Talos Energy (TALO) 10-K 1 Mar 23 2022 FY Annual report Financial data

Document and Entity Information

Document and Entity Information - USD ($)	12 Months Ended
	Dec. 31, 2022	Feb. 21, 2023	Jun. 30, 2022
Cover [Abstract]
Document Type	10-K
Amendment Flag	false
Document Period End Date	Dec. 31, 2022
Document Fiscal Year Focus	2022
Document Fiscal Period Focus	FY
Trading Symbol	TALO
Title of 12(b) Security	Common Stock
Security Exchange Name	NYSE
Entity Registrant Name	Talos Energy Inc.
Document Annual Report	true
Document Transition Report	false
Entity Small Business	false
Entity Emerging Growth Company	false
ICFR Auditor Attestation Flag	true
Auditor Name	Ernst & Young LLP
Auditor Location	Houston, Texas
Auditor Firm ID	42
Entity Current Reporting Status	Yes
Entity Interactive Data Current	Yes
Entity Shell Company	false
Entity Incorporation, State or Country Code	DE
Entity File Number	001-38497
Entity Tax Identification Number	82-3532642
Entity Address, Address Line One	333 Clay Street
Entity Address, Address Line Two	Suite 3300
Entity Address, City or Town	Houston
Entity Address, State or Province	TX
Entity Address, Postal Zip Code	77002
City Area Code	713
Local Phone Number	328-3000
Entity Central Index Key	0001724965
Current Fiscal Year End Date	--12-31
Entity Filer Category	Large Accelerated Filer
Entity Common Stock, Shares Outstanding		126,370,218
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Public Float			$ 1,076,771,374
Documents Incorporated by Reference	Portions of the registrant’s definitive proxy statement relating to the 2023 Annual Meeting of Stockholders are incorporated by reference into Part III of this report.

CONSOLIDATED BALANCE SHEETS

CONSOLIDATED BALANCE SHEETS - USD ($) $ in Thousands	Dec. 31, 2022	Dec. 31, 2021
Current assets:
Cash and cash equivalents	$ 44,145	$ 69,852
Accounts receivable
Trade, net	150,598	173,241
Joint interest, net	54,697	28,165
Other, net	6,684	18,062
Assets from price risk management activities	25,029	967
Prepaid assets	84,759	48,042
Other current assets	1,917	1,674
Total current assets	367,829	340,003
Property and equipment:
Proved properties	5,964,340	5,232,479
Unproved properties, not subject to amortization	154,783	219,055
Other property and equipment	30,691	29,091
Total property and equipment	6,149,814	5,480,625
Accumulated depreciation, depletion and amortization	(3,506,539)	(3,092,043)
Total property and equipment, net	2,643,275	2,388,582
Other long-term assets:
Assets from price risk management activities	7,854	2,770
Equity method investments	1,745	0
Other well equipment inventory	25,541	17,449
Operating lease assets	5,903	5,714
Other assets	6,479	12,297
Total assets	3,058,626	2,766,815
Current liabilities:
Accounts payable	128,174	85,815
Accrued liabilities	219,769	130,459
Accrued royalties	52,215	59,037
Current portion of long-term debt	0	6,060
Current portion of asset retirement obligations	39,888	60,311
Liabilities from price risk management activities	68,370	186,526
Accrued interest payable	36,340	37,542
Current portion of operating lease liabilities	1,943	1,715
Other current liabilities	60,359	33,061
Total current liabilities	607,058	600,526
Long-term liabilities:
Long-term debt, net of discount and deferred financing costs	585,340	956,667
Asset retirement obligations	501,773	373,695
Liabilities from price risk management activities	7,872	13,938
Operating lease liabilities	14,855	16,330
Other long-term liabilities	176,152	45,006
Total liabilities	1,893,050	2,006,162
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, 2022 and 2021	0	0
Common stock $0.01 par value; 270,000,000 shares authorized; 82,570,328 and 81,881,477 shares issued and outstanding as of December 31, 2022 and 2021, respectively	826	819
Additional paid-in capital	1,699,799	1,676,798
Accumulated deficit	(535,049)	(916,964)
Total stockholdersʼ equity	1,165,576	760,653
Total liabilities and stockholdersʼ equity	$ 3,058,626	$ 2,766,815

CONSOLIDATED BALANCE SHEETS (Pa

CONSOLIDATED BALANCE SHEETS (Parenthetical) - $ / shares	Dec. 31, 2022	Dec. 31, 2021
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	82,570,328	81,881,477
Common stock, shares outstanding	82,570,328	81,881,477

CONSOLIDATED STATEMENTS OF OPER

CONSOLIDATED STATEMENTS OF OPERATIONS - USD ($) shares in Thousands, $ in Thousands	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Revenues:
Total revenues	$ 1,651,980	$ 1,244,540	$ 575,936
Operating expenses:
Lease operating expense	308,092	283,601	246,564
Production taxes	3,488	3,363	1,054
Depreciation, depletion and amortization	414,630	395,994	364,346
Write-down of oil and natural gas properties	0	18,123	267,916
Accretion expense	55,995	58,129	49,741
General and administrative expense	99,754	78,677	79,175
Other operating (income) expense	33,902	32,037	(11,550)
Total operating expenses	915,861	869,924	997,246
Operating income (expense)	736,119	374,616	(421,310)
Interest expense	(125,498)	(133,138)	(99,415)
Price risk management activities income (expense)	(272,191)	(419,077)	87,685
Equity method investment income	14,222	0	0
Other income (expense)	31,800	(6,988)	3,018
Net income (loss) before income taxes	384,452	(184,587)	(430,022)
Income tax benefit (expense)	(2,537)	1,635	(35,583)
Net income (loss)	$ 381,915	$ (182,952)	$ (465,605)
Net income (loss) per common share:
Basic	$ 4.63	$ (2.24)	$ (6.88)
Diluted	$ 4.56	$ (2.24)	$ (6.88)
Weighted average common shares outstanding:
Basic	82,454	81,769	67,664
Diluted	83,683	81,769	67,664
Oil
Revenues:
Revenues	$ 1,365,148	$ 1,064,161	$ 506,788
Natural Gas
Revenues:
Revenues	227,306	130,616	53,714
NGL
Revenues:
Revenues	$ 59,526	$ 49,763	$ 15,434

CONSOLIDATED STATEMENTS OF CHAN

CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS' EQUITY (DEFICIT) - USD ($) $ in Thousands	Total	Common Stock	Preferred Stock	Additional Paid-in Capital	Accumulated Deficit
Balance at Dec. 31, 2019	$ 1,078,277	$ 542		$ 1,346,142	$ (268,407)
Balance, shares at Dec. 31, 2019		54,197,004
Equity based compensation	16,462			16,462
Equity-based compensation tax withholdings	(827)			(827)
Equity-based compensation stock issuances		$ 1		(1)
Equity-based compensation stock issuances, shares		180,525
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
Equity based compensation	20,165			20,165
Equity-based compensation tax withholdings	(3,161)			(3,161)
Equity-based compensation stock issuances		$ 6		(6)
Equity-based compensation stock issuances, shares		601,488
Net income (loss)	(182,952)				(182,952)
Balance at Dec. 31, 2021	$ 760,653	$ 819		1,676,798	(916,964)
Balance, shares at Dec. 31, 2021	81,881,477	81,881,477
Equity based compensation	$ 27,611			27,611
Equity-based compensation tax withholdings	(4,603)			(4,603)
Equity-based compensation stock issuances		$ 7		(7)
Equity-based compensation stock issuances, shares		688,851
Net income (loss)	381,915				381,915
Balance at Dec. 31, 2022	$ 1,165,576	$ 826		$ 1,699,799	$ (535,049)
Balance, shares at Dec. 31, 2022	82,570,328	82,570,328

CONSOLIDATED STATEMENTS OF CASH

CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Cash flows from operating activities:
Net income (loss)	$ 381,915	$ (182,952)	$ (465,605)
Adjustments to reconcile net income (loss) to net cash provided by operating activities
Depreciation, depletion, amortization and accretion expense	470,625	454,123	414,087
Write-down of oil and natural gas properties and other well inventory	0	23,729	268,615
Amortization of deferred financing costs and original issue discount	14,379	13,382	6,804
Equity-based compensation expense	15,953	10,992	8,669
Price risk management activities expense (income)	272,191	419,077	(87,685)
Net cash received (paid) on settled derivative instruments	(425,559)	(290,164)	143,905
Equity method investment income	(14,222)	0	0
Loss (gain) on extinguishment of debt	1,569	13,225	(1,662)
Settlement of asset retirement obligations	(69,596)	(67,988)	(43,933)
Gain on sale of assets	303	(687)	0
Changes in operating assets and liabilities:
Accounts receivable	14,927	(35,396)	(34,645)
Other current assets	(36,545)	(18,901)	35,934
Accounts payable	24,258	(6,261)	27,096
Other current liabilities	73,531	64,800	4,200
Other non-current assets and liabilities, net	(13,990)	14,409	26,143
Net cash provided by operating activities	709,739	411,388	301,923
Cash flows from investing activities:
Exploration, development and other capital expenditures	(323,164)	(293,331)	(362,942)
Cash paid for acquisitions, net of cash acquired	(3,500)	(5,399)	(315,962)
Proceeds from sale of property and equipment, net	1,937	4,983	0
Contributions to equity method investees	(2,250)	0	0
Proceeds from sale of equity method investment	15,000	0	0
Net cash used in investing activities	(311,977)	(293,747)	(678,904)
Cash flows from financing activities:
Proceeds from issuance of common stock	0	0	71,100
Issuance of senior notes	0	600,500	0
Redemption of senior notes and other long-term debt	(18,184)	(356,803)	(5,364)
Proceeds from Bank Credit Facility	85,000	100,000	350,000
Repayment of Bank Credit Facility	(460,000)	(365,000)	(60,000)
Deferred financing costs	(189)	(27,833)	(1,287)
Other deferred payments	0	(7,921)	(11,921)
Payments of finance lease	(25,493)	(21,804)	(17,509)
Employee stock awards tax withholdings	(4,603)	(3,161)	(827)
Net cash provided by (used in) financing activities	(423,469)	(82,022)	324,192
Net increase (decrease) in cash and cash equivalents	(25,707)	35,619	(52,789)
Cash and cash equivalents:
Balance, beginning of period	69,852	34,233	87,022
Balance, end of period	44,145	69,852	34,233
Supplemental non-cash transactions:
Capital expenditures included in accounts payable and accrued liabilities	105,773	45,761	74,957
Debt exchanged for common stock	0	0	35,960
Supplemental cash flow information:
Interest paid, net of amounts capitalized	$ 91,809	$ 68,891	$ 67,443

Organization, Nature of Busines

Organization, Nature of Business and Basis of Presentation	12 Months Ended
	Dec. 31, 2022
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Organization, Nature of Business and Basis of Presentation	Note 1 — Organization, Nature of Business and Basis of Presentation Organization and Nature of Business Talos Energy Inc. (the “Parent Company”) is a Delaware corporation originally incorporated on November 14, 2017 . On May 10, 2018 , the Parent Company consummated a combination between Talos Energy LLC and Stone Energy Corporation (“Stone”) (such combination, “Stone Combination”). Talos Energy LLC, which was the acquirer of Stone for financial reporting and accounting purposes, was formed in 2011 and commenced commercial operations on February 6, 2013 . The Parent Company conducts all business operations through its operating subsidiaries, owns no operating assets and has no material operations, cash flows or liabilities independent of its subsidiaries. The Parent Company’s common stock is traded on the New York Stock Exchange under the ticker symbol “TALO.” The Parent Company (including its subsidiaries, collectively “Talos” or the “Company”) is a technically driven independent exploration and production company focused on safely and efficiently maximizing long-term value through its operations, currently in the United States (“U.S.”) and offshore Mexico both through upstream oil and gas exploration and production and the development of carbon capture and sequestration (“CCS”) opportunities. The Company leverages decades of technical and offshore operational expertise in the acquisition, exploration and development of assets in key geological trends that are present in many offshore basins around the world. With a focus on environmental stewardship, the Company also utilizes its expertise to explore opportunities to reduce industrial emissions through the Company’s CCS initiatives along the coast of the U.S. Gulf of Mexico. Basis of Presentation and Consolidation The Consolidated Financial Statements have been prepared in accordance with GAAP and include the accounts of the Parent Company and entities in which the Parent Company holds a controlling financial interest. Both majority-owned subsidiaries and any variable interest entity in which the Parent Company is the primary beneficiary are consolidated. All intercompany transactions have been eliminated. All adjustments are of a normal, recurring nature and are necessary to fairly present the financial position, results of operations and cash flows for the periods reflected herein. The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities as of the date of the financial statements, the reported amounts of revenues and expenses during the reporting periods and the reported amounts of proved oil and natural gas reserves. Actual results could differ from those estimates. Segments The Company has two operating segments: (i) exploration and production of oil, natural gas and NGLs (“Upstream Segment”) and (ii) CCS (“CCS Segment”). The Upstream Segment is the Company’s only reportable segment. The legal entities included in the CCS Segment have been designated as unrestricted, non-guarantor subsidiaries of the Company for purposes of the Bank Credit Facility (as defined in Note 2 — Summary of Significant Accounting Policies ) and indenture governing the senior notes. See additional information in Note 13 — Segment Information.

Summary of Significant Accounti

Summary of Significant Accounting Policies	12 Months Ended
	Dec. 31, 2022
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Summary of Significant Accounting Policies	Note 2 — Summary of Significant Accounting Policies Overview of Significant Accounting Policies Cash and Cash Equivalents — The Company presents cash as “Cash and cash equivalents” on the Company’s Consolidated Balance Sheets. The Company considers all cash, money market funds and highly liquid investments with an original maturity of three months or less as cash and cash equivalents. Cash and cash equivalents are carried at cost, which approximates fair value. Accounts Receivable and Allowance for Expected Credit Losses — Accounts receivable are stated at the historical carrying amount net of an allowance for expected credit losses. At each reporting period, the recoverability of material receivables is assessed using historical data, current market conditions and reasonable and supported forecasts of future economic conditions to determine their expected collectability. A loss-rate methodology is used to estimate the allowance for expected credit losses to be accrued on material receivables to reflect the net amount to be collected. As of December 31, 2022 and 2021 , the Company had allowances of $ 10.7 million and $ 15.1 million, respectively, presented net in accounts receivable on the Consolidated Balance Sheets. The Company presented $ 3.2 million and $ 10.0 million of long-term refund claims for value added taxes paid in Mexico in “Other assets” on the Consolidated Balance Sheets as of December 31, 2022 and 2021 , respectively. Current refund claims for value added taxes paid in Mexico of $ 1.7 million and $ 3.9 million is presented net of an allowance in “Other” accounts receivable on the Consolidated Balance Sheets as of December 31, 2022 and 2021 , respectively. Price Risk Management Activities — The Company uses commodity price derivatives to manage fluctuating oil and natural gas market risks. The Company periodically enters into commodity derivative contracts, which may require payments to (or receipts from) counterparties based on the differential between a fixed price and a variable price for a fixed quantity of oil or natural gas without the exchange of underlying volumes. Commodity derivatives are recorded on the Consolidated Balance Sheets at fair value with settlements of such contracts and changes in the unrealized fair value recorded in earnings each period. Realized gains and losses on the settlement of commodity derivatives and changes in their unrealized gains and losses are reported in “Price risk management activities income (expense)” on the Consolidated Statements of Operations. The Company classifies cash flows related to derivative contracts based on the nature and purpose of the derivative. As the derivative cash flows are considered an integral part of the Company’s oil and natural gas operations, they are classified as cash flows from operating activities. The Company does not enter into derivative agreements for trading or other speculative purposes. The commodity derivative’s fair value reflects the Company’s best estimate with priority based upon exchange or over-the-counter quotations. Quoted valuations may not be available due to location differences or terms that extend beyond the period for which quotations are available. Where quotes are not available, the Company then utilizes other valuation techniques or models to estimate market values. These modeling techniques require the Company to make estimations of future prices, price correlation, market volatility and liquidity. The Company’s actual results may differ from its estimates, and these differences can be favorable or unfavorable. Prepaid Assets — Prepaid assets primarily represent prepaid subscriptions, insurance, progress payments for well equipment and deposits with the Office of Natural Resources Revenue (“ONRR”) . The progress payments made for well equipment relate to long lead time items which the Company has not taken title to as of period end. The deposits with ONRR represent the Company’s estimated federal royalties payable within thirty days of the production date. On a monthly basis the Company adjusts the deposit based on actual royalty payments remitted to the ONRR. Accounting for Oil and Natural Gas Activities — The Company follows the full cost method of accounting for oil and natural gas exploration and development activities. Under the full cost method, substantially all costs incurred in connection with the acquisition, development and exploration of oil and natural gas reserves are capitalized. These capitalized amounts include the internal costs directly related to acquisition, development and exploration activities, asset retirement costs and capitalized interest. Under the full cost method, dry hole costs and geological and geophysical costs are capitalized into the full cost pool, which is subject to amortization and assessed for impairment on a quarterly basis through a ceiling test calculation as discussed below. Capitalized costs associated with proved reserves are amortized on a country-by-country basis over the life of the total proved reserves using the unit of production method, computed quarterly. Conversely, capitalized costs associated with unproved properties and related geological and geophysical costs, exploration wells currently drilling and capitalized interest are initially excluded from the amortizable base. The Company transfers unproved property costs into the amortizable base when properties are determined to have proved reserves or when the Company has completed an unproved properties evaluation resulting in an impairment. The Company evaluates each of these unproved properties individually for impairment at least annually. Additionally, the amortizable base includes future development costs, dismantlement, restoration and abandonment costs, net of estimated salvage values, and geological and geophysical costs incurred that cannot be associated with specific unproved properties or prospects in which the Company owns a direct interest. The Company capitalizes overhead costs that are directly related to exploration, acquisition and development activities. The Company’s capitalized costs are limited to a ceiling based on the present value of future net revenues from proved reserves, computed using a discount factor of 10 %, plus the lower of cost or estimated fair value of unproved oil and natural gas properties not being amortized less the related tax effects. Generally, any costs in excess of the ceiling are recognized as a non-cash “Write-down of oil and natural gas properties” on the Consolidated Statements of Operations and an increase to “Accumulated depreciation, depletion and amortization” on the Company’s Consolidated Balance Sheets. The expense may not be reversed in future periods, even though higher oil, natural gas and NGL prices may subsequently increase the ceiling. The Company performs this ceiling test calculation each quarter. In accordance with the SEC rules and regulations, the Company utilizes SEC Pricing when performing the ceiling test. The Company also holds prices and costs constant over the life of the reserves, even though actual prices and costs of oil and natural gas are often volatile and may change from period to period. Under the full cost method of accounting for oil and natural gas operations, assets whose costs are currently being depreciated, depleted or amortized are assets in use in the earnings activities of the enterprise and do not qualify for capitalization of interest cost. Investments in unproved properties for which exploration and development activities are in progress and other major development projects that are not being currently depreciated, depleted or amortized are assets qualifying for capitalization of interest costs. When the Company sells or conveys interests in oil and natural gas properties, the Company reduces its oil and natural gas reserves for the amount attributable to the sold or conveyed interest. The Company treats sales proceeds on non-significant sales as reductions to the cost of the Company’s oil and natural gas properties. The Company does not recognize a gain or loss on sales of oil and natural gas properties, unless those sales would significantly alter the relationship between capitalized costs and proved reserves. Accounting for CCS Development Activities — Expenditures for CCS during the preliminary stages of development are charged to expense as incurred until the development of the project is considered probable. These costs primarily include professional fees associated with front-end engineering and design work, costs of securing necessary regulatory approvals and other preliminary investigation and development activities. The pre-construction stage of project development begins once construction of the individual project becomes probable. Certain costs may be capitalized prior to a project becoming probable and include: land acquisition costs; detailed engineering design work; and costs that have an alternative use (e.g., stratigraphic test well). Capitalized development costs are included as a component of other long-term assets during the pre-construction stage of development. These capitalized costs are charged to expense if a project is abandoned or management otherwise determines the costs to be unrecoverable. CCS contracts that convey subsurface rights for geologic pore space are accounted for as intangible assets and amortized over their estimated useful life. As of December 31, 2022 and 2021, the Company had $ 1.4 million and nil intangible assets, respectively. These assets are classified as other long-term assets and included in “Other assets” on the Consolidated Balance Sheets. Costs to renew or extend the life of CCS intangible assets are capitalized and amortized over the remaining useful life. Other Property and Equipment — Other property and equipment is recorded at cost and consists primarily of leasehold improvements, office furniture and fixtures and computer hardware. Acquisitions and betterments are capitalized; maintenance and repairs are expensed as incurred. Depreciation is provided using the straight-line method over estimated useful lives of three to ten years . Equity Method Investments — If the entity is organized as a limited partnership or limited liability company and maintains separate ownership accounts, the Company accounts for its investment using the equity method if the Company’s ownership interest is between  3 % and  50 %, unless the Company’s interest is so minor that it has virtually no influence over the investee’s operating and financial policies. For all other types of investments, the Company applies the equity method of accounting if its ownership interest is between  20 % and  50 % and the Company’s exercise significant influence over the investee’s operating and financial policies. In applying the equity method of accounting, the investments are initially recognized at cost and subsequently adjusted for the Company’s proportionate share of earnings, losses, contributions and distributions. Investments accounted for using the equity method are reflected as “Equity method investments” on the Consolidated Balance Sheets. The equity in earnings of an investee are reflected in “Equity method investment income (loss)” on the Consolidated Statement of Operations. The gain or loss from the full or partial sale of an equity method investment is presented in the same line item in which the Company reports the equity in earnings of the investee. The Company assesses equity method investments for impairment whenever changes in the facts and circumstances indicate a loss in value has occurred if the loss is deemed to be other-than-temporary. When the loss is deemed to be other-than-temporary, the carrying value of the equity method investment is written down to fair value. The impairment charge is included as a component of the Company’s share of the earning or losses of the investee. No impairment charges have been recorded during the years ended December 31, 2022, 2021 and 2020 . Other Well Equipment Inventory — Other well equipment inventory primarily represents the cost of equipment to be used in the Company’s oil and natural gas drilling and development activities such as drilling pipe, tubulars and certain wellhead equipment. When well equipment is supplied to wells, the cost is capitalized in oil and gas properties, and if such property is jointly owned, the proportionate costs will be reimbursed by third party participants. The Company’s well equipment is stated at the lower of cost or net realizable value. The Company recorded nil , $ 5.6 million and $ 0.7 million of impairment to adjust inventory to net realizable value, which was expensed and reflected in “Other operating (income) expense” on the Consolidated Statements of Operations, during the years ended December 31, 2022, 2021 and 2020 , respectively. Leases — At inception, contracts are reviewed to determine whether the agreement contains a lease. To the extent an arrangement is determined to include a lease, it is classified as either an operating or a finance lease, which dictates the pattern of expense recognition in the income statement. Operating leases are reflected as “Operating lease assets,” “Current portion of operating lease liabilities” and “Operating lease liabilities” on the Consolidated Balance Sheets. Finance leases are included in “Property and equipment,” “Other current liabilities” and “Other long-term liabilities” on the Consolidated Balance Sheets. A right-of-use (“ROU”) asset representing our right to use an underlying asset for the lease term and a lease liability representing our obligation to make lease payments arising from the lease are recognized on the Consolidated Balance Sheets for all leases, regardless of classification. The ROU asset is initially measured as the present value of the lease liability adjusted for any payments made prior to lease commencement, including any initial direct costs incurred and incentives received. Lease liabilities are initially measured at the present value of future minimum lease payments, excluding variable lease payments, over the lease term. As most of our leases do not provide an implicit rate, the Company generally uses an incremental borrowing rate based on the estimated rate of interest for collateralized borrowing over a similar term of the lease payments at commencement date. The Company has elected to account for lease and non-lease components in its contracts as a single lease component for all asset classes except for our leased floating production vessel class. Our lease terms may include options to extend or terminate the lease when it is reasonably certain that the Company will exercise that option. The Company has elected, as an accounting policy, not to record leases with terms of twelve months or less (i.e., short-term) on the Consolidated Balance Sheets. See Note 5 — Leases for additional information . Debt Issuance Costs — The Company presents debt issuance costs associated with revolving line-of-credit arrangements as a reduction of the carrying value of long-term debt. Asset Retirement Obligations — The Company has obligations associated with the retirement of its oil and natural gas wells and related infrastructure. The Company has obligations to plug wells when production on those wells is exhausted, when the Company no longer plans to use them or when the Company abandons them. The Company accrues a liability with respect to these obligations based on its estimate of the timing and amount to replace, remove or retire the associated assets. In estimating the liability associated with its asset retirement obligations, the Company utilizes several assumptions, including a credit-adjusted risk-free interest rate, estimated costs of decommissioning services, estimated timing of when the work will be performed and a projected inflation rate. Changes in estimate represent changes to the expected amount and timing of payments to settle its asset retirement obligations. Typically, these changes result from obtaining new information about the timing of its obligations to plug and abandon oil and natural gas wells and the costs to do so. After initial recording, the liability is increased for the passage of time, with the increase being reflected as “Accretion expense” on the Company’s Consolidated Statements of Operations. If the Company incurs an amount different from the amount accrued for asset retirement obligations, the Company recognizes the difference as an adjustment to proved properties. Decommissioning Obligations — Certain counterparties in divestiture transactions or third parties in existing leases that have filed for bankruptcy protection or undergone associated reorganizations may not be able to perform required abandonment obligations. The Company may be held jointly and severally liable for the decommissioning of various facilities and related wells. The Company accrues losses associated with decommissioning obligations when such losses are probable and reasonably estimable. When there is a range of possible outcomes, the amount accrued is the most likely outcome within the range. If no single outcome within the range is more likely than the others, the minimum amount in the range is accrued. These accruals may be adjusted as additional information becomes available. In addition, when decommissioning obligations are reasonably possible, the Company discloses an estimate for a possible loss or range of loss (or a statement that such an estimate cannot be reasonably made). See Note 12 — Commitments & Contingencies for additional information. Share-Based Compensation — Certain of the Company’s employees participate in its equity-based compensation plan. The Company measures all employee equity-based compensation awards at fair value on the date awards are granted to its employees . The fair value of the stock-based awards is determined at the date of grant and is not remeasured for awards classified as equity unless the award is modified. Liability classified awards are remeasured at each reporting period. The Company records share-based compensation, net of actual forfeitures, for the RSUs and PSUs in “General and administrative expense” on the Consolidated Statements of Operations, net of amounts capitalized to oil and gas properties. See Note 8 — Employee Benefits Plans and Share-Based Compensation for additional information. Restricted Stock Units (“RSUs”) — Share-based compensation is based on the market price of the Company’s common stock on the grant date and recognized over the requisite service period using the straight-line method. Performance Share Units (“PSUs”) with Market Based Conditions — Share-based compensation is based on the grant date fair value determined using a Monte Carlo valuation model for awards with a market condition and recognized over the requisite service period using the straight-line method. Estimates used in the Monte Carlo valuation model are considered highly-complex and subjective. The number of shares of common stock issuable upon vesting ranges from zero to 200 % of the number of PSUs granted based on the Company’s total shareholder return (“TSR”). Share-based compensation related to PSUs with a market condition are recognized as the requisite service period is fulfilled, even if the market condition is not achieved. PSUs with Performance Based Conditions — Share-based compensation is based on the market price of the Company’s common stock on the grant date and recognized over the requisite service period using the straight-line method for awards with a performance condition. The Company recognizes compensation cost for awards with performance conditions if and when the Company concludes that it is probable that the performance condition will be achieved. The Company reassesses the probability of vesting at each reporting period for awards with performance conditions and adjusts compensation cost based on its probability assessment. The Company recognizes a cumulative catch-up adjustment for such changes in its probability assessment in subsequent reporting periods, using the grant date fair value of the award whose terms reflect the updated probable performance condition (which could be either a reversal or increase in expense). The number of shares of common stock issuable upon vesting ranges from zero to 200 % of the number of PSUs granted based on a metric associated with the Company’s own operations or activities. Revenue Recognition — Revenues are recorded based from the sale of oil, natural gas and NGL quantities sold to purchasers. The Company records revenues from the sale of oil, natural gas and NGLs based on quantities of production sold to purchasers under short-term contracts (less than twelve months) at market prices when delivery to the customer has occurred, title has transferred, prices are fixed and determinable and collection is reasonably assured. This occurs when production has been delivered to a pipeline or when a barge lifting has occurred. The Company recognizes transportation costs as a component of lease operating expense when it is the shipper of the product. Each unit of product typically represents a separate performance obligation, therefore, future volumes are wholly unsatisfied and disclosure of the transaction price allocated to remaining performance obligations is not required. Gas Imbalances — Revenues are recorded based on the actual sales volumes sold to purchasers. An imbalance receivable or payable is recorded only to the extent the imbalance is in excess of its share of remaining proved developed reserves in an underlying property. Our imbalances are presented gross on our Consolidated Balance Sheets. At December 31, 2022 and 2021 , our imbalance receivable was approximately $ 1.7 million and $ 1.7 million, respectively, and imbalance payable was approximately $ 2.5 million and $ 2.5 million, respectively. Production Handling Fees — The Company presents certain reimbursements for costs from certain third parties as a reduction of “Lease operating expense” on the Consolidated Statements of Operations. ONRR Federal Royalty Refund — Included within “Other operating (income) expense” on the Consolidated Statements of Operations is income from the Company’s multi-year federal royalty refund claim from the ONRR. The Company records income when a refund is filed and its collection is reasonably assured. The refunds for the years ended December 31, 2022, 2021 and 2020 were $ 0.6 million, nil and $ 8.9 million, respectively. Income Taxes — The Company records current income taxes based on estimates of current taxable income and provides for deferred income taxes to reflect estimated future income tax payments and receipts. The impact to changes in tax laws are recorded in the period the change is enacted. Deferred taxes represent the tax impacts of differences between the financial statement and tax bases of assets and liabilities and carryovers at each year end. The Company classifies all deferred tax assets and liabilities, along with any related valuation allowance, as long-term on the Consolidated Balance Sheets. The realization of deferred tax assets depends on recognition of sufficient future taxable income during periods in which those temporary differences are deductible. The Company reduces deferred tax assets by a valuation allowance when, based on estimates, it is more likely than not that a portion of those assets will not be realized in a future period. The deferred tax asset estimates are subject to revision, either up or down, in future periods based on new facts or circumstances. In evaluating the Company’s valuation allowances, the Company considers cumulative book losses, the reversal of existing temporary differences, the existence of taxable income in carryback years, tax planning strategies and future taxable income for each of its taxable jurisdictions, the latter two of which involve the exercise of significant judgment. Changes to the Company’s valuation allowances could materially impact its results of operations. The Company’s policy is to classify interest and penalties associated with underpayment of income taxes as “Interest expense” and “General and administrative expense” on the Consolidated Statements of Operations, respectively. Income (Loss) Per Share — Basic net income per common share (“EPS”) is computed by dividing net income (loss) by the weighted average number of shares of common stock outstanding during the period. Except when the effect would be antidilutive, diluted EPS includes the impact of RSUs, PSUs and outstanding warrants. See Note 10 — Income (Loss) Per Share for additional information. Fair Value Measure of Financial Instruments — Financial instruments generally consist of cash and cash equivalents, accounts receivable, commodity derivatives, accounts payable and debt. The carrying amount of cash and cash equivalents, accounts receivable and accounts payable approximates fair value due to the highly liquid nature of these instruments. Current fair value accounting standards define fair value, establish a consistent framework for measuring fair value and stipulate the related disclosure requirements for each major asset and liability category measured at fair value on either a recurring or nonrecurring basis. These standards also clarify fair value is an exit price, presenting the amount that would be received to sell an asset or paid to transfer a liability, in an orderly transaction between market participants. The Company follows a three-level hierarchy, prioritizing and defining the types of inputs used to measure fair value depending on the degree to which they are observable as follows: • Level 1 – Inputs to the valuation methodology are quoted prices (unadjusted) for identical assets or liabilities in active markets. • Level 2 – Inputs to the valuation methodology include quoted prices for similar assets and liabilities in active markets, and inputs that are observable for the asset or liability, either directly or indirectly, for substantially the full term of the financial statement. • Level 3 – Inputs to the valuation methodology are unobservable (little or no market data), which require the reporting entity to develop its own assumptions, and are significant to the fair value measurement. Assets and liabilities measured at fair value are based on one or more of three valuation techniques. The valuation techniques are as follows: • Market Approach – Prices and other relevant information generated by market transactions involving identical or comparable assets or liabilities. • Cost Approach – Amount that would be required to replace the service capacity of an asset (replacement cost). • Income Approach – Techniques to convert expected future cash flows to a single present value amount based on market expectations (including present value techniques, option-pricing and excess earnings models). Authoritative guidance on financial instruments requires certain fair value disclosures to be presented. The estimated fair value amounts have been determined using available market information and valuation methodologies. Considerable judgment is required in interpreting market data to develop the estimates of fair value. The use of different assumptions or valuation methodologies may have a material effect on the estimated fair value amounts. Variable Interest Entities — Upon inception of a contractual agreement, the Parent Company performs an assessment to determine whether the arrangement contains a variable interest in a legal entity and whether that legal entity is a variable interest Entity (“VIE”). The Parent Company assesses all aspects of its interests in an entity and uses judgment when determining if it is the primary beneficiary. The primary beneficiary has both the power to direct the activities of the VIE that most significantly impact the entity’s economic performance and the obligation to absorb losses or the right to receive benefits from the VIE that could potentially be significant to the VIE. Other qualitative factors that are considered include decision-making responsibilities, the VIE capital structure, risk and rewards sharing, contractual agreements with the VIE, voting rights and level of involvement of other parties. A reassessment of the primary beneficiary conclusion is conducted when there are changes in the facts and circumstances related to a VIE. See Note 11 — Related Party Transactions for additional information. Concentration of Credit Risk Consisting principally of cash and cash equivalents, accounts receivable and commodity derivatives, the Company is subject to concentrated financial instruments credit risk. Cash and cash equivalents balances are maintained in financial institutions, which at times, exceed federally insured limits. The Company monitors the financial condition of these institutions and has not experienced losses on these accounts. Commodity derivatives are entered into with registered swap dealers, all of which participate in the Company’s senior reserve-based revolving credit facility (the “Bank Credit Facility”). The Company monitors the financial condition of these institutions and has not experienced losses due to counterparty default on these instruments. The Company markets 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, 2022 2021 2020 Shell Trading (US) Company 44 % 45 % 47 % Valero Energy Corporation 23 % ** ** Chevron Products Company 11 % 29 % 12 % Phillips 66 ** ** 22 % ** 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, 2022
Business Combinations [Abstract]
Asset Acquisitions	Note 3 — Acquisitions Asset Acquisitions Acquisitions qualifying as an asset acquisition requires, among other items, that the cost of the assets acquired and liabilities assumed to be recognized on the Consolidated Balance Sheets by allocating the asset cost on a relative fair value basis. The fair value measurements of the oil and natural gas properties acquired and asset retirement obligations assumed were derived utilizing an income approach and based, in part, on significant inputs not observable in the market. These inputs represent Level 3 measurements in the fair value hierarchy and include, but are not limited to, estimates of reserves, future operating and development costs, future commodity prices, estimated future cash flows and appropriate discount rates. These inputs required significant judgments and estimates by the Company’s management at the time of the valuation. Transaction costs incurred on an asset acquisition are capitalized as a component of the assets acquired and any contingent consideration is recognized as the contingency is resolved. Acquisition of LLOG Properties — On November 16, 2020 , the Company completed the acquisition of select oil and natural gas assets from LLOG Exploration & Production Company, L.L.C. (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. 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 (the “Castex Energy 2005 Acquisition”). 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 valued at $ 35.4 million and (iii) $ 1.4 million in transaction related expenses, inclusive of customary closing adjustments.
Business Combination	Business Combinations Acquisitions qualifying as business combinations are accounted for under the acquisition method of accounting, which requires, among other items, that assets acquired and liabilities assumed be recognized on the Consolidated Balance Sheets at their fair values as of the acquisition date. 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. EnVen Acquisition — On September 21, 2022 , the Company executed a merger agreement to acquire EnVen Energy Corporation (“EnVen”), a private operator in the Deepwater U.S. Gulf of Mexico (the “EnVen Acquisition,” and such agreement, the “EnVen Merger Agreement”). The Company incurred $ 9.0 million of transaction related costs for the year ended December 31, 2022. These costs are reflected in “General and administrative expense” on the Consolidated Statements of Operations. Subsequent Event — On February 13, 2023, the Company completed the EnVen Acquisition for consideration consisting of (i) $ 207.3 million in cash and (ii) 43.8 million shares of the Company’s common stock valued at $ 832.2 million . Due to the timing of the EnVen Acquisition, the Company is unable to estimate the purchase price allocation of such acquisition at this time. ILX and Castex Acquisition — On February 28, 2020 , the Company acquired the outstanding limited liability interests in certain wholly owned subsidiaries of ILX Holdings, LLC; ILX Holdings II, LLC; ILX Holdings III LLC and Castex Energy 2014, LLC, each a related party and an affiliate of the Riverstone Funds (as defined in Note 11 — Related Party Transactions ) (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) $ 303.1 million in cash after customary closing adjustments and (ii) an aggregate 110,000 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 Conversion Stock was valued at $ 156.2 million. The cash consideration was funded with borrowings under the Bank Credit Facility. The Company incurred $ 12.1 million of transaction related costs, of which $ 8.7 million was recognized in the year ended December 31, 2020. These costs are reflected in “General and administrative expense” on the Consolidated Statements of Operations. The following table presents revenue and net income attributable to the assets acquired in the ILX and Castex Acquisition: Year Ended December 31, 2020 Revenue $ 126,857 Net loss $ ( 6,011 ) Pro Forma Financial Information (Unaudited) — The following supplemental pro forma financial information (in thousands, except per common share amounts), presents the consolidated results of operations for the year ended December 31, 2020 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 Revenue $ 634,921 Net loss $ ( 449,988 ) Basic net loss per common share $ ( 6.48 ) Diluted net loss per common share $ ( 6.48 )

Property, Plant and Equipment

Property, Plant and Equipment	12 Months Ended
	Dec. 31, 2022
Oil and Gas Property [Abstract]
Property, Plant and Equipment	Note 4 — Property, Plant and Equipment Proved Properties The Company’s interests in oil and natural gas proved properties are located in the United States, primarily in the Gulf of Mexico deep and shallow waters. During 2022, 2021 and 2020 , the Company’s ceiling test computations resulted in a write-down of its U.S. oil and natural gas properties of nil , nil and $ 267.9 million, respectively. At December 31, 2022, its ceiling test computation was based on SEC pricing of $ 96.03 per Bbl of oil, $ 6.80 per Mcf of natural gas and $ 33.89 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 located in the shallow waters off the coast of Mexico’s Tabasco state. The following table sets forth a summary of the Company’s oil and natural gas property costs not being amortized at December 31, 2022, by the year in which such costs were incurred (in thousands): Year Ended December 31, Total 2022 2021 2020 2019 and Prior Acquisition United States $ 29,646 $ 2,221 $ — $ 27,322 $ 103 Exploration United States 13,707 2,696 4,727 1,753 4,531 Exploration Mexico 111,430 1,170 3,460 13,853 92,947 Total unproved properties, not subject to amortization $ 154,783 $ 6,087 $ 8,187 $ 42,928 $ 97,581 The excluded costs will be included in the amortization base as properties are evaluated and proved reserves are established or impairment is determined. The $ 111.4 million of capitalized exploration cost in Mexico relates to the Zama Field Development Plan for submission to the Mexican regulator for final approval. The Company expects to transfer the cost into the amortization base by 2024. The Company’s evaluation of unproved property located offshore Mexico resulted in a non-cash impairment of nil , $ 18.1 million and $ 0.1 million for the years ended December 31, 2022, 2021 and 2020, respectively, presented as “Write-down of oil and natural gas properties” on the Consolidated Statements of Operations. The non-cash impairment is primarily attributable to the Company’s operations in offshore Mexico in Block 31 associated with the Company’s non-consent of the proposed appraisal plan during the fourth quarter of 2021. Asset Retirement Obligations The asset retirement obligations included in the Consolidated Balance Sheets in current and non-current liabilities, and the changes in that liability were as follows (in thousands): Year Ended December 31, 2022 2021 Balance, beginning of period $ 434,006 $ 442,269 Obligations acquired — 433 Obligations incurred 1,140 52 Obligations settled ( 69,596 ) ( 67,988 ) Obligations divested ( 1,572 ) ( 340 ) Accretion expense 55,995 58,129 Changes in estimate (1) 121,688 1,451 Balance, end of period $ 541,661 $ 434,006 Less: Current portion 39,888 60,311 Long-term portion $ 501,773 $ 373,695 (1) Changes in estimate for the year ended December 31, 2022 were primarily due to an increase in estimated service costs.

Leases

Leases	12 Months Ended
	Dec. 31, 2022
Leases [Abstract]
Leases	Note 5 — Leases The Company has operating leases principally for office space, drilling rigs, compressors and other equipment necessary to support the Company’s operations. Additionally, the Company has a finance lease related to the use of the Helix Producer I (the “HP-I”), a dynamically positioned floating production facility that interconnects with the Phoenix Field through a production buoy. The HP-I is utilized in the Company’s oil and natural gas development activities and the ROU asset was capitalized and included in proved property and depleted as part of the full cost pool. Once items are included in the full cost pool, they are indistinguishable from other proved properties. The capitalized costs within the full cost pool are amortized over the life of the total proved reserves using the unit-of-production method, computed quarterly. Costs associated with the Company’s leases are either expensed or capitalized depending on how the underlying asset is utilized. In November 2022, the Company exercised its option to extend the lease of the HP-I through June 1, 2024. The extension resulted in a remeasurement of the lease liability to $ 166.3 million and corresponding adjustment to proved property. The lease costs described below are presented on a gross basis and do not represent the Company’s net proportionate share of such amounts. A portion of these costs have been or may be billed to other working interest owners. The Company’s share of these costs is included in property and equipment, lease operating expense or general and administrative expense, as applicable. The components of lease costs were as follows (in thousands): Year Ended December 31, 2022 2021 2020 Finance lease cost - interest on lease liabilities $ 7,558 $ 11,453 $ 15,748 Operating lease cost, excluding short-term leases (1) 2,281 2,706 3,361 Short-term lease cost (2) 55,072 38,472 53,573 Variable lease cost (3) 1,450 1,356 543 Total lease cost $ 66,361 $ 53,987 $ 73,225 (1) Operating lease cost reflect a single lease cost, calculated so that the cost of the lease is allocated over the lease term on a straight-line basis. (2) Short-term lease costs are reported at gross amounts and primarily represent costs incurred for drilling rigs, most of which are short-term contracts not recognized as a ROU asset and lease liability on the Consolidated Balance Sheets. (3) Variable lease costs primarily represent differences between minimum payment obligations and actual operating charges incurred by the Company related to its long-term leases. The present value of the fixed lease payments recorded as the Company’s ROU asset and liability, adjusted for initial direct costs and incentives were as follows (in thousands): Year Ended December 31, 2022 2021 Operating leases: Operating lease assets $ 5,903 $ 5,714 Current portion of operating lease liabilities $ 1,943 $ 1,715 Operating lease liabilities 14,855 16,330 Total operating lease liabilities $ 16,798 $ 18,045 Finance leases: Proved property $ 166,261 $ 124,299 Other current liabilities $ 16,306 $ 27,083 Other long-term liabilities 149,064 13,138 Total finance lease liabilities $ 165,370 $ 40,221 The table below presents the lease maturity by year as of December 31, 2022 (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 2023 $ 3,774 $ 30,782 2024 3,579 30,782 2025 3,645 30,782 2026 3,712 30,782 2027 3,596 30,782 Thereafter 5,727 74,389 Total lease payments $ 24,033 $ 228,299 Imputed interest ( 7,235 ) ( 62,929 ) Total lease liabilities $ 16,798 $ 165,370 The table below presents the weighted average remaining lease term and discount rate related to leases: Year Ended December 31, 2022 2021 2020 Weighted average remaining lease term: Operating leases 6.4 years 7.4 years 7.8 years Finance leases 7.4 years 1.4 years 2.4 years Weighted average discount rate: Operating leases 11.8 % 11.9 % 12.0 % Finance leases 9.2 % 21.9 % 21.9 % The table below presents the supplemental cash flow information related to leases (in thousands): Year Ended December 31, 2022 2021 2020 Operating cash outflow from finance leases $ 7,181 $ 11,453 $ 15,748 Operating cash outflow from operating leases $ 3,722 $ 3,864 $ 2,648 ROU assets obtained in exchange for new finance lease liabilities $ 166,261 $ — $ — ROU assets obtained in exchange for new operating lease liabilities $ 474 $ 1,020 $ —

Financial Instruments

Financial Instruments	12 Months Ended
	Dec. 31, 2022
Financial Instruments [Abstract]
Financial Instruments	Note 6 — Financial Instruments As of December 31, 2022 and 2021, the carrying amounts of cash and cash equivalents, accounts receivable and accounts payable approximate their fair values because of the short-term nature of these instruments. Debt Instruments The following table presents the carrying amounts, net of discount and deferred financing costs, and estimated fair values of the Company’s debt instruments (in thousands): December 31, 2022 December 31, 2021 Carrying Fair Carrying Fair 12.00 % Second-Priority Senior Secured Notes – due January 2026 $ 590,132 $ 674,542 $ 588,838 $ 685,945 7.50 % Senior Notes – due May 2022 $ — $ — $ 6,060 $ 6,145 Bank Credit Facility – matures November 2024 $ ( 4,792 ) $ — $ 367,829 $ 375,000 The carrying value of the senior notes are presented net of the original issue discount and deferred financing costs. Fair value is estimated (representing a Level 1 fair value measurement) using quoted secondary market trading prices. The carrying amount of the Company’s Bank Credit Facility is presented net of deferred financing costs. The fair value of the Bank Credit Facility is estimated based on the outstanding borrowings under the Bank Credit Facility since it is secured by the Company’s reserves and the interest rates are variable and reflective of market rates (representing a Level 2 fair value measurement). Oil and Natural Gas Derivatives The Company attempts to mitigate a portion of its commodity price risk and stabilize cash flows associated with sales of oil and natural gas production. The Company utilizes oil and natural gas swaps and costless collars. Swaps are contracts where the Company either receives or pays depending on whether the oil or natural gas floating market price is above or below the contracted fixed price. Costless collars consist of a purchased put option and a sold call option with no net premiums paid to or received from counterparties. Collar contracts typically require payments by the Company if the NYMEX average closing price is above the ceiling price or payments to the Company if the NYMEX average closing price is below the floor price. The Company has elected not to designate any of its derivative contracts for hedge accounting. Accordingly, commodity derivatives are recorded on the Consolidated Balance Sheets at fair value with settlements of such contracts, and changes in the unrealized fair value, recorded as “Price risk management activities income (expense)” on the Consolidated Statements of Operations in each period. The following table presents the impact that derivatives, not designated as hedging instruments, had on its Consolidated Statements of Operations (in thousands): Year Ended December 31, 2022 2021 2020 Net cash received (paid) on settled derivative instruments $ ( 425,559 ) $ ( 290,164 ) $ 143,905 Unrealized gain (loss) 153,368 ( 128,913 ) ( 56,220 ) Price risk management activities income (expense) $ ( 272,191 ) $ ( 419,077 ) $ 87,685 The following tables reflect the contracted volumes and weighted average prices under the terms of the Company's derivative contracts as of December 31, 2022: Swap Contracts Production Period Settlement Index Average Daily Weighted Average Crude oil: (Bbls) (per Bbl) January 2023 – December 2023 NYMEX WTI CMA 17,863 $ 72.46 January 2024 – December 2024 NYMEX WTI CMA 5,240 $ 73.95 Natural gas: (MMBtu) (per MMBtu) January 2023 – December 2023 NYMEX Henry Hub 26,395 $ 3.76 January 2024 – June 2024 NYMEX Henry Hub 10,000 $ 3.25 Collar Contracts Production Period Settlement Index Average Weighted Weighted Crude oil: (Bbls) (per Bbl) (per Bbl) January 2023 – December 2023 NYMEX WTI CMA 2,512 $ 70.00 $ 86.59 January 2024 – March 2024 NYMEX WTI CMA 2,000 $ 70.00 $ 88.00 Natural gas: (MMBtu) (per MMBtu) (per MMBtu) January 2023 – December 2023 NYMEX Henry Hub 10,000 $ 5.25 $ 8.46 January 2024 – December 2024 NYMEX Henry Hub 10,000 $ 4.00 $ 6.90 The following tables provide additional information related to financial instruments measured at fair value on a recurring basis (in thousands): December 31, 2022 Level 1 Level 2 Level 3 Total Assets: Oil and natural gas derivatives $ — $ 32,883 $ — $ 32,883 Liabilities: Oil and natural gas derivatives — ( 76,242 ) — ( 76,242 ) Total net liability $ — $ ( 43,359 ) $ — $ ( 43,359 ) December 31, 2021 Level 1 Level 2 Level 3 Total Assets: Oil and natural gas derivatives $ — $ 3,737 $ — $ 3,737 Liabilities: Oil and natural gas derivatives — ( 200,464 ) — ( 200,464 ) Total net liability $ — $ ( 196,727 ) $ — $ ( 196,727 ) Financial Statement Presentation Derivatives are classified as either current or non-current assets or liabilities based on their anticipated settlement dates. Although the Company has master netting arrangements with its counterparties, the Company presents its derivative financial instruments on a gross basis in its Consolidated Balance Sheets. The following table presents the fair value of derivative financial instruments as well as the potential effect of netting arrangements on the Company's recognized derivative asset and liability amounts (in thousands): December 31, 2022 December 31, 2021 Assets Liabilities Assets Liabilities Oil and natural gas derivatives: Current $ 25,029 $ 68,370 $ 967 $ 186,526 Non-current 7,854 7,872 2,770 13,938 Total gross amounts presented on balance sheet 32,883 76,242 3,737 200,464 Less: Gross amounts not offset on the balance sheet 32,883 32,883 3,737 3,737 Net amounts $ — $ 43,359 $ — $ 196,727 Credit Risk The Company is subject to the risk of loss on its financial instruments as a result of nonperformance by counterparties pursuant to the terms of their contractual obligations. The Company has entered into International Swaps and Derivative Association agreements with counterparties to mitigate this risk. The Company also maintains credit policies with regard to its counterparties to minimize overall credit risk. These policies require (i) the evaluation of potential counterparties’ financial condition to determine their creditworthiness; (ii) the regular monitoring of counterparties’ credit exposures; (iii) the use of contract language that affords the Company netting or set off opportunities to mitigate exposure risk; and (iv) potentially requiring counterparties to post cash collateral, parent guarantees, or letters of credit to minimize credit risk. The Company’s assets and liabilities from commodity price risk management activities at December 31, 2022 represent derivative instruments from eight counterparties; all of which are registered swap dealers that have an “investment grade” (minimum Standard & Poor’s rating of BBB- or better) credit rating, and 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, 2022
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, 2022 2021 12.00 % Second-Priority Senior Secured Notes – due January 2026 $ 638,541 $ 650,000 7.50 % Senior Notes – due May 2022 — 6,060 Bank Credit Facility – matures November 2024 — 375,000 Total debt, before discount and deferred financing cost 638,541 1,031,060 Discount and deferred financing cost ( 53,201 ) ( 68,333 ) Total debt, net of discount and deferred financing costs 585,340 962,727 Less: Current portion of long-term debt — 6,060 Long-term debt, net of discount and deferred financing costs $ 585,340 $ 956,667 12.00% Second-Priority Senior Secured Notes The 12.00% Second-Priority Senior Secured Notes due 2026 (the “ 12.00 % Notes”) were issued pursuant to an indenture dated January 4, 2021 and the first supplemental indenture dated January 14, 2021 between the Parent Company (the “Parent Guarantor”), Talos Production Inc. (the “Issuer”), and certain of the Issuer's subsidiaries (the “Subsidiary Guarantors” and, together with the Parent Guarantor, the “Guarantors”) and Wilmington Trust, National Association, as trustee and collateral agent. The 12.00 % Notes rank pari passu in right of payment and constitute a single class of securities for all purposes under the indentures. The 12.00% Notes are fully and unconditionally guaranteed, jointly and severally, on a senior unsecured basis by the Parent Guarantor and on a second-priority senior secured basis by each of the Subsidiary Guarantors and will be unconditionally guaranteed on the same basis by certain of the Issuer’s future subsidiaries. The 12.00% Notes are secured on a second-priority basis by liens on substantially the same collateral as the Issuer’s existing first-priority obligations under its Bank Credit Facility. The 12.00 % Notes mature January 15, 2026 and have interest payable semi-annually each January 15 and July 15 . At any time prior to January 15, 2023 , the Company may redeem up to 40 % of the principal amount of the 12.00% Notes at a redemption rate of 112.00 % of the principal amount plus accrued and unpaid interest. At any time prior to January 15, 2023, the Company may also redeem some or all of the 12.00% Notes at a price equal to 100 % of the principal amount of the 1 2.00% Notes, plus a “make-whole premium,” together with accrued and unpaid interest, if any, to, but excluding, the date of redemption. Thereafter, the Company may redeem all or a portion of the 12.00% Notes in whole at any time or in part from time to time at the following redemption prices (expressed as percentages of principal amount) plus accrued and unpaid interest if redeemed during the period commencing on January 15 of the years set forth below : Period Redemption Price 2023 106.00 % 2024 103.00 % 2025 and thereafter 100.00 % The indenture governing the 12.00% Notes applies certain limitations on the Company’s ability and the ability of its subsidiaries to, among other things, (i) incur, assume or guarantee additional indebtedness or issue certain convertible or redeemable equity securities; (ii) create liens to secure indebtedness; (iii) pay distributions on equity interests, repurchase equity securities or redeem junior lien, unsecured or subordinated indebtedness; (iv) make investments; (v) restrict distributions, loans or other asset transfers from Talos Production Inc.’s restricted subsidiaries; (vi) consolidate with or merge with or into, or sell substantially all of Talos Production Inc.’s properties to, another person; (vii) sell or otherwise dispose of assets, including equity interests in subsidiaries; and (viii) enter into transactions with affiliates. The 12.00 % Notes contain customary quarterly and annual reporting, financial and administrative covenants. The Company was in compliance with all debt covenants at December 31, 2022. The Issuer initiated a notes consent solicitation on October 21, 2022, to obtain the requisite holders’ consent to certain amendments to the indenture governing the Issuer’s 12.00 % Notes to permit the incurrence of indebtedness in respect of the 11.75 % Senior Secured Second Lien Notes due 2026 of EnVen (the “Notes Consent Solicitation”). The Notes Consent Solicitation expired on October 27, 2022, with holders of 95.8 % of the aggregate principal amount of the 12.00% Notes outstanding consenting. As a result, the Issuer entered into a second supplemental indenture to the base indenture on October 27, 2022 , which became effective upon its execution. The Issuer offered holders of the 12.00% Notes consideration equal to 50 basis points times the principal amount of the 12.00% Notes held by such consenting holder (“Consent Fee”). During the year ended December 31, 2022 , the Company repurchased $ 11.5 million of the 12.00 % Notes. The debt repurchases resulted in a loss on extinguishment of debt for the year ended December 31, 2022 of $ 1.6 million, which is presented as “Other income (expense)” on the Consolidated Statements of Operations. Subsequent Event — On February 13, 2023 , the Issuer paid the Consent Fee of approximately $ 3.1 million in the aggregate in connection with the closing of the EnVen Acquisition. 11.00% Second-Priority Senior Secured Notes On January 13, 2021, the Company redeemed $ 347.3 million aggregate principal amount of the 11.00 % Second-Priority Senior Secured Notes due 2022 (the “11.00% Notes”) at 102.75 % plus accrued and unpaid interest using the proceeds from the issuance of the 12.00% Notes. The debt redemption resulted in a loss on extinguishment of debt of $ 13.2 million for the year ended December 31, 2021, which is included in “Other income (expense)” on the Consolidated Statements of Operations. On June 15, 2020, the Company entered into an exchange agreement pursuant to which the Company agreed to exchange $ 37.2 million aggregate principal amount of the 11.00 % Notes from certain holders in exchange for 3.1 million shares of the Company’s common stock plus cash in an amount equal to accrued interest up to the June 18, 2020 settlement date. Additionally, during the year ended December 31, 2020, the Company repurchased $ 6.4 million of the 11.00 % Notes. The exchange agreement and debt repurchases resulted in a gain on extinguishment of debt for the year ended December 31, 2020 of $ 1.7 million, which is included in “Other income (expense)” on the Consolidated Statements of Operations. 7.50% Senior Notes On May 31, 2022 , the 7.50 % Senior Notes matured and were redeemed at an aggregate principal of $ 6.1 million plus accrued and unpaid interest. Bank Credit Facility The Company maintains a Bank Credit Facility with a syndicate of financial institutions. The Bank Credit Facility provides for the determination of the borrowing base based on the Company’s proved producing reserves and a portion of the Company's proved undeveloped reserves. The borrowing base is redetermined by the lenders at least semi-annually during the second quarter and fourth quarter of each year. On May 4, 2022, the Company entered into a (i) Borrowing Base Redetermination Agreement and Eighth Amendment to Credit Agreement (the “Eighth Amendment”) and (ii) Incremental Agreement of Increasing Lenders (“Incremental Agreement”). The Eighth Amendment and the Incremental Agreement, among other things, (i) increased the borrowing base from $ 950.0 million to $ 1.1 billion and (ii) increased the commitments from $ 791.3 million to $ 806.3 million. On December 23, 2022, the Company entered into the Incremental Agreement and Ninth Amendment to Credit Agreement (the “Ninth Amendment”). The Ninth Amendment, among other things, (i) extends the maturity date of the Bank Credit Facility from November 12, 2024 to March 31, 2027 , (ii) increases the borrowing base from $ 1.1 billion to $ 1.5 billion and (iii) increases commitments from $ 806.3 million to $ 965.0 million, in each case contingent upon the closing of the EnVen Acquisition and the occurrence of certain events related thereto. The Bank Credit Facility no longer bears interest at the applicable London InterBank Offered Rate plus the applicable margin. Interest under the Bank Credit Facility accrues at the Company’s option either at an alternate base rate (“ABR”) plus the applicable margin (“ABR Loans”), an adjusted term secured overnight financing rate (“SOFR”) plus the applicable margin (“Term Benchmark Loans”) or adjusted daily simple SOFR plus the applicable margin (“RFR Loans”). The ABR is based on the greater of (a) the prime rate, (b) a federal funds rate plus 0.5 % or (c) the adjusted term SOFR for a one-month interest period plus 1.00 %. The adjusted term SOFR is equal to the term SOFR for each applicable tenor (e.g., one-month, three-months, six-months, and twelve-months) calculated and published by the CME Group Inc. plus 0.10 %. The adjusted daily simple SOFR is equal to the overnight SOFR calculated and published by the Federal Reserve Bank of New York plus 0.10 %. In addition, the Company is obligated to pay a commitment fee on the unutilized portion of the commitments. The pricing grid below shows the applicable margin for Term Benchmark Loans, RFR Loans and ABR Loans as well as the commitment fee rate, in each case, prior to closing of the EnVen Acquisition, based upon the applicable borrowing base utilization percentage: Borrowing Base Utilization Percentage Utilization Term Benchmark Loans and RFR Loans ABR Loans Commitment Level 1 < 25 % 3.00 % 2.00 % 0.50 % Level 2 ≥ 25 % < 50 % 3.25 % 2.25 % 0.50 % Level 3 ≥ 50 % < 75 % 3.50 % 2.50 % 0.50 % Level 4 ≥ 75 % < 90 % 3.75 % 2.75 % 0.50 % Level 5 ≥ 90 % 4.00 % 3.00 % 0.50 % The Ninth Amendment provides that the above applicable margins for Term Benchmark Loans, RFR Loans and ABR Loans, each decrease by an amount equal to 0.25 % from and after the closing of the EnVen Acquisition. The commitment fee rate also decreases to 0.375 % from and after the closing of the EnVen Acquisition when the borrowing base utilization percentage is less than 50 %. The Bank Credit Facility has certain debt covenants, the most restrictive of which is that the Company must maintain a Consolidated Total Debt to EBITDAX Ratio (as defined in the Bank Credit Facility) of no greater than 3.00 to 1.00 calculated each quarter utilizing the most recent twelve months to determine EBITDAX. The Company must also maintain a current ratio no less than 1.00 to 1.00 each quarter. Under the Bank Credit Facility, unutilized commitments are included in current assets in the current ratio calculation. The Bank Credit Facility is secured by, among other things, mortgages covering at least 90.0 % (or, from and after the closing of the EnVen Acquisition, 85.0 %) of the oil and natural gas assets of the Company. The Bank Credit Facility is fully and unconditionally guaranteed by the Company and certain of its wholly-owned subsidiaries. As of December 31, 2022, the Company's borrowing base was $ 1.1 billion with total commitments of $ 806.3 million . Additionally, no more than $ 200.0 million (or, from and after the closing of the EnVen Acquisition, $ 250.0 million) of the Company’s borrowing base can be used as letters of credit with current commitments at $ 150.0 million. The amount the Company is able to borrow with respect to the borrowing base is subject to compliance with the financial covenants and other provisions of the Bank Credit Facility. The Company was in compliance with all debt covenants at December 31, 2022. See Note 12 — Commitments and Contingencies for the amount of letters of credit issued under the Bank Credit Facility as of December 31, 2022. Subsequent Event — On February 10, 2023, the Company borrowed $ 130.0 million primarily used to fund the cash portion of the purchase price in the EnVen Acquisition. On February 13, 2023 , as a result of the closing of the EnVen Acquisition, the borrowing base increased, commitments increased and the other changes all described above as contingent on the closing of the EnVen Acquisition went into effect. As of closing of the EnVen Acquisition, the Bank Credit Facility had approximately $ 754.2 million of undrawn commitments. Limitation on Restricted Payments Including Dividends The Company has not historically declared or paid any cash dividends on its capital stock. However, to the extent the Company determines in the future that it may be appropriate to pay a special dividend or initiate a quarterly dividend program, the Company’s ability to pay any such dividends to its stockholders may be limited to the extent its consolidated subsidiaries are limited in their ability to make distributions to the Parent Company, including the significant restrictions that the agreements governing the Company’s debt impose on the ability of its consolidated subsidiaries to make distributions and other payments to the Parent Company. With respect to entities accounted for under the equity method, the Company’s primary equity method investee as of December 31, 2022 did not have any undistributed earnings. The Bank Credit Facility contains restrictions on the ability of Talos Production Inc. to transfer funds to the Parent Company in the form of cash dividends, loans or advances. The Bank Credit Facility restricts distributions and other payments to the Parent Company, subject to certain baskets and other exceptions described therein including the payment of operating expense incurred in the ordinary course of business and for income taxes attributable to its ownership in Talos Production Inc. Under the Bank Credit Facility, general distributions and other restricted payments may be made to the Company so long as after giving pro forma effect to the making of any such restricted payment (i) no default or event of default has occurred and is continuing; (ii) available commitments exceed 25 % of the then effective loan limit; (iii) the pro forma current ratio of 1.0 to 1.0 is satisfied; and (iv) either (A) the Consolidated Total Debt to EBITDAX Ratio (as defined in the Bank Credit Facility) is not greater than 1.75 to 1.00 and the aggregate amount of such restricted payments does not exceed the Available Free Cash Flow Amount (as defined in the Bank Credit Facility) at the time made or (B) the Consolidated Total Debt to EBITDAX Ratio is not greater than 1.00 to 1.00. In addition, the indenture governing the 12.00% Notes restricts the Company’s consolidated subsidiaries from, directly or indirectly, among other things, declaring or paying any dividend on account of their equity securities, subject to certain limited exceptions described in the indenture. Such exceptions include, among other things, if (i) no default has occurred or would occur as a result thereof, (ii) immediately after giving effect to such transaction on a pro forma basis, the issuer could incur $ 1.00 of additional indebtedness in compliance with a fixed charge coverage ratio of 2.25 to 1.00, (iii) the ratio of the issuer’s total debt to EBITDA ratio is not greater than 3.00 to 1.00, and (iii) if payments pursuant to such transaction, together with the aggregate amount of certain other restricted payments, is less than the cumulative credit permitted under the indenture. At December 31, 2022 , restricted net assets of the Company’s consolidated subsidiaries exceeded 25 %. Subsequent Event — EnVen Acquisition On February 13, 2023 , in conjunction with the closing of the EnVen Acquisition, the Company assumed EnVen’s 11.75% Senior Secured Second Lien Notes due 2026 (the “EnVen Second Lien Notes”) with a principal amount of $ 257.5 million. The EnVen Second Lien Notes mature on April 15, 2026 and interest accrues and is to be paid semi-annually in cash in arrears on April 15th and October 15th of each year. The indenture governing the EnVen Second Lien Notes requires the redemption of $ 15.0 million of the principal amount outstanding at par value on April 15th and October 15th of each year. The EnVen Second Lien Notes are governed by an indenture by and among Energy Ventures GoM LLC, EnVen Finance Corporation as co-issuers, the guarantors party thereto and Wilmington Trust, National Association as trustee and collateral agent, dated as of April 15, 2021 (“EnVen Second Lien Notes Indenture”). Talos Production Inc. and certain of its subsidiaries entered into a supplemental indenture to the EnVen Second Lien Notes Indenture which, inter alia, provides for the assumption of the indebtedness in respect of the EnVen Second Lien Notes by Talos Production Inc., as well as guarantees of such indebtedness by certain subsidiaries of Talos Production Inc., as contemplated by the terms of the EnVen Second Lien Notes Indenture. The EnVen Second Lien Notes Indenture contains certain covenants, which are customary with respect to non-investment grade debt securities, including limitations on the Company’s ability to incur and guarantee additional indebtedness, repay, redeem, or repurchase certain debt and capital stock, issue certain preferred stock or similar equity securities, pay dividends or make other distributions on capital stock, enter into certain types of transactions with affiliates, make loans or investments, and make other restricted payments. Additionally, certain covenants restrict Talos Production Inc. subsidiaries’ ability to pay dividends, create liens, and sell certain assets. EnVen’s reserve based loan facility, which had no borrowings as of February 13, 2023 , was terminated at the time of the EnVen Acquisition.

Employee Benefits Plans and Sha

Employee Benefits Plans and Share-Based Compensation	12 Months Ended
	Dec. 31, 2022
Share-Based Payment Arrangement [Abstract]
Employee Benefits Plans and Share-Based Compensation	Note 8 — Employee Benefits Plans and Share-Based Compensation Long Term Incentive Plans On May 11, 2021, the Company’s stockholders approved the Talos Energy Inc. 2021 Long Term Incentive Plan (the “2021 LTIP”), which had previously been approved by the board of directors of the Company. No further awards will be granted under the Talos Energy Inc. Long Term Incentive Plan (the “2018 LTIP”) (together with the 2021 LTIP, the “LTIP Plans”). The 2021 LTIP provides for potential grants of: (i) incentive stock options qualified as such under U.S. federal income tax laws (“ISOs”), (ii) stock options that do not qualify as ISOs (together with ISOs, “Options”), (iii) stock appreciation rights, (iv) restricted stock awards, (v) RSUs, (vi) awards of vested stock, (vii) dividend equivalents, (viii) other share-based or cash awards and (ix) substitute awards. Employees, non-employee directors and consultants of the Company and its affiliates are eligible to receive awards under the 2021 LTIP. The 2021 LTIP authorizes the Company to grant awards of up to 8,639,415 shares of the Company’s common stock, subject to the share counting and share recycling provisions of the 2021 LTIP. Restricted Stock Units – Employees — RSUs granted to employees under the LTIP Plans primarily vest ratably over an approximate three year period subject to such employee’s continued service through each vesting date. Upon vesting, each RSU represents a contingent right to receive one share of common stock. The total unrecognized share-based compensation expense related to these RSUs at December 31, 2022 was approximately $ 24.6 million, which is expected to be recognized over a weighted average period of 1.7 years. Restricted Stock Units – Non-employee Directors — RSUs granted to non-employee directors under the LTIP Plans vested approximately one year following the date of grant, subject to such non-employee director’s continued service through the vesting date. Upon vesting, these RSUs represent a contingent right to receive one share of common stock for each RSU for 60 %, and cash for the remaining 40 %. The total unrecognized share-based compensation expense related to these RSUs at December 31, 2022 was approximately $ 0.2 million, which is expected to be recognized over a weighted average period of 0.2 years. Of the unrecognized share-based compensation expense, $ 0.1 million relates to liability awards and will be subsequently remeasured at each reporting period. The following table summarizes RSU activity: Restricted Stock Weighted Average Unvested RSUs at December 31, 2019 733,777 $ 25.20 Granted 1,284,797 $ 10.02 Vested ( 273,787 ) $ 25.09 Forfeited ( 91,799 ) $ 19.65 Unvested RSUs at December 31, 2020 1,652,988 $ 13.73 Granted 1,102,038 $ 13.11 Vested ( 669,832 ) $ 15.01 Forfeited ( 101,995 ) $ 12.46 Unvested RSUs at December 31, 2021 1,983,199 $ 13.02 Granted 2,297,465 $ 13.23 Vested ( 967,269 ) $ 14.14 Forfeited ( 97,891 ) $ 14.34 Unvested RSUs at December 31, 2022 (1) 3,215,504 $ 12.79 (1) As of December 31, 2022 , 25,257 of the unvested RSUs were accounted for as liability awards in “Accrued liabilities” on the Consolidated Balance Sheet. The Company considers its intent and ability to settle awards in cash or shares in determining whether to classify the awards as equity or as a liability. Certain awards granted during the year ended December 31, 2021 were originally classified as liability awards; however, these awards became equity-classified awards upon stockholder approval of the 2021 LTIP. The aggregate amount of compensation cost related to these awards is determined by the fair value of the award on the modification date. Performance Share Units – Employees — PSUs granted to employees under the LTIP Plans represent the contingent right to receive one share of common stock. However, the number of shares of common stock issuable upon vesting ranges from zero to 200 % of the target number of PSUs granted. The total unrecognized share-based compensation expense related to these PSUs at December 31, 2022 was approximately $ 14.0 million, which is expected to be recognized over a weighted average period of 1.8 years. The following table summarizes PSU activity: Performance Weighted Average Unvested PSUs at December 31, 2019 417,831 $ 39.31 Granted 441,642 $ 13.05 Forfeited ( 25,301 ) $ 37.67 Unvested PSUs at December 31, 2020 834,172 $ 25.46 Granted 586,995 $ 18.96 Vested ( 391,308 ) $ 39.43 Forfeited ( 14,400 ) $ 18.48 Unvested PSUs at December 31, 2021 1,015,459 $ 16.41 Granted (1) 629,666 $ 23.73 Vested (2) ( 14,474 ) $ 13.05 Forfeited ( 16,486 ) $ 17.48 Cancelled ( 975,564 ) $ 16.42 Unvested PSUs at December 31, 2022 638,601 $ 23.66 (1) There were 314,833 PSUs granted that are eligible to vest based on continued employment and the Company’s annualized absolute total shareholder return (“TSR”) over a three-year performance period. An additional 314,833 PSUs were granted and are eligible to vest based on continued employment and the Company’s return on the wells included in the 2022 drill program over a three-year performance period. (2) The performance period for the relative TSR awards ended on December 31, 2022. The payout on these awards was 0 % based on actual performance over the performance period as certified by the Compensation Committee of the Company’s Board of Directors in early 2023. Since these awards were legally forfeited they will again be available for new awards under the recycling provisions of the 2021 LTIP. Certain awards granted during the year ended December 31, 2021 were originally classified as liability awards; however, these awards became equity-classified awards upon stockholder approval of the 2021 LTIP. The following table summarizes the assumptions used in the Monte Carlo simulations to calculate the fair value of the relative or absolute TSR PSUs granted and modified at the date indicated: 2022 2021 2020 Grant Grant Modification Grant Grant September 20 March 5 May 11 March 8 March 5 Expected term (in years) 2.3 2.8 2.6 2.8 2.8 Expected volatility 74.3 % 82.2 % 80.9 % 78.3 % 48.8 % Risk-free interest rate 3.9 % 1.6 % 0.3 % 0.3 % 0.6 % Dividend yield — % — % — % — % — % Fair value (in thousands) $ 621 $ 8,668 $ 9,715 $ 11,129 $ 5,763 Modification — During March 2022, the outstanding PSUs held by certain executive officers that were awarded in 2020 and 2021 were cancelled and, in connection with this cancellation, 1,147,352 of RSUs were granted (the “Retention RSUs”). The Retention RSUs will vest ratably each year over two years, generally contingent upon continued employment through each such date. The cancellation of the PSUs along with the concurrent grant of the Retention RSUs are accounted for as a modification. The incremental cost of $ 9.7 million will be recognized prospectively over the modified requisite service period. Additionally, the remaining unrecognized grant or modification date fair value of the original PSUs will be recognized over the original remaining requisite service period. Share-based Compensation Costs Share-based compensation costs associated with RSUs, PSUs and other awards are reflected as “General and administrative expense” on the Consolidated Statements of Operations, net amounts capitalized to “Proved Properties” on the Consolidated Balance Sheets. Because of the non-cash nature of share-based compensation, the expensed portion of share-based compensation is added back to net income in arriving at “Net cash provided by operating activities” on the Consolidated Statements of Cash Flows. The following table presents the amount of costs expensed and capitalized (in thousands): Year Ended December 31, 2022 2021 2020 Share-based compensation costs $ 28,280 $ 20,560 $ 16,462 Less: Amounts capitalized to oil and gas properties 12,327 9,568 7,793 Total share-based compensation expense $ 15,953 $ 10,992 $ 8,669

Income Taxes

Income Taxes	12 Months Ended
	Dec. 31, 2022
Income Tax Disclosure [Abstract]
Income Taxes	Note 9 — Income Taxes Income Tax Expense (Benefit) The components of income tax expense (benefit) were as follows (in thousands): Year Ended December 31, 2022 2021 2020 Current income tax expense (benefit): United States $ 1,375 $ ( 5 ) $ ( 499 ) Mexico 432 ( 993 ) 185 Total current income tax expense (benefit) $ 1,807 $ ( 998 ) $ ( 314 ) Deferred income tax expense (benefit): United States $ 659 $ ( 1,067 ) $ 35,923 Mexico 71 430 ( 26 ) Total deferred income tax expense (benefit) $ 730 $ ( 637 ) $ 35,897 Total income tax expense (benefit) $ 2,537 $ ( 1,635 ) $ 35,583 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, 2022 2021 2020 Income tax expense (benefit) at the federal statutory tax rate $ 80,735 $ ( 38,763 ) $ ( 90,304 ) State income taxes 1,591 ( 674 ) ( 14,215 ) Impact of foreign operations 15,657 ( 11,920 ) ( 1,030 ) Effect of change in state rate — 2,008 — Prior year taxes ( 2,920 ) 486 ( 4,237 ) Legal entity reorganization — — ( 17,566 ) Change in valuation allowance ( 96,537 ) 45,547 162,213 Other permanent differences 4,011 1,681 722 Total income tax expense (benefit) $ 2,537 $ ( 1,635 ) $ 35,583 Effective tax rate 0.66 % 0.89 % ( 8.27 )% The Company’s effective tax rate for the years ended December 31, 2022 and 2021 differed from the federal statutory rate of 21.0 % primarily due t o recording a full valuation allowance against its federal, state and foreign deferred tax assets. The Company’s effective tax rate for the year ending December 31, 2020 differed from the federal statutory rate of 21.0 % primarily due to a non-cash tax expense of $ 162.2 million related to the recognition of a valuation allowance for its excess federal and state deferred tax assets. This expense was partially offset by a tax benefit of $ 17.6 million from adopting the final Treasury Regulations under Section 163(j) of the Internal Revenue Code (the “IRC”) for tax years ended December 31, 2018 and December 31, 2019. The adoption of the final Treasury Regulations reduced the non-cash tax expense recognized in the year ending December 31, 2019 from the legal entity conversion of a partnership to a corporation. 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, 2022 2021 Deferred tax assets: Federal net operating loss $ 159,257 $ 153,849 Foreign tax loss carryforward 44,462 49,932 State net operating loss 24,787 24,265 Tax credits 107 303 Interest expense carryforward 23,262 — Asset retirement obligations 115,848 92,823 Derivatives 9,273 42,075 Other well equipment inventory 1,891 5,680 Accrued bonus 5,863 5,087 Share-based compensation 5,296 3,833 Operating lease liabilities 3,669 4,081 Finance lease liabilities 32,559 — Other 7,142 5,424 Total deferred tax assets 433,416 387,352 Valuation allowance ( 129,105 ) ( 224,266 ) Total deferred tax assets, net $ 304,311 $ 163,086 Deferred tax liabilities: Oil and gas properties $ 302,602 $ 160,002 Operating lease assets 1,323 1,423 Prepaid 2,530 3,075 Total deferred tax liabilities 306,455 164,500 Net deferred tax liability $ ( 2,144 ) $ ( 1,414 ) Net Operating Loss The table below presents the details of the Company’s net operating loss carryovers as of December 31, 2022 (in thousands): Amount Expiration Year Federal net operating losses $ 525,745 2035 - 2037 Federal net operating losses $ 232,620 Unlimited Foreign tax loss carryforward $ 148,206 2025 - 2032 State net operating losses $ 125,958 2025 - 2037 State net operating losses $ 277,031 Unlimited As of December 31, 2022, the Company had U.S. federal net operating loss carryforwards (“NOLs”) of approximately $ 758.4 million , all of which is subject to limitation under Section 382 of the IRC. IRC Section 382 provides an annual limitation with respect to the ability of a corporation to utilize its tax attributes, against future U.S. taxable income in the event of a change in o wnership. If not utilized, such carryforwards would begin to expire at the end of 2035 . Valuation Allowance The Company recorded a valuation allowance of $ 129.1 million and $ 224.3 million as of December 31, 2022 and 2021, respectively. Deferred income tax assets and liabilities are recorded related to NOLs and temporary differences between the book and tax basis of assets and liabilities expected to produce tax deductions and income in the future. The realization of these assets depends on recognition of sufficient future taxable income in specific tax jurisdictions in which those temporary differences or NOLs relate. In assessing the need for a valuation allowance, the Company considers whether it is more likely than not that some portion or all of the deferred tax assets will not be realized using available positive and negative evidence, including future reversals of temporary differences, tax-planning strategies and future taxable income, to estimate whether sufficient future taxable income will be generated to permit use of deferred tax assets. A significant piece of objective negative evidence evaluated is the cumulative loss incurred over recent years. Such objective negative evidence limits our ability to consider other subjective positive evidence. The Company intends to continue maintaining a full valuation allowance on our deferred tax assets until there is sufficient evidence to support the reversal of all or some portion of these allowances. However, if positive earnings continue to be realized and future earnings are anticipated, the Company believes that there is a reasonable possibility that within the next 12 months, sufficient positive evidence may become available to allow us to reach a conclusion that a significant portion of the valuation allowance will no longer be needed. Release of the valuation allowance would result in the recognition of certain deferred tax assets and a decrease to income tax expense for the period the release is recorded. However, the exact timing and amount of the valuation allowance release are subject to change on the basis of the level of profitability that the Company achieves and anticipates realizing in future years. 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, 2022 2021 Total unrecognized tax benefits, beginning balance $ 696 $ 648 Increases in unrecognized tax benefits as a result of: Tax positions taken during a prior period 100 21 Tax positions taken during the current period 39 27 Total unrecognized tax benefits, ending balance $ 835 $ 696 The Company recognizes interest and penalties related to uncertain tax positions as “Interest Expense” and “General and administrative expense” on the Consolidated Statements of Operations, respectively. Years Open to Examination The 2019 through 2021 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, 2018 are closed, except to the extent of any NOL carryover balance.

Income (Loss) Per Share

Income (Loss) Per Share	12 Months Ended
	Dec. 31, 2022
Earnings Per Share [Abstract]
Income (Loss) Per Share	Note 10 — Income (Loss) Per Share Basic earnings per common share is computed by dividing net income (loss) attributable to common stockholders by the weighted average number of shares of common stock outstanding during the period. Except when the effect would be antidilutive, diluted earnings per common share includes the impact of RSUs, PSUs and outstanding warrants. The warrants expired unexercised on February 28, 2021. The following table presents the computation of the Company’s basic and diluted income (loss) per share were as follows (in thousands, except for the per share amounts): Year Ended December 31, 2022 2021 2020 Net income (loss) $ 381,915 $ ( 182,952 ) $ ( 465,605 ) Weighted average common shares outstanding — basic 82,454 81,769 67,664 Dilutive effect of securities 1,229 — — Weighted average common shares outstanding — diluted 83,683 81,769 67,664 Net income (loss) per common share: Basic $ 4.63 $ ( 2.24 ) $ ( 6.88 ) Diluted $ 4.56 $ ( 2.24 ) $ ( 6.88 ) Anti-dilutive potentially issuable securities excluded from diluted common shares 865 1,709 5,019

Related Party Transactions

Related Party Transactions	12 Months Ended
	Dec. 31, 2022
Related Party Transactions [Abstract]
Related Party Transactions	Note 11 — Related Party Transactions Apollo Funds and Riverstone Funds On February 3, 2012, Talos Energy LLC completed a transaction with funds and other alternative investment vehicles managed by Apollo Management VII, L.P. and Apollo Commodities Management, L.P., with respect to Series I (“Apollo Funds”), and entities controlled by or affiliated with Riverstone Energy Partners V, L.P. (“Riverstone Funds” and together with the Apollo Funds, the “Sponsors”) and members of management pursuant to which the Company received a private equity capital commitment. On January 3, 2022, the Apollo Funds ceased being a beneficial owner of more than five percent of the Company’s common stock. Riverstone Funds held 14.9 % of the Company’s common stock as of December 31, 2022. ILX and Castex Acquisition On February 28, 2020 the Company acquired assets and liabilities at fair value from sellers that include, the Riverstone Sellers, affiliates of the Riverstone Funds. See additional details in Note 3 — Acquisitions. Whistler Acquisition On August 31, 2018 , the Company acquired Whistler Energy II, LLC from Whistler Energy II Holdco, LLC, an affiliate of the Apollo Funds. A settlement agreement related to a dispute regarding the decommissioning obligation of a Deepwater well was executed in September 2021. For the year ended December 31, 2021 , the Company recognized a $ 4.4 million gain resulting from the settlement which is reflected in “Other income (expense)” on the Company’s Consolidated Statements of Operations. Registration Rights Agreements On May 10, 2018, the Company entered into a Registration Rights Agreement (the “Original Equity Registration Rights Agreement”) with certain of the Apollo Funds and the Riverstone Funds, certain funds controlled by Franklin Advisers, Inc. (“Franklin”) and certain clients of MacKay Shields LLC (“MacKay Shields”), relating to the registered resale of the Company’s common stock owned by such parties as of the closing of the Stone Combination (the “Original Registrable Securities”). The Company and the Riverstone Sellers (and their designated affiliates) agreed under the Purchase Agreements to enter into an amendment to the Original Equity Registration Rights Agreement (such amendment, the “Registration Rights Agreement Amendment,” and the Original Equity Registration Rights Agreement, as amended by the Registration Rights Agreement Amendment, the “Registration Rights Agreement”). The Registration Rights Agreement Amendment will add each of the Riverstone Sellers (or one or more of its designated affiliates) as parties to the Registration Rights Agreement and provide such parties with customary registration rights with respect to the Series A Convertible Preferred Stock (and Conversion Stock) (each as defined below) that the Riverstone Sellers received at the closing of the ILX and Castex Acquisition (the “New Registrable Securities” and together with the Original Registrable Securities, the “Registrable Securities”). Under the Registration Rights Agreement, the Company is required to file a shelf registration statement within 30 days of the Company’s receipt of written request by a holder of Registrable Securities (a “Holder”). Each Holder will be limited to two demand registrations in any twelve-month period. The Holders have the right to request that the Company initiate underwritten offerings of the Company’s common stock; provided, that the Apollo Funds and the Riverstone Funds will have the right to demand three underwritten offerings in any twelve-month period, and Franklin and MacKay Shields will only have the collective right to demand one underwritten offering. The Holders have customary piggyback rights with respect to any underwritten offering that the Company conducts for as long as the Holders and their respective affiliates own 5 % of the Registrable Securities. Each Holder will agree to a lock up with underwriters in the event of an underwritten offering, provided that the lock up will not apply to any Holder who does not have a right to participate in such underwritten offering. The Registration Rights Agreement have terminated with respect to Franklin and MacKay Shields. Additionally, the Apollo Funds no longer have piggyback rights effective January 3, 2022. The Registration Rights Agreement will otherwise terminate at such time as there are no Registrable Securities outstanding. In connection with the closing of the ILX and Castex Acquisition, and pursuant to the Purchase Agreements, as amended, the Company and ILX Holdings, LLC, ILX Holdings II, LLC, ILX Holdings III LLC and Riverstone V Castex 2014 Holdings, L.P., a Delaware limited partnership and designee of Castex Energy 2014, LLC, entered into the Registration Rights Agreement Amendment to the Registration Rights Agreement to, among other things, add each of the Riverstone Sellers (or one or more of its designated affiliates) as parties to the Registration Rights Agreement and provide such parties with customary registration rights with respect to the Company’s Series A Convertible Preferred Stock issued to the Riverstone Sellers at the closing of the ILX and Castex Acquisition The Company will bear all of the expenses incurred in connection with any offer and sale, while the selling stockholders will be responsible for paying underwriting fees, discounts and selling commissions. The Company incurred fees of nil , $ 0.7 million and $ 0.2 million for the fiscal years ended December 31, 2022, 2021 and 2020, respectively. In June and November of 2021, the Company entered into separate secondary underwriting agreements with certain stockholders affiliated with the Sponsors (the “Selling Stockholders”), pursuant to which the Selling Stockholders sold shares of common stock of the Company. Each secondary offering was made pursuant to a prospectus supplement filed with the SEC. The Selling Stockholders received all the proceeds from these offerings. In connection with the Company’s entry into the EnVen Merger Agreement on September 21, 2022 to acquire EnVen, the Company entered into a registration rights agreement (the “2022 Registration Rights Agreement”) with Adage Capital Partners, L.P. (“Adage”) and affiliated entities of Bain Capital, LP (“Bain”). Pursuant to the 2022 Registration Rights Agreement, the Company grants to Adage and Bain certain demand, “piggy-back” and shelf registration rights with respect to the shares of the Company’s common stock to be received by such entities in the EnVen Acquisition, subject to certain customary thresholds and conditions. Additionally, the Company agrees to pay certain expenses of the parties incurred in connection with the exercise of their rights under such agreement and to indemnify them for certain securities law matters in connection with any registration statement filed pursuant thereto. The 2022 Registration Rights Agreement will become effective at the closing of the EnVen Acquisition. Subsequent Event — On February 13, 2023 , in conjunction with the closing of the EnVen Acquisition, the 2022 Registration Rights Agreement became effective. Adage and Bain hold approximately 5.1 % and 12.3 %, respectively, of the Company’s outstanding shares of common stock. Amended and Restated Stockholders’ Agreement On May 10, 2018 , the Company entered into a Stockholders’ Agreement (the “Stockholders’ Agreement”) by and among the Company and the other parties thereto. On February 24, 2020 , the Company and the other parties thereto amended the Stockholders’ Agreement to, among other things, add 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. On March 29, 2022 , the Company and other parties thereto, entered into the Amended and Restated Stockholders’ Agreement, in connection with the resignation of certain members of the Company's Board of Directors (the “Amended and Restated Stockholders’ Agreement”). The Amended and Restated Stockholders’ Agreement, among other things, (i) terminates the rights of the Apollo Funds under the Stockholders’ Agreement and (ii) eliminates the requirement that the Board of Directors consist of ten members. The Riverstone Funds have agreed to vote their shares of the Company’s common stock in favor of any nominee designated and nominated for election to the Board of Directors in accordance with the terms of the Amended and Restated Stockholders’ Agreement and in a manner consistent with the recommendation of the Nominating and Governance Committee with respect to all other nominees. In connection with the pending EnVen Acquisition, the Company and the Riverstone Funds have agreed to terminate the Amended and Restated Stockholders’ Agreement, which will eliminate the Riverstone Funds’ designation rights with respect to the Company’s Board of Directors. Subsequent to the termination of the Amended and Restated Stockholders’ Agreement, the Riverstone Funds’ present designee to the Company’s Board of Directors, Mr. Robert M. Tichio, will immediately tender his resignation. The termination of the Amended and Restated Stockholders’ Agreement is contingent upon the successful closing of the EnVen Acquisition. Subsequent Event — On February 13, 2023 , in conjunction with the closing of the EnVen Acquisition, the Amended and Restated Stockholders’ Agreement was terminated and Mr. Robert M. Tichio resigned from the Company’s Board of Directors. Riverstone Support Agreement In connection with the pending EnVen Acquisition, the Company, EnVen and the Riverstone Funds entered into a support agreement pursuant to which the Riverstone Funds have agreed, among other things, to (i) vote all shares of Company common stock beneficially owned (a) in favor of the share issuance to EnVen equityholders, (b) in favor of the amendment and/or restatement of the Company’s organizational documents as necessary or appropriate to reflect the termination of the Amended and Restated Stockholders’ Agreement, (c) in favor of any other proposals necessary or appropriate in connection with the EnVen Acquisition and (d) against, among other things, (A) any Acquisition Proposal (as defined in the EnVen Merger Agreement) with respect to the Company and (B) any other proposal that could reasonably be expected to materially impede or delay the EnVen Acquisition or result in a breach of any representation or covenant of the Company under the EnVen Merger Agreement (as defined herein), (ii) terminate the Amended and Restated Stockholders’ Agreement, and (iii) cause Mr. Tichio to resign from the Company’s Board of Directors, in each case of the foregoing clauses (ii) and (iii), effective immediately prior to, but conditioned on, the occurrence of the closing of the EnVen Acquisition. Legal Fees The Company has engaged the law firm Vinson & Elkins L.L.P. (“V&E”) to provide legal services. An immediate family member of William S. Moss III, the Company’s Executive Vice President and General Counsel and one of its executive officers, is a partner at V&E. For the years ended December 31, 2022, 2021 and 2020 , the Company incurred fees of approximately $ 4.8 million, $ 3.1 million and $ 3.5 million, respectively, of which $ 1.3 million, $ 0.2 million and $ 0.7 million were payable at each respective balance sheet date for legal services performed by V&E. Bayou Bend CCS LLC On March 8, 2022, the Company made a $ 2.3 million cash contribution for a 50 % membership interest in Bayou Bend. On May 24, 2022, the Company sold a 25 % membership interest to Chevron U.S.A. Inc. (“Chevron”) for upfront cash consideration of $ 15.0 million. Chevron also agreed to fund up to $ 10.0 million of contributions to Bayou Bend on the Company’s behalf, of which $ 1.4 million was funded during the year ended December 31, 2022 . The Bayou Bend investment will be increased with an offsetting gain as the capital carry is funded by Chevron. The Company recognized a $ 15.3 million gain on the partial sale of its investment in Bayou Bend during the year ended December 31, 2022, which is included in “Equity method investment income” on the Consolidated Statements of Operations. As of December 31, 2022 , the Company owns a 25 % membership interest in Bayou Bend, which is a variable interest entity and accounted for using the equity method of accounting. Bayou Bend has a CCS site located offshore Jefferson County, Texas, near the Beaumont and Port Arthur, Texas industrial corridor that is in the early stages of development. The development of the Bayou Bend CCS hub project is currently being financed through equity contributions from its members. The Company’s maximum exposure to loss as result of its involvement with Bayou Bend is the carrying amount of its investment. Under an operating agreement, which was amended on May 24, 2022, the Company has agreed to provide certain services to facilitate Bayou Bend’s operations and to fulfill other general and administrative functions relating to the operation and management of Bayou Bend and its business. The Company will invoice Bayou Bend for reimbursement of direct and indirect general and administrative expenses incurred as well as all other direct out-of-pocket costs and expenses incurred or paid on behalf of Bayou Bend. The Company had a $ 0.7 million related party receivable from Bayou Bend as of December 31, 2022 .

Commitments and Contingencies

Commitments and Contingencies	12 Months Ended
	Dec. 31, 2022
Commitments and Contingencies Disclosure [Abstract]
Commitments and Contingencies	Note 12 — Commitments and Contingencies Legal Proceedings and Other Contingencies From time to time, the Company is involved in litigation, regulatory examinations and administrative proceedings primarily arising in the ordinary course of business in jurisdictions in which the Company does business. Although the outcome of these matters cannot be predicted with certainty, the Company’s management believes none of these matters, either individually or in the aggregate, would have a material effect upon the Company’s financial position; however, an unfavorable outcome could have a material adverse effect on the Company’s results from operations for a specific interim period or year. On March 23, 2022, the Company entered into a settlement agreement to receive $ 27.5 million to resolve previously pending litigation, which was filed on October 23, 2017, against a third-party supplier related to quality issues. As part of the settlement agreement, the Company released all of its claims in the litigation. The settlement is reflected as “Other income (expense)” on the Consolidated Statements of Operations. Performance Obligations Regulations with respect to the Company's operations govern, among other things, engineering and construction specifications for production facilities, safety procedures, plugging and abandonment of wells, removal of facilities in the U.S. Gulf of Mexico and certain obligations under the production sharing contracts with Mexico. As of December 31, 2022, the Company had secured performance bonds from third party sureties totaling $ 740.6 million . The cost of securing these bonds is reflected as “Interest expense” on the Consolidated Statements of Operations. Additionally, as of December 31, 2022, the Company had secured letters of credit issued under its Bank Credit Facility totaling $ 3.9 million . Letters of credit that are outstanding reduce the available revolving credit commitments. See Note 7 — Debt for further information on the Bank Credit Facility. The table below summarizes the Company’s total minimum commitments associated with vessel commitments, purchase obligations and other miscellaneous commitments as of December 31, 2022 (in thousands): 2023 2024 2025 2026 Thereafter Total Vessel Commitments (1) $ 41,938 $ — $ — $ — $ — $ 41,938 Committed purchase orders (2) 41,148 — — — — 41,148 EnVen Acquisition (3) 259,858 — — — — 259,858 Other commitments (4) 9,627 327 327 — — 10,281 Total $ 352,571 $ 327 $ 327 $ — $ — $ 353,225 (1) Includes vessel commitments the Company will utilize for certain Deepwater well intervention, drilling operations and decommissioning activities. These commitments represent gross contractual obligations and accordingly, other joint owners in the properties operated by the Company will be billed for their working interest share of such costs. (2) Includes committed purchase orders to execute planned future drilling activities. These commitments represent gross contractual obligations and accordingly, other joint owners in the properties operated by the Company will be billed for their working interest share of such costs. (3) Includes cash consideration and contingent fees related to the EnVen Acquisition. See Note 15 — Subsequent Events for further information on the EnVen Acquisition. (4) Includes commitment to acquire additional lease acreage associated with our CCS Segment. Decommissioning Obligations The Company has divested various leases, wells and facilities located in the U.S. Gulf of Mexico where the purchasers typically assume all abandonment obligations acquired. Certain of these counterparties in these divestiture transactions or third parties in existing leases have filed for bankruptcy protection or undergone associated reorganizations and may not be able to perform required abandonment obligations. Under certain circumstances, regulations or federal laws could require the Company to assume such obligations. The Company reflects expenses incurred related to estimated decommissioning obligations in “Other operating (income) expense” on the Consolidated Statements of Operations. The decommissioning obligations included in the Consolidated Balance Sheets as “Other current liabilities” and “Other long-term liabilities”, and the changes in that liability were as follows (in thousands): Year Ended December 31, 2022 2021 2020 Balance, beginning of period $ 24,336 $ — $ — Additions 8,900 21,056 — Changes in estimate 22,658 — — Reimbursements due from third parties — 3,280 — Settlements ( 1,625 ) — — Balance, end of period $ 54,269 $ 24,336 $ — Less: Current portion 42,069 3,756 — Long-term portion $ 12,200 $ 20,580 $ — Although it is reasonably possible that the Company could receive state or federal decommissioning orders in the future or be notified of defaulting third parties in existing leases, the Company cannot predict with certainty, if, how or when such orders or notices will be resolved or estimate a possible loss or range of loss that may result from such orders. However, the Company could incur judgments, enter into settlements or revise our opinion regarding the outcome of certain notices or matters, and such developments could have a material adverse effect on our results of operations in the period in which the amounts are accrued and our cash flows in the period in which the amounts are paid.

Segment Information

Segment Information	12 Months Ended
	Dec. 31, 2022
Segment Reporting [Abstract]
Segment Information	Note 13 — Segment Information The Company’s operations are managed through two operating segments: (i) Upstream Segment and (ii) CCS Segment. The Upstream Segment is the Company’s only reportable segment. The Company’s chief operating decision-maker (“CODM”) is the President and Chief Executive Officer, who reviews operating results to make decisions about allocating resources and assessing performance for the entire company. The profit or loss metric used to evaluate segment performance is Adjusted EBITDA, which is defined as net income (loss) plus interest expense; income tax expense (benefit); depreciation, depletion, and amortization; accretion expense; non-cash write-down of oil and natural gas properties; transaction and other (income) expenses; decommissioning obligations; the net change in the fair value of derivatives (mark to market effect, net of cash settlements and premiums related to these derivatives); (gain) loss on debt extinguishment; non-cash write-down of other well equipment inventory; and non-cash equity-based compensation expense. Corporate general and administrative expense include certain shared costs such as finance, accounting, tax, human resources, information technology and legal costs that are not directly attributable to each of operating segment. A portion of these expenses are allocated based on the percentage of employees dedicated to each operating segment. The remaining expenses are included in the reconciliation of reportable segment Adjusted EBITDA to consolidated pre-tax net income (loss) as an unallocated corporate general and adminsitrative expense. The accounting policies of the segments are the same as those described in the summary of significant accounting policies. The Company’s CODM does not review assets by segment as part of the financial information provided and therefore, no asset information is provided in the table below. The following table presents selected segment information for the periods indicated (in thousands): Upstream All Other (1) Total Revenues from External Customers: Year Ended December 31, 2022 $ 1,651,980 $ — $ 1,651,980 Year Ended December 31, 2021 1,244,540 — 1,244,540 Year Ended December 31, 2020 575,936 — 575,936 Equity in the Net Income of Investees Accounted for by the Equity Method: Year Ended December 31, 2022 $ 101 $ ( 1,166 ) $ ( 1,065 ) Year Ended December 31, 2021 — — — Year Ended December 31, 2020 — — — Adjusted EBITDA: Year Ended December 31, 2022 $ 859,840 $ ( 12,786 ) $ 847,054 Year Ended December 31, 2021 $ 615,798 $ ( 4,782 ) 611,016 Year Ended December 31, 2020 435,327 — 435,327 Segment Expenditures: Year Ended December 31, 2022 $ 452,674 $ 2,778 $ 455,452 Year Ended December 31, 2021 338,822 — 338,822 Year Ended December 31, 2020 405,525 — 405,525 (1) The CCS Segment is included in the “All Other” category. The CCS Segment is an emerging business in the start-up phase of operations and the business that does not currently generate any revenues. The CCS Segment’s business activities are conducted through both wholly owned subsidiaries and equity method investments with industry partners. Equity method investments is a business strategy that enables us to achieve favorable economies of scale relative to the level of investment and business risk assumed. Reconciliations The following tables present reconciliations of reportable segment information to the Company’s consolidated totals (in thousands): Year Ended December 31, 2022 2021 2020 Adjusted EBITDA: Total for reportable segments $ 859,840 $ 615,798 $ 435,327 All other ( 12,786 ) ( 4,782 ) — Unallocated corporate general and administrative expense ( 5,280 ) ( 4,542 ) ( 5,088 ) Interest expense ( 125,498 ) ( 133,138 ) ( 99,415 ) Depreciation, depletion and amortization ( 414,630 ) ( 395,994 ) ( 364,346 ) Accretion expense ( 55,995 ) ( 58,129 ) ( 49,741 ) Write-down of oil and natural gas properties — ( 18,123 ) ( 267,916 ) Transaction and other (income) expenses (1) 34,513 ( 5,886 ) ( 14,917 ) Decommissioning obligations (2) ( 31,558 ) ( 21,055 ) — Derivative fair value loss (gain) (3) ( 272,191 ) ( 419,077 ) 87,685 Net cash paid on settled derivative instruments (3) 425,559 290,164 ( 143,905 ) Gain (loss) on extinguishment of debt ( 1,569 ) ( 13,225 ) 1,662 Non-cash write-down of other well equipment inventory — ( 5,606 ) ( 699 ) Non-cash equity-based compensation expense ( 15,953 ) ( 10,992 ) ( 8,669 ) Income (loss) before income taxes $ 384,452 $ ( 184,587 ) $ ( 430,022 ) (1) Other income (expense) includes restructuring expenses, cost saving initiatives and other miscellaneous income and expenses that we do not view as a meaningful indicator of our operating performance. For the year ended December 31, 2022 , the amount includes $ 27.5 million gain as a result of the settlement agreement to resolve previously pending litigation that was filed in October 2017 that is further discussed in Note 12 — Commitments and Contingencies. Additionally, it includes a $ 15.3 million gain for the year ended December 31, 2022 on partial sale of our investment in Bayou Bend that is further discussed in Note 11 — Related Party Transactions . For the year ended December 31, 2020, the amount includes $ 1.4 million of legal entity restructuring costs and $ 1.3 million of severance related cost saving initiatives due to the COVID-19 pandemic. (2) Estimated decommissioning obligations were a result of working interest partners or counterparties of divestiture transactions that were unable to perform the required abandonment obligations due to bankruptcy or insolvency. See Note 12 — Commitments and Contingencies for additional information on decommissioning obligations. (3) The adjustments for the derivative fair value (gains) losses and net cash receipts (payments) on settled commodity derivative instruments have the effect of adjusting net loss for changes in the fair value of derivative instruments, which are recognized at the end of each accounting period because we do not designate commodity derivative instruments as accounting hedges. This results in reflecting commodity derivative gains and losses within Adjusted EBITDA on an unrealized basis during the period the derivatives settled. Year Ended December 31, 2022 2021 2020 Segment Expenditures: Total reportable segments $ 452,674 $ 338,822 $ 405,525 All other 2,778 — — Change in capital expenditures included in accounts payable and accrued liabilities ( 60,011 ) 28,258 16,002 Plugging & abandonment ( 69,596 ) ( 67,988 ) ( 43,933 ) Decommissioning obligations settled ( 1,625 ) — — Investment in CCS intangibles and equity method investees ( 2,778 ) — — Other deferred payments — ( 7,921 ) ( 11,921 ) Non-cash well equipment inventory transfers ( 6 ) 1,086 ( 3,030 ) Other 1,728 1,074 299 Exploration, development and other capital expenditures $ 323,164 $ 293,331 $ 362,942

Supplemental Oil and Gas Disclo

Supplemental Oil and Gas Disclosures (Unaudited)	12 Months Ended
	Dec. 31, 2022
Extractive Industries [Abstract]
Supplemental Oil and Gas Disclosures (Unaudited)	N ote 14 — Suppl emental Oil and Gas Disclosures (Unaudited) Capitalized Costs Aggregate amounts of capitalized costs relating to oil, natural gas and NGL activities and the aggregate amount of related accumulated depletion and amortization as of the dates indicated are presented below (in thousands): Year Ended December 31, 2022 2021 2020 Proved properties $ 5,964,340 $ 5,232,479 $ 4,945,550 Unproved oil and gas properties, not subject to amortization (1) 154,783 219,055 254,994 Total oil and gas properties 6,119,123 5,451,534 5,200,544 Less: Accumulated depletion 3,484,590 3,072,907 2,680,254 Net capitalized costs $ 2,634,533 $ 2,378,627 $ 2,520,290 Depletion and amortization rate (Per MBoe) (2) $ 18.95 $ 16.71 $ 31.42 (1) Amount includes $ 111.4 million, $ 110.3 million and $ 121.7 million of unproved properties, not subject to amortization, related to the Company’s operations in offshore Mexico for the years ended December 31, 2022, 2021 and 2020, respectively. (2) Year ended December 31, 2020 includes the impact of a write-down of U.S. oil and natural gas properties as a result of the Company’s ceiling test computations. See Note 4 — Property, Plant and Equipment for additional information. Included in the depletable basis of proved oil and gas properties is the estimate of the Company’s proportionate share of asset retirement costs relating to these properties which are also reflected as “Asset retirement obligations” on the accompanying Consolidated Balance Sheets. See Note 4 — Property, Plant and Equipment for additional information. Costs Incurred for Property Acquisition, Exploration and Development Activities The following table reflects the costs incurred in oil, natural gas and NGL property acquisition, exploration and development activities during the years indicated (in thousands). Costs incurred also include new asset retirement obligations established in the current year, as well as increases or decreases to the asset retirement obligations resulting from changes to estimates during the year. Year Ended December 31, 2022 2021 2020 Property acquisition costs: Proved properties $ — $ 210 $ 422,833 Unproved properties, not subject to amortization 2,221 — 95,242 Total property acquisition costs 2,221 210 518,075 Exploration costs (1) 125,889 23,844 59,422 Development costs 541,512 245,058 362,011 Total costs incurred $ 669,622 $ 269,112 $ 939,508 (1) Amount includes $ 1.2 million, $ 6.6 million and $ 14.6 million of exploration costs related to the Company’s operations in offshore Mexico for the years ended December 31, 2022, 2021 and 2020 , respectively. Estimated Quantities of Proved Oil, Natural Gas and NGL Reserves The Company employs full-time experienced reserve engineers and geologists who are responsible for determining proved reserves in compliance with SEC guidelines. There are numerous uncertainties inherent in estimating quantities of proved reserves and projecting future rates of production and timing of development expenditures. The reserve data in the following tables only represent estimates and should not be construed as being exact. Engineering reserve estimates were prepared based upon interpretation of production performance data and subsurface information obtained from the drilling of existing wells. The Company’s Director of Reserves, internal reservoir engineers and geologists analyzed and prepared reserve estimates on all oil and natural gas fields. All of the Company’s proved oil, natural gas and NGL reserves are located in the U.S. Gulf of Mexico. At, December 31, 2022, 2021 and 2020 , 100 % of proved oil, natural gas and NGL reserves attributable to all of the Company’s oil and natural gas properties were estimated and compiled for reporting purposes by the Company’s reservoir engineers and audited by Netherland, Sewell & Associates, Inc. (“NSAI”), independent petroleum engineers and geologists. The following table presents the Company’s estimated proved reserves at its net ownership interest: Oil (MBbls) Gas (MMcf) NGL (MBbls) Oil Total proved reserves at December 31, 2019 106,754 155,998 8,981 141,735 Revision of previous estimates ( 14,633 ) ( 56,358 ) ( 168 ) ( 24,195 ) Production (1) ( 13,665 ) ( 28,652 ) ( 1,559 ) ( 19,999 ) Purchases of reserves 26,903 181,872 3,528 60,743 Extensions and discoveries 3,948 4,348 76 4,749 Total proved reserves at December 31, 2020 109,307 257,208 10,858 163,033 Revision of previous estimates 13,619 8,979 5,137 20,252 Production ( 16,159 ) ( 32,795 ) ( 1,875 ) ( 23,500 ) Extensions and discoveries 997 2,961 315 1,806 Total proved reserves at December 31, 2021 107,764 236,353 14,435 161,591 Revision of previous estimates ( 5,625 ) ( 8,302 ) ( 2,002 ) ( 9,010 ) Production ( 14,561 ) ( 32,215 ) ( 1,793 ) ( 21,723 ) Sales of reserves ( 158 ) ( 7,625 ) — ( 1,429 ) Extensions and discoveries 3,639 31,340 2,288 11,150 Total proved reserves at December 31, 2022 91,059 219,551 12,928 140,579 Total proved developed reserves as of: December 31, 2020 85,007 204,054 8,104 127,120 December 31, 2021 93,420 186,442 11,792 136,286 December 31, 2022 80,285 161,727 9,315 116,555 Total proved undeveloped reserves as of: December 31, 2020 24,300 53,154 2,754 35,913 December 31, 2021 14,344 49,911 2,643 25,305 December 31, 2022 10,774 57,824 3,613 24,024 (1) Excludes approximately 3.0 MBoe of Mexico well test production . During 2022, proved reserves decreased by 21.0 MMBoe primarily due to a decrease of 21.7 MMBoe of production. Additionally, there was a decrease of 9.0 MMBoe primarily due to timing of development of certain PUD locations to move beyond five years at the Phoenix Field in the Green Canyon core area and sales of reserves of 1.4 MMBoe primarily related to the Brushy Creek Field in the Shelf and Gulf Coast core area. The decrease was partially offset by 11.2 MMBoe of estimated proved reserves from extensions and discoveries primarily from evaluations of the Pompano Field and the Ram Powell Field located in the Mississippi Canyon core area. During 2021 , proved reserves decreased by 1.4 MMBoe primarily due to a decrease of 23.5 MMBoe of production. The decrease was partially offset by revision to previous estimates of 20.3 MMBoe due to increase in commodity prices as well as 1.8 MMBoe of estimated proved reserves from extensions and discoveries primarily from an evaluation of Crown and Anchor Field located in the Mississippi Canyon core area. During 2020 , proved reserves decreased by 21.3 MMBoe primarily due to a decrease of 20.0 MMBoe of production and revision to previous estimates of 24.2 MMBoe due to decrease in commodity prices. The decrease was partially offset by the addition of 60.7 MMBoe added through purchases from the ILX and Castex Acquisition, Castex Energy 2005 Acquisition and LLOG Acquisition as well as 4.7 MMBoe of estimated proved reserves from extensions and discoveries primarily from an evaluation of Green Canyon 18 and Claiborne Fields. 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, 2022 2021 2020 Future cash inflows $ 10,674,896 $ 8,496,005 $ 4,927,497 Future costs: Production ( 1,906,752 ) ( 1,868,818 ) ( 1,105,211 ) Development and abandonment ( 1,873,453 ) ( 1,422,507 ) ( 1,236,874 ) Future net cash flows before income taxes 6,894,691 5,204,680 2,585,412 Future income tax expense ( 1,114,409 ) ( 676,778 ) ( 141,515 ) Future net cash flows after income taxes 5,780,282 4,527,902 2,443,897 Discount at 10% annual rate ( 1,411,834 ) ( 1,087,291 ) ( 538,963 ) Standardized measure of discounted future net cash flows $ 4,368,448 $ 3,440,611 $ 1,904,934 Future cash inflows are computed by applying SEC Pricing to year-end quantities of proved reserves. The discounted future cash flow estimates do not include the effects of derivative instruments. See the following table for SEC Pricing used in determining the standardized measure: Year Ended December 31, 2022 2021 2020 Oil price per Bbl $ 96.03 $ 67.14 $ 39.47 Natural gas price per Mcf $ 6.80 $ 3.71 $ 1.97 NGL price per Bbl $ 33.89 $ 26.62 $ 9.89 Future net cash flows are discounted at the prescribed rate of 10 %. Actual future net cash flows may vary considerably from these estimates. Although the Company’s estimates of total proved reserves, development and abandonment costs and production rates were based on the best information available, the development and production of oil and gas reserves may not occur in the periods assumed. All estimated costs to settle asset retirement obligations associated with our proved reserves have been included in our calculation of development and abandonment of the standardized measure of discounted future net cash flows for each period presented. Actual prices realized, costs incurred and production quantities may vary significantly from those used. Therefore, such estimated future net cash flow computations should not be considered to represent the Company’s estimate of the expected revenues or the current value of existing proved reserves. Changes in Standardized Measure of Discounted Future Net Cash Flows Principal changes in the standardized measure of discounted future net cash flows attributable to the Company’s proved oil, natural gas and NGL reserves are as follows (in thousands): Year Ended December 31, 2022 2021 2020 Standardized measure, beginning of year $ 3,440,611 $ 1,904,934 $ 2,537,595 Sales and transfers of oil, net gas and NGLs produced during the period ( 1,340,400 ) ( 957,576 ) ( 339,557 ) Net change in prices and production costs 2,388,442 2,049,980 ( 1,468,304 ) Changes in estimated future development and abandonment costs ( 84,391 ) ( 57,876 ) 32,589 Previously estimated development and abandonment costs incurred 20,107 69,125 46,143 Accretion of discount 392,600 199,849 299,302 Net change in income taxes ( 327,265 ) ( 391,834 ) 361,875 Purchases of reserves — — 730,611 Sales of reserves ( 5,218 ) — — Extensions and discoveries 202,239 45,485 71,589 Net change due to revision in quantity estimates ( 255,743 ) 426,357 ( 309,338 ) Changes in production rates (timing) and other ( 62,534 ) 152,167 ( 57,571 ) Standardized measure, end of year $ 4,368,448 $ 3,440,611 $ 1,904,934

Subsequent Events

Subsequent Events	12 Months Ended
	Dec. 31, 2022
Subsequent Events [Abstract]
Subsequent Events	Note 15 — Subsequent Events EnVen Acquisition For additional information, see the following: • Note 3 — Acquisitions • Note 7 — Debt • Note 11 — Related Party Transactions

Schedule I - Condensed Financia

Schedule I - Condensed Financial Information of Registrant (Parent Only)	12 Months Ended
	Dec. 31, 2022
Condensed Financial Information Disclosure [Abstract]
Schedule I - Condensed Financial Information of Registrant (Parent Only)	Schedule I. Condensed Financial Information of Registrant TALOS ENERGY INC. (PARENT ONLY) BALANCE SHEETS (In thousands, except share amounts) Year Ended December 31, 2022 2021 ASSETS Current assets: Accounts receivable: Other, net $ — $ 523 Prepaid assets 169 141 Other current assets 36 — Total current assets 205 664 Other long-term assets: Investments in subsidiaries 1,168,053 761,739 Total assets $ 1,168,258 $ 762,403 LIABILITIES AND STOCKHOLDERSʼ EQUITY Current liabilities: Accounts payable $ 249 $ 178 Accrued liabilities 728 497 Other current liabilities 62 — Total current liabilities 1,039 675 Long-term liabilities: Other long-term liabilities 1,643 1,075 Total liabilities 2,682 1,750 Stockholdersʼ equity: Preferred stock, $ 0.01 par value; 30,000,000 shares authorized and no shares issued or outstanding as of December 31, 2022 and 2021 — — Common stock $ 0.01 par value; 270,000,000 shares authorized; 82,570,328 and 81,881,477 shares issued and outstanding as of December 31, 2022 and 2021, respectively 826 819 Additional paid-in capital 1,699,799 1,676,798 Accumulated deficit ( 535,049 ) ( 916,964 ) Total stockholdersʼ equity 1,165,576 760,653 Total liabilities and stockholdersʼ equity $ 1,168,258 $ 762,403 TALOS ENERGY INC. (PARENT ONLY) STATEMENTS OF OPERATIONS (In thousands) Year Ended December 31, 2022 2021 2020 Operating expenses: General and administrative expense $ 2,145 $ 1,322 $ 1,404 Total operating expenses 2,145 1,322 1,404 Operating expense ( 2,145 ) ( 1,322 ) ( 1,404 ) Interest income (expense) — ( 5 ) 7 Other expense ( 1 ) ( 2 ) ( 2 ) Equity earnings (loss) from subsidiaries 385,968 ( 180,548 ) ( 431,446 ) Net income (loss) before income taxes 383,822 ( 181,877 ) ( 432,845 ) Income tax expense ( 1,907 ) ( 1,075 ) ( 32,760 ) Net income (loss) $ 381,915 $ ( 182,952 ) $ ( 465,605 ) TALOS ENERGY INC. (PARENT ONLY) STATEMENTS OF CASH FLOWS (In thousands) Year Ended December 31, 2022 2021 2020 Cash flows from operating activities: Net cash provided used in operating activities $ ( 809 ) $ ( 876 ) $ ( 936 ) Cash flows from investing activities: Distributions from subsidiaries 809 879 943 Contributions to subsidiaries — ( 3 ) ( 71,107 ) Net cash provided by (used in) investing activities 809 876 ( 70,164 ) Cash flows from financing activities: Proceeds from issuance of common stock — — 71,100 Net cash provided by financing activities — — 71,100 Net increase (decrease) in cash and cash equivalents — — — Cash and cash equivalents: Balance, beginning of period — — — Balance, end of period $ — $ — $ — TALOS ENERGY INC. (PARENT ONLY) NOTES TO CONDENSED FINANCIAL STATEMENTS December 31, 2022 Note 1 — Basis of Presentation Pursuant to the rules and regulations of the SEC, the parent only condensed financial information of Talos Energy, Inc. do not reflect all of the information and notes normally included with financial statements prepared in accordance with GAAP. Therefore, these condensed financial statements should be read in conjunction with the consolidated financial statements and related notes included under Part IV, Item 15. Exhibits and Financial Statement Schedules in this Annual Report.

Summary of Significant Accoun_2

Summary of Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2022
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Organization, Nature of Business, Basis of Presentation and Consolidation	Organization and Nature of Business Talos Energy Inc. (the “Parent Company”) is a Delaware corporation originally incorporated on November 14, 2017 . On May 10, 2018 , the Parent Company consummated a combination between Talos Energy LLC and Stone Energy Corporation (“Stone”) (such combination, “Stone Combination”). Talos Energy LLC, which was the acquirer of Stone for financial reporting and accounting purposes, was formed in 2011 and commenced commercial operations on February 6, 2013 . The Parent Company conducts all business operations through its operating subsidiaries, owns no operating assets and has no material operations, cash flows or liabilities independent of its subsidiaries. The Parent Company’s common stock is traded on the New York Stock Exchange under the ticker symbol “TALO.” The Parent Company (including its subsidiaries, collectively “Talos” or the “Company”) is a technically driven independent exploration and production company focused on safely and efficiently maximizing long-term value through its operations, currently in the United States (“U.S.”) and offshore Mexico both through upstream oil and gas exploration and production and the development of carbon capture and sequestration (“CCS”) opportunities. The Company leverages decades of technical and offshore operational expertise in the acquisition, exploration and development of assets in key geological trends that are present in many offshore basins around the world. With a focus on environmental stewardship, the Company also utilizes its expertise to explore opportunities to reduce industrial emissions through the Company’s CCS initiatives along the coast of the U.S. Gulf of Mexico. Basis of Presentation and Consolidation The Consolidated Financial Statements have been prepared in accordance with GAAP and include the accounts of the Parent Company and entities in which the Parent Company holds a controlling financial interest. Both majority-owned subsidiaries and any variable interest entity in which the Parent Company is the primary beneficiary are consolidated. All intercompany transactions have been eliminated. All adjustments are of a normal, recurring nature and are necessary to fairly present the financial position, results of operations and cash flows for the periods reflected herein. The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities as of the date of the financial statements, the reported amounts of revenues and expenses during the reporting periods and the reported amounts of proved oil and natural gas reserves. Actual results could differ from those estimates. Segments The Company has two operating segments: (i) exploration and production of oil, natural gas and NGLs (“Upstream Segment”) and (ii) CCS (“CCS Segment”). The Upstream Segment is the Company’s only reportable segment. The legal entities included in the CCS Segment have been designated as unrestricted, non-guarantor subsidiaries of the Company for purposes of the Bank Credit Facility (as defined in Note 2 — Summary of Significant Accounting Policies ) and indenture governing the senior notes. See additional information in Note 13 — Segment Information.
Cash and Cash Equivalents	Cash and Cash Equivalents — The Company presents cash as “Cash and cash equivalents” on the Company’s Consolidated Balance Sheets. The Company considers all cash, money market funds and highly liquid investments with an original maturity of three months or less as cash and cash equivalents. Cash and cash equivalents are carried at cost, which approximates fair value.
Accounts Receivable and Allowance for Expected Credit Losses	Accounts Receivable and Allowance for Expected Credit Losses — Accounts receivable are stated at the historical carrying amount net of an allowance for expected credit losses. At each reporting period, the recoverability of material receivables is assessed using historical data, current market conditions and reasonable and supported forecasts of future economic conditions to determine their expected collectability. A loss-rate methodology is used to estimate the allowance for expected credit losses to be accrued on material receivables to reflect the net amount to be collected. As of December 31, 2022 and 2021 , the Company had allowances of $ 10.7 million and $ 15.1 million, respectively, presented net in accounts receivable on the Consolidated Balance Sheets. The Company presented $ 3.2 million and $ 10.0 million of long-term refund claims for value added taxes paid in Mexico in “Other assets” on the Consolidated Balance Sheets as of December 31, 2022 and 2021 , respectively. Current refund claims for value added taxes paid in Mexico of $ 1.7 million and $ 3.9 million is presented net of an allowance in “Other” accounts receivable on the Consolidated Balance Sheets as of December 31, 2022 and 2021 , respectively.
Price Risk Management Activities	Price Risk Management Activities — The Company uses commodity price derivatives to manage fluctuating oil and natural gas market risks. The Company periodically enters into commodity derivative contracts, which may require payments to (or receipts from) counterparties based on the differential between a fixed price and a variable price for a fixed quantity of oil or natural gas without the exchange of underlying volumes. Commodity derivatives are recorded on the Consolidated Balance Sheets at fair value with settlements of such contracts and changes in the unrealized fair value recorded in earnings each period. Realized gains and losses on the settlement of commodity derivatives and changes in their unrealized gains and losses are reported in “Price risk management activities income (expense)” on the Consolidated Statements of Operations. The Company classifies cash flows related to derivative contracts based on the nature and purpose of the derivative. As the derivative cash flows are considered an integral part of the Company’s oil and natural gas operations, they are classified as cash flows from operating activities. The Company does not enter into derivative agreements for trading or other speculative purposes. The commodity derivative’s fair value reflects the Company’s best estimate with priority based upon exchange or over-the-counter quotations. Quoted valuations may not be available due to location differences or terms that extend beyond the period for which quotations are available. Where quotes are not available, the Company then utilizes other valuation techniques or models to estimate market values. These modeling techniques require the Company to make estimations of future prices, price correlation, market volatility and liquidity. The Company’s actual results may differ from its estimates, and these differences can be favorable or unfavorable.
Prepaid Assets	Prepaid Assets — Prepaid assets primarily represent prepaid subscriptions, insurance, progress payments for well equipment and deposits with the Office of Natural Resources Revenue (“ONRR”) . The progress payments made for well equipment relate to long lead time items which the Company has not taken title to as of period end. The deposits with ONRR represent the Company’s estimated federal royalties payable within thirty days of the production date. On a monthly basis the Company adjusts the deposit based on actual royalty payments remitted to the ONRR.
Accounting for Oil and Natural Gas Activities	Accounting for Oil and Natural Gas Activities — The Company follows the full cost method of accounting for oil and natural gas exploration and development activities. Under the full cost method, substantially all costs incurred in connection with the acquisition, development and exploration of oil and natural gas reserves are capitalized. These capitalized amounts include the internal costs directly related to acquisition, development and exploration activities, asset retirement costs and capitalized interest. Under the full cost method, dry hole costs and geological and geophysical costs are capitalized into the full cost pool, which is subject to amortization and assessed for impairment on a quarterly basis through a ceiling test calculation as discussed below. Capitalized costs associated with proved reserves are amortized on a country-by-country basis over the life of the total proved reserves using the unit of production method, computed quarterly. Conversely, capitalized costs associated with unproved properties and related geological and geophysical costs, exploration wells currently drilling and capitalized interest are initially excluded from the amortizable base. The Company transfers unproved property costs into the amortizable base when properties are determined to have proved reserves or when the Company has completed an unproved properties evaluation resulting in an impairment. The Company evaluates each of these unproved properties individually for impairment at least annually. Additionally, the amortizable base includes future development costs, dismantlement, restoration and abandonment costs, net of estimated salvage values, and geological and geophysical costs incurred that cannot be associated with specific unproved properties or prospects in which the Company owns a direct interest. The Company capitalizes overhead costs that are directly related to exploration, acquisition and development activities. The Company’s capitalized costs are limited to a ceiling based on the present value of future net revenues from proved reserves, computed using a discount factor of 10 %, plus the lower of cost or estimated fair value of unproved oil and natural gas properties not being amortized less the related tax effects. Generally, any costs in excess of the ceiling are recognized as a non-cash “Write-down of oil and natural gas properties” on the Consolidated Statements of Operations and an increase to “Accumulated depreciation, depletion and amortization” on the Company’s Consolidated Balance Sheets. The expense may not be reversed in future periods, even though higher oil, natural gas and NGL prices may subsequently increase the ceiling. The Company performs this ceiling test calculation each quarter. In accordance with the SEC rules and regulations, the Company utilizes SEC Pricing when performing the ceiling test. The Company also holds prices and costs constant over the life of the reserves, even though actual prices and costs of oil and natural gas are often volatile and may change from period to period. Under the full cost method of accounting for oil and natural gas operations, assets whose costs are currently being depreciated, depleted or amortized are assets in use in the earnings activities of the enterprise and do not qualify for capitalization of interest cost. Investments in unproved properties for which exploration and development activities are in progress and other major development projects that are not being currently depreciated, depleted or amortized are assets qualifying for capitalization of interest costs. When the Company sells or conveys interests in oil and natural gas properties, the Company reduces its oil and natural gas reserves for the amount attributable to the sold or conveyed interest. The Company treats sales proceeds on non-significant sales as reductions to the cost of the Company’s oil and natural gas properties. The Company does not recognize a gain or loss on sales of oil and natural gas properties, unless those sales would significantly alter the relationship between capitalized costs and proved reserves.
Accounting for CCS Development Activities	Accounting for CCS Development Activities — Expenditures for CCS during the preliminary stages of development are charged to expense as incurred until the development of the project is considered probable. These costs primarily include professional fees associated with front-end engineering and design work, costs of securing necessary regulatory approvals and other preliminary investigation and development activities. The pre-construction stage of project development begins once construction of the individual project becomes probable. Certain costs may be capitalized prior to a project becoming probable and include: land acquisition costs; detailed engineering design work; and costs that have an alternative use (e.g., stratigraphic test well). Capitalized development costs are included as a component of other long-term assets during the pre-construction stage of development. These capitalized costs are charged to expense if a project is abandoned or management otherwise determines the costs to be unrecoverable. CCS contracts that convey subsurface rights for geologic pore space are accounted for as intangible assets and amortized over their estimated useful life. As of December 31, 2022 and 2021, the Company had $ 1.4 million and nil intangible assets, respectively. These assets are classified as other long-term assets and included in “Other assets” on the Consolidated Balance Sheets.
Intangible Assets, Costs Incurred to Renew or Extend	Costs to renew or extend the life of CCS intangible assets are capitalized and amortized over the remaining useful life.
Other Property and Equipment	Other Property and Equipment — Other property and equipment is recorded at cost and consists primarily of leasehold improvements, office furniture and fixtures and computer hardware. Acquisitions and betterments are capitalized; maintenance and repairs are expensed as incurred. Depreciation is provided using the straight-line method over estimated useful lives of three to ten years .
Equity Method Investments	Equity Method Investments — If the entity is organized as a limited partnership or limited liability company and maintains separate ownership accounts, the Company accounts for its investment using the equity method if the Company’s ownership interest is between  3 % and  50 %, unless the Company’s interest is so minor that it has virtually no influence over the investee’s operating and financial policies. For all other types of investments, the Company applies the equity method of accounting if its ownership interest is between  20 % and  50 % and the Company’s exercise significant influence over the investee’s operating and financial policies. In applying the equity method of accounting, the investments are initially recognized at cost and subsequently adjusted for the Company’s proportionate share of earnings, losses, contributions and distributions. Investments accounted for using the equity method are reflected as “Equity method investments” on the Consolidated Balance Sheets. The equity in earnings of an investee are reflected in “Equity method investment income (loss)” on the Consolidated Statement of Operations. The gain or loss from the full or partial sale of an equity method investment is presented in the same line item in which the Company reports the equity in earnings of the investee. The Company assesses equity method investments for impairment whenever changes in the facts and circumstances indicate a loss in value has occurred if the loss is deemed to be other-than-temporary. When the loss is deemed to be other-than-temporary, the carrying value of the equity method investment is written down to fair value. The impairment charge is included as a component of the Company’s share of the earning or losses of the investee. No impairment charges have been recorded during the years ended December 31, 2022, 2021 and 2020 .
Other Well Equipment Inventory	Other Well Equipment Inventory — Other well equipment inventory primarily represents the cost of equipment to be used in the Company’s oil and natural gas drilling and development activities such as drilling pipe, tubulars and certain wellhead equipment. When well equipment is supplied to wells, the cost is capitalized in oil and gas properties, and if such property is jointly owned, the proportionate costs will be reimbursed by third party participants. The Company’s well equipment is stated at the lower of cost or net realizable value. The Company recorded nil , $ 5.6 million and $ 0.7 million of impairment to adjust inventory to net realizable value, which was expensed and reflected in “Other operating (income) expense” on the Consolidated Statements of Operations, during the years ended December 31, 2022, 2021 and 2020 , respectively.
Leases	Leases — At inception, contracts are reviewed to determine whether the agreement contains a lease. To the extent an arrangement is determined to include a lease, it is classified as either an operating or a finance lease, which dictates the pattern of expense recognition in the income statement. Operating leases are reflected as “Operating lease assets,” “Current portion of operating lease liabilities” and “Operating lease liabilities” on the Consolidated Balance Sheets. Finance leases are included in “Property and equipment,” “Other current liabilities” and “Other long-term liabilities” on the Consolidated Balance Sheets. A right-of-use (“ROU”) asset representing our right to use an underlying asset for the lease term and a lease liability representing our obligation to make lease payments arising from the lease are recognized on the Consolidated Balance Sheets for all leases, regardless of classification. The ROU asset is initially measured as the present value of the lease liability adjusted for any payments made prior to lease commencement, including any initial direct costs incurred and incentives received. Lease liabilities are initially measured at the present value of future minimum lease payments, excluding variable lease payments, over the lease term. As most of our leases do not provide an implicit rate, the Company generally uses an incremental borrowing rate based on the estimated rate of interest for collateralized borrowing over a similar term of the lease payments at commencement date. The Company has elected to account for lease and non-lease components in its contracts as a single lease component for all asset classes except for our leased floating production vessel class. Our lease terms may include options to extend or terminate the lease when it is reasonably certain that the Company will exercise that option. The Company has elected, as an accounting policy, not to record leases with terms of twelve months or less (i.e., short-term) on the Consolidated Balance Sheets. See Note 5 — Leases for additional information
Debt Issuance Costs	Debt Issuance Costs — The Company presents debt issuance costs associated with revolving line-of-credit arrangements as a reduction of the carrying value of long-term debt.
Asset Retirement Obligations	Asset Retirement Obligations — The Company has obligations associated with the retirement of its oil and natural gas wells and related infrastructure. The Company has obligations to plug wells when production on those wells is exhausted, when the Company no longer plans to use them or when the Company abandons them. The Company accrues a liability with respect to these obligations based on its estimate of the timing and amount to replace, remove or retire the associated assets. In estimating the liability associated with its asset retirement obligations, the Company utilizes several assumptions, including a credit-adjusted risk-free interest rate, estimated costs of decommissioning services, estimated timing of when the work will be performed and a projected inflation rate. Changes in estimate represent changes to the expected amount and timing of payments to settle its asset retirement obligations. Typically, these changes result from obtaining new information about the timing of its obligations to plug and abandon oil and natural gas wells and the costs to do so. After initial recording, the liability is increased for the passage of time, with the increase being reflected as “Accretion expense” on the Company’s Consolidated Statements of Operations. If the Company incurs an amount different from the amount accrued for asset retirement obligations, the Company recognizes the difference as an adjustment to proved properties.
Decommissioning Obligations	Decommissioning Obligations — Certain counterparties in divestiture transactions or third parties in existing leases that have filed for bankruptcy protection or undergone associated reorganizations may not be able to perform required abandonment obligations. The Company may be held jointly and severally liable for the decommissioning of various facilities and related wells. The Company accrues losses associated with decommissioning obligations when such losses are probable and reasonably estimable. When there is a range of possible outcomes, the amount accrued is the most likely outcome within the range. If no single outcome within the range is more likely than the others, the minimum amount in the range is accrued. These accruals may be adjusted as additional information becomes available. In addition, when decommissioning obligations are reasonably possible, the Company discloses an estimate for a possible loss or range of loss (or a statement that such an estimate cannot be reasonably made). See Note 12 — Commitments & Contingencies for additional information.
Share-Based Compensation	Share-Based Compensation — Certain of the Company’s employees participate in its equity-based compensation plan. The Company measures all employee equity-based compensation awards at fair value on the date awards are granted to its employees . The fair value of the stock-based awards is determined at the date of grant and is not remeasured for awards classified as equity unless the award is modified. Liability classified awards are remeasured at each reporting period. The Company records share-based compensation, net of actual forfeitures, for the RSUs and PSUs in “General and administrative expense” on the Consolidated Statements of Operations, net of amounts capitalized to oil and gas properties. See Note 8 — Employee Benefits Plans and Share-Based Compensation for additional information. Restricted Stock Units (“RSUs”) — Share-based compensation is based on the market price of the Company’s common stock on the grant date and recognized over the requisite service period using the straight-line method. Performance Share Units (“PSUs”) with Market Based Conditions — Share-based compensation is based on the grant date fair value determined using a Monte Carlo valuation model for awards with a market condition and recognized over the requisite service period using the straight-line method. Estimates used in the Monte Carlo valuation model are considered highly-complex and subjective. The number of shares of common stock issuable upon vesting ranges from zero to 200 % of the number of PSUs granted based on the Company’s total shareholder return (“TSR”). Share-based compensation related to PSUs with a market condition are recognized as the requisite service period is fulfilled, even if the market condition is not achieved. PSUs with Performance Based Conditions — Share-based compensation is based on the market price of the Company’s common stock on the grant date and recognized over the requisite service period using the straight-line method for awards with a performance condition. The Company recognizes compensation cost for awards with performance conditions if and when the Company concludes that it is probable that the performance condition will be achieved. The Company reassesses the probability of vesting at each reporting period for awards with performance conditions and adjusts compensation cost based on its probability assessment. The Company recognizes a cumulative catch-up adjustment for such changes in its probability assessment in subsequent reporting periods, using the grant date fair value of the award whose terms reflect the updated probable performance condition (which could be either a reversal or increase in expense). The number of shares of common stock issuable upon vesting ranges from zero to 200 % of the number of PSUs granted based on a metric associated with the Company’s own operations or activities.
Revenue Recognition	Revenue Recognition — Revenues are recorded based from the sale of oil, natural gas and NGL quantities sold to purchasers. The Company records revenues from the sale of oil, natural gas and NGLs based on quantities of production sold to purchasers under short-term contracts (less than twelve months) at market prices when delivery to the customer has occurred, title has transferred, prices are fixed and determinable and collection is reasonably assured. This occurs when production has been delivered to a pipeline or when a barge lifting has occurred. The Company recognizes transportation costs as a component of lease operating expense when it is the shipper of the product. Each unit of product typically represents a separate performance obligation, therefore, future volumes are wholly unsatisfied and disclosure of the transaction price allocated to remaining performance obligations is not required.
Gas Imbalances	Gas Imbalances — Revenues are recorded based on the actual sales volumes sold to purchasers. An imbalance receivable or payable is recorded only to the extent the imbalance is in excess of its share of remaining proved developed reserves in an underlying property. Our imbalances are presented gross on our Consolidated Balance Sheets. At December 31, 2022 and 2021 , our imbalance receivable was approximately $ 1.7 million and $ 1.7 million, respectively, and imbalance payable was approximately $ 2.5 million and $ 2.5 million, respectively.
Production Handling Fees	Production Handling Fees — The Company presents certain reimbursements for costs from certain third parties as a reduction of “Lease operating expense” on the Consolidated Statements of Operations.
ONRR Federal Royalty Refund	ONRR Federal Royalty Refund — Included within “Other operating (income) expense” on the Consolidated Statements of Operations is income from the Company’s multi-year federal royalty refund claim from the ONRR. The Company records income when a refund is filed and its collection is reasonably assured. The refunds for the years ended December 31, 2022, 2021 and 2020 were $ 0.6 million, nil and $ 8.9 million, respectively.
Income Taxes	Income Taxes — The Company records current income taxes based on estimates of current taxable income and provides for deferred income taxes to reflect estimated future income tax payments and receipts. The impact to changes in tax laws are recorded in the period the change is enacted. Deferred taxes represent the tax impacts of differences between the financial statement and tax bases of assets and liabilities and carryovers at each year end. The Company classifies all deferred tax assets and liabilities, along with any related valuation allowance, as long-term on the Consolidated Balance Sheets. The realization of deferred tax assets depends on recognition of sufficient future taxable income during periods in which those temporary differences are deductible. The Company reduces deferred tax assets by a valuation allowance when, based on estimates, it is more likely than not that a portion of those assets will not be realized in a future period. The deferred tax asset estimates are subject to revision, either up or down, in future periods based on new facts or circumstances. In evaluating the Company’s valuation allowances, the Company considers cumulative book losses, the reversal of existing temporary differences, the existence of taxable income in carryback years, tax planning strategies and future taxable income for each of its taxable jurisdictions, the latter two of which involve the exercise of significant judgment. Changes to the Company’s valuation allowances could materially impact its results of operations. The Company’s policy is to classify interest and penalties associated with underpayment of income taxes as “Interest expense” and “General and administrative expense” on the Consolidated Statements of Operations, respectively.
Income (Loss) Per Share	Income (Loss) Per Share — Basic net income per common share (“EPS”) is computed by dividing net income (loss) by the weighted average number of shares of common stock outstanding during the period. Except when the effect would be antidilutive, diluted EPS includes the impact of RSUs, PSUs and outstanding warrants. See Note 10 — Income (Loss) Per Share for additional information.
Fair Value Measure of Financial Instruments	Fair Value Measure of Financial Instruments — Financial instruments generally consist of cash and cash equivalents, accounts receivable, commodity derivatives, accounts payable and debt. The carrying amount of cash and cash equivalents, accounts receivable and accounts payable approximates fair value due to the highly liquid nature of these instruments. Current fair value accounting standards define fair value, establish a consistent framework for measuring fair value and stipulate the related disclosure requirements for each major asset and liability category measured at fair value on either a recurring or nonrecurring basis. These standards also clarify fair value is an exit price, presenting the amount that would be received to sell an asset or paid to transfer a liability, in an orderly transaction between market participants. The Company follows a three-level hierarchy, prioritizing and defining the types of inputs used to measure fair value depending on the degree to which they are observable as follows: • Level 1 – Inputs to the valuation methodology are quoted prices (unadjusted) for identical assets or liabilities in active markets. • Level 2 – Inputs to the valuation methodology include quoted prices for similar assets and liabilities in active markets, and inputs that are observable for the asset or liability, either directly or indirectly, for substantially the full term of the financial statement. • Level 3 – Inputs to the valuation methodology are unobservable (little or no market data), which require the reporting entity to develop its own assumptions, and are significant to the fair value measurement. Assets and liabilities measured at fair value are based on one or more of three valuation techniques. The valuation techniques are as follows: • Market Approach – Prices and other relevant information generated by market transactions involving identical or comparable assets or liabilities. • Cost Approach – Amount that would be required to replace the service capacity of an asset (replacement cost). • Income Approach – Techniques to convert expected future cash flows to a single present value amount based on market expectations (including present value techniques, option-pricing and excess earnings models). Authoritative guidance on financial instruments requires certain fair value disclosures to be presented. The estimated fair value amounts have been determined using available market information and valuation methodologies. Considerable judgment is required in interpreting market data to develop the estimates of fair value. The use of different assumptions or valuation methodologies may have a material effect on the estimated fair value amounts.
Variable Interest Entities	Variable Interest Entities — Upon inception of a contractual agreement, the Parent Company performs an assessment to determine whether the arrangement contains a variable interest in a legal entity and whether that legal entity is a variable interest Entity (“VIE”). The Parent Company assesses all aspects of its interests in an entity and uses judgment when determining if it is the primary beneficiary. The primary beneficiary has both the power to direct the activities of the VIE that most significantly impact the entity’s economic performance and the obligation to absorb losses or the right to receive benefits from the VIE that could potentially be significant to the VIE. Other qualitative factors that are considered include decision-making responsibilities, the VIE capital structure, risk and rewards sharing, contractual agreements with the VIE, voting rights and level of involvement of other parties. A reassessment of the primary beneficiary conclusion is conducted when there are changes in the facts and circumstances related to a VIE. See Note 11 — Related Party Transactions for additional information.
Concentration of Credit Risk	Concentration of Credit Risk Consisting principally of cash and cash equivalents, accounts receivable and commodity derivatives, the Company is subject to concentrated financial instruments credit risk. Cash and cash equivalents balances are maintained in financial institutions, which at times, exceed federally insured limits. The Company monitors the financial condition of these institutions and has not experienced losses on these accounts. Commodity derivatives are entered into with registered swap dealers, all of which participate in the Company’s senior reserve-based revolving credit facility (the “Bank Credit Facility”). The Company monitors the financial condition of these institutions and has not experienced losses due to counterparty default on these instruments. The Company markets 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, 2022 2021 2020 Shell Trading (US) Company 44 % 45 % 47 % Valero Energy Corporation 23 % ** ** Chevron Products Company 11 % 29 % 12 % Phillips 66 ** ** 22 % ** 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, 2022
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, 2022 2021 2020 Shell Trading (US) Company 44 % 45 % 47 % Valero Energy Corporation 23 % ** ** Chevron Products Company 11 % 29 % 12 % Phillips 66 ** ** 22 % ** Less than 10 %

Acquisitions (Tables)

Acquisitions (Tables) - ILX and Castex	12 Months Ended
	Dec. 31, 2022
Business Acquisition [Line Items]
Summary of Revenue and Net Income Attributable to Assets Acquired	The following table presents revenue and net income attributable to the assets acquired in the ILX and Castex Acquisition: Year Ended December 31, 2020 Revenue $ 126,857 Net loss $ ( 6,011 )
Supplemental Proforma Information	The following supplemental pro forma financial information (in thousands, except per common share amounts), presents the consolidated results of operations for the year ended December 31, 2020 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 Revenue $ 634,921 Net loss $ ( 449,988 ) Basic net loss per common share $ ( 6.48 ) Diluted net loss per common share $ ( 6.48 )

Property, Plant and Equipment (

Property, Plant and Equipment (Tables)	12 Months Ended
	Dec. 31, 2022
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, 2022, by the year in which such costs were incurred (in thousands): Year Ended December 31, Total 2022 2021 2020 2019 and Prior Acquisition United States $ 29,646 $ 2,221 $ — $ 27,322 $ 103 Exploration United States 13,707 2,696 4,727 1,753 4,531 Exploration Mexico 111,430 1,170 3,460 13,853 92,947 Total unproved properties, not subject to amortization $ 154,783 $ 6,087 $ 8,187 $ 42,928 $ 97,581
Schedule of Asset Retirement Obligations	The asset retirement obligations included in the Consolidated Balance Sheets in current and non-current liabilities, and the changes in that liability were as follows (in thousands): Year Ended December 31, 2022 2021 Balance, beginning of period $ 434,006 $ 442,269 Obligations acquired — 433 Obligations incurred 1,140 52 Obligations settled ( 69,596 ) ( 67,988 ) Obligations divested ( 1,572 ) ( 340 ) Accretion expense 55,995 58,129 Changes in estimate (1) 121,688 1,451 Balance, end of period $ 541,661 $ 434,006 Less: Current portion 39,888 60,311 Long-term portion $ 501,773 $ 373,695 (1) Changes in estimate for the year ended December 31, 2022 were primarily due to an increase in estimated service costs.

Leases (Tables)

Leases (Tables)	12 Months Ended
	Dec. 31, 2022
Leases [Abstract]
Components of Lease Costs	The components of lease costs were as follows (in thousands): Year Ended December 31, 2022 2021 2020 Finance lease cost - interest on lease liabilities $ 7,558 $ 11,453 $ 15,748 Operating lease cost, excluding short-term leases (1) 2,281 2,706 3,361 Short-term lease cost (2) 55,072 38,472 53,573 Variable lease cost (3) 1,450 1,356 543 Total lease cost $ 66,361 $ 53,987 $ 73,225 (1) Operating lease cost reflect a single lease cost, calculated so that the cost of the lease is allocated over the lease term on a straight-line basis. (2) Short-term lease costs are reported at gross amounts and primarily represent costs incurred for drilling rigs, most of which are short-term contracts not recognized as a ROU asset and lease liability on the Consolidated Balance Sheets. Variable lease costs primarily represent differences between minimum payment obligations and actual operating charges incurred by the Company related to its long-term leases.
Schedule of ROU Asset and Liability, Adjusted for Initial Direct Costs and Incentives	The present value of the fixed lease payments recorded as the Company’s ROU asset and liability, adjusted for initial direct costs and incentives were as follows (in thousands): Year Ended December 31, 2022 2021 Operating leases: Operating lease assets $ 5,903 $ 5,714 Current portion of operating lease liabilities $ 1,943 $ 1,715 Operating lease liabilities 14,855 16,330 Total operating lease liabilities $ 16,798 $ 18,045 Finance leases: Proved property $ 166,261 $ 124,299 Other current liabilities $ 16,306 $ 27,083 Other long-term liabilities 149,064 13,138 Total finance lease liabilities $ 165,370 $ 40,221
Schedule of Lease Maturity	The table below presents the lease maturity by year as of December 31, 2022 (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 2023 $ 3,774 $ 30,782 2024 3,579 30,782 2025 3,645 30,782 2026 3,712 30,782 2027 3,596 30,782 Thereafter 5,727 74,389 Total lease payments $ 24,033 $ 228,299 Imputed interest ( 7,235 ) ( 62,929 ) Total lease liabilities $ 16,798 $ 165,370
Schedule of Weighted Average Remaining Lease Term and Discount Rate	The table below presents the weighted average remaining lease term and discount rate related to leases: Year Ended December 31, 2022 2021 2020 Weighted average remaining lease term: Operating leases 6.4 years 7.4 years 7.8 years Finance leases 7.4 years 1.4 years 2.4 years Weighted average discount rate: Operating leases 11.8 % 11.9 % 12.0 % Finance leases 9.2 % 21.9 % 21.9 %
Supplemental Cash Flow Information Related to Leases	The table below presents the supplemental cash flow information related to leases (in thousands): Year Ended December 31, 2022 2021 2020 Operating cash outflow from finance leases $ 7,181 $ 11,453 $ 15,748 Operating cash outflow from operating leases $ 3,722 $ 3,864 $ 2,648 ROU assets obtained in exchange for new finance lease liabilities $ 166,261 $ — $ — ROU assets obtained in exchange for new operating lease liabilities $ 474 $ 1,020 $ —

Financial Instruments (Tables)

Financial Instruments (Tables)	12 Months Ended
	Dec. 31, 2022
Financial Instruments [Abstract]
Schedule of Carrying Amounts and Estimated Fair Values of Financial Instruments	The following table presents the carrying amounts, net of discount and deferred financing costs, and estimated fair values of the Company’s debt instruments (in thousands): December 31, 2022 December 31, 2021 Carrying Fair Carrying Fair 12.00 % Second-Priority Senior Secured Notes – due January 2026 $ 590,132 $ 674,542 $ 588,838 $ 685,945 7.50 % Senior Notes – due May 2022 $ — $ — $ 6,060 $ 6,145 Bank Credit Facility – matures November 2024 $ ( 4,792 ) $ — $ 367,829 $ 375,000
Schedule of Impact that Derivatives not Qualifying as Hedging Instruments in Condensed Consolidated Statements of Operations	The following table presents the impact that derivatives, not designated as hedging instruments, had on its Consolidated Statements of Operations (in thousands): Year Ended December 31, 2022 2021 2020 Net cash received (paid) on settled derivative instruments $ ( 425,559 ) $ ( 290,164 ) $ 143,905 Unrealized gain (loss) 153,368 ( 128,913 ) ( 56,220 ) Price risk management activities income (expense) $ ( 272,191 ) $ ( 419,077 ) $ 87,685
Schedule of Contracted Volumes and Weighted Average Prices and will Receive Under the Terms of Derivative Contracts	The following tables reflect the contracted volumes and weighted average prices under the terms of the Company's derivative contracts as of December 31, 2022: Swap Contracts Production Period Settlement Index Average Daily Weighted Average Crude oil: (Bbls) (per Bbl) January 2023 – December 2023 NYMEX WTI CMA 17,863 $ 72.46 January 2024 – December 2024 NYMEX WTI CMA 5,240 $ 73.95 Natural gas: (MMBtu) (per MMBtu) January 2023 – December 2023 NYMEX Henry Hub 26,395 $ 3.76 January 2024 – June 2024 NYMEX Henry Hub 10,000 $ 3.25 Collar Contracts Production Period Settlement Index Average Weighted Weighted Crude oil: (Bbls) (per Bbl) (per Bbl) January 2023 – December 2023 NYMEX WTI CMA 2,512 $ 70.00 $ 86.59 January 2024 – March 2024 NYMEX WTI CMA 2,000 $ 70.00 $ 88.00 Natural gas: (MMBtu) (per MMBtu) (per MMBtu) January 2023 – December 2023 NYMEX Henry Hub 10,000 $ 5.25 $ 8.46 January 2024 – December 2024 NYMEX Henry Hub 10,000 $ 4.00 $ 6.90
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, 2022 Level 1 Level 2 Level 3 Total Assets: Oil and natural gas derivatives $ — $ 32,883 $ — $ 32,883 Liabilities: Oil and natural gas derivatives — ( 76,242 ) — ( 76,242 ) Total net liability $ — $ ( 43,359 ) $ — $ ( 43,359 ) December 31, 2021 Level 1 Level 2 Level 3 Total Assets: Oil and natural gas derivatives $ — $ 3,737 $ — $ 3,737 Liabilities: Oil and natural gas derivatives — ( 200,464 ) — ( 200,464 ) Total net liability $ — $ ( 196,727 ) $ — $ ( 196,727 )
Schedule of Fair Value of Derivative Financial Instruments	The following table presents the fair value of derivative financial instruments as well as the potential effect of netting arrangements on the Company's recognized derivative asset and liability amounts (in thousands): December 31, 2022 December 31, 2021 Assets Liabilities Assets Liabilities Oil and natural gas derivatives: Current $ 25,029 $ 68,370 $ 967 $ 186,526 Non-current 7,854 7,872 2,770 13,938 Total gross amounts presented on balance sheet 32,883 76,242 3,737 200,464 Less: Gross amounts not offset on the balance sheet 32,883 32,883 3,737 3,737 Net amounts $ — $ 43,359 $ — $ 196,727

Debt (Tables)

Debt (Tables)	12 Months Ended
	Dec. 31, 2022
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, 2022 2021 12.00 % Second-Priority Senior Secured Notes – due January 2026 $ 638,541 $ 650,000 7.50 % Senior Notes – due May 2022 — 6,060 Bank Credit Facility – matures November 2024 — 375,000 Total debt, before discount and deferred financing cost 638,541 1,031,060 Discount and deferred financing cost ( 53,201 ) ( 68,333 ) Total debt, net of discount and deferred financing costs 585,340 962,727 Less: Current portion of long-term debt — 6,060 Long-term debt, net of discount and deferred financing costs $ 585,340 $ 956,667
Summary of Redemption Prices of 12.% Notes	Thereafter, the Company may redeem all or a portion of the 12.00% Notes in whole at any time or in part from time to time at the following redemption prices (expressed as percentages of principal amount) plus accrued and unpaid interest if redeemed during the period commencing on January 15 of the years set forth below Period Redemption Price 2023 106.00 % 2024 103.00 % 2025 and thereafter 100.00 %
Schedule of Pricing Grid for Borrowing Base Utilization Percentage	The pricing grid below shows the applicable margin for Term Benchmark Loans, RFR Loans and ABR Loans as well as the commitment fee rate, in each case, prior to closing of the EnVen Acquisition, based upon the applicable borrowing base utilization percentage: Borrowing Base Utilization Percentage Utilization Term Benchmark Loans and RFR Loans ABR Loans Commitment Level 1 < 25 % 3.00 % 2.00 % 0.50 % Level 2 ≥ 25 % < 50 % 3.25 % 2.25 % 0.50 % Level 3 ≥ 50 % < 75 % 3.50 % 2.50 % 0.50 % Level 4 ≥ 75 % < 90 % 3.75 % 2.75 % 0.50 % Level 5 ≥ 90 % 4.00 % 3.00 % 0.50 % The Ninth Amendment provides that the above applicable margins for Term Benchmark Loans, RFR Loans and ABR Loans, each decrease by an amount equal to 0.25 % from and after the closing of the EnVen Acquisition. The commitment fee rate also decreases to 0.375 % from and after the closing of the EnVen Acquisition when the borrowing base utilization percentage is less than 50 %.

Employee Benefits Plans and S_2

Employee Benefits Plans and Share-Based Compensation (Tables)	12 Months Ended
	Dec. 31, 2022
Share-Based Payment Arrangement [Abstract]
Summary of Restricted Stock Units Activity	The following table summarizes RSU activity: Restricted Stock Weighted Average Unvested RSUs at December 31, 2019 733,777 $ 25.20 Granted 1,284,797 $ 10.02 Vested ( 273,787 ) $ 25.09 Forfeited ( 91,799 ) $ 19.65 Unvested RSUs at December 31, 2020 1,652,988 $ 13.73 Granted 1,102,038 $ 13.11 Vested ( 669,832 ) $ 15.01 Forfeited ( 101,995 ) $ 12.46 Unvested RSUs at December 31, 2021 1,983,199 $ 13.02 Granted 2,297,465 $ 13.23 Vested ( 967,269 ) $ 14.14 Forfeited ( 97,891 ) $ 14.34 Unvested RSUs at December 31, 2022 (1) 3,215,504 $ 12.79 As of December 31, 2022 , 25,257 of the unvested RSUs were accounted for as liability awards in “Accrued liabilities” on the Consolidated Balance Sheet.
Summary of Performance Share Units Activity	The following table summarizes PSU activity: Performance Weighted Average Unvested PSUs at December 31, 2019 417,831 $ 39.31 Granted 441,642 $ 13.05 Forfeited ( 25,301 ) $ 37.67 Unvested PSUs at December 31, 2020 834,172 $ 25.46 Granted 586,995 $ 18.96 Vested ( 391,308 ) $ 39.43 Forfeited ( 14,400 ) $ 18.48 Unvested PSUs at December 31, 2021 1,015,459 $ 16.41 Granted (1) 629,666 $ 23.73 Vested (2) ( 14,474 ) $ 13.05 Forfeited ( 16,486 ) $ 17.48 Cancelled ( 975,564 ) $ 16.42 Unvested PSUs at December 31, 2022 638,601 $ 23.66 (1) There were 314,833 PSUs granted that are eligible to vest based on continued employment and the Company’s annualized absolute total shareholder return (“TSR”) over a three-year performance period. An additional 314,833 PSUs were granted and are eligible to vest based on continued employment and the Company’s return on the wells included in the 2022 drill program over a three-year performance period. (2) The performance period for the relative TSR awards ended on December 31, 2022. The payout on these awards was 0 % based on actual performance over the performance period as certified by the Compensation Committee of the Company’s Board of Directors in early 2023. Since these awards were legally forfeited they will again be available for new awards under the recycling provisions of the 2021 LTIP.
Summary of Assumptions Used to Calculate the Grant Date Fair Value of TSR PSUs Granted	The following table summarizes the assumptions used in the Monte Carlo simulations to calculate the fair value of the relative or absolute TSR PSUs granted and modified at the date indicated: 2022 2021 2020 Grant Grant Modification Grant Grant September 20 March 5 May 11 March 8 March 5 Expected term (in years) 2.3 2.8 2.6 2.8 2.8 Expected volatility 74.3 % 82.2 % 80.9 % 78.3 % 48.8 % Risk-free interest rate 3.9 % 1.6 % 0.3 % 0.3 % 0.6 % Dividend yield — % — % — % — % — % Fair value (in thousands) $ 621 $ 8,668 $ 9,715 $ 11,129 $ 5,763
Schedule of Recognized Share Based Compensation Expense, Net	The following table presents the amount of costs expensed and capitalized (in thousands): Year Ended December 31, 2022 2021 2020 Share-based compensation costs $ 28,280 $ 20,560 $ 16,462 Less: Amounts capitalized to oil and gas properties 12,327 9,568 7,793 Total share-based compensation expense $ 15,953 $ 10,992 $ 8,669

Income Taxes (Tables)

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2022
Income Tax Disclosure [Abstract]
Components of Income Tax Expense (Benefit)	The components of income tax expense (benefit) were as follows (in thousands): Year Ended December 31, 2022 2021 2020 Current income tax expense (benefit): United States $ 1,375 $ ( 5 ) $ ( 499 ) Mexico 432 ( 993 ) 185 Total current income tax expense (benefit) $ 1,807 $ ( 998 ) $ ( 314 ) Deferred income tax expense (benefit): United States $ 659 $ ( 1,067 ) $ 35,923 Mexico 71 430 ( 26 ) Total deferred income tax expense (benefit) $ 730 $ ( 637 ) $ 35,897 Total income tax expense (benefit) $ 2,537 $ ( 1,635 ) $ 35,583
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, 2022 2021 2020 Income tax expense (benefit) at the federal statutory tax rate $ 80,735 $ ( 38,763 ) $ ( 90,304 ) State income taxes 1,591 ( 674 ) ( 14,215 ) Impact of foreign operations 15,657 ( 11,920 ) ( 1,030 ) Effect of change in state rate — 2,008 — Prior year taxes ( 2,920 ) 486 ( 4,237 ) Legal entity reorganization — — ( 17,566 ) Change in valuation allowance ( 96,537 ) 45,547 162,213 Other permanent differences 4,011 1,681 722 Total income tax expense (benefit) $ 2,537 $ ( 1,635 ) $ 35,583 Effective tax rate 0.66 % 0.89 % ( 8.27 )%
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, 2022 2021 Deferred tax assets: Federal net operating loss $ 159,257 $ 153,849 Foreign tax loss carryforward 44,462 49,932 State net operating loss 24,787 24,265 Tax credits 107 303 Interest expense carryforward 23,262 — Asset retirement obligations 115,848 92,823 Derivatives 9,273 42,075 Other well equipment inventory 1,891 5,680 Accrued bonus 5,863 5,087 Share-based compensation 5,296 3,833 Operating lease liabilities 3,669 4,081 Finance lease liabilities 32,559 — Other 7,142 5,424 Total deferred tax assets 433,416 387,352 Valuation allowance ( 129,105 ) ( 224,266 ) Total deferred tax assets, net $ 304,311 $ 163,086 Deferred tax liabilities: Oil and gas properties $ 302,602 $ 160,002 Operating lease assets 1,323 1,423 Prepaid 2,530 3,075 Total deferred tax liabilities 306,455 164,500 Net deferred tax liability $ ( 2,144 ) $ ( 1,414 )
Summary of Net Operating Loss Carryovers	The table below presents the details of the Company’s net operating loss carryovers as of December 31, 2022 (in thousands): Amount Expiration Year Federal net operating losses $ 525,745 2035 - 2037 Federal net operating losses $ 232,620 Unlimited Foreign tax loss carryforward $ 148,206 2025 - 2032 State net operating losses $ 125,958 2025 - 2037 State net operating losses $ 277,031 Unlimited
Summary of Balances In Uncertain Tax Positions	Balances in the uncertain tax positions are as follows (in thousands): Year Ended December 31, 2022 2021 Total unrecognized tax benefits, beginning balance $ 696 $ 648 Increases in unrecognized tax benefits as a result of: Tax positions taken during a prior period 100 21 Tax positions taken during the current period 39 27 Total unrecognized tax benefits, ending balance $ 835 $ 696

Income (Loss) Per Share (Tables

Income (Loss) Per Share (Tables)	12 Months Ended
	Dec. 31, 2022
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, 2022 2021 2020 Net income (loss) $ 381,915 $ ( 182,952 ) $ ( 465,605 ) Weighted average common shares outstanding — basic 82,454 81,769 67,664 Dilutive effect of securities 1,229 — — Weighted average common shares outstanding — diluted 83,683 81,769 67,664 Net income (loss) per common share: Basic $ 4.63 $ ( 2.24 ) $ ( 6.88 ) Diluted $ 4.56 $ ( 2.24 ) $ ( 6.88 ) Anti-dilutive potentially issuable securities excluded from diluted common shares 865 1,709 5,019

Commitments and Contingencies (

Commitments and Contingencies (Tables)	12 Months Ended
	Dec. 31, 2022
Commitments and Contingencies Disclosure [Abstract]
Summary of Total Minimum Commitments	The table below summarizes the Company’s total minimum commitments associated with vessel commitments, purchase obligations and other miscellaneous commitments as of December 31, 2022 (in thousands): 2023 2024 2025 2026 Thereafter Total Vessel Commitments (1) $ 41,938 $ — $ — $ — $ — $ 41,938 Committed purchase orders (2) 41,148 — — — — 41,148 EnVen Acquisition (3) 259,858 — — — — 259,858 Other commitments (4) 9,627 327 327 — — 10,281 Total $ 352,571 $ 327 $ 327 $ — $ — $ 353,225 (1) Includes vessel commitments the Company will utilize for certain Deepwater well intervention, drilling operations and decommissioning activities. These commitments represent gross contractual obligations and accordingly, other joint owners in the properties operated by the Company will be billed for their working interest share of such costs. (2) Includes committed purchase orders to execute planned future drilling activities. These commitments represent gross contractual obligations and accordingly, other joint owners in the properties operated by the Company will be billed for their working interest share of such costs. (3) Includes cash consideration and contingent fees related to the EnVen Acquisition. See Note 15 — Subsequent Events for further information on the EnVen Acquisition. (4) Includes commitment to acquire additional lease acreage associated with our CCS Segment.
Summary of Decommissioning Obligations Included in Consolidated Balance Sheets	The decommissioning obligations included in the Consolidated Balance Sheets as “Other current liabilities” and “Other long-term liabilities”, and the changes in that liability were as follows (in thousands): Year Ended December 31, 2022 2021 2020 Balance, beginning of period $ 24,336 $ — $ — Additions 8,900 21,056 — Changes in estimate 22,658 — — Reimbursements due from third parties — 3,280 — Settlements ( 1,625 ) — — Balance, end of period $ 54,269 $ 24,336 $ — Less: Current portion 42,069 3,756 — Long-term portion $ 12,200 $ 20,580 $ —

Segment Information (Tables)

Segment Information (Tables)	12 Months Ended
	Dec. 31, 2022
Segment Reporting [Abstract]
Summary of Information by Business Segment	The following table presents selected segment information for the periods indicated (in thousands): Upstream All Other (1) Total Revenues from External Customers: Year Ended December 31, 2022 $ 1,651,980 $ — $ 1,651,980 Year Ended December 31, 2021 1,244,540 — 1,244,540 Year Ended December 31, 2020 575,936 — 575,936 Equity in the Net Income of Investees Accounted for by the Equity Method: Year Ended December 31, 2022 $ 101 $ ( 1,166 ) $ ( 1,065 ) Year Ended December 31, 2021 — — — Year Ended December 31, 2020 — — — Adjusted EBITDA: Year Ended December 31, 2022 $ 859,840 $ ( 12,786 ) $ 847,054 Year Ended December 31, 2021 $ 615,798 $ ( 4,782 ) 611,016 Year Ended December 31, 2020 435,327 — 435,327 Segment Expenditures: Year Ended December 31, 2022 $ 452,674 $ 2,778 $ 455,452 Year Ended December 31, 2021 338,822 — 338,822 Year Ended December 31, 2020 405,525 — 405,525 (1) The CCS Segment is included in the “All Other” category. The CCS Segment is an emerging business in the start-up phase of operations and the business that does not currently generate any revenues. The CCS Segment’s business activities are conducted through both wholly owned subsidiaries and equity method investments with industry partners. Equity method investments is a business strategy that enables us to achieve favorable economies of scale relative to the level of investment and business risk assumed.
Schedule of Reconciliation of Reportable Segment Information to the Company's Consolidated Totals	The following tables present reconciliations of reportable segment information to the Company’s consolidated totals (in thousands): Year Ended December 31, 2022 2021 2020 Adjusted EBITDA: Total for reportable segments $ 859,840 $ 615,798 $ 435,327 All other ( 12,786 ) ( 4,782 ) — Unallocated corporate general and administrative expense ( 5,280 ) ( 4,542 ) ( 5,088 ) Interest expense ( 125,498 ) ( 133,138 ) ( 99,415 ) Depreciation, depletion and amortization ( 414,630 ) ( 395,994 ) ( 364,346 ) Accretion expense ( 55,995 ) ( 58,129 ) ( 49,741 ) Write-down of oil and natural gas properties — ( 18,123 ) ( 267,916 ) Transaction and other (income) expenses (1) 34,513 ( 5,886 ) ( 14,917 ) Decommissioning obligations (2) ( 31,558 ) ( 21,055 ) — Derivative fair value loss (gain) (3) ( 272,191 ) ( 419,077 ) 87,685 Net cash paid on settled derivative instruments (3) 425,559 290,164 ( 143,905 ) Gain (loss) on extinguishment of debt ( 1,569 ) ( 13,225 ) 1,662 Non-cash write-down of other well equipment inventory — ( 5,606 ) ( 699 ) Non-cash equity-based compensation expense ( 15,953 ) ( 10,992 ) ( 8,669 ) Income (loss) before income taxes $ 384,452 $ ( 184,587 ) $ ( 430,022 ) (1) Other income (expense) includes restructuring expenses, cost saving initiatives and other miscellaneous income and expenses that we do not view as a meaningful indicator of our operating performance. For the year ended December 31, 2022 , the amount includes $ 27.5 million gain as a result of the settlement agreement to resolve previously pending litigation that was filed in October 2017 that is further discussed in Note 12 — Commitments and Contingencies. Additionally, it includes a $ 15.3 million gain for the year ended December 31, 2022 on partial sale of our investment in Bayou Bend that is further discussed in Note 11 — Related Party Transactions . For the year ended December 31, 2020, the amount includes $ 1.4 million of legal entity restructuring costs and $ 1.3 million of severance related cost saving initiatives due to the COVID-19 pandemic. (2) Estimated decommissioning obligations were a result of working interest partners or counterparties of divestiture transactions that were unable to perform the required abandonment obligations due to bankruptcy or insolvency. See Note 12 — Commitments and Contingencies for additional information on decommissioning obligations. (3) The adjustments for the derivative fair value (gains) losses and net cash receipts (payments) on settled commodity derivative instruments have the effect of adjusting net loss for changes in the fair value of derivative instruments, which are recognized at the end of each accounting period because we do not designate commodity derivative instruments as accounting hedges. This results in reflecting commodity derivative gains and losses within Adjusted EBITDA on an unrealized basis during the period the derivatives settled.
Reconciliation of Reportable Segment Expenditures	Year Ended December 31, 2022 2021 2020 Segment Expenditures: Total reportable segments $ 452,674 $ 338,822 $ 405,525 All other 2,778 — — Change in capital expenditures included in accounts payable and accrued liabilities ( 60,011 ) 28,258 16,002 Plugging & abandonment ( 69,596 ) ( 67,988 ) ( 43,933 ) Decommissioning obligations settled ( 1,625 ) — — Investment in CCS intangibles and equity method investees ( 2,778 ) — — Other deferred payments — ( 7,921 ) ( 11,921 ) Non-cash well equipment inventory transfers ( 6 ) 1,086 ( 3,030 ) Other 1,728 1,074 299 Exploration, development and other capital expenditures $ 323,164 $ 293,331 $ 362,942

Supplemental Oil and Gas Disc_2

Supplemental Oil and Gas Disclosures (Unaudited) (Tables)	12 Months Ended
	Dec. 31, 2022
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, 2022 2021 2020 Proved properties $ 5,964,340 $ 5,232,479 $ 4,945,550 Unproved oil and gas properties, not subject to amortization (1) 154,783 219,055 254,994 Total oil and gas properties 6,119,123 5,451,534 5,200,544 Less: Accumulated depletion 3,484,590 3,072,907 2,680,254 Net capitalized costs $ 2,634,533 $ 2,378,627 $ 2,520,290 Depletion and amortization rate (Per MBoe) (2) $ 18.95 $ 16.71 $ 31.42 (1) Amount includes $ 111.4 million, $ 110.3 million and $ 121.7 million of unproved properties, not subject to amortization, related to the Company’s operations in offshore Mexico for the years ended December 31, 2022, 2021 and 2020, respectively. (2) Year ended December 31, 2020 includes the impact of a write-down of U.S. oil and natural gas properties as a result of the Company’s ceiling test computations. See Note 4 — Property, Plant and Equipment for additional information.
Schedule of Costs Incurred in Oil, Natural Gas and NGL Property Acquisition, Exploration and Development Activities	The following table reflects the costs incurred in oil, natural gas and NGL property acquisition, exploration and development activities during the years indicated (in thousands). Costs incurred also include new asset retirement obligations established in the current year, as well as increases or decreases to the asset retirement obligations resulting from changes to estimates during the year. Year Ended December 31, 2022 2021 2020 Property acquisition costs: Proved properties $ — $ 210 $ 422,833 Unproved properties, not subject to amortization 2,221 — 95,242 Total property acquisition costs 2,221 210 518,075 Exploration costs (1) 125,889 23,844 59,422 Development costs 541,512 245,058 362,011 Total costs incurred $ 669,622 $ 269,112 $ 939,508 (1) Amount includes $ 1.2 million, $ 6.6 million and $ 14.6 million of exploration costs related to the Company’s operations in offshore Mexico for the years ended December 31, 2022, 2021 and 2020 , respectively.
Schedule of Estimated Proved Reserves at Net Ownership Interest	The following table presents the Company’s estimated proved reserves at its net ownership interest: Oil (MBbls) Gas (MMcf) NGL (MBbls) Oil Total proved reserves at December 31, 2019 106,754 155,998 8,981 141,735 Revision of previous estimates ( 14,633 ) ( 56,358 ) ( 168 ) ( 24,195 ) Production (1) ( 13,665 ) ( 28,652 ) ( 1,559 ) ( 19,999 ) Purchases of reserves 26,903 181,872 3,528 60,743 Extensions and discoveries 3,948 4,348 76 4,749 Total proved reserves at December 31, 2020 109,307 257,208 10,858 163,033 Revision of previous estimates 13,619 8,979 5,137 20,252 Production ( 16,159 ) ( 32,795 ) ( 1,875 ) ( 23,500 ) Extensions and discoveries 997 2,961 315 1,806 Total proved reserves at December 31, 2021 107,764 236,353 14,435 161,591 Revision of previous estimates ( 5,625 ) ( 8,302 ) ( 2,002 ) ( 9,010 ) Production ( 14,561 ) ( 32,215 ) ( 1,793 ) ( 21,723 ) Sales of reserves ( 158 ) ( 7,625 ) — ( 1,429 ) Extensions and discoveries 3,639 31,340 2,288 11,150 Total proved reserves at December 31, 2022 91,059 219,551 12,928 140,579 Total proved developed reserves as of: December 31, 2020 85,007 204,054 8,104 127,120 December 31, 2021 93,420 186,442 11,792 136,286 December 31, 2022 80,285 161,727 9,315 116,555 Total proved undeveloped reserves as of: December 31, 2020 24,300 53,154 2,754 35,913 December 31, 2021 14,344 49,911 2,643 25,305 December 31, 2022 10,774 57,824 3,613 24,024 (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, 2022 2021 2020 Future cash inflows $ 10,674,896 $ 8,496,005 $ 4,927,497 Future costs: Production ( 1,906,752 ) ( 1,868,818 ) ( 1,105,211 ) Development and abandonment ( 1,873,453 ) ( 1,422,507 ) ( 1,236,874 ) Future net cash flows before income taxes 6,894,691 5,204,680 2,585,412 Future income tax expense ( 1,114,409 ) ( 676,778 ) ( 141,515 ) Future net cash flows after income taxes 5,780,282 4,527,902 2,443,897 Discount at 10% annual rate ( 1,411,834 ) ( 1,087,291 ) ( 538,963 ) Standardized measure of discounted future net cash flows $ 4,368,448 $ 3,440,611 $ 1,904,934
Schedule of Base Prices Used in Determining Standardized Measure	Future cash inflows are computed by applying SEC Pricing to year-end quantities of proved reserves. The discounted future cash flow estimates do not include the effects of derivative instruments. See the following table for SEC Pricing used in determining the standardized measure: Year Ended December 31, 2022 2021 2020 Oil price per Bbl $ 96.03 $ 67.14 $ 39.47 Natural gas price per Mcf $ 6.80 $ 3.71 $ 1.97 NGL price per Bbl $ 33.89 $ 26.62 $ 9.89
Schedule of Principal Changes in Standardized Measure of Discounted Future Net Cash Flows	Principal changes in the standardized measure of discounted future net cash flows attributable to the Company’s proved oil, natural gas and NGL reserves are as follows (in thousands): Year Ended December 31, 2022 2021 2020 Standardized measure, beginning of year $ 3,440,611 $ 1,904,934 $ 2,537,595 Sales and transfers of oil, net gas and NGLs produced during the period ( 1,340,400 ) ( 957,576 ) ( 339,557 ) Net change in prices and production costs 2,388,442 2,049,980 ( 1,468,304 ) Changes in estimated future development and abandonment costs ( 84,391 ) ( 57,876 ) 32,589 Previously estimated development and abandonment costs incurred 20,107 69,125 46,143 Accretion of discount 392,600 199,849 299,302 Net change in income taxes ( 327,265 ) ( 391,834 ) 361,875 Purchases of reserves — — 730,611 Sales of reserves ( 5,218 ) — — Extensions and discoveries 202,239 45,485 71,589 Net change due to revision in quantity estimates ( 255,743 ) 426,357 ( 309,338 ) Changes in production rates (timing) and other ( 62,534 ) 152,167 ( 57,571 ) Standardized measure, end of year $ 4,368,448 $ 3,440,611 $ 1,904,934

Organization, Nature of Busin_2

Organization, Nature of Business and Basis of Presentation - Additional Information (Details)	12 Months Ended
	Dec. 31, 2022 Segment
Basis Of Presentation And Schedule Of Accounting Policy [Line Items]
Number of Operating Segments	2
Entity Incorporation, Date of Incorporation	Nov. 14, 2017
Stone Energy Corporation
Basis Of Presentation And Schedule Of Accounting Policy [Line Items]
Business Acquisition, Effective Date of Acquisition	May 10, 2018
Talos Energy LLC
Basis Of Presentation And Schedule Of Accounting Policy [Line Items]
Organization commenced commercial operations	Feb. 06, 2013

Summary of Significant Accoun_4

Summary of Significant Accounting Policies - Additional Information (Details) - USD ($)	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Summary Of Significant Accounting Policies [Line Items]
Allowance for expected credit losses	$ 10,700,000	$ 15,100,000
Impairment charges	0	0	$ 0
Intangible assets	1,400,000	0
Receivable
Summary Of Significant Accounting Policies [Line Items]
Gas Balancing Asset (Liability)	1,700,000	1,700,000
Payable
Summary Of Significant Accounting Policies [Line Items]
Gas Balancing Asset (Liability)	2,500,000	2,500,000
Other operating (income) expense
Summary Of Significant Accounting Policies [Line Items]
Multi-year federal royalty refund claim	600,000	0	8,900,000
Impairment to adjust other well equipment inventory	0	5,600,000	$ 700,000
MEXICO
Summary Of Significant Accounting Policies [Line Items]
Value added tax receivable, Noncurrent	3,200,000	10,000,000
Value added tax receivable, Current	$ 1,700,000	$ 3,900,000
Minimum
Summary Of Significant Accounting Policies [Line Items]
Other property and equipment, estimated useful lives	3 years
Minimum | Performance Share Unit
Summary Of Significant Accounting Policies [Line Items]
Number of common stock issuable upon vesting, percentage range of PSUs granted	0%
Minimum | Performance Shares
Summary Of Significant Accounting Policies [Line Items]
Number of common stock issuable upon vesting, percentage range of PSUs granted	0%
Maximum
Summary Of Significant Accounting Policies [Line Items]
Other property and equipment, estimated useful lives	10 years
Maximum | Performance Share Unit
Summary Of Significant Accounting Policies [Line Items]
Number of common stock issuable upon vesting, percentage range of PSUs granted	200%
Maximum | Performance Shares
Summary Of Significant Accounting Policies [Line Items]
Number of common stock issuable upon vesting, percentage range of PSUs granted	200%
Measurement Input Discount Rate
Summary Of Significant Accounting Policies [Line Items]
Present value of future net revenues from proved reserves, discount rate	10%
Limited Partnership or Limited Liability Company Type Investment | Minimum
Summary Of Significant Accounting Policies [Line Items]
Equity Method Investment, Ownership Percentage	3%
Limited Partnership or Limited Liability Company Type Investment | Maximum
Summary Of Significant Accounting Policies [Line Items]
Equity Method Investment, Ownership Percentage	50%
Other Investment type | Minimum
Summary Of Significant Accounting Policies [Line Items]
Equity Method Investment, Ownership Percentage	20%
Other Investment type | Maximum
Summary Of Significant Accounting Policies [Line Items]
Equity Method Investment, Ownership Percentage	50%

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, 2022	Dec. 31, 2021	Dec. 31, 2020
Shell Trading (US) Company
Concentration Risk [Line Items]
Concentration risk, percentage	44%	45%	47%
Valero energy corporation
Concentration Risk [Line Items]
Concentration risk, percentage	23%
Chevron Products Company
Concentration Risk [Line Items]
Concentration risk, percentage	11%	29%	12%
Phillips 66
Concentration Risk [Line Items]
Concentration risk, percentage			22%

Summary of Significant Accoun_6

Summary of Significant Accounting Policies - Schedule of Percent of Consolidated Revenue of Major Customers, Those Whose Total Represented 10% or More of Oil, Natural Gas and NGL Revenues (Parenthetical) (Details) - Sales Revenue - Customer Concentration Risk	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Valero energy corporation
Concentration Risk [Line Items]
Concentration risk, percentage	23%
Valero energy corporation | Maximum
Concentration Risk [Line Items]
Concentration risk, percentage		10%	10%
Phillips 66
Concentration Risk [Line Items]
Concentration risk, percentage			22%
Phillips 66 | Maximum
Concentration Risk [Line Items]
Concentration risk, percentage	10%	10%

Acquisitions - Asset Acquisitio

Acquisitions - Asset Acquisitions - Additional Information (Details) - USD ($) shares in Millions, $ in Millions	Nov. 16, 2020	Aug. 05, 2020
LLOG Acquisition
Business Acquisition [Line Items]
Effective date of asset acquisition	Nov. 16, 2020
Asset acquisition, date of acquisition agreement	Nov. 16, 2020
Asset Acquisition, Consideration Transferred	$ 13.2
Acquisition, transaction related cost	$ 0.2
Castex 2005 Acquisition
Business Acquisition [Line Items]
Effective date of asset acquisition		Aug. 05, 2020
Asset acquisition, date of acquisition agreement		Jun. 19, 2020
Aggregate consideration of cash		$ 6.5
Aggregate shares issued		4.6
Acquisition, transaction related cost		$ 1.4
Castex 2005 Acquisition | Common Stock
Business Acquisition [Line Items]
Common stock value		$ 35.4

Acquisitions - Business Combina

Acquisitions - Business Combination - Additional Information (Details) - USD ($) $ in Millions							3 Months Ended	12 Months Ended
	Feb. 13, 2023	Sep. 21, 2022	Mar. 30, 2020	Feb. 28, 2020	Feb. 28, 2020	Jul. 01, 2019	Mar. 31, 2020	Dec. 31, 2022	Dec. 31, 2020
Series A Convertible Preferred Stock
Business Acquisition [Line Items]
Conversion stock issued to sellers							11,000,000
ILX and Castex
Business Acquisition [Line Items]
Business acquisition, effective date				Feb. 28, 2020	Feb. 28, 2020
Business acquisition acquisition agreement effective date						Jul. 01, 2019
Cash consideration				$ 303.1
Conversion Stock value				$ 156.2
ILX and Castex | Series A Convertible Preferred Stock
Business Acquisition [Line Items]
Aggregate shares issued			110,000	110,000
ILX and Castex | Contingent Convertible Preferred Stock
Business Acquisition [Line Items]
Conversion stock issued to sellers			11,000,000
ILX and Castex | General and Administrative Expense
Business Acquisition [Line Items]
Cumulative transaction related costs									$ 12.1
Acquisition, transaction related cost									$ 8.7
EnVen Energy Corporation
Business Acquisition [Line Items]
Business Acquisition, Date of Acquisition Agreement		Sep. 21, 2022
EnVen Energy Corporation | Subsequent Event
Business Acquisition [Line Items]
Business acquisition, effective date	Feb. 13, 2023
Business Combination, Provisional Information, Initial Accounting Incomplete, Reasons	Due to the timing of the EnVen Acquisition, the Company is unable to estimate the purchase price allocation of such acquisition at this time.
Cash consideration	$ 207.3
Common stock value	$ 832.2
EnVen Energy Corporation | General and Administrative Expense
Business Acquisition [Line Items]
Acquisition, transaction related cost								$ 9
EnVen Energy Corporation | Common Stock | Subsequent Event
Business Acquisition [Line Items]
Aggregate shares issued	43,800,000

Acquisitions - Business Combi_2

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

Acquisitions - Business Combi_3

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

Property, Plant and Equipment -

Property, Plant and Equipment - Additional Information (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2022 USD ($) $ / bbl $ / Mcf	Dec. 31, 2021 USD ($) $ / bbl $ / Mcf	Dec. 31, 2020 USD ($) $ / bbl $ / Mcf
Property, Plant and Equipment [Line Items]
Write-down of oil and natural gas properties | $	$ 0	$ 18,123	$ 267,916
Zama prospect
Property, Plant and Equipment [Line Items]
Anticipated timing of inclusion of costs in amortization calculation	The $111.4 million of capitalized exploration cost in Mexico relates to the Zama Field Development Plan for submission to the Mexican regulator for final approval. The Company expects to transfer the cost into the amortization base by 2024.
Oil (MBbls)
Property, Plant and Equipment [Line Items]
SEC pricing | $ / bbl	96.03	67.14	39.47
Gas (MMcf)
Property, Plant and Equipment [Line Items]
SEC pricing | $ / Mcf	6.80	3.71	1.97
NGL (MBbls)
Property, Plant and Equipment [Line Items]
SEC pricing | $ / bbl	33.89	26.62	9.89
US
Property, Plant and Equipment [Line Items]
Write-down of oil and natural gas properties | $	$ 0	$ 0	$ 267,900
US | Oil (MBbls)
Property, Plant and Equipment [Line Items]
SEC pricing | $ / bbl	96.03
US | Gas (MMcf)
Property, Plant and Equipment [Line Items]
SEC pricing | $ / Mcf	6.80
US | NGL (MBbls)
Property, Plant and Equipment [Line Items]
SEC pricing | $ / bbl	33.89
Mexico
Property, Plant and Equipment [Line Items]
Write-down of oil and natural gas properties | $	$ 0	$ 18,100	$ 100
Mexico | Zama prospect
Property, Plant and Equipment [Line Items]
Capitalized exploration costs | $	$ 111,400

Property, Plant and Equipment_2

Property, Plant and Equipment - Summary of Oil and Natural Gas Property Costs Not Being Amortized (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Capitalized Costs Of Unproved Properties Excluded From Amortization [Line Items]
Total unproved properties, not subject to amortization	$ 154,783	$ 219,055	$ 254,994
United States
Capitalized Costs Of Unproved Properties Excluded From Amortization [Line Items]
Acquisition	29,646
Exploration	13,707
Mexico
Capitalized Costs Of Unproved Properties Excluded From Amortization [Line Items]
Exploration	111,430
Total unproved properties, not subject to amortization	111,400	110,300	121,700
2022
Capitalized Costs Of Unproved Properties Excluded From Amortization [Line Items]
Total unproved properties, not subject to amortization	6,087
2022 | United States
Capitalized Costs Of Unproved Properties Excluded From Amortization [Line Items]
Acquisition	2,221
Exploration	2,696
2022 | Mexico
Capitalized Costs Of Unproved Properties Excluded From Amortization [Line Items]
Exploration	$ 1,170
2021
Capitalized Costs Of Unproved Properties Excluded From Amortization [Line Items]
Total unproved properties, not subject to amortization		8,187
2021 | United States
Capitalized Costs Of Unproved Properties Excluded From Amortization [Line Items]
Acquisition		0
Exploration		4,727
2021 | Mexico
Capitalized Costs Of Unproved Properties Excluded From Amortization [Line Items]
Exploration		$ 3,460
2020
Capitalized Costs Of Unproved Properties Excluded From Amortization [Line Items]
Total unproved properties, not subject to amortization			42,928
2020 | United States
Capitalized Costs Of Unproved Properties Excluded From Amortization [Line Items]
Acquisition			27,322
Exploration			1,753
2020 | Mexico
Capitalized Costs Of Unproved Properties Excluded From Amortization [Line Items]
Exploration			$ 13,853
2019 and Prior
Capitalized Costs Of Unproved Properties Excluded From Amortization [Line Items]
Total unproved properties, not subject to amortization				$ 97,581
2019 and Prior | United States
Capitalized Costs Of Unproved Properties Excluded From Amortization [Line Items]
Acquisition				103
Exploration				4,531
2019 and Prior | Mexico
Capitalized Costs Of Unproved Properties Excluded From Amortization [Line Items]
Exploration				$ 92,947

Property, Plant and Equipment_3

Property, Plant and Equipment - Schedule of Asset Retirement Obligations (Details) - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Oil and Gas Property [Abstract]
Balance, beginning of period		$ 434,006	$ 442,269
Obligations acquired		0	433
Obligations incurred		1,140	52
Obligations settled		(69,596)	(67,988)
Obligations divested		(1,572)	(340)
Accretion expense		55,995	58,129	$ 49,741
Changes in estimate	[1]	121,688	1,451
Balance, end of period		541,661	434,006	$ 442,269
Less: Current portion		39,888	60,311
Long-term portion		$ 501,773	$ 373,695
[1] Changes in estimate for the year ended December 31, 2022 were primarily due to an increase in estimated service costs.

Leases - Additional Information

Leases - Additional Information (Details) - USD ($) $ in Thousands	Dec. 31, 2022	Nov. 30, 2022	Dec. 31, 2021
Lease, Cost [Abstract]
Finance Lease, Liability, Statement of Financial Position [Extensible Enumeration]		Liabilities
Lease liability	$ 165,370	$ 166,300	$ 40,221

Leases - Components of Lease Co

Leases - Components of Lease Costs (Details) - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Lease, Cost [Abstract]
Finance lease cost - interest on lease liabilities		$ 7,558	$ 11,453	$ 15,748
Operating lease cost, excluding short-term leases	[1]	2,281	2,706	3,361
Short-term lease cost	[2]	55,072	38,472	53,573
Variable lease cost	[3]	1,450	1,356	543
Total lease cost		$ 66,361	$ 53,987	$ 73,225
[1] Operating lease cost reflect a single lease cost, calculated so that the cost of the lease is allocated over the lease term on a straight-line basis. Short-term lease costs are reported at gross amounts and primarily represent costs incurred for drilling rigs, most of which are short-term contracts not recognized as a ROU asset and lease liability on the Consolidated Balance Sheets. Variable lease costs primarily represent differences between minimum payment obligations and actual operating charges incurred by the Company related to its long-term leases.

Leases - Schedule of Right-of-U

Leases - Schedule of Right-of-Use Asset and Liability, Adjusted for Initial Direct Costs and Incentives (Details) - USD ($) $ in Thousands	Dec. 31, 2022	Nov. 30, 2022	Dec. 31, 2021
Operating leases:
Operating lease assets	$ 5,903		$ 5,714
Current portion of operating lease liabilities	$ 1,943		$ 1,715
Operating Lease, Liability, Current, Statement of Financial Position [Extensible List]	Current portion of operating lease liabilities		Current portion of operating lease liabilities
Operating lease liabilities	$ 14,855		$ 16,330
Total operating lease liabilities	16,798		18,045
Finance leases:
Proved property	$ 166,261		$ 124,299
Finance Lease, Right-of-Use Asset, Statement of Financial Position [Extensible Enumeration]	Other assets		Other assets
Other current liabilities	$ 16,306		$ 27,083
Finance Lease, Liability, Current, Statement of Financial Position [Extensible List]	Other current liabilities		Other current liabilities
Other long-term liabilities	$ 149,064		$ 13,138
Finance Lease, Liability, Noncurrent, Statement of Financial Position [Extensible List]	Other long-term liabilities		Other long-term liabilities
Total finance lease liabilities	$ 165,370	$ 166,300	$ 40,221

Leases - Schedule of Lease Matu

Leases - Schedule of Lease Maturity (Details) - USD ($) $ in Thousands	Dec. 31, 2022	Nov. 30, 2022	Dec. 31, 2021
Leases [Abstract]
Operating Leases, 2023	$ 3,774
Operating Leases, 2024	3,579
Operating Leases, 2025	3,645
Operating Leases, 2026	3,712
Operating Leases, 2027	3,596
Operating Leases, Thereafter	5,727
Operating Leases, Total lease payments	24,033
Operating Leases, Imputed interest	(7,235)
Total operating lease liabilities	16,798		$ 18,045
Finance Leases, 2023	30,782
Finance Leases, 2024	30,782
Finance Leases, 2025	30,782
Finance Leases, 2026	30,782
Finance Leases, 2027	30,782
Finance Leases, Thereafter	74,389
Finance Leases, Total lease payments	228,299
Finance Leases, Imputed interest	(62,929)
Finance Leases	$ 165,370	$ 166,300	$ 40,221

Leases - Schedule of Weighted A

Leases - Schedule of Weighted Average Remaining Lease Term and Discount Rate (Details)	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Weighted average remaining lease term:
Operating leases	6 years 4 months 24 days	7 years 4 months 24 days	7 years 9 months 18 days
Finance leases	7 years 4 months 24 days	1 year 4 months 24 days	2 years 4 months 24 days
Weighted average discount rate:
Operating leases	11.80%	11.90%	12%
Finance leases	9.20%	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, 2022	Dec. 31, 2021	Dec. 31, 2020
Lessee Cash Flow Information [Abstract]
Operating cash outflow from finance leases	$ 7,181	$ 11,453	$ 15,748
Operating cash outflow from operating leases	3,722	3,864	2,648
ROU assets obtained in exchange for new finance lease liabilities	166,261	0	0
ROU assets obtained in exchange for new operating lease liabilities	$ 474	$ 1,020	$ 0

Financial Instruments - Schedul

Financial Instruments - Schedule of Carrying Amounts and Estimated Fair Values of Financial Instruments (Details) - USD ($) $ in Thousands	Dec. 31, 2022	Dec. 31, 2021
Debt Instrument [Line Items]
Carrying Amount	$ 585,340	$ 962,727
12.00% Second-Priority Senior Secured Notes - due January 2026
Debt Instrument [Line Items]
Carrying Amount		588,838
Carrying Amount	590,132
Fair Value	674,542	685,945
7.50% Senior Notes – due May 2022
Debt Instrument [Line Items]
Carrying Amount	0	6,060
Fair Value	0	6,145
Bank Credit Facility - matures November 2024
Debt Instrument [Line Items]
Carrying Amount		367,829
Carrying Amount	(4,792)
Fair Value	$ 0	$ 375,000

Financial Instruments - Sched_2

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

Financial Instruments - Additio

Financial Instruments - Additional Information (Details)	12 Months Ended
	Dec. 31, 2022 Counterparty
Concentration Risk [Line Items]
Credit risk, financial instruments	The Company is subject to the risk of loss on its financial instruments as a result of nonperformance by counterparties pursuant to the terms of their contractual obligations. The Company has entered into International Swaps and Derivative Association agreements with counterparties to mitigate this risk. The Company also maintains credit policies with regard to its counterparties to minimize overall credit risk. These policies require (i) the evaluation of potential counterparties’ financial condition to determine their creditworthiness; (ii) the regular monitoring of counterparties’ credit exposures; (iii) the use of contract language that affords the Company netting or set off opportunities to mitigate exposure risk; and (iv) potentially requiring counterparties to post cash collateral, parent guarantees, or letters of credit to minimize credit risk. The Company’s assets and liabilities from commodity price risk management activities at December 31, 2022 represent derivative instruments from eight counterparties; all of which are registered swap dealers that have an “investment grade” (minimum Standard & Poor’s rating of BBB- or better) credit rating, and 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.
Counterparty Risk Investment Grade [Member]
Concentration Risk [Line Items]
Number of counterparties description	all of which
Counterparty Risk Diversification [Member]
Concentration Risk [Line Items]
Number of counterparties	8

Financial Instruments - Sched_3

Financial Instruments - Schedule of Impact that Derivatives not Qualifying as Hedging Instruments in Condensed Consolidated Statements of Operations (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative fair value loss (gain)	$ (272,191)	$ (419,077)	$ 87,685
Gain Loss on Derivative Instruments Unrealized Component
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative fair value loss (gain)	153,368	(128,913)	(56,220)
Commodity Contract
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative fair value loss (gain)	(272,191)	(419,077)	87,685
Commodity Contract | Gain Loss on Derivative Instruments Realized Component
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative fair value loss (gain)	$ (425,559)	$ (290,164)	$ 143,905

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, 2022 MMBTU $ / MMBTU $ / bbl bbl
Crude Oil | January 2023 - December 2023 | Swaps
Derivative [Line Items]
Settlement Index	NYMEX WTI CMA
Average Daily Volumes | bbl	17,863
Weighted Average Swap Price | $ / bbl	72.46
Crude Oil | January 2024 - December 2024 | Swaps
Derivative [Line Items]
Settlement Index	NYMEX WTI CMA
Average Daily Volumes | bbl	5,240
Weighted Average Swap Price | $ / bbl	73.95
Crude Oil | July 2023 - December 2023 | Collars
Derivative [Line Items]
Settlement Index	NYMEX WTI CMA
Average Daily Volumes | bbl	2,512
Weighted average put price | $ / bbl	70
Weighted average call price | $ / bbl	86.59
Crude Oil | January 2024 - March 2024 | Collars
Derivative [Line Items]
Settlement Index	NYMEX WTI CMA
Average Daily Volumes | bbl	2,000
Weighted average put price | $ / bbl	70
Weighted average call price | $ / bbl	88
Natural Gas | January 2023 - December 2023 | Swaps
Derivative [Line Items]
Settlement Index	NYMEX Henry Hub
Weighted Average Swap Price | $ / MMBTU	3.76
Average Daily Volumes | MMBTU	26,395
Natural Gas | January 2023 - December 2023 | Collars
Derivative [Line Items]
Settlement Index	NYMEX Henry Hub
Average Daily Volumes | MMBTU	10,000
Weighted average put price | $ / MMBTU	5.25
Weighted average call price | $ / MMBTU	8.46
Natural Gas | January 2024 - December 2024 | Collars
Derivative [Line Items]
Settlement Index	NYMEX Henry Hub
Average Daily Volumes | MMBTU	10,000
Weighted average put price | $ / MMBTU	4
Weighted average call price | $ / MMBTU	6.90
Natural Gas | January 2024 - June 2024 | Swaps
Derivative [Line Items]
Settlement Index	NYMEX Henry Hub
Weighted Average Swap Price | $ / MMBTU	3.25
Average Daily Volumes | MMBTU	10,000

Financial Instruments - Summary

Financial Instruments - Summary of Additional Information Related to Financial Instruments Measured at Fair Value on Recurring Basis (Details) - USD ($) $ in Thousands	Dec. 31, 2022	Dec. 31, 2021
Oil and Natural Gas Derivatives
Assets:
Oil and natural gas derivatives	$ 0	$ 0
Liabilities:
Oil and natural gas derivatives	(43,359)	(196,727)
Fair Value on Recurring Basis
Liabilities:
Total net liability	(43,359)	(196,727)
Fair Value on Recurring Basis | Oil and Natural Gas Derivatives
Assets:
Oil and natural gas derivatives	$ 32,883	$ 3,737
Derivative Asset, Statement of Financial Position [Extensible Enumeration]	Assets	Assets
Liabilities:
Oil and natural gas derivatives	$ (76,242)	$ (200,464)
Derivative Liability, Statement of Financial Position [Extensible Enumeration]	Liabilities	Liabilities
Fair Value on Recurring Basis | Level 1
Liabilities:
Total net liability	$ 0	$ 0
Fair Value on Recurring Basis | Level 1 | Oil and Natural Gas Derivatives
Assets:
Oil and natural gas derivatives	$ 0	$ 0
Derivative Asset, Statement of Financial Position [Extensible Enumeration]	Assets	Assets
Liabilities:
Oil and natural gas derivatives	$ 0	$ 0
Derivative Liability, Statement of Financial Position [Extensible Enumeration]	Liabilities	Liabilities
Fair Value on Recurring Basis | Level 2
Liabilities:
Total net liability	$ (43,359)	$ (196,727)
Fair Value on Recurring Basis | Level 2 | Oil and Natural Gas Derivatives
Assets:
Oil and natural gas derivatives	$ 32,883	$ 3,737
Derivative Asset, Statement of Financial Position [Extensible Enumeration]	Assets	Assets
Liabilities:
Oil and natural gas derivatives	$ (76,242)	$ (200,464)
Derivative Liability, Statement of Financial Position [Extensible Enumeration]	Liabilities	Liabilities
Fair Value on Recurring Basis | Level 3
Liabilities:
Total net liability	$ 0	$ 0
Fair Value on Recurring Basis | Level 3 | Oil and Natural Gas Derivatives
Assets:
Oil and natural gas derivatives	$ 0	$ 0
Derivative Asset, Statement of Financial Position [Extensible Enumeration]	Assets	Assets
Liabilities:
Oil and natural gas derivatives	$ 0	$ 0
Derivative Liability, Statement of Financial Position [Extensible Enumeration]	Liabilities	Liabilities

Financial Instruments - Sched_5

Financial Instruments - Schedule of Fair Value of Derivative Financial Instruments (Details) - USD ($) $ in Thousands	Dec. 31, 2022	Dec. 31, 2021
Price Risk Derivatives [Line Items]
Assets from price risk management activities	$ 25,029	$ 967
Assets from price risk management activities	7,854	2,770
Liabilities from price risk management activities	68,370	186,526
Liabilities from price risk management activities	7,872	13,938
Oil and Natural Gas Derivatives
Price Risk Derivatives [Line Items]
Assets from price risk management activities	25,029	967
Assets from price risk management activities	7,854	2,770
Total gross amounts presented on balance sheet, Assets	32,883	3,737
Gross amounts not offset on the balance sheet	32,883	3,737
Net Amounts	0	0
Liabilities from price risk management activities	68,370	186,526
Liabilities from price risk management activities	7,872	13,938
Total gross amounts presented on balance sheet, Liabilities	76,242	200,464
Gross amounts not offset on the balance sheet	32,883	3,737
Net Amounts	$ 43,359	$ 196,727

Debt - Summary of Detail Compri

Debt - Summary of Detail Comprising Debt and Related Book Values (Details) - USD ($) $ in Thousands	Dec. 31, 2022	Dec. 31, 2021
Debt Instrument [Line Items]
Total debt, before discount and deferred financing cost	$ 638,541	$ 1,031,060
Discount and deferred financing cost	(53,201)	(68,333)
Total debt, net of discount and deferred financing costs	585,340	962,727
Less: current portion of long-term debt	0	6,060
Long-term debt, net of discount and deferred financing costs	585,340	956,667
7.50% Senior Notes – due May 2022
Debt Instrument [Line Items]
Total debt, net of discount and deferred financing costs	0	6,060
Senior Notes | 12.00% Second-Priority Senior Secured Notes - due January 2026
Debt Instrument [Line Items]
Total debt, before discount and deferred financing cost	638,541	650,000
Senior Notes | 7.50% Senior Notes – due May 2022
Debt Instrument [Line Items]
Total debt, before discount and deferred financing cost	0	6,060
Bank Credit Facility | Bank Credit Facility - matures November 2024
Debt Instrument [Line Items]
Total debt, before discount and deferred financing cost	$ 0	$ 375,000

Debt - Summary of Detail Comp_2

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

Debt - Additional information (

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

12 Months Ended

Feb. 13, 2023

Feb. 10, 2023

Jan. 15, 2023

Dec. 23, 2022

Oct. 27, 2022

Oct. 21, 2022

May 31, 2022

Jan. 13, 2021

Jun. 15, 2020

Dec. 31, 2022

Dec. 31, 2021

Dec. 31, 2020

May 04, 2022

Jan. 14, 2021

Debt Instrument [Line Items]

Debt instrument frequency of periodic payment

The indenture governing the EnVen Second Lien Notes requires the redemption of $15.0 million of the principal amount outstanding at par value on April 15th and October 15th of each year.

Debt instrument, repurchase amount

$ 0

$ 0

$ 35,960,000

Gain (loss) on extinguishment of debt

(1,569,000)

(13,225,000)

$ 1,662,000

Debt instrument, face amount

$ 638,541,000

$ 1,031,060,000

DebtInstrument covenant description

The Bank Credit Facility has certain debt covenants, the most restrictive of which is that the Company must maintain a Consolidated Total Debt to EBITDAX Ratio (as defined in the Bank Credit Facility) of no greater than 3.00 to 1.00 calculated each quarter utilizing the most recent twelve months to determine EBITDAX.

Limitation on Restricted Payments Including Dividends, Description

The Company has not historically declared or paid any cash dividends on its capital stock. However, to the extent the Company determines in the future that it may be appropriate to pay a special dividend or initiate a quarterly dividend program, the Company’s ability to pay any such dividends to its stockholders may be limited to the extent its consolidated subsidiaries are limited in their ability to make distributions to the Parent Company, including the significant restrictions that the agreements governing the Company’s debt impose on the ability of its consolidated subsidiaries to make distributions and other payments to the Parent Company. With respect to entities accounted for under the equity method, the Company’s primary equity method investee as of December 31, 2022 did not have any undistributed earnings.The Bank Credit Facility contains restrictions on the ability of Talos Production Inc. to transfer funds to the Parent Company in the form of cash dividends, loans or advances. The Bank Credit Facility restricts distributions and other payments to the Parent Company, subject to certain baskets and other exceptions described therein including the payment of operating expense incurred in the ordinary course of business and for income taxes attributable to its ownership in Talos Production Inc. Under the Bank Credit Facility, general distributions and other restricted payments may be made to the Company so long as after giving pro forma effect to the making of any such restricted payment (i) no default or event of default has occurred and is continuing; (ii) available commitments exceed 25% of the then effective loan limit; (iii) the pro forma current ratio of 1.0 to 1.0 is satisfied; and (iv) either (A) the Consolidated Total Debt to EBITDAX Ratio (as defined in the Bank Credit Facility) is not greater than 1.75 to 1.00 and the aggregate amount of such restricted payments does not exceed the Available Free Cash Flow Amount (as defined in the Bank Credit Facility) at the time made or (B) the Consolidated Total Debt to EBITDAX Ratio is not greater than 1.00 to 1.00. In addition, the indenture governing the 12.00% Notes restricts the Company’s consolidated subsidiaries from, directly or indirectly, among other things, declaring or paying any dividend on account of their equity securities, subject to certain limited exceptions described in the indenture. Such exceptions include, among other things, if (i) no default has occurred or would occur as a result thereof, (ii) immediately after giving effect to such transaction on a pro forma basis, the issuer could incur $1.00 of additional indebtedness in compliance with a fixed charge coverage ratio of 2.25 to 1.00, (iii) the ratio of the issuer’s total debt to EBITDA ratio is not greater than 3.00 to 1.00, and (iii) if payments pursuant to such transaction, together with the aggregate amount of certain other restricted payments, is less than the cumulative credit permitted under the indenture. At December 31, 2022, restricted net assets of the Company’s consolidated subsidiaries exceeded 25%.

Subsequent Event | EnVen Energy Corporation

Debt Instrument [Line Items]

Business Acquisition, Effective Date of Acquisition

Feb. 13, 2023

Credit facility, borrowings outstanding

$ 0

Minimum

Debt Instrument [Line Items]

Restricted net assets, subsidiaries exceeded

25%

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

Debt Instrument [Line Items]

Debt instrument, redemption price, percentage

102.75%

Debt instrument, interest rate, stated percentage

11%

Debt instrument, repurchase amount

$ 37,200,000

7.50% Senior Notes – due May 2022

Debt Instrument [Line Items]

Debt instrument maturity date

May 31, 2022

May 31, 2022

May 31, 2022

Debt instrument, interest rate, stated percentage

7.50%

7.50%

7.50%

Debt instrument redemption, description

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

Debt instrument, face amount

$ 6,100,000

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

Debt Instrument [Line Items]

Fixed Charge Coverage Ratio Satisfied With Incurrence Of Additional Indebtedness Amount

$ 1

Date of Second Supplemental Indenture

Oct. 27, 2022

12.00% Second-Priority Senior Secured Notes - due January 2026 | Maximum | Restrictions which limit the payment of dividends

Debt Instrument [Line Items]

Consolidated total debt to EBITDAX ratio

3

Debt instrument fixed charge coverage ratio

2.25

Bank Credit Facility - matures November 2024

Debt Instrument [Line Items]

Credit facility, maximum borrowing capacity

$ 1,100,000,000

Bank credit facility, description

The borrowing base is redetermined by the lenders at least semi-annually during the second quarter and fourth quarter of each year. On May 4, 2022, the Company entered into a (i) Borrowing Base Redetermination Agreement and Eighth Amendment to Credit Agreement (the “Eighth Amendment”) and (ii) Incremental Agreement of Increasing Lenders (“Incremental Agreement”). The Eighth Amendment and the Incremental Agreement, among other things, (i) increased the borrowing base from $950.0 million to $1.1 billion and (ii) increased the commitments from $791.3 million to $806.3 million. On December 23, 2022, the Company entered into the Incremental Agreement and Ninth Amendment to Credit Agreement (the “Ninth Amendment”). The Ninth Amendment, among other things, (i) extends the maturity date of the Bank Credit Facility from November 12, 2024 to March 31, 2027, (ii) increases the borrowing base from $1.1 billion to $1.5 billion and (iii) increases commitments from $806.3 million to $965.0 million, in each case contingent upon the closing of the EnVen Acquisition and the occurrence of certain events related thereto.

Percentage of mortgage covering oil and natural gas assets

90%

Line of Credit Facility, Commitments

$ 806,300,000

Bank Credit Facility - matures November 2024 | Subsequent Event

Debt Instrument [Line Items]

Proceeds from Lines of Credit

$ 130,000,000

Bank Credit Facility - matures November 2024 | Subsequent Event | EnVen Energy Corporation

Debt Instrument [Line Items]

Line of Credit Facility, Remaining Borrowing Capacity

$ 754,200,000

Bank Credit Facility - matures November 2024 | Letter of Credit

Debt Instrument [Line Items]

Line of Credit Facility, Commitments

$ 150,000,000

Bank Credit Facility - matures November 2024 | Adjusted Daily Simple Secured Overnight Financing Rate [Member]

Debt Instrument [Line Items]

Debt Instrument, Basis Spread on Variable Rate

0.10%

Bank Credit Facility - matures November 2024 | Base Rate Federal Funds [Member]

Debt Instrument [Line Items]

Debt Instrument, Basis Spread on Variable Rate

0.50%

Bank Credit Facility - matures November 2024 | One Month Adjusted Term Secured Overnight Financing Rate [Member]

Debt Instrument [Line Items]

Debt Instrument, Basis Spread on Variable Rate

1%

Bank Credit Facility - matures November 2024 | Adjusted Term Secured Overnight Financing Rate [Member]

Debt Instrument [Line Items]

Debt Instrument, Basis Spread on Variable Rate

0.10%

Bank Credit Facility - matures November 2024 | Pro Forma | EnVen Energy Corporation

Debt Instrument [Line Items]

Percentage of mortgage covering oil and natural gas assets

85%

Bank Credit Facility - matures November 2024 | Minimum

Debt Instrument [Line Items]

Debt instrument covenant current ratio.

1

Bank Credit Facility - matures November 2024 | Maximum

Debt Instrument [Line Items]

Consolidated total debt to EBITDAX ratio

3

Bank Credit Facility - matures November 2024 | Maximum | Letter of Credit

Debt Instrument [Line Items]

Line of Credit Facility, Commitments

$ 200,000,000

Bank Credit Facility - matures November 2024 | Maximum | Pro Forma | Letter of Credit | EnVen Energy Corporation

Debt Instrument [Line Items]

Line of Credit Facility, Commitments

$ 250,000,000

Bank Credit Facility

Debt Instrument [Line Items]

Line of credit facility, Dividend restrictions

The Bank Credit Facility restricts distributions and other payments to the Parent Company, subject to certain baskets and other exceptions described therein including the payment of operating expense incurred in the ordinary course of business and for income taxes attributable to its ownership in Talos Production Inc. Under the Bank Credit Facility, general distributions and other restricted payments may be made to the Company so long as after giving pro forma effect to the making of any such restricted payment (i) no default or event of default has occurred and is continuing; (ii) available commitments exceed 25% of the then effective loan limit; (iii) the pro forma current ratio of 1.0 to 1.0 is satisfied; and (iv) either (A) the Consolidated Total Debt to EBITDAX Ratio (as defined in the Bank Credit Facility) is not greater than 1.75 to 1.00 and the aggregate amount of such restricted payments does not exceed the Available Free Cash Flow Amount (as defined in the Bank Credit Facility) at the time made or (B) the Consolidated Total Debt to EBITDAX Ratio is not greater than 1.00 to 1.00.

Bank Credit Facility | Restrictions which limit the payment of dividends

Debt Instrument [Line Items]

Percentage of commitments exceeding the effective loan limit

25%

Bank Credit Facility | Applicable Margin Percentage Decrease

Debt Instrument [Line Items]

Debt Instrument, Basis Spread on Variable Rate

0.25%

Bank Credit Facility | Pro Forma

Debt Instrument [Line Items]

Debt instrument maturity date

Mar. 31, 2027

Bank Credit Facility | Minimum

Debt Instrument [Line Items]

Credit facility, maximum borrowing capacity

$ 950,000,000

Line of Credit Facility, Commitments

791,300,000

Bank Credit Facility | Minimum | Restrictions which limit the payment of dividends

Debt Instrument [Line Items]

Pro Forma Current Ratio

1

Bank Credit Facility | Minimum | Pro Forma

Debt Instrument [Line Items]

Credit facility, maximum borrowing capacity

$ 1,100,000,000

Line of Credit Facility, Commitments

806,300,000

Bank Credit Facility | Maximum

Debt Instrument [Line Items]

Credit facility, maximum borrowing capacity

1,100,000,000

Line of Credit Facility, Commitments

$ 806,300,000

Bank Credit Facility | Maximum | Restrictions which limit the payment of dividends

Debt Instrument [Line Items]

Consolidated total debt to EBITDAX ratio

1

Bank Credit Facility | Maximum | Pro Forma

Debt Instrument [Line Items]

Credit facility, maximum borrowing capacity

1,500,000,000

Line of Credit Facility, Commitments

$ 965,000,000

Bank Credit Facility | Maximum | Restricted payments does not exceed the available free cash flow amount | Restrictions which limit the payment of dividends

Debt Instrument [Line Items]

Consolidated total debt to EBITDAX ratio

1.75

Enven Second Lien Notes | Subsequent Event | EnVen Energy Corporation

Debt Instrument [Line Items]

Debt instrument maturity date

Apr. 15, 2026

Level 1

Debt Instrument [Line Items]

Line of Credit Facility, Unused Capacity, Commitment Fee Percentage

0.375%

0.50%

Level 1 | Term Benchmark Loans and RFR Loan

Debt Instrument [Line Items]

Debt Instrument, Basis Spread on Variable Rate

3%

Level 1 | Alternate Base Rate

Debt Instrument [Line Items]

Debt Instrument, Basis Spread on Variable Rate

2%

Level 1 | Maximum

Debt Instrument [Line Items]

Borrowing base utilization percentage

25%

Level 2

Debt Instrument [Line Items]

Line of Credit Facility, Unused Capacity, Commitment Fee Percentage

0.375%

0.50%

Level 2 | Term Benchmark Loans and RFR Loan

Debt Instrument [Line Items]

Debt Instrument, Basis Spread on Variable Rate

3.25%

Level 2 | Alternate Base Rate

Debt Instrument [Line Items]

Debt Instrument, Basis Spread on Variable Rate

2.25%

Level 2 | Minimum

Debt Instrument [Line Items]

Borrowing base utilization percentage

25%

Level 2 | Maximum

Debt Instrument [Line Items]

Borrowing base utilization percentage

50%

Commitment Fee Rate | Maximum | Pro Forma | Revolving Credit Facility

Debt Instrument [Line Items]

Borrowing base utilization percentage

50%

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

Debt Instrument [Line Items]

Debt instrument, interest rate, stated percentage

11%

11%

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

3.1

Debt instrument, repurchase amount

$ 347,300,000

$ 6,400,000

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

Debt Instrument [Line Items]

Gain (loss) on extinguishment of debt

$ (13,200,000)

$ 1,700,000

Senior Notes | 7.50% Senior Notes – due May 2022

Debt Instrument [Line Items]

Debt instrument maturity date

May 31, 2022

May 31, 2022

Debt instrument, interest rate, stated percentage

7.50%

7.50%

Debt instrument, face amount

$ 0

$ 6,060,000

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

Debt Instrument [Line Items]

Debt instrument, redemption price, percentage

12%

Debt instrument maturity date

Jan. 15, 2026

Jan. 15, 2026

Debt instrument frequency of periodic payment

semi-annually

Debt instrument payment terms

semi-annually each January 15 and July 15

Debt instrument, interest rate, stated percentage

12%

12%

12%

Debt instrument redemption, description

At any time prior to January 15, 2023, the Company may redeem up to 40% of the principal amount of the 12.00% Notes at a redemption rate of 112.00% of the principal amount plus accrued and unpaid interest. At any time prior to January 15, 2023, the Company may also redeem some or all of the 12.00% Notes at a price equal to 100% of the principal amount of the 12.00% Notes, plus a “make-whole premium,” together with accrued and unpaid interest, if any, to, but excluding, the date of redemption. Thereafter, the Company may redeem all or a portion of the 12.00% Notes in whole at any time or in part from time to time at the following redemption prices (expressed as percentages of principal amount) plus accrued and unpaid interest if redeemed during the period commencing on January 15 of the years set forth below:

Debt Instrument Redemption Prior Period

Jan. 15, 2023

Debt instrument, face amount

$ 638,541,000

$ 650,000,000

Debt instrument, repurchase amount

11,500,000

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

Debt Instrument [Line Items]

Notes Solicitation Consents Fee Consideration

$ 3,100,000

Senior Notes | 12.00% Second-Priority Senior Secured Notes - due January 2026 | Other Income (Expense)

Debt Instrument [Line Items]

Gain (loss) on extinguishment of debt

$ 1,600

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

Debt Instrument [Line Items]

Maximum percentage of principal amount option to redeem

40%

Senior Notes | Enven Second Lien Notes | Subsequent Event

Debt Instrument [Line Items]

Debt instrument, periodic payment, principal

15,000,000

Senior Notes | Enven Second Lien Notes | Subsequent Event | EnVen Energy Corporation

Debt Instrument [Line Items]

Debt instrument, face amount

$ 257,500,000

Line of Credit [Member]

Debt Instrument [Line Items]

Line of Credit Facility, Borrowing Capacity, Description

The Bank Credit Facility provides for the determination of the borrowing base based on the Company’s proved producing reserves and a portion of the Company's proved undeveloped reserves.

Line of Credit [Member] | Bank Credit Facility - matures November 2024

Debt Instrument [Line Items]

Debt instrument, face amount

$ 0

$ 375,000,000

Notes Solicitation Consent [Member] | 12.00% Second-Priority Senior Secured Notes - due January 2026

Debt Instrument [Line Items]

Amount of notes consents received from notes consent solicitation

95.80%

Notes Solicitation Consents Fee Consideration, Basis Points

0.50%

Notes Solicitation Consent Permit Enven Senior Notes Indebtedness | Enven Second Lien Notes | EnVen Energy Corporation

Debt Instrument [Line Items]

Debt instrument, interest rate, stated percentage

11.75%

Debt Instrument, Redemption, Period One | Senior Notes | 12.00% Second-Priority Senior Secured Notes - due January 2026

Debt Instrument [Line Items]

Debt instrument, redemption price, percentage

112%

Debt Instrument, Redemption, Period Two | Senior Notes | 12.00% Second-Priority Senior Secured Notes - due January 2026

Debt Instrument [Line Items]

Debt instrument, redemption price, percentage

100%

Debt - Summary of Redemption Pr

Debt - Summary of Redemption Prices of 12.% Notes (Details) - 12.00% Second-Priority Senior Secured Notes - due January 2026	12 Months Ended
	Dec. 31, 2022
Debt Instrument, Redemption, Period Three
Debt Instrument, Redemption [Line Items]
Debt instrument, redemption price, percentage	106%
Debt Instrument, Redemption, Period Four
Debt Instrument, Redemption [Line Items]
Debt instrument, redemption price, percentage	103%
Debt Instrument, Redemption, Period After Five
Debt Instrument, Redemption [Line Items]
Debt instrument, redemption price, percentage	100%

Debt - Schedule of Pricing Grid

Debt - Schedule of Pricing Grid for Borrowing Base Utilization Percentage (Details)		12 Months Ended
	Feb. 13, 2023	Dec. 31, 2022
Level 1
Debt Instrument [Line Items]
Commitment fee percentage	0.375%	0.50%
Level 1 | Term Benchmark Loans and RFR Loan
Debt Instrument [Line Items]
Basis Spread on Variable Rate		3%
Level 1 | Alternate Base Rate
Debt Instrument [Line Items]
Basis Spread on Variable Rate		2%
Level 2
Debt Instrument [Line Items]
Commitment fee percentage	0.375%	0.50%
Level 2 | Term Benchmark Loans and RFR Loan
Debt Instrument [Line Items]
Basis Spread on Variable Rate		3.25%
Level 2 | Alternate Base Rate
Debt Instrument [Line Items]
Basis Spread on Variable Rate		2.25%
Level 3
Debt Instrument [Line Items]
Commitment fee percentage		0.50%
Level 3 | Term Benchmark Loans and RFR Loan
Debt Instrument [Line Items]
Basis Spread on Variable Rate		3.50%
Level 3 | Alternate Base Rate
Debt Instrument [Line Items]
Basis Spread on Variable Rate		2.50%
Level 4
Debt Instrument [Line Items]
Commitment fee percentage		0.50%
Level 4 | Term Benchmark Loans and RFR Loan
Debt Instrument [Line Items]
Basis Spread on Variable Rate		3.75%
Level 4 | Alternate Base Rate
Debt Instrument [Line Items]
Basis Spread on Variable Rate		2.75%
Level 5
Debt Instrument [Line Items]
Commitment fee percentage		0.50%
Level 5 | Term Benchmark Loans and RFR Loan
Debt Instrument [Line Items]
Basis Spread on Variable Rate		4%
Level 5 | Alternate Base Rate
Debt Instrument [Line Items]
Basis Spread on Variable Rate		3%
Maximum [Member] | Level 1
Debt Instrument [Line Items]
Utilization		25%
Maximum [Member] | Level 2
Debt Instrument [Line Items]
Utilization		50%
Maximum [Member] | Level 3
Debt Instrument [Line Items]
Utilization		75%
Maximum [Member] | Level 4
Debt Instrument [Line Items]
Utilization		90%
Minimum [Member] | Level 2
Debt Instrument [Line Items]
Utilization		25%
Minimum [Member] | Level 3
Debt Instrument [Line Items]
Utilization		50%
Minimum [Member] | Level 4
Debt Instrument [Line Items]
Utilization		75%
Minimum [Member] | Level 5
Debt Instrument [Line Items]
Utilization		90%

Employee Benefits Plans and S_3

Employee Benefits Plans and Share-Based Compensation - Additional Information (Details) - USD ($) $ in Millions	1 Months Ended	12 Months Ended
	Mar. 31, 2022	Dec. 31, 2022		Dec. 31, 2021	Dec. 31, 2020
Restricted Stock Units
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Unvested restricted stock units and award, granted		2,297,465		1,102,038	1,284,797
Share-Based Payment Arrangement, Plan Modification, Incremental Cost		$ 9.7
Performance Shares
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Contingent Right Upon Vesting to Receive Common Stock		1
Share-based compensation expense recognized period		1 year 9 months 18 days
Share-based compensation expense unrecognized		$ 14
Unvested restricted stock units and award, granted		629,666	[1]	586,995	441,642
Performance Shares | Minimum
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Share-Based Compensation Arrangement by Share-Based Payment Award, Award Vesting Rights, Percentage		0%
Performance Shares | Maximum
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Share-Based Compensation Arrangement by Share-Based Payment Award, Award Vesting Rights, Percentage		200%
Executive Officer | Restricted Stock Units
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Unvested restricted stock units and award, granted	1,147,352
Long Term Incentive Plan
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Share-Based Compensation authorized to grant		8,639,415
Long Term Incentive Plan | Performance Shares
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Description of method used to calculate fair value		Monte Carlo simulations
Long Term Incentive Plan | Employees | Restricted Stock Units
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Share-Based Compensation Arrangement by Share-Based Payment Award, Award Vesting Period		3 years
Contingent Right Upon Vesting to Receive Common Stock		1
Share-based compensation expense recognized period		1 year 8 months 12 days
Share-based compensation expense unrecognized		$ 24.6
Long Term Incentive Plan | Non-employee Directors | Restricted Stock Units
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Share-Based Compensation Arrangement by Share-Based Payment Award, Award Vesting Period		1 year
Share-based compensation expense recognized period		2 months 12 days
Contingent Right Upon Vesting to Receive Common Stock Percentage		60%
Contingent Right Upon Vesting to Receive Cash Percentage		40%
Share-based compensation expense liabilities		$ 0.1
Share-based compensation expense unrecognized		$ 0.2
[1] There were 314,833 PSUs granted that are eligible to vest based on continued employment and the Company’s annualized absolute total shareholder return (“TSR”) over a three-year performance period. An additional 314,833 PSUs were granted and are eligible to vest based on continued employment and the Company’s return on the wells included in the 2022 drill program over a three-year performance period.

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, 2022		Dec. 31, 2021	Dec. 31, 2020
Restricted Stock Units
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Unvested beginning of the period	1,983,199		1,652,988	733,777
Granted	2,297,465		1,102,038	1,284,797
Vested	(967,269)		(669,832)	(273,787)
Forfeited	(97,891)		(101,995)	(91,799)
Unvested end of the period	3,215,504	[1]	1,983,199	1,652,988
Unvested weighted average grant date fair value, beginning of the period	$ 13.02		$ 13.73	$ 25.20
Unvested weighted average grant date fair value, granted	13.23		13.11	10.02
Unvested weighted average grant date fair value, vested	14.14		15.01	25.09
Unvested weighted average grant date fair value, forfeited	14.34		12.46	19.65
Unvested weighted average grant date fair value, end of the period	$ 12.79	[1]	$ 13.02	$ 13.73
Performance Shares
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Unvested beginning of the period	1,015,459		834,172	417,831
Granted	629,666	[2]	586,995	441,642
Vested	(14,474)	[3]	(391,308)
Forfeited	(16,486)		(14,400)	(25,301)
Cancelled	(975,564)
Unvested end of the period	638,601		1,015,459	834,172
Unvested weighted average grant date fair value, beginning of the period	$ 16.41		$ 25.46	$ 39.31
Unvested weighted average grant date fair value, granted	23.73	[2]	18.96	13.05
Unvested weighted average grant date fair value, vested	13.05	[3]	39.43
Unvested weighted average grant date fair value, forfeited	17.48		18.48	37.67
Unvested weighted average grant date fair value, Cancelled	16.42
Unvested weighted average grant date fair value, end of the period	$ 23.66		$ 16.41	$ 25.46
[1] As of December 31, 2022 , 25,257 of the unvested RSUs were accounted for as liability awards in “Accrued liabilities” on the Consolidated Balance Sheet. There were 314,833 PSUs granted that are eligible to vest based on continued employment and the Company’s annualized absolute total shareholder return (“TSR”) over a three-year performance period. An additional 314,833 PSUs were granted and are eligible to vest based on continued employment and the Company’s return on the wells included in the 2022 drill program over a three-year performance period. The performance period for the relative TSR awards ended on December 31, 2022. The payout on these awards was 0 % based on actual performance over the performance period as certified by the Compensation Committee of the Company’s Board of Directors in early 2023. Since these awards were legally forfeited they will again be available for new awards under the recycling provisions of the 2021 LTIP.

Employee Benefits Plans and S_5

Employee Benefits Plans and Share-Based Compensation - Schedule of Restricted Stock and Performance Share Units Activity (Parenthetical) (Details) - shares	12 Months Ended
	Dec. 31, 2022		Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Restricted Stock Units
Share-Based Compensation Arrangement by Share-Based Payment Award [Line Items]
Granted	2,297,465		1,102,038	1,284,797
Unvested RSUs	3,215,504	[1]	1,983,199	1,652,988	733,777
Performance Shares
Share-Based Compensation Arrangement by Share-Based Payment Award [Line Items]
Granted	629,666	[2]	586,995	441,642
Unvested RSUs	638,601		1,015,459	834,172	417,831
Maximum | Performance Shares
Share-Based Compensation Arrangement by Share-Based Payment Award [Line Items]
Share-Based Compensation Arrangement by Share-Based Payment Award, Award Vesting Rights, Percentage	200%
Minimum [Member] | Performance Shares
Share-Based Compensation Arrangement by Share-Based Payment Award [Line Items]
Share-Based Compensation Arrangement by Share-Based Payment Award, Award Vesting Rights, Percentage	0%
Absolute Total Shareholder Return Award | Performance Shares
Share-Based Compensation Arrangement by Share-Based Payment Award [Line Items]
Granted	314,833
Share-Based Compensation Arrangement by Share-Based Payment Award, Award Vesting Period	3 years
Return On Drilling Program Award
Share-Based Compensation Arrangement by Share-Based Payment Award [Line Items]
Share-Based Compensation Arrangement by Share-Based Payment Award, Award Vesting Period	3 years
Return On Drilling Program Award | Performance Shares
Share-Based Compensation Arrangement by Share-Based Payment Award [Line Items]
Granted	314,833
Relative Total Shareholder Return Award | Performance Shares
Share-Based Compensation Arrangement by Share-Based Payment Award [Line Items]
Share based payment payout percentage	0%
Accrued Liabilities | Restricted Stock Units
Share-Based Compensation Arrangement by Share-Based Payment Award [Line Items]
Unvested RSUs	25,257
[1] As of December 31, 2022 , 25,257 of the unvested RSUs were accounted for as liability awards in “Accrued liabilities” on the Consolidated Balance Sheet. There were 314,833 PSUs granted that are eligible to vest based on continued employment and the Company’s annualized absolute total shareholder return (“TSR”) over a three-year performance period. An additional 314,833 PSUs were granted and are eligible to vest based on continued employment and the Company’s return on the wells included in the 2022 drill program over a three-year performance period.

Employee Benefits Plans and S_6

Employee Benefits Plans and Share-Based Compensation - Summary of Assumptions Used to Calculate the Grant Date Fair Value (Details) - Performance Shares - USD ($) $ in Thousands	Sep. 20, 2022	Mar. 05, 2022	May 11, 2021	Mar. 08, 2021	Mar. 05, 2020
Grant Date September 20, 2022
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Expected term (in years)	2 years 3 months 18 days
Expected volatility	74.30%
Risk-free interest rate	3.90%
Dividend yield	0%
Fair value (in thousands)	$ 621
Grant Date March 5, 2022
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Expected term (in years)		2 years 9 months 18 days
Expected volatility		82.20%
Risk-free interest rate		1.60%
Dividend yield		0%
Fair value (in thousands)		$ 8,668
Grant Date May 11, 2021
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Expected term (in years)			2 years 7 months 6 days
Expected volatility			80.90%
Risk-free interest rate			0.30%
Dividend yield			0%
Fair value (in thousands)			$ 9,715
Grant Date March 8, 2021
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Expected term (in years)				2 years 9 months 18 days
Expected volatility				78.30%
Risk-free interest rate				0.30%
Dividend yield				0%
Fair value (in thousands)				$ 11,129
Grant Date March 5, 2020
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Expected term (in years)					2 years 9 months 18 days
Expected volatility					48.80%
Risk-free interest rate					0.60%
Dividend yield					0%
Fair value (in thousands)					$ 5,763

Employee Benefits Plans and S_7

Employee Benefits Plans and Share-Based Compensation - Schedule of Recognized Share Based Compensation Expense, Net (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Share-Based Payment Arrangement [Abstract]
Share-based compensation costs	$ 28,280	$ 20,560	$ 16,462
Less: Amounts capitalized to oil and gas properties	12,327	9,568	7,793
Non-cash equity-based compensation expense	$ 15,953	$ 10,992	$ 8,669

Income Taxes - Components of In

Income Taxes - Components of Income Tax Expense (Benefit) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Current income tax expense (benefit)
United States	$ 1,375	$ (5)	$ (499)
Mexico	432	(993)	185
Total current income tax expense (benefit)	1,807	(998)	(314)
Deferred income tax expense (benefit)
United States	659	(1,067)	35,923
Mexico	71	430	(26)
Total deferred income tax expense (benefit)	730	(637)	35,897
Total income tax expense (benefit)	$ 2,537	$ (1,635)	$ 35,583

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, 2022	Dec. 31, 2021	Dec. 31, 2020
Income Tax Disclosure [Abstract]
Income tax expense (benefit) at the federal statutory tax rate	$ 80,735	$ (38,763)	$ (90,304)
State income taxes	1,591	(674)	(14,215)
Impact of foreign operations	15,657	(11,920)	(1,030)
Effect of change in state rate	0	2,008
Prior year taxes	(2,920)	486	(4,237)
Legal entity reorganization	0	0	(17,566)
Change in valuation allowance	(96,537)	45,547	162,213
Other permanent differences	4,011	1,681	722
Total income tax expense (benefit)	$ 2,537	$ (1,635)	$ 35,583
Effective tax rate	0.66%	0.89%	(8.27%)

Income Taxes - Additional Infor

Income Taxes - Additional Information (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Income Tax Disclosure [Line Items]
Federal statutory rate	21%	21%	21%
Income tax benefit (expense)	$ (2,537)	$ 1,635	$ (35,583)
Operating loss carryforwards limitation on use	As of December 31, 2022, the Company had U.S. federal net operating loss carryforwards (“NOLs”) of approximately $758.4 million, all of which is subject to limitation under Section 382 of the IRC. IRC Section 382 provides an annual limitation with respect to the ability of a corporation to utilize its tax attributes, against future U.S. taxable income in the event of a change in ownership. If not utilized, such carryforwards would begin to expire at the end of 2035.
Valuation allowance	$ 129,105	$ 224,266
Valuation allowance, commentary	In assessing the need for a valuation allowance, the Company considers whether it is more likely than not that some portion or all of the deferred tax assets will not be realized using available positive and negative evidence, including future reversals of temporary differences, tax-planning strategies and future taxable income, to estimate whether sufficient future taxable income will be generated to permit use of deferred tax assets. A significant piece of objective negative evidence evaluated is the cumulative loss incurred over recent years. Such objective negative evidence limits our ability to consider other subjective positive evidence. The Company intends to continue maintaining a full valuation allowance on our deferred tax assets until there is sufficient evidence to support the reversal of all or some portion of these allowances. However, if positive earnings continue to be realized and future earnings are anticipated, the Company believes that there is a reasonable possibility that within the next 12 months, sufficient positive evidence may become available to allow us to reach a conclusion that a significant portion of the valuation allowance will no longer be needed. Release of the valuation allowance would result in the recognition of certain deferred tax assets and a decrease to income tax expense for the period the release is recorded. However, the exact timing and amount of the valuation allowance release are subject to change on the basis of the level of profitability that the Company achieves and anticipates realizing in future years.
Earliest Tax Year
Income Tax Disclosure [Line Items]
Income tax examination, Year	2019
Latest Tax Year
Income Tax Disclosure [Line Items]
Income tax examination, Year	2021
Federal and State
Income Tax Disclosure [Line Items]
Deferred tax assets, valuation allowance expense (benefit)			$ 162,200
Federal
Income Tax Disclosure [Line Items]
Operating loss carryforwards	$ 758,400
Internal Revenue Code
Income Tax Disclosure [Line Items]
Income tax benefit (expense)	$ 17,600
Internal Revenue Code | Federal | Capital loss carryforward
Income Tax Disclosure [Line Items]
Operating loss carryforwards expiration year	2035

Income Taxes - Summary of Signi

Income Taxes - Summary of Significant Components of Deferred Tax Assets and Liabilities (Details) - USD ($) $ in Thousands	Dec. 31, 2022	Dec. 31, 2021
Deferred tax assets:
Federal net operating loss	$ 159,257	$ 153,849
Foreign tax loss carryforward	44,462	49,932
State net operating loss	24,787	24,265
Tax credits	107	303
Interest expense carryforward	23,262	0
Asset retirement obligations	115,848	92,823
Derivatives	9,273	42,075
Other well equipment inventory	1,891	5,680
Accrued bonus	5,863	5,087
Share-based compensation	5,296	3,833
Operating lease liabilities	3,669	4,081
Finance lease liabilities	32,559	0
Other	7,142	5,424
Total deferred tax assets	433,416	387,352
Valuation allowance	(129,105)	(224,266)
Total deferred tax assets, net	304,311	163,086
Deferred tax liabilities:
Oil and gas properties	302,602	160,002
Operating lease assets	1,323	1,423
Prepaid	2,530	3,075
Total deferred tax liabilities	306,455	164,500
Net deferred tax liability	$ (2,144)	$ (1,414)

Income Taxes - Summary of Net O

Income Taxes - Summary of Net Operating Loss Carryovers (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2022 USD ($)
Operating Loss Carryforwards [Line Items]
Operating loss carryforwards limitation on use	As of December 31, 2022, the Company had U.S. federal net operating loss carryforwards (“NOLs”) of approximately $758.4 million, all of which is subject to limitation under Section 382 of the IRC. IRC Section 382 provides an annual limitation with respect to the ability of a corporation to utilize its tax attributes, against future U.S. taxable income in the event of a change in ownership. If not utilized, such carryforwards would begin to expire at the end of 2035.
Federal
Operating Loss Carryforwards [Line Items]
Net operating losses carryforward, Amount	$ 758,400
Federal | Minimum
Operating Loss Carryforwards [Line Items]
Net operating losses, Expiration year	2035
Federal | Maximum
Operating Loss Carryforwards [Line Items]
Net operating losses, Expiration year	2037
Federal | 2035 - 2037
Operating Loss Carryforwards [Line Items]
Net operating losses carryforward, Amount	$ 525,745
Federal | Unlimited Expiration Year
Operating Loss Carryforwards [Line Items]
Net operating losses carryforward, Amount	$ 232,620
Operating loss carryforwards limitation on use	Unlimited
Foreign | Minimum
Operating Loss Carryforwards [Line Items]
Net operating losses, Expiration year	2025
Foreign | Maximum
Operating Loss Carryforwards [Line Items]
Net operating losses, Expiration year	2032
Foreign | 2025 - 2032
Operating Loss Carryforwards [Line Items]
Net operating losses carryforward, Amount	$ 148,206
State | Minimum
Operating Loss Carryforwards [Line Items]
Net operating losses, Expiration year	2025
State | Maximum
Operating Loss Carryforwards [Line Items]
Net operating losses, Expiration year	2037
State | Unlimited Expiration Year
Operating Loss Carryforwards [Line Items]
Net operating losses carryforward, Amount	$ 277,031
Operating loss carryforwards limitation on use	Unlimited
State | 2025 - 2037
Operating Loss Carryforwards [Line Items]
Net operating losses carryforward, Amount	$ 125,958

Income Taxes - Summary of Balan

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

Income (Loss) Per Share - Summa

Income (Loss) Per Share - Summary of Computation of Basic and Diluted Income (Loss) Per Share (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Earnings Per Share [Abstract]
Net income (loss)	$ 381,915	$ (182,952)	$ (465,605)
Weighted average common shares outstanding — basic	82,454	81,769	67,664
Dilutive effect of securities	1,229	0	0
Weighted average common shares outstanding — diluted	83,683	81,769	67,664
Basic	$ 4.63	$ (2.24)	$ (6.88)
Diluted	$ 4.56	$ (2.24)	$ (6.88)
Anti-dilutive potentially issuable securities excluded from diluted common shares	865	1,709	5,019

Related Party Transactions - Ad

Related Party Transactions - Additional Information (Details) $ in Thousands

1 Months Ended

12 Months Ended

Feb. 13, 2023

Sep. 21, 2022

May 24, 2022 USD ($)

Mar. 08, 2022 USD ($)

Mar. 30, 2020 shares

Feb. 28, 2020 shares

Feb. 28, 2020

May 10, 2018 Offering Registration

May 31, 2022 USD ($)

Aug. 31, 2018

Dec. 31, 2022 USD ($)

Dec. 31, 2021 USD ($)

Dec. 31, 2020 USD ($)

Dec. 31, 2019

Related Party Transaction [Line Items]

General and administrative expense

$ 99,754

$ 78,677

$ 79,175

Equity method investment payment

2,250

0

0

Proceeds from sale of equity method investment

$ 15,000

0

0

Stockholders agreement date

May 10, 2018

Stockholders agreement amendment date

Feb. 24, 2020

Amended restated stockholders agreement date

Mar. 29, 2022

Subsequent Event

Related Party Transaction [Line Items]

Amended restated stockholders agreement termination date

Feb. 13, 2023

Secondary Offering Expenses

Related Party Transaction [Line Items]

General and administrative expense

$ 0

700

200

ILX and Castex

Related Party Transaction [Line Items]

Business Acquisition, Effective Date of Acquisition

Feb. 28, 2020

Feb. 28, 2020

ILX and Castex | Series A Convertible Preferred Stock

Related Party Transaction [Line Items]

Share issued on merger | shares

110,000

110,000

Shares issued upon conversion | shares

11,000,000

EnVen Energy Corporation

Related Party Transaction [Line Items]

Business Acquisition, Date of Acquisition Agreement

Sep. 21, 2022

EnVen Energy Corporation | Subsequent Event

Related Party Transaction [Line Items]

Business Acquisition, Effective Date of Acquisition

Feb. 13, 2023

Riverstone Funds

Related Party Transaction [Line Items]

Percentage of common stock held

14.90%

Vinson & Elkins L.L.P.

Related Party Transaction [Line Items]

General and administrative expense

$ 4,800

3,100

3,500

Legal fees payable

1,300

200

$ 700

Bayou Bend

Related Party Transaction [Line Items]

Equity method investment payment

$ 2,300

Related party receivable

$ 700

Bayou Bend | Bayou Bend LLC

Related Party Transaction [Line Items]

Equity Method Investment, Ownership Percentage

50%

25%

Bayou Bend | Equity Method Investment Income

Related Party Transaction [Line Items]

Gain on partial disposal of investment

$ 15,300

Bain | EnVen Energy Corporation | Pro Forma | Subsequent Event

Related Party Transaction [Line Items]

Stock ownership percentage

12.30%

Adage | EnVen Energy Corporation | Pro Forma | Subsequent Event

Related Party Transaction [Line Items]

Stock ownership percentage

5.10%

Chevron U.S.A Inc

Related Party Transaction [Line Items]

Proceeds from sale of equity method investment

$ 15,000

Chevron U.S.A Inc | Bayou Bend

Related Party Transaction [Line Items]

Equity method investment ownership percentage sold

25%

Additional Mandatory Cash Contributions Capital Carry Company Portion Received

$ 1,400

Chevron U.S.A Inc | Bayou Bend | Maximum

Related Party Transaction [Line Items]

Additional Mandatory Cash Contributions Capital Carry Company Portion

$ 10,000

Whistler Energy II Holdco LLC [Member] | Apollo Funds | Whistler Energy II, LLC

Related Party Transaction [Line Items]

Business Acquisition, Date of Acquisition Agreement

Aug. 31, 2018

Whistler Energy II Holdco LLC [Member] | Apollo Funds | Whistler Energy II, LLC | Other Operating (Income) Expense

Related Party Transaction [Line Items]

Gain (Loss) related to decommissioning obligation settlement

$ 4,400

Riverstone Funds, Apollo Funds, Mac Kay Shields LLC and Franklin Advisers Inc | 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%

Registration agreement, termination description

The Registration Rights Agreement have terminated with respect to Franklin and MacKay Shields. Additionally, the Apollo Funds no longer have piggyback rights effective January 3, 2022. The Registration Rights Agreement will otherwise terminate at such time as there are no Registrable Securities outstanding.

Commitments and Contingencies -

Commitments and Contingencies - Additional Information (Details) - USD ($) $ in Millions	Mar. 23, 2022	Dec. 31, 2022
Loss Contingencies [Line Items]
Gain (Loss) Related to Litigation Settlement, Total	$ 27.5
Surety Bond
Loss Contingencies [Line Items]
Surety performance bonds outstanding		$ 740.6
Bank Credit Facility | Letter of Credit
Loss Contingencies [Line Items]
Letters of credit outstanding amount		$ 3.9

Commitments and Contingencies_2

Commitments and Contingencies - Summary of Total Minimum Commitments (Details) $ in Thousands	Dec. 31, 2022 USD ($)
Contractual Obligation [Line Items]
2023	$ 352,571
2024	327
2025	327
2026	0
Thereafter	0
Total	353,225
Vessel Commitments
Contractual Obligation [Line Items]
2023	41,938	[1]
2024	0	[1]
2025	0	[1]
2026	0	[1]
Thereafter	0	[1]
Total	41,938	[1]
Committed Purchase Orders
Contractual Obligation [Line Items]
2023	41,148	[2]
2024	0	[2]
2025	0	[2]
2026	0	[2]
Thereafter	0	[2]
Total	41,148	[2]
EnVen Acquisition
Contractual Obligation [Line Items]
2023	259,858	[3]
2024	0	[3]
2025	0	[3]
2026	0	[3]
Thereafter	0	[3]
Total	259,858	[3]
Other Commitments
Contractual Obligation [Line Items]
2023	9,627	[4]
2024	327	[4]
2025	327	[4]
2026	0	[4]
Thereafter	0	[4]
Total	$ 10,281	[4]
[1] Includes vessel commitments the Company will utilize for certain Deepwater well intervention, drilling operations and decommissioning activities. These commitments represent gross contractual obligations and accordingly, other joint owners in the properties operated by the Company will be billed for their working interest share of such costs. Includes committed purchase orders to execute planned future drilling activities. These commitments represent gross contractual obligations and accordingly, other joint owners in the properties operated by the Company will be billed for their working interest share of such costs. Includes cash consideration and contingent fees related to the EnVen Acquisition. See Note 15 — Subsequent Events for further information on the EnVen Acquisition. Includes commitment to acquire additional lease acreage associated with our CCS Segment.

Commitments and Contingencies_3

Commitments and Contingencies - Summary of Decommissioning Obligations Included in Consolidated Balance Sheets (Details) - Decommissioning Abandonment Obligations - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Loss Contingencies [Line Items]
Balance, beginning of period	$ 24,336	$ 0	$ 0
Additions	8,900	21,056	0
Changes in estimate	22,658	0	0
Reimbursements due from third parties	0	3,280	0
Settlements	(1,625)	0	0
Balance, end of period	54,269	24,336	0
Other Current Liabilities
Loss Contingencies [Line Items]
Less: Current portion	42,069	3,756	0
Other Noncurrent Liabilities
Loss Contingencies [Line Items]
Long-term portion	$ 12,200	$ 20,580	$ 0

Segment Information - Additiona

Segment Information - Additional Information (Details)	12 Months Ended
	Dec. 31, 2022 Segment
Segment Reporting [Abstract]
Number of operating segments	2

Segment Information- Summary of

Segment Information- Summary of information by Business Segment (Details) - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Segment Reporting Information [Line Items]
Revenues from External Customers		$ 1,651,980	$ 1,244,540	$ 575,936
Equity in the Net Income of Investees Accounted for by the Equity Method		14,222	0	0
Adjusted EBITDA		847,054	611,016	435,327
Segment Expenditures		455,452	338,822	405,525
Operating Segments [Member]
Segment Reporting Information [Line Items]
Equity in the Net Income of Investees Accounted for by the Equity Method		(1,065)
Operating Segments [Member] | Upstream
Segment Reporting Information [Line Items]
Revenues from External Customers		1,651,980	1,244,540	575,936
Equity in the Net Income of Investees Accounted for by the Equity Method		101	0	0
Adjusted EBITDA		859,840	615,798	435,327
Segment Expenditures		452,674	338,822	405,525
Operating Segments [Member] | All Other
Segment Reporting Information [Line Items]
Revenues from External Customers	[1]	0	0	0
Equity in the Net Income of Investees Accounted for by the Equity Method	[1]	(1,166)	0	0
Adjusted EBITDA	[1]	(12,786)	(4,782)	0
Segment Expenditures	[1]	$ 2,778	$ 0	$ 0
[1] The CCS Segment is included in the “All Other” category. The CCS Segment is an emerging business in the start-up phase of operations and the business that does not currently generate any revenues. The CCS Segment’s business activities are conducted through both wholly owned subsidiaries and equity method investments with industry partners. Equity method investments is a business strategy that enables us to achieve favorable economies of scale relative to the level of investment and business risk assumed.

Segment Information - Schedule

Segment Information - Schedule of Reconciliation of Reportable Segment Information to the Company's Consolidated Totals (Details) - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Segment Reporting Information [Line Items]
Adjusted EBITDA		$ 847,054	$ 611,016	$ 435,327
Unallocated corporate general and administrative expense		99,754	78,677	79,175
Interest expense		(125,498)	(133,138)	(99,415)
Depreciation, depletion and amortization		(414,630)	(395,994)	(364,346)
Write-down of oil and natural gas properties		0	18,123	267,916
Derivative fair value loss (gain)		(272,191)	(419,077)	87,685
Gain (loss) on extinguishment of debt		(1,569)	(13,225)	1,662
Non-cash equity-based compensation expense		15,953	10,992	8,669
Income (loss) before income taxes		384,452	(184,587)	(430,022)
Segment Reconciling Items [Member]
Segment Reporting Information [Line Items]
Unallocated corporate general and administrative expense		(5,280)	(4,542)	(5,088)
Interest expense		(125,498)	(133,138)	(99,415)
Depreciation, depletion and amortization		(414,630)	(395,994)	(364,346)
Accretion expense		(55,995)	(58,129)	(49,741)
Write-down of oil and natural gas properties		0	(18,123)	(267,916)
Transaction and other (income) expenses	[1]	34,513	(5,886)	(14,917)
Decommissioning Obligations	[2]	(31,558)	(21,055)	0
Derivative fair value loss (gain)	[3]	(272,191)	(419,077)	87,685
Net cash paid on settled derivative instruments	[3]	425,559	290,164	(143,905)
Gain (loss) on extinguishment of debt		(1,569)	(13,225)	1,662
Non-cash write-down of other well equipment inventory		0	(5,606)	(699)
Non-cash equity-based compensation expense		(15,953)	(10,992)	(8,669)
Reportable segment | Operating Segments [Member]
Segment Reporting Information [Line Items]
Adjusted EBITDA		859,840	615,798	435,327
All Other | Operating Segments [Member]
Segment Reporting Information [Line Items]
Adjusted EBITDA	[4]	$ (12,786)	$ (4,782)	$ 0
[1] Other income (expense) includes restructuring expenses, cost saving initiatives and other miscellaneous income and expenses that we do not view as a meaningful indicator of our operating performance. For the year ended December 31, 2022 , the amount includes $ 27.5 million gain as a result of the settlement agreement to resolve previously pending litigation that was filed in October 2017 that is further discussed in Note 12 — Commitments and Contingencies. Additionally, it includes a $ 15.3 million gain for the year ended December 31, 2022 on partial sale of our investment in Bayou Bend that is further discussed in Note 11 — Related Party Transactions . For the year ended December 31, 2020, the amount includes $ 1.4 million of legal entity restructuring costs and $ 1.3 million of severance related cost saving initiatives due to the COVID-19 pandemic. Estimated decommissioning obligations were a result of working interest partners or counterparties of divestiture transactions that were unable to perform the required abandonment obligations due to bankruptcy or insolvency. See Note 12 — Commitments and Contingencies for additional information on decommissioning obligations. The adjustments for the derivative fair value (gains) losses and net cash receipts (payments) on settled commodity derivative instruments have the effect of adjusting net loss for changes in the fair value of derivative instruments, which are recognized at the end of each accounting period because we do not designate commodity derivative instruments as accounting hedges. This results in reflecting commodity derivative gains and losses within Adjusted EBITDA on an unrealized basis during the period the derivatives settled. The CCS Segment is included in the “All Other” category. The CCS Segment is an emerging business in the start-up phase of operations and the business that does not currently generate any revenues. The CCS Segment’s business activities are conducted through both wholly owned subsidiaries and equity method investments with industry partners. Equity method investments is a business strategy that enables us to achieve favorable economies of scale relative to the level of investment and business risk assumed.

Segment Information - Schedul_2

Segment Information - Schedule of Reconciliation of Reportable Segment Information to the Company's Consolidated Totals (Details) (Parenthetical) - USD ($) $ in Millions		12 Months Ended
	Mar. 23, 2022	Dec. 31, 2022	Dec. 31, 2020
Segment Reporting Information [Line Items]
Gain (Loss) Related to Litigation Settlement, Total	$ 27.5
Operating Segments [Member]
Segment Reporting Information [Line Items]
Gain (Loss) Related to Litigation Settlement, Total		$ 27.5
Legal entity restructuring costs			$ 1.4
Operating Segments [Member] | Bayou Bend CCS LLC [Member]
Segment Reporting Information [Line Items]
Gain on partial disposal of investment		$ 15.3
Operating Segments [Member] | One-time Termination Benefits [Member]
Segment Reporting Information [Line Items]
Severance Costs			$ 1.3

Segment Information - Reconcili

Segment Information - Reconciliation of Reportable Segment Expenditures (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Segment Reporting Information [Line Items]
Plugging & abandonment	$ 69,596	$ 67,988	$ 43,933
Other deferred payments	0	(7,921)	(11,921)
Exploration, development and other capital expenditures	323,164	293,331	362,942
Operating Segments [Member] | Reportable segment
Segment Reporting Information [Line Items]
Segment Expenditures	452,674	338,822	405,525
Operating Segments [Member] | All Other [Member]
Segment Reporting Information [Line Items]
Segment Expenditures	2,778	0	0
Segment Reconciling Items [Member]
Segment Reporting Information [Line Items]
Change in capital expenditures included in accounts payable and accrued liabilities	(60,011)	28,258	16,002
Plugging & abandonment	(69,596)	(67,988)	(43,933)
Decommissioning obligations settled	(1,625)	0	0
Investment in CCS intangibles and equity method investees	(2,778)	0	0
Other deferred payments	0	(7,921)	(11,921)
Non-cash well equipment inventory transfers	(6)	1,086	(3,030)
Other	$ 1,728	$ 1,074	$ 299

Supplemental Oil and Gas Disc_3

Supplemental Oil and Gas Disclosures (Unaudited) - Schedule of Capitalized Costs Related to Oil, Natural Gas and NGL Activities and Related Accumulated Depletion and Amortization (Details) $ in Thousands	Dec. 31, 2022 USD ($) $ / Boe	Dec. 31, 2021 USD ($) $ / Boe	Dec. 31, 2020 USD ($) $ / Boe
Extractive Industries [Abstract]
Proved properties	$ 5,964,340	$ 5,232,479	$ 4,945,550
Unproved oil and gas properties, not subject to amortization	154,783	219,055	254,994
Total oil and gas properties	6,119,123	5,451,534	5,200,544
Less: Accumulated depletion	3,484,590	3,072,907	2,680,254
Net capitalized costs	$ 2,634,533	$ 2,378,627	$ 2,520,290
Depletion and amortization rate (Per Boe) | $ / Boe	18.95	16.71	31.42

Supplemental Oil and Gas Disc_4

Supplemental Oil and Gas Disclosures (Unaudited) - Schedule of Capitalized Costs Related to Oil, Natural Gas and NGL Activities and Related Accumulated Depletion and Amortization (Parenthetical) (Details) - USD ($) $ in Thousands	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Capitalized Costs Relating To Oil And Gas Producing Activities By Geographic Area [Line Items]
Unproved properties, not subject to amortization	$ 154,783	$ 219,055	$ 254,994
Mexico
Capitalized Costs Relating To Oil And Gas Producing Activities By Geographic Area [Line Items]
Unproved properties, not subject to amortization	$ 111,400	$ 110,300	$ 121,700

Supplemental Oil and Gas Disc_5

Supplemental Oil and Gas Disclosures (Unaudited) - Additional Information (Details) - MMBoe	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Reserve Quantities [Line Items]
Audited percentage of proved oil, natural gas and NGL reserves attributable to all of oil and natural gas properties	100%	100%	100%
Proved Developed and Undeveloped Reserve, Net (Energy), Period (Increase) Decrease	21	1.4	21.3
Sales of reserves	1.4
Decrease of production	21.7	23.5	20
Revision to previous estimates	(9)	20.3	(24.2)
Estimated proved reserves from extensions and discoveries	11.2	1.8	4.7
Prescribed rate of discounted future net cash flows	10%
Multiple Acquisitions
Reserve Quantities [Line Items]
Purchases of estimated proved reserves			60.7

Supplemental Oil and Gas Disc_6

Supplemental Oil and Gas Disclosures (Unaudited) - Schedule of Costs Incurred in Oil, Natural Gas and NGL Property Acquisition, Exploration and Development Activities (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Property acquisition costs:
Proved properties	$ 0	$ 210	$ 422,833
Unproved properties, not subject to amortization	2,221	0	95,242
Total property acquisition costs	2,221	210	518,075
Exploration costs	125,889	23,844	59,422
Development costs	541,512	245,058	362,011
Total costs incurred	$ 669,622	$ 269,112	$ 939,508

Supplemental Oil and Gas Disc_7

Supplemental Oil and Gas Disclosures (Unaudited) - Schedule of Costs Incurred in Oil, Natural Gas and NGL Property Acquisition, Exploration and Development Activities (Parenthetical) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Costs Incurred Oil And Gas Property Acquisition Exploration And Development Activities [Line Items]
Exploration costs	$ 125,889	$ 23,844	$ 59,422
Mexico
Costs Incurred Oil And Gas Property Acquisition Exploration And Development Activities [Line Items]
Exploration costs	$ 1,200	$ 6,600	$ 14,600

Supplemental Oil and Gas Disc_8

Supplemental Oil and Gas Disclosures (Unaudited) - Schedule of Estimated Proved Reserves at Net Ownership Interest (Details)	12 Months Ended
	Dec. 31, 2022 MBoe MMBoe MMBbls MMcf	Dec. 31, 2021 MBoe MMBoe MMcf MMBbls	Dec. 31, 2020 MBoe MMBoe MMcf MMBbls
Reserve Quantities [Line Items]
Revision of previous estimates | MMBoe	9	(20.3)	24.2
Production | MMBoe	(21.7)	(23.5)	(20)
Sales of reserves | MMBoe	(1.4)
Extensions and discoveries | MMBoe	11.2	1.8	4.7
Oil (MBbls)
Reserve Quantities [Line Items]
Total proved reserves, beginning balance	107,764	109,307	106,754
Revision of previous estimates	(5,625)	13,619	(14,633)
Production	(14,561)	(16,159)	(13,665)	[1]
Sales of reserves	(158)
Purchases of reserves			26,903
Extensions and discoveries	3,639	997	3,948
Total proved reserves, ending balance	91,059	107,764	109,307
Total proved developed reserves	80,285	93,420	85,007
Total proved undeveloped reserves	10,774	14,344	24,300
Gas (MMcf)
Reserve Quantities [Line Items]
Total proved reserves, beginning balance | MMcf	236,353	257,208	155,998
Revision of previous estimates | MMcf	(8,302)	8,979	(56,358)
Production | MMcf	(32,215)	(32,795)	(28,652)	[1]
Sales of reserves | MMcf	(7,625)
Purchases of reserves | MMcf			181,872
Extensions and discoveries | MMcf	31,340	2,961	4,348
Total proved reserves, ending balance | MMcf	219,551	236,353	257,208
Total proved developed reserves | MMcf	161,727	186,442	204,054
Total proved undeveloped reserves | MMcf	57,824	49,911	53,154
NGL (MBbls)
Reserve Quantities [Line Items]
Total proved reserves, beginning balance	14,435	10,858	8,981
Revision of previous estimates	(2,002)	5,137	(168)
Production	(1,793)	(1,875)	(1,559)	[1]
Sales of reserves	0
Purchases of reserves			3,528
Extensions and discoveries	2,288	315	76
Total proved reserves, ending balance	12,928	14,435	10,858
Total proved developed reserves	9,315	11,792	8,104
Total proved undeveloped reserves	3,613	2,643	2,754
Oil Equivalent (MBoe)
Reserve Quantities [Line Items]
Total proved reserves, beginning balance | MBoe	161,591	163,033	141,735
Revision of previous estimates | MBoe	(9,010)	20,252	(24,195)
Production | MBoe	(21,723)	(23,500)	(19,999)	[1]
Sales of reserves | MBoe	(1,429)
Purchases of reserves | MBoe			60,743
Extensions and discoveries | MBoe	11,150	1,806	4,749
Total proved reserves, ending balance | MBoe	140,579	161,591	163,033
Total proved developed reserves | MBoe	116,555	136,286	127,120
Total proved undeveloped reserves | MBoe	24,024	25,305	35,913
[1] Excludes approximately 3.0 MBoe of Mexico well test production

Supplemental Oil and Gas Disc_9

Supplemental Oil and Gas Disclosures (Unaudited) - Schedule of Estimated Proved Reserves at Net Ownership Interest (Parenthetical) (Details)	12 Months Ended
	Dec. 31, 2022 MMBoe	Dec. 31, 2021 MMBoe	Dec. 31, 2020 MBoe MMBoe
Reserve Quantities [Line Items]
Excludes well test production | MMBoe	21.7	23.5	20
Mexico
Reserve Quantities [Line Items]
Excludes well test production | MBoe			3

Supplemental Oil and Gas Dis_10

Supplemental Oil and Gas Disclosures (Unaudited) - Schedule of Standardized Measure of Discounted Future Net Cash Flows Related to Interest in Proved Oil, Natural Gas and NGL Reserves (Details) - USD ($) $ in Thousands	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Extractive Industries [Abstract]
Future cash inflows	$ 10,674,896	$ 8,496,005	$ 4,927,497
Future costs:
Production	(1,906,752)	(1,868,818)	(1,105,211)
Development and abandonment	(1,873,453)	(1,422,507)	(1,236,874)
Future net cash flows before income taxes	6,894,691	5,204,680	2,585,412
Future income tax expense	(1,114,409)	(676,778)	(141,515)
Future net cash flows after income taxes	5,780,282	4,527,902	2,443,897
Discount at 10% annual rate	(1,411,834)	(1,087,291)	(538,963)
Standardized measure of discounted future net cash flows	$ 4,368,448	$ 3,440,611	$ 1,904,934	$ 2,537,595

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, 2022 $ / bbl $ / Mcf	Dec. 31, 2021 $ / bbl $ / Mcf	Dec. 31, 2020 $ / bbl $ / Mcf
Oil
Discounted Future Net Cash Flows Relating To Proved Oil And Gas Reserves [Line Items]
SEC pricing	96.03	67.14	39.47
Natural Gas
Discounted Future Net Cash Flows Relating To Proved Oil And Gas Reserves [Line Items]
SEC pricing | $ / Mcf	6.80	3.71	1.97
NGL
Discounted Future Net Cash Flows Relating To Proved Oil And Gas Reserves [Line Items]
SEC pricing	33.89	26.62	9.89

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, 2022	Dec. 31, 2021	Dec. 31, 2020
Extractive Industries [Abstract]
Standardized measure, beginning of year	$ 3,440,611	$ 1,904,934	$ 2,537,595
Sales and transfers of oil, net gas and NGLs produced during the period	(1,340,400)	(957,576)	(339,557)
Net change in prices and production costs	2,388,442	2,049,980	(1,468,304)
Changes in estimated future development and abandonment costs	(84,391)	(57,876)	32,589
Previously estimated development and abandonment costs incurred	20,107	69,125	46,143
Accretion of discount	392,600	199,849	299,302
Net change in income taxes	(327,265)	(391,834)	361,875
Purchases of reserves	0	0	730,611
Sales of reserves	(5,218)	0	0
Extensions and discoveries	202,239	45,485	71,589
Net change due to revision in quantity estimates	(255,743)	426,357	(309,338)
Changes in production rates (timing) and other	(62,534)	152,167	(57,571)
Standardized measure, end of year	$ 4,368,448	$ 3,440,611	$ 1,904,934

Schedule I - Balance Sheets (De

Schedule I - Balance Sheets (Details) - USD ($) $ in Thousands	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Accounts receivable
Other, net	$ 6,684	$ 18,062
Prepaid assets	84,759	48,042
Other current assets	1,917	1,674
Total current assets	367,829	340,003
Other long-term assets:
Investments in subsidiaries	1,745	0
Total assets	3,058,626	2,766,815
Current liabilities:
Accounts payable	128,174	85,815
Accrued liabilities	219,769	130,459
Other current liabilities	60,359	33,061
Total current liabilities	607,058	600,526
Long-term liabilities:
Other long-term liabilities	176,152	45,006
Total liabilities	1,893,050	2,006,162
Stockholdersʼ Equity:
Preferred stock, $0.01 par value; 30,000,000 shares authorized and no shares issued or outstanding as of December 31, 2022 and 2021	0	0
Common stock $0.01 par value; 270,000,000 shares authorized; 82,570,328 and 81,881,477 shares issued and outstanding as of December 31, 2022 and 2021, respectively	826	819
Additional paid-in capital	1,699,799	1,676,798
Accumulated deficit	(535,049)	(916,964)
Total stockholdersʼ equity	1,165,576	760,653	$ 926,601	$ 1,078,277
Total liabilities and stockholdersʼ equity	3,058,626	2,766,815
Parent
Accounts receivable
Other, net	0	523
Prepaid assets	169	141
Other current assets	36	0
Total current assets	205	664
Other long-term assets:
Investments in subsidiaries	1,168,053	761,739
Total assets	1,168,258	762,403
Current liabilities:
Accounts payable	249	178
Accrued liabilities	728	497
Other current liabilities	62	0
Total current liabilities	1,039	675
Long-term liabilities:
Other long-term liabilities	1,643	1,075
Total liabilities	2,682	1,750
Stockholdersʼ Equity:
Preferred stock, $0.01 par value; 30,000,000 shares authorized and no shares issued or outstanding as of December 31, 2022 and 2021	0	0
Common stock $0.01 par value; 270,000,000 shares authorized; 82,570,328 and 81,881,477 shares issued and outstanding as of December 31, 2022 and 2021, respectively	826	819
Additional paid-in capital	1,699,799	1,676,798
Accumulated deficit	(535,049)	(916,964)
Total stockholdersʼ equity	1,165,576	760,653
Total liabilities and stockholdersʼ equity	$ 1,168,258	$ 762,403

Schedule I - Balance Sheets (_2

Schedule I - Balance Sheets (Details) (Paranthetical) - $ / shares	Dec. 31, 2022	Dec. 31, 2021
Condensed Balance Sheet Statements, Captions [Line Items]
Preferred Stock, Par or Stated Value Per Share	$ 0.01	$ 0.01
Preferred Stock, Shares Authorized	30,000,000	30,000,000
Preferred Stock, Shares Issued	0	0
Preferred Stock, Shares Outstanding	0	0
Common Stock, Par or Stated Value Per Share	$ 0.01	$ 0.01
Common Stock, Shares Authorized	270,000,000	270,000,000
Common Stock, Shares, Issued	82,570,328	81,881,477
Common Stock, Shares, Outstanding	82,570,328	81,881,477
Parent Company [Member]
Condensed Balance Sheet Statements, Captions [Line Items]
Preferred Stock, Par or Stated Value Per Share	$ 0.01	$ 0.01
Preferred Stock, Shares Authorized	30,000,000	30,000,000
Preferred Stock, Shares Issued	0	0
Preferred Stock, Shares Outstanding	0	0
Common Stock, Par or Stated Value Per Share	$ 0.01	$ 0.01
Common Stock, Shares Authorized	270,000,000	270,000,000
Common Stock, Shares, Issued	82,570,328	81,881,477
Common Stock, Shares, Outstanding	82,570,328	81,881,477

Schedule I - Statements of Oper

Schedule I - Statements of Operations (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
General and administrative expense	$ 99,754	$ 78,677	$ 79,175
Total operating expenses	(915,861)	(869,924)	(997,246)
Operating expense	736,119	374,616	(421,310)
Interest expense	(125,498)	(133,138)	(99,415)
Other income (expense)	31,800	(6,988)	3,018
Net income (loss) before income taxes	384,452	(184,587)	(430,022)
Income tax benefit (expense)	(2,537)	1,635	(35,583)
Net income (loss)	381,915	(182,952)	(465,605)
Parent
General and administrative expense	2,145	1,322	1,404
Total operating expenses	2,145	1,322	1,404
Operating expense	(2,145)	(1,322)	(1,404)
Interest expense	0	(5)	7
Other income (expense)	(1)	(2)	(2)
Equity earnings (loss) from subsidiaries	385,968	(180,548)	(431,446)
Net income (loss) before income taxes	383,822	(181,877)	(432,845)
Income tax benefit (expense)	(1,907)	(1,075)	(32,760)
Net income (loss)	$ 381,915	$ (182,952)	$ (465,605)

Schedule I - Statements of Cash

Schedule I - Statements of Cash Flows (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Cash flows from operating activities:
Net cash provided used in operating activities	$ 709,739	$ 411,388	$ 301,923
Cash flows from investing activities:
Net cash used in investing activities	(311,977)	(293,747)	(678,904)
Cash flows from financing activities:
Proceeds from Issuance of Common Stock	0	0	71,100
Net cash provided by (used in) financing activities	(423,469)	(82,022)	324,192
Net increase (decrease) in cash and cash equivalents	(25,707)	35,619	(52,789)
Cash and cash equivalents:
Balance, beginning of period	69,852	34,233	87,022
Balance, end of period	44,145	69,852	34,233
Parent
Cash flows from operating activities:
Net cash provided used in operating activities	(809)	(876)	(936)
Cash flows from investing activities:
Distributions from subsidiaries	809	879	943
Contributions to subsidiaries	0	(3)	(71,107)
Net cash used in investing activities	809	876	(70,164)
Cash flows from financing activities:
Proceeds from Issuance of Common Stock	0	0	71,100
Net cash provided by (used in) financing activities	0	0	71,100
Net increase (decrease) in cash and cash equivalents	0	0	0
Cash and cash equivalents:
Balance, beginning of period	0	0	0
Balance, end of period	$ 0	$ 0	$ 0