oil and Gas Disclosures (Unaudited)	12 Months Ended
	Dec. 31, 2021
Extractive Industries [Abstract]
Supplemental Oil and Gas Disclosures (Unaudited)	Note 13 — 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, 2021 2020 Proved properties $ 5,232,479 $ 4,945,550 Unproved oil and gas properties, not subject to amortization (1) 219,055 254,994 Total oil and gas properties 5,451,534 5,200,544 Less: Accumulated depletion 3,072,907 2,680,254 Net capitalized costs $ 2,378,627 $ 2,520,290 Depletion and amortization rate (Per MBoe) (2) $ 16.71 $ 31.42 (1) Amount includes $ 110.3 million and $ 121.7 million of unproved properties, not subject to amortization, related to the Company’s operations in offshore Mexico for the years ended December 31, 2021 and 2020, respectively. (2) Year ended December 31, 2020 includes the impact of a write-down of its U.S. oil and natural gas properties as result of the Company's ceiling test computations. See Note 4 — Property, Plant and Equipment for additional information. 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 4 — Property, Plant and Equipment 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, 2021 2020 2019 Property acquisition costs: Proved properties $ 210 $ 422,833 $ 27,660 Unproved properties, not subject to amortization — 95,242 16,062 Total property acquisition costs 210 518,075 43,722 Exploration costs (1) 23,844 59,422 209,161 Development costs 245,058 362,011 292,547 Total costs incurred $ 269,112 $ 939,508 $ 545,430 (1) Amount includes $ 6.6 million, $ 14.6 million and $ 74.2 million of exploration costs related to the Company’s operations in offshore Mexico for the year ended December 31, 2021, 2020 and 2019 , 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 sub-surface 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, 2021, 2020 and 2019 , 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 Total proved reserves at December 31, 2018 112,539 171,024 10,696 151,739 Revision of previous estimates ( 5,553 ) ( 15,898 ) ( 1,237 ) ( 9,440 ) Production ( 13,844 ) ( 23,306 ) ( 1,228 ) ( 18,956 ) Purchases of reserves 2,094 2,626 130 2,662 Extensions and discoveries 11,518 21,552 620 15,730 Total proved reserves at December 31, 2019 106,754 155,998 8,981 141,735 Revision of previous estimates ( 14,633 ) ( 56,358 ) ( 168 ) ( 24,195 ) Production (1) ( 13,665 ) ( 28,652 ) ( 1,559 ) ( 19,999 ) Purchases of reserves 26,903 181,872 3,528 60,743 Extensions and discoveries 3,948 4,348 76 4,749 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 Total proved developed reserves as of: December 31, 2019 72,016 115,381 6,733 97,979 December 31, 2020 85,007 204,054 8,104 127,120 December 31, 2021 93,420 186,442 11,792 136,286 Total proved undeveloped reserves as of: December 31, 2019 34,738 40,617 2,248 43,756 December 31, 2020 24,300 53,154 2,754 35,913 December 31, 2021 14,344 49,911 2,643 25,305 (1) Excludes approximately 3.0 MBoe of Mexico well test production . 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. During 2020 , proved reserves decreased by 21.3 MMBoe primarily due to a decrease of 20.0 MMBoe of production and revision to previous estimates of 24.2 MMBoe due to decrease in commodity prices. The decrease was partially offset by the addition of 60.7 MMBoe added through purchases from the ILX and Castex Acquisition, Castex Energy 2005 Acquisition and LLOG Acquisition as well as 4.7 MMBoe of estimated proved reserves from extensions and discoveries primarily from an evaluation of Green Canyon 18 and Claiborne Fields. During 2019 , proved reserves decreased by 10.0 MMBoe primarily due to a decrease of 19.0 MMBoe of production and revision to previous estimates of 9.7 MMBoe due to the Phoenix and Ram Powell Fields. The decrease was partially offset by the addition of 15.7 MMBoe of estimated proved reserves from extensions and discoveries primarily from an evaluation of Green Canyon 21, Pompano, and Ewing Bank 305 as well as 3.0 MMBoe added through purchases from the Gunflint Acquisition. 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, 2021 2020 2019 Future cash inflows $ 8,496,005 $ 4,927,497 $ 7,151,875 Future costs: Production ( 1,868,818 ) ( 1,105,211 ) ( 1,633,432 ) Development and abandonment ( 1,422,507 ) ( 1,236,874 ) ( 1,464,270 ) Future net cash flows before income taxes 5,204,680 2,585,412 4,054,173 Future income tax expense ( 676,778 ) ( 141,515 ) ( 662,317 ) Future net cash flows after income taxes 4,527,902 2,443,897 3,391,856 Discount at 10% annual rate ( 1,087,291 ) ( 538,963 ) ( 854,261 ) Standardized measure of discounted future net cash flows $ 3,440,611 $ 1,904,934 $ 2,537,595 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 base prices used in determining the standardized measure: Year Ended December 31, 2021 2020 2019 Oil price per Bbl $ 67.14 $ 39.47 $ 61.01 Natural gas price per Mcf $ 3.71 $ 1.97 $ 2.59 NGL price per Bbl $ 26.62 $ 9.89 $ 26.17 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 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. 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, 2021 2020 2019 Standardized measure, beginning of year $ 1,904,934 $ 2,537,595 $ 3,340,246 Sales and transfers of oil, net gas and NGLs produced during the period ( 957,576 ) ( 339,557 ) ( 665,226 ) Net change in prices and production costs 2,049,980 ( 1,468,304 ) ( 849,696 ) Changes in estimated future development costs ( 57,876 ) 32,589 ( 75,564 ) Previously estimated development costs incurred 69,125 46,143 117,049 Accretion of discount 199,849 299,302 392,526 Net change in income taxes ( 391,834 ) 361,875 129,590 Purchases of reserves — 730,611 75,009 Extensions and discoveries 45,485 71,589 306,515 Net change due to revision in quantity estimates 426,357 ( 309,338 ) ( 199,576 ) Changes in production rates (timing) and other 152,167 ( 57,571 ) ( 33,278 ) Standardized measure, end of year $ 3,440,611 $ 1,904,934 $ 2,537,595

Summary of Significant Accoun_2

Summary of Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2021
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. On May 10, 2018, the Parent Company consummated a combination between Talos Energy LLC and Stone Energy Corporation (“Stone”) (such combination, “Stone Combination”). Talos Energy LLC, which was the acquirer of Stone for financial reporting and accounting purposes, was formed in 2011 and commenced commercial operations on February 6, 2013. 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.”) Gulf of Mexico and offshore Mexico both upstream through oil and gas exploration and production and downstream through the development of future carbon capture and storage 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. With a focus on environmental stewardship, the Company also utilizes its expertise to explore opportunities to reduce industrial emissions through our carbon capture and storage collaborative arrangements 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 each subsidiary from the date of inception. 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. Certain reclassifications have been made to the prior year presentation to conform to the current year presentation. Amounts previously included as income in “Other” within “Revenues and Other” on the Consolidated Statements of Operations are now reflected in “Other operating (income) expense” as a component of “Total operating expenses” on the Consolidated Statements of Operations. The Company has two operating segments: (i) exploration and production of oil, natural gas and NGLs (“E&P Segment”) and (ii) carbon capture and sequestration (“CCS Segment”). The E&P Segment is the Company’s only reportable segment. The CCS Segment did not meet any of the quantitative thresholds to be a separate reportable segment. It did no t generate any revenue and incurred $ 4.3 million of general and administrative expense during the year ended December 31, 2021. The CCS Segment did no t have any assets at December 31, 2021.
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, 2021 and 2020 , the Company had allowances of $ 15.1 million and $ 9.2 million, respectively, presented net in accounts receivable on the Consolidated Balance Sheets. The Company presented $ 10.0 million and $ 19.1 million of long-term refund claims for value added taxes paid in Mexico in “Other assets” on the Consolidated Balance Sheets as of December 31, 2021 and 2020 , respectively. Current refund claims for value added taxes paid of $ 3.9 million and nil is presented net of an allowance in “Other” accounts receivable on the Consolidated Balance Sheets as of December 31, 2021 and 2020 , respectively.
Prepaid Assets	Prepaid Assets — Prepaid assets primarily represent deposits with the Office of Natural Resources Revenue (“ONRR”) . 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.
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. Gas Imbalances — Revenues are recorded based on the actual sales volumes sold to purchasers. An imbalance receivable or payable is recorded only to the extent the imbalance is in excess of its share of remaining proved developed reserves in an underlying property. Our imbalances are presented gross on our Consolidated Balance Sheets. At December 31, 2021 and 2020 , our imbalance receivable was approximately $ 1.7 million and $ 1.7 million, respectively, and imbalance payable was approximately $ 2.5 million and $ 3.6 million, respectively. 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. The refunds for the years ended December 31, 2021, 2020 and 2019 were nil , $ 8.9 million and $ 19.3 million, respectively.
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 .
Other Well Equipment Inventory	Other Well Equipment Inventory — Other well equipment inventory 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. The Company’s well equipment is stated at the lower of cost or net realizable value. The Company recorded $ 5.6 million, $ 0.7 million, and $ 0.2 million of impairment to adjust inventory to net realizable value, which was expensed and reflected in “Other operating (income) expense” on the Consolidated Statements of Operations, during the years ended December 31, 2021, 2020 and 2019 , respectively.
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.
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. As of December 31, 2021 , the Company incurred $ 3.8 million and $ 20.6 million in obligations reflected as “Other current liabilities” and “Other long-term liabilities”, respectively, on the Consolidated Balance Sheets. 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 12 — Commitments & Contingencies for additional information.
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.
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. 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.
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 restricted stock units (“RSUs”), performance share units (“PSUs”) and outstanding warrants. See Note 10 — Income (Loss) Per Share 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 and recognizes compensation cost on a straight-line basis in the Company’s financial statements over the requisite service period of each grant . 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, but is remeasured at each reporting period for awards classified as a liability. The Company records share-based compensation, net of actual forfeitures, for the RSUs and PSUs in “General and administrative expense” on the Consolidated Statements of Operations, net of amounts capitalized to oil and gas properties. See Note 8 — 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 — Share-based compensation is based on the grant date fair value determined using a Monte Carlo valuation model 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”) relative to the TSR achieved by a specified industry peer group. Share-based compensation related to PSUs is recognized as the requisite service period is fulfilled, even if the market condition is not achieved.
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 substantially all 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, 2021 2020 2019 Shell Trading (US) Company 45 % 47 % 58 % Chevron Products Company 29 % 12 % ** Phillips 66 ** 22 % 28 % ** 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.

Summary of Significant Accoun_3

Summary of Significant Accounting Policies (Tables)	12 Months Ended
	Dec. 31, 2021
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, 2021 2020 2019 Shell Trading (US) Company 45 % 47 % 58 % Chevron Products Company 29 % 12 % ** Phillips 66 ** 22 % 28 % ** Less than 10 %

Acquisitions (Tables)

Acquisitions (Tables)	12 Months Ended
	Dec. 31, 2021
LLOG Acquisition
Business Acquisition [Line Items]
Summary of Allocation of Purchase Price to Assets Acquired and Liabilities Assumed	The following table presents the allocation of the purchase price to the assets acquired and liabilities assumed, based on their relative fair values, on November 16, 2020 (in thousands): Property and equipment $ 17,421 Asset retirement obligations ( 4,234 ) Allocated purchase price $ 13,187
Castex 2005 Acquisition
Business Acquisition [Line Items]
Summary of Allocation of Purchase Price to Assets Acquired and Liabilities Assumed	The following table presents the allocation of the purchase price to the assets acquired and liabilities assumed, based on their relative fair values, on August 5, 2020 (in thousands): Property and equipment $ 46,626 Asset retirement obligations ( 3,320 ) Allocated purchase price $ 43,306
Summary of Purchase Price	The following table summarizes the purchase price, inclusive of customary closing adjustments (in thousands except share and per share data): Talos common stock 4,602,460 Talos common stock price per share (1) $ 7.69 Talos common stock value $ 35,393 Cash consideration $ 6,500 Transaction cost $ 1,413 Total purchase price $ 43,306
ILX and Castex
Business Acquisition [Line Items]
Summary of Purchase Price	The following table summarizes the purchase price (in thousands except share and per share data): Talos Conversion Stock 11,000,000 Talos common stock price per share (1) $ 14.20 Conversion Stock value $ 156,200 Cash consideration $ 385,000 Customary closing and post-closing adjustments ( 81,878 ) Net cash consideration $ 303,122 Total purchase price $ 459,322
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 28, 2020 (in thousands): Current assets (1) $ 11,060 Property and equipment 496,835 Other long-term assets 148 Current liabilities ( 16,520 ) Other long-term liabilities ( 32,201 ) Allocated purchase price $ 459,322 (1) Includes trade and other receivables of $ 8.2 million.
Summary of Revenue and Net Income Attributable to Assets Acquired	The following table presents revenue and net income attributable to the assets acquired in the ILX and Castex Acquisition: Year Ended December 31, 2020 Revenue $ 126,857 Net loss $ ( 6,011 )
Supplemental Proforma 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, 2020 and 2019 as if the ILX and Castex Acquisition had occurred on January 1, 2019. The unaudited pro forma information was derived from historical statements of operations of the Company and the Sellers adjusted to (i) include depletion expense applied to the adjusted basis of the oil and natural gas properties acquired, (ii) include interest expense to reflect borrowings under the Bank Credit Facility, (iii) eliminate the write-down of oil and natural gas properties on the assets acquired to reflect the pro-forma ceiling test calculation and (iv) include weighted average basic and diluted shares of common stock outstanding, which was calculated assuming the 11.0 million shares of Conversion Stock were issued to the Sellers. This information does not purport to be indicative of results of operations that would have occurred had the ILX and Castex Acquisition occurred on January 1, 2019, nor is such information indicative of any expected future results of operations. Year Ended December 31, 2020 2019 Revenue $ 634,921 $ 1,246,391 Net income (loss) $ ( 449,988 ) $ 148,091 Basic net income (loss) per common share $ ( 6.48 ) $ 2.27 Diluted net income (loss) per common share $ ( 6.48 ) $ 2.26

Property, Plant and Equipment (

Property, Plant and Equipment (Tables)	12 Months Ended
	Dec. 31, 2021
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, 2021, by the year in which such costs were incurred (in thousands): Year Ended December 31, Total 2021 2020 2019 2018 and Prior Acquisition United States $ 46,757 $ — $ 37,704 $ 3,216 $ 5,837 Exploration United States 62,038 16,242 11,195 31,111 3,490 Exploration Mexico 110,260 2,736 13,853 48,508 45,163 Total unproved properties, not subject $ 219,055 $ 18,978 $ 62,752 $ 82,835 $ 54,490
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, 2021 2020 Balance, beginning of period $ 442,269 $ 369,478 Obligations acquired (1) 433 44,311 Obligations incurred 52 4,511 Obligations settled ( 67,988 ) ( 43,933 ) Obligations divested ( 340 ) ( 185 ) Accretion expense 58,129 49,741 Changes in estimate 1,451 18,346 Balance, end of period $ 434,006 $ 442,269 Less: Current portion 60,311 49,921 Long-term portion $ 373,695 $ 392,348 (1) Year ended December 31, 2020 includes $ 35.3 million, $ 3.3 million and $ 4.2 million of asset retirement obligations assumed in the ILX and Castex Acquisition, Castex Energy 2005 Acquisition and LLOG Acquisition, respectively.

Leases (Tables)

Leases (Tables)	12 Months Ended
	Dec. 31, 2021
Leases [Abstract]
Components of Lease Costs	The components of lease costs were as follows (in thousands): Year Ended December 31, 2021 2020 2019 Finance lease cost - interest on lease liabilities $ 11,453 $ 15,748 $ 19,115 Operating lease cost, excluding short-term leases (1) 2,706 3,361 3,261 Short-term lease cost (2) 38,472 53,573 85,865 Variable lease cost (3) 1,356 543 11 Total lease cost $ 53,987 $ 73,225 $ 108,252 (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 right-of-use asset and lease liability on the Consolidated Balance Sheets. Variable lease costs primarily represent differences between minimum payment obligations and actual operating charges incurred by the Company related to its long-term leases.
Schedule of Right-of-Use Asset and Liability, Adjusted for Initial Direct Costs and Incentives	The present value of the fixed lease payments recorded as the Company’s right-of-use asset and liability, adjusted for initial direct costs and incentives were as follows (in thousands): Year Ended December 31, 2021 2020 Operating leases: Operating lease assets $ 5,714 $ 6,855 Current portion of operating lease liabilities $ 1,715 $ 1,793 Operating lease liabilities 16,330 18,554 Total operating lease liabilities $ 18,045 $ 20,347 Finance leases: Proved property $ 124,299 $ 124,299 Other current liabilities $ 27,083 $ 21,804 Other long-term liabilities 13,138 40,222 Total finance lease liabilities $ 40,221 $ 62,026
Schedule of Lease Maturity	The table below presents the lease maturity by year as of December 31, 2021 (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 2022 $ 3,712 $ 33,257 2023 3,652 13,857 2024 3,454 — 2025 3,519 — 2026 3,584 — Thereafter 9,258 — Total lease payments $ 27,179 $ 47,114 Imputed interest ( 9,134 ) ( 6,893 ) Total lease liabilities $ 18,045 $ 40,221
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, 2021 2020 2019 Weighted average remaining lease term: Operating leases 7.4 years 7.8 years 8.4 years Finance leases 1.4 years 2.4 years 3.4 years Weighted average discount rate: Operating leases 11.9 % 12.0 % 10.2 % Finance leases 21.9 % 21.9 % 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, 2021 2020 2019 Operating cash outflow from finance leases $ 11,453 $ 15,748 $ 19,115 Operating cash outflow from operating leases $ 3,864 $ 2,648 $ 1,812 Right-of-use assets obtained in exchange for new $ 1,020 $ — $ 2,225

Financial Instruments (Tables)

Financial Instruments (Tables)	12 Months Ended
	Dec. 31, 2021
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, 2021 December 31, 2020 Carrying Fair Carrying Fair 12.00 % Second-Priority Senior Secured Notes – January 2026 $ 588,838 $ 685,945 $ — $ — 11.00 % Second-Priority Senior Secured Notes – April 2022 $ — $ — $ 343,579 $ 355,935 7.50 % Senior Notes – due May 2022 $ 6,060 $ 6,145 $ 6,060 $ 5,238 Bank Credit Facility – matures November 2024 $ 367,829 $ 375,000 $ 635,873 $ 640,000
Schedule of Impact that Derivatives not Qualifying as Hedging Instruments in Condensed Consolidated Statements of Operations	The following table presents the impact that derivatives, not designated as hedging instruments, had on its Consolidated Statements of Operations (in thousands): Year Ended December 31, 2021 2020 2019 Net cash received (paid) on settled derivative instruments $ ( 290,164 ) $ 143,905 $ ( 8,820 ) Unrealized loss ( 128,913 ) ( 56,220 ) ( 86,517 ) Price risk management activities income (expense) $ ( 419,077 ) $ 87,685 $ ( 95,337 )
Schedule of Contracted Volumes and Weighted Average Prices and will Receive Under the Terms of Derivative Contracts	The following table reflects the contracted volumes and weighted average prices under the terms of the Company's derivative contracts as of December 31, 2021: Swap Contracts Production Period Settlement Index Average Weighted Crude oil: (Bbls) (per Bbl) January 2022 – December 2022 NYMEX WTI CMA 23,523 $ 52.42 January 2023 – December 2023 NYMEX WTI CMA 7,463 $ 63.13 Natural gas: (MMBtu) (per MMBtu) January 2022 – December 2022 NYMEX Henry Hub 43,392 $ 2.77 January 2023 – December 2023 NYMEX Henry Hub 16,408 $ 3.29
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, 2021 Level 1 Level 2 Level 3 Total Assets: Oil and natural gas swaps $ — $ 3,737 $ — $ 3,737 Liabilities: Oil and natural gas swaps — ( 200,464 ) — ( 200,464 ) Total net liability $ — $ ( 196,727 ) $ — $ ( 196,727 ) December 31, 2020 Level 1 Level 2 Level 3 Total Assets: Oil and natural gas swaps and costless collars $ — $ 7,821 $ — $ 7,821 Liabilities: Oil and natural gas swaps and costless collars — ( 75,635 ) — ( 75,635 ) Total net liability $ — $ ( 67,814 ) $ — $ ( 67,814 )
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, 2021 December 31, 2020 Assets Liabilities Assets Liabilities Oil and natural gas derivatives: Current $ 967 $ 186,526 $ 6,876 $ 66,010 Non-current 2,770 13,938 945 9,625 Total gross amounts presented on balance sheet 3,737 200,464 7,821 75,635 Less: Gross amounts not offset on the balance sheet 3,737 3,737 4,877 4,877 Net amounts $ — $ 196,727 $ 2,944 $ 70,758

Debt (Tables)

Debt (Tables)	12 Months Ended
	Dec. 31, 2021
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, 2021 2020 12.00 % Second-Priority Senior Secured Notes – due January 2026 $ 650,000 $ — 11.00 % Second-Priority Senior Secured Notes – due April 2022 — 347,254 7.50 % Senior Notes – due May 2022 6,060 6,060 Bank Credit Facility – matures November 2024 375,000 640,000 Total debt, before discount and deferred financing cost 1,031,060 993,314 Discount and deferred financing cost ( 68,333 ) ( 7,802 ) Total debt, net of discount and deferred financing costs 962,727 985,512 Less: Current portion of long-term debt 6,060 — Long-term debt, net of discount and deferred financing costs $ 956,667 $ 985,512
Summary of Redemption Prices of 12.% Notes	Thereafter, 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 106.00 % 2024 103.00 % 2025 100.00 %
Schedule of Pricing Grid for Borrowing Base Utilization Percentage	The pricing grid below shows the applicable margin for LIBOR loans and ABR loans as well as the commitment fee rate based upon the applicable borrowing base utilization percentage: Borrowing Base Utilization Percentage Utilization LIBOR Loans ABR Loans Commitment Level 1 < 25 % 3.00 % 2.00 % 0.50 % Level 2 ≥ 25 % < 50 % 3.25 % 2.25 % 0.50 % Level 3 ≥ 50 % < 75 % 3.50 % 2.50 % 0.50 % Level 4 ≥ 75 % < 90 % 3.75 % 2.75 % 0.50 % Level 5 ≥ 90 % 4.00 % 3.00 % 0.50 %

Employee Benefits Plans and S_2

Employee Benefits Plans and Share-Based Compensation (Tables)	12 Months Ended
	Dec. 31, 2021
Share-based Payment Arrangement [Abstract]
Summary of Restricted Stock Units Activity	The following table summarizes RSU activity: Restricted Stock Weighted Average Unvested RSUs at December 31, 2018 138,704 $ 33.85 Granted 732,771 $ 24.39 Vested ( 69,235 ) $ 33.72 Forfeited ( 68,463 ) $ 25.43 Unvested RSUs at December 31, 2019 733,777 $ 25.20 Granted 1,284,797 $ 10.02 Vested ( 273,787 ) $ 25.09 Forfeited ( 91,799 ) $ 19.65 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) 1,983,199 $ 13.02 As of December 31, 2021 , 25,592 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, 2018 231,542 $ 44.47 Granted 218,060 $ 33.96 Forfeited ( 31,771 ) $ 40.27 Unvested PSUs at December 31, 2019 417,831 $ 39.31 Granted 441,642 $ 13.05 Forfeited ( 25,301 ) $ 37.67 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
Summary of Assumptions Used to Calculate the Grant Date Fair Value of PSUs Granted	The following table summarizes the assumptions used in the Monte Carlo simulations to calculate the fair value of the PSUs granted and modified at the date indicated: 2021 2020 2019 Modification Grant Grant Grant May 11 March 8 March 5 March 5 May 16 Expected term (in years) 2.6 2.8 2.8 2.8 2.6 Expected volatility 80.9 % 78.3 % 48.8 % 46.9 % 44.8 % Risk-free interest rate 0.3 % 0.3 % 0.6 % 2.5 % 2.1 % Dividend yield — % — % — % — % — % Fair value (in thousands) $ 9,715 $ 11,129 $ 5,763 $ 6,195 $ 1,210
Schedule of Recognized Share Based Compensation Expense, Net	The following table presents the amount of cost expensed and capitalized (in thousands): Year Ended December 31, 2021 2020 2019 Share-based compensation costs $ 20,560 $ 16,462 $ 12,924 Less: Amounts capitalized to oil and gas properties 9,568 7,793 5,960 Total share-based compensation expense $ 10,992 $ 8,669 $ 6,964

Income Taxes (Tables)

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2021
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, 2021 2020 2019 Current income tax expense (benefit): United States $ ( 5 ) $ ( 499 ) $ 437 Mexico ( 993 ) 185 1,183 Total current income tax expense (benefit) $ ( 998 ) $ ( 314 ) $ 1,620 Deferred income tax expense (benefit): United States $ ( 1,067 ) $ 35,923 $ ( 37,131 ) Mexico 430 ( 26 ) ( 630 ) Total deferred income tax expense (benefit) $ ( 637 ) $ 35,897 $ ( 37,761 ) Total income tax expense (benefit) $ ( 1,635 ) $ 35,583 $ ( 36,141 )
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, 2021 2020 2019 Income tax expense (benefit) at the federal statutory tax rate $ ( 38,763 ) $ ( 90,304 ) $ 4,744 State income taxes ( 674 ) ( 14,215 ) 1,396 Impact of foreign operations ( 11,920 ) ( 1,030 ) ( 4,948 ) Effect of change in state rate 2,008 — — Prior year taxes 486 ( 4,237 ) ( 1,950 ) Other adjustments — — 137 Legal entity reorganization — ( 17,566 ) 39,336 Change in valuation allowance 45,547 162,213 ( 75,196 ) Other permanent differences 1,681 722 340 Total income tax expense (benefit) $ ( 1,635 ) $ 35,583 $ ( 36,141 ) Effective tax rate 0.89 % ( 8.27 )% ( 159.99 )%
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, 2021 2020 Deferred tax assets: Federal net operating loss $ 153,849 $ 133,804 Foreign tax loss carryforward 49,932 45,980 State net operating loss 24,265 25,740 Asset retirement obligations 92,823 106,604 Tax credits 303 522 Derivatives 42,075 16,346 Other well equipment inventory 5,680 9,470 Accrued bonus 5,087 3,069 Operating lease liabilities 4,081 4,904 Other 9,257 7,727 Total deferred tax assets 387,352 354,166 Valuation allowance ( 224,266 ) ( 178,998 ) Total deferred tax assets, net $ 163,086 $ 175,168 Deferred tax liabilities: Oil and gas properties $ 160,002 $ 170,596 Deferred financing — 1,765 Operating lease assets 1,423 1,652 Prepaid 3,075 3,216 Total deferred tax liabilities 164,500 177,229 Net deferred tax liability $ ( 1,414 ) $ ( 2,061 )
Summary of Net Operating Loss Carryovers	The table below presents the details of the Company’s net operating loss carryovers as of December 31, 2021 (in thousands): Amount Expiration Year Federal net operating losses $ 534,964 2035 - 2037 Federal net operating losses $ 197,651 Unlimited Foreign tax loss carryforward $ 166,440 2025 - 2031 State net operating losses $ 125,958 2025 - 2037 State net operating losses $ 268,221 Unlimited
Summary of Balances In Uncertain Tax Positions	Balances in the uncertain tax positions are as follows (in thousands): Year Ended December 31, 2021 2020 Total unrecognized tax benefits, beginning balance $ 648 $ 791 Increases in unrecognized tax benefits as a result of: Tax positions taken during a prior period 21 ( 208 ) Tax positions taken during the current period 27 65 Total unrecognized tax benefits, ending balance $ 696 $ 648

Income (Loss) Per Share (Tables

Income (Loss) Per Share (Tables)	12 Months Ended
	Dec. 31, 2021
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, 2021 2020 2019 Net income (loss) $ ( 182,952 ) $ ( 465,605 ) $ 58,729 Weighted average common shares outstanding — basic 81,769 67,664 54,185 Dilutive effect of securities — — 228 Weighted average common shares outstanding — diluted 81,769 67,664 54,413 Net income (loss) per common share: Basic $ ( 2.24 ) $ ( 6.88 ) $ 1.08 Diluted $ ( 2.24 ) $ ( 6.88 ) $ 1.08 Anti-dilutive potentially issuable securities excluded 1,709 5,019 4,220

Commitments and Contingencies (

Commitments and Contingencies (Tables)	12 Months Ended
	Dec. 31, 2021
Commitments and Contingencies Disclosure [Abstract]
Summary of Total Minimum Commitments Associated With Long-Term Non-cancelable Operating Lease	The table below summarizes the Company’s total minimum commitments associated with vessel commitments and purchase obligations as of December 31, 2021 (in thousands): 2022 2023 2024 2025 Thereafter Total Vessel Commitments (1) $ 29,710 $ — $ — $ — $ — $ 29,710 Committed purchase orders (2) 3,153 — — — — 3,153 Total $ 32,863 $ — $ — $ — $ — $ 32,863

Supplemental Oil and Gas Disc_2

Supplemental Oil and Gas Disclosures (Unaudited) (Tables)	12 Months Ended
	Dec. 31, 2021
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, 2021 2020 Proved properties $ 5,232,479 $ 4,945,550 Unproved oil and gas properties, not subject to amortization (1) 219,055 254,994 Total oil and gas properties 5,451,534 5,200,544 Less: Accumulated depletion 3,072,907 2,680,254 Net capitalized costs $ 2,378,627 $ 2,520,290 Depletion and amortization rate (Per MBoe) (2) $ 16.71 $ 31.42 (1) Amount includes $ 110.3 million and $ 121.7 million of unproved properties, not subject to amortization, related to the Company’s operations in offshore Mexico for the years ended December 31, 2021 and 2020, respectively. (2) Year ended December 31, 2020 includes the impact of a write-down of its U.S. oil and natural gas properties as result of the Company's ceiling test computations. See Note 4 — Property, Plant and Equipment for additional information.
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, 2021 2020 2019 Property acquisition costs: Proved properties $ 210 $ 422,833 $ 27,660 Unproved properties, not subject to amortization — 95,242 16,062 Total property acquisition costs 210 518,075 43,722 Exploration costs (1) 23,844 59,422 209,161 Development costs 245,058 362,011 292,547 Total costs incurred $ 269,112 $ 939,508 $ 545,430 (1) Amount includes $ 6.6 million, $ 14.6 million and $ 74.2 million of exploration costs related to the Company’s operations in offshore Mexico for the year ended December 31, 2021, 2020 and 2019 , 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 Total proved reserves at December 31, 2018 112,539 171,024 10,696 151,739 Revision of previous estimates ( 5,553 ) ( 15,898 ) ( 1,237 ) ( 9,440 ) Production ( 13,844 ) ( 23,306 ) ( 1,228 ) ( 18,956 ) Purchases of reserves 2,094 2,626 130 2,662 Extensions and discoveries 11,518 21,552 620 15,730 Total proved reserves at December 31, 2019 106,754 155,998 8,981 141,735 Revision of previous estimates ( 14,633 ) ( 56,358 ) ( 168 ) ( 24,195 ) Production (1) ( 13,665 ) ( 28,652 ) ( 1,559 ) ( 19,999 ) Purchases of reserves 26,903 181,872 3,528 60,743 Extensions and discoveries 3,948 4,348 76 4,749 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 Total proved developed reserves as of: December 31, 2019 72,016 115,381 6,733 97,979 December 31, 2020 85,007 204,054 8,104 127,120 December 31, 2021 93,420 186,442 11,792 136,286 Total proved undeveloped reserves as of: December 31, 2019 34,738 40,617 2,248 43,756 December 31, 2020 24,300 53,154 2,754 35,913 December 31, 2021 14,344 49,911 2,643 25,305 (1) Excludes approximately 3.0 MBoe of Mexico well test production .
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, 2021 2020 2019 Future cash inflows $ 8,496,005 $ 4,927,497 $ 7,151,875 Future costs: Production ( 1,868,818 ) ( 1,105,211 ) ( 1,633,432 ) Development and abandonment ( 1,422,507 ) ( 1,236,874 ) ( 1,464,270 ) Future net cash flows before income taxes 5,204,680 2,585,412 4,054,173 Future income tax expense ( 676,778 ) ( 141,515 ) ( 662,317 ) Future net cash flows after income taxes 4,527,902 2,443,897 3,391,856 Discount at 10% annual rate ( 1,087,291 ) ( 538,963 ) ( 854,261 ) Standardized measure of discounted future net cash flows $ 3,440,611 $ 1,904,934 $ 2,537,595
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 base prices used in determining the standardized measure: Year Ended December 31, 2021 2020 2019 Oil price per Bbl $ 67.14 $ 39.47 $ 61.01 Natural gas price per Mcf $ 3.71 $ 1.97 $ 2.59 NGL price per Bbl $ 26.62 $ 9.89 $ 26.17
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, 2021 2020 2019 Standardized measure, beginning of year $ 1,904,934 $ 2,537,595 $ 3,340,246 Sales and transfers of oil, net gas and NGLs produced during the period ( 957,576 ) ( 339,557 ) ( 665,226 ) Net change in prices and production costs 2,049,980 ( 1,468,304 ) ( 849,696 ) Changes in estimated future development costs ( 57,876 ) 32,589 ( 75,564 ) Previously estimated development costs incurred 69,125 46,143 117,049 Accretion of discount 199,849 299,302 392,526 Net change in income taxes ( 391,834 ) 361,875 129,590 Purchases of reserves — 730,611 75,009 Extensions and discoveries 45,485 71,589 306,515 Net change due to revision in quantity estimates 426,357 ( 309,338 ) ( 199,576 ) Changes in production rates (timing) and other 152,167 ( 57,571 ) ( 33,278 ) Standardized measure, end of year $ 3,440,611 $ 1,904,934 $ 2,537,595

Organization, Nature of Busin_2

Organization, Nature of Business and Basis of Presentation - Additional Information (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2021USD ($)Segment	Dec. 31, 2020USD ($)	Dec. 31, 2019USD ($)
Basis Of Presentation And Schedule Of Accounting Policy [Line Items]
Number of Operating Segments | Segment	2
General and administrative expense	$ 78,677	$ 79,175	$ 77,209
Assets	2,766,815	2,834,546
Revenues	1,244,540	$ 575,936	$ 908,064
Carbon Capture And Sequestration[ Member]
Basis Of Presentation And Schedule Of Accounting Policy [Line Items]
General and administrative expense	4,300
Assets	0
Revenues	$ 0

Summary of Significant Accoun_4

Summary of Significant Accounting Policies - Additional Information (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Summary Of Significant Accounting Policies [Line Items]
Allowance for expected credit losses	$ 15,100	$ 9,200
Impairment to adjust other well equipment inventory	5,600	700	$ 200
Other current liabilities	33,061	24,155
Other long-term liabilities	45,006	54,372
Receivable
Summary Of Significant Accounting Policies [Line Items]
Gas Balancing Asset (Liability)	1,700	1,700
Payable
Summary Of Significant Accounting Policies [Line Items]
Gas Balancing Asset (Liability)	2,500	3,600
Decommissioning Obligations
Summary Of Significant Accounting Policies [Line Items]
Other current liabilities	3,800
Other long-term liabilities	20,600
Other operating (income) expense
Summary Of Significant Accounting Policies [Line Items]
Multi-year federal royalty refund claim	0	8,900	$ 19,300
MEXICO
Summary Of Significant Accounting Policies [Line Items]
Value added tax receivable, Noncurrent	10,000	$ 19,100
Value added tax receivable, Current	$ 3,900
Minimum
Summary Of Significant Accounting Policies [Line Items]
Other property and equipment, estimated useful lives	3 years
Number of common stock issuable upon vesting, percentage range of PSUs granted	0.00%
Maximum
Summary Of Significant Accounting Policies [Line Items]
Other property and equipment, estimated useful lives	10 years
Number of common stock issuable upon vesting, percentage range of PSUs granted	200.00%
Measurement Input Discount Rate
Summary Of Significant Accounting Policies [Line Items]
Present value of future net revenues from proved reserves, discount rate	10.00%

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, 2021	Dec. 31, 2020	Dec. 31, 2019
Shell Trading (US) Company
Concentration Risk [Line Items]
Concentration risk, percentage	45.00%	47.00%	58.00%
Phillips 66
Concentration Risk [Line Items]
Concentration risk, percentage		22.00%	28.00%
Chevron Products Company
Concentration Risk [Line Items]
Concentration risk, percentage	29.00%	12.00%

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 - Chevron Products Company	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Concentration Risk [Line Items]
Concentration risk, percentage	29.00%	12.00%
Maximum
Concentration Risk [Line Items]
Concentration risk, percentage			10.00%

Acquisitions - Asset Acquisitio

Acquisitions - Asset Acquisitions - Additional Information (Details) $ in Thousands	Nov. 16, 2020USD ($)	Aug. 05, 2020USD ($)Propertyshares	Mar. 30, 2020shares	Feb. 28, 2020USD ($)	Jan. 11, 2019USD ($)	Dec. 31, 2020USD ($)shares	Dec. 31, 2019USD ($)
Business Acquisition [Line Items]
Aggregate shares issued | shares						4,602,460
General and Administrative Expense
Business Acquisition [Line Items]
Acquisition, transaction related cost						$ 8,700	$ 3,400
ILX and Castex
Business Acquisition [Line Items]
Purchase price				$ 459,322
ILX and Castex | Contingent Convertible Preferred Stock
Business Acquisition [Line Items]
Conversion stock issued to sellers | shares			11,000,000
LLOG Acquisition
Business Acquisition [Line Items]
Effective date of asset acquisition	Nov. 16, 2020
Asset acquisition agreement effective date	Aug. 1, 2020
Asset acquisition, date of acquisition agreement	Nov. 16, 2020
Asset Acquisition, Consideration Transferred	$ 13,200
Acquisition, transaction related cost	$ 200
Castex 2005 Acquisition
Business Acquisition [Line Items]
Effective date of asset acquisition		Aug. 5, 2020
Asset acquisition agreement effective date		Apr. 1, 2020
Asset acquisition, date of acquisition agreement		Jun. 19, 2020
Aggregate consideration of cash		$ 6,500				6,500
Asset Acquisition, Consideration Transferred						43,306
Aggregate shares issued | shares		4,600,000
Acquisition, transaction related cost		$ 1,400				$ 1,413
Number of properties | Property		16
Gunflint Acquisition
Business Acquisition [Line Items]
Asset Acquisition, Consideration Transferred					$ 27,900
Asset Acquisition, Price of Acquisition, Expected					$ 29,600
Percentage of non-operated working interest acquired					9.60%

Acquisitions - Asset Acquisit_2

Acquisitions - Asset Acquisitions - Summary of Allocation of Purchase Price to Assets Acquired and Liabilities Assumed (Details) - USD ($) $ in Thousands	Nov. 16, 2020	Aug. 05, 2020
LLOG Acquisition
Business Acquisition [Line Items]
Property and equipment	$ 17,421
Asset retirement obligations	(4,234)
Allocated purchase price	$ 13,187
Castex 2005 Acquisition
Business Acquisition [Line Items]
Property and equipment		$ 46,626
Asset retirement obligations		(3,320)
Allocated purchase price		$ 43,306

Acquisitions - Asset Acquisit_3

Acquisitions - Asset Acquisitions - Summary of Purchase Price, Subject to Customary Post-Closing Adjustments (Details) - USD ($) $ / shares in Units, $ in Thousands		Aug. 05, 2020	Dec. 31, 2020
Asset Acquisition [Line Items]
Talos common stock			4,602,460
Castex 2005 Acquisition
Asset Acquisition [Line Items]
Talos common stock		4,600,000
Cash consideration		$ 6,500	$ 6,500
Transaction cost		$ 1,400	1,413
Allocated purchase price			43,306
Castex 2005 Acquisition | Common Stock
Asset Acquisition [Line Items]
Talos common stock price per share	[1]	$ 7.69
Talos common stock value			$ 35,393
[1]	Represents the closing price of the Company’s common stock on August 5, 2020, the closing date of the Castex Energy 2005 Acquisition.

Acquisitions - Business Combina

Acquisitions - Business Combination - Additional Information (Details) - USD ($) $ in Millions	Mar. 30, 2020	Feb. 28, 2020	Jul. 01, 2019	Mar. 31, 2020	Dec. 31, 2020	Dec. 31, 2019
Series A Convertible Preferred Stock
Business Acquisition [Line Items]
Conversion stock issued to sellers				11,000,000
General and Administrative Expense
Business Acquisition [Line Items]
Acquisition, transaction related cost					$ 8.7	$ 3.4
ILX and Castex
Business Acquisition [Line Items]
Business acquisition, effective date		Feb. 28, 2020
Business acquisition acquisition agreement effective date			Jul. 1, 2019
Cash consideration		$ 385
ILX and Castex | Series A Convertible Preferred Stock
Business Acquisition [Line Items]
Aggregate shares issued	110,000	110,000
ILX and Castex | Contingent Convertible Preferred Stock
Business Acquisition [Line Items]
Conversion stock issued to sellers	11,000,000
ILX and Castex | General and Administrative Expense
Business Acquisition [Line Items]
Acquisition, transaction related cost		$ 12.1

Acquisitions - Business Combi_2

Acquisitions - Business Combination - Summary of Purchase Price, Subject to Customary Post-Closing Adjustments (Details) - USD ($) $ / shares in Units, $ in Thousands		Feb. 28, 2020	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Business Acquisition [Line Items]
Net cash consideration			$ 5,399	$ 315,962	$ 37,916
ILX and Castex
Business Acquisition [Line Items]
Talos Conversion Stock		11,000,000
Talos common stock price per share	[1]	$ 14.20
Conversion Stock value		$ 156,200
Cash consideration		385,000
Customary closing and post-closing adjustments		(81,878)
Net cash consideration		303,122
Total purchase price		$ 459,322
[1]	Represents the closing price of the Company’s common stock on February 28, 2020, the closing date of the ILX and Castex Acquisition. The purchase price was based on the value of the Conversion Stock as the value approximates the value of the Preferred Shares as a result of the automatic conversion and dividend rights described in that certain Certificate of Designation, Preferences, Rights and Limitations.

Acquisitions - Business Combi_3

Acquisitions - Business Combination - Summary of Allocation of Purchase Price to Assets Acquired and Liabilities Assumed Including the Measurement Period Adjustments (Details) - ILX and Castex $ in Thousands	Feb. 28, 2020USD ($)
Business Acquisition [Line Items]
Current assets	$ 11,060
Property and equipment	496,835
Other long-term assets	148
Current liabilities	(16,520)
Other long-term liabilities	(32,201)
Allocated purchase price	$ 459,322

Acquisitions - Business Combi_4

Acquisitions - Business Combination - Summary of Allocation of Purchase Price to Assets Acquired and Liabilities Assumed Including the Measurement Period Adjustments (Parenthetical) (Details) $ in Millions	Feb. 28, 2020USD ($)
ILX and Castex | Trade and Other Receivables
Business Acquisition [Line Items]
Primary fair values of receivables acquired	$ 8.2

Acquisitions - Business Combi_5

Acquisitions - Business Combination - Summary of Revenue and Net Income Attributable to Assets Acquired (Details) - ILX and Castex $ in Thousands	12 Months Ended
	Dec. 31, 2020USD ($)
Business Acquisition [Line Items]
Revenue	$ 126,857
Net income (loss)	$ (6,011)

Acquisitions - Business Combi_6

Acquisitions - Business Combination - Summary of Supplemental Proforma Information (Details) - ILX and Castex - USD ($) $ / shares in Units, $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Business Acquisition [Line Items]
Revenue	$ 634,921	$ 1,246,391
Net income (loss)	$ (449,988)	$ 148,091
Basic net income (loss) per common share	$ (6.48)	$ 2.27
Diluted net income (loss) per common share	$ (6.48)	$ 2.26

Property, Plant and Equipment -

Property, Plant and Equipment - Additional Information (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2021USD ($)$ / Mcf$ / bbl	Dec. 31, 2020USD ($)$ / bbl$ / Mcf	Dec. 31, 2019USD ($)$ / bbl$ / Mcf
Property, Plant and Equipment [Line Items]
Write-down of oil and natural gas properties | $	$ 18,123	$ 267,916	$ 12,221
Oil (MBbls)
Property, Plant and Equipment [Line Items]
SEC pricing	67.14	39.47	61.01
Gas (MMcf)
Property, Plant and Equipment [Line Items]
SEC pricing | $ / Mcf	3.71	1.97	2.59
NGL (MBbls)
Property, Plant and Equipment [Line Items]
SEC pricing	26.62	9.89	26.17
US
Property, Plant and Equipment [Line Items]
Write-down of oil and natural gas properties | $	$ 0	$ 267,900	$ 0
US | Oil (MBbls)
Property, Plant and Equipment [Line Items]
SEC pricing	67.14
US | Gas (MMcf)
Property, Plant and Equipment [Line Items]
SEC pricing | $ / Mcf	3.71
US | NGL (MBbls)
Property, Plant and Equipment [Line Items]
SEC pricing	26.62
Mexico
Property, Plant and Equipment [Line Items]
Write-down of oil and natural gas properties | $	$ 18,100	$ 100	$ 12,200

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, 2021	Dec. 31, 2020
Capitalized Costs Of Unproved Properties Excluded From Amortization [Line Items]
Total unproved properties, not subject to amortization	$ 219,055	$ 254,994
United States
Capitalized Costs Of Unproved Properties Excluded From Amortization [Line Items]
Acquisition	46,757
Exploration	62,038
Mexico
Capitalized Costs Of Unproved Properties Excluded From Amortization [Line Items]
Exploration	110,260
Total unproved properties, not subject to amortization	110,300	$ 121,700
2021
Capitalized Costs Of Unproved Properties Excluded From Amortization [Line Items]
Total unproved properties, not subject to amortization	18,978
2021 | United States
Capitalized Costs Of Unproved Properties Excluded From Amortization [Line Items]
Exploration	16,242
2021 | Mexico
Capitalized Costs Of Unproved Properties Excluded From Amortization [Line Items]
Exploration	2,736
2020
Capitalized Costs Of Unproved Properties Excluded From Amortization [Line Items]
Total unproved properties, not subject to amortization	62,752
2020 | United States
Capitalized Costs Of Unproved Properties Excluded From Amortization [Line Items]
Acquisition	37,704
Exploration	11,195
2020 | Mexico
Capitalized Costs Of Unproved Properties Excluded From Amortization [Line Items]
Exploration	13,853
2019
Capitalized Costs Of Unproved Properties Excluded From Amortization [Line Items]
Total unproved properties, not subject to amortization	82,835
2019 | United States
Capitalized Costs Of Unproved Properties Excluded From Amortization [Line Items]
Acquisition	3,216
Exploration	31,111
2019 | Mexico
Capitalized Costs Of Unproved Properties Excluded From Amortization [Line Items]
Exploration	48,508
2018 and Prior
Capitalized Costs Of Unproved Properties Excluded From Amortization [Line Items]
Total unproved properties, not subject to amortization	54,490
2018 and Prior | United States
Capitalized Costs Of Unproved Properties Excluded From Amortization [Line Items]
Acquisition	5,837
Exploration	3,490
2018 and Prior | Mexico
Capitalized Costs Of Unproved Properties Excluded From Amortization [Line Items]
Exploration	$ 45,163

Property, Plant and Equipment_3

Property, Plant and Equipment - Schedule of Asset Retirement Obligations (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Oil and Gas Property [Abstract]
Balance, beginning of period	$ 442,269	$ 369,478
Obligations acquired	433	44,311
Obligations incurred	52	4,511
Obligations settled	(67,988)	(43,933)
Obligations divested	(340)	(185)
Accretion expense	58,129	49,741	$ 34,389
Changes in estimate	1,451	18,346
Balance, end of period	434,006	442,269	$ 369,478
Less: Current portion	(60,311)	(49,921)
Long-term portion	$ 373,695	$ 392,348

Property, Plant and Equipment_4

Property, Plant and Equipment - Schedule of Asset Retirement Obligations (Parenthetical) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020
Property, Plant and Equipment [Line Items]
Obligations acquired	$ 433	$ 44,311
ILX and Castex
Property, Plant and Equipment [Line Items]
Obligations acquired		35,300
Castex 2005 Acquisition
Property, Plant and Equipment [Line Items]
Obligations acquired		3,300
LLOG Acquisition
Property, Plant and Equipment [Line Items]
Obligations acquired		$ 4,200

Leases - Components of Lease Co

Leases - Components of Lease Costs (Details) - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Lease, Cost [Abstract]
Finance lease cost - interest on lease liabilities		$ 11,453	$ 15,748	$ 19,115
Operating lease cost, excluding short-term leases	[1]	2,706	3,361	3,261
Short-term lease cost	[2]	38,472	53,573	85,865
Variable lease cost	[3]	1,356	543	11
Total lease cost		$ 53,987	$ 73,225	$ 108,252
[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 right-of-use 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.

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, 2021	Dec. 31, 2020
Operating leases:
Operating lease assets	$ 5,714	$ 6,855
Current portion of operating lease liabilities	$ 1,715	$ 1,793
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	$ 16,330	$ 18,554
Total operating lease liabilities	18,045	20,347
Finance leases:
Proved property	$ 124,299	$ 124,299
Finance Lease, Right-of-Use Asset, Statement of Financial Position [Extensible Enumeration]	Other assets	Other assets
Other current liabilities	$ 27,083	$ 21,804
Finance Lease, Liability, Current, Statement of Financial Position [Extensible List]	Other current liabilities	Other current liabilities
Other long-term liabilities	$ 13,138	$ 40,222
Finance Lease, Liability, Noncurrent, Statement of Financial Position [Extensible List]	Other long-term liabilities	Other long-term liabilities
Total finance lease liabilities	$ 40,221	$ 62,026

Leases - Schedule of Lease Matu

Leases - Schedule of Lease Maturity (Details) - USD ($) $ in Thousands	Dec. 31, 2021	Dec. 31, 2020
Leases [Abstract]
Operating Leases, 2022	$ 3,712
Operating Leases, 2023	3,652
Operating Leases, 2024	3,454
Operating Leases, 2025	3,519
Operating Leases, 2026	3,584
Operating Leases, Thereafter	9,258
Operating Leases, Total lease payments	27,179
Operating Leases, Imputed interest	(9,134)
Total operating lease liabilities	18,045	$ 20,347
Finance Leases, 2022	33,257
Finance Leases, 2023	13,857
Finance Leases, Total lease payments	47,114
Finance Leases, Imputed interest	(6,893)
Finance Leases	$ 40,221	$ 62,026

Leases - Schedule of Weighted A

Leases - Schedule of Weighted Average Remaining Lease Term and Discount Rate (Details)	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Weighted average remaining lease term:
Operating leases	7 years 4 months 24 days	7 years 9 months 18 days	8 years 4 months 24 days
Finance leases	1 year 4 months 24 days	2 years 4 months 24 days	3 years 4 months 24 days
Weighted average discount rate:
Operating leases	11.90%	12.00%	10.20%
Finance leases	21.90%	21.90%	21.90%

Leases - Supplemental Cash Flow

Leases - Supplemental Cash Flow Information Related to Leases (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Lessee Cash Flow Information [Abstract]
Operating cash outflow from finance leases	$ 11,453	$ 15,748	$ 19,115
Operating cash outflow from operating leases	3,864	$ 2,648	1,812
Right-of-use assets obtained in exchange for new operating lease liabilities	$ 1,020		$ 2,225

Financial Instruments - Schedul

Financial Instruments - Schedule of Carrying Amounts and Estimated Fair Values of Financial Instruments (Details) - USD ($) $ in Thousands	Dec. 31, 2021	Dec. 31, 2020
Debt Instrument [Line Items]
Carrying Amount	$ 962,727	$ 985,512
12.00% Second-Priority Senior Secured Notes
Debt Instrument [Line Items]
Carrying Amount	588,838
Fair Value	685,945
11.00% Second-Priority Senior Secured Notes – due April 2022
Debt Instrument [Line Items]
Carrying Amount		343,579
Fair Value		355,935
7.50% Senior Notes – due May 2022
Debt Instrument [Line Items]
Carrying Amount	6,060	6,060
Fair Value	6,145	5,238
Bank Credit Facility - matures November 2024
Debt Instrument [Line Items]
Carrying Amount	367,829	635,873
Fair Value	$ 375,000	$ 640,000

Financial Instruments - Sched_2

Financial Instruments - Schedule of Carrying Amounts and Estimated Fair Values of Financial Instruments (Parenthetical) (Details)	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020
12.00% Second-Priority Senior Secured Notes
Debt Instrument [Line Items]
Debt instrument interest rate	12.00%
Senior notes, maturity date	Jan. 15, 2026
11.00% Second-Priority Senior Secured Notes – due April 2022
Debt Instrument [Line Items]
Debt instrument interest rate		11.00%
Senior notes, maturity date		Apr. 3, 2022
7.50% Senior Notes – due May 2022
Debt Instrument [Line Items]
Debt instrument interest rate	7.50%	7.50%
Senior notes, maturity date	May 31, 2022	May 31, 2022

Financial Instruments - Additio

Financial Instruments - Additional Information (Details)	12 Months Ended
	Dec. 31, 2021Counterparty
Fair Value Balance Sheet Grouping Financial Statement Captions [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 creditworthiness; (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, 2021 represent derivative instruments from seven counterparties; all of which are registered swap dealers that have an “investment grade” (minimum Standard & Poor’s rating of BBB- or better) credit rating, and all 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.
Price Risk Derivative [Member] | Counterparty Risk Investment Grade [Member]
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items]
Number of counterparties	7

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, 2021	Dec. 31, 2020	Dec. 31, 2019
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Price risk management activities income (expense)	$ (419,077)	$ 87,685	$ (95,337)
Gain Loss on Derivative Instruments Unrealized Component [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Price risk management activities income (expense)	(128,913)	(56,220)	(86,517)
Commodity Contract [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Price risk management activities income (expense)	(419,077)	87,685	(95,337)
Commodity Contract [Member] | Gain Loss on Derivative Instruments Realized Component [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Price risk management activities income (expense)	$ (290,164)	$ 143,905	$ (8,820)

Financial Instruments - Sched_4

Financial Instruments - Schedule of Contracted Volumes and Weighted Average Prices and will Receive Under the Terms of Derivative Contracts (Details) - Swaps	12 Months Ended
	Dec. 31, 2021MMBTU$ / bbl$ / MMBTUbbl
Crude Oil | January 2022 - December 2022
Derivative [Line Items]
Settlement Index	NYMEX WTI CMA
Average Daily Volumes | bbl	23,523
Weighted Average Swap Price | $ / bbl	52.42
Crude Oil | January 2023 - December 2023
Derivative [Line Items]
Settlement Index	NYMEX WTI CMA
Average Daily Volumes | bbl	7,463
Weighted Average Swap Price | $ / bbl	63.13
Natural Gas | January 2022 - December 2022
Derivative [Line Items]
Settlement Index	NYMEX Henry Hub
Weighted Average Swap Price | $ / MMBTU	2.77
Average Daily Volumes | MMBTU	43,392
Natural Gas | January 2023 - December 2023
Derivative [Line Items]
Settlement Index	NYMEX Henry Hub
Weighted Average Swap Price | $ / MMBTU	3.29
Average Daily Volumes | MMBTU	16,408

Financial Instruments - Summary

Financial Instruments - Summary of Additional Information Related to Financial Instruments Measured at Fair Value on Recurring Basis (Details) - Fair Value on Recurring Basis - USD ($) $ in Thousands	Dec. 31, 2021	Dec. 31, 2020
Liabilities:
Total net liability	$ (196,727)	$ (67,814)
Oil And Natural Gas Swaps
Assets:
Derivative Asset	3,737
Liabilities:
Derivative Liability	(200,464)
Oil And Natural Gas Swaps And Costless Collars
Assets:
Derivative Asset		7,821
Liabilities:
Derivative Liability		75,635
Level 1
Liabilities:
Total net liability	0	0
Level 1 | Oil And Natural Gas Swaps
Assets:
Derivative Asset	0
Liabilities:
Derivative Liability	0
Level 1 | Oil And Natural Gas Swaps And Costless Collars
Assets:
Derivative Asset		0
Liabilities:
Derivative Liability		0
Level 2
Liabilities:
Total net liability	(196,727)	(67,814)
Level 2 | Oil And Natural Gas Swaps
Assets:
Derivative Asset	3,737
Liabilities:
Derivative Liability	(200,464)
Level 2 | Oil And Natural Gas Swaps And Costless Collars
Assets:
Derivative Asset		7,821
Liabilities:
Derivative Liability		75,635
Level 3
Liabilities:
Total net liability	0	0
Level 3 | Oil And Natural Gas Swaps
Assets:
Derivative Asset	0
Liabilities:
Derivative Liability	$ 0
Level 3 | Oil And Natural Gas Swaps And Costless Collars
Assets:
Derivative Asset
Liabilities:
Derivative Liability		$ 0

Financial Instruments - Sched_5

Financial Instruments - Schedule of Fair Value of Derivative Financial Instruments (Details) - USD ($) $ in Thousands	Dec. 31, 2021	Dec. 31, 2020
Price Risk Derivatives [Line Items]
Assets from price risk management activities	$ 967	$ 6,876
Assets from price risk management activities	2,770	945
Liabilities from price risk management activities	186,526	66,010
Liabilities from price risk management activities	13,938	9,625
Oil and Natural Gas Derivatives
Price Risk Derivatives [Line Items]
Assets from price risk management activities	967	6,876
Assets from price risk management activities	2,770	945
Total gross amounts presented on balance sheet, Assets	3,737	7,821
Gross amounts not offset on the balance sheet	3,737	4,877
Net Amounts	0	2,944
Liabilities from price risk management activities	186,526	66,010
Liabilities from price risk management activities	13,938	9,625
Total gross amounts presented on balance sheet, Liabilities	200,464	75,635
Gross amounts not offset on the balance sheet	3,737	4,877
Net Amounts	$ 196,727	$ 70,758

Debt - Summary of Detail Compri

Debt - Summary of Detail Comprising Debt and Related Book Values (Details) - USD ($) $ in Thousands	Dec. 31, 2021	Dec. 31, 2020
Debt Instrument [Line Items]
Total debt, before discount and deferred financing cost	$ 1,031,060	$ 993,314
Discount and deferred financing cost	(68,333)	(7,802)
Total debt, net of discount and deferred financing costs	962,727	985,512
Less: current portion of long-term debt	6,060	0
Long-term debt, net of discount and deferred financing costs	956,667	985,512
11.00% Second-Priority Senior Secured Notes – due April 2022
Debt Instrument [Line Items]
Total debt, net of discount and deferred financing costs		343,579
7.50% Senior Notes – due May 2022
Debt Instrument [Line Items]
Total debt, net of discount and deferred financing costs	6,060	6,060
Senior Notes | 12.00% Second-Priority Senior Secured Notes - due January 2026
Debt Instrument [Line Items]
Total debt, before discount and deferred financing cost	650,000
Senior Notes | 11.00% Second-Priority Senior Secured Notes – due April 2022
Debt Instrument [Line Items]
Total debt, before discount and deferred financing cost	0	347,254
Senior Notes | 7.50% Senior Notes – due May 2022
Debt Instrument [Line Items]
Total debt, before discount and deferred financing cost	6,060	6,060
Bank Credit Facility | Bank Credit Facility Matures November Two Thousand Twenty Four [Member]
Debt Instrument [Line Items]
Total debt, before discount and deferred financing cost	$ 375,000	$ 640,000

Debt - Summary of Detail Comp_2

Debt - Summary of Detail Comprising Debt and Related Book Values (Parenthetical) (Details)	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Jan. 14, 2021
11.00% Second-Priority Senior Secured Notes – due April 2022
Debt Instrument [Line Items]
Debt instrument interest rate		11.00%
Senior notes, maturity date		Apr. 3, 2022
7.50% Senior Notes – due May 2022
Debt Instrument [Line Items]
Debt instrument interest rate	7.50%	7.50%
Senior notes, maturity date	May 31, 2022	May 31, 2022
Bank Credit Facility - matures November 2024
Debt Instrument [Line Items]
Bank credit facility, maturity date	Nov. 12, 2024
Senior Notes | 12.00% Second-Priority Senior Secured Notes - due January 2026
Debt Instrument [Line Items]
Debt instrument interest rate	12.00%		12.00%
Senior notes, maturity date	Jan. 15, 2026
Senior Notes | 11.00% Second-Priority Senior Secured Notes – due April 2022
Debt Instrument [Line Items]
Debt instrument interest rate		11.00%
Senior notes, maturity date	Apr. 3, 2022	Apr. 3, 2022
Senior Notes | 7.50% Senior Notes – due May 2022
Debt Instrument [Line Items]
Debt instrument interest rate	7.50%	7.50%
Senior notes, maturity date	May 31, 2022	May 31, 2022
Bank Credit Facility | Bank Credit Facility - matures November 2024
Debt Instrument [Line Items]
Bank credit facility, maturity date	Nov. 12, 2024	Nov. 12, 2024

Debt - Additional information (

Debt - Additional information (Details) - USD ($) $ in Thousands, shares in Millions	Jan. 15, 2023	Jan. 13, 2021	Jun. 15, 2020	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019	Dec. 21, 2021	Sep. 30, 2021	Aug. 02, 2021	Jun. 30, 2021	Jan. 14, 2021
Debt Instrument [Line Items]
Gain (loss) on extinguishment of debt				$ (13,225)	$ 1,662	$ 0
Credit facility, maximum borrowing capacity				950,000
Debt Instruments				1,031,060	993,314
Debt instrument, repurchase amount				356,803	$ 5,364	$ 10,567
Carbon Capture And Sequestration[ Member]
Debt Instrument [Line Items]
Provision to facilitate investments				$ 50,000
11.00% Second-Priority Senior Secured Notes - due April 2022
Debt Instrument [Line Items]
Debt instrument, redemption price, percentage		102.75%
Debt instrument, interest rate, stated percentage			11.00%
Debt instrument, repurchase amount			$ 37,200
7.50% Senior Notes – due May 2022
Debt Instrument [Line Items]
Debt instrument maturity date				May 31, 2022	May 31, 2022
Debt instrument frequency of periodic payment				semi-annually
Debt instrument payment terms				semi-annually each May 31 and November 30
Debt instrument, interest rate, stated percentage				7.50%	7.50%
Debt instrument redemption, description				The 7.50% Notes mature May 31, 2022 and have interest payable semi-annually each May 31 and November 30. The Company may redeem all or a portion of the 7.50% Notes at redemption prices (expressed as percentages of the principal amount) equal to: (i) 105.625% for the twelve-month period beginning on May 31, 2021 and (ii) 100% beginning May 31, 2022, in each case, plus accrued and unpaid interest at the redemption date.
Debt instrument, face amount				$ 6,100
Bank Credit Facility - matures November 2024
Debt Instrument [Line Items]
Credit facility, maximum borrowing capacity				$ 950,000				$ 960,000
Bank credit facility, description				The borrowing base is redetermined by the lenders at least semi-annually during the second quarter and fourth quarter each year. On June 22, 2021, the Company entered into a Borrowing Base Redetermination Agreement and Sixth Amendment to Credit Agreement (the “Sixth Amendment”). The Sixth Amendment, among other things, (i) extended the maturity date of the Bank Credit Facility from May 10, 2022 to November 12, 2024
Line of Credit Facility, Commitments				$ 791,300					$ 730,000	$ 655,000
Weighted average interest rate				3.50%
Bank Credit Facility - matures November 2024 | Letter of Credit
Debt Instrument [Line Items]
Line of Credit Facility, Commitments				$ 150,000
Bank Credit Facility - matures November 2024 | London Interbank Offered Rate
Debt Instrument [Line Items]
Debt Instrument, Basis Spread on Variable Rate				1.00%
Bank Credit Facility - matures November 2024 | Base Rate Federal Funds [Member]
Debt Instrument [Line Items]
Debt Instrument, Basis Spread on Variable Rate				0.50%
Bank Credit Facility - matures November 2024 | Minimum
Debt Instrument [Line Items]
Debt covenant to EBITDAX				3.00%
Debt covenant current ratio				1.00%
Line of Credit Facility, Commitments							$ 730,000
Bank Credit Facility - matures November 2024 | Minimum | London Interbank Offered Rate
Debt Instrument [Line Items]
Debt Instrument, Basis Spread on Variable Rate				1.00%
Bank Credit Facility - matures November 2024 | Maximum
Debt Instrument [Line Items]
Line of Credit Facility, Commitments							$ 791,300
Bank Credit Facility - matures November 2024 | Maximum | Letter of Credit
Debt Instrument [Line Items]
Line of Credit Facility, Commitments				$ 200,000
Senior Notes | 11.00% Second-Priority Senior Secured Notes - due April 2022
Debt Instrument [Line Items]
Debt instrument, interest rate, stated percentage		11.00%		11.00%	11.00%
Debt instrument, shares issued in conversion for repurchased and retired notes			3.1
Debt Instruments		$ 347,300
Debt instrument, repurchase amount					$ 6,400
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)	$ 1,700
Senior Notes | 7.50% Senior Notes – due May 2022
Debt Instrument [Line Items]
Debt instrument maturity date				May 31, 2022	May 31, 2022
Debt instrument, interest rate, stated percentage				7.50%	7.50%
Debt Instruments				$ 6,060	$ 6,060
Senior Notes | 12.00% Second-Priority Senior Secured Notes - due January 2026
Debt Instrument [Line Items]
Debt instrument maturity date				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				12.00%							12.00%
Debt instrument redemption, description				At any time prior to January 15, 2023, the Company may redeem up to 40% of the principal amount of the 12.00% Notes at a redemption rate of 112.00% of the principal amount plus accrued and unpaid interest. At any time prior to January 15, 2023, the Company may also redeem some or all of the 12.00% Notes at a price equal to 100% of the principal amount of the 12.00% Notes, plus a “make-whole premium,” together with accrued and unpaid interest, if any, to, but excluding, the date of redemption. Thereafter, the Company may redeem all or a portion of the 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 Instruments				$ 650,000
Senior Notes | 12.00% Second-Priority Senior Secured Notes - due January 2026 | Forecast
Debt Instrument [Line Items]
Maximum percentage of principal amount option to redeem	40.00%
Line of Credit [Member]
Debt Instrument [Line Items]
Line of Credit Facility, Borrowing Capacity, Description				The Bank Credit Facility provides for 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 November 2024
Debt Instrument [Line Items]
Debt Instruments				$ 375,000	$ 640,000
Debt Instrument, Redemption, Period One | 7.50% Senior Notes – due May 2022
Debt Instrument [Line Items]
Debt instrument, redemption price, percentage				105.625%
Debt Instrument, Redemption, Period One | Senior Notes | 12.00% Second-Priority Senior Secured Notes - due January 2026
Debt Instrument [Line Items]
Debt instrument, redemption price, percentage	112.00%
Debt Instrument, Redemption, Period Two | Senior Notes | 7.50% Senior Notes – due May 2022
Debt Instrument [Line Items]
Debt instrument, redemption price, percentage				100.00%
Debt Instrument, Redemption, Period Two | Senior Notes | 12.00% Second-Priority Senior Secured Notes - due January 2026
Debt Instrument [Line Items]
Debt instrument, redemption price, percentage				100.00%

Debt - Summary of Redemption Pr

Debt - Summary of Redemption Prices of 12.% Notes (Details) - 12.00% Second-Priority Senior Secured Notes - due January 2026	12 Months Ended
	Dec. 31, 2021
Debt Instrument, Redemption, Period Three
Debt Instrument, Redemption [Line Items]
Debt instrument, redemption price, percentage	106.00%
Debt Instrument, Redemption, Period Four
Debt Instrument, Redemption [Line Items]
Debt instrument, redemption price, percentage	103.00%
Debt Instrument, Redemption, Period Five
Debt Instrument, Redemption [Line Items]
Debt instrument, redemption price, percentage	100.00%

Debt - Schedule of Pricing Grid

Debt - Schedule of Pricing Grid for Borrowing Base Utilization Percentage (Details)	12 Months Ended
	Dec. 31, 2021
Level 1
Debt Instrument [Line Items]
Commitment fee percentage	0.50%
Level 1 | London Interbank Offered Rate
Debt Instrument [Line Items]
Basis Spread on Variable Rate	3.00%
Level 1 | Alternate Base Rate
Debt Instrument [Line Items]
Basis Spread on Variable Rate	2.00%
Level 2
Debt Instrument [Line Items]
Commitment fee percentage	0.50%
Level 2 | London Interbank Offered Rate
Debt Instrument [Line Items]
Basis Spread on Variable Rate	3.25%
Level 2 | Alternate Base Rate
Debt Instrument [Line Items]
Basis Spread on Variable Rate	2.25%
Level 3
Debt Instrument [Line Items]
Commitment fee percentage	0.50%
Level 3 | London Interbank Offered Rate
Debt Instrument [Line Items]
Basis Spread on Variable Rate	3.50%
Level 3 | Alternate Base Rate
Debt Instrument [Line Items]
Basis Spread on Variable Rate	2.50%
Level 4
Debt Instrument [Line Items]
Commitment fee percentage	0.50%
Level 4 | London Interbank Offered Rate
Debt Instrument [Line Items]
Basis Spread on Variable Rate	3.75%
Level 4 | Alternate Base Rate
Debt Instrument [Line Items]
Basis Spread on Variable Rate	2.75%
Level 5
Debt Instrument [Line Items]
Commitment fee percentage	0.50%
Level 5 | London Interbank Offered Rate
Debt Instrument [Line Items]
Basis Spread on Variable Rate	4.00%
Level 5 | Alternate Base Rate
Debt Instrument [Line Items]
Basis Spread on Variable Rate	3.00%
Maximum [Member] | Level 1
Debt Instrument [Line Items]
Utilization	25.00%
Maximum [Member] | Level 2
Debt Instrument [Line Items]
Utilization	50.00%
Maximum [Member] | Level 3
Debt Instrument [Line Items]
Utilization	75.00%
Maximum [Member] | Level 4
Debt Instrument [Line Items]
Utilization	90.00%
Minimum [Member] | Level 2
Debt Instrument [Line Items]
Utilization	25.00%
Minimum [Member] | Level 3
Debt Instrument [Line Items]
Utilization	50.00%
Minimum [Member] | Level 4
Debt Instrument [Line Items]
Utilization	75.00%
Minimum [Member] | Level 5
Debt Instrument [Line Items]
Utilization	90.00%

Employee Benefits Plans and S_3

Employee Benefits Plans and Share-Based Compensation - Additional information (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2021	May 11, 2021	Mar. 08, 2021	Mar. 05, 2020	May 16, 2019	Mar. 05, 2019
Minimum
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Number of shares of common stock issuable upon vesting, percentage range of target number of PSUs granted	0.00%
Maximum
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Number of shares of common stock issuable upon vesting, percentage range of target number of PSUs granted	200.00%
Performance Share Units
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Share based compensation grants, vesting period	3 years
Contingent Right Upon Vesting to Receive Common Stock	1
Share-based compensation expense recognized period	1 year 9 months 18 days
Share-based compensation expense unrecognized	$ 8,800
Share-based compensation expense unrecognized		$ 9,715	$ 11,129	$ 5,763	$ 1,210	$ 6,195
Description of method used to calculate fair value	Monte Carlo simulations
Performance Share Units | Minimum
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Number of shares of common stock issuable upon vesting, percentage range of target number of PSUs granted	0.00%
Performance Share Units | Maximum
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Number of shares of common stock issuable upon vesting, percentage range of target number of PSUs granted	200.00%
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 | Employees | Restricted Stock Units
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Share based compensation grants, vesting period	3 years
Contingent Right Upon Vesting to Receive Common Stock	1
Share-based compensation expense recognized period	1 year 9 months 18 days
Share-based compensation expense unrecognized	$ 14,200
Long Term Incentive Plan | Non-employee Directors | Restricted Stock Units
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Share based compensation grants, vesting period	1 year
Share-based compensation expense recognized period	2 months 12 days
Contingent Right Upon Vesting to Receive Common Stock Percentage	60.00%
Contingent Right Upon Vesting to Receive Cash Percentage	40.00%
Share-based compensation expense liabilities	$ 100
Share-based compensation expense unrecognized	$ 100

Employee Benefits Plans and S_4

Employee Benefits Plans and Share-Based Compensation - Schedule of Restricted Stock and Performance Share Units Activity (Details) - $ / shares	12 Months Ended
	Dec. 31, 2021		Dec. 31, 2020	Dec. 31, 2019
Restricted Stock Units
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Unvested beginning of the period	1,652,988		733,777	138,704
Granted	1,102,038		1,284,797	732,771
Vested	(669,832)		(273,787)	(69,235)
Forfeited	(101,995)		(91,799)	(68,463)
Unvested end of the period	1,983,199	[1]	1,652,988	733,777
Unvested weighted average grant date fair value, beginning of the period	$ 13.73		$ 25.20	$ 33.85
Unvested weighted average grant date fair value, granted	13.11		10.02	24.39
Unvested weighted average grant date fair value, vested	15.01		25.09	33.72
Unvested weighted average grant date fair value, forfeited	12.46		19.65	25.43
Unvested weighted average grant date fair value, end of the period	$ 13.02	[1]	$ 13.73	$ 25.20
Performance Share Units
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Unvested beginning of the period	834,172		417,831	231,542
Granted	586,995		441,642	218,060
Vested	(391,308)
Forfeited	(14,400)		(25,301)	(31,771)
Unvested end of the period	1,015,459		834,172	417,831
Unvested weighted average grant date fair value, beginning of the period	$ 25.46		$ 39.31	$ 44.47
Unvested weighted average grant date fair value, granted	18.96		13.05	33.96
Unvested weighted average grant date fair value, vested	39.43
Unvested weighted average grant date fair value, forfeited	18.48		37.67	40.27
Unvested weighted average grant date fair value, end of the period	$ 16.41		$ 25.46	$ 39.31
[1]	As of December 31, 2021 , 25,592 of the unvested RSUs were accounted for as liability awards in “Accrued liabilities” on the Consolidated Balance Sheet.

Employee Benefits Plans and S_5

Employee Benefits Plans and Share-Based Compensation - Schedule of Restricted Stock and Performance Share Units Activity (Parenthetical) (Details) - Restricted Stock Units - shares	12 Months Ended
	Dec. 31, 2021		Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Granted	1,102,038		1,284,797	732,771
Unvested RSUs	1,983,199	[1]	1,652,988	733,777	138,704
Accrued Liabilities
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unvested RSUs	25,592
[1]	As of December 31, 2021 , 25,592 of the unvested RSUs were accounted for as liability awards in “Accrued liabilities” on the Consolidated Balance Sheet.

Employee Benefits Plans and S_6

Employee Benefits Plans and Share-Based Compensation - Summary of Assumptions Used to Calculate the Grant Date Fair Value (Details) - Performance Share Units - USD ($) $ in Thousands	May 11, 2021	Mar. 08, 2021	Mar. 05, 2020	May 16, 2019	Mar. 05, 2019
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Expected term (in years)	2 years 7 months 6 days	2 years 9 months 18 days	2 years 9 months 18 days	2 years 7 months 6 days	2 years 9 months 18 days
Expected volatility	80.90%	78.30%	48.80%	44.80%	46.90%
Risk-free interest rate	0.30%	0.30%	0.60%	2.10%	2.50%
Dividend yield	0.00%	0.00%	0.00%	0.00%	0.00%
Fair value (in thousands)	$ 9,715	$ 11,129	$ 5,763	$ 1,210	$ 6,195

Employee Benefits Plans and S_7

Employee Benefits Plans and Share-Based Compensation - Schedule of Recognized Share Based Compensation Expense, Net (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Employee Service Share Based Compensation Allocation Of Recognized Period Costs [Line Items]
Total share-based compensation expense	$ 20,560	$ 16,462	$ 12,924
Less: amounts capitalized to oil and gas properties	9,568	7,793	5,960
Total share-based compensation expense, net	$ 10,992	$ 8,669	$ 6,964

Income Taxes - Components of In

Income Taxes - Components of Income Tax Expense (Benefit) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Current income tax expense (benefit)
United States	$ (5)	$ (499)	$ 437
Mexico	(993)	185	1,183
Total current income tax expense (benefit)	(998)	(314)	1,620
Deferred income tax expense (benefit)
United States	(1,067)	35,923	(37,131)
Mexico	430	(26)	(630)
Total deferred income tax expense (benefit)	(637)	35,897	(37,761)
Total income tax expense (benefit)	$ (1,635)	$ 35,583	$ (36,141)

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, 2021	Dec. 31, 2020	Dec. 31, 2019
Income Tax Disclosure [Abstract]
Income tax expense (benefit) at the federal statutory tax rate	$ (38,763)	$ (90,304)	$ 4,744
State income taxes	(674)	(14,215)	1,396
Impact of foreign operations	(11,920)	(1,030)	(4,948)
Effect of change in state rate	2,008
Prior year taxes	486	(4,237)	(1,950)
Other adjustments	0		137
Legal entity reorganization	0	(17,566)	39,336
Change in valuation allowance	45,547	162,213	(75,196)
Other permanent differences	1,681	722	340
Total income tax expense (benefit)	$ (1,635)	$ 35,583	$ (36,141)
Effective tax rate	0.89%	(8.27%)	(159.99%)

Income Taxes - Additional Infor

Income Taxes - Additional Information (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Income Tax Disclosure [Line Items]
Federal statutory rate	21.00%	21.00%	21.00%
Deferred tax assets, valuation allowance	$ 224,266	$ 178,998
Income tax benefit (expense)	$ 1,635	(35,583)	$ 36,141
Operating loss carryforwards limitation on use	As of December 31, 2021, the Company had U.S. federal net operating loss carryforwards (“NOLs”) of approximately $732.6 million, of which $546.5 million is 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 in 2035.
Valuation allowance	$ 224,300	179,000
Write-down of oil and natural gas properties	$ 18,123	267,916	12,221
Earliest Tax Year
Income Tax Disclosure [Line Items]
Income tax examination, Year	2018
Latest Tax Year
Income Tax Disclosure [Line Items]
Income tax examination, Year	2020
Federal and State
Income Tax Disclosure [Line Items]
Deferred tax assets, valuation allowance expense (benefit)		162,200	(80,200)
Federal
Income Tax Disclosure [Line Items]
Deferred tax assets, valuation allowance expense (benefit)			(75,200)
Operating loss carryforwards	$ 732,600
Foreign
Income Tax Disclosure [Line Items]
Deferred tax assets, valuation allowance expense (benefit)			5,000
Operating loss carryforwards	166,440
Internal Revenue Code
Income Tax Disclosure [Line Items]
Income tax benefit (expense)	17,600
Internal Revenue Code | Federal
Income Tax Disclosure [Line Items]
Income tax benefit (expense)		$ 17,600
Internal Revenue Code | Federal | Capital loss carryforward
Income Tax Disclosure [Line Items]
Operating loss carryforwards	$ 546,500
Operating loss carryforwards expiration year	2035
Subsidiaries
Income Tax Disclosure [Line Items]
Income tax benefit (expense)			(39,300)
Tax expense represents the non-cash impact from the legal entity conversion			$ 38,900

Income Taxes - Summary of Signi

Income Taxes - Summary of Significant Components of Deferred Tax Assets and Liabilities (Details) - USD ($) $ in Thousands	Dec. 31, 2021	Dec. 31, 2020
Deferred tax assets:
Federal net operating loss	$ 153,849	$ 133,804
Foreign tax loss carryforward	49,932	45,980
State net operating loss	24,265	25,740
Asset retirement obligations	92,823	106,604
Tax credits	303	522
Derivatives	42,075	16,346
Other well equipment inventory	5,680	9,470
Accrued bonus	5,087	3,069
Operating lease liabilities	4,081	4,904
Other	9,257	7,727
Total deferred tax assets	387,352	354,166
Valuation allowance	(224,266)	(178,998)
Total deferred tax assets, net	163,086	175,168
Deferred tax liabilities:
Oil and gas properties	160,002	170,596
Deferred financing	0	1,765
Operating lease assets	1,423	1,652
Prepaid	3,075	3,216
Total deferred tax liabilities	164,500	177,229
Net deferred tax (liability)	$ (1,414)	$ (2,061)

Income Taxes - Summary of Net O

Income Taxes - Summary of Net Operating Loss Carryovers (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2021USD ($)
Federal
Operating Loss Carryforwards [Line Items]
Net operating losses carryforward, Amount	$ 732,600
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	$ 534,964
Federal | Unlimited Expiration Year
Operating Loss Carryforwards [Line Items]
Net operating losses carryforward, Amount	$ 197,651
Net operating losses, Expiration term	Unlimited
Foreign
Operating Loss Carryforwards [Line Items]
Net operating losses carryforward, Amount	$ 166,440
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	2031
State
Operating Loss Carryforwards [Line Items]
Net operating losses carryforward, Amount	$ 125,958
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	$ 268,221
Net operating losses, Expiration term	Unlimited

Income Taxes - Summary of Balan

Income Taxes - Summary of Balances In Uncertain Tax Positions (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020
Income Tax Uncertainties [Abstract]
Total unrecognized tax benefits, beginning balance	$ 648	$ 791
Tax positions taken decrease during a prior period	(21)	(208)
Tax positions taken during the current period	27	65
Total unrecognized tax benefits, ending balance	$ 696	$ 648

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, $ in Thousands	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Earnings Per Share [Abstract]
Net income (loss)	$ (182,952)	$ (465,605)	$ 58,729
Weighted average common shares outstanding — basic	81,769	67,664	54,185
Dilutive effect of securities			228
Weighted average common shares outstanding — diluted	81,769	67,664	54,413
Basic	$ (2.24)	$ (6.88)	$ 1.08
Diluted	$ (2.24)	$ (6.88)	$ 1.08
Anti-dilutive potentially issuable securities excluded from diluted common shares	1,709	5,019	4,220

Related Party Transactions - Ad

Related Party Transactions - Additional Information (Details) $ in Thousands	Mar. 30, 2020shares	Feb. 28, 2020shares	May 10, 2018OfferingRegistration	Aug. 31, 2018	Dec. 31, 2021USD ($)	Dec. 31, 2020USD ($)	Dec. 31, 2019USD ($)
Related Party Transaction [Line Items]
General and administrative expense					$ 78,677	$ 79,175	$ 77,209
Secondary Offering Expenses
Related Party Transaction [Line Items]
General and administrative expense					700	200	700
ILX and Castex | Series A Convertible Preferred Stock
Related Party Transaction [Line Items]
Share issued on merger | shares	110,000	110,000
Shares issued upon conversion | shares	11,000,000
Apollo Funds | Whistler Energy II, LLC | Whistler Energy II Holdco, LLC
Related Party Transaction [Line Items]
Due from Related Parties, Current						1,100
Business acquisition, date of acquisition agreement				Aug. 31, 2018
Vinson & Elkins L.L.P.
Related Party Transaction [Line Items]
Legal fees payable					200	700	2,300
General and administrative expense					$ 3,100	$ 3,500	$ 4,200
Registration Rights Agreement | Riverstone Funds, Apollo Funds, Mac Kay Shields LLC and Franklin Advisers Inc
Related Party Transaction [Line Items]
Number of days required to file shelf registration statement			30 days
Number of demand registrations allowed in any twelve-month period | Registration			2
Number of underwritten offerings to demand in any twelve-month period | Offering			3
Number of underwritten offerings to demand | Offering			1
Percentage of registrable securities owned, underwritten offerings			5.00%
Registration agreement, termination description							The Registration Rights Agreement have terminated with respect to Franklin and MacKay Shields. Additionally, the Apollo Funds no longer have piggyback rights effective January 3, 2022. The Registration Rights Agreement will otherwise terminate at such time as there are no Registrable Securities outstanding.
Principal owner member
Related Party Transaction [Line Items]
Percentage of common stock held by sponsors					36.40%
Other Operating Income (Expense) [Member] | Apollo Funds | Whistler Energy II, LLC | Whistler Energy II Holdco, LLC
Related Party Transaction [Line Items]
Gain (Loss) related to decommissioning obligation settlement					$ 4,400

Commitments and Contingencies -

Commitments and Contingencies - Additional Information (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2021USD ($)
Loss Contingencies [Line Items]
Performance obligations	$ 32,863
Surety Bond
Loss Contingencies [Line Items]
Surety performance bonds outstanding	724,400
Other Operating Income (Expense) [Member]
Loss Contingencies [Line Items]
Decommissioning Obligations	21,100
Bank Credit Facility | Letter of Credit
Loss Contingencies [Line Items]
Letters of credit outstanding amount	$ 13,600

Commitments and Contingencies_2

Commitments and Contingencies - Summary of Total Minimum Commitments Associated With Long-Term Non-cancelable Operating Lease (Details) $ in Thousands	Dec. 31, 2021USD ($)
Contractual Obligation [Line Items]
2022	$ 32,863
2023	0
2024	0
2025	0
Thereafter	0
Total	32,863
Vessel Commitments
Contractual Obligation [Line Items]
2022	29,710	[1]
2023	0	[1]
2024	0	[1]
2025	0	[1]
Thereafter	0	[1]
Total	29,710	[1]
Committed Purchase Orders
Contractual Obligation [Line Items]
2022	3,153	[2]
2023	0	[2]
2024	0	[2]
2025	0	[2]
Thereafter	0	[2]
Total	$ 3,153	[2]
[1]	Includes vessel commitments the Company will utilize for certain Deepwater well intervention 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.

Supplemental Oil and Gas Disc_3

Supplemental Oil and Gas Disclosures - Schedule of Capitalized Costs Related to Oil, Natural Gas and NGL Activities and Related Accumulated Depletion and Amortization (Details) $ in Thousands	Dec. 31, 2021USD ($)$ / Boe	Dec. 31, 2020USD ($)$ / Boe
Extractive Industries [Abstract]
Proved properties	$ 5,232,479	$ 4,945,550
Unproved oil and gas properties, not subject to amortization	219,055	254,994
Total oil and gas properties	5,451,534	5,200,544
Less: Accumulated depletion	(3,072,907)	(2,680,254)
Net capitalized costs	$ 2,378,627	$ 2,520,290
Depletion and amortization rate (Per Boe) | $ / Boe	16.71	31.42

Supplemental Oil and Gas Disc_4

Supplemental Oil and Gas Disclosures - 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, 2021	Dec. 31, 2020
Capitalized Costs Relating To Oil And Gas Producing Activities By Geographic Area [Line Items]
Unproved properties, not subject to amortization	$ 219,055	$ 254,994
Mexico
Capitalized Costs Relating To Oil And Gas Producing Activities By Geographic Area [Line Items]
Unproved properties, not subject to amortization	$ 110,300	$ 121,700

Supplemental Oil and Gas Disc_5

Supplemental Oil and Gas Disclosures - Additional Information (Details) - MMBoe	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Reserve Quantities [Line Items]
Percentage of proved oil, natural gas and NGL reserves attributable to all of oil and natural gas properties	100.00%	100.00%	100.00%
Proved Developed and Undeveloped Reserve, Net (Energy), Period Increase (Decrease)	1.4	21.3	10
Decrease of production	23.5	20	19
Revision to previous estimates	(20.3)	(24.2)	(9.7)
Estimated proved reserves from extensions and discoveries	1.8	4.7	15.7
Purchases of estimated proved reserves		60.7
Prescribed rate of discounted future net cash flows	10.00%
Gunflint Acquisition
Reserve Quantities [Line Items]
Purchases of estimated proved reserves			3

Supplemental Oil and Gas Disc_6

Supplemental Oil and Gas Disclosures - 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, 2021	Dec. 31, 2020	Dec. 31, 2019
Property acquisition costs:
Proved properties	$ 210	$ 422,833	$ 27,660
Unproved properties, not subject to amortization	0	95,242	16,062
Total property acquisition costs	210	518,075	43,722
Exploration costs	23,844	59,422	209,161
Development costs	245,058	362,011	292,547
Total costs incurred	$ 269,112	$ 939,508	$ 545,430

Supplemental Oil and Gas Disc_7

Supplemental Oil and Gas Disclosures - Schedule of Costs Incurred in Oil, Natural Gas and NGL Property Acquisition, Exploration and Development Activities (Parenthetical) (Details) - USD ($)	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Costs Incurred Oil And Gas Property Acquisition Exploration And Development Activities [Line Items]
Exploration costs	$ 23,844,000	$ 59,422,000	$ 209,161,000
Mexico
Costs Incurred Oil And Gas Property Acquisition Exploration And Development Activities [Line Items]
Exploration costs	$ 6,600	$ 14,600,000	$ 74,200,000

Supplemental Oil and Gas Disc_8

Supplemental Oil and Gas Disclosures - Schedule of Estimated Proved Reserves at Net Ownership Interest (Details)	12 Months Ended
	Dec. 31, 2021MMBoeMBoeMMBblsMMcf	Dec. 31, 2020MBoeMMBoeMMcfMMBbls		Dec. 31, 2019MBoeMMBoeMMBblsMMcf
Reserve Quantities [Line Items]
Revision of previous estimates | MMBoe	20.3	24.2		9.7
Production | MMBoe	(23.5)	(20)		(19)
Purchases of reserves | MMBoe		60.7
Extensions and discoveries | MMBoe	1.8	4.7		15.7
Oil (MBbls)
Reserve Quantities [Line Items]
Total proved reserves, beginning balance	109,307	106,754		112,539
Revision of previous estimates	13,619	(14,633)		(5,553)
Production	(16,159)	(13,665)	[1]	(13,844)
Purchases of reserves		26,903		2,094
Extensions and discoveries	997	3,948		11,518
Total proved reserves, ending balance	107,764	109,307		106,754
Total proved developed reserves	93,420	85,007		72,016
Total proved undeveloped reserves	14,344	24,300		34,738
Gas (MMcf)
Reserve Quantities [Line Items]
Total proved reserves, beginning balance | MMcf	257,208	155,998		171,024
Revision of previous estimates | MMcf	8,979	(56,358)		(15,898)
Production | MMcf	(32,795)	(28,652)	[1]	(23,306)
Purchases of reserves | MMcf		181,872		2,626
Extensions and discoveries | MMcf	2,961	4,348		21,552
Total proved reserves, ending balance | MMcf	236,353	257,208		155,998
Total proved developed reserves | MMcf	186,442	204,054		115,381
Total proved undeveloped reserves | MMcf	49,911	53,154		40,617
NGL (MBbls)
Reserve Quantities [Line Items]
Total proved reserves, beginning balance	10,858	8,981		10,696
Revision of previous estimates	5,137	(168)		(1,237)
Production	(1,875)	(1,559)	[1]	(1,228)
Purchases of reserves		3,528		130
Extensions and discoveries	315	76		620
Total proved reserves, ending balance	14,435	10,858		8,981
Total proved developed reserves	11,792	8,104		6,733
Total proved undeveloped reserves	2,643	2,754		2,248
Oil Equivalent (MBoe)
Reserve Quantities [Line Items]
Total proved reserves, beginning balance | MBoe	163,033	141,735		151,739
Revision of previous estimates | MBoe	20,252	(24,195)		(9,440)
Production | MBoe	(23,500)	(19,999)	[1]	(18,956)
Purchases of reserves | MBoe		60,743		2,662
Extensions and discoveries | MBoe	1,806	4,749		15,730
Total proved reserves, ending balance | MBoe	161,591	163,033		141,735
Total proved developed reserves | MMBoe	136,286	127,120		97,979
Total proved undeveloped reserves | MMBoe	25,305	35,913		43,756
[1]	Excludes approximately 3.0 MBoe of Mexico well test production

Supplemental Oil and Gas Disc_9

Supplemental Oil and Gas Disclosures - Schedule of Estimated Proved Reserves at Net Ownership Interest (Parenthetical) (Details)	12 Months Ended
	Dec. 31, 2021MMBoe	Dec. 31, 2020MMBoeMBoe	Dec. 31, 2019MMBoe
Reserve Quantities [Line Items]
Excludes well test production | MMBoe	23.5	20	19
Mexico
Reserve Quantities [Line Items]
Excludes well test production | MBoe		3

Supplemental Oil and Gas Dis_10

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, 2021	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Extractive Industries [Abstract]
Future cash inflows	$ 8,496,005	$ 4,927,497	$ 7,151,875
Future costs:
Production	(1,868,818)	(1,105,211)	(1,633,432)
Development and abandonment	(1,422,507)	(1,236,874)	(1,464,270)
Future net cash flows before income taxes	5,204,680	2,585,412	4,054,173
Future income tax expense	(676,778)	(141,515)	(662,317)
Future net cash flows after income taxes	4,527,902	2,443,897	3,391,856
Discount at 10% annual rate	(1,087,291)	(538,963)	(854,261)
Standardized measure of discounted future net cash flows	$ 3,440,611	$ 1,904,934	$ 2,537,595	$ 3,340,246

Supplemental Oil and Gas Dis_11

Supplemental Oil and Gas Disclosures (Unaudited) - Schedule of Base Prices Used in Determining Standardized Measure (Details)	12 Months Ended
	Dec. 31, 2021$ / bbl$ / Mcf	Dec. 31, 2020$ / bbl$ / Mcf	Dec. 31, 2019$ / bbl$ / Mcf
Oil
Discounted Future Net Cash Flows Relating To Proved Oil And Gas Reserves [Line Items]
SEC pricing	67.14	39.47	61.01
Natural Gas
Discounted Future Net Cash Flows Relating To Proved Oil And Gas Reserves [Line Items]
SEC pricing | $ / Mcf	3.71	1.97	2.59
NGL
Discounted Future Net Cash Flows Relating To Proved Oil And Gas Reserves [Line Items]
SEC pricing	26.62	9.89	26.17

Supplemental Oil and Gas Dis_12

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, 2021	Dec. 31, 2020	Dec. 31, 2019
Extractive Industries [Abstract]
Standardized measure, beginning of year	$ 1,904,934	$ 2,537,595	$ 3,340,246
Sales and transfers of oil, net gas and NGLs produced during the period	(957,576)	(339,557)	(665,226)
Net change in prices and production costs	2,049,980	(1,468,304)	(849,696)
Changes in estimated future development costs	(57,876)	32,589	(75,564)
Previously estimated development costs incurred	69,125	46,143	117,049
Accretion of discount	199,849	299,302	392,526
Net change in income taxes	(391,834)	361,875	129,590
Purchases of reserves		730,611	75,009
Extensions and discoveries	45,485	71,589	306,515
Net change due to revision in quantity estimates	426,357	(309,338)	(199,576)
Changes in production rates (timing) and other	152,167	(57,571)	(33,278)
Standardized measure, end of year	$ 3,440,611	$ 1,904,934	$ 2,537,595