Talos Energy (TALO) 10-K 11 Mar 21 2020 FY Annual report Financial data

Document and Entity Information

Document and Entity Information - USD ($)	12 Months Ended
	Dec. 31, 2020	Mar. 03, 2021	Jun. 30, 2020
Cover [Abstract]
Document Type	10-K
Amendment Flag	false
Document Period End Date	Dec. 31, 2020
Document Fiscal Year Focus	2020
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
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	Accelerated Filer
Entity Common Stock, Shares Outstanding		81,279,989
Entity Well-known Seasoned Issuer	No
Entity Voluntary Filers	No
Entity Public Float			$ 213,227,480
Documents Incorporated by Reference	Portions of the registrant’s definitive proxy statement relating to the 2021 Annual Meeting of Shareholders are incorporated by reference into Part III of this report.

CONSOLIDATED BALANCE SHEETS

CONSOLIDATED BALANCE SHEETS - USD ($) $ in Thousands	Dec. 31, 2020	Dec. 31, 2019
Current assets:
Cash and cash equivalents	$ 34,233	$ 87,022
Accounts receivable
Trade, net	106,220	107,842
Joint interest, net	50,471	16,552
Other	18,448	6,346
Assets from price risk management activities	6,876	8,393
Prepaid assets	29,285	65,877
Other current assets	1,859	1,952
Total current assets	247,392	293,984
Property and equipment:
Proved properties	4,945,550	4,066,260
Unproved properties, not subject to amortization	254,994	194,532
Other property and equipment	32,853	29,843
Total property and equipment	5,233,397	4,290,635
Accumulated depreciation, depletion and amortization	(2,697,228)	(2,065,023)
Total property and equipment, net	2,536,169	2,225,612
Other long-term assets:
Assets from price risk management activities	945
Other well equipment inventory	18,927	7,732
Operating lease assets	6,855	7,779
Other assets	24,258	54,375
Total assets	2,834,546	2,589,482
Current liabilities:
Accounts payable	104,864	71,357
Accrued liabilities	163,379	154,816
Accrued royalties	27,903	31,729
Current portion of asset retirement obligations	49,921	61,051
Liabilities from price risk management activities	66,010	19,476
Accrued interest payable	9,509	10,249
Current portion of operating lease liabilities	1,793	1,594
Other current liabilities	24,155	20,180
Total current liabilities	447,534	370,452
Long-term liabilities:
Long-term debt, net of discount and deferred financing costs	985,512	732,981
Asset retirement obligations	392,348	308,427
Liabilities from price risk management activities	9,625	511
Operating lease liabilities	18,554	17,239
Other long-term liabilities	54,372	81,595
Total liabilities	1,907,945	1,511,205
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, 2020 and 2019
Common stock $0.01 par value; 270,000,000 shares authorized; 81,279,989 and 54,197,004 shares issued and outstanding as of December 31, 2020 and 2019, respectively	813	542
Additional paid-in capital	1,659,800	1,346,142
Accumulated deficit	(734,012)	(268,407)
Total stockholdersʼ equity	926,601	1,078,277
Total liabilities and stockholdersʼ equity	$ 2,834,546	$ 2,589,482

CONSOLIDATED BALANCE SHEETS (Pa

CONSOLIDATED BALANCE SHEETS (Parenthetical) - $ / shares	Dec. 31, 2020	Dec. 31, 2019
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	81,279,989	54,197,004
Common stock, shares outstanding	81,279,989	54,197,004

CONSOLIDATED STATEMENTS OF OPER

CONSOLIDATED STATEMENTS OF OPERATIONS - USD ($) shares in Thousands, $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Revenues and Other:
Total revenues and other	$ 587,486	$ 927,620	$ 891,288
Operating expenses:
Depreciation, depletion and amortization	364,346	345,931	288,719
Write-down of oil and natural gas properties	267,916	12,221
Accretion expense	49,741	34,389	35,344
General and administrative expense	79,175	77,209	85,816
Total operating expenses	1,008,796	714,526	638,159
Operating income (expense)	(421,310)	213,094	253,129
Interest expense	(99,415)	(97,847)	(90,114)
Price risk management activities income (expense)	87,685	(95,337)	60,435
Other income	3,018	2,678	1,012
Net income (loss) before income taxes	(430,022)	22,588	224,462
Income tax benefit (expense)	(35,583)	36,141	(2,922)
Net income (loss)	$ (465,605)	$ 58,729	$ 221,540
Net income (loss) per common share:
Basic	$ (6.88)	$ 1.08	$ 4.81
Diluted	$ (6.88)	$ 1.08	$ 4.81
Weighted average common shares outstanding:
Basic	67,664	54,185	46,058
Diluted	67,664	54,413	46,061
Oil and Gas Properties
Operating expenses:
Lease operating expense	$ 246,564	$ 243,427	$ 226,291
Production taxes	1,054	1,349	1,989
Oil
Revenues and Other:
Total revenues and other	506,788	833,118	781,815
Natural Gas
Revenues and Other:
Total revenues and other	53,714	55,278	73,610
NGL
Revenues and Other:
Total revenues and other	15,434	19,668	$ 35,863
Other
Revenues and Other:
Total revenues and other	$ 11,550	$ 19,556

CONSOLIDATED STATEMENTS OF CHAN

CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS' EQUITY (DEFICIT) - USD ($) $ in Thousands	Total	Cumulative Effect Adjustment	Common Stock	Preferred Stock	Additional Paid-in Capital	Accumulated Deficit	Accumulated DeficitCumulative Effect Adjustment
Balance at Dec. 31, 2017	$ (54,087)	$ (325)	$ 312		$ 493,952	$ (548,351)	$ (325)
Balance, shares at Dec. 31, 2017			31,244,085
Sponsor Debt Exchange	102,000		$ 29		101,971
Sponsor Debt Exchange, Shares			2,874,049
Stone Combination	731,964		$ 201		731,763
Stone Combination, Shares			20,037,634
Equity based compensation	6,404				6,404
Net income (loss)	221,540					221,540
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			53,787
Shares withheld for taxes on equity transactions	(333)				(333)
Shares withheld for taxes on equity transactions, Shares			(12,551)
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		54,197,004
Balance, shares at Dec. 31, 2019	0
Equity based compensation	$ 16,462		$ 2		16,460
Equity based compensation, Shares			248,357
Shares withheld for taxes on equity transactions	(827)		$ (1)		(826)
Shares withheld for taxes on equity transactions, Shares			(67,832)
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

CONSOLIDATED STATEMENTS OF CASH

CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Cash flows from operating activities:
Net income (loss)	$ (465,605)	$ 58,729	$ 221,540
Adjustments to reconcile net income (loss) to net cash provided by operating activities
Depreciation, depletion, amortization and accretion expense	414,087	380,320	324,063
Write-down of oil and natural gas properties and other well inventory	268,615	12,386	244
Amortization of deferred financing costs and original issue discount	6,804	5,207	4,253
Equity based compensation, net of amounts capitalized	8,669	6,964	2,893
Price risk management activities expense (income)	(87,685)	95,337	(60,435)
Net cash received (paid) on settled derivative instruments	143,905	(8,820)	(111,147)
Gain on Extinguishment of debt	(1,662)
Settlement of asset retirement obligations	(43,933)	(75,331)	(112,946)
Changes in operating assets and liabilities:
Accounts receivable	(34,645)	5,788	(786)
Other current assets	35,934	(15,114)	(2,624)
Accounts payable	27,096	7,523	(48,825)
Other current liabilities	4,200	(35,459)	32,044
Other non-current assets and liabilities, net	26,143	(43,797)	15,171
Net cash provided by operating activities	301,923	393,733	263,445
Cash flows from investing activities:
Exploration, development and other capital expenditures	(362,942)	(463,409)	(240,914)
Cash (paid for) received from acquisitions, net of cash acquired	(315,962)	(37,916)	278,409
Proceeds from sale of other property and equipment		5,369
Net cash provided by (used in) investing activities	(678,904)	(495,956)	37,495
Cash flows from financing activities:
Proceeds from issuance of common stock	71,100
Redemption of Senior Notes and other long-term debt	(5,364)	(10,567)	(25,257)
Proceeds from Bank Credit Facility	350,000	110,000	319,000
Repayment of Bank Credit Facility	(60,000)	(25,000)	(54,000)
Deferred financing costs	(1,287)	(1,963)	(17,002)
Other deferred payments	(11,921)	(9,921)
Payments of finance lease	(17,509)	(14,133)	(12,952)
Employee stock transactions	(827)	(333)
Net cash provided by (used in) financing activities	324,192	48,083	(193,211)
Net increase (decrease) in cash, cash equivalents and restricted cash	(52,789)	(54,140)	107,729
Cash, cash equivalents and restricted cash:
Balance, beginning of period	87,022	141,162	33,433
Balance, end of period	34,233	87,022	141,162
Supplemental Non-Cash Transactions:
Capital expenditures included in accounts payable and accrued liabilities	74,957	90,956	100,664
Debt exchanged for common stock	35,960
Supplemental Cash Flow Information:
Interest paid, net of amounts capitalized	$ 67,443	$ 62,571	53,476
LLC Bank Credit Facility
Cash flows from financing activities:
Repayment of Bank Credit Facility			$ (403,000)

Formation and Basis of Presenta

Formation and Basis of Presentation	12 Months Ended
	Dec. 31, 2020
Organization Consolidation And Presentation Of Financial Statements [Abstract]
Formation and Basis of Presentation	Note 1 — Formation and Basis of Presentation Formation and Nature of Business Talos Energy Inc. (“Talos” or the “Company”) is a technically driven independent exploration and production company focused on safely and efficiently maximizing value through its operations, currently in the United States (“U.S.”) Gulf of Mexico and offshore Mexico. The Company leverages decades of geology, geophysics and offshore operations expertise towards the acquisition, exploration, exploitation and development of assets in key geological trends that are present in many offshore basins around the world. Talos Energy Inc. was formed in connection with the previously disclosed business combination between Talos Energy LLC and Stone Energy Corporation (“Stone”) that occurred on May 10, 2018, pursuant to which Talos Energy LLC and Stone became indirect wholly owned subsidiaries of Talos Energy Inc. Talos Energy LLC — Talos Energy LLC was formed in 2011 and commenced commercial operations on February 6, 2013. Prior to February 6, 2013, Talos Energy LLC had incurred certain general and administrative expenses associated with the start-up of its operations. 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. Stone Combination — On May 10, 2018 (the “Stone Closing Date”), the Company (f/k/a Sailfish Energy Holdings Corporation) consummated the transactions contemplated by that certain Transaction Agreement, dated as of November 21, 2017 (the “Transaction Agreement”), by and among Stone, the Company, Sailfish Merger Sub Corporation (“Merger Sub”), Talos Energy LLC and Talos Production LLC (which was converted into a Delaware Corporation and named Talos Production Inc. in 2019), pursuant to which, among other items, each of Stone, Talos Production LLC and Talos Energy LLC became wholly-owned subsidiaries of the Company (the “Stone Combination”). Prior to the Stone Closing Date, the Company did not conduct any material activities other than those incident to its formation and the matters contemplated by the Transaction Agreement. On the Stone Closing Date, the following transactions, among others, occurred: (i) Stone underwent a reorganization pursuant to which Merger Sub merged with and into Stone, with Stone continuing as the surviving corporation and a direct wholly-owned subsidiary of the Company (the “Merger”) and each share of Stone’s common stock outstanding immediately prior to the Merger (other than treasury shares held by Stone, which were cancelled for no consideration) was converted into the right to receive one share of the Company’s common stock, par value $0.01 (the “Common Stock”) and (ii) the Sponsors contributed all of the equity interests in Talos Production LLC (which at that time owned 100% of the equity interests in Talos Energy LLC) to the Company in exchange for an aggregate of 31,244,085 shares of Common Stock (the “Sponsor Equity Exchange”). Concurrently with the consummation of the Transaction Agreement, the Company consummated the transactions contemplated by that certain Exchange Agreement, dated as of November 21, 2017 (the “Exchange Agreement”), among the Company, Stone, the Talos Issuers (defined below), the various lenders and noteholders of the Talos Issuers listed therein, certain funds controlled by Franklin Advisers, Inc. (“Franklin”) (such controlled noteholders, the “Franklin Noteholders”), and certain clients of MacKay Shields LLC (“MacKay Shields”) (such noteholders, the “MacKay Noteholders”), pursuant to which (i) the Apollo Funds and Riverstone Funds contributed $102.0 million in aggregate principal amount of 9.75% Senior Notes due 2022 (“9.75% Senior Notes”) issued by Talos Production LLC and Talos Production Finance, Inc. (together, the “Talos Issuers”) to the Company in exchange for an aggregate of 2,874,049 shares of Common Stock (the “Sponsor Debt Exchange”); (ii) the holders of second lien bridge loans (“11.00% Bridge Loans”) issued by the Talos Issuers exchanged such 11.00% Bridge Loans for $172.0 million aggregate principal amount of 11.00% Second-Priority Senior Secured Notes due 2022 of the Talos Issuers (“11.00% Notes”) and (iii) Franklin Noteholders and MacKay Noteholders exchanged their 7.50% Senior Notes due 2022 issued by Stone (“7.50% Notes”) for $137.4 million aggregate principal amount of 11.00% Notes. Substantially concurrent therewith, the Company consummated an exchange offer and consent solicitation, pursuant to which the holders of the 7.50% Notes, excluding the 7.50% Notes held by the Franklin Noteholders and the MacKay Noteholders, exchanged their 7.50% Notes for 11.00% Notes and a cash payment, and a solicitation of consents to proposed amendments to the 7.50% Notes. Approximately $81.5 million in aggregate principal amount of the 7.50% Notes were validly tendered, and approximately $6.1 million in aggregate principal amount of 7.50% Notes remained outstanding as of the Stone Closing Date. As a result of the closing of the transactions contemplated by the Transaction Agreement and the Exchange Agreement (the “Transactions”) the former stakeholders of Talos Energy LLC held approximately 63% of the Company’s outstanding Common Stock and the former stockholders of Stone held approximately 37% of the Company’s outstanding Common Stock as of the Stone Closing Date. Basis of Presentation and Consolidation The Consolidated Financial Statements have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”) and include 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 are reflected herein. The Company has evaluated subsequent events through the date the Consolidated Financial Statements were issued. Talos Energy LLC was considered the accounting acquirer in the Stone Combination under GAAP. Accordingly, the historical financial and operating data of Talos Energy Inc., which covers periods prior to the Stone Closing Date, reflects the assets, liabilities and results of operations of Talos Energy LLC and does not reflect the assets, liabilities and results of operations of Stone. For the periods prior to May 10, 2018, the Company retrospectively adjusted its Consolidated Statement of Changes in Stockholders’ Equity and the weighted average shares used in determining earnings per share to reflect the number of shares Talos Energy LLC received in the Stone Combination. Beginning on May 10, 2018, common stock is presented to reflect the legal capital of Talos Energy Inc. 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. For presentation purposes, as of December 31, 2020, operating expenses previously presented as “Direct lease operating expense,” “Insurance” and “Workover and maintenance expense” have been combined and presented as “Lease operating expense” on the Company’s Consolidated Statements of Operations. Such reclassification had no effect on our results of operations, financial position or cash flows. The Company has one reportable segment, which is the exploration and production of oil, natural gas and NGLs. Substantially all the Company’s long-lived assets, proved reserves and production sales are related to the Company’s operations in the United States. Recently Adopted Accounting Standards Credit Risk Losses — In June 2016, the Financial Accounting Standards Board issued ASU 2016-13, Financial Instruments - Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments, which changes accounting requirements for the recognition of credit losses from an incurred or probable impairment methodology to a current expected credit losses (“CECL”) methodology. The CECL model is applicable to the measurement of credit losses on financial assets measured at amortized cost, including, but not limited to trade receivables. The guidance was adopted on January 1, 2020 using a modified retrospective approach. The adoption of this guidance did not have a material effect on the Company’s Consolidated Financial Statements or related disclosures. Accounts receivable resulting from the sale of crude oil, natural gas and NGL production and joint interest billings to our partners for their share of expenditures on joint venture projects for which we are the operator are the primary financial assets within the scope of the standard. Although these receivables are from a diverse group of companies, including major energy companies, pipeline companies and joint interest owners, they are concentrated in the oil and gas industry. This concentration has the potential to impact our overall exposure to credit risk in that these companies may be similarly affected by changes in economic and financial conditions, commodity prices or other conditions. 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. At each reporting period the loss-rate is determined utilizing historical data, current market conditions and reasonable and supported forecast of future economic conditions. Our allowance for uncollectable receivables was $9.2 million at December 31, 2020 and $9.9 million at December 31, 2019. Guarantor Financial Information — In March 2020, the SEC adopted final rules that simplify the disclosure requirements related to certain registered securities under SEC Regulation S-X, Rules 3-10 and 3-16, permitting registrants to provide certain alternative financial disclosures and non-financial disclosures in lieu of separate Consolidated Financial Statements for subsidiary issuers and guarantors of registered debt securities (which the Company previously presented within the notes to the Financial Statements included in its Annual Report on Form 10-K and Quarterly Reports on Form 10-Q) if certain conditions are met. The disclosure requirements, as amended, are now located in newly created Rules 13-01 and 13-02 of Regulation S-X and are generally effective for filings on or after January 4, 2021, with early adoption permitted. The Company early adopted the new disclosure requirements effective as of July 1, 2020 and are providing the summarized financial information and related disclosures in Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations in this Form 10-K.

Summary of Significant Accounti

Summary of Significant Accounting Policies	12 Months Ended
	Dec. 31, 2020
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 Uncollectible Accounts — Accounts receivable are stated at the historical carrying amount net of an allowance for uncollectible accounts of $9.2 million at December 31, 2020 and $9.9 million at December 31, 2019. 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. The Company presented $19.1 million and $18.0 million of refund claims for value added taxes paid in Mexico in “Other assets” on the Consolidated Balance Sheets as of December 31, 2020 and 2019, respectively. Prepaid Assets — Prepaid assets primarily represent deposits with the Office of Natural Resources Revenue (“ONRR”) and transaction escrow related to the ILX and Castex Acquisition as further defined in Note 3 — Acquisitions. 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. The transaction escrow was applied to the purchase price that closed in the first quarter of 2020. The escrow for the years ended December 31, 2020 and 2019 were nil and $31.8 million, respectively. 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 recorded gross on our Consolidated Balance Sheets. At December 31, 2020 and 2019, our imbalance receivable was approximately $1.7 million and $1.7 million, respectively, and imbalance payable was approximately $3.6 million and $3.6 million, respectively. Production Handling Fees — The Company presented 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 in “Other” within “Revenues and Other” 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, 2020, 2019 and 2018 were $8.9 million, $19.3 million and nil, respectively. 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 quarterly. 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 percent, plus the lower of cost or estimated fair value of unproved oil and natural gas properties not being amortized less the related tax effects. 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, computer hardware and software. Acquisitions, renewals 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 this inventory is supplied to wells, the cost of this inventory 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 inventory is stated at the lower of cost or net realizable value. The Company recorded $0.7 million, $0.2 million, and $0.2 million of impairment to adjust inventory to net realizable value, which was expensed and reflected in lease operating expense, during the years ended December 31, 2020, 2019 and 2018, respectively. Fair Value Measure of Financial Instruments — Financial instruments generally consist of cash and cash equivalents, restricted cash, accounts receivable, commodity derivatives, accounts payable and debt. The carrying amount of cash and cash equivalents, restricted cash, 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 “A ccretion expense ” in the Company’s C onsolidated S tatements of O perations. If the Company incurs an amount different from the amount accrued for decommissioning obligations, the Company recognizes the difference as an adjustment to proved properties. 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)” in 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 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, we generally use our 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 we will exercise that option. The Company has elected to not apply the recognition requirements of Topic 842 to leases with durations of twelve months or less (i.e. short-term). Income Taxes — Prior to the Stone Combination, Talos Energy LLC was a partnership for U.S. federal income tax purposes and was not subject to U.S. federal income tax or state income tax (in most states) at the entity level. As such, Talos Energy LLC did not recognize U.S. federal income tax expense or state income tax expense in most states. In connection with the Stone Combination, Talos Energy LLC was contributed to the Company, which is subject to U.S. federal and state 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. Changes in tax laws are recorded in the period they are 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. The Company measures all employee equity based compensation awards at fair value as calculated using an option pricing method for valuing such securities on the date awards are granted to its employees and recognize compensation cost on a straight-line basis in the Company’s financial statements over the vesting period of each grant according to ASC 718, Compensation—Stock Compensation. During 2020, the Company issued RSUs and PSUs to certain employees and non-employee directors. The fair value of the stock-based awards is determined at the date of grant and is not remeasured for awards classified as equity, 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 RSUs — Share-based compensation is based on the market price of the Company’s Common Stock on the grant date and recognized over the vesting period using the straight-line method as the requisite service period is fulfilled. PSUs — Share-based compensation is based on the grant date fair value determined using a Monte Carlo valuation model and recognized over the vesting 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 and balances are maintained i n financial institutions, which at times, exceed federally insured limits. The Company monitor s 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, 2020 2019 2018 Shell Trading (US) Company 47 % 58 % 65 % Phillips 66 22 % 28 % 18 % Chevron Products Company 12 % ** ** ** Less than 10% The loss of a major customer could have material adverse effect on the Company in the short term. However, the Company believes it would be able to obtain other customers to market its oil, natural gas and NGL production.

Acquisitions

Acquisitions	12 Months Ended
	Dec. 31, 2020
Business Combinations [Abstract]
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 consist of interests in 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 date of the closing 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). The following table presents the allocation of the purchase price to the assets acquired and liabilities assumed, based on their relative fair values, on January 11, 2019 (in thousands): Property and equipment $ 28,912 Asset retirement obligations (996 ) Allocated purchase price $ 27,916 Acquisition of Whistler Energy II, LLC — On August 31, 2018, the Company completed the acquisition of all the issued and outstanding membership interests of Whistler Energy II, LLC (“Whistler”) from Whistler Energy II Holdco, LLC, an affiliate of the Apollo Funds (the “Whistler Acquisition”), for $52.6 million ($14.8 million, net of $37.8 million of cash acquired). The $37.8 million of cash acquired consists of $30.8 million of cash collateral posted by Whistler and released by third party surety companies at closing and $7.0 million of cash on hand for working capital purposes. Through the acquisition, the Company acquired and assumed all of Whistler’s oil and natural gas assets and the associated asset retirement obligations for interests located in Green Canyon Block 18, Green Canyon Block 60 and Ewing Bank Blocks 944 and 988, including a fixed production platform on Green Canyon Block 18. 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 31, 2018 (in thousands): Current assets (1) $ 45,337 Property and equipment 35,344 Other long-term assets 66 Current liabilities (4,261 ) Asset retirement obligations (23,862 ) Allocated purchase price $ 52,624 (1) Includes $37.8 million of cash acquired and trade receivables of $3.2 million, which the Company expects all to be realizable. 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 (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 payment and escrow deposit were 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 date of the closing 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, which the Company expects all to be realizable. The Company incurred approximately $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 have been 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 for the year ended December 31, 2020: 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 Combination Between Talos Energy LLC and Stone Energy Corporation — On May 10, 2018, the Company consummated the Transactions contemplated by the Transaction Agreement and Exchange Agreement, pursuant to which, among other things, Talos Energy LLC and Stone became wholly-owned subsidiaries of the Company. The combination was executed as an all-stock transaction whereby the former stakeholders of Talos Energy LLC held approximately 63% of the Company’s outstanding Common Stock and the former stockholders of Stone held approximately 37% of the Company’s outstanding Common Stock as of the Stone Closing Date. The purchase price of $ 732.0 million is based on the closing price of Stone common stock and common warrants immediately prior to closing. The following table summarizes the purchase price (in thousands, except per share data): Stone Energy common stock - issued and outstanding as of May 9, 2018 20,038 Stone Energy common stock price $ 35.49 Common stock value $ 711,149 Stone Energy common stock warrants - issued and outstanding as of May 9, 2018 3,528 Stone Energy common stock warrants price $ 5.90 Common stock warrants value $ 20,815 Total purchase price $ 731,964 During 2018, the Company incurred approximately $88.6 million of transaction related costs, of which, $32.5 million was expensed and reflected in “General and administrative expense” on the Consolidated Statements of Operations. The remaining $56.1 million was the result of (i) $9.3 million in work fees paid to holders of the 11.00% Notes reflected as a debt discount reducing “Long-term debt” on the Consolidated Balance Sheets and (ii) $46.8 million in fees for seismic use agreements for change in control provisions and reflected in “Proved properties” on the Consolidated Balance Sheets. The following table presents the final allocation of the purchase price to the assets acquired and liabilities assumed, based on their fair values on May 10, 2018 (in thousands): Current assets (1) $ 372,963 Property and equipment 886,406 Other long-term assets 19,494 Current liabilities (132,846 ) Long-term debt (235,416 ) Other long-term liabilities (178,637 ) Allocated purchase price $ 731,964 (1) Includes $293.0 million of cash acquired. The fair values of current assets acquired includes trade receivables and joint interest receivables of $43.3 million and $3.5 million, respectively, which the Company expects all to be realizable. The follow table presents revenue and net income attributable to the assets acquired in the Stone Combination for the years ended December 31, 2020, 2019 and 2018: Year Ended December 31, 2020 2019 2018 Revenue $ 187,211 414,056 332,944 Net income (loss) $ (1,232 ) 187,428 148,473 Pro Forma Financial Information (Unaudited) — The following supplemental pro forma information (in thousands, except per common share amounts), presents the consolidated results of operations for the year ended December 31, 2018 as if the Stone Combination had occurred on January 1, 2018. The unaudited pro forma information was derived from historical statements of operations of the Company and Stone and adjusted to include (i) depletion and accretion expense applied to the adjusted basis of the oil and natural gas properties acquired, (ii) interest expense to reflect the debt transactions contemplated by the Exchange Agreement and (iii) general and administrative expense adjusted for transaction related costs incurred. This information does not purport to be indicative of results of operations that would have occurred had the Stone Combination occurred on January 1, 2018, nor is such information indicative of any expected future results of operations. Year Ended December 31, 2018 Revenue $ 1,013,184 Net income $ 274,577 Basic net income per common share $ 5.07 Diluted net income per common share $ 5.07

Property, Plant and Equipment

Property, Plant and Equipment	12 Months Ended
	Dec. 31, 2020
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. The Company follows the full cost method of accounting for its oil and natural gas exploration and development activities. Pursuant to SEC Regulation S-X, Rule 4-10, under the full cost method of accounting, the Company’s capitalized oil and natural gas 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. The Company performs this ceiling test calculation each quarter utilizing SEC pricing. During 2020, 2019 and 2018, the Company’s ceiling test computations resulted in a write-down of its U.S. oil and natural gas properties of $267.9 million, nil and nil, respectively. At December 31, 2020, its ceiling test computation was based on SEC pricing of $39.47 per Bbl of oil, $1.97 per Mcf of natural gas and $9.89 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 and Block 31 located in the shallow waters off the coast of Mexico’s Veracruz and Tabasco states. The following table sets forth a summary of the Company’s oil and natural gas property costs not being amortized at December 31, 2020, by the year in which such costs were incurred (in thousands): Year Ended December 31, Total 2020 2019 2018 2017 and Prior Acquisition United States $ 80,799 $ 61,315 $ 3,268 $ 16,216 $ — Exploration United States 52,470 12,714 32,698 5,761 1,297 Exploration Mexico 121,725 14,811 61,809 14,362 30,743 Total unproved properties, not subject to amortization $ 254,994 $ 88,840 $ 97,775 $ 36,339 $ 32,040 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 in Block 2 offshore Mexico, specifically future exploratory drilling opportunities, results from exploratory wells drilled during the second quarter of 2019 and the Block 2 production sharing contract’s expiration date resulted in the Company recording a non-cash impairment presented as “Write-down of oil and natural gas properties” on the Consolidated Statements of Operations. For the years ended December 31, 2020, 2019 and 2018, the Company recorded an impairment of $0.1 million, $12.2 million and nil, respectively. Asset Retirement Obligations The discounted asset retirement obligations included in the Consolidated Balance Sheets in current and non-current liabilities, and the changes in that liability during each of the years ended December 31, 2020 and 2019 were as follows (in thousands): Year Ended December 31, 2020 2019 Asset retirement obligations at January 1 $ 369,478 $ 382,817 Fair value of asset retirement obligations acquired (1) 44,311 5,047 Obligations settled (43,933 ) (75,331 ) Fair value of asset retirement obligations divested (185 ) (5,450 ) Accretion expense 49,741 34,389 Obligations incurred 4,511 4,111 Changes in estimate 18,346 23,895 Asset retirement obligations at December 31 $ 442,269 $ 369,478 Less: Current portion (49,921 ) (61,051 ) Long-term portion $ 392,348 $ 308,427 (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, 2020
Leases [Abstract]
Leases	Note 5 — Leases The Company enters into service contracts and other contractual arrangements for the use of office space, drilling, completion and abandonment equipment (e.g., drilling rigs), production related equipment (e.g., compressors) and other equipment from third-party lessors to support its operations. The Company’s leasing activities as a lessor are negligible. 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. The amounts disclosed herein primarily represent costs associated with properties operated by the Company that are presented on a gross basis and do not reflect 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 depending on how the leased asset is utilized. The components of lease costs were as follows (in thousands): Year Ended December 31, 2020 2019 Finance lease cost - interest on lease liabilities (1) $ 15,748 $ 19,115 Operating lease cost, excluding short-term leases (2) 3,361 3,261 Short-term lease cost (3) 53,573 85,865 Variable lease cost (4) 543 11 Total lease cost $ 73,225 $ 108,252 (1) The Helix Producer I (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 reserved using the unit-of-production method, computed quarterly. (2) 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. (3) 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. (4) 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 are as follows (in thousands): Year Ended December 31, 2020 2019 Operating leases: Operating lease assets $ 6,855 $ 7,779 Current portion of operating lease liabilities $ 1,793 $ 1,594 Operating lease liabilities 18,554 17,239 Total operating lease liabilities $ 20,347 $ 18,833 Finance leases: Proved property (1) $ 124,299 $ 124,299 Other current liabilities $ 21,804 $ 17,509 Other long-term liabilities 40,222 62,026 Total finance lease liabilities $ 62,026 $ 79,535 (1) 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. The table below presents the lease maturity by year as of December 31, 2020 (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 2021 $ 4,079 $ 33,257 2022 4,302 33,257 2023 4,239 13,857 2024 3,315 — 2025 3,293 — Thereafter 12,497 — Total lease payments $ 31,725 $ 80,371 Imputed interest (11,378 ) (18,345 ) Total $ 20,347 $ 62,026 The table below presents the weighted average remaining lease term and discount rate related to leases for the years ended December 31, 2020 and 2019: Year Ended December 31, 2020 2019 Weighted average remaining lease term: Operating leases 7.8 years 8.4 years Finance leases 2.4 years 3.4 years Weighted average discount rate: Operating leases 12.0 % 10.2 % Finance leases 21.9 % 21.9 % The table below presents the supplemental cash flow information related to leases for the years ended December 31, 2020 and 2019 (in thousands): Year Ended December 31, 2020 2019 Operating cash outflow from finance leases $ 15,748 $ 19,115 Financing cash outflow from finance leases $ 17,509 $ 14,133 Operating cash outflow from operating leases $ 2,648 $ 1,812 Right-of-use assets obtained in exchange for new operating lease liabilities $ — $ 2,225

Financial Instruments

Financial Instruments	12 Months Ended
	Dec. 31, 2020
Financial Instruments [Abstract]
Financial Instruments	Note 6 — Financial Instruments The following table presents the carrying amounts and estimated fair values of the Company’s financial instruments (in thousands): December 31, 2020 December 31, 2019 Carrying Amount Fair Value Carrying Amount Fair Value 11.00% Second-Priority Senior Secured Notes – due April 2022 (1) $ 343,579 $ 355,935 $ 383,871 $ 401,128 7.50% Senior Notes – due May 2022 $ 6,060 $ 5,238 $ 6,060 $ 5,030 Bank Credit Facility – matures May 2022 (1) $ 635,873 $ 640,000 $ 343,050 $ 350,000 Oil and Natural Gas Derivatives $ (67,814 ) $ (67,814 ) $ (11,594 ) $ (11,594 ) (1) The carrying amounts are net of discount and deferred financing costs. As of December 31, 2020 and 2019, 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. 11.00% Second-Priority Senior Secured Notes – due April 2022 The $347.3 million aggregate principal amount of 11.00% Notes is reported on the Consolidated Balance Sheets at its carrying value, net of original issue discount and deferred financing costs, see Note 7 — Debt 7.50% Senior Notes – due May 2022 The $6.1 million aggregate principal amount of 7.50% Notes is reported on the Consolidated Balance Sheets at its carrying value, see Note 7 — Debt Bank Credit Facility – matures May 2022 The Company and Talos Production Inc., our wholly-owned subsidiary that was formerly known as Talos Production LLC, maintains a Bank Credit Facility with a borrowing base of $985.0 million at December 31, 2020 (the “Bank Credit Facility”), which is reported on the Consolidated Balance Sheets at its carrying value net of deferred financing costs (see Note 7 – Debt 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 C onsolidated B alance S heet s at fair value with settlements of such contracts, and changes in the unre alized fair value, recorded as “P rice risk management activities income (expense) ” on the C onsolidated S tatements of O perations in each period . The following table presents the impact that derivatives, not qualifying as hedging instruments, had on its Consolidated Statements of Operations (in thousands): Year Ended December 31, 2020 2019 2018 Net cash received (paid) on settled derivative instruments $ 143,905 $ (8,820 ) $ (111,147 ) Unrealized gain (loss) (56,220 ) (86,517 ) 171,582 Price risk management activities income (expense) $ 87,685 $ (95,337 ) $ 60,435 The following table reflects the contracted volumes and weighted average prices the Company will receive under the terms of its derivative contracts as of December 31, 2020: Production Period Instrument Type Average Daily Volumes Weighted Average Swap Price Weighted Average Put Price Weighted Average Call Price Crude Oil – WTI: (Bbls) (per Bbl) (per Bbl) (per Bbl) January 2021 – December 2021 Swaps 22,948 $ 43.20 $ — $ — January 2021 – December 2021 Collars 1,000 $ — $ 30.00 $ 40.00 January 2022 – December 2022 Swaps 10,616 $ 44.45 $ — $ — Crude Oil – LLS: (Bbls) (per Bbl) (per Bbl) (per Bbl) January 2021 – December 2021 Swaps 3,000 $ 38.83 $ — $ — Natural Gas – NYMEX Henry Hub: (MMBtu) (per MMBtu) (per MMBtu) (per MMBtu) January 2021 – December 2021 Swaps 58,907 $ 2.56 $ — $ — January 2021 – December 2021 Collars 5,000 $ — $ 2.50 $ 3.10 January 2022 – December 2022 Swaps 29,649 $ 2.60 $ — $ — January 2023 – June 2023 Swaps 5,000 $ 2.61 $ — $ — The following tables provide additional information related to financial instruments measured at fair value on a recurring basis (in thousands): 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 ) December 31, 2019 Level 1 Level 2 Level 3 Total Assets: Oil and natural gas swaps and costless collars $ — $ 8,393 $ — $ 8,393 Liabilities: Oil and natural gas swaps and costless collars — (19,987 ) — (19,987 ) Total net liability $ — $ (11,594 ) $ — $ (11,594 ) 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 at December 31, 2020 and 2019 (in thousands): December 31, 2020 December 31, 2019 Assets Liabilities Assets Liabilities Oil and natural gas derivatives: Current $ 6,876 $ 66,010 $ 8,393 $ 19,476 Non-current 945 9,625 — 511 Total $ 7,821 $ 75,635 $ 8,393 $ 19,987 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 entered into International Swaps and Derivative Association agreements with counterparties to mitigate this risk. The Company also maintains credit policies with regard to its counterparties to minimize overall credit risk. These policies require (i) the evaluation of potential counterparties’ financial condition to determine their credit worthiness; (ii) the regular monitoring of counterparties’ credit exposures; (iii) the use of contract language that affords the Company netting or set off opportunities to mitigate exposure risk; and (iv) potentially requiring counterparties to post cash collateral, parent guarantees, or letters of credit to minimize credit risk. The Company’s assets and liabilities from commodity price risk management activities at December 31, 2020 represent derivative instruments from nine counterparties; all of which are registered swap dealers that have an “investment grade” (minimum Standard & Poor’s rating of BBB- or better) credit rating, and 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, 2020
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, 2020 2019 11.00% Second-Priority Senior Secured Notes – due April 2022 $ 347,254 $ 390,868 7.50% Senior Notes – due May 2022 6,060 6,060 Bank Credit Facility – matures May 2022 640,000 350,000 Total debt, before discount and deferred financing cost 993,314 746,928 Discount and deferred financing cost (7,802 ) (13,947 ) Total debt, net of discount and deferred financing costs $ 985,512 $ 732,981 11.00% Second-Priority Senior Secured Notes – due April 2022 The 11.00% Notes were issued pursuant to an indenture dated May 10, 2018, between Talos Production Inc. (formerly Talos Production LLC) and Talos Production Finance Inc., the subsidiary guarantors party thereto and Wilmington Trust, National Association, as trustee and collateral agent. The 11.00% Notes mature April 3, 2022 and have interest payable semi-annually each April 15 and October 15. Prior to May 10, 2021, the Company may, at its option, redeem all or a portion of the 11.00% Notes at 102.75% of the principal amount plus accrued and unpaid interest. Thereafter, the Company may redeem all or a portion of the 11.00% Notes at redemption prices decreasing annually from May 10 at 102.75% to 100.0% plus accrued and unpaid interest. The indenture governing the 11.00% Notes applies certain limitations on the Company’s ability and the ability of its subsidiaries to, among other things, (i) incur additional indebtedness or issue certain preferred shares; (ii) pay dividends and make certain other restricted payments; (iii) create restrictions on the payment of dividends or other distributions to the Company from its restricted subsidiaries; (iv) create liens on certain assets to secure debt; (v) make certain investments; (vi) engage in sales of assets and subsidiary stock; (vii) transfer all or substantially all of its assets or enter into merger or consolidation transactions; and (viii) engage in transactions with affiliates. The 11.00% Notes contain customary quarterly and annual reporting, financial and administrative covenants. The Company was in compliance with all debt covenants at December 31, 2020. 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 presented as “Other income (expense)” on the Consolidated Statements of Operations. 7.50% Senior Notes – due May 2022 The 7.50% Notes represent the remaining $6.1 million of long-term debt assumed in the Stone Combination that were not exchanged for 11.00% Notes pursuant to the 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. Prior to May 31, 2021, the Company may, at its option, redeem all of the 7.50% Notes at 105.63% of the principal amount plus accrued and unpaid interest. Thereafter, the Company may redeem all or a portion of the 7.50% Notes at redemption prices decreasing annually at May 31 from 105.63% to 100.0% plus accrued and unpaid interest. Bank Credit Facility – matures May 2022 The Company and Talos Production Inc. maintain a Bank Credit Facility with a syndicate of financial institutions, with a borrowing base of $985.0 million as of December 31, 2020. The Bank Credit Facility matures on May 10, 2022, provided that the Bank Credit Facility mandates a springing maturity that is 120 days prior to the maturity date of the 11.00% Notes (such 120 days prior being December 4, 2021), if greater than $25.0 million of the 11.00% Notes or any permitted refinancing indebtedness in respect thereof is outstanding on such date. The Bank Credit Facility bears interest based on the borrowing base usage, at the applicable London InterBank Offered Rate, plus applicable margins ranging from 3.00% to 4.00% or an alternate base rate, based on the federal funds effective rate plus applicable margins ranging from 2.00% to 3.00%. In addition, the Company is obligated to pay a commitment fee of 0.50% on the unutilized portion of the commitments. 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. The Bank Credit Facility provides for determination of the borrowing base based on the Company’s proved producing reserves and a portion of our PUD reserves. The borrowing base is redetermined by the lenders at least semi-annually during the second quarter and fourth quarter each year. Upon closing of the ILX and Castex Acquisition on February 28, 2020, As of December 31, 2020, no more than $200.0 million of the Company’s borrowing base can be used as letters of credit. 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, 2020. As of December 31, 2020, the Company had $640.0 million of outstanding borrowings and $13.6 million in letters of credit issued under the Bank Credit Facility. Subsequent Events Issuance of 12.00% Second-Priority Senior Notes – due January 2026 — On January 4, 2021, the Company issued $500.0 million in aggregate principal amount of 12.00% Second-Priority Senior Secured Notes due January 2026 On January 14, 2021, the Company issued $150.0 million in aggregate principal amount of the 12.00% Notes pursuant to the first supplemental indenture dated January 14, 2021. The $150.0 million and $500.0 million in 12.00% Notes rank pari passu in right of payment and constitute a single class of securities for all purposes under the indenture. The issuances of 12.00% Notes on January 4, 2021 and January 14, 2021 resulted in $600.5 million in gross proceeds. Redemption of 11.00% Second-Priority Senior Secured Notes – due April 2022 — On January 13, 2021, the Company redeemed $347.3 million aggregate principal amount of the 11.00% Notes using the proceeds from the issuance of 12.00% Notes. As result of the issuances of the 12.00% Notes exceeding $550.0 million, the Bank Credit Facility borrowing base was reduced from $985.0 million to $960.0 million under the terms of the Bank Credit Facility. Additionally, the redemption of the 11.00% Notes eliminated the Bank Credit Facility mandated springing maturity that was 120 days prior to the maturity date of the 11.00% Notes, if greater than $25.0 million of the 11.00% Notes are outstanding. Bank Credit Facility – matures May 2022 — On January 14, 2021, the borrowing base was reduced from $985.0 million to $960.0 million per the terms of the credit facility as a result of the additional indebtedness from the 12.00% Notes. Additionally, during January 2021, the Company repaid $175.0 million of outstanding borrowings under the Bank Credit Facility. Inclusive of the $25.0 million reduction to the borrowing base and $175.0 million repayment, the Company had $465.0 million of outstanding borrowings and $13.6 million in letters of credit issued under the $960.0 million borrowing base.

Employee Benefits Plans and Sha

Employee Benefits Plans and Share-Based Compensation	12 Months Ended
	Dec. 31, 2020
Disclosure Of Compensation Related Costs Sharebased Payments [Abstract]
Employee Benefits Plans and Share-Based Compensation	Note 8 — Employee Benefits Plans and Share-Based Compensation Stone Change of Control and Severance Plans As a result of the Stone Combination, t he Company assumed the Stone Energy Corporation Executive Severance Plan and Stone Energy Corporation Employee Severance Plan, each a legacy plan of Talos Petroleum LLC (f/k/a Stone Energy Corporation). The plans provided for the payment of severance and change in control benefits to certain individuals who, prior to the Stone Combination, were executive officers or employees of Talos Petroleum LLC, in each case upon an involuntary termination within twelve months of the Stone Closing Date. For the years ended December 31, 2020, 2019 and 2018 the Company incurred nil, $0.2 million and $7.8 million, respectively, of severance expense, reflected in “General and administrative expense” on the Consolidated Statements of Operations. The plans were terminated on July 11, 2019. Talos Energy Inc. Long Term Incentive Plan Under the Talos Energy Inc. Long Term Incentive Plan (the “LTIP”), the Company may issue, subject to approval by the Talos board of directors, grants of options (including incentive stock options), stock appreciation rights, restricted stock, restricted stock units, stock awards, dividend equivalents, other stock-based awards, cash awards, substitute awards or any combination of the foregoing to employees, directors and consultants. The LTIP authorizes the Company to grant awards of up to 5,415,576 shares of the Company’s common stock. Restricted Stock Units – Employees — RSUs granted to employees under the LTIP primarily vest ratably over an approximate three year period subject to such employee’s continued service through each vesting date. Upon vesting, each RSU represents a contingent right to receive one share of Common Stock. The total unrecognized share-based compensation expense related to these RSUs at December 31, 2020 was approximately $14.3 million, which is expected to be recognized over a weighted average period of 1.8 years. Restricted Stock Units – — RSUs granted to non-employee directors under the LTIP 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, 2020 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 for the years ended December 31, 2020, 2019 and 2018: Restricted Stock Units Weighted Average Grant Date Fair Value Unvested RSUs at December 31, 2017 — $ — Granted 139,411 $ 33.85 Vested (53 ) $ 32.86 Forfeited (654 ) $ 32.86 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 Performance Share Units – Employees — PSUs granted to employees under the LTIP 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 The following table summarizes PSU activity for the years ended December 31, 2020, 2019 and 2018: Performance Share Units Weighted Average Grant Date Fair Value Unvested PSUs at December 31, 2017 — $ — Granted 232,891 $ 44.47 Vested — $ — Forfeited (1,349 ) $ 42.94 Unvested PSUs at December 31, 2018 231,542 $ 44.47 Granted 218,060 $ 33.96 Vested — $ — Forfeited (31,771 ) $ 40.27 Unvested PSUs at December 31, 2019 417,831 $ 39.31 Granted 441,642 $ 13.05 Vested — $ — Forfeited (25,301 ) $ 37.67 Unvested PSUs at December 31, 2020 834,172 $ 25.46 The grant date fair value of the PSUs, calculated using a Monte Carlo simulation, was $5.8 million, $7.4 million and $10.4 million for the years ended December 31, 2020, 2019 and 2018. The following table summarizes the assumptions used to calculate the grant date fair value of the PSUs granted for the years ended December 31, 2020, 2019 and 2018: 2020 Grant Date 2019 Grant Date 2018 Grant Date March 5 March 5 May 16 August 29 September 28 Number of simulations 100,000 100,000 100,000 100,000 100,000 Expected term (in years) 2.8 2.8 2.6 2.7 2.6 Expected volatility 48.8 % 46.9 % 44.8 % 50.6 % 47.4 % Risk-free interest rate 0.6 % 2.5 % 2.1 % 2.7 % 2.9 % Dividend yield — % — % — % — % — % Talos Energy LLC Series B Units Prior to the Stone Combination, the Limited Liability Company Agreement of Talos Energy LLC established Series A, Series B and Series C Units. Series B Units were generally intended to be used as incentives for Talos Energy LLC employees. Series B Units do not participate in distributions prior to vesting or until Series A Units have received cumulative distributions equal to (i) the original cash contributed to the Company for such Series A Units and (ii) an 8% return, compounded annually (the “Aggregate Series A Payout”), and Series C Units have received no distributions. In connection with the Transactions, the Series A, Series B and Series C Units were exchanged for an equivalent number of units in each of an entity affiliated with the Apollo Funds and an entity affiliated with the Riverstone Funds, each of which hold Common Stock of the Company. The modification did not result in incremental value to the Series B Units. For accounting and financial reporting purposes, the Series B Units are deemed to be equity awards, and the compensation expense related to these awards is recorded on a straight-line basis over the vesting period in the Company’s Consolidated Financial Statements and is reflected as a corresponding credit to “Accumulated deficit” on the Consolidated Balance Sheets. The Company’s unrecognized compensation expense at December 31, 2020 is approximately $3.4 million, which will be recognized upon an Aggregate Series A Payout. New Talos Energy LLC Series B Units In connection with the transactions contemplated in the Exchange Agreement on May 10, 2018, an entity affiliated with the Apollo Funds and an entity affiliated with the Riverstone Funds, each of which hold Common Stock in the Company as a result of the Sponsor Debt Exchange, established new Series A Units (“New Series A Units”) and new Series B Units (“New Series B Units”). The New Series B Units are generally intended to be used as incentives for Talos Energy LLC employees. The New Series B Units do not participate in distributions prior to vesting or until the New Series A Units have received cumulative distributions of $102.0 million. After issuance, 80% of the New Series B Units vest on a monthly basis over a four year period based on the initial vesting schedule of the original Series B Units, subject to continued employment. All unvested New Series B Units fully vest upon the cumulative distribution of $102.0 million. For accounting and financial reporting purposes, the New Series B Units are deemed to be equity awards, and the compensation expense related to these awards is recorded on a straight-line basis over the vesting period in the Company’s Consolidated Financial Statements and is reflected as a corresponding credit to “Accumulated deficit” on the Consolidated Balance Sheets. The New Series B Units issued were valued using the option pricing method for valuing securities. In this method, the rights and claims of each security are modeled as a portfolio of Black-Scholes-Merton call options written on the total equity of the entities affiliated with the Apollo Funds and Riverstone Funds. The total value of the equity is calculated in an iterative process that results in the New Series A Units being valued at par. The risk-free rate of interest is based on the U.S. Treasury yield curve on the grant date. The expected time to a liquidity event is based on a weighted average calculation of management’s estimate considering market conditions and expectations. The expected volatility of equity is based on the volatility of the assets of similar publicly traded companies using a Black-Scholes-Merton model. The discount for lack of marketability is based on the restrictions on the New Series B Units and the volatility of the New Series B Units using a Black-Scholes-Merton model. The Company’s unrecognized compensation expense at December 31, 2020 is approximately $1.0 million, which will be recognized upon the New Series A Units receiving a cumulative distribution. Share-based Compensation Expense, net Share-based compensation expense associated with RSUs, PSUs and Series B Units are reflected as General administrative expense, in the statements of operations, net amounts capitalized to “Proved properties”, in 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” in the Consolidated Statements of Cash Flows. For the years ended December 31, 2020, 2019 and 2018, share-based compensation expense did not have an associated income tax benefit. The Company recognized the following share-based compensation expense, net for the years ended December 31, 2020, 2019 and 2018 (in thousands): Year Ended December 31, 2020 2019 2018 Talos Energy Inc. Long Term Incentive Plan $ 16,227 $ 12,523 $ 2,091 Talos Energy LLC Series B Units 192 256 666 New Talos Energy LLC Series B Units 43 145 3,752 Total share-based compensation expense 16,462 12,924 6,509 Less: amounts capitalized to oil and gas properties (7,793 ) (5,960 ) (3,616 ) Total share-based compensation expense, net $ 8,669 $ 6,964 $ 2,893

Income Taxes

Income Taxes	12 Months Ended
	Dec. 31, 2020
Income Tax Disclosure [Abstract]
Income Taxes	Note 9 — Income Taxes Prior to the Stone Combination, Talos Energy LLC was a partnership for U.S. federal income tax purposes and was not subject to U.S. federal income tax or state income tax (in most states) at the entity level. As such, Talos Energy LLC did not recognize U.S. federal income tax expense or state income tax expense in most states. Talos Energy LLC’s operations in the shallow waters off the coast of Mexico are conducted under a different legal form and are subject to foreign income taxes. Income Tax Expense (Benefit) The components of income tax expense (benefit) were as follows (in thousands): Year Ended December 31, 2020 2019 2018 Current income tax expense (benefit) United States $ (499 ) $ 437 $ — Mexico 185 1,183 1,345 Total current income tax expense (benefit) $ (314 ) $ 1,620 $ 1,345 Deferred income tax expense (benefit) United States $ 35,923 $ (37,131 ) $ 1,064 Mexico (26 ) (630 ) 513 Total deferred income tax expense (benefit) 35,897 (37,761 ) 1,577 Total income tax expense (benefit) $ 35,583 $ (36,141 ) $ 2,922 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, 2020 2019 2018 Income tax expense (benefit) at the federal statutory tax rate $ (90,304 ) $ 4,744 $ 47,137 Earnings not subject to tax — — 9,980 State income taxes (14,215 ) 1,396 11,738 Foreign income taxes — — 1,008 Foreign rate differential (1,030 ) (4,948 ) 432 Prior year taxes (4,237 ) (1,950 ) 417 Other adjustments — 137 800 Change in tax status — — (35,925 ) Legal entity reorganization (17,566 ) 39,336 — Change in valuation allowance 162,213 (75,196 ) (32,665 ) Other permanent differences 722 340 — Total income tax expense (benefit) $ 35,583 $ (36,141 ) $ 2,922 Effective tax rate (8.27 )% (159.99 )% 1.30 % 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 regulations under Sec. 163(j) of the Internal Revenue Code for tax years ended December 31, 2018 and December 31, 2019. The adoption of the final 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, 2020 2019 Deferred tax assets: Federal net operating loss $ 133,804 $ 131,204 Foreign tax loss carryforward 45,980 2,316 State net operating loss 25,740 24,270 Asset retirement obligations 106,604 89,059 Tax credits 522 449 Derivatives 16,346 2,794 Other well equipment inventory 9,470 10,014 Accrued bonus 3,069 3,753 Operating lease liabilities 4,904 2,317 Other 7,727 7,004 Total deferred tax assets 354,166 273,180 Valuation allowance (178,998 ) (19,118 ) Total deferred tax assets, net $ 175,168 $ 254,062 Deferred tax liabilities: Oil and gas properties $ 170,596 $ 211,216 Deferred financing 1,765 3,752 Operating lease assets 1,652 1,814 Prepaid 3,216 3,419 Total deferred tax liabilities 177,229 220,201 Net deferred tax asset (liability) $ (2,061 ) $ 33,861 Net Operating Loss The table below presents the details of the Company’s net operating loss carryovers as of December 31, 2020 (in thousands): Amount Expiration Year Federal net operating losses $ 537,938 2035 - 2037 Federal net operating losses $ 99,223 Unlimited Foreign tax loss carryforward $ 153,266 2025 - 2030 State net operating losses $ 400,568 2025 - 2040 As of December 31, 2020, the Company had U.S. federal net operating loss carryforwards (“NOLs”) of approximately Valuation Allowance The Company recorded a valuation allowance of $179.0 million and $19.1 million as of December 31, 2020 and 2019, 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. Through the third quarter of 2020 and year ended December 31, 2019, the Company maintained a valuation allowance related to certain state and foreign deferred tax assets. The Company did not maintain a valuation allowance against its federal deferred tax assets and a significant portion of its state deferred tax assets due to the sustained positive operating performance during the most recent three-year period and the availability of expected future taxable income. During the fourth quarter of 2020, the Company recorded a write down of oil and natural gas properties of $267.9 million, which resulted in the Company having a cumulative loss for the most recent three-year 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, 2020 2019 Total unrecognized tax benefits, beginning balance $ 791 $ 360 Increases in unrecognized tax benefits as a result of: Tax positions taken during a prior period (208 ) 8 Tax positions taken during the current period 65 423 Settlements with taxing authorities — — Lapse of applicable statute of limitations — — Total unrecognized tax benefits, ending balance $ 648 $ 791 The Company recognizes interest and penalties related to uncertain tax positions as interest expense and general and administrative expenses, respectively. Years Open to Examination The 2017 through 2019 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, 2016 are closed (except to the extent of any NOL carryover balance).

Income (Loss) Per Share

Income (Loss) Per Share	12 Months Ended
	Dec. 31, 2020
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 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, 2020 2019 2018 (1) Net income (loss) $ (465,605 ) $ 58,729 $ 221,540 Weighted average common shares outstanding — basic 67,664 54,185 46,058 Dilutive effect of securities — 228 3 Weighted average common shares outstanding — diluted 67,664 54,413 46,061 Net income (loss) per common share: Basic $ (6.88 ) $ 1.08 $ 4.81 Diluted $ (6.88 ) $ 1.08 $ 4.81 Anti-dilutive potentially issuable securities excluded from diluted common shares (2) 5,019 4,220 3,538 (1) For the periods prior to May 10, 2018, the Company retrospectively adjusted the weighted average shares used in determining earnings per share to reflect the number of shares Talos Energy LLC received in the Stone Combination. (2) Includes 3.5 million warrants

Related Party Transactions

Related Party Transactions	12 Months Ended
	Dec. 31, 2020
Related Party Transactions [Abstract]
Related Party Transactions	Note 11 — Related Party Transactions 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, for $459.3 million (comprised of $303.1 million in net cash paid and $156.2 million in Conversion Stock). See additional details in Note 3 – Acquisitions. Whistler Acquisition On August 31, 2018, the Company acquired certain properties from Whistler Energy II Holdco, LLC, an affiliate of the Apollo Funds, for $52.6 million ($14.8 million, net of $37.8 million of cash acquired). Included in current assets acquired as of December 31, 2020 is $1.1 million in receivables from an affiliate of the Apollo Funds to reimburse the Company for certain payments made post-closing. See additional details in Note 3 – Acquisitions. 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 and certain clients of MacKay Shields LLC, 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 we 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 we conduct 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 has terminated with respect to Franklin and will terminate with respect to MacKay Shields in the event that MacKay Shields ceases to beneficially own 5% or more of the then outstanding shares of the Company’s common stock. 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. Fees incurred by the Company in conjunction with the Original Equity Registration Rights Agreement were $0.2 million, $0.7 million and $1.8 million for the fiscal years ended December 31, 2020, 2019 and 2018, respectively. 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. 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 Vinson & Elkins L.L.P. For the years ended December 31, 2020, 2019 and 2018 approximately 4.2 Service Fee Agreement The Company entered into service fee agreements with Apollo Funds and Riverstone Funds for the provision of certain management consulting and advisory services. Under each agreement, the Company paid a fee equal to the higher of (i) a certain percentage of earnings before interest, income taxes, depletion, depreciation and amortization and (ii) a fixed fee payable quarterly, provided, however, such fees did not exceed in each case $0.5 million, in aggregate, for any calendar year. For the years ended December 31, 2020, 2019 and 2018, the Company incurred approximately nil, nil and $0.5 million, respectively, for these services. These fees are recognized in “General and administrative expense” on the Consolidated Statements of Operations. In connection with the Stone Combination on May 10, 2018, the Service Fee Agreement was terminated. Debt Modification Work Fees In 2018, the Company paid $9.3 million in work fees to holders of the 11.00% Bridge Loans and 7.50% Notes to exchange into 11.00% Notes as a result of the Stone Combination. The Apollo Funds and Riverstone Funds received $4.1 million and the Franklin Noteholders and McKay Noteholders received $3.3 million as a result of the work fees paid.

Commitments and Contingencies

Commitments and Contingencies	12 Months Ended
	Dec. 31, 2020
Commitments And Contingencies Disclosure [Abstract]
Commitments and Contingencies	Note 12 — Commitments and Contingencies Legal Proceedings and Other Contingencies The Company is named as a party in certain lawsuits and regulatory proceedings arising in the ordinary course of business. The Company does not expect that these matters, individually or in the aggregate, will have a material adverse effect on its financial condition. Performance Obligations Regulations with respect to offshore operations govern, among other things, engineering and construction specifications for production facilities, safety procedures, plugging and abandonment of wells, removal of facilities and to guarantee the execution of the minimum work program under the Mexico production sharing contracts. As of December 31, 2020 and 2019, the Company had secured performance bonds totaling approximately $651.8 million and $637.3 million, respectively. As of December 31, 2020 and 2019, the Company had $13.6 million and $13.6 million, respectively, in letters of credit issued under its Bank Credit Facility. The table below summarizes the Company’s total minimum commitments associated with vessel commitments and purchase obligations as of December 31, 2020 (in thousands): 2021 2022 2023 2024 Thereafter Total Vessel Commitments (1) $ 800 $ — $ — $ — $ — $ 800 Committed purchase orders (2) 2,165 — — — — 2,165 Total $ 2,965 $ — $ — $ — $ — $ 2,965 (1) (2)

Selected Quarterly Financial Da

Selected Quarterly Financial Data	12 Months Ended
	Dec. 31, 2020
Quarterly Financial Information Disclosure [Abstract]
Selected Quarterly Financial Data (Unaudited)	Note 13 —Selected Quarterly Financial Data (Unaudited) Unaudited quarterly financial data are as follows (in thousands): March 31 June 30 September 30 December 31 Quarter Ended 2020 Revenues $ 187,764 $ 88,874 $ 135,137 $ 175,711 Write-down of oil and natural gas properties $ 57 $ — $ — $ 267,859 Operating income (expense) $ (4,212 ) $ (94,603 ) $ (37,059 ) $ (285,436 ) Price risk management activities income (expense) $ 243,217 $ (68,682 ) $ (19,882 ) $ (66,968 ) Net income (loss) $ 157,749 $ (140,611 ) $ (52,000 ) $ (430,743 ) Net income (loss) per common share: Basic $ 2.71 $ (2.14 ) $ (0.73 ) $ (5.73 ) Diluted $ 2.69 $ (2.14 ) $ (0.73 ) $ (5.73 ) Weighted average common shares outstanding: Basic 58,240 65,807 71,286 75,199 Diluted 58,572 65,807 71,286 75,199 Quarter Ended 2019 Revenues $ 178,713 $ 286,810 $ 228,857 $ 233,240 Operating income $ 18,369 $ 94,872 $ 52,883 $ 46,970 Price risk management activities income (expense) $ (109,579 ) $ 29,990 $ 43,760 $ (59,508 ) Net income (loss) $ (109,636 ) $ 94,764 $ 73,297 $ 304 Net income (loss) per common share: Basic $ (2.02 ) $ 1.75 $ 1.35 $ 0.01 Diluted $ (2.02 ) $ 1.74 $ 1.35 $ 0.01 Weighted average common shares outstanding: Basic 54,156 54,178 54,200 54,203 Diluted 54,156 54,451 54,430 54,559

Supplemental Oil and Gas Disclo

Supplemental Oil and Gas Disclosures (Unaudited)	12 Months Ended
	Dec. 31, 2020
Extractive Industries [Abstract]
Supplemental Oil and Gas Disclosures (Unaudited)	Note 14 —Supplemental Oil and Gas Disclosures (Unaudited) Capitalized Costs Aggregate amounts of capitalized costs relating to oil, natural gas and NGL activities and the aggregate amount of related accumulated depletion and amortization as of the dates indicated are presented below (in thousands): Year Ended December 31, 2020 2019 Proved properties $ 4,945,550 $ 4,066,260 Unproved oil and gas properties, not subject to amortization (1) 254,994 194,532 Total oil and gas properties 5,200,544 4,260,792 Less: Accumulated depletion (2,680,254 ) (2,051,856 ) Net capitalized costs $ 2,520,290 $ 2,208,936 Depletion and amortization rate (Per Boe) $ 31.42 $ 18.05 (1) Amount includes $121.7 million and $106.9 million of unproved properties, not subject to amortization related to the Company’s Mexico properties for the years ended December 31, 2020 and 2019, respectively Included in the depletable basis of proved oil and gas properties is the estimate of the Company’s proportionate share of asset retirement costs relating to these properties which are also reflected as “Asset retirement obligations” in the accompanying Consolidated Balance Sheets. At December 31, 2020 and 2019, the Company’s liability for oil and gas asset retirement obligations totaled $442.3 million and $369.5 million, respectively. 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 cost estimates during the year. Year Ended December 31, 2020 2019 2018 Property acquisition costs: Proved properties $ 422,833 $ 27,660 $ 850,515 Unproved properties, not subject to amortization 95,242 16,062 65,063 Total property acquisition costs 518,075 43,722 915,578 Exploration costs (1) 59,422 209,161 93,780 Development costs 362,011 292,547 215,467 Total costs incurred $ 939,508 $ 545,430 $ 1,224,825 (1) Amount includes $14.6 million, $74.2 million and $16.9 million of exploration costs related to the Company’s Mexico properties for the year ended December 31, 2020, 2019 and 2018, 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, At, December 31, 2020, 2019 and 2018, 100% of proved oil, natural gas and NGL reserves attributable to all of the Company’s oil and natural gas properties were estimated and compiled for reporting purposes by the Company’s reservoir engineers and audited by Netherland, Sewell & Associates, Inc. (“NSAI”), independent petroleum engineers and geologists. The following table presents the Company’s estimated proved reserves at its net ownership interest: Oil (MBbls) Gas (MMcf) NGL (MBbls) Oil Equivalent (MBoe) Total proved reserves at December 31, 2017 72,804 127,656 6,547 100,625 Revision of previous estimates 2,595 (37,933 ) 3,187 (539 ) Production (11,771 ) (22,771 ) (1,176 ) (16,742 ) Purchases of reserves 44,788 95,661 2,074 62,806 Extensions and discoveries 4,123 8,411 64 5,589 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 (1) (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 (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 Total proved developed reserves as of: December 31, 2018 85,530 131,364 8,104 115,528 December 31, 2019 72,016 115,381 6,733 97,979 December 31, 2020 85,007 204,054 8,104 127,120 Total proved undeveloped reserves as of: December 31, 2018 27,009 39,660 2,592 36,211 December 31, 2019 34,738 40,617 2,248 43,756 December 31, 2020 24,300 53,154 2,754 35,913 (1) Excludes approximately 3.0 MBoe of Mexico well test production 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 and differentials. 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. During 2018, the Company added 51.1 MMBoe of estimated proved reserves, which included 62.8 MMBoe added through purchases of 59.3 MMBoe from the Stone Combination and 3.5 MMBoe from the Whistler Acquisition. The Company also added 5.6 MMBoe of estimated proved reserves from extensions and discoveries primarily from an evaluation of Green Canyon Block 18. The increase was partially offset by a decrease of 16.7 MMBoe of production. 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, 2020 2019 2018 Future cash inflows $ 4,927,497 $ 7,151,875 $ 8,654,631 Future costs: Production (1,105,211 ) (1,633,432 ) (1,740,850 ) Development and abandonment (1,236,874 ) (1,464,270 ) (1,349,005 ) Future net cash flows before income taxes 2,585,412 4,054,173 5,564,776 Future income tax expense (141,515 ) (662,317 ) (862,473 ) Future net cash flows after income taxes 2,443,897 3,391,856 4,702,303 Discount at 10% annual rate (538,963 ) (854,261 ) (1,362,057 ) Standardized measure of discounted future net cash flows $ 1,904,934 $ 2,537,595 $ 3,340,246 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, 2020 2019 2018 Oil price per Bbl $ 39.47 $ 61.01 $ 69.42 Natural gas price per Mcf $ 1.97 $ 2.59 $ 3.08 NGL price per Bbl $ 9.89 $ 26.17 $ 29.50 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, 2020 2019 2018 Standardized measure, beginning of year $ 2,537,595 $ 3,340,246 $ 1,807,669 Sales and transfers of oil, net gas and NGLs produced during the period (339,557 ) (665,226 ) (727,969 ) Net change in prices and production costs (1,468,304 ) (849,696 ) 1,578,330 Changes in estimated future development costs 32,589 (75,564 ) 32,328 Previously estimated development costs incurred 46,143 117,049 45,937 Accretion of discount 299,302 392,526 180,767 Net change in income taxes 361,875 129,590 (585,017 ) Purchases of reserves 730,611 75,009 943,519 Extensions and discoveries 71,589 306,515 148,068 Net change due to revision in quantity estimates (309,338 ) (199,576 ) 190,853 Changes in production rates (timing) and other (57,571 ) (33,278 ) (274,239 ) Standardized measure, end of year $ 1,904,934 $ 2,537,595 $ 3,340,246 F-42

Subsequent Events

Subsequent Events	12 Months Ended
	Dec. 31, 2020
Subsequent Events [Abstract]
Subsequent Events	Note 15 —Subsequent Events Debt For additional information, see Note 7 – Debt.

Summary of Significant Accoun_2

Summary of Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2020
Organization Consolidation And Presentation Of Financial Statements [Abstract]
Formation and Nature of Business	Formation and Nature of Business Talos Energy Inc. (“Talos” or the “Company”) is a technically driven independent exploration and production company focused on safely and efficiently maximizing value through its operations, currently in the United States (“U.S.”) Gulf of Mexico and offshore Mexico. The Company leverages decades of geology, geophysics and offshore operations expertise towards the acquisition, exploration, exploitation and development of assets in key geological trends that are present in many offshore basins around the world. Talos Energy Inc. was formed in connection with the previously disclosed business combination between Talos Energy LLC and Stone Energy Corporation (“Stone”) that occurred on May 10, 2018, pursuant to which Talos Energy LLC and Stone became indirect wholly owned subsidiaries of Talos Energy Inc. Talos Energy LLC — Talos Energy LLC was formed in 2011 and commenced commercial operations on February 6, 2013. Prior to February 6, 2013, Talos Energy LLC had incurred certain general and administrative expenses associated with the start-up of its operations. 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. Stone Combination — On May 10, 2018 (the “Stone Closing Date”), the Company (f/k/a Sailfish Energy Holdings Corporation) consummated the transactions contemplated by that certain Transaction Agreement, dated as of November 21, 2017 (the “Transaction Agreement”), by and among Stone, the Company, Sailfish Merger Sub Corporation (“Merger Sub”), Talos Energy LLC and Talos Production LLC (which was converted into a Delaware Corporation and named Talos Production Inc. in 2019), pursuant to which, among other items, each of Stone, Talos Production LLC and Talos Energy LLC became wholly-owned subsidiaries of the Company (the “Stone Combination”). Prior to the Stone Closing Date, the Company did not conduct any material activities other than those incident to its formation and the matters contemplated by the Transaction Agreement. On the Stone Closing Date, the following transactions, among others, occurred: (i) Stone underwent a reorganization pursuant to which Merger Sub merged with and into Stone, with Stone continuing as the surviving corporation and a direct wholly-owned subsidiary of the Company (the “Merger”) and each share of Stone’s common stock outstanding immediately prior to the Merger (other than treasury shares held by Stone, which were cancelled for no consideration) was converted into the right to receive one share of the Company’s common stock, par value $0.01 (the “Common Stock”) and (ii) the Sponsors contributed all of the equity interests in Talos Production LLC (which at that time owned 100% of the equity interests in Talos Energy LLC) to the Company in exchange for an aggregate of 31,244,085 shares of Common Stock (the “Sponsor Equity Exchange”). Concurrently with the consummation of the Transaction Agreement, the Company consummated the transactions contemplated by that certain Exchange Agreement, dated as of November 21, 2017 (the “Exchange Agreement”), among the Company, Stone, the Talos Issuers (defined below), the various lenders and noteholders of the Talos Issuers listed therein, certain funds controlled by Franklin Advisers, Inc. (“Franklin”) (such controlled noteholders, the “Franklin Noteholders”), and certain clients of MacKay Shields LLC (“MacKay Shields”) (such noteholders, the “MacKay Noteholders”), pursuant to which (i) the Apollo Funds and Riverstone Funds contributed $102.0 million in aggregate principal amount of 9.75% Senior Notes due 2022 (“9.75% Senior Notes”) issued by Talos Production LLC and Talos Production Finance, Inc. (together, the “Talos Issuers”) to the Company in exchange for an aggregate of 2,874,049 shares of Common Stock (the “Sponsor Debt Exchange”); (ii) the holders of second lien bridge loans (“11.00% Bridge Loans”) issued by the Talos Issuers exchanged such 11.00% Bridge Loans for $172.0 million aggregate principal amount of 11.00% Second-Priority Senior Secured Notes due 2022 of the Talos Issuers (“11.00% Notes”) and (iii) Franklin Noteholders and MacKay Noteholders exchanged their 7.50% Senior Notes due 2022 issued by Stone (“7.50% Notes”) for $137.4 million aggregate principal amount of 11.00% Notes. Substantially concurrent therewith, the Company consummated an exchange offer and consent solicitation, pursuant to which the holders of the 7.50% Notes, excluding the 7.50% Notes held by the Franklin Noteholders and the MacKay Noteholders, exchanged their 7.50% Notes for 11.00% Notes and a cash payment, and a solicitation of consents to proposed amendments to the 7.50% Notes. Approximately $81.5 million in aggregate principal amount of the 7.50% Notes were validly tendered, and approximately $6.1 million in aggregate principal amount of 7.50% Notes remained outstanding as of the Stone Closing Date. As a result of the closing of the transactions contemplated by the Transaction Agreement and the Exchange Agreement (the “Transactions”) the former stakeholders of Talos Energy LLC held approximately 63% of the Company’s outstanding Common Stock and the former stockholders of Stone held approximately 37% of the Company’s outstanding Common Stock as of the Stone Closing Date.
Basis of Presentation and Consolidation	Basis of Presentation and Consolidation The Consolidated Financial Statements have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”) and include 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 are reflected herein. The Company has evaluated subsequent events through the date the Consolidated Financial Statements were issued. Talos Energy LLC was considered the accounting acquirer in the Stone Combination under GAAP. Accordingly, the historical financial and operating data of Talos Energy Inc., which covers periods prior to the Stone Closing Date, reflects the assets, liabilities and results of operations of Talos Energy LLC and does not reflect the assets, liabilities and results of operations of Stone. For the periods prior to May 10, 2018, the Company retrospectively adjusted its Consolidated Statement of Changes in Stockholders’ Equity and the weighted average shares used in determining earnings per share to reflect the number of shares Talos Energy LLC received in the Stone Combination. Beginning on May 10, 2018, common stock is presented to reflect the legal capital of Talos Energy Inc. 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. For presentation purposes, as of December 31, 2020, operating expenses previously presented as “Direct lease operating expense,” “Insurance” and “Workover and maintenance expense” have been combined and presented as “Lease operating expense” on the Company’s Consolidated Statements of Operations. Such reclassification had no effect on our results of operations, financial position or cash flows. The Company has one reportable segment, which is the exploration and production of oil, natural gas and NGLs. Substantially all the Company’s long-lived assets, proved reserves and production sales are related to the Company’s operations in the United States.
Recently Adopted Or Issued Accounting Standards	Recently Adopted Accounting Standards Credit Risk Losses — In June 2016, the Financial Accounting Standards Board issued ASU 2016-13, Financial Instruments - Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments, which changes accounting requirements for the recognition of credit losses from an incurred or probable impairment methodology to a current expected credit losses (“CECL”) methodology. The CECL model is applicable to the measurement of credit losses on financial assets measured at amortized cost, including, but not limited to trade receivables. The guidance was adopted on January 1, 2020 using a modified retrospective approach. The adoption of this guidance did not have a material effect on the Company’s Consolidated Financial Statements or related disclosures. Accounts receivable resulting from the sale of crude oil, natural gas and NGL production and joint interest billings to our partners for their share of expenditures on joint venture projects for which we are the operator are the primary financial assets within the scope of the standard. Although these receivables are from a diverse group of companies, including major energy companies, pipeline companies and joint interest owners, they are concentrated in the oil and gas industry. This concentration has the potential to impact our overall exposure to credit risk in that these companies may be similarly affected by changes in economic and financial conditions, commodity prices or other conditions. 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. At each reporting period the loss-rate is determined utilizing historical data, current market conditions and reasonable and supported forecast of future economic conditions. Our allowance for uncollectable receivables was $9.2 million at December 31, 2020 and $9.9 million at December 31, 2019. Guarantor Financial Information — In March 2020, the SEC adopted final rules that simplify the disclosure requirements related to certain registered securities under SEC Regulation S-X, Rules 3-10 and 3-16, permitting registrants to provide certain alternative financial disclosures and non-financial disclosures in lieu of separate Consolidated Financial Statements for subsidiary issuers and guarantors of registered debt securities (which the Company previously presented within the notes to the Financial Statements included in its Annual Report on Form 10-K and Quarterly Reports on Form 10-Q) if certain conditions are met. The disclosure requirements, as amended, are now located in newly created Rules 13-01 and 13-02 of Regulation S-X and are generally effective for filings on or after January 4, 2021, with early adoption permitted. The Company early adopted the new disclosure requirements effective as of July 1, 2020 and are providing the summarized financial information and related disclosures in Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations in this Form 10-K.
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 Uncollectible Accounts	Accounts Receivable and Allowance for Uncollectible Accounts — Accounts receivable are stated at the historical carrying amount net of an allowance for uncollectible accounts of $9.2 million at December 31, 2020 and $9.9 million at December 31, 2019. 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. The Company presented $19.1 million and $18.0 million of refund claims for value added taxes paid in Mexico in “Other assets” on the Consolidated Balance Sheets as of December 31, 2020 and 2019, respectively.
Prepaid Assets	Prepaid Assets — Prepaid assets primarily represent deposits with the Office of Natural Resources Revenue (“ONRR”) and transaction escrow related to the ILX and Castex Acquisition as further defined in Note 3 — Acquisitions. 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. The transaction escrow was applied to the purchase price that closed in the first quarter of 2020. The escrow for the years ended December 31, 2020 and 2019 were nil and $31.8 million, respectively.
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 recorded gross on our Consolidated Balance Sheets. At December 31, 2020 and 2019, our imbalance receivable was approximately $1.7 million and $1.7 million, respectively, and imbalance payable was approximately $3.6 million and $3.6 million, respectively. Production Handling Fees — The Company presented 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 in “Other” within “Revenues and Other” 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, 2020, 2019 and 2018 were $8.9 million, $19.3 million and nil, 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 quarterly. 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 percent, plus the lower of cost or estimated fair value of unproved oil and natural gas properties not being amortized less the related tax effects. 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, computer hardware and software. Acquisitions, renewals 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 this inventory is supplied to wells, the cost of this inventory 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 inventory is stated at the lower of cost or net realizable value. The Company recorded $0.7 million, $0.2 million, and $0.2 million of impairment to adjust inventory to net realizable value, which was expensed and reflected in lease operating expense, during the years ended December 31, 2020, 2019 and 2018, respectively.
Fair Value Measure of Financial Instruments	Fair Value Measure of Financial Instruments — Financial instruments generally consist of cash and cash equivalents, restricted cash, accounts receivable, commodity derivatives, accounts payable and debt. The carrying amount of cash and cash equivalents, restricted cash, 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 “A ccretion expense ” in the Company’s C onsolidated S tatements of O perations. If the Company incurs an amount different from the amount accrued for decommissioning obligations, the Company recognizes the difference as an adjustment to proved properties.
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)” in 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 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, we generally use our 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 we will exercise that option. The Company has elected to not apply the recognition requirements of Topic 842 to leases with durations of twelve months or less (i.e. short-term).
Income Taxes	Income Taxes — Prior to the Stone Combination, Talos Energy LLC was a partnership for U.S. federal income tax purposes and was not subject to U.S. federal income tax or state income tax (in most states) at the entity level. As such, Talos Energy LLC did not recognize U.S. federal income tax expense or state income tax expense in most states. In connection with the Stone Combination, Talos Energy LLC was contributed to the Company, which is subject to U.S. federal and state 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. Changes in tax laws are recorded in the period they are 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	Share-Based Compensation — Certain of the Company’s employees participate in its equity based compensation. The Company measures all employee equity based compensation awards at fair value as calculated using an option pricing method for valuing such securities on the date awards are granted to its employees and recognize compensation cost on a straight-line basis in the Company’s financial statements over the vesting period of each grant according to ASC 718, Compensation—Stock Compensation. During 2020, the Company issued RSUs and PSUs to certain employees and non-employee directors. The fair value of the stock-based awards is determined at the date of grant and is not remeasured for awards classified as equity, 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 RSUs — Share-based compensation is based on the market price of the Company’s Common Stock on the grant date and recognized over the vesting period using the straight-line method as the requisite service period is fulfilled. PSUs — Share-based compensation is based on the grant date fair value determined using a Monte Carlo valuation model and recognized over the vesting 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 and balances are maintained i n financial institutions, which at times, exceed federally insured limits. The Company monitor s 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, 2020 2019 2018 Shell Trading (US) Company 47 % 58 % 65 % Phillips 66 22 % 28 % 18 % Chevron Products Company 12 % ** ** ** Less than 10% The loss of a major customer could have material adverse effect on the Company in the short term. However, the Company believes it would be able to obtain other customers to market its oil, natural gas and NGL production.

Summary of Significant Accoun_3

Summary of Significant Accounting Policies (Tables)	12 Months Ended
	Dec. 31, 2020
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, 2020 2019 2018 Shell Trading (US) Company 47 % 58 % 65 % Phillips 66 22 % 28 % 18 % Chevron Products Company 12 % ** ** ** Less than 10%

Acquisitions (Tables)

Acquisitions (Tables)	12 Months Ended
	Dec. 31, 2020
ILX and Castex
Business Acquisition [Line Items]
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, which the Company expects all to be realizable.
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 (1) Represents the closing price of the Company’s common stock on February 28, 2020, the date of the closing 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.
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 for the year ended December 31, 2020: 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
Stone Energy Corporation
Business Acquisition [Line Items]
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 May 10, 2018 (in thousands): Current assets (1) $ 372,963 Property and equipment 886,406 Other long-term assets 19,494 Current liabilities (132,846 ) Long-term debt (235,416 ) Other long-term liabilities (178,637 ) Allocated purchase price $ 731,964 (1) Includes $293.0 million of cash acquired. The fair values of current assets acquired includes trade receivables and joint interest receivables of $43.3 million and $3.5 million, respectively, which the Company expects all to be realizable.
Summary of Purchase Price	The following table summarizes the purchase price (in thousands, except per share data): Stone Energy common stock - issued and outstanding as of May 9, 2018 20,038 Stone Energy common stock price $ 35.49 Common stock value $ 711,149 Stone Energy common stock warrants - issued and outstanding as of May 9, 2018 3,528 Stone Energy common stock warrants price $ 5.90 Common stock warrants value $ 20,815 Total purchase price $ 731,964
Summary of Revenue and Net Income Attributable to Assets Acquired	The follow table presents revenue and net income attributable to the assets acquired in the Stone Combination for the years ended December 31, 2020, 2019 and 2018: Year Ended December 31, 2020 2019 2018 Revenue $ 187,211 414,056 332,944 Net income (loss) $ (1,232 ) 187,428 148,473
Supplemental Proforma Information	The following supplemental pro forma information (in thousands, except per common share amounts), presents the consolidated results of operations for the year ended December 31, 2018 as if the Stone Combination had occurred on January 1, 2018. The unaudited pro forma information was derived from historical statements of operations of the Company and Stone and adjusted to include (i) depletion and accretion expense applied to the adjusted basis of the oil and natural gas properties acquired, (ii) interest expense to reflect the debt transactions contemplated by the Exchange Agreement and (iii) general and administrative expense adjusted for transaction related costs incurred. This information does not purport to be indicative of results of operations that would have occurred had the Stone Combination occurred on January 1, 2018, nor is such information indicative of any expected future results of operations. Year Ended December 31, 2018 Revenue $ 1,013,184 Net income $ 274,577 Basic net income per common share $ 5.07 Diluted net income per common share $ 5.07
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 (1) Represents the closing price of the Company’s common stock on August 5, 2020, the date of the closing of the Castex Energy 2005 Acquisition.
Gunflint 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 January 11, 2019 (in thousands): Property and equipment $ 28,912 Asset retirement obligations (996 ) Allocated purchase price $ 27,916
Whistler Energy II, LLC
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 31, 2018 (in thousands): Current assets (1) $ 45,337 Property and equipment 35,344 Other long-term assets 66 Current liabilities (4,261 ) Asset retirement obligations (23,862 ) Allocated purchase price $ 52,624 (1) Includes $37.8 million of cash acquired and trade receivables of $3.2 million, which the Company expects all to be realizable.

Property, Plant and Equipment (

Property, Plant and Equipment (Tables)	12 Months Ended
	Dec. 31, 2020
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, 2020, by the year in which such costs were incurred (in thousands): Year Ended December 31, Total 2020 2019 2018 2017 and Prior Acquisition United States $ 80,799 $ 61,315 $ 3,268 $ 16,216 $ — Exploration United States 52,470 12,714 32,698 5,761 1,297 Exploration Mexico 121,725 14,811 61,809 14,362 30,743 Total unproved properties, not subject to amortization $ 254,994 $ 88,840 $ 97,775 $ 36,339 $ 32,040
Schedule of Asset Retirement Obligations	Asset Retirement Obligations The discounted asset retirement obligations included in the Consolidated Balance Sheets in current and non-current liabilities, and the changes in that liability during each of the years ended December 31, 2020 and 2019 were as follows (in thousands): Year Ended December 31, 2020 2019 Asset retirement obligations at January 1 $ 369,478 $ 382,817 Fair value of asset retirement obligations acquired (1) 44,311 5,047 Obligations settled (43,933 ) (75,331 ) Fair value of asset retirement obligations divested (185 ) (5,450 ) Accretion expense 49,741 34,389 Obligations incurred 4,511 4,111 Changes in estimate 18,346 23,895 Asset retirement obligations at December 31 $ 442,269 $ 369,478 Less: Current portion (49,921 ) (61,051 ) Long-term portion $ 392,348 $ 308,427 (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, 2020
Leases [Abstract]
Components of Lease Costs	The components of lease costs were as follows (in thousands): Year Ended December 31, 2020 2019 Finance lease cost - interest on lease liabilities (1) $ 15,748 $ 19,115 Operating lease cost, excluding short-term leases (2) 3,361 3,261 Short-term lease cost (3) 53,573 85,865 Variable lease cost (4) 543 11 Total lease cost $ 73,225 $ 108,252 (1) The Helix Producer I (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 reserved using the unit-of-production method, computed quarterly. (2) 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. (3) 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. (4) 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 are as follows (in thousands): Year Ended December 31, 2020 2019 Operating leases: Operating lease assets $ 6,855 $ 7,779 Current portion of operating lease liabilities $ 1,793 $ 1,594 Operating lease liabilities 18,554 17,239 Total operating lease liabilities $ 20,347 $ 18,833 Finance leases: Proved property (1) $ 124,299 $ 124,299 Other current liabilities $ 21,804 $ 17,509 Other long-term liabilities 40,222 62,026 Total finance lease liabilities $ 62,026 $ 79,535 (1) 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.
Schedule of Lease Maturity	The table below presents the lease maturity by year as of December 31, 2020 (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 2021 $ 4,079 $ 33,257 2022 4,302 33,257 2023 4,239 13,857 2024 3,315 — 2025 3,293 — Thereafter 12,497 — Total lease payments $ 31,725 $ 80,371 Imputed interest (11,378 ) (18,345 ) Total $ 20,347 $ 62,026
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 for the years ended December 31, 2020 and 2019: Year Ended December 31, 2020 2019 Weighted average remaining lease term: Operating leases 7.8 years 8.4 years Finance leases 2.4 years 3.4 years Weighted average discount rate: Operating leases 12.0 % 10.2 % Finance leases 21.9 % 21.9 %
Supplemental Cash Flow Information Related to Leases	The table below presents the supplemental cash flow information related to leases for the years ended December 31, 2020 and 2019 (in thousands): Year Ended December 31, 2020 2019 Operating cash outflow from finance leases $ 15,748 $ 19,115 Financing cash outflow from finance leases $ 17,509 $ 14,133 Operating cash outflow from operating leases $ 2,648 $ 1,812 Right-of-use assets obtained in exchange for new operating lease liabilities $ — $ 2,225

Financial Instruments (Tables)

Financial Instruments (Tables)	12 Months Ended
	Dec. 31, 2020
Financial Instruments [Abstract]
Schedule of Carrying Amounts and Estimated Fair Values of Financial Instruments	The following table presents the carrying amounts and estimated fair values of the Company’s financial instruments (in thousands): December 31, 2020 December 31, 2019 Carrying Amount Fair Value Carrying Amount Fair Value 11.00% Second-Priority Senior Secured Notes – due April 2022 (1) $ 343,579 $ 355,935 $ 383,871 $ 401,128 7.50% Senior Notes – due May 2022 $ 6,060 $ 5,238 $ 6,060 $ 5,030 Bank Credit Facility – matures May 2022 (1) $ 635,873 $ 640,000 $ 343,050 $ 350,000 Oil and Natural Gas Derivatives $ (67,814 ) $ (67,814 ) $ (11,594 ) $ (11,594 ) (1) The carrying amounts are net of discount and deferred financing costs.
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 qualifying as hedging instruments, had on its Consolidated Statements of Operations (in thousands): Year Ended December 31, 2020 2019 2018 Net cash received (paid) on settled derivative instruments $ 143,905 $ (8,820 ) $ (111,147 ) Unrealized gain (loss) (56,220 ) (86,517 ) 171,582 Price risk management activities income (expense) $ 87,685 $ (95,337 ) $ 60,435
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 the Company will receive under the terms of its derivative contracts as of December 31, 2020: Production Period Instrument Type Average Daily Volumes Weighted Average Swap Price Weighted Average Put Price Weighted Average Call Price Crude Oil – WTI: (Bbls) (per Bbl) (per Bbl) (per Bbl) January 2021 – December 2021 Swaps 22,948 $ 43.20 $ — $ — January 2021 – December 2021 Collars 1,000 $ — $ 30.00 $ 40.00 January 2022 – December 2022 Swaps 10,616 $ 44.45 $ — $ — Crude Oil – LLS: (Bbls) (per Bbl) (per Bbl) (per Bbl) January 2021 – December 2021 Swaps 3,000 $ 38.83 $ — $ — Natural Gas – NYMEX Henry Hub: (MMBtu) (per MMBtu) (per MMBtu) (per MMBtu) January 2021 – December 2021 Swaps 58,907 $ 2.56 $ — $ — January 2021 – December 2021 Collars 5,000 $ — $ 2.50 $ 3.10 January 2022 – December 2022 Swaps 29,649 $ 2.60 $ — $ — January 2023 – June 2023 Swaps 5,000 $ 2.61 $ — $ —
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, 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 ) December 31, 2019 Level 1 Level 2 Level 3 Total Assets: Oil and natural gas swaps and costless collars $ — $ 8,393 $ — $ 8,393 Liabilities: Oil and natural gas swaps and costless collars — (19,987 ) — (19,987 ) Total net liability $ — $ (11,594 ) $ — $ (11,594 )
Schedule of Fair Value of Derivative Financial Instruments	The following table presents the fair value of derivative financial instruments at December 31, 2020 and 2019 (in thousands): December 31, 2020 December 31, 2019 Assets Liabilities Assets Liabilities Oil and natural gas derivatives: Current $ 6,876 $ 66,010 $ 8,393 $ 19,476 Non-current 945 9,625 — 511 Total $ 7,821 $ 75,635 $ 8,393 $ 19,987

Debt (Tables)

Debt (Tables)	12 Months Ended
	Dec. 31, 2020
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, 2020 2019 11.00% Second-Priority Senior Secured Notes – due April 2022 $ 347,254 $ 390,868 7.50% Senior Notes – due May 2022 6,060 6,060 Bank Credit Facility – matures May 2022 640,000 350,000 Total debt, before discount and deferred financing cost 993,314 746,928 Discount and deferred financing cost (7,802 ) (13,947 ) Total debt, net of discount and deferred financing costs $ 985,512 $ 732,981

Employee Benefits Plans and S_2

Employee Benefits Plans and Share-Based Compensation (Tables)	12 Months Ended
	Dec. 31, 2020
Disclosure Of Compensation Related Costs Sharebased Payments [Abstract]
Summary of Restricted Stock Units Activity	The following table summarizes RSU activity for the years ended December 31, 2020, 2019 and 2018: Restricted Stock Units Weighted Average Grant Date Fair Value Unvested RSUs at December 31, 2017 — $ — Granted 139,411 $ 33.85 Vested (53 ) $ 32.86 Forfeited (654 ) $ 32.86 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
Summary of Performance Share Units Activity	The following table summarizes PSU activity for the years ended December 31, 2020, 2019 and 2018: Performance Share Units Weighted Average Grant Date Fair Value Unvested PSUs at December 31, 2017 — $ — Granted 232,891 $ 44.47 Vested — $ — Forfeited (1,349 ) $ 42.94 Unvested PSUs at December 31, 2018 231,542 $ 44.47 Granted 218,060 $ 33.96 Vested — $ — Forfeited (31,771 ) $ 40.27 Unvested PSUs at December 31, 2019 417,831 $ 39.31 Granted 441,642 $ 13.05 Vested — $ — Forfeited (25,301 ) $ 37.67 Unvested PSUs at December 31, 2020 834,172 $ 25.46
Summary of Assumptions Used to Calculate the Grant Date Fair Value of PSUs Granted	The following table summarizes the assumptions used to calculate the grant date fair value of the PSUs granted for the years ended December 31, 2020, 2019 and 2018: 2020 Grant Date 2019 Grant Date 2018 Grant Date March 5 March 5 May 16 August 29 September 28 Number of simulations 100,000 100,000 100,000 100,000 100,000 Expected term (in years) 2.8 2.8 2.6 2.7 2.6 Expected volatility 48.8 % 46.9 % 44.8 % 50.6 % 47.4 % Risk-free interest rate 0.6 % 2.5 % 2.1 % 2.7 % 2.9 % Dividend yield — % — % — % — % — %
Schedule of Recognized Share Based Compensation Expense, Net	The Company recognized the following share-based compensation expense, net for the years ended December 31, 2020, 2019 and 2018 (in thousands): Year Ended December 31, 2020 2019 2018 Talos Energy Inc. Long Term Incentive Plan $ 16,227 $ 12,523 $ 2,091 Talos Energy LLC Series B Units 192 256 666 New Talos Energy LLC Series B Units 43 145 3,752 Total share-based compensation expense 16,462 12,924 6,509 Less: amounts capitalized to oil and gas properties (7,793 ) (5,960 ) (3,616 ) Total share-based compensation expense, net $ 8,669 $ 6,964 $ 2,893

Income Taxes (Tables)

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2020
Income Tax Disclosure [Abstract]
Components of Income Tax Expense (Benefit)	Income Tax Expense (Benefit) The components of income tax expense (benefit) were as follows (in thousands): Year Ended December 31, 2020 2019 2018 Current income tax expense (benefit) United States $ (499 ) $ 437 $ — Mexico 185 1,183 1,345 Total current income tax expense (benefit) $ (314 ) $ 1,620 $ 1,345 Deferred income tax expense (benefit) United States $ 35,923 $ (37,131 ) $ 1,064 Mexico (26 ) (630 ) 513 Total deferred income tax expense (benefit) 35,897 (37,761 ) 1,577 Total income tax expense (benefit) $ 35,583 $ (36,141 ) $ 2,922
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, 2020 2019 2018 Income tax expense (benefit) at the federal statutory tax rate $ (90,304 ) $ 4,744 $ 47,137 Earnings not subject to tax — — 9,980 State income taxes (14,215 ) 1,396 11,738 Foreign income taxes — — 1,008 Foreign rate differential (1,030 ) (4,948 ) 432 Prior year taxes (4,237 ) (1,950 ) 417 Other adjustments — 137 800 Change in tax status — — (35,925 ) Legal entity reorganization (17,566 ) 39,336 — Change in valuation allowance 162,213 (75,196 ) (32,665 ) Other permanent differences 722 340 — Total income tax expense (benefit) $ 35,583 $ (36,141 ) $ 2,922 Effective tax rate (8.27 )% (159.99 )% 1.30 %
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, 2020 2019 Deferred tax assets: Federal net operating loss $ 133,804 $ 131,204 Foreign tax loss carryforward 45,980 2,316 State net operating loss 25,740 24,270 Asset retirement obligations 106,604 89,059 Tax credits 522 449 Derivatives 16,346 2,794 Other well equipment inventory 9,470 10,014 Accrued bonus 3,069 3,753 Operating lease liabilities 4,904 2,317 Other 7,727 7,004 Total deferred tax assets 354,166 273,180 Valuation allowance (178,998 ) (19,118 ) Total deferred tax assets, net $ 175,168 $ 254,062 Deferred tax liabilities: Oil and gas properties $ 170,596 $ 211,216 Deferred financing 1,765 3,752 Operating lease assets 1,652 1,814 Prepaid 3,216 3,419 Total deferred tax liabilities 177,229 220,201 Net deferred tax asset (liability) $ (2,061 ) $ 33,861
Summary of Net Operating Loss Carryovers	The table below presents the details of the Company’s net operating loss carryovers as of December 31, 2020 (in thousands): Amount Expiration Year Federal net operating losses $ 537,938 2035 - 2037 Federal net operating losses $ 99,223 Unlimited Foreign tax loss carryforward $ 153,266 2025 - 2030 State net operating losses $ 400,568 2025 - 2040
Summary of Balances In Uncertain Tax Positions	Balances in the uncertain tax positions are as follows (in thousands): Year Ended December 31, 2020 2019 Total unrecognized tax benefits, beginning balance $ 791 $ 360 Increases in unrecognized tax benefits as a result of: Tax positions taken during a prior period (208 ) 8 Tax positions taken during the current period 65 423 Settlements with taxing authorities — — Lapse of applicable statute of limitations — — Total unrecognized tax benefits, ending balance $ 648 $ 791

Income (Loss) Per Share (Tables

Income (Loss) Per Share (Tables)	12 Months Ended
	Dec. 31, 2020
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, 2020 2019 2018 (1) Net income (loss) $ (465,605 ) $ 58,729 $ 221,540 Weighted average common shares outstanding — basic 67,664 54,185 46,058 Dilutive effect of securities — 228 3 Weighted average common shares outstanding — diluted 67,664 54,413 46,061 Net income (loss) per common share: Basic $ (6.88 ) $ 1.08 $ 4.81 Diluted $ (6.88 ) $ 1.08 $ 4.81 Anti-dilutive potentially issuable securities excluded from diluted common shares (2) 5,019 4,220 3,538 (1) For the periods prior to May 10, 2018, the Company retrospectively adjusted the weighted average shares used in determining earnings per share to reflect the number of shares Talos Energy LLC received in the Stone Combination. (2) Includes 3.5 million warrants

Commitments and Contingencies (

Commitments and Contingencies (Tables)	12 Months Ended
	Dec. 31, 2020
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, 2020 (in thousands): 2021 2022 2023 2024 Thereafter Total Vessel Commitments (1) $ 800 $ — $ — $ — $ — $ 800 Committed purchase orders (2) 2,165 — — — — 2,165 Total $ 2,965 $ — $ — $ — $ — $ 2,965 (1) (2)

Selected Quarterly Financial _2

Selected Quarterly Financial Data (Tables)	12 Months Ended
	Dec. 31, 2020
Quarterly Financial Information Disclosure [Abstract]
Schedule Of Unaudited Quarterly Financial Data	Unaudited quarterly financial data are as follows (in thousands): March 31 June 30 September 30 December 31 Quarter Ended 2020 Revenues $ 187,764 $ 88,874 $ 135,137 $ 175,711 Write-down of oil and natural gas properties $ 57 $ — $ — $ 267,859 Operating income (expense) $ (4,212 ) $ (94,603 ) $ (37,059 ) $ (285,436 ) Price risk management activities income (expense) $ 243,217 $ (68,682 ) $ (19,882 ) $ (66,968 ) Net income (loss) $ 157,749 $ (140,611 ) $ (52,000 ) $ (430,743 ) Net income (loss) per common share: Basic $ 2.71 $ (2.14 ) $ (0.73 ) $ (5.73 ) Diluted $ 2.69 $ (2.14 ) $ (0.73 ) $ (5.73 ) Weighted average common shares outstanding: Basic 58,240 65,807 71,286 75,199 Diluted 58,572 65,807 71,286 75,199 Quarter Ended 2019 Revenues $ 178,713 $ 286,810 $ 228,857 $ 233,240 Operating income $ 18,369 $ 94,872 $ 52,883 $ 46,970 Price risk management activities income (expense) $ (109,579 ) $ 29,990 $ 43,760 $ (59,508 ) Net income (loss) $ (109,636 ) $ 94,764 $ 73,297 $ 304 Net income (loss) per common share: Basic $ (2.02 ) $ 1.75 $ 1.35 $ 0.01 Diluted $ (2.02 ) $ 1.74 $ 1.35 $ 0.01 Weighted average common shares outstanding: Basic 54,156 54,178 54,200 54,203 Diluted 54,156 54,451 54,430 54,559

Supplemental Oil and Gas Disc_2

Supplemental Oil and Gas Disclosures (Unaudited) (Tables)	12 Months Ended
	Dec. 31, 2020
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, 2020 2019 Proved properties $ 4,945,550 $ 4,066,260 Unproved oil and gas properties, not subject to amortization (1) 254,994 194,532 Total oil and gas properties 5,200,544 4,260,792 Less: Accumulated depletion (2,680,254 ) (2,051,856 ) Net capitalized costs $ 2,520,290 $ 2,208,936 Depletion and amortization rate (Per Boe) $ 31.42 $ 18.05 (1) Amount includes $121.7 million and $106.9 million of unproved properties, not subject to amortization related to the Company’s Mexico properties for the years ended December 31, 2020 and 2019, respectively
Schedule of Costs Incurred in Oil, Natural Gas and NGL Property Acquisition, Exploration and Development Activities	The following table reflects the costs incurred in oil, natural gas and NGL property acquisition, exploration and development activities during the years indicated (in thousands). Costs incurred also include new asset retirement obligations established in the current year, as well as increases or decreases to the asset retirement obligations resulting from changes to cost estimates during the year. Year Ended December 31, 2020 2019 2018 Property acquisition costs: Proved properties $ 422,833 $ 27,660 $ 850,515 Unproved properties, not subject to amortization 95,242 16,062 65,063 Total property acquisition costs 518,075 43,722 915,578 Exploration costs (1) 59,422 209,161 93,780 Development costs 362,011 292,547 215,467 Total costs incurred $ 939,508 $ 545,430 $ 1,224,825 (1) Amount includes $14.6 million, $74.2 million and $16.9 million of exploration costs related to the Company’s Mexico properties for the year ended December 31, 2020, 2019 and 2018, respectively.
Schedule of Estimated Proved Reserves at Net Ownership Interest	The following table presents the Company’s estimated proved reserves at its net ownership interest: Oil (MBbls) Gas (MMcf) NGL (MBbls) Oil Equivalent (MBoe) Total proved reserves at December 31, 2017 72,804 127,656 6,547 100,625 Revision of previous estimates 2,595 (37,933 ) 3,187 (539 ) Production (11,771 ) (22,771 ) (1,176 ) (16,742 ) Purchases of reserves 44,788 95,661 2,074 62,806 Extensions and discoveries 4,123 8,411 64 5,589 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 (1) (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 (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 Total proved developed reserves as of: December 31, 2018 85,530 131,364 8,104 115,528 December 31, 2019 72,016 115,381 6,733 97,979 December 31, 2020 85,007 204,054 8,104 127,120 Total proved undeveloped reserves as of: December 31, 2018 27,009 39,660 2,592 36,211 December 31, 2019 34,738 40,617 2,248 43,756 December 31, 2020 24,300 53,154 2,754 35,913 (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, 2020 2019 2018 Future cash inflows $ 4,927,497 $ 7,151,875 $ 8,654,631 Future costs: Production (1,105,211 ) (1,633,432 ) (1,740,850 ) Development and abandonment (1,236,874 ) (1,464,270 ) (1,349,005 ) Future net cash flows before income taxes 2,585,412 4,054,173 5,564,776 Future income tax expense (141,515 ) (662,317 ) (862,473 ) Future net cash flows after income taxes 2,443,897 3,391,856 4,702,303 Discount at 10% annual rate (538,963 ) (854,261 ) (1,362,057 ) Standardized measure of discounted future net cash flows $ 1,904,934 $ 2,537,595 $ 3,340,246
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, 2020 2019 2018 Oil price per Bbl $ 39.47 $ 61.01 $ 69.42 Natural gas price per Mcf $ 1.97 $ 2.59 $ 3.08 NGL price per Bbl $ 9.89 $ 26.17 $ 29.50
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, 2020 2019 2018 Standardized measure, beginning of year $ 2,537,595 $ 3,340,246 $ 1,807,669 Sales and transfers of oil, net gas and NGLs produced during the period (339,557 ) (665,226 ) (727,969 ) Net change in prices and production costs (1,468,304 ) (849,696 ) 1,578,330 Changes in estimated future development costs 32,589 (75,564 ) 32,328 Previously estimated development costs incurred 46,143 117,049 45,937 Accretion of discount 299,302 392,526 180,767 Net change in income taxes 361,875 129,590 (585,017 ) Purchases of reserves 730,611 75,009 943,519 Extensions and discoveries 71,589 306,515 148,068 Net change due to revision in quantity estimates (309,338 ) (199,576 ) 190,853 Changes in production rates (timing) and other (57,571 ) (33,278 ) (274,239 ) Standardized measure, end of year $ 1,904,934 $ 2,537,595 $ 3,340,246 F-42

Formation and Basis of Presen_2

Formation and Basis of Presentation - Additional Information (Details) $ / shares in Units, $ in Thousands	May 10, 2018USD ($)$ / sharesshares	Nov. 21, 2017USD ($)shares	Dec. 31, 2020USD ($)Segment$ / shares	Dec. 31, 2019USD ($)$ / shares	Dec. 31, 2018
Basis Of Presentation And Schedule Of Accounting Policy [Line Items]
Common stock par value | $ / shares	$ 0.01		$ 0.01	$ 0.01
Senior notes, outstanding amount			$ 993,314	$ 746,928
Number of reportable segment | Segment			1
Allowance for uncollectable receivables			$ 9,200	$ 9,900
ASU 2016-13
Basis Of Presentation And Schedule Of Accounting Policy [Line Items]
Change in accounting principle, accounting standards update, adopted [true or false]			true
Change in accounting principle, accounting standards update, adoption date			Jan. 1, 2020
Change in accounting principle, accounting standards update, immaterial effect [true false]			true
Talos Energy LLC Stakeholders | Talos Energy Inc.
Basis Of Presentation And Schedule Of Accounting Policy [Line Items]
Percentage of voting interest acquired	63.00%
Stone Energy Corporation Stockholders | Talos Energy Inc.
Basis Of Presentation And Schedule Of Accounting Policy [Line Items]
Percentage of voting interest acquired	37.00%
7.50% Senior Notes due 2022
Basis Of Presentation And Schedule Of Accounting Policy [Line Items]
Debt instrument interest rate			7.50%	7.50%
Senior notes, maturity date			May 31, 2022	May 31, 2022
Senior notes, principal amount			$ 6,100
11.00% Second-Priority Senior Secured Notes – due April 2022
Basis Of Presentation And Schedule Of Accounting Policy [Line Items]
Debt instrument interest rate			11.00%	11.00%
Senior notes, maturity date			Apr. 3, 2022	Apr. 3, 2022
Senior Notes | 9.75% Senior Notes
Basis Of Presentation And Schedule Of Accounting Policy [Line Items]
Proceeds from issuance of senior notes		$ 102,000
Debt instrument interest rate		9.75%
Shares issued on exchange agreement | shares		2,874,049
Senior Notes | 9.75% Senior Notes ? due July 2022
Basis Of Presentation And Schedule Of Accounting Policy [Line Items]
Senior notes, maturity date			Jul. 31, 2022
Senior Notes | 7.50% Senior Notes due 2022
Basis Of Presentation And Schedule Of Accounting Policy [Line Items]
Debt instrument interest rate		7.50%	7.50%		7.50%
Senior notes, maturity date			May 31, 2022
Proceeds from Issuance of senior secured notes in exchange of 11% senior secured notes		$ 137,400
Senior notes, principal amount	$ 81,500
Senior notes, outstanding amount	$ 6,100		$ 6,060	$ 6,060
Senior Notes | 11.00% Second-Priority Senior Secured Notes – due April 2022
Basis Of Presentation And Schedule Of Accounting Policy [Line Items]
Debt instrument interest rate		11.00%	11.00%		11.00%
Senior notes, maturity date			Apr. 3, 2022
Senior notes, outstanding amount			$ 347,254	$ 390,868
Debt instrument interest rate exchanged percentage	11.00%
Bridge Loans | 11.00% Bridge Loans
Basis Of Presentation And Schedule Of Accounting Policy [Line Items]
Debt instrument interest rate		11.00%
Proceeds from issuance of bridge loans in exchange of 11% senior secured notes		$ 172,000
Stone Energy Corporation
Basis Of Presentation And Schedule Of Accounting Policy [Line Items]
Closing date of merger agreement			May 10, 2018
Stone Energy Corporation | 7.50% Senior Notes due 2022
Basis Of Presentation And Schedule Of Accounting Policy [Line Items]
Debt instrument interest rate			7.50%
Senior notes, maturity date			May 31, 2022
Senior notes, principal amount			$ 6,100
Stone Energy Corporation | 11.00% Second-Priority Senior Secured Notes – due April 2022
Basis Of Presentation And Schedule Of Accounting Policy [Line Items]
Debt instrument interest rate			11.00%
Senior notes, maturity date			Apr. 3, 2022
Senior notes, principal amount			$ 347,300
Talos Production LLC
Basis Of Presentation And Schedule Of Accounting Policy [Line Items]
Percentage of voting interest acquired	100.00%
Share issued on merger | shares	31,244,085

Summary of Significant Accoun_4

Summary of Significant Accounting Policies - Additional Information (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Summary Of Significant Accounting Policies [Line Items]
Allowance for uncollectible accounts	$ 9.2	$ 9.9
Income tax refund claims	19.1	18
Gas imbalance receivable	1.7	1.7
Gas imbalance payable	3.6	3.6
Impairment to adjust other well equipment inventory	$ 0.7	0.2	$ 0.2
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%
Other Revenue
Summary Of Significant Accounting Policies [Line Items]
Refund liability	$ 8.9	19.3
ILX and Castex
Summary Of Significant Accounting Policies [Line Items]
Escrow deposit		$ 31.8

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, 2020	Dec. 31, 2019	Dec. 31, 2018
Shell Trading (US) Company
Concentration Risk [Line Items]
Concentration risk, percentage	47.00%	58.00%	65.00%
Phillips 66
Concentration Risk [Line Items]
Concentration risk, percentage	22.00%	28.00%	18.00%
Chevron Products Company
Concentration Risk [Line Items]
Concentration risk, percentage	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, 2020	Dec. 31, 2019	Dec. 31, 2018
Concentration Risk [Line Items]
Concentration risk, percentage	12.00%
Maximum
Concentration Risk [Line Items]
Concentration risk, percentage		10.00%	10.00%

Acquisitions - Business Combina

Acquisitions - Business Combination - Additional Information (Details) $ in Thousands	Nov. 16, 2020USD ($)	Aug. 05, 2020USD ($)Propertyshares	Mar. 30, 2020shares	Feb. 28, 2020USD ($)shares	Dec. 10, 2019	May 10, 2018USD ($)	Dec. 31, 2020USD ($)shares	Dec. 31, 2019USD ($)	Dec. 31, 2018USD ($)
Senior Notes | Second Priority Senior Secured Notes
Business Acquisition [Line Items]
Senior notes, stated interest rate						11.00%
ILX and Castex
Business Acquisition [Line Items]
Aggregate consideration of cash				$ 385,000
Acquisition, transaction related cost				12,100
Purchase price				$ 459,322
ILX and Castex | General and Administrative Expense
Business Acquisition [Line Items]
Acquisition, transaction related cost							$ 8,700	$ 3,400
ILX and Castex | Contingent Convertible Preferred Stock
Business Acquisition [Line Items]
Conversion stock issued to sellers | shares				11,000,000
Stone Energy Corporation
Business Acquisition [Line Items]
Acquisition, transaction related cost									$ 88,600
Purchase price						$ 731,964
Acquisition, transaction related fees to note holders and for seismic use agreements									56,100
Acquisition, transaction related fees paid to note holders									9,300
Acquisition, transaction related fees for seismic use agreements									46,800
Stone Energy Corporation | General and Administrative Expense
Business Acquisition [Line Items]
Acquisition, transaction related cost									$ 32,500
Talos Energy LLC Stakeholders | Talos Energy Inc.
Business Acquisition [Line Items]
Percentage of voting interest acquired						63.00%
Talos Energy LLC Stakeholders | ILX and Castex
Business Acquisition [Line Items]
Aggregate consideration of cash				$ 385,000
Closing date of merger agreement					Jul. 1, 2019
Talos Energy LLC Stakeholders | ILX and Castex | Common Stock
Business Acquisition [Line Items]
Conversion of stock, new issuance | shares			11,000,000
Talos Energy LLC Stakeholders | ILX and Castex | Series A Convertible Preferred Stock
Business Acquisition [Line Items]
Aggregate shares issued | shares			110,000	110,000
Conversion of stock, new issuance | shares			11,000,000
Stone Energy Corporation Stockholders | Talos Energy Inc.
Business Acquisition [Line Items]
Percentage of voting interest acquired						37.00%
LLOG Acquisition
Business Acquisition [Line Items]
Aggregate consideration of cash	$ 13,200
Acquisition, transaction related cost	$ 200
Castex 2005 Acquisition
Business Acquisition [Line Items]
Aggregate consideration of cash		$ 6,500					6,500
Acquisition, transaction related cost		$ 1,400					1,413
Number of properties | Property		16
Purchase price							$ 43,306
Castex 2005 Acquisition | Common Stock
Business Acquisition [Line Items]
Aggregate shares issued | shares		4,600,000					4,602,460

Acquisitions - Asset Acquisitio

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	Jan. 11, 2019	Aug. 31, 2018
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
Gunflint Acquisition
Business Acquisition [Line Items]
Property and equipment			$ 28,912
Asset retirement obligations			(996)
Allocated purchase price			$ 27,916
Whistler Energy II, LLC
Business Acquisition [Line Items]
Current assets				$ 45,337
Property and equipment				35,344
Other long-term assets				66
Current liabilities				(4,261)
Asset retirement obligations				(23,862)
Allocated purchase price				$ 52,624

Acquisitions - Summary of Purch

Acquisitions - Summary of Purchase Price, Inclusive of Customary Closing Adjustments (Details) - USD ($) $ / shares in Units, $ in Thousands	Aug. 05, 2020	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Business Acquisition [Line Items]
Net cash consideration paid at closing		$ 315,962	$ 37,916	$ (278,409)
Castex 2005 Acquisition
Business Acquisition [Line Items]
Cash consideration	$ 6,500	6,500
Transaction cost	$ 1,400	1,413
Total purchase price		$ 43,306
Castex 2005 Acquisition | Common Stock
Business Acquisition [Line Items]
Talos common stock	4,600,000	4,602,460
Talos common stock price per share		$ 7.69
Talos common stock value		$ 35,393

Acquisitions - Asset Acquisit_2

Acquisitions - Asset Acquisitions - Additional Information (Details) - USD ($) $ in Millions	Jan. 11, 2019	Aug. 31, 2018
Gunflint Acquisition
Business Acquisition [Line Items]
Percentage of non-operated working interest acquired	9.60%
Purchase price	$ 29.6
Customary purchase price adjustments	$ 27.9
Whistler Energy II, LLC
Business Acquisition [Line Items]
Purchase price		$ 52.6
Business acquisition purchase price net		14.8
Available cash acquired		37.8
Business combination cash collateral		30.8
Business combination cash on hand for working capital		$ 7

Acquisitions - Asset Acquisit_3

Acquisitions - Asset Acquisitions - Summary of Allocation of Purchase Price to Assets Acquired and Liabilities Assumed (Parenthetical) (Details) - Whistler Energy II, LLC $ in Millions	Aug. 31, 2018USD ($)
Business Acquisition [Line Items]
Cash acquired	$ 37.8
Trade Accounts Receivable
Business Acquisition [Line Items]
Primary fair values of receivables acquired	$ 3.2

Acquisitions - Summary of Pur_2

Acquisitions - Summary of Purchase Price (Details) - USD ($) $ / shares in Units, $ in Thousands	Feb. 28, 2020	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Business Acquisition [Line Items]
Net cash consideration paid at closing		$ 315,962	$ 37,916	$ (278,409)
ILX and Castex
Business Acquisition [Line Items]
Talos Conversion Stock	11,000,000
Talos common stock price per share	$ 14.20
Conversion Stock value	$ 156,200
Cash consideration	385,000
Customary closing and post-closing adjustments	(81,878)
Net cash consideration paid at closing	303,122
Total purchase price	$ 459,322

Acquisitions - Business Combi_2

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_3

Acquisitions - Business Combination - Summary of Allocation of Purchase Price to Assets Acquired and Liabilities Assumed Including the Measurement Period Adjustments (Parenthetical) (Details) $ in Millions	Dec. 31, 2020USD ($)
ILX and Castex | Trade and Other Receivables
Business Acquisition [Line Items]
Primary fair values of receivables acquired	$ 8.2

Acquisitions - Business Combi_4

Acquisitions - Business Combination - Summary of Revenue and Net Income Attributable to Assets Acquired (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
ILX and Castex
Business Acquisition [Line Items]
Revenue	$ 126,857
Net income (loss)	(6,011)
Stone Energy Corporation
Business Acquisition [Line Items]
Revenue	187,211	$ 414,056	$ 332,944
Net income (loss)	$ (1,232)	$ 187,428	$ 148,473

Acquisitions - Business Combi_5

Acquisitions - Business Combination - Summary of Supplemental Proforma Information (Details) - USD ($) $ / shares in Units, $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Business Acquisition [Line Items]
Revenue			$ 1,013,184
Net income (loss)			$ 274,577
Basic net income (loss) per common share			$ 5.07
Diluted net income (loss) per common share			$ 5.07
ILX and Castex
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

Acquisitions - Business Combi_6

Acquisitions - Business Combination - Summary of Purchase Price (Details) - USD ($) $ / shares in Units, $ in Thousands	May 10, 2018	Dec. 31, 2020	Dec. 31, 2019	May 09, 2018
Business Acquisition [Line Items]
Common stock value		$ 813	$ 542
Stone Energy Corporation
Business Acquisition [Line Items]
Stone Energy common stock - issued and outstanding as of May 9, 2018				20,038
Stone Energy common stock price	$ 35.49
Common stock value	$ 711,149
Stone Energy common stock warrants - issued and outstanding as of May 9, 2018				3,528
Stone Energy common stock warrants price	$ 5.90
Common stock warrants value	$ 20,815
Total purchase price	$ 731,964

Acquisitions - Business Combi_7

Acquisitions - Business Combination - Summary of Allocation of Purchase Price to Assets Acquired and Liabilities Assumed (Details) - Stone Energy Corporation $ in Thousands	May 10, 2018USD ($)
Business Acquisition [Line Items]
Current assets	$ 372,963
Property and equipment	886,406
Other long-term assets	19,494
Current liabilities	(132,846)
Long-term debt	(235,416)
Other long-term liabilities	(178,637)
Allocated purchase price	$ 731,964

Acquisitions - Business Combi_8

Acquisitions - Business Combination - Summary of Allocation of Purchase Price to Assets Acquired and Liabilities Assumed (Parenthetical) (Details) - Stone Energy Corporation $ in Millions	May 10, 2018USD ($)
Business Acquisition [Line Items]
Cash acquired	$ 293
Trade Accounts Receivable
Business Acquisition [Line Items]
Primary fair values of receivables acquired	43.3
Joint Interest Receivables
Business Acquisition [Line Items]
Primary fair values of receivables acquired	$ 3.5

Property, Plant and Equipment -

Property, Plant and Equipment - Additional Information (Details)	3 Months Ended		12 Months Ended
	Dec. 31, 2020USD ($)	Mar. 31, 2020USD ($)	Dec. 31, 2020USD ($)$ / bbl$ / Mcf	Dec. 31, 2019USD ($)	Dec. 31, 2018USD ($)
Property, Plant and Equipment [Line Items]
Write-down of oil and natural gas properties			$ 268,615,000	$ 12,386,000	$ 244,000
Write-down of oil and natural gas properties	$ 267,859,000	$ 57,000	267,916,000	12,221,000
Block 2
Property, Plant and Equipment [Line Items]
Write-down of oil and natural gas properties			100,000	$ 12,200,000
US
Property, Plant and Equipment [Line Items]
Write-down of oil and natural gas properties			$ 267,900,000
Unweighted average first day of month commodity price for crude oil for prior twelve months | $ / bbl			39.47
Unweighted average first day of month commodity price for natural gas for prior twelve months | $ / Mcf			1.97
Unweighted average first day of month commodity price for natural gas liquids for prior twelve months | $ / bbl			9.89
Measurement Input Discount Rate
Property, Plant and Equipment [Line Items]
Present value of future net revenues from proved reserves, discount rate			10.00%

Property, Plant and Equipment_2

Property, Plant and Equipment - Summary of Oil and Natural Gas Property Costs Not Being Amortized (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2020USD ($)
Capitalized Costs Of Unproved Properties Excluded From Amortization [Line Items]
Total unproved properties, not subject to amortization	$ 254,994
United States
Capitalized Costs Of Unproved Properties Excluded From Amortization [Line Items]
Acquisition	80,799
Exploration	52,470
Mexico
Capitalized Costs Of Unproved Properties Excluded From Amortization [Line Items]
Exploration	121,725
2020
Capitalized Costs Of Unproved Properties Excluded From Amortization [Line Items]
Total unproved properties, not subject to amortization	88,840
2020 | United States
Capitalized Costs Of Unproved Properties Excluded From Amortization [Line Items]
Acquisition	61,315
Exploration	12,714
2020 | Mexico
Capitalized Costs Of Unproved Properties Excluded From Amortization [Line Items]
Exploration	14,811
2019
Capitalized Costs Of Unproved Properties Excluded From Amortization [Line Items]
Total unproved properties, not subject to amortization	97,775
2019 | United States
Capitalized Costs Of Unproved Properties Excluded From Amortization [Line Items]
Acquisition	3,268
Exploration	32,698
2019 | Mexico
Capitalized Costs Of Unproved Properties Excluded From Amortization [Line Items]
Exploration	61,809
2018
Capitalized Costs Of Unproved Properties Excluded From Amortization [Line Items]
Total unproved properties, not subject to amortization	36,339
2018 | United States
Capitalized Costs Of Unproved Properties Excluded From Amortization [Line Items]
Acquisition	16,216
Exploration	5,761
2018 | Mexico
Capitalized Costs Of Unproved Properties Excluded From Amortization [Line Items]
Exploration	14,362
2017 and Prior
Capitalized Costs Of Unproved Properties Excluded From Amortization [Line Items]
Total unproved properties, not subject to amortization	32,040
2017 and Prior | United States
Capitalized Costs Of Unproved Properties Excluded From Amortization [Line Items]
Exploration	1,297
2017 and Prior | Mexico
Capitalized Costs Of Unproved Properties Excluded From Amortization [Line Items]
Exploration	$ 30,743

Property, Plant and Equipment_3

Property, Plant and Equipment - Schedule of Asset Retirement Obligations (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Oil And Gas Property [Abstract]
Asset retirement obligations	$ 369,478	$ 382,817
Fair value of asset retirement obligations acquired	44,311	5,047
Obligations settled	(43,933)	(75,331)
Fair value of asset retirement obligations divested	(185)	(5,450)
Accretion expense	49,741	34,389	$ 35,344
Obligations incurred	4,511	4,111
Changes in estimate	18,346	23,895
Asset retirement obligations	442,269	369,478	$ 382,817
Less: Current portion	(49,921)	(61,051)
Long-term portion	$ 392,348	$ 308,427

Property, Plant and Equipment_4

Property, Plant and Equipment - Schedule of Asset Retirement Obligations (Parenthetical) (Details) $ in Millions	12 Months Ended
	Dec. 31, 2020USD ($)
ILX and Castex
Property, Plant and Equipment [Line Items]
Fair value of asset retirement obligations assumed	$ 35.3
Castex 2005 Acquisition
Property, Plant and Equipment [Line Items]
Fair value of asset retirement obligations assumed	3.3
LLOG Acquisition
Property, Plant and Equipment [Line Items]
Fair value of asset retirement obligations assumed	$ 4.2

Leases - Components of Lease Co

Leases - Components of Lease Costs (Details) - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2020	Dec. 31, 2019
Leases [Abstract]
Finance lease cost - interest on lease liabilities	[1]	$ 15,748	$ 19,115
Operating lease cost, excluding short-term leases	[2]	3,361	3,261
Short-term lease cost	[3]	53,573	85,865
Variable lease cost	[4]	543	11
Total lease cost		$ 73,225	$ 108,252
[1]	The Helix Producer I (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 reserved using the unit-of-production method, computed quarterly.
[2]	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.
[3]	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.
[4]	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, 2020	Dec. 31, 2019
Operating leases:
Operating lease assets		$ 6,855	$ 7,779
Current portion of operating lease liabilities		1,793	$ 1,594
Operating Lease, Liability, Current, Statement of Financial Position [Extensible List]			us-gaap:OperatingLeaseLiabilityCurrent
Operating lease liabilities		18,554	$ 17,239
Total operating lease liabilities		20,347	18,833
Finance leases:
Proved property	[1]	124,299	124,299
Other current liabilities		21,804	$ 17,509
Finance Lease, Liability, Current, Statement of Financial Position [Extensible List]			us-gaap:OtherLiabilitiesCurrent
Other long-term liabilities		40,222	$ 62,026
Finance Lease, Liability, Noncurrent, Statement of Financial Position [Extensible List]			us-gaap:OtherLiabilitiesNoncurrent
Total finance lease liabilities		$ 62,026	$ 79,535
[1]	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.

Leases - Schedule of Lease Matu

Leases - Schedule of Lease Maturity (Details) - USD ($) $ in Thousands	Dec. 31, 2020	Dec. 31, 2019
Leases [Abstract]
Operating Leases, 2021	$ 4,079
Operating Leases, 2022	4,302
Operating Leases, 2023	4,239
Operating Leases, 2024	3,315
Operating Leases, 2025	3,293
Operating Leases, Thereafter	12,497
Operating Leases, Total lease payments	31,725
Operating Leases, Imputed interest	(11,378)
Operating Leases	20,347	$ 18,833
Finance Leases, 2021	33,257
Finance Leases, 2022	33,257
Finance Leases, 2023	13,857
Finance Leases, Total lease payments	80,371
Finance Leases, Imputed interest	(18,345)
Finance Leases	$ 62,026	$ 79,535

Leases - Schedule of Weighted A

Leases - Schedule of Weighted Average Remaining Lease Term and Discount Rate (Details)	Dec. 31, 2020	Dec. 31, 2019
Weighted average remaining lease term:
Operating leases	7 years 9 months 18 days	8 years 4 months 24 days
Finance leases	2 years 4 months 24 days	3 years 4 months 24 days
Weighted average discount rate:
Operating leases	12.00%	10.20%
Finance leases	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, 2020	Dec. 31, 2019	Dec. 31, 2018
Cash Paid For Amounts Included In Measurement Of Lease Liabilities [Abstract]
Operating cash outflow from finance leases	$ 15,748	$ 19,115
Financing cash outflow from finance leases	17,509	14,133	$ 12,952
Operating cash outflow from operating leases	$ 2,648	1,812
Right-of-use assets obtained in exchange for new operating lease liabilities		$ 2,225

Financial Instruments - Schedul

Financial Instruments - Schedule of Carrying Amounts and Estimated Fair Values of Financial Instruments (Details) - USD ($) $ in Thousands		Dec. 31, 2020	Dec. 31, 2019
Oil and Natural Gas Derivatives
Debt Instrument [Line Items]
Carrying Amount		$ (67,814)	$ (11,594)
Fair Value		(67,814)	(11,594)
11.00% Second-Priority Senior Secured Notes – due April 2022
Debt Instrument [Line Items]
Carrying Amount	[1]	343,579	383,871
Fair Value	[1]	355,935	401,128
7.50% Senior Notes – due May 2022
Debt Instrument [Line Items]
Carrying Amount		6,060	6,060
Fair Value		5,238	5,030
Bank Credit Facility – matures May 2022
Debt Instrument [Line Items]
Carrying Amount	[1]	635,873	343,050
Fair Value	[1]	$ 640,000	$ 350,000
[1]	The carrying amounts are net of discount and deferred financing costs.

Financial Instruments - Sched_2

Financial Instruments - Schedule of Carrying Amounts and Estimated Fair Values of Financial Instruments (Parenthetical) (Details)	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Bank Credit Facility – matures May 2022
Debt Instrument [Line Items]
Senior notes, maturity date	May 10, 2022	May 10, 2022
11.00% Second-Priority Senior Secured Notes – due April 2022
Debt Instrument [Line Items]
Debt instrument interest rate	11.00%	11.00%
Senior notes, maturity date	Apr. 3, 2022	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, 2020USD ($)counterparty	Dec. 31, 2019
Investment Grade Credit Rating
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items]
Number of counterparties | counterparty	9
11.00% Second-Priority Senior Secured Notes – due April 2022
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items]
Debt instrument interest rate	11.00%	11.00%
Senior notes, maturity date	Apr. 3, 2022	Apr. 3, 2022
7.50% Senior Notes – due May 2022
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items]
Debt instrument interest rate	7.50%	7.50%
Senior notes, maturity date	May 31, 2022	May 31, 2022
Senior notes, principal amount	$ 6,100,000
New Bank Credit Facility
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items]
Senior notes, maturity date	May 10, 2022
Credit facility, maximum borrowing capacity	$ 985,000,000
Stone Energy Corporation | 11.00% Second-Priority Senior Secured Notes – due April 2022
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items]
Debt instrument interest rate	11.00%
Senior notes, maturity date	Apr. 3, 2022
Senior notes, principal amount	$ 347,300,000
Stone Energy Corporation | 7.50% Senior Notes – due May 2022
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items]
Debt instrument interest rate	7.50%
Senior notes, maturity date	May 31, 2022
Senior notes, principal amount	$ 6,100,000

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	3 Months Ended								12 Months Ended
	Dec. 31, 2020	Sep. 30, 2020	Jun. 30, 2020	Mar. 31, 2020	Dec. 31, 2019	Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Derivative Instruments And Hedging Activities Disclosure [Abstract]
Net cash received (paid) on settled derivative instruments									$ 143,905	$ (8,820)	$ (111,147)
Unrealized gain (loss)									(56,220)	(86,517)	171,582
Price risk management activities income (expense)	$ (66,968)	$ (19,882)	$ (68,682)	$ 243,217	$ (59,508)	$ 43,760	$ 29,990	$ (109,579)	$ 87,685	$ (95,337)	$ 60,435

Financial Instruments - Sched_4

Financial Instruments - Schedule of Contracted Volumes and Weighted Average Prices and will Receive Under the Terms of Derivative Contracts (Details)	12 Months Ended
	Dec. 31, 2020MMBTU$ / bbl$ / MMBTUbbl
Crude Oil | WTI | January 2021 – December 2021 | Swaps
Derivative [Line Items]
Instrument Type	Swaps
Average Daily Volumes | bbl	22,948
Weighted Average Swap Price | $ / bbl	43.20
Crude Oil | WTI | January 2021 – December 2021 | Collars
Derivative [Line Items]
Instrument Type	Collars
Average Daily Volumes | bbl	1,000
Weighted Average Put Price | $ / bbl	30
Weighted Average Call Price | $ / bbl	40
Crude Oil | WTI | January 2022 – December 2022 | Swaps
Derivative [Line Items]
Instrument Type	Swaps
Average Daily Volumes | bbl	10,616
Weighted Average Swap Price | $ / bbl	44.45
Crude Oil | LLS | January 2021 – December 2021 | Swaps
Derivative [Line Items]
Instrument Type	Swaps
Average Daily Volumes | bbl	3,000
Weighted Average Swap Price | $ / bbl	38.83
Natural Gas | January 2022 – December 2022 | Swaps | NYMEX Henry Hub
Derivative [Line Items]
Instrument Type	Swaps
Weighted Average Swap Price | $ / MMBTU	2.60
Average Daily Volumes | MMBTU	29,649
Natural Gas | January 2021 – December 2021 | Swaps | NYMEX Henry Hub
Derivative [Line Items]
Instrument Type	Swaps
Weighted Average Swap Price | $ / MMBTU	2.56
Average Daily Volumes | MMBTU	58,907
Natural Gas | January 2021 – December 2021 | Collars | NYMEX Henry Hub
Derivative [Line Items]
Instrument Type	Collars
Weighted Average Put Price | $ / MMBTU	2.50
Weighted Average Call Price | $ / MMBTU	3.10
Average Daily Volumes | MMBTU	5,000
Natural Gas | January 2023 – June 2023 | Swaps | NYMEX Henry Hub
Derivative [Line Items]
Instrument Type	Swaps
Weighted Average Swap Price | $ / MMBTU	2.61
Average Daily Volumes | MMBTU	5,000

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, 2020	Dec. 31, 2019
Liabilities:
Total net liability	$ (67,814)	$ (11,594)
Oil And Natural Gas Swaps And Costless Collars
Assets:
Oil and natural gas swaps and costless collars	7,821	8,393
Liabilities:
Oil and natural gas swaps and costless collars	(75,635)	(19,987)
Level 2
Liabilities:
Total net liability	(67,814)	(11,594)
Level 2 | Oil And Natural Gas Swaps And Costless Collars
Assets:
Oil and natural gas swaps and costless collars	7,821	8,393
Liabilities:
Oil and natural gas swaps and costless collars	$ (75,635)	$ (19,987)

Financial Instruments - Sched_5

Financial Instruments - Schedule of Fair Value of Derivative Financial Instruments (Details) - USD ($) $ in Thousands	Dec. 31, 2020	Dec. 31, 2019
Price Risk Derivatives [Line Items]
Current, Assets	$ 6,876	$ 8,393
Non-current, Assets	945
Current, Liabilities	66,010	19,476
Non-current, Liabilities	9,625	511
Oil and Natural Gas Derivatives
Price Risk Derivatives [Line Items]
Current, Assets	6,876	8,393
Non-current, Assets	945
Assets	7,821	8,393
Current, Liabilities	66,010	19,476
Non-current, Liabilities	9,625	511
Liabilities	$ 75,635	$ 19,987

Debt - Summary of Detail Compri

Debt - Summary of Detail Comprising Debt and Related Book Values (Details) - USD ($) $ in Thousands	Dec. 31, 2020	Dec. 31, 2019	May 10, 2018
Debt Instrument [Line Items]
Total debt, before discount and deferred financing cost	$ 993,314	$ 746,928
Discount and deferred financing cost	(7,802)	(13,947)
Total debt, net of discount and deferred financing costs	985,512	732,981
Senior Notes | 11.00% Second-Priority Senior Secured Notes – due April 2022
Debt Instrument [Line Items]
Total debt, before discount and deferred financing cost	347,254	390,868
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	$ 6,100
Bank Credit Facility | Bank Credit Facility – matures May 2022
Debt Instrument [Line Items]
Total debt, before discount and deferred financing cost	$ 640,000	$ 350,000

Debt - Summary of Detail Comp_2

Debt - Summary of Detail Comprising Debt and Related Book Values (Parenthetical) (Details)	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018	Nov. 21, 2017
11.00% Second-Priority Senior Secured Notes – due April 2022
Debt Instrument [Line Items]
Debt instrument interest rate	11.00%	11.00%
Senior notes, maturity date	Apr. 3, 2022	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 May 2022
Debt Instrument [Line Items]
Senior notes, maturity date	May 10, 2022
Senior Notes | 11.00% Second-Priority Senior Secured Notes – due April 2022
Debt Instrument [Line Items]
Debt instrument interest rate	11.00%		11.00%	11.00%
Senior notes, maturity date	Apr. 3, 2022
Senior Notes | 7.50% Senior Notes – due May 2022
Debt Instrument [Line Items]
Debt instrument interest rate	7.50%		7.50%	7.50%
Senior notes, maturity date	May 31, 2022
Bank Credit Facility | Bank Credit Facility – matures May 2022
Debt Instrument [Line Items]
Senior notes, maturity date	May 10, 2022

Debt - Additional information (

Debt - Additional information (Details) - USD ($) shares in Millions

Jan. 16, 2023

Jan. 15, 2023

May 10, 2021

Jan. 14, 2021

Jan. 14, 2021

Jan. 04, 2021

Jun. 15, 2020

Jan. 31, 2021

Dec. 31, 2020

Dec. 31, 2019

Jan. 13, 2021

Dec. 07, 2020

Jun. 19, 2020

Feb. 28, 2020

Feb. 27, 2020

Dec. 31, 2018

May 10, 2018

Nov. 21, 2017

Debt Instrument [Line Items]

Debt instrument redemption, description

The indenture governing the 11.00% Notes applies certain limitations on the Company’s ability and the ability of its subsidiaries to, among other things, (i) incur additional indebtedness or issue certain preferred shares; (ii) pay dividends and make certain other restricted payments; (iii) create restrictions on the payment of dividends or other distributions to the Company from its restricted subsidiaries; (iv) create liens on certain assets to secure debt; (v) make certain investments; (vi) engage in sales of assets and subsidiary stock; (vii) transfer all or substantially all of its assets or enter into merger or consolidation transactions; and (viii) engage in transactions with affiliates. The 11.00% Notes contain customary quarterly and annual reporting, financial and administrative covenants. The Company was in compliance with all debt covenants at December 31, 2020. 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 presented as “Other income (expense)” on the Consolidated Statements of Operations.

Gain on extinguishment of debt

$ 1,662,000

Senior notes, outstanding amount

$ 993,314,000

$ 746,928,000

7.50% Senior Notes – due May 2022

Debt Instrument [Line Items]

Debt instrument, redemption price, percentage

105.63%

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, face amount

$ 6,100,000

7.50% Senior Notes – due May 2022 | Minimum

Debt Instrument [Line Items]

Debt instrument, redemption price, percentage

100.00%

7.50% Senior Notes – due May 2022 | Maximum

Debt Instrument [Line Items]

Debt instrument, redemption price, percentage

105.63%

Bank Credit Facility – matures May 2022

Debt Instrument [Line Items]

Debt instrument maturity date

May 10, 2022

Debt instrument, face amount

$ 25,000,000

Credit facility, maximum borrowing capacity

$ 985,000,000

Debt instrument, springing maturity date

Dec. 4, 2021

Bank credit facility, description

The Bank Credit Facility matures on May 10, 2022, provided that the Bank Credit Facility mandates a springing maturity that is 120 days prior to the maturity date of the 11.00% Notes (such 120 days prior being December 4, 2021), if greater than $25.0 million of the 11.00% Notes or any permitted refinancing indebtedness in respect thereof is outstanding on such date.

Debt instrument springing maturity period

120 days

Commitment fee percentage

0.50%

Line of credit outstanding borrowing amount

$ 640,000,000

Letters of credit outstanding amount

13,600,000

Bank Credit Facility – matures May 2022 | Castex 2005 Acquisition

Debt Instrument [Line Items]

Line of credit facility lender approval for access capacity amount

$ 25,000,000

Bank Credit Facility – matures May 2022 | ILX and Castex

Debt Instrument [Line Items]

Credit facility, maximum borrowing capacity

$ 985,000,000

$ 985,000,000

$ 1,150,000,000

$ 950,000,000

Bank Credit Facility – matures May 2022 | Subsequent Event

Debt Instrument [Line Items]

Debt instrument, face amount

$ 25,000,000

$ 25,000,000

Credit facility, maximum borrowing capacity

$ 960,000,000

960,000,000

$ 960,000,000

Debt instrument springing maturity period

120 days

Line of credit outstanding borrowing amount

465,000,000

Letters of credit outstanding amount

13,600,000

Repayment of outstanding borrowings

175,000,000

Line of credit reduction to borrowing base

$ 25,000,000

Bank Credit Facility – matures May 2022 | Letter of Credit

Debt Instrument [Line Items]

Credit facility, maximum borrowing capacity

$ 200,000,000

Bank Credit Facility – matures May 2022 | Minimum

Debt Instrument [Line Items]

Debt covenant current ratio

100.00%

Bank Credit Facility – matures May 2022 | Minimum | London Interbank Offered Rate

Debt Instrument [Line Items]

Debt Instrument, Basis Spread on Variable Rate

3.00%

Bank Credit Facility – matures May 2022 | Minimum | Base Rate

Debt Instrument [Line Items]

Debt Instrument, Basis Spread on Variable Rate

2.00%

Bank Credit Facility – matures May 2022 | Maximum

Debt Instrument [Line Items]

Debt covenant to EBITDAX

300.00%

Bank Credit Facility – matures May 2022 | Maximum | London Interbank Offered Rate

Debt Instrument [Line Items]

Debt Instrument, Basis Spread on Variable Rate

4.00%

Bank Credit Facility – matures May 2022 | Maximum | Base Rate

Debt Instrument [Line Items]

Debt Instrument, Basis Spread on Variable Rate

3.00%

12.00% Second-Priority Senior Notes - due January 2026 | Subsequent Event

Debt Instrument [Line Items]

Debt instrument maximum borrowings

$ 550,000,000

$ 550,000,000

Senior Notes | 11.00% Second-Priority Senior Secured Notes - due April 2022

Debt Instrument [Line Items]

Debt instrument maturity date

Apr. 3, 2022

Debt instrument frequency of periodic payment

semi-annually

Debt instrument payment terms

semi-annually each April 15 and October 15

Debt instrument, interest rate, stated percentage

11.00%

11.00%

11.00%

Debt instrument, repurchase amount

$ 37,200,000

$ 6,400,000

Debt instrument, shares issued in conversion for repurchased and retired notes

3.1

Senior Notes | 11.00% Second-Priority Senior Secured Notes - due April 2022 | Subsequent Event

Debt Instrument [Line Items]

Debt instrument, interest rate, stated percentage

11.00%

Senior notes, outstanding amount

$ 347,300,000

Senior Notes | 11.00% Second-Priority Senior Secured Notes - due April 2022 | Other Income (Expense)

Debt Instrument [Line Items]

Gain on extinguishment of debt

$ 1,700,000

Senior Notes | 11.00% Second-Priority Senior Secured Notes - due April 2022 | Forecast

Debt Instrument [Line Items]

Debt instrument, redemption price, percentage

102.75%

Senior Notes | 11.00% Second-Priority Senior Secured Notes - due April 2022 | Minimum

Debt Instrument [Line Items]

Debt instrument, redemption price, percentage

100.00%

Senior Notes | 11.00% Second-Priority Senior Secured Notes - due April 2022 | Maximum

Debt Instrument [Line Items]

Debt instrument, redemption price, percentage

102.75%

Senior Notes | 7.50% Senior Notes – due May 2022

Debt Instrument [Line Items]

Debt instrument maturity date

May 31, 2022

Debt instrument, interest rate, stated percentage

7.50%

7.50%

7.50%

Debt instrument, face amount

$ 81,500,000

Senior notes, outstanding amount

$ 6,060,000

$ 6,060,000

$ 6,100,000

Senior Notes | 12.00% Second-Priority Senior Notes - due January 2026 | Subsequent Event

Debt Instrument [Line Items]

Debt instrument maturity date

Jan. 31, 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%

12.00%

Debt instrument, face amount

$ 500,000,000

Debt Instrument, interest payable commencing date

Jul. 15, 2021

Debt instrument additional principal amount issued

$ 150,000,000

$ 150,000,000

Gross proceeds from Issuance of Debt

$ 600,500,000

Senior Notes | 12.00% Second-Priority Senior Notes - due January 2026 | Forecast

Debt Instrument [Line Items]

Debt instrument, redemption price, percentage

112.00%

Maximum percentage of principal amount option to redeem

40.00%

Senior Notes | 12.00% Second-Priority Senior Notes - due January 2026 | Minimum | Forecast

Debt Instrument [Line Items]

Debt instrument, redemption price, percentage

100.00%

Senior Notes | 12.00% Second-Priority Senior Notes - due January 2026 | Maximum | Forecast

Debt Instrument [Line Items]

Debt instrument, redemption price, percentage

106.00%

Employee Benefits Plans and S_3

Employee Benefits Plans and Share-Based Compensation - Additional information (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
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
Options conversion in common stock shares	1
Share-based compensation expense recognized period	1 year 6 months
Share-based compensation expense unrecognized	$ 7.4
Share-based compensation grant date fair value	$ 5.8	$ 7.4	$ 10.4
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%
Executive Severance Plan
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Termination period	12 months
Plan termination date	Jul. 11, 2019
Executive Severance Plan | General and Administrative Expense
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Severance Costs1		$ 0.2	$ 7.8
Long Term Incentive Plan
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Share-Based Compensation authorized to grant	5,415,576
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
Options conversion in common stock shares	1
Share-based compensation expense recognized period	1 year 9 months 18 days
Share-based compensation expense unrecognized	$ 14.3
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
Options conversion in common stock shares	1
Share-based compensation expense recognized period	2 months 12 days
Share-based compensation expense unrecognized	$ 0.1
Options conversion percentage in RSUs	60.00%
Options conversion percentage in cash	40.00%
Share-based compensation expense liabilities	$ 0.1
Talos Energy LLC Series B Units | Series A Units
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Share-based compensation expense unrecognized	$ 3.4
Percentage of compounded annual returns attained covenant	8.00%
Talos Energy LLC Series B Units | Series C Units
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Distribution paid	$ 0
New Talos Energy LLC Series B Units | New Series B Units
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Share based compensation grants, vesting period	4 years
Distribution paid	$ 102
Percentage of units to be vested covenant	80.00%
New Talos Energy LLC Series B Units | New Series A Units
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Share-based compensation expense unrecognized	$ 1

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, 2020	Dec. 31, 2019	Dec. 31, 2018
Restricted Stock Units
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Unvested restricted stock units and award beginning of the period	733,777	138,704
Unvested restricted stock units and award, granted	1,284,797	732,771	139,411
Unvested restricted stock units and award, vested	(273,787)	(69,235)	(53)
Unvested restricted stock units and award, forfeited	(91,799)	(68,463)	(654)
Unvested restricted stock units and award, end of the period	1,652,988	733,777	138,704
Unvested weighted average grant date fair value, beginning of the period	$ 25.20	$ 33.85
Unvested weighted average grant date fair value, granted	10.02	24.39	$ 33.85
Unvested weighted average grant date fair value, vested	25.09	33.72	32.86
Unvested weighted average grant date fair value, forfeited	19.65	25.43	32.86
Unvested weighted average grant date fair value, end of the period	$ 13.73	$ 25.20	$ 33.85
Performance Share Units
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Unvested restricted stock units and award beginning of the period	417,831	231,542
Unvested restricted stock units and award, granted	441,642	218,060	232,891
Unvested restricted stock units and award, forfeited	(25,301)	(31,771)	(1,349)
Unvested restricted stock units and award, end of the period	834,172	417,831	231,542
Unvested weighted average grant date fair value, beginning of the period	$ 39.31	$ 44.47
Unvested weighted average grant date fair value, granted	13.05	33.96	$ 44.47
Unvested weighted average grant date fair value, forfeited	37.67	40.27	42.94
Unvested weighted average grant date fair value, end of the period	$ 25.46	$ 39.31	$ 44.47

Employee Benefits Plans and S_5

Employee Benefits Plans and Share-Based Compensation - Summary of Assumptions Used to Calculate the Grant Date Fair Value (Details) - Performance Share Units - Simulation	Mar. 05, 2020	May 16, 2019	Mar. 05, 2019	Sep. 28, 2018	Aug. 29, 2018
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Number of simulations	100,000	100,000	100,000	100,000	100,000
Expected term (in years)	2 years 9 months 18 days	2 years 7 months 6 days	2 years 9 months 18 days	2 years 7 months 6 days	2 years 8 months 12 days
Expected volatility	48.80%	44.80%	46.90%	47.40%	50.60%
Risk-free interest rate	0.60%	2.10%	2.50%	2.90%	2.70%

Employee Benefits Plans and S_6

Employee Benefits Plans and Share-Based Compensation - Schedule of Recognized Share Based Compensation Expense, Net (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Employee Service Share Based Compensation Allocation Of Recognized Period Costs [Line Items]
Total share-based compensation expense	$ 16,462	$ 12,924	$ 6,509
Less: amounts capitalized to oil and gas properties	(7,793)	(5,960)	(3,616)
Total share-based compensation expense, net	8,669	6,964	2,893
Talos Energy Inc. Long Term Incentive Plan
Employee Service Share Based Compensation Allocation Of Recognized Period Costs [Line Items]
Total share-based compensation expense	16,227	12,523	2,091
Talos Energy LLC Series B Units
Employee Service Share Based Compensation Allocation Of Recognized Period Costs [Line Items]
Total share-based compensation expense	192	256	666
New Talos Energy LLC Series B Units
Employee Service Share Based Compensation Allocation Of Recognized Period Costs [Line Items]
Total share-based compensation expense	$ 43	$ 145	$ 3,752

Income Taxes - Components of In

Income Taxes - Components of Income Tax Expense (Benefit) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Current income tax expense (benefit)
United States	$ (499)	$ 437
Mexico	185	1,183	$ 1,345
Total current income tax expense (benefit)	(314)	1,620	1,345
Deferred income tax expense (benefit)
United States	35,923	(37,131)	1,064
Mexico	(26)	(630)	513
Total deferred income tax expense (benefit)	35,897	(37,761)	1,577
Total income tax expense (benefit)	$ 35,583	$ (36,141)	$ 2,922

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, 2020	Dec. 31, 2019	Dec. 31, 2018
Income Tax Disclosure [Abstract]
Income tax expense (benefit) at the federal statutory tax rate	$ (90,304)	$ 4,744	$ 47,137
Earnings not subject to tax			9,980
State income taxes	(14,215)	1,396	11,738
Foreign income taxes			1,008
Foreign rate differential	(1,030)	(4,948)	432
Prior year taxes	(4,237)	(1,950)	417
Other adjustments		137	800
Change in tax status			(35,925)
Legal entity reorganization	(17,566)	39,336
Change in valuation allowance	162,213	(75,196)	(32,665)
Other permanent differences	722	340
Total income tax expense (benefit)	$ 35,583	$ (36,141)	$ 2,922
Effective tax rate	(8.27%)	(159.99%)	1.30%

Income Taxes - Additional Infor

Income Taxes - Additional Information (Details) - USD ($) $ in Thousands	3 Months Ended		12 Months Ended
	Dec. 31, 2020	Mar. 31, 2020	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Income Tax Disclosure [Line Items]
Federal statutory rate			21.00%	21.00%
Deferred tax assets, valuation allowance	$ 178,998		$ 178,998	$ 19,118
Tax expense represents the non-cash impact from the legal entity conversion				38,900
Operating loss carryforwards expiration year			2035
Valuation allowance	179,000		$ 179,000	19,100
Period of cumulative loss position			3 years
Write-down of oil and natural gas properties	267,859	$ 57	$ 267,916	12,221
Earliest Tax Year
Income Tax Disclosure [Line Items]
Income tax examination, Year			2017
Latest Tax Year
Income Tax Disclosure [Line Items]
Income tax examination, Year			2019
Federal and State
Income Tax Disclosure [Line Items]
Deferred tax assets, valuation allowance	162,200		$ 162,200	80,200
Federal
Income Tax Disclosure [Line Items]
Deferred tax assets, valuation allowance				75,200
Operating loss carryforwards	637,200		637,200
Foreign
Income Tax Disclosure [Line Items]
Deferred tax assets, valuation allowance				5,000
Operating loss carryforwards	153,266		153,266
Internal Revenue Code | Federal and State
Income Tax Disclosure [Line Items]
Deferred tax assets, valuation allowance				17,600	$ 17,600
Internal Revenue Code | Federal
Income Tax Disclosure [Line Items]
Operating loss carryforwards	$ 537,900		$ 537,900
Subsidiaries
Income Tax Disclosure [Line Items]
Tax expense related to the reorganization of subsidiaries				$ 39,300

Income Taxes - Summary of Signi

Income Taxes - Summary of Significant Components of Deferred Tax Assets and Liabilities (Details) - USD ($) $ in Thousands	Dec. 31, 2020	Dec. 31, 2019
Deferred tax assets:
Federal net operating loss	$ 133,804	$ 131,204
Foreign tax loss carryforward	45,980	2,316
State net operating loss	25,740	24,270
Asset retirement obligations	106,604	89,059
Tax credits	522	449
Derivatives	16,346	2,794
Other well equipment inventory	9,470	10,014
Accrued bonus	3,069	3,753
Operating lease liabilities	4,904	2,317
Other	7,727	7,004
Total deferred tax assets	354,166	273,180
Valuation allowance	(178,998)	(19,118)
Total deferred tax assets, net	175,168	254,062
Deferred tax liabilities:
Oil and gas properties	170,596	211,216
Deferred financing	1,765	3,752
Operating lease assets	1,652	1,814
Prepaid	3,216	3,419
Total deferred tax liabilities	177,229	220,201
Net deferred tax (liability)	$ (2,061)
Net deferred tax asset		$ 33,861

Income Taxes - Summary of Net O

Income Taxes - Summary of Net Operating Loss Carryovers (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2020USD ($)
Operating Loss Carryforwards [Line Items]
Net operating losses, Expiration year	2035
Federal
Operating Loss Carryforwards [Line Items]
Net operating losses carryforward, Amount	$ 637,200
Net operating losses, Expiration term	Unlimited
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 - 2038
Operating Loss Carryforwards [Line Items]
Net operating losses carryforward, Amount	$ 537,938
Federal | Unlimited Expiration Year
Operating Loss Carryforwards [Line Items]
Net operating losses carryforward, Amount	99,223
Foreign
Operating Loss Carryforwards [Line Items]
Net operating losses carryforward, Amount	$ 153,266
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	2030
State
Operating Loss Carryforwards [Line Items]
Net operating losses carryforward, Amount	$ 400,568
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	2040

Income Taxes - Summary of Balan

Income Taxes - Summary of Balances In Uncertain Tax Positions (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Income Tax Disclosure [Abstract]
Total unrecognized tax benefits, beginning balance	$ 791	$ 360
Tax positions taken decrease during a prior period	(208)
Tax positions taken during a prior period		8
Tax positions taken during the current period	65	423
Total unrecognized tax benefits, ending balance	$ 648	$ 791

Income (Loss) Per Share - Summa

Income (Loss) Per Share - Summary of Computation of Basic and Diluted Income (Loss) Per Share (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2020	Sep. 30, 2020	Jun. 30, 2020	Mar. 31, 2020	Dec. 31, 2019	Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Earnings Per Share [Abstract]
Net income (loss)	$ (430,743)	$ (52,000)	$ (140,611)	$ 157,749	$ 304	$ 73,297	$ 94,764	$ (109,636)	$ (465,605)	$ 58,729	$ 221,540
Weighted average common shares outstanding — basic	75,199	71,286	65,807	58,240	54,203	54,200	54,178	54,156	67,664	54,185	46,058
Dilutive effect of securities										228	3
Weighted average common shares outstanding — diluted	75,199	71,286	65,807	58,572	54,559	54,430	54,451	54,156	67,664	54,413	46,061
Basic	$ (5.73)	$ (0.73)	$ (2.14)	$ 2.71	$ 0.01	$ 1.35	$ 1.75	$ (2.02)	$ (6.88)	$ 1.08	$ 4.81
Diluted	$ (5.73)	$ (0.73)	$ (2.14)	$ 2.69	$ 0.01	$ 1.35	$ 1.74	$ (2.02)	$ (6.88)	$ 1.08	$ 4.81
Anti-dilutive potentially issuable securities excluded from diluted common shares									5,019	4,220	3,538

Income (Loss) Per Share - Sum_2

Income (Loss) Per Share - Summary of Computation of Basic and Diluted Income (Loss) Per Share (Parenthetical) (Details) - shares shares in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Antidilutive Securities Excluded From Computation Of Earnings Per Share [Line Items]
Anti-dilutive potentially issuable securities excluded from diluted common shares	5,019	4,220	3,538
Warrant
Antidilutive Securities Excluded From Computation Of Earnings Per Share [Line Items]
Anti-dilutive potentially issuable securities excluded from diluted common shares	3,500
Warrants expiration date	Feb. 28, 2021

Related Party Transactions - Ad

Related Party Transactions - Additional Information (Details)	Mar. 30, 2020shares	Feb. 28, 2020USD ($)shares	Dec. 10, 2019	Aug. 31, 2018USD ($)	May 10, 2018RegistrationOffering	Aug. 31, 2018USD ($)	Dec. 31, 2020USD ($)	Dec. 31, 2019USD ($)	Dec. 31, 2018USD ($)	Nov. 21, 2017
Related Party Transaction [Line Items]
Net of cash acquired							$ 315,962,000	$ 37,916,000	$ (278,409,000)
7.50% Senior Notes – due May 2022
Related Party Transaction [Line Items]
Debt instrument, interest rate, stated percentage							7.50%	7.50%
11.00% Second-Priority Senior Secured Notes – due April 2022
Related Party Transaction [Line Items]
Debt instrument, interest rate, stated percentage							11.00%	11.00%
Bridge Loans
Related Party Transaction [Line Items]
Debt instrument, interest rate, stated percentage									11.00%
Senior Notes | 7.50% Senior Notes – due May 2022
Related Party Transaction [Line Items]
Debt instrument, interest rate, stated percentage							7.50%		7.50%	7.50%
Senior Notes | 11.00% Second-Priority Senior Secured Notes – due April 2022
Related Party Transaction [Line Items]
Debt instrument, interest rate, stated percentage							11.00%		11.00%	11.00%
Original Equity Registration Rights Agreement
Related Party Transaction [Line Items]
Fees incurred in conjunction with agreement							$ 200,000	$ 700,000	$ 1,800,000
Whistler Energy II, LLC
Related Party Transaction [Line Items]
Purchase price				$ 52,600,000
Available cash acquired				$ 37,800,000
Stone Energy Corporation
Related Party Transaction [Line Items]
Closing date of merger agreement							May 10, 2018
Work fees to debt holders									9,300,000
Stone Energy Corporation | 7.50% Senior Notes – due May 2022
Related Party Transaction [Line Items]
Debt instrument, interest rate, stated percentage							7.50%
Stone Energy Corporation | 11.00% Second-Priority Senior Secured Notes – due April 2022
Related Party Transaction [Line Items]
Debt instrument, interest rate, stated percentage							11.00%
Apollo Funds | Whistler Energy II, LLC | Whistler Energy II Holdco, LLC
Related Party Transaction [Line Items]
Net of cash acquired						$ 14,800,000
Business acquisition, date of acquisition agreement						Aug. 31, 2018
Aggregate consideration of cash						$ 52,600,000
Available cash acquired						$ 37,800,000
Primary fair values of receivables acquired							$ 1,100,000
Franklin Advisers, Inc. and MacKay Shields LLC | Registration Rights Agreement
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%
Threshold percentage of outstanding shares of common stock for termination of agreement					5.00%
Registration agreement, termination description								The Registration Rights Agreement has terminated with respect to Franklin and will terminate with respect to MacKay Shields in the event that MacKay Shields ceases to beneficially own 5% or more of the then outstanding shares of the Company’s common stock. The Registration Rights Agreement will otherwise terminate at such time as there are no Registrable Securities outstanding.
Vinson & Elkins L.L.P.
Related Party Transaction [Line Items]
Legal fees incurred							3,500,000	$ 4,200,000	4,400,000
Legal fees payable							700,000	$ 2,300,000	1,100,000
Apollo and Riverstone Funds
Related Party Transaction [Line Items]
Work fees to debt holders									4,100,000
Apollo and Riverstone Funds | Service Fee Agreement | Shareholder Service
Related Party Transaction [Line Items]
Service fee									500,000
Apollo and Riverstone Funds | Service Fee Agreement | Shareholder Service | Maximum
Related Party Transaction [Line Items]
Service fee							$ 500,000
Apollo and Riverstone Funds | Stone Energy Corporation | Service Fee Agreement | Shareholder Service
Related Party Transaction [Line Items]
Closing date of merger agreement							May 10, 2018
Franklin and McKay Noteholders
Related Party Transaction [Line Items]
Work fees to debt holders									$ 3,300,000
ILX and Castex
Related Party Transaction [Line Items]
Purchase price		$ 459,322,000
Net of cash acquired		303,122,000
Aggregate consideration of cash		385,000,000
ILX and Castex | Talos Energy LLC Stakeholders
Related Party Transaction [Line Items]
Aggregate consideration of cash		$ 385,000,000
Closing date of merger agreement			Jul. 1, 2019
ILX and Castex | Series A Convertible Preferred Stock | Talos Energy LLC Stakeholders
Related Party Transaction [Line Items]
Share issued on merger | shares	110,000	110,000
Shares issued upon conversion | shares	11,000,000
ILX and Castex | Riverstone Funds
Related Party Transaction [Line Items]
Purchase price		$ 459,300,000
Business combination, conversion stock		156,200,000
Net of cash acquired		$ 303,100,000

Commitments and Contingencies -

Commitments and Contingencies - Additional Information (Details) - USD ($) $ in Thousands	Dec. 31, 2020	Dec. 31, 2019
Loss Contingencies [Line Items]
Performance obligations	$ 2,965
Bank Credit Facility | Letter of Credit
Loss Contingencies [Line Items]
Credit facility	13,600	$ 13,600
Production Sharing Contracts | Mexico
Loss Contingencies [Line Items]
Performance obligations	$ 651,800	$ 637,300

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, 2020USD ($)
Contractual Obligation [Line Items]
2021	$ 2,965
Total	2,965
Vessel Commitments
Contractual Obligation [Line Items]
2021	800	[1]
Total	800	[1]
Committed Purchase Orders
Contractual Obligation [Line Items]
2021	2,165	[2]
Total	$ 2,165	[2]
[1]
[2]

Selected Quarterly Financial _3

Selected Quarterly Financial Data - Schedule Of Quarterly Financial Data (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2020	Sep. 30, 2020	Jun. 30, 2020	Mar. 31, 2020	Dec. 31, 2019	Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Quarterly Financial Information Disclosure [Abstract]
Revenues	$ 175,711	$ 135,137	$ 88,874	$ 187,764	$ 233,240	$ 228,857	$ 286,810	$ 178,713	$ 587,486	$ 927,620	$ 891,288
Write-down of oil and natural gas properties	267,859			57					267,916	12,221
Operating income (expense)	(285,436)	(37,059)	(94,603)	(4,212)	46,970	52,883	94,872	18,369	(421,310)	213,094	253,129
Price risk management activities income (expense)	(66,968)	(19,882)	(68,682)	243,217	(59,508)	43,760	29,990	(109,579)	87,685	(95,337)	60,435
Net income (loss)	$ (430,743)	$ (52,000)	$ (140,611)	$ 157,749	$ 304	$ 73,297	$ 94,764	$ (109,636)	$ (465,605)	$ 58,729	$ 221,540
Net income (loss) per common share:
Basic	$ (5.73)	$ (0.73)	$ (2.14)	$ 2.71	$ 0.01	$ 1.35	$ 1.75	$ (2.02)	$ (6.88)	$ 1.08	$ 4.81
Diluted	$ (5.73)	$ (0.73)	$ (2.14)	$ 2.69	$ 0.01	$ 1.35	$ 1.74	$ (2.02)	$ (6.88)	$ 1.08	$ 4.81
Weighted average common shares outstanding:
Basic	75,199	71,286	65,807	58,240	54,203	54,200	54,178	54,156	67,664	54,185	46,058
Diluted	75,199	71,286	65,807	58,572	54,559	54,430	54,451	54,156	67,664	54,413	46,061

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, 2020USD ($)$ / MBoe	Dec. 31, 2019USD ($)$ / MBoe
Extractive Industries [Abstract]
Proved properties	$ 4,945,550	$ 4,066,260
Unproved oil and gas properties, not subject to amortization	254,994	194,532
Total oil and gas properties	5,200,544	4,260,792
Less: Accumulated depletion	(2,680,254)	(2,051,856)
Net capitalized costs	$ 2,520,290	$ 2,208,936
Depletion and amortization rate (Per Boe) | $ / MBoe	31.42	18.05

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, 2020	Dec. 31, 2019
Capitalized Costs Relating To Oil And Gas Producing Activities By Geographic Area [Line Items]
Unproved properties, not subject to amortization	$ 254,994	$ 194,532
Mexico
Capitalized Costs Relating To Oil And Gas Producing Activities By Geographic Area [Line Items]
Unproved properties, not subject to amortization	$ 121,700	$ 106,900

Supplemental Oil and Gas Disc_5

Supplemental Oil and Gas Disclosures - Additional Information (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2020USD ($)MMBoe	Dec. 31, 2019USD ($)MMBoe	Dec. 31, 2018USD ($)MMBoe
Reserve Quantities [Line Items]
Oil and gas asset retirement obligations | $	$ 442,269	$ 369,478	$ 382,817
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 reserves decrease	21.3	10	51.1
Decrease of production	20	19	16.7
Revision to previous estimates	24.2	9.7
Estimated proved reserves from extensions and discoveries		15.7	5.6
Purchases of estimated proved reserves			62.8
Prescribed rate of discounted future net cash flows	10.00%
ILX and Castex Acquisition
Reserve Quantities [Line Items]
Estimated proved reserves from extensions and discoveries	60.7
LLOG Acquisition
Reserve Quantities [Line Items]
Purchases of estimated proved reserves	4.7
Gunflint Acquisition
Reserve Quantities [Line Items]
Purchases of estimated proved reserves		3
Stone Energy Corporation
Reserve Quantities [Line Items]
Purchases of estimated proved reserves			59.3
Whistler Energy II, LLC
Reserve Quantities [Line Items]
Purchases of estimated proved reserves			3.5

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, 2020	Dec. 31, 2019	Dec. 31, 2018
Property acquisition costs:
Proved properties	$ 422,833	$ 27,660	$ 850,515
Unproved properties, not subject to amortization	95,242	16,062	65,063
Total property acquisition costs	518,075	43,722	915,578
Exploration costs	59,422	209,161	93,780
Development costs	362,011	292,547	215,467
Total costs incurred	$ 939,508	$ 545,430	$ 1,224,825

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 ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Costs Incurred Oil And Gas Property Acquisition Exploration And Development Activities [Line Items]
Exploration costs	$ 59,422	$ 209,161	$ 93,780
Mexico
Costs Incurred Oil And Gas Property Acquisition Exploration And Development Activities [Line Items]
Exploration costs	$ 14,600	$ 74,200	$ 16,900

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, 2020MBoeMMBoeMBblsMMcf	Dec. 31, 2019MBoeMMBoeMBblsMMcf	Dec. 31, 2018MBoeMMBoeMBblsMMcf
Reserve Quantities [Line Items]
Total proved reserves, beginning balance | MMBoe	10	51.1
Revision of previous estimates | MMBoe	(24.2)	(9.7)
Production | MMBoe	(20)	(19)	(16.7)
Purchases of reserves | MMBoe			62.8
Extensions and discoveries | MMBoe		15.7	5.6
Total proved reserves, ending balance | MMBoe	21.3	10	51.1
Oil (MBbls)
Reserve Quantities [Line Items]
Total proved reserves, beginning balance	106,754	112,539	72,804
Revision of previous estimates	(14,633)	(5,553)	2,595
Production	(13,665)	(13,844)	(11,771)
Purchases of reserves	26,903	2,094	44,788
Extensions and discoveries	3,948	11,518	4,123
Total proved reserves, ending balance	109,307	106,754	112,539
Total proved developed reserves	85,007	72,016	85,530
Total proved undeveloped reserves	24,300	34,738	27,009
Gas (MMcf)
Reserve Quantities [Line Items]
Total proved reserves, beginning balance | MMcf	155,998	171,024	127,656
Revision of previous estimates | MMcf	(56,358)	(15,898)	(37,933)
Production | MMcf	(28,652)	(23,306)	(22,771)
Purchases of reserves | MMcf	181,872	2,626	95,661
Extensions and discoveries | MMcf	4,348	21,552	8,411
Total proved reserves, ending balance | MMcf	257,208	155,998	171,024
Total proved developed reserves | MMcf	204,054	115,381	131,364
Total proved undeveloped reserves | MMcf	53,154	40,617	39,660
NGL (MBbls)
Reserve Quantities [Line Items]
Total proved reserves, beginning balance	8,981	10,696	6,547
Revision of previous estimates	(168)	(1,237)	3,187
Production	(1,559)	(1,228)	(1,176)
Purchases of reserves	3,528	130	2,074
Extensions and discoveries	76	620	64
Total proved reserves, ending balance	10,858	8,981	10,696
Total proved developed reserves	8,104	6,733	8,104
Total proved undeveloped reserves	2,754	2,248	2,592
Oil Equivalent (MBoe)
Reserve Quantities [Line Items]
Total proved reserves, beginning balance | MBoe	141,735	151,739	100,625
Revision of previous estimates | MBoe	(24,195)	(9,440)	(539)
Production | MBoe	(19,999)	(18,956)	(16,742)
Purchases of reserves | MBoe	60,743	2,662	62,806
Extensions and discoveries | MBoe	4,749	15,730	5,589
Total proved reserves, ending balance | MBoe	163,033	141,735	151,739
Total proved developed reserves | MBoe	127,120	97,979	115,528
Total proved undeveloped reserves | MBoe	35,913	43,756	36,211

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, 2020MMBoe	Dec. 31, 2019MBoeMMBoe	Dec. 31, 2018MMBoe
Reserve Quantities [Line Items]
Production | MMBoe	20	19	16.7
Mexico
Reserve Quantities [Line Items]
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, 2020	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Extractive Industries [Abstract]
Future cash inflows	$ 4,927,497	$ 7,151,875	$ 8,654,631
Future costs:
Production	(1,105,211)	(1,633,432)	(1,740,850)
Development and abandonment	(1,236,874)	(1,464,270)	(1,349,005)
Future net cash flows before income taxes	2,585,412	4,054,173	5,564,776
Future income tax expense	(141,515)	(662,317)	(862,473)
Future net cash flows after income taxes	2,443,897	3,391,856	4,702,303
Discount at 10% annual rate	(538,963)	(854,261)	(1,362,057)
Standardized measure of discounted future net cash flows	$ 1,904,934	$ 2,537,595	$ 3,340,246	$ 1,807,669

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, 2020$ / bbl$ / Mcf	Dec. 31, 2019$ / bbl$ / Mcf	Dec. 31, 2018$ / bbl$ / Mcf
Oil
Discounted Future Net Cash Flows Relating To Proved Oil And Gas Reserves [Line Items]
Base price	39.47	61.01	69.42
Natural Gas
Discounted Future Net Cash Flows Relating To Proved Oil And Gas Reserves [Line Items]
Base price | $ / Mcf	1.97	2.59	3.08
NGL
Discounted Future Net Cash Flows Relating To Proved Oil And Gas Reserves [Line Items]
Base price	9.89	26.17	29.50

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, 2020	Dec. 31, 2019	Dec. 31, 2018
Extractive Industries [Abstract]
Standardized measure, beginning of year	$ 2,537,595	$ 3,340,246	$ 1,807,669
Sales and transfers of oil, net gas and NGLs produced during the period	(339,557)	(665,226)	(727,969)
Net change in prices and production costs	(1,468,304)	(849,696)	1,578,330
Changes in estimated future development costs	32,589	(75,564)	32,328
Previously estimated development costs incurred	46,143	117,049	45,937
Accretion of discount	299,302	392,526	180,767
Net change in income taxes	361,875	129,590	(585,017)
Purchases of reserves	730,611	75,009	943,519
Extensions and discoveries	71,589	306,515	148,068
Net change due to revision in quantity estimates	(309,338)	(199,576)	190,853
Changes in production rates (timing) and other	(57,571)	(33,278)	(274,239)
Standardized measure, end of year	$ 1,904,934	$ 2,537,595	$ 3,340,246